The

Lease Pumper’s Handbook

The Oklahoma Commission on Marginally Producing

Oil and Gas Wells

Marginal Well Commission Lease Pumper’s Handbook Disclaimer

This publication is provided “as is” without warranty of any kind, either expressed or implied, including, but not limited to, the implied warranties of merchantability, fitness for a particular purpose, or non-infringement. The Marginal Well Commission assumes no responsibility for errors or omissions in this publication or other documents which are referenced by or linked to this publication. References to corporations, their services and products, are provided “as is” without warranty of any kind, either expressed or implied. In no event shall the Marginal Well Commission be liable for any special, incidental, indirect or consequential damages of any kind, or any damages whatsoever, including, without limitation, those resulting from loss of use, data or profits, whether or not advised of the possibility of damage, and on any theory of liability, arising out of or in connection with the use of this information. This publication could include technical or other inaccuracies or typographical errors. Changes are periodically added to the information herein; these changes will be incorporated in new editions of this publication.

Published by

The

COMMISSION on MARGINALLY PRODUCING

OIL and GAS WELLS

of OKLAHOMA

First Edition2003

Written by

Leslie V. Langston

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Foreword

To Petroleum Operators, Lease Pumpers, and Field Personnel

We take very seriously our obligation to assist you in every way possible to besuccessful in bringing quality training in your Production Operations. The Commissionhas been in agreement with me that an important goal was to improve first the quality oftraining available for the LEASE PUMPER. We needed a manual that can make a directimpact in our ability to understand how to do our best - in the skills needed in how toproduce the most possible oil and gas from marginally producing wells. This alsoincludes a higher level of skill in performing HANDS ON daily duties.

After many discussions among the commissioners and many of you in the field of howto achieve this goal, we began a search for someone to write the first edition. After muchsearch, we did commit the project, and have met this first objective. You will note thatthe training outline has been designed with the thought in mind that this publication canbe updated easily to permit us to keep abreast of changes in field.

Our future plans include using this publication as a springboard toward the developmentof the needs for a series of appropriate training programs. When these are groupedtogether, they will form the basis for a comprehensive Operators handbook of fieldoperations and procedures designed to meet many of other field training needs that havenot yet been addressed. This goal includes topics in designing constructing andmaintenance of producing facilities. Another might include basic Well Servicing andworkover. A final manual in this series may also include topics for Field Supervision andManagement. The Common thread that must tie all of these together is the strict goal ofall materials must meet definite needs in field activities and solve real problems.

We especially welcome your comments and assistance in these endeavors.

Sincerely,

Rick ChapmanExecutive Director (1996-2000)

Commission on Marginally Producing Oil and Gas Wells,State of Oklahoma

1218-B West Rock Creek RoadNorman, Oklahoma 73069-8590

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Dedication

To All Lease Pumpers

We dedicate this training manual to all of the oilfield LEASE PUMPERS. It takes aspecial type of personal drive, dedication, or whatever you choose to call it for a person tochoose Lease Pumping as a career.

This is an occupation where most of your work is done in all types of weather whileworking alone, with few thanks, and possibly only a small herd of cattle as company.This takes a high level of self motivation. Everyone is not capable of working alone andefficiently directing their own work efforts and work ethics and be successful.

The purpose of gathering information for this publication is to assist you inunderstanding your job better and become more professional in the performance of yourlease duties. This should result in your extending the producing life of marginallyproducing oil and gas wells.. If the life of the wells are not extended or it does not makeit easier for you to maintain your production to an acceptable level, we have failed in thismission. The writing of this material was done by people who have gauged a lot of tanksand sold a lot of oil and does not necessarily reflect the opinions of the Commission. Wedo hope, however, that somewhere in this publication, you will receive enough newthoughts, knowledge, or personal motivation to make this effort worthwhile andcontinuously improve your skill at your chosen occupation.

We wish you every success at your occupation as a Lease Pumper.

Sincerely,

John A. TaylorChairman (1992-1998)

Commission on Marginally Producing Oil and Gas WellsState of Oklahoma

1218-B West Rock Creek RoadNorman, Oklahoma 73069-8590

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The Lease Pumper’s Handbook

Introduction

The LEASE PUMPER’S HANDBOOK has been written to assist you in producing oil andgas from marginally producing wells. This information should be appropriate anywhere thatcrude oil may be found. Every well that has been drilled where crude oil has been discoveredexperiences the reality that with each day’s production, there is less oil remaining in thereservoir than there was yesterday so production declines. Eventually, production will be so lowthat all wells will be plugged and abandoned. You must have the knowledge and skills necessaryto extend or even increase your production and the life of the field with the lowest practicallifting cost. Some fields in the United States have a projected life of more than 100 years, andthis is a long time. When your wells are plugged and abandoned, a tremendous amount of oil isalways left in the reservoir.

We welcome you to this edition of the Lease Pumper’s Handbook. We know that thispublication will undergo many revisions through the years, and possibly some of these changesmay even be a result of your actions. Regardless of how good or poor this handbook may be, itrepresents a step in the right direction in developing for you a meaningful publication that willhelp you do a better job and be more successful in your chosen occupation. Different terms andprocedures are also in use in different sections of the country, so bear with us if you are notfamiliar with a few of the ones used here. For instance a new, inexperienced worker might becalled a worm, squirrel, weevil, boll weevil, or half a dozen other names.

The information included in this publication is directed at the lease pumper. The roustabout infield maintenance needs to know much more about many subjects that do not apply to your job.What this person needs to know has been deliberately left out. An example of this is in cuttingand threading pipe or laying flow lines. Basic information, however, must be included in allmanuals.

The daily duties of the LEASE PUMPER are extremely varied and complex. Since no twoleases are alike, no two lease pumpers will have been assigned identical responsibilities evenwhen working for the same company. This is the way it should be and is everywhere. It is notpossible to write a publication that will exactly include what just you do each day, so you mayhave to search several publications to answer all of your questions. This publication should,however, include information about most of your normal daily pumping duties. The purpose ofthis book is to increase your field procedure knowledge and give you more ability to do a goodjob in the field. Good luck in both your chosen occupation and studies.

Sincerely,

Leslie V. Langston

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TABLE OF CONTENTS

INTRODUCTIONS.

A. Cover Sheet. Book Title.

B. Publishing Information. First Edition, 2003.

C. Foreword. Rick Chapman, Executive Director (1996-2000)Commission on Marginally Producing Oil and Gas Wells,State of Oklahoma.

D. Dedication. John A. Taylor, Chairman (1992-1998)Commission on Marginally Producing Oil And Gas Wells,State of Oklahoma.

E. Author’s Introduction. Leslie V. Langston, Author, First Edition

F. Commission Introduction. Liz Fajen, Executive Director,Commission on Marginally Producing Oil and Gas Wells,State of Oklahoma.

CHAPTERS

CHAPTER 1. RESPONSIBILITIES AND EMPLOYEE-EMPLOYERRELATIONSA. Duties and Responsibilities of the Lease Pumper

1. Job Duties.2. Work Hours.

· Lease pumper work schedules.· Lunch time.

3. Company Policies.· Contract pumping services.· Honesty is critical for employer trust.

4. Special Precautions.· The use of drugs or alcohol.· Hazards from heat sources.· Carrying firearms to work.

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B. Field Operations1. Dressed for Work and Weather.

· Full-length pants.· Long-sleeved shirt or coveralls.· Steel-toed shoes.· Eyeglasses and protective shields.· Gloves.· Hard hat.

2. Miscellaneous Gear.· Rags or wipes.· Pens, pencils, and paper.· Other items.

3. Typical Lease Hand Tools.· Vehicle tool and equipment storage.· The lease pumper’s toolbox and storage shed.

4. Oil Gauging and Test Equipment.5. Lease Operating Expenses.

· Supply expenses.6. Government Regulating Agencies.

· The Bureau of Land Management (BLM).· Occupational Safety and Health Administration (OSHA).· Environmental protection and standards.

CHAPTER 2. TRANSPORTATION, COMMUNICATIONS, AND LEASEMAINTENANCE

A. Getting to the Lease1. Vehicle Expense and Maintenance.

· Taking care of the lease vehicle.· Driving to and from the lease.· Lease roads.

2. Company Policies for Vehicle Use.· Personal use of the vehicle.· Unauthorized personnel in the vehicle.

3. Locating the Lease.· Location identification signs.· The federal system of rectangular surveys.· Locating the next lease.· Survey markers.

B. Routine and Emergency Communications1. What Is an Emergency?2. Emergency Telephone Numbers.3. Company and Personnel Communications.

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4. Field Support Services Telephone Numbers.5. Lease Locations.

C. General Lease Maintenance1. Landowner and Lease Operator Rights.2. Off-Road Travel.3. Livestock Injuries.4. Plants and Animals.5. Lease Maintenance.

· Road maintenance.· Cattle guards and gates.· Fences.· Vista of the lease.· Weed control.· Trash removal· Open pits and vents.· Lease offices.· Soil contamination.

CHAPTER 3. SAFETYA. Personal Safety

1. Good Judgment and Common Sense.· Being prepared.

2. Taking Unnecessary Chances.3. Making Safety a Part of the Job.4. Industry Standard Notices, Warning Signs, and Markers.

· DANGER.· WARNING.· CAUTION.· NOTICE.· SAFETY.· RADIATION.· The location of safety and fire safety equipment.· Barriers.· Typical lease signs.

5. Safety Equipment.· Breathing apparatus.· Goggles.· Hearing protection.· Eye wash stations.· Spark-proof tools.

B. Hydrogen Sulfide and Natural Gas Safety.1. Introduction to Hydrogen Sulfide Gas

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2. What Is Hydrogen Sulfide?

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3. Properties of Hydrogen Sulfide.4. The Dangers of Breathing H2S.5. Safe Working Procedures in Gaseous Areas.

· Safety training programs for working around hydrogen sulfide.· Where will the lease pumper encounter hydrogen sulfide?

6. Breathing Apparatus.· Individual fresh air packs.· The five-minute air pack.· The thirty-minute backpack.· Compressing fresh air.· The industrial sized bottle and hose.· Trailer-mounted equipment.· Taking care of air breathing equipment.

CHAPTER 4. UNDERSTANDING THE OIL WELLA. Looking Downhole

1. Oil-bearing Reservoirs.2. Formation Shapes.

· Dome formations.· Anticline formations.· Fault trap formations.· Reef trap formations.· Lens formations.· Unconformities.

3. The Anatomy of an Oil Well.B. Drilling Operations

1. Contracting the Well to Be Drilled.· The tool pusher.· The driller.· The derrick worker.· The floor workers.· Motor man.· Company representative.

2. Drilling the Well.3. Downhole Measurements.4. The Surface String of Casing.5. Intermediate Strings of Casing.6. Drill Stem Tests and Drilling Breaks.7. Keeping the Hole Full Gauge and the Packed Hole Assembly.8. Drilling a Straight Hole.

C. Completing the Well1. The Final String of Casing.

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· Cased-hole completion.· Open-hole completion.

2. Perforating and Completion.3. Tubing.4. The Tubing String.

· Mud anchor.· Perforations.· Seating nipple.· Tubing.· The packer.· The holddown.

5. Correlating Perforations.6. A Typical Wellhead.

· The casing head.· The intermediate head with casing hanger.· The tubing hanger.

CHAPTER 5. FLOWING WELLS AND PLUNGER LIFTA. Producing Flowing Wells

1. Allowables.· Coning wells and pulling in gas and water.· Effects of poor production techniques.

2. Several Operators Owning Wells in the Same Reservoir.3. What Makes a Well Flow Naturally?

· Packer removal.4. Producing a Flowing Well.

· Master gate valve.·· The pressure gauge.· The wing valve.·· The check valve· The casing valve.· The variable choke valve.· The positive choke.

5. The Skilled Pumper and Marginally Flowing Wells.B. Plunger Lift

1. The Cost of Changing a Well to Mechanical Lift.2 How Plunger Lift Works.3. Benefits of Plunger Lift.

· Reduce lifting costs.· Conserve formation gas pressure.· Increase production.· Produce with a low casing pressure.

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· Prevent water buildup.· Avoid gas-locked pump problems.· Reduce gas/oil ratio.· Scrape tubing paraffin.· Improve ease of operation.· Use pneumatic or electronic controllers.· Achieve lower installation and operating costs.

4. Plunger Selection.· Solid.· Brush.· Metal pad.· Wobble washer.· Flexible.· Clean-up plungers.

5. Bumper Housings and Catcher.6. Footpiece and Stop.7. Time Controls.

CHAPTER 6. MECHANICAL LIFTA. Pump Operation

1. Application of Mechanical Pumping.2. How Mechanical Lift Works.3. Problems Caused by the Cyclic Load Factor.4. Pumping at the Wrong Speed.

B. Operating and Servicing the Pumping Unit.1. Mechanical Lift with Electric Prime Movers.2. Mechanical Lift with Natural Gas Engines.3. Pumping Schedules.4. Automatic Controls.5. Maintaining the Pumping Unit.

· The daily inspection.· The weekly inspection.· The monthly inspection.· The three- and six-month inspection.· Pitman arm and gearbox problems.

6. Direction of Rotation.7. Gearbox Oil.8. Typical Pumping Unit Problems.

C. Wellhead Design and the Polished Rod1. Preparing the Well for Pumping Downhole.2. Pumping Wellheads.3. Selection of Polished Rods, Clamps, Liners, and Stuffing Boxes.

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· Polished rod.· The polished rod liner.· The polished rod clamp.· The stuffing box.· The polished rod lubricator.· The rod rotator.

4. Tubing, Casing, and Flow Line Check Valves.· The tubing check valve.· The casing check valve.· The flow line check valve.

D. The Downhole Pump1. Basic Components of the Pump.

· Standing valve.· Barrel tube.· Plunger.·· Traveling valve.·· Holddown seal assembly.

2. Pumps Designs.· Insert pumps.· Tubing pumps.·· Other styles of pumps.

CHAPTER 7. ELECTRICAL SUBMERSIBLE LIFTA. Electric Submersible Lift

1. Electrical Submersible Pumps.2. Advantages and Disadvantages of the Electrical Submersible Lift System.

· Advantages.· Disadvantages.

3. Downhole Components.· Motor.· Protector.· Gas separator.· Pump.· Cable.

4. Surface Components.· Tubing head.· Chart meter.· Control box.· Transformers.· Electrical supply system.

5. Special Surface Considerations.

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B. Operating Electrical Submersible Lift1. Well Operation and Automatic Controls.2. The Electrical Submersible Pump Well.3. Continuous Operation.4. Intermittent Operation.5. Servicing the Well When Problems Occur.

CHAPTER 8. HYDRAULIC LIFTA. Introduction to Hydraulic Lift

1. Principles of Hydraulic Lift.2. Designing and Installing Hydraulic Lift Systems at the Wellhead.3. The Insert Pump.4. The Free Pump5. The Jet Pump.6. Advantages and Disadvantages of Hydraulic Lift.

· Advantages.· Disadvantages.

B. The One-Well Hydraulic Lift System1. The One-Well Hydraulic System.2. The Advantages and Disadvantages of the One-Well System.

· Advantages.· Disadvantages.

C. The Central Power Hydraulic Lift System1. Central Power System from the Tank Battery.2. Crude Oil for Power.

· The power oil lines.3. Produced Water for Power.4. Closed Power Oil Systems.5. Analyzing Production and Testing the Wells.

· Modifications to the manifold.· Advantages and disadvantages.

CHAPTER 9. GAS LIFTA. Introduction to Gas Lift

1. The Use of Gas Lift.2. Advantages in Using Gas Lift.3. Setting Up a Gas Lift System.

· Gas compression and distribution.· Control valve.· Packer.· Tubing valves.· The wellhead and the two-pin recorder.

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4. How Gas Lift Works.· Sequences in unloading the well.

5. Tank Battery Arrangements for Gas Lift.B. Conventional Mandrels

1. Conventional Mandrel and Tubing Arrangements.2. Placing the Tubing and Valves in Order.3. The Gas Lift Valve.

C. Side-Pocket Mandrels1. The Side-Pocket Mandrel System.2. Producing Oil Through the Casing.3. Continuous and Intermittent Gas Lift.4. The Wireline Machine and Wireline Safety.

CHAPTER 10. THE TANK BATTERYA. Basic Tank Battery Systems

1. Oil Storage at the Drilling Site.2. The Natural Production Curve for a New Well.3. The Very First Production.

· Gauging new production at the well location.· Storing oil in rectangular tanks.· Safety in gauging and testing oil in round vertical tanks.· Gauging procedures and tank charts.· Gauging the holding tank on the location.

4. Storing and Accounting for Produced Crude Oil and Salt Water.5. What Is Produced from the Well?6. Designing a Tank Battery.

· How the tank battery works.· Basic tank battery components.· Flow lines.· Header lines from the wells.· Vessels.

B. Pressurized Vessels1. The Flow Line.

· Laying new flow lines.· Road crossings.

2. The Header.3. Pressurized Vessels.

· Tank battery typical operating pressures.· The emulsion inlet.· The gas outlet.· The drain outlet.· The high oil outlet.

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· The lower liquid outlet or water leg.· Floats.

4. The Separator.· Operation of the two-stage vertical separator.· Pressure safety devices.

5. The Heater/Treater.· Controlling the height of the water.· The fluid sight glasses.· Backpressure valves for pressurized vessels.

6. Interior Design of the Vertical Heater/Treater.· Inlet line.· At the bottom.· The oil trip upward.· The water leg.

C. Atmospheric Vessels1. Major Low-Pressure Gas System Components.2. Styles of Atmospheric Vessels.3. Common Lines and Openings of Atmospheric Vessels.

· The emulsion inlet.· The equalizer inlet or outlet (Option 1).· The overflow line (Option 2).· The gas outlet.· The oil outlet.· The side drain outlet (Option 1). Side outlet.· The side drain outlet (Option 2).· The bottom drain outlet.

4. The Gun Barrel or Wash Tank.5. The Stock Tank.

· Cone-bottomed tanks.· The stock tank openings.· The oil inlet line.· The drain line inside the tank.

6. The Water Disposal Tank.7 The Pit.8. The Dike.9. Vessels Solve Unusual Problems.

D. Emulsion Line Systems1. Emulsion from the Well.2. The Flow Lines and Header.

· The header.3. Chemical Injection at the Header.

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E Crude Oil Line Systems and Equipment1. Lines from the Separator.2. Lines from the Separator to the Heater/Treater.3. Lines from the Heater/Treater to the Gun Barrel.4. Lines from the Gun Barrel to the Stock Tanks.5. The Equalizer Line from Stock Tank to Stock Tank.

F. Circulating and Water Disposal Systems1. Produced Water at the Tank Battery.2. Water Separation from the Heater/Treater and the Gun Barrel.

· The gun barrel.3. The Circulating System.4. The Water Disposal Tank.5. Solving Circulating and Disposal Problems.

· Circulating oil while removing water from the system.· Automatic circulation from the LACT unit.· Emptying vessels for maintenance.· Cleaning tank bottoms.

6. The Circulating Pump.7. Hauling the Water by Truck.8. Water Injection.

G. The Crude Oil Sales System1. The Oil Sales System.2. Selling Oil by Truck Transport.3. Selling Oil with the LACT Unit.

H. Tank Battery Design Review1. What Does a Tank Battery Look Like?2. No Atmospheric Vessels.3. The Tank Battery Producing No Gas or Water.4. The Tank Battery Requiring a Gun Barrel.5. Tank Battery with Two Heater/Treaters and Two Stock Tanks.6. Single Tank with Shop-Made Gun Barrel on Stand.

CHAPTER 11. MOTORS, ENGINES, PUMPS, AND COMPRESSORSA. Motors

1. Fundamentals of Electricity.2. The Lease Electrical System.3. Control Boxes and Fuses.4. Time Clocks and Percentage Timers.

· The 24-hour time clock.· The percentage timer.

5. The Automated Control Box.6. Electric Motors.7. Electrical Safety.

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8. Costs of Electricity.B. Engines

1. Introduction to Engines.2. Two- and Four-Cycle Engines.3. What Makes an Engine Run?

· A heat source.· Fuel.· Compression.· Safety systems.

4. Engine Oils and Oil Additives.5. Gasoline and Gasoline Additives.6. Antifreeze and Radiators.7. Single- and Multiple-Cylinder Engines.8. Diesel Engines.9. Natural Gas Fuel Systems.

· Problems with wet gas containing water vapor.C. Circulating Pumps and Air Compressors

1. Tank Battery Circulating Pumps.2. Installation and Maintenance.3. Understanding Gas Pressure.4. Air Compressors.5. Air Compressor Maintenance.6. Gas Compressor Operation.

CHAPTER 12. GAUGING AND ANALYZING DAILY PRODUCTIONA. Lease Duties

1. What Makes an Outstanding Lease Pumper?· Skills needed to become an outstanding lease pumper.

2. Beginning the Day on the Lease.· Everything should be checked and observed during the morning rounds.· Visual Inspection.

3. Planning and Scheduling .· Monthly, quarterly, semiannual, and annual maintenance.· Monthly Schedule.· Well testing.· Circulating tank bottoms.· Chemical treating schedule.· Planning upcoming tasks.

B. Gauging Daily Production and Inspecting the Tank Battery1. Approaching the Tank Battery.

· The visual inspection.

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2. Gauging Equipment.· The gauge line.

3. Gauging Oil and the Grease Book.· Gauging the stock tank.· Gauging water levels.· Switching tanks and opening equalizer lines.· Alternate day gauging.

C. Analyzing Daily Production1. Problems with Short Production.

· At the Tank Battery.· A flow line has broken or become plugged.· At the well surface.· Downhole.

2. Problems with Overproduction.· Determining if the overproduction is oil or water.· When the tank battery is still in balance.

D. Unitizing the Reservoir and Commingling Production1. Satellite Tank Batteries.2. Problems and Solutions for Combined Flow Lines.

· The individual well tester.· Well tests at the satellite tank batteries.· Operation of satellite tank batteries.

3. Unitizing Fields Under One Operator.4. Commingling Different Pay Zones.5. Unitizing a Reservoir.

· Problems in production that justify the need for unitization.· The effects of unitizing.

6. Commingling Wells with Different Well Operators.7. Working for More than One Operator.

E. Repairs and Maintenance1. Effects of Reduced Production.2. A Reasonable Workload.3. At the Tank Battery.4. Leaks in Lines.

· Upwind precautions when gas is present.5. Pumping Unit and Wellhead Maintenance.6. Automation Control Maintenance.

CHAPTER 13. TESTING, TREATING, AND SELLING CRUDE OIL.A. Testing and Treating

1. Treating Oil, Corrosion, and Scale.· Treating crude oil before sales.

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· Reducing corrosion damage.· Scale deposits and sand stabilization.

2. Testing Crude Oil.· Eight inches of emulsion and thiefing the bottom.· Tagging bottom with the thief.· Checking the bottom.· 1% or less BS&W and the centrifuge.· Oil temperature correction.· API gravity and the hydrometer.

B. Methods Used to Treat BS&W.1. Overview of Treating Methods.2. Gravity.

· Flash and slow water gravity separation in treating crude oil.3. The Use of Time in Treating Oil.4. Separating Crude Oil and BS&W by Movement.5. The Effects of Chemicals in Treating Crude Oil.6. The Effects of Heat in Treating Crude Oil.7. Treating Oil by Chemical-Electrical Processes.

C. Treating with Chemicals.1. Purposes of Treating Chemicals.

· The use of detergents to remove water.· Use of solvents for paraffin.· Bottom breakers for tank bottom emulsions.

2. Introduction to Chemical Injectors, Styles, and Operation.· Treating oil at the tubing perforations or downhole.· Injecting chemicals at the tank battery.· Producing sellable crude oil.· Batch treatment while circulating.

3. Special Treating Processes.· Cleaning tank bottoms.· The hot oiler.· The slop tank.

D. Selling Crude Oil1. Preparing to Sell the Oil.

· End of the month oil sales overload.2. Selling Oil.

· Requirements for a full transport load.· Selling split loads.· Communication with the gauger.· The note jar.· Witnessing the oil sale and the rejection notice.

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3. Seals and Seal Accounting.· The run ticket.

4. Selling Oil by Use of the LACT Unit and Surge Tanks.· Hot oiling.

CHAPTER 14. WELL TESTINGA. Introduction to Well Tests.

1. Introduction to Well Testing.2. Pre-Test Preparation.

· Shutting the well in.· Normalizing production by producing the well before testing.

3. Preparing the Tank Battery for Testing a Well.4. Four Basic Well Tests.

· Potential test.· Daily test.· Productivity test.· Gas/oil ratio test.

5. Typical Test Information.· General lease information (typical for all tests.)· Well information.· Pumping well information.· Tank battery information.· Special data.

B. Standard Tests.1. The Reservoir and Drive Mechanisms.2. Potential Tests.

· Purposes of the new well potential test.· Purposes for conducting a potential test after working over an existing well.· Potential testing conclusions.

3. Daily Production Tests.4. Productivity Tests.5 Gas/Oil Ratio Tests.6. Testing Gas Wells.7. Quick and Short-Term Special Purpose Tests.

· Bucket and Barrel Tests.C. Special Tests.

1. Well Logs and Surveys.2. Pressure Surveys.3. Temperature Surveys.4. Other Well Tests.

· Caliper surveys.· Running scrapers.

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D. Gauges and Gauge Calibration.1. Quality of Gauges.2. Gauge Construction.3. Safety Gauges.

· Liquid-filled gauges.4. Adjustable and Test Gauges.5. Calibrating Gauges and the Dead Weight Tester.

·· Testing the pressure of the well directly.

CHAPTER 15. ENHANCING OIL RECOVERY.A. Enhanced Recovery.

1. Introduction to Enhanced Recovery.2. Enhanced Recovery Terminology.3. Technology Keeps Changing Improving Procedures.4. Not All of Yesterday’s Procedures Will Become Obsolete.

B. Primary Recovery.1. Primary or First-Stage Recovery.

· Production allowables and productivity testing.· Sand and acid fracing.· Stabilizing formation sand and scale.· Echometer, dynamometer, gas lift, plunger lift, and other well analysis and

automation control systems.· Hydrotesting, tracer surveys, well logging, and other surveys.· Moving the casing perforations up or down the hole.· Changing lift systems.

2. Production Stimulation Through Horizontal Drilling.3. Beam Gas Compressors for Stripper Production.4. Venting Casing Gas at the Wellhead.5. Perforation Orientation.

· Raising casing perforations.· Lowering casing perforations.· Tubing/casing orientation.

6. Innovative Procedures.C. Secondary Recovery.

1. Secondary Recovery.2. Water Injection and Water Flood.3. Preparing a Well for Water Injection.

· Downhole preparation.· Wellhead preparation.

4. Operating the Water Flood System and Typical Problems.· Intermittent Operation.

5. Gas Injection and Pressure Maintenance.

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D. Tertiary Recovery.1 Introduction to Tertiary Recovery.2. Miscible Displacement Processes.

· Miscible hydrocarbon displacement.· CO2 injection.· Inert gas injection.

3. Chemical Processes.· Surfactant-polymer injection.· Polymer flooding.· Caustic or alkaline flooding.

4. Thermal Processes.· Steam stimulation.· Steam and hot water injection.· In-situ combustion.

CHAPTER 16. CORROSION, SCALE, AND CATHODIC PROTECTION.A. Corrosion and Scale.

1. Introduction to Corrosion.2. Carbon Dioxide Corrosion.3. Hydrogen Sulfide Corrosion.4. Oxygen Corrosion.5. Electrochemical Corrosion.6. Problems with Scale.

· Stopping scale in the formation and chemical treatment.· Protective coatings.· Scale removal.· Problems with scale caused by construction practices.

7. Other Types of Corrosion.B. Corrosion Protection.

1. How to Prevent Corrosion Damage.· Rust.· Oxidation.· Painting.· Inside coating and linings.· Oiling the outside.· Insulating flanges.· Sacrificial anodes.· Electrical current.· Tarring and wrapping for underground black metal lines.· Conduits.· Fiberglass.· Galvanized bolted tanks.

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· Stainless steel and metal plating.· Plastic flow lines.· Chemical protection.· Mechanical barriers.

2. Locating Corrosion Damage Downhole.3. Protecting the Casing Long String.

· The use of insulating flange unions.· The use of sacrificial anodes.

4. Corrosion Protection at the Tank Battery.· Tank battery elevation and ground protection.· Lines protection.· Protecting vessels on the inside.

CHAPTER 17. WELL SERVICING AND WORKOVER.A. Well Servicing.

1. Introduction to Well Servicing.2. Styles of Well Servicing and Workover Units.

· Single-pole units.· Double-pole units.· Mast style units.· Single- and double-drum well servicing units.

3. Roading the Well Servicing Unit to the Lease.4. Approaching the Well.5. Setting Up the Well Servicing Unit.6. The Well Records.

B. Pulling the Rod String and Pump.1. The Rod String Records.2. The Strength of the Rod String.3. Straight and Tapered Rod Strings.4. Pulling and Running Rod Strings.

· Power rod tongs.· Pulling stuck pumps.

5. Running the Rod String into the Hole.· After the rod job is finished.

6. Fishing Parted Rod Strings.7. Fiberglass Rods.8. Downhole Pump Problems.

C. The Tubing String.1. Tubing and Casing Perforation Depth Comparisons.2. Selection of Tubing Quality.3. Tubing Lengths and Threads.4. Measuring Line Pipe and Tubing Diameter.

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5. Pulling and Running Tubing.· The mud anchor.· Pipe length measurements.· Perforated nipple.· Seating nipples.· Packers, hold-downs and safety joints.· The tubing string.· Pup joints.· Wellhead hangers.

6. Typical Tubing Problems and Solutions.· Split collars and holes in tubing.· Standing valves.· Split tubing and hydrotesting.

D. Wire Line Operations.1. Five Uses for Wire Lines in Servicing Wells.2. Wire Rope.3. Functions of Guy Lines.4. Functions of Line from Drum to Blocks.5. Sand Lines.6. Solid Wire Lines.7. Electric Lines.

E. Well Workover.1. Well Workover Operations.

· Killing flowing wells and blowout preventers.· Blowout preventers.

2. Stuck Pipe.· Salt bridges.· Scale deposits.· Sand control.

3. Drilling with Tubing.4. Stripping Wells.5. Fishing Tubing.

· Running impression blocks.· Hard impression blocks.· The soft impression block.· Fishing tools.

6. Fracing/Hydraulic Fracturing Wells.7. Pulling and Running Tubing Under Pressure.

CHAPTER 18. GAS WELLS.A. Introduction to Natural Gas Wells.

1. Understanding the Gas Well.

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2. Wellheads and Christmas Trees.3. Reservoir Characteristics of Gas Wells and Gas Production.4. Producing the Gas Well.5. The Wellhead and Safety Devices.

· The tubing safety valve.·· The surface safety valve.

B. Fluid Separation.1. The High-Pressure Gas Well Separators.2. Three-Stage, High-Pressure Separation and Indirect Heating.3. Vertical Separators That Do Not Require Heat.

C. Gas Dehydration.1. Gas Dehydration.2. Operating the Dehydration Unit.

· The inlet scrubber.· The contact tower.· The glycol pump.· The dual-action pumps.· The heat exchanger surge tank.· The three-phase gas, glycol, and condensate separator.· The reboiler.

3. Tank Batteries for Gas Wells.D. Gas Compression and Sales.

1. Natural Gas Compression.2. Natural Gas Measurements.3. Testing Gas Wells.4. Pipelines and Pipeline Problems.

· The removal of liquids from pipelines.5. Treating and Drying Natural Gas.6. Transporting Natural Gas Long Distances.

·· Cross-country gas lines.E. Natural Gas Systems.

1. The High-Pressure Gas Line System.2. Controlling the Pressure in the Separators and the Heater/Treater.3. The Well Testing Gas Measurement System.4. The Gas High Pressure Gathering System.5. The Low Pressure Gas Line System and the Vapor Recovery Unit.

· The vapor recovery unit.6. The Flare and the Gas Sales System.

CHAPTER 19. RECORD-KEEPINGA. Lease Records.

1. Advantages of Maintaining a Lease Records Book.2. Setting up the Lease Records Book.

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3. Setting up Standard Records.4. The Daily Gauge or Grease Book.

B. Well Records.1. Introduction to Well Records.2. Lease Drilling Records.3. Pumping Unit Information.4. Wellhead Records.5. Casing Records.6. Tubing and Packer Information.

· Packers and Holddowns.· Pulling Tension on the Tubing String.

7. Sucker Rods, Pump Design, and Service Records.8. Current Rod Servicing Records.

· Past Rod Pulling Record.9. Electrical Information.

· Control boxes and fuse information.· Electrical motor information.

10. Electrical motor information.C. Petroleum Production Records.

1. Production Record-keeping.2. Typical Lease Operation Records.3. Production Reports.

· Types of written oil production reports.· Gas production records.

4. Important Production Records.· Well Information.· Single-Well Tank Batteries.

5. Monthly Tank Battery Total Production Record.· Problem analysis from monthly test data.

6. Records for Daily Use.· Yesterday’s tank gauges.· The daily, seven-day, eight-day, or monthly production report.· Monthly tank battery production of oil, water, and gas, and daily averages.· Monthly individual well tests.· Chemical consumption records.

7. Benefits of Production Records.8. Supply Purchases.9. Time Sheets for Work Performed.

· Company employees.· Contract labor.

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D. Materials Records.1. Materials Control.

· Theft by Employees.2. Controlled Lease Equipment Storage.

· Location of a storage area.· Security fencing.· Weed and mud control.

3. Pipe Storage.· Pipe and rod storage areas and magnetic orientation.· Classifying used pipe.· Pipe rack design and numbering systems.· Pipe range.· Pipe collaring and condition.· Pipe separation and layering.

4. Storage of Other Materials.· Arrangement, pads, docks, and weather protection.· Junk and scrap designations.· Chemical and drum storage, content marking, and accounting.· Winterizing and deterioration control.

5. Joint Venture Inventory and Accounting.6. Transfer Forms and Procedures.

· Materials transferred out of storage.· Materials transferred into storage.· Materials being transferred from one lease to another.

7. Identification of All Chemicals Used or Stored on the Lease.·· Identifying Chemicals and Marking Barrels.

8. End of the Month Chemical Inventory.· Measuring barrel content.

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APPENDIXES

APPENDIX A. TOOLS AND RECORDS.A - 1 API pump Designations.A - 2 API Sizes of Pumping Unit Designations.A - 3 Pump Abbreviations.A - 4 Kickover Tools for Running Gas Lift Valves.A - 5 Kickover Tool For Pulling Gas Lift Valves.A - 6 55-Gallon Drum Measurements.A - 7 The 7-Day Daily Gauge Report.A - 8 The 8-Day Daily Gauge Report.A - 9 The Weekly Gauge Report. (Vertical)A - 10 The Monthly Gauge Report.A - 11 Materials Transfer Record.A - 12 Pipe Tally Sheet.A - 13 Fishing Rods.A - 14 Rod Fishing Tools.A - 15 Lease Information Record.A - 16 Motor/Engine Records.

APPENDIX B. PUMPING UNITSB - 1. Types and Styles of Mechanical Pumping Units.

1. Development of the Walking Beam Mechanical Pumping Unit.2. Styles of Pumping Units.3. Conventional Units.4. The Air-Balanced Pumping Unit.5. Mark Unitorque Units.6. Low Profile Units.7. Other Styles of Pumping Units.

B - 2. Selecting and Setting Up Pumping Units.1. Selecting the Correct Pumping Unit Base.2. Height of the Base.3. Preparing the Base.4. Centering the Horse Head Bridle Carrier Bar over the Hole.5. Leveling the Pumping Unit.6. Safety Grounding.7. Selecting Guard Rails and Belt Guards.

B - 3. Changing Pumping Unit Adjustments.1. Designing the Pumping Unit to Do the Job.2. Changing the Counterweight Position to Balance the Rod Load.3. Beam-Balanced Pumping Units.4. Changing Stroke Length.

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5. Lowering and Raising Rods.B - 4. Belts And Sheaves.

1. Introduction to Belts and Sheaves.2. V-Belts, Sizes, Widths, and Depths.3. Types of Belts Based on Load Performance.4. Number of Belts Required to Start and Pull Loads.5. Lengths of Belts in Inches.6. Belt Life.7. Styles of Sheaves.8. Number of Grooves.9. The Keyway.10. Math Calculations.

APPENDIX C. TANK BATTERIES.C - 1. Understanding the Tank Battery.

1. Openings to Vessels for Lines.2. The Shape and Purpose of Vessels.3. From the Well to the Tank Battery.

APPENDIX D. PIPE, CASING, AND TUBING.D - 1. Pipe, Casing, and Tubing.

1. Seamed and Seamless Steel Pipe.2. Pipe Schedules for Surface Construction.3. Lengths or Classes of Pipe.4. Sizes of Pipe.5. Tubing6. Casing.

APPENDIX E. CHEMICAL TREATMENT.E - 1. Special Information About Chemical Pumps.

1. The Principles of Chemical Pumps and Injectors.2. Mechanical Chemical Injectors.3. The Low-Pressure Pneumatic Injector.4. The High-Pressure Pneumatic Injector.5. The Electrical Injector Pump.6. The New Style of Chemical Pumps.7. Barrel Racks and Bulk Storage Containers.

E - 2. Solving Special Treating Problems.1. Location, Installation, Operation and Maintenance of Chemical Injectors.2. Treating Oil: A Review.

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3. Other Treating Procedures That Have Not Been Reviewed.4. Batch Treating the Heater/Treater.5. Treating High Bottoms by Circulating with Pump and Hoses.

APPENDIX F. MATHEMATICS.F - 1 Important Conversion FactorsF - 2 Lease Pumper Sample Math ProblemsF - 3 Belts And SheavesF - 4 Multiplication Table

APPENDIX G. GLOSSARY OF PRODUCTION TERMS.

APPENDIX I. INDEX

ACKNOWLEDGMENTS.

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The Lease Pumper’s Handbook

CHAPTER 1

RESPONSIBILITIES AND EMPLOYEE-EMPLOYER RELATIONS

A. Duties and Responsibilities of the Lease Pumper1. Job Duties.2. Work Hours.

· Lease pumper work schedules.· Lunch time.

3. Company Policies.· Contract pumping services.· Honesty is critical for employer trust.

4. Special Precautions.· The use of drugs or alcohol.· Hazards from heat sources.· Carrying firearms to work.

B. Field Operations1. Dressed for Work and Weather.

· Full-length pants.· Long-sleeved shirt or coveralls.· Steel-toed shoes.· Eyeglasses and protective shields.· Gloves.· Hard hat.

2. Miscellaneous Gear.· Rags or wipes.· Pens, pencils, and paper.· Other items.

3. Typical Lease Hand Tools.· Vehicle tool and equipment storage.· The lease pumper’s toolbox and storage shed.

4. Oil Gauging and Test Equipment.5. Lease Operating Expenses.

· Supply expenses.6. Government Regulating Agencies.

· The Bureau of Land Management (BLM).· Occupational Safety and Health Administration (OSHA).· Environmental protection and standards.

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1A-1

The Lease Pumper’s Handbook

Chapter 1Responsibilities and Employee-Employer Relations

Section A

DUTIES AND RESPONSIBILITIES OF THE LEASE PUMPER

This handbook presents information thatmust be known to the group of field workerswho produce so much of the nation’s energy.This occupation, like many others today,may be known by a number of differenttitles within the industry, such asproduction technician. However, thismanual will use the long respected andaccepted title of lease pumper. While theassigned duties of a lease pumper may varyfrom company to company and even fromlease to lease within the same company,some duties are almost always part of thelease pumper’s responsibilities, and theseduties are the primary focus of this book.

A-1. Job Duties.

The lease pumper’s primary jobresponsibility is to produce, treat, and sell asmuch crude oil and natural gas as possiblewith the lowest cost. These costs—oftenreferred to as operating costs or liftingcosts—consist of all lease expenses, costs oftools and equipment, vehicles, supplies suchas chemicals, utilities such as electricity, andsalaries of personnel who work the lease,including the lease pumper. There are manyother not-so-obvious expenses such aspaying for the original purchase of the lease,royalties, costs of well services, andsupervisory and office expenses. Even lessobvious than these are taxes, insurance,employee benefits, lease support, andpossibly bank interest and debt repayment.

The lease must make a profit above all ofthese expenses. Most of the oil sold, if notall of it, will be produced from pumpingwells or wells with some type of enhancedrecovery. As production from a welldeclines (and most wells are low productionor marginally producing wells), the incomefrom the lease also declines, while the timeand cost required to coax productionincreases. Thus, the challenge for the leasepumper to make a profit from the leasebecomes more difficult—which means thatgood skills become even more important.

Another challenge of a career as a leasepumper is to be a good self-starter who canget a job done without a lot of supervision.Some people are capable of working steadilyall day by themselves doing necessary andconstructive work. Others are not highlymotivated and do not do well at pushingthemselves, working well only when theyhave continuous work supervision. When alease pumper lacks the self-discipline to dothe work that is required to maintain thelease, the equipment and site will becomerun down, and the lack of adequate attentionwill soon be obvious in the appearance ofthe lease and the production records.

A-2. Work Hours.

While many lease pumpers are consideredto be full-time employees working fortyhours per week, others work part-timeaccumulating less than forty hours each

1A-2

week, especially lease pumpers that work avariety of leases as a relief worker, filling infor lease pumpers who are sick, on vacation,or on their days off.

Employers differ in how they count a leasepumper’s number of hours. Some leaseoperators consider that the work day beginsas soon as the lease pumper begins the tripto the lease and does not end until the returntrip is completed. This is called port-to-portpay. Other operators mark the start of theworkday as the time when the lease pumperactually arrives at the lease. This may bereferred to as lease-time pay. It is notunusual for a lease operator to pay for traveltime one way and not the other. Whenaccepting employment, the lease pumpermust clearly understand the terms forcalculating pay. Acceptance of these termsis usually a condition of employment.

Lease pumper work schedules. Most leasepumpers get into the habit of going to workearly, arriving at the lease once the day isfully light so that everything on the lease canbe easily observed. Another advantage ofarriving early is that major problems thatmay have occurred during the night can beidentified. In this way, if the problemrequires that a service company respond,there is a better chance that they will be ableto come the same day.

While starting work after sunrise maybenefit the lease pumper, oilfield workers inactive districts have probably already beenworking for several hours, especially in largecompanies. The early morning tasks foroilfield workers with a major oil companymay follow a schedule such as:

4:00 a.m. Rig tool pushers get morningreports from rig crews.

5:00 a.m. Rig reports are telephoned tohome office.

6:00 a.m. Superintendents and supervisorsmeet to plan day.

7:00 a.m. Field supervisors and pushersmeet to outline day and makecontract labor arrangements.

8:00 a.m. Field workers arrive to begin day.

Lunch time. Lease operators differ in howthey count the time the lease pumper spendseating lunch in terms of hourly wages.Some employers pay straight through lunchtime if the lease pumper remains on the site,but do not count the time if the lease pumperleaves the lease to eat. One reason for thispolicy is that it is often possible for the leasepumper to eat while monitoring anoperation, such as circulating oil. As withother employment policies, the lease pumpermust clearly understand the allowancesmade for lunch.

A-3. Company Policies.

Most companies operate with set policies.Larger companies may maintain documentsdetailing these policies. These policies maygive information about:

· The work day and work week.· Probationary and permanent employment.· Overtime policies.· Sick time.·· Vacation time.·· Insurance plan.· Holidays and holiday work policies.· Savings plans.· Retirement plan.· Worker’s compensation.· Social security.· Tax withholdings.· Education plans.· Disciplinary actions and termination

policies.· Other important topics.

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Many leases are held by small companies.It is not uncommon for an applicant for aposition as a lease pumper to meet with thecompany owner during the hiring process.Often the owner or hiring supervisor mayoffer the job to a prospective employeeduring the first interview. Therefore, theperson interviewing for the job should beprepared to ask key questions that will helpthe applicant decide whether or not to takethe job. Such questions may include:

· What is the salary being offered?· What is the company’s policy on

advancement and pay increases?· What are duties of the job?· What hours of the day will be worked?· Is time driving to and from work

considered hours worked?· Is lunch time considered to be work

hours?· Which days of the week will be worked?· Is overtime paid and how is it figured?· What is the company policy on holidays,

vacation, sick leave, and other types ofabsences (jury duty, bereavement,military duty, etc.)?

· Who works the lease on those days whenthe regular lease pumper is off?

· What happens when the relief pumpergets sick?

· Is the lease pumper allowed to take thevehicle home?

· How are necessary supplies obtained?· What purchasing authority does the lease

pumper have?· Does the company offer a retirement

plan?

Because the duties of a lease pumper canvary greatly from company to company, theexperienced lease pumper may want to askspecific about the job duties andresponsibilities. For example, the applicant

may ask, “Am I expected to bump bottomand lift rod strings by myself? Do I help pullrod and tubing strings?” The prospectiveemployee may want to visit the lease site sothat the company representative can explainwhat the job entails. This also gives theapplicant a chance to see how well the leaseis maintained, whether the equipment is ingood repair, whether the access roads havebeen kept up, and other indications of howimportant such things are to the company.

Thus, there can be many differences inworking for a small company or working fora large one. The large company may havemore structure, with established policies andprocedures as well as a large support staff,contracted services, perhaps new tools andequipment, and other features that appeal tosome lease pumpers. On the other hand, asmaller company may not offer the supportstructure and fringe benefits that a largecompany can afford, but may appeal to somelease pumpers due to their greater flexibilityand the work can be very satisfying. Oftenthe lease pumper becomes almost like familywith the owners and, in some instances, willeventually own such a company.

Contract pumping services. Manycompanies now contract construction,maintenance, and pumping services insteadof hiring their own personnel. This is thecontinuation of a trend that started manyyears ago when production companies begancontracting with drilling companies thenwith well service providers and eventuallywith workover specialists. Today, manylease operators lease, such as largecompressors and engines, and the movementwill probably progress to the leasing ofpumping units, flow lines, and tankbatteries. This movement means that somelease pumpers have little responsibility formaintenance and can focus on production

1A-4

and selling the oil and gas produced. Leasepumpers who prefer the maintenance tasksassociated with the job may findemployment with equipment leasingcompanies more to their liking.

Honesty is critical for employer trust.The lease pumper is the only one who knowsexactly what happens on the lease each day.The problems that occur may happendownhole, involve the automated or surfaceequipment, or be caused by an action of thelease pumper or contract personnel. Somepeople have trouble admitting to the smallestmistake or error in judgment. This canresult in false reports being submitted, whichmay lead to incorrect wrong conclusionsbeing made concerning lease problems.

As an illustration, suppose that a leasepumper inspects a pumping unit. At thatparticular time of the day, the unit happenedto be in an automatic off cycle and was notpumping. As part of the inspection, the leasepumper turns the control switch through theoff position to run and completes theinspection. The switch should then be resetfor automatic control. However, if the leasepumper fails to turn the switch far enough tore-engage the automatic control and leaves itin the off position, the well will be shutdown. It will not produce any oil until thelease pumper returns, meaning that there islikely to be no production for 24 hours. Theoil shortage the next day was caused by thelease pumper’s carelessness, but no oneknows that except the guilty party. Whatshould the lease pumper put in the report?There may be a temptation to list theproblem as a control failure. But doing somay mean that a well servicing unit isdispatched when no problem exists

In another example, the lease pumper mayaccidentally leave a casing valve closed afterinjecting fluid down the casing during a

treatment of a pumping well. In this case,production from the well will decline and,after about three days, will fall almost tozero. The problem can be easily correctedby slowly bleeding off the casing pressure,but the lease pumper may be tempted to hidethe mistake.

Such actions are obviously dishonest, butin many cases they are easy for the leasepumper to get away with for on most daysno one but the lease pumper visits the site.Yet if an employer cannot trust the leasepumper to be honest about mistakes thatanyone can make, how can that employer beassured that the lease pumper is not cheatingon oil production, abusing purchasingauthority, using the vehicle for personalerrands, or even going to the leases asrequired. The hiring of a lease pumper is atremendous act of faith on the part of thelease owner. Just as some people may nothave the initiative to be their own boss,some do not have the degree of honesty tofulfill their half of this relationship of trust.

A-4. Special Precautions

The use of drugs or alcohol. Clearly leaseoperators will not tolerate the use of illegaldrugs and the consumption of alcohol on thejob and while traveling to and from thelease. The lease owner may require periodicunannounced drug tests and is entitled takeappropriate actions if problems occur.However, the lease pumper should also beaware that some over-the-counter andprescription medications can impair aworker’s ability to operate a vehicle or toperform work around moving equipment.When taking medicine, the lease pumpershould check the label or consult a physicianor pharmacist about possible side-effectsthat may prevent the safe performance ofrequired tasks.

1A-5

Hazards from heat sources. Oil and gasare important because the energy theycontain can be released through burning. Forthis reason, an oil or gas lease naturallypresents risks of fire and explosions. Add tothis the dangers presented by fuels, storedmaterials, soiled rags, and other potentialfire hazards, and it becomes clear why somany lease operators restrict the use andpresence of heat sources on the lease site.For example, smoking may be allowed onlyin the vehicle and only with the use of thevehicle cigarette lighter. Carrying matchesor a lighter may be forbidden (Figure 1).These regulations and policies may seemrestrictive but are aimed toward saving lifeand preventing suffering.

Carrying firearms to work. Leasepumpers should refer to their company’spolicy on carrying firearms to work

Figure 1. On some leases, the use of openflames may be forbidden.

These are just a few of the policies andpractices that a company or lease operatormay put into effect with regard to leaseoperations. The lease pumper shoulddiscuss policies with the lease operator todetermine what practices are acceptable andwhich are not allowed.

1A-6

1B-1

The Lease Pumper’s Handbook

Chapter 1Responsibilities and Employee-Employer Relations

Section B

FIELD OPERATIONS

In addition to understanding the duties andresponsibilities described in the previoussection, the lease pumper must be properlyoutfitted to do the work that is required. Thismeans wearing clothing and other gear thatwill allow the job to be done efficiently andsafely and having and maintaining the toolsrequired to do all assigned tasks.

The cost of lease tools is just one of theexpenses required in the operation of a lease.Supplies such as chemicals and utilities suchas electricity also contribute to these costs.Often the lease pumper can take actions toreduce operating costs and improve theprofitability of the lease.

Another influence on field operations andoperating costs is the requirements imposedby regulatory agencies.

This section provides an overview of whatit takes for the lease pumper to be properlyoutfitted and equipped as well as otherfactors that influence field operations andoperating costs.

B-1. Dressed for Work and Weather.

Most of the work performed by a leasepumper is done outdoors and must be doneno matter what the weather is. This meansthat a lease pumper must dress appropriatelyfor the work to be done and the weatherconditions. This means that the cloths mustallow the lease pumper enough freedom ofmovement to do the required tasks whileproviding protection against moving or hot

equipment, chemical splatter, fallingmaterials, and other risks. The clothingmust also provide protection against theenvironment, including cold and wetweather or intense sun and heat. The leasepumper must also be aware that weather canchange quickly, so that in the course of a daythe lease pumper may need protectionagainst cold in the morning and protectionagainst the sun in the afternoon or the daymay start out warm and dry but end cold andwet. Clothing can be added or removed,according to changes in the weather. A poorselection of clothing can adversely affect jobperformance.

Normal lease pumper attire may include:

· Full-length pants.· Long-sleeved shirt or coveralls.· Steel-toed shoes.· Eyeglasses and protective shields.· Gloves. Rubber gloves for some tasks

and cloth gloves for others.· Hard hat.

Full-length pants and long shirt sleeves.Many of the chemicals and crude oilsinvolved in the job can be a health hazard ifnot handled properly. Some chemicals arecapable of penetrating the skin and enteringthe body just by coming into physicalcontact. This is especially true when the oilor chemical is extremely hot. Full-lengthclothing is the first line of defense againstchemicals, oil, sun damage, and insect bites.

1B-2

Steel-toed shoes. Sturdy shoes with steeltoe protectors shield the feet from fallingobjects. Many serious foot injuries can beavoided by wearing protective shoes.

Eyeglasses and protective shields. Manyof the jobs that a lease pumper performspresent risks to the eyes. These risks includechemicals that may splash into the eyes,flying objects from moving parts orhammering, intense light from welding orcutting equipment, and other dangers.Because of the number of different types ofrisks, several styles and types of eyeprotection are required (Figure 1). Forexample, shatter-resistant glasses mayprotect against a flying object approachingthe eye directly but offer little protectionagainst chemical splashes from the side orthe bright light and spatter from a gas cuttingtorch.

Figure 1. Some lease activities require theuse of eye protection.

Gloves. While there are many types ofgloves available, they are not equally suitedfor all jobs performed by the lease pumper.Cotton gloves are satisfactory for clearingbrush or handling some equipment, butleather gloves may wear better whenworking with pipe and wire rope. Leather

gloves as well as rubber gloves offer someprotection against electrical shock. Rubbergloves or gloves of other special materialsmay also afford protection against harmfulchemicals, such as some of the chemicalsused to test oil prior to sale. The leasepumper should have the different types ofgloves required for the tasks to be performedand replacement gloves when those becomeworn or unusable due to contamination.

Hard hat. A hat offers some protectionagainst the elements and may reduce thechance of injury from falling objects andoverhanging obstacles. However, sometasks performed by the lease pumper presentgreater risks of head injury and require thelevel of protection offered by a hard hat.Many companies require lease pumpers towear hard hats whenever they are on thelease and outside the vehicle. In fact,everyone who enters the lease may berequired to wear a hard hat.

Lease pumpers should follow theircompany’s policies with regard to wearinghard hats. Hard hats vary in style and fit andfeatures, such as brim width. If more thanone style of hat is suitable for the work to beperformed, a lease pumper should choose ahard hat that is personally comfortable sothat there will be no reluctance to wear itwhen required.

B-2. Miscellaneous Gear.

There are some items that most leasepumpers consider to be indispensable forday-to-day operations. These may include:

· Rags or wipes.· Pen, pencils, and paper.· Pocket knife.· Measuring tape.· Pocket calculator.

1B-3

Rags or wipes. The lease pumper needs agood supply of wipes to clean tools,equipment, hands, vehicles, and mosteverything else that visits the lease. Somefield workers use paper wipes, while othersprefer cloth rags. The latter may be shopclothes that have been rented or purchasedfrom an equipment or uniform supplier.Another source of rags is used clothing froman outlet that sells clothing by the pound orbundle. This material can then be cut to auseful size. Many lease pumpers takeadvantage of bargain sources of rags becausethe rags quickly become soiled and wornand because there are so many items to keepclean, including the vehicle, tools, toolboxes, gauging and shakeout equipment, theareas around thief hatches, and other placesregularly involved in the work. Keeping thesite and equipment clean will enhance safetyby reducing the chances of slipping on an oilspot, will improve efficiency by making iteasier to get around the site, and will reducethe time spent on other maintenance, such aslubrication and corrosion protection.

Pens, pencils, and paper. The leasepumper must maintain the lease record book,record the hours worked by special crews,make notes about equipment and supplyneeds and work to be done, updateequipment readings, and perform a host ofother tasks that require a written record. It isimportant to keep pens, pencils, and paperavailable, even if the company has electronicequipment to record gauges and fieldreadings.

Other items. The lease pumper may alsowant to carry a pocket knife, measuring tape,vernier scale, paint marking stick, calculator,and spare site and vehicle keys. Many ofthese items may prove handy for daily tasks,while others may be most useful in an

emergency, such as when the keys have beenlocked in the vehicle or dropped in a snowdrift in the dark.

B-3. Typical Lease Hand Tools.

The tools that are required on the leasewill depend on how much of the fieldwork isdone by company personnel. As noted in theprevious section, there is a trend in theindustry to contract with a field servicecompany for much of the service andmaintenance. This approach greatly reducesthe number and types of tools that the leasepumper must carry, sometimes to the extentthat the lease pumper is required to furnishthe hand tools.. In some cases, leasepumpers drive their own vehicles and arethen reimbursed for the miles driven. Thismileage pay must cover the cost of the fuel,maintenance, insurance, and replacement ofthe vehicle.

The following lists include the basic toolsnecessary to perform the duties that aregenerally expected of a lease pumper.However, the exact requirements will varyfrom company to company. Lease pumpersshould ascertain before accepting a job thetools that are required to do the work, thosewith which they will be provided, and anythat they may be expected to provide. Thelease pumper should also determine thecompany policy on replacing tools that arelost, broken, or worn.

This means that an important task of thelease pumper is to learn to take care of thosetools. It can be frustrating to need aparticular wrench to open a valve only torealize that that wrench was left lying on thepickup fender two wells earlier and is nowforever lost somewhere six feet off the roadin tall grass. Some lease pumpers who arecareless with their tools are quick to makerequests for lost tools to replacement

1B-4

supervisors when their regular supervisor ison vacation, neglecting to mention that thesetools have already been replaced twice thisyear. This is why some companies assigntools, and, when the lease pumper leaves thejob, each tool must be accounted for or thereplacement cost is deducted from the finalpaycheck. If the lease pumper is not heldresponsible for issued tools, the lease ownermay not be able to afford to keep a leasepumper who is careless with tools.

Vehicle tool and equipment storage. Thelease pumper’s vehicle generally providesthree main areas of storage: the glovecompartment, elsewhere in the passengercompartment, and in the rear of the vehicleor bed of the pickup. Rear storage areasgenerally contain toolboxes or otherequipment containers to protect the tools andkeep them organized. For safety andsecurity, toolboxes should be lockable andthe vehicle should be equipped with a rollbar. Common contents of these areasinclude:

Glove compartment.Calculator. Test gauge.Pens, paper, pencils. Measuring tape.Daily gauge book. Pocket knife.Lease record book. Safety goggles.Flashlight and batteries.

Cab storage.First-aid kit.H2S backpack (if required)Small fire extinguisher.Hard hat.

Rear compartment.Water can. Motor oil.Oil squirt can. Gasoline can.Engine water. Antifreeze.Miscellaneous parts as needed.

The lease pumper’s toolbox and storageshed. It would be impossible andimpractical for the lease pumper to try tocarry every tool and all the supplies thatcould possibly be needed for the situationsthat can arise on an oil or gas lease. Thereare a few tools that are generally essential tobeing able to pump a lease efficiently, buteven so the tools that the lease pumpercarries will depend to a great degree on thenumber of wells on the lease(s), the type ofequipment on the lease that must beserviced, the amount of work support that isavailable, and the depth of maintenance thatmust be performed. Most of the commonlyused tools will be carried in the vehicle.Other tools may be stored on the lease in thelease pumper’s office—sometimes called adoghouse—or in a storage building. If a toolcan conveniently be stored at the lease, thisis desirable since tools can become rathershop worn and ragged within a short timewhen carried around in the vehicle overrough roads.

A minimum set of tools may include:

Digging, moving, and hauling.Shovel. Rake.Hoe. Moving bar.Tying rope. Small chain.Pick. Chain boomer.Weed cutter. Post hole digger.

Mechanic-style tools.Screwdriver assortment. Wire cutters.Allen hex wrenches. Pliers.Fencing pliers. Socket set(s).Needle nose pliers. Punches.Open-/box-end wrenches. Chisels.Adj. smooth jaw wrenches. Hammers.Adj. pipe wrenches. Hack saw.Assorted files. Snips.Locking pliers. Wire brushes.36-inch pipe wrench. Putty knife.

1B-5

Miscellaneous items.Safety wire. Feeler gauges.Tubing tools. Packing hook.Vernier style caliper. Ease-outs.Steel wool or sandpaper. Cleaning fluid.Small bolt assortment. Paint brush.Grease fitting asst. Small bolts.Nuts. Washers.Cotter pins. Shim stock.

B-4. Oil Gauging and Test Equipment.

Gauging, test, and other special equipmentshould be transported in suitable cases.Typically, this equipment may include:

· Gauge line with required tape.· Oil thief.· Centrifuge, hand or electric.· Centrifuge tubes, 12.5 or 100 ml.· Hydrometer, appropriate range.· Thermometer (preferably with scoop).· Kolor Kut paste.· Wipe rags.· Tank seals.· Squirt can with cleaning fluid.

Figure 2. A typical set of gauging and oilanalysis tools.

(Courtesy W.L. Walker Company)

B-5. Lease Operating Expenses.

The preceding paragraphs should givesome indication of the tremendousinvestment required to stock a lease with the

required tools and equipment. Tools andsupplies are just one of the expenses thatcontribute to the cost of operating an oil orgas lease. The salaries and benefits of thelease pumper and other employees is also anexpense that must be paid for from themoney made selling petroleum productsfrom the well. Some lease operatingexpenses are set—that is, little that the leasepumper does will affect the amount of theexpense. Some of the typical set expensesinclude:

· Drilling and workover costs.· Management costs.· Salaries.· Vehicle purchase cost.· Daily supply costs.· Lease purchase costs.

Obviously the lease pumper does havesome influence over some of these costs. Forexample, if a lease pumper abuses sickleave, the company will have to pay more insalaries to provide relief. If the leasepumper drives the vehicle recklessly anddoes not care for it, it will have to bereplaced more often. Further, there are othercosts that are directly affected by how wellthe lease pumper performs the requiredtasks. Some of the operating cost that thelease pumper can most directly influenceare:

Supply expenses. Supply expenses can beoften reduced through the careful use ofsupplies. This does not mean to avoidbuying required supplies, such as notlubricating equipment to save the cost ofgrease. This is false economy as the damageto the equipment far exceeds the cost of thegrease. Suggestions in saving supply costsinclude:

1B-6

· Stuffing box packing. Stuffing boxpacking on a shallow well (less than2,000 feet deep) with stripper productionshould easily last a year or even twoeven if the engine runs 24 hours a day.The lease pumper should learn not onlyhow to adjust the packing correctly, butalso how to recognize the problemscausing high packing consumption andthen to solve the problem. Stuffingboxes (Figure 3) often leak because thelease pumper over-tightens them just tobe sure that they do not leak.

Figure 3. A stuffing box.

· Lease electricity. In most areas, electriccompanies have at least two charge ratesfor the electricity that they provide. Ahigher cost is usually charged forelectricity used during peak loadperiods—that is, when electricityconsumption is at its highest, such asfrom 8 a.m. to 5 p.m. If a well must runfour hours per day to meet production

requirements, the lease pumper shouldset the well to operate during non-peakperiods so that the cost of electricity isless. Another consideration is that pumpengines draw a heavy electrical loadwhen they first start to get the idle partsmoving. If a well must pump 10 hoursper day, it will take less electricity to runit for 10 hours straight rather than to startthe engine five times to run two hourseach (though other factors may also haveto be considered).

Figure 4. Chemical injection system.

· Chemical expense. One of the methodsof treating oil is the use of chemicals(Figure 4). Oil treating chemicals can bevery expensive. Sometimes a leasepumper may add extra chemicals,thinking that if a little is good, then moreis better. Another lease pumper maysimply be careless at measuring or mayspill chemical. A typical cost for

1B-7

treatment chemicals is $30 per gallon. Ifa lease pumper has five wells and wastesone gallon of chemical per month at eachwell, the company pays $150 per month,or $1,800 annually, for wastedchemicals.

B-6. Government Regulating Agencies.

There are several agencies that the leasepumper may have to deal with in the field.The purpose of these agencies is to ensurethat lease operations are safe, efficient, donot excessively harm the environment, andare consistent with other concerns of thenation and its people. Some of the moreimportant agencies are:

The Bureau of Land Management (BLM).The federal government owns much of themineral rights in the United States. TheBureau of Land Management overseesactivities on these public lands to protect thecitizens’ property. BLM inspectors monitoroil and gas lease operations and issueguidelines, such as requiring that the handleon the sales line be sealed in such a mannerthat the valve cannot be opened unless theseal has been broken. Publications areavailable that contain guidelines for drilling,production, and pipeline operations.

Occupational Safety and HealthAdministration (OSHA). Work on thelease site is generally subject to therequirements of the Occupational Safety andHealth Act. Under the guidelines of the act,

employees must be advised of the dangersthey face. This information is usuallyprovided through training or throughwarning indicators or signs. OSHAregulations may also define protective gearrequirements, such as hard hats and safetyface shields, and prescribe how the gear is tobe used. For example, when performingduties, such as gauging tanks that containhydrogen sulfide gas, the lease pumper isrequired to wear a mask that provides asource of breathable air and that prevents theworker from breathing the toxic hydrogensulfide. Additionally, the worker must wearthe mask in such a way that a good seal isobtained, which may mean that beards andfacial hair may be forbidden or required tobe trimmed in such a way that the maskprovides the required seal. Employers aresubject to severe fines and penalties if theiremployees are not in compliance withOSHA regulations, and employees can bepunished or fired for failing to comply withgovernment or company safety policies.

Environmental protection and standards.Many laws have been passed to protect theenvironment. These laws help to protect theair, soil, surface water, and groundwaterfrom contamination. Special guidelineshave been issued for various industries,including petroleum production. Specialconcerns for lease pumpers are oil spills,venting high volumes of gases, or the loss ofsalt water or oil. Even pipe that is pulled outof a well may be contaminated by radiationand have to be stored in a special manner.

1B-8

2-i

The Lease Pumper’s Handbook

CHAPTER 2.

TRANSPORTATION, COMMUNICATIONS, AND LEASE MAINTENANCE

A. Getting to the Lease1. Vehicle Expense and Maintenance.

· Taking care of the lease vehicle.· Driving to and from the lease.· Lease roads.

2. Company Policies for Vehicle Use.· Personal use of the vehicle.· Unauthorized personnel in the vehicle.

3. Locating the Lease.· Location identification signs.· The federal system of rectangular surveys.· Locating the next lease.· Survey markers.

B. Routine and Emergency Communications1. What Is an Emergency?2. Emergency Telephone Numbers.3. Company and Personnel Communications.4. Field Support Services Telephone Numbers.5. Lease Locations.

C. General Lease Maintenance1. Landowner and Lease Operator Rights.2. Off-Road Travel.3. Livestock Injuries.4. Plants and Animals.5. Lease Maintenance.

· Road maintenance.· Cattle guards and gates.· Fences.· Vista of the lease.· Weed control.· Trash removal· Open pits and vents.· Lease offices.· Soil contamination.

2-ii

2A-1

The Lease Pumper’s Handbook

Chapter 2Transportation, Communications, and Lease Maintenance

Section A

GETTING TO THE LEASE

Because many leases are located in remoteareas, lease pumpers frequently have to drivelong distances to visit all of the wells undertheir care. Thus, two major concerns of thelease pumper are having a dependable modeof transportation to travel to the lease sitesand the ability to find and identify the exactlocation of the wells to be serviced. Thissection discusses the means of getting to thelease.

Figure 1. A lease pumper and the leasevehicle.

(courtesy Marathon Oil Co. Safety Dept.,Iraan, Texas)

A-1. Vehicle Expense and Maintenance.

As discussed in the previous chapter, leaseoperating expenses, including vehicle andequipment maintenance, are of constantimportance to the lease operator. The leaseoperator is not only concerned with the cost

of the vehicle but also with the expenses ofmaintaining the vehicle. The lease pumpercan help keep these expenses reasonablethrough the proper use and maintenance ofthe vehicle.

Taking care of the lease vehicle. Thesupervisor is well aware of how well thelease pumper takes care of the lease vehicle.Most oil companies maintain monthly andannual records that give costs per mile andtotal expenses. When a company has severallease pumpers, these records can reflect howthe lease pumpers take care of their vehiclesand can indicate their driving habits.

Some lease vehicles have a high cost permile because of long driving distances, oftenover poor rocky roads with roadmaintenance. But even the operating costsand maintenance needs of these vehicles canbe reduced through good driving habits.High speeds with excessive braking lowerfuel economy, wear out the running systemor gear train more quickly, and will result inan undependable vehicle. The lease pumpermust always observe good driving practicesand drive with care. Driving with a heavyfoot on the accelerator can seldom bejustified.

Driving to and from the lease. If a lease isseveral miles away from the lease pumper’shome, it is easy to fall into the habit ofdriving too fast. When going to work, thelease pumper is usually thinking about the

2A-2

problems of the day, planning how toachieve the daily work objectives, andthinking about the many things that can gowrong. Distracted in this way, the leasepumper continues to accelerate.

On the way home, the lease pumper isthinking about all of the things to do athome, the little league game tonight,mowing the lawn, getting ready for a fishingtrip or vacation, and dozens of otherthoughts. There is so much to do thatexceeding the speed limit seems justified—after all, it’s just for today. But before long,the lease pumper develops the habit ofspeeding every day and loses good drivingjudgment. Now the lease pumper is abusingthe vehicle not occasionally but every day.

Lease roads. Lease roads are expensive tokeep up. There are so many other needs thatare required to maintain or enhanceproduction, and money seldom becomesavailable for road maintenance. Many leaseowners are willing to pay higher vehicleexpenses rather than spend money on roads.

Figure 2. A typical lease road.

The lease pumper must use common sensedriving the lease roads. It is important tokeep speeds low enough to keep frombruising the tires on rocks. Tire replacementbills will reflect the lease pumper’s drivinghabits. If there is a large rock on the leaseroad, the lease pumper should stop andmove it to the side rather than create a newroad from driving around it.

A-2. Company Policies for Vehicle Use.

Personal use of the vehicle. Many leaseoperators allow their lease pumpers to takethe lease vehicle home. That makes it easyto develop bad habits. The lease pumpermay occasionally stop at a convenience storebecause, after all, it is right on the way. Thelease pumper may need to buy some stamps,and the post office is only a few blocksaway, so the trip gets a little longer.

Soon, the lease pumper has developed thehabit of making minor detours away fromthe direct route to work as a part of the dailyroutine, so that it becomes a perk, or fringebenefit, to the job. After all, the leasepumper works all business hours fromMonday through Friday for the company,and this is the only time many of thesebusinesses are open.

While these side-trips may be acceptablewith some companies, lease pumpers shouldclearly understand the policies of their owncompanies and use good judgment.

Unauthorized personnel in the vehicle.The lease pumper who picks up hitchhikersor takes someone along on the job can createproblems for all involved, including theemployer and passenger. It is difficult whena close friend or relative is visiting from faraway, and the lease pumper must drive off towork leaving them behind. After all, thelease pumper is driving a vehicle designed

2A-3

for two or more people and is working aloneand may not even see another companyemployee for the rest of the week.

The first problem is with insurance. Whathappens if the lease pumper has an accidentand the passenger is seriously injured orkilled? Who will pay the immediatemedical expenses and even long-rangemedical recovery and rehabilitationexpenses? These costs can quickly exceed ahundred thousand dollars and expensivetreatments could continue for years. Whowill pay the bills? What if the passenger hasno insurance? There is a good possibilitythat the company’s insurance will not coverthe expenses either. It could fall to the leasepumper’s insurance, and that insurer mayalso refuse to pay because the injuryoccurred while violating company policies.

This situation could lead to lawsuits,which can result in multimillion-dollarsettlements. Even if the lease pumper shouldwin the lawsuit and not be held responsible,lawyer’s fees and court costs can proveexpensive.

While larger companies are likely to havepolicies against permitting riders in leasevehicles, many smaller lease operators willnot have written policies against the practiceand may not verbally object to permittingpassengers to ride with the lease pumper forthe day. But the lease pumper must alwaysbe aware of the position in which thecompany or lease owner is placed. As agood employee, the lease pumper should atleast discuss the matter with the employer.They may also determine the stance of thecompany’s insurance carrier. If the leaseowner has no objections, the lease pumpermay consider purchasing a permanent ortemporary rider policy that can be attachedto a personal insurance policy in order toprotect the employer, the passenger, and thelease pumper.

A-3. Locating the Lease.

During the last few years, an effort has beenmade to name roads in rural areas thatprovide access to a residence. This assists inmail and package delivery and can helpworkers find a lease.

Location identification signs. Whether ornot a road is named, many lease operatorswill erect a lease identification sign to aid indirecting service trucks to their productionlocations. Some of the information that eachsign might include is:

· The lease operator.· The lease name. The lease is often

named after the owner of the mineralrights.

· The lease location based on theGeological Survey system.

The federal system of rectangularsurveys. Most globes show the horizontallines or latitudes and vertical lines orlongitudes that are used to mark the surfaceof the earth. In the United States, the entirecountry, except for the original colonies andthe state of Texas, is designated with arectangular survey system. All land in thissystem is divided into squares that areapproximately one mile on each side. Theseone square-mile blocks are called sections.Each group of 36 sections with six sectionson a side is called a township. The sectionswithin a township are numbered beginningin the northeast corner of the township andgoing west. The numbering then goes southto the next row of sections and continueseast. In this way, the first, third, and fifthrows as numbered from the top or northedge of the township are numbered east towest and the even-numbered rows (2, 4, and6) are numbered west to east. Thus, section

2A-4

1 within a township is in the northeastcorner and section 36 is in the southeastcorner (Figure 3).

Figure 3. Numbering of the sections in atownship.

Townships are also numbered within asurvey area. The numbering of townships isbased on latitudes and longitudes. Anotherterm for longitude line is meridian and onelongitude for a particular survey area iscalled a principal meridian. More thantwenty principal meridians have beendesignated in the U.S.

Principal meridians are crossed by latitudelines. One latitude line within a survey areais designated the baseline.

An example may clarify this system.Oklahoma has two survey areas: thepanhandle is under one survey area and theremainder of the state is under a secondsurvey area. The principal meridian for themajor portion of Oklahoma is called theIndian Meridian and lies close along alongitude of 97°14’ West. The baseline forthis portion of the state lies close to latitude34°30’ North and crosses the principalmeridian in south central Oklahoma (Figure4).

The intersection of the principal meridianand the baseline divides the survey area intoquadrants. A column of townships locatednorth and south of each other is referred toas a range. A row of townships running eastand west of each other is referred to as atownship. Ranges are numbered beginningat the principal meridian. Thus, all of thetownships along the west side of theprincipal meridian are referred to as Range 1West or R1W. The next column oftownships to the west are designated Range2 West or R2W and so on until the westernedge of the survey area is reached.Similarly, the first column of townships onthe east side of the principal meridian arereferred to as Range 1 East or R1E. Thisnumbering continues consecutively to theeastern edge of the survey area.

Figure4. Principal meridian and baselinelocations in Oklahoma.

The rows of townships are numbered in asimilar manner. Thus, the baseline of thesurvey area forms the southern boundary ofTownship 1 North or T1N and the northernboundary of Township 1 South or T1S. Thenumbering of the rows of townshipscontinues north and south to the ends of thesurvey area.

6 5 4 3 2 1

7 8 9 10 11 12

18 17 16 15 14 13

19 20 21 22 23 24

30 29 28 27 26 25

31 32 33 34 35 36

2A-5

This system allows the identification of apiece of land within one square mile. Forexample, if a lease is located on Section 31of township T7N, R14E, the lease pumperknows that the land is in the seventh row oftownships north of the baseline and thefourteenth column of townships east of theprincipal meridian. Further, the lease is onthe section of land located in the southwestcorner of that township.

This system of identifying land is used tocreate a legal description of most rural land(though some land, especially within townsand cities, may be identified with a systemof plats). The legal description locates asection of land by means of its township andnumbered section location and thenidentifies portions of the section. Forexample, a section of land contains about640 acres. If a piece of property consists ofthe 160 acres—that is, one-fourth of thesection—in the northwest part of the sectionwithin the township described in theprevious paragraph, the legal description ofthat piece of property may be given as T7N,R14E, Sect. 31, NW¼. Often thedescription is written beginning with thesmallest division, thus: NW¼, Sect. 31,T7N, R14E.

Naturally, this system would beimpractical if a person had to actually start atthe intersection of the principal meridian andthe baseline to locate a particular parcel ofland. Many land maps identify the townshipsusing this system. Additionally, most leaseshave signs that identify the well locationswithin the section. These are generallygiven as a distance in feet as measured fromtwo boundaries of the section. For example,assume that the well is located 660 feet fromthe north boundary line of the section and1,980 feet from the west boundary line, thenthe location can be indicated as 660' FNL(from north line) and 1,980' FWL. If a line

is drawn east to west across the property at660 feet from the north boundary line, thewell should be located along that line at adistance of 1,980 feet from the westboundary line. For this well location, thelease site may display as sign containing thefollowing:

John Doe Oil CompanyFederal C Jones No. Y7660' FNL-1,980' FWL,Sec 31-T7N- R14E- OK

Reading the sign from the end, shows thatthe well is located in Oklahoma (OK). Statesare generally designated by their two-letterpostal abbreviations. The state abbreviationmay or may not appear on the sign.

Within this survey area, the well is locatedon section 31 of the township that is 7 northand 14 east of the intersection of theprincipal meridian and the baseline. Thisspecific well is situated 660 feet from thenorth line of the section and 1,980 feet fromthe west line of the section.

Other information given on the signincludes:

John Doe Oil Company. This is thepresent owner of the oil well. If theowner changes, the sign is changed,and a closing bond must be placed ineffect for the life of the well.

Federal C Jones. The federal governmentowns the mineral rights, and the Cindicates that this is the operator’sthird federal lease. Elsewhere therewill be land representing leaseFederal A and at some other block ofleased land is Federal B lease. Theseleases may or may not be active, butwill not be redesignated once theletter is assigned. If an oil company

2A-6

leases more than 26 (the number ofletters in the alphabet) blocks offederal land, the designations wouldstart at the beginning of the alphabetwith an A added to each identifier, sothat the 27th well would be AA, the28th would be AB, and so on. Thisprocess would be repeated throughthe alphabet, and started over withBA, BB, BC, etc. if required.

Jones. A lease name may be designated bythe operator. Often this will be thename of the surface rights owner.

No. Y7. The well itself will often bedesignated by a letter and a number.The number generally represents thesequence of the wells drilled on thelease. In the example, the sign refersto the seventh well drilled on thislease. The letter is a code for thestatus of the well. For example, Yindicates that problems wereencountered while drilling the welland the initial well was plugged, therig repositioned, and the well re-drilled from the surface. A dry holemarker should be located nearby.

Locating the next lease. In addition toproviding a legal description of a piece ofland, knowing the section location can alsohelp a lease pumper find another lease. Forexample, assume that a lease pumper is atthe lease gate in the northeast corner of thelease described above and now needs totravel to the southeast corner of Section 28,T8N, R13E. Each section is approximatelyone mile or 5,280 feet along each side. Thelease to be visited next is one township tothe west and one to the north. The northeastcorner of section 31 is one mile east of theR13E column of townships. It is then five

miles north to the row T8N townships.Traveling another mile north will take thelease pumper to the south edge of the row ofsections in T8N, R13E that includes Section28. The lease pumper would then have totravel three sections or miles west to reachthe southeast corner of Section 28. The totaldistance traveled would be 1 + 5 + 1 + 3 =10 miles.

Of course the exact distance may vary forseveral reasons. First, there may not beroads that allow the lease pumper to followthat exact route. It may be necessary totravel an extra distance and double back toreach the desired destination. Thecircumference of the earth (the distancearound the earth at a latitude) getsprogressively smaller as the distance fromthe equator increases. The earth also hascontinuous elevation changes to furthercomplicate distance measurements. Thedriving distance from one side of a townshipto the other can be considerably more thansix miles if there are a lot of hills and valleysto cross.

In those areas of the country where theFederal System of Rectangular Surveys isnot used, the lease pumper must be familiarwith latitude and longitude designations thatuse compass directions and a system of 360degrees in a circle, 60 minutes in a degree,and 60 seconds in a minute.

Survey markers. Before drilling wells on alease, to locate the exact spot to drill thewell, an accurate land survey must be madeby a professional survey crew. This surveywill begin at some recorded and recognizedaccurate marker as close to the leased landas possible. The survey crew will thendetermine the location of the lease relative tothe witness point. Because land surveys canbe expensive and their costs increase inproportion to the distance from the starting

2A-7

point, lease operators will often ask thesurvey crew to place a survey marker on thelease or as near to it as possible. Thismarker (Figure5) will generally be installedin cement or other permanent structures.Often a sign will be posted nearby to

indicate the presence of a survey marker(Figure 6). The survey marker may becentrally located within a lease area so thatas more wells are drilled, future surveys canbe made from the marker point that the firstsurvey crew has established.

2A-8

2B-1

The Lease Pumper’s Handbook

Chapter 2Transportation, Communications, and Lease Maintenance

Section B

ROUTINE AND EMERGENCY COMMUNICATIONS

One of the interesting aspects of work as alease pumper is that the job is seldom thesame from day to day. Depending on thelevel of production, the status of theequipment, the requirements of themaintenance schedule, and numerous otherfactors, different tasks will be required todaythan were required yesterday. Tasks that arerepeated from the previous day may be donein a different way, performed to a differentdegree, or accomplished on other equipmentor at a different site. The lease pumper isalso likely to encounter unexpectedsituations, such as a leaking pipe, an enginethat has locked up, livestock in the overflowpit, or other surprise. Often performingroutine tasks or dealing with emergencieswill require that the lease pumper contactsomeone by telephone or radio.

Generally, phone books are not availableon the lease site and it is unlikely that thelease pumper will be able to memorize thenumber of every resource who may have tobe contacted, as well as one or two backupsif the first choice on the list cannot bereached. So the lease pumper must haveimmediately at hand the informationnecessary to deal with these situations.Further, if the lease operator or supervisorcannot be reached for directions in dealingwith a situation, the lease pumper must havesome idea of what to do and what he or shedoes not have authority to do. This sectionprovides tools and suggestions that will help

prepare the lease pumper to deal withemergencies.

B-1. What Is an Emergency?

Basically, an emergency is any situationthat is causing an undesired result or has thepotential to cause and undesired effectunless immediate corrective action is taken.When an emergency presents itself on thehighway driving to or from the leases or invarious situations that might arise on thelease, the lease pumper must be prepared. Itis too late to ask the boss what to do in anemergency when time does not permitcontacting anyone or when the requiredperson cannot be reached. The lease pumperneeds to know what to do in advance.

As an illustration, if a large hole hasopened on the side of a stock tank and oil ispouring out onto the ground forming a smallpond, the lease pumper should immediatelybegin circulating the oil out of the leakingvessel even before switching the tank. Thenthe lease pumper should call the office torequest a vacuum truck to pick up whateveroil can be salvaged. Time is money andholding the loss to a minimum requiresquick action. By planning ahead with thesupervisor for this type of situation, the leasepumper will know what to do when thesituation arises. By having contactinformation, such as the name of a vacuumtruck operator, the lease pumper will have a

2B-2

course of action if no one at the office can becontacted.

The list of possible lease emergencies isextensive. If electrical power to the leasehas been disrupted, most of the time no onewill know about the problem until the leasepumper arrives. The electrical servicecompany may not know there is a problemuntil they are notified. Other emergenciesmay involve life-threatening situations andrequire contacting medical personnel. Thelease pumper should have all relevantnumbers available in advance of theemergency.

If the lease pumper does not have a two-way radio or mobile telephone, then thenearest phone will have to be used. It maybe a farm or ranch house, a nearby town,another worker who has mobilecommunications, etc. This is one reasonthat the lease pumper should becomefamiliar with the area around each lease andget to know people who live nearby. To beadequately prepared, the lease pumpershould plan two or more response optionsand carry the information required to carryout all planned options.

The remainder of this section providestools and guidelines that a lease pumper mayfind useful in planning routine andemergency communications.

B-2. Emergency Telephone Numbers.

Page 2B-5 provides a form that lists someof the persons and agencies that the leasepumper may have to contact while on thejob. The form also provides spaces forlisting contact information. The leasepumper should complete a form similar tothe one shown and keep it in the vehicle. Ifthe lease pumper is working at sites spreadover a large area, it may necessary to have aseparate form for each of the different

leases. For example, it is not unusual for alease pumper to work leases that are indifferent law enforcement jurisdictions ordifferent fire districts. Some rural areas andsmall towns do not have 911 emergencyservice, so the lease pumper must also knowwhether 911 can be used at a site or if aspecific telephone number must be dialed.

B-3. Company and PersonnelCommunications.

Another list that is convenient to have iscontact information for company personneland for others who may work on the lease,such as relief personnel. Even if the leasepumper knows this information, the listshould be comprehensive because when thelease pumper is off duty, ill, on vacation, orgone on a family emergency, the informationmay be needed by relief personnel who maynot be as familiar with the company,employees, or staffing structure.

A suggested form for this information isshown on pages 2B-7 and 2B-8. However,the specific information required will varyfrom one operation to another, so the formmay include information that is not neededfor one lease pumper, while omittinginformation that is vital to those working adifferent lease. Each lease pumper shouldlist information that may be of value on thejob or to a relief person.

B-4. Field Support Services TelephoneNumbers.

As noted earlier in the example concerninga leak in a stock tank, maintenance of leaseoften requires completing tasks for whichthe lease pumper is not qualified orequipped. Times also arise when the leasepumper may have to buy supplies, such asengine fan belts or hardware to replace nuts

2B-3

and bolts that have worked loose andbecome lost. These situations representother instances in which the lease pumperwill benefit from having information abouthow to contact the suppliers. Sometimes itis also important to know the physicaladdresses of suppliers so that the requireditems can be picked up.

A sample form for listing suppliers andsupport service resources is shown on pages2B-9 and 2B-10. While the form includes alist of typical types of service providers, theexact needs of a particular lease or companymay differ, so the lease pumper shouldmodify the form so that all requiredresources can be listed.

B-5. Lease Locations.

Because lease sites may be located inremote areas and be hard to find, it is a good

idea for the lease pumper to carryinformation about how to reach a site.Obviously, this would be helpful for reliefpersonnel or service providers who may notbe familiar with how to reach the site. Butthe information can also be helpful to theregular lease pumper in describing alternateroutes for reaching the site in the event thatthe normal route is closed due to roadconstruction, weather conditions, bridgesbeing out, etc. In describing how to reachthe lease, the lease pumper should includetown names, highway numbers, milemarkers, distances, and descriptions of cattleguards, road divisions, highway signs, andother noticeable landmarks that will help toidentify the route.

An example of a form that may be used todescribe lease site locations is provided onpage 2B-11.

2B-4

2B-5

COMMUNICATION INFORMATION

Nearest Telephones:

1. Name_______________________ Location ______________________________________

2. Name_______________________ Location ______________________________________

Emergency Numbers

The National General Emergency Number 911 or ___________________________

State Highway Patrol. City_______________________ ____________________________

City Police. City________________________ ____________________________

Fire Department. City_________________________ ____________________________

County ______________________ ____________________________

Ambulance and Paramedics

Hospital, City ___________________________ __________________________________

Hospital, City ___________________________ __________________________________

Federal Game and Fish Department __________________________________

State Game and Fish Department __________________________________

Forest Department __________________________________

Environmental Department --------------------------------------------------

Other ------------------------------------------ Other-------------------------------------------

2B-6

2B-7

COMPANY AND PERSONNEL COMMUNICATIONS

Regular Lease Pumper

Name ___________________________ Address ____________________________________City ____________________________ State ___________________Zip_________________Home telephone __________________ Mobile _________________Fax _________________In case of emergency notify _________________________ Relationship _________________If unable to reach this person, call ____________________ Relationship _________________Vacation Schedule ____________________________________________________________Special Information ___________________________________________________________

Relief Pumper Information

Relief Pumper 1

Name ___________________________ Address ____________________________________City ____________________________ State ____________________ Zip _______________Home telephone __________________ Mobile ___________________ Fax _______________In case of emergency notify _________________________ Relationship __________________If unable to reach this person, call ____________________ Relationship __________________Vacation Schedule _____________________________________________________________Special Information ____________________________________________________________

Relief Pumper 2

Name ___________________________ Address ____________________________________City ____________________________ State ____________________ Zip _______________Home telephone __________________ Mobile ___________________Fax _______________In case of emergency notify _________________________ Relationship _________________If unable to reach this person, call _____________________ Relationship _________________Vacation Schedule _____________________________________________________________Special Information ____________________________________________________________

Lease Operator Information

Company name (Lease owner/Company) ___________________________________________Business mailing address ________________________________________________________City _______________________________ State _____________________ Zip ____________Telephone _________________________________ Fax _______________________________Owner/Manager ___________________________ Telephone ___________________________My supervisor ______________________________ Title ______________________________Office telephone ____________________________ Mobile ____________________________Home telephone _______________________________________________________________

2B-8

COMPANY AND PERSONNEL COMMUNICATIONS(Continued)

Contract Pumper Information

Company name ________________________________________________________________Business mailing address _________________________________________________________Owner/Manager _____________________________ Telephone _________________________My supervisor _______________________________ Title _____________________________Office telephone ___________________ Mobile _________________ Fax _________________Home telephone ____________________________ Fax ________________________________

Other information

2B-9

FIELD SERVICES SUPPORT SERVICES TELEPHONE NUMBERS

Pipeline or oil transport company Name _________________________________________Telephone _____________________________________

Weekend or Emergency ____________________________________

Water transport company Name _________________________________________Telephone _____________________________________

Weekend or Emergency ____________________________________

Rural electrical company Name _________________________________________Telephone _____________________________________

Weekend or Emergency ____________________________________

Electrical services and repairs Name _________________________________________Telephone _____________________________________

Weekend or Emergency ____________________________________

Electrical motor rewinding Name _________________________________________Telephone _____________________________________

Weekend or Emergency ____________________________________

Hot oiling services Name _________________________________________Telephone _____________________________________

Weekend or Emergency ____________________________________

Chemical supplier Name _________________________________________Telephone _____________________________________

Weekend or Emergency ____________________________________

Oilfield supplies (Store 1) Name _________________________________________Telephone _____________________________________

Weekend or Emergency ____________________________________

Oilfield supplies (Store 2) Name _________________________________________Telephone _____________________________________

Weekend or Emergency ____________________________________

Maintenance and construction Name _________________________________________Telephone _____________________________________

Weekend or Emergency ____________________________________

2B-10

FIELD SERVICES SUPPORT SERVICES TELEPHONE NUMBERS(Continued)

Well servicing and workover Name __________________________________________Telephone ______________________________________

Weekend or Emergency _____________________________________

Downhole pump repairs (1) Name __________________________________________Telephone ______________________________________

Weekend or Emergency _____________________________________Address __________________________________________________

Downhole pump repairs (2) Name __________________________________________Telephone ______________________________________

Weekend or Emergency _____________________________________Address __________________________________________________

Engine and mechanical (1) Name __________________________________________Telephone ______________________________________

Weekend or Emergency _____________________________________Address __________________________________________________

Engine and mechanical (2) Name __________________________________________Telephone ______________________________________

Weekend or Emergency _____________________________________Address __________________________________________________

OTHERS_______________________ Name __________________________________________

Telephone ______________________________________Weekend or Emergency _____________________________________Address__________________________________________________

_______________________ Name __________________________________________Telephone ______________________________________

Weekend or Emergency _____________________________________Address __________________________________________________

Comments ____________________________________________________________________

_____________________________________________________________________________

2B-11

HOW TO REACH EACH LEASE

Lease 1. Name___________________________________ Location ______________________

_____________________________________________________________________________

_____________________________________________________________________________

_____________________________________________________________________________

Lease 2. Name___________________________________ Location ______________________

_____________________________________________________________________________

_____________________________________________________________________________

_____________________________________________________________________________

Lease 3. Name___________________________________ Location ______________________

_____________________________________________________________________________

_____________________________________________________________________________

_____________________________________________________________________________

2B-12

2C-1

The Lease Pumper’s Handbook

Chapter 2Transportation, Communications, and Lease Maintenance

Section C

GENERAL LEASE MAINTENANCE

Previous sections have discussed therelationship between the lease pumper andthe lease owner, as well as the influence ofregulatory agencies. Another importantplayer in lease operations is the owner of theland on which the wells are situated. Thissection focuses on maintaining a goodrelationship with the landowner and the roleof good lease maintenance in thatrelationship.

C-1. Landowner and Lease OperatorRights.

Under United States laws, surface rightsand mineral rights are recognized asseparate property and can both be owned bythe same individual, owned by differentindividuals, or owned jointly by manyindividuals or companies. During the earlyyears of our country’s history, mineral rightswere generally sold with the land. Asminerals of value were discovered, thegovernment began retaining mineral rightsand withdrawing them from future sales.Now it is quite common for the surfacerights to have one owner while the mineralrights belong to other individuals, stategovernments, the federal government,foundations, Indian nations, counties, cities,banks, land grant universities, or some otherowner. They may even be owned by anentity in another country.

The surface rights may also be owned bythe state, the federal government, an Indian

nation, others, or a combination of these.The owner of the surface rights or thelandowner has the right to use the surfaceof the land. The landowner also has theright to fence the land, control the use of thesurface, and control access to the property.In some cases, the persons residing on theland may not own it but may be leasetenants. The surface rights of somegovernment-owned land are leased underlong-term agreements. Often families havelived on land under this type of leaseagreement for several generations and havemuch of their wealth invested in landimprovements. When the mineral rights areleased, the landowner or lessee will receivepayment for any damages caused byexploration for minerals.

The mineral rights owner or lessee has theright to search for minerals under most ofthe land. Before the first well is drilled, theowner or lessee of the mineral rights mustreach an agreement with the surface rightsowner, generally involving payment of asum of money to compensate for the use of apart of the land. This includes not only theareas on which wells and equipment arelocated but also land for access roads. Thisagreement is usually in force for as long asthe wells are being produced. As additionalwells are drilled, additional fees will be paidfor damage to the land and for the loss ofincome from land involved. When thehydrocarbons have been depleted and thelast well has been plugged and abandoned,

2C-2

the lease to enter the property and the rightto use the existing roads and locationsusually expires. The land reverts back to theland surface owner, and the lease operatormust withdraw from using these facilities incompliance with the original and subsequentland use agreements.

A landowner who does not own any of themineral rights and who will not receive anyfurther compensation for the loss of the landmay not feel too friendly toward the leaseoperator. The landowner may prefer tomaintain privacy and may feel invaded. Forthis reason, the lease pumper, as the leaseoperator’s representative, must try tomaintain good relations with the landowner.

C-2. Off-Road Travel.

Mineral lease agreements specify the typeand location of road construction, the widthsof the roads, and locations of wells, tankbatteries, and pits. If a mud hole develops ina low area of the access road, the leasepumper may be tempted to drive around it.As this bypass grows muddy, the pumperand other lease visitors drive even farther offthe road to avoid the water and mud, makingthe roadway even wider. Instead of trying tosolve the problem by bringing in a load ofsmall rock and fill to repair the road damage,the lease pumper has exceeded the width ofthe leased road width by many feet and isdriving on private property. Other damagethat can occur as a result of such right-of-way violations include dead grass, soilerosion, and collisions with equipment orlivestock. Often the first indication that thesurface rights owner does not approve of thelease pumper’s practices is a bill to the leaseoperator for damages.

The landowner may go directly to the leaseoperator or hire a lawyer to seekcompensation for damages. Some

landowners take direct action by changingthe lock on the gate or forbidding the leasepumper entry to the property. In some cases,the damage may have been caused by a thirdparty, such as a well service crew, but thelandowner will still generally consider theproblem to be the lease operator’s fault.

Regardless of the property damage, real orimaginary, caused or not caused by thepumper, serious problems can begin whenthe lease pumper or anyone working for theoil operator drives off the leased roads orlocations. The lease pumper is arepresentative of the lease operator, and thelandowner will hold the lease operatoraccountable for damages. The pumpershould always try to get along with thelandowner, take pride in maintaining thevista of the land adjacent to the leased roads,and not drive off the agreed-to routes. Whenit is necessary to get off the roadway toexamine nearby installations, the leasepumper should use common sense and walkif damage or problems may result fromdriving, or if the landowner might object.Any trash or other objects that have blownoff lease-related vehicles should be pickedup the first time that it is noticed and notallowed to accumulate. Trash barrels shouldbe available at convenient locations andemptied on a regular schedule.

When possible, the landowner should becultivated as a friend. Some landowners andlease pumpers become such close friendsthat the operator is allowed a lot of latitude.Then if a situation arises that the landownerconsiders to be a problem, the chances aregreater that the landowner will simply talk tothe lease pumper rather than getting angry.

C-3. Livestock Injuries.

Many leases are located in ranching andfarming country where livestock roams

2C-3

freely across the leases and access roads. Asthe lease pumpers drive around performingtheir daily duties, livestock is encounteredregularly. Livestock may develop the habitof seeking shade close to lease equipment ifthe area is not fenced (Figure 1). The leaseoperator must install adequate fencing tokeep these animals from accidentallydamaging delicate and automatic equipment.Calves, goats, or sheep may lie down in theshade cast by the counterweights of apumping unit next to the counterweightguards. While lying down, the animals areonly a few inches high and low enough towork themselves under some fences. Then,when they stand up, they are inside the fencenext to the counterweights. If the pumpingunit starts automatically, the young animalmay panic and injure itself on the fence orequipment. This is a problem for theanimal, the lease pumper, and the rancherthat could have been avoided with properfencing.

Figure 1. Cattle like to stand in the shadeof oil field equipment.

Guards are added to equipment to protectagainst injury to people, not animals. A1200-pound bull may decide to scratch hisitching hide against a small valve stickingout on a header. Doing so, the bull can turnvalves on or off, break delicate lines andvalves, disconnect electrical grounding lines,

turn a pumping unit on or off, change avariable choke setting, and create a host ofother odd and unexpected surprises. Thelease pumper may need to add close meshedwire around some units to protect animalsand to protect the equipment (Figure 2).

Figure 2. Fences may have to be installedaround equipment to keep livestock out.

The lease pumper must recognize thelandowner’s right to run livestock on theproperty and willingly accept responsibilityfor protecting them from being injured bythe actions of oilfield equipment or fluidsthat they may eat, lick, or drink.

Care must be taken when driving throughlivestock herds. When a herd of cattle whoare used to being fed supplement feed arefirst placed on the lease, they may pursue thelease pumper diligently for a few daysexpecting food. At every stop that first day,the lease pumper will be surrounded bycattle that expect to be fed.

The responsibility of the lease operator forinjuring cattle will vary depending upon thetype of other vehicle traffic on the lease. Ifthe road is an unfenced public roadway, thelease operator cannot be held accountablefor animals injured by other drivers. If,however, the lease is on private land behindlocked gates with an absence of traffic, thekilling of a domestic animal by the lease

2C-4

pumper or a servicing company vehicle ismore obvious. Landowners usuallyrecognize that animals are sometimesinjured or die from other causes, but theoperator needs to acknowledge and paydamages when the accident occurs as aresult of the lease pumper’s activities orequipment movement. At the same time,when the lease pumper notices a sick orinjured animal, the owner will usuallyappreciate being notified. This will help topromote good relations with the landowner.

C-4. Plants and Animals.

The lease pumper will come into contactalmost daily with plants, birds, and animalsthat are on the lease. The plants may benative or planted by the landowner as a cashcrop or to improve the vista and appearanceof the land. Wild birds and animals areregulated and protected by the state fish andgame department and, in some cases, byfederal regulation. The landowner may alsoconsider wildlife to be part of the propertyand exercise some degree of care for them.

It is not possible to pump a lease withoutcoming into contact with wildlife. Birds aregoing to nest on the oilfield equipment, andwild animals will seek shelter under theequipment. The lease pumper and the leaseoperator do not have the absolute right to tryto control wild animals on the lease. Sometruckers have a policy that if a threatened orendangered species of wild bird is nesting onthe equipment, they will wait until the youngbirds have hatched and left the nest beforethe equipment will be hauled.

The lease pumper should talk to thelandowner when experiencing problems thatare caused by plants or domestic or wildanimals and, if necessary, to the fish andgame department before taking actions thatmay compound the problems.

C-5. Lease Maintenance.

General lease maintenance is the leastliked part of the job for many lease pumpers,who may feel that they were hired toproduce oil wells. But a lease can occupy alot of country. While some steam recoverywells in tar sand areas may be drilled withone-per-acre spacing and shallow wells may,with permits, be drilled on each 10 acres ofland, the more common spacing for shallowwells is one per 20 acres and for mediumdepth wells one per 40 acres. This meansthat 16 wells can be drilled on each squaremile, placing wells about 1,320 feet or aquarter of a mile apart and about 660 feetfrom the nearest property line for theirclosest spacing. Most fields do not exhibitthis density. Thus, most wells are going tobe more than a quarter of a mile apart. So alease pumper who takes care of several wellsis likely to be working a large area of land.

The lease pumper and the lease companywill generally have responsibility formaintaining several aspects of the large areacovered by the lease, including:

· Roads.· Cattle guards and gates.· Fences.· Vista of the lease.· Weed control.· Trash removal· Open pits and vents.· Lease offices and stored equipment.· Soil contamination caused by spills.

Road maintenance. Roads are expensive tobuild and maintain. As a result, unless thewells are high producers, little money isavailable for road repairs. Pot holesdevelop, rainy seasons may cause water andmud on the roadway, and rocks seem togrow larger daily and work to the surface.

2C-5

A good lease pumper will spend a smallamount of time periodically performingmiscellaneous road services, such as movinglarger rocks to the edge of the roadway. Anoccasional small load of gravel in mud holeswill usually help to keep them from growinglarger. Sections of road where these types ofproblems develop are generally short, soeffort is required to prevent small problemsfrom becoming big ones.

Cattle guards and gates. Once a producingwell has been established on a site, the needfor daily access by the lease pumper begins.To allow vehicles to pass through the fencesthat are likely to surround the lease, thecompany will probably install a fence or acattle guard and will be responsible formaintaining them. Sometimes a cattle guardis preferable so that the lease pumper willnot have to stop and get out of the vehicletwice just to open and close gates.

When the cattle guard or gate is installed,the first safety consideration is the distancefrom the highway to the cattle guard. Thisdistance must be great enough to permit awell servicing unit or the longest truck andtrailer transport to stop completely off thepublic road or highway before crossing thecattle guard or opening a gate. If the truckcannot get completely off the road before thedriver gets out to open a gate or security bar,an accident may be caused by the truckblocking the road.

Access roads are often built at the leaseoperator’s expense and maintained by thelease operator, unless a joint responsibilityagreement has been reached. Although thelandowner may find it convenient tooccasionally use the road, it may be the leaseoperator’s complete responsibility tomaintain the cattle guard or gate. Cattleguards must periodically be cleaned out andsometimes re-leveled if they become hazards

to drive across. If the well is closed andabandoned, the lease operator will usuallyremove the cattle guard and replace thesection of fence, or install a gate if the roadsare to remain.

Figure 3 illustrates a poor cattle guardinstallation. Note that the guard has becomefilled with dirt, allowing animals to walkacross it, and that the ends do not haveexpanded wire across them from the centerpost to the outside. Small animals andcalves can enter at the ends.

Figure 3. A poorly maintained cattleguard.

Fences. The perimeter fences on a lease areusually owned by the landowner and are oflittle or no concern to the lease operator. Asthe lease operator drills wells and producesoil, there will be many occasions wherefences need to be constructed. Themaintenance of these fences is usually theresponsibility of the lease pumper.

Some of these fences are to protect oilfieldworkers, plants, domestic animals, andwildlife. In populated or heavily traveledareas, these fences are to protect childrenand to keep people away from automatic

2C-6

equipment and other facilities. Gates intothe protective enclosures should bepadlocked.

The quality of the fence that is built willdepend greatly on what type of service it issupposed to provide, and if it is to remainfor only a few days or for a long term. Thetypes and sizes of animals to be excludedwill govern the fence design, including thetype of fencing material (such as squaremesh wire, chicken fencing, or barbed wire),the height of the fence or number of strandsof wire fencing, the spacing of the fencefrom the ground, and the type and placementof fence posts.

Some fences are only temporary and maybe in use for just a few weeks. The fence inFigure 5 fits this category. The posts are notset very deep, the wire is stretched loosely,and it was probably built by one person. Asthe three strands were attached (starting withthe lower strand and working upward), eachstrand wrapped around the post as the strandwas completed so that the remainder of thatcoil of wire was not cut but just hung overthe post.

Figure 5. Temporary fence.

When the wire is removed, each coil isreturned to its original loop, and the rollremains in one piece. Since this wire isreserved for temporary fences, the company

does not end up with a bundle of many shortsections of wire. This is an excellentprocedure to follow in temporary situations.If the fence must keep out sheep, goats, orcalves, more strands can be added to thelower section of the fence.

When wells, tank batteries, or otherfacilities must be installed in towns or alongwell-traveled highways, the fencing must bemuch more secure, and cyclone fencing isgenerally used. The height of the fence andthe trim or barbed wire requirements areadjusted according to need. In thephotograph in Figure 2C-6, the fence wouldbe too low for in-town installations wherechildren may be playing and no barbed wirewould be installed on the top.

Figure 6. A security fence has beeninstalled around this pumping unit

because the well is near a busy highway.

Vista of lease. The vista of the lease refersto the general appearance of the equipmentand everything on the lease including piperacks, idle equipment, junk, and scrapmaterials. As a regular habit, everythingshould be arranged neatly. Pipe racksshould be arranged in order. Every joint ofpipe should be aligned straight on the rackwith similar amounts of overhang on eachend and be collared and racked neatly.Available stripping materials to separate

2C-7

layers of pipe should be in neat stacksaligned with the racks. Stored equipmentshould be in aligned rows and chemicalbarrels organized in rows. Permanent linesshould be in 90-degree grid linearrangements when entering the tank batteryand should look neat.

Operating along organized patternsbecomes a way of life and should always befollowed in every instance possible.Materials are moved on a regular basis onthe lease, and every contractor performingspecialized services on the lease will followcompany procedures. If the lease pumperkeeps everything neat and aligned, otherworkers will keep materials neat andaligned. If the site becomes unorganizedand jumbled, that is the way other will placesupplies and equipment from the time theyunload it. Well organized stored equipmentis never an unexpected benefit. It is theresult of operating with well organizedpolicies and procedures.

Weeds. Weeds and vegetation should bekept clear of equipment and stored materials.Excessive vegetation is not only unsightly,but it can be a fire hazard, accumulate trash,increase rust and corrosion of metal, providea haven for snakes and other animals, andcover up holes and other hazards. The leasepumper should ensure that excessivevegetation is cleared or trimmed back.

Trash removal. Trash should notaccumulate on the lease. No leaseagreement with a landowner gives the leasepumper or anyone entering the lease toservice the wells the right to scatter trash,bottles, and cans along the right-of-way.With private lease roads, the lease operator’sresponsibility is to remove trashimmediately and keep the roadway clean.The best procedure is to stop and pick up

any trash instantly, every time that it is seen.In this way, trash never begins toaccumulate. The lease pumper should beable to drive all over the lease and never seea can, piece of plastic, or other trash lying onor beside the roads.

Open pits and vents. Open pits arecommonly used in the oil fields. Open pitsinvite local and migratory birds to land on orbeside the ponds and get a drink. Because ofdams and the lowering of water tables bypumps, water is no longer as widelyavailable across the bird migratory flyways.The number of deaths of animals and birdsdue to oil and non-potable water isstaggering.

Similarly, open vents present attractivenesting and roosting spots for birds, bats,squirrels, and other animals.

The petroleum industry and the leasepumper must comply with open pit and ventregulations. The petroleum industry is doingan outstanding job in meeting thesenecessary regulations and has done much toprotect wildlife.

Pits at the well must be fenced to protectagainst the possibility of people or animalsfalling into them. If the pit contains anyfluids, the lease pumper may also berequired to put protective netting over thetop.

Pits at the tank battery are consideredpermanent installations. The fences are putin with more care. The pit lining is of highquality; the cover netting is carefullyplanned.

The number of species that have beenthoughtlessly wiped out of existence sincethe industrial revolution is startling. Withinour children’s lifetime hundreds of majoranimals and birds will be lost forever.Careful maintenance practices can help stemthe tide of this tragedy.

2C-viii

Lease Offices. Lease offices are generallyreferred to as dog houses. Lease offices areusually small—such as 8 feet wide and 12feet long—one-room buildings that providea little room for desk work and storage. Forsome large leases, the building may be muchlarger or smaller and house several daytimepumpers, each with individual desks. Thesefacilities may have an attached materialsstorage room with a truck unloading door atthe back. The office may even stock a fewoften-used fittings.

A common practice is to run a gas linefrom the battery to heat the building. Naturalgas in pure form is colorless and odorless.Thus, a leak in the gas line can present adanger, as can carbon monoxide If the heateris not properly vented.

Thus, lease buildings must be maintainedfor good appearance and safety.

Soil contamination. The chemicals,petroleum production, salt water, and othersubstances that the lease pumper handles onthe site can cause damage to theenvironment. Spills of these materials maypresent hazards to people, livestock, andwildlife and, as runoff from rain, to fish.Such substances can kill grass and othervegetation and may keep anything from

growing in the spot for many years.If the lease pumper spills such materials or

finds a leak involving such materials, everyeffort must be made to clean it up.Sometimes this can be accomplished by thelease pumper by following product labelinstructions, which may indicate that soilshould be mixed with the spill, that watershould be used to dilute it, that a chemicalneutralizer should be applied, or that otheraction should be taken. In some instances, aspecial cleanup crew will have to be calledin.

Further, depending on the substance andthe amount involved as well as whatbecomes contaminated (such as soil versus awaterway), the spill may have to be reportedto a regulatory agency.

Obviously, there are many areas ofresponsibility in maintaining a lease. Ofextreme importance is building a goodrelationship with the landowner and otherswho may be affected by lease operations. Inthis way, the work of maintaining the leaseis more likely to be a shared responsibilityand any problems that develop may beworked out agreeably.

3-i

The Lease Pumper’s Handbook

CHAPTER 3

SAFETY

A. Personal Safety1. Good Judgment and Common Sense.

· Being prepared.2. Taking Unnecessary Chances.3. Making Safety a Part of the Job.4. Industry Standard Notices, Warning Signs, and Markers.

· DANGER.· WARNING.· CAUTION.· NOTICE.· SAFETY.· RADIATION.· The location of safety and fire safety equipment.· Barriers.· Typical lease signs.

5. Safety Equipment.· Breathing apparatus.· Goggles.· Hearing protection.· Eye wash stations.· Spark-proof tools.

B. Hydrogen Sulfide and Natural Gas Safety.1. Introduction to Hydrogen Sulfide Gas2. What Is Hydrogen Sulfide?3. Properties of Hydrogen Sulfide.4. The Dangers of Breathing H2S.5. Safe Working Procedures in Gaseous Areas.

· Safety training programs for working around hydrogen sulfide.· Where will the lease pumper encounter hydrogen sulfide?

6. Breathing Apparatus.· Individual fresh air packs.· The five-minute air pack.· The thirty-minute backpack.· Compressing fresh air.· The industrial sized bottle and hose.· Trailer-mounted equipment.· Taking care of air breathing equipment.

3-ii

3A-1

The Lease Pumper’s Handbook

Chapter 3Safety

Section A

PERSONAL SAFETY

Much of the work that the lease pumperdoes is done alone. While following propersafety practices is always important, safety iseven more important when a person isperforming potentially dangerous tasks andno one else is around to assist if an injuryoccurs or the person loses consciousness.For these reasons, it is especially importantfor the lease pumper to be careful and not totake any unnecessary chances. To assist thelease pumper, companies put into placesafety procedures, provide safety equipment,and post signs that warn of dangers on thejob site. This section discusses theseimportant elements of job safety.

A-1. Good Judgment and Common Sense.

Working alone is not the same as workingwith a group. The lease pumper workingalone needs to remember at all times thatany problems that occur must be smallenough that lease pumper can work out ofthem alone. The lease pumper never takesdangerous chances unless the event isalready in motion, and this action is a lastresort to avoid death or to preventexceptional injury. As an illustration, agood lease pumper would never walk undera load on a winch line rather than walkaround it. If the engine should stall or theline break, the lease pumper is risking injuryand possibly death to save a few minutes.The savings in time is not worth a fraction ofthe risk.

Being prepared. In being prepared to workalone, the lease pumper must be prepared formany contingencies. This means planningahead for problems that may occur andtaking steps to prevent those problems or tolessen the impact if they do occur. Forexample, a problem with the vehicle canleave the lease pumper stranded, and usuallyon the most remote part of the lease. Whatdoes the lease pumper do if the vehicle has aflat tire and the spare is also flat? What ifthis occurs on a warm summer night in anarea full of rattlesnakes? Is there a flashlightavailable? Have the flashlight batteries beenchecked lately? Should the spare tire beenchecked for air occasionally? This is thekind of planning that is required to avoiddangerous situations.

The lease pumper should make it a habit tocheck the spare regularly. Just a thump willusually do. If lease engines must be startedwith jumper cables off the vehicle battery,the lease pumper should have two batteriesmounted under the hood. It is easy toconnect them so that both charge, and onecan be used as the field battery. If thevehicle battery fails, the lease pumper canjump-start the pickup off the engine starterbattery. For a few dollars, the lease pumpercan buy a small compressor that will run offthe vehicle battery or a device that usesvehicle engine compression to pump up alow tire or flat spare. An extra set of keyswill be helpful if the lease pumperaccidentally locks the keys in the vehicle.

3A-2

Communications are important when thelease pumper needs help from someone elsebecause of an accident, a problem with thevehicle, an urgent problem with the leaseequipment, or other emergency. A radio orportable telephone can be invaluable in suchsituations. Knowing the location of thenearest public telephone or house with aphone can also be important if the radio hasbeen damaged or loses power because of abattery problem or if cell phones are out ofrange. Many companies, knowing theimportance of communicating with theirlease pumpers, provide phones or radios.

The lease pumper must think about whatto do in various types of emergenciesbecause such problems occur regularly.

A-2. Taking Unnecessary Chances.

Many of the problems that peopleencounter while working alone developbecause the worker took an unnecessarychance. For example, assume that a leakdevelops at a coupling and that a smallamount of gas is escaping. The leasepumper can install a collar leak clamp in lessthan 15 minutes. Surely nothing will happenin so short a time so it is not necessary toshut in wells or isolate and bleed thepressure off the line before the installation.Invariably, a complication arises. The leasepumper has trouble finding a suitable clampand the wrench to install it, so 15 minutesbecome 30. The wrench slips whileinstalling the clamp and the coupling breaks.The lease pumper drops the wrench, causinga spark that ignites the gas. Many incidentsare on record where oilfield workers havedied repairing small leaks. In cost cases, theleaks looked too small to be risky, sochances were taken and the field worker waskilled because of carelessness. No one wasaround to give first-aid. If the wind had

been blowing or if the leak had not occurredin a low area, perhaps the gas would nothave accumulated. Every accident is thesum of a series of unfortunate circumstancesand poor decisions.

This does not mean that the lease pumpermust fear death constantly in order to do thework. But the lease pumper must evaluateevery action in each specific situation andanticipate the potential outcomes. When itappears that the action is risky, the leasepumper should consider other actions orobtain the help necessary to reduce the risksinvolved to a safe level.

A-3. Making Safety a Part of the Job.

Many people feel that safety is like a coat.When the weather is cold they put it on, andwhen it is warm they take it off. When asituation comes up that may be dangerous,they become concerned about safety, andwhen the crisis is gone thoughts of safetydisappear. A safety attitude has everythingto do with work, but it also has everything todo with driving, fishing, or taking a walk.Safety is a way of life.

How the lease pumper drives to workreflects an attitude toward safety. Speedlimits are set as a safety reminder tomotorists concerning a speed that canexpected to be safe for an alert driver in avehicle in good condition with fair weather,dry roads, and normal traffic. When theseconditions are met, most drivers begin tofeel that a few miles per hour over the speedlimit would be just as safe. In truth, they areprobably right, as long as conditions remainideal. But when the lease pumper is cruisingalong at that speed, thinking about all of thetasks that are waiting at the lease, thesituation has changed: there is no longer analert driver. A light rain begins to fall, andnow the pavement is no longer dry, but the

3A-3

driver is no longer thinking about drivingconditions or about slowing down. Then,just as the lease pumper meets an oncomingcar—without warning—an emergencyoccurs: a tire blows, something falls off atruck, or a hundred other possibilities. Oneof the vehicles invades the opposite lane byseveral feet. It occurs in the blink of an eye,and the lease pumper is driving too fast forproper defensive action.

At this instant, it does not matter whocaused the accident or why it happened. Thewound is just as severe and the crash is justas fatal.

People have been severely injured whiledriving across the lease and hitting the endof the cattle guard, because they werereading a newspaper while driving, ortalking on a radio or telephone. In eachcase, something had become more importantto that person than safety. It takes a lot ofthought and effort to make safety a routinepart of a person’s life, but it takes littlethought or effort for a lack of safety to bepart of a person’s death.

A-4. Industry Standard Notices, WarningSigns, and Markers.

In the same way that highway signs—suchas stop signs, yield signs, and railroadcrossing signs—have shapes and colorsrelated to their meaning, signs used byindustry to warn of danger and provide otherinformation often use standard shapes andcolors and even messages. The appearanceand meaning of signs have been refined andstandardized over the years until the size,shape, and colors indicate something from adistance, even before they are within readingdistance. Generally these signs provideinformation about potential dangers orinformation about equipment and supplies,such as the location of fire extinguishers and

first-aid kits. Many of these signs are usedby the petroleum industry and can be foundon oil and gas leases.

Additionally, lease sites are generallymarked with a sign that is unique to theindustry. These signs describe welllocations in such a way that they can beprecisely located on the lease site.

Both types of signs provide informationthat is useful to the lease pumper and otherswho may visit a lease site. This sectionpresents information about the use of thesesigns and how to interpret them.

Industry standard signs are made from awide range of materials, including wood,aluminum, fiberglass, various plastics, andmetal. They may be painted and letteredwith enamel, acrylic, reflectivecompositions, or any of various othermethods. Examples of some of these signsare shown in Figure 1.

Figure 1. Some of the signs that may beseen on a lease site.

(Courtesy Marathon Safety Department,Iraan, Texas.)

There are some basic information signsthat are generally black lettering on a whitebackground, such as KEEP OUT. Other

3A-4

signs identify the location of general safetydevices, such as first-aid kits, or the locationof fire safety equipment, such as fireextinguishers. Many of the industrystandard signs consist of two halves: anupper header that describes the type ofinformation and the lower half whichcontains the information.

The header and the information sectiongenerally have set color combinations for thelettering and the background to providefurther clues about the purpose of the sign.The following paragraphs describe signs thatmay be found in the oil field or in otherrelated industries. The signs are identifiedby their headers.

· DANGER.White lettering on red background. Thebackground may be oval with black corners.The information area has a whitebackground with black lettering. Dangersigns are used to indicate a condition thatcould lead to death or serious injury.Typical information may include:

High Voltage.Flammable Materials.Equipment Starts Automatically.No Smoking.Hard Hat Area.High Pressure Gas Line.

· WARNING.Black lettering on an orange background forboth the header and information areas.Warning signs indicate a condition thatcould lead to permanent injury but generallynot to death. Typical examples include:

Ear Protection Required in this Area.Hard Hat Area.Eye Protection Required.Do Not Use Two-Way Radios.

· CAUTION.White lettering on yellow background on theheader. The information area contains blacklettering on a yellow background. Cautionsigns are installed where the danger is notlikely to lead to death or serious injury orwhere the risk is not always present. Typicalcaution signs include:

Step Down.Low Head Room.Use Hand Rails.Trucks Turning.

· SAFETY.White lettering on a green background.Lettering in the information area is black onwhite. Safety signs are generally remindersof good safety practices, such as:

Keep This Area Clean.Wash Your Hands.Safety Begins With You.

· NOTICE.White letters on a blue background. Theinformation area has a white backgroundwith black lettering. Notices generallyprovide advisory information, such as:

Keep Doors Closed.Authorized Personnel Only.Tornado Shelter.

· RADIATION.Purple lettering on yellow background. Theheading may say radiation, danger, orwarning, often based on the risk presented.Typical conditions described in theinformation area include:

Radiation Hazard.X-Ray Equipment in Use.Radioactive Waste.

3A-5

While safety signs have been standardizedto a large degree, the lease pumper is likelyto see many variations from what has beendescribed. For example, the use of colorsfor particular headers may vary. Dependingon the risk presented by a condition, theheader may be different for signs that havethe same information.

The location of safety and fire safetyequipment. The general safety notices aregenerally green lettering on a whitebackground or white lettering on a greenbackground. These signs are generallyposted near the location of first-aid kits,safety showers, eye washes, or other areasthat may be sought in the event of anaccident.

Fire safety notices are red lettering on awhite background. They are used to markthe locations of fire exits, fire extinguishers,fire blankets, fire hoses, and other items thatmay be useful in escaping or fighting a fire.

Barriers. Barriers are used to prevent entryinto an area or route personnel and vehiclesalong desired paths of travel. The mostcommon types of barriers used in the oilfieldare:

· Pylons or cones. There are generally redor orange.

· Barrels.· A-Frames with 4-inch diagonal

alternating white/red reflective stripes.· Barricade tape.

Typical lease signs. Some of the mostcommon industry standard signs that may befound at the well site or tank battery include:

· Hard Hat Required.· Authorized Personnel Only.· Do Not Enter.

· Equipment Starts Automatically.· High Voltage.· No Smoking.· H2S Poisonous Gas.· Air Pack Required.

Most of these signs are intended to reducesafety risks to personnel who are authorizedto be on the lease site. Additional signs mayalso be provided to warn workers of dangersthey may encounter when approaching thelease. Other signs that may be found on thelease are intended for persons who do nothave a valid reason for entering the site.Some examples of these signs include:

· Private Road.· Private Property.· No Trespassing.· Travel at Your Own Risk.· Speed Limit.· Keep Gate Closed.· Livestock on Road.· No Hunting or Fishing.

A-5. Safety Equipment.

Because there are dangers on the lease,companies generally provide safetyequipment for their employees and visitorsto the lease. Sometimes safety equipment isrequired by state or federal regulations. Thefollowing paragraphs discuss some of themore important pieces of safety equipmentlikely to be found on a lease.

Breathing apparatus. There are severalstyles of fresh air packs commonly availablefor field use, and these are reviewed inSection B. The lease pumper always carriesa personal air mask on the job. Some leasesstore air packs on the lease for otherpersonnel in a protective cabinet.

3A-6

Goggles. Wearing goggles (Figure 2) isrecommended when gauging atmosphericvessels that produce hydrogen sulfide orwhen using a vapor recovery unit where thetank has several ounces of pressure inside.Wearing goggles is mandatory in anysituation where there may be flying objects.

Hearing protection. Earmuffs (Figure 2)must be worn in situations where a loudnoise may be experienced. Such noises maydamage hearing or interfere with the senseof balance.

Figure 2. Examples of ear and eyeprotection.

(Courtesy MSA)

Eye wash stations. Eye wash stations(Figure 3) are available for installationwhere there is a high risk of eye injuriesfrom particles or chemicals. When gauginga tank, the lease pumper’s eyes are exposedto hot gases rushing up out of the tank, andsevere eye injuries can occur in seconds withthe worker hardly being aware of it. Thehot, poisonous gas open the pores in thesurface of the eyes and penetrate them. Assoon as the person looks away, the coolerambient air will close these pores, trappingthe gas in the eyes and causing a reactionthat is similar to burning the eyes fromexposure to the light of an arc welder. Thisextremely painful experience will last for atleast 24 hours until the gas escapes ordiffuses into the body. Eye wash solutionand lubricant are available at any drug storeand should be carried in the lease pumper’sfirst-aid kit.

Figure 3. An eye-wash station.

Spark-proof tools. Spark-proof tools(Figure 4) are used to reduce the chances ofcreating a spark that might create a fire orignite an explosive atmosphere.

Figure 4. Examples of spark-proof tools.(Courtesy Marathon Safety Department)

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Spark-proof tools are usually made ofbrass and are expensive. Most leasepumpers do not carry many spark-prooftools. A hammer and one small adjustablewrench are usually the limit of the ones thatmay be needed. Emergency rescue vehiclesoften carry a few to use in extricating peoplefrom wrecked vehicles and other possibleexplosive situations.

Many other types of safety equipment areavailable, and lease pumpers should

determine what types of equipment will helpmake the job safer for their specificsituation. For example, some lease pumperschoose to wear back protection belts if theyare expected to do a great deal of lifting.Lease pumpers should occasionally examinethe safety equipment that is available andassess which items would benefit their worksituations. Often the company will bewilling to provide those safety items that thelease pumper believes to be necessary.

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3B-1

The Lease Pumper’s Handbook

Chapter 3Safety

Section B

HYDROGEN SULFIDE AND NATURAL GAS SAFETY

B-1. Introduction to Hydrogen SulfideGas

Prior to the mid-1950's, very littlepublicity was given to the dangers ofpumping leases with high hydrogen sulfide(H2S) gas levels. Then improved drilling rigswere built that could drill to 20,000 feet anddeeper. With the deeper wells, higherbottom hole pressures were encountered,and more H2S was present. The natural gasin a few wells contained more than 75% H2Sand had a high sulfur content. A few wellsin Canada had H2S rates that exceeded 90%.Because hydrogen sulfide causes steel tobecome very brittle, these wells wereplugged.

Carbon dioxide reserves were tapped, andthe gas was injected into wells for enhancedrecovery. But this also causes steel tobecome very brittle, so producers turned towaterflood injection to push petroleumfluids. However, during this process andduring well workover, sulfate-reducingbacteria enter the well and begin generatingH2S. Thus, wells that had never producedH2S before exhibited hydrogen sulfideproblems. The number of deaths resultingfrom these gases increased dramatically overa 20-year period.

By 1975 regulations were being written toprotect the worker from this growing danger.H2S is common throughout the world whereoil has been discovered, so the problem isnot limited to the United States or Canada.

To be able to work wells with high H2Sconcentration, special additives, such as ironoxides, have been added to drilling muds toabsorb hydrogen sulfide. Iron Sponge is onesuch patented absorbers.

In earlier times, if a lease pumper diedfrom exposure to hydrogen sulfide, the leasepumper’s survivors were awarded a pensionof six months to two years of the deceased’ssalary. With growing concern for workersafety and revised laws, regulations, andcourt judgments that may award enormousamounts of money when negligence can beproven, companies now have betterequipment, hydrogen sulfide training,upgraded literature, and exposureconsiderations.

B-2. What Is Hydrogen Sulfide?

Hydrogen sulfide is a naturally occurringgas that is produced along with natural gasand crude oil. It can be fatal if breathed.Tanks that contain a deadly amount of thisgas are usually marked with a star or someother indication of the presence of hydrogensulfide. With this warning, the lease pumpermay be required to wear a fresh air gas maskwhen gauging or sampling the crude oil.

B-3. Properties of Hydrogen Sulfide.

It is important to understand the physicalproperties of hydrogen sulfide in order tounderstand why it acts the way it does.Physical properties of H2S are:

3B-2

· A colorless gas with a composition oftwo parts hydrogen and one part sulfur.

· Slightly heavier than air; it seeks lowerareas, especially pits and cellars.

· Odor of rotten eggs in small doses.Higher concentrations cause paralysis ofthe olfactory nerve within 60 seconds sothat no odor is detected.

· Extremely toxic (poisonous).· Explosive in air.· Soluble in water.· Boiling point -75° F.· Melting point -119° F.· Density of liquid 0.790 @ 60° F.· API gravity 47.6.· Burns with a blue flame.· Attacks most metals to form sulfides,

which are usually insoluble precipitates.· Dissolves in water to form a weak hydro-

sulfurous acid.

B-4. The Dangers of Breathing H2S.

The toxicity levels of H2S are generallygiven as the number of parts per million(ppm) in air. This means that for a 10 ppmconcentration of H2S, there would be tenliters of H2S in a million liters of air. How agiven concentration will affect a specificperson depends on a number of factors, suchas the person’s health and personalsusceptibility, how active they are whenexposed, air temperature and humidity, andmany other factors. The following valuesare intended as general guidelines only.

1 ppm = 0.0001% (1/10,000of 1%) Can be smelled.

10 ppm = 0.001% (1/1,000 of1%)8-hour exposure permitted.

100 ppm = 0.01% (1/100 of1%) Numbs smell in 3-15

minutes. May burn eyes andthroat.

200 ppm = 0.02% (2/100 of1%) Numbs smell rapidlyand burns eyes and throat.

500 ppm = 0.05% (5/100 of1%) Causes loss ofreasoning and balance.Results in respiratorydisturbances in 2-15 minutes.Requires prompt artificialresuscitation.

700 ppm = 0.07% (7/100 of1%) Causes loss ofconsciousness quickly.Breathing will stop and deathresults immediately if notrescued promptly.

1,000 ppm = 0.10% (1/10 of 1%)Unconsciousness occurs atonce. Permanent braindamage may result if notrescued promptly.

Monitors are available to measure aperson’s exposure to H2S (Figure 1).

Figure 1. Hydrogen sulfideexposure meters.

(courtesy Mine Safety Equipment Co.)

B-5. Safe Working Procedures inGaseous Areas.

When the lease pumper must enter gaseousareas alone, there are definite safeguards touse. The lease pumper should always

3B-3

observe extra safety margins because there isno backup. Safety equipment should be onbefore entering the area (Figure 2). Thelease pumper should wear the equipmentuntil the contaminated area is exited.

Figure 2. A warning gate that indicatesthe presence of H2S and the requirement

for breathing apparatus.

Safety training programs for workingaround hydrogen sulfide. Safety trainingprograms are available for working in H2Senvironments. It is important for leasepumpers to take this training. Formaltraining will usually result in betterunderstanding than just receiving a pamphletto read in some spare time. The leasepumper also gains experience practicingwith safety equipment, H2S detectors,monitors, exposure recorders, 30-minutebackpacks, the 5-minute emergency escapepack, and many situations rarely seen in thefield. In addition, trainees visit with otherswho have had different experiences.

When working in a group, someone withinthe group is required to have had training sothat this knowledge is available to the group.When working alone, however, the leasepumper must have had this formal training.

Figure 3. The windsock on the site showsthe direction of the wind and whether

H2S buildup is likely.

Where will the lease pumper encounterhydrogen sulfide? Some of the commonareas that H2S can be encountered:

· Pits or low areas on still days (Figure 3).· Drilling muds.· Gauging tanks.· Closed tanks and vessels.· Pump leaks.· Contaminated sulfur.· Injection of sour gas.· Tank bottoms.· Water injection.· Vapor recovery units.· Acidizing wells.

3B-4

As this list indicates, H2S can be almostanywhere on the lease. This does not meanthat lease pumpers must fear H2S while onthe job, but it does mean that they mustrespect and understand the conditions underwhich H2S may be found and never takechances.

B-6. Breathing Apparatus.

Fresh air systems can be quite simple toelaborate. The most common system is justa portable air pack. Others may involve anindustrial size fresh air bottle strapped intothe bed of a pickup with a long hose on areel either in the pickup or on a stand nearthe bottom step of the tank battery walkway.Because this system can save lives, the leasepumper should use it and take care of theequipment.

When trying to decide what type ofbreathing apparatus will be best and themost practical for the lease, the leasepumper must first understand the job dutiesand know where and under what conditionsH2S may occur.

Individual fresh air packs. When workingin the oil fields, there are times when it isessential to have fresh air available. Beforethe development of modern equipment,hand-driven fresh air systems were used.While such systems supplied breathable air,they had serious limitations. For each jobwithin a high-risk area or if a rescue orassistance was needed, at least oneadditional person was required to pumpfresh air.

Today, even the self-contained fresh airsystem continues to undergo improvement.For example, at one time fresh air containerswere heavy steel. The newer aluminum andfiberglass containers are only a fraction ofthe weight of the former ones. Today’s

control systems are also lighter and morecompact. With proper equipment, the leasepumper can perform many field duties wheregas is present safely without any back-up.

The four most popular fresh air units andsystems for use in oil fields are:

· The five-minute air pack (Figure 4).· The thirty-minute air pack (Figure 4).· The models utilizing large industrial size

bottles.· The trailer-mounted standby units.

Figure 4. Five-minute and 30-minute airpacks on a service bench.

(courtesy Marathon Safety Department,Iraan, Texas)

The five-minute air pack. The-five minuteair pack is widely recognized as a safetybackup system. Even in areas where airpacks are marginally needed, the five-minutepack can be worn for emergency escape.

When working in areas such as derrickswhen pulling oil wells, cleaning insidetanks, and other situations where air is beingcontinuously supplied by a long hose, thelease pumper should wear five-minute packas a backup. If the lease pumper must workin an area where more than just a fewseconds away, a backup systems shouldalways be carried.

The thirty-minute backpack. The thirty-minute fresh air unit is widely used by leasepumpers. Since it takes only a few minutesto gauge tanks, the backpack can last for a

3B-5

week or more before it must be refilled. Itcomes in a form-fitting box and should bestored there at all times when not in use. Theair pack as well as the inside of the boxshould be kept clean. The lease pumpershould carry one or two replacement partssuch as the head strap or spider. When onestrap breaks, it should be replaced before thebackpack is worn again.

Compressing fresh air. Air bottles can befilled in most towns for a fee at fire stations.In areas where much fresh air is consumed,such as towns with nearby oil fields,companies sell this refill service.

When a company consumes a largeamount of fresh air, the owners will installtheir own refilling equipment (Figure 5).The compressor utilizes ambient air to refillthe bottles. The compressor will firstcompress the air by injecting it into a seriesof industrial sized bottles. This group ofbottles acts as a volume tank, and, since theyare filled in advance, this reduces the timeneeded to refill bottles.

Figure 5. An air compressor used to fillair bottles.

(courtesy Marathon Safety Department,Iraan, Texas)

Because of the heat generated whenrefilling small bottles, such as the 30-minutebottles, the bottles are immersed in a watertank while being refilled.

The 30-minute bottle is stamped with adate. It must be periodically inspected and,after a set time has passed, it is against thelaw to refill it. The bottle must be replacedwith one that meets the inspection test. Aheavy fine is imposed, so when the bottle iscondemned it must not be refilled.

The industrial-sized bottle and hose. Theindustrial-sized bottle with air line and facemask is a valuable fresh air system whenlarge volumes of air are needed (Figure 6). Itcan be rigged up countless ways at the tankbattery, in the pickup, or on a trailer.

Figure 6. Industrial-sized bottlesawaiting to be refilled. The water tank to

the left is used to cool smaller bottleswhen they are being filled.

(courtesy Marathon Safety Department,Iraan, Texas)

3B-6

Since the bottle is too large and heavy towear, an air hose is used to pipe air from thebottle to the user. A fresh air mask isutilized by the person breathing the air(Figure 7). When pulling some wells, all ofthe well servicing crew will be breathing airfrom masks and hoses. Often it is just onstand-by and, if a horn goes off indicatinggas conditions, then the masks will be usedwhile rigging up to kill the well again.Cleaning tanks is another situation wherethese bottles are highly used.

Figure 7. Worker wearing an air maskfed by an industrial bottle. He is also

wearing a 5-minute escape pack.(courtesy Mine Safety Appliance Co.)

The industrial size bottle can be utilized twoways. It may be mounted in a pickup, and areel hose used from the pickup whilegauging. The bottle may be installed at theend of the walkway on the ground.

Trailer-mounted equipment. The airtrailer carries the selected equipment neededfor well servicing, cleaning tanks, newconstruction, and other field jobs (Figure 8).This will usually include industrial sizebottles, air lines and masks, 30-minutebackpacks, 5-minute packs, monitors,sensors, and any other equipment that mightbe needed for specific jobs. If an emergencyshould arise on the job, the trailer is thecenter of the staging area where instructionsare issued.

Figure 8. Trailer-mounted fresh airequipment.

(courtesy Marathon Safety Department,Iraan, Texas)

Taking care of air breathing equipment.Judging employees by how well they useand take care of equipment is easy to do.Just visually inspecting equipment andlooking at the bottle refill schedule tellsmost of the story.

As soon as the lease pumper receives theequipment, the first thing to do is to inspectit, then put it on, adjust the straps to fit, openthe valves, set the rate, and find out if itworks satisfactorily. Since most of theequipment is buckled on with quick connectfittings, all of the adjustments stay set fromone wearing to the next. If a supervisor

3B-7

checks the equipment and finds that it is stillwrapped as shipped or when checked last, itis obvious that the lease pumper is not usingit at all.

This is expensive equipment and will giveservice according to the way that it is caredfor. The lease pumper’s work is relatively

clean with little exposure to greasier jobs,such as well servicing. Every time the airbreathing equipment is used, the leasepumper must take a few moments to be surethat it is clean and properly stored forprotection. Anything less is not satisfactorypersonal work attitude and action.

3B-8

4-i

The Lease Pumper’s Handbook

CHAPTER 4

UNDERSTANDING THE OIL WELL

A. Looking Downhole1. Oil-bearing Reservoirs.2. Formation Shapes.

· Dome formations.· Anticline formations.· Fault trap formations.· Reef trap formations.· Lens formations.· Unconformities.

3. The Anatomy of an Oil Well.B. Drilling Operations

1. Contracting the Well to Be Drilled.· The tool pusher.· The driller.· The derrick worker.· The floor workers.· Motor man.· Company representative.

2. Drilling the Well.3. Downhole Measurements.4. The Surface String of Casing.5. Intermediate Strings of Casing.6. Drill Stem Tests and Drilling Breaks.7. Keeping the Hole Full Gauge and the Packed Hole Assembly.8. Drilling a Straight Hole.

C. Completing the Well1. The Final String of Casing.

· Cased-hole completion.· Open-hole completion.

2. Perforating and Completion.3. Tubing.4. The Tubing String.

· Mud anchor.· Perforations.· Seating nipple.· Tubing.· The packer.

4-ii

· The holddown.5. Correlating Perforations.6. A Typical Wellhead.

· The casing head.· The intermediate head with casing hanger.·· The tubing hanger.

4A-1

The Lease Pumper’s Handbook

Chapter 4Understanding the Oil Well

Section A

LOOKING DOWNHOLE

The part of the well operation that isunderground is generally referred to asdownhole. There are several reasons whythe lease pumper must understand what it islike downhole. This need for understandingbegins at a basic level in knowing theprocedure for drilling a well, responsibilitiesof the rig personnel, how decisions are madewhen drilling, and how the bore hole isfinished when casing strings are run andcemented into position. During theproduction phase, the lease pumper mustknow what is happening in the formation,the production interval or perforated area,the tubing string, the flow lines, and theprocessing vessels—from the bottom of thehole all the way to the stock tank.

The lease pumper must also have someknowledge of what causes oil and gasproduction to slow down or stop and whatoptions may be available to identify or evenremedy the problem. With experience, thelease pumper will recognize the symptomsfor a wide range of downhole problems asthey begin to affect production and will havesome knowledge of what can be done torestore production.

Many small operators do their own wellservicing, and the lease pumper may work aspart of the service crew. This could lead tothe lease pumper becoming the well servicecrew operator when pulling and running rodsand tubing.

Even if the company contracts all of thewell services to others, quite often the lease

pumper acts as a representative of the oilcompany and supervises the well serviceoperation to ensure that everything isperformed to the company’s satisfaction.Further, the lease pumper must understandwhat records must be kept, how toaccurately record any changes madedownhole, and how to submit changerecords to the office. This chapter presentsinformation on how a well is drilled andcompleted. This first section discusses thestructure of oil-bearing formations andprovides an overview of oil well design.

A-1. Oil-bearing Reservoirs.

The purpose of a well is to bring oil andgas up from underground deposits.Petroleum researchers generally agree thatoil and gas consist of the chemical remainsof ancient plants and animals. Theseremains were laid down as deposits on thebeds of ancient seas. As layers of sand andother sediments covered these chemicalremains, the pressures built up to compressthe minerals into rock. The hydrogen andcarbon portions of the plant and animalremains combined to form chemical chainsreferred to as hydrocarbons, or natural gasand crude oil.

Over time, more layers of rock will form.Some types of rock, such as sandstone, areporous—that is, there are openings betweenthe grains of the rock, and water, oil, and/orgas can sometimes occupy this space. These

4A-2

fluids may remain in the porous rock or, ifacted upon by other pressures, they maymove from one place in the formation toanother. Other types of rocks, like granite,are nonporous.

These layers of porous and nonporous rockare called strata (singular, stratum).Hydrocarbons remain trapped in the strata ofporous rock when the porous rock isenclosed with layers of nonporous rock orwhen certain types of rock formations keepthe oil contained in an area. This area maybe referred to as a reservoir and theformation as oil-bearing rock or sometimesas the pay section.

Oil is found in stratified rock that wasloose sand at one time before beingcompressed under pressure into sedimentaryrock. Igneous rock—that which was formedby heat as from a volcano–is nonporous andnever contains oil. Metamorphic formationsof sedimentary rock—such as limestone thathas metamorphosed to marble—will notusually contain oil. The most common oil-bearing formations consist of:

Stratified rock Abbreviation

Sandstone SLimestone LSDolomite DoloConglomerate ConglUnconsolidated sand US

A-2. Formation Shapes.

An analysis of rock samples and landformations can tell geologists whether agiven area is likely to have oil deposits.Through various types of tests that measurethe underground formations, petroleumexploration crews can determine thelocations of probable petroleum reservoirs.By using special instruments, oil exploration

crews can measure the speed of soundassociated with the density of undergroundformations to determine whether thoseformations are likely to contain oilreservoirs. Great strides have been made inunderstanding the many shapes of reservoirssince the discovery of overthrust belts in the1970's. The use of computers and softwareprograms continues to improve the ability ofgeophysicists and geologists in determiningwhether hydrocarbons are likely to be found.

After considering numerous factors, the oilcompany may make the decision that adeposit of petroleum is great enough tojustify drilling a well.

There are many formation shapes that canresult in underground reservoirs. Thecharacteristics of these formations aresometimes visible along roadcuts, canyons,and other areas where the layering of theearth can be observed. Some of the moreimportant oil-trapping formations include:

Dome formations. Dome formationsdevelop when underground pressures pushup against the layers above, causing a fold inthe strata to rise dramatically. Undergroundhydrocarbons may be trapped within thedome or trapped in the donut-shapedformations surrounding the dome. As thereservoir is produced, the oil may be driventoward the center of the dome or, in othersituations, it may migrate outward. Anotherterm used for dome reservoirs is plug traps.Often the dome formation consists of salt.

Anticline formations. An anticline is anupward fold of the formation. Instead ofcreating a dome shape, the upward foldspreads across a wide area, often many milesthough it may be quite narrow in manyareas. An anticline can develop finger-likeprojections that trap petroleum and that canbe very productive if discovered. Some

4A-3

anticlines disappear for many miles thencrop up unexpectedly, only to disappear thenreappear perhaps several times. The depthof the reservoir may vary from shallow todeep over the length of the anticline.

Fault trap formations. Fault traps areformed by the shearing or breaking of theearth at great depths. This break is called afault, and fault lines are frequently the sitesof earthquakes as the two split sections ofearth shift relative to each other. Faults maybe visible on the surface of the ground.

If the formations on each side of the faultmove so that the strata on one side of thebreak no longer line up with the same strataon the other side of the fault, it is possiblethat a porous layer will become aligned witha nonporous stratum on the other side of thefault. When this occurs, oil and gas can betrapped on the porous side. Oil may bediscovered only on one side of the fault oron both sides. Many dry holes have beendrilled following a productive fault line.

Reef trap formations. Reef trap formationswere usually developed by great limestoneand dolomite deposits. These depositsgenerally contain the minerals from deadmarine plants and animals. Often theseminerals are dissolved as water passesthrough the formation. This can createcavities in which hydrocarbons may becometrapped and held.

Lens formations. The term lens formationgenerally refers to any strata in which theoil-bearing rock is penetrated by bands ofnonporous rock. This causes the pay sectionto be broken into small reservoirs. For thisreason, lens formations can make it difficultto properly complete and produce a well.

One type of lens formation occurs when anunderlying nonporous stratum undergoes

extensive folding. The folds may penetratethe oil-bearing layer at intervals like arumpled blanket. Pockets of oil, water, orgas may become isolated in small sections ofthe porous layer between the folds of thelens formation. Depending on whether or notthe nonporous rock completely separates theoil-bearing layer, hydrocarbons may or maynot be able to flow between the pockets.This means that hydrocarbon productionmay vary slightly or even dramatically fromwell to well along the oil-bearing stratum.In some cases, each isolated section mayhave to be drilled separately. Sections willdeplete at different rates. It may be difficultto determine how to enhance.

Unconformities. Unconformities wereformed by the rock formations being thrustupward and worn off by actions of theelements. After this wearing away occurred,an impervious stratum was laid down toform a cap over the end of the porous layer.These formations trap and preserve oilreservoirs. Some of the most significant oilfields in the world reflect partialunconformities.

A-3. The Anatomy of an Oil Well.

Perhaps the best way to learn about theprocess of drilling an oil well is to firstconsider a completed oil well and thenreview how everything came together tocreate the finished well.

Figure 1 on the next page shows the wellas it is being drilled. With the derrick inplace, drill pipe is run into the hole with thebit cutting through the rock formations at theend of the drill pipe. Mud is pumped intothe top of the drill pipe and forced out thelower end. This serves several purposes.The mud cools the drill bit and forces thecuttings up the side of the hole and to the top

4A-4

where they are emptied into the mud pit.The mud also reduces the chances of thehole walls crumbling and helps to preventthe uncontrolled release of oil and gas.

As the well is drilled, casing is installed.The drill pipe is removed from the hole andheavy steel pipe is installed in the hole. Thispipe is filled with cement and topped with aplug. Mud is then pumped into the casingwhile the cement is still wet. The pressureof the mud forces the plug and cement downthe inside of the casing so that the cement isforced into the space between the casing andwalls of the bore hole from the bottom of thecasing. The cement will fill this space to thesurface of the well. Once the cementhardens, the drilling continues if necessary.The crew switches to a smaller drill bit thatwill fit inside the casing and drills throughthe plug at the bottom of the hole and intothe next formation.

When the well has been drilled into theoil-bearing rock, the drill pipe is removedand the last string of casing installed andcemented in place. A section of the casingthat passes through the reservoir will then beperforated—that is, holes will be created toallow oil and gas to pass into the casing.After the casing has been perforated, tubingis installed. The tubing is smaller diameterpipe that goes down inside the casing.Tubing is used to bring oil and gas to the

surface. Once the well goes into production,the derrick is removed and the tubing istopped with a set of control valves known asa Christmas tree or wellhead.

This overview should help clarify the moredetailed information in the followingsection.

Figure 1. A drilling rig in erected to borea well. Note the pipe in the rack

alongside the derrick.

4B-1

The Lease Pumper’s Handbook

Chapter 4Understanding the Oil Well

Section B

DRILLING OPERATIONS

No two wells are alike, even if they arelocated near each other and are drilled intothe same oil-bearing formation. Manyvariables may enter into the drilling process.People, equipment, procedures, and manyother factors affect the drilling operation andcan contribute to problems with thecompleted well. The outcomes of thedrilling procedure will forever influence theproduction of the well. This sectionprovides information to assist the leasepumper in understanding the nature of thedrilling operation.

B-1. Contracting the Well to Be Drilled.

When a contract to drill an oil well issigned, many conditions and agreements areincluded. The drilling rig contractor willhave agreed to drill a well to a specifieddepth. The conditions for payment areincluded. The contract payment may bebased on the time on the location, a set sumof money, or by the foot. Most wells arecontracted by the foot, but the contract islikely to make allowances for unforeseenproblems and nondrilling activities, such astime spent allowing the casing cement to set.

While the drilling rig is moving in toprepare for drilling, this is referred to asmove in and rig up (MIRU). Most drillingtoday is done with a jackknife rig that can bemoved to the well location and raised in justa few sections rather than the built-in-placederricks that were once used.

Personnel involved during drilling include:

The tool pusher. The drilling companyprovides a supervisor for the rig while thewell is being drilled. At one time, thisindividual was called a tool pusher. Today,more and more rig crews include petroleumengineers, the terms drilling engineer,production engineer, and similar titles havebecome popular. To avoid implying that theposition must be held by an engineer, thismanual uses the term tool pusher.

The tool pusher is generally in charge ofthe drilling rig and is in charge of everymoving part of the rig. The tool pusherpurchases rig supplies and supervises thedrilling procedures and rig personnel.Radios and cellular telephones have madecommunications so easy that the tool pushermay be in charge of two or more rigs at onetime and may not always be present on aspecific site.

Because of the critical nature of this typeof supervision for around-the-clock drillingoperations, the tool pusher is often providedwith a small mobile home on the well site toremain at the drilling operation for days at atime in the event of problems.

The driller. The driller is directly in chargeof the drilling four- or five-person rig crewand generally operates the draw works, thesystem of cables and pulleys used to runpipe into the hole and to pull pipe from thewell. Normally, the driller will have worked

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all of the positions on the rig crew over aperiod of years and is, thus, veryexperienced. When a large drilling rig isbeing moved, all four drilling crews aresupporting the rig move. The driller mayperform the tool pusher’s duties when thelatter is off.

The derrick worker. The derrick workerworks high above the floor when the pipe isbeing pulled or run during regularoperations. This position is commonlyreferred to as a derrick man.

On most modern rigs, sections of drill pipeare held vertically in a rack along side thederrick awaiting to be added to the drillingstring as the bit works its way deeper intothe ground. One of the duties of the derrickworker is to handle pipe that is added to orremoved from the drill string. Pipe is addedas the drill bit cuts deeper into the ground.Pipe is removed as the drill string is pulledfrom the ground once the drilling iscomplete or to replace the bit or to deal witha drilling problem. The pipe is raised andlowered with elevators. The pipe is storedbetween “fingers” in the rack next to aplatform referred to as a monkey board.

When the rig is drilling, the derrick workersupervises and assists the two floor workersin maintaining the cleanliness of the rig.The derrick worker generally supervises andassists in equipment repairs and oftencatches and labels the mud samples. Thederrick worker may also operate the drawworks to provide the driller with time to fillout reports and perform other duties. Thisalso gives the derrick worker experience indriller duties to prepare for a possiblepromotion.

The floor workers. There are two floorworkers on the rig floor while pulling andrunning pipe. These personnel are also

referred to as floor hands or roughnecks.The more experienced individual is usuallyreferred to as the lead and operates the leadtong. The second person on the flooroperates the back-up tong and may bereferred to as the back-up. The floorworkers are generally the least experiencedmembers of the crew.

Motor man. If the rig has a five-personcrew, the fifth individual may be called themotor worker or motor man. In thissituation, either the motor worker or thederrick worker may have the mostexperience and relieve the driller duringvacation. The motor worker may also beassigned the duty of catching drillingsamples.

Company representative. The seniormember of the crew, such as the tool pusher,or another person will serve as the officialrepresentative of the oil operator. With asmall oil company, this may actually be theowner of the company. The company ispaying the full cost of drilling the new welland owns it when it is completed. Thecompany representative oversees everyaspect of the operation from building theroad to being sure that the casing is availablewhen it is needed to the delivery andinstallation of the wellhead and Christmastree. In most cases, the companyrepresentative makes the final decisionsconcerning most of the formation tests.

B-2. Drilling the Well.

When the drilling rig is moved onto thelease to begin drilling a new well, the leasepumper, as an employee of the operatingcompany, may have responsibilities relatedto the operation. Most drilling rigs havesuitable steel mud pits, and the operating

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company may have constructed an earthmud pit with a plastic liner to receive theexcess fluids and the drilling cuttings.Although most rigs will have from two tofour steel pits, the very first pit will have ashale shaker mounted on top to allow thedrilling mud to fall through the screens. Theformation cuttings slide down the vibratinginclined screen and fall over the side anddirectly into the earth mud pit.

Figure 1. A tri-cone drilling bit.

The lease pumper is likely to beresponsible for looking out for thelandowner’s interests during the drillingoperation, especially if the drilling iscontracted. If the mud pit is not properlyfenced, the land owner’s cattle may try to getinto the pit to get a drink of water.Occasionally, lost circulation materials areadded, and the livestock are attracted tothem. The livestock may also try to eatgreasy rags, plastic, and other trash thatblows away from the rig.

When the hole is finished, it will takeseveral weeks or even months before themud will dry out enough for the cuttings inthe pit to be leveled out on the location. Assoon as the rig shuts down, the landownerwill expect the lease pumper to maintain aclean, well-fenced pit capable of protectinglivestock from harm. Sometimes fence willhave to be installed as soon as the drillingstarts.

B-3. Downhole Measurements.

The lease pumper is also likely to beresponsible for maintaining the well records.One of the most important set of records isthe downhole measurements. Thesemeasurements record the dimensions ofevery section of pipe used in the well.

Downhole diameters are important inorder to know the sizes of tools, pumps, etc.that will pass through the pipe, as well ascouplings and other components required tocomplete the installation. Casing is a nameapplied to any pipe that is cemented intoplace. The moveable strings of pipe insidethe fixed casing that can be easily pulled andrun back in when working the well over arecalled tubing. Casing and tubing are alwaysmeasured by outside diameter. If the samepipe is used on the surface, it is called linepipe and is measured by inside diameter.Casing, tubing, and line pipe do notnecessarily refer to the design of the pipe.The purpose of the pipe or where it is used iswhat determines its name.

Downhole lengths must be known in orderto accurately determine the depth of thewell, the location of the perforations, andother features vital to good production. Asthe well is drilled, distances are measuredfrom the top of the kelly bushing (KB),which is the sliding bushing that sits in thetop of the rotary table on the drilling rig

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floor. The KB allows the drill kelly to slidedown through it while the pipe is rotatingand the hole is being drilled. Theabbreviation KB will appear somewhere onthe drilling report records to indicate thatthis is the initial point from which alldownhole measurements are made.All measurements are made to one-hundredth of a foot. Instead of using inches,each foot is divided into ten parts, and eachtenth of a foot is divided into ten parts.Thus, 10’6” is equal to 10 and one-half feetor 10.50’. All rig tapes use this system ofmeasurement, making it easier to addlengths. For example, three lengths of pipeare 19’9¼”, 20’3/32”, and 20”4-5/16”,respectively, when measured with aconventional steel tape. Using hundredthsof a foot, the same measurements would be19.77, 20.09, and 20.36. These are numbersthat can be handled by a conventionalcalculator. As the well is completed,everything that goes downhole, such astubing, rods, and pumps, is measured in thehundredths of a foot.

After the casing pipe has been set(cemented permanently in the hole) and thebraiden head or wellhead has been installed,the distance from the top of the wellhead upto the top of the kelly bushing is measuredand then subtracted from all drilling recordsso that well records are accurate once thedrilling rig is gone.

B-4. The Surface String of Casing.

Much of the water that people drink comesfrom underground reservoirs of fresh water.Protecting the fresh water zones is one of themost important considerations when drillinga new well. The bottom of the string ofsurface casing must extend well below thefresh water zones. The surface hole is alsodrilled deep enough to pass through any

loose materials until stable rock has beenencountered before the surface pipe is set orcemented into place.

Before the surface casing is made up or“run in the hole,” it is carefully measuredand inspected. The couplings may also bewelded to prevent future leaks. Centralizersand scratchers are installed on the pipe. Thecentralizers (Figure 2) are bow-shaped stripsof steel that will hold the pipe in the centerof the hole away from the walls. Thispermits cement to be forced up through thehole on the outside of the pipe to form agood cement bond.

Figure 2. A casing centralizer.

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Then scratchers (Figure 3) are put on thepipe to scrape the drilling mud off the wallsof the hole. This allows the cement to bondto the pipe and to the walls of the hole. Thecaked-on drilling mud is removed from thewalls of the hole by raising and lowering thepipe several times to scrape it loose. Ascement is pumped down into the holethrough the casing and out the bottom, itrises toward the surface outside the casing toform a good cement bond completely aroundthe pipe all the way to the surface. Whenthe well is plugged, the pipe is left in place.

Figure 3. Scratchers used to remove fromthe walls of the hole.

B-5. Intermediate Strings of Casing.

Some oil wells will be deep enough that asecond string of pipe is cemented into thehole above the production reservoir. Thisstring is often installed to correct adversehole conditions such as sloughing, heaving,high-pressure gas, or lost circulation zones.Each time a string of casing is added, asmaller bit is used, small enough to goinside the new casing and drill out thebottom, usually down to the reservoir.

Occasionally, in deep wells, a taperedstring of casing is installed, consisting ofstrings of casing with successively smallerdiameters. This is done because ofeconomics or physical limits of the casingstring. First, a relatively large casing is setthat reaches from the surface and part of theway down the hole toward the reservoir.Then a slightly smaller bit and string of drillpipe is used. A casing hanger is installed atthe bottom of each string of casing to allowthe next size of pipe to be lowered throughthat section before it is securely attached andcemented into place. As the casing is run, itmay be periodically filled with drilling mudto keep it from collapsing from the excessiveexternal pressure. This is referred to asfloating the pipe in.

B-6. Drill Stem Tests and DrillingBreaks.

One of the most important decisions thatthe drilling supervisor makes is determiningwhat to do when a drilling break occurs. Adrilling break is a sudden increase in the rateat which the bit cuts through the earth and itindicates that the formation is more porous.A porous layer may contain hydrocarbons,such as crude oil or natural gas.

By taking into consideration how fast themud pump is operating, the distance to thebottom of the well, and the volume of thespace outside of the drill pipe, the crew cancalculate how long it will be before cuttingsfrom the drilling break zone reach thesurface. When the cuttings from the zonethe drilling break occurred in arrive, theperson catching samples will test thecuttings under an ultraviolet light or blacklight. Should crude oil be present, thesample will glow under the black light.

High mud pressures may prevent a goodsample from reaching the surface, and the

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solution might be to run a drill stem test. Inthis test, the drill pipe takes the place of thetubing string.

The production company decides if the testis to be run. The rig must stop drilling newhole until it is over, and an hourly rate mayused until drilling begins again.

Allowances are made in the contract toprovide time to run pipe and cement it intoposition. When the rig stops drilling to runpipe, the lease operator will pay by the hour,or some other appropriate amount tocompensate for rig expense during the timespent running casing, cementing, andwaiting on the cement to set and get hard.

The time while the cement sets is referredto as WOC or waiting on cement on thedrilling report. During this time, the rigcrew is busy cleaning the rig floor,rearranging the drill pipe on the racks, andgetting a smaller drill bit ready to begindrilling again. The new drilling bit will beconsiderably smaller than the previous bitbecause the drill bit and pipe must be smallenough to go through the casing to reach thebottom or cemented pipe and drill beyond itto extend the depth of the hole toward the oilreservoir.

B-7. Keeping the Hole Full Gauge andthe Packed Hole Assembly.

The bit wears in diameter as well as toothsharpness as the hole is drilled. As the bitdiameter shrinks, so does the hole diameter.To overcome this problem, a reamer is runright behind the bit. A series of rollingcones rotate as the bit is turned and thesecones ream the hole slightly larger. Reamingthe hole one time is usually sufficient. Thebit also wears on the shoulders, and, withouta reamer, when the crew pulls the drill pipeto run a new bit, the new bit will havetrouble getting back to bottom.

Figure 4. A reamer used to maintain holediameter as the bit wears.

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B-8. Drilling a Straight Hole.

It is not generally possible to drill astraight hole from the surface all the way tothe oil reservoir. Factors such as the densityof the formation, uneven wear on the bit,flexing of the drill pipe, and other conditionsmay result in the hole becoming deviated offtrue vertical depth (TVD). Generally, thehole is still usable for oil production.

Drilling the hole involves a continuousseries of decisions to adjust the drillingtechnique to obtain the best results.Considerations include obtaining a good,usable hole, getting good performance andlife from the bit, and making good drillingprogress. The two principal means ofcontrolling these factors are the rotationalspeed of the bit and the amount of weightapplied. Maximum penetration rate and astraight hole is maintained by varying theamount of drill pipe weight applied to the bitand the r.p.m. of the bit. A good balance ofthe two must be determined, and thatbalance may have to be adjusted asconditions, such as the density of theformation or the depth of the hole, change.

As the bit encounters formations that arenot horizontal, it will have a tendency toclimb uphill. To help solve this problem,more drill collars will be run on top of thereamer. Drill collars add weight and makethe pipe more rigid.

Even the use of collars will not solve alldrilling problems. Another commonproblem is having the bit get stuck ingrooves that can develop in the sides of thehole. These grooves, called key seats, areformed as the drill pipe flexes underpressure and rubs the side of the hole. Thethreaded ends of the drill pipe are known asconnections and are larger in diameter thanthe body or tube of the drill pipe. Theseconnections, being larger in diameter thanthe rest of the pipe, sometimes become stuckin the key seats, especially when the crewstarts pulling the bit out of the hole.

Another problem that may develop can becaused by the corkscrew profile of thedrilled hole. Because the formations are notof the same density all the way down to theproduction zone and the bit wears and thedrill pipe flexes, the hole rarely goes straightdown but instead has a twisted profile like acorkscrew. However, the tubing string tendsto hang vertically in the hole, meaning that itis likely to rub against the casing as it comesinto contact with the bends in the corkscrew.This contact can lead to holes being worn inthe casing and in the tubing. Tubing collarscan wear to the point that they fracture,allowing the tubing string to collapse intothe well. Methods of addressing some ofthese problems are addressed in the WellServicing and Workover section of thishandbook.

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4C-1

The Lease Pumper’s Handbook

Chapter 4Understanding the Oil Well

Section C

COMPLETING THE WELL

As noted in the previous section, once thewell has been drilled and the casingcemented in, tubing is installed to bring oiland gas up from the reservoir. The tubingconnects to the wellhead where a controlvalve system such as a Christmas tree isinstalled to permit control over the rate anddirection of flow of the products raised fromthe reservoir. The valve assembly is oftenreferred to as the wellhead. This sectionprovides more details about tubing andwellheads.

C-1. The Final String of Casing.

Some oil wells only have two strings ofcasing—that is, the surface pipe and thefinal string that reaches from the surface allthe way through the reservoir to the bottomof the hole. This final string is also referredto as the oil string or long string.

If the well is deep, the upper joints of thefinal string may be designed to have moretensile strength and the lower joints may bedesigned for collapse strength. If the lowerjoints are heavier than any other joint in thelong string, a similar joint is placed at thetop so that any tool that will go through thefirst joint will go through them all. This topjoint is sometimes referred to as a gaugejoint.

Cased-hole completion. As the bit drillsthrough the reservoir that containshydrocarbons, an analysis of the cuttings

assists in determining what type ofcompletion will be done. Most oil wells arecompleted by running the casing all of theway through the reservoir. Enough cementis then pumped down through the inside ofthe casing and up between the casing and theopen rock formation to cement the string inplace all the way through the producing zoneand to a selected distance above theimpervious cap.

Open-hole completion. In some wells,casing is not run through the reservoir.Instead, the well is drilled to immediatelyabove the oil producing reservoir. Casing isthen run and cemented into place. After thecement has set, the well is drilled in. Thedrilling in procedure involves drillingthrough the reservoir and leaving thereservoir open, creating what is referred toas an open-hole completion.

C-2. Perforating and Completion.

After the cement has set in the final stringof a cased hole completion, the next step isto perforate the casing. In the early days ofdrilling, a charge of nitroglycerin was set offin the well bottom to create fractures in thereservoir formation.

Later, the bullet perforating gun was used.It fired .50-caliber shells through the wallsof the casing, but proved dangerous becauseaccidental discharges before the gun wasplaced into the well occasionally killed

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people. Also, flow paths created by thebullet tended to fill in with crushed rock.

The jet gun now in use can penetrate muchdeeper as it is required to perforate the wallof the casing, the cement, and many inchesinto the rock of the formation.

When preparing to perforate, the crewneeds to know the bottomhole pressureinside the pipe and the anticipated pressureinside the formation. If the pressure is muchgreater in the formation than inside thecasing, the instant that the perforations areestablished through the pipe, fluids drivenby the bottomhole pressure will rush into thecasing and blow the perforating gun up thehole at a tremendous speed, wadding up theelectric line ahead of it and creatingnumerous problems.

C-3. Tubing.

True tubing is seamless, not welded, pipe.This construction increases its strength andreduces the possibility of production lossdue to split tubing. Tubing pipe was onceproduced with 10-pitch V-threads, but mostof this has been replaced by improved tubingwith 8-pitch round threads, generallyreferred to as 8 round. The round threadsare rolled into the pipe, not cut by athreading machine. The 8 round tubing ismuch stronger and easier to make up withless danger of cross threading.

Tubing is classified according to its wallthickness and the quality of the metal usedto make it. The tubing must be matched tothe installation, including the depth of thewell and factors such as high gas pressures.Typically, tubing is designated with a letterand a number. For example, H-40 is aneconomical tubing used for shallow wells, J-55 may be used for wells to about 7,000 feet,and P-105 is a heavy-duty pipe often usedfor deep wells. Exotic metallurgies are usedin problem wells

Because tubing must reach an exact depthin the well and be installed without being cutand threaded, tubing is available in randomlengths from 28-32 feet and in shorterlengths called pup joints. Pup joints (Figure1) are available in even two-foot lengths of2, 4, 6, 8, 10, or 12 feet and are added at thetop of the tubing string for final spacing.

Figure 1. A tubing pup joint.(courtesy Dover Corporation, Norris

Division)

Additional information about tubing isprovided in Chapter 17C and included inAppendix D, Pipe, Tubing, and Casing.

C-4. The Tubing String.

The tubing string is run in the well afterthe casing has been cemented into place andthe reservoir has been opened to the wellbore. A typical tubing string consists of thefollowing items from the bottom up:

· Mud anchor.· Perforated subs.· Seating nipple.· Pup joint (optional).· Packer or holddown (optional).· Safety joint (optional).· Tubing.· Pup joints (as needed).· Tubing hanger or slips and seal.· Spacer pup joints.

The mud anchor. The mud anchor isbasically a joint of tubing at the bottom ofthe string that is used to:

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· Collect fine silt or mud that is removedeach time that the tubing string is pulled.

· Provide a protected place to contain thepump gas anchor while the pump is in thehole.

· Allow the tubing string to be set on thewell bottom without damaging the stringor plugging the intake of the rod pump.

A mud anchor is a full joint of tubing butmay be cut off to be no more than 16-24 feetlong. Some companies use a tubing capplug or a collar and bull plug to close off thebottom end. Others cut off the bottom upsetsection and weld the opening closed withany acceptable method so that it has noexternal protrusions that may get stuck orcollect scale. Still others will slice thebottom four ways then heat and close thebottom by folding the four flaps over with alarge steel hammer.

Perforations. A portion of the tubing stringin the reservoir must be perforated so that oiland water may enter. The perforations in astring of tubing may be arranged in any ofseveral ways. Some of these options are to:

· Install a perforated pup joint (Figure 2)above the mud anchor by using a collar inbetween. These perforated pup joints maybe as short as 2 feet or up to about 12 feetlong. The typical length selected is 3 or 4feet. The holes are ½ inch in diameterand spaced a few inches apart on all foursides. These small holes prevent largeobjects from entering the tubing.

Figure 2. A perforated pup joint.(courtesy Dover Corporation, Norris

Division)

· Leave the bottom of the pipe open belowthe seating nipple or use a short joint.Very few operators use this approachbecause large objects may enter and causethe pump to stop functioning.

· Perforate the mud anchor with an electricdrill or by cutting holes with anoxyacetylene torch. These holes begin nofarther than 6 inches below the upset onall four sides and extend 2-4 feet. Theholes are 3-6 inches apart.

Seating nipples. The seating nippleprovides a connection for the pump whilesealing the pump to the tubing. This sealpermits fluid to be produced up through theseating nipple and pumped to the surface.Cup- and mechanical-type seats are used.The cup-type requires a seating distance ofabout 6 inches. Either three or four cupswill be placed on the pump. A larger no-goring of metal above the cups prevents thepump from sliding through the seatingnipple.

Cup-type seating nipples are reversible. Areversible seating nipple is 12-16 incheslong. When scoring or other damage thatmay cause the seat to leak occurs, the nipplecan be reversed to provide a new seatingsurface.

The mechanical-type seating nipple isabout 8-10 inches long and is not reversible.The seat is usually tapered at the top toaccept a metal-to-metal seat. The seat on thepump is made of a metal that gives slightlyto ensure that the seating nipple seals.

The packer. Flowing wells may becompleted with or without a packer. Apacker provides a seal downhole that canblock the flow of fluids between the tubingand the wellbore wall or casing. The packeris installed in a tubing string near the bottomand is set just above the casing perforations.

4C-4

The packer can help the well flow reducingthe cross-sectional area of the opening,increasing the flow velocity. If a well doesnot have high bottom hole pressure, the gaspressure in the annular space or annulus—that is, the space between the tubing and thecasing—will bleed into the tubingperforations as the casing empties of liquid.This casing pressure acts as a flow cushionwhile liquid accumulates once more in thewell. A packer can reduce this erraticchange in pressure.

The holddown. A holddown is similar to apacker in that it latches the tubing to thecasing near the bottom of the well just abovethe casing perforations. However, theholddown does not form a seal between thecasing and the tubing in the annular space;therefore, fluids may pass by it freely ineither direction without restriction.

If the well is deep and is to be completedas a pumping well, the holddown will beinstalled to prevent breathing—that is, theup and down movement of the bottom of thetubing with each stroke of the rods.Breathing is reviewed in detail in theProducing Pumping Wells section.

C-5. Correlating Perforations.

When running the tubing in the hole, oneof the most important tasks is setting theperforations in the casing at the mostdesirable depth from the surface. This willaffect the performance of the well, thenumber of barrels of fluid produced, theamount of gas produced, as well as howmuch gas is retained in the formation.

There are several options for correlatingperforations, and operators must reach theirown conclusions as to which is best for aparticular well and for reaching theirproduction goals.

C-6. A Typical Wellhead.

As each string of casing is run into thewell, an appropriate wellhead section mustbe installed. Figure 3 shows a wellhead witha Christmas tree mounted on top. Thisconfiguration would be satisfactory for aflowing well. Below the Christmas tree, thewellhead consists of two sections: thecasing head (labeled A in the drawing) andthe intermediate head (labeled B).

Figure 3. A typical wellhead andChristmas tree.

The casing head (A). The unit illustratedmay have external threads, internal threads,or a slip-on collar for welding directly to thecasing. The welded installation allows thetubing string to be positioned at a preciselevel. This is especially important for apumping unit installation. A plug, a ballvalve, or gate valve may be installed on one

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side, and a 2-inch bleeder valve is installedon the other side. The valve that is installedon the surface pipe is left open to preventpressure from developing that might threatenthe fresh water zone. Typically, thewellhead will use a gate valve, which is oneof the three multiple round opening styles ofvalves: the gate, needle, and globe. Such avalve is often referred to merely as a gate.

Figure 4. A casing hanger with hangerlocking devices shown.

The intermediate head with casinghanger. The final string of casing willusually be suspended from the intermediatehead. The casing hanger bolts on top of thecasing head generally have a metal seal ringand 12 or more studs with nuts. Somecasing hangers, such as the one shown inFigure 4, provide a means of attaching thetubing string to the casing hanger. If the

final string is attached to the casing hanger,there will be two openings on the sides withvalves screwed into the sides. One willusually be available and the second side willbe connected to the flow line going to thetank battery.

The tubing hanger. The final step inrunning tubing is to install the tubinghanger, popularly called the donut. Thetubing hanger should be cleaned and coveredwith a lubricant or thread compound beforebeing lowered into the hole. The dogs orlocking devices should be run in snugly tohold the top tapered edge firmly down. Thisallows the safe removal of the Christmastree with pressure still on the casing.

Figure 5. A tubing hanger.

Additional information about wellheadsand their use is presented in later chapters.

4C-6

5-i

The Lease Pumper’s Handbook

CHAPTER 5

FLOWING WELLS AND PLUNGER LIFT

A. Producing Flowing Wells1. Allowables.

· Coning wells and pulling in gas and water.· Effects of poor production techniques.

2. Several Operators Owning Wells in the Same Reservoir.3. What Makes a Well Flow Naturally?

· Packer removal.4. Producing a Flowing Well.

· Master gate valve.·· The pressure gauge.· The wing valve.·· The check valve· The casing valve.· The variable choke valve.· The positive choke.

5. The Skilled Pumper and Marginally Flowing Wells.B. Plunger Lift

1. The Cost of Changing a Well to Mechanical Lift.2 How Plunger Lift Works.3. Benefits of Plunger Lift.

· Reduce lifting costs.· Conserve formation gas pressure.· Increase production.· Produce with a low casing pressure.· Prevent water buildup.· Avoid gas-locked pump problems.· Reduce gas/oil ratio.· Scrape tubing paraffin.· Improve ease of operation.· Use pneumatic or electronic controllers.· Achieve lower installation and operating costs.

4. Plunger Selection.· Solid.· Brush.· Metal pad.· Wobble washer.· Flexible.

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· Clean-up plungers.5. Bumper Housings and Catcher.6. Footpiece and Stop.7. Time Controls.

5A-1

The Lease Pumper’s Handbook

Chapter 5Flowing Wells and Plunger Lift

Section A

PRODUCING FLOWING WELLS

The gas and water in a formation maycreate a pressure that forces fluids from therock when an opening, such as the well, iscreated. This pressure can be strong enoughto force the fluids to the surface. In thiscase, the well may be referred to as a flowingwell. If this level of pressure is less, a pumpor lift system must be installed to bring thewater, oil, and gas to the surface. Manywells start out as flowing wells but must beworked over to install a lift system in thelater years of their production lives.

This chapter discusses both flowing wellsand wells with plunger lift systems.However, before considering how oil isbrought to the surface, the regulation ofproduction is discussed.

A-1. Allowables.

Generally, a lease operator would like toproduce as much oil and gas as possiblebecause that is what leads to revenues fromthe well. However, maximum productionrates may not be in the best interests of thereservoir or the environment or the economyor other considerations beyond the financialinterests of the lease operator. Because thelease operator may not be aware of all thefactors that should be considered or may notvoluntarily do what is in the best interests ofthe nation and others, agencies have beenestablished to regulate the production of oiland gas. At a state or local level, such anagency may be called a Petroleum

Commission, Oil Commission, RailroadCommission, or other name. These agenciesassist petroleum producers in understandingreservoir problems and promote operatorcooperation. One of their primary tasks is toregulate the amount of production allowedfor a reservoir, often with limits set for bothoil and gas. These production limits,commonly called allowables, preventproduction abuses in reservoirs through thefollowing objectives:

· Protecting the reservoir. Allowablesand regulations are aimed first atprotecting the longevity and stability ofthe reservoir. Good production practicescan add years to the producing life of thereservoir and result in a much higherfinal production from the field.

· Protecting the rights of otheroperators. Allowables protect the livesof the wells of all operators who haveproducing wells in a reservoir.Regulating the amount of gas that maybe produced can preserve bottomholepressure, meaning that producers do nothave to resort to lift systems as soon.Because of oil production regulation,reservoirs are not depleted as quickly orunevenly, even when more than onelease operator is producing from thereservoir.

Coning wells and pulling in gas andwater. Some wells are capable of producing

5A-2

much more oil than is allowed. If the well iswater-driven—that is, bottom pressure issupplied by water carrying oil into thecasing—the lease pumper may be tempted toover-produce the well. This temptation isespecially severe if equipment breakdownsor other problems have put the lease behindits production goals. However, doing somay damage the well’s productioncapability. Fluids under pressure move toareas of lower pressure. In this case, the lowpressure is at the bottom of the well bore,causing fluids to rush from every direction.Oil flows in from each area of the reservoir,unwanted gas forces its way down throughthe oil bearing sands from above, and waterpushes upward into the oil zone from below.

Very soon a situation develops where thegas cone stays in position even when thewell is at rest. When the lease pumperopens the valve, more gas than usual will beproduced, sweeping water into the well.This water will stay in this position whilethe well is at rest. As water surges up, itdrives out the oil. The small differences inweight require many years to fall backnaturally so that the oil can return to itsoriginal level. The lease pumper can reducethe production capacity of the well to afraction of its uncontrolled production rate.

Effects of poor production techniques. Itreally does not matter who has decided tooverproduce the well: the owner, fieldsupervisor, or the lease pumper. The wellhas been damaged, and the company mustpay the price with lowered production.Treating the well more gently will notcasually restore it to the former level ofproduction. The recommended practice isnot to overproduce a well by more than tenpercent of its maximum daily productionpotential. This means that if a day ofproduction is lost, it will require ten days to

make up the loss. The well may reach theend of the month still short. However, thisis much better than damaging the wellcapability because continued overproductionwill soon result in being short every month.

Occasionally a lease pumper may hearother pumpers talk with pride of theirabilities as a pumper because they make upfor lost production in one well byoverproducing other wells on the sly. Whenthe production problems get corrected, theyhave managed to maintain full productionoverall. Even their supervisors may beextremely pleased. In fact, all this effort hasactually accomplished is to shorten the livesof the wells and dramatically reduce theirlong-range capabilities.

A-2. Several Operators Owning Wells inthe Same Reservoir.

The United States is one of the fewcountries in the world where mineral rightscan be owned by individuals, companies,trusts, states, and the government. As aresult, occasionally the production practicesof one lease operator may cause extremeproduction problems for offset wells—thatis, wells operating near the first lease. Thisreduction can become so severe that nearbywells are killed, meaning that they no longerproduce oil or gas, because hydrocarbons arepulled away from the outer areas of thereservoir where the offset wells may be.

If the reservoir is high in some areas andlow in others, wells in the higher elevationsmay produce only gas. Wells drilled in thelowest area may produce extremely highvolumes of water and very little oil. Wellsin the middle range may produce highvolumes of oil with very little gas andvirtually no water.

If the operator of the wells in the higherarea produces high volumes of gas and

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lowers the reservoir pressure, the wellsproducing a high volume of oil willgradually stop producing oil. If the leaseoperator owning wells in the lower zonesproduces massive amounts of water, thiswill stimulate the water drive and, with thelowered formation pressure, allow the watertable to rise so that production from the highoil-production wells falls off.

Many lawsuits have been filed from thesetypes of problems. The best solution is forthe operators involved to agree to aproduction plan for the whole reservoir sothat it can be produced efficiently for thebenefit of all the operators.

A-3. What Makes a Well Flow Naturally?

A well flows naturally when it has asufficiently high bottomhole pressure toforce the fluids to flow from the formationall the way to the stock tank without externalor internal assistance. Most naturallyflowing wells receive their bottomholepressure from water drive, which is thepressure created by the movement of waterwithin the formation. As oil and gas areremoved from the formation, water may fillthe space vacated by the hydrocarbons dueto the lower pressures in that area. This is arelatively slow process taking many years tooccur.

For the well to flow, the bottomholepressure must be great enough to lift thecolumn of fluid in the tubing to thewellhead, push the fluid through the flowline to the tank battery into a pressurizedseparating vessel, and still retain enoughpressure to push it through any additionaltreating vessels and into the sales or stocktank. So how much pressure is required?

A common rule of thumb is that if the wellhas a wellhead pressure of about 100 poundswith a standing column of liquid in the

tubing, this is usually sufficient pressure toallow the well to flow. The higher thepressure, the higher the volume capacity andthe ease of flow.

Figure 1. A typical wellhead for anaturally flowing well.

(courtesy ABB Vetco Gray)

Packers are placed near the bottom of thetubing string in the annulus of flowing wellsto prevent the surge effect that will occur ifno packer is present. The flowing wellwithout a high bottomhole pressure willproduce erratically without a packer. As anillustration, if a flowing well without apacker produces mostly gas with very littleliquid for a short period of time, most of theliquid in the tubing and casing will beproduced toward the tank battery. As the

5A-4

casing is emptied of liquid, the gas pressurecontained in the annulus will break aroundinto the tubing perforations. This suddensurge of gas will empty most of the liquidout of the well all of the way to the tankbattery. This loss of gas will reduce the gaspressure dramatically in the casing all of theway through the system.

After this pressure has blown down, andliquid once more begins to accumulate in thebottom of the well, the casing pressure actsas a flow cushion or as a pressure surge tank.The casing pressure must build back up to alevel that will allow the well to developenough bottomhole pressure to cause it toflow again. This erratic action of flowingwells can be reduced or eliminated byplacing a packer in the well near the bottom.Very high volume flowing wells may beproduced through the casing, however, andthese wells do not have packers.

Packer removal. When a well will not flowand is converted from a flowing well to apumping well, the packer may be removed,and the casing valve is eventually opened tothe tank battery at all times to removebottomhole formation pressure. A checkvalve is placed in the casing line near thewellhead to prevent the oil that is beingpumped out of the tubing from circulatingback into and down the casing.

The bottomhole pressure of the well hasnow been reduced to the separator pressureplus flow line resistance, plus the weight ofthe column of fluid in the annulus. Thelease pumper must always be aware of anysituation that might change this balance,because every change will affect the oilproduction from the well. If the pumperraises the separator pressure by 5 pounds,the formation pressure has been raised by 5pounds, and oil production will declineaccordingly, especially for a short period of

time. When the gas production has beenreduced to the traces classification, thecasing valve may be open to the atmosphere.

A-4. Producing a Flowing Well.

The typical flowing well will have aChristmas tree composed of a master gatevalve, a pressure gauge, a wing valve, and achoke. The Christmas tree may also haveone or more check valves. The functions ofthese devices are explained in the followingparagraphs.

Figure 2. A typical flowing wellconfiguration with a Christmas tree,master gate valve, wing valve, checkvalve, variable choke, and flow line.

Master gate valve. The master gate valve isa high quality valve. It will provide fullopening, which means that it opens to thesame inside diameter as the tubing so thatspecialized tools may be run through it. Itmust be capable of holding the full pressureof the well safely for all anticipatedpurposes. This valve is usually left fullyopen and is not used as a throttling valve tocontrol flow.

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The pressure gauge. A high-pressure steeltee is placed above the master gate valve. Atapped bull plug and a ½-inch needle valvewith gauge are placed on top of the well.The high-pressure needle valves areavailable in both straight (180-degree) andell (90-degree) configurations where thevalve pressure can be read from aconvenient angle.

Figure 3. Pressure gauge and valves usedon top of the well.

The wing valve. The wing valve can be amulti-round opening valve similar to themaster gate valve or it can be a quarter-round opening. Plug valves are sometimesused, though the ball valve is becomingpopular because of the ease of operation.Further, it is easy to determine even from adistance if the valve is open or closed. Ballvalves cannot collect water in the bottom ofthe valve as can some plug valves. Ballvalves are usually also more economical topurchase. When shutting in the well, thewing gate or valve is normally used so thatthe tubing pressure can be easily read.

The check valve. Almost withoutexception, a check valve is installed in theflow line as it leaves the well. A second oneis installed at the tank battery just before theline enters the tank battery separator header.Occasionally, an operator will prefer toinstall the check valve just after the wingvalve but before the choke. Other operatorsinstall the check valve on the ground, afterthe line has turned toward the tank battery.This optional union and a ground-levelcheck valve may be installed to permit easyremoval of the Christmas tree and riser pipefor well workover. Some operators willinstall all three.

The casing valve. Even if a packer hasbeen installed in the annular space near thebottom of the well, the casing will usually beconnected to the Christmas tree and the linegoing to the tank battery. This will permitthe casing to be opened, closed, bled down,and, in some cases, allow the flowing well tobe produced through the casing as well asthe tubing. If a packer is installed, this lineconnection serves no purpose until thepacker is turned loose or is completelyremoved by a well servicing crew. Thecasing valve is usually a multiple roundopening gate valve and can withstand highpressure. Like the wing valve, it does nothave to be full opening. This valve can beused to determine packer leaks or determineif the tubing has developed leaks.

The variable flow choke valve. Thevariable flow choke valve is typically a verylarge needle valve. Its calibrated opening isadjustable in 1/64 inch increments. Chokesare available in steel, stainless steel, andtungsten carbide steel and are, therefore,expensive. . High-quality steel is used inorder to withstand the high-speed flow ofabrasive materials that pass through the

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choke, usually for many years, with littledamage except to the dart or seat.

Figure 4. A unibolt design variable flowchoke valve. A portion of the valve hasbeen cut away to show the high-quality

steel construction and the flow path.(courtesy Cooper Cameron Valves)

The valve pictured in Figure 4 is of theunibolt design. The seal where the twohalves of the union joints is a seal ringsimilar to the ones where the wellheadsections and the Christmas tree join thewellhead. This is a high-pressure steel sealand will withstand several thousand pounds.The unibolt union is often referred to as thewellhead union. The variable choke valvecan be installed where the production flowswith the dart, or running, or it can beinstalled where it flows against the pointedend of the dart or stem. As pictured, theunibolt choke has been installed to flow withthe point of the dart. The choke valve inFigure 3 is installed so that the well flowsagainst the point.

Because of the expense of the valve andthe amount of fluid produced, the ¾-inchvariable choke is very popular. Chokes of 1

inch or more are available but are practicalonly for very high producing wells.

Choke valves are marked to show the sizeof the opening. If the valve is fully opened,the last number will indicate its size. Forexample, if the last number is 48, then thevalve is 48/64ths or a ¾-inch choke. If thefinal number is 64, then it is a 1-inch chokeand can be opened to 64/64ths. Theindicator sleeve can be loosened, usuallywith a set screw, and the setting correctedwhile the valve is closed.

If the well flows oil that may have a littleparaffin, salt water, and scale, productionmay slowly drop as the orifice becomesclogged. Periodically opening the choke to ahigher setting for a short period of time, thenclosing it, then opening it back up to flushthe seat clean, and finally slowly pinching itback to the original setting may eliminatethe scale that can collect in the choke.

Occasionally, the choke valve will be setat a rate of production that allows water tofall back down the tubing string and collectat the bottom of the well or in the matrixarea. As this water builds up, it will begin torestrict oil production. It may even kill thewell. This will require a swabbing unit to becalled out to swab the water blanket up tothe tank battery to allow the well to continueto flow. The use of soap sticks is a commonmeans of stimulating flow from a wellloaded up with water. Opening the choke toan increased flow rate for a short period oftime occasionally, then setting it back at itsusual setting may prevent this problem.

In order to monitor this situation, the leasepumper will need to write down the wellhead pressure before beginning and for atleast one or two more periods to determine ifthe flow characteristics of the well haveimproved. Another solution is to conduct aproductivity test to determine if other flowcycles would be more appropriate.

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The positive choke. The positive chokemay be located at the well on the Christmastree (Figure 5) or on the inlet manifold justahead of the first separating vessel (Figure6). In many situations, there will be apositive choke at both locations. When thepositive choke is located at both thewellhead and at the tank battery, it givespositive benefits.

Figure 5. A positive choke installed onthe wellhead.

Figure 6. A positive choke installed at thetank battery.

One of the distinct advantages of thevariable choke over the positive choke is theease with which the setting can be changed.Flow through positive chokes is regulated bychoosing a properly sized flow bean that willallow the well to produce the correct amountof oil daily. The chart in Figure 7 offers 74sizes of beans shut-in to 14/64ths of an inch.These flow beans are sized to permit 5% and10% increases in flowing rates.

Figure 7. Chart showing sizes ofavailable flow bean inserts for positive

choke valves.(courtesy Cooper Cameron Valves)

If the orifice size in the flow bean is a littlelarger at the well than at the tank battery toallow for expansion of the fluids. The finalexpansion occurs at the tank battery. Thefluids will undergo a temperature reductionat the wellhead and also at the tank battery.Permitting this pressure reduction to occurin two steps instead of one can reduce thepossibility of the line freezing.

The intermittent control for all wells is atthe tank battery, and this centralizes theautomation at one location instead of beingat each wellhead. When the positive choke

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is at the wellhead, a wing gate is installedbetween it and the wellhead. A secondvalve is installed after the positive choke.This allows the choke to be easily isolated,bled down, and repaired or changed.

A-5. The Skilled Pumper and MarginallyFlowing Wells.

As bottomhole pressure declines, therewill be a corresponding decline in oil andgas production. During this period ofreduced production or as the hydrocarbonsin the reservoir are nearing depletion, thewell is referred to as a stripper well or amarginally producing well. Much of thenation’s oil production comes frommarginally producing wells.

As production from a flowing welldeclines, the lease operator will have tomake a decision as to whether an artificiallift system should be installed. To a largedegree, the maximum life of a flowing well

before it must be converted to artificial lift iscontrolled by the lease pumper. One of themost important skills of a lease pumper isthe ability to make the correct decisions ofhow to produce each well in the marginallyproducing period before it goes on artificiallift. Some people have the interest,experience, patience, and ability tounderstand what is going on downhole, andthe skill to make a flowing well produce formonths or even years longer than otherpeople. Some people never truly developthis skill.

A skilled lease pumper, who takes time tolearn how to rock a well, alternately openingand closing the tubing bleeder andoccasionally the casing valve, may bring awell back to life and do an outstanding jobin obtaining a satisfactory volume ofproduction with limited down time. Thisability can extend the life of a flowing wellbefore artificial lift is necessary.

5B-1

The Lease Pumper’s Handbook

Chapter 5Flowing Wells and Plunger Lift

Section B

PLUNGER LIFT

The use of plunger lifts has increaseddramatically during the past decade and hasled to increased oil production. Improvedtechnology, computers, better equipmentdependability, and additional services havecontributed to this increased use. Plungerlift is available in complex computer-controlled models and simple basic systems.This section discusses the use of plunger lift.

B-1. The Cost of Changing a Well toMechanical Lift.

Once the bottomhole pressure in a well is nolonger adequate to cause it to flow, theoperator must determine if it will beworthwhile to install a lift system. Theinitial costs can be substantial, even with aminimum installation. The actual transitionof a well from flowing to pumping requires:

· A well servicing crew to rig up andremove the packer, possibly install ahold-down in the casing, reinstall thetubing string, and run the rod string.

· The purchase of a downhole pump.· The purchase of a string of rods.· The purchase of a pumping unit.· Construct a base and have it set.· Install and line up the pumping unit on

the base and over the hole.· Remove the Christmas tree and rebuild

the wellhead (Figure 1).· Provide a source of power to run the

pump either by running electricity to the

location or providing an engine and asource of fuel. An electrical setup willrequire an automatic control and anelectric motor. A engine may operate ongas from the well or from stored fuels.

Figure 1. Two typical wellhead designsfor wells using plunger lift.

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B-2. How Plunger Lift Works.

A wing valve control on the wellheadcloses the flow line to the tank battery, andthis stops the flow of fluids up through thetubing to the tank battery. The bumperhousing and catcher on the wellhead releasea free falling gas lift plunger, which dropsby gravity from the wellhead downwardthrough the tubing. An open valve in theplunger allows fluids from below to passthrough it as it falls. Gravity continues tomake the plunger fall all the way to thebottom of the well.

When the gas lift plunger strikes bottom, itmakes contact with a footpiece spring,closing the valve. Downhole pressurecontinues to build up and also allows oil andwater to accumulate on top of the plunger.After a specified time or tubing pressurelevel, the controller causes a flow line motorvalve at the surface on the wellhead to open,allowing the gas and fluids accumulated inthe tubing to flow toward the tank battery.

The differential pressure change across theplunger lift valve causes the plunger totravel toward the surface at a rate of 500-1,000 feet per minute, depending onadjustable choke settings, fluid loads, andbottomhole pressure. As the plunger movesupward pushed by the built-up formationpressure below it, the fluid above theplunger is lifted to the surface.

On oil wells and weak gas wells, thearrival of the plunger at the surface activatesa magnetically controlled sensor thatimmediately closes the flow line motorvalve, conserving tubing and formation gaspressure until the next cycle. The catcher inthe bumper housing releases the plunger.The plunger again starts falling, and thecycle begins again, repeating itself as oftenas the settings and pressures allow.

Figure 2. Plunger lift system.(courtesy of Production Control Services,

Inc.)

B-3. Benefits of Plunger Lift.

The benefits of converting a marginallyproducing flowing well to a lift system canbe enormous in many situations. Some of

5B-3

reasons for choosing a plunger lift systemover other type include:

· Reduce lifting costs.· Conserve formation gas pressure.· Increase production.· Produce with a low casing pressure.· Prevent water buildup.· Avoid gas-locked pump problems.· Reduce gas/oil ratio.· Scrape tubing paraffin.· Improve ease of operation.· Use pneumatic or electronic controllers.· Reduce installation and operating costs.

Note: When a plunger system is installed, agauge ring of the same size as the proposedmandrel to be used in the plunger lift systemshould be run down the well. This willidentify any problems that could prevent theplunger from free-falling through the tubing.

Reduce lifting costs. The plunger lift has alower lifting cost than most other systems ofartificial lift. With the less complexsystems, the well itself supplies the gaspressure needed for operation. The morecomplex electrical systems require very littlepower and this can be supplied with a solarpanel.

Conserve formation gas pressure. Asquickly as the plunger arrives at the bumperhousing at the surface, the flow line is shutin, stopping any additional formation gasfrom flowing to the tank battery and into thegas system. The gas needs to remain in theformation as long as possible to driveadditional oil to the well bore in the future.When the formation gas is gone, the wellwill stop producing. The conservation offormation gas is one of the outstandingbenefits of plunger lift, and no other liftsystem can offer this advantage.

Increase production. Through productivitytesting where the well is produced undermany different time limits and situations, themost productive parameters can bedetermined and followed to result in thehighest possible production. By reducingthe column of fluid lifted and lifting it moreoften, production can usually be increased.

Produce with a low casing pressure.Plunger lift allows a well to continue to flowwith less than 100 pounds of casingpressure. The plunger will stay on bottomuntil sufficient lifting pressure has built up.The signal to open the flow line valve willbe transmitted to the surface through thecasing pressure.

Prevent water buildup. When a well isflowing by choke control and the liftingpressure has become so marginal that thewell will barely flow, the produced water,being heavier than oil, will have a tendencyto allow the oil and gas to flow with thewater falling back to the bottom of the hole.This water buildup will cause the well tobecome waterlogged and stop flowing untilthe water has been blown or swabbed off.With plunger lift the water is produced alongwith the oil every time the plunger makes atrip to the surface, and water does notaccumulate at the bottom of the well.

Avoid gas-locked pump problems. Whena well with high gas production is put on amechanical pumping unit, the pump candevelop a tendency to gas lock and stop thewell from producing. The plunger liftsystem does not have this problem.

Reduce gas/oil ratio. In some fields, oilproduction is regulated by the amount of gasthat is produced with each barrel of oil. Theeffort is to retain as much gas in the

5B-4

reservoir as possible to push oil to thewellbore. Some fields have allowablesadjusted to reflect the amount of gasproduced daily. Plunger lift does well inreducing gas production, which results inincreased oil allowables. This willdramatically extend the production life ofthe reservoir and the amount of oilproduced.

Scrape tubing paraffin. While the plungeris traveling up the tubing each cycle, it actsas an excellent wiper to remove paraffin thatmay cling to the tubing. Paraffin leaves theformation suspended in the oil. As thewellbore temperature drops, the paraffincomes out of solution and is deposited in thetubing. The plunger can also remove scalethat is still soft.

Improve ease of operation. The basicoperation of plunger lift systems is simple.Even the more complex systems arebecoming easier to operate with newdevelopments in technology. Advances inpersonal computers and electronicminiaturization allow controllers to performfunctions that were not possible a few yearsago, almost to the point of making decisions.

Use pneumatic or electronic controllers.Automatic controls allow the pumping timeof the well to be precisely controlled toallow the most efficient use of energy and toreduce the loss of gas.

Reduce installation and operating costs.Plunger systems generally cost less to install,operate, and maintain than other lift systems.

B-4. Plunger Selection.

There are five main types of plungers:solid, brush, metal pad, wobble washer, andflexible (Figure 3)

Figure 3. Some of the types of plungersavailable.

(courtesy of McLean & Sons, Inc.)

Solid. The solid plunger is a solid steelcylinder with a smooth or grooved surface.Gas passing around the plunger during itstrip upward must have a velocity muchgreater than the plunger and liquid load.The gas passing the plunger wipes the tubingclean of liquids and reduces liquid fallback.

Brush. A brush plunger consists of amandrel and a brush segment that may ormay not be replaceable. The brush segmentis oversized with respect to the tubinginternal diameter, and this characteristiccreates the sealing mechanism. Brushplungers are particularly good for wells thatsuffer from sand flowback or tubingimperfections.

5B-5

Metal pad. The metal pad plunger hasseveral spring-activated metal pads thatconform to the internal tubing diameter.These plungers may have one or severalconcentric sets of pads along the bodyarranged in various patterns. Pad plungersprovide the highest level of mechanical sealwhen properly sized.

Wobble washer. The wobble washerplunger is designed to keep tubing free ofparaffin, salt, and scale. It is constructed ofshifting steel rings or washers mountedalong a solid mandrel. The washers wipethe tubing clean, removing the unwantedproduct before it has a chance to crystallize.

Flexible. New on the market are plungersbuilt with a flexible mandrel for deviatedhole and coiled tubing applications.Articulated cup and brush plungers areavailable with this new design feature.These flexible plungers range in size from ¾inch to 2-7/8 inches. Many times a flexibleplunger will run in a standard tubing stringthat has bends or crimps, reducing the needto pull tubing.

Clean-up plungers. Among the plungerspictured in Figure 3 is a clean-up free-fallplunger with a fishing neck. These arefrequently used to handle formation sand,frac sand, scale, and so forth. The clean-upplunger is usually replaced with theexpanding blade plunger when the well hascleaned itself. If the plunger should stick inthe tubing during the clean-up procedure, thefishing neck makes it easier to retrieve.

B-5. Bumper Housings and Catcher.

The bumper housing and catcher performseveral functions. The bumper provides acushioned bumper to stop the plunger from

moving as it reaches the top of its travel andenters the housing. The housing also helpsprovide lubrication.

The arrival unit recognizes that the plungerhas arrived at the top of its travel and sendsa signal to the control panel, or controller,which sends a signal to the flowline valve,causing it to close.

The lease pumper can engage the catcher,which will catch the plunger the next timethat it arrives at the surface. This willpermit the plunger to be removed, inspected,serviced, and placed back into operation atthe pumper’s convenience.

Figure 4. Common components of aplunger lift system: (left to right) a

controller, plunger, bumper, and housingwith lubricator and electronic sensor.

(courtesy of Production Control Services,Inc.)

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B-6. Controllers.

Most controllers (Figure 5) can be operatedwith time control or with pressure cycles.Timers may be set for straight timed shut-inor operated with high/low pressuremeasurements through the use of flow linethrottle pilot pressure and a differentialpressure switch. With this type of flexibilityavailable to the lease pumper, plunger liftcan be an ideal method for operating wells.By reducing the loss of formation gas, agreat deal of additional oil may berecovered.

Figure 5. An electronic controller.(courtesy of Production Control Services,

Inc.)

B-7. Plunger Lift Configurations.

It should be evident from this section thatplunger lift systems can be configured in anumber of ways to meet the needs of aspecific well. By matching the components

and the controller settings to conditions ofan individual well, the lease pumper cancome close to maximizing the efficiency ofthe well.

Note the plunger lift shown in Figure 6. Afull opening gate valve is located just underthe oil well bumper housing and arrival unitand catcher. This particular installation waspowered by a solar panel located to the right,just out of the picture. The casing valve hasa pressure gauge and connection providingpressure to the controller. Just to the right ofthe bumper housing is a line that controls theshut-in of the flow line.

Figure 6. A plunger lift wellhead showingthe bumper housing, arrival unit, catcher,

and controller.(courtesy of McLean & Sons, Inc.)

Plunger lift is one method of artificial lift.Other techniques are presented later in thishandbook, but many of the objectives andconsiderations described here are applicableto other lift methods as well.

5B-7

6-i

The Lease Pumper’s Handbook

CHAPTER 6

MECHANICAL LIFT

A. Pump Operation1. Application of Mechanical Pumping.2. How Mechanical Lift Works.3. Problems Caused by the Cyclic Load Factor.4. Pumping at the Wrong Speed.

B. Operating and Servicing the Pumping Unit.1. Mechanical Lift with Electric Prime Movers.2. Mechanical Lift with Natural Gas Engines.3. Pumping Schedules.4. Automatic Controls.5. Maintaining the Pumping Unit.

· The daily inspection.· The weekly inspection.· The monthly inspection.· The three- and six-month inspection.· Pitman arm and gearbox problems.

6. Direction of Rotation.7. Gearbox Oil.8. Typical Pumping Unit Problems.

C. Wellhead Design and the Polished Rod1. Preparing the Well for Pumping Downhole.2. Pumping Wellheads.3. Selection of Polished Rods, Clamps, Liners, and Stuffing Boxes.

· Polished rod.· The polished rod liner.· The polished rod clamp.· The stuffing box.· The polished rod lubricator.· The rod rotator.

4. Tubing, Casing, and Flow Line Check Valves.· The tubing check valve.· The casing check valve.· The flow line check valve.

D. The Downhole Pump1. Basic Components of the Pump.

· Standing valve.· Barrel tube.

6-ii

· Plunger.·· Traveling valve.·· Holddown seal assembly.

2. Pumps Designs.· Insert pumps.· Tubing pumps.·· Other styles of pumps.

6A-1

The Lease Pumper’s Handbook

Chapter 6Mechanical Lift

Section A

PUMP OPERATION

There are four types of power that arecommonly used to provide artificial lift inthe oil field. There are:

· Mechanical lift powered by a motor orengine on the surface

· Hydraulic lift, where oil or water ispumped down into the well to operate ahydraulic pump

· Electric submersible pump, where apump at the bottom of the well is drivenby electricity from the surface

· Gas lift, where natural gas injected intothe tubing at intervals lightens theweight of the fluid, helping it rise to thesurface

All four of these systems offer advantagesand disadvantages for specific situations.During the life of a well, more than one ofthese systems may be used. Occasionallythe same type of system may be installed asecond time on the same well. Mechanicallift is one of the more commonly used formsof artificial lift and is the subject of thissection. The other types of lift are discussedin the next three chapters.

A-1. Application of Mechanical Pumping.

The mechanical pumping unit remains asone of the best ways to produce artificial liftwells. It is also satisfactory for marginallyproducing wells, and the majority of allartificial lift wells use mechanical lift.

This system of pumping works well forlow production because the surfaceequipment requires very little daily attention.Each installation is an independent system,is economical to maintain, is easilyautomated, and is ideal for both intermittentas well as continuous production.

Other lift methods may be moreappropriate for a specific situation and forhigher production rates, but for manyapplications mechanical lift is ideal,including in shallow offshore wells.

A-2. How Mechanical Lift Works.

The mechanical pumping unit works onthe same operating principles as a windmillor any water well that has a string of suckerrods, a standing and a traveling ball on thebottom, and power at the top. Figure 1shows a typical pumping unit. Thesesystems, sometimes called rod pumpingunits, work with an up and downreciprocating motion.

Figure 1. A conventional beam-stylepumping unit.

6A-2

The crank of the pumping unit is driven ina circular motion by the rotation of thesheaves or pulleys, belts, and gearbox. Thegearbox is driven by the prime mover,generally a gas-powered engine or anelectric motor. The pitman arms areconnected to the walking beam, and therotary action is converted into reciprocatingpower to the walking beam and the horsehead. A set of counterweights offsets theweight of the string of rods and part of theweight of the fluid in the tubing. The stringof rods usually extends through the tubing tothe bottom of the well, and a pump isinstalled below the fluid level at the bottomof the hole. By using a ball-and-seat style ofstanding and traveling valves, the liquid—usually a combination of oil and water—ispumped from the bottom of the oil well tothe surface, through the flow line, and intothe tank battery.

As the pumping unit starts, the head of thepumping unit moves upward, lifting thesucker rod string and the plunger in thepump. The traveling ball or valve closes sothat oil cannot pass through the plunger as itmoves upward. This action lifts the fluid inthe tubing string toward the surface, whilealso creating reduced pressure below theplunger. The standing valve in the bottomof the pump opens due to the reducedpressure, allowing additional fluid to enterthe bottom of the pump.

As the rod string starts moving downward,the increased pressure from above closes thestanding valve in the bottom of the pump.This prevents the oil that has entered thepump barrel from flowing back into theformation and allows pressure to build upbetween the valves, which opens thetraveling valve as the pressure between thevalves grows greater than the weight of thefluid in the tubing. The plunger passesdown through the fluid that entered the

pump barrel during the upstroke, trapping iton top of the plunger once the travelingvalve closes as the next upstroke begins, andthe cycle will be repeated. The timerequired for each cycle is determined by howthe pumping unit is configured, includingthe speed of the prime mover, the ratio ofgears in the gearbox, and the sizes of thesheaves or pulleys. This cycle time isreferred to as strokes per minute (SPM) andis partially determined by the revolutions perminute (RPM) of the prime mover.

Figure 2. A ball and seat valve, a designcommonly used for the standing and

traveling valves in mechanical liftsystems.

This description of mechanical pumpingaction shows that the unit lifts liquids to thesurface only on the upstroke. On the otherhand, the plunger in a hydraulic lift pumplifts liquid on the upstroke and also on thedownstroke. Since no rods are moving, thispump can also move much more rapidlythan the rod pump, so it is capable of liftinga much higher volume of liquid.

The electric submersible pump and gas liftsystems also lift continuously while inoperation. Thus, these three systems arecapable of lifting a higher volume per day

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than mechanical lift systems. However,since most wells do not run continuously,whether lift occurs during the wholeoperation or only half of the cycle is notnecessarily the most important considerationin the choice of an artificial lift system.

As the rod string moves up and downduring the pumping cycle, many changesoccur downhole.

· As the rod string moves upward, theweight of the column of oil in the tubingis transferred from the standing valve tothe traveling valve.

· The length of the rod string grows longeras the plunger tries to lift the weight ofthe liquid above and tries to overcome thefriction and surface tension between theoil and tubing.

· As the weight of the column of liquid islifted, there is less weight on the tubing,and the length of the tubing string getsshorter—that is, the bottom of the tubingstring moves up the hole a short distance.

· The friction of the upward-moving oilalso exerts a small lifting force on thetubing.

· As the plunger moves downward, theweight of the column of oil in the tubingis transferred from the traveling valveback to the standing valve.

· The length of the rod string grows shorteras it pushes back down against the freshlyaccumulated fluid.

· With the traveling valve open, the weightof the column of liquid rests on thestanding valve and is exerted against thetubing string. This increased load causesthe tubing string to become longer. Thebottom of the tubing string movesdownward, from a few inches to severalfeet, depending on the depth of the well,the weight of the column of fluid, and thesize of the tubing.

· The downward movement of the tubingresults in over-traveling of the pump—that is, the pump is moving away fromthe surface and accumulating additionalfluid during the downstroke.

The action of the rods and tubing inresponse to these changing forces is calledthe cyclic load factor, and the up and downmovement of the tubing in the hole isreferred to as breathing. These changes inthe length of the rod string and the tubingstring can be computed so that the length ofthe surface stroke can be adjustedaccordingly.

A-3. Problems Caused by the CyclicLoad Factor.

Several problems can result from thecyclic loading and breathing action of therod string and tubing string. Some are:

· As the tubing and collars move up anddown in the casing, holes may wear in thecasing and cause a casing leak.

· The collars or tubing may wear to thepoint that the string begins leaking liquidfrom inside the tubing back into thecasing, where it falls back to the bottomof the hole. In extreme situations thetubing string can separate. Wear isespecially high when the tubing or collaris rubbing at the bends or dog legs in thecasing that are a natural result of thedrilling process.

· The stretching of the rods and shorteningof the tubing results in a shorter relativestroke length inside the pump than thetravel of the rod string at the surface. Thisresults in lower pumping efficiency andreduced production. The lease pumpermust pump the well longer to overcomethis loss in pump stroke. For a shallow

6A-4

marginal well, this is usually not a greatproblem because the typical well does notpump a full twenty-four hours per day.

A tubing holddown can be installed nearthe bottom of the tubing string to reduce theup and down movement at the bottom of thestring. A tubing holddown is similar to apacker except that it does not have rubber toseal against the casing. Fluids may movefreely by the holddown. To preventmovement in the upper area of the tubingstring, it may be necessary to pull severalthousand pounds of tension on the tubingstring. As an illustration, a 10,000-foot wellwith 2-7/8-inch tubing may have a tension of25,000 pounds pulled on it above the weightof the string. The installation of holddownsis routine in all deeper wells.

A-4. Pumping at the Wrong Speed.

Problems created by the cyclic load factorcan also be compounded by pumping theunit at the wrong speed. On medium to deepwells, as the top rods begin movingdownward at the surface, the pump travelingvalve at the bottom is still moving up. Theproblem reverses when the top rod startsmoving up and the pump traveling valve isstill going down. This problem can become

exaggerated if the pumping operation is notcarefully planned so that the SPM, RPM,sheave diameter, and other factors are notcarefully matched to the characteristics ofthe well, such as depth and fluid weight andviscosity. If the cyclic load factor is large—that is, there is a great deal of stretch in therod and tubing strings and their travelrelative to each other is out ofsynchronization—pumping efficiency can begreatly reduced. In such a case, increasingthe number of strokes per minute mayactually decrease the length of the stroke atthe bottom of the hole. Although SPM hasincreased, the amount of fluid produced hasdecreased.

Most pump companies provide a servicethrough which they will calculate the properarrangement of the pump components basedon the pumping conditions, such as thedepth of the well, size of rods, length ofstroke, and strokes per minute.

Such planning, when properly matched tothe characteristics of the well, will help toensure that mechanical lift is suitable for thelease. The remaining sections of thischapter discuss the operation andmaintenance of mechanical lift systems,while other lift methods are discussed in thechapters that follow.

6B-1

The Lease Pumper’s Handbook

Chapter 6Mechanical Lift

Section B

OPERATING AND SERVICING THE PUMPING UNIT

Most active oil wells are marginallyproducing wells that have been converted tolift systems. The percentage of wells onmechanical lift is so great that all of thewells on many leases are on pumping units.This method of artificial lift is sodependable and easy to operate that manylease pumpers prefer mechanical lift overany other artificial lift system. This sectioncovers the operation and maintenance of amechanical lift system.

Figure 1. A pumping unit driven by anelectric motor. Note the power controlbox on the power line pole. Two othersare on the far side of the pumping unit.

B-1. Mechanical Lift with Electric PrimeMovers.

Wells with electric motors as their primemovers are easily programmed to operate onfull automation and easy to learn to operate.In a typical installation with electricalcontrols, such as that shown in Figure 1, the

power line brings electricity to a spot nearthe location but outside of the guy line area.A fuse panel is installed and the power lineis run underground, usually to the back ofthe pumping unit. On a post, a secondelectrical panel is installed with an on/offswitch. An automatic control box is alsoattached to the post. The lease pumper mustfully understand how to operate thesecomponents and be aware of problems thatmay develop.

B-2. Mechanical Lift with Natural GasEngines.

Operating pumping units with natural gasengines are quite different from producingwells that utilize electrical prime movers.This is especially true when the fuel supplyis gas from that well. Under theseconditions, the lease pumper vents the gasnot used for fuel and tries to maintain theformation back pressure as close as possibleto zero. Information on this procedure isprovided in Chapter 11, Section B, Engines.

Normally, the lease pumper is on the sitefor no more than 8 hours each day. Thus, ifthe pumping unit is started and stoppedmanually, there are a limited number ofpumping schedules that can be used. Thepumping unit can run around the clock,though, as will be explained later, this willnot necessarily result in more oil production.A second option is for the lease pumper tostart the pumping unit just before leaving thelease and shutting it off upon returning the

6B-2

next day. That would result in the unitrunning for approximately 16 hours, whichagain means little effective oil production.Finally, the lease pumper can run thepumping unit during normal working hours.The lease pumper could, thus, have thepumping unit run continuously during thattime or could cycle the pumping unit on andoff during the 8 hours.

A more efficient approach is to use anengine control. These devices allow theengine to start and stop without the leasepumper being present.

Engines offer opportunities that are notavailable with electric motors. The pumpcan be set to within 1 inch of tappingbottom. Thus, when the pump no longerpumps oil, increasing the RPM of the enginewill allow the pump to tap bottom due to therod having stretched. Once the pump hasbeen restored, the RPM can be readjusted toprevent the pump from tapping bottom.

Pumping unit engines must be properlytuned at a level of dependable operation. Apoor maintenance program will result in lostproduction and add a lot of duties to thelease pumper’s busy schedule.

B-3. Pumping Schedules.

Determining how long to run the pumpduring a 24-hour period and the ideal cyclingschedule can be difficult. For example, ifoperating a well that produces oil and water12 hours per day leads to maximum oilproduction, there are a number of ways toachieve a 12-hour runtime, including:

· 12 hours on and 12 hours off· 6 hours on and 6 hours off in two cycles· 2 hours on and 2 hours off in six cycles· 1 hour on and 1 hour off in 12 cycles· 30 minutes on and 30 minutes off around

the clock· 15 minutes on and 15 minutes off around

the clock

While the well is off, the liquid levelbuilds up in the bottom of the hole in thecasing. As it builds higher, the weight of thecolumn builds up backpressure. Asbackpressure increases, the rate at which oilenters the well from the formation will slowuntil the backpressure equals the hydrostaticpressure of the formation, at which time allmovement will stop. So there is an idealamount of time to allow fluid to accumulate,for beyond that time no more oil will flowinto the well. Thus, running the pump forjust 20 minutes each hour, may result in thesame oil production as running the pump for12 hours each day and would require only 8hours of runtime.

By the same token, if the system can pumpthe full accumulation of oil to the surfacewith 30 minutes of operation, there is nopoint in running the pump for an hour at atime.

On the other hand, if the pump is runwithout allowing the full accumulation offluid, the reduced backpressure may allow asteadier flow of hydrocarbons into the well.For example, if the rate of formation flowinto the well drops by approximately halfeach hour until the flow ceases after 18hours and then it takes 6 hours of pumpoperation to remove the accumulated fluid,one pumping plan would be to run the pump6 hours straight each day. However, byrunning the pump more frequently to keepthe backpressure from building up, a higherformation flow rate may be maintained. Forexample, running the pump for 15 minuteseach hour would still total 6 hours ofoperation each day and formation flowwould not cease during the day. As a result,overall production may be higher.

There are other economic factors that mayalso need to be considered. In Chapter 14,Well Testing, additional information isincluded concerning productivity testing todetermine the best way to produce a well.

6B-3

B-4. Automatic Controls.

There are two general types of timingcontrols for pump operation. A 24-hourclock may be used to set the on and offperiods during one day or a percentage timercan be used to regulate the percentage oftime that the pump is on within a givenperiod. Percentage timers are often found inthe newer automatic control boxes instead of24-hour clocks, although both still have theirplace and will continue to be available forspecial applications.

There are several styles of the 24-hourclock. Some are controllable in 15-minuteon-and-off cycles, while others can becontrolled for intervals of 5 minutes or less.These clocks are well suited for settingpumps to run at a specific time of day orwith irregular pumping cycles.

Percentage timers are available in cycles of15 minutes or more. Percentage timers haveone control dial that allows the timer to beset to run a selected percentage of the timercycle. Thus, if a 15-minute timer is set for a50-percent runtime, the pumping unit willoperate for 7½ minutes and then be off for7½ minutes during each 15-minute cycle.Because there are 96 15-minute cycles in aday, the unit will run 7½ minutes througheach of the 96 cycles in a day.

Similarly, if a 2-hour timer is used withthe dial set for 25%, the unit will come onfor 30 minutes and then turn off for 1 hourand 30 minutes, and then come on again.This cycle will be repeated 12 times per day,and the unit will run 12 times per day for atotal runtime of 6 hours or 25% of a day.

B-5. Maintaining the Pumping Unit.

The first step in maintaining the pumpingunit is to set up a good maintenanceschedule in the lease records book and tofollow it. One reason that the record book isso important is that it helps the lease pumper

to use the correct maintenance procedures.For example, the typical supply store willhave many types of lubricants, in variousweights, with different additives, andavailable in tubes, buckets, and other stylesof containers. For each application at thelease site, a limited number of lubricantswill be appropriate to use, and often onlyone that is truly suitable. The lease pumpercannot be expected to remember each typeof lubricant that is required and where itshould be used. By maintaining completeand accurate records, the lease pumper canbe assured of using the correct type andamount of lubricant and will know whenequipment has been lubricated or will nextrequire the lubricant to be changed. Further,the lease pumper can avoid mixinglubricants that may not be compatible witheach other.

The daily inspection. Oil field equipmentis very dependable and can operate for yearsbetween serious problems. Still, the dailyinspection can extend the life of the unit bylocating problems before damage hasoccurred. When making any inspection, thelease pumper should listen carefully with thevehicle radio volume turned completelydown because the sounds a pumping unitmakes can tell a lot about its condition. Theinspection should also include a check forlubricating oil leaks, as well as looking onthe ground for loose objects, such as bolts,nuts, and washers.

The weekly inspection. The steps of theweekly inspection include:

1. Perform the steps of the daily inspection.2. Walk completely around the pumping

unit and observe it in operation.3. Stop at good observation points to watch

assembled parts for one complete

6B-4

revolution, looking for unusual motionand vibration and listening for noises.

4. Check to see that the white line on thepitman arm safety pins is properlyaligned. (See “Pitman arm and gearboxproblems” below.)

The monthly inspection. The steps of themonthly inspection include:

1. Complete the steps of the weeklyinspection.

2. Check the fluid level in the gearbox ifthere is evidence of a leak (Figure 2).

Figure 2. Checking the oil level andcondition in the gearbox.

(courtesy of Lufkin Industries, Inc.)

3. Lubricate worn saddle, tail, and pitmanarm bearings (Figure 3).

Figure 3. Lubricating the saddle and tailbearings.

(courtesy of Lufkin Industries, Inc.)

The three- and six-month inspection. Thethree- and six-month inspections areespecially important. Some new pumpingunits need to be fully lubricated every sixmonths (Figure 4). As the unit gets worn,this interval needs to be shortened to everyfive months and then four months and thenthree months. With some units, lubricationmay be necessary every month, with specialmaintenance attention in between. A part ofthese inspections is performed with thepumping unit in motion, and part of it isperformed with the unit shut down and thebrake lever set.

Figure 2. Checking the oil level in the aircylinder on an air-balanced unit.(courtesy of Lufkin Industries, Inc.)

Pitman arm and gearbox problems. Twoof the most damaging situations that mayoccur to the pumping unit are a pitman armcoming loose and the stripping of gear teethin the gearbox.

When the stroke length of a pumping unitis changed (Figure 5), extreme care shouldbe given to correctly cleaning, lubricating,keying, and tightening the wrist pin on thecrank pin bearing. If the nut should workloose and come off, the hole in the crankwill be damaged, the walking beam twisted,and the wrist pin destroyed.

6B-5

Figure 5. Changing the stroke length.(courtesy of Lufkin Industries, Inc.)

A white line should be painted across oneface of the nut from the safety pin to thecounterweight, and a line drawn for severalinches on the crank. This line allows thelease pumper to recognize any change in thealignment of the components, even if thecrank is in motion. During the dailyinspections afterward, the pumper shouldnote the smallest changes that may indicatethat the nut is loosening. In the first weekafter changing the stroke length, these nutsshould be checked for movement every day.

When checking the oil level in thegearbox, the lease pumper should payspecial attention for the presence of metalflakes in the oil. Small samples can beobtained from the lower petcock or plug. Bywiping the oil on a clean cloth, any metalcuttings can usually be detected. Whenmetal cuttings are detected, the cover shouldbe removed, the gearbox flushed out andcleaned, and new oil added.

Periodically, but at least once per year, thegearbox cover should be removed and theinterior closely examined with a flashlight.Figure 6) This is especially true of chain-driven units. Lubrication troughs should bechecked to ensure that all of the bearings arereceiving a sufficient amount of oil and thatthe oil level is high enough to engage the oildippers and gears. The oil should bechanged and the filter cleaned on a periodicbasis. Gearboxes can also collect water andsludge that should be removed periodicallyfor maximum bearing and chain or gear life.

Figure 6. A gearbox with the coverremoved for inspection.

(courtesy of Lufkin Industries, Inc.)

B-6. Direction of Rotation.

For conventional gear-driven, walkingbeam pumping units, some companieschange the direction of rotation every sixmonths or annually so that the forces thatwear the gears are applied to the oppositesides of the gear teeth. This change of thedirection of rotation is achieved by reversingthe connection of any two wires of the three-phase motor. Consequently, this service isnot possible on pumping units driven bynatural gas engines. With the Mark seriespumping units (see Appendix B), thepumping unit weights must be rising towardthe well head as the pumping unit is running.Chain drive gearboxes also usually requirethat the unit counterweights move in aspecific direction in order for the gearbox toreceive lubrication. The direction of rotationof each pumping unit should be recorded inthe pumper’s field manual so that when anelectric motor is replaced, the lease pumpercan tell the person replacing the motorwhich direction the pumping unit wasrotating before the problem occurred.

6B-6

B-7. Gearbox Oil.

Different styles and sizes of pumping unitsrequire different types of oil in the gearbox.There are also several types of gearboxes.These include single-gear drives, double-gear drives, and chain drives. The gears alsohave dippers that pick up oil on eachrevolution, carry it up, and pour it into atrough so that it can lubricate the four shaftbearings.

Some of the problems that are caused bypoor maintenance are:

· Poor lubrication due to low oil level· Rust as a result of water in the oil· Starting difficulty due to low oil or

overly viscous oil, especially in coldweather

· Poor lubrication due to the gearboxbeing overfilled, resulting in foam

· Sludge accumulation because differenttypes of oil have been mixed, because ofincorrect additives, or because the oil hasaged

· Poor coverage of the gear surfacesbecause the oil is too thin or overheated

· Gear wear due to contaminants such asdirt and bits of metal in the oil

Most of the listed problems can be cured bya proper gearbox flush and oil change.

B-8. Typical Pumping Unit Problems.

There are many indications of problemswith a pumping unit that the lease pumper

must recognize and know how to correct.Chapter 11 includes information about

electricity, automated control panels,electrical problems, and engines as primemovers.

Appendix B provides a review of pumpingunit maintenance information (Figure 7).This appendix includes topics such as stylesand sizes of pumping units, setting andmaintenance requirements, procedures forchanging the stroke and balance, and otheradjustments.Figure 7. Well component manufacturers

and suppliers can provide helpfulinformation about equipment

maintenance, such as the lubricatingpoints shown here.

Appendix F includes mathematicalcalculations needed for topics such ascomputing belt lengths, sheave sizes, andstrokes per minute.

6C-1

The Lease Pumper’s Handbook

Chapter 6Mechanical Lift

Section C

WELLHEAD DESIGN AND THE POLISHED ROD

When a flowing well is converted to amechanical pumping arrangement, anydownhole packers must be removed and atubing holddown installed as requiredaccording to pumping depth requirements.The packer must be removed to lower theformation pressure to stimulate fluids toflow to the well bore because of reducedbottom hole pressure.

A second need is to rebuild the wellhead tomeet pumping needs. Occasionally, apumping unit is installed just to lift waterblankets off the matrix area so that the wellwill flow again. In this situation, a chokevalve will remain after the wing valve andwill be used to control well production.

Special downhole pumps can be installedto handle natural gas along with any oil andwater produced, but in this section astandard pumping arrangement is reviewed.

C-1. Preparing the Well for PumpingDownhole.

Packers are usually removed when thewell is being prepared for mechanicalpumping. Packers are removed to permit gasto be produced up through the annular space.Some style of holddown is required toprevent breathing of the tubing when thewell is pumping. Occasionally, if it is notdesirable to remove the packer, it can just bereleased to allow gas to pass beside it andleft in the hole. The operation of holddownswas reviewed in Section A of this chapter

and will be discussed further in Chapter 17,Well Servicing and Well Workover.

C-2. Pumping Wellheads.

Figure 1 shows one method of connectingthe pumping wellhead on the well. TheChristmas tree has been removed and anadapter flange or bonnet has been installedwith a pumping tee mounted on top. Aquarter-round opening valve and a checkvalve have been installed in the pumping teeand the annular wellhead. These areconnected together with nipples and unions.

The four-way tee on the tubing headerpictured has a flow line pressure safety shut-in mounted on top. If the flow line shouldbecome plugged, freeze, or break, the safetyswitch will shut the well in until it receivesproper attention. The controls reset whenthe well is placed back into production.

Figure 1. Wellhead with tubing andcasing connection and shut-in control.

6C-2

Figure 2. A typical pumping wellheadthat includes a polished rod, polished rodclamp, polished rod liner, rod lubricator,stuffing box, pumping tee, tubing head,

and casing head.(courtesy of Dandy Specialties and Larkin

Products)

C-3. Selection of Polished Rods, Clamps,Liners, and Stuffing Boxes.

When selecting the polished rod and otherwellhead equipment (Figure 2) severalfactors need to be considered. Some ofthese are:

Polished rod. When selecting polishedrods, many people purchase them too short.When working on troublesome wells, thecrew will encounter problems when itbecomes necessary to lower the rod string totag or tap bottom and perform otherservicing functions

The polished rod needs to be long enoughto be able to lower the polished rod liner allthe way to the top of the stuffing box withthe horse head at the top of the stroke. Thetop of the rod needs to extend through thebridle carrier bar with room to install asuitable clamp and additional room abovethe clamp to allow the string to be loweredenough to tag bottom.

With the horse head still at the top and themaximum amount of rod out of the hole, thepolished rod must extend below the stuffingbox far enough to lower the liner all the waydown against the stuffing box.

The polished rod liner. The polished rodliner is placed on the polished rod to protectit from wear. It is easier to prevent stuffingbox packing leakage with a larger diameterliner. The polished rod liner should be aslong as the maximum stroke length plus atleast two feet. If it is too short, it will have atendency to hang on obstacles in thewellhead on the upstroke or will createproblems when trying to tag bottom.

When the clamp above the stuffing box isadjusted, the polished rod clamp on the linermust NEVER be tightened. Every time thisclamp is tightened on the liner, it puts a

6C-3

series of indentations in the liner. Withevery stroke of the pumping unit, a smallamount of oil and compressed gas is lost tothe atmosphere when the damaged section ofthe polished rod liner comes up through thestuffing box. This leakage will continue aslong as the liner is used. The lost oil iscontinuously running down on the stuffingbox and wellhead, creating constant cleaningproblems. The one moment of carelessnessthat put the indentations in the liner cancause problems, time loss, and unnecessaryreplacement expenses.

The polished rod clamp. The polished rodclamp (Figure 3) is used to support the rodstring while the weight is being carried bythe bridle and carrier bar. These clamps areavailable with one bolt or up to four or fivebolts to match the rod load. Occasionallytwo clamps are used on a polished rod forsafety. There may also be a polished rodclamp below the carrier bar. This is acommon practice on wells that have ahistory of polished rod failures with the rodbreaking at the carrier bar. This safetyclamp is installed to prevent the rod stringfrom going through the stuffing box wherethe well may flow. Several spills have beenprevented by this practice.

Figure 3. A two-bolt polished rod clamp.

The stuffing box. In the earlier years of thepetroleum industry, most stuffing boxesused donut-shaped packing. It wasmanufactured with many types of additives,such as graphite and lead, to improve itsefficiency.

Figure 4. Stuffing box with cone stylepacking.

(courtesy of Trico Industries, Inc.)

During recent years, cone-shaped packing(Figure 4) has become very popular, andmany thousands of packing boxes with cone-shaped packing are in service across theindustry. An improved model is on themarket that is virtually leak-proof, though itscost may not be justified for marginalstripper wells.

With a marginal well of medium toshallow depth, the cone style is still highlysatisfactory. If common sense and cautionare used when installing and periodically

6C-4

tightening the packing, a set of packing canlast for several years and have almost noleakage. Various qualities of packing areavailable. By keeping careful records andtracking costs, a lease pumper can determinewhich is the most economical practice in theselection and maintenance of packing. Themost important action, though, is to keep thepumping unit carrier bar well centered overthe hole.

Most stuffing boxes have a grease fittingon the side of the box. If the stuffing box ismade so this fitting points toward thepumping unit, the lease pumper must getbetween the stuffing box and the pumpingunit to lubricate the box. Since this is donewhile the unit is running, the edge of thehorse head can strike the worker on thedownstroke. People have been seriouslywounded in this situation. Even on largeunits, the fitting should always point out orto the side.

The polished rod lubricator. A free-floating polished rod lubricator with wick-action felt wiper pads may be installed onthe polished rod just above the stuffing box.This device supplies additional lubricationto the polished rod and extends the life ofthe packing. When no oil is being produced,this lubrication prevents the polished rodfrom heating up and damaging the packing,so such a lubricator is particularly helpful onwells that produce erratically. Aninexpensive non-detergent oil is satisfactoryfor use.

The rod rotator. One of the by-products ofoil production is paraffin. Paraffin is a waxymixture of hydrocarbons that can coat rods,tubing, valves, and surface pipe internally asthe fluids come into contact with them. Atdepths, the heat of the earth will maintainthe paraffin in a liquid state. However, as

the paraffin rises in the hole with theproduction fluids, it hardens. Paraffin willturn from a liquid to a solid and be depositedin the tubing and on rods.

Figure 5. A rod rotator used to removeparaffin and scale.

One way of combating paraffin buildup isthe use of a rod rotator (Figure 5). The rodrotator is installed on the wellhead andconnected to the walking beam. With eachstroke of the pumping unit, the rotator willrotate the rods a fraction of one revolution.Scrapers are fixed to the rods close enoughto have a slight over-travel with each stroke.As the rods are rotated, paraffin is scrapedoff. There are many styles of paraffin-cuttingpaddles, most of which are flat or circular.

Other methods of dealing with paraffininclude the injection of chemicals andrunning hot oil down the well. Onceparaffin reaches the surface with the oil, it isgenerally addressed with chemicals and/orheat from a heater/treater. Steam is oftenused to remove paraffin from parts such asrods and tubing after it has been pulled andlaid out on racks.

6C-5

C-4. Tubing, Casing, and Flow LineCheck Valves.

Another possible source of problems at apumping unit wellhead are check valves.When trash or scale accumulates under theseat of the check valve or an internal failureoccurs, the check valve may lose its abilityto seal and allow fluid to leak back into thewellbore.

Two wellheads are shown in Figure 6.The one on the left has a working pressureof 300-500 pounds. The one on the right hasa working pressure of 2,000 pounds. Thepressure rating of a valve and screwconnections can be determined by observingthe embossed numbers molded into theforgings. Every lease pumper must be ableto determine fitting pressure ratings bycasual examination.

Both illustrations show all three wellheadcheck valves. One is located on the upper

horizontal line from the tubing just after thewing valve. The second is located directlybelow the upper one in the line from thecasing. This line also has a wing valve.After both lines come together and aredirected toward the tank battery, a thirdvalve and check valve are installed.

The tubing check valve. During certaintypes of productivity tests, it is necessary tocheck the downhole pressure applied to thetubing. For the test to be accurate, thispressure must be isolated from casingpressures. The check valve just past thetubing wing valve prevents casing pressuresfrom flowing back through the bleeder valvewhen the downhole pump action is checkedat the 1-inch bleeder valve next to thepumping tee.

Figure 6. Two pumping wellheads. The one on the left is a medium-pressure unit and theone on the right is a high-pressure unit.

The casing check valve. The casing checkvalve allows the produced gas from thecasing to flow to the tank battery. Thisaction is essential to allow new productionto migrate from the formation into the wellbore, where the gas flows to the tank battery

through the casing and the liquid is pumpedto the tank battery through the tubing.

The casing check valve prevents theproduced liquids pumped out of thetubing—both oil and water—fromcirculating back to the bottom of the well.

6C-6

Even a slight leak in this check valve willresult in loss of new production and willconfuse the pumper as to the amount of oilbeing produced.

The flow line check valve. The checkvalve in the flow line near the wellheadprevents several problems from occurring inthe event that one or both of the wellheadcheck valves fail. If the tubing shoulddevelop a leak, then the weight of the

column may draw the oil in the flow lineback into the bottom of the well. Thesecheck valves can also prevent produced oilin the header from flowing back to the well,and the production from all wells flowingback into the formation.

By configuring these check valvesproperly, the lease pumper can gain a moreaccurate picture of what is occurring at thewell.

6D-1

The Lease Pumper’s Handbook

Chapter 6Mechanical Lift

Section D

THE DOWNHOLE PUMP

In a mechanical lift system, a pump ofsome configuration is required to transferthe oil from the production zone to thesurface. Several styles of pumps are used,but they all have the same basic components.The styles of pumps are then distinguishedfrom each other by the way the componentsare assembled and how they function. Thissection focuses on the similarities anddifferences among the basic styles ofmechanical lift pumps.

D-1. Basic Components of the Pump.

The five basic components of downholepumps are:

· Standing valve.· Barrel tube.· Plunger.·· Traveling valve.· Holddown seal assembly.

Standing valve. The standing valve, at thebottom of the pump, is a one-way valve thatallows fluid to flow from the formation intothe barrel. A standing valve consists of aball that rests on a narrow-lipped seat(Figure 1). This ball and seat assembly iscontained in a valve cage with the ball ontop or up as it is installed in the well.Pressure from below can unseat the ball andallow fluid to move past the valve.However, pressure from above keeps theball seated so that fluid does not leak backpast the valve.

Figure 1. Components of a ball and seatstanding valve.

(courtesy of Harbison Fischer)

The ball and seat are finished to sealagainst each other as a set and sealedtogether as a unit. These paired componentsshould always be kept together. Two sizesof balls are available with each size of seat.These are the standard American PetroleumInstitute (API) size and a smaller alternatesize that allows viscous fluids and debris topass between the valve guides and the ball.Occasionally double valves are installed totry to solve specific problems.

Barrel tube. The barrel is the portion of thepump into which fluid from the formationflows. The barrel may be a separatecomponent that is inserted into the tubing orit may be a portion of the tubing, dependingon the pump design. Otherwise the principaldifferences between different barrels is the

6D-2

type and thickness of metal used and howthe barrel accommodates the plunger used.Typically, pump barrel tubes are available inthree thicknesses: thin wall, standard wall,and heavy wall. The wall material may bevarious grades of carbon steel, stainlesssteel, brass, or Monel and may have chromeplating. The metal may also be treated forprotection against corrosion and chemicalsand hardened for extra strength.

The barrel tubing must be machined forthe installation. This will include the threaddesign and the proper clearances for the typeof plunger used. Some pumps also useliners, which must be accommodated in thebarrel design.

Figure 2. Examples of barrel tubes.(courtesy of Harbison Fischer)

Plunger. The plunger moves the fluid fromthe bottom of the pump to the top of thepump. This movement may be a result ofthe plunger moving within the barrel or dueto the barrel moving around the plunger.Plungers are classified as metallic or non-metallic. Metallic plungers are available ina wide range of metal compositions andtreating procedures similar those used forbarrels.

Clearances between the barrel and metallicplungers are very precise. The clearancesmust be correct after installation in the hole

with the pump temperature normalized tothe bottom hole temperatures.

Barrels and plungers are also selected toresist CO2 and H2S corrosion. The plungermay also be grooved or non-groovedaccording to well conditions.

The non-metallic plungers or soft-packplungers come in various designs of cupsand rings. Ring designs may be referred toas regular flexite, wide flexite, compositionring, soft-packed, and other terms. The soft-pack cup composition and method ofassembly is selected based on wellconditions such as poor lubrication, fluidswith high corrosive or abrasive properties,temperature, and fluid gravity.

Figure 3. Examples of plungers.(courtesy of Harbison Fischer)

Traveling valve. The traveling valve is atthe top of the pump. Like the standingvalve, it is a one-way valve. It allows oil toflow out of the barrel and keeps the fluidfrom flowing back into the barrel. Althoughthe standing valve and traveling valve areseparate parts, for a given pump, these twovalves may be the same size, have the samecomposition, and be interchangeable.Consequently, the construction andoperation are the same as that describedabove with regard to standing valves.

6D-3

Holddown seal assembly. The holddownseal assembly or simply holddown creates aseal between the pump and the tubing. Thereare three types of holddown assemblies: twomechanical and one cup type. These threestyles are shown in Figure 3. Each must beinstalled with an appropriate seating nipplein the tubing string. The seating nipples forthe cup-type assembly are available in twolengths. The short model provides oneseating area, while the longer model isreversible and can be turned around in thetubing to provide a new seating area if theother has been damaged.

Both mechanical and cup styles ofholddowns are satisfactory for manyinstallations, but if the bottom holetemperature is 250° F. or greater, amechanical holddown should be used.

Figure 4. Holddown seal assemblies. Thetwo on the left are mechanical types while

the one on the right is a cup type.(courtesy of Trico Industries, Inc.)

D-2. Pumps Designs.

There are four basic designs of downholepumps, including three styles of insertpumps and one type of tubing pump (Figure5).

Figure 5. Four styles of downhole pumps.(courtesy of Trico Industries, Inc.)

Insert pumps. The term insert indicatesthat the pump has been assembled as acomplete functional pump and inserted into

6D-4

the tubing string. An insert pump may havea moving or a stationary barrel and it may beanchored at the top or the bottom. Thus, thethree styles of insert pumps include designswith:

· Traveling barrel, bottom anchor.· Stationary barrel, top anchor.· Stationary barrel, bottom anchor.

· Traveling barrel, bottom anchorinsert pump. The traveling barrel isvery versatile. It will operate in normalwells, sandy wells, and corrosive wellswith good results. With each stroke, itsurges the fluids around the bottom ofthe pump which reduces the possibilityof sand sticking the pump in the hole.The open-style valve cages provide lessrestriction when pumping heavy crudeoils. The traveling barrel has a greaterresistance against bursting, especiallywhen a heavy barrel is used. One of thedisadvantages of this pump design is thatit will gas lock easier than the modelswith the stationary barrel because thestanding valve is smaller than thetraveling barrel. It is less efficient incrooked holes because the outside of thebarrel wears during operation; therefore,a guide above the pump may benecessary.

· Stationary barrel, top anchor insertpump. With this pump, the holddown isat the top of the pump, so most of thepump hangs below the seating nippleand tubing perforations. This is a goodconfiguration with sandy wells becauseof the swirling action of the fluidsaround the top of the pump while it is inoperation. The pressure inside the pumpbarrel is much greater than the casingpressure outside the pump. This isbecause the inside must withstand the

pressure generated by the column offluid. This limits the depth at which thepump can be safely run. Gas poundingcan also cause the barrel to split. Withshallow (less than 5,000 feet in depth),sandy wells, this pump design can givegood performance.

· Stationary barrel, bottom anchorinsert pump. The stationary barrel,bottom anchor pump is subject tocorrosion and sanding conditions on theoutside of the barrel, but this is generallythe most satisfactory of all of the insertpumps. Because of its design, thestanding valve can be larger than thetraveling valve. The column of fluidinside the tubing supports the outside ofthe pump barrel at all times. Thisreduction in differential pressure resultsin longer pump life and improvedefficiency. This pump is used in shallowto very deep wells. Sand settling aroundthe barrel and scale can make it difficultto pull the pump. This can generally besolved by stripping the well—that is,pulling the rods and tubing at the sametime; also referred to as a stripper job.

Tubing pumps. The tubing pump isdifferent from the insert pump because thebarrel of the pump is run in the hole as partof the tubing string. Usually the standingvalve and the traveling valve are run in onthe rod string. After the standing valve islowered to the bottom of the hole, the rodsturn to release it. The rods are thenpositioned up a few inches, and the pump isready to begin pumping. The standing valvecan be reattached for pulling, servicing, andre-running when pulling rods.

An up-arrow has been added to Figure 5 toindicate the location of the clutch and alsowhere the pump separates to allow it topump. The part above this arrow is the

6D-5

action section. It moves up and down witheach stroke of the pump and contains thetraveling valve and plunger. The sectionbelow this arrow is the stationary section ofthe pump and contains the standing valve.

There are obvious advantages to running atubing pump, such as pumping largevolumes in water flood projects. One of thedisadvantages is the necessity of pulling thetubing string to service the pump barrel Thesecond disadvantage is the high fluid load onthe rod string. This results in additional rodstretch and loss of bottom hole stroke.

Other styles of pumps. Other designs ofdownhole pumps exist. Some are justvariations of those described, while othersmeet the needs of specific installations. Theassistance of a pump manufacturer isinvaluable when planning pumpinstallations, especially for special needs.

Appendices A-1 and A-2 provideadditional information about API numberdesignations.

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7-i

The Lease Pumper’s Handbook

CHAPTER 7

ELECTRICAL SUBMERSIBLE LIFT

A. Electric Submersible Lift1. Electrical Submersible Pumps.2. Advantages and Disadvantages of the Electrical Submersible Lift System.

· Advantages.· Disadvantages.

3. Downhole Components.· Motor.· Protector.· Gas separator.· Pump.· Cable.

4. Surface Components.· Tubing head.· Chart meter.· Control box.· Transformers.· Electrical supply system.

5. Special Surface Considerations.B. Operating Electrical Submersible Lift

1. Well Operation and Automatic Controls.2. The Electrical Submersible Pump Well.3. Continuous Operation.4. Intermittent Operation.5. Servicing the Well When Problems Occur.

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7A-1

The Lease Pumper’s Handbook

Chapter 7Electrical Submersible Lift

Section A

ELECTRIC SUBMERSIBLE LIFT

The previous chapter explained the use ofmechanical lift as a means of bringing fluidsto the surface when bottom hole pressure isnot adequate in a new or previously naturallyflowing well. With time, production maydecline to the point that mechanical lift is nolonger effective. The lease operator may trychanging the mechanical lift system tocompensate for the declining production byadjusting the length of stroke on thepumping unit and changing the sheaves toincrease the number of strokes per minute. Along-stroke pumping unit with lightercounterweights may be installed.

As the production of natural gas and crudeoil continues to diminish and waterproduction increases, particularly in water-driven reservoirs, the lease operator maybegin waterflood, an enhanced recoverymethod in which water is injected into thereservoir at one well to drive hydrocarbonsto other wells (see Chapter 15). However,with time oil production will continue to falland water production will increase. As thisoccurs, the pumping time is increased untilthe lease pumper is producing the welltwenty-four hours a day.

At this time, the most practical way toimprove production is to install a systemwith greater production capability. One ofthe choices, especially in high-volumewaterflood operations, is the electricallydriven submersible pump. A submersiblepump is one that is lowered into the fluid tobe pumped.

A-1. Advantages and Disadvantages ofthe Electrical Submersible Lift System.

Advantages. One of the most importantadvantages to this system is its ability topump very large volumes of fluid at shallowto medium depths. Casing size is also notimportant to being able to pump these highvolumes. As waterflood volumes increase,it is common to pump several thousandbarrels of fluid a day while trying to improveformation sweep efficiency.

This system is easy to adapt to automationand can pump intermittently or continuously.

For shallow wells, the investment isrelatively low.

Disadvantages. The buildup of scaledeposits or gyp can interfere with theoperation of submersible pumps. Also, thecost of electricity can also be very high,especially in remote areas. The system haslimited flexibility under some producingconditions, and the entire system in the wellmust be pulled when a problem isencountered.

A-2. Electrical Submersible Pumps.

An electric submersible pumping unitconsists of an electric motor and a pump(Figure 1). The motor is on the bottom of theassembly, and the pump is on top. Anelectrical line is strapped to the outside ofthe tubing, and the whole assembly is

7A-2

lowered into the hole with the pump andmotor set below the liquid level. As themotor turns, it rotates a stack of liquid-lifting cups or disks in the pump. The morecups that are added, the higher it will lift theliquid.

Figure 1. A motor and pump assembly.(courtesy of Reda Pump Company)

A-3. Downhole Components.

Motor. The first component that is loweredinto the well is the electric motor. Themotor size is designed to lift the estimatedvolume of production.

Protector. The protector is attached to thetop of the pump to seal the motor and allowa drive shaft in the center to drive the pump.

Gas separator. A gas separator separatesthe gas and liquid for pumping.

Pump. The pump is designed to carry thefluid load. The shaft may be of Monel, andthe stages be made of a corrosion- and wear-resistant material. The pump has a rotarycentrifugal action.

Cable. A cable leads out of the top of themotor, up the side of the pump, is strappedto the outside of every joint of tubing fromthe motor to the surface of the well, and isextended on the surface to the controljunction box.

The cable consists of three strands ofcontinuous wire. The cable is flat with thewires side-by-side as it reaches from themotor up beside the pump to the tubing, atwhich point it becomes round. The cablemay have a metal shield to protect it fromdamage.

A-4. Surface Components.

Tubing head. The tubing head is designedto support the tubing string and provide aseal to permit the electrical line to passthrough the head. This seal is usuallydesigned to hold a minimum of 3,000 psi.

Chart meter. An optional component, thechart meter records the daily performance of

7A-3

the well that is easily read and can provideinformation that helps to identify a host ofoperational problems that may occur.

Figure 2. The surface equipment,including the power line, transformers,control box, meter chart, and wellhead.

(courtesy of Reda Pump Company)

Control box. The control box controls theflow of electricity to the pump motor. Itallows the well to be operated continuously

or intermittently or to be shut off. It alsoprovides protection from surges or changesin the electricity that may occur.

Transformers. The transformers are usuallylocated at the edge of the lease site. Theytransform the electricity provided over thepower lines so that it is the correct voltageand amperage to operate the pump motor.

Electrical supply system. This is generallythe commercial power distribution system.The highest available voltage produces themost efficient performance.

A-5. Special Surface Considerations.

Many operators are very innovative wheninstalling a new system. A joint of pipefrom the well to the control panel willprovide a conduit through which to run thepower cable. It will be possible to runvehicles over the conduit, yet not damagethe cable.

A post and hanger near the control panelmay provide a place to hang a few extraloops of the pump cable so that the pumpcan be positioned lower without having tosplice the cable.

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The Lease Pumper’s Handbook

Chapter 7Electrical Submersible Lift

Section B

OPERATING ELECTRICAL SUBMERSIBLE LIFT

B-1. Well Operation and AutomaticControls.

The amount of fluid being produced froma well may require continuous operation allday or it may only require operation for apart of a day. The volume of fluid thatneeds to be produced daily from the well andthe well capacity will indicate the bestoperating practices.

A few years ago most of the automatedcontrols looked very much alike. With thetremendous surge in computer technologyand miniaturization of automationcomponents, new designs come out everyfew months so that equipment controls maynot be recognized without specialinstructions.

Figure 1. A wellhead for an electricalsubmersible pump with a pressure gauge,check valve, union, ball valve, and a hose

for checking production.

The check valve on the wellhead musthold when operating the submersible pump.If the check valve leaks, the liquid can drainback into the formation. This can cause thepump to turn counterclockwise while thewell is shut in. If the power is turned onwhile the pump is spinning in the reversedirection, the sudden torque can cause shaftfailure. The pump would then have to bepulled, repaired, and replaced to restoreservice. The wellhead gauge will usuallyindicate if a problem is developing.

B-2. The Electrical Submersible PumpWell.

The well installation and controls may beexceedingly simple or more elaborate,depending on well depth, type of equipment,and volumes of fluids produced. Figure 1shows an electrical submersible pump wellthat is about as simple as a system can be. Ithas everything that it needs to operate but,on a marginally producing well, would havea minor impact on the lease income in theevent of problems. Higher producing wellswill have more elaborate systems to allowthe pumper to recognize and analyzeproduction problems quickly and moreaccurately in order to reduce downtime.

B-3. Continuous Operation.

A chart can be installed at the wellhead toindicate pump and well performance. When

7B-2

the pump is operating continuously, thechart will have two steady lines on it, oneindicating the casing pressure while it isrunning, and the other the tubing pressure inthe flow line.

When the well is operating normally, thelease pumper should note the normalreading. When the well has problems, therecording chart will aid in identifying thetype of problem that has occurred and whenit began. Without this chart, analysis ofpump performance is more difficult.

Figure 2. A chart graph monitoringcontinuous operation.

(courtesy of Reda Pump Company)

B-4. Intermittent Operation.

When the well is operating intermittently,the casing pressure will increase while thewell is at rest, and the tubing pressure willbe lower. When the well comes on, thecasing pressure will drop as the liquid levelin the casing falls, and the line pressure onthe tubing will increase. A whole series ofdiagrams is available for reference to assist

the lease pumper in making logical decisionswhen the lines on the chart do not follow thenormal operating pattern.

Figure 3. A chart graph monitoringintermittent operation.

(courtesy of Reda Pump Company)

B-5. Servicing the Well When ProblemsOccur.

Special equipment must be brought to thelocation when servicing the well. It is alsorecommended that a special experiencedtechnician be present to make decisionswhen questions arise and to direct theworkover procedure in order to solveproblems.

As the tubing is pulled, the cable clampsand bands must be removed and the electricline spooled onto a special trailer that hasbeen brought to the lease for the workover.As it is run back into the hole after the pumphas been serviced, the electric line is re-clamped to the outside of the tubing.

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The Lease Pumper’s Handbook

CHAPTER 8

HYDRAULIC LIFT

A. Introduction to Hydraulic Lift1. Principles of Hydraulic Lift.2. Designing and Installing Hydraulic Lift Systems at the Wellhead.3. The Insert Pump.4. The Free Pump5. The Jet Pump.6. Advantages and Disadvantages of Hydraulic Lift.

· Advantages.· Disadvantages.

B. The One-Well Hydraulic Lift System1. The One-Well Hydraulic System.2. The Advantages and Disadvantages of the One-Well System.

· Advantages.· Disadvantages.

C. The Central Power Hydraulic Lift System1. Central Power System from the Tank Battery.2. Crude Oil for Power.

· The power oil lines.3. Produced Water for Power.4. Closed Power Oil Systems.5. Analyzing Production and Testing the Wells.

· Modifications to the manifold.·· Advantages and disadvantages.

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8A-1

The Lease Pumper’s Handbook

Chapter 8Hydraulic Lift

Section A

INTRODUCTION TO HYDRAULIC LIFT

A-1. Principles of Hydraulic Lift.

Hydraulic lift is a system where a liquid,usually crude oil, is pumped downhole underhigh pressure to operate a reciprocatingpump or a jet pump. This is a very flexiblepumping system and can be used to producelow- to high-volume wells. This system iscapable of producing a higher volume offluid than the mechanical lift pump.

Hydraulic lift uses a triplex plunger stylepump and pumps oil or water under veryhigh pressure. The pump pressure is usuallybetween 2,000-5,000 pounds per square inch(PSI) and pushes the liquid to the wellheadand downhole to operate the pump.

Figure 2. A high-pressure central powertriplex.

(courtesy of Trico Industries, Inc.)

When liquid reaches the bottom of thewell, it enters the top of the hydraulicallyoperated reciprocating pump (Figure 2). Thereciprocating action of the pump will pullnew oil from the annular space and combineit with the power oil. It is then forced backto the surface and through the flow line tothe tank battery.

Figure2. Illustration of the downstrokeand the upstroke of a hydraulic pump.

(courtesy of Trico Industries, Inc.)

8A-2

The required power oil or produced wateris reclaimed and reused to continueoperating the wells. As an illustration, foreach three barrels of liquid pumped downhole, five barrels will be produced back tothe surface. The additional oil producedrepresents new production and is treated andsold The pump produces oil on both theupstroke and the downstroke, or 100 percentof the time. The pump stroke speed is easilyadjustable by turning a valve.

A-2. Designing and Installing HydraulicLift Systems at the Wellhead.

The hydraulic lift system can be installedin any of several different ways in placingthe liquid under pressure and in wellheadand downhole arrangements. These include:

· Fixed insert.· Fixed casing.· Free parallel.· Free casing.· Jet pump.· Commingled power fluids.· Closed power fluid.

This chapter covers the fixed insert andthe free parallel pump, plus a brief reviewof the jet pump.

A-3. The Insert Pump.

When the first well on the lease isdesigned to operate by hydraulic lift, theoperator must decide if it is to be operateddownhole by a fixed insert or a free parallelsystem. The actual pump is the sameregardless of the system selected, but majorchanges are made in how the two strings ofmoveable pipe are installed and in thewellhead selected.

With the insert design, the pump isattached to the bottom of a small string oftubing, possibly ¾ inch, and is lowered intothe hole inside the 2-3/8-inch tubing. Ametal-to-metal seat on the bottom of thepump seats against the tubing seating nipple.The weight of the small string holds the seatin place. A packer is not used so the gas isproduced up through the annulus, just aswith the mechanical pumping well. It isthen commingled back with the power andproduced fluids at the wellhead and entersthe flow line.

Since the hydraulic pump is lowered intothe well on the bottom of a small string ofupset tubing, a pulling unit is required topull this small string to change the pump inthe well.

Figure 3. Hydraulic pump designs,including a fixed insert design (left) and a

free parallel pump (third from left).(courtesy of Trico Industries, Inc.)

8A-3

Occasionally the pump may collect debrisor trash (any solid objects are referred to astrash) under the pump seat and productionwill lessen or cease. Even the column offluid inside the 2-3/8-inch tubing may belost back into the formation. A lift pistoncan be attached above the top of thewellhead so that power oil may be divertedin under this piston to be able to raise anddrop the small tubing string and pump toreseat the pump. This will remove the trash,and the pump will begin to operate normallyagain. This action by the pumper may benecessary many times in the life of a pump.

The pumping wellhead valve is designedso that a quarter turn of the valve handlechanges both valve openings to the correctposition to achieve this action. Changing itback will restore it to the standard producingposition and allow the pump and smallstring of tubing to drop back to the bottomand re-seat.

A-4. The Free Parallel Pump.

With the free parallel pump system, asmall string of tubing is strapped to theoutside of the tubing string and both stringsof pipe are lowered into the hole at the sametime. After the two strings of pipe havebeen lowered into the hole and the wellheadinstalled, a plug or cap can be removed fromthe wellhead and the pump dropped free-fallinto the tubing.

When the hydraulic valve is opened for thepower fluid to flow into the well, the powerfluid will carry the pump to the bottom. Assoon as it seats in the seating nipple, it willbegin to pump.

The power fluid and the produced fluidswill flow over at the bottom of the tubingstring and be produced to the surfacethrough the small string of pipe that was

attached to the outside of the tubing. Thenatural gas that is being produced will travelto the surface through the annulus space,will be commingled back with the powerfluid and produced fluids as it leaves thewellhead and will flow to the tank batteryjust as it would with any pumping well.

One of the leading advantages of the freepump over the fixed or insert pump is thatno well servicing unit is needed to changethe pump. It can be pumped to the surfaceby switching one valve on the wellhead andcan be changed by one person. After thepump has been pumped to the surface, acatcher mechanism will secure the pump anda small hoist can be used to lift it out of thehole.

When the pump becomes unseated on thebottom due to trash, the same valve can beused to kick the pump up the hole and clearthe trash. The valve is then turned back toits original position to allow the pump toreseat. This action may be necessary manytimes in the life of the pump before it mustgo to the repair shop.

A-5. The Jet Pump.

Jet action is achieved by the use of aventuri tube, which is cone shapednarrowing of the flow path. This causes anincreased flow rate of the fluid, whichcreates a low-pressure area that draws fluidsto it.

The jet pump (Figure 4) offers severaladvantages over the fixed and free pump inspecial situations. It has been installed inmany offshore wells where space is at apremium, and one triplex unit can supportthe need for power oil to several wells. Jetpumps can also be used in horizontalcompletions and with continuous coiledtubing.

8A-4

A-6. Advantages and Disadvantages ofHydraulic Lift.

Advantages. There are some advantagesover other high production systems by usinghydraulic lift. One of them is the ease inchanging the volume of fluid being pumped.A wide range of crosshead plungers andliners are available to change the volume ofpower fluid pumped.

Another advantage includes the highvolume of production that the pump willhandle each day. With the free pump, thelease pumper or a field technician can alsochange the pump without the need forcalling out a well servicing crew and unit.

Disadvantages. Some of the disadvantagesmay be problems in maintaining asatisfactory supply of clean power fluid,downtime due to equipment failure, and thecomplexity of the operations. Multipletubing strings are also needed as well ashydraulic power lines.

Figure 4. Components of a jet pump.(courtesy of Trico Industries, Inc.)

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The Lease Pumper’s Handbook

Chapter 8Hydraulic Lift

Section B

THE ONE-WELL HYDRAULIC LIFT SYSTEM

Figure 1. A single well unidraulic system.(courtesy of Trico Industries, Inc.)

B-1. The One-Well Hydraulic System.

Hydraulic systems are available to serve asingle well or as a central power system thatserves two or more wells. With the one-wellsystem (Figure 1), the hydraulic triplexsystem is placed on the edge of the location.

The power line is run from the hydraulic unitto the wellhead. The produced fluid line,including the commingled power oil, isreturned to the hydraulic system vessel. Thevessel is a three-stage separator. The waterfalls to the bottom and by line heightautomation is dumped into the flow line

8B-2

along with the produced gas to be directed tothe tank battery. The gas comes off the topof the vessel.

The oil in the vessel is first utilized tooperate the hydraulic lift system through aspecial line from the vessel to the triplexpump. It is placed under high pressure bythe triplex pump, piped from the edge of thelocation to the wellhead, and downhole tooperate the pump. The downhole pump,which lifts oil on both the upstroke and thedownstroke, pulls fluid from the formation,where it combines or commingles with thepower oil, and is pumped back to the vesselat the edge of the location.

Any oil above the amount needed tooperate the pump automatically flows outand is commingled with the produced gasand water into the flow line to flow to thetank battery.

To place the system into service, enoughoil must be transported from the tank batteryto fill the tubing with oil, operate the systemuntil it is full of fluid, and send produced oilto the tank battery. A small truck transportwill haul enough oil to activate the system.Manifold bypass systems can be installed atthe tank battery and at the well to make thetransport unnecessary.

After the system has been activated, asmall horizontal vessel will separate theproduced gas and excess liquid and dump itinto the flow line. The vessel retains enough

liquid above the operating system needs toallow the system to operate for a short timewithout running out of liquid. This reducesthe need for pumping or hauling oil backfrom the tank battery.

B-2. The Advantages and Disadvantagesof the One-Well System.

Advantages. There are several advantagesto operating a one-well system over thecentral power type. One is that the triplexequipment is smaller.

A second advantage is that when a triplexproblem occurs and the unit must be shut infor repairs, only one well is shut in. Theother wells on the lease are independent andcontinue as usual.

The length of the power oil line is reducedfrom the distance to the tank battery, to justthe distance across the location.

Disadvantages. A disadvantage is that atriplex must be installed at each location.This also requires a prime mover at everylocation, either mechanical or electric. If itis electric, a power line must be run to everylocation.

Another disadvantage is the purchasingand maintenance of many pieces of identicalequipment that will require maintenance andrepairs.

8C-1

The Lease Pumper’s Handbook

Chapter 8Hydraulic Lift

Section C

THE CENTRAL POWER HYDRAULIC LIFT SYSTEM

Figure 1. Diagram of a central power hydraulic lift system.

C-1. Central Power System from theTank Battery.

Some operators prefer to use a centralhydraulic power system over providing eachindividual well with a separate system. Onetriplex pump may supply power oil for asmany as eight wells, depending upon therequired power oil volume needed. The gasboot in Figure 1 is usually part of theheater/treater, so a power oil tank is needed.

The power oil tank is the last tank in the oilprocessing system and is located just beforethe crude oil stock or sales tanks.

C-2. Crude Oil for Power.

Crude oil is the most common source ofhydraulic power for hydraulic lift. A specialtank to supply this oil is installed in thebattery at the end of the treating system, butjust ahead of the oil sales system.

8C-2

The supply line from this tank is locatedabout two feet below the line where excessproduction equalizes over as sellableproduction. To achieve this reserve thepower oil tank in Figure 1 is taller than thesales tanks.

An emergency power oil supply line isprovided with a valve located about two feetbelow the regular supply line. This givesemergency operating oil for use by openinga valve. After the emergency is over andproduced oil begins to equalize into the salestanks again, this lower line is closed againuntil needed. When needed, additional oilcan be pumped back from a sales tank.

The power oil lines. The hydraulic triplexsystem is located near the tank battery(Figure 2). After the header has beeninstalled near the triplex, a separate poweroil supply line is run to each oil well.Usually a 1-inch line is satisfactory. A flowline is then run from the well back to thetank battery. This means that two linesconnect each well into the system.

Figure 2. The central power systemshowing the oil lines to individual wells.

(courtesy of Trico Industries, Inc.)

C-3. Produced Water for Power.

Some operators have been very successfulutilizing produced water for hydraulicpower. However, to be suitable, the watermust not contain scale and corrosivecompounds that can not be satisfactorilycontrolled.

The advantages of this type of system areobvious at a glance. Water is much easier tocontrol or neutralize than oil. The systemcan draw water by installing a special fittingon the heater/treater or by tapping directlyinto the produced water disposal system.The tank battery does not need to bemodified, and the power oil tank does nothave to be installed.

C-4. Closed Power Oil Systems.

By the addition of a third line installedfrom the surface to the hydraulic pump at thebottom of the well, the power oil iscontained in a sealed system and is retainedand used over and over again.

This type of system can make the wellperform satisfactorily when the producedfluids are too corrosive to be used for power.This system requires that a special power oiltank be installed near the triplex unit to beable to pull power oil as needed, as well asto be able to return it to the tank for re-use.

C-5. Analyzing Production and Testingthe Wells.

To be able to know where production iscoming from and identify productionproblems as they occur, a satisfactorydistribution manifold must be assembled.The diagram on the next page (Figure 3)illustrates a typical installation.

The power oil enters the manifold from thefront lower right corner as shown in the

8C-3

illustration. The first low manifold on theright is the automatic bypass. The secondheader from the right is the individual welltest line. By opening this system, the poweroil will first go through volume regulatingvalves, then through a meter that tracks thenumber of barrels that have gone through itin a given period of time. After the oil goesthrough the back line and comes forwardagain to the selected well header, that valveis opened and the front valve closed so thatthe test can begin. After the test has beencompleted, the valves must be returned totheir original settings.

The five front risers from the left side ofthe manifold are the five wells beingsupplied with power oil from this manifold.

The sixth riser from the left is the test line,which was described above.

Modifications to the manifold. The headermay be modified in many ways to meet theneeds of the lease operator. As an example,openings can be added to allow the injectionof soluble plugs or scrapers to combatparaffin buildup. Treating chemicals mayalso be easily added.

Advantages and disadvantages. Many ofthe advantages, such as having to maintainonly one system, can also be disadvantages,because when shut in for repairs ormaintenance, all systems are down.

Figure 3. Diagram of a central power system supporting five wells. The manifold hasprovisions for testing the wells along with an automatic bypass to use when wells have

problems.(courtesy of Trico Industries, Inc.)

8C-4

9-i

The Lease Pumper’s Handbook

CHAPTER 9

GAS LIFT

A. Introduction to Gas Lift1. The Use of Gas Lift.2. Advantages in Using Gas Lift.3. Setting Up a Gas Lift System.

· Gas compression and distribution.· Control valve.· Packer.· Tubing valves.· The wellhead and the two-pin recorder.

4. How Gas Lift Works.· Sequences in unloading the well.

5. Tank Battery Arrangements for Gas Lift.B. Conventional Mandrels

1. Conventional Mandrel and Tubing Arrangements.2. Placing the Tubing and Valves in Order.3. The Gas Lift Valve.

C. Side-Pocket Mandrels1. The Side-Pocket Mandrel System.2. Producing Oil Through the Casing.3. Continuous and Intermittent Gas Lift.4. The Wireline Machine and Wireline Safety.

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9A-1

The Lease Pumper’s Handbook

Chapter 9Gas Lift

Section A

INTRODUCTION TO GAS LIFT

Figure 1. Diagram of a typical gas lift system.(courtesy of McMurry-Macco Lift Systems)

A-1. The Use of Gas Lift.

Many wells flow naturally withoutartificial stimulation when the well is firstdrilled. As time passes and the reservoir gaspressure drops, oil production begins to slowdown, and the number of barrels of oilproduced daily begins to decline. When gasis introduced into the tubing below the levelof liquid in the hole, the column of fluid inthe tubing weighs less than the bottom holepressure, and the well begins to flow again.

Where gas is available, gas lift is usedextensively in producing wells. Thisadditional stimulation allows the wells toflow again. It is especially popular for wellsthat have marginal flow, providing a littleboost in the daily production that canamount to several barrels.

In offshore production, where every squarefoot of platform costs thousands of dollars toconstruct and space is limited, gas lift isoften used. Gas lift occupies very littlespace at the wellhead, and many directional

9A-2

wells can be drilled close together and easilyproduced. This system is a common choicewhen lift stimulation is desirable offshore.

In other situations, gas lift again becomesa favored option in order:

· To assist a flowing well by increasingproduction.

· To produce wells that will not flowwithout assistance.

· To unload a well that accumulates headsof water so that, after unloading, the wellwill then flow naturally.

· To produce high volumes of water to beused in waterflood.

· To remove solids by back flowingdisposal wells.

This system is also utilized to stimulatewells with a low bottom hole pressure, andwhere water or oil may overload the systemand kill the well. Gas is also used for manyother purposes in different wells, such aschemical injection and water flood.

A-2. Advantages in Using Gas Lift.

Many advantages can be realized with gaslift. No gas is lost to the atmosphere in thisproduction process, and the same gas can beutilized over and over. It is not uncommonfor a gas lift well to produce as few as 40barrels of fluid a day or more than 20,000barrels by producing through the annulusrather than through the tubing. This makesgas lift a very flexible system. There arealso other advantages to the gas lift system,such as:

· Initial equipment costs may be lower thanother systems.

· It costs less to maintain the system.· Equipment is easily installed and

serviced.

· It allows intermittent operation for lowproduction wells.

· The system adapts easily to wellsproducing sand that may damage othersystems.

· Gas lift is well suited for deviated wellswhere rod wear will occur.

A-3. Setting Up a Gas Lift System.

Three major sets of components arenecessary to set up a gas lift system:

· Inlet. A supply of dry, high-pressure gas.· Downhole. Appropriate downhole well

arrangements· Outlet. An appropriate production

handling facility.

Gas compression and distribution. Thefirst step in installing a gas lift system ishaving a large, satisfactory supply of dry,high-pressure gas. If wet field gas is to beused, a scrubber must be installed to removecondensate and water and a compressor tostep the gas pressure up high enough forlease distribution and injection. Drip potsmay also have to be installed to removefallout condensate and water that willseparate under line pressure. The idealsituation is to pipe the wet or rich natural gasto a processing facility to remove all liquids.Then the dry or lean gas is piped back to thegas lift lease for compression and injection.A lease distribution system must supply thegas to each of the gas lift wells.

Control valve. Near to where the line fromthe compressor is connected to the wellhead,a valve is installed in the line to open orclose the gas to the well. A second chokevalve is installed next to the wellhead toregulate or throttle the gas that is beinginjected. This valve will be choked to

9A-3

permit the pumper to inject the minimumamount of gas to obtain maximumproduction.

Packer. A packer is run just above thecasing perforations to isolate the annularspace above the casing and tubingperforations.

Tubing valves. As the tubing is run into thehole, several valves are installed in thetubing string at specific predeterminedlocations along the string. All of thesevalves are located below the fluid level inthe tubing and are spaced several hundredfeet apart. The pressure required to openeach of these valves is pre-determined by themanufacturer by injecting nitrogen into eachvalve.

Figure 2. Diagram of a wellhead with atwo-pin pressure recorder.

(courtesy of McMurry-Macco Lift Systems)

The wellhead and the two-pin recorder. Atwo-pin pressure recorder can be located onthe wellhead to track the gas lift operation inthe casing and in the tubing. It can record

the pressures in the sequencing of the gas liftvalves during the unloading sequence andallow the efficiency of the operation to bemonitored.

The chart is used to calculate how muchgas is being injected, and a choke is used toset the injection rate on the desired volume.Many problems can be detected byexamining the charts—such as lowproduction, cycles that are too long or short,freezing in the injection gas line, etc.

A-4. How Gas Lift Works.

The objective of gas lift is to reduce theweight of the column of fluid in the tubingso that the bottom hole pressure of the wellis adequate to lift the column and toovercome the resistance of the tubing, pipes,and connections. With this reduced weight,natural flow may begin or production mayincrease. The well will continue to flow aslong as fluid enters the well from theformation, and the weight of the column ismaintained light enough to be lifted by thebottom hole pressure.

Sequences in unloading the well. As gaspressure is injected into the casing, the firstor highest gas lift valve opens. As gas isinjected into the column of liquid, thecolumn becomes lighter and part of theliquid flows to the tank battery. After thisfirst stage action, the second valve opens,and another slug or column of oil is liftedout.

After the second column has been liftedout of the tubing the third valve opens, andthe procedure continues until the column offluid in the tubing weighs less than thebottom hole pressure. At this point, the wellwill begin to flow.

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A-5. Tank Battery Arrangements for GasLift.

When changing from a mechanical liftsystem to gas lift, changes may have to bemade at the tank battery to be able to handle

the increased production of natural gas,crude oil, and formation water. Acomparison should be made on all three ofthese handling systems to be sure that thetank battery can handle the increase of fluidswithout overloading any of these systems.

9B-1

The Lease Pumper’s Handbook

Chapter 9Gas Lift

Section B

CONVENTIONAL MANDRELS

When installing the gas lift system, thefirst decision is in selecting either theconventional or side-pocket mandrelarrangement. This section reviews theconventional system, and Section Cdiscusses side-pocket mandrels.

B-1. Conventional Mandrel and TubingArrangements.

Conventional gas lift tubing mandrels(Figure 1) have external ported lugs toaccept the gas valves. The valves areinstalled on the outside of the gas liftmandrel, which is inserted at appropriatedepths in the tubing string. The mandrel andgas lift valves are run into the well as part ofthe tubing string. To service these valves,the tubing string must be pulled out of thehole by a well servicing crew.

The conventional gas lift system will alsohave a packer located just above the casingand tubing perforations. The annular spaceis closed on bottom, so that gas injected intothis area from the gas compressor located onthe surface will cause the system to function.

B-2. Placing the Tubing and Valves inOrder.

The gas lift valves will be a specifieddistance apart and a specified distance offbottom. Before the tubing string is hauled tothe location, the pipe is usually rolled out ona rack and the joints measured and selected

to allow a specific length for each valvegroup.

Figure 1. Examples of conventional gaslift mandrels.

(courtesy of Camco Products and ServicesCompany)

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When the selected pipe is loaded on thetruck, a number 1 is written on each joint. Asoft rope is laid across the loaded pipe toseparate and identify it because this is thefirst pipe that will be run in the hole. Thejoints that are selected for the second valvegroup to be run are then separated. Thispipe is loaded and a number 2 written oneach joint.

The truck is progressively loaded withgroups 3, 4, and so forth until the full stringof tubing has been measured and selected.Every gas lift mandrel will also be identifiedas the valves are assembled and installed onthe mandrel before it leaves the shop.

As this string of pipe and mandrels are runinto the well, each joint is again measuredand listed in the order that they are run. Thisgroup order is maintained every time that thetubing string is pulled and the valvesserviced. This maintains the correct valvespacing to assure that the well will flowcorrectly after the service job has beencompleted, and that the correct valve is inthe designated location. Each gas lift valvewill be custom serviced for a particular welland must be run into the well in a specificorder to obtain the desired service.

B-3. The Gas Lift Valve.

The gas lift valve must be set to openunder a specified pressure. This may beautomated by the use of a spring or, moreoften, a gas-operated bellows.

The upper chamber of the gas lift valve isan open chamber filled with a neutral gasunder pressure. The fill valve is similar to atire valve core and is set to a specifiedpressure, then sealed with a plug.

The lower section of the valve is a bellowswith a round end that is pushed against aseat by the neutral gas pressure on theinside.

Figure 2. Examples of gas lift valves.(courtesy of CAMCO)

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This lower valve is exposed to the annuluspressure of the well. The casing pressureopens the valve to permit gas to enter thewell to commingle with the fluid and makeit lighter.

As the second valve opens and beginsunloading the second section, the upper gaslift valve closes, and all of the lift gas entersthe tubing through the lower valve. As the

third valve opens, the second valve closes,so that the only valve open is the third orlowest valve. This continues until the gasenters the tubing through the lowest valve,and all of the others above this valve areclosed. The well will continue to remain inan unloaded condition as long as gas isbeing injected continuously.

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9C-1

The Lease Pumper’s Handbook

Chapter 9Gas Lift

Section C

SIDE-POCKET MANDRELS

C-1. The Side-Pocket Mandrel System.

The side-pocket mandrel system is popularbecause the valves can be pulled, serviced,and run by using a wireline machine. Thewell servicing unit is not needed, and it isnot necessary to pull the tubing string. Thisis especially popular offshore because of thereduced equipment and personnelrequirements. The procedures for runningand pulling and valves from side pocketmandrels are included in Appendices A-09-01 and A-09-02.

C-2. Producing Oil Through the Casing.

For low- to medium-volume gas lift wells,the gas is injected down the casing annularspace, and the oil is produced up through thetubing. This is the most commonarrangement for gas lift, and this system canbe used on wells producing less than 50barrels of oil per day to those that produceseveral thousand.

For high- and extremely high-volumewells, the gas will be injected down thetubing and the oil will be produced up thecasing through the annulus. Whenproducing through the casing, a packer is notneeded. Some wells using this arrangementmay produce more than 25,000 barrels of oila day. This system can be especiallyproductive in waterflood situations wherethe amount of water being produced dailykeeps increasing.

Figure 1. Examples of side-pocketmandrels.

(courtesy of CAMCO Products and ServicesCompany)

C-3. Continuous and Intermittent GasLift.

Continuous operation is the easiest methodto use in gas lift. With some wells,especially when they produce a high volumeof water, an unloading procedure must beused to make the well flow again. If theflowing condition can be maintained withouthaving to unload the well again, continuousoperation will be more effective (Figure 2).

9C-2

Figure 2. Chart of continuous gas liftoperation.

(courtesy of McMurry-Macco)

Figure 3. Chart of intermittent gas liftoperation.

(courtesy of McMurry-Macco)

For low producing wells where the columnbuild-up between cycles is not very great,intermittent operation is satisfactory.

C-4. The Wireline Machine and WirelineSafety.

The wireline machine can be utilized towork on well maintenance problems otherthan just pulling and running gas lift valves.The wireline tools can also be used to cutparaffin, bail sand, and remove scale withoutpulling the tubing. In flowing wells whereparaffin is a problem, the paraffin can be cutdaily between flow cycles withoutinterrupting production. Safety valves canalso be serviced.

With high production wells, especiallyoffshore units where the well might bedifficult to approach in the event of ablowout or fire, additional safety equipmentis installed. By running two strings oftubing into the top of the well, safety valvescan be installed below the surface to permitthe well to be controlled in case of anemergency.

When working with a wireline machineregardless of the type of work beingperformed (servicing gas lift wells, servicingsafety valves, or running well surveys), thelease pumper must respect the wireline.Never approach it when it is running. Awire loop is dangerous.

.

10-i

The Lease Pumper’s Handbook

CHAPTER 10

THE TANK BATTERY

A. Basic Tank Battery Systems1. Oil Storage at the Drilling Site.2. The Natural Production Curve for a New Well.3. The Very First Production.

· Gauging new production at the well location.· Storing oil in rectangular tanks.· Safety in gauging and testing oil in round vertical tanks.· Gauging procedures and tank charts.· Gauging the holding tank on the location.

4. Storing and Accounting for Produced Crude Oil and Salt Water.5. What Is Produced from the Well?6. Designing a Tank Battery.

· How the tank battery works.· Basic tank battery components.· Flow lines.· Header lines from the wells.· Vessels.

B. Pressurized Vessels1. The Flow Line.

· Laying new flow lines.· Road crossings.

2. The Header.3. Pressurized Vessels.

· Tank battery typical operating pressures.· The emulsion inlet.· The gas outlet.· The drain outlet.· The high oil outlet.· The lower liquid outlet or water leg.· Floats.

4. The Separator.· Operation of the two-stage vertical separator.· Pressure safety devices.

5. The Heater/Treater.· Controlling the height of the water.· The fluid sight glasses.· Backpressure valves for pressurized vessels.

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6. Interior Design of the Vertical Heater/Treater.· Inlet line.· At the bottom.· The oil trip upward.· The water leg.

C. Atmospheric Vessels1. Major Low-Pressure Gas System Components.2. Styles of Atmospheric Vessels.3. Common Lines and Openings of Atmospheric Vessels.

· The emulsion inlet.· The equalizer inlet or outlet (Option 1).· The overflow line (Option 2).· The gas outlet.· The oil outlet.· The side drain outlet (Option 2).· The bottom drain outlet.

4. The Gun Barrel or Wash Tank.5. The Stock Tank.

· Cone-bottomed tanks.· The stock tank openings.· The oil inlet line.· The drain line inside the tank.

6. The Water Disposal Tank.7 The Pit.8. The Dike.9. Vessels Solve Unusual Problems.

D. Emulsion Line Systems1. Emulsion from the Well.2. The Flow Lines and Header.

· The header.3. Chemical Injection at the Header.

E Crude Oil Line Systems and Equipment1. Lines from the Separator.2. Lines from the Separator to the Heater/Treater.3. Lines from the Heater/Treater to the Gun Barrel.4. Lines from the Gun Barrel to the Stock Tanks.5. The Equalizer Line from Stock Tank to Stock Tank.

F. Circulating and Water Disposal Systems1. Produced Water at the Tank Battery.2. Water Separation from the Heater/Treater and the Gun Barrel.

· The gun barrel.3. The Circulating System.4. The Water Disposal Tank.

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5. Solving Circulating and Disposal Problems.· Circulating oil while removing water from the system.· Automatic circulation from the LACT unit.· Emptying vessels for maintenance.· Cleaning tank bottoms.

6. The Circulating Pump.7. Hauling the Water by Truck.8. Water Injection.

G. The Crude Oil Sales System1. The Oil Sales System.2. Selling Oil by Truck Transport.3. Selling Oil with the LACT Unit.

H. Tank Battery Design Review1. What Does a Tank Battery Look Like?2. No Atmospheric Vessels.3. The Tank Battery Producing No Gas or Water.4. The Tank Battery Requiring a Gun Barrel.5. Tank Battery with Two Heater/Treaters and Two Stock Tanks.6. Single Tank with Shop-Made Gun Barrel on Stand.

10-iv

10A-1

The Lease Pumper’s Handbook

Chapter 10The Tank Battery

Section A

BASIC TANK BATTERY SYSTEMS

A-1. Oil Storage at the Drilling Site.

The most logical place to begin studyingthe tank battery is at the wellhead and thedrilling rig where the whole process begins.

Even before running casing, a drill stemtest may be run on a well. This is aprocedure intended to produce the wellthrough the drill pipe. At this point, a testtank is normally used as a substitute for atank battery. If the test shows that the wellmay have commercial potential—that is, thewell will eventually pay for the drilling andoperating costs and make the company aprofit—the casing will be run and set.

After casing has been cemented into placeand perforated and the well has been treated,production can begin. If it is a flowing well,the production may begin by simply openinga choke valve.

Figure 1. A drill stem test is being run atthis drilling rig. Note that gas is beingvented in a flare in the left side of the

photograph.

With some wells, however, the leaseoperator must begin production by callingout a swabbing unit to swab or lift a blanket(or column) of liquid—either water or oil—out of the tubing to reduce the bottom holepressure. This action is intended to reducethe weight of the standing column of fluid inthe tubing so that it is less than theformation pressure, allowing new fluid toenter the well bore at the casing perforation.The weight generated by a column of oil isless than the weight of an identical columnof salt water. By swabbing the water out andallowing the lighter oil to enter at theperforations, the reduced weight of thecolumn may allow the bottom hole pressureto cause the well to flow. If the bottom holepressure is higher than the weight of thecolumn of standing fluid, the well may startflowing without further stimulation.

As the well is swabbed or flowed into avessel, the first tank gauging will usually bedone or supervised by the company drillingor production supervisor or possibly by awell servicing employee. In the end,however, it will become the responsibility ofthe lease pumper to track production,recording the amount of gas, oil, and waterproduced, even if the gas is vented.

Gas will usually be lost to the atmosphereor, in some cases, burned as it is flared. Apin recorder with an orifice plate can beinstalled to measure the true volume.

Since the lease pumper must account forall oil and water produced, these liquids will

10A-2

be produced to a tank and gauged often. Thefluid produced will be measured and thenumber of produced barrels determinedseveral times a day until the well has beencleaned up and a rate of production for theoil, gas, and water has been determined.

A-2. The Natural Production Curve for aNew Well.

When a new well is put on line or beginsto produce oil, the pressure around the wellbore is equal to the pressure throughout thereservoir. As production continues, thepressure in the matrix area and around thewell bore decreases, while the time that ittakes for the pressure to build back up toinitial formation pressure increases,according to formation porosity. As thisoccurs, any new fluids produced must bepushed farther and farther through theformation to enter the well bore. The fartherthe oil must travel, the more time it takes toget to the well bore. The gas may bypassgreat pockets of oil unless the reservoir isvery porous and good production practicesare followed by the lease pumper. Pressureat the wellhead will be reduced, and theamount of oil produced will decline.

Figure 2. Oil production curve.

This is a natural flowing condition for allwells described by the curve in Figure 2. Therates of change will be controlled byformation pressure, the type of drive,thickness of the pay zone, porosity of therock, viscosity of the oil, and many otherfactors.

A-3. The Very First Production.

When producing a new well or an existingwell that has been worked over, chemicalsor muds may initially be produced thatshould not be fed into the tank batterysystem because the mud may fill the totaltank battery facilities and cut off tankoperation. For this reason, an open top tankor other vessel on location may be utilized tohold the initial production.

Gauging new production at the welllocation. The gauging and accounting forproduced oil usually begins at the well site.The use of Kolor Kut or some suitable gaugeline paste will assist in determining theoil/water interface level. As the productionfirst begins, the thief will assist the leasepumper in checking the oil/water ratio andindicate the condition of the tank bottom.The gas production can be measured with asingle-pen recorder and orifice plate at theend of the gas line.

Storing oil in rectangular tanks.Rectangular storage tanks may not have atop. A set of steps will assist in allowingcomfortable gauging of the vessel andchecking of the produced liquids. If no stepsare available, they can be constructed veryeconomically or temporarily borrowed fromanother lease facility.

Safety in gauging and testing oil in roundvertical tanks. Instead of a walkway,

10A-3

round, vertical tanks used to temporarilystore oil usually have a ladder bolted to theside centered on the thief hatch. A metalhoop or band about 30 inches acrossinstalled at the top of the ladder allows thelease pumper to have both hands free forgauging the amount of liquid, using KolorKut paste to determine the oil/waterinterface level, taking a hydrometer readingto check API gravity, obtaining watersamples to determine water weight, andthieving the tank to determine emulsionbuildup on the bottom.

If a metal hoop is not on the tank, one canbe built for only a few dollars. The hoopcan be removed and stored and used againwhen needed. A second option is to utilize asafety belt with side snaps that can befastened to the ladder. The safety belt iseasy to carry and store.

Figure 3. A portion of a tank chart for a210-barrel tank.

Gauging procedures and tank charts. Asshown in the tank chart in Figure 3, tanksare usually gauged to the nearest ¼ of aninch. For a high producing well, gaugingmay be done to the nearest inch. On theother hand, a very low producing well maybe gauged to the nearest 1/8 of an inch. Thiswill permit better tracking of how the well is

producing every day and will aid inindicating production problems. Gaugingprocedures are covered extensively inChapter 12.

Gauging the holding tank on the location.The steps for gauging the holding tankinclude:

1. Gauge and record the total amount ofliquid in the holding tank.

2. Determine the oil/water interface level byusing Kulor Kut.

3. Thief the tank if necessary to check waterlevel, bottom emulsion build-up, and tocheck the API gravity.

Note: Obtaining the gravity, temperature,and water weight may be necessary onlyone time or periodically to establish thequality of oil produced and to identifyproblems in treating.

4. Sample the oil to determine BS&Wcontent.

5. Obtain a water sample to determine waterweight per gallon.

6. Record each gauging time.7. Compute oil and water produced.

Tank charts may not be available fortemporary rectangular or a round, verticaltanks. A tank chart can be developed in afew minutes that will be accurate enough forthe initial calculation of estimatedproduction. If the oil is sold by transportdirect from the location, the oil will beestimated by a chart when loaded, butaccurately metered for number of barrels asit is unloaded. In Appendix F, in the mathsection, computations for making a tankchart are included. For round horizontaltanks, a chart is required. Companies thatlease tanks have charts available.

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A-4. Storing and Accounting forProduced Crude Oil and Salt Water.

The lease operator is required to give adaily, weekly, and/or monthly accounting ofall oil, water, and natural gas that isproduced from every well. This accountingrecord begins the first day that the wellproduces fluid and ends when the well isplugged or taken out of service. Records aremaintained by regulating agencies thatrecord cumulative lists of all oil, gas, andwater produced during the life of the well.

Temporary tanks are likely to be used untila decision has been made concerning thesize of permanent tanks to be installed andwhere the tank battery will be located. Thiswill depend upon the amount of oil beingproduced, how large the lease acreage is, andthe immediate availability of additionaldrilling funds in the event that the well is agood producer.

When the fluids begin to be produced fromthe well, the lease pumper will becomeresponsible for gauging the tank on a regularschedule and accounting for all fluidsproduced. (See Chapter 19, RecordKeeping).

A-5. What Is Produced from the Well?

The goal is to produce and sell crude oiland natural gas. Along with these twofluids, the well will produce BS&W, orbasic sediment and water, which is primarilywater and a little formation sand as well asother compounds and elements. Figure 4illustrates a small part of the byproducts.Some of these byproducts are valuable andare readily purchased by the petrochemicalindustry. Asphalt is used in highwayconstruction, and natural gas can beconverted to synthetic rubber and used togenerate electricity. The textile and dye

industries depend heavily on petroleum, andparaffin is used by many industries. Sulfurand water contribute to the formation ofacids in the well and tank battery and causecorrosion.

Since all of these elements are produced invarying amounts from each well, specificvessels within the tank batteries are designedto accommodate and solve varyingprocessing problems and procedures.

When a well produces a high level ofhydrogen sulfide gas, special gaugingprocedures must be followed for employeesafety. These precautions are in addition tothe usual standards for working aroundnatural gas. The lease pumper must beespecially aware of the dangers of workingwith natural gas and hydrogen sulfide, sincethe pumper works alone most of the time.

A-6. Designing a Tank Battery.

There are many factors to be consideredwhen a tank battery is constructed. The tankbattery must be of a sufficient size to handlethe amount of fluid produced but also tohandle the many problems that might becaused by the quality of the fluid produced.

The wells from one reservoir have manyconditions in common, such as the gravity ofthe oil and temperature. Each reservoir willhave its own characteristics, and each tankbattery is designed to accommodatewhatever is produced to that tank batteryonly. If a reservoir is structured at an angleor on an incline, the upper wells mayproduce oil and gas only, while the wells atthe lower zone may be water drive andproduce a lot of water. Wells in the upperzone may have pressure maintenance whilethose in the lower zone use water drive.When a reservoir is several miles long, thewells at one side and depth vary greatly fromwells at the other side and depth.

10A-5

Therefore, a number of factors influencethe design of the tank battery. The leasepumper must:

· Understand the purpose for the variousvessels that make up a tank battery aswell as what vessels are available forconsideration.

· Know how each vessel is constructed onthe inside.

· Know the location of each vessel withinthe system.

· Know how the vessels operate.· Know problems that the vessels can

solve.· Have good problem-solving skills.

How the tank battery works. The abilityof the lease pumper to understand andoperate the typical tank battery begins byfully understanding the most common tankbattery components and systems, the primarypurpose of each part within the system, whatproblems that it is solving, and how eachpart works. This is the purpose of theinformation in this chapter. Additionalinformation about tank batteries is describedin Appendix C, Additional Tank BatteryInformation.

Figure 4. A tank battery with two watertanks (black), a gun barrel, and two oil

stock tanks (gray).

Basic tank battery components. The mostcommon components in the average or basictank battery include:

Lines from the wells to the vessels:· Flow lines from the wells.· Headers or manifolds to connect the wells

to the separators.· Lines to connect various vessels.

The basic vessels:· Production and the test separators.· Heater/treater.· Gun barrel or wash tank.· Stock tanks.· Water disposal tank.· Earth pits or slush pit.· The firewall, dike, or berm.

The equipment:· Circulating pump.· Chemical injection pump(s).· Vapor recovery unit.· LACT unit (if connected to a pipeline).· Gas measurement and test system.· Containers for end of sales lines (if the

oil is transported by truck).

Appropriate line systems and fittings:· Flow lines from the wells.· Inlet header or manifold to separators.· Crude oil lines from separators to the

heater/treater, gun barrel, and stock tanks.Equalizer lines.

· The high-pressure gas system. Gas linesfrom the separators and heater/treaters tothe sales outlet.

· The low-pressure gas system and thevapor recovery unit.

· The water collection system from thevarious vessels to the water disposal tankand the pit.

· The circulating and vessel emptying orfilling system.

· Sales systems. LACT or truck transport.· Water disposal systems.· Special purpose systems.

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Flow lines. Flow lines may be made of steel,plastic, or fiberglass. Steel lines may bewelded, made of threaded regular line pipe,or upset tubing that has been removed froma well and downgraded. Some lines havegrooved clamps instead of collars. Whenthe line may be subjected to high pressurefrom the well, steel will usually be used.

Fiberglass is frequently used in extremelycorrosive conditions, or polyethylene may beused for lower pressure conditions.Polyethylene has become extreme popularbecause of its low price, ease of use, andlong life.

Figure 5. The header system at a largetank battery.

Header lines from the wells. As the flowlines from each well enter the tank battery,they are lined up to come in parallel to eachother, and a header is constructed to receivethese lines.

The header pictured in Figure 5 has thelines entering from the lower right. Thefluid flows through a valve, a check valve,then turns up through an ell. As the fluidreaches the top of the header, a tee is in theline with valves to the right and to the left.The right-hand line goes to the testseparator, and the left-hand line goes to theproduction separator. Each line has a painted

number or a metal plate on it that identifiesthe well. Note that all the valves are quarter-round opening. As the lease pumper walksalong the header, it is clear at a glance whichvalves are open, which valves are closed,which wells are shut in, and which well is ontest. This is a good construction practice.

As the wells leave the header to enter theprocessing vessels, the vessel may bebypassed or the flow may be directedthrough the vessel. At this point, chemicalis added. By injecting the chemical after theheader but before the emulsion reaches theseparator, the treating process really begins.The second alternative is to inject thechemical at the wellhead. For additionalinformation about chemical injection andtreatment, see Chapter 13, Testing, Treatingand Selling Crude Oil, and Appendix E,Understanding Chemical Pumps.

Vessels. The basic vessels are:

· The regular and test separator.Pressurized. Separates gas and liquid.The test separator is utilized to testindividual wells and the two-phaseseparators are more common than three-phase.

· The heater/treater. May be pressurizedor atmospheric. Heat treats and separatesoil, water, and gas. It is a three-phasevessel.

· The gun barrel or wash tank. Separatesoil, water, and small amounts of gas.Atmospheric. A three-phase vessel.

· The stock tank (s). Stores oil until sold.Atmospheric.

· The water disposal tank. Stores wateruntil it is disposed of or re-injected.Atmospheric.

· The circulating pump. Circulates oil toremove water, clean tank bottoms, andempty and fill vessels.

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· The lined slush pit. Stores producedwater. Limited use now. An emergencyoverflow vessel in some situations.

· The firewall or dike aroundatmospheric vessels. Although the dikeis not a formal tank, it is required aroundmany vessels as an emergency open airtank in the event of leaks and must becapable of containing 1½ times the totalcapacity of all tanks.

Through most of the earlier days of theoilfields, these were the first specializedvessels and components included in astandard tank battery. Today the possibilityof having a tank battery with exactly theseeight components only is rather low. Therule of thumb of what components will beused is governed by the one basic rule: thecomponents that are needed to produce andsell the oil and gas. By the end of the life ofan oilfield, wells may have been producedby two or more methods of artificial lift, andthe tank battery arrangement may have beenaltered or changed several times. The stocktanks may have been reduced to just one. As

production becomes very low and if theformation gas pressure has been almostdepleted, the high-pressure separator is nolonger needed and is removed. As thereservoir is depleted, the expensiveheater/treater may give way to a wash tankor gun barrel or even just a stock tank with awater boot attached to the side to separatethe produced water. Many wash tanks areshop-made out of a piece of casing and canbe very small. They are always taller thanthe stock tank and are easily identified.They may be set on a platform foratmospheric operation. As water flood isadded to stimulate production, these newcapabilities must be added, and, as a rule,water flood is the most common of mostenhanced recovery operations.

Regardless of the controlling factors, thelease pumper must fully understand theoperation of the basic tank battery. On thefollowing two pages is a diagram that showshow these and other components may beconnected in a typical tank battery.

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10B-1

The Lease Pumper’s Handbook

Chapter 10The Tank Battery

Section B

PRESSURIZED VESSELS

This section focuses on the pressurizedvessels and related equipment commonlyused for tank batteries:

· The flow line. From the well to the tankbattery.

· The header. A manifold of all flow linesto the first pressurized vessel.

· The separator. Typically, the firstpressurized vessel in the system.

· The heater/treater. Typically, thesecond pressurized vessel in the system.

The information presented in this sectionis general in nature due to the manyvariations in equipment configurations andspecific uses by different companies.

B-1. The Flow Line.

A flow line is laid from the well to thetank battery. Where there is a long distanceto the tank battery and the production is low,the lines may be joined at some convenientspot so that one line is laid from that point tothe tank battery. This does not present aproblem except when one of the wells needsto be tested. To test wells individually, awell tester, mounted on a small double-axletrailer, can be brought to each location. Thesecond option is to shut one well in whilethe other is being tested. Limiting one flowline to several wells is never an idealsituation but may be the cheapest alternative.

The material selected for the flow linesdepends on many factors. Options include:

· Steel is usually preferred for high-pressure and flowing wells. It can bestandard line pipe, heavy-duty line pipe,or new or used upset tubing. It can alsobe welded, use pipeline couplings, orhave groove clamps. Steel can be plastic-coated to combat corrosion and scaleaccumulation.

· Polyethylene may be selected formedium- to low-pressure lines and can bepractical also when paraffin or scale ispresent. It is especially satisfactory whensteel lines deteriorate rapidly.

· Fiberglass can also be considered whenextremely corrosive conditions areencountered.

Figure 1. Polyethylene line to be laid as aflow line.

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Laying new flow lines. When laying newflow lines, the weather must be considered.If a line is laid straight from one point toanother in hot weather, when it gets cool itwill shrink several feet in length. When itgets extremely cold it will shrink many feetin length. This will cause it to pull so hardthat it will part, or in extremely hotsituations it may buckle. Placing correctslow bends in flow lines can accommodatethis problem, with plastic pipe add a fewslow curves to provide extra line near thedestination points and road crossings.

Road crossings. When crossing a leasewith a flow line, it is always best to lay ajoint of casing across the road and run theline through it (Figure 2). If the ends of thecasing are to be sealed or buried, a vent iswelded to the casing to remove gasses inevent of a line leak. A riser is welded intothe conduit line at each end before it isburied to allow this to occur. All steel linesthat go through a conduit should be coatedand wrapped.

Figure 2. A road crossing for flow line.

B-2. The Header.

As the flow lines approach the tankbattery, they are lined up about 18 inchesapart and enter the tank battery parallel to

each other. As they come up through a riser,a check valve is installed. In the event ahole should develop in a flow line and thischeck valve does not seal, all of theproduction entering the header can flowback through this line and result in a largeoil spill. If the check valve on the casing ofthe well should become locked open, notonly will the well begin to circulate bylosing the produced oil back down the well,but produced oil from the header can flowback down the flow line and also be lostdown the well.

A tee will be installed in multiple wellbatteries, so that the flow may be divertedinto the production or the test separator. Theline to the heater/treater will have aconnection in it to allow the injection oftreating chemical. When injecting thechemical at the tank battery instead of at thewell, it is always injected into the header andusually after the header but before the firstvessel. This is standard procedure.

Quarter-round opening valves—either plugor ball—are more appropriate for the tankbattery than multiple round opening valvesbecause the lease pumper can determine ifthey are open or closed at a glance.

The header should also have a lineinstalled to permit the flow to the separatorto be diverted through a bypass around thevessel. Most vessels must be bypassed whilerepairs or changes are made.

B-3. Pressurized Vessels.

Tank battery typical operating pressures.

· Separators. Separators will have amaximum operating pressure of about100 pounds with a test pressure of 150pounds. Normal operating pressure isfrom 15-50 pounds, 25-35 pounds isabout average. The pressure must be

10B-3

great enough to push the liquid from theseparator into the heater/treater with asmall safety margin.

· Heater/treaters. These vessels are largeraround than separators, so it takes athicker shell to hold the same pressure.Thicker shells raise the cost of the vesselto a much higher level. Fifty poundsoperating pressure is about average with atest pressure of less than 100 pounds for aheater/treater. A higher pressureseparator is usually located ahead of it tolower the operating pressures to savemoney during construction. Verticalheater/treaters are taller than the stocktank and the oil outlet is about the sameheight. One pound of pressure will liftoil about three feet, so 10-15 pounds ofpressure will usually be satisfactory at theheater/treater.

There are several openings and lines thatall pressurized vessels have in common(Figure 3). There are also a few openingsand lines that are normally limited in useand are installed on specific purpose vessels.A good understanding of the purpose andlocations of specific special purpose linesfor pressurized vessels is important to thelease pumper.

The emulsion inlet. The emulsion inlet islocated on the side of the vessel near the topand above the fluid level in the vessel.Some pressurized vessels, such as theseparator, will have a diverter plate on theinside to give the fluids a swirling motionupon entry. This allows the gas to break outof the liquid phase and reduce liquidcarryover into the gas sales. Emulsion inletlines are usually above the operating liquidlevel to prevent loss of liquids from thevessel in the event of line leaks before theline gets to the vessel and siphoning effects.

The gas outlet. The gas outlet is alwayslocated at the center of the top. A mistextractor will be installed inside the vesselto further limit liquid carryover.

The drain outlet. The drain outlet islocated in the center of the bottom.

The high oil outlet (optional). If the oiloutlet is located high on the upper side of thepressurized vessel as it is in theheater/treater, this will be the oil outlet andalso the height of the fluid in the vessel.

Figure 3. Typical line Openings in apressurized vessel.

The lower liquid outlet or water leg. If aliquid outlet is located near the bottom onthe side of the vessel and is utilized as awater leg, this will indicate that the vessel isa three-stage separator. The fluid will beseparated into the base contents, gas, oil, andwater. If a fire tube is also added for heat,then it will become a heater/treater.Heater/treaters are also three stageseparators.

During the summer months, mostcompanies try to use the heater/treater as a

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three stage separator, operating it withoutheat with only chemical treating in order tosave and sell the gas. This procedure workswell for lighter (higher API gravity crude)oils. If the crude oil is heavy and has a highparaffin and water content, the oil may nottreat without heat.

Floats. Floats in vessels may be discriminateor indiscriminate, according to need anddesign. The purpose of a float is to controlthe level of liquid inside a vessel by meansof an outside arm or pneumatic mechanism.

· Indiscriminate floats. Indiscriminatefloats are made to float on both oil orwater indiscriminately. The size of thefloat depends upon the power that ittakes to operate the control arm, theturbulence of the liquid, the volumemoving through the vessel, the length ofthe arm, the weight of the ball, andseveral other factors. The ball float isthe most common indiscriminate float.

· Discriminate floats. Discriminate floatsin the oilfield are floats that have adensity or weight that will allow them tosink in oil but float on water. The floatwill operate on this interface. Since theweight per gallon of oil will varyaccording to the viscosity of the oil, andthe weight of water will vary accordingto how much salt is contained in thewater, discriminate floats are availablewith several densities. Oil will weighover 7 pounds per gallon and water willweigh 8.3-9.6 pounds per gallon. Freshwater weighs 8.3 pounds per gallon andat about 9.6 pounds it begins to reachmaximum natural salt saturation.

Ball floats are usually weighted with sandto allow them to sink through the oil phasebut float in the water phase.

B-4. The Separator.

There are several styles of separatorsclassified by shape and by separationmethod. The basic shapes of separators are:

· Vertical separators· Spherical separators· Horizontal separators

The basic separation methods are:

· Two-stage· Three-stage·· Metering

Operation of the two-stage verticalseparator. The two-stage verticalseparators have historically beenmanufactured in three styles: right-hand,left-hand, and the combination. Thecombination vessel has two identicalemulsion inlet openings, located opposite ofeach other about two-thirds of the way upthe sides of the vessel. All of the otheropenings are standard and this is the onlydifference between them. One of the inletopenings will be selected as the mostappropriate to face the inlet manifold, andthe other will be plugged, usually with a fourinch bull plug. The right and the left handseparators will only have one inlet opening,and these are opposite from the other. Thedesign of a two-stage vertical vessel isshown as a cutaway in Figure 4 and as aphotograph in Figure 5 on the next page.

The gas will rise to the top, go through amist extractor which is built into the top ofthe separator, and enter the gas line. Thisgas pressure is not really high pressure in aliteral sense, because it is usually no morethan 20-50 pounds.

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Figure 4. Cutaway drawing of a verticalseparator showing the operation of the

vessel.

Since the atmospheric vessels will have nomore than a few ounces of back pressure—usually 2-4 ounces—the pressure is high inrelation to the atmospheric vessels, and thispressure is never directed toward anatmospheric pressured vessel.

The dumping of oil and water is regulatedby a float-controlled dump valve. In newerdesigns, this valve draws the liquid from

much closer to the bottom than previousstyles, reducing corrosion problems. Thiswas achieved by adding a short line insidethe separator that ends near the bottom,reducing the amount of corrosive water thatis present below the dump valve outlet.

A pressure gauge is added above thedump valve and a sight gauge glass ismounted to the left of the dump valve. The

Figure 5. A typical two-stage verticalseparator with high-level alarm.

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pressure gauge line turns upward inside asecond short section of pipe that has a capon top. If the liquid level rises all the way tothe gas outlet, none will enter the gauge. Ahail guard is added to protect the sight gaugeglass from being accidentally broken bypeople, animals, or hail. An O-ring is placedon a new sight glass at the fluid level. Aglance at this periodically gives an instantreference to several operating problems. Astring may be tied on the glass to replace theO-ring when it becomes weather crackedand drops off.

The emulsion inlet has a device thatforces the oil to swirl as it enters. Thiscircular action creates turbulence in theliquid phase and accelerates gas breakoutfrom the liquid. This lowers the amount ofmist lost into the gas line.

As the fluid is dumped out of theseparator, it will be directed toward theheater/treater, gun barrel, or a stock tank.The dump valve should be gently tested byhand periodically to be sure that it is stillworking freely and is not becoming frozenin one position. Care must be exercised,because a harsh push may break the float off,necessitating repairs.

The two valves on the sight glass have abuilt-in reamer on the valve seat to keep thehole into the tank open and to removeparaffin or scale that might accumulate.These should be carefully closed and openedperiodically to ream them clean and to keepthe fluid level in the gauge accurate. Thelease pumper can close the bottom gaugevalve and leave the top one open, then openthe drain cock that is screwed into thebottom opening of the bottom valve to flushout the gauge glass. Experience at eachseparator will help determine how often thismay be required. It may be necessary tooccasionally adjust a valve stem packing ifleakage or oil staining should occur.

Some separators have pneumatic insteadof mechanical controls (Figure 6). Note thegas line coming off the top of the vessel tosupply gas pressure to operate the diaphragmoperated dump valve. Since the diaphragmis a medium- to low-pressure automationdevice, a pressure regulator is installed inthe line to reduce the pressure and protectthe valve.

Figure 6. A separator with pneumaticcontrols.

Pressure safety devices. Two types ofsafety devices are placed on top ofpressurized vessels: the pop-off or reliefvalve and the rupture disc or safety head(Figure 7).

The pop-off valve is set near the limit ormaximum pressure that might cause thevessel to become dangerous. The pop-offvalve has stainless steel springs, ball and

10B-7

seat, and other parts to prevent rust fromchanging the setting or making them fail tooperate correctly. The pop-off valve canrelease the excessive pressure and has theability to automatically shut off when thepressure returns to a safe level. It is anautomatic valve requiring little or nomaintenance.

The safety rupture disc is a thin, dome-shaped disc made of stainless steel,aluminum, or, in the case of some olderseparators, brass. The rupture pressure ofthe disc is several pounds higher than thesafety release valve. When the safety releasevalve fails to open and the pressurecontinues to rise above a safe limit, therupture disc will burst, releasing the pressureon the vessel. When the rupture disc bursts,the pressure will continue to be released intothe atmosphere until the lease pumper comesby and shuts in the well or switches from thevessel. For this reason a line from therupture disc may be run to the pit to preventground contamination. But if a line isplumbed from the rupture disc to a pit, itmust be run so that there are no low placeswhere water can collect and freeze duringcold weather.

Figure7. Examples of safety releasevalves and pressure rupture discs.

B-5. The Heater/Treater

The heater/treater (Figure 8) is a three-stage, pressurized vessel with heatingcapabilities, although they are alsomanufactured as atmospheric vessels. To beatmospheric, the stock tanks must be lowenough to allow the oil and water to gravityflow to the stock tank and the water disposalsystem.

Figure 8. A typical verticalheater/treater. The lines can be seen

entering the vessel. The site gauges andfirebox are on the opposite side.

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Three stage means the fluid is removedthrough three lines. In the heater/treaterpictured nearby, the oil, water, gas emulsioncoming into the vessel enters through thehighest line on the right side of the vessel.This should not be confused with the gasline that comes off the center of the top.

The natural gas flows out through the gasline coming off the center of the top of thevessel through the line to the right. Abackpressure valve is installed nearby tocontrol the pressure inside the vessel.

The produced oil flows out the lower lineon the right side of the vessel. about eightfeet from the top. This is the fluid levelinside the vessel. Note that a liquid valvewith a back pressure weight is installedapproximately four feet from the ground.This valve controls the amount of oilstanding in the down comer line and doesnot control the height of the liquid in thetank.

The water comes out of a line on thelower left side of the vessel at 90 degreesfrom the other lines, and the water goes upand spills over the water leg a small distancelower than the oil outlet. The height of thewater in the water leg is controlled by avalve identical to the oil outlet control valve.

The heater/treater is usually the onlypressurized vessel in the tank battery systemwhere the heights of the fluids in the vesselare controlled by line height. The fluidlevels in the gun barrel are also controlled byline height. The water level in the bottom ofthe heater/treater is maintained atapproximately one foot above the fire tube.Oil does, however, come into contact withthe fire tube.Most operators try to heat the producedcrude oil only in the winter. The use ofappropriate chemicals and the heat from thesun is usually satisfactory for treating oil inthe summer months. The firebox can

consume a lot of gas. Selling the gasprovides income toward the purchase of thechemicals. It is a give-and-take situation indetermining when heat is necessary.

Controlling the height of the water.Earlier, the use of the beam balance scale inweighing water and oil was reviewed.Calculations for computing the height of thewater leg is reviewed in Appendix F,Formulas and Calculations.

The height of the water in theheater/treater should be approximately onefoot above the top of the fire tube.

The amount of water in the heater/treateris controlled by raising or lowering theheight of the side boot on the water leg. Ifthe weir nipple is raised in the water legboot, the amount of water retained inside theheater/treater will be higher. If the weirnipple is lowered, the water retained will belower. The total fluid column height willremain constant, controlled by the height ofthe oil outlet opening.

The fluid sight glasses. The lower fluidlevel sight glass should display water in thelower half and oil in the top half. If thelower valve is occasionally closed, it is agood practice to close and re-open the topvalve, and then bleed the lower petcock intoa container. This will effectively clean theglass to allow the liquid level to correctitself. Tie a small rag at this level to indicatefuture level changes.

The top sight glass will have oil in thebottom and gas in the top. It can be cleanedin the same manner.

Backpressure valves for pressurizedvessels. The Kimray diaphragm-operatedbackpressure valves are widely accepted bythe petroleum industry as a dependableautomatic operating valve (Figure 9). It is a

10B-9

very popular selection for controlling theback pressure for the separator, theheater/treater, the emergency vent line, andthe gas purchasing company, and on severalother vessels where a back pressure valve isinstalled. The term backpressure refers tothe pressure in back of the valve. Thevalve that controls pressure after thebackpressure valve or downstream is usuallyreferred to as a regulator.

Figure 9. A diaphragm-operatedbackpressure valve.

(courtesy Kimray, Inc.)

The treater oil and water valves (Figure10) are used to control the dumping of oiltoward the stock tanks and the water towardthe water disposal and injection system.These are basically liquid dump valves. Theinstallation of the valve is shown in Figure11. The drawing shows one method ofsecuring the necessary gas pressure to the oilor water valve that prevents fluctuations ingas pressure from affecting the operation ofthe valve.

Figure 10. Treater oil and water valves.(courtesy Kimray, Inc.)

Figure 11. How the treater liquid valve isinstalled.

(courtesy Kimray, Inc.)

As the oil spills out of the heater/treaterinto the oil line, or water spills over theequalizer riser on the water outlet line, these

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liquids create a downward pressure againstthe valve. When the column of liquid buildsup to about four or five feet in the line, thevalve opens, allowing part of it to flowtoward the next vessel. The height of theline, not the valve, controls the liquid levelin the vessel. As the pressure gets lower, thevalve closes again.

A gas line comes off the top of the vesseland connects to this valve. The purpose ofthis line is to equalize the gas pressure insidethe vessel across the liquid dump valve. If aflowing well opens up or someone opens avalve and a surge of additional pressurecomes into the vessel through the inlet line,this change in pressure will also occur onboth sides of the diaphragm. This change inpressure will have no effect upon theoperation of the valve.

The height of the water leg is determinedby the weight per square inch of the columnof salt water and the weight of the oil on topof the water. The height of this column ofliquid is from the oil overflow outlet to thebottom of the vessel.

In Appendix F, Mathematics, theprocedure for calculating the height of waterlegs is reviewed.

The float-controlled separator dumpvalve pictured in Figure 12 is a popularvalve. The pressure below the seat of thevalve is transferred to the top mechanism ofthe valve. This removes any stress orunusual pressures from being exerted againstthe diaphragms in the valve and results insmooth and dependable valve action.

If the dump valve arm needs to operate inthe opposite direction, remove the bolts inthe top, rotate the top one-half turn, andreplace the bolts. Now the mechanism willoperate in the opposite direction. Thedirection of the arm can also be turned in theopposite direction according to need.

Figure 12. A float-controlled separatordump valve.

(courtesy Kimray, Inc.)

B-6. Interior Design of the VerticalHeater/Treater.

In the past, two types of heater/treatershave been constructed. During the past fewyears, several innovative changes have madethe basic design more efficient, so only onetype is illustrated. This is the style designedfor high water production.

Inlet line. The inlet line enters above thefluid level. The gas, being lighter, flashseparates and goes up through the mistextractor and into the gas line. The liquidfalls to the bottom of the vessel through atube.

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Figure 13. Interior view of aheater/treater.

(courtesy of Sivalls, Inc.)

At the bottom. At the bottom, the freewater that has flash separated continues ondown and out of the vessel through the waterleg, absorbing very little of the vessel heat.The oil migrates up through the watersection, past the fire tube, and is heated as itcontinues to migrate up to the oil section ofthe heater/treater.

The oil trip upward. As the oil travelsupward, it moves from one side to the otherpassing upward through openings, whileany suspended water contacts the plates,separates, and moves back downwardtoward the water leg and on to the disposalsystem. When the oil reaches the top, it fallsinto the oil outlet and on to the gun barrel orthe stock tank. Any new gas that breaks outpasses upward through a provided tube up tothe mist extractor and into the gas system.This tube also equalizes pressure betweenthe upper and the lower section of the vessel.

The water leg. The operation of the waterleg is also visible, and the weight of thewater in the water leg is exactly the weightof the water and oil column inside thisvessel. This three-stage separation is fullycontrolled by line heights instead of adiscriminate float as it is in the free waterknockout. This vessel is one of the mostuseful vessels in oilfields.

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10C-1

The Lease Pumper’s Handbook

Chapter 10The Tank Battery

Section C

ATMOSPHERIC VESSELS

All atmospheric vessels operate atatmospheric air pressure, meaning thepressure of the surrounding air. Atmosphericpressure at sea level is 14.7 pounds persquare inch or 29.92 inches of mercury.Atmospheric pressure decreases with risingelevation. Thus, air pressure on top of amountain is less than that at sea level. Thisis referred to as PSIA, or pounds per squareinch, absolute.

Atmospheric vessels form the low-pressure gas system. Every time thepressure is reduced on hydrocarbons or theliquid is placed in motion, additional gasesbreak out. This goes on continuously. Asmall amount of gas is even entrained withinthe produced water. To reduce the loss ofthe light-end petroleum products fromevaporation and to allow the gas to berecovered, atmospheric vessels operate witha gas backpressure of 2 to no more than 8ounces. The thief hatch has a built-inpressure safety release. The vent line willusually have a 2-4 ounce safety backpressure release valve.

All atmospheric vessels are capable ofwithstanding the pressures generated by theweight of the liquid in the vessel. Theweight of a column of fluid can besummarized as follows:

· Oil. As a rule of thumb, oil weighs 1/3pound per square inch (psi) times thedepth of the column or depth in feet. If atank has 15 feet of oil in it and has a 2-ounce backpressure valve, the weight at

the bottom of the tank is about 5 pounds,2 ounces per square inch, thus:

(1/3 lb/ft x 15 feet) + 2 oz. ofbackpressure = 5 lbs-2 oz. psi

· Water. As a rule of thumb, waterweighs ½ pound per square inch timesthe depth or height of the column in feet.If a tank has 15 feet of water in it andhas a 2-ounce backpressure valve, theweight at the bottom of the tank is about7 pounds, 10 ounces per square inch.

(½ lb/ft x 15 feet) + 2 oz. backpressure =7½ lbs + 2 oz psi = 7 lbs.-10 oz. psi

Figure 1. Tank battery atmosphericvessels including a gun barrel, four oil

storage tanks, and two water tanks.

C-1. Major Low-Pressure Gas SystemComponents.

The major components of the low-pressuregas system (Figure 1) include:

10C-2

· Gun barrel or wash tank. A large three-stage atmospheric separator designed toseparate the fluid produced from the oilwell into oil, gas, and water, as well asbeing the first vessel in the low-pressuregas system (Figure 2).

· Stock tank. Acts as a surge tank at thesame time when a LACT unit isoperating. A vessel to store produced oiluntil enough has been accumulated to sellto the pipeline or transport.

Figure 2. A common arrangement of thegun barrel and stock tanks.

(courtesy of National Tank Company)

· Water disposal tank. A vessel utilizedto hold the produced water (usually salty)until it is re-injected into someunderground formation.

· The lined pit. Formerly called a slushpit when BS&W was drained into the pitand the emulsion burned. Presently,some lined pits are still used to producewater if only a few barrels are produceddaily. Under current regulations the pitstill has a use as an overflow facility.

· The dike or firewall or escarpment.The dike is an earthen wall built aroundthe tank battery atmospheric vessels,designed to contain liquid spills.

C-2. Styles of Atmospheric Vessels.

Atmospheric vessels were made ofredwood for many years. Redwood vesselswere very stable and were not greatlyaffected by corrosion. They did haveproblems, however, in maintaining a waterblanket on top of them and in the groovesbetween the staves. Woodpeckerssometimes made holes in them. The steelbands had to be tightened periodically, andthe tanks had to be re-strapped occasionallyto determine the tank’s capacity. The fewredwood tanks that remain in the oilfieldstoday are generally used as water tanks orgun barrels.

Bolted steel tanks—such as the stock tanksshown in Figure 2—later replaced redwoodtanks, and welded tanks (Figure 3, left) havetaken the place of most of the bolted tanks.Fiberglass tanks (Figure 3, right) are beingwidely used, but may not withstand highwinds when empty. The low, widefiberglass tank is popular for water disposal.Guy lines are placed on most of these tanksfor safety. Rubber and fiberglass liners areoften placed in steel tanks to combatcorrosion. Some paints aid in extendingtank life.

Figure 3. Examples of welded tanks (left)and fiberglass tanks (right).

Atmospheric tanks are selected on thebasis of need for the site and in a size that isappropriate to the production volumes fromthe well. Common capacities include:

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Capacity of selected standard bolted oilfield tanks.

Nominal Size Dimensions Barrelsin Barrels Dia. x Height per Foot

Low 250 15' 4-5/8 x 8' 1/2" 33.11Low 500 21' 6-1/2" x 8' 1/2" 64.91High 500 15' 4-5/8 x 16' 1" 33.11High 1000 21' 6-1/2" x 16' 1" 64.91

Capacity of selected standard welded oilfield tanks (Fiberglass tanks are similar insize).

Nominal Size Dimensions Barrelsin Barrels Dia. x Height per Foot

100 8' x 10' 8.95200 12' x 10' 20.14210 10' x 15' 13.99295 11' x 17.6’ 16.93400 12' x 20' 20.14

C-3. Common Lines and Openings ofAtmospheric Vessels.

Figure 4 shows a diagram of anatmospheric vessel with the typical openingsindicated and labeled. Each opening andcommon design variations are discussed inthe following paragraphs.

The emulsion inlet. The emulsion inlet isusually located on the top of the tank. Awalkway is usually provided and the line hasa quarter-round opening valve, either a plug-or ball-type. A down-comer line is ofteninstalled inside the tank to reduce light-endevaporation and static electricity and theresulting metal loss from electrolysis. Whenseveral wells are producing to the same tankbattery, there will also be a second emulsioninlet from the test three-stage vessel.

Figure 4. Line openings typically used inatmospheric vessels.

The equalizer inlet or outlet (Option 1).This is the highest opening on the side of thevessel. When it is used as an equalizer, itallows one tank to be completely filledbefore the fluid flows through the equalizerline and begins to fill the second tank. Thisusually occurs while the lease pumper is noton site, providing an easy means of toppingoff tanks.

The overflow line (Option 2). This is asecond option for the use of the highestopening on the side of the vessel. When it isused as an overflow line, the liquids can bedirected toward a lined pit or even the waterdisposal tank. This acts as a good optionwhen production may be erratic or whenautomated equipment fails to function asanticipated.

The gas outlet. The gas outlet line islocated in the center of the top of the vessel.It is connected to the low-pressure ventsystem and has a 2-ounce backpressurevalve to reduce light-end evaporation.Without this backpressure, some gas wellswill build production up to a partially full

10C-4

level and then will gradually beginevaporating all of the additional liquidproduction. The lease records will indicatethis problem, and corrective mechanicaladjustments can be performed to stop thisloss of production and income. The secondfunction of the valve is to prevent the tankfrom filling with oxygenated air when thetank is emptied. This can result in anexplosive mixture. The safe tank is onefilled with natural gas.

The oil outlet. This outlet is used as an oiloutlet when the vessel is used as a gun barreland determines the liquid operating level. Itis also used as an oil outlet whenever thetank is used as a skimmer tank for final oilor water removal. Skimmer tanks can behooked up several ways to meet lease needsand resemble a wash tank in assembly.

The side drain outlet (Option 1). Sideoutlet. The side drain outlet is used forseveral important functions such asremoving water accumulated fromproduction or well testing, cleaning oil tolower the BS&W level, and cleaning heavytank bottoms.

The side drain outlet (Option 2). Anotheruse of the side drain outlet is for the waterleg when the tank is used as a gun barrel.

The bottom drain outlet. There are threestyles of tank bottoms. The most commonstyle is flat with the drain line on the side.The two styles of cone-bottomed tanks arereviewed later in this chapter.

C-4. The Gun Barrel or Wash Tank.

An advantage of the wash tank over thegun barrel is that it slows the oil down as itgoes through the vessel. The oil stays in the

wash tank much longer, allowing more timefor the water to drop out. The oil and waterflow into the central flume or side boot,travel downward through a spreader, thenwork their way upward. The water falls tothe bottom and is removed through the waterleg. Any gas that continues to break outgoes up into the low-pressure gas system.

The gun barrel washes the oil to remove asmuch water as possible before the oil goesthrough the oil line to the stock tank. Waterwill continue to drop out of the oil as long asit remains in the tank battery. Even thoughthe system may treat the oil to less than onepercent BS&W before it goes to the stocktank, the stock tanks will need to becirculated periodically to keep the bottomsclean. Clean in reference to tank bottomsindicates that there is less emulsion on thebottom than the level that the pipeline ortransport company requires at the time thatthe oil is purchased and removed.

Figure 5. Atmospheric gun barrel madefrom a vertical separator and a pipe

platform.

The water leg operates in the same manneras the water leg on the heater/treater. In thesystem shown in Figure 5, the gun barrelwas shop manufactured from a used verticalseparator. The operator brought the

10C-5

production line down through the former gasline to the bottom on the inside. The waterleg is made from white PVC line, and thegas line was installed at an angle to the topcenter of the welded 210-barrel stock tankthrough the former safety pop-off opening.

The gun barrel with side boot (Figure 6)has become one of the more popular gunbarrel installations. As shown, the emulsionenters the boot located high on the right sidewhere the liquid and gas separate. Theliquid falls to the bottom in the tube andenters the vessel in the bottom perforatedheader where the oil will begin to make itsway to the upper oil area. The waterremains in the water area at the bottom andgoes out through the side combinationoutlet—that is, the drain and water leg. Ifthe gun barrel uses a standard stock tank, itmust be elevated on a mound of fill toapproximately one foot higher than the stocktanks.

Figure 6. Diagram of a gun barrel with aside boot.

C-5. The Stock Tank.

The stock tank is similar to the gun barrel.Most stock tanks, however, have a strikeplate directly under the thief hatch. This is aplate that the gauge line plumb bob willstrike or bump against each time the tank isgauged. The purpose of this plate is toprevent damaging or punching holes in thebottom while gauging the tank.

There are three styles of stock tankbottoms available: a standard flat bottomand two styles of cone-bottomed tanks.

Cone-bottomed tanks. Cone-shapedbottoms are excellent for circulating andtreating the bottoms (emulsion in the bottomof the tank) for leases with paraffin and alow API gravity oil.

To prepare the site for a cone-bottomedtank, the ground must be tapered at thecorrect angle and a small hole dug exactly inthe center to hold the bottom projection(sump). A satisfactory layer of pea gravel orsand and a double layer of 120-pound felt(tar paper) or other suitable barrier may beplaced on the ground prior to setting thetank. This is a good corrosion barrier andallows the tank to breathe under the bottom,allowing moisture to evaporate.

Figure 7. Style 1 cone-bottomed tank.

The style of tank shown in Figure 7 isoften used, though it is not obviously a cone-bottomed tank. A check of the tank chartwill show that the tank has a cone-shapedbottom because the first ¼-inch reading will

10C-6

contain several barrels of oil. This isbecause the reading must include thecapacity of the cone bottom.

Figure 8. Style 2 cone-bottomed tank.

Figure 8 shows a cone-bottomed tank thatactually has an air space under it. There isalso a metal plate several inches wide thatthe vessel rests on to prevent it from sinkinginto the ground from the weight of the oil.This design is easily recognized because thepipeline connection must be elevated toallow one foot for BS&W and emulsion(Figure 9). These styles of tanks are popularwith the lease pumper because of the easethey present when circulating and cleaningbad tank bottoms.

Figure 9. A Style 2 cone-bottomed tankshowing how the sales outlet is raised

above the BS&W level.

The stock tank openings. The stock tank isan atmospheric vessel designed to hold thecrude oil until enough production has been

accumulated to sell. This may beaccumulated in a few days or may requiremany weeks. This is usually a minimum ofone transport load, which requires a 210-barrel tank. This allows approximately 160-180 barrels to be sold and approaches themaximum weight allowed to be hauled onthe highway. Stock tanks can be purchasedas small or as large as needed.

The stock tank has four possible openingson the sides. One opening, 12 inches off thebottom, faces the front. This is the openingprovided to install the oil sales line. Oil maybe sold by pipeline or by the truck transportload. Illustrations of these two systems areincluded in Chapter 13.

On the back of the tank, approximately 4inches from bottom, is a 4-inch drainopening. This line is connected to the drainand circulating system.

On the front near the top of the tank and at45 degrees to the left and to the right, or justone opening on each tank, there are 4-inchopenings provided to connect the tankstogether with equalizing lines. This willallow a tank to top out or finish fillingduring the hours that the pumper is notpresent, and any additional oil produced willgravity feed over to the next selected tank.When the pumper comes back to the tankbattery, the fill lines are switched so that thefull tank is isolated for final testing, treatingif needed, and made ready to be sold.

The oil inlet line. Some companies install adown-comer line inside the tank on the inletline. Since some welded tanks do not havethreads on the inside of the vessel, the line iswelded inside a nipple where it can belowered inside through the top. One or two½-inch holes are drilled into the down-comer near the top to prevent a siphon effectand to allow any free gas to escape. The linegoes down to within a foot of the bottom.

10C-7

There are several benefits to this line. Iteliminates much of the static electricitycaused by oil dumping into the tankviolently and thus lessens corrosion byelectrolysis. A second benefit is that it stopsthe high splatter effect of the incoming oilstriking the liquid surface and reduces theamount of light-ends going out the low-pressure gas line. A third, and possibly themost important benefit, is that when oil iscirculated, the high volume of liquidentering the tank sweeps up or stirs up theaccumulated BS&W that piles up under theinlet area and assists greatly in keeping thebottoms clean. The rolling action stimulatestreatment and water fallout.

The drain line inside the tank. The drainline opening is located on the back of thetank about 4 inches from the bottom. Thisline should be extended inside the tank untilit is within a foot or so of being under thethief hatch opening. Actually, a series ofvery small holes drilled in the bottom can bebeneficial. An ell is screwed on the end orthe end is turned down to place the openingwithin 1 inch of bottom.

When the well produces paraffin, some ofit clings to the tubing and entrains a smallamount of water. Eventually, the paraffinbecomes heavier than oil and settles to thebottom when it enters the tank. Thisemulsion can build up many inches thick onbottom. When the bottom of the tank iscirculated, a small amount of this emulsionis pulled up. As the less viscous upper oilchannels down, it vacuums out a smallpocket and most of the bottom emulsionnever moves or requires hours to shift.

C-6. The Water Disposal Tank.

The disposal tank (Figure 10) is usually ashort tank that holds a minimum of one

transport load of water or about 200 barrels.This water will usually be pumped down adisposal or a water flood well. The tank isshort to aid in water removal from the tankbattery system. Some are manufactured intwo matching halves for easy shipment andassembly. More extensive informationabout water disposal tanks is contained inChapter 15, Enhancing Oil Recovery.

The water disposal tank has replaced thepit as a general disposal system. This hasbecome common because of environmentalregulations.

Figure 10. A water disposal tank.

C-7. The Pit.

The pit is an atmospheric open tank withearth walls to hold produced water. Manyyears ago it was called a slush pit. The wordslush implies a thick emulsion or one withhigh paraffin content. This word is not usedas often as in earlier years. Historically, theterm slush pit has also been used inreference to the drilling rig pit.

The newer style pits have a plastic liner ormembrane that prevents the earth frombecoming contaminated by the salt and othercompounds contained in the water.Frequently, pits are covered with a net meshfor wildlife safety. Pits will continue to be

10C-8

used in the future for both drilling andproduction operations because they serve asan excellent holding tank in the event ofvessel overflow and may enclose emergencygas flares.

C-8. The Dike.

In some areas, an earthen dike is requiredaround all vessels that contain fluid thatmight contaminate the ground. The holdingcapacity of these dikes is usually one andone-half times the capacity of all the vesselsinside the dike. When a dike is constructed,steps should be installed over the top aswalk paths to prevent people from walkingacross the dike at odd points. Walkingacross these dikes causes continuous damageto the dike so that the top edge wears away.If the walkway is high, safety hand railsshould also be provided.

Figure 11. The dike around a tankbattery should be able to hold a volume

one-and-one-half times the capacity of allof the vessels.

C-9. Vessels Solve Unusual Problems.

Some identical vessels may be installed intwo or more different locations within thebattery or on the lease in order to solvecompletely different, unrelated processingproblems. These uses are not alwaysapparent, especially when a specific type ofvessel is installed in an unusual location.Though the vessel will certainly be there toaccommodate a need and solve a specificproblem, but that problem may be unique tothat battery. The lease pumper should neverbe reluctant to ask what the purpose of avessel is and why that style of vessel wasselected. Understanding these solutions mayhelp the lease pumper to solve similarproblems at a different tank battery.

Consider a few examples. A small vesselor riser may be installed ahead of a liquidmeter just to prevent a slug of gas fromhitting the meter. This is a solution similarto placing the gas eliminator ahead of themeter in the LACT unit. A line heater maybe used to thin fluids near the wells so thatthick emulsion can flow to the tank battery.A line heater may be installed between theheader and the two-stage separator toprevent ice from forming in separators andcausing them to overflow in cold weather.A stock tank may be utilized as a gun barrel.A separator may be used as a scrubber forcleaning firebox gas.

The list of unusual installations containsmany possibilities. It is limited only by thelease pumper’s imagination and knowledgeof vessel performance.

10D-1

The Lease Pumper’s Handbook

Chapter 10The Tank Battery

Section D

EMULSION LINE SYSTEMS

Figure 1. Diagram of tank battery lines with emulsion lines indicated by an E.

D-1. Emulsion from the Well.

When an oil well produces fluid—crudeoil, natural gas, water, and othercompounds—it is generally referred to as anemulsion. When this term is used, itgenerally refers to everything that comes outof the well before the separation processbegins. After the gas is removed, theremaining liquid is usually referred to ascrude oil. This crude oil will possiblycontain a little or a great amount of water.

Water removal is the next step in the treatingprocess in preparing the crude oil for sale.

The emulsion from the oil well or the gaswell determines what the tank battery lookslike, which vessels will be installed, and thesizes of those vessels. A few of the factorsthat control the design of the tank batteryinclude the volume of oil and gas that isbeing produced daily, the number of wells tobe drilled and produced to the tank battery,the gravity of the crude oil, the amount ofwater being produced, the amount of

10D-2

paraffin, the anticipated life of the reservoir,difficulties in treating, and other factors.

One of the most important factors thatmust be determined from the beginning ishow hard it will be to remove enough waterto sell the oil. If the API gravity of theproduced oil is high, this separation isusually relatively simple because the crudeoil is thin and flows easily. A three-stageseparator or the addition of a wash tank is allthat is needed.

If the crude oil has a low gravity, verylittle water is flash removed (removed in justa few seconds or minutes) or is difficult toremove. Additional vessels and processeswill have to be considered for the operation.Once the installation requirements aredetermined, the flow line can be laid andconstruction of the tank battery can begin.

D-2. The Flow Lines and Header.

As the flow lines enter the tank battery,they are usually aligned and oriented withthe vessels so that they are parallel to eachother and approximately 18 inches apart.The distance apart is governed by themakeup arrangement of the header. Byusing a 12-inch nipple and two tees as theheader is made up, the line separation willbe established at 18 inches. Flow lines maybe of steel, plastic, or fiberglass. The lastfittings in the flow line before it connects tothe header are an optional valve, a 6-inchnipple, a union, another 6-inch nipple, arequired check valve, and another 6-inchnipple. At this point, the flow line enters theheader tee.

When an oil leak or line break occurs inthe flow line, the check valve is the onlysafety device to prevent the emulsions fromall of the wells that produce through theheader from flowing back and being lost onthe ground. If the check valve at the tank

battery header should fail and the casingcheck valve at a near-by pumping well alsofail, it is not unusual for most of the dailyproduction from all wells to be lostdownhole into the offending well. Inaddition, there are no indications of anyproblem when inspecting the system. Thewell will show good, strong pump action atthe bleeder valve, although the well is justcirculating.

Figure 2. Flow lines entering the header.Often the lines are numbered like these

for easy identification.

The header. The purpose of the header is tocontrol which crude oil system each wellflows through as the oil progresses throughthe system on its way to the oil holdingtanks.

When the tank battery has only one well, asimple system is provided. When it is amarginally producing well, the system issmall, and, because a lot of time is availableto treat oil, the lease pumper can usuallytreat and sell the oil successfully withminimal facilities.

When all of the production is marginal, thecost of constructing a second productionsystem may never be justified, and thetreating system is a barrel test, a bucket test,or an individual well tester.

10D-3

The important consideration in designingthe header is to stand the valves up wherethey can be inspected at a glance todetermine if each valve is open or closed. Ifthe valves are controlled by automation, atattletale or indicator of some style isusually included in the valve design forvisual inspection in determining if it is openor closed. As a rule, multiple round openingvalves are never used when designing aheader because they lead to mistakes insettings and production problems, loss ofproduction, and spills. Well numbers shouldbe indicated on all header lines.

There are several popular styles ofheaders, and many of them are described inthis manual. Any chosen style is good aslong as the valves are easy to understand.Normally, headers are designed with only aproduction header and a test header. Whena great number of wells are producing to asingle battery, this number will be increasedto three with the wells producing throughtwo production headers, and one testheader.

Figure 3. A three-line header with a four-inch test line (left).

D-3. Chemical Injection at the Header.

Chemical is injected at the tank battery at alocation after the header but before the first

vessel. This is usually just ahead of theseparator. The chemical is added after theheader to ensure that the produced oil getschemical in the event one or two wells areshut in. On large, high-productioninstallations, the chemical will be mixedwell regardless of where it is injected.

Some chemical injectors are simpleinjectors attached to a barrel on a stand.With stripper production, this is stillcommon. The larger installations beingconnected at tank batteries today have a lowtub to catch any drips that may develop.Federal law requires that any tank with avolume of 600 gallons or greater havesecondary containment. The chemical isusually in fiberglass tanks on a stand. Asign instructs the field personnel on the typeof chemical being used, and a tube storingwritten literature about the chemical isattached to the stand. A truck will come byon a schedule and add chemical to the tankas needed.Two chemical injection systems are shownin Figures 4 and 5. The first features thesimple pump system that has been commonfor more than the past fifty years.

Figure 4. A chemical injection systemusing a barrel and pump.

10D-4

The system shown in Figure 5 represents thelatest style of installation that meets presentrequirements for high-volume installations.Note that the system includes severalfeatures to enhance safety and environmentalprotection. Beneath the chemical tanks is adrip and leak collection pan. The signbeneath the tank on the right identifies thechemicals and warns of their hazards.Additional information is contained in a tubenext to the tank. This system worksparticularly well with large headers.Chemical treatment is always required forhard-to-treat oil, so this system will continueto be used for many more years.

Figure 5. The chemical injection systemfor a large tank battery with injection at

the header.

10E-1

The Lease Pumper’s Handbook

Chapter 10The Tank Battery

Section E

CRUDE OIL LINE SYSTEMS AND EQUIPMENT

Figure 1. The crude oil lines in this diagram of a tank battery are labeled with an O.

E-1. Lines from the Separator.

Crude oil lines from the separator shouldlead directly to the stock tank. A divertermanifold is assembled in the line to provideline openings for connections to lead to andfrom specialized vessels, such as aheater/treater or a gun barrel. The crude oilthen continues on toward the stock tank. Thespecialized vessel can then be utilized orbypassed according to need. When water

and paraffin are also produced withmedium- to low-gravity oil, the secondvessel in the system will probably be aheater/treater.

E-2. Lines from the Separator to theHeater/Treater.

For fire safety the heater/treater is locateda minimum of 100 feet from the nearesthatch that contains gas. Although the

10E-2

outside air supporting the flame in theheater/treater must travel through a flamearrester (for fire safety), this distance isalways maintained.

The lines to and from a conventional styleheater/treater (Figure 2) are obvious. Thehighest side line on the right is the inlet.The second line down as seen from thisangle is the oil outlet, and the water comesout the lower left opening. The gas comesoff the top.

On the vessel in the background of thephotograph, the right line is the inlet, thesecond line to the left is the oil outlet, thethird line is the gas line, and the fourth (theone on the left) is the water disposal line.

Figure 2. The lines on theseheater/treaters are color-coded to identify

the fluids they contain.

For the lease pumper, understanding theuse of each line does not create any problem,even if the lines are buried because each one

serves a different purpose. Even a casualexamination of the line and the connectionsthat make up that line will allow the leasepumper to easily identify the purpose of eachline. However, during installation of thevessel, it may be necessary to remove around manway plate and examine the insideusing a spark-proof flashlight to verify thepurpose of each outlet. The manufacturerwill also be able to provide this information.

When the crude oil enters the verticalheater/treater, it travels down to contact aspreader baffle in the lower section of thevessel. A plate welded in the vessel justbelow the inlet channels the incoming oildown a tube, allowing the water to drop tothe bottom of the vessel and out. The oilmigrates up through the water section,contacts the heated tube, and moves upwardthrough the wash section. There, the baffleplates remove most of the remaining water.Water continues to drop out of the oil untilthe time that it enters the sales line.

The horizontal heater/treater, which useselectricity to separate water and oil,dramatically increases the efficiency of theoperation. This type of heater/treater isdescribed in Chapter 13, Testing, Treating,and Selling Crude Oil.

E-3. Lines from the Heater/Treater to theGun Barrel.

If a gun barrel is the next vessel in thesystem, the oil outlet line from theheater/treater drops to ground level andtravels to the gun barrel. The line enters thegun barrel down through a central flume orthrough an external boot arrangement aspictured in Figure 3. In this system, thecrude oil inlet line comes in from the backside, travels up through the 2-inch line, andenters the gas boot from the left side. Theflash separator (the large container on top)

10E-3

allows the gas to break out of the liquid andtravel upward and into the low-pressure gassystem.

Figure 3. The gun barrel crude oil inletboot (center).

The oil then travels downward through theinlet boot, enters the vessel at about the 12-inch level, and travels across the spreader.The spreader is a long horizontal pipe goingacross the bottom of the gun barrel withmany small holes in it to distribute the crudeoil all the way across the vessel. The oilcomes out of the holes and works its way upthrough the water in droplet form. The freewater remains in the lower part of the gunbarrel and travels out through the water legto the disposal system.

As shown in Figure 3, additional supportis often provided to the boot by braces, suchas the V-shaped brace attached to the topedge of the tank to stabilize the boot. Asecond stabilizer is welded to the bootdown-comer and the side of the tank foradditional support.

The line system from the separator shouldalways provide a means of producingdirectly to the stock tanks without goingthrough the heater/treater or the gun barrel.

E-4. Lines from the Gun Barrel to theStock Tanks.

The oil outlet line from the upper side ofthe gun barrel to the stock tank is normallyinstalled directly to the top of the stocktanks. This line may come off the gun barrelat a 45o angle, so the distance is usually onlya few feet away to the first stock tank.

Figure 4 illustrates how the line is installedto allow the oil to flow by gravity feed to thestock tank. A shutoff valve is normallyinstalled just above the stock tank as shown.The line must be of sufficient size to avoidrestrictions and to accommodate production.

Figure 4. The oil line from the gun barrel(left) to the stock tank. Note that the

handle of the valve is perpendicular to theflow of the line, meaning that the valve is

closed.

E-5. The Equalizer Line from StockTank to Stock Tank.

The equalizer line is a line located near thetop edge of the tank at an angle of 45o to theside and approximately 10 inches down.

10E-4

This line connects the two stock tanks. Thisequalizer line allows the lease pumper to topout a tank (fill it almost full) during anytime of the day or during the hours that thelease pumper is off so that the tank is full ofoil when the lines are switched. This savesthe pumper much time, and the tank isalways full when the oil is sold.

There are two ways of installing anequalizer line. Figures 5 and 6 show bothsystems. In the system in Figure 5, the oilmust go to the next tank, while in the systemshown in Figure 6, the oil can go to anyselected tank. Most walkways, however, fitsnugly to the tank so that the secondapproach is not always available. The pipewould occupy part of the walkway space,and this would be a safety hazard.

When the crude oil is sold through apipeline, several valves will have to beclosed, a seal inserted, and the valve handlelocked in a closed position. There are twocommon styles of seals. One is a flat strapthat locks together, and the second is a wireand lead seal.

The gauger will probably seal both thedrain line and the oil inlet. The seal on thesales line will then have to be broken toremove the valve handle. These seals willhave the name of the pipeline company anda serial number stamped on them in raisedletters for identification. After the oil hasbeen sold, the valve is closed and a new sealis put in place to make sure that this valveremains closed when oil is not beingpurchased. All seal numbers are accountedfor, and occasionally the company willrequire that the used seals accompany thesales ticket when it is turned in to the office.

Figure 5. An equalizer system in whichequalizing can be done only to the next

tank.

Figure 6. An equalizer system in whichany of several tanks can be selected for

filling next.

10F-1

The Lease Pumper’s Handbook

Chapter 10The Tank Battery

Section F

CIRCULATING AND WATER DISPOSAL SYSTEMS

Figure 1. Diagram of the circulating and water disposal systems. Water lines are markedwith a W.

F-1. Produced Water at the TankBattery.

Many reservoirs are water driven, soproducing water along with the oil and gas isa common situation. As the amount ofwater produced to the tank battery increases

or is difficult to remove, special vessels,lines, and systems are installed and operatedto assist in the removal and disposal of theadditional water. (Figure 1) Water isremoved by the heater/treater and the gunbarrel by separating the incoming emulsioninto natural gas, crude oil, and water. There

10F-2

are several other vessels that automaticallyseparate out water, but these specializedvessels are beyond the scope of this study.

By raising or lowering the water leg a fewinches, the lease pumper can change theoil/water interface level dramatically insidethe vessel, reducing or increasing theamount of oil held in the vessel. This alsochanges the treating ability. Occasionallythe heater/treater or gun barrel water legmust be adjusted to obtain the best results.

F-2. Water Separation from theHeater/Treater and the Gun Barrel.

The heater/treater and the gun barrelutilize natural forces to separate the oil andwater by line height. With the heater/treaterpictured in Figure 2, the crude oil inlet lineis the upper line on the right side.

After the emulsion enters the vessel, mostof the gas flash separates, and the oil andwater flows downward through a tube. Thewater continues down and out through thewater leg, and the emulsified oil passes bythe firebox on its way back up to the upperoil level at the top. The gas goes out thecenter of the top, then down through theouter right line. The cleaned oil comes outthe lower right or inside line.

The water comes out the lower left line,travels up through the inner tube, spills overthe top, and falls down through the outertube. The upper connection on this linecontains only gas and equalizes the pressurebetween the vessel and the top of the waterleg. This connection also stabilizes the lineand holds it upright. To compute the heightof the water leg line, refer to Index F,Formulas and Calculations.

The height of the liquid inside the oil andthe water outlet lines remains constant atabout 4 feet above the automatic diaphragmcontrol valve. This valve is located within a

few feet of the ground and is controlled by aweight on an arm. Additional weight can beadded but is seldom needed. The level of oiland water inside the vessel is controlled byline height, not by the dump valves.Additional weight is occasionally added tothe liquid dump valve when problems havebeen experienced.

Figure 2. A vertical heater/treater withthe water leg and other lines shown.

The gun barrel. As shown in Figure 3, theemulsion enters the gun barrel through theline on the left side of the flume. The gasbreaks out in the large boot at the top and

10F-3

enters the gas system in the top of the vessel.The liquid emulsion falls down through thelarge tube below the boot to the bottom. Itthen enters the vessel through a spreaderacross the bottom, where the oil works itsway upward through the water inside.

Figure 3. A gun barrel installed as part ofan automated circulating system.

The produced oil flows out through theline on the upper left side close to the topand flows to the stock tank. The watercomes out the lower line in the front, movesupward through the water leg, spills over tothe right, and flows to the water tank to theright. Since the lines are not made of steel, astiff arm stands out from the center of theside of the tank. Vertical pipe saddle/clampssupport the weight of the line and liquid toprevent leaks. The two lines on the leftcenter of the vessel are special purpose, suchas for steaming, hot oiling, pulling oil off touse in treating the wells, injecting water intothe system to be cleaned before disposal, andother special procedures.

F-3. The Circulating System.

The circulating system (Figure 4) moves oilfrom the stock tanks back through theheater/treater or gun barrel to removeexcessive BS&W from the oil.

Figure 4. The stock tank drains are in theforeground while the heater/treater andcirculating pump are in the background.

The circulating system is usually operatedmanually for low-volume stripperproduction. In high-production wells withdifficult-to-treat oil, the system equipment,lines, and vessels are upgraded. The pumpwill come on automatically and circulate thetank bottom back through the heater/treaterfor a short period of time. The frequencyand duration of circulation must be based onproduction needs. This procedure iscontinued day and night until the tank of oilis full and has been isolated for sale.Because of the risk of high-volume fluidloss, the system must be kept in topcondition. Spills can be expensive to clean

10F-4

up. The benefits, however, are enormous insaved treating time and chemicalconsumption. Frequent circulation alonecan often reduce chemical costsdramatically.

F-4. The Water Disposal Tank.

The water disposal tank for a small batteryusually holds the equivalent of one transportload or about 250 barrels. It is usually madeof fiberglass, stands 8 feet high, and has netmaterial or a fiberglass dome across the topfor bird safety. Large tank batteries andlarge water flood projects may have 20-foottall water tanks that hold 2,000 barrels.

A satisfactory set of steps for inspectingand gauging the tank is a necessity.Inspections are to check water levels and theaccumulation of crude oil in the system. Insome closed systems, an oil blanket ispreserved over the water to prevent oxygensaturation, oxygen corrosion, and pluggingproblems downhole. This oil blanket assistsin blocking oxygen/water contact.

Figure 5. The basic water disposal systeminvolves draining the water from the gunbarrel and moving it through a line to the

water disposal tank.

F-5. Solving Circulating and DisposalProblems.

Three processes occur in the water systemand may be going on at the same time:

· The heater/treater and gun barrel areproducing water into the water disposaltank or the pit.

·· A stock tank is circulating the bottom ofthe tank being produced into.

·· The water flood pump is injecting waterback into the formation.

All of these operations occur automaticallyfor planned intervals and durations. Yet thelease pumper must be able to override thesystems, engage the pump to empty anyvessel on location, refill and reactivate anyvessel on the location, and possibly performother functions according to the need of themoment. This requires careful considerationwhen designing the systems. Some systemsare designed for single-purpose conditionsand have no flexibility of action. Othersystems are very complex to achieve thedesired objectives.

It is not usually possible to solve everyproblem easily, but some of the commonproblems that may be encountered are:

Circulating oil while removing waterfrom the system. A good installationallows circulation of a tank bottom withoutinterfering with the normal water disposaloperation. The discharge of water from thethree-stage separation vessels (theheater/treater and the gun barrel) to thedisposal tank should be able to continuewithout interruption while the circulating isin process.

During this dual operation, the leasepumper must ensure that liquids do not buildup in these vessels faster than the vessel can

10F-5

handle them. This results in excessivevolumes of water flowing to the disposaltank. After the circulating is finished, toomuch oil and not enough water are containedin the vessels, throwing them out-of-balanceand possibly causing oil to go down thedisposal system line.

Out-of-balance conditions can occur dueto several reasons, such as:

· Undersized or restricted oil lines.· Undersized or restricted water lines.· Circulating too long in one cycle.· Not enough time between cycles to

permit the vessels to re-balance.· Water production is low so it takes a long

time to re-balance· Water leg is set at wrong level.· Water flood has caused the weight of the

water to change, and the water leg has notbeen re-set to compensate for this change.

Automatic circulation from the LACTunit. When the BS&W level goes upbeyond the set percentage in the LACT unit,the three-way diverter valve willautomatically open and send the oil backthrough the heater/treater for re-cleaning orBS&W removal. When the BS&W level isreduced, the oil will automatically bediverted back through the barrel counter andsales line. The volume of oil diverted mustbe low enough for the heater/treater tofunction with this new volume, in additionto the regular volume produced, and stillremain in balance.

Emptying vessels for maintenance. Anyvessel in the system may need to be emptiedfor repairs. This can be done by openingand closing the correct valves. When drainlines are installed to every vessel, thiscapability to empty any vessel in the systemindividually is built-in. This saves time and

expense when repairs become necessary.Operating without such lines can causemuch higher maintenance expenses and willlead to a system that is inefficient andfrustrating to operate as it consumes toomuch of the lease pumper’s time every timea minor problem occurs.

Cleaning tank bottoms. Cleaning tankbottoms without removing the manway plateusually involves extensive use of thecirculating pump. This function requiresdifferent procedures from the routinecirculating procedure. It might even requirethe use of a flexible hose and a pipeextension that will reach the bottom of thetank and extend out through the thief hatch.It may also require forcing the liquidalternately in both directions—into the tankthrough the line stirring up the bottom—andvacuuming the liquid out for cleaning. Thismay require a portable pump with hoses.

F-6. The Circulating Pump.

The circulating pump is an essential tool tomaintain clean tank bottoms and for sellingcrude oil with an acceptable level of BS&W.Most of the time it is used for cleaning crudeoil, but it can also pump all of the liquid outof any vessel when that vessel must beopened for cleaning or repair. It is alsoutilized to pump liquid back into somevessels as needed when placing them backinto service after repairs. By use of thecirculating pump, the operation of thesevessels may be balanced within hours.

It may also be used to pump all oilcontained in several vessels as well as tankbottoms into one tank in order to sell asmuch oil as possible each month. Withproper installation, for small batteries andlimited operations, it may also be used topump the produced water back into the

10F-6

reservoir for water flood or water disposal.Methods of connecting the pump to allowoperation in either direction are reviewed inChapter 17, in the surface pump section.

F-7. Hauling the Water by Truck.

Produced water is often hauled by truck tothe nearest injection well, which may havetanks located nearby to receive water. Theload of water will range from 160-200barrels. The operator may pay someone elseto dispose of the water or do this on thelease as a water disposal or a water floodproject. Hauling liquids by truck transport isreviewed in Chapter 15, Enhancing OilRecovery.

F-8. Water Injection.

For the small water injection project, thetotal project may be operated by a simplewater-level control switch to turn the pump

on and off. A typical disposal tank switch isillustrated in Figure 6. The pump moves thewater to one or more injection wells. Someof the latest technology involves waterinjection into a currently producing well.Water injection is reviewed in Chapter 15,Enhancing Oil Recovery.

Figure 6. A typical water injection

control.

10G-1

The Lease Pumper’s Handbook

Chapter 10The Tank Battery

Section G

THE CRUDE OIL SALES SYSTEM

Figure 1. Components of the crude oil sales system are marked with an S.

G-1. The Oil Sales System.

The oil sales system (Figure 1) is one partof the tank battery system that must meetspecific regulations. This is because a partof the oil contained in the vessel is owned bythe well operator, but some of it belongs themineral rights owner(s). The oil purchaser,pipeline, or transportation company payseach of these parties separately for the oil

purchased. Regulations governing theaccumulation and sale of crude oil are veryrigid to protect the interests of both parties.

All valves below the liquid level line maybe required to have seals on them, but thesales valves have recorded seals that cannotbe removed without accounting for everyseal. These seals are placed on the salesvalves by the crude oil purchaser, and, if anyare removed, they may have to be saved and

10G-2

turned in to the office for accounting to thetransportation company as to why it wasremoved.

The sales line openings are usually located12 inches above the bottom of the tank.This provides sufficient room below theopening for the emulsion that accumulateson the bottom and cannot be sold. Thenormal field tank has sales openings for 4-inch pipe and, normally, 4-inch pipe is usedin the full sales system.

G-2. Selling Oil by Truck Transport.

Oil is sold by transport when a pipeline isnot available or the cost of installing apipeline cannot be justified. The transporttruck supplies the flexible hoses utilized tocomplete the connection from the truck tothe line opening. A good truck driver willnot lose more than a few drops of oil whenthe loading has been completed.

The tank battery pictured in Figure 2 hastwo tanks, one for water and one for storingproduced oil. The two lines are connected tothe tank at the 12-inch level. The oil tankhas a seal that was placed on it by thecontracted oil purchaser, but if the watertank has a seal, it would be put on by the oiloperator.

Figure 2. A tank battery set up fortransporting oil by truck.

Both tanks have separate lines and a box tocatch any spilled oil or water from theloading process. Most operators requiretheir lease pumper to be present when oil issold. When water is hauled, it is notnecessary that the lease pumper be present.

A mailbox (Figure 3) is provided for theconvenience of the transport driver and thelease pumper so that they can communicatewith each other. The transport driver has aplace to leave the load ticket, and thepumper can communicate where and whenthe next load will be available.

Figure 3. A mailbox is provided to allowcommunication between the transport

driver and the lease pumper.

Note that a riser is located to the left of theoil sales line valve on both tanks. Thisallows the tanks to be switched from theground and reduces the amount of time thatthe lease pumper must spend near the thiefhatch opening, especially when the tankcontains a high level of hydrogen sulfide.

A grounding post is provided near the hoseconnection box to give the truck driver agood, stable connection to ground the truckbefore the oil or water loading processbegins. This reduces the possibility of aspark occurring in the area of the liquidopening.

10G-3

G-3. Selling Oil with the LACT Unit.

Selling oil by the use of a Lease AutomaticCustody Transfer Unit (Figure 4) is an idealmethod for selling oil. In this system, the oilsales line is always left open to the stocktanks. The stock tank then acts as a surgetank since the LACT will operateintermittently.

As fluid builds up in the tank, a switchsends a signal to the LACT unit so that itwill come on and begin selling oil. As thefluid gets low in the tank, it will shut theunit in, and no more oil will be sold until thelevel comes back up and the cycle beginsagain.

The sale cycle will continue as long as thetank battery is producing pipeline oil. Thisterm indicates that the BS&W level is lowenough for the oil to be acceptable. If theBS&W level should get high enough that theoil is no longer acceptable pipeline oil, theBS&W diverter valve will open and send theoil back to the heater/treater.

The detector probe on the riser of the inletline of the unit will continue to reject thepurchase of additional oil until pipeline oil isagain detected. At that time the detectorprobe will send a signal to the diverter valveto change to the sales position, and sales willbegin again..

The reading on the sales meter will berecorded daily. The BS&W sampler must beblended or mixed periodically and theaverage determined. This correction factorwill be effective for all oil sold since the lasttime that it was averaged. Since the oilcontained in the sampler is owned by theproduction operator, the sample will becirculated back into the upstream sales lineor stock tank.

A second factor that must be used todetermine how much oil has been sold is thepositive displacement meter test. Thenumber should approach 1.0000 but willgenerally be a little over or a little under,such as 0.9997 or 1.0009. These tests areperformed by a meter testing company usinga trailer-mounted meter prover or a mastermeter with its own meter factor. The oilsales opening is normally placed one footabove the bottom of the tank. The primaryautomatic on/off control switch for theLACT unit is usually installed on the side ofthe tank approximately 2 feet off bottom.This allows the pump to operate withoutdanger of drawing natural gas into the saleslines. For safety purposes a secondarycontrol switch may be placed 1-2 feet abovethe primary switch. This added safetygenerally results in a dependable system.

Figure 4. Two views of a Lease Automatic Custody Transfer System.

10G-4

10H-1

The Lease Pumper’s Handbook

Chapter 10The Tank Battery

Section H

TANK BATTERY DESIGN REVIEW

H-1. What Does a Tank Battery LookLike?

As indicated throughout this chapter, atank battery is designed to meet theparticular needs of the hydrocarbons cominginto it. Part of the production characteristicsthat affect the design of the tank batteryinclude:

· How many barrels of oil are producedeach day? This regulates the size of thetanks installed.

· How is the oil sold? How long is thetank unavailable due to being sold bypipe line? This helps determine howmany vessels are needed.

· How much gas is being produced andwhat is the shut-in pressure? Thisregulates how many pressurized vesselswill be required, and what pressure rangethe vessels may be subjected to. Theamount of gas also determines whetherpressurized vessels are required at all.

· How much water is being produced andwhat is the salt content?

· What is the gravity of the oil? Is it thinand fluid or thick and viscous when it isproduced cold? How much paraffin,asphalt, or sand is being produced? Howdifficult is it to remove the sand,especially fine sand with paraffin? Howdifficult is it to treat the oil?

· How corrosive is the water and whatother unique problems are encountered?

H-2. No Atmospheric Vessels.

When wells produce pipeline oil with nowater or paraffin, they can be flowed directlythrough the separator, through a LACT unit,and into the pipeline. The tank battery inFigure 1 contains a large horizontal standardseparator, a test separator, and a LACT unit.There are eleven flowing or gas lift wellsand no atmospheric vessels. It alsoeliminates the need for the circulating pump,water disposal and injection system, and allof the problems associated with oil treating.

The daily production is automaticallytransmitted to a computer and, if anythingunusual occurs in the daily production, analarm will be automatically recorded.

Figure 1. An 11-well tank battery thathas no stock tanks due to selling the oil

directly through a LACT unit.

Figure 2 shows a second view of the sametank battery displaying the positive chokeslocated on the upper left corner of theheader, the two separator lines with the

10H-2

smaller test line, and an innovativeinstallation. An oil-saver hopper is locatedon the vertical line just below the positivechoke. Any residue oil can be poured intothe hopper and re-injected into the system bygas pressure through the 2-inch line actingas a volume tank by closing the choke valveand opening another.

Figure 2. A close up of the header andthe oil-saver hopper used on the tank

battery shown in Figure 1.

H-3. The Tank Battery Producing NoGas or Water.

The tank battery pictured in Figure 3shows the classic design for a one-vesseltank battery. It illustrates how simple a tankbattery can be. The oil is hauled bytransport. Only traces of gas are producedbecause none is being sold. The well doesnot produce any water and has a deluxeladder and walkway installation. At thesame time, it is not apparent whether theunit is an oil tank battery, a distillate (orcondensate) tank battery, or a water tankbattery from a gas well. A gas well thatproduces water but does not produce anydistillate or condensate will look exactly likethe pictured tank battery so that it will benecessary to read the sign on it or thief the

tank or check the lease records to determinewhat type of tank battery it is.

Figure 3. A single vessel tank battery.

H-4. The Tank Battery Requiring a GunBarrel.

Figure 4 illustrates a tank battery with agun barrel, two stock tanks, and one watertank. An air tank is installed with a reel-typehose for connecting to the breather mask.The low battery walkway has ladders at bothends, and the ladder on the gun barrel isdesigned to permit easy analysis of thisvessel. The warning gate for the gun barrelis not installed.

Figure 4. A gun barrel with two stocktanks and a water tank.

10H-3

H-5. Tank Battery with TwoHeater/Treaters and Two Stock Tanks.

The tank battery in Figure 5 is designed withtwo heater/treaters and no gun barrel. Theheater/treaters are of different sizes, so thesmaller one is the test vessel. Since onlytwo tanks are on the location and the surfacelines indicate that the tank battery produceswater, it is easy to tell which tank is for oiltank and which is for water.

In all likelihood, the crude oil beingproduced to this tank battery has an APIgravity of 30 or less. The oil is probablyrelatively difficult to treat, and heat wouldpossibly be needed all winter but not duringthe summer months. If the emulsion wereslow to break, a gun barrel would also beneeded.

Figure 5. A tank battery with two 500-barrel stock tanks, two heater/treaters,

and two gas sales meters.

H-6. Single Tank with Shop-Made GunBarrel on Stand.

This method (Figure 6) is used withextremely low producing tank battery withonly one well. The operation of the shop-made gun barrel is easy to trace, and thelease pumper will understand the operationof the system at a glance with no instruction.

Figure 6. A single vessel tank batterywith a shop-made gun barrel and a

covered pit.

The single-tank does have a backpressure

ounce valve on the gas line to reduce liquidloss and the resulting reduction of gravitybecause of this loss.

A tank battery is designed to meet theneeds of each group of wells, so that eachinstallation is somewhat unique, thoughwell-planned tank battery vessels areinstalled in a specific order.

10H-4

11-i

The Lease Pumper’s Handbook

CHAPTER 11

MOTORS, ENGINES, PUMPS, AND COMPRESSORS

A. Motors1. Fundamentals of Electricity.2. The Lease Electrical System.3. Control Boxes and Fuses.4. Time Clocks and Percentage Timers.

· The 24-hour time clock.· The percentage timer.

5. The Automated Control Box.6. Electric Motors.7. Electrical Safety.8. Costs of Electricity.

B. Engines1. Introduction to Engines.2. Two- and Four-Cycle Engines.3. What Makes an Engine Run?

· A heat source.· Fuel.· Compression.· Safety systems.

4. Engine Oils and Oil Additives.5. Gasoline and Gasoline Additives.6. Antifreeze and Radiators.7. Single- and Multiple-Cylinder Engines.8. Diesel Engines.9. Natural Gas Fuel Systems.

· Problems with wet gas containing water vapor.C. Circulating Pumps and Air Compressors

1. Tank Battery Circulating Pumps.2. Installation and Maintenance.3. Understanding Gas Pressure.4. Air Compressors.5. Air Compressor Maintenance.6. Gas Compressor Operation.

11-ii

11A-1

The Lease Pumper’s Handbook

Chapter 11Motors, Engines, Pumps, and Compressors

Section A

MOTORS

A-1. Fundamentals of Electricity.

There are three characteristics of electricalpower that must be matched to a piece ofequipment. First, the equipment will requireeither direct current or alternating current.Electricity that flows in one direction iscalled direct current (DC). Battery-poweredequipment, including flashlights and radios,operate on direct current. Most equipmentthat runs on electricity from commercialpower lines uses alternating current (AC).Electricity in an AC power system rapidlyswitches flow direction as it moves througha circuit. AC power generates less heat thanDC, so for transmitting current over highlines for a long distance, AC is used.

How quickly AC power switches directionis referred to as its cycle rate. In the UnitedStates, electricity operates at 60 cycles persecond. A cycle consists of two changes indirection, so 60-cycle current changesdirection 120 times per second.

In Europe and many other countries,electricity operates at 50 cycles per second.Electrical equipment will not operate at thecorrect speed or may not operate at all if thecorrect cycle rate is not used.

The third concern is that the voltage of theelectricity and the voltage requirements ofthe equipment match. The typical housevoltage in the U.S. is 110 volts, though 220-volt power is used for some appliances suchas heating and air conditioning systems,clothes dryers, and water heaters. At the

well site, electrical lighting and standardpower outlets will generally operate on 110volts, though larger equipment such as pumpmotors will often use 220 or even 440 volts.System voltage is changed through the useof transformers. The electricity beingcarried through power lines over longdistances will be at voltages of severalthousand volts. A transformer on the leasesite power pole will step the power down tothe level to be used by the site equipment.

Electrical plugs and outlets with differentvoltage ratings will differ to preventequipment from being plugged into thewrong system. Standard electrical systemsin some foreign countries are 220 volts.

A-2. The Lease Electrical System.

Most higher voltage equipment (220 V andabove) operate on three-phase power. Three-phase power has to be converted to singlephase to power common consumer itemssuch as drills, lights, etc. A network ofelectrical lines distribute power to eachinstallation and equipment across the lease.Occasionally, a system will have fouroverhead lines, but a three-line system ismore common and is described in thissection.

This network of pole-mounted high linesoriginates from generators miles away. Itdistributes electricity to surrounding areasfor many hundreds of square miles. Theamount of electricity consumed on a lease is

11A-2

insignificant compared to the overall amountof electricity supplied to an area.Consequently, if the lease suffers a loss ofelectricity, the power company will not beaware of the problem until they aretelephoned or otherwise notified.

After the electrical power line enters thelease, it is distributed to poles containingthree fuses and appropriate step-downtransformers suitable to operate the wells(Figure 1). As voltage is stepped downthrough a transformer in a direct ratio, theamperage, a measure of how much workelectricity can do, is stepped up. Electricmotors run on 110, 220, or 440 volts.Occasionally, a different voltage will beencountered.

Figure 1. Typical line fuses and step-downtransformer common to most leases.

Figure 2. Pole with one fuse out of service.

As shown in Figures 1 and 2, there arethree fuses on the electrical pole. Figure 2shows a blown fuse. A blown fuse is easy toidentify because fuses are spring-loaded and,when blown, will usually trip loose and hangdown. If this should occur, all equipmentdownstream from the circuit served by thosefuses should be removed from service asquickly as possible and left out of serviceuntil the fuse has been replaced. Thisprevents equipment burnout.

The electric company that owns the linemust be notified when a fuse is out. Theyare generally understanding of the severityof the situation and respond quickly toreplace it.

A-3. Control Boxes and EquipmentFuses.

The last high line pole should be installedfar outside of the well servicing guy linearea for safety reasons. The power line trailsdown the pole into a fuse box, with anadjacent disconnect lever to electricallyisolate the site while performing majorrepairs. The electrical line continues downthe pole and runs underground in galvanizedwaterproof pipe (conduit) to the pumpingunit or other equipment.

An automatic control box (Figure 3, on thenext page) is mounted near the installationto operate the equipment. In the photograph,the control box is located near the upperedge of the picture. The equipment fuses arethe cylindrical objects in the lower front ofthe box. When performing any services orworkover operations at the well, the breakerarm on the control box should always bepulled to electrically isolate the equipmentand locked out in order to prevent electricalaccidents at the well or installation. Theinstallation illustrated also contains twotimers, one automated and one manual.

11A-3

Figure 3. Control box containing oneautomated 24-hour time controller and

one manual controller.

A-4. The Automated Control Box.

The lease pumper needs to understand thebasic functions of the automated controlbox. In a typical unit, electricity enters thebottom of the box and is run to the upperright corner as it progresses through the box.The first wiring is diverted to a lightningarrester located outside the box. The boxcontains a breaker to disconnect theelectricity and remove a unit from service.

Three fuses are located just below thebreaker. This is the first line of defense toprotect a system from overload. Two wires,

one from a side lead and the second from thecenter wire, are connected to a small 110-volt transformer. These two wires then leadto the control switch located on the outsideof the box.

The control switch has three positions.When turned to the on position, theequipment will run continuously. When thecontrol is set to off, the equipment is turnedoff until the control is changed. If set toautomatic, the time clock will controloperation. This device has three leads to itfrom the fuses on the top side, and the leadsfrom the bottom run out of the box and areconnected to the power motor. Setting thetime clock to a run or on position willengage electromagnetic units in the powercontrol unit and the equipment will run.When the timer hits an off cycle, the powerto the electromagnets is turned off, andsprings separate or disengage the leads toturn the equipment off.

The power control usually has a carbonstack reset button and three heat safetycontrols that shut the unit in to protect themotor. With a minimum of instruction, theoperator can troubleshoot simple problems,such as resetting the carbon stack orchanging a fuse.

A-5. Time Clocks and Percentage Timers.

There are many styles of time controllers,but most can be categorized as either timeclocks or percentage timers. The time clockis normally mounted in a metal boxapproximately 6 inches wide by 10 incheshigh by 3 inches deep. The percentage timeris a much smaller plastic control with onedial.

The 24-hour time clock. This type of clockis divided into 24 one-hour increments.Normally, the day half of the clock is

11A-4

portrayed in silver while the night half ispainted black. Most of these clocks havepins for on/off control in 15-minuteincrements. Running time can be dividedaround the clock or restricted to when thepumper is physically on the lease. A fewtimers are controlled in five-minuteincrements. For marginal wells, the timer isset to pump a certain portion of each hour onthe time clock. With the well not pumpingfor extended time periods, the fluid buildupwill prevent additional fluid from enteringthe wellbore.

The percentage timer. This timer allowsthe pumper to run a unit a certain percentageof the day. Typical percentage timersoperate based on an interval of time, such as15 minutes or 1 hour. The time is set for apercentage of that time interval. Forexample, if the timer has a 15-minuteinterval and is set for 50%, it will run 7½minutes and be off 7½ minutes. This willhappen every 15 minutes or 96 times eachday. Overall, the pump will run a total of 12hours in a 24-hour period or 50% of thetime.

A-6. Electric Motors.

As noted earlier, electric motors on thelease are usually rated at 110, 220, or 440volts. While electric motors can be woundto run at many speeds, they typically operateat 1100, 1400, 1725, or 3450 rpm.

Most pumping unit electric motors havenine wires leading out of the motor and intothe wiring box on the side of the motor(Figure 4). Each of these wires will benumbered, and instructions on the plate willindicate that they should be grouped intothree sets of three. These three lead groupswill then be attached to the three wires fromthe control panel. If the motor is running in

the wrong direction when the power isturned back on, any two leads can beloosened and reversed to change the rotationof the motor.

Figure 4. Electric motor and control box.The motor wiring can be changed to use

three different motor speeds.

Some motors can accept either 220 voltsor 440 volts. If this is true of the motorbeing installed, instructions on the motor’sside plate will indicate which three wires goin each group for a specific voltages. Ifthese instructions are not on the plate, themotor must be placed in service using thevoltage stamped on the plate.

A-7. Electrical Safety.

The operator must always respect the leaseelectrical system. If handled improperly, itcan be dangerous or deadly. This does notimply that electricity is too dangerous to use,but it does mean that good work habits mustbe developed and always followed. When apumper is at work, there is usually no onewithin sight or hearing. The pumper mustoperate electrically powered equipment,change fuses, make minor changes, andoperate automated controls with no one tohelp if trouble arises.

11A-5

The best way a pumper can be protected isto be knowledgeable about handlingelectricity and to use good work habits.These include:

· Having a good pair of insulated workgloves to wear when handling electricity.They should not be used for any otherpurpose and should be kept clean.

· Isolating a system from electrical powerbefore performing any service.

· Learning the correct way to performelectrical work duties.

· Not taking chances.· Locking the electricity out of service as

needed.

A-7. Costs of Electricity.

The company pays for the electricitydelivered to the lease as part of the operatingcosts for producing oil. Generally, there aretwo major cost concerns in providingelectricity to the lease: the initial cost ofobtaining electrical service and the cost forthe electricity consumed. Theseconsiderations can determine whether amarginal well is profitable and should becarefully managed.

Power companies may have a five-yearminimum billing to cover part of the costs ofinstalling the line to a new well. The

production company will occasionally lay atemporary electric line on top of the groundfrom another well to run new wells untiltheir productivity has been determined.

Power companies do not charge the samerate for electricity at all times of the day.Most charge a higher rate during normaloffice hours, such as 8 a.m. to 5 p.m. This iscalled their peak hours rate. Similarly thepower company may charge a higher rate forperiods of high usage, which is called theirpeak load rate. The lease pumper can helpreduce costs by avoiding electrical usagethat results in peak hour or peak loadcharges. For example, pumping units drawmuch more current when starting up thanwhen they are running. This may favorrunning the pumps for a few long cyclesrather than lots of short cycles if productioncan be maintained. The operator shouldalternate running units and stagger startingtimes in order to reduce billing. If possible,electrical equipment should run more duringnon-peak hours. The lease pumper maywant to circulate tank bottoms and otherfunctions while on the site during peakhours. This may be offset by running pumpsduring periods of cheaper power costs.

The operation supervisor should be awareof electrical billing practices and can provideadvice in this matter.

11A-6

11B-1

The Lease Pumper’s Handbook

Chapter 11Motors, Engines, Pumps, and Compressors

Section B

ENGINES

B-1. Introduction to Engines.

Engines have been used as prime moverssince the first wells were drilled. Since theycontinue to play a major role today, thepumper must have a basic knowledge ofhow to operate and maintain many types ofengines.

When no electricity is available to a newwell that has insufficient gas pressure toflow, a mechanical pumping unit with anatural gas engine will probably be installed,at least temporarily. This is especially truefor a wildcat well where the only knowledgeavailable is that it produces enough oil tojustify completing it. Regardless, thepumper must operate and maintain an enginethat will run 24 hours a day, probably usingcasing gas as fuel (Figure 1).

Figure 1. A single-cylinder engine with aflywheel, typical of many engines used in

oilfields.(courtesy Arrow Specialty Co., Inc.)

B-2. Two- and Four-Cycle Engines.

Engines typically used on the lease site arecalled internal combustion engines becausethe fuel is burned inside the engine. Thefuel is burned in a hollow area of the enginecalled a cylinder. Fuel is allowed into thecylinder through an intake valve and thebyproducts of fuel combustion are removedfrom through an exhaust valve. A pistonmoves up and down within the cylinder tocompress the fuel for more powerfulcombustion. When the compressed fuelexplodes, the piston is driven back down thecylinder. It is this downward movement ofthe piston that actually produces the powergenerated by an engine so that it can be usedto do work. This whole process is describedas a series of four strokes. A stroke is themovement of the piston along its full travelin one direction. The strokes of an internalcombustion engine are:

· Intake stroke. With the exhaust valveclosed and the intake valve open, thepiston moves down or away from thecylinder head, drawing a mixture of airand fuel into the cylinder. As the pistonreaches bottom, the intake valve closes.

· Compression stroke. With both valvesclosed, the piston moves up or toward thecylinder head, compressing the fuel/airmixture into 1/10 or less of the volume.

· Power stroke. With the intake andexhaust valves closed, the spark plug

11B-2

ignites the fuels, an explosion occurs.The resulting power pushes the pistondown or away from the cylinder head.

· Exhaust stroke. The exhaust valveopens and as the piston returns to the topor toward the cylinder head, it pushes thebyproducts of combustion gas out of thecylinder.

The combustion process just described iscalled a four-cycle process because there arefour strokes for each ignition event. Someengines, called two-cycle engines, have anignition event every time the piston comes tothe top of the cylinder. With two cycleengines, used in some outboard engines andmotorcycles, lubricating oil must be addedinto the gasoline. With a four-cycle engine,oil circulates outside of the combustionchamber. Almost all field engines are four-cycle. The events of the four-cycle processmust occur at the correct time in relation toeach other. For example, during the ignitionevent, the fuel mixture must be compressedand the valves must be closed. This is calledengine timing.

B-3. What Makes an Engine Run?

The three things that make up the firingtriangle of the gasoline or natural gas engineare a heat source, fuel, and compression. Foran engine to run, it must have the correctamount of all three with correct timing.When troubleshooting an engine, these areitems that must be checked. Additionally,an engine includes two safety systems, oneto lubricate moving parts and one to helpremove heat from the engine. The leasepumper is expected to have a workingknowledge of these systems in order to keepengines operating dependably, including theability to change and service basic enginecomponents and properly time engines.

A heat source. The usual heat source for aninternal combustion engine is electricity—specifically, a spark jumping across the gapof a spark plug. Other electrical componentsmay include a battery, voltage regulator,generator (or alternator), starter, distributor,coil (or low-tension coils), spark plugs, andappropriate wiring. Spark plugs must be thecorrect size, have the proper gap setting, andbe of the correct temperature range, whichgenerally include cold, standard, and hot.Some engines have a magneto electricalsystem with the coil, distributor, condenser,and points built into the magneto. Someengines have low-tension magnetos, whichcost more but can greatly reduce magnetoproblems. Newer engines may have solid-state ignition systems. Battery maintenanceincludes ensuring that service-free batteriesare not left outside in a rundown conditionin freezing weather.

Because engines remain in service forseveral years, the lease pumper must knowhow to service all types of heat sources.

Fuel. The fuel system includes a fuel supply,air filter, carburetor, and mixing chamber.Fuel may be gasoline, natural gas, butane, ordiesel. The gasoline system requires acarburetor with a float and fuel filter or afuel injection system. Natural gas and butanesystems require a gas or a combinationcarburetor. Diesel systems use a fueldistributor and a injector system. Pumperduties include air and fuel cleaning systemsmaintenance, adjustments, and minor repair.

Compression. This involves mechanicalparts such as the engine block, pistons,rings, valves, and timing system.Maintenance performed by the pumper inthis area depends upon job duties, availabletime, experience, tool and supportavailability, and many other factors.

11B-3

Safety systems. Safety systems to protectthe engine include the lubricating safetysystem and the cooling safety system. Thesesafety components shut down an enginewithout damage in the event of emergencyconditions. A medium-sized engine will costseveral thousand dollars, thus representing asubstantial investment. The safety systemsmust always be kept in operating condition.

The lubricating system circulates oil overmoving parts to reduce friction and wear.Two critical aspects of the lubricatingsystem are oil level—that is, the amount ofoil in the system—and oil pressure, which isa measure of whether there is enoughpressure from the oil pump to move oilthroughout the engine. The oil level safetysystem uses a float to measure how much oilis in the lubricating system. If the oil getslow, the float falls and makes contact withthe engine block to ground the ignition andshut down the engine. The oil pressuresafety system has a contact that will groundthe ignition if the pressure drops too low.

The cooling system circulates coolant—amixture of water and antifreeze—around theengine parts to remove the heat produced byengine operation. The coolant passesthrough a radiator, where moving airremoves heat from the coolant. Atemperature gauge monitors coolanttemperature, with a contact that moves withchanges in coolant temperature. If thetemperature rises to a predetermine level,such as 212° F, the contacts grounds theignition system and shuts down the engine.

B-4. Engine Oils and Oil Additives.

The lubricating system is filled with oil.The oil must be suited for the engine andoperating conditions in terms of viscosityand additives. The term viscosity refers tothe how quickly a given oil will pour when

the oil is cold and when it is hot. Viscositycan be thought of as the thickness of oil andis referred to as weight, such as 10 weight,30 weight, and 50 weight, with the highernumber representing a thicker or higherviscosity oil. Engine oils are available inmultiple viscosities, such as 10-40, whichmeans that at a cold temperature, it will flowas quickly as a 10 weight, but when it is hotit will flow as slowly as a 40 weight oil.

Although oils may be similar inappearance, they can vary greatly incontents, especially in the additives theycontain. Additives are chemicals that areadded to the oil to overcome potentialproblems. Some of the more commonadditives include:

· Sulfur neutralizer to prevent theelements in the crankcase fromcombining and forming acids.

· Anti-wear agents to reduce engine wear,especially during the warm-up periodwhich is when the most wear occurs.

· Rust inhibitors to reduce rust and sludgewhen the engine is either running or off.Sensitive metals can rust, even below theoil level.

· Viscosity index improvers to maximizethe ability of oil to adhere to the metal sothat components above the oil line retainlubrication for start-up and while runningto reduce wear.

· Homogenizing agents retain carbon andother foreign agents in suspension so thatthey are carried to the filter system. Whilethese agents cause the oil to be darker,they actually keep the engine cleaner.

As oil circulates through the engine and isexposed to heat, byproducts of combustion,and the elements, it breaks down, losing itslubricating abilities, and the additives breakdown. For these reasons, the engine oil and

11B-4

filter must be changed periodically. Thereplacement oil must be of the properviscosity and contain the additivesrecommended by the engine manufacturer.

B-5. Gasoline and Gasoline Additives.

When purchasing gasoline, care must alsobe taken to obtain the correct grade andquality of product. When selecting qualityfuels, considerations include:

· Sulfur neutralizers are added to reduceengine wear caused from acids beingcreated within the system through fuelsand water condensation.

· Carburetor cleaners reduce the varnishbuildup that causes carburetor parts tostick and the jet holes to narrow or plug.

· Water absorbents break down andremove water that otherwise willaccumulate in the gas tank, lines, andcarburetor, causing rust and occasionallyfreezing.

· Anti-glow agents prevent carbonsdeposited in the engine heads frombecoming hot (glowing) enough to ignitethe fuel. These hot spots can ignite thefuel ahead of the power stroke (knocking)or, after the ignition system has been shutoff, keep the engine running (dieseling).

· Octane improvers. These improveengine performance and burn slower toreduce rod bearing wear and dramaticallyextend the life of the engine. The higherthe octane, the slower the gasoline willburn. With slower burning high octanefuel, the initial impact on the piston isless severe. This results in more milesper gallon, less damage to the engine, anda cleaner engine inside. It is not unusualto have a lower cost per mile and betterperformance on an engine when using ahigher octane than with regular fuel.

B-6. Antifreeze and Radiators.

There are many benefits to running a goodantifreeze in an engine, including:

· Prevention of rust and corrosion.Ethylene glycol is a natural rust inhibitor.

· Lubrication of the water pump.Ethylene glycol is also a natural lubricantand lubricates the water pump.

· Transfer of heat more easily. Bytransferring heat more easily, the engineruns warmer in the winter and cooler inthe summer. The boiling point of anti-freeze is 263° F.

· Prevention of water from freezing. Theprimary reason for adding antifreeze tothe water is obviously to prevent thewater from freezing.

Antifreeze should be maintained in mostengines year-round because of the additionalprotection it gives to the engine other thancold weather protection.

When mixing antifreeze, the basic methodis to mix two gallons of water and onegallon of antifreeze, or a 1/3 mixture. Thisgives protection down to 0° F., or 32 degreesbelow freezing. In colder climates a 1:1mixture may be more appropriate.

Antifreeze mixing ratios.

PartsWater

PartsAnti-

freeze%

Freezesat °F

Boilsat °F

3 1 25 +102 1 33 0

20 7 35 -35 2 40 -12 258

20 9 45 -221 1 50 -34 263

20 11 55 -48 266

11B-5

B-7. Single- and Multiple-CylinderEngines.

Single-cylinder oilfield engines (Figure 2)are used extensively on circulating pumps(vertical cylinder small engines), and as theprime mover (horizontal cylinder, mediumto large engines) for shallow and mediumdepth oil wells. Engines that are largeenough to operate pumping units are slow-running engines with large flywheels thatrotate at a speed of 300-500 revolutions perminute. The large flywheels store energy intheir movement, which allows the engine torun smoothly. Instead of having severalspark plugs and an electrical distributingsystem, the system is reduced to a magneto,one wire, and a spark plug. This greatlyreduces electrical maintenance requirements.The sheave is almost twice as large as thoseon multiple-cylinder engines, and belts movemuch slower across the engine sheave. Thestarting system is usually composed of aportable starter and a pair of jumper cables.It uses a vehicle starting battery.

Figure 2. Single-cylinder four-cycleengine using marginal casing gas for

power.

Multiple-cylinder engines are morecomplex, have a large number of parts, andrun at speeds of 900-1600 rpm. Theelectrical system may require a battery,

starter, voltage regulator, distributor,possibly a coil for each cylinder, and morespark plugs. Since it does not have largeflywheels to store energy, the engine mustrotate much faster to run smoothly.

B-8. Diesel Engines.

Diesel engines do not use a spark to ignitethe fuel on each power stroke. Instead, theheat generated by engine compression isenough to ignite the fuel. Thus, thecompression stroke compresses only air, andas the piston approaches the top of its stroke,diesel fluid is injected into cylinder, and itignites instantly. Because of the extremeheat generated, diesel fuel contains alubricant for the cylinder, rings, and valvestems.

Diesel engines are assembled with looserclearances than gasoline engines. Steelexpands as it gets hot, and diesel enginesgenerate more heat than gasoline types. As aresult, the diesel engine makes more noisewhen it is first started but grows quieter as itgets warm. If the engine is going to be usedagain in a short time after becoming idle, theengine is left running. To start the engine incold weather, the cylinders have glow plugsthat are turned on a few minutes before theengine is cranked in order to provideignition heat.

B-9. Natural Gas Fuel Systems.

Natural gas engines can be a veryeconomical way to drive pumps, especiallywhen gas is drawn from a well where a gasengine may be pumping. Figure 3 illustratesthe components of a typical gas system. Ascrubber and volume tank are installed justahead of each facility whenever gas is wet.With dry gas, the scrubber is either notrequired or is much smaller and used simplyto trap rust out of the system.

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Figure 3. Natural gas supply systemincluding pressure regulators, scrubber,

volume tanks, and line system.(courtesy Arrow Specialties, Co., Inc.)

The system begins with a regulator thatreduces the gas pressure to protect thedownstream system, followed by a scrubberor wash tank. With small engines this is thecomplete system, except for an ounce gauge

and a flexible connecting hose. Engines willneed a fuel pressure of 6-8 ounces.

For larger engines requiring a high volumeof gas, a second tank is needed as illustratedin Figure 3 to maintain a sufficient reservesupply volume. The riser between thepictured tanks acts as a shock absorber toprotect the vessels and regulators.

Problems with wet gas containing watervapor. When the natural gas supply linecontains water vapor and is connected to thecasing, problems can be encountered in thewinter in keeping the system operational.

In cold weather, warm gas gets cold after itleaves the wellhead, and the vaporcondenses into free water. This watercollects in the line and, because of slowmovement, accumulates and freezes in theriser as the line turns up into the scrubber.

Each night in the winter, this moisture mayfreeze and shut down the system. A smallshop-made blow-down tank can be installedon the inlet line to act as a drip pot to collectthis moisture. It will be necessary tooccasionally blow down this system as itgets full.

11C-1

The Lease Pumper’s Handbook

Chapter 11Motors, Engines, Pumps, and Compressors

Section C

CIRCULATING PUMPS AND AIR COMPRESSORS

Pumps are used for many purposes on oiland gas the leases, and there are many stylesof pumps. Pumps can be classified by theirpressure rating: high, medium, or low.Some pumps will pump only very cleanliquid, while others are capable of pumpingliquids containing mud, small rocks, andother emulsions with very little or minimumpump damage. There are two basic styles ofpumps: the centrifugal pump and thepositive displacement pump.

C-1. Tank Battery Circulating Pumps.

The most common pump that the leasepumper operates is the tank batterycirculating pump. For medium- and high-volume producing tank batteries, this pumpis often permanently installed and the primemover is an electric motor (Figure 1). Onleases where no electricity is available at thetank battery, a single-cylinder gasoline-powered engine is common. When the oil isdifficult to treat, the automated electricalpump may circulate the bottom of the tankinto which fluid is being produced. Thishappens for a few minutes every hour.

For marginally producing oil wells, thecirculating pump may be a portable modelthat is gasoline powered and moved frombattery to battery as needed. In this event,the pump is either trailer mounted or needsto be small enough to be carried easily withone hand. This is because it must be moved,installed, and operated by one person. The

most convenient style pump is the one withthe pump mounted to the motor becauseskid-mounted units are too heavy for oneperson to hand load on a regular basis.

Figure 1. A permanently installed,electrically driven circulating pump with

an adjacent control box.

C-2. Installation and Maintenance.

Circulating pumps are located in thesystem with the inlet connected to the drainsystem and the outlet piped back to theproduction line after the separator but aheadof the treating system. If no treating vesselsare in the system, the outlet is connected intothe oil system just ahead of the stock tanksfor circulating.

The ideal arrangement in some tankbatteries is to install the pump in the middleof a loop system where it can pump in eitherdirection. Most transport trucks are piped inthis manner so that the tanker can both load

11C-2

and unload itself as needed. There can bemany reasons for the pumper needing topump in either direction at the tank battery.

The maintenance of the pump includeslubricating the bearings or changing theshaft packing as needed. The maintenanceof the circulating pump engine consistsprimarily of changing the oil as scheduled,keeping the belt tension correct, and gappingor changing the spark plug as needed. Manyof the problems in the carburetion systemare caused by allowing water or trash toenter the gas tank—for example, fromstoring fuel in a rusty and dirty container.

C-3. Understanding Gas Pressure.

One characteristic of gases is that they tryto fill all the space in any container intowhich they are placed. The force that a gasexerts on the walls of its container isreferred to as gas pressure. If the containeris made smaller or if more air is forced intothe same volume, then the gas pressureincreases. This is referred to as compressingthe gas, and it is the same action that occurswhen the piston moves up the cylinder,making the volume of the cylinder smallerand compressing the fuel/air mixture. An aircompressor simply pumps more air into acontainer, leading to greater air pressure.

Normal atmospheric pressure at sea levelis approximately 14.7 psi. This is basicallythe pull of gravity or weight of a column ofair 1 inch x 1 inch and all the way into outerspace. As one goes to a higher elevation,there is less air above each square inch, soatmospheric pressure decreases withaltitude. A container open to the atmospherewill have an inside pressure the same asatmospheric pressure at that location.

Gases tend to move from areas of highpressure to areas of low pressure, and thisphenomenon can be used to do work. For

example, compressed air has a pressure thatis greater than that of the surrounding air.Thus, compressed air can be used to moveobjects, including control valves.

In a similar way, if there is an area with apressure less than atmospheric, thesurrounding air will try to move in thatdirection. These areas of lower pressure arereferred to as vacuums. Vacuums are oftenused to move gases and liquids. Forexample, as the piston moves down acylinder in an engine, a vacuum is created inthe cylinder. Because the fuel/air mixturefrom the carburetor is essentially atatmospheric pressure, when the intake valveopens, the mixture flows into the cylinderwhere the pressure is lower.

Gas pressure is measured through the useof gauges. Gauges used to measurecompressed gases and sometimes vacuumtypically provide readings in pounds persquare inch (psi). Vacuum gauges usuallyprovide readings as inches of mercury (in.Hg), though it is often referred to as inchesof vacuum. This measurement scale isbased on the movement of liquid mercurywithin a glass column. At sea level,absolute vacuum is considered to be 29.92inches of mercury. This is the greatestvacuum that can be created.

Figure 2. Comparison of vacuum andabsolute pressures.

11C-3

When dealing with gas pressures on an oillease, there are two common ways ofreferring to the pressure. PSIG, or poundsper square inch, gauge is the pressure insidevessels and lines. The accuracy of thepressure reading depends upon the gaugeitself. PSIA, or pounds per square inch,absolute, is the pressure on the outside ofthe vessels and lines—that is, normalatmospheric pressure.

C-4. Air Compressors.

Air compressors (Figure 3) are installed attank batteries to supply air to operateautomated equipment. Even thoughautomated valves can be controlled bynatural gas, several problems can beencountered that will cost the lease operatormany times the price of installing andmaintaining an air compressor.

Figure 3. A tank battery air compressorused to provide clean air to operate

automation valves and controls.

Natural gas can contain corrosivecompounds that are not easily removed byusing a scrubber. Expensive controllers canbecome contaminated, plugged, or corrodedby using some natural gases.

Air compressors in the field are usuallyoperated by using an electric motor.

Maintenance usually involves maintainingcorrect belt tension, checking the oil level inthe compressor, keeping air filters clean,draining accumulated water from the airtank, and lubricating the bearings.

C-5. Air Compressor Maintenance.

Air compressors are easily maintainedbecause they are fully automated and pumpair on demand as it is consumed. One of themaintenance tasks is to make sure that thereare no air leaks in the system. Leaks cancause the system to run longer to make upfor lost air.

The inlet air filter will need to be checkedand cleaned on a maintenance schedule. Theoil in the compressor will also need to bechecked on a regular basis. The oil will needto be changed according to manufacturer’sspecifications and be refilled with therecommended oil. Hydraulic or compressoroil is not the same blend as engine oil.

C-6. Gas Compressor Operation.

Tank batteries located near or within citylimits or oil storage tanks that vent largequantities of natural gas may include gascompressors. These gas compressors areautomatically turned on and off by low-pressure controls. The unit is referred to asa vapor recovery unit. This unit takes thelow-pressure gas from the tanks, compressesit, and injects it into the high-pressure salessystem.

As the gas leaves the tank battery, justahead of the compressor, it passes through atank (scrubber) that removes the distillate.This distillate is pumped back into the stocktanks periodically. Low-pressure gascompressors will usually have vane-typecompressors that require a lubricatingsystem.

11C-4

The compressor will probably have anoiling lubricator on it to provide oil forlubrication. The lease pumper mustregularly fill this lubricator with oil and keepbasic records on oil consumption. This isdone to track how much oil is beingconsumed and to know how often oil mustbe added.

The sight glasses on the lubricator arefilled with a water-soluble glycerinesolution. As the oil enters the pump andtravels upward through the glass, the numberof drops of oil being injected per minute canbe counted because the oil is lighter than theglycerine.

12-i

The Lease Pumper’s Handbook

CHAPTER 12

GAUGING AND ANALYZING DAILY PRODUCTION

A. Lease Duties1. What Makes an Outstanding Lease Pumper?

· Skills needed to become an outstanding lease pumper.2. Beginning the Day on the Lease.

· Everything should be checked and observed during the morning rounds.· Visual Inspection.

3. Planning and Scheduling .· Monthly, quarterly, semiannual, and annual maintenance.· Monthly Schedule.· Well testing.· Circulating tank bottoms.· Chemical treating schedule.· Planning upcoming tasks.

B. Gauging Daily Production and Inspecting the Tank Battery1. Approaching the Tank Battery.

· The visual inspection.2. Gauging Equipment.

· The gauge line.3. Gauging Oil and the Grease Book.

· Gauging the stock tank.· Gauging water levels.· Switching tanks and opening equalizer lines.· Alternate day gauging.

C. Analyzing Daily Production1. Problems with Short Production.

· At the Tank Battery.· A flow line has broken or become plugged.· At the well surface.· Downhole.

2. Problems with Overproduction.· Determining if the overproduction is oil or water.· When the tank battery is still in balance.

D. Unitizing the Reservoir and Commingling Production1. Satellite Tank Batteries.2. Problems and Solutions for Combined Flow Lines.

· The individual well tester.· Well tests at the satellite tank batteries.

12-ii

· Operation of satellite tank batteries.3. Unitizing Fields Under One Operator.4. Commingling Different Pay Zones.5. Unitizing a Reservoir.

· Problems in production that justify the need for unitization.· The effects of unitizing.

6. Commingling Wells with Different Well Operators.7. Working for More than One Operator.

E. Repairs and Maintenance1. Effects of Reduced Production.2. A Reasonable Workload.3. At the Tank Battery.4. Leaks in Lines.

· Upwind precautions when gas is present.5. Pumping Unit and Wellhead Maintenance.6. Automation Control Maintenance.

12A-1

The Lease Pumper’s Handbook

Chapter 12Gauging and Analyzing Daily Production

Section A

LEASE DUTIES

A-1. What Makes an Outstanding LeasePumper?

Although some lease pumpers are hardworking individuals, they may barelyachieve satisfactory production levels.Fortunately, the majority are good leasepumpers. However, a few have anoutstanding ability to produce wells. Thisability is built by excellent work habits andthe desire to continuously improve theiranalytical and operational skills.

Skills needed to become an outstandinglease pumper. Outstanding lease pumpershave the ability to understand what isoccurring on the lease, in the formation, andhow all facets of the operation can beimproved. This includes understanding howto coax additional oil out of the formation,superior knowledge of oil treating, andexcellent operations management.

Outstanding lease pumpers:

· Have job satisfaction. They enjoy theirjob and keep an active interest in theirprofession.

· Show pride in their work. They takepride in their ability, appearance, theappearance of the site, equipment andsupply organization, and cleanliness.

· Have the ability to make as much oil aspossible. They continuously study howproduction can be improved.

· Keep tank bottoms clean. This beginseven before production is switched intothe tank.

· End the month with less than one tank ofoil on hand at each tank battery ifpossible. They schedule tank sales inadvance and call the gauger early.

· Put in a full day of constructive workwithout resentment. Outstanding leasepumpers never get into the habit ofleaving the job early.

· Keep lease expenses to a minimum butrecognize when a special expenditure willpay dividends.

· Take care of the vehicle and tools.· Drive conservatively.· Work well with all types of people.· Are honest.· Do not abuse alcohol or drugs.· Observe good safety practices.

A-2. Beginning the Day on the Lease.

When arriving on the lease in the morning,the pumper should review the workschedule. The scheduled duties should beaggressively worked so that there is time forspecial projects and challenges.

The pumper must have the ability to stayproductive during the entire workday andefficiently identify and solve the day’sproblems.

12A-2

Everything should be checked andobserved during the morning rounds.Light work should be completed during themorning so that the afternoon can bedevoted to outstanding lease needs. Thiswill prevent the need to double back onpreviously covered ground. Light workincludes checking pumping units, observingstuffing boxes, and making sure thateverything is operating normally.

The typical work day includes thefollowing activities:

· Tank gauging. Tanks should be gaugedas early as possible. Many companieswill let the pumper set the starting time.

· Performance of other required daily andscheduled duties.

· Production computation and checking forproblems.

· Observing all wells and equipment.· Identifying and solving problems as they

arise while still keeping the regularlyscheduled maintenance program.

One or more units should be scheduled tobe pumping at the beginning of the day. If awell is pumping, the electrical service is inworking order. If not, this is likely the firstproblem to be corrected. If a well is notpumping, it may be best to turn the electriccontroller from automatic to manual toobserve it in motion.

A section of a pumping unit should beobserved for a full rotation. If an air spaceopens up, the unusual action will be notedinstantly. A white line should be painted ona pitman arm nut and observed at least onetime a week. This is to allow the leasepumper to observe any movement of the nut.

After an inspection, the lease pumpershould check to see that the controller hasbeen set to the automatic position.

Visual inspection. Trash should not beallowed on the ground around pumping unitsor moving equipment. Debris should beremoved from a location after well work hasbeen performed to prevent problems frombeing obscured. Clean grounds will allowthe observation of some problems frominside the vehicle.

Any loose parts on the ground should benoted. Small bolts, nuts, or washers in anarea that is regularly cleaned may be anindication of problems. The pumping unitmay need to be shut down until the source isidentified.

The height of the liquid line on the sightglass of a pressure vessel should be observedevery day. A small string can be tied aroundthe sight glass and slid up or down to theexact producing liquid level. When passedon a daily basis, the performance of thevessel can be observed at a glance. This canmake a significant difference in the gaugeanalysis when pumping marginal wells.When the oil level begins creeping upward,it may be an indication of water in the oilline to the tanks. It can also indicate whenthe vessel develops enough liquid headabove it to kick part of the water over intothe stock tank. When this occurs, the levelwill go down below the marker level andthis cycle will begin the process again.

The pumper should listen while observing.If a pumping unit is squeaking, it either has aproblem or may require lubrication.

Observations are only useful whencombined with thoughtful analysis.Correctly analyzing problems helps to builda better pumper.

A-3. Planning and Scheduling.

Whether serving a small company or apumper contractor, outstanding leasepumpers work from a planned schedule.

12A-3

They understand what makes up a goodschedule, develop one, and follow it asclosely as possible.

Each detail of work is not planned down tothe exact day for most lease work, but someduties are so important that they will bescheduled with clear time objectives. Manyprojects, such as individual well tests,lubricating pumping units, treating wells,walking flow lines, pressure testing flowlines at the wellhead, filling chemicalpumps, lubricating valve stems, and a hostof other activities, can be planned andperformed on a schedule.

Monthly, quarterly, semiannual, andannual maintenance. Maintenanceschedules should be completed and posted inthe lease records book (discussed in Chapter19). Some pages must be custom designedto fit the specific maintenance needs of thelease operation. Tasks will be shared byboth regular and relief pumpers. Dependingon the specifics of the lease, this mayinclude, but is not limited to, servicingpumping units, checking gearboxes,changing engine oil, and lubricating plugvalves.

Monthly Schedule. The lease pumpershould have specific maintenance goals thatare achieved every month. A monthlypumping plan is easy to develop and beginsthe same way every month. With time, theplan is fine-tuned and becomes a valuabletool. Monthly activities include:

· Well testing· Circulating tank bottoms· Chemical treating· Planning upcoming tasks

Well testing. Well testing should begin inthe first few days of the month, and each

well should be tested once per month. Theregular pumper must maintain a testingrecord. This essential task should not berelegated to a relief pumper.

Reviewing the most recent record againstthose from previous months helps maintain apulse on the condition of every well. Therecord reveals when wells are maintainingproduction, falling, need pulling, or canincrease production.

For a one-well battery, a typical day ischosen and recorded as a test. Averagingthe month produces invalid results because itusually also includes down time.

Testing procedures are reviewed inChapter 13, Testing, Treating, and SellingCrude Oil.

Circulating tank bottoms. Every time oilis sold, the bottom must be cleaned. Ifproblems are encountered while treating oil,every time that a tank of oil is sold, theremaining oil and bottom emulsion shouldbe circulated through the treating system andinto the receiving tank. If it did not circulateout to a low level it should be switched backand produced there until it accumulatesapproximately one foot of new oil. It is thencirculated out again into the receiving tank.This should be repeated until the bottom issatisfactorily clean.

Bad tank bottoms are often caused byneglect and accumulation. It may sometimesbe necessary to pump water into the tank tolift the emulsion and stir so that it can moveand treat. Even after tank bottoms aresatisfactorily clean, this procedure isrepeated with every tank sale. At thebeginning of the month when oil sellingtimes are known, the tank should becirculated and kept as clean as possible.This is reviewed in more detail underChapter 13, Testing, Treating. and SellingCrude Oil.

12A-4

Chemical treating schedule. Chemicalconsumption should be computed on aregular schedule. This should be balancedagainst the barrels of emulsion produced.Treating must be kept on schedule to keepthe amount of time and chemical consumedto a minimum. Chemical action is oftenimproved by simply circulating the oil.Movement provides additional conditioning.

Planning upcoming tasks. As the end ofthe month approaches, the upcomingmonth’s activities should be planned,including those tasks required in the firstweek of the month. An efficient schedule

balances sufficient maintenance time toprevent problems while avoiding theunnecessary expense and time of over-servicing. Planning becomes easier asexperience is gained.

Some duties such as well tests should beperformed within the first three weeks of themonth. This will free the latter part of themonth for oil treating and other importantduties. Delaying treatment of a tank of oilmay result in its not being sold until the nextmonth, and thus payment to the oil companywill be delayed for another month.

12B-1

The Lease Pumper’s Handbook

Chapter 12Gauging and Analyzing Daily Production

Section B

GAUGING DAILY PRODUCTION AND INSPECTING THE TANK BATTERY

B-1. Approaching the Tank Battery.

Over time, the pumper should gain theability to perform a meticulous but almostautomatic review of the tank battery. Beforethe vehicle has been parked, some problemsmay have been determined already.

The tank battery is the hub from whichmost lease pumper activities are controlledeach day. When oil production is normal orslightly up, the pumper will feel good andhave time to take care of many needs. Ifproduction is down, the pumper must checkdozens of small potential causes and searchfor solutions that might have caused theshortage. If production is too high, thepumper is possibly more alarmed than had itbeen too short and again must investigatemany systems in the search for the rootcause of the problem.

The visual inspection. An obvious problemthat may be seen while approaching thebattery is oil or water running across theroad. The problem may present itself as asmall black streak down the side of a tank oralong a line, indicating a pinhole size leak ora loose connection.

If a tank of oil had been available for sale,there may be tire tracks from a gauger’spickup or transport truck. If a sales linevalve is open, the gauger has come by andaccepted the oil. If tracks are present, thenthe pumper should also look for a receipt inthe communication bottle.

Before leaving the tank battery, thepumper should know:

· How much oil and water are in all of thetanks.

· The height of the fluid levels in all sightglasses.

· The pressures on all gauges.· The levels of water in the disposal

system and pit.· Whether any oil has been carried over

into the water system.

Hopefully, everything will appear normalwhen looking across from the tank batterywalkway.

B-2. Gauging Equipment.

A good gauge line is needed for gaugingthe tanks. In addition, clean rags or a linewiper are needed to wipe the oil off thegauge line and plumb bob. The leasepumper should never allow oil to drip off theline.

The gauge line. Figure 1 shows a typicalgauge line. It consists of a frame, tape, andplumb bob. This is an expensive item, and itmust be cared for properly in order to avoidthe cost of replacement. Caution must beused to prevent the thief hatch lid fromfalling on the tape while it is being used andto prevent a kink from developing in theline. The plumb bob is made from ¾-inch

12B-2

brass and weighs 20-22 ounces. This givesit sufficient weight to pull the tape off thereel as it drops toward the striker plate that ismounted in the bottom of the tank. Thestriker plate prevents holes from beingpunched in the bottom of the tank over yearsof gauging. As indicated in Figure 2, severalstyles of plumb bobs are available.

Figure 1. The gauge line with a double-duty tape.

(courtesy of W.L. Walker Company)

Figure 2. A wide assortment of plumbbobs is available.

(courtesy of W.L. Walker Company)

The line wiper or little Joe (Figure 3) is ahandy tool. It is mounted on the gaugingtool between the handle and the frame.After striking or tagging bottom and as theline is reeled, the wiper trigger is squeezedlightly to wipe the line clean. The line wiperpays for itself by dramatically reducing thenumber of rags consumed while gauging aswell as by returning the oil from the lineback into the tank.

Figure 3. A line wiper or Little Joe.(courtesy of W.L. Walker Company)

Gauge lines are available in chrome ornubian (black) finishes or a combination ofthese two finishes as shown in Figure 4.They are available in inch, hundredths of afoot, and metric scales.

Figure 4. Two styles of gauge lines.(courtesy of W.L. Walker Company)

12B-3

Three frames are available. One size holds18-, 25-, and 33-foot tapes. A second sizeholds 50-, 66-, and 75-foot tapes. A thirdsize takes 75- and 100-foot tapes. Theshorter tapes are more popular for typicallease use.

Chrome-clad tapes are best when gaugingheavier, low-gravity crudes. Dark-coloredcrude stands out distinctly on the chromeline. The chrome-clad line may need to beoiled and dusted to get an accurate readingwhen gauging lighter crudes.

Nubian lines are best when gauging lightcrudes and distillates. Distillate orcondensate is often so clear that, in atransparent glass, it looks like water. Sinceit evaporates off the gauge line before thegauge can be read, oil or powder may needto be put on the line before gauging to give aclear reading. Similar problems may also beencountered when gauging water.

Since water will drop out of the crude oilwhen it is produced into the stock tank, thebottom must be checked occasionally to seehow much water is accumulating. In coldweather, more may be carried over thanduring the summer months. At appropriatetimes it must be determined how much freewater is in the stock tank. This can be doneby using a thief or gauging paste on thegauge line.

The thief (Figure 5) can quickly show howmuch water is on the bottom of a tank. It isdropped into the tank and a bottom sample ispulled. While wearing plastic or rubbergloves, the lease pumper must pour thesample across the palm of one hand while itis over the thief hatch. As it turns from freeoil into sludge, the water and BS&W levelscan be determined. The thief manufacturedby the W. L. Walker Company is verycommonly used. Use of the thief is coveredmore extensively in Chapter 13, Testing,Treating, and Selling Crude Oil.

Figure 5. The Tulsa thief with brass andclear barrels, and a 12-inch trip rod.(courtesy of W.L. Walker Company)

The second way to determine water levelis by using a gauging paste such as KolorKut (Figure 6). This golden brown pastewill retain its color in crude oil, but will turna brilliant red when it comes into contactwith water. It is applied to the line at anestimated spot for the water level, then thetank is gauged. The use of Kolor Kut isfurther discussed in Chapter 13.

Figure 6. Kolor Kut paste.(courtesy of W.L. Walker Company)

12B-4

B-3. Gauging Oil and the Grease Book.

Before the lease pumper gauges the tank,an approximate gauge should already beknown. The pumper should know to thenearest ¼ inch how much oil there should beon any day based on the previous day’sreading and the expected daily production.

The pumper should carry a daily gaugebook or grease book that contains all gaugereadings over a period of several months.This book is not the same as the larger andmore extensive lease records book that iscarried in the glove compartment. The dailygauge book is small enough to be kept in apocket but is large enough to record gaugesfor four months to a year, depending uponhow it is set up and how extensively it isused. Occasionally a pumper will carry asmall pad while taking readings and thentransfer the gauge readings to the greasebook later. With this procedure the greasebook remains clean. The setup and use ofthe grease book is reviewed more thoroughlyin Chapter 19.

Gauging the stock tank. There aremultiple techniques for gauging tanks.Some gaugers lower the plumb bob into thetank by unreeling the handle, being carefulthat the line never touches the edge of thethief hatch but stays in the center of theopening. Others drop it in and step back withthe line almost horizontal as it is sliding overthe edge of the thief hatch and into the tank.By using a light thumb pressure on the line,it slides very freely into the tank.

Regardless of the technique used, the lineshould be slowed down several inchesbefore the plumb bob touches bottom. Thenit should be lowered gently by hand until theplumb bob touches the bottom lightly. Theline may need to be raised and lowered, orspudded, several times to work through

sludge but without bouncing the plumb bob.If the plumb bob is bounced even slightly,the line will produce false readings. Oil willsurge up the line, the plumb bob will lean tothe side, and the line will show as much as½ inch more oil than is in the tank.

The pumper must learn to gauge tanksaccurately. If a tank is gauged ten times, thereading should never vary more than 1/8 ofan inch between the highest and the lowestreadings. However, the lease pumper’sgauging procedures may result in slightlydifferent readings than those of othergaugers, such as the one who purchases theoil.

As soon as the tank has been gauged, thepumper should review the previous day’sgauge and calculate the production quantity.The number of barrels over or short shouldbe noted immediately. If the accuracy of thegauge is suspect or if the difference is toogreat, the tank should be gauged again.Section 12-C discusses the action needed ifthe oil is long or short.

Gauging water levels. Even if the oilreadings agree with what was expected, thegauger should check the water tank while atthe tank battery, look at the gauge level inthe sight glasses, and be sure that everythingis functioning normally. Meter readings atthe battery (such as the number of barrels ofwater to the disposal system) should be readand recorded.

Switching tanks and opening equalizerlines. Equalizer lines should always beopened well before they are needed. If thetank is available, the equalizer can beopened before a condition should cause thetank to overflow. It is embarrassing to washoil from the side of a tank because of amiscalculation, and this also createsunnecessary problems for the company.

12B-5

Alternate day gauging. When there are alarge number of wells to gauge, productionis marginal, and the leases are many milesapart, it may be more practical to gaugesome of the tank batteries every other day.This allows more time to work on the leaseand eliminates many miles of hard driving.

With a marginal lease it is occasionallyfeasible, when both management and thepumper agree, to split days off and not havea relief pumper. Some pumpers prefer thisapproach.

12B-6

12C-1

The Lease Pumper’s Handbook

Chapter 12Gauging and Analyzing Daily Production

Section C

ANALYZING DAILY PRODUCTION

When a stock tank is gauged (Figure 1),the anticipated production level may bedetected, or the level may be long (more oilthan expected) or short (less oil thanexpected). Usually if the production is shortor long, the pumper’s next action is to re-gauge the tank.

Figure 1. Gauging daily production ofcrude oil.

C-1. Problems with Short Production.

If the second gauge confirms that the tankis short, the pumper must investigate thereason for the loss. The four potential sitesof loss are:

· At the tank battery.· From a broken or plugged flow line.· At the well surface.· Downhole.

At the tank battery. Even if it is suspectedthat production was lost because a well

failed to produce as scheduled or because ofa problem downhole, the logical place tostart is at the tank battery after re-gauging.This should only take a few minutes tocheck out. A visual inspection upon arrivalat the property will have already confirmedthat there are no leaks, so if the problem is atthe battery, it must be in a vessel. Potentialproblems include:

· Oil in the separator gas line. There aremany causes that may prevent separatorsfrom functioning correctly. If a float hasbroken off in the separator, the totalemulsion may go down the gas line. Thiscan be determined in seconds byobserving the sight glass and feeling theaction of the float to dump valve linkageor by force dumping the pneumatic valvecontrol. A diaphragm control valve candevelop a gas leak. Mud daubers (smallwasps) can plug the vent holes inpneumatic valve breathing holes withmud if the holes do not have the correctscreened fitting.

· Oil is trapped in the heater/treaterwash tank. The oil level sight glass onthe heater/treater should be checked andthe gun barrel thiefed. If the oil dump linefrom these vessels plugs or an oil valve isclosed, the accumulating oil will forcewater down the water disposal line until itempties all of the water from the vessel.The oil will then go into the disposalsystem or to the pit. Water accumulation

12C-2

should be checked in both of these places.A glance at a functioning gauge glass willusually confirm or reject the possibility ofa heater/treater problem. Sight glassesthat are allowed to plug and become non-functional will cause problems inproduction analysis. They must be keptfully open and functioning correctly.

· Paraffin. Wax can accumulate at theoil/water interface level in the gun barreland seal off at the edges. This sealprevents proper oil/water separationaction and forces all liquid production outthe water disposal line. A steamer or hotoiler and chemical treatment is usuallyrequired to melt the paraffin and force itinto the produced oil tank. This is one ofthe many reasons that a gun barrel isperiodically checked for performance andmust have a satisfactory ladder orwalkway access.

The water disposal system should bechecked for excessive water accumulation. Ifwater disposal is metered, a readingcomparison from the past few days willreflect excessive water disposal. If these arenot the source of the problem, other systemsunique to the battery should be checked.

A flow line has broken or becomeplugged. These lines are normally inspectedon a regular schedule and are rarely thesource of the problem. However, to bethorough, they should be checked.

If the line is on the surface, it should bewalked—that is, the pumper should walkalong the line checking for leaks andplugged sections, occasionally tapping theline with a small hammer to locate plugs.The sound is more solid when it contains nogas. Lines under roadways become pluggedoccasionally. Use of conduit around the pipecan reduce this problem.

At the well surface. At the well, theproblem can be on the surface or downhole.Since it is much easier to check surfaceequipment, troubleshooting should beginhere. Surface problems at the well include:

· A well was accidentally turned off. Thisis a fairly common and simple mistake,especially among inexperienced pumpers.By producing the well for a short timeand gauging late, much of the shortagecan be made up the same day that itoccurs.

· Electrical failure. Electrical problemsare common. The pumping unit must beturned on to check for electricalproblems. This repair can be as simple aspushing the reset button or replacing afuse or as serious as changing out amotor. Fuse problems are often causedby using incorrectly rated fuses. Mostautomatic boxes can have more than onefuse. Occasionally, field mice and otheranimals can cause problems, such aschewed wiring, if the motor vents are notcovered with hail screen.

Figure 2. Forged steel Catawissa swingcheck valve.

(courtesy of Dandy Specialties, Inc.)

· A casing check valve may have failedto close properly. An example of acheck valve is shown in Figure 2. If thecasing check valve fails to close properly,the produced liquids may be circulatingback to the bottom of the well through

12C-3

the annulus. If this occurs, the bleederwill have exceptionally good pumpaction, but the well will produce no oil tothe tank battery. Often a simple cleaningof a check valve will correct the problem.To test the possibility of check valvefailure, close the casing valve for twohours with the well pumping, then reopenit. If a casing check valve also fails at thetank battery, it is not unusual for theproduction from other wells to flow backand be lost back into the formation.

· A leak in a casing check valve on thetubing will give a similar indication. Ifthe check valve is leaking, the leasepumper should re-gauge the stock tankfor a production increase.

· A valve accidentally left closed. As thegas pressure builds up in the annularspace and in the formation close to thewell, the well will stop producing oil.This is most likely to happen whenprocedures have been done at the wellthat required valves to be closed, such astreating the well with chemicals that werecirculated down the annular space.

When a closed valve is reopened, it shouldbe done very slowly. The pressure maybuild up to several hundred pounds and thissudden surge to the tank battery can rupturean atmospheric tank. The valve should beslightly opened and allowed to bleed off fora period of time. Opening should becompleted only after the pressure has bledoff. A valve should never be placed to thewide open position suddenly.

Sometimes the failure will be the result ofa combination of one or more of theseproblems.

Downhole. Some downhole problems thatlead to a loss of production, such as a worn-out pump, parted rods, or a hole in the

tubing, will require a well servicing job.Several other problems, however, can besolved from the surface without a pullingunit. Common problems include:

· Pump valve not seating. If the problemis in the pump, it may be determined byfirst opening the tubing bleeder valvewhile the unit is pumping. The pumpmay have trash under the standing ortraveling ball. The pump should belowered by raising the rod clamp abovethe pumping unit carrier bar and thenstarted. This will allow the downholepump to start bottoming out. With somewells this procedure may be necessary tostimulate the pump back into action.With wells on engines, pump tapping canbe started by merely increasing the RPMif it is spaced to meet this need.

· Gas lock. Pumps are occasionallyimproperly serviced by supplycompanies. Common problems caninclude use of a barrel that is too long ora pull rod that is too short. The twovalves are then too far apart when thepump is collapsed or pushed all the wayin. This can result in gas being trappedbetween the valves. Even when the rodsare lowered to make it tap, the only thingthat will break the gas lock is to eitherwait until the casing fluid builds upenough hydrostatic pressure to overridethe problem (which may require severaldays) or to unseat the pump to lower thehydrostatic head inside the tubing.Neither of these is a good solution.

· Salt bridges downhole will cause aproblem similar to closed valves with aresulting loss in production. To solvethis problem, the lease pumper must dropa load of fresh water down the annulus.This is very dangerous as fresh waterseals off some zones.

12C-4

· Plugged casing or tubing perforationscan prevent oil from entering the well.The casing can also fill become sandedup—that is, filled with sand from theproduction zone.

· A worn or failed pump may lead toproduction losses. Checking the leaserecord book may confirm this. The datesof the last several pump changes shouldbe checked. Pumps will usually last asimilar amount of time for a given well,so by checking how long the pump hasbeen in use, the problem can be isolatedas it begins to develop and before totalfailure occurs.

· Tubing can split due to a number ofreasons. Sometimes a split in the tubingwill seal as pressure is removed, only toopen again when the tubing ispressurized, allowing fluids to escapethrough the split.

Some downhole problems, such as a wornpump or split tubing, may be indicated by afailure to develop pressure in the tubing. Tocheck for this problem, the pump is run toplace pressure on the tubing. The test issimple, but it requires common sense andcaution. The proper method is as follows:

1. Place a pressure gauge in the pumpingbleeder valve.

2. Close the tubing wing valve to the tankbattery.

3. Turn the pumping unit for onerevolution.

4. Turn the pumping unit off.5. Check the gauge pressure.

CAUTION: Never look the gaugedirectly in the face for safety reasons.

6. If no pressure develops, repeat theprocedure.

7. After pressurizing the column, let it sit

for several minutes to allow time to notepressure changes.

The bleeder valve and other surfaceconnections may be standard pressurefittings, so extreme care should always beexercised when pressurizing a wellhead.The gas column in the tubing determineshow quickly the pressure comes up. If thetubing contains a full column of liquid, thepressure will escalate rapidly. On shallowwells after pressure has been pumped up onthe wellhead the rods will not fall, and thepumping unit bridle loses contact with therod clamp.

If the unit does not develop pressure, therod string may need to be lowered or othertests run. The problem should be reported toa supervisor before a well servicingcompany is called.

If the pump has good pump action but stilldoes not produce fluid, a problem such assplit tubing is likely.

Chapter 17 discusses downhole problemsin detail.

C-2. Problems with Overproduction.

If the oil gauge is higher than expected, thepumper should be pessimistic. While thereis a very remote possibility that a waterflood project has caused an increase, it ismuch more likely that there is a productionproblem. For example, there may be aplugged water leg line in the wash tank orheater/treater or possibly a closed watervalve. If thiefing a tank confirms that oil isbeing excessively produced, there is almostcertainly a plugged water drain line causingwater to rise in the wash tank orheater/treater, thus flushing excessiveamounts of oil to the stock tanks. Problemssuch as this normally occur in three-stagevessels that utilize a water leg.

12C-5

A quick check of the gauge glasses in theheater/treater, a Kolor Kut test on the gunbarrel, and a quick look at the water disposalsystem will usually indicate the location ofthe problem in a few minutes.

The problem must be solved quickly or allwater being produced from the wells willflow into the stock tank. The lease pumpershould make sure that stock tanks haveenough room so that excessive oilproduction cannot overflow onto the ground.

After the problem has been located andsolved, the correct amount of oil and waterwill need to be circulated back through theheater/treater so the system can be re-balanced.

Determining if the overproduction is oilor water. A good pumper who takes care ofthe lease well should always know howmuch BS&W is in every tank. The last runticket provides the reading as well as testsbefore sale of the oil. To determine if theoverproduction is oil or water, the pumpershould run a quick Kolor Kut test todetermine the bottom condition, thief thebottom of the tank, or if in doubt do both.Both of these tests can be performed in lessthan 15 minutes.

If a heater/treater or gun barrel is at thesite, the excess production will probably be

oil, and the tank battery is entering anunbalanced situation that must be broughtback into balance. The pumper shouldcheck all the sight glasses for level changes.

When the tank battery is still in balance.If all systems are known to be functioningnormally, then the oil must have come fromthe formation. The common causes forwells to overproduce are as follows:

· Increasing pumping unit time. Pumpingunit time can be increased and a smallamount of oil can be gained for a fewdays, but production will return to theoriginal level with the wells pumpinglonger. Pumping time costs money.However, if the pumper is overproducingthe wells, cutting back the pumping timewill cause a slight reduction inproduction for a few days. If thepumping time is sufficient, the wellsshould be produced efficiently inconsideration of time.

· A well has broken a gas lock. When apump breaks a gas lock, it will produceadditional oil until the annular space hasbeen emptied of liquid, then it will returnto the original production level.

12C-6

12D-1

The Lease Pumper’s Handbook

Chapter 12Gauging and Analyzing Daily Production

Section D

UNITIZING THE RESERVOIR AND COMMINGLING PRODUCTION.

D-1. Satellite Tank Batteries.

A satellite tank battery is a sub-tankbattery located between part of the wells andthe main tank battery. Gas may be sold froma satellite tank battery and water may beremoved and pumped into the water disposalsystem, but the oil is retained and piped tothe main tank battery where it is combinedwith other oil produced from the lease.Satellite tank batteries are used on leaseswhere wells are scattered over a large area tosimplify operations and reduce line lengths.

Figure 1 illustrates a large satellite tankbattery with the header located at the farright. Next is a line heater that prevents theregular separator from developing ice in theline during winter months. There are twovertical separators, one heater/treater fortesting the wells, and a communicationbuilding that contains equipment to send amessage to both the lease pumper and ananswering service when problems occur. Italso has the ability to shut in all the wells.In addition, it can be set up to automaticallytest the wells in a rotating manner.

Figure 1. A large satellite tank batterywith no stock tanks.

D-2. Problems and Solutions forCombined Flow Lines.

Production operations that flow theproduced emulsion from two or more wellsthrough one common flow line to the tankbattery is the simplest form of a satellitearrangement. This saves the oil companythe cost of purchasing and installing newlong flow lines as well as futuremaintenance of the second or third line.

While the cost of a flow line can be saved,this arrangement presents new problems tothe lease pumper. For example, how can amonthly production test on each well beobtained without shutting in each well forone day each month during testing? Evenmore important when producing marginalwells is the problem of testing combinedemulsions. Until all oil and water in theflow line junction point of the two lines tothe tank battery is produced, the combinedemulsion is being tested. A large part of thetest emulsion is still contained in the flowline when the test is over.

The individual well tester. The obviousanswer to the testing problem is to move thewell test to the well location site, rather thanperforming it at the tank battery. Afterselecting a convenient spot near the well orthe edge of the location, a testing manifoldcan be installed. The junction point can beturned into a satellite tank battery. A typicaltester is shown in Figure 2. The testing

12D-2

manifold is made by cutting the line andplacing the following fittings into it in theorder given:

· Tee· 6-inch nipple· Plug valve· 6-inch nipple· Second tee· 6-inch nipple· Union.

Figure 2. An individual well tester with aquarter-barrel dump used to test wells at

the well location.

The tees are installed running, and in eachtee a 6-inch nipple and a plug valve areinstalled, completing the test manifold.Optionally the two test valves can be leftstanding vertically or pointing to the sidewith all three valve stems pointing up. Thisis the most common position.

A trailer-mounted individual well testercan be brought to the well location. Onceconnected with satisfactory pressure-ratedflexible hoses it is ready to test the well.The individual well tester will allow thepumper to separate the entering emulsioninto gas and liquid, measure the amount ofeach, then allow them to recombine into theflow line to be produced to the tank battery.A sampler will periodically take a liquid

sample. At the end of the test the liquidsample is blended, then two samples areremoved and run through a shake-outmachine or centrifuge to determine thepercentages of oil and water in the producedfluid. This, along with a gas chart withappropriate information, completes the test.

Well tests at the satellite tank batteries.Occasionally, it is not satisfactory to movewell testing to each individual well location,making it necessary to move the testingequipment to the junction point where linescome together. At this point a bypass headershould be installed that connects all wells toa test separator. One well at a time shouldbe diverted through the test separator fortesting purposes. Occasionally, however,there are other needs, such as separating thewater for water disposal or gas sales to thegas company.

This creates a recognizable satellite tankbattery. It does not necessarily contain aflow splitter, but instead may containheater/treaters, line heaters, water tanks, orother combinations of equipment. The ruleof thumb is that the equipment is installed tomeet the operator’s needs. There willseldom be two identical satellite tankbatteries.

Operation of satellite tank batteries.Common functions of a satellite tank batteryinclude:

· Well testing· Water separation for disposal· Gas separation for sale or re-injection· Pre-treatment of oil or water.

The operation of the satellite tank batterywill be defined by the operator. Since thepurpose and style vary widely, it is notpossible to define every situation.

12D-3

D-3. Unitizing Fields Under OneOperator.

Whole books have been written explainingthe need and processes for unitizing anoilfield. This section includes only some ofthe high points.

When a field is unitized, one operator,usually a major operator of the wells in thereservoir, will take over the operation of thereservoir and field for the life of the wells.This unitized field is a long-term operation.

Every well in the field is tested withapproved witnesses observing every welltest. These individual daily well tests recordthe ability of each well to produce gas, oil,and water. All of these figures are addedtogether, and a percentage value of the unitfor each well and operator is established.

The unitized field protects all well ownersfrom suffering formation abuse to theirinterests by those operators who producetheir wells in a manner that benefit themonly while causing damage and loss ofproduction to others. It also allowsbeneficial enhanced recovery practices tobegin and end as needed. Pressuremaintenance can be implemented at higherelevations and there can be water flood atthe lower sections.

D-4. Commingling Different Pay Zones.

When the operator has a small amount ofproduction from two different pay zones, therights to production are owned by the sameindividual or agency, and the two crudes aresimilar in gravity, it is possible to get apermit to produce them into a common tankbattery or commingle the productiontogether. This allows the oil to be sold morefrequently and reduces the loss of the lighterends into the atmosphere. It also eliminatesthe need to construct two separate tankbatteries.

The operator is still responsible, however,for accounting for how much oil, gas, andwater was produced from each of the twozones. Two separators or heater/treatersmay be required as well as provisions tometer all of the fluids produced from eachreservoir. The tank battery is usuallyidentical to a tank battery designed tocombine the production facilities from twodifferent operators. This is reviewed in thenext two sections.

D-5. Unitizing a Reservoir.

Unitized field operations occur only infields where two or more operators haveproducing wells in the same pay zone.When a reservoir is large it may extendseveral miles in length and width. All wellsmay produce from similar distances above orbelow sea level, or the field may be on anincline and be much higher at one end thanthe other.

Problems in production that justify theneed for unitization. Wells produce atdifferent rates in the same field. If thereservoir is on an angle and is water driven,the operators on the higher level willproduce at a high gas-to-oil ratio. In thissituation, wells produce a large amount ofgas and very little oil. Operators who haveproduction in the center of the reservoir willproduce a large amount of oil with very littlegas. This lease has a low gas-to-oil ratio.The operators at the lower edge of thereservoir will produce less oil and morewater.

Over time, every action of an operator willaffect the other operators. If the operator onthe upper areas produces a high rate of gasand very little oil, this will lower thepressure on the upper end and cause the oiland water at the lower zones to begin

12D-4

moving toward this area and upward. Theoperator in the middle will begin to losereservoir pressure, and water will begin tomigrate in. The operator whose wells are inthe lower zone will be affected by all of theoperators with wells in the upper and middlezones. The gas pressure will fall, oilproduction will decline, and water willincrease.

The effects of unitizing. When the field orreservoir is unitized, one operator takes overthe operation of all wells in that reservoirand operates them as an independent oilcompany. Usually the oil company with alarger investment and a higher capability forproducing wells efficiently is selected as theoperator. As part of the procedure forcreating the unit, all wells are witness testedand their rate of production established.Several other factors are included, and eachoperator is guaranteed a share of the profitsaccording to the value of the company’sshare of the unit. The practice ofoverproducing high-volume gas wells willbe adjusted, and a pressure maintenanceprogram will begin. The water will bereinjected in the lower zone. In the long rungross production may be increased, but thelife of the field may be extendeddramatically. The operating company willbe allowed to recover all operating costsbefore profits are distributed.

D-6. Commingling Wells with DifferentWell Operators.

To develop the ability to survive in a toughoil market, operators search for methods tolower company costs. One method gainingin popularity is to combine some of the fieldoperations to operate as one company.Figures 3 and 4 reflect how a commingledtank battery might look.

Figure 3. A commingled tank battery withtwo operators. The battery has three

tanks, four heater/treaters, and three gasmeter runs.

Figure 4. Two of the heater/treaters canbe owned by the operators and the third

reserved for treating oil in the tankbattery. The fourth is used for well

testing

On the left side of Figure 3 are three gasmeters and the stock tanks. On the right arefour heater/treaters.

Each company in the scenario tank batteryhas its own heater/treater with the producedcrude oil dumping to one common tankbattery. Each company has its own signnearby identifying company ownership. Atthe lower left of each heater/treater, a smallmetering separator has been installed tomeasure oil production before it is dumpedinto the common or joint venture stocktanks.

Figure 5 is a picture taken at the back ofthe heater/treaters, looking toward the stocktanks and three gas sales meters. Two are

12D-5

for the individual operators and the third isjointly owned as part of the tank battery. Thecirculating pump is located between the tankbattery and the heater/treaters forconvenience in treating the oil. It can alsobe set on automatic scheduling forcontinuous treatment.

Figure 5. Each operator owns one header,and the closer line goes to the test

heater/treater. The test gas meter is atright.

Also at the back of the heater/treaters aretwo company headers to direct the flow ofoil from the wells toward the heater/treaters.The header has a second manifold thatpermits the wells to be directed toward thetest heater/treater. The gas meter to the rightmeasures the produced gas from the testheater/treater and is then directed back intothe operator’s gas system.

The small metering separator (Figure 6) isset at the base of the heater/treater andoperates at the identical gas pressure. Byusing gas-operated motor valves, themetering separator can be alternately filledwith oil, then dumped to the tank battery. Itis recorded each time it is dumped. Thesegauges are read daily at approximately thesame time to record how the wells areproducing.

Figure 6. The small metering separatorthat measures the oil from the

heater/treater before it is commingled inthe tank battery.

D-7. Working for More than OneOperator.

It is not unusual for a lease pumper towork for more than one operator. If thelease pumper is a contract pumper and isdriving a personally owned vehicle, thisshould not create too great a problem,especially for one or two isolated nearbywells.

However, if the lease pumper is driving acompany-owned pickup, consumingcompany-purchased fuel, and working aneight hour day, it would not be possible tocontract pump other wells unless it was fullyauthorized and approved by the companythat is supplying the vehicle and fuel. In thissituation the payment check should go to thecompany and a special agreement forpayment to the pumper for extra work timeagreed upon.

There are so many possibilities of how awork agreement with the employer can beagreed upon that common sense mustprevail to prevent problems fromdeveloping. If the pumper is working for asmall company, a workable agreement may

12D-6

be possible. The company may evenwelcome the pumper establishing theagreement. The larger the company is,however, the more difficult it becomes towork for two operators. The employingcompany has enough work for the pumper toconsume the entire workday, and it may notbe possible to split time. Whether or not itis a gauge and telephone only situation orrequires some physical work when it isindicated is another factor. Some work

situations can consume considerable worktime, and one job or the other may suffer forlack of attention when needed.

When considering accepting a second part-time job, the pumper should:

· Secure approval from the primaryemployer if needed.

· Not let regular work suffer because of thedivided responsibilities.

12E-1

The Lease Pumper’s Handbook

Chapter 12Gauging and Analyzing Daily Production

Section E

REPAIRS AND MAINTENANCE

E-1. Effects of Reduced Production.

The lease pumper is expected tocontinually maintain and repair everythingmechanical in the field. For example, whenthere is a flat on the lease vehicle, thepunctured tire is not automatically discarded.If it is repairable, it should be patched andexpected to continue to give satisfactoryperformance for the life of the tire.

This is also true for the tank battery,pumping units, engines, equipment that hasbeen pulled out of service, other materialsstored in the pipe yard, and all equipment onthe lease. All of the equipment ismanufactured to be repairable, and the leasepumper must learn to maintain manysystems. A lease with high oil productionwill have more funds available for contractand company repair personnel, but thecompany will still strive for maximumefficiency and production.

As production declines, so do the dollarsavailable for maintenance and repairsupport. As production declines to marginalwell level, it may approach the point wherethe operator will lose money if the companycontracts out many repairs. In this situation,the lease pumper wears many hats, must beskilled at many lease maintenance tasks, andis a highly valued employee.

This does not imply that the job is moredifficult but that job duties are more varied.As production declines, the entire leaseslows down. Since less oil is produced there

is more time available for treating. Thisadded time requires less chemical perhundred barrels for treatment because thereis additional circulation time to give moretreating and settling time.

The tank battery is also easier to operateand maintain. Less automated equipmentwill be required on the lease. As formationpressure declines, the volume of gasproduced may drop so low that gas is ventedat the well casing valve, a vacuum may bepulled on the formation, and the tank batterymay not produce enough gas to sell. Theheater/treater may be switched toatmospheric operation rather thanpressurized and during the warmer monthsact just as a three-stage separator. As thesechanges begin, the lease pumper’s jobdescription also changes to meet the leaseneeds.

E-2. A Reasonable Workload.

As lease income is reduced, the pumperwill perform some duties that wouldnormally be performed by other personnelwhen the income was greater. The leaseoperator, however, must limit the amount ofphysical effort lifting jobs that the leasepumper is expected to perform to a level thatone person can safely perform.

The lease pumper must be skilled in anumber of tasks and willingly perform leasetasks that are acceptable for one person todo. The lease pumper must also recognize

12E-2

that some jobs require two or more people tosafely perform, and a single individualshould not be required or expected toperform these alone. Some safety rulesinclude the following:

· Use common sense in every taskperformed. Never take needlesschances.

· Avoid lifting objects that are too heavyfor one person.

· Safety comes first. Sometimes a tasktakes longer to do it safely. Take the safeway.

· The lease operator must always observethe same practices and insist that goodfield procedures always be followed.

E-3. At the Tank Battery.

The lease pumper is commonly expectedto perform the following maintenance tasks:

· Repair small leaks on the sides of vessels.These are usually low on the vessels andrepaired with patches and plugs. Alwayslower the level of the liquid in the vesselbelow the spot being repaired. Never tryto patch a leak on the side when the oillevel is above the leak.

· Clean oil spots on tanks as they are made.Keep everything as clean as possible.

· Cut weeds around walkways andautomatic control boxes, especially wheresnakes are common.

· Do not allow bees to make hives in theequipment.

· Tighten small fittings when they seep oil.Always remove the pressure first.

· Lubricate plug valves as needed.· Replace valve stem packing as needed.· Adjust linkage on dump valves.· Install leak clamps.

· Tighten bolts when bolted tanks leak.· Clean and replace sight glasses.· Paint repaired items that cannot be

allowed to rust.· Adjust temperature controls.· Maintain automated equipment.

E-4. Leaks in Lines.

The lease pumper is usually expected toinstall leak clamps on flow lines whenneeded. Repairing leaks can be extremelydangerous, especially when working alone.Gas cannot be smelled after a few minutesor seconds, so lines should be repaired afterbleeding the pressure off the line. Noassistance is typically available to a leasepumper fixing leaks.

Upwind precautions when gas is present.A person should always be positionedupwind from a natural gas source. However,the breeze passing on both sides of a personcreates a low pressure area in front. Gas issucked towards the person’s face. Standinga little to the right or left will break thevacuum effect and will reduce the amount ofgas being sucked up into the face. Whengauging a tank, the lease pumper should alsostand with the wind directly at the back,facing the direction the windsock points(Figure 1) and turned slightly to one side sothe wind will keep the gas out of the face.

Figure 1. During maintenance, the leasepumper must remain aware of wind

direction.

12E-3

E-5. Pumping Unit and WellheadMaintenance.

The lease pumper is always required toservice pumping units. This includeslubricating bearings and maintaining gear oillevels. On small units the pumper may alsobe expected to perform the following tasks:

· Tighten belts and adjust as needed.· Replace belts when needed.· Lower rods to bump bottom and raise

them back up to stimulate pumping.· Pack stuffing boxes and adjust packing as

needed.· Replace fuses when they burn out.· Maintain chemical pumps.· Batch treat wells with chemical by

dumping it down the annulus.

E-6. Automation Control Maintenance.

There are many actions that the leasepumper can take to keep automatedequipment functioning correctly. Theequipment manufacturer is usually verycooperative in supplying the neededliterature to explain how a piece ofequipment operates. Local supplycompanies can offer invaluable advice onwhere to acquire this information.

The functions of most unfamiliar itemsthat need to be repaired can be understoodafter careful examination. Good fieldmechanics do this on a regular basis andperform a good job. The pumper should nothesitate to ask questions of other people.These tasks will become easier asexperienced is gained.

12E-4

13-i

The Lease Pumper’s Handbook

CHAPTER 13

TESTING, TREATING, AND SELLING CRUDE OIL

A. TESTING AND TREATING1. Treating Oil, Corrosion, and Scale.

· Treating crude oil before sales.· Reducing corrosion damage.· Scale deposits and sand stabilization.

2. Testing Crude Oil.· Eight inches of emulsion and thiefing the bottom.· Tagging bottom with the thief.· Checking the bottom.· 1% or less BS&W and the centrifuge.· Oil temperature correction.· API gravity and the hydrometer.

B. METHODS USED TO TREAT BS&W.1. Overview of Treating Methods.2. Gravity.

· Flash and slow water gravity separation in treating crude oil.3. The Use of Time in Treating Oil.4. Separating Crude Oil and BS&W by Movement.5. The Effects of Chemicals in Treating Crude Oil.6. The Effects of Heat in Treating Crude Oil.7. Treating Oil by Chemical-Electrical Processes.

C. TREATING WITH CHEMICALS.1. Purposes of Treating Chemicals.

· The use of detergents to remove water.· Use of solvents for paraffin.· Bottom breakers for tank bottom emulsions.

2. Introduction to Chemical Injectors, Styles, and Operation.·· Treating oil at the tubing perforations or downhole.· Injecting chemicals at the tank battery.· Producing sellable crude oil.· Batch treatment while circulating.

3. Special Treating Processes.· Cleaning tank bottoms.· The hot oiler.· The slop tank.

D. SELLING CRUDE OIL1. Preparing to Sell the Oil.

13-ii

· End of the month oil sales overload.2. Selling Oil.

· Requirements for a full transport load.· Selling split loads.· Communication with the gauger.· The note jar.· Witnessing the oil sale and the rejection notice.

3. Seals and Seal Accounting.· The run ticket.

4. Selling Oil by Use of the LACT Unit and Surge Tanks.· Hot oiling.

13A-1

The Lease Pumper’s Handbook

Chapter 13Testing, Treating, and Selling Crude Oil

Section A

TESTING AND TREATING

There are several reasons why the leasepumper chemically treats crude oil systems.The pumper needs to understand chemical-related problems and how treatment can helpalleviate the problem. Typical reasons fortreatment include:

· Removing water from produced crude oil· Treating produced water prior to re-

injection· Preserving casing and tubing from

corrosion· Reducing paraffin and asphalt

accumulation· Reducing scale accumulation· Preventing gas sales lines from freezing

A-1. Treating Oil, Corrosion, and Scale.

The lease pumper stores chemicals on thelease that have been formulated to meetseveral treating needs. Chemicals are oftendelivered in 55-gallon drums. Becausepaper labels deteriorate over time, drumsstored on the lease should be marked with apaint marking stick for future reference andidentification. Recording procedures areincluded in Chapter 19, Record-Keeping.

The purposes for these chemicals include:

· Treating crude oil before sales· Reducing corrosion damage· Scale deposits and sand stabilization

Treating crude oil before sales. Mostchemicals for treating crude oil are used tolower the BS&W content to an acceptablelevel prior to sale. There are several types ofchemicals for treating oil, and chemicalcompanies use different terminology todescribe the same compound. The pumpermust understand the purpose of each type,know when to use them, and always be aseconomical as possible when using them.Chemicals may be water-soluble, oil-soluble, or soluble in either.

Oil treating chemicals include:

· Oxygen scavenger· Corrosion inhibitor· Surfactant (a soap)· Paraffin solvent (a thinner)· Demulsifier· Other chemicals according to need.

Overuse of some chemicals can causeemulsion problems that require veryexpensive solutions. Some chemicals areused to solve problems created byovertreating. These are much moreexpensive than basic treating chemicals.

Reducing corrosion damage. Corrosioncan be a big problem and can occurdownhole by eating holes in either thetubing and casing or in surface facilities.Corrosion inhibitors prevent this.

13A-2

Scale deposits and sand stabilization.Scale is treated as it enters the productionsystem and in the formation before it candevelop. Scale inhibitors must be matchedto the conditions of the produced water.

A-2. Testing Crude Oil.

Long before a sellable amount of crude oilin the stock tank has accumulated, animportant task is to test the oil to determineif the BS&W level is low enough to beaccepted by the pipeline or trucktransporting company gauger. The gaugerwill usually be more careful in analyzing theoil if the pumper witnesses gauging andtesting procedures.

Eight inches of emulsion and thiefing thebottom. The BS&W or emulsion levelaccumulated on the bottom of the stock tankmust be no more than what the localpurchaser allows, typically 8 inches or less.The content of this heavy BS&W emulsionis usually a mixture of crude oil, salt water,paraffin, possibly a small amount of asphalt,formation sand, and a host of othercompounds. This mixture is heavier thanfree crude oil so it falls to the bottom andmay float on the water. Water in oilproduction is usually as salty as ocean water.The sand can be finer than bath powder andis, therefore, difficult to separate.

Crude oil weighs less than 8 pounds pergallon. Fresh water weighs 8.33 pounds pergallon. Produced salt water usually weighsmore than 8.33 pounds per gallon andreaches a natural saturation point at about9.6 pounds. This mixture is homogenizedand blended together and is difficult to treatand separate. Free saltwater will migrate tothe bottom. When the tank is thiefed, thestratifying of oil, BS&W, and free waterbecomes obvious.

This natural separation can occasionally beused to a distinct advantage when treatingtank bottoms. If neglected, the bottomemulsion will become so heavy that thepumper will have to spud the plumb bobthrough it to gauge the tank.

Tagging bottom with the thief. Whentagging bottom with the thief, the graduatedtrip rod must be set accurately. As the thiefapproaches bottom, it must move veryslowly to prevent agitation that would resultin a false reading. After tagging bottom, thethief should be lifted approximately one inchand then dropped sharply.

If the thief is lifted five or six inchesvigorously and then dropped, BS&W will beagitated. The test will indicate a higherbottom than is actually present, as well as agreater BS&W percentage for the bottomshakeout. After excessive stirring of thebottom, an accurate reading may not bepossible until sufficient time has beenallowed for settling.

Checking the bottom. To check the bottomlevel, the lease pumper should follow thisprocedure:

1. Put on plastic gloves.2. Lower the thief to the bottom of the

tank.3. Secure the sample.4. Bring it back to the top.5. Give it a side twitch after the top of the

thief has cleared the oil to allow a smallamount of oil to spill out.

6. When it stops dripping, lift the thief outof the tank with one hand and place arag under the bottom of the thief withthe other hand to keep the tank clean.

7. Slowly pour the oil out of the top of thethief across the palm of the other glovedhand. With close observation, it can

13A-3

easily be seen when the oil thickens andturns to emulsion.

8. Hold the thief vertically again and lookinside as well as outside. The level ofthe emulsion remaining in the thief canbe easily read. This is the height of thetank bottom. The side of the thief ismarked in inches.

As remaining emulsion is poured back intothe tank, the point at which free waterappears can also be determined.

1% or less BS&W and the centrifuge.BS&W contained in the crude must notexceed the maximum levels specified by thecrude purchaser—usually less than 1%. Todetermine this, the lease pumper should usethe following procedure:

1. Take one sample of crude oil from nearthe top.

2. Take a second sample approximately 10or 12 inches above the bottom.

3. Place the two samples in a centrifugeand determine the amount of BS&W ineach.

4. Add these two values together.5. Divide by two.

This computation gives the averageBS&W throughout the tank. Since theaverage is computed on a straight line andactual contamination is on a curved line, theoil purchaser has a small “shakeout”advantage.

To make the reading more accurate,another step can be added that involvestaking a third sample from the center of thetank and dividing by three. Occasionally atank will test as sellable by the three-samplemethod, while it would be rejected under thetwo-sample method.

There are several popular styles ofcentrifuges and three styles of tubes:

· 12.5 milliliter (ml)· 100 ml pear-shaped· 100 ml short cone-shaped.

Centrifuge tubes are expensive, so extremecare should be taken in handling them.

When oil is sold, the 100-ml tube isgenerally used to analyze the sample. Thepear-shaped tube is more accurate when verylow percentages of BS&W need to bemeasured.

The 12.5-ml size hand shakeout machineis commonly used and is satisfactory forestimates. A sturdy bracket should be madeand fastened securely to the bed of thepickup to support the unit when in use. It ispossible to fasten it to the tank battery stepsor on a board, but the bracket is usuallymore workable. When properly maintained,the machine will last for years. Repair partscan be ordered from supply companies.

Oil temperature correction. It is moredifficult to treat cold oil than warm oil.When slow moving oil is produced from thewell, it will be approximately thetemperature of the earth that it is comingthrough. Deep wells are hotter at the bottomthan shallow wells, and as oil rises in thewell and leaves the production zone, itbecomes cooler. As oil cools, it does notflow as easily, and the viscosity becomesthicker, thus supporting more BS&W. Aheater/treater may be needed to heat the oilto assist in separation, especially in winter.Flow lines in most sections of the countryare left on top of the ground to absorb theheat from the sun in order to treat theBS&W out of the oil. If chemical is injectedat the wellhead or at the bottom of the wellthrough the annulus, the treating processmay be easier. In winter the oil should betreated as quickly as possible before itbecomes colder on the surface.

13A-4

When the purchase price of crude oil isquoted, it must be at an exact temperatureand gravity with no contamination to receivethe posted price. The Scoop Master tankthermometer is an accurately computeddevice that contains a holding pocket toreduce temperature changes while it is beingread. It is attached to the gauger’s tray by acord that allows it to be lowered into themiddle of the tank of oil to obtain the exacttemperature.

When oil is sold, the number of barrels iscomputed, then the temperature correctionfactor is applied. If the oil is cold, thisfactor will increase the number of barrelsshown as sold. If the oil temperature isabove the temperature at the quoted price,the number of barrels computed as sold willbe reduced.

API gravity and the hydrometer. Thereare two methods for computing gravity. Thespecific gravity method compares the weightof oil to an identical volume of water at thesame temperature. Under this system, purewater at 60° Fahrenheit represents a specificgravity of 1.000. A lighter liquid wouldhave a value less than 1.000, while a liquidheavier than water would have a higherspecific gravity.

The API gravity system sets the value ofwater at 60° Fahrenheit as 10. However, inthe API method, a lighter liquid has a highervalue. Oil will usually measure more than15 but less than 50. Condensate will rangeabove 50 into the 70s. As the number getslower, the oil will be thicker, darker, andmore difficult to treat. As the number getshigher, it will be thinner. As it approachesdistillate, it may give the appearance of

uncolored gasoline or kerosene. The higherthe API gravity, the easier it is to treat. 16gravity oil weighs approximately 8 poundsper gallon and 336 pounds per barrel. 50gravity oil weighs 6.51 pounds per gallonand 273 pounds per barrel.

The API gravity of all oil sold isdetermined by the use of a hydrometer. Inorder to obtain the gravity of the oil, thefollowing procedure is used:

1. Lower the thief to approximately thecenter of the tank.

2. Trip it closed.3. Raise it up to where the support lip of

the thief can be hung on the side of thehatch.

4. Gently lower the appropriate hydrometerinto the oil and allow it to float until thetemperature of the hydrometer adjusts tothe temperature of the oil.

The hydrometer will have a range of 10-20points. The hydrometer will float in the oilat the level of the gravity indicated at the topof the liquid.

The transport driver carries a set of 3 to 4hydrometers in a case that will cover therange of gravity readings for all of the oilproduced in the field, from distillate to aheavy gravity. Each gravity level has avalue or reduction in the quoted price of thecrude. This cost impact is one reason whythe pumper must analyze the oil prior to thesale. The pumper must know the readingthat the transport driver should indicate onthe run ticket.

13B-1

The Lease Pumper’s Handbook

Chapter 13Testing, Treating, and Selling Crude Oil

Section B

METHODS USED TO TREAT BS&W

B-1. Overview of Treating Methods.

Separation is the procedure whereby amixed fluid of gas, oil, and water separatesinto these different components. Manyfactors influence the separation of water andoil, and often work at the same time withvarious degrees of success. Some of themore important factors include:

· Gravity· Time· Movement· Chemicals· Heat· Electricity.

A knowledgeable pumper understands allfactors and combinations of factors thatresult in a good pipeline oil separation witha minimum drain on time and expensivechemicals. As wells become marginal andproduction is from the final stripping of thereservoir, the oil can become much moreemulsified and difficult to treat.

B-2. Gravity.

Gravity causes the separation of crude oiland water. Water will slowly separate fromthe crude oil from the time it is produceduntil it is sold. The water can be free water,which falls out rapidly, or it can beemulsified with oil, paraffin, and otherelements and compounds, become very

difficult to separate, and require a lot oftime. This natural separation also occurs atan ever slower rate.

Gravity affects larger droplets of watermore forcefully, causing them to sink to thebottom more rapidly. Smaller droplets fallslower than larger droplets. Crude oil islighter than salt water, and gravity will causethe water to work toward the bottom. Thesmaller the droplet of water, the less thegravity pull and the harder it is to remove. Ifthe heavier water can be broken loose fromthe oil and paraffin, then gravity will causethe water to work its way down through theliquid to the bottom of the vessel. Paraffinand other compounds form a strong surfacetension around these droplets, and with lowgravity oil the tension cannot be reducedwithout assistance by the use of time,movement, chemical, heat, electricity, or acombination of procedures.

Flash and slow water gravity separationin treating crude oil. To successfully treatcrude oil and make it sellable, the pumperneeds to consider what needs to beaccomplished and the best way to proceed toachieve that goal. Two concepts to fullyunderstand are flash separation and slowseparation. If separation occurs within a fewminutes, it is referred to as flash separation.Slow separation requires hours or days.

After these fluids have separated, they areusually removed from the vessels throughdifferent lines.

13B-2

B-3. The Use of Time in Treating Oil.

It takes time to break the water out of theoil. Some produced water will separate soslowly that it would require far more timethan is available, so action is taken to beginthis process as soon as a last tank of oil issold. If a pumper waits until a tank of oil isalmost full before treatment, the ability touse time is lost.

Many decisions concerning time aregoverned by how much oil is produced andthe treating problems anticipated. If oil issold every few days from a tank battery andhas treating problems, the pumper shouldbegin treating the oil as soon as it is takenoff the sales line. More chemicals than usualcan be used because, with frequent sales,income is higher and funds are available.

If the wells are marginal producers,production is low, and there can be severalweeks or even months between sales. Thepumper will have a lot of time but not muchchemical available because of the lowincome. The pumper will learn how to usetime and movement and natural separationto an advantage.

B-4. Separating Crude Oil and BS&W byMovement.

Total separation is not feasible. Asemulsion falls out, it accumulates near thebottom of the tank. The emulsion must berecirculated with crude oil from the stocktank back through the separation cycle toassist the process and keep tank bottomsclean.

Movement is the cheapest of all treatingprocesses after time alone. If a smallamount of oil is regularly circulated from thestock tank through the heater/treater or washtank (gun barrel), this movement alone willtreat much of the water out of the oil.

B-5. The Effects of Chemicals in TreatingCrude Oil.

Chemicals are one of the most effectiveand common methods of treating water outof crude oil. An oil soluble surfactant canbe added to the crude oil either at thewellhead or just ahead of the separator orfirst tank battery vessel. This oil solublechemical is usually a form of soap thatreduces the surface tension in paraffin andwater droplets. This allows the water toseparate by breaking apart from thehydrocarbons.

Figure 1. A chemical reservoir tank,electric pump, and lines for chemicalinjection at the wellhead. Note that

chemical identification information hasnot yet been added.

Treating oil is just one of many reasons forusing chemicals on the lease. The pumpershould know the functions of all chemicalsand how to apply them properly.

13B-3

B-6. The Effects of Heat in TreatingCrude Oil.

Heater/treaters (Figure 3) are usedextensively to heat and treat crude oil. Heatis applied to the crude oil by both the sunand by burners in heater/treaters.

Figure 3. Chem-electric heater/treater fortreating crude oil.

When possible, flow lines are left on thesurface in order to take advantage of

summer heat. During this time, heat isturned off and the vessel becomes a largethree-stage separator.

As little heat as possible is used to treatoil. Some oil companies have set up anobjective of eliminating all use of heat andfire boxes in treating oil. This is anextremely aggressive approach that willresult in a dramatic reduction in lease gasconsumption. However, technology tocompletely eliminate heating from thetreating process is several years away.

B-7. Treating Oil by Chemical-ElectricalProcesses.

The electrical heater/treater is the mosteffective method for treating high volumesof crude oil. Because of the cost ofelectricity, this method is not practical forextremely low producing wells.

One chem-electric heater/treater will out-perform several standard verticalheater/treaters. Consequently, it is verypopular where there are large volumes totreat as well as offshore where platformspace is extremely expensive to build.

13B-4

13C-1

The Lease Pumper’s Handbook

Chapter 13Testing, Treating, and Selling Crude Oil

Section C

TREATING WITH CHEMICALS

C-1. Purposes of Treating Chemicals.

Many substances are produced along withoil and gas. Water, salt, paraffin, asphalt,iron, sulfur, and sand create many emulsionsand compounds that become difficult totreat. These must be reduced to acceptablelevels in order to sell oil and gas.

It can be confusing to the new leasepumper to dive right into terms such asdemulsifiers, emulsion breakers, wettingagents, and other terminology. Instead, theexplanations in this chapter will begin bydescribing the end objective of treating oil,the basic problem that needs to be solved,and how these goals can be reached.

The use of detergents to remove water.The primary agent used to reduce surfacetension of oil and water droplets is a soap-like compound called a surfactant. Thesurfactant can be both water- and oil-soluble. It is used to reduce the surfacetension and viscosity of heavy crudes andcan assist in removing iron sulfide.Detergents are often used in chemicaltreatments of oil to remove water. Also,they reduce the surface tension in emulsionsto allow small droplets to form into largerones that can then be separated by gravity.

Use of solvents for paraffin. Paraffinsolvents are used to thin paraffin and lowerviscosity. These can be used downhole to

prevent paraffin from clinging to the insideof the tubing, and in the tank battery to thinparaffin and reduce surface tension. It has ahigh penetrating capability similar to casinghead gasoline or drip that condenses in gastransmission pipelines. Casing headgasoline can be very volatile or explosive. Itcan be used everywhere oil is treated and isusually not as expensive as surfactant-basedchemicals.

Bottom breakers for tank bottomemulsions. Bottom breakers are chemicalsthat are used to reduce the viscosity of theemulsions that accumulate on the bottoms oftanks. They are the most expensive of thecommon oil treating chemicals. A five-gallon container will usually cost more than$100 and may need to be specially blendedfor unique site problems.

Other treating chemicals and mixtures areavailable but are also usually directedtoward solving these three problems.

C-2. Introduction to Chemical Injectors,Styles, and Operation.

Several styles of chemical injectors orchemical pumps are pictured in this chapter.Appendix E gives an overview ofmechanical, electrical, and pneumaticchemical pumps and special treatingequipment.

13C-2

It is desirable to begin treatment as early aspossible. As a rule, it is too expensive tobegin the treatment in the formation.Treating for sand and scale production maypossibly begin in the formation, but treatingfor BS&W in crude oil usually begins at theperforations where it enters the well, theChristmas tree or pumping wellhead, or thetank battery. Accurate injection recordsshould be kept by the lease pumper, andwhen chemicals are added, consumptionshould be calculated regularly.

Treating oil at the tubing perforations ordownhole. Figure 1 illustrates a typicalinstallation where the objective is to treat oilbefore it reaches the surface. Oil is injectedinto the casing on the side of the wellheadopposite the casing valve that allowsformation gas to be produced into the flowline.

Figure 1. Chemical injection to treat oil atthe perforations at the bottom of the well.

A small stainless steel bypass line from thebleeder opening of the pumping tee allows asmall stream of circulating fluid to beinjected with the chemicals. This increasesthe total volume of fluid and reduces thetime required for the chemicals to reachbottom.

A check valve is installed near thepumping tee to prevent the chemical frombeing diverted directly into the flow line.With a valve at each end, it is simple toisolate the line for repair purposes. Byconnecting another chemical line thatcontains a valve to bypass the circulatingline, the injection of chemical can bediverted directly onto the flow line withoutgoing downhole.The mechanical pump shown in Figure 2 canbe installed on the base of the pumping unitand connected with a small rope or cable,eliminating the need for electricity. Onepump can inject paraffin solvent downholeto prevent paraffin buildup on the sucker rodstring. The second container can inject oiltreating chemicals either downhole ordirectly into the flow line.

Figure 2. Mechanical chemical pump witha sash cord connection to the walkingbeam. It has a weight to move it downand is the safest method for operation.

13C-3

Note that the wellhead also has provisionswhereby the well can be batch treated downthe casing. The wellhead contains a pressurecontrol that shuts in the well if the flow linepressure builds up above the setting level. Asmall blowout preventer allows pressure tobe shut in while the upper polished rodpacking and pressure packing are replaced.

The advantage of injecting the chemical atthe well is that the oil is treated while beingpushed toward the tank battery and thechemicals are blended into the mixture. Thedisadvantage of injecting at the well is thatwhen the well is down, even during a normalcycle, the tank battery is not receiving thechemicals needed for blending with otherwells. It is too expensive to install andmaintain chemical pumps at every well.

There have been many injuries to arms andlegs during the downstroke of mechanicalpumps when construction reinforcementrods were used to operate the arm. The useof rope or small cable eliminates this hazard.

Figure 3. Injecting chemicals at the tankbattery.

Injecting chemicals at the tank battery.The typical placement of chemical injectorpumps at the tank battery is after the headerwhere all wells come together but before thefirst vessel (Figure 3). This is just ahead ofthe separator or before the first vessel,whether it is pressure or atmospheric.

Producing sellable crude oil. Tankbottoms should be kept clean. This is acardinal rule to follow when pumping alease. Most tank batteries have a minimumof two tanks. As soon as one tank of oil issold, the remaining oil from that tank shouldbe pumped through the treating facilities andinto the second tank. There will always bealmost a foot of oil. Also, this oil is pumpedthrough the treating facility. Occasionallythere will only be one stock tank. If so,simply hook up the portable pump (Figure 4)and pump it from the bottom back into thesame tank. This will assist in keeping the oilclean and sellable.

Figure 4. A portable chemical pump.(courtesy of Arrow Specialty Co.)

13C-4

The employer must be willing to cooperatewith the pumper by providing a few suitabletools necessary to treat the oil. Whentreating equipment is acquired, it must bedesigned to perform the task. The pumpershould sit down with the employer as neededto secure workable equipment to do a goodjob.

Since the pumper works alone, if aportable circulating pump is used, it must belight enough to transport conveniently. Theportable circulating pump is small. If it isnot trailer-mounted, the centrifugal pump isbolted directly to the motor and not skid-mounted. Otherwise, it is too heavy for oneperson to handle.

Batch treatment while circulating. Whencirculating oil for treatment, chemicals mayneed to be added while the tank is stillcirculating. One easy solution to addingchemicals slowly is to use a container suchas an empty gallon plastic container that hasa small drip hole punched in the bottom.This should be set in the thief hatch openingand chemical poured into it while the oil isbeing circulated. It will take fifteen minutesor so for the chemical to drip in for a goodtreating blend.

Some operators use a bottle of butane anda 50-foot air hose to roll the tank. The airline to the bottle is connected with it sittingon the ground. The end of the hose isweighted and carried up the ladder. The endis then lowered into the tank until it reachesbottom. The drip container is placed in thehatch and the bottle turned on to a lowsetting. Other problems on the lease can betended to while the tank is being rolled andtreated by the butane mixing the chemicalwith the tank bottom. Some lease operatorsuse dry ice instead of butane for thisprocedure.

C-3. Special Treating Processes.

Cleaning tank bottoms. Tanksoccasionally accumulate an emulsion thatmust be removed. When this occurs, themanway plate may have to be removed fromthe back of the tank and the tank cleaned. Asmall depression may be dug and lined and avacuum truck called. The vacuum truck hasa diaphragm-operated pump with flappercheck valves and can pump almost anythingfrom the tank

The hot oiler. Occasionally, the tank of oilmay develop so much paraffin and such alarge volume of water that it does not reactto normal treating procedures. Often thisoccurs during the colder winter months. Inthis case, a hot oiler truck (Figure 5) must becalled.

Figure 5. The hot oiler can heat oil as wellas produce super hot steam for steam

treating.

The hot oiler will load 20 or more barrelsof oil on the truck from the tank battery intoits oil tank. The oil is heated and pumpedback into the tank through a flexible high-pressure metal hose to the battery. It is thenpumped through a line that extends downthrough the thief hatch to the bottom of thetank.

13C-5

As the oil is heated and pumped back intothe tank, it will raise the temperature of thetank high enough that the paraffin will meltand become fluid again. Water will then fallto the bottom.

It normally will take a hot oiler severalhours to complete this heating and rollingprocedure. Upon completion, the free wateris pumped off. As soon as the temperatureof the oil falls to an acceptable level, the oilis sold.

Figure 6. A slop tank used in treatingvery difficult-to-treat oil.

The slop tank. When treating problemsrecur at a tank battery, some companiessolve the problem by installing a slop tank(Figure 6). This is a potentially invaluabletank that has become popular in areas wherethe use of lined pits is limited, and where atank habitually develops high bottoms.

When the tank of oil has a high bottomthat is difficult to treat, a few inches of thebottom is pumped off into the slop tank tomake the tank sellable. As soon as the oil issold, the bottom is pumped back through thetreating facilities and into the tank of oilbeing filled. When the tank is filled, and thehigh bottom occurs again, the procedure isrepeated.

Other systems, such as the rolling system,may also be installed to combat treatingproblems.

13C-6

13D-1

The Lease Pumper’s Handbook

Chapter 13Testing, Treating, and Selling Crude Oil

Section D

SELLING CRUDE OIL

D-1. Preparing to Sell the Oil.

Preparing to sell a tank of oil requiressubstantially more work than the actual saleitself. If the gauger thinks the pumper iscareless in preparing the tank for the saleand the oil must frequently be rejected, thegauger will be more inclined to refuse theoil. A turndown should be a rare event.Some leases have very difficult treatingproblems. Every lease has its own treatingcharacteristics.

Turndowns are bad for both the pumperand the transport gauger. The gauger mustalways have a back-up load to pick up inevent of a turndown. However, thisalternate load may be many miles away,causing the gauger to haul one less load thatday. His company and possibly the gaugerwill make less money.

The three conditions that must usually bemet for acceptance are:

· A full load is available.· The bottom is a minimum of 4 inches

below the outlet connection.· The BS&W throughout averages 1% or

less.

End of the month oil sales overload. If atank of oil is almost full and the end of themonth is approaching, the tank should besold. This will allow the employer toreceive his payment for the oil a monthearlier than if the pumper waited until next

month. Most employers appreciate thepumper selling all oil possible this month.However, all pumpers in your area will alsothink the same thing. As the end of themonth approaches, the gauger or purchaseris flooded with requests and not all can behonored. Tank runs should be reasonablyscheduled in advance with your purchaser toprevent this problem. Full tanks normallycarry a priority over almost full tanks withyour gauger at the end of the month.

D-2. Selling Oil

Requirements for a full transport load.Crude oil purchasers usually require theaccumulation of a full truckload (Figure 1)or tank full of oil before purchase. The tworeasons for this requirement are safety andcost.

Figure 1. Selling oil by truck transport.

13D-2

· Safety. It is difficult to transport a partialload of liquid safely. When the transportturns a corner, oil will climb up the wallof the tank and with excessive speed canturn the truck and trailer over. When thetransport goes up or down inclines, theliquid rushes back and forward with apowerful force. Although the trailer tankis built with baffles to help withstandthese forces, the safe trailer is a full one.

· Cost It costs the same amount to haul orpump into a pipeline regardless ofwhether the tank is full or not. It is amatter of economics to require a full loadbefore purchasing it.

Selling split loads. It is difficult to sell lessthan a full load of oil. However, mostpurchasers will accommodate emergenciessuch as a hole in the tank or problems with avessel. Possibly there is another tank nearbythat will allow the transport to be fullyloaded. Occasionally when there is a partialload of condensate and the weather is hot,the evaporation will equal and even exceedthe production. The lease pumper mustrecognize such problems and search forreasonable solutions.

Communication with the gauger. Eacharea may have a different method ofcommunicating to the gauger that there is aload of oil ready for sale. Some oiltransported by pipeline still uses a visualcueing system of metal markers at the tankbattery. As gaugers make their rounds, theyput the oil on line when they drive by.

These days, however, requests are usuallycalled in by radio or telephone. Regardlessof the system used, adequate notice shouldbe given to the gauger.

The note jar. Every tank battery shouldhave a note jar (Figure 2). This can be as

simple as a pint or quart clear glass jar withtwo holes punched in the lid. The lid iswired to the outside of the tank walkwaysteps, creating an efficient mailbox. Whenthe gauger puts a tank on the transport line, anote is usually put in the jar with the topreading. After the tank of oil is sold, a copyof the run ticket is left in the jar if thepumper is not present. Different companieshave different policies regarding thewitnessing of gauges and selling oil.

Figure 2. Glass jar for pumper-to-gaugercommunications when selling oil.

Witnessing the oil sale and the rejectionnotice. When the gauger rejects the tank ofoil for purchase, a rejection notice on aprinted form is placed in the tank batterynote jar, and a copy possibly turned in to thepurchasing company. The form will listreasons the load was unacceptable, date,pumping company name, lease and tanknumber.

Some companies require the pumper towitness every step of the purchase orrejection. Even if not required, it is still agood practice. Sometimes it is necessary fortop gauges to match. If the ambienttemperature is warmer than the tank of oil,the gauged volume will increase. If it islower, the gauged volume will decrease.This is a normal situation. If the pumper last

13D-3

gauged yesterday, the level will almostcertainly always be slightly different today.

D-3. Seals and Seal Accounting.

There are two types of seals in commonuse (Figure 3). The most commonly usedtype for years has been a flat, narrow metalstyle that must be pushed through a dart inorder to be installed correctly.

Figure 3. Two styles of tank seals.

The second style is a soft wire that has alead head. The wire is run through a smallhole, then doubled back and run through itagain. The wires are pulled tight, and thelead is crimped to hold it in place. The wiremust be cut in order to remove the handle oropen the valve.

When a tank of oil is sold by transport orby pipe line, the seal on the sales line valveon the front of the tank must be cut,removed, and the number on the sealrecorded. At the end of the sale a new sealis placed through the dart, and the valve isresealed until the next sale. These seals areput on the tank by the purchasing companyand usually have the name of the companyimprinted in raised letters on the seal. Theseal must be cut in order to remove it.

If this seal must be removed for anyreason, the owner of the seal should benotified. If the oil is sold by transport, theregulations for cutting the seal may not becritical. If the oil is sold by pipeline, awitness from the pipeline company may

need to be present for removal andreplacement of the seal.

If the oil is sold by transport, the seal onthe sales line valve will possibly be the onlyseal used. If the oil is sold by pipeline, thevalve may be open from six hours to twodays, so before the sales line valve isopened, the drain line on the back and theinlet valve must be sealed. These seals mustremain in place until after the sales linevalve has been closed and the seal replaced.

The run ticket. The run ticket (Figure 4) isproof of an oil sale, listing the purchaser,date of the purchase, seller, method oftransportation, lease location, lease name,tank battery, and other information.

Figure 4. A run ticket.

13D-4

The tank number at the battery is usuallyassigned by the oil purchasing company.Tank numbers are in order from left to rightwhen facing the tank battery. If the numbersare not in sequence, this usually implies thata tank has been replaced or has had aproblem that required the capacity to be re-strapped.

The run ticket illustrated in Figure 4 showsthat the tank had a capacity of 210 barrels,and the 15-foot tank contained 13 feet, 5 andno quarter inches. Since the bottom of theequalizer would be at about the 14 footlevel, the tank was within 6 inches ofmaximum capacity.

The 4-inch pipeline connection is 1 foothigh, and the oil was pulled down to 1 foot,6 and 2/4 inches. To pull the oil down tothis level, the transport driver would havehad to slow the pump suction down at aboutthe two foot level, then keep lowering thesuction speed to prevent air from beingsucked in. It would take too long to lowerthe level using this procedure.

The BS&W level was 5¼ inches and was2½ inches below the maximum allowedlevel. The observed gravity of 38.3 is below40 gravity, so there may have been a smallprice reduction for lower gravity. TheBS&W level throughout the tank was 4/10of one percent, well below the 1% allowed.The observed temperature on thethermometer was 72° F. The temperature onthe hydrometer was also 72°. There wouldbe a small volume adjustment fortemperature correction.

The truck drove 132 miles round trip tohaul the oil, and it took from 11:50 until12:20, or 30 minutes to load the oil. This isa long distance to travel if the oil must berejected. There are 533 numbers differencein the number of the seal that was removedand the number of the one replaced. This isa marginally producing well.

A check for payment will be made thefollowing month. Typically, the royaltyowed to the mineral rights owner will bemailed directly to this owner and theoperator’s share will be mailed to theoperator.

D-4. Selling Oil by Use of the LACT Unitand Surge Tanks.

The best method for selling crude oil is byuse of the lease automatic custody transfer(LACT) unit (Figures 5 and 6).

Figure 5. The LACT Unit. Oil travels leftto right through this system. The control

panel is visible in the background.

Figure 6. A picture of a second LACTunit. The two lines in the foreground are

for the prover loop.

13D-5

Oil can be produced to the LACT unit byuse of the oil line that comes over the top ofthe tank, and the LACT sales line is leftopen at all times. As oil is produced into thestock tank, it rises and a level controllerturns on an electric motor in the LACT unit.As the oil is sold and the level of oil lowers,the level controller turns the LACT unit off.The stock tank will act as a surge tank toachieve this objective. The first componentof the LACT unit is a liquid transfer pump.The purpose of this pump is to place thefluid under approximately 30 pounds ofpressure. This reduces the amount of gasthat may break out while the oil is in theLACT unit and allows a positivedisplacement meter to operate accurately.The last component before the pipelinecompany’s system is a backpressure valve tomaintain this pressure.

As the oil travels up through the riser, theBS&W percentage is constantly monitored.The BS&W monitor controls a divertervalve. As the oil moves across the top of theriser, it passes through a screen and aireliminator. As it moves across anddownward, a sample of oil is diverted intothe sampler tank for BS&W analysis.BS&W is never monitored on a horizontalline because the liquids separate and stratify.

As the liquid return horizontal, it passesthrough a three-way diverter valve. If the oilis not sellable, it is diverted back through thetreating facilities. If it is pipeline grade oil,it will continue through the positivedisplacement meter, the prover manifold,and the backpressure valve. At this point itis now owned by the pipeline company.

The prover loop determines the accuracyof the positive displacement meter. As

pumps wear, they usually pump more fluidthan is indicated on the meter reading. Afterthe meter is tested, a correction factor isgiven to the lease operator and the oilpurchaser. The reading is always close to1.0000. A typical reading might be 0.998 or1.0015.

The gauger and the pumper willperiodically meet at the LACT unit andblend the oil in a sample container and worka sample. They will then empty the samplertank back into the sales line and read themeter. These figures, along with thetemperature correction and correction meternumber, will determine the oil sales sincethe last average to be computed.

Hot oiling. It may become necessary to callfor a hot oiler, a truck mounted with apropane heater to treat the oil. Cold oil ispulled from the tank bottom, heated, thenput back into the tank. This thins the oil,melts paraffin back into a liquid state, andallows water to fall out. Chemicals can beadded to assist in reducing surface tensionon the droplets of water. Oil movement alsoassists in this treating.

Hot oil is more difficult and dangerous topump because of the change in viscosity andthe danger of ignition of vapors coming offthe heated oil. Some truck transportcompanies may not purchase the oil after hotoiling until it has cooled to less than 100° F.It is to the advantage of the productioncompany to sell the crude oil as quickly aspossible after hot oiling in order to sell moreparaffin and remove it from the system sothat it cannot congeal and cause problemsagain in the tank.

13D-6

14-i

The Lease Pumper’s Handbook

CHAPTER 14

WELL TESTING

A. INTRODUCTION TO WELL TESTS.1. Introduction to Well Testing.2. Pre-Test Preparation.

· Shutting the well in.· Normalizing production by producing the well before testing.

3. Preparing the Tank Battery for Testing a Well.4. Four Basic Well Tests.

· Potential test.· Daily test.· Productivity test.· Gas/oil ratio test.

5. Typical Test Information.· General lease information (typical for all tests.)· Well information.· Pumping well information.· Tank battery information.· Special data.

B. STANDARD TESTS.1. The Reservoir and Drive Mechanisms.2. Potential Tests.

· Purposes of the new well potential test.· Purposes for conducting a potential test after working over an existing well.· Potential testing conclusions.

3. Daily Production Tests.4. Productivity Tests.5 Gas/Oil Ratio Tests.6. Testing Gas Wells.7. Quick and Short-Term Special Purpose Tests.

· Bucket and Barrel Tests.C. SPECIAL TESTS.

1. Well Logs and Surveys.2. Pressure Surveys.3. Temperature Surveys.4. Other Well Tests.

· Caliper surveys.· Running scrapers.

14-ii

D. GAUGES AND GAUGE CALIBRATION.1. Quality of Gauges.2. Gauge Construction.3. Safety Gauges.

· Liquid-filled gauges.4. Adjustable and Test Gauges.5. Calibrating Gauges and the Dead Weight Tester.

·· Testing the pressure of the well directly.

14A-1

The Lease Pumper’s Handbook

Chapter 14Well Testing

Section A

INTRODUCTION TO WELL TESTS

A-1. Introduction to Well Testing.

There are many reasons for testing a well,and several distinct types of well tests.Because of the wide variety of problems thatmay be encountered, well tests may haveslightly different purposes and names. Thisis understandable because of unitizedreservoirs and dozens of variations inenhanced recovery.

Many people in charge of testing wellswill also develop their own terminology fordetermining what to call a particular test.Even after hearing what the companysupervisor calls the test, it may have littlemeaning to others until the test procedureand the purpose of the test is described indetail. However, this book uses the mostwidely accepted names for testing wells.

Unless wells are tested at regular intervals,the lease operator cannot determine how oilcomes from each well and which haveproduction problems. Other reasons are justas important. Economic gain is alwaysimportant, but if the lease enters theenhanced recovery phase with water flood orsecondary recovery practices, analyzing welltests is the primary method of determiningthe success or failure of an enhancedrecovery process. Since artificiallyoccurring forces in the formation such assecondary and tertiary recovery can increasethe amount of oil recovered from a reservoir,well tests trace the success and failure ofenhanced recovery.

A-2. Pre-Test Preparation.

To accurately test a well, the lease pumpermust prepare the well for testing. There aretwo ways of preparing the well for a test—either produce it every day normally or shutit in one day before the test. The pumpermust know what type of test is to be takenand do the best possible job of preparing thewell for the test. For some tests, the bottomhole shut-in pressure prior to performing thetest may be needed.

Shutting the well in. In flowing wells,some tests require that the well build up toits maximum wellhead pressure. When awell is to be tested from a shut-in condition,the casing and master tubing valves areclosed so that no gas, oil, or water isproduced. After closing the valves, noiseshould not be detected from the wellhead. Ifnoise can be heard, this indicates that a valveis leaking and, until an additional valve isclosed or the valve has been repaired orreplaced, an accurate test cannot be made.As with pumping wells, when a circulatingline has been run from the tubing to thecasing so that inhibitors or chemicals can beinjected at the wellhead, the circulating linevalve must also be closed.

Twenty-four hours is the standard amountof pre-test shut-in time. Different wells,however, may be tested after a longer orshorter shut-in period. If the formation paysection is composed of coarse sandstone

14A-2

with a high porosity, 16 hours may provideenough time for the wellhead pressure tobuild to its maximum pressure so that thetest may begin. If the formation iscomposed of tight shale (clay compressedinto rock) and has a lower porosity, it mayrequire more than one day for the well tobuild up to maximum pressure. Experiencewill teach the pumper how much shut intime is necessary to allow the pressure tobuild up in each well to its maximum levelbefore testing can begin.

The pressure will build up rather rapidlywhen the well is first shut in but will slowdown over time. The longer it is shut in, theslower will be the rate of pressure increaseuntil it levels off at the maximum pressure.

Normalizing production by producing thewell before testing. Normalizing a wellmeans that the well must produce its normalaverage amount of oil, water, and gas eachday for several days prior to testing. If awell has been purposely shut in for one ormore days, turning it back on may producefar more oil than if it had been producingnormally.

As an example, the first day a well returnsto production, it may produce 125% of anormal day’s production. The second day, itmay produce 112% of a day’s production.On the third day it may produce 105%production, and on the fourth day, it may bealmost back to 100% of normal production.After three days, it may have made up 42%of one day’s production. Each wellproduces differently from every other well.

Many factors influence whether a pumpingwell is producing a normal amount of oiland gas or if it is developing a problem.Experience will give the lease pumperadditional causes. These same reasons willalso factor into the problems encounteredwhen testing a well.

A-3. Preparing the Tank Battery forTesting a Well.

Care must be taken in preparing the tankbattery to receive and measure the producedfluids. The valves in the lines must beturned to the correct positions to direct theproduced oil to a stock tank where it can bemeasured, the gas metered before enteringthe gas sales system, and the free watermeasured through a liquid measuring deviceor by other methods.

In a large tank battery, the well to be testedwill be switched manually or automaticallyinto the test separator (Figure 1). The gas ismeasured and recorded on a chart or in acomputerized recorder, and the oil and wateris directed to a metering heater/treater. Theoil is directed to the oil holding tank. Thewater is also measured then directed into thewater disposal system.

Figure 1. A test separator.

In small, low production tank batteries, oiland water may be diverted through the testseparator, and all of the liquid produced intothe same tank. Before the test begins, thetotal liquid in the tank is gauged, and theexact amount of liquid in the tankdetermined. The second step is to thief thetank and determine the oil/water interfacelevel. A shakeout of the oil may also be

14A-3

taken to determine the suspended BS&Wpercentage. If needed, the API gravity andtemperature will be taken. The number ofbarrels of oil and water in the tank iscomputed.

At the end of the test, the new fluid level isgauged and recorded and thiefed in the samemanner as the first time. The total volumeof oil and water in the tank is computedagain and, by simple subtraction, the amountof oil and water produced is easilycalculated. The acquired water can becirculated out of the tank into the disposalsystem. This assists in cleaning the bottomof the tank.

Figure 2. A differential, static, andtemperature gas recorder.

(courtesy of ITT Barton)

The natural gas must also be measured. Byturning to the prior well test information inthe lease records book before the test isstarted, the correct gas meter orifice plate

can be selected, and the gas system set upfor the test (Figure 2). The ink pens on thechart should be moved lightly at thebeginning to ensure that they are feeding inkand the correct time of day when the testbegins is indicated on the chart. Somepressure recorders are computerized and donot have a paper chart.

A-4. Four Basic Well Tests.

The general purpose for conducting a welltest is usually defined within the name of thetest. While requirements may differ, thefour basic tests, along with preparation andpurposes are:

Potential test.·· Requires a 24 hour shut-in period prior to

testing.· Is performed on new wells and wells that

have been worked over.·· Purpose: To determine the maximum 24-

hour potential capability of a well toproduce oil, gas, and water.

Daily test.· Requires normalizing prior to testing.· Is performed one time every month on a

continuing schedule for the life of thewell.

· Purpose: To determine how much fluidthe well is producing daily within amonth without affecting the well’s abilityto continue to produce fluids.

Productivity test.· Requires normalizing prior to testing.·· Evaluates the well in various modes and

cycles of operation.·· Purpose: To determine the best way to

produce the most hydrocarbons with theleast damage to the well’s ability.

14A-4

Gas/oil ratio test.· Requires a 24 hour shut-in period prior to

testing.· Reveals when wells produce too much

gas, which prematurely lowers reservoirpressure and affects all wells in thereservoir.

· Purpose: To determine how many cubicfeet of gas is produced per barrel of oil.

A-5. Typical Test Information.

Every test will require that the amounts ofoil and water produced be recorded. Gasproduction is recorded except for producingstripper wells where casing valves are opento the atmosphere. Wellhead pressures oftubing and casing are recorded on allflowing wells.

Lease information (typical for all tests.)

· Company name (may already be on form)· Field· Lease name· Number of well to be tested· Date test started· Completion date· Type of test· Method of producing well or type of lift· Conditions before test (shut-in or

producing)· Hours produced· Oil produced· Free water produced· Total fluid produced· Gas produced· Temperature of gas· Oil BS&W content of produced oil· Gravity of oil· Temperature of oil· Gas/oil ratio· Comments

Well information.· Method of production (flowing, plunger

lift, gas lift, etc.)· Tubing shut-in pressure before test· Tubing pressure at end of test· Casing shut-in pressure before test· Casing pressure at end of test· Packer information (if used)· Choke description and setting for test· Well reaction to flowing· Appropriate flow artificial lift assistance· Flow cycle information· Other information as needed

Pumping well information.· Stroke length· Strokes per minute· Pump bore size· Flow line pressure· Casing pressure if appropriate· Pumping cycles· Special pumping information

Tank battery information.· Lines switched correctly· Initial tank gauges or meters read and

tank number recorded· Tank size· Oil and water levels in test tank

determined· Gas line size· Correct orifice plate installed.· New gas chart placed on meter· Other appropriate preparation· Vessel pressure and temperature recorded

as needed· Comments

Special data.· Intermittent data· Interval data· Injection time and pressure

14A-5

· Power fluid injected and description· Special lift information· Meter readings

Almost all information gathered in testingany well is common to all tests of that well.

Some of the information recorded is criticalto some tests because of the varyingpurposes of the tests. Prior test information,used as a reference only, will save time insetting up the test.

14A-6

14B-1

The Lease Pumper’s Handbook

Chapter 14Well Testing

Section B

STANDARD TESTS

B-1. The Reservoir and DriveMechanisms.

The reservoir can be thought of as aportable sprayer such as might be used tospray fertilizer or weed-killer. Once thesprayer has been pumped up, air is pushingagainst the fluid in the tank. Squeezing thehandle allows the air to push the liquid outto create the spray. Until the trigger issqueezed, the fluid stays in the tank eventhough it is under pressure. The tank is likethe reservoir, holding fluid under pressure.Drilling into the reservoir is like creating aspray tube and the valves in the well are likethe trigger on the sprayer, allowingcontrolled releases of the fluid in the tank.Various types of forces—either natural orartificial—may force the oil out of the well.However, like the sprayer, when that forcedeclines to the point that it cannot force theoil to the surface, then the well will stopproducing just as the sprayer will not sprayuntil it has been recharged with air.

The reservoir can have pressure applied toit just as the sprayer can be recharged. Onetype of pressure is that exerted by water thatis trapped in the oil-bearing formation or insurrounding formation. As the oil isremoved from the reservoir, water migratesinto the reservoir to replace the oil andforces more oil out of the reservoir. This isan example of water drive. As the oil isproduced out of the formation, the

perforations must be moved upward tocontinue producing oil. Unless this isperformed, the well will change to waterproduction only. The water may be a naturalpart of the formation or it may be pumpedinto the formation to enhance production.

Some formations are completely saturatedwith liquid with natural gas contained withinthe liquid. When a new well is produced,the natural gas will break out of the oil as itis being produced. After a certain amount ofoil has been produced, the formation willthen begin to have free natural gas breakingout that will begin to work its way to the topof the reservoir. This is an example ofsolution-gas drive.

In some cases, the top of the reservoir isfilled with natural gas with oil pooled at thelower part of the reservoir. The operatormust drill deep enough so that the casingperforations are in the oil-bearing zone.This is an illustration of gas cap drive.

A fourth type of formation has almost nopressure, except for the weight of the oilitself. Perforations must continue to belowered toward the bottom of the hole tocontinue to produce oil. This is an exampleof a gravity drainage reservoir.

The type of reservoir drive is important towell production, the method utilized, and therate of depletion. In the geology of the well,the type of structure is important. The typeof drive can also greatly influence welltesting.

14B-2

B-2. Potential Tests.

The potential test is performed on a wellthat has very recently been drilled or workedover. The primary purpose of this test is todetermine how much oil, water, and gas thiswell will produce in 24 hours. To preparefor this test the well is usually shut in for 24hours before the test begins, and the test isusually run for 24 hours.

Another factor determined by the new wellpotential is the pay-off factor. The potentialhelps determine if it will be profitable todrill other wells and, if it was a worked-overwell, whether it would be profitable to workover additional wells.

Purposes of the new well potential test. Ifthe well is new, information gained fromthis test is important to the company. Somequestions that it should help answer are:

· Will the regulating agencies place anallowable on the well to regulateproduction?

· Is this a profitable well? Will the wellpay out?

· Should offset wells be drilled? Wouldthey be commercially feasible?

· Should casing be run?· What size tank battery should be built?

Where should it be located in order to beconvenient to receive flow lines fromthese additional wells?

· If it is a commercially viable well, howlarge is the estimated reservoir? Howmuch oil and/or gas will it produce in thefuture?

· Should a pipeline be built to it whenselling oil or should the oil be hauled bytransport?

· Does it produce enough natural gas to becommercial? How many wells should bedrilled to justify building a gas line?

· How much water is being produced?What should be done with it?

Purposes for conducting a potential testafter working over an existing well. Someof the important questions answered byconducting a potential test after workingover an existing well are as follows:

· Did the workover solve the productionproblems or achieve the goals of theworkover?

· Did the well produce more hydrocarbonsthan it did before it was worked over, orwas production restored to anticipatedlevels?

· Was excessive water production pluggedoff successfully by the workover?

· Will the workover ever pay out and makea profit?

· Should the same or similar type ofworkover be performed to other wells inthe same reservoir?

Potential testing conclusions. Thepotential test is used to analyze new wellperformance and to solve problems inmaintaining and enhancing production fromexisting wells. It covers such a broadspectrum, it can be easily understood whyspecial names may be attached to particularfacets of it.

B-3. Daily Production Tests.

After a well has been normalized, a dailyproduction test may be performed. This testindicates how much oil, gas, and water isnormally produced by the well.

The daily production test is performedonce each month on every well owned bythe company. The results of these tests areposted in a permanently maintained recordbook with a sheet for each well. For each

14B-3

year, the company will have 12 postings onthe sheet for an individual well. If possible,the ledger paper should be wide enough thateach monthly record only occupies one line.The lease pumper should also maintainappropriate records in the lease recordsbook. (See Chapter 19.)

In preparation for conducting the monthlydaily production test, the well must benormalized. This means that the well mustbe produced during this period of timewithout serious problems. As the test isperformed, the well will be producing itsnormal production for the full 24-hourperiod. Since the average well is producedat its maximum capacity every day, anddaily allowable may be set higher than thewell can possibly produce, the well isalready being produced at its maximumcapacity during the test.

As these tests are posted in the recordbooks, a very important collection ofreference information is accumulated. At aglance, it can be seen if the well is producingnormally or if production is fallingexcessively each month and problems arebeginning to develop. After a new pump isrun, production will probably increasebecause of the improved efficiency of thepump. As the pump begins to wear, thepumping unit may need to be run longer orstimulated in some other manner to maintainthe production average.

Without a properly maintained leaserecords book, the pumper is basicallyoperating by guesswork in performing thetesting and daily duties. The operator is notin a verifiable position to reach precisereasons for lowered production, and part ofthe ability to know when there is a problemis lost until perhaps there is a productionfailure. The pumper should be able to alertthe supervisor about a lease problem, ratherthan vice versa.

With a one-well tank battery, the companymay make a monthly production average anddiscontinue the monthly daily productiontest. The problem with this system is that itdoes not give an accurate picture of howmuch production was lost during the monthbecause of downtime caused by pumpfailure, equipment failure, unexpectedproblems, and other reasons that may becorrected. The pumper should still pick aconvenient day and continue to perform thetest. This will reveal how much productionwas lost during the month due to problems.This is valuable information when askingthe supervisor for problem solving work orexpenditures to improve production.

The advantages of conducting a daily testeach month include the following:

· Identifies failing downhole pumps.· Indicates problems caused by a closed

casing valve on a pumping well.· Identifies a gas locked pump.· Alerts the pumper to increasing flow line

pressures on pumping wells. As a flowline plugs, it will cause a correspondingproduction drop due to increasedformation backpressure.

· Reveals leaking flow lines.· Reveals casing and gas anchor

perforation plugging.· Reflects salt bridging in cyclic producing

wells.· Indicates tubing leaks.· Indicates time clock problems.

B-4. Productivity Tests.

This series of tests is performed as neededor upon request to help determine the bestway to produce a well. Basic productivitytests should be conducted by the leasepumper on a periodic basis to help maintainor improve production. This procedure

14B-4

takes several days or weeks with manyadjustments to production time to gatheradequate information.

The best results in conducting productivitytests may be achieved by having anechometer and dynamometer availablewhere draw-down rates and fill times can beaccurately established and pump actioncarefully calculated and observed. Thismethod requires valuable equipment andsomewhat specialized training that may notbe available. Some pumpers, however, arevery proficient at this analysis with nospecial equipment—just experience and anunderstanding of what is happeningdownhole. When conducting productivitytests, it helps to understand what type ofdrive exists in the formation.

To begin a productivity test of a pumpingwell, the casing should be pumped empty ofliquid in the bottom of the well. At thispoint, the pumping unit should be shut in.By running an echo analysis every fifteen tothirty minutes, the fill rate of liquid enteringthe casing in the bottom of the well can beestablished. The longer the pumper waits,the more bottom hole pressure the welldevelops, and the slower the liquid enters.After sufficient liquid has accumulated, thepumping unit should be placed back inoperation, and an echo analysis run everyfifteen minutes or so to establish the drawdown rate. This rate depends upon pumpefficiency, size of tubing and pump, strokesper minute, and other factors.

Many people work for smaller companiesthat do not have echo analysis ordynamometer equipment available, and thelease owner will not be receptive to theexpense of hiring this service. Theirreasoning is that wells were produced formany decades before these pieces ofequipment were designed and improved tothe level that it has been developed today.

Even for companies that own thisequipment, it may take a few days or longerbefore the lease can be tested. The pumpermay not be able to wait days or weeks toanalyze problems and take action that willcontinue and possibly enhance production.

Some of the productivity tests that can beperformed without instruments include:

· Experimenting with well time controls toenhance production.

· Making changes slowly. It may takeseveral days to a week before the effect ofthe changes settles back down to normal.

Some alternative methods of obtaining thisinformation include the following:

· How to recognize some changes withoutinstruments.

· Some wells running intermittently willproduce more oil than if they runcontinuously.

· With many wells, rods can be lightlygripped with two fingers and so that thepump pounding the liquid can actually befelt. The pumper will also know if thepump is tapping bottom.

· With many wells the pumper can alsofeel when the pump is pumping well.

· By lightly touching the rods with a dampfinger, the temperature changes will tellthe pumper when it is pumping (coolrod), and when it is pumping off (warmto hot rod).

· When the pumper opens a bleeder hoseinto a bucket to check pump action and todetermine if the well has a problem, therelease of pressure expands the gas,allowing the well to flow for a fewstrokes. Once true pump action isobtained, the pumper can determine ifthere are pump problems.

14B-5

Some factors that will help the pumper inanalysis of the production from a well are:

· History of the well. What is normalproduction?

· Scale and paraffin accumulation,especially in the well bore andperforation area.

· Type of formation and how tight it is.· A large pump moves liquid quickly. Is

this the best way?· A small pump moves liquid slowly. Is

this the best way?· Type of drive.· Type of reservoir.· Frequency of pump repairs.· Strokes per minute of the pumping unit.· Setting of tubing perforations in relation

to the casing perforations.· Flow line backpressure against the

formation.

B-5. Gas/Oil Ratio Tests.

These tests are performed as needed todetermine the ratio of cubic feet of gas beingproduced to each barrel of oil.

The purpose for conducting the gas/oilratio tests is for pumper use and to informregulating agencies how many cubic feet ofnatural gas are being produced per barrel ofoil. This amount of gas, multiplied by thenumber of barrels of oil produced, equals thetotal cubic feet of gas that is being removedfrom the reservoir daily.

In some reservoirs it is important to leaveas much gas in the formation as long aspossible or even to return it to the formationuntil the oil has been depleted. Then the gaswill be produced and sold. This can becomeimportant because when the natural gassupply in the reservoir is exhausted, no forceremains to push crude oil toward the well.

When reservoir pressure is depleted, thepumper must re-inject another force into thereservoir to replace it to stimulateproduction or plug the wells. Without thisgas movement and pressure, oil will nolonger be produced.

Most reservoirs are large enough thatmany different operators own the wells thatproduce hydrocarbons from one. If thereservoir slopes upward, one operator mayhave several wells in the higher gas zone.The offset operator’s wells, being higher upin the reservoir, only produce gas or gas withvery little oil. This operator produces all ofthe gas possible out of the reservoir, whileothers produce very little gas. Productionfrom the first operator’s wells, in time, willbegin to slow down for lack of a pressuremaintenance program. If the whole reservoiris water drive, these wells will be the firstones to turn to water.

If gas had remained in the reservoir longer,the pumper would have produced more oilfor several years longer. One set of wellsmay be progressively harmed by prematureover-production of gas by other operators.Low gas production limits are good. Gasallowables are enforced to protect the wellsto permit maximum hydrocarbon recovery.

Gas/oil ratio tests are necessary andenforced to extend the life of an oil field.This results in a higher hydrocarbonrecovery, which is good for the industry, themineral right owner, and the country. Oneof the best solutions is to unitize the fieldunder one operator so long-range planningand good production practices may bepossible.

B-6. Quick and Short-Term SpecialPurpose Tests.

The pumper should learn the many waysthat abbreviated tests can be performed that

14B-6

determine which wells are not producingaccording to schedule. Sometimes thesolution to returning the well to service is assimple as bumping bottom for a fewminutes. This troubleshooting ability shouldbe acquired by the lease pumper becausethese talents are used almost daily whenproducing marginal wells.

Bucket and barrel tests. In a situationwhere there are a large number of pumpingwells producing into the same tank battery,the tank is gauged in the morning with oneor more wells are off. The pumper mustmake an effort to determine which wells areoff. To perform a full daily test might

require two weeks or more, so quick testingprocedures need to be performed.

Part of the problem in performing a buckettest through the bleeder is that when thevalve is opened the flow line pressure isremoved. When this backpressure isremoved, the gas in the column of oil beginsbreaking out and expanding, giving a falsereading of new oil being produced. A smallbackpressure valve that screws into thebleeder valve opening will prevent the lossof backpressure and give a more accuratereading.

The pumper needs to become proficient atperforming bucket and barrel tests in orderto isolate problem wells very quickly.

14C-1

The Lease Pumper’s Handbook

Chapter 14Well Testing

Section C

SPECIAL TESTS

C-1. Well Logs and Surveys.

As a well is drilled, many special logs arerun to determine information concerning thecommercial viability of a well. Theseinclude both open hole and cased logs,cement bond logs, directional surveys, andtracer surveys. It would consume too muchspace to review each of these in this manual.

Special production tests and surveys,however, are run on flowing wells to gatherspecific information. Two of the mostcommon tests performed on flowing wellsare pressure and temperature surveys. Therecan be many special reasons for runningthese tests, but this manual will discuss theprocedures and general purposes only.

C-2. Pressure Surveys.

Pressure surveys are run for severalreasons. One purpose is to project theproducing life of the field. As the testinstrument (Figure 1) is lowered into thehole, the altitude above sea level is a factorin locating at what depths below the surfacethe pressures must be taken.

Figure 1. A quartz pressure gauge.(courtesy of GRC Amerada Gauges)

To obtain the needed pressures, theinstrument is mounted on the wellhead in ashort lubricator, similar in appearance to aswabbing lubricator, and the instrument isrun into the hole on a solid wire line(slickline) or by a logging truck. The mastergate is opened and the instrument is loweredinto the well according to the instructionsfrom the production company office.

As the pressure recording instrument islowered into the hole, it is stopped atspecific points for a few minutes in order toobtain a straight reference line.

Pressure surveys are run on most flowingwells every six to twelve months. Thepumper is notified as to when the well is tobe shut in for this test and when it will berun. This will allow the pumper to bepresent at the test and to place the well backinto service at the conclusion of the test. Inpreparation for this test the well is shut inlong enough to record the maximum bottomhole pressure.

C-3. Temperature Surveys.

Temperature surveys are an excellent toolto help determine if there are casing leaks.A temperature recording instrument islowered slowly on a small solid wire line tothe bottom of the hole. The procedures forrunning this test are identical to theprocedures for obtaining well pressures. Atspecific depths, the instrument is stopped fora short interval to give a series of reference

14C-2

points. At most casing leaks, gas willexpand as it leaves the casing to enter alower pressure area. This expansion createsa drop in temperature, indicating a possibleleak.

C-4. Other Well Tests.

Several other procedures may beperformed to check well conditions. Acouple of the more common include:

Caliper surveys. A caliper survey tool isrun on an electric line. After it reaches thedesired depth, steel fingers are released todrag on the inside surface of the casing as itis slowly retrieved. Each finger draws a lineon the chart, and every time a pitted spot isencountered, the arm goes farther out,resulting in a spike on the chart.

As the survey tool goes through a collar,all of the fingers or bows go out to providereference marks to identify which joints arepitted and how deep each pit is. Calipersurveys are run in wells where the tubingmay be damaged by corrosion. They give agood reference as to when the tubing isreaching the limit of its dependable life andof the condition of each joint of tubing.

Running scrapers. When a packer or otherlarge tool is planned to be run in the casingwith a diameter that is only slightly smallerthan the casing, a tool is run that will scrapethe inside of the casing to avoid the risk ofsticking the tool in the hole. By running ascraper into the hole and retrieving it beforerunning the packer, the pumper can reducethe possibility of problems.

There are many other testing tools that areutilized in production operations that thepumper will encounter over time.

Figure 2. Cross-section of the quartzcrystal pressure gauge.

(courtesy of GRC Amerada Gauges)

14D-1

The Lease Pumper’s Handbook

Chapter 14Well Testing

Section D

GAUGES AND GAUGE CALIBRATION

D-1. Quality of Pressure Gauges.

Pressure gauges are available in manydifferent sizes, price ranges, and styles(Figure 1). They can vary from very cheapto very expensive. The most importantconsiderations when purchasing a newgauge are what level of accuracy is needed,how much vibration and shock the gauge besubjected to, and what will be done with thereading after it is obtained.

Figure 1. Typical gauge assortment.(courtesy of Helicoid Instruments)

Simply glancing at a gauge when it is inservice to determine the approximatepressure on a line is not particularly critical.Even inexpensive gauges can provide anapproximation. However, more accurate

and, thus, expensive gauges are required for.well tests where pressure will be reviewedclosely to determine if the reservoir has hadany pressure drop in the past year andaccurately know how many pounds ofpressure are involved. This is an instancewhen the pumper should use the mostaccurate gauge available—a test gauge thatcan be calibrated. If a pressure gauge issubjected to pounding by a high-pressurepump, such as a triplex, where the hand ofthe gauge fluctuates rapidly back and forth,an adjustable vibration dampener can beinstalled ahead of it to reduce the shock andextend the life of the gauge.

D-2. Gauge Construction.

Historically, the most common style ofgauges in the oil fields had a bourdon tubeon the inside to transmit the pressure to thehand. The second style is operated byexerting pressure against a spring.

The bourdon tube (Figure 2) is a long,curved, flat tube that extends about two-thirds to three-fourths of the distance on theinside of the gauge. It has a pivot point inthe center of the gauge for attaching thehand, and the end of the bourdon tube isconnected to the pivot with a lever. Theinside of the tube is shorter than the outsideand, as pressure is applied to the inside, thetube moves to the outside at the end. Thisaction moves the hand of the gauge in a ratioto the amount of pressure applied.

14D-2

Figure 2. A bourdon tube.(courtesy of Helicoid Instruments)

D-3. Safety Gauges.

When working with high pressure, thepumper should use a gauge with safetyprovisions and possibly improved glass inthe face. A good quality safety gauge willhave a rubber plug mounted in the back thatcan blow out if the tube should rupture.Also, safety glasses should be worn whenopening a gauge to eliminate the possibilityof blowing broken glass into the face andeyes. The pumper should stand slightly toone side, never directly in front of a gaugewhen opening it.

Liquid-filled gauges. The liquid-filledgauge is a sealed gauge filled withtransparent liquid behind the glass or plasticface. Corrosion and oxidation cause seriousdamage to a gauge that is not sealed.Gauges that are not liquid filled may becomehard to read and inaccurate with time.

D-4. Adjustable Test Gauges.

The pressure gauge used for testing a wellis usually a test gauge (Figure 3). This issimply a better quality of gauge that can becalibrated for accuracy.

Figure 3. Gauge and dead weight tester.

Test gauges have an adjustment screw onthe face, side, or back. By pressurizing thegauge to a specific known pressure with adead weight tester, the adjustment screw canbe used to correct any error in the reading.Economy gauges do not have calibration oradjustment capabilities.

Most pumpers carry their test gaugeswrapped in a clean soft cloth stored safely inthe vehicle. This will be in a specificsection of the tool box or even in the glovecompartment. It may be necessary to havethe gauge re-calibrated by the factory or alaboratory occasionally if the pressure on thetest must be exact. The cam and rollergeared gauge is a good test gauge because ofits proven long life and accuracy.

When purchasing new gauges, it is best toselect a gauge with a pressure range wherethe hand turns to an approximately verticalposition or the center of the measurablepressure range. They are usually moredependable when they are correctly selected.

D-5. Calibrating Gauges and the DeadWeight Tester.

Figure 3 illustrates a gauge tester. Tooperate the dead weight tester and calibratethe gauge, the procedure on the next pageshould be followed:

14D-3

1. Remove the tester cover and loosen theplug that is screwed in where the gaugeis mounted on the right side.

2. On the left, close the back black valve.3. Open the front valve and crank the

handle upward. This pulls hydraulicfluid from the center reservoir to thespace under the plunger of the crank.

4. Close the front valve and open the backone.

5. Crank the handle downward so that fluidbegins to move to the center pedestalstem.

6. Remove the right-hand plug and, when itfills with oil, tighten the gauge intoplace.

7. Place the correct amount of weight on

the center pedestal as the left-hand screwis screwed down so that the weights arelifted to the correct height, and the gaugeis then visually checked for accuracy.

8. Use a screwdriver to adjust the hand onthe gauge.

Testing the pressure of the well directly.A high-pressure hose several feet long witha small diameter is available that will permitconnection directly from the dead weighttester to the wellhead. Pressure of the tubingor casing can then be accurately determineddirectly from the tester without using agauge in the system. In situations whereextremely accurate pressure measurementsare needed, this is an accurate method.

14D-4

15-i

The Lease Pumper’s Handbook

CHAPTER 15

ENHANCING OIL RECOVERY

A. ENHANCED RECOVERY1. Introduction to Enhanced Recovery.2. Enhanced Recovery Terminology.3. Technology Keeps Changing Improving Procedures.4. Not All of Yesterday’s Procedures Will Become Obsolete.

B. PRIMARY RECOVERY.1. Primary or First-Stage Recovery.

· Production allowables and productivity testing.· Sand and acid fracing.· Stabilizing formation sand and scale.· Echometer, dynamometer, gas lift, plunger lift, and other well analysis and

automation control systems.· Hydrotesting, tracer surveys, well logging, and other surveys.· Moving the casing perforations up or down the hole.· Changing lift systems.

2. Production Stimulation Through Horizontal Drilling.3. Beam Gas Compressors for Stripper Production.4. Venting Casing Gas at the Wellhead.5. Perforation Orientation.

· Raising casing perforations.· Lowering casing perforations.· Tubing/casing orientation.

6. Innovative Procedures.C. SECONDARY RECOVERY.

1. Secondary Recovery.2. Water Injection and Water Flood.3. Preparing a Well for Water Injection.

· Downhole preparation.· Wellhead preparation.

4. Operating the Water Flood System and Typical Problems.· Intermittent Operation.

5. Gas Injection and Pressure Maintenance.D. TERTIARY RECOVERY.

1 Introduction to Tertiary Recovery.2. Miscible Displacement Processes.

· Miscible hydrocarbon displacement.· CO2 injection.

15-ii

· Inert gas injection.3. Chemical Processes.

· Surfactant-polymer injection.· Polymer flooding.· Caustic or alkaline flooding.

4. Thermal Processes.· Steam stimulation.· Steam and hot water injection.· In-situ combustion.

15A-1

The Lease Pumper’s Handbook

Chapter 15Enhancing Oil Recovery

Section A

ENHANCED RECOVERY

A-1. Introduction to Enhanced Recovery.

The primary function of the lease pumperis to produce the most possible oil and gas atthe lowest effective lifting cost. Thispurpose governs most of the pumper’s dailyactivities. To this end, the pumper mustlearn how each individual well has producedin the past and study each independently tomaintain and enhance recovery.

When the drilling industry was young inthe United States, kerosene for lamps wasbig business. Gasoline was in low demandbecause the automobile industry was justbeginning. The first oil wells were shallowand were produced as hard as possible toachieve the most production in the shortestpossible time. These same objectives stillapply to some degree today, but the pumpermust learn how to extend the producing lifeof the well better than in the past throughenhanced recovery practices.

In the past, natural gas in the reservoir wasdepleted very rapidly, and the wells went dryin some fields after producing less than 15%of the available crude oil. When gas wasdepleted in the formation, pressure wasgone, and the oil stopped flowing to the wellbore. The field had played out.

As a better understanding of what washappening downhole became known andbetter production methods came to bepracticed, the percentage of available crude

oil recovered steadily increased. Today,with good enhanced recovery practices,more than 60% of the available oil in areservoir can be recovered. In some fields,even a higher percentage can be recovered.This still leaves a huge amount of oilwaiting in the formations for tomorrow’senhanced recovery technology.

Names have been attached to the reservoirstripping processes to give meaning to thevarious stages of controlled depletion. Newnames or different meanings to the sameprocess keep appearing in print with variouswriters, but this chapter will adhere to theolder, more common terminology.

A-2. Enhanced Recovery Terminology.

The first step to understanding enhancedrecovery is to review a few basic terms andto understand their meanings andimplications.

· Enhanced recovery. This is anumbrella term that includes all recoveryprocesses. The word enhanced ingeneral means good, better, or improvedrecovery practices and does not identifythe procedure used or the level ofsuccess achieved.

· Flood. The use of the word flood indescribing an enhanced recovery practiceindicates that the recovery force is

15A-2

injected in one well and must berecovered from a different well after ithas been pushed across the reservoir.With flood there are issues withcontrolling injection volumes, studyinginjection patterns, slugging volumes orapplying alternating forces, controllingfluid channeling, and trying to achievethe best possible sweep efficiency.

· First-stage or primary recovery. Thisbegins with the completion of a newwell. It includes all forms of naturallyflowing and artificial lift systems thatproduce fluids from the well bore to thetank battery. It can be a flowing well,have a pumping unit, plunger lift, gaslift, hydraulic lift, electrical submersiblelift, or any other lift system. First-stagerecovery also includes many forms ofgood well completion, treating, andstimulation practices that are performedon most wells to achieve optimumproduction.

· Secondary recovery. This term almostalways refers to simple water flood orreservoir pressure maintenance throughgas injection. Either is added as acontinuous force to the formationoutside the perforations. The force mustgo out through the casing perforationsinto the formation, be pushed throughthe formation, and produced backthrough a different well.

· Tertiary or third-stage recovery. Tobe referred to as tertiary or third-stagerecovery, two or more forces are addedto the formation, such as steam (heat andwater), carbon dioxide and gas, waterand chemicals, and slugging practices(the alternate injection of two types offluids). This may or may not be a finalrecovery technique. Slugging iscommon in tertiary recovery, and one ofthe two forces is usually water.

A-3. Technology Keeps Changing.

With each year that passes, newtechnology makes some commonly usedfield procedures obsolete or less desirable.At the same time, these new procedures costmoney to implement and may be tooexpensive to be practical for low producing,stripper, or marginally producing wells.

Some things, however, always remainconstant. Gas still rises to the top and waterfalls to bottom, leaving oil in the middle.Consequently, the pumper can stillunderstand what is happening regardless ofthe systems or methods that are introduced.The pumper must also keep up with howthese innovative procedures work and whenthey need to be added to the wells.

A-4. Not All of Yesterday’s ProceduresWill Become Obsolete.

With the invention of the rotary drilling bitbefore 1920 and the jackknife rotary rig inthe 1930s, the cable tool rig was declaredobsolete. However, for the foreseeablefuture, a few cable tool rigs are stillsearching for oil. Cable tool water welldrilling units are still being manufacturedand operated. The cable tool rig remains aneconomical unit for drilling shallow wells.

Present-day drilling procedures will bereplaced with techniques that permit wells tobe drilled in much less time, to greaterdepths, and with more accuracy, resulting ingreater production than is possible today.

Yet, many of the procedures common intoday’s oilfields will still be recognized andused far into the future. The skill developedby the lease pumper in understanding whatmay have caused a shortfall in oil productionand how to restore production will continueto be important to the oil producer and to thewelfare of the lease.

15B-1

The Lease Pumper’s Handbook

Chapter 15Enhancing Oil Recovery

Section B

PRIMARY RECOVERY

B-1. Primary or First-Stage Recovery.

During the past 100 years, manyinnovative methods have been used toenhance first-stage recovery. Although noadditional force is added into the formationon a continuing basis, many enhancingworkover jobs involve procedures that areextended deep into the reservoir—such asfracing, chemical treating, and, morerecently, horizontal drilling. Outstandingprimary recovery or well treatment practicesthat continue to enhance recovery include:

Production allowables and productivitytesting. Placing allowables (productionlimits) on some wells by company orregulating agencies can significantly extendthe life of the wells and greatly increaselong-range recovery. When severalcompanies are producing from the samereservoir, oil companies may requestregulations that limit production to protecttheir wells from offset operators who mayabuse the reservoir through overproduction.

Through productivity testing on ascheduled basis, wells can conserve gaspressure and produce more oil for a longerperiod of time. The goal is to reduce gasproduction while stimulating oil production.Conation of water and gas can be reducedand controlled if the lease pumperunderstands what causes these problems andhow to avoid damaging the wells.

Sand and acid fracing. Fracturing orfracing methods are techniques used tomade the formation more porous. Sandfracing stimulates wells by using sand toprop open a formation. Acid fracing usesacids and other chemicals to etch openingsin tight formations. These treatmentscontinue to be popular and contribute toincreased recovery in tight formations withlow porosity.

Other fracing procedures such as the use ofheat and pressure are also gaining inpopularity. Newer technology includes theaddition of tracers while fracing to controlreservoir damage.

Stabilizing formation sand and scale.These two enhanced recovery procedurescontinue to be improved through researchand technology. Sand and scale in theformation are stabilized by pumpingchemicals into the reservoir. This producesmore fluids with fewer problems. Importantconsiderations in these procedures arelocation and relationship of casing andtubing perforations, as well as sand screensand gravel packing.

Echometer, dynamometer, gas lift,plunger lift, and other well analysis andautomation control systems. During recentyears, great strides have been made in manymethods of automating producing wells withcomputer-controlled systems that obtain

15B-2

maximum production, lower lifting costs,and identify well problems as soon as theyoccur. These systems continuously analyzeproduction, control well production, andmake changes in production time. They alsoprint out a daily well analysis reportdetailing well problems.

Hydrotesting, tracer surveys, welllogging, and other surveys. Theseprocedures can provide information that isvaluable in deciding what types ofenhancements may be effective.

Moving the casing perforations up ordown the hole. When a well extends manyfeet into the reservoir, perforations need tobe moved up or down the casing in order torestore production. This need is determinedby the type and shape of the formation, howthe well was originally completed, and thetype of drive in the reservoir. Some strataalso have impervious layers within thereservoir that separate sections that produceat different rates. The location of tubingperforations in relation to casingperforations also dramatically affects theproduction from each well.

Changing lift systems. During the life of awell, the lift system may need to be changedseveral times as performance changes. Forexample, a well may have flowed when firstdrilled, then later placed on gas lift, followedby mechanical lift, hydraulic lift, back tomechanical lift, and finally had a beam gascompressor added. Selecting the type ofartificial lift is always a best-guess decision.

The number of activities that may enhanceproduction from the wells requires the leasepumper and the lease operator tocontinuously study all wells to enhanceproduction and make surface and wellbore

changes to meet changing reservoirconditions. When the production of a welldramatically falls, sometimes it is verydifficult to analyze the root cause of theproblem and decide what corrective actionmust be performed. Many analysis methodsare available and it is always a difficultchoice to select the best methods for findingthe answers. Many times wells are pluggedtoo early in their producing life because thelease operator never identified the trueproblem that caused the loss of productionand workover procedures did not solve theproblem. This can occur even withoutstanding operators.

B-2. Production Stimulation ThroughHorizontal Drilling.

The greatest technology advancement indrilling procedures in recent years has beenthe development of the equipment andtechniques used in horizontal drilling. Thecontrolled ability to deviate drilling from avertical direction to a controlled horizontaldirection has revolutionized the industry.

Along with the development of thesetechniques came the innovation of a drill bitand mud motor assembly with a slight bendin the middle. The next development wasefficiency in tracking and orienting the mudmotor; so the rig could continue to drill withthe drill string not rotating while the bit wasturned by the mud motor.

By turning the drill string, the bit drilledstraight ahead with a wobble, but with stablemotion and not greatly increasing the holesize. With the pipe standing still and themud motor turning, the direction beingdrilled can be corrected or changed withorientation control.

With these improved techniques, a rig candrill down near the reservoir, turn horizontalin the oil producing zone, then drill for more

15B-3

than a mile in the pay zone. This drill andcompletion technique exposes so much openreservoir hole that it will increase productionfrom the new well many times over previousdrilling methods.

Many older wells are also being workedover using this technique. After workover,many wells produce more oil than when theywere originally drilled. The success ofhorizontal drilling has been phenomenal,and the procedure continues to be improved.The ability and skill of the horizontaldrilling specialist supervising this procedureand the correct interpretation of well logsgreatly affects the success or failure of theseproduction enhancement objectives.

B-3. Beam Gas Compressors.

The movement of gas in the reservoirstops when the pressure of reservoir gas isequal to the weight of the fluid column andthe resistance in the flow line and tankbattery. Production of oil falls to zero. Itbecomes necessary to either plug andabandon the well or find another solutionthat will restore enough production to extendthe producing life of the well.

Figure 1. A typical beam gas compressor.(courtesy of Permian Production Equipment,

Inc. )

One option available is to install a beamgas compressor (Figure 1). The design of abeam gas compressor allows it to pull gasfrom the casing and reservoir, compress it,and inject it into the flow line downstreamfrom the flow line check valve. This canremove backpressure from the formation andallow fluids to migrate to the wellbore again.

The pumping unit supplies power tooperate the compression cylinder. Manystripper wells have increased their dailyproduction 300% or more with this system.This increase in income can pay for theequipment on many wells in just a fewmonths. The compressor cylindercompresses gas on both the up and the downstrokes with no lost motion. Operation of abeam gas compressor is shown in Figure 2.

Figure 2. Operation of the beam gascompressor.

(courtesy of Permian Production Equipment,Inc.)

15B-4

B-4. Venting Casing Gas at the Wellhead.

When the volume of gas being producedfrom the well has been reduced to tracelevels, another method to stimulate oilproduction may be used. This is to open thecasing valve to the atmosphere and allow thecasing pressure at the surface to fall to zero.

Although this volume of gas is extremelysmall, this production procedure will removebackpressure from the casing and formationand allow it to begin producing again.

When venting the gas at the wellhead bybarely opening the casing valve, oxygen canenter the top of the casing and can contributeto oxygen corrosion. To reduce oxygencorrosion, some operators install a ball andseat standing valve from a downhole pumpplaced vertically in the casing opening. Theweight of the ball seals out oxygen and onlya few ounces of pressure remains on thecasing.

A hose from the tubing bleeder valve intoa swage in the casing valve will allow thepumper to visually check well performanceeasily. The produced liquids are bled backinto the casing, which is coated with oil as itfalls back to the bottom of the hole. This oilcoating can also assist in preventingoxidation.

Since implementation of this procedureinvolves merely opening a casing valve, it isa popular way to extend well life.

B-5. Perforation Orientation.

Perforation orientation includes two areasthat affect the well’s ability to produce crudeoil. The first is a review of the location ofperforations in the formation. The second isto determine if oil production can bestimulated by closing off these perforationsand moving them either up or down the hole.

Raising casing perforations. When wellsare completed in water-drive reservoirs thatare many feet thick, perforations may beplaced above the water/oil interface level butbelow the gas zone. Eventually, the watertable in the reservoir rises, and waterproduction from the well increases.Perforations then need to be cemented off,and the well re-perforated at a higher level.This will restore part of the oil production,lower the water production, and extend thelife of the well.

Lowering casing perforations. With a wellproduced in a gas-drive reservoir, the oillevel will lower in the formation and thewell will begin to produce more gas and lessoil.

Overproducing gas from the well canresult in several undesirable results. Thefirst is caused by bleeding off the formationgas. This continued lowering of the gaspressure results in a like reduction in oilproduction. The second condition that it setsup is to allow water to rise in the reservoir ifit is also water drive.

By cementing off top perforations and re-perforating lower perforations, oilproduction may again increase and gasproduction may be reduced. Beforeperforations are lowered, a plunger lift mayneed to be installed or a pressuremaintenance program implemented to slowdown gas loss.

Tubing/casing orientation. One of theprocedures that must be determined by thelease operator is deciding where tubingperforations will be placed in relation tocasing perforations. They can be placedabove, even with, or below casingperforations.

Different companies have different reasonsfor deciding where they orient the tubing

15B-5

perforations in relation to the casingperforations. This orientation not onlyaffects the amount of fluid that will beproduced, but it also maintains a fluid or gasblanket on the formation and a smallpressure against the formation. It also to asmall degree affects paraffin and scaleproblems that may be encountered in theperforation area and the tubing.

B-6. Innovative Procedures.

The skill needed to produce marginal wellsdemands a close study of what is occurringto the wells, an understanding of how thewells were completed, what changes will berequired in the future to maintain profitableproduction, a keen understanding of whenthese changes must be made, and having thedesire to study and try to continuouslyenhance production.

One of the most important requirements inlease production enhancement is controlledby the lease pumper. This person mustdevelop a deep understanding of production,make good decisions daily, and workconsistently at the job. The pumper shouldkeep the following factors in mind:

· Type of reservoir.· Flow at each well. Is it increasing?· Does the efficiency of the chemicals need

to be retested?· What are offset operators doing to

stimulate production?· A large pump moves liquid quickly. Is

this the best way?· A small pump moves liquid slowly. Is

this the best way?· Frequency of pump repairs.· Setting of tubing perforations in relation

to the casing perforations.· Flow line backpressure against the

formation.· Should the type of mechanical lift be

changed?· How long has it been since the last

productivity test?· Pumping unit strokes per minute.· Pumping unit stroke length.· Causes for down times.· Changes in production profiles.

15B-6

15C-1

The Lease Pumper’s Handbook

Chapter 15Enhancing Oil Recovery

Section C

SECONDARY RECOVERY

C-1. Secondary Recovery.

In simple terms, secondary recovery is theaddition of basic water flood or gas flood(i.e., pressure maintenance) as a continuousforce. Secondary recovery methods shouldbe introduced very early in the life of a fieldwhile the income and profits from the wellsare high enough to pay for the additionalequipment and installation costs.

As noted in the following sections, thereare many problems with water and gas asdrive mechanisms. Nevertheless, they bothcontribute greatly to enhanced recovery.They can double the amount of oil producedfrom the reservoir during the life of thewells.

Water flood is the term used to describethe increase in oil recovery by injectingwater into an oil-producing reservoir. Whengas is injected, it is not referred to as gasflood, but instead is referred to as pressuremaintenance.The term injection well is a general term thatmeans that either water or gas is injectedinto a well.

Water disposal is a term used when waterdoes not enter an oil-producing zone.

C-2. Water Injection and Water Flood.

In the early years of experimenting withenhanced recovery, water flood wasintroduced. This secondary recoverypractice solved a major problem of well

operation. It provided a way to dispose ofundesirable water without the water beingused to stabilize firewalls around tankbatteries, control vegetation growth, andwater lease roads. At the same time, thewater raised production of the available oilin the reservoir.

Water flood remains a keystone to manymethods of enhanced recovery. It is anexcellent second-stage recovery techniqueand is also a major factor in slugging andblending and extends deeply into manytertiary recovery procedures throughout theproducing life of the reservoir.

One problem with water flood is that it isdifficult to push water through the formationas a vertical wall—that is, the water willspread out in the formation rather than movethrough it evenly. Gravity pulls the leadingedge of the water down and causes it tomove downward as it progresses through thereservoir. It can travel under the oil andleave a large amount of oil behind.

Figure 1. Wellhead set up for waterinjection.

15C-2

Nevertheless, water continues to be one ofthe best enhanced recovery tools available.Water flood should be carefully designedand properly installed because it willprobably be in place for the life of the wellor until equipment needs major changes.

C-3. Preparing a Well for WaterInjection.

Downhole preparation. When preparingan injection well, the casing must be testedfor leaks, a packer added near the casingperforations to seal the annulus space, andthe space filled with a packer fluid to protectit from corrosion. This process must receiveformal approval before it can be placed inoperation and must be witnessed byregulating agencies when installed.

Pressure in the annulus is checkedregularly to determine that the casing ortubing has no leaks and that the injectionpressure in the tubing is not excessive.

Figure 2. A wing valve used for waterinjection.

(courtesy of Baker SPD, a Baker Oil Toolscompany)

Wellhead preparation. When preparingthe wellhead for water injection, the pumperwill typically have a full opening master gateon the tubing. The wing assembly, aspictured in Figure 2, includes a valve, asolids screen, volume meter, throttling valveto regulate volume, a pressure gauge, and acheck valve to prevent fluid loss from theinjection well in the event of a line breaking.

C-4. Operating the Water Flood Systemand Typical Problems.

Some water injection systems require acollection system to gather all water fromseveral tank batteries. This may involvelarge water holding tanks, filters, a high-volume injection pump with waterdistribution lines to each well, and chokevalves. Other low-pressure, small-volume,one-injection well systems can be verysimple in design and operation (Figure 3).

A problem that may be encountered is thecollection of oil in the water disposalsystem. This can be solved by installing askimmer tank immediately ahead of thepump. The skimmer tank is a simplifiedwash tank or gun barrel. Oil enters thetank, is recovered, and is pumped backinto the oil production system. Waterbelow this level is injected.

Figure 3. Low-volume, low pressurewater disposal and injection system.

15C-3

Intermittent Operation. Automating thewater flood system for a basic automatedinjection system is a very simple procedurewhen simply injecting water that is producedon the lease. A simple hydrostaticallycontrolled on/off switch arrangement tocontrol the injection pump is all that isneeded (Figure 4). If the system is small andthe tank will not run over if the systemshould fail to function properly during the16-hour period that the pumper is off thesite, no backup system is required.

Figure 4. Automatic controls to allowintermittent operation of the water

disposal system. Note that a second set ofcontrols is provided as a safety backup.

If a larger volume is produced, a secondhigher level control is satisfactory to give afluid level backup system. Normally, thelower control will start the system as thewater level accumulates to a set height andturn it off when it is pumped down to alower level. If the system should fail, the

water level in the tank will build up, and theupper control will engage as a system safetyon/off pump control switch. This switchwill periodically need to be operated toverify that it will function if needed.

C-5. Gas Injection and PressureMaintenance.

The re-injection of produced gas into theformation for reservoir pressure maintenancealso plays a large role in secondary recovery.

Gas injection wells are in operation whereit is essential that all or part of the producedgas be re-injected for pressure maintenance.As gas is collected from the tank batteries, itneeds to be dried sufficiently either througha gas plant or through a gas scrubber toremove enough distillate or condensate toallow it to be re-compressed for injection.

The gas injection well is prepared in amanner similar to a water injection well. Inaddition, it will usually have a safety valveinstalled in the tubing string near the surfaceto protect the well from blowout if thesurface injection line should break.

An example of a gas injection well forpressure maintenance is shown in Figure 5.Note that in this variety, injection gas comesfrom either side if the unit. This well has adownhole safety valve.

Figure 5. Gas injection well forsecondary stage recovery pressure

maintenance.

15C-4

The first problem encountered with the gasinjection recovery method is that althoughthe gas was injected as a wall, it is verylight. Consequently, as it travels through theformation, it migrates to the upper areas ofthe reservoir, travels over the heavier liquids(including the crude oil), and leaves verylarge pockets of oil behind.

The second problem encountered is thatbeing lighter than oil, the gas will have a

tendency to finger—that is, break intosmaller streams—and channel to therecovery well, bypassing much of the oil andreducing the sweep efficiency.

The third problem is that it is difficult forthe injected gas to recombine with the oilremaining in the formation. It can evenmake the remaining oil heavier and harder tomove.

15D-1

The Lease Pumper’s Handbook

Chapter 15Enhancing Oil Recovery

Section D

TERTIARY RECOVERY

D-1. Introduction to Tertiary Recovery.

Third-stage—tertiary—recovery is usuallyimplemented and introduced slowly duringwater flood or pressure maintenanceprograms. However, in some reservoirs it isimplemented soon after the first well isdrilled. As with secondary recovery, tertiarymethods should be introduced very early inthe life of a field while income and profitscan justify the additional equipment andinstallation expenses.

Although the term may not be usedconsistently throughout the industry, tertiaryrecovery, as used here, means that two ormore forces are added to the formation. Thiscan include water and heat for steam, waterand carbon dioxide (CO2) sluggedalternately into the reservoir, polymers, ormany other systems. Three of the morecommon processes that will be encounteredare miscible displacement, chemical, andthermal. Variations for each are listedbelow.

Miscible displacement processes· Miscible hydrocarbon processes· CO2 injection· Inert gas injection

Chemical processes· Surfactant-polymer injection· Polymer flooding· Caustic flooding

Thermal processes· Steam stimulation· Steam flooding· Hot water injection· In-situ combustion (fire flood)

Some of the goals in enhanced recoverywithin the reservoir include:

· Lowering interfacial tension to allow theoil to be recovered.

· Wettability change of the formation rockfrom oil-wet to water-wet.

· Wettability change from water-wet to oil-wet.

· Emulsification and entrapment.· Solubilizing the rigid films at the point of

the oil-water interface.

D-2. Miscible Displacement Processes.

Miscible hydrocarbon displacement.Miscible displacement processes involve theintroduction of a fluid or solvent into thereservoir that will completely mix withreservoir oil and release the forces that causethe retention of oil in the rock matrix. Thisallows the solvent-oil mixture to be swept tothe producing well. Some of these fluids orsolvents are:

· Alcohol· Refined hydrocarbons· Condensed hydrocarbon gasses

15D-2

· CO2

· Liquefied petroleum gasses· Exhaust gasses

Fluids or solvents that mix with the oil inthe reservoir can be very expensive and costmany times the value of the recovered oil.After the slug of fluids or solvents isinjected, alternate slugs of cheaper water orgas are used to make the process profitableby receiving maximum benefits.

There are three different misciblehydrocarbon displacement processes forimproving recovery:

· Miscible slug process· Enriched gas process· High-pressure lean gas process

The use of inert miscible gas injection isincreasing, and projects of this type areexpected to continue to expand. They maypotentially be used to recover a highpercentage of the enhanced recoveryreserves in the United States

CO2 injection. This process involvespumping carbon dioxide into injection wellsand, after sweeping it through the reservoir,recovering the natural gas and CO2 fromnearby wells. The CO2 is separated from thenatural gas and re-injected many times.

Combining CO2 with heavy oils isdifficult. Temperature, pressure, and oilcomposition conditions are difficult forcarbon dioxide to obtain. Even if it does notfully combine, however, it will function as asolution gas drive. CO2 is soluble in bothoil and gas and causes fluids to swell. Thisis far more efficient than the injection ofLPG and natural gas.

There are, however, some disadvantages toCO2 injection. Since it thins the emulsion, itmay cause early breakthrough to the

producing wells, reducing sweep efficiency,and allowing large pockets of heavy crude tobe bypassed and left in the formation. Watermay be alternately slugged into theformation to reduce this fingering. It alsodramatically increases the volume of CO2-saturated water that is produced.

When CO2 combines with water, it formshighly corrosive carbonic acid. Wellheadsare usually prepared by installing stainlesssteel seals, bolts, and other trim to combatthe problem.

Initial projects indicate that CO2 floodmight result in as much as 40% of the totaloil recovered.

Inert gas injection. Inert gas injectionprocedures are very similar to injecting leanor dry natural gas. Although the scope ofnitrogen (N2) injection projects indicates thata higher pressure is needed to get idealmixing action, inert gas is exposed to crudeoil many times as it is swept through theformation and will result in an increase inproduction. Inert gas injection appears to beideal for a limited number of reservoirs.

D-3. Chemical Processes.

Chemical flood processes are not usedextensively and account for less than 1% oftotal tertiary recovery. This is because theprocesses are characterized by high cost,complex technology, and high risk.

Surfactant-polymer injection. This is atwo- step process. The first step is injectionof a surfactant slug. A surfactant is awetting agent that breaks the surface tensionbetween substances. The second step is theinjection of a polymer mobility buffer. Thesurfactant slug may also be referred to asmicellar solution, micro-emulsion, solubleoil, or swollen micelle. The purpose of the

15D-3

surfactants is to lower interfacial tension andto displace oil that cannot be displaced bywater alone. The purpose of the polymer isto provide mobility control for a morepiston-like displacement.

This system has not been totallysatisfactory because of the adsorption ofsurfactants on the reservoir rock, slugbreakdown, and the lowering of the ability tomobilize oil.

Polymer flooding. Polymers are substanceswith large molecules. When mixed withwater, polymers increase the viscosity of thewater, thus enhancing sweep efficiency.

There are two classes of polymers used inoil recovery:

· Polyacrylamides· Polysaccharrides

Polyacrylamides are generally used inconcentrations of 50-1000 parts per million.The use of polyacrylamides decreases themobility of the injected fluid by decreasingthe permeability of the reservoir rock.

A polysaccharride reduces the mobility ofthe injected fluid by increasing the viscosityof the fluid with very low levels ofpermeability reduction occurring in thereservoir rock. Although this results in acomplex flow behavior, the viscosities ofthese fluids are significantly higher thanwater and result in a significant increase inlong-range production.

Caustic or alkaline flooding. Caustic oralkaline flooding is a process wherein thealkalinity of injected water is raised toimprove recovery beyond basicwaterflooding. Water with a pH of 7 isconsidered neutral. As the pH value of asubstance decreases toward 1, the substanceis more acidic. As the numbers increase

from 8 to the maximum of 14, the substanceis more alkaline. A level of 12-13approaches the maximum level of alkalinitypractical for this process.

Caustic flooding is an economical option,because the cost of caustic chemicals is lowcompared to other tertiary enhancementsystems. The final production gained is less,but the cost can be substantially cheaper,thus resulting in a higher income.

D-4. Thermal Processes.

Steam stimulation. Steam stimulation is ageneral term used when steam is injectedinto a well, then produced back out throughthe same well. This method is also referredto as cyclic steam injection, steam soak, orhuff and puff.

With this process, up to 1,000 barrels ofwater per day are super-heated and injectedinto the well. Steam injection is continuedfor 10-30 days, then the well is shut in for asoak period of 1-4 weeks. During this shut-in period, heat dissipates into the reservoir.This thins or reduces the viscosity of theheavy crude oil, expands the volume of theoil causing fluid movement, and allows it tobe pushed through the reservoir more easily.

The well is returned to production andproduced until it has again slowed down tothe level that the process of steam injectionneeds to begin again. After much of thereservoir oil has been recovered from thewells, then the cyclic steam flood may beconverted to steam injection. The steam isinjected into one well, and the resultingfluids are produced from other nearby wells.Steam flood in some reservoirs has resultedin dramatic production stimulation.

Steam and hot water injection. Steaminjection continues to grow in importance inenhanced recovery. Steam injection

15D-4

accounts for approximately 20% ofenhanced recovery processes. Steam floodwells are drilled on an approximate five-acrespacing and require a reservoir depth ofapproximately ten or more feet. Steam floodis most effective in wells no deeper than5,000 feet.

Steam flood acts in a similar manner aswater flood in relation to injection andproducing well arrangements. The obviousadvantage is crude oil expansion. Itcontinues to expand as the pressure drops,and a water bank develops as the steamcondenses.

Hot water injection is effective to somedegree but, because of heat loss, it is not aseffective as steam flood and can result infingering and loss of sweep efficiency.

In-situ combustion. In-situ means “inplace” and in-situ combustion indicates thata fire will be ignited within the formation.By injecting compressed air into theinjection well this fire is driven across thereservoir. The heat generated by the fire willreduce the viscosity of the oil leading to adrop in pressure, which will allow the oil to

expand, resulting in movement and possiblyincreased production.

There are two different in-situ combustionprocesses. In the first, forwardcombustion, the fire is ignited in theformation near the air injection well, andwith continuing air injection the fire andproduced oil is driven toward nearbyproducing wells.

The second process is referred to asreverse combustion. In this process, fire isignited in the formation near the air injectionwell, and after fire has been driven for apredetermined distance from the injectionwell air injection is switched to the nearbyproducing wells. The fire will burn towardthose wells, while oil production direction isreversed and produced through the initial airinjection well.

The in-situ method is not always costeffective. Because of the large amount ofheat left behind from forward combustion,several other methods other than the drycombustion described above are beingdeveloped. These are referred to as wet andpartially wet combustion.

16-i

The Lease Pumper’s Handbook

CHAPTER 16

CORROSION, SCALE, AND CATHODIC PROTECTION

A. CORROSION AND SCALE.1. Introduction to Corrosion.2. Carbon Dioxide Corrosion.3. Hydrogen Sulfide Corrosion.4. Oxygen Corrosion.5. Electrochemical Corrosion.6. Problems with Scale.

· Stopping scale in the formation and chemical treatment.· Protective coatings.· Scale removal. Problems with scale caused by construction practices.

7. Other Types of Corrosion.B. CORROSION PROTECTION.

1. How to Prevent Corrosion Damage.· Rust.· Oxidation.· Painting.· Inside coating and linings.· Oiling the outside.· Insulating flanges.· Sacrificial anodes.· Electrical current.· Tarring and wrapping for underground black metal lines.· Conduits.· Fiberglass.· Galvanized bolted tanks.· Stainless steel and metal plating.· Plastic flow lines.· Chemical protection.· Mechanical barriers.

2. Locating Corrosion Damage Downhole.3. Protecting the Casing Long String.

· The use of insulating flange unions.· The use of sacrificial anodes.

4. Corrosion Protection at the Tank Battery.· Tank battery elevation and ground protection.· Lines protection.· Protecting vessels on the inside.

16-ii

16A-1

The Lease Pumper’s Handbook

Chapter 16Corrosion, Scale, and Cathodic Protection

Section A

CORROSION AND SCALE

The purpose of this chapter is to assist thelease pumper in understanding corrosion andhow to reduce the damage it causes in wellsand surface facilities. In addition, thischapter provides a basic overview of scaleand scale control for wells that produce a lotof water. Examples of corrosion and scaleproblems are shown in Figures 1 and 2.

Figure 1. Note corrosion on left item, adownhole pump part, and a parted rod.

Figure 2. Scale in a cut-out section oftubing showing how it is deposited inside

the unprotected pipe.

A-1. Introduction to Corrosion.

Corrosion is a general term for a reactionbetween a metal and its environment thatcauses the metal to breakdown. While thereare many types of corrosion, they all involveeither a chemical reaction or anelectrochemical reaction. In chemicalreactions, chemicals in the environmentreact with the metal to create differentchemicals. Thus, atoms or molecules of themetal combine with other atoms ormolecules that contact the metal to formdifferent, generally weaker, materials. Rustis an example of this type of corrosion.

In electrochemical corrosion, theenvironment around the metal results in thecreation of an electrical current, which issimply a flow of electrons. The metalcorrodes by giving up electrons to create theelectrical flow.

The oil field environment is filled withmetal pipes and other components that oftenexposed to chemicals that can causecorrosion, especially when the metal andchemicals are in a solution such as downholefluids. The pumper must understand how toreduce corrosive damage to the metal inwells, flow lines, tank batteries, andequipment.

There are four general types of corrosionof concern in the oil field. These involvethree chemicals of concern andelectrochemical corrosion. The types ofcorrosion include:

16A-2

· Carbon dioxide (sweet corrosion)· Hydrogen dioxide (sour corrosion)· Oxygen corrosion (oxidation)· Electrochemical corrosion

A-2. Carbon Dioxide Corrosion.

Carbon dioxide (CO2) is a corrosivecompound found in natural gas, crude oil,condensate, and produced water. CO2

corrosion, or sweet corrosion, is common inthe oil fields in southern Oklahoma, NewMexico, the Permian Basin of Texas, andthe Continental Shelf along the Gulf ofMexico because of the high CO2 content ofthe crude from these areas. Specialrefineries capable of refining high CO2 crudeoil are expensive to build and maintain.Most of these refineries in the U.S. areclustered in the Gulf Coast area. Much ofthe crude oil from Alaska must be refined inthis area because it also contains a largeamount of CO2.

CO2 is composed of one atom of carbonwith two atoms of oxygen. When combinedwith water (H2O), carbon dioxide producescarbonic acid (H2CO2). Carbonic acidcauses a reduction in the pH of water andresults in corrosion when it comes in contactwith steel. When iron (Fe) combines withcarbonic acid, it produces iron carbonate(FeCO2). Iron carbonate is not as strong asthe refined iron or steel used to make thewell components.

The damage caused by sweet corrosion inoil wells usually results in pitted sucker rodsand the formation of hairline cracks.Corrosion test coupons can be inserted intothe lines to indicate the level of iron removaland other corrosive conditions. Calipersurveys can also be used to determine theextent of tubing damage. Chemicalinjection, alloys, and protective coatings areused to combat the problem.

A-3. Hydrogen Sulfide Corrosion.

Hydrogen sulfide (H2S) occurs inapproximately 40% of all wells. Theamount of H2S appears to increase as thewell grows older. H2S combines with waterto form sulfuric acid (H2SO4), a stronglycorrosive acid. Corrosion due to H2SO4 isoften referred to as sour corrosion. Sincehydrogen sulfide combines easily withwater, damage to stock tanks below waterlevels can be severe.

Solutions to sour corrosion problems aresimilar to those for sweet corrosion. Thisincludes the use of chemicals, alloys, andcoatings to combat the problem and reducethe damage. Circulating chemical down theannulus is a common practice to treatdownhole problems.

When sufficient amounts of H2S areproduced with the emulsion, the pumpermust wear a gas mask when gauging orworking oil—that is, testing oil at the thiefhatch to determine if it is ready for sale(Figure 3).

Figure 3. Where H2S gas is present, sourcorrosion is likely and breathing

apparatus is required.

16A-3

A-4. Oxygen Corrosion.

Oxygen corrosion or oxidation is the mostcommon form of corrosion. On steel andiron, oxidation typically takes the form ofrust. Painting the tank battery and othersurface equipment to eliminate this contactis basic oxygen corrosion protection.

Oxygen corrosion begins when equipmentmakes contact with the atmosphere andmoisture. Under these conditions, the ironand oxygen react with each other to formferric oxide (Fe2O3), which is commonlyreferred to as rust. Oxidation can also occurwith other metals, including aluminum.Although the compounds formed will bedifferent, the results are the same in that themetal is weakened, usually undergoingembrittlement in which the metal becomesbrittle. Oxidation can also accelerate thedamage from sweet corrosion.

An oil blanket is often deliberatelymaintained on produced water to block theatmospheric oxygen from contacting thewater. A system that prevents theatmosphere from making contact with theproduced water is referred to as a closedsystem. A system that allows the air tocontact the produced water is referred to asan open system. Stripper wells are oftenproduced with the casing valve open to theatmosphere, which promotes downholecorrosion. Water flood can also injectoxygen into the formation, promotingoxidation. Open systems are sometimespreferred because the formation of rust canactually help to protect against some formsof corrosion, such as electrochemicalcorrosion described later.

A-5. Electrochemical Corrosion.

There are two common types ofelectrochemical corrosion. One is the result

of electrical current leaking into theenvironment. Electrical current may beplanned to power electrical equipment or itmay be generated accidentally, such as thestatic electricity produced by the windblowing. Corrosion can occurs wherever theelectrical current leaks into the environment.For example, poor grounding may allowstray current to enter a pipe. When thecurrent reaches a wet area, the current mayflow from the pipe. Electrochemicalcorrosion is likely to occur at that point.

The second type of electrochemicalcorrosion is more common. It occurs whenmetal in water, such as downhole parts orpipe laid in moist soils, becomes part of anelectrical cell. Such a cell is essentially anacid battery and will be formed just aboutany time two different types of metals areplaced in an acidic solution. Electrons fromone metal will flow to the other metal. Thisresults in the metal that gives up electronsbeing eaten away and the other metalbuilding up a brittle coating. The metal thatgives up electrons and corrodes away isreferred to as the anode, and the metal thatcollects electrons is called the cathode.

Techniques that are implemented to slowdown or eliminate electrochemical corrosionare referred to as cathodic protection. Incathodic protection, the flow of electricalcurrent is altered to prevent the metal to beprotected from serving as an anode.

A-6. Problems with Scale.

Scale, or gyp, is carried with water in asolution and migrates toward the well bore.Problems with scale can begin as itapproaches the matrix or well bore area. Itcan plug the formation, casing, and tubingperforations; make tubing in the hole stick;fill tubing to the point that the pump cannotbe pulled without stripping; and plug flow

16A-4

lines. At the tank battery it can fill lines andvessels and accumulate in the bottom as asolid. Scale can accelerate electrochemicaldamage by acting as a cathode to the steel,resulting in deep pitting.

Stopping scale in the formation andchemical treatment. The first place tosolve problems with scale is in theformation. Chemicals are available that canbe blended with water and pumped into theformation to stabilize the scale and highlyreduce its accumulation in the system. Itmay be necessary to acidize the wellsperiodically to clean up the immediatereservoir area and to reopen the casingperforations. Special small materials thatare water- or oil-soluble can be blended intothe fracing compounds to control the processand increase the efficiency of the treatment.

Figure 4. The chemical tank(background) and the pump and injectiontee (left of wellhead) are used to combat

scale with chemicals.

Protective coatings. Special coatings canbe applied to reduce the ability of scale tocling to the inside of the tubing. Withflowing wells, this coating may be appliedlike paint. On pumping wells the rod actionwould damage the coating. Consequently,special chemicals can be circulated down the

casing that are produced back up through thetubing to protect perforations, tubing, andthe downstream flow line and tank battery.This treatment can be a continuous orperiodic batch treatment.

Scale removal. When systems arepermitted to fill with scale, it may benecessary to disassemble, clean, and rebuildof the system. A good and efficient scalecontrol program must be maintained.

Scale can be reduced and removed by slowand expensive chemical processes. Scaleaccumulation in tubing can also be scrapedor drilled out. In vessels, it may require theremoval of the manway plates, entering thevessel with the proper safety equipment, andphysically shoveling the accumulation out.

Problems with scale caused byconstruction practices. Good constructionpractices should always be followed toprevent building systems that trap scale andcause unexpected problems. As an example,the line from the wellhead to the tank batteryshould not contain any 90-degree bends.Even an ell in the line may not besatisfactory. Pipe can be bent or slow curvesinstalled to eliminate any scale trapsbetween the well and the tank battery.

A-7. Other Types of Corrosion

Many environmental factors can influencethe effects of corrosion. The chemicalcontent of the soil and the production fluid,the climate, the materials used for wellcomponents, and other factors have aneffect. The presence of microorganisms canaccelerate corrosion, and microbiologicalcorrosion in which organisms eat thematerials or chemically transform them isalso common.

16B-1

The Lease Pumper’s Handbook

Chapter 16Corrosion, Scale, and Cathodic Protection

Section B

CORROSION PROTECTION

B-1. How to Prevent Corrosion Damage.

To stop corrosion, the pumper must makechanges in the environment that prevent thechemical reactions and electrical currentsthat cause corrosion. Since corrosion affectsvirtually all equipment on the lease, a wide-reaching prevention program is necessary.Good corrosion prevention begins on thefirst day of the first installation with thedrilling of well number one and continues onall equipment at the most affordable level.

This is emphasized because the cost ofdrilling the well, installing the necessarysurface equipment, and constructingfacilities must be invested while the wellproduces enough oil to support the recoveryof this expense. As wells become marginalproducers, income from production maybarely cover lifting costs alone. Funds arerarely available for expensive methods ofcorrosion protection.

There are many methods of protection, andno one system is used exclusively anywhere.The pumper should become familiar with allprotective methods in order to make logicaldecisions. These include chemical,mechanical, and electrical methods such as:

· Rust· Oxidation· Painting· Inside coating and lining· Oiling

· Insulating flanges· Sacrificial anodes· Applied electrical current· Conduits· Fiberglass components· Galvanized bolted tanks· Stainless steel and metal plating· Plastic flow lines· Mechanical barriers

Rust. While rust is often considereddestructive, it can be a natural first level ofprotection for ferrous (iron-containing)metals. The rust itself can protect theoutside of a flow line while the producedcrude oil partially protects it on the inside.

When equipment is first constructed andinstalled, unpainted metal rapidly oxidizes.As the rust ages, it gets heavier, a scale isformed, and the corrosion rate slows down.In the dry southwest where rainfall is lowand the ground surface stays dry, surfaceflow lines are seldom painted or treatedbecause rust rarely gets severe enough tocause leaks. Many unpainted lines are stillin service after more than fifty years.

Oxidation. Oxidation is also a natural firstlevel of protection on non-ferrous(containing no iron) metals. Oxidation oncopper, aluminum, and other non-ferrousmetals provides protection similar to rust oniron. Aluminum has not been popular in oilfields except for use as temporary water

16B-2

lines to drilling rigs. When some types ofoilfield acids contact aluminum, extensivedamage can occur in a short period of time.

Painting. Most equipment in tank batteries,especially welded tanks and lines, is paintedimmediately after construction to preventcorrosion. Galvanized, stainless steel,nickel-plated, and other corrosion-resistantmaterials do not normally require painting.However, galvanized pipe is not suitable forcarrying petroleum products.

Inside coating and linings. Coating lineson the inside is popular for protectionagainst some types of corrosion, especiallyin downhole tubing. Linings may also beused in some lines and vessels. Anotherlevel of natural protection inside the linesand vessels comes from naturally producedcompounds such as the crude oil itself and,in some instances, scale. Scale is the buildupof minerals that can be dissolved ingroundwater and deposited on tubing andcasing.

Oiling the outside. At one time, crude andother oils were sprayed on pipe andequipment that was put in storage forextended periods of time. A good heavy oilwith a small paraffin content will sprayeasily, protect nearly as well as paint, andlast for several years. Non-corrosive oil alsoprovides significant protection to the inside.This practice is less common today due toenvironmental concerns.

Insulating flanges. Insulating flanges areused extensively to prevent electrical currentflow. With steel lines, an insulated flangeunion can be placed above ground level ateach end of a line, near the well, and nearthe tank battery. This acts as a buffer toblock static and stray electricity.

Sacrificial anodes. Sacrificial anodes areoften installed in liquid holding vessels. Forexample, by installing two to four sacrificialanodes in a heater/treater near the fireboxand below the water line, a path is providedfor electricity to travel from the anode to thecathode, protecting the vessel. Thus, theanode provides the electrons for current flowrather than the part being protected. Theanode is “sacrificed” and must beperiodically replaced as it corrodes away.

Electrical current. Electrical current canbe imposed in selected areas to protect theoutside of a downhole casing. Shallowcathodic protection wells can be drilled nearoperating wells and, by use of a sacrificialanode in these holes, small amounts ofcurrent (milliampere range) can be directedto the wells and removed at the wellhead togreatly reduce casing material loss andprevent casing leaks.

Figure 1. A cathodic protection well.

Conduits. Conduits are used extensivelywhere lines must pass under roads to protectthem from moisture. Vents are also installedto allow leaking fluids to escape.

16B-3

Fiberglass. Initially, fiberglass was usedinside tanks to extend their life. Now tanksmade entirely of fiberglass are available.These are widely accepted in water disposaland chemical injection systems, and theiruse continues to expand for holding crudeoil.

Galvanized bolted tanks. Galvanizedbolted tanks are not subject to corrosion andwere standard for years. Many are stillcommon in the field.

Stainless steel and metal plating. Stainlesssteel bolts, seal rings, gaskets, and smalltubing have replaced more corrosive partsthat fail due to embrittlement and metalfatigue. Nickel plating is also highly used.

Plastic flow lines. In recent years, plasticssuch as polyethylene, polyvinyl chloride(PVC), and other synthetics are replacingsteel and rubber in corrosive situations.

Chemical protection. Chemicals still offerprotection in casings and other hard-to-reachareas. These chemicals are constantly beingimproved and are very effective.

Mechanical barriers. Mechanical methodscan effectively stop some equipmentcorrosion problems. One method is toremove oil- or water-saturated soil fromcontacting lines or equipment. Also,insulating materials such as gravel and tarredfelt under tanks will allow air to circulateand greatly extend their lives. Tarring andwrapping underground black metal linesprevents water and chemicals in the soilfrom contacting the lines. This method isoften used to protect pipe in wet areas.Finally, a simple downhole pump ball andseat can stop oxygen from entering openannulus valves, yet allow gas to escape.

B-2. Locating Corrosion DamageDownhole.

Corrosion downhole at the well has causedproduction problems since the first wellswere drilled. Corrosion can create holes inthe casing and cause formation leaks inupper zones. This can also allow oil to flowout the surface pipe valve and overflow thecellar. The hole in the casing can even be inan offset well rather than one from whichhydrocarbons are escaping. The surfacevalve cannot be closed in this situationbecause it may force the oil and gas to breakinto the upper freshwater zone,compounding the problem.

Temperature surveys are conductedperiodically on flowing wells to check forholes in the casing. The expansion of theescaping fluids at the leak creates a cold spotthat can be detected by the survey.

Another method of locating holes in casingis to run a casing survey. Gas pressure canbe injected into the annular space with thewell shut in, depressing the liquids backdown to the casing perforations where thepressure chart will level off to a straight line.As the gas injection is stopped and the wellsits pressurized for a 24-hour period, thepressure should remain constant on thechart. If it falls, there is a hole in the casing.

B-3. Protecting the Casing Long String.

Protecting the inside of the casing stringthat is cemented through or to the oilproducing zone can be important incorrosive wells. Protection can be achievedby periodically scheduling the application ofa chemical protective inhibitor blanket onthe surface of the pipe all the way down thehole by batch injecting the chemical into theannular space. A carrying agent, such asseveral barrels of crude oil or water, may

16B-4

need to be mixed with the chemical to giveit sufficient volume to allow the inhibitor toquickly flow by gravity to the bottom of thewell without channeling or streaking on theway down. This results in 100% coverage.

Preventing electrochemical corrosion ofthe outside of the casing requires a differentapproach. Since the string of pipe iscemented as it passes through theimpervious cap and is bolted at thewellhead, the only opening into it is thesurface valve on the wellhead. Drilling mudis usually caked around the outside of thecasing from the surface down, so corrosion-inhibiting liquids cannot be injected at thesurface and be expected to coat the outsideof the pipe. The solution is to block or stopthe electrochemical process, which is causedby oxygen and acid.

The use of insulating flange unions.Insulated flange unions (Figure 2) areinstalled at the well and the tank battery toprevent the flow of electrical current into thewell through the casing. When electricityflows into the casing, metal is removed atthe point where it leaves the well. Thesepoints act as anodes. By preventing the flowof electricity into the well, the amount ofiron lost will be reduced.

Figure 2. An insulated flange union thatis installed near the well. The valve is

used to periodically record line pressure.

The use of sacrificial anodes. The idealsolution is to drill another shallow hole near-by and install a series of sacrificial anodes.Lines are run to the surface and connectedthrough a control panel to a power line. Acontrolled electrical current is run throughthe sacrificial anode from this special well.The current runs through the earth and entersthe well casing and comes up through thecasing. This turns the casing anode into acathode and corrosion stops. A protectivescale will even develop on the outside of thecasing at this point, offering additionalprotection.

B-4. Corrosion Protection at the TankBattery.

Corrosion protection at the tank batterybegins before the tank battery is constructed.As the tank battery is constructed,appropriate steps of the construction aredirected toward corrosion protection.

Tank battery elevation and groundprotection. The tank battery location iselevated several inches above thesurrounding area. Dirt is bladed up to give ita slight elevation above the surroundingterrain. A side taper is added that will allowrainwater to run off. Several cubic yards ofcrushed rock are placed under the vessels soair can circulate under them to evaporate anywater that might be present. This rock isthen covered with a double layer of 120-pound roofing felt to further insulate thetank from the rock.

The pressurized vessels are set on concretebases to keep them level and support theweight of the vessel, fluid, and lines.Crushed rock may then be spread over theopen ground to control vegetation growth,which may trap moisture and promotecorrosion from organisms.

16B-5

Lines protection. When lines are laid, areaswith heavy vegetation and standing watershould be avoided. Coated and wrappedpipe or elevated lines offer some protectionwhen these areas cannot be avoided. Manystyles of insulated unions are available foruse near the well and also just before theflow lines enter the tank battery to reduceelectrochemical corrosion in the line.

Protecting vessels on the inside. Paint isalways used at the tank battery as the firstmethod of protecting vessels. A secondmethod is to protect the inside of the vesselwith special epoxy-type paint and fiberglassliners. The method selected to protect thevessel on the inside will depend upon whatcorrosive agents are contained in theproduced crude oil.

Fiberglass vessels and PVC water lineshave also reduced some corrosion problems.Improved fiberglass vessels (Figure 3) arebecoming more common as new batteriesare built and vessels replaced. Low-pressurewater injection systems are beingconstructed with plastic and PVC.

Figure 3. Fiberglass gun barrel or washtank with PVC water leg to reduce

problems from line corrosion.

Another method is to protect the vesselwith chemicals. These may be injected atthe tank battery, but the most logical place toinject them is down the casing annulus toprotect the full system.

Sacrificial anodes are widely used inheater/treaters (Figure 4). These anodesmust be replaced as they corrode in order toprovide continual protection of the vessel.The anode is inserted into the vessel in thelower water area, and a ground wire isattached from the anode to the fireboxflange. Here, current is diverted into the linesystem to protect the bottom section of theheater/treater from pitting. Oil-saturated dirtis removed from around the steel lines andclean sand put back into its place. Thisstops the formation of galvanic cells which

cause line leaks.

Figure 4. Heater/treater firebox viewwith two sacrificial anodes visible, one tothe right and the second directly below

the fire tube flange.

16B-6

17-i

The Lease Pumper’s Handbook

CHAPTER 17

WELL SERVICING AND WORKOVER

A. WELL SERVICING.1. Introduction to Well Servicing.2. Styles of Well Servicing and Workover Units.

· Single-pole units.· Double-pole units.· Mast style units.· Single- and double-drum well servicing units.

3. Roading the Well Servicing Unit to the Lease.4. Approaching the Well.5. Setting Up the Well Servicing Unit.6. The Well Records.

B. PULLING THE ROD STRING AND PUMP.1. The Rod String Records.2. The Strength of the Rod String.3. Straight and Tapered Rod Strings.4. Pulling and Running Rod Strings.

· Power rod tongs.· Pulling stuck pumps.

5. Running the Rod String into the Hole.· After the rod job is finished.

6. Fishing Parted Rod Strings.7. Fiberglass Rods.8. Downhole Pump Problems.

C. THE TUBING STRING.1. Tubing and Casing Perforation Depth Comparisons.2. Selection of Tubing Quality.3. Tubing Lengths and Threads.4. Measuring Line Pipe and Tubing Diameter.5. Pulling and Running Tubing.

· The mud anchor.· Pipe length measurements.· Perforated nipple.· Seating nipples.· Packers, hold-downs and safety joints.· The tubing string.· Pup joints.· Wellhead hangers.

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6. Typical Tubing Problems and Solutions.· Split collars and holes in tubing.· Standing valves.· Split tubing and hydrotesting.

D. WIRE LINE OPERATIONS.1. Five Uses for Wire Lines in Servicing Wells.2. Wire Rope.3. Functions of Guy Lines.4. Functions of Line from Drum to Blocks.5. Sand Lines.6. Solid Wire Lines.7. Electric Lines.

E. WELL WORKOVER.1. Well Workover Operations.

· Killing flowing wells and blowout preventers.· Blowout preventers.

2. Stuck Pipe.· Salt bridges.· Scale deposits.· Sand control.

3. Drilling with Tubing.4. Stripping Wells.5. Fishing Tubing.

· Running impression blocks.· Hard impression blocks.· The soft impression block.· Fishing tools.

6. Fracing/Hydraulic Fracturing Wells.7. Pulling and Running Tubing Under Pressure.

17A-1

The Lease Pumper’s Handbook

Chapter 17Well Servicing and Workover

Section A

WELL SERVICING

A-1. Introduction to Well Servicing.

Some wells are plugged and abandonedtoo early because the people responsible formaintaining the well did not recognize orunderstand why it stopped producing and didnot know how to restore production.

In order to keep wells producing oil andgas, the pumper must understand theproblems that can occur and how productioncan be restored. Any problems that occurdownhole must be correctly identified andrepaired. This means that rods and tubingmust be occasionally pulled.

The pumper must understand what wellservicing equipment is available, how itfunctions, what problems may be occurringin the reservoir, and what must be done torestore production.

A-2. Styles of Well Servicing andWorkover Units.

There are three styles of basic wellservicing units based on their mast or poledesign. All three are manufactured today,although the two smaller models have alimited market. The smaller pole units areavailable with one or two drums, while thelarger mast unit has two drums.

Single-pole units. Single-pole units areused to service shallow wells. Since the

well servicing unit has one pole, the rodsand tubing are laid down on a rack. The unitcan be operated with only an operator and afloor person, although for most wells it isbetter to have a third helper.

The unit has as many as eight guy lines,four for the lower section, and four for theupper section to be guyed after extending theupper section. After folding the pole mastup on most single-pole units, the two frontload supporting guy lines must be fastenedbefore the upper mast pole can be telescopedup. For safety and when the wind isblowing, it is better to guy all four lowerlines before telescoping.

The mast can be telescoped to differentheights, according to what job is planned.Since most rods are 25 feet long, for a rodjob only the mast can be lower than for aservice job that involves tubing, which canexceed 32 feet. The higher pin level willallow tubing and 30-foot rods to be pulled.When telescoped to maximum height, rodscan be pulled in doubles and laid on racks.

These units are still popular with operatorswho have many shallow wells and do theirown service work.

Double-pole units. The double-pole unit ismore efficient than the single-pole, becauserods can be hung in the derrick in doubles,and the tubing can stand in singles. It stillallows the option of laying the rods down in

17A-2

singles or doubles and the tubing in singles.When pulling rods, the box can break oneither side, so the rods must go back into thehole in the same order from which they werebroken out.

When pulling tubing, the collar is used tosupport and lift the string, so the connectionmust always be broken out of the top of thecollar. When possible, the tubing should alsobe run back in the well in the reverse orderof being removed. More thread leaks will beencountered when the joints are jumbled inrandom order each time they are pulled.Thread lubricant should always be appliedwhen running the pipe back into the hole.Cards are available from rod suppliers toshow how tight the rods should be made up.

The double-pole unit support truck is notmuch larger than the one for the single mastunit. With two poles braced together,however, it can pull medium depth wells,allowing many operators to pull most oftheir own wells. This unit can also performlight workover duties and can be operatedwith a three- or a four-person crew.

Mast style units. Figure 1 illustrates a maststyle well servicing unit. This unit is capableof pulling standard 25-foot rods in triplesand tubing in doubles. Fiberglass rods are37½ feet long and can be pulled in doubles.Since the rods are racked by a person on thederrick, they can be pulled very rapidly. Fordeeper wells, the work is almost alwaysperformed with the mast style units.

Single- and double-drum well servicingunits. A well servicing unit may have oneor two drums. If it has a single drum,operators usually just pull rods and tubing orswab, although it can be used both ways byswapping the lines. A double-drum unitcontains a swab line for swabbing, cuttingscale and paraffin, pulling standing valves,

running impression blocks, setting andremoving downhole tools, as well as otherfunctions.

The single- and double-pole units mayhave one or two drums. The larger standardmast type unit has two.

A-3. Roading the Well Servicing Unit tothe Lease.

Driving the well servicing unit to the leasecan present several road hazards. Theservice rig is heavy and slow moving. It isusually followed by a crew truck pulling atool security trailer. The drivers should talkabout safety and observe good roadpractices.

The crew truck should trail the servicingrig at a comfortable distance so that vehiclesneeding to pass will have enough room topass each the truck and rig separately.

When the road rises, especially on a roughlease road, extra separation must be allowed.If the driver of the well servicing unit missesa gear or if the engine should die, the wellservicing unit may roll backward down theslope. This can present exceptional risk tothe crew truck occupants.

Figure 1. A typical telescoping mast typepulling unit.

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A-4. Approaching the Well.

When backing the unit up to the well, aperson should stand in front of the unit onthe driver’s side so that signals can be seeneasily by the driver. Another person at theback of the rig should watch the pumpingunit and the pulling unit and signalinstructions to be relayed to the driver by theperson in front of the rig. The pumping unitmust be turned off with the horse head in aposition where it cannot be hit by the pullingunit or poles, and the pumping unit brakeshould be set. A sill or 6” x 8” wood blockapproximately two feet long should beplaced on the ground so that the unit willback up against it and cannot strike thepumping unit or wellhead in event thedriver’s foot slips off the brake. The unitshould be set the correct distance from thewellhead and be square with the anchors andleveled with the leg screws. This allows theblocks to hang directly over the hole.

Figure 2. Guying the pulling unit.(courtesy of Williamsport Wirerope Works,

Inc.)

A-5. Setting Up the Well Servicing Unit.

When setting up the double mast unit,there are usually only six guy lines. Two of

these are pre-set in length and reach from thetop front of the lower section to theheadache rack that supports the mast when itis folded down. After the lower mast hasbeen set up and these two guys are tight, theupper section is telescoped up and theremaining four guy lines attached to theanchors.

The correct method of guying a pullingunit is shown in Figure 2.

A-6. Well Records.

There are five records or pieces ofinformation that the person in charge of thewell servicing operation should haveavailable. These are:

· Casing information. This sheet lists thedistance from the wellhead to the top ofthe perforations, the number ofperforation shots and arrangement, thedistance that they cover, and the casedhole distance from the bottomperforation to the bottom of the opencasing.

· Tubing tally sheet. This is an itemizedlisting of the tubing hanger, pup joints,joints of pipe, safety joint, packer, hold-down, seating nipple, perforated joint,mud anchor, and bull plug in exact orderand length from the tubing head to thebottom of the string. This sheet will alsoprovide the grade of the tubing, if thejoints are measured with the thread off oroverall, the average length of the fulljoints of pipe, and a listing of all otherequipment in the hole. Additionalinformation may also be listed.

· Complete packer or holddowndescription. This sheet will list allspecial equipment such as packers,holddowns, and safety joints in the hole.These should be identified by

17A-4

manufacturer, year of manufacture,metal content, brand, style, model,description, and instructions on how torelease and latch this equipment duringworkover operations. Enoughinformation about the downholeequipment should be available that allquestions on pulling and servicing areanswered.

· Rod tally sheet. This identifies the sizeand length of every rod in the hole,including the polished rod, pony rods,sucker rods, safety joint, pump, and gasanchor. Rods should be identified bybrand and described with instructions on

how to release any safety joint in thehole. If the well has a tapered string, thenumber of rods in each size should beincluded.

· Complete pump description. If thepump must be replaced or fished out ofthe hole, a complete description of itshould be on file.

A more complete description of theimportance of this information andillustrations of the downhole well recordsthat should be maintained in the field recordbook are in Chapter 19. The pumper shouldbe familiar with these important records.

17B-1

The Lease Pumper’s Handbook

Chapter 17Well Servicing and Workover

Section B

PULLING THE ROD STRING AND PUMP

B-1. Rod String Records.

When performing well servicing work, itis important to have access to the latest wellrecords, including the last pulling record thatshows what is currently in the hole.

An illustration of a pipe tally is shown inFigure 1.

Figure 1. A tubing record and a rodrecord must be maintained on every well.

B-2. The Strength of the Rod String.

If the well is 2,000 feet deep or less, allequipment made to go downhole will meet

the strength requirements of the installation.Little attention is given to tensile strength.If the well is 10,000 feet deep, rods andtubing capable of supporting a 10,000-footstring with a satisfactory operation andsafety margin must be used. Satisfactoryrecords of the API tensile strength must bemaintained and must include the API ratingof every rod in the hole.Companies that manufacture sucker rods useAPI designations such as C, D, and K toidentify the quality of the rod, includingtensile strength and corrosion resistance.This letter is also stamped on the flat side ofthe pin. Class C rods are used in light tomedium applications, and D is used inmedium- and high-tensile strengthapplications. An example of an API Class Dsucker rod is shown in Figure 2.

Figure 2. API Class D sucker rod.(courtesy of Trico Industries, Inc.)

17B-2

When a string of rods or tubing has beenexposed to severe service and the wellbegins to have excessive problems such asparting rods or breaks, a new or betterquality string will be run in the well. Theused string will usually be downgraded onestep and re-used in a well that requires alower tensile strength since they shouldnever be graded back to their original levelof service.

When these used rods are transported tothe storage yard, they should be stored andrecorded with their lower rating. Commonsense must be used when placing them backin service. The lease pumper should acceptthe inventory classification record, not thestamped designation. Thus, whenpurchasing used rods or tubing, the leasepumper should make sure that thedowngrade practice has been followed.

B-3. Straight and Tapered Rod Strings.

The API has guidelines for identifying therod system in the well. Rod diametermeasurements are in fractions of an inch,with numbers assigned based on eighths ofan inch. The table below shows thenumbering system. The first line shows arod with a one-half inch diameter body.Since one-half inch contains four one-eighthincrements, this rod is designated with a 4and is referred to as a number four rod.Number four rods will work in a water well,but are not usually found in the oil field.

½ = 4 1/8"-increments, or a # 4 string.5/8 = 5 1/8"-increments, or #5.3/4 = 6 1/8"-increments, or #6.7/8 = 7 1/8"-increments, or #7.8/8 = 1 inch or 8 1/8"-increments, or #8.9/8 = 1-1/8 inch or 9 1/8"-increments, or #9.10/8 = 1¼ inch or 10 1/8"-increments, or

#10.

With this method of identification, it iseasy to represent the rod string with just afew numbers even if it is a tapered string.Rod string identification numbers are asfollows:

APIRod

RodDia.

APIRod

RodDia.

44 = All ½" 86 = 1", 7/8", ¾"54 = 5/8", ½" 87 = 1", 7/8"55 = All 5/8" 88 = All 1"64 = ¾", 5/8", ½ 96 = 1-1/8", 1",

7/8", ¾'65 = ¾", 5/8" 97 = 1-1/8", 1",

7/866 = All ¾" 98 = 1-1/8", 1"75 = 7/8, ¾, 5/8" 99 = All 1-1/8"76 = 7/8", ¾" 107 = 1¼", 1-1/8,

1", 7/8"77 = All 7/8" 108 = 1¼", 1-1/8",

1"85 = 1", 7/8", ¾",

5/8"109 = 1¼", 1-1/8"

Figure 3 illustrates a method of identifyingthe rod quality to be used at a well site.

Figure 3. Sign at well specifying rodquality.

17B-3

Some rod strings are tapered. Tapered rodstrings do not actually use tapered rods. Inthis context, tapered means that top of thestring has larger rods and that smaller rodsare used in lower portions of the string.When going in the hole, a selected numberof the smallest rods are run immediatelyafter the pump is set in the hole. A change-over coupling is then added and the nextlarger size is run. A selected number of thissize is run, and, if a third size is used, asecond change-over coupling is added sothat the next larger size can be run. Thereare several advantages to this approach:

· It lowers the string weight and, thus,reduces the weight load.

· A smaller gearbox or pumping unit canbe used.

· The horsepower or electrical energyneeded is reduced.

This is a common practice in deeper wells.The tensile strength, stretch, strokes perminute, and other parameters are limitingfactors and must be considered whendesigning tapered strings. When designingtapered strings, the pumper should alwaysconsult with qualified engineers whounderstand sucker rod installations

B-4. Pulling and Running Rod Strings.

Some lease pumpers with small oilcompanies may be in charge of wellservicing when the owner is not present. Atother companies, the lease pumper is notonly in charge but runs the well servicingunit or physically assists as a member of thecrew. With larger companies, the pumpermay only be a spectator who must return thewell to service after the job is completed.

When pulling and running rod strings,always handle rods in a manner that will run

them back into the hole in the same orderthat they were pulled. The use of a rodelevator (Figure 4) is recommended. Sincethe boxes are allowed to break at either sideon some rigs, this saves problems withdouble or no boxes when running them backin the hole.

Figure 4. A rod elevator.(courtesy of Trico Industries)

When making up rods, always use thecorrect make-up procedures. This includesusing proper tools, such as special handwrenches (Figure 5). The rods can bedamaged by over-tightening just as easily asnot being tightened enough. Make-up chartsare available and should be followed.

17B-4

Figure 5. Typical hand rod wrenches.(courtesy of Trico Industries)

When laying rods down on a rack, careshould be taken at all times to preventdamaging or kinking the rods. Extreme caremust be used when picking up the pump;sometimes a center bridle support must beused.

Power rod tongs. Many companies preferthat their rods be made up with power tongs.When correctly used, the rods are made upexactly to manufacturer’s specifications. Thecorrect torque should be used to preventstretching the neck of the pin, which cancause the rod to break under load.

Pulling stuck pumps. Rods are normallypulled through the use of a rod hook (Figure6). Normally, the rods will come outwithout excessive problems. However,sometimes the rods will bind or a pump willget stuck.

Figure 6. A snap-in spring lift rod hook.(courtesy of Trico Industries)

One of the most difficult decisions thelease pumper may have to make occurswhen a pump refuses to be pulled out of theseating nipple. If the rods are new, theyhang in an even row at the bottom in thederrick. The bottom pins line up. Whenpulling tension on the rods, the rods alwaysstretch as the operator pulls a tension. Ifpulled too hard, their ability to return to theoriginal length can be exceeded. The stretch

17B-5

is permanent. When these rods are hung inthe derrick, it is obvious to everyone thatthey have been stretched. If the supervisorhas placed the pumper in charge ofoverseeing the well servicing operation, thepumper has to decide whether the maximumrecommendation on the weight indicator hasbeen reached.

There are several options if a pump isstuck. The operator could be allowed to pullmore tension but at the risk of stretching therods beyond their ability to return to theoriginal length. Alternately, the pumpercould begin a stripping job, which meansstripping out the rods and tubing andextending the pulling time and cost. If thereis a safety joint in the rod string, the pumpermay decide to disconnect the rod string atthis point, and pull the rods and tubingseparately.

For wells that develop pump stickingproblems, many options are available that donot involve stretching the rods or having oilspilled on the location. A supervisor shouldbe contacted for a final solution beforerisking damaging the rod string or beginninga more expensive stripping job.

B-5. Running the Rod String into theHole.

If the pumper oversees running the rodstring into the hole, a careful listing shouldbe made as everything goes in. Even for apump change, there may be differences inpump length. As the rod string is run in, thefollowing should be listed:

· Gas anchor. Many production peoplerecommend that the gas anchor be longenough to contain 1½ times the capacityof the pump. When very little bottomhole space is available, the gas anchormay be as short as six inches and contain

many small holes along the sides andbottom. The pumper must knowcompany policy and must know howlong the tubing mud anchor is to makethe gas anchor length decision.

· Downhole pump. When changing out aworn pump, the pump is taken out of thehole, laid beside the replacement pump,and the bottom of the no-go sections arelined up. If the new pump is eightinches longer than the one beingreplaced, the clamp on the polished rodwill need to be lowered approximatelyeight inches, so that the pump will havethe same spacing. This can bedetermined by comparing the pumps.Occasionally, the differences in pumplengths will necessitate removal oraddition of a pony rod, or exchangingone length for another of a differentlength. The length of the stroke shouldbe compared and noted on thereplacement pump record. A completedescription of the new pump needs to beentered in the record. This informationwill be essential if the pump needs to befished out of the hole.

· Pony rods and the pump record. Thefirst pony rod installed is the lift ponyrod between the downhole pump and therod string. It is listed in this position.New and rebuilt pumps are deliveredwith a description tag. This is alwayssent to the office attached to the rod tallysheet. If no changes are made in rods ortubing and the pumps are identical, nonew tally sheets are necessary and thetag is simply attached to a sheet of papergiving the date and a brief explanation ofwhere it was installed.

· Safety release tool. A safety releasetool is next installed if one is to be used.Release instructions should be noted inthe report.

17B-6

· Rod string. The number of rods runneeds to be counted and entered into therecord. If it is a tapered string, thenumber of each size should be listedseparately. Although a length is given,permanent rod stretch may actuallychange the length of the string by manyfeet.

· Pony rods. Additional pony rods areused just before the polished rod isreattached as needed to space out thewell. Pony rods are available in two-footlengths from two to twelve feet. Otherspecial lengths may be encountered.

· Polished rod and lift pony rod. Thepolished rod is installed last, and the liftpony on the top may be left in positionor removed. If it is removed, a couplingneeds to be left on the polished rod toprotect the threads (Figure 7).

Figure 7. The threads of polished rodsneed to be protected if the lift pony is

removed. Shown from left are 5/8-, ¾-,7/8-, and 1-inch rods.

· Polished rod liner. If a polished rodliner is used, it is placed over thepolished rod. It needs to be at a

minimum of 2-3 feet longer than thestroke length. This allows the rods to belifted a small distance without pullingthe liner out of the stuffing box and alsoallows a wick-type lubricator to beadded. The longer the pumping unitstroke, the more polished rod liner isneeded below the stuffing box to be ableto pick up the string. It also needs to belong enough that the stroke length of thepumping unit can be extended.

After the rod job is finished. Before therod record is sent to the office, a secondcopy is made. On this report, the listingorder is reversed. This final sheet has rodslisted in correct order from the top down,just as they are in the hole, and will beretrieved the next time that the well ispulled. This sheet will be forwarded to theoffice. A copy of this record is entered inthe lease pumper’s lease record book forfuture use.

Returning the well to service involvesmuch more than just turning on a switch.Close attention must be given to the wellwhen the fluid reaches the stuffing box sothat packing tension may be adjusted, thepolished rod liner checked for leaks, allvalves opened to the battery, and allequipment set properly.

B-6. Fishing Parted Rod Strings.

Fishing parted rods is a common problemwhen the rod string has corrosion and pittingproblems. The break usually occurs in therod but can occur anywhere along the string.When fishing, rods are pulled, oneadditional rod and the fishing tool are added,and all are sent back down the well to “catchthe fish.” If the pump unseats and starts out,the brake is adjusted as needed to preventgrabbing or bouncing action of the well

17B-7

servicing unit brake when they are applied.Jarring may cause the overshot to releaseand drop the fished rods, possiblycorkscrewing all of the dropped rods andparting the tubing.

Pulling tubing after dropping a rod stringrequires special considerations to preventstripping parted tubing from over the rodstring and leaving a loose rod string in thecasing. These are especially hard to fish.

When fishing parted rods, the pumper willneed proper fishing tools. One of the typicalfishing tools is illustrated in Figure 8. Thereare several other styles that may be needed.There are several styles of rod boxes, andthese may require special considerations. Ifthe pumper’s company owns its own fishingtools, they should be kept well greased andin a waterproof storage location. AppendixA addresses typical fishing problems.

Figure 8. Typical sucker rod fishing tool.(courtesy of Trico Industries)

B-7. Fiberglass Rods.

Fiberglass rods have become widelyaccepted because their quality hasdramatically improved over the years.Fiberglass rods are usually 37½ feet long, soinstead of pulling rods in triples on atelescoping well servicing unit as with steelrods, the lease pumper pulls them indoubles.

When installing fiberglass rods, a part ofthe string requires steel rods at the bottom tohold the string in a constant tensioncondition. These steel rods are installedimmediately above the pump. This preventsthe fiberglass rods from being operated in acompression mode.Since fiberglass rods weigh one-third theweight of steel, a smaller gearbox can beplaced on the pumping unit.

With the use of fiberglass rods, the travellength of the pump is dramatically increasedand the weight of the rod string is decreased.

When laying fiberglass rods down orpicking them up during a well servicing job,the lease pumper should always tail the rodsby carrying them in or out rather than lettingthem drag or scrape on the rack.

If fiberglass rods are used, the leasepumper should obtain from the manufactureror supplier a booklet of instructions for careand handling of fiberglass sucker rods.

Fiberglass rods are stored and handledmuch like steel rods, although a few specialconsiderations should be taken. Fiberglassrods should be stored inside a warehouse,under a roof, and/or covered to prevent fiberbloom from occurring while they are instorage. While in storage for three monthsor longer, these rods should be shieldedagainst ultraviolet rays by storing theminside or with a protective tarp.

The rods should never be thrown ordragged. When they are lifted, they need be

17B-8

tailed in. Wooden sills are less damagingthan steel. When nicked, rod damage ispermanent and the joint may need to bereplaced. If a rod is cross threaded, a tapand die (Figure 7) should be run, the threadslubricated, and the joint screwed backtogether correctly.

Figure 7. A tap and die for two rod sizes.

B-8. Downhole Pump Problems.

The most common reason for wellservicing is to replace the pump because ofvalve wear or because the barrel and plungerclearance has worn excessively. This willoccur on a fairly regular schedule and, byreferring to the pump replacement record,

the next service job can almost be predicted.By studying the pump failure andunderstanding why each one failed, thepumper can occasionally make smallchanges such as using a better adaptedmetallic content or changing the pumparrangement. This may extend the life of thepump dramatically. Occasionally, doublevalving a pump may extend its life.

The shop doing pump repairs must alsoperform them accurately each time. Manyrepair shops may not be the most appropriateone for a job. They may not know thecorrect repair procedures or may not havethe proper parts for servicing. For example,if a replacement barrel has been used that istoo long it can place additional spacebetween the two valves and promote gaslocking. Sometimes when a pump isrepaired on a “while-you-wait” basis,substitutions may be made for the correctreplacement repair parts. This can causeshorter pump life. These types of repairsshould be avoided.

The pumper should always search for waysto reduce the necessity of pulling rods andtry to lower lifting costs. This sectioncontains only a small sampling of theinformation that is needed about rods andpump repairs.

17C-1

The Lease Pumper’s Handbook

Chapter 17Well Servicing and Workover

Section C

THE TUBING STRING

C-1. Tubing and Casing Perforation.

The relationship of casing perforations totubing perforations is important to theperformance of the well, whether it is aflowing well or produced by artificial lift.The lease operator must know if the tubingperforations are above or below the casingperforations or at the same level (Figure 1).This can be critical as to how much oil thewell produces and the problemsencountered.

Figure 1. Relationship of wellperforations.

(courtesy of Harbison Fisher)

For wells that produce a lot of scale,production personnel operate under differentphilosophies. One school of thought is thatthe higher the tubing perforations can beraised above the casing perforations and stillachieve a satisfactory daily production, theless the scale will break out of the water inthe tubing and flow line. Some companiesraise the tubing perforations a few feetabove the casing perforations, while othercompanies move them much higher.

Some operators maintain that if tubingperforations are placed even with or lowerthan the casing perforations, the reduction inreservoir pressure will increase dailyproduction, resulting in increased income tosolve the additional production problems.

Other companies place the tubingperforations below the casing perforationseven if it results in a tubing arrangementwhere the tubing has no mud anchor. Ashop-made two-foot perforated joint is used.The joint is closed on bottom and has dozensof ½-inch holes drilled into it. A collar isused to screw it directly under the seatingnipple. This reduces the length of the pumpgas anchor to one foot or less. Companiesfavoring this method maintain that it givesthe highest daily average production.

The most typical tubing arrangement is toplace the tubing perforations a few feetabove the casing perforations. Thismaintains a small amount of liquid againstthe formation, instead of having a drained ordry matrix area at the bottom of the hole.

17C-2

The lease pumper should know thecompany preferences, and a supervisor isusually able to provide this information.

C-2. Selection of Tubing Quality.

Tubing is available in many different wallthicknesses and qualities of metal. Typicaltubing ratings include:

· H-40. This is the most economicaltubing and is used on wells that are notvery deep.

· J-55. Most medium depth wells use thistubing. It will be found in wells up toapproximately 7,000 feet deep.

· C-75. This tubing is not quite ascommon but gives dependable servicewhere pipe better than J-55 is required.

· N-80. This pipe gives very good servicein wells to approximately 12,000 feet ormore in depth.

· P-105. This is an example of the heavierduty pipe needed for wells that aredrilled deeper, where high gas pressuresare encountered.

· Additional tubing ratings. Additionalclassifications go from x-heavy line pipeon the lower end to 110, 125, 140, 150,and 155 on the upper end. With wellsexceeding 20,000 feet, special pipe hasbeen developed.

C-3. Tubing Lengths and Threads.

Tubing is an extruded seamless pipe that issold in random lengths from 28-40 feet(Figure 2). It is measured with a hundredthof a foot tape. By joint selection, a string ofpipe can be made up to any specific length.Pup joints are available in two-footincrements up to twelve feet long. A markmay be stamped on the outside a few feetfrom the end to show its quality rating. The

stamping may be a simple H, J, C, N, or P.On used tubing, this stamped number maybe located after cleaning with a wire brush.

Threads may be round or V-shaped, with 8round serving as the standard thread today.Round threads are hot rolled into the metaland are much stronger than the older V-thread style. Changeover couplings areavailable when different threads areencountered.

Figure 2. The end of a joint of tubingshowing the upset end and the tubing

collar.

C-4. Measuring Line Pipe and TubingDiameter.

New oilfield workers sometimes havetrouble understanding the sizes of pipe andshould memorize the following two rules:

· Line pipe is measured by insidediameter because it is associatedwith production volume.

·· Tubing is measured by outsidediameter because this is the insidediameter of lifting tools needed torun tubing into the hole.

17C-3

Pipe used on the surface for flow lines andfor constructing tank batteries is usuallyreferred to simply as line pipe and is alwaysmeasured by inside diameter. For example,2" line pipe has an inside diameter of 2".

On the other hand, 2-3/8" tubing has aninside diameter of 2", and an outsidediameter of 2-3/8". When 2-3/8" tubing isused for flow lines or other high- or low-pressure applications on the surface, manycompanies refer to the pipe as 2" line pipe intheir records. This does not create a problemwhen joints are measured. Common sensewill dictate if it is tubing being used on thesurface because line pipe for oil fields isusually 25 feet long and tubing is longer.

Line pipe and tubing comparison.

·· 2-3/8 inch tubing is 2 inch line pipe.· 2-7/8 inch tubing is 2½ inch line pipe.· 3½ inch tubing is 3 inch line pipe.· 4½ inch tubing is 4 inch line pipe.

Smaller tubing is also available with aninside diameter of ¾", 1", 1¼", and 1½", aswell as streamlined special sizes. Otherspecial sizes are reviewed in Appendix D.

C-5. Pulling and Running Tubing.

During tubing make-up, care must betaken that the correct power is applied. Ifthe joint is made up too loose, it may leak,and, if too tight, it expands the coupling anddamages the threads. When standing thepipe in the derrick, care must be taken toprevent damaging the threads.

Dropping rabbits through tubing. Whenrunning new or replacement tubing into awell, a rabbit is always dropped through thejoint to be sure that it is fully open. Astanding valve containing the no-go section

can be used for this. This will identifyscaled or out-of-round joints, because therabbit will hang up and fail to fall throughthe joint. It is preferable to identify theproblem before the joint is run into the hole.

Tubing is usually broken out and made upwith hydraulic tubing tongs. For some work,mechanical tools such as crummies are usedand are available on well servicing units.

The advantages to hydraulic tongs overhand tools are obvious. The desired torquecan be dialed into the tongs’ power settingsand additional or less power is available ondemand. Correct pressure when runningpipe is an assurance that threads will not bedamaged on make-up.

C-6. Identifying and Recording theTubing String Components.

The mud anchor. The mud anchor is thefirst joint run in the hole. It is usually a fulljoint with a tubing bull plug on bottom.When the tubing is pulled, this joint willusually contain several feet of sediment,formation, or drilling mud and will beemptied. The mud anchor also protects thegas anchor on the rod pump.

Pipe length measurements. By jointselection, a string of pipe or group of jointscan be made up to a specific length. This isespecially important when spacing gas liftvalves or adjusting the total string length.

Perforated nipple. The perforated nipplemay be two, four, six, or more feet long andis a pup joint with many rows ofapproximately ½-inch holes drilled throughall four sides. Special combination mudanchor/perforated joints may be shop-made.The coupling or collar that connects eachjoint of the tubing string together must be ofequal or better quality than the tubing.

17C-4

Seating nipples. A seating nipple is a shortjoint of upset thickness tubing that has atapered opening at either end to allow thepump to seat into it and seal the openingbetween the pump and the tubing.

Seating nipples are only long enough toseat the pump as long as the seat will hold.Cup-type seating nipples are less than a footlong. A longer seating nipple is availablethat is long enough to be reversible. If theseating surface becomes scratched ordamaged, it can be turned upside down and anew seat is available. Mechanical-typeseating nipples may not be reversible.

Packers, holddowns and safety joints.Records must contain specific informationabout special equipment that may have beeninstalled such as packers, holddowns, andsafety joints. This may be brand, model,serial number, method of how to set the tool,and how to release and remove it. Forexample, if a 25-year-old tool is removed,fished, run, or re-dressed, records are neededthat must supply identifying information

The tubing string. Tubing is a randomlength string of pipe with each jointmeasuring from 28-40 feet long. Whenmeasured, the tally sheet must indicate if itis measured overall or with the 1½ inches ofthread left off. This changes themeasurement of the string length by 15 feetper 100 joints. The third and most accuratemethod of measurement is taken when pipeis hanging from the elevators, measuringfrom the top of the collar to top of the nextcollar with the slips removed. This gives theinstallation length.

When loading the string from the storageyard, some companies measure the pipeoverall, including thread, but remove thethread measurement when running it into thehole for perforation correlation reasons.

If the string has problems and is beingremoved after many years, the pumper needsto know exactly what comes next and havean exact description. For this reason, pipe isalways run back into the hole in the sameorder that it was removed.

Pup joints. When all of the full-lengthjoints that can be run are made up, the finaltubing spacers added are pup joints. Pupjoints are available in two foot incrementsfrom 2-12 feet long. One and one-half footas well as three-foot joints may be available.

As many pup joints as necessary will beadded until tubing perforations are at the

correct depth in relation to casingperforations.

Wellhead hangers. The final item added inthe tubing string is either the tubing hangeror the slips, according to the wellhead style.Another final act is to set the packer or latchonto the tubing holddown to prevent tubingbreathing. It may also be necessary to pull atension on the tubing.

C-7. Typical Tubing Problems.

Typical tubing string problems includesplit collars, holes caused by corrosion, andsplit tubing (Figure 3). With such problems,a well may stop producing fluid, even whileshowing good pump action from the bleeder.

Figure 3. A split collar, damaged brasspump part, corrosion damage, and two

worn sucker rod boxes.

17C-5

Leaks or production problems can also beconfirmed by placing a pressure gauge in thebleeder valve, closing the wing valve, andpumping against a closed-in system. Thisprocedure needs to be coordinated with twopeople, with one standing at the electricalswitch or clutch and the other observing thegauge. This procedure can also clear debrisout of a pump valve. For safety reasons, thelease pumper should never stand directly infront of a gauge when it is being pressurized.

Split collars and holes in tubing. Theseproblems usually result in no production atthe bleeder and are relatively easy to locate.A typical solution is to mix a small amountof tracer material such as aluminum paint infive gallons of diesel fuel or kerosene, andpour it down the tubing. As the well ispulled, the leaking joint can be identified byobserving the tracer material or aluminumpaint on the outside. After identifying andreplacing the leaking joint, the pipe is runback into the hole, and the well placed backinto production. Normally only one holewill be found.

Standing valves. A standing valve can bedropped into the tubing to seat in the pumpseating nipple in situations where the hole inthe tubing is difficult to locate. The hole isfilled with fluid, pressure applied at thesurface, and the tubing pulled. When fluidis reached or the tracer fluid is observed, itshould be possible to locate the hole or splitjoint.

After the problem has been solved, thestanding valve can be retrieved with the sandline and an overshot, then the pipe can berun back into the hole and the well placedback into production. A good standingvalve such as the one shown in Figure 3 willallow the pumper to release the fluid weight

before having to unseat it. This reduces thepressure needed to unseat it.

Figure 4. A 3-cup standing valve fromHarbison Fischer.

Split tubing and hydrotesting.Occasionally a split joint of tubing can bevery difficult to locate. Oil may or may notbe produced. The bleeder valve may showgood production, but no liquid travels to thetank battery. A standard pumping flow linepressure check at the bleeder valve canconfirm the possibility of a split joint. Ifmonthly flow line pressures are not takenand recorded, the pumper cannot know whatthe pressure should be. Consequently, thereis no basis of reference to identify a problemin this manner.

When all other methods of locating thetubing leak fails, one option remains. Thetubing can be hydrotested. Whenhydrotesting, the full tubing string may bepulled and two joints tested at a time underhigh pressure as the tubing is run back intothe hole. A special two-person crew and aspecially equipped truck are brought to thelease. Three sucker rods are used to rig upthe 75-foot long tool. As each “double” oftubing is dropped into the hole, it is pressuretested. The tool is pulled up each time, so isjust below the slips while testing. It isconsidered too dangerous to the safety of thefloor crew to test above the slips.

Many other methods may be used whentrying to solve problems of poor production.

17C-6

17D-1

The Lease Pumper’s Handbook

Chapter 17Well Servicing and Workover

Section D

WIRE LINE OPERATIONS

D-1. Five Uses for Wire Lines inServicing Wells.

There are many styles of wire lineavailable for use in the oilfields. The wireused is generally either solid wire or wirerope. There are five major purposes for wirelines around well servicing units.

Surface uses:· Guying the pulling unit· Line from drum to blocks

Downhole uses:· Sand lines· Solid wire lines· Electric lines

D-2. Wire Rope.

Wire rope consists of strands of solid wirebraided in specific patterns around a core tocreate various shapes (Figure 1). Theseparts of a wire rope are shown in Figure 2.

Figure 1. Typical shapes of wire rope.(courtesy of Williamsport Wirerope Works,

Inc.)

Figure 2. Parts of a wire rope.(courtesy of Williamsport Wirerope Works,

Inc.)

17D-2

Wire lines are available in right- and left-hand lay or twist (Figure 3).

Figure 3. Several types of wire rope lay.(courtesy of Williamsport Wirerope Works,

Inc.)

The correct method of measuring lines isshown in Figure 4. This is important whenselecting wire rope accessories such asclamps, blocks, and sheaves.

Figure 4. Methods of measuring lines.(courtesy of Williamsport Wirerope Works,

Inc.)

As illustrated in Figure 5, wire ropes canbe damaged. Guy, sand, an all other linesmust be protected. Extreme care must beused to prevent damage to the lines. Thelines should always be inspected prior touse.

Figure 5. Typical wire rope problems.(courtesy of Williamsport Wirerope Works,

Inc.)

17D-3

D-3. Functions of Guy Lines.

Wire rope used for guy lines is usuallyright-hand regular lay. This line is availablein many sizes, and the pumper shouldpurchase a line that will not break underload. This line is smaller than the lines usedon the drum. When purchasing guy lines,check with the manufacturer to select thecorrect line and core.

D-4. Functions of Line from Drum toBlocks.

The draw works line used to drill an oilwell is different from the lines used on awell servicing unit. The wire rope used forwell servicing is rotation-resistant so that theelevators will remain in the same positionwhile traveling up through the derrick,especially when using a single line. Thelines are designed to be used on the surface.When purchasing a new line, the pumperwill need 500-800 feet or more in order tolower tubing blocks from the crown to thefloor. A reserve amount needs to be storedbehind the drum divider so that 20 or morefeet can be periodically cut off according tothe ton-mile schedule. This will extend thelife of the line.

D-5. Sand Lines.

Sand lines are placed on the second drumof the pulling unit or on the drum closer tothe cab. Many downhole services areperformed by the well servicing crew usingthe sand line, so it must be long enough toreach the bottom of the hole. Some typicalwell servicing crew services are:

· Swabbing fluids. This operationinvolves dropping a swab down the holeand lifting fluid out to a vessel to remove

it from the tubing to a holding tank.When completing a new well, fracing, orperforming other operations, swabbing isnecessary to clean up the well bore andmatrix area. A satisfactory lubricatorwith the proper valves and accessories isneeded.

· Bailing sand. As fluids are produced,sand may migrate from the formationand settle in the bottom of the hole. Asand bailer may be lowered to thebottom of the hole when the tubing ispulled on some wells and the sandbailed.

· Cutting paraffin and scale. The wellservicing crew may cut paraffin andscale with the sand line with specialtools (Figure 6).

Figure 6. One style of paraffin scraper.

· Running impression blocks. Anotherfunction of the sand line is to run animpression block. When a fish or looseobject in the hole is lost, the pumpermust go fishing to try to retrieve it.When fishing, it is often desirable to runan impression tool in and set it down onthe lost item in order to know how tograb hold of the object. A standard orhard impression block is a flat-bottomedtool made of lead. It resembles a flat-bottomed drill bit from a distance.

· Running scrapers. Before running apacker into the hole, the well servicingcrew generally runs a scraper slightlylarger than the packer to remove anyscale or paraffin. This also checks forcollapsed casing.

17D-4

· Pulling standing valves. Whenproblems are encountered whilechecking for or locating tubing leaks, astanding valve can be dropped into thehole and the tubing filled with water. Asthe tubing is pulled, the water level willdrop to the level of the hole. When thatpoint is reached, the leaking joint isreplaced. The sand line can be run in thehole to retrieve the standing valvewithout having to pull the remainingjoints.

D-6. Solid Wire Lines.

The solid wire line is a single strand ofwire. It is run into wells to perform specialtests and functions. Several sizes of wire areavailable, according the depth of the welland job to be performed. These jobs aregenerally tests or valve placement using adownhole tool usually referred to as a bomb.

Temperature surveys are run primarily todetect casing (or tubing) leaks, although theyserve other needs as well. Temperaturesurveys are run each six months to one yearto test for leaks in flowing wells. The leakwill be detected by a temperature drop ordecrease due to the expansion of theescaping gas.

Pressure surveys are run on a yearlyschedule to determine pressure drop andremaining reservoir fluids. By taking thepressure drop and comparing it to theprevious year’s reading, the remaining fluidsin the reservoir and the remaining life of thewell can be projected. This is also animportant factor in regulating theeffectiveness of gas injection and reservoirpressure maintenance. For flowing wells thedate when artificial lift may becomedesirable is projected and funds to install itcan be scheduled.

Directional surveys can also beconducted with a wire line while drilling awell. A clock in the survey bomb is set for apre-determined time and the tool is loweredinto the hole. After the appropriate time haslapsed, the clock will trigger the directionimpression on a small bull’s eye disk, rotatethe disk 180 degrees, make a secondimpression, and retrieve the tool.

Solid wire lines are used to run andretrieve special tools, such as gas lift valvesin wells with side pocket mandrels. Thewire line machine is used to change gas liftvalves, scrape paraffin and scale, andperform several other functions. There areseveral other uses for the small solid linesuch as running, perforating, and retrievingblind plugs.

D-7. Electric Lines.

Electric lines are used for many purposesin oil wells. When a well is being drilled,open hole survey logs are run to evaluateformations that are being drilled todetermine if hydrocarbons encountered haveenough volume to make a commercial well.After the casing has been run, cased holelogs can also be conducted. When thecasing is cemented, this is usually followedwith a cement bond log.

In production operations electric logs arerun for many purposes. All wells areperforated by use of electric lines. They arealso used for measuring depth, conductingtemperature and pressure surveys, measuringpressure drop during fracing operations,running tracer surveys, and many otherpurposes.

17E-1

The Lease Pumper’s Handbook

Chapter 17Well Servicing and Workover

Section E

WELL WORKOVER

E-1. Well Workover Operations.

When a well has a problem more seriousthan changing out a pump, repairing a holein the tubing, fishing a parted rod, or otherbasic well service need, it is referred to aswell workover. This section highlights a fewof the problems and necessary workoverprocedures that may be encountered.

Killing flowing wells and blowoutpreventers. In most cases when a flowingwell is to be worked over, the well must bekilled before service can begin. This isusually done with a transport truck similar tothe truck that hauls oil or water. Wells canbe killed with oil, formation water, or treatedwater. Water is used when it will notdamage the formation. After the kill fluidhas been injected and until the injected fluidexerts more downward pressure than bottomhole pressure, the well will sometimes go onvacuum. Water is injected until the desiredamount has reached bottom. At some point,all fluid movement stops. The well is deadand can be worked on.

With flowing wells, the injected fluidslowly dissipates into the formation, and thewell begins to flow again after a period oftime. This means the volume of kill fluidinjected is proportional to the work beingperformed. The pumper must not only beginthe work, but must always be prepared toclose the well back in if it begins to comeback to life or flow.

Figure 1. Specialized equipment for wellworkover, including a water tank,

hydraulic power for rotating head, mudpump, and mud pit.

If a blowout preventer or BOP is to beinstalled, the crew needs to be prepared for aquick transfer in removing the Christmastree and the BOP installation.

If water is injected as a killing fluid,potassium chloride may need to be mixedwith the water to prevent formationhydration. This is especially true if anyshale is present in the reservoir. Enoughwater is injected to kill the well for theneeded time before it may disperse in theformation and allow the well to beginflowing again. Swabbing will remove theload water to speed up the process.

Blowout preventers. A typical blowoutpreventer used for workover will usuallyconsist of two sections. The upper section

17E-2

contains rams that fit around the pipe if itshould become necessary to close them. Thelower section contains blind rams that can beclosed if necessary whenever the pipe is outof the hole. This will permit control of thewell if it should begin to flow while the pipeis in the hole or if it is out or on the bank.

E-2. Stuck Pipe.

Stuck pipe can be caused from severalproblems, such as salt bridges, scaledeposits, and sand accumulating in thebottom of the hole. The pumper does notusually know that the tubing is stuck untiltension is pulled on the tubing and it cannotbe moved.

Salt bridges. Salt bridges can occur on apumping well whenever it pumps manycycles a day and the water being produced isextremely salty.

While the well is off between pumpingcycles, the salt water rises in the casing, andwhen pumping, water is pumped down to alevel near the tubing perforations. Eachtime this is done, a thin layer of salt mayadhere to tubing and casing walls. Since thisoccurs thousands of times, these thin layersbuild up until salt bridges the area betweenthe tubing and the casing. If this areabridges completely, gas cannot be releasedto the tank battery, and the pressure near thewell bore increases to formation pressure.Oil production will fall dramatically andeventually cease.

To solve this problem, fresh water may bedropped down the casing annulus atscheduled intervals to dissolve the salt,reduce the buildup, and prevent bridging.

Scale deposits. Scale is carried into theannular space dissolved in water. It isdeposited on the walls of the casing and

tubing much in the same way as salt. Aspressure and temperature are lowered on thewater, the suspended scale breaks out. Thisscale can bridge the tubing in the hole aswell as stick the pump and reduce the size ofthe tubing to make it too small to beremoved. The tubing may need to be pulledout of the hole, laid on a rack, and reamed ordrilled out.

With flowing wells a special coating onthe tubing can reduce scale buildup. Withpumping wells it may become necessary tocirculate a scale-reducing chemical down theannulus. This may be done periodicallythrough batch treatment or pumped into theannular space daily.

Sand control. Sand can be periodicallybailed from the well or the well may begravel packed. Screened perforated jointsmay also be installed to filter out the sand.If sand is a problem, a maintenance programwill need to be developed to meet the needsof the lease.

E-3. Drilling with Tubing.

On some leases, it may be necessary todrill out scale in the bottom of the holeperiodically. The tubing in the well can beutilized as drill pipe by the use of a rotatinghead and a power swivel. Some operatorsperform this service to their wells as neededto restore production.

E-4. Stripping Wells.

Stripping a well is a process of pulling therods and tubing simultaneously. This beginsby breaking the rod string out by setting thestring down, engaging the pump clutch ornotches, and turning the rods to the left.After many rounds of turning, the rods willbreak at some point. Rod tongs or a wheel

17E-3

may be used for this purpose. The part ofthe rod string that breaks loose is removed.Tubing is pulled until the rods are reached,and the procedure repeated until all of therods and tubing has been stripped out orremoved.

All downhole pumps have a clutch orengaging notch built into them for thispurpose. With most pumps, there is a clutchon the bottom only, so the rod string must belowered until this off-set notch assemblyengages. The rods to the left can be turnedto break them out. Other pumps have aclutch assembly on both the bottom and top,so the rod string may be lifted to engage itand break the rods loose. The location canbe determined in a few minutes by raising orlowering the rod string and turning it until itengages.

Problems are encountered by losing oilthrough spilling it on the ground, lighter oilsheading (flowing up out of the tubing) andflowing, and even blowing out and coveringthe rig and location with oil, causingenvironmental damage and a majorequipment clean-up. Special equipment andprocedures such as swabbing can be used toprevent this contamination.

Safety joints can be installed in the rod andtubing string to unlatch and pull most of thestring easily. This procedure presentsspecial problems such as the tubing safetydevice turning loose while trying to unlatchthe rod safety device.

When stripping a well, some leasepumpers attempt to turn the rod and casingstring by using a rod wrench with anextension or cheater. This is a dangerouspractice and should not be attempted.

E-5. Fishing Tubing.

When fishing a loose string of tubing in thehole, there may be problems latching onto

the broken part that is in the hole. Todetermine the problem, an impression blockis run. It may be necessary to design andmake a special fishing tool for catching thefish.

Running impression blocks. When animpression block is run, the type of block tobe used must be selected. Rental blocks areusually made of a soft lead, but a softermaterial may be needed to get a deeperimpression. This are made of tar.

Hard impression blocks. When running alead impression, the tool is lowered into thehole by running it onto the tubing string. Theamount of pressure applied and the mannerof obtaining the impression depends on theweight of the tubing string being lowered.The lighter the string, the faster it is loweredto strike the fish to obtain the impression.After examining the impression, a decisionis made as to the best method of fishing.

The soft impression block. A softimpression block is usually a shop-madetool. A hole is drilled in the neck of aswage, then roofing tar is poured into it witha short crown. After lowering it into thehole on three or four joints of tubing, thesand line is attached. It can be run to bottomquickly, and very little pressure is necessaryto receive a deep impression.

Fishing tools. There are many types offishing tools that can be rented for fishing.A spear works well for a jagged opening,and an overshot with a milling surface canbe used to catch a round fish. When the fishis too far to one side, a shop-formed offsetfinger can be made to wrap around the fishby turning the pipe. The local tool rentalcompany also has fishing specialistsavailable to supervise special fishing jobs.

17E-4

E-6. Fracing/Hydraulic Fracturing Wells.

There is an abundance of new technologyavailable for use when stimulating wellsthrough a fracturing process. This requiresapplying enough hydraulic pressure to therock formation to split the rock, thenpumping sand into the fracture, propping thefracture open to allow oil and gas to flow tothe well bore.

Several fluids are used to carry thetreatment to the formation when fracingwells. The easily available fluids are leasewater, fresh treated water, and crude oil.Several petroleum-based fluids are alsoused.

Sand frac is a common procedure usingnatural and manufactured agents. Theformation is fractured and spread open, andseveral sizes of a special sand are pumped inas a propping agent. Rock salt, which iswater soluble, and moth balls, which are oilsoluble, may be added to block receptivepassages during the fracing process toextend the fracture deeper into the formationand improve the final results.

With acid fracing, an acid is pumped intothe hole under high pressure to open therock and etch rock away to permanentlyopen the formation. A time neutralizer isadded to make the acid safe to produce backafter the job has been completed.

Other special fracs may be performed suchas an explosive heat frac. The explosionwill back flush the formation toward thereservoir. The heat is especially effective inshallow, low bottom hole temperature wellswhere tars, paraffins, and other firmpetroleum products plug the formation and

cut off production. A water blanket is addedabove the charge to add weight and force theheat into the formation.

E-7. Pulling and Running Tubing UnderPressure.

By using two sets of blowout preventerswith a space nipple in between, a well canbe worked over without killing the well. Itis also possible to work over a well while itis producing.

Figure 2. A well workover rig with adouble blowout stack so that workovercan be performed while the well is still

under pressure and even while it isproducing oil and gas.

18-i

The Lease Pumper’s Handbook

CHAPTER 18

GAS WELLS

A. INTRODUCTION TO NATURAL GAS WELLS.1. Understanding the Gas Well.2. Wellheads and Christmas Trees.3. Reservoir Characteristics of Gas Wells and Gas Production.4. Producing the Gas Well.5. The Wellhead and Safety Devices.

· The tubing safety valve.·· The surface safety valve.

B. FLUID SEPARATION.1. The High-Pressure Gas Well Separators.2. Three-Stage, High-Pressure Separation and Indirect Heating.3. Vertical Separators That Do Not Require Heat.

C. GAS DEHYDRATION.1. Gas Dehydration.2. Operating the Dehydration Unit.

· The inlet scrubber.· The contact tower.· The glycol pump.· The dual-action pumps.· The heat exchanger surge tank.· The three-phase gas, glycol, and condensate separator.· The reboiler.

3. Tank Batteries for Gas Wells.D. GAS COMPRESSION AND SALES.

1. Natural Gas Compression.2. Natural Gas Measurements.3. Testing Gas Wells.4. Pipelines and Pipeline Problems.

· The removal of liquids from pipelines.5. Treating and Drying Natural Gas.6. Transporting Natural Gas Long Distances.

·· Cross-country gas lines.E. NATURAL GAS SYSTEMS.

1. The High-Pressure Gas Line System.2. Controlling the Pressure in the Separators and the Heater/Treater.3. The Well Testing Gas Measurement System.4. The Gas High Pressure Gathering System.

18-ii

5. The Low Pressure Gas Line System and the Vapor Recovery Unit.· The vapor recovery unit.

6. The Flare and the Gas Sales System.

18A-1

The Lease Pumper’s Handbook

Chapter 18Gas Wells

Section A

INTRODUCTION TO NATURAL GAS WELLS

Many people will casually refer to all thewells in a field as oil wells. When it isnecessary to specify exactly what type ofhydrocarbons are being produced from adesignated well, the designations maybecome oil well or gas well.

A-1. Understanding the Gas Well.

The typical production from a gas well isprimarily natural gas, often accompanied byliquid hydrocarbons and water. Thehydrocarbon liquid is usually referred to ascondensate or distillate.

· Condensate implies that the liquid wasalready in a vapor form, and only onestep is required—condensing—to changethe fluid from a gas to a liquid. Thecondensing may have occurred as thevapor was leaving the formation, as itflowed up the tubing, as it passed throughthe processing equipment, or even as ittraveled through the gas transmissionpipeline. The condensed liquid may be asclear as tap water.

· Distillate implies that a two-step processoccurs where the liquid is transformedfrom a liquid state to a vapor, thencondensed back to a liquid form. This isa common purifying process that resultsin the production of a crude or casinghead gasoline that contains little or no oil.

A-2. Wellheads and Christmas Trees.

A typical medium- to low-volume gas wellhas a double master gate and a safety valvenext to the wing gate. The wellhead valvesare often referred to as gate valves, which isoften referred to merely as a gate. Theupper master gate is always used when itbecomes necessary to shut in the well. Thelower one is in reserve so that if the uppervalve fails, the lower one can be closed tomake it possible to safely close the well in torepair the upper valve. A gas well may ormay not have a packer installed, dependingon how the tubing string is installed.

A-3. Reservoir Characteristics of GasWells and Gas Production.

A gas well is any well that produces a lotof gas and very little oil. The oil is usually avery light crude with a high viscosity or APIgravity rating—that is, the weight of thecrude as compared to the weight of a similarvolume of water. An oil well usuallyproduces a heavier crude with a lowerviscosity and produces a higher percentageof oil versus gas. The gas produced from anoil well may be low or high volume,depending on the placement of the well inthe reservoir and where the well is drilled.

Condensate may leave the formation as aliquid or as a gas. If it leaves the formationas a gas, it may begin condensing to a liquid

18A-2

as it travels up the hole and the pressure andthe temperature decrease. The fluid fallingback down the hole when this occurs canaffect production dramatically. Gaseouscondensate with a lower hydrocarboncontent may remain a gas. Plunger lift iswidely used to assist in moving these liquidsto the surface.

A-4. Producing the Gas Well.

Production in gas wells is measured in cubicfeet. A well may be capable of producingless than a hundred thousand cubic feet ofgas a day or have a potential of over onehundred million cubic feet a day. Each wellis different in volume of production,pressures, condensate, and water production.The support equipment will changeaccording to need.

In most cases, gas from the well isdelivered to a transportation pipelineoperated by a gas purchasing company. Thegas purchasing company will accept gas aslong as a market is available. In the event ofoversupply or in emergency situations, thegas purchasing company representative mayclose the well in as needed. Occasionally agas well may be shut in for an extendedperiod of time. This seldom occurs with anoil well or the gas produced in conjunctionwith producing oil. Thus, producing naturalgas as a by-product along with crude oil is amore stable product sales market.

A-5. The Wellhead and Safety Devices.

A typical medium- to low-volume gas wellas pictured in Figure 1 has a double mastergate and a safety valve next to the wing gate.The upper master gate is always used whenit becomes necessary to shut in the well.The lower one is in reserve so that if theupper valve fails, the lower one can be

closed to make it possible to safely close thewell in to repair the upper valve. A gas wellmay or may not have a packer installed,depending on how the tubing string isinstalled.

Figure 1. A gas well with a dual ordouble master gate valve, safety valve,

wing valve, and variable choke.

A gas well may have two types of safetyshut-in controls. Each serves a differentpurpose, although the results can be similarin that both systems shut the well in.

The tubing safety valve. The safety valveinstalled downhole in the tubing will shut inthe well in the event the line should breakand a large volume of gas is beingdischarged. This safety valve is checked ona regular schedule to ensure that it will closein the event of an emergency. A wirelinecompany sets, services, and retrieves thesevalves. Many companies do not install thedownhole safety valve for medium- and low-volume wells. A hydraulically opened valvecan be installed such that the wellautomatically shuts in whenever thispressure is reduced. This system has beenused extensively offshore, even for flowingwells.

18A-3

The surface safety valve. The surfacesafety valve signal to shut in the well isusually controlled at the high-pressureseparator. A hi-lo valve with hi-lo pilot andbypass will shut the well in on either high orlow pressure of the sales line. A smallstainless steel tube leads from the safetyvalve on the Christmas tree to the controlvalve at the separator.

The picture of the gas wellhead in Figure 1shows the surface safety valve. Both Figure2 and Figure 3 show the same type ofcontrol.

Figure 2. A small gas well with a three-phase separator and compressor in the

background.

Figure 3. A high-volume gas well.

The gas well shown in Figure 4 has no safetyvalves or even dual master gates. It has beencompleted like any typical flowing well.This indicates very low production.

Figure 4. A low-volume gas well.

18A-4

18B-1

The Lease Pumper’s Handbook

Chapter 18Gas Wells

Section B

FLUID SEPARATION

Figure 1. A high-pressure gas well separator that keeps the choke valve from freezing.

B-1. High-Pressure Gas Well Separators.

Several styles of separators aremanufactured for use on gas wells. All ofthese separators operate at high pressure. Alow-pressure oil separator is designed tooperate on 100 pounds or less of gaugepressure. The gas well separator is usuallydesigned to operate at 1,000 pounds pressureor more, with a test pressure ofapproximately 2,000 pounds.

To achieve this pressure, the diameter ofthe vessel is small, usually 24 inches or less,

with a much heavier wall thickness. Forsafety, the sight glasses also use muchheavier construction. The separator canalways be identified instantly, just byobserving the liquid level sight glass.

B-2. Three-Phase, High-PressureSeparation and Indirect Heating.

When the gas well has a very high pressureand the gas contains water moisture, the gasexpands quickly coming out of the choke,becomes very cold, and begins forming ice

18B-2

inside the gas lines. Soon, the ice fills theline for several feet past the choke, the wellfreezes, and production of gas ceases. Aftera period of time, the ice will melt, and thewell will begin to flow again. After a shorttime, the line freezes again. To solve thisproblem, a heated water bath unit wasdesigned. This system is illustrated inFigure 1.

This unit has a heated container. Thefirebox heats the water, and then the waterheats the gas and choke valve. The gasenters the water chamber, makes severalloops back and forth, then goes through thechoke. This hot gas keeps the ice melted atthe choke and allows the well to produce.The produced gas then moves up, travelshorizontally through the three-stageseparator, and on to the dehydration unit forfinal clean-up and drying.

The fluids in the gas—the oil and water—are processed through the high-pressureseparator. The water falls to the bottom isremoved through the water outlet motorvalve. It then flows to the water disposalstorage tank. The oil flows over the waterdisposal unit and travels through the oiloutlet motor valve to the distillate storagetank.

As water is lost by evaporation out of theatmospheric heat chamber, makeup watercan be poured back in through the top of thehydrocarbon separation unit. When it hasbeen determined that too much distillate isbeing sent down the gas line, a small low-pressure flash separator unit can be added tothe unit to separate more distillate. It canincrease distillate production.

B-3. Vertical Separators That Do NotRequire Heat.

The vertical high-pressure separatorpictured in Figure 2 is a three-phase design.

The inlet line from the well enters theseparator on the left side. The gas goes upthrough the center of the top and is directedto the dehydration unit. The two round floatcontrols that are at the right front of thevessel regulate the height of the liquids inthe vessel.

Figure 2. A high-pressure, three-phaseseparator.

The upper indiscriminate float controls thecondensate level in the vessel. Thepneumatic diaphragm control valve on theleft front of the vessel dumps this liquid tothe oil stock tank in the tank battery. Thelower float control has a discriminate floatinside the lower part of the vessel anddumps the water out through the pneumaticdiaphragm control valve at the lower rightside of the picture. These controls can bemore easily identified in the close-upphotograph in Figure 3.

18B-3

Figure 3. A closer view of the pneumaticcondensate and water dump valves and ashop-made gas scrubber from Figure 2.

A high-pressure 1-inch line and regulatordirects gas to the shop-made gas scrubberthat sits on the ground at the right side of thepicture. This scrubber removes any finalliquids ahead of the pneumatic controls.Safety valves and rupture discs are alsomounted on the upper right side.

The basic system for a small gas well thatproduces only trace amounts of liquidincludes a small separator, a water holdingtank, and a gas meter (Figure 4). This alongwith the well completes the total gas wellsystem.

Figure 4. A basic gas well system for lowgas volume and little fluid production.

18B-4

18C-1

The Lease Pumper’s Handbook

Chapter 18Gas Wells

Section C

GAS DEHYDRATION

Figure 1. An glycol dehydration unit.

C-1. Gas Dehydration.

Gas, as it leaves the separator, willprobably be saturated with distillate andwater vapor. Gas in this condition isreferred to as wet or rich gas. The purpose ofthe dehydration unit (Figure 1) is to reducethe level of the water and distillateremaining in the gas. After these vapors

have been removed, it is referred to as dry orlean gas. The field glycol dehydration unithas other popular names such as the stackpack or thermo pack. As the gas leaves thedehydrator, it will still contain somemoisture and distillate, but it will have alower dewpoint, the temperature at whichthe gas will form condensation.

18C-2

C-2. Operating the Dehydration Unit.

The dehydrator is part of the separator unit(Figure 2) and may use either ethyleneglycol or tri-ethylene. In the followingparagraphs, glycol is referred to but the sameprinciples apply to a system using tri-

ethylene.

Figure 2. A separator unit withdehydration unit, a knee tub, and the

water and distillate tank battery.

The inlet scrubber. The two-phase inletscrubber (Figure 3) is the first vessel in thedehydration unit that the wet gas enters. Thewet gas is divided into drier gas and liquid.The gas is diverted into a circular action,passes up through a stainless steel wire meshmist extractor, then flows on toward thecontact tower. The condensate (and water)that is stripped out of the gas is dumped tothe distillate stock tank.

The contact tower. The contact tower(Figure 3) is the vessel that is designed todry the gas. The gas enters the contact towernear the bottom through a chimney tray.The gas works its way up through bubble-type trays filled with ethylene glycol, whichhas a natural attraction to water. The glycolabsorbs the water contained in the gas, andthe gas passes up and out the top of thetower.

Figure 3. Note the inlet scrubber andcontact tower in this view of a

dehydration unit.

As the gas returns to ground level throughthe down-comer line, it passes through theglycol-gas heat exchanger where theoutgoing gas cools the glycol coming intothe contactor. The dry gas leaves thedehydration unit to be compressed andmeasured as it leaves the location.

The glycol pump. Glycol is pumped intothe contact tower by a dual-purpose pump(such as the Kimray glycol energy exchangepump), which moves glycol up through thecooler or heat exchanger and into the top ofthe contact tower. The glycol trickles downthrough the contact trays where it collectswater and condensate and flows to thebottom of the contact tower.

18C-3

The dual-action pumps. The dual-actionglycol pump pulls the wet glycol out of thebottom of the contact tower through a high-pressure strainer, where it is pumped alongwith a little gas through the bottom sectionof the reboiler.

The heat exchanger surge tank. The wetglycol is circulated through the heatexchanger surge tank and into a three-phasegas, glycol, and condensate separator.

The three-phase gas, glycol, andcondensate separator. As the fluid entersthe end of the three-phase separator, thefluid stratifies into three layers. The gascomes to the top and fuels the reboiler andsupplies it with stripper gas.The second layer formed is the condensate,which is controlled by an indiscriminatefloat. The float directs the fluid to the tankbattery into a tank for distillate andcondensate. The water-laden glycol isdirected toward the reboiler for waterremoval.

The reboiler. The purpose of the reboiler isto boil off the water that was removed fromthe contact tower but leave the glycol. Thisis done by raising the temperature to a levelthat will cause the water to evaporate butwhich is below the boiling point of glycol.

Figure 4. A small reboiler.

The reboiler operates at a temperature ofapproximately 350° F. If the reboiler has aback-up temperature control, this secondcontrol is set 20° higher. Water boils at212° F, but, if it is under pressure orcontains any contaminants, it requires moreheat. Glycol boils at a temperature higherthan this temperature setting.

The water vapor rises in the stripping stilland condenser. It trickles down an angledpipe and is collected in a foot tub (Figure 5).This tube has to be insulated to prevent thewater from freezing in cold weather.

Figure 5. A water collection tub.

The water collects in these short, smallvolume tanks, and vacuum trucks come byperiodically to remove the accumulatedwater to prevent overflow.

C-3. Tank Batteries for Gas Wells.

Tank batteries for gas wells, as a rule, areless imposing than tank batteries for oilwells. Most gas wells will produce distillateand water. Distillate has such a high APIgravity that these two fluids flash separatealmost instantly. Since they separate usuallyin a matter of seconds, no treating vesselsare necessary. This means that there is noneed for heater/treaters, gun barrels, freewater knockouts, or flow splitters.

18C-4

There are, however, a host of supportvessels and equipment designed just to takecare of the needs of gas wells. The tankbattery for a gas well (Figure 6) is basicallyjust like any other tank battery with oneexception. Condensate has a very highgravity and acts as a penetrating liquid sothat seep leaks that lose a small amount ofliquid may develop unless the fittings aremade up properly. With time, the installationbecomes stained and looks bad. Because theproduced fluids will be a little different fromeach well, the vessels to be considered innew construction are the two- and three-phase separator, the condensate storage tank,the water disposal tank, and possibly achemical injector.

Figure 6. A gas well tank battery. Notethe two loading lines—one for condensate

and one for water.

The dehydration unit has either one or twosmall separators that produce condensate,according to how much is contained in thegas. The small tank shown in Figure 7 was

set up just to serve the needs of adehydration unit because for fire safety, thetank battery was a long distance away.

Because of the high gravity of the distillatein the tank battery, the tank vent valve is ofconsiderable importance. Evaporation outof this vessel can be so great that in the heatof summer, the evaporation can be severalbarrels a day. A higher back pressure maybe required, and if smaller loads or splitloads are sold, income from the distillatemay be dramatically increased. Carefulaccounting and measurement will indicatethe lease needs in sales of liquids.

Figure 7. A small tank used to storecondensates.

18D-1

The Lease Pumper’s Handbook

Chapter 18Gas Wells

Section D

GAS COMPRESSION AND SALES

D-1. Natural Gas Compression.

In some systems, natural gas has to becompressed to a high pressure to betransported by pipeline across the country. Ifpressure at the location needs to be morethan 500 pounds, compression is required.As this pressure falls due to line resistanceand the line volume increases as other wellsare added to the gathering system, othercompressors are installed.

The gas compressor will have a series ofautomatic controls that shut it in in the eventof problems such as a loss of pressureindicating a line break, a high buildup ofpressure indicating a plugged or frozen line,or a low supply pressure. If an engine isutilized in compressing the gas, a series ofengine safety switches will also be installed.

Figure 1. At this site, the gasmeasurement meter is protected against

weather in a building.

D-2. Natural Gas Measurement.

A gas meter is installed on the location ashort distance after the compressor tomeasure the amount of gas sold (Figure 1).The production company owns the gas as itcomes out of the well and through the three-phase hydrocarbon separation unit.

As the gas leaves the production unit, it isusually owned by the gas company. Thismeans the gas purchasing company alsoowns the dehydration unit and thecompressor. In this event, the gas companywill also own the small vessel that storescondensate that has been separated from thedehydration unit and is responsible foremptying the knee tub as needed.

The gas reservoir must be large enoughand have sufficient pressure to make it acommercially profitable investment. Thefactor that governs who owns what is howmuch gas does the well produce. For lowproducers, the production company may notonly own everything, but the company maybe required to lay the line at their expense toconnect to the natural gas gathering system.The gas from the wells is sold by contract,and the conditions of that contract are agreedupon by both parties.

A gas meter is installed a short distancefrom the compressor to measure the amountof natural gas sold. This may be a simplechart meter or a more complex one with a

18D-2

solar panel and radio communication withthe gas company (Figure 2).

Figure 2. A gas meter powered by a solarpanel. Readings are sent to the gas

company via radio.

D-3. Testing Gas Wells.

There are several methods used in testinggas wells. One of the simplest tests is toshut it in for an exact specified length oftime and record the shut-in pressure. Afterthis has been performed, the well is returnedto service. The purpose is to determinereservoir pressures remaining to projectremaining reservoir volumes as well asprojecting when a gas compressor may berequired.

A second method of testing is to beginfrom a shut-in condition and flow the gaswell where a specific backpressure curve ismaintained to determine correct chokesettings and to determine condensate (ordistillate) and/or water production at variousflow rates. Some tests are performed tomeet regulation requirements and to setallowables.

In preparing to test the well, the pumpermay need to flow the well vigorouslyenough to clean up the well bore prior toshutting it in. Wells that stabilize bottomhole pressure slowly may need to be shut in

up to four days prior to the test. Theequipment used to measure the volume isbasically the same as with oil productionwells but in some situations will handle alarger volume of gas.

Abbreviations commonly used inmeasuring gas flow are:

BCPMM Barrels of condensate permillion cubic feet of gas

BHP Bottom hole pressureCF Cubic feetCFM Cubic feet per minuteMCF 1,000 cubic feetMMCF 1,000,000 cubic feetMMCFD Million cubic feet per dayMSCF 1,000 standard cubic feet

D-4. Pipelines and Pipeline Problems.

As the gas goes down the pipeline, theamount of water and condensate remainingin the gas is of great concern to the pipelinecompany. As the fluid condenses back intoa liquid state, it has to be pushed along withthe gas or it will accumulate in low spotsand result in back pressure while the gas istrying to push it over the next rise. Thewater will also freeze in winter time, andbetween the water, distillates, and othercontaminants, a jelly-like substance calledhydrates forms in the line and results in linerestrictions.

When a mist of water accompanies thedistillate and condenses back to a liquid, itcontains little or no salt so it freezes easily,at around 32° Fahrenheit or 0° centigrade.This causes the lines to freeze on the insideand chokes off production. Appropriateproduction techniques must be adapted toovercome this problem. The well will beginto freeze and flow in cycles, and in thewinter it may just stay frozen.

18D-3

In Figure 3, the chemical tank near the gascompressor injects methanol, an antifreeze,into the line. This antifreeze, trickling intothe line, assists in keeping the water fromfreezing and blocking the line.

Figure 3. A gas compressor with amethanol injection tank.

The removal of liquids from pipelines.The problem of liquid, popularly called drip,being pushed down the line still exists. Thisliquid must be removed. Liquid collectiontanks (Figure 4) are installed in low areaswhere this drip accumulates. In the past,these containers were often referred to asdrip pots. This condensate is very volatile,unpredictable, and good safety practicesmust be used to handle it. With oxygen anda spark, it is very explosive and requirestraining to be able to handle it safely.

Figure 4. Gas lines in a collection systemwith drain lines to condensate tanks or

drip pots.

D-5. Treating and Drying Natural Gas.

Before natural gas can be transported longdistances across the country for consumptionin other areas, all liquids must be removed.In addition to the petroleum condensates,which can be compared to gasoline, thebutane and propane must also be removed.Special natural gas processing plants (Figure5) are constructed in many locations in alarge gas field to be able to process the gas.

Figure 5. A plant for drying gas andprocessing natural gas.

D-6. Transporting Natural Gas LongDistances.

Before natural gas can be transported, itmust be dried and all liquids removed.Natural gas is a very clean burning fuel andcan be marketed in many ways. It suppliessteam power for operating electricalgenerating plants, manufacturing plants, andthe petro-chemical industry. It can becompressed and marketed for short-distancetravel as CNG, compressed natural gas.Marketing natural gas in this form isbecoming more popular across the country.Some city bus companies and servicecompanies are converting to this system. Itcan be reduced even further into LNG, or

18D-4

liquefied natural gas. New Zealand hasbeen using LNG for long distance travelautomobiles for some time. It is gaining inpopularity. China used ANG, atmosphericpressure natural gas, for city buses manyyears ago. The large gas bladders attachedto the top were as large as the buses.

Cross-country gas lines. Cross-country gaslines are large and transport gas all across

the country. Compressor stations along theline boost pressure for continuous flow.When problems occur in the line, the line islarge enough to act as a surge chamber, orreserve supply, so that minor interruptionsdo not affect the end-user. The pipelinecompanies do a good job in supplying gaswith little or no interruptions.

18E-1

The Lease Pumper’s Handbook

Chapter 18Producing Natural Gas Wells

Section E

NATURAL GAS SYSTEMS

Figure 1. The high and low pressure gas system is indicated by the letter G.

E-1. The High-Pressure Gas Line System.

The natural gas system at the tank battery(Figure 1) begins in the first vessel that theproduced fluid enters and where the naturalgas is separated. The high-pressure gassystem is really not high pressure, especiallywhen considering the truly high pressure ofbottom hole and wellhead pressures. Highpressure is just the separator pressure, whichmay vary from as low as 20 pounds to as

much as 50 pounds. When producingstripper wells, the well pressure has usuallybeen depleted. It is usually producing withthe assistance of a mechanical pumping unitand makes a low volume of gas. The casingvalve may even be open to the atmosphere.As the downhole pump pumps fluid,however, enough gas will usually break outof the oil so that a separator pressure can bemaintained as needed.

18E-2

E-2. Controlling the Pressure in theSeparators and the Heater/Treater.

Controlling the pressure in pressurizedvessels is usually done by using adiaphragm-controlled automaticbackpressure valve (Figure 2). These valveshave a spring, bolt, and nut arrangement ontop for easy adjustment. Since fluid canonly flow from a higher to a lower pressuredvessel, the separator must carry a higherpressure than the heater/treater. In turn theatmospheric vessels have the lowest pressurein the system, which is just a few ounces.Fluid will flow from one atmospheric vesselto another by line height or pump.

Figure 2. An automatic backpressure gasvalve.

(courtesy of Kimray, Inc.)

E-3. The Well Testing Gas MeasurementSystem.

All wells are normally tested one time permonth. The well will be tested through a

separator, heater/treater, or by producingdirectly to a stock tank, according toemulsion content. Figure 3 shows a gastesting system that requires a gas chart, a gasmeter, and an orifice plate holder installed inthe gas line.

Figure 3. A gas test system that includesa gas meter with chart recorder.

E-4. The Gas High Pressure GatheringSystem.

As indicated in Figure 1, the heater/treaterwill have a backpressure valve located nearthe vessel. Each of the two separators willalso have its own backpressure valveinstalled in the lines just before they jointogether. The backpressure valves areidentified on the chart by a round black doton the gas line drawing.

Each of the three vessels will have a gaspressure that is appropriate for that vessel.The heater/treater will have a lower pressurethan the separator to permit the fluid to flowfrom the separator to the heater/treater.

E-5. The Low Pressure Gas Line Systemand the Vapor Recovery Unit.

Each of the atmospheric vessels will havea gas line coming out of the center of the topof each vessel. Even though the gas in the

18E-3

system flows through the line to a vaporrecovery unit, a safety release must beprovided. One design has two A-framesupport stands, and the end of the pipe turnsup for about 1 foot. On the end of thisconnection, a one-ounce backpressure valve(Figure 4) is attached. This permits the gasto escape in the event the pressure inside thevessel exceeds the safety vent setting. Theounce pressure rating is usually indicated inraised letters on the side of the fitting.

Figure 4. Horizontal and vertical one-once backpressure valves for atmospheric

vessels.(courtesy of Sivalls, Inc.)

The vapor recovery unit. The vaporrecovery unit is placed in a locationbetween the atmospheric vessels and thehigh pressure gas system. The tank batterycan be tested for gas loss due to gas enteringthe atmosphere to evaluate the value of thevapor recovery unit.

The higher the API gravity of the crude oiland the higher the temperature of the crudeoil, the higher the vapor loss. Even with lowgravity oil, a heater/treater used to treat theoil increases the vapor loss. When the tankbattery is located in a community,regulations may require the installation of avapor recovery unit.

The vapor recovery system (Figure 5) is askid-mounted unit that contains severalcomponents. When the gas enters the unit, itpasses through a final liquid recovery unit toremove any distillate that may becondensing out of the gas. This vessel isimportant, because the gas is going to becompressed to a pressure greater than theseparator pressure so that it can be re-injected into the high pressure gas system.

Figure 5. A vapor recovery unit.

The compressor is a gas compressor andcannot handle any significant amount ofliquid. If the vessel should fill up withliquid and this liquid spill over into thecompressor, the unit could be damaged. Anautomatic control will send the accumulatedliquid back to the stock tank, or it will haveto be performed mechanically by the leasepumper. Either way, the pumper willperiodically check the liquid level in thevessel.

Gas can be very dry, and most gascompressors require lubrication to preventmetal galling and the resulting mechanicalproblems.

E-6. The Flare and the Gas Sales System.

All of the gas systems come together intoone system before leaving the tank battery.

18E-4

This includes the separators, heater/treaters,and the vapor recovery line from the lowpressure atmospheric vessel collectionsystem.

The gas company will install abackpressure control valve, a gasmeasurement meter, and a check valve intheir system just outside the fence of thetank battery. As an illustration, consider atank battery gas system having separatorpressures of 30 and 35 pounds. Theheater/treater has a pressure of 25 pounds.This means the system is operating withpressures of 25, 30, and 35 pounds. Theflare vent pressure may have to be set at 50pounds.

The gas company may set their gas linepressure at 15 pounds. This pressure islower than the lowest vessel operatingpressure, so everything will operate asnormal. The gas company will have an areacompressor that steps the gas pressure up tomore than 500 pounds so it will move downtheir line at a rapid rate, providing room forthe gas and that of other operators.

If the gas company has a slowdownaccepting gas, and the line pressure builds

up to 45 pounds, the system will stillcontinue to function, but the backpressure onthe pumping wells will slow downproduction dramatically. The tank batterywill appear to be operating normally, but thesystem will be encountering productionproblems. If the pressure in the gascompany line builds up to 55 pounds, all ofthe gas production is being vented to theflare (Figure 6), and this may requireshutting in the wells temporarily.

Figure 6. A gas vent and protective pit.

19-i

The Lease Pumper’s Handbook

CHAPTER 19. RECORD-KEEPINGA. LEASE RECORDS.

1. Advantages of Maintaining a Lease Records Book.2. Setting up the Lease Records Book.3. Setting up Standard Records.4. The Daily Gauge or Grease Book.

B. WELL RECORDS.1. Introduction to Well Records.2. Lease Drilling Records.3. Pumping Unit Information.4. Wellhead Records.5. Casing Records.6. Tubing and Packer Information.

· Packers and Holddowns.· Pulling Tension on the Tubing String.

7. Sucker Rods, Pump Design, and Service Records.8. Current Rod Servicing Records.

· Past Rod Pulling Record.9. Electrical Information.

· Control boxes and fuse information.· Electrical motor information.

10. Electrical motor information.C. PETROLEUM PRODUCTION RECORDS.

1. Production Record-keeping.2. Typical Lease Operation Records.3. Production Reports.

· Types of written oil production reports.· Gas production records.

4. Important Production Records.· Well Information.· Single-Well Tank Batteries.

5. Monthly Tank Battery Total Production Record.· Problem analysis from monthly test data.

6. Records for Daily Use.· Yesterday’s tank gauges.· The daily, seven-day, eight-day, or monthly production report.· Monthly tank battery production of oil, water, and gas, and daily averages.· Monthly individual well tests.· Chemical consumption records.

7. Benefits of Production Records.8. Supply Purchases.

19-ii

9. Time Sheets for Work Performed.· Company employees.· Contract labor.

D. MATERIALS RECORDS.1. Materials Control.

· Theft by Employees.2. Controlled Lease Equipment Storage.

· Location of a storage area.· Security fencing.· Weed and mud control.

3. Pipe Storage.· Pipe and rod storage areas and magnetic orientation.· Classifying used pipe.· Pipe rack design and numbering systems.· Pipe range.· Pipe collaring and condition.· Pipe separation and layering.

4. Storage of Other Materials.· Arrangement, pads, docks, and weather protection.· Junk and scrap designations.· Chemical and drum storage, content marking, and accounting.· Winterizing and deterioration control.

5. Joint Venture Inventory and Accounting.6. Transfer Forms and Procedures.

· Materials transferred out of storage.· Materials transferred into storage.· Materials being transferred from one lease to another.

7. Identification of All Chemicals Used or Stored on the Lease.·· Identifying Chemicals and Marking Barrels.

8. End of the Month Chemical Inventory.· Measuring barrel content.

19A-1

The Lease Pumper’s Handbook

Chapter 19Record-keeping

Section A

LEASE RECORDS

A-1. Advantages of Maintaining a LeaseRecords Book.

The lease records book is a small book thatshould be kept in the glove compartment orother convenient spot inside the cab of thelease pumper’s vehicle. It is an essentialtool used by outstanding pumpers that saveshours of work every month and reducescostly mistakes. If a lease records book isnot maintained, the pumper will encounternumerous problems. Good pumpers becomebetter when this book is set up and used.

The purpose of this section is to provideideas and directions on what type of recordscan be important and how to set up ameaningful information and performancehandbook. Special equipment on each leasewill require that the pumper decide whatinformation is important to know. Time anda reduction in errors are the big factors thatwill make the pumper aware of what recordsare or are not useful.

The information contained in the bookmay be rather basic for some leases andrather extensive for others. A sample of thequestions the book can answer includes:

· What electrical fuses are used on thelease? What are their sizes, currentratings, and location?

· Is the pumping unit gear- or chain-drive?· Which direction does the motor turn?· What size plate is needed in the orifice

meter to test each well?

· How many of each type and length of beltare needed?

· Can substitute belts be used? Willanother size fit and, if yes, what length?

· How many sheave grooves are availablefor belts?

· What size, quality, and quantity of rodpacking is needed?

· Was more oil per day produced thismonth or last? Three months ago? Sixmonths ago?

· What type and weight oil is needed foreach gearbox or other piece ofequipment?

· What spark plugs are needed for differentmodels of engines used on the lease?How many, what brand, and what modelnumber are in the engines?

Extensive reasons can be given concerningthe need for a lease records book andproblems projected to justify having it. Thebest way to judge the convenience of havingsuch a book is for the pumper to begin one.After using one and enjoying the benefits,the pumper will never choose to be withoutone again. It will very rapidly become abible of lease operations information.

A-2. Setting up the Lease Records Book.

The lease records book is custom designedby the pumper and contains most of theimportant facts about the lease. Forexample, the pumper has the option of

19A-2

dividing the book into lease or individualwell sections. Thus, no two lease recordsbooks are exactly alike, but the following aresome general guidelines to use when settingup the book.

· It must be a binder with three or morerings in which pages can be removed,rearranged, added, or exchanged, asneeded.

· Section or sheets with lease number tabsare convenient to divide it into specificareas and leases.

· Blank and lined page sheets are needed.The pumper should have a source forfuture paper insert needs. Full size 8½” x11” paper is recommended.

· By using blank sheets, the pumper candesign custom information pages, even ifwritten by hand. Most duplicatingmachines will accept and print on thepaper with holes that fit the notebook.

A-3. Setting up Standard Records.

The standard records that are kept are upto the lease pumper. The followingarrangement is used by many pumpers:

· Communications Information.· Pumping Well Records.· Electric Motor, Control Box, and Engine

Records.· Materials Records.

As records needs are analyzed, the pumpercan select what types of information may bemost appropriate. If the company has a full-time mechanic, electrician, and maintenancecrew, records needs may be less than for thelease pumper who does not have thisextensive of support. As few records aspossible should be set up, but, when indoubt, this book should be used to record

odd information that may become veryimportant to know at some future date.

A-4. The Daily Gauge or Grease Book.

The grease book is just as important as thelease records book and should be postedcarefully every day, retained and stored forseveral years.

Questions will arise—next month or nextyear—and although a day’s activities willfade in the pumper’s mind, it willoccasionally become important to obtainproduction figures or other information for aspecific day.

Notes or records should be maintained asdaily rounds are made. If books are filledout at a later time, the pumper may notaccurately recall all of the information.Notes should be made about the equipmentchecked, oil and water gauged, meters read,wells tested, gas sold, and repairs made.

The book may be divided into sections,one for each lease. Some pumpers notch thetop corner of the pages alternately by batteryto make it easy to reference or make otheradjustments so the book is easy to use. Thestock tanks are listed in ascending numbersfrom left to right, and the last two letters canbe used to identify them. This is usuallyenough information for identification. Aline can be drawn across the page beforework is begun each day and the date writtenin.

After gauges are posted each day, the nextlines can be used for water volume ifappropriate, engines started, any work doneat the battery, etc. with brief notes statingwhat was performed. A daily record maycontain the following information:

·· Tank numbers and sizes.· Posting today’s gauges.· Today’s activities.

19A-3

· Oil sold, treated, circulated, andchemical added.

· BS&W levels.· Engine fluids added and any repairs.· Well testing.· Well status.· Wells pulled or shut in.· Meter readings.· Servicing records and lease activities.· Any other important activity.

Some pumpers prefer to record the dateand gauges on the left side, and the activities

that may need to be recalled on the rightside.

At the end of the month or otherconvenient time, some records in the greasebook will need to be transferred to the leaserecords book.

When any section in the grease book hasbeen filled, it gets confusing to mix theinformation, so it is usually best to start anew book. The dates that this book wasused should be included on the front ifpossible and the book stored for possiblefuture reference.

19A-4

19B-1

The Lease Pumper’s Handbook

Chapter 19Record-keeping

Section B

WELL RECORDS

B-1. Introduction to Well Records.

It is not the lease pumper’s responsibilityto record and maintain the company’spermanent records. To be more successful,however, the pumper needs to understandlease records and recognize what ishappening on the lease by examining theserecords and noting changes that may beoccurring daily. By examining theproduction records being submitted, thecompany supervisor can assess part of theproduction changes that are occurring.However, the pumper can see these changesdaily and should be able to bring them to thesupervisor’s attention.

To be able to make an educated analysis ofwhat is occurring at the wells, the pumpercan maintain the lease records bookdescribed in the previous section to assist inrecognizing lease changes as they occur.Most field supervisors will support thepumper in this effort by providinginformation from permanent drilling andwell records.

B-2. Lease Drilling Records.

The well drilling record is maintained forthe life of the well. It not only records thecompletion and initial tests of the completedwell, but it also contains information aboutthe reservoir and future changes to the well

that may extend its producing life.The pumper does not need to see the

complete drilling record, but a few itemsfrom it will provide an understanding ofdownhole pipe arrangements. Usefulinformation about each well includes:

· The year it was drilled.· Initial production of water, oil, and gas.· Depth and size of casing.· Depth from wellhead to perforations.· Number of perforations and spread.· How much open hole is in the well.· The distance from the kelly bushing to

the wellhead.

The casing size and perforation record isreferenced every time a change is made inthe tubing string to place temporary tubingperforations in the desired position inreference to the permanent casingperforations. The pumper also needs toknow how many perforations were made andthe distance from the top to the lowestperforation. Occasionally, more than onezone has been perforated. Other importantinformation is included such as any openhole.

When re-completing the well, raising orlowering the casing perforations, orperforming many other work-overprocedures, this record is vital to the job.

19B-2

B-3. Pumping Unit Information.

Pumping unit information may include:

· Manufacturer tag information.· Direction of rotation.· Service records and requirements.· Belts, sheaves, shafts, keyways, and

adjustments available.· Stroke lengths, gear ratios, strokes per

minute, etc.

B-4. Wellhead Records.

Wellhead records include only thatinformation that the pumper needs to knowabout the wellhead. This includes only thoseitems that can be seen on the wellhead.When the pumper has a wellhead problem,there is an immediate need to know suchinformation. As an illustration, assume thatthe pumper has just pulled a well and doesnot have the correct pony rods to finalize thespacing of the rods. Every pumping well inthe field usually has a lift pony rod on it, sowhat size are they and where are theylocated? If a well servicing crew is waitingto continue spacing the rods and chargingfor being on the lease, knowing where tofind an appropriate pony rod may save thecompany a great deal of money. Data thatthe pumper may need to know include:

· Length of polished rods.· Dimensions of the rod liner.· Gasket sizes.· Stuffing box information.· Packing information.· Polished rod clamp bolts—number,

diameter, length, etc.· Types of valves installed on the wellhead.· Information about other components on

the wellhead.

B-5. Casing Records.

Most companies require that rods andtubing be installed in a very specific manner.Tubing perforations must be a specificdistance above, even with, or below casingperforations. The gas anchor must be aspecific length. The pumper needs to learnhow the company prefers these to be setbefore making decisions when supervising awell servicing crew pulling a well on one ofthe leases.

B-6. Tubing and Packer Information.

Every time a problem is encountered whilepulling tubing or unseating or reseating apacker, this record needs to be available. Itlists the quality of the tubing, a measurementof every joint in the string, the manufacturer,size and type of packer or holddown,instructions on how to unlatch or release it,how to place it back into service, and thedistance from the wellhead to the tubingperforations.

The two records that the lease pumpershould maintain about the tubing string are:

· A tubing tally and description sheet.· A record of when the tubing string was

pulled with a description of the problemand solution.

Tubing records must be exact. As thepumper runs pipe in the hole, the item goingin first is listed first, then the second, and soforth. After the string has been run in thehole and the job has been completed, it islisted again by turning it around, because thelast item that went in is on top and the finallist is from the top down.

The thread of a joint of tubing isapproximately 1½ inches long. The pumpermay measure a joint over-all as it is run in

19B-3

the hole, measured without the thread formore accuracy, or actually lifted off the slipsand measured from the top of one collar tothe top of the next collar for total accuracy.Normally, just measuring it without threadsis acceptable for most installations. If thepumper has 200 joints in the hole, and aremeasuring overall, perforations will beapproximately thirty feet above what thetally shows less pipe stretch.

A sample rod or tubing tally sheet ispresented in Appendix A-19-01.

Packers and Holddowns. A packer orholddown may stay in a well for many yearsbefore it needs to be pulled. The well recordneeds to list the packer manufacturer, thetype of packer, and setting and releaseinstructions. When the pumper runs a newpacker or makes a change in a well, thisinformation must also be submitted to thecompany office so that this record can beupdated and corrected.

Pulling Tension on the Tubing String.Deeper wells have a bottom holddown onthe tubing string to stop any breathing of thetubing and the resulting wear on the pipe. Awell over 10,000 feet deep may have morethan 25,000 pounds of tension plus theweight of the tubing. This may exceed100,000 pounds on the weight indicator asthe tubing hanger seats. The pumper needsto know this before pulling the well.

B-7. Sucker Rods, Pump Design, andService Records.

The records that the lease pumper maymaintain on each pumping well are:

· A rod tally and description sheet.· Complete description of the bottom hole

pump.

· A record of each time the rod string waspulled for the past few years and adescription of the problems and solutions.

These records are important when aproblem occurs with the rod string ordownhole pump. When a well is pulled, thelength of the removed pump is compared tothe length of the replacement pump. Thelength of the stroke can also be compared aswell as the style of the pump. When thepump is laid down, pumps are placed side byside and visually verified. The replacementpump is bucket tested to verify its ability topump before it is run into the hole.

When the pulling record is sent in from thefield to the office, the pump description tag,which is attached to the replacement pump,should be attached to the materials transferand repair sheets. It can be important for thelease pumper to be able to refer to the leaserecords book to determine how long thepump was in the hole and compare it to thelast several pull dates. This gives instantinsight into the success of pump repairs aswell as possibly indicating why pumps arefailing. Sometimes a minor change orupgrade in the pump design can double thelength of time that it will last in the wellwithout replacement, dramatically reducingdowntime and pulling costs.

The lease pumper can make suggestions tothe supervisor concerning questions orconclusions that can be observed with goodlease performance information.

B-8. Current Rod Servicing Records.

The procedure for listing a rod string issimilar to the procedure for listing tubingexcept for the full sucker rods. Since all ofthese are 25, 30, or 37½ feet, the pumperonly needs to list the number in the hole. Ifrods have stretched, there can be many feet

19B-4

of stretch in each rod, so the length of therod string will not correlate exactly with thelength of the tubing string. While the rodsare hanging in the derrick, however, thepumper can see at a glance the amount ofstretch that has been pulled into the rods.

A rod listing may look as follows:

1. 16.23 Polished rod, 1"2. 4.00 Pony rod. 3/4"3. 8.00 Pony rod 3/4"4. 4,200.00 168 25-foot sucker rods 3/4"5. 16.34 Pump, 1-1/4, travel rod,

bottom holddown.6. 10.33 Gas anchor, 1"

4,254.90 Total length

Past Rod Pulling Record. It is importantthat the lease pumper know the dates that thewell has been pulled in the past. A pumpwill last similar lengths of time. If the pumpnormally lasts for two years, and it has failedafter four months, the pumper should firstsuspect a problem other than the pump. Thepulling record is very informative whenproduction begins to decline. The problemmay involve more than one well.

The listing sheet is simple to set up. Thelease pumper need only take a lined sheet ofpaper and draw vertical lines and addheadings. This sheet can be individual foreach well or a lease record, listing all wellson one sheet. The information headingsshould be similar to the following:

Well Pulling Record.

Lease Well# Date Rods Tubing Pump Pump PumpPulled Pulled Changed Size Length Remarks

Jones 3 2-17-01 X No Yes 1-1/8 12'4" Barrel was worn out.Jones 6 4-22-01 X X No 1-1/4 13'4" Hole in tubing

B-9. Electrical Information.

Information regarding prime moverequipment should include electrical controlboxes, fuses, motors, and enginemaintenance information. All sections ofthe lease records book are important, but theelectrical section is especially important ifthe pumper does not have much basicknowledge of electrical systems.

Control boxes and fuse information. Thelease may use several types of electricalcontrol boxes, but two are most common—

the simple arm action fuse box and theautomated style containing the time clock,manual and automated controls, andappropriate safety and protectiveconsiderations.

Most lease pumpers do not work onautomated control panels. However, they doaffect the lease pumper in that the pumpermay have to call out an electrician. If thepumper can supply the electrician with themanufacturer and number of the partscontained in the panel, the electrician canbring correct repair parts. This can save atleast a day in repair time.

19B-5

The following may need to be identified:

· Style.· Fuse size, current handling capacity

rating, and description.· Transformer.· Time clock or percentage timer.· Manual motor reset starter.· Overload relays.· Temperature safety breakers.· Lightning arrester.

Electrical motor information. Whenlisting the information contained on the plateof the electric motor, the pumper needs tolist everything available and take somemeasurements.

B-10. Other Well Record Information.Engine information should include engine

identification, servicing, repair, andaccessory information. This can be includedon one general sheet. The pumper mayprefer to make a list showing a schedule forservicing.

Special workover records should describethe workover and report fishing or otherproblems. This includes problems such asdrilling out scale, stuck pipe, or fracing awell. Some companies simply add some ofthis information as an update to appropriateparts of the well records.

19B-6

19C-1

The Lease Pumper’s Handbook

Chapter 19Record-keeping

Section C

PETROLEUM PRODUCTION RECORDS

C-1. Production Record-keeping.

The lease pumper’s primary job is toproduce and sell the most possible oil andgas economically. In addition, the pumperhas other responsibilities, such as notabusing the wells by producing them in amanner that will damage their integrity, pullin water, or conate the gas.

Each production company varies in theirfrequency and method of reporting, formsused, and lease responsibility. Usually, thesmaller the company, the more responsibilitythe pumper carries. As productioninformation is recorded and submitted, theserecords continually indicate field andproduction conditions. The pumper needs tobecome an expert in reading andunderstanding what these records mean andtake appropriate action to meet thesechanging conditions.

In this age of personal computers andinstant communication capabilities, methodsof recording and entering lease records arerapidly changing. With some companiestank gauges are phoned in to the office asthey are taken, and all accounting iscomputed in the office and posted instantly.

The lease pumper, however, is the personon the firing line. As a dedicated employee,the pumper must be instantly aware ofwhether the production is over, short, or justright as a tank is gauged. Since the pumperis at the operation, if action is needed it canbegin immediately.

For this reason this section begins witholder field procedures and typical pumperresponsibilities. If production is all frommarginally producing wells, chances are thatmany of the older procedures are still in useand have some appropriate content. Parts ofthese procedures are still relevant. In anyevent, the pumper should follow whateverpart is applicable.

C-2. Typical Lease Operation Records.

Records regarding activities on the leasethat the lease pumper makes may include:

· Daily and monthly oil production recordsfor every lease tank battery.

· One daily production test record eachmonth for every well on every leaselisting all oil, gas, and water produced.

· A report of all oil and gas sold on thelease.

· A record of any oil hauled for specialpurposes, such as well chemical batchtreatment, hot oiling, etc.

· A record of all produced water injected ortransported off the lease.

· A record of the number of every sealremoved and added.

· Records of every well problem and wellspulled.

· With some operators pipe tallies of anydownhole changes and a transfer recordof all material, pipe, or rod changes if thepumper oversees the well servicing.

19C-2

· A materials transfer ticket for every pieceof equipment or pipe that is moved andits new location on the lease.

· A monthly chemical record of openingand closing inventory for the month, aswell as accounting for consumption andneeds for the near future.

· A number reading for all meters on theleases.

· Any appropriate environmental records ofspills or other problems.

· Time sheets for the pumper and anyspecial labor that is under the pumper’ssupervision.

· Reports for any special projects.· Vehicle mileage, repair, service, or fuel

tickets.

C-3. Production Reports.

To report daily production, the leasepumper may use any of a variety of methods,including:

· By written reports for daily, seven-day,eight-day, or monthly production.

· By computerized systems.· By telephone or radio.

Types of written oil production reports.The company may require the pumper towrite a daily record of all oil produced ateach tank battery. Once the seven-dayreport was the most common. Productionreports were pulled every Monday morningand on the first day of the month. Theyrepresented a midnight gauge (taken at daygauging time), although the true gauge timewas recorded.

With the seven-day report, as many as sixsets of records can be reported each month.To reduce paperwork, the eight-day reportbecame more common, and records were

submitted four times a month, on the 1st, 9th,17th, and 25th of every month. An exampleof an eight-day report is included at the endof this section. This is still a commonmethod because with the radio andtelephones, the pumper usually talks to theoffice immediately when urgent problemsarise.

Gas production records. Gas productionrecords, other than special tests, are recordedfrom the lease either on a chart or bycomputers. They require very little effort bythe pumper. The pumper will, however,usually make a chart record when testing awell.

This record only requires 12 lines in therecord book per tank battery to record a yearof production. The pumper can use thesefigures to determine at a glance how well thelease performed compared to the priormonth or year.

C-4. Important Production Records.

The lease pumper wants to know howcurrent production compares to past periodsof performance. Is the well making thesame amount of production, falling off, orabout the same? The pumper will need toknow this each month for each tank batteryand for every well. The pumper should tellthe company when everything is going well,remaining constant, or declining. With afew simple records the pumper can makegood judgments as to where problems maybe beginning.

There are two places to keep up with thewelfare of the lease—at the well and at thetank battery. Even if there is only one wellgoing into the tank battery, the tank batteryproduction figures are just as important asthe well production figures.

19C-3

Well Information. A well test recordshould be set up that indicates the dailyproduction test for each well. A separatesheet should be used for each well toeliminate confusion when comparing themonthly production figures. This recordshould only occupy one line for each month,even if it means using the back of the firstsheet and the front of the next page. Onlyone figure is needed for the month. Thisrecord can also be set up in column form ifpreferred. With the passage of time onepage of records will extend for six months totwo years into the past, depending on systemselected, so as the record is read, it will tellthe pumper a great deal of information abouteach well. Some of the information thatneeds to be posted includes:

Information Sheet Heading.· Lease· Well number· Test time (24 hours)

Line Information.· Date of test· Pump cycles· Total hours produced· Total barrels per day (BPD)· Barrels of oil· Percentage oil· Total barrels water· Percent of water· Wellhead shakeout· Cubic feet of gas· Gas/oil ratio· Orifice plate size· Temperature· Well bleeder pressure or flowing

pressures· Separator pressure· Other desired information· Comments

Each pumper will need to adjust this list tothe specific needs of the lease. Too muchinformation is better than a short list. Tomake a good well production analysis, theinformation must be complete.

Single-Well Tank Batteries. When onewell goes into one battery, a specific day ofthe month can be selected and declared a testday. The pumper will also average the dailyproduction from the tank battery and showthis as a daily test. In this event, the pumperwill also need to project any downtime sothat it is known how the average wasderived.

C-5. Monthly Tank Battery TotalProduction Record.

At the end of each month, the pumper liststhe total production of oil, water, and gas.By dividing these results by the number ofdays the well produced during the month, adaily average is computed. As a year ofrecords is kept and daily averages compared,the pumper will get a good overview ofproduction. This is the best guide toindicate how the wells are performing.

Problem analysis from monthly test data.Some questions that can be answered fromthe production information include:

· How did the lease do this month?· Are any wells declining in production?· Which wells need productivity tests?· Which wells are having pump problems?· Do any wells have a tubing problem?· Is it time to treat and stimulate the

reservoir?· Which wells are developing higher

wellhead pressure?· Are higher casing pressures lowering

production?

19C-4

Figure 1. A tank chart to convert gaugedepths to volume of liquid. This chart isfor a cone-bottomed tank and allows for

3.83 barrels in the cone.

If the pumper does not maintain andseriously compare daily productionstatistics, the most important informationavailable to judge lease performance is beinglost.

C-6. Records for Daily Use.

Some records are so valuable that they arereferred to almost daily in working on thelease. Regardless of the method used toreport the production of the past 24 hours,the lease pumper must understand what ishappening on the lease, produce the mostpossible oil, and keep lifting costs as low aspossible while still doing a good job. This isnot possible without production referencesthat can be checked quickly as needed. Someof these records are:

Yesterday’s tank gauges. The grease bookused to record today’s activities will containa record of yesterday’s tank gauges, which

will show production volume based on tankcharts (Figure 1). Every day’s oil and waterproduction is rendered into feet and inches,so as soon as today’s gauge is completed andrecorded, the pumper can know how thelease did. Is it over, just right, or short?Corrective action may be needed. If thiscannot be determined, the reference systemneeds to be improved.

The daily, seven-day, eight-day, ormonthly production report. This is animportant record for the productionsupervisor and company. It details howmuch oil was produced daily and lists all oilsales. This informs the company of howmuch income they will receive the followingmonth for this period of time, shows resultsof well tests, itemizes all major leaseproblems during the reporting period, anddetails how much oil was over or short.

The lease pumper should double-checkthis report before sending it to the companyto ensure that all math is accurate and allinformation easy to read.

Monthly tank battery production of oil,water, and gas, and daily averages. Thelease records book will contain a monthlytotal of oil, water, and gas produced, a dailyaverage, gas/oil ratios, and water/oilpercentages. This record only consumes oneline per month and provides a continuingpulse of how the lease is performing.

This simple record provides answers toquestions such as:

· How much oil is being sold?· How much water is being injected or

hauled?· Are injection pressures changing?· How much gas is being sold?· How are production averages changing?· Where are the problems?

19C-5

Monthly individual well tests. Possibly themost valuable record that the lease pumpercarries is the monthly well production testrecord. This is a test where the well hasbeen normalized for several days and a 24-hour test performed. This test is performedone time each month on every well on thelease. It is just as important to carefullyperform this test on batteries with one wellas on a battery with several wells.

This record is important because itprovides the pumper with a measuring toolon how the lease, wells, and pumps aredoing. Needed information includes:

· How much tank room will be required toperform this test?

· What orifice plate will be required for thegas reading to stay on the chart?

· Is production falling, constant, orincreasing? How much?

· Is the gas/oil/water ratio changing?· Is the flow line pressure changing?

Chemical consumption records. Thechemical consumption record for eachmonth is important to maintain because it isan important part of the lifting cost perbarrel. Because there is treated oil not yetsold, it is difficult to render into a cost perbarrel from the records. It does, however,give the pumper an accurate record of dailyconsumption. By noting the barrels of oilproduced each month, it is relativelyaccurate. The pumper should know howmuch chemical is being consumed per 100barrels of oil treated.

C-7. Benefits of Production Records.

There are many benefits from maintainingproduction records. After maintaining theserecords for a few months, the pumper wouldnever be without them. Some benefits are:

· Knowing how much oil and gas was lostduring the month because of leaseproblems. This figure can also beprojected into lost dollars, and theanalysis of why it was lost may illustratethe importance of equipment maintenanceand pinpoint special problems.

· Indicating wells beginning to havedownhole problems such as pump wear.

· Assisting in determining whenproductivity tests should be conducted.They allow monthly analysis of wellconditions.

· Indicating increased production fromwells that have been worked over and thefeasibility of working over other wells.

· Showing loss of production that occurswith time and natural depletion.

Benefits will change according to leaseconditions.

C-8. Supply Purchases.

The lease operator will have written orverbal policies concerning supply purchases.For larger operators where bids canperiodically be taken and where case lotpurchases are cheaper per item, the pumpershould work closely with the leasesupervisor when making purchases.Companies usually require advance approvalfor the purchase of higher quantities ofsupplies or some types of purchases, such astool replacement.

C-9. Time Sheets for Work Performed.

Company employees. Time sheets foremployees are usually required, even with asmall company. This confirms that thepumper receives all pay earned and is astatement to the company confirming thatthe pumper worked the time submitted.

19C-6

Contract labor. When the pumper isrequired to confirm the accuracy of workhours submitted by contract labor, themethod of time-keeping should be discussedwith the contract labor supervisor. It may bepreferable to record work to the nearest 15-

minute interval in order to be fair to both thecontractor and the production company. Thepumper must always be accurate in keepingthese records to be fair with the employer aswell as the contractor.

8-day production report to be completed by the lease pumper.

19D-1

The Lease Pumper’s Handbook

Chapter 19Record-keeping

Section D

MATERIALS RECORDS

D-1. Materials Control.

Keeping a record of every piece ofequipment on the lease that has either beeninstalled or is in reserve for future use is animportant function within the petroleumindustry. All of the varied items stored onthe lease are usually referred to as materials.Maintaining accurate records of this materialis a necessary part of the job. Whenequipment or supplies are needed, theserecords will indicate if it is on hand, can bemoved from another location, or must beacquired.

As material is acquired, the tendency is tostore it on the lease, even if the leaseoperator office is in a nearby town. If storedwithin city or town limits, material may besubject to additional property taxes. Beingeasily available to meet lease needs is alsoan important consideration.

Oilfield equipment is very expensive topurchase and transport and represents a largelease operator investment. The pumper willalmost always have a certain amount ofmaterials on hand available for immediateuse. The lease pumper is often in charge ofoverseeing the storage and welfare of thisequipment, and this means that the pumperhas responsibility and accountability foreverything on the lease. When equipment ormaterials are missing without the pumper’sknowledge of where it went, the employermust be notified immediately.

Theft. Prevention of theft of oilfield pipeand equipment is an important part of thelease pumper’s job. Lease equipment can beprotected from theft or loss to a large degreeby following good practices. The petroleumoperator, because theft is such a commonproblem in the oil field, usually has a lowtolerance for theft and will prosecute to thelimit of the law.

Theft by employees. A large part of theft inthe oilfields is a result of actions orpermissiveness by the lease pumper. Ifanything is missing when needed, thepumper usually comes under close scrutinyby company management. Sometimes thepumper knows who may have stolen themissing items, even if the pumper isinnocent. Suspicious activities or visitorson the lease should be noted and reported,and the pumper must never assume theyhave the owner’s permission to removeanything from the lease without priorapproval. The pumper should alsodiscourage visits by people who aresuspected of surveying the lease for whatthey can return after hours to steal.

D-2. Controlled Lease EquipmentStorage.

Controlled lease security is commonpractice. Often equipment is temporarilyleft on a lease location, but for many reasons

19D-2

(such as the appearance of the lease) may bemoved to one central area of controlledstorage.

Some of the replacement equipment, repairparts, and supplies usually on hand on thelease are:

· Rods and tubing for well repairs.· A small assortment of pony rods and

tubing subs.· Fuses.· Electric motors.· Steel and plastic pipe.· Fittings and leak clamps· Barrels of several types of chemical.· Equipment that has been pulled out of

service.· Equipment waiting to be installed.· Damaged and surplus equipment.· Joint venture equipment.· Walkways, ladders, and vessels.· Junked equipment being retained for

spare parts to repair similar equipment.· Scrap equipment whose value is only in

the weight of the material.· A host of other repair and maintenance

materials such as motors, vessels, andwalkways.

Location of a storage area. The operatorwill usually secure landowner permission touse a small area as a controlled storage area.It may be an abandoned well site or requiresetting up a special controlled area or yard.Usually, the first thing considered is asecurity gate. It can be a simple locked gateacross the road with cable wings extended tothe sides, or a specially designed storageyard with a Private Road sign.

Security fencing. Security fencing—usually cyclone fencing—is the first step tosetting up a secure storage area.

Occasionally this secure area will alsoinclude a dog house for storage of materialsneeding weatherproof storage and a place tofill out production records. This fenced areashould be large enough to allow trucks toenter, turn, load, and unload equipment.

Weed and mud control. Crushed rock or asimilar material is usually placed on thelocation, especially on roads and on theequipment storage areas to reducemaintenance problems caused by vegetationgrowth and control of mud. The yard shouldbe placed where maintenance will notbecome a burden.

D-3. Pipe Storage.

A minimum number of joints of pipe andsucker rods are stored on most locations forreplacement purposes. Due to the cost oflabor and short notice delivery requests, it ismore practical to have a few joints availablenearby to reduce downtime and haulingexpenses. Major centralized storage areasmay have more extensive stocks of materialsfor the area or several leases.

Pipe and rod storage areas and magneticorientation. Many companies demand thattheir pipe be stored in alignment with themagnetic pull of the earth—that is, north andsouth. This may reduce crystallization fromoccurring while the pipe is in storage. Manycommercial storage companies carefullyalign their pipe storage racks with this inmind.

Classifying used pipe. Pipe is classified bythe composition of the steel and the depththat it may be run, such as H-40, J-55, andN-80. Although pipe is lightly stamped toshow this classification, used pipe is usuallylowered one rating number when it is moved

19D-3

to the storage area as used. As anillustration, J-55 pipe may be reclassified asH-40. This is normal practice just to becertain that the pipe will performsatisfactorily when returned to service. Forthis reason, the pumper must accept the pipebook or office classification, even if thenumber on the pipe indicates that it is ofhigher quality.

Pipe rack design and numbering systems.The pipe rack needs to be well designed andstrong enough to support the amount of pipeto be stored. It needs to be high enough toallow for easy rolling of the pipe off or ontothe rack and onto the truck trailer.

A sign on the rack identifies the rack andsometimes what is stored on it (Figure 1).This identification may also identify thenumber of joints, size, and quality.

Figure 1. Pipe stored on site and labeledfor location and classification.

Pipe range. Casing may also be identifiedby length. This length is usually on thestorage record. The longer the joint, thefewer connections that have to be made upwhen running it. Range numbers are asfollows:

30 to 35 foot pipe is Range 135 to 40 foot pipe is Range 240 to 45 foot pipe is Range 3

Pipe collaring and condition. Pipe isalways neatly aligned and collared when it isplaced on the rack. The threads should becleaned and lubricated and, if threadprotectors are available, they are screwedonto the pipe.

Pipe separation and layering. Whenseveral layers of pipe or sucker rods arestored on a rack, lumber is used to separatethe layers. This allows the pipe to be easilyrolled and placed in neat order. Thethickness of the lumber is selected accordingto the weight of the pipe. A scotch or blockis nailed on the board, next to the pipe at theends to prevent the joints from rolling off.

The stripping lumber that separates pipelayers is valuable company property. Thismaterial should be handled and stored withcare because it will be used again and againwhen the next loads of pipe are hauled to theyard. Unauthorized removal of strippingmaterial from the lease is theft.

D-4. Storage of Other Materials.

Crushed rock pads, as well as 8x10-inchsills, may be needed when storing heavyequipment. Equipment should be storedleveled, balanced, and off the ground.

Arrangement, pads, docks, and weatherprotection. Some space should be availablein the secure area for delicate equipment andsupply storage where protection may beessential. Timber-covered pads may beneeded for small equipment, and a truckheight dock with a roof is of great valuewhen off-the-ground storage is needed.

A plat or drawing of the storage areashould be made, designating all areas bysome numbering system. Pipe racks alsoneed sub-numbering systems indicating eastto west or another appropriate numbering

19D-4

system preference. Several sizes andclassifications of pipe will occasionally bestored on the same rack, and the numbercount must be included on the working list.Unlisted materials seem to disappear.

Junk and scrap designations. Whenequipment has been pulled out of service, itmay be classified as junk or scrap. Junk isvaluable material because it has many partsthat may be salvaged for re-use. Whenmaterial is classified as scrap, it has been nolonger usable, is not reparable, or hasbecome obsolete. When selling these itemsby bid, junk brings a much higher price thanscrap because much of it will be salvagedand re-sold. Many times a junked item istoo valuable to sell because other similarunits are running in the field, and salvageparts can be used to repair other equipment.

Materials going to junk or scrap usuallyhave a weight estimate. When this scrap orjunk is sold, the weights should basicallyagree with the amount shown on the records.Even scrap has a value.

Chemical and drum storage, contentmarking, and accounting. All 55-gallondrums should be stored in neat order andseparated by content. Content and generallythe date received should be identified by useof a paint marking.

Figure 2. Chemicals should be properlystored and only kept if required.

The lease pumper should maintain achemical inventory to know when thechemical supply on hand is low and moreshould be ordered.

Proper determination of the actual contentsand correct disposition of abandoned barrelsof chemical left on the lease can costhundreds of dollars per barrel, so nochemical should be allowed to stay on thelease if it does not serve a purpose.

Winterizing and deterioration control.When engines and specialized equipment aremoved into storage, they should bewinterized—that is, the water removed andall openings sealed. When a piece ofequipment is received, the pumper shouldmake a notation on the to-do list and checkit as early as possible for proper storage.Valves in engines can be damaged if rain isallowed to enter through an exhaust opening.

D-5. Joint Venture Inventory andAccounting.

Occasionally a lease is a part of a jointventure. This means that the lease has twoor more owners, and all equipment andmaterials brought into storage are part of thisproject. They must not be mixed with thestock fully owned by the company. Somesimple system, such as an X in front of allinventory numbers and stamped on theequipment, can identify it as joint ventureequipment at a glance. This equipment isrestricted and cannot be used without propermanagement approval.

D-6. Transfer Forms and Procedures.

As a project in the field begins, allmaterials that arrive on the location havebeen transferred and appropriate recordsplaced in the lease operator’s office. When

19D-5

materials such as pipe are shipped, a smallextra amount is added to allow for changesand to prevent construction shortages. Afterthe project has been completed, this extramaterial must be transferred into appropriatestorage or to another location or project.These transfers are important, so recordsneed to be accurate and complete.

A typical type of transfer form is shown inAppendix A-11. When transferring pipe outof storage, a pipe tally sheet mustaccompany the transfer sheet. A typical pipetally sheet is illustrated in Appendix A-12.Common sense must be used when fillingout this form. It will not meet all needs, soif it does not contain the specifically neededinformation space, the pumper should usethe back side of the form to write additionalnotes. The word OVER should be used onthe front to indicate that more information iswritten on the back of the form.

The location of all pipe and equipment onthe lease is listed on company records. Pipeis either in use as a part of an installation oris in storage. If it is in storage, the exactlocation should be noted on the materialstransfer form. Except with pipe transfers, aseparate form should be avoided becausethey can become separated. Somecompanies request a drawing on the back ifit includes the laying of a pipeline.

Materials transferred out of storage. Amaterials transfer form is usually writtenevery time material is transferred. Materialincludes all forms of pipe and equipment,but usually excludes supplies unless they arevery expensive. Only the spaces that applyto that particular item are utilized. Asimplified version without prices may bedeveloped for field use.

When transferring pipe out of storage,more pipe than is needed is usuallytransferred, just to be sure enough is on

location to complete the job. Whatever isleft over must be accounted for after the jobhas been completed. A specific destinationis included on the transfer, and some type ofcorrespondence should be sent to thewarehouse materials inventory person toindicate that the project has been completed.

Materials transferred into storage. Whenmaterials are transferred into storage (if thestorage area is comprehensive), a notationmust be made showing where it is stored. Ifpipe has been downgraded, this must beindicated on the transfer as it is unloaded.Identification marks may be needed. If thematerial is part of a joint venture, this mustalso be noted.

Materials being transferred from onelease to another. When material is beingtransferred from one lease to another, a fullexplanation may be needed. Occasionally,special notations must be made on the backexplaining the project. The office personnelshould not have to guess why the materialwas needed or for what it was used.

D-7. Identification of All Chemicals Usedor Stored on the Lease.

The lease records book should have arecord of every chemical used or stored onthe lease. This is extremely important.

Identifying chemicals and markingbarrels. Because barrel markings may fade,a paint stick should be used so that everybarrel can be identified. Regulations requirethat the contents of every chemical barrel beidentified before it can be properly disposed.The identification and disposal can costseveral hundred dollars for each barrel if itscontents are not known.

19D-6

Identification numbers on barrels shouldbe a minimum of 1 inch high or larger andeasily read. A number system can beadopted to specify chemical purpose such asO for treating oil, B for bottom breaker, Sfor paraffin solvent, F for stabilizingformations, P for cathodic protection, and soforth. Barrels should also be groupedaccording to content to aid in end of themonth inventory and to know when to notifythe office that supply is low. It may also beuseful to identify the supplier.

Other information that must be notedincludes the following:

· Date of purchase.· Name of the chemical.· Purpose of the chemical.· Chemical mixing ration.· Where used.· How it is used.· How often is it used.· Storage life.· Other pertinent information as needed.

When a service crew leaves the lease afterperforming contract services, all barrelsshould leave with them and nothing leftbehind for the pumper to handle.

D-8. End of the Month ChemicalInventory.

At the end of every month, the pumpershould inventory the chemical on hand andcompare those quantities to what is posted inthe lease records book. At this time, aprojection can be made of how muchchemical was used and when more will beneeded. It is easy enough to develop achemical accounting system.

Measuring barrel content. As chemical onhand is inventoried, measuring the amountremaining in barrels is more difficult totransfer into a gallon accounting. A 55-gallon drum volume chart has been includedin Appendix A-6 for convenience in makingthis estimate.

A-i

APPENDIX A

TOOLS AND RECORDS

A - 1 API pump Designations.A - 2 API Sizes of Pumping Unit Designations.A - 3 Pump Abbreviations.A - 4 Kickover Tools for Running Gas Lift Valves.A - 5 Kickover Tool For Pulling Gas Lift Valves.A - 6 55-Gallon Drum Measurements.A - 7 The 7-Day Daily Gauge Report.A - 8 The 8-Day Daily Gauge Report.A - 9 The Weekly Gauge Report. (Vertical)A - 10 The Monthly Gauge Report.A - 11 Materials Transfer Record.A - 12 Pipe Tally Sheet.A - 13 Fishing Rods.A - 14 Rod Fishing Tools.A - 15 Lease Information Record.A - 16 Motor/Engine Records.

A-ii

A-1

The Lease Pumper’s Handbook

Appendix ATools and Records

Section 1

API PUMP DESIGNATIONS

(courtesy of Harbison Fischer)

A-2

The Lease Pumper’s Handbook

Appendix ATools and Records

Section 2

API SIZES OF PUMPING UNIT DESIGNATIONS

Pumping Unit Size Designations.Pumping unit sizes and the load that can be suspended safely from the sucker rods are reduced

to 5 designations that can be written on one line. A permanent metal plate is attached to thegearbox with these identifying numbers printed on them. These designations in order are:

1. Type of Pumping Unit.A. Air Balanced.B Beam BalancedB-P Beam Balanced (Pin Mount)C Conventional (Standard)CT Conventional (Two Point)C-P Conventional (Pin Mounted)C-M Conventional (Portable)M Mark II UnitorqueLP Low ProfileRM Reverse Mark

2. Peak Torque Rating In Thousands Of Inch Pounds.

3. D Double Reduction Gear Reducer.

4. Polished Rod Load Rating In Hundreds Of Pounds.

5. Stroke Length In Inches.

A-3

The Lease Pumper’s Handbook

Appendix ATools and Records

Section 3

PUMP ABBREVIATIONS

(courtesy of Trico Industries, Inc.)

A-4

The Lease Pumper’s Handbook

Appendix ATools and Records

Section 4

KICKOVER TOOLS FOR RUNNING GAS LIFT VALVES

(courtesy of CAMCO Products and Services)

A-5

The Lease Pumper’s Handbook

Appendix ATools and Records

Section 5KICKOVER TOOL FOR PULLING GAS LIFT VALVES

(courtesy of CAMCO Products and Services)

A-6

The Lease Pumper’s Handbook

Appendix ATools and Records

Section 6

55-GALLON DRUM MEASUREMENTS

Drum HorizontalGallons m3

Measured DepthInches mm

Drum VerticalGallons m3

0.902.514.546.889.47

0.0030.0100.0170.0260.036

12345

255176102127

1.723.455.176.908.62

0.0070.0130.0200.0260.033

12.2615.1918.2521.3924.59

0.0460.0580.0690.0810.093

678910

152178203229254

10.3412.0713.7915.5817.24

0.0390.0460.0520.0590.065

27.8231.0634.2837.4640.56

0.1050.1180.1300.1420.154

1112131415

279305330356381

18.9720.6922.4124.1425.86

0.0720.0780.0850.0910.098

43.5646.4349.1251.6053.81

0.1650.1760.1860.1950.204

1617181920

406432457483508

28.5929.3131.0332.7634.48

0.1080.1110.1180.1240.131

55.6657.00

0.2110.216

2122232425

533559584610635

36.2137.9339.6541.3843.10

0.1370.1440.1500.1570.163

Calculations based on:

2627282930

660685711737762

44.8346.5548.2550.0051.72

0.1700.1760.1830.1890.196

Drum height = 33.35 inchesor 845 mmDrum capacity = 57.325 gals.or 0.217 m3

313233

33.25

787813838845

53.4555.1756.8957.33

0.2020.2090.2150.217

A-7

THE BARREL CHART

The barrel chart is handy for calculatinghow much chemical is on hand. This isespecially important at the end of the monthin determining how much chemical is onhand, what types, and whether a waitingperiod for delivery is required. Mostchemicals used to treat crude oil, clean tankbottoms, treat injection water, inject as acasing preservative, treat scaleaccumulation, or other purposes on the leaseare custom blended. If chemicals are notordered until the supplies are deplete, thelease pumper may run out of requiredchemicals before they can be blended anddelivered. This may result in a lot ofdifficult-to-treat crude oil accumulating.

The barrel chart allows the amount ofchemical in a barrel to be computed whetherthe barrel is standing vertically or lying onits side. Although the chart is in 1 inchincrements, it is easy to interpolate to thenearest quarter-inch if required. If a barrel isused for short time tests on wells, this chartis extremely useful.

The chemical record should be updated inthe lease information and performancehandbook every month. This gives thelease pumper an instant reference of monthlyuse of every chemical stocked, andconsumption and restock dates are easilyprojected long in advance of running out. Italso allows the computation of the amountof chemical consumed per hundred barrelsof oil sold. These figures can help the leasepumper determine whether chemicalconsumption is appropriate for productionneeds and results.

The chemical records will also correctlyidentify the contents of every barrel of liquidheld on the lease and the amount on hand. Ifthe contents of a barrel are unknown, acompany must pay to have the chemicalanalyzed and identified so that it can bedisposed of properly to meet environmentalregulations. If accurate records are kept, agreat deal of money can be saved. Thus, thelease pumper should keep good records andnever allow the lease to accumulate evenone barrel of unknown liquids.

A-8

The Lease Pumper’s Handbook

Appendix ATools and Records

Section 7

THE 7-DAY DAILY GAUGE REPORT

A-9

The Lease Pumper’s Handbook

Appendix ATools and Records

Section 8

THE 8-DAY DAILY GAUGE REPORT

A-10

The Lease Pumper’s Handbook

Appendix ATools and Records

Section 9

THE WEEKLY GAUGE REPORT (VERTICAL)

A-11

The Lease Pumper’s Handbook

Appendix ATools and Records

Section 10

THE MONTHLY GAUGE REPORT

A-12

The Lease Pumper’s Handbook

Appendix ATools and Records

Section 11

MATERIALS TRANSFER RECORD

A-13

The Lease Pumper’s Handbook

Appendix ATools and Records

Section 12

PIPE TALLY SHEET

A typical well servicing report that is filled out each time rods or tubing are pulled on the site.Everything run into the hole is described in detail. Packers and other components must haverelease instructions in the remarks. Components are listed in order of being run into the hole.

A-14

The Lease Pumper’s Handbook

Appendix ATools and Records

Section 13

FISHING RODS

(courtesy of Trico Industries)

A-15

The Lease Pumper’s Handbook

Appendix ATools and Records

Section 14

ROD FISHING TOOLS

(courtesy of Trico Industries)

A-16

The Lease Pumper’s Handbook

Appendix ATools and Records

Section 15

LEASE INFORMATION RECORD

LEASE INFORMATION

Name of Lease ________________________________________________________________Location of Lease ______________________________________________________________Well Number________________ Depth of Well______________ Date Drilled_____________

PUMPING UNIT INFORMATION

Date Installed______________Manufacturer____________________________ Style of Unit____________________________Size______________ Serial No.______________________ Direction of Rotation____________Stroke Lengths Available_______________________________ Length inUse_______________Gear Ratio_________________________ Strokes Per Minute Now_______________________Pumping Unit Sheave Diameter_______________ Number of Grooves_____________________Belt Width _______________________ Number and Size of Belts________________________Shaft Size____________________ Keyway_______________ Maximum Size ______________Style of Pumping Unit Skid________________________ Style of Base____________________Gearbox Oil________________ Capacity_____________ Bearing Grease__________________Rod Lubricator Oil __________________________ Stuffing Box Lubrication_______________Prime Mover_______________________________ Strokes Per Minute___________________Remarks______________________________________________________________________

BELT DRIVE INFORMATION

Number of Belts____________ Size____________ Length______________ Type___________Belt Capacity: Prime Mover__________________ Pumping Unit_________________________Sheave Description: Prime Mover: Diameter_________ Shaft Size________ Keyway________

Pumping Unit: Diameter________ Shaft Size________ Keyway________Prime Mover Adjustment Available (Inches)

Toward Unit_____________________ Away from Unit_________________________How Will This Affect Belt Guard?__________________________________________________

A-17

WELLHEAD INFORMATION

Lease_____________________ Well No.____________________ Date Listed______________Polished Rod: Thread Up___________ Thread Down____________ Length________________Polished Rod Liner: I.D.______ O.D._____ Length_______________ Gasket Size___________Lift Pony on Top of Polished Rod ______X______X_____________Lubricator Brand ______________Pad Description________________ Oil Used_____________Stuffing Box Brand._______________________ I.D. of Packing__________________________Packing Brand __________________Inserts Needed(Describe)__________________________________________________ Packing Quality or Info.___________________________________Polished Rod Clamp Bolts: How Many? ________ Diameter__________Length_____________Pumping Tee_________________________ Bleeder Valve______________________________Wing Valve__________________________ Wing CheckValve___________________________Casing Valve_________________________ Casing Check Valve_________________________Other (Rotators, Misc.)_________________________________________________________________________________________________________________________________________

CASING RECORDS

Depth from Wellhead to Perforations _______________________________________________Description of Perforations _______________________________________________________Open Hole Below Perforations ____________________________________________________

PIPE AND TUBING

Type of Tubing. (Check One) H-40______ J-55______ C-75______ N-80_______ P-105______Other (Describe) ________________________________________________________________Threads: 8 Round _________________________ Other than 8 Rd.________________________Average Joint Length __________________ Pipe Measured: Threads Off______ Overall______Packer or Holddown. To Set______________________________________________________To Release______________________________________ Tension Pulled____________Pounds

COMMENTS:

A-18

The Lease Pumper’s Handbook

Appendix ATools and Records

Section 16

MOTOR/ENGINE RECORDS

Electrical Motor Information

Manufacturer __________________________ Type of Frame____________________________Horsepower ___________________________ Volts Required____________________________Amperage _____________________________ RPM___________________________________Shaft Diameter _________________________ Keyway_________________________________Sheave Diameter___________________ Style__________________ Grooves_______________Can Voltage Be Changed? (Yes/No)___________ If Yes, describe______________________________________________________________________________________________________Mounting Bracket: Width______________________ Length____________________________

Engine Information

Field ___________________________ Lease_________________ Location ________________Type of Installation______________________________________________________________Make of Engine___________________ Model________________ SerialNo.________________Number of Cylinders_______________ Rings_________________ Bearings________________Valve Clearances: Intake____________________ Exhaust______________________________Spark Plugs______________________ Magneto ______________ Magneto Rotation_________Coil ____________________________ Distributor ____________________________________Carburetor_____________________________________________________________________Battery size______________________ Date Installed__________________________________Starter __________________________ Generator_____________________________________Oil: Capacity_____________________ Brand_________________ Weight_________________Oil Filter ________________________ ChangeSchedule________________________________Radiator: Capacity________________ Quarts Antifreeze________ Freeze point_____________Radiator Hose Sizes: Upper_________ Lower_________________ Water pump_____________Fan belt _________________________ Clutch________________________________________Shaft Diameter ____________________ Keyway______________________________________Sheave Style ______________________ Diameter______________ Number of grooves_______Drive Belt Size and Length _______________________________________________________

A-19

Date Engine Was Installed_____________________ Date Overhauled_____________________Gas Log and Scrubber Information _________________________________________________Maintenance Notes ____________________________________________________________________________________________________________________________________________

B-i

APPENDIX B

PUMPING UNITS

B - 1. Types and Styles of Mechanical Pumping Units.1. Development of the Walking Beam Mechanical Pumping Unit.2. Styles of Pumping Units.3. Conventional Units.4. The Air-Balanced Pumping Unit.5. Mark Unitorque Units.6. Low Profile Units.7. Other Styles of Pumping Units.

B - 2. Selecting and Setting Up Pumping Units.1. Selecting the Correct Pumping Unit Base.2. Height of the Base.3. Preparing the Base.4. Centering the Horse Head Bridle Carrier Bar over the Hole.5. Leveling the Pumping Unit.6. Safety Grounding.7. Selecting Guard Rails and Belt Guards.

B - 3. Changing Pumping Unit Adjustments.1. Designing the Pumping Unit to Do the Job.2. Changing the Counterweight Position to Balance the Rod Load.3. Beam-Balanced Pumping Units.4. Changing Stroke Length.5. Lowering And Raising Rods.

B - 4. Belts And Sheaves.1. Introduction to Belts and Sheaves.2. V-Belts, Sizes, Widths, and Depths.3. Types of Belts Based on Load Performance.4. Number of Belts Required to Start and Pull Loads.5. Lengths of Belts in Inches.6. Belt Life.7. Styles of Sheaves.8. Number of Grooves.9. The Keyway.10. Math Calculations.

B-ii

B-1

The Lease Pumper’s Handbook

Appendix BPumping Units

Section 1

TYPES AND STYLES OF MECHANICAL PUMPING UNITS

B1-1. Development of the Walking BeamMechanical Pumping Unit.

Mechanical pumping units have undergonemany advances since the early years whenone central roundhouse station pumpedmany wells. During the mid-1920’s, LufkinIndustries, Inc. made their first pumpingunit. This wood beam unit began capturingpart of the market that had been supplied bymanufacturers of the round wooden wheel,the roundhouse model, and several otherstyles of units. The single counterweightgearbox with one pitman arm was firstmarketed in 1925 and was very efficient.The pump jack and workover mast wereremoved from the Lufkin pumping unitshown in Figure 1 in the late 1980’s, thoughthe unit was still pumping every day. It haspumped several hundred thousand barrels ofoil.

Figure 1. Lufkin pumping unit from theearly 1920s.

A gear-driven pump jack powered by a flatbelt was developed by Alamo Duplex. Tomove the pumping unit out of gear, the beltwas shifted over to an idler gear. Thesebecame more popular for water wells thanoil wells, because of their limited size. Theunit pictured in Figure 2 was removed fromservice in the 1970’s. Note that thewellhead and stuffing box were designed aspart of the unit base.

Figure 2. The Alamo Duplex GearedPumping Unit with flat belts.

B-2

Figure 3. The 1926 Lufkin Crank-Balanced Pumping Unit is still in service

today with only slight modification.

The next pumping unit that Lufkin offeredbegan manufacture on July 15, 1926,although it was 1931 before the designbecame popular. This unit with twin cranksand counterweights proved to be an idealdesign (Figure 3). It was well balanced andeven served as the stepping stone fordevelopment of the Mark series. After morethan seventy years of service, thismechanical beam-balanced model, with onlyminor changes, is still available for purchasetoday.

B1-2. Styles of Pumping Units.

There are four basic styles of beam-balanced pumping units:

· Conventional units.· The Mark series units.· Air-balanced units.· Low-profile units.

These styles are so common that three orfour of them may be represented on a singlelease.

B1-3. Conventional Units.

Conventional units are characterized by aSamson post in the middle of the walkingbeam. However, there are four majorvariations in conventional unit design.These include:

· Beam-balanced.· Crank-balanced.· Reverse Mark.· Slant-hole.

Beam-balanced. This pumping unit gets itsname from the fact that weights are added tothe tail of the walking beam behind the tailbearing or equalizer bearing to counterbalance the weight of the sucker rod string.Many manufacturers have sold variations ofthis design over the years, such as the smallunit shown in Figure 4.

Figure 4. A small beam-balancedpumping unit.

It may be necessary to lift the cover of thegearbox to know the correct direction ofrotation for this unit while it is in operationand to determine how to maintain it. Somewill have herringbone gears that permit themto rotate in either direction. Others are chaindriven, and some of these get lubricationonly when they are rotated in the correct

B-3

direction. Some operate with 50 weightmotor oil in the gearbox, others require 90weight gear oil, and some even require 120weight oil for long life and properperformance. Holes are drilled in the flangeof the walking beam to permit changing thestroke length. These units are generally usedfor shallow wells.

The standard beam-balanced pumping unitwith counterweight balance and two pitmanarms has been the workhorse of the industrysince Lufkin put it on the market in 1926.Used primarily for medium to deep wells, itis still manufactured by several companies.

Crank-balanced. This unit has alreadybeen pictured in (Figure 3). The crank-balanced unit was the workhorse of theindustry for more than fifty years withoutmuch competition. This unit is still populartoday and continues to be sold.

Figure 5. The Reverse Mark pumpingunit.

(courtesy of Lufkin Industries, Inc.)

Reverse Mark model. A newer style ofconventional unit being manufactured is theReverse Mark unit. At a distance, it isdifficult to distinguish it from the standard

unit. However, note the differences in thepumping geometry apparent in Figure 5.These include the location of the saddlebearing in relation to the walking beamcenter and the off-center pitman arm pinhole. The improved performance of theReverse Mark series results in a reduction intorque and power requirements. It canoperate with a smaller reducer and primemover.

Slant-hole model. To meet special needs,the slant-hole unit (Figure 6) was developed.These units can operate and pump wells at adeviation angle of 45 degrees. Slant-holepumping units have a horse head that ismuch longer below the walking beam than aconventional head. As the unit makes arevolution, this longer head and othermodifications cause the bridle to sweepforward with each stroke to provide thecorrect angle of 45 degrees.

Figure 6. A slant-hole unit.(courtesy of Lufkin Industries, Inc.)

B1-4. The Air-Balanced Pumping Unit.

The air-balanced unit has enjoyed a halfcentury of service in the oil fields. Althoughit is not as common as the conventional and

B-4

the mark series, in some areas it is extremelypopular. Compressed air in a cylinder underthe front of the walking beam is utilized tooffset the weight of the column of rods andfluid in the well, eliminating the need forcounterweights.The air-balanced unit (Figure 7) is extremelydesirable for deep, heavy pumping loadswhere the counterweight load needed toinstall a conventional unit would beprohibitive and a long stroke is desired.Another of the advantages of the air-balanced pumping unit is the accuratefinger-tip control of the balance of thepumping load. This balance operatesautomatically.

The air-balanced unit has an aircompressor mounted behind the gearbox forair makeup. To balance this unit the leasepumper merely disengages the clutch andobserves where the walking beam stops. Ifit is horizontal, the unit is balanced. Byturning a dial, the unit can be re-balanced ina few minutes. This is the only unit thatoffers this simple balancing feature for amassive pumping unit.

Figure 7. An air-balanced pumping unit.

Figure 8. The Mark II UnitorquePumping Unit.

(courtesy of Lufkin Industries, Inc.)

B1-5. Mark Unitorque Units.

The introduction of the Mark seriespumping unit (Figure 8) by Lufkin Industriesmore than thirty years ago changed thetrends in the pumping unit industry. Thisdramatically improved unit and its uniquegeometry revolutionized the design ofmechanical pumping units everywhere. TheMark pumping unit design greatly improvedpumping geometry and the efficiency of thepumping unit.

The Mark unit is lighter in weight,resulting in lowered materials andtransportation costs. The unit requires justtwo lighter weight pads and is able to pumpa deeper well. The dynamics of the unit alsoresulted in lowering horsepowerrequirements, lower lifting costs, lower peakloads, and longer rod life. For medium todeep wells, the Mark series is used in a largeshare of pumping unit installations.

B1-6. Low Profile Units.

Pumping units are located almosteverywhere. This includes on farms and

B-5

ranches, in cities, on golf courses, inorchards, and elsewhere. Some specialapplication pumping units have beendesigned to reduce their intrusion on thevista and to prevent interference with otheroperations. For example, at one timepumping units in irrigated crop land wereplaced in holes to avoid interfering withsprinkler systems. With low profile units(Figure 9), giant sprinkling systems canoperate and travel right over the pumpingunit while watering crops. This installationmay require the well to be completed with alowered wellhead also to reduce the profileby lowering the base as much as possible.The low profile unit continues to beimproved and fills a definite need in theindustry.

Figure 9. A low-profile pumping unit.(courtesy of Lufkin Industries, Inc.)

B1-7. Other Styles of Pumping Units.

Many other styles of mechanical pumpingunits are available on the market, such asstyles where the rods rotate. The sizes of theAPI recognized pumping units vary from thevery small to the very large.

B-6

The Lease Pumper’s Handbook

Appendix BPumping Units

Section 2

SELECTING AND SETTING UP PUMPING UNITS

B2-1. Selecting the Correct Pumping UnitBase.

When selecting a pumping unit, regardlessof whether it is new or used, the firstconsideration is to choose an appropriatebase. The base will generally be a metalskid or a pre-formed concrete structure.Bases are designed to meet many differentconditions (Figure 1). For example, the typeof prime mover is a critical factor. Multiple-cylinder engines require a different skiddesign than single-cylinder engines. If theprime mover is to be an electric motor, anelevated skid, built closer to the gearboxreduces the belt length and size of the beltguard. The shorter belt also gives muchbetter service, lasts longer, and costs less.

A different concrete pad will be requiredfor the shorter pumping units with elevatedmotors. If the pumping unit is to be set onthe ground, with either compacted rock orsills, the steel base must be almost threetimes as wide as a pumping unit that is to bebolted down on a pre-formed concrete base.

Once a pumping unit is on the location andready to install it, there are several importantfactors that must be considered, such as typeof pumping unit skid base, selection of agood base for the crushed rock pad, andother factors. This section addresses manyof these basic considerations.

Figure 1. There are many styles of metalbases for different installation needs.

(courtesy of Lufkin Industries, Inc.)

B2-2. Height of the Base.

The pumping unit base must be highenough to allow sufficient distance for thenecessary fittings between the horse headand the wellhead on the pump downstroke.To determine how high the base must be, thedistance from the bottom of the pumpingunit carrier bar on the downstroke to the topof the wellhead must be determined. With

B-7

the riser nipple, the pumping tee, and thestuffing box installed, the height of wellheadabove the ground must be measured. Manyproblems with base height result when thesefactors are not considered so that the surfacepipe with the wellhead is set too high. Thiscan cause the pumping unit to have to beplaced on a high mound of crushed rock,pipe framed pumping unit stand, or concretebase. Occasionally, more than one basemust be stacked on top of each other to solvethis problem (Figure 2).

Figure 2. A pumping unit set on twoconcrete bases to allow for the height of

the wellhead.

The depth of the well should also beconsidered. Shallow wells should have alower wellhead than deep ones because theunits are so small and low.

After determining the distance from thetop of the stuffing box to the bottom of thecarrier bar, 12 inches is subtracted to allowfor the installation of a polished rod linerand possibly a rod lubricator, whileproviding room for a polished rod clamp.The remaining distance is the from the topof the polished rod liner to the bottom of thecarrier bar on the downstroke.

B2-3. Preparing the Base.

There are three main factors to considerwhen installing a base for a pumping unit.These factors are :

· Earth stability and preparation.· The type of skid on the pumping unit.· Preparation of the base to receive the

pumping unit.

Earth stability and preparation.Regardless of the style of base used, thepumping unit needs to be set on a firm bedof gravel. Once the height of the base hasbeen determined, the area is covered withgravel or crushed rock and leveled. Somelease pumpers bury a straight 2x4 board inthe center of the gravel for the full length ofthe base. This gives a satisfactory supportfor the level as the crew works the gravel toa flat surface. The level must also be turnedacross the pad to check side-to-side levelingto prevent the pumping unit from leaning toone side. After the gravel bed is level, theboard is removed and the space it occupiedcan be filled in with gravel by hand.

Type of skid base on the pumping unit.The style of pumping unit as well as thestyle of steel skid are important in decidingwhat pad and base design is used.Generally, pumping units with wide basesare placed on crushed rock pads with boardslaid upon the pad. The boards extendbeyond the width of the pumping unit skidbase. In this way, the weight of the pumpingunit is distributed over the length of theboards and, thus, spread over the crushedrock pad. When the boards are laid upon therock pad, they are first leveled andstabilized—that is, sufficient rock is placedunder and around the boards to keep themfrom shifting.

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…Pumping units that have narrow skids aregenerally placed on concrete bases—eitherpre-formed structures or poured-in-placeconcrete. This approach can also be used forunits with wide skids. Pre-formed concretebases are installed using techniques similarto the use of boards. In other words, theconcrete blocks are placed on the crushedrock pad, leveled, and stabilized.

If the concrete is laid at the site, a smooth,level pad of concrete is poured (Figure 3).Often the pumping unit is bolted to theconcrete base by means of bolts embeddedin the concrete. The correct placement ofthe bolts can be made easier through the useof frames that help locate the bolt positionsso that they line up with the holes in the skidof the pumping unit (Figure 4).

A pumping unit that uses a multiple-cylinder engine prime mover will usually beset on a full concrete base that may even beell-shaped to allow for the engine.

Preparing the base to receive thepumping unit. Before installing the base onthe crushed rock pad, the pumping unitshould be on hand and ready to install.Occasionally the steel base of the pumpingunit must be modified before it can bemounted on the selected base. For example,mounting holes may be required to fit thebolts on the pre-formed concrete base.

Other factors that may need to beconsidered include the orientation of thepumping unit on the pad. For example, whatis the best and safest way to get electricity toan electric motor prime mover? If an engineis used as a prime mover, the direction of thewinter and summer wind should beconsidered so that the radiator of the enginecan be positioned to take advantage ofcooling in the summer and warming in thewinter.

Figure 3. Laying out the concrete pad fora pumping unit.

(courtesy of Lufkin Industries, Inc.)

Figure 4. A frame can be used to assist inthe placing anchor bolts in the correctlocations for the pumping unit skid.

(courtesy of Lufkin Industries, Inc.)

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B2-4. Centering the Horse Head BridleCarrier Bar over the Hole.

Another item that should be carefullychecked when installing the pumping unit isthat the carrier bar is perfectly centered overthe hole. When the rods hang perfectlycentered in the stuffing box under load, thechances of a stuffing box leak are lessenedand the need to buy packing is reduced.This also prevents polished rod and/or linerwear and metal-to-metal galling, scoring,and wear. Damaging the polished rod orliner due to unnecessary side wear ordamage is expensive to repair and costly inpacking replacement due to short workinglife. On a shallow well with a well-centeredpolished rod, a set of packing can last forseveral years and will not need to betightened as often.

B2-5. Leveling the Pumping Unit.

Occasionally a pumping unit must beremoved and the base re-leveled because ofcontinuing problems with stuffing box leaks.Often this is caused by the pumping unitsettling unevenly because of an unstablepad. The amount that the pumping unit isleaning can be easily determined byremoving the packing from the stuffing boxto check the centering of the polished rod inthe stuffing box with the horse head at thetop, at the center, and at the bottom of thestroke. This is a check that the lease pumpercan easily make when a stuffing box beginsto leak excessively. Occasionally a tiltedpumping unit can be leveled by insertingshims between the pumping unit and thebase. Otherwise, the base must be re-leveledto support the pumping unit evenly.

B2-6. Safety Grounding.

When a pumping unit has an electricmotor as a prime mover, one of the possibledangers is electrical shock from a short. Agrounding system should be installed on allelectrically driven pumping units forpersonal protection. The system is made upof bare copper ground wires that connectappropriate areas of the wellhead, such asthe electric motor, the control box, and thepumping unit. A clamp was formerlyattached to one of the 2-inch casing nippleson the wellhead beside the casing valve.However, tests have shown that having theground cable attached to the wellhead cancause galvanic corrosion that leads to tubing,casing, and rod corrosion. The acceptedpractice today utilizes a ground rod driveninto the earth near the control panel.

The best method of preventing anelectrical shock in the event of a short is toperiodically check the electrical system to besure the grounding system is intact.Generally, there are no problemsmaintaining the integrity of this system,except for the line that is attached to thewellhead, which is where the electricity issupposed to go in event of a problem. Whenthe well is worked on, the ground line maybe removed and not reattached at the end ofthe job. It can also be broken off just fromworkers walking on it at the wellhead. Thelease pumper should check this clamp aminimum of every six months on every well.

B2-7. Selecting Guard Rails and BeltGuards.

Protective guards should be installedaround all moving equipment. Thesedevices not only protect workers around theunit, but they protect cows, horses, sheep,and wild animals from injury. Guard rails(Figure 5) should be selected to meet

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particular needs. To do so, adjustments mayhave to be made beyond the manufacturer’srails. These are designed primarily toprotect people. Sheep fencing or othersuitable protection may also be addedaccording to need.

Figure 5. One style of guard rails.(courtesy of Lufkin Industries, Inc.)

Counterweights on the Mark series pumpmove upward toward the wellhead and anappropriate guard should always be placedbetween the front of the pumping unit andthe wellhead.

Occasionally it is desirable to put guardrails only around the counterweightmovement area. For some pumping units,this is a satisfactory arrangement.

Belt Guards. Belt guards (Figure 6) offer alarge margin of safety when working arounda pumping unit. When making andinstalling a belt guard, care must beexercised in the construction to be sure thatit agrees with available belt lengths.

Figure 6. Belt guards installed on a largepumping unit.

(courtesy of Lufkin Industries, Inc.)

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The Lease Pumper’s Handbook

Appendix BPumping Units

Section 3

CHANGING PUMPING UNIT ADJUSTMENTS

There are many reasons for makingchanges in the design and adjustments of themechanical pumping unit. Most of thesechanges in adjustments seek to achieve amore efficiently operating pumping unit, tochange downhole pump action, to stimulateoil production, or to solve specific problems.Some of the common adjustments are:

· Changing the counterweight balance.· Changing stroke length.· Lowering and raising the rod string to

stimulate gas locked or failing pumps.· Changing the number of strokes per

minute.· Making changes such as belt length,

motor size, dynamometer controls, etc.

Figure 1. Because of a need to pump alarge volume of water, this pumping unitis much larger than would normally be

required.

Most of these changes are not typicallyperformed by the lease pumper. Somerequire a crew and special equipment. Jobdescriptions vary, however, from lease tolease and with different lease operators. Thelease pumper’s duties also depend on thedepth of the wells, pumping unit size, anddaily work load. The purpose of this sectionis to give an overview of such procedures.

B3-1. Designing the Pumping Unit to Dothe Job.

Regardless of the cause—natural waterdrive, water flood, etc.—the well may haveto pump high volumes of water along withthe oil. In Figure 1, an over-sized pumpingunit has been installed on a shallow well tosupport production of the desired daily oiland water volume. The counterweights havebeen removed to achieve near balance of therod load. This installation achieves thedesired pumping goals, but it is not assatisfactory as a correctly designed pumpingunit. The gearbox is oversized for the joband may be operating at a higher RPM thanis recommended by the manufacturer whichcould lead to oil foaming and lubricationproblems.

Pumping unit manufacturers will assembleand sell a long stroke unit with a reducedsize gearbox designed to meet special needs.The requirement for custom-designedpumping units increased with the growing

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use of enhanced recovery. When pulling apumping unit from storage to place it backinto service, it may be necessary to check themanufacturer’s production record tounderstand the design and capability of apumping unit. As an illustration, LufkinIndustries, Inc. has a record of every unitthat they have ever manufactured.

B3-2. Changing the CounterweightPosition to Balance the Rod Load.

Counterweights are moved in or out on thecrank as needed to balance the pumping load(Figure 2). The counterweights of the unitare adjusted along the crank arm to balancethe weight of the rod string. The heavier therod string, the farther out on the arm theweights must be. When moving theseweights, it may be necessary to refer to themanufacturer’s operation manual or hire anexperienced service person to place thepitman arm in the correct position toperform this procedure, based on the powerrequired to move them. There are severaltechniques used for balancing older models.

Pumping unit weights are manufactured inseveral sizes to meet balancing needs. Thin,auxiliary weights can be added to thecounterweight when it is not heavy enough.

When balancing counterweight loads onunits that have electrical power, an ammetershould be used to monitor amperage on theupstroke and downstroke.

It has been customary through the years tobalance the rod load with a slightly “rodheavy” attitude. This means that each timethe unit stops pumping, the unit will stop onthe downstroke and the polished rod in thehole. This keeps the rod free of dirt andextends the life of the rod and packing.

The lease pumper should always checkwith the manufacturer’s representative whenmaking dramatic changes.

Figure 2. To balance some pumpingunits, the counterweights are

repositioned.(courtesy of Lufkin Industries, Inc.)

When weights are repositioned or removedfrom a pumping unit, the balance of the unitcan suddenly shift with the weight of the rodstring being applied to the end of thewalking beam. This can cause a sudden and

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dangerous swing in the balance beam. Toprevent this, most adjustment proceduresrequire that the brake be chained to preventthe beam from moving. (Figure 3).

Figure 3. Correct procedure for chainingthe brake.

(courtesy of Lufkin Industries, Inc.)

B3-3. Beam-Balanced Pumping Units.

For balancing beam-balanced pumpingunits, there are several styles of weights.Most weights are simply bolted onto the tailend of the walking beam. Some brands ofunits have limited adjustments, and othersonly have a means of adding or removingweights. Sometimes weights are added orremoved by bolting them on. Others haveracks that hold cast iron bars. The methodsare not always obvious. If in doubt of theadjustment options or methods, the leasepumper should ask someone withappropriate experience.

B3-4. Changing Stroke Length.

The stroke length on most pumping unitsis adjustable. The crank arm generally hasthree holes in a line or in a triangular pattern

so that moving the weights to a differenthole will change the stroke length by severalinches. do not create many problems whenChanging the stroke length on beam-balanced units is generally a matter ofmoving the walking beam and the U-bolts atthe tail equalizer to a different set of holes.On some, the walking beam can also bemoved on the Samson post also. When thisis done, the unit may have to be realignedover the hole.

To change the stroke length on a crank andcounterweight unit, the general procedure is:

1. To prepare the pumping unit for thechange, move the counterweight to aposition slightly below being straightacross horizontally.

Figure 4. Changing the pumping unitstroke length.

(courtesy of Lufkin Industries, Inc.)

2. Remove the weight of the rod stringfrom the carrier bar.

3. Lower the polished rod liner until it issitting on the stuffing box

4. Place a polished rod clamp on the rodand snug it against the liner.

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5. After tightening the rod clamp, engagethe prime mover to move the walkingbeam until the rod weight has beenremoved from carrier bar

6. Set the brake and chain the brake of thepumping unit so that it cannot move.

7. Clean and oil the new holes, removingall rust and paint.

8. Change the pins to the new holes.9. Tighten and key the nuts.10. Grease the previously used holes to

prevent rust.11. Mark the nut so that position changes

can be detected.

B3-5. Lowering and Raising Rods.

(NOTE: The following is intended as aguide only and should not be construed asspecific instructions. There are certaindangers associated with performing theseduties. These processes are to be performedby a competent, knowledgeable technicianwith experience in pumping unit operations.All tools and equipment should be designedspecifically for use in performing thesetasks. The use of faulty or improper tools ora lack of specific knowledge in performingthese tasks could lead to serious injury ordeath. The person or persons attempting toperform these tasks are doing so at their ownrisk. This guide is only a suggestion and isnot to be construed as specific instructionsas different types of units require differentprocesses in performing these tasks.)

There are several reasons that rods mayhave to be lowered or raised. Pumps mayhave to be lowered to break a gas lock or totap a pump to stimulate trash removal fromunder the balls and seats. If the pump hasavailable space, occasionally pump actioncan be restored by raising the rods or raisingand then lowering them. It may be possibleto unseat the pump then re-seat it.

When rods are lowered to tap bottom, thismeans that on the downstroke, the pump iscompletely closed together and the toptraveling part of the clutch strikes thestanding clutch half. This sends a shockthrough the pump to loosen the trash underthe seats so the pump can begin pumping.

Pump repair companies may not agree thattapping wells is necessary, but manyproduction companies perform this functionas a matter of practice before pulling anywell. Some shallow- and medium-depthwells must tap at all times; otherwise, theywill not continue to pump for more than afew days or hours at a time. If properlyadjusted, many shallow wells can tap forseveral years, and the pump shows nodamage when pulled. Occasionally, the rodsmust be raised before lowering them torestore pump action. The procedure is:

1. Stop the unit with the head down and setthe brake.

2. Loosen the polished rod liner packingnut and set screw.

3. Lower the liner until it is resting on topof the stuffing box.

4. Place a clamp on the polished rod sittingon top of the liner and tighten it.

5. Loosen the clamp on top of the carrierbar, raise it several inches, and re-tighten.

WARNING: Never grab the polishedrod between the carrier bar and theclamp. If the clamp slips, everything inbetween will be crushed.

6. Let the brake off slowly to allow the rodweight to be placed back on the carrierbar clamp.

7. Remove the lower clamp from thepolished rod, raise the liner, retighten the

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packing, and tighten the set screw.8. Turn on the unit.

This will lower the rods, and the unitshould be tapping bottom lightly. If thepump does not tap, the lease pumper mustrepeat the process until it does tap.

The procedure to raise rods includes thefollowing steps:

1. Stop the pumping unit with the crank atabout the 10 to 11 o’clock position orabout 15 degrees before top dead centerand set the brake.

2. Lower the polished rod liner byloosening the packing nut, backing offthe set screw, and lowering the rod linerdown to the stuffing box.

3. Tighten the polished rod clamp with itsitting on the polished rod liner.

4. Loosen the brake.5. Turn on the pumping unit.6. As the head comes down with the

weights at the 12 o’clock position, turnthe power off and set the brake.

WARNING: Several inches of rod will

be exposed. NEVER GRAB THISAREA. If the upper clamp slips,everything in between will be crushed.

7. Loosen the upper clamp, allow it to dropback down on the carrier bar, then re-tighten.

8. Remove the clamp above the polishedrod liner.

9. Let the brake off and turn the unit untilthe horse head is down. Set the brake.

10. Lift the polished rod liner a few inches.11. Tighten the packing nut and the set

screw.

The lease pumper must never get in ahurry when lowering or raising rods.Experience teaches much of what needs tobe known. By looking in the lease recordsbook, the lease pumper will know the lengthof the pumping unit stroke and the strokeaction available in the pump. This willassist greatly in deciding the correct action.Without adequate records, the lease pumperwill just have to rely on judgment.

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The Lease Pumper’s Handbook

Appendix BPumping Units

Section 4

BELTS AND SHEAVES

B4-1. Introduction to Belts and Sheaves.

A good understanding of belts and sheavesis important in obtaining satisfactoryperformance from a wide range of belt-driven equipment, especially pumping units.Poor operation practices lead to unnecessarydown time, loss of production, a decreases inincome, and increases in lifting costs perbarrel of oil

Belt manufacturers want their customers toobtain satisfactory results from using theirproduct and publish free or low-costbooklets to assist in belt and sheaveselection and maintenance. As anillustration, the Gates Rubber Companypublishes two booklets that can be obtainedthrough local Gates distributors:

· The Pumper’s Friend. (A Guide for V-Belts and Sheaves). 12 pages

· Gates Industrial Drive Products &Preventive Maintenance Guide. 78pages.

B4-2. V-Belt Sizes, Widths, and Depths.

Industrial V-belts (Figure 1) are availablein two styles: super and high power. Thesecome in the following sizes with widths anddepths in inches:

Super HC V-Belt Sizes.

Size Width Depth3V & 3VX 3/8 21/645V & 5VX 5/8 35/648V 1 7/8

Hi-Power II V-Belt Sizes.

A ½ 5/16B 21/32 13/32C 7/8 17/32D 1¼ ¾E 1½ 29/32

Figure 1. Cross-section of a high-powerV-belt.

(courtesy of Gates Rubber Company)

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B4-3. Types of Belts Based on LoadPerformance.

V-belts may be purchased in two or morequalities. The primary governing factor indeciding which quality to buy depends uponthe load performance and type of service thatis required. A standard style belt will havethe rubber on the sides exposed to theatmosphere, while the more expensive styleswill be fully encased in a tough, cloth, flexweave cover. For all-weather outdoorapplications such as pumping unit belts, thefully cased belt is tough, shock resistant, andlong lasting.

The second factor to consider whenpurchasing belts that will be placed onmulti-belt sheaves is whether to purchasematched length individual belts or to order ajoined power band belt, with the belts joinedtogether with a common backing (Figure 2).The joined belts can solve many long spanstability problems.

Figure 2. Cross-section of a power bandjoined belt.

(courtesy of Gates Rubber Company)

B4-4. Number of Belts Required to Startand Pull Loads.

Selecting the size and number of belts foran installation such as a circulating pump orliquid injection system will depend uponseveral factors, such as:

· The surge load placed on the belts whenstarting up the unit.

· The load while the unit is in operation.· How often the unit starts and stops.

The starting load is possibly the mostimportant consideration. If the belts slipunder the starting load or if they are toosmall and run hot under severe load, the lifeof the belts will be short, and the companywill be paying for these initial installationmistakes as long as the unit is left inoperation without solving the problem. Allinstallations require adequate planning andselection of a sufficient size belt to do thejob efficiently. It is not unusual to expectsome belts to last twenty years or longer.

B4-5. Lengths of Belts in Inches.

Size Short Long Increments

3VX 25 140 1½” to 8"5VX 50 355 3" to 20"8V 100 560 6" to 25"

A 26 182 1" to 15"B 31 316 1" to 15"C 55 422 2" to 30"D 110 663 7" to 60"E 187 664 15" to 60"

As shown in the chart above, industrialbelts may be purchased in lengths fromabout 2-55 feet. The shorter belts can be

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purchased in incremental lengths of 1 inchor less and, in the heavier belts, up to 60inches between lengths.

As each size of belt gets longer, additionaladjustment space must be provided. Sincethe side movement of the skid rails thatsupport the prime mover provides for theselection of two or more belt lengths, smallmotors may be moved only a few inches toprovide for belt replacement and correcttension, but the larger ones must haveseveral feet of adjustment capabilities.

B4-6. Belt Life.

Belt life is governed by correct sheavesizes, speeds, balance of units, eliminationof slippage with correct belt tension, correctbelt selection, proper alignment, and othercontrollable factors. If an installationrequires belt replacement too often,something is wrong in the design and shouldbe corrected.Each time a belt runs over a sheave, it mustbe flexed in and out under load. The fasterthe belt travels, the more times it flexes perminute, and the more heat that is generated.This can dramatically shorten the life of thebelt. When planning high-speed or heavy-load installations, the manufacturer’s beltengineering experts should be contacted toassist with planning the design of theinstallation. Idler pulleys will occasionallysolve these problems.

B4-7. Styles of Sheaves.

There are two basic types of sheaves.Smaller sheaves, one inch or less indiameter, are usually one piece and bored tosize to fit the shaft. Variable pitch sheavesthat permit changing the speed of theequipment by adjusting the pitch are usually

small sheaves. The larger sheaves used onpumping units and equipment with driveshafts over 1 inch in diameter typically useheavy-duty tapered split bushings and hubs.Two common styles of two-piece sheavesare the QD sheave (Figure 3) and the taper-lock sheaves (Figure 4). Of these two, theQD style is very popular in the oilfield.

Figure 3. A QD sheave(courtesy of Gates Rubber Company)

Figure 4. A taper-lock sheave.(courtesy of Gates Rubber Company)

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B4-8. Number of Grooves.

Smaller sheaves seldom use more than twoor three belts, but the C, D, and E sizes mayhave up to ten or even twelve grooves. It iscommon for there to be grooves withoutbelts so that more can be added if required.

Sheave diameter and belt flexing. Whenusing a small belt, the sheave may also besmall. Each belt has a limit as to how muchbend it can be subjected to without severelyweakening the belt and reducing itsproductive life. The speed at which sheavesrun is largely determined by the number offeet per minute of belt travel. A maximumspeed of 6,500 feet per minute seems to betypical. The minimum acceptable andlargest diameters available for QD sheavesare as follows:

Belt Diameter Largest Grooves3V 2.20 33.5' 1 to 105V 4.40 50 1 to 128V 12.50 71 1 to 12

A/B 3.75 38.35 1 to 10C 5.40 50.40 1 to 12D 12.6 58.6 1 to 10

B4-9. The Keyway.

Inserting a key in a square keyway in thesheave locks the sheave with a keyway inthe shaft and keeps the sheave from slipping.The sheave may also be held in place by aset screw, if needed. Keys will be of anappropriate size according to the diameter ofthe sheave. The larger the sheave, the largerthe key and keyway. The end of the key willbe slightly tapered to allow it to enter easily.

If the two key slots are of different sizes,combination keys are available to allow theuse of sheaves on shafts that have a differentsize keyway. These combination keys arecapable of performing satisfactorily withoutdanger of failure caused by size.

B4-10. Math Calculations.

The lease pumper is often required tocalculate various factors when installing andmaintaining belts. These include:

· Calculating belt length, full formula· Calculating belt length, short formula· Changing sheave size to change

revolutions per minute (RPM)· Changing pumping unit strokes per

minute (SPM)

Such calculations are reviewed inAppendix E, Math.

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C-i

APPENDIX C

TANK BATTERIES

C - 1. Understanding the Tank Battery.1. Openings to Vessels for Lines.2. The Shape and Purpose of Vessels.3. From the Well to the Tank Battery.

C-ii

C-1

The Lease Pumper’s Handbook

Appendix CTank Batteries

Section 1

UNDERSTANDING THE TANK BATTERY

The purpose of this appendix is to provideinformation about basic tank batteries, thepurpose of each vessel, where it is installedin the system, what vessels should beinstalled ahead of it, what vessels should beinstalled after it, and how to operate most ofthem with a minimum number of problems.

Two tank batteries, even when theysupport oil or gas production from the sameformation, are seldom alike. The leasepumper needs to be able to approach avessel, look it over, generally understandwhat is taking place inside the vessel, andknow how it is being used for that particulartank battery. The petroleum industry isflexible in handling special productionproblems, and an understanding of theproblems at a lease site may be necessary toexplain why a vessel was installed in aparticular fashion that may not be themethod normally expected.

Generally, the term vessel is applied to allthe containment structures in the tankbattery. More precisely, only thosestructures that are pressurized are vessels,while those that are atmospheric are referredto as tanks. Thus, vessels are generallyinvolved in some process, such as phaseseparation, while tanks are usually storagecontainers, as in stock tanks. In thisdiscussion of the tank battery, bothatmospheric and pressurized vessels aredescribed and the generic term vessel is usedunless specifically referring to a tank.

C1-1. Openings to Vessels for Lines.

There are six standard vessel openings forline attachment, plus a few special purposeones. Standard openings are:

· Inlet· First liquid outlet· Gas vent· Drain· Overflow· Second liquid outlet

These lines all meet a specific need. Somevessels may have two openings to meet thesame need. This may make the vesselflexible for right- or left-hand installations.The opening may be a bolted flange or awelded half coupling, which is a heavy-dutygrooved nipple welded to the vessel, such asVictaulic of America fittings.

Inlet. The purpose of the inlet is to receiveproduced fluids. This includes everythingthat comes out of the well: oil, water, gas,and suspended solids such as sand, salt,paraffin, asphalt, scale or gyp, drilling mud,and a host of other elements and compounds.

Inlets are usually located above the fluidline on either the side of the vessel, as invertical separators, or on the top, as in somehorizontal vessels and stock tanks.

The third location for an inlet line isapproximately a foot above bottom when the

C-2

vessel serves as an automated surge tank.This is common in automated water disposaltank lines or oil sales lines just ahead of theLACT unit. The inlet line is basic to everyvessel.

Gas Vent. The purpose of the gas vent is toremove the produced gas. It is usuallylocated at the highest point at the top of thevessel. This line may also contain a safetyrelease or pop valve and a pressure safetyrupture plate. The gas vent opening is basicwith every vessel.

Oil outlet. The purpose of the oil outlet is toremove crude oil from the vessel. Thisoutlet line is located either at the operatingfluid level of the vessel or below the fluidlevel and activated by an indiscriminatefloat. In stock tanks, this outlet is generallylocated one foot from the bottom and can beautomated or controlled by a valve.

Drain line. Vessels have to be emptiedoccasionally, so a drain is provided.

Overflow line. When fluid is flowing into avessel with no automatic outlet, an overflowline is provided. On tank batteries, this lineis used regularly and is often referred to asan equalizer line.

Second liquid outlet. The purpose of thesecond liquid outlet is to remove theproduced water. This outlet is located nearthe bottom of the tank. This is an optionalline that is installed in three-phase vesselswhere the fluid is separated into gas, oil, andwater.

Special purpose lines. There are a host ofreasons why a special purpose line may beattached to a vessel, such as oil sales lines,

rolling system lines, etc. Small openings arealso provided with many vessels for installingpressure gauges, fluid level gauges, safetyalarms, and other attachments. These arediscussed with each vessel.

C1-2. The Shape and Purpose of Vessels.

Major considerations in tank battery designinclude:

· Shape of vessel· Pressure rating· Number of phases· Temperature· Purpose of vessel

Shape of vessel. Vessels may be rectangular,with or without tops. Round vessels may bevertical with a rounded top and bottom,horizontal with rounded ends, or spherical.Each shape has special applications.

Pressure rating. As fluid is produced fromthe well, it may be flowing under highpressure or under low pressure with artificiallift. Regardless of how the well is produced,there must be enough pressure for the fluid toreach the surface, flow to the tank battery,and into the vessels.

Initial vessels in the tank battery are usuallypressurized vessels, such as the separator,heater/treater, flow splitter, line heater, andthe free water knockout. Separators haveworking pressures, ranging from a fewpounds to many thousands of pounds.Pressurized vessels have rounded corners.

Atmospheric pressure tanks in the tankbattery system include the gun barrel (orwash tank), water disposal tanks, skimmertanks, power oil tanks, slop tanks, and stocktanks. These tanks are designed to operatewith a maximum pressure of a few ounces.

C-3

Number of phases. A two-phase separatoris a vessel that separates the incomingemulsion into two fluids. The gas goes outthe top gas line, and the liquid is dumped outof the vessel with an indiscriminate float.Most separators are two-phase vessels.

The gun barrel, the free-water knockout,and the three-phase separator are all goodillustrations of three-phase vessels. Theincoming emulsion is separated into threefluids. The gas goes out the gas line on thetop of the vessel, the oil goes out a line at ornear the upper fluid level of the vessel, andthe produced water goes out the water linelocated near the bottom of the vessel.

Temperature. Crude oil is heated for anyof several reasons. Heater/treaters heatcrude oil to assist in removing the basicsediment and water content to a level to beable acceptable to sell the oil. This is themost common use of heat.

Other uses of heat include preventing icefrom forming in the system, keeping heavycrude thin enough to make it flow to the tankbattery, and keeping paraffin in a fluid state.

Purpose of vessel. Each field supervisor isfaced with problems unique to that lease,and supervisors may solve the same problemin many different ways. Thus, a vessel inone tank battery may serve a purpose that isnot required of that vessel in another nearbytank battery, and a vessel that is adequate forhandling a problem at one lease may notmeet that need at another.

C1-3. From the Well to the Tank Battery.

Two types of equipment can be located inthe flow line between the well and the tankbattery: the line heater and the satellite tankbattery.

Installing a line heater in a flow line.There are several reasons for installing a lineheater in a flow line. Emulsions producedfrom an oil well may freeze, jell, or solidifyand block the flow line. Heat added to theemulsion may keep it in a fluid state until itgets to the tank battery. Some of theproduced fluids that may solidify are waterthat does not contain salt, paraffin, asphalt,and crude oils with a very low API gravity.Occasionally, a line heater must be addedeven when the tank battery is constructed onthe edge of the well location pad.

Satellite tank battery. A satellite tankbattery is a separate system that may be addedto the well or group of wells to serve any ofseveral special purposes. These may includethe support of:

· Well testing· Separating water for disposal· Separating gas for sale or re-injection.· Pre-treating oil or water.

Various vessels can be selected to supportthese functions.

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D-i

APPENDIX D

PIPE, CASING, AND TUBING

D - 1. Pipe, Casing, and Tubing.1. Seamed and Seamless Steel Pipe.2. Pipe Schedules for Surface Construction.3. Lengths or Classes of Pipe.4. Sizes of Pipe.5. Tubing6. Casing.

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D-1

The Lease Pumper’s Handbook

Appendix DPipe, Casing, and Tubing

Section 1

PIPE, CASING, AND TUBING

This appendix has been designed to givethe lease pumper a basic knowledge of theuse of oilfield production pipe and fittings,casing, and tubing.

D1-1. Seamed and Seamless Steel Pipe.

Iron in its pure form has limited use inmanufacturing pipe. After it has beencombined with one or more other metals, anew compound called steel is formed. Steelis much stronger than iron, and steel pipehas been used in oilfield construction sincethe first wells were drilled.

Through the history of oil production,efforts have been made to improve steel pipeto make it more resistant to deterioration dueto corrosion and the action of acids and saltfound in hydrocarbons.

Pipe is available in both welded andseamless manufacture. The seamless pipe ismore expensive but is stronger and moreresistant to problems. Welded pipe is fusedwith heat and electricity applied to theparent materials without using welding rod.

D1-2. Pipe Schedules for SurfaceConstruction.

Pipe that is purchased for surfaceconstruction is available in several wallthicknesses and quality ratings. This isreferred to as the pipe schedule number.

Pipe schedule numbers range from thelightest weight, 10, to a maximum weight of

160. From 10 to 40, it is numbered in 10-point increments. From 40 to 160, it isnumbered in 20-point increments. Thus, theschedule increments are 10, 20, 30, 40, 60,80, 100, 120, 140, and 160.

Many pipe suppliers stock pipe 4-6 inchesin diameter in schedule 40 for low- andmedium-pressure installations, schedule 80for high-pressure use, and schedule 160 forextra high-pressure applications. In largersized pipe applications, all of the scheduledweights are available on order.

D1-3. Length or Classes of Pipe.

Pipe in common use in the oilfield is notalways the same length as pipe purchased atthe local hardware or lumber store fortypical commercial use. Pipe for oilfield useis usually purchased from the local oilfieldsupply store. Some pipe bought at eitherplace may be of the same quality, but someis not. Lengths of small pipe at the hardwarestore will probably be available in lengths of21 feet. The oilfield supply store may havepipe up to 2 inches in diameter availableonly in 21-foot lengths. Two-inch to 4-inchpipe is usually available in 25-foot lengths.

D1-4. Sizes of Pipe.

Pipe is sized by its diameter. There aremany sizes of pipe with the sizes rangingfrom 1/8 inch up to several feet in diameter.Pipe used for surface applications such as

D-2

flow lines and tank battery construction ismeasured by inside diameter and is usuallyreferred to as line pipe. These lines areusually 2 inch and generally no larger than 4inch.

The sizes of line pipe used in tank batteryconstruction varies. Flow lines and the oillines at the tank battery are usually 2-inch,and water drain lines may be any size from2-4 inches. General use is as follows:

Table D-2. SIZES OF FIELD CONSTRUCTION PIPE

Pipe Threads Joint Weight GeneralSize per Inch Length per Foot Use(inches) (feet) (pounds)

1/8 27 21 Special application¼ 18 21 Highly used3/8 18 21 Special application½ 14 21 Highly used¾ 14 21 Special application1 11 ½ 21 Highly used1 ¼ 11 ½ 21 Special application1 ½ 11 ½ 21 Special application2 11 ½ 21/25 4.7 Highly used2 ½ 8 25 6 Special application3 8 25 General use4 8 25 11 General use

The 1/16 inch size tap and die is readily available but the pipe and fittings are not. Thus, forpractical purposes, the smallest size included in this listing is 1/8 inch and up.

D1-5. Tubing.

Tubing is the moveable string in the oilwell. Tubing is manufactured in variousdifferent mixtures of steel. The stronger thesteel is, the higher its tensile strength and themore each joint costs. The lowest grade orclass of tubing is called H-40. This tubing isapproved for use in shallow wells. Fordeeper wells, tubing of higher grades mustbe used, selected to match the well depth.

The general classes of tubing mostcommonly used for oil production include:

H-40 Shallow wellsJ-55C-75 Deeper wellsN-80P-105 Deep wells

Tubing is available with inside diametersof 1-4 inches but tubing size is measured by

D-3

outside diameter. The two most commonsizes are 2-3/8" O.D. and 2-7/8" O.D.

Tubing comes in random lengths of 28-32feet long. Standard well tubing comes withupset ends. The joints within the string,other than possibly the bottom mud anchor,are installed without cutting and threading.Joints less than full length are called pupjoints and are available in 2-foot incrementsfrom 2-12 feet. Lengths in the 18-24 footrange may be available on special order.

Upset tubing must be installed to an exactdepth from the braiden head or the top of thewellhead downhole to the tubingperforations. By measuring and selectingtubing of required lengths, a tubing stringcan be made up to an exact depth.

Accurate records must be kept listingevery joint of tubing in every well. Theserecords must show the type, size, and lengthof every joint in order of installation.

Table 2. TUBING SIZE (EXTERNAL UPSET END)

OD Weight I.D. Cu. Ft /Ft Ft/Cu. Ft Bbl/Ft Ft/Bbl

1.050 1.20 0.824 0.00370 270.270 0.00066 1515.1521.315 1.80 1.049 0.00600 166.667 0.00107 934.5791.315 2.25 0.957 0.00500 200.000 0.00089 1123.5961.660 2.40 1.380 0.01039 96.246 0.00185 540.5411.900 2.90 1.610 0.01414 70.721 0.00252 396.8252.375 4.10 2.041 0.02272 44.014 0.00405 246.9142.375 4.70 1.995 0.02171 46.062 0.00387 258.3982.375 5.95 1.867 0.01901 52.604 0.00334 294.9852.875 6.50 2.441 0.03250 30.769 0.00579 172.7122.875 8.70 2.259 0.02783 35.932 0.00496 201.6133.500 8.50 3.018 0.04968 19.478 0.00870 112.9943.500 9.30 2.992 0.04882 20.483 0.00870 114.9433.500 12.95 2.750 0.04125 24.242 0.00735 136.0544.000 9.50 3.548 0.06866 14.565 0.01223 81.7664.500 12.75 3.958 0.08544 11.704 0.01522 65.703

D1-6. Casing.

Casing is the fixed or cemented string ofpipe in oil and gas wells and is measured byoutside diameter. Sizes for land wells maybe as small as 4½ inches. As the well getsdeeper, the surface casing gets much larger.Tubing and casing are measured by thediameter of the lifting tools or elevators.With oilfield pipe strength ratings, even asthe pipe wall increases in thickness so that

the pipe will be stronger, the outsidediameter remains the same size so that thelifting and makeup tools continue to fit.This means, of course, that the higherstrength pipe will have a smaller insidediameter than a lower rated pipe with thesame outside diameter.

Perforating casing. When an oilwell isperforated, the shooting of the jet gun causesa shock to the joint being perforated. For

D-4

this reason, the perforation joint or jointsmay be heavier pipe to try to preventproblems that would result if lighter pipewere perforated. This means that they are ator near the bottom of the string and have asmaller inside diameter.

Because of problems caused in casingstrings with a smaller inside diameter, such

as having tools get stuck near the bottom ofthe hole, the top joint of casing is always thesame size on the inside as the smallest insidediameter joint. By adopting this practice,any tool that will go through the first jointwill go through any joint in the string,including the perforated joint.

E-i

APPENDIX E

CHEMICAL TREATMENT

E - 1. Special Information About Chemical Pumps.1. The Principles of Chemical Pumps and Injectors.2. Mechanical Chemical Injectors.3. The Low-Pressure Pneumatic Injector.4. The High-Pressure Pneumatic Injector.5. The Electrical Injector Pump.6. The New Style of Chemical Pumps.7. Barrel Racks and Bulk Storage Containers.

E - 2. Solving Special Treating Problems.1. Location, Installation, Operation and Maintenance of Chemical Injectors.2. Treating Oil: A Review.3. Other Treating Procedures That Have Not Been Reviewed.4. Batch Treating the Heater/Treater.5. Treating High Bottoms by Circulating with Pump and Hoses.

E-1

The Lease Pumper’s Handbook

Appendix EChemical Treatment

Section 1

SPECIAL INFORMATION ABOUT CHEMICAL PUMPS

E1-1. The Principles of Chemical Pumpsand Injectors.

Chemical pumps can be a great help intreating oil, or they can be nothing buttrouble if the lease pumper does notunderstand how they work and does notkeep them repaired and adjusted correctly.When they are in good shape they will savetime and help keep the oil properly treated.

The heart of the chemical pump is thechemical injector. The body of the injectoris made of forged steel. The chemical mustmove upward through the injector to preventair locks. When the body of the pump isworn due to plunger friction, it can bemachined out oversize and last many moreyears with a larger plunger.

Figure 1 shows a typical injector. Thenumbers in the following paragraphs refer tothe part labels in the illustration.

Figure 1. Parts of an injector.(courtesy of Arrow Specialty Co.)

The plunger moves back and forth in areciprocating action. As it moves back,vacuum lifts the lower ball check valve (13,bottom) open, pulling fluid in from thechemical reserve tank. The plunger can bepulled back by a gear (5) or have a pindropped in through a hole.

As the plunger is pushed back into theinjector, the upper ball check valve (13, top)is opened by the pressure on the chemical,and the chemical is injected into the oilbeing treated. The plunger stem packing nut(12) must be tightened a small amountoccasionally to keep the packing (4) tight toform a seal against the plunger. Thispacking will have to be replaced every fewyears to prevent chemical loss and air locks.To remove air locks from between the twoball valves, while the plunger is being pulledout the air bleeder rod (11) must be keptclosed, and while the plunger is beingpushed back in, the air bleeder rod should beopened so that the air can be removed.

E1-2. Mechanical Chemical Injectors.

Mechanical chemical injectors are usuallylocated at the well site mounted on the baseof the mechanical pumping unit. This pumphas been very popular through the years andgives good service.

Mechanical injectors are usually driven bythe use of a flexible line to lift the arm and aweight to lower it. In years past, steel

E-2

reinforcement rods were popular, but if thelease pumper placed an arm or leg under therod on the downstroke, serious injurieswerepossible. The upper end is attached tothe H-section of the walking beam and canbe moved away from the saddle bearing fora longer stroke or closer for a shorter stroke.

The mechanical chemical injector inFigure 2 would work well when a surfactantmust be injected for oil treating, and paraffinsolvent must be injected down the casing toreduce paraffin accumulation downhole.

Figure 2. A mechanical chemical injectorthat is installed on the pumping unit.

(courtesy of Arrow Specialty Co.)

E1-3. The Low-Pressure PneumaticInjector.

The low-pressure chemical injector isutilized where very low gas pressure isavailable. If a tank battery has no high-pressure vessels, such as a separator, but hasonly a gun barrel and stock tanks, chemicalmay be injected mechanically and accuratelywith the low-pressure pneumatic pump. Byinstalling 2- to 4-ounce backpressure valveson an atmospheric vessel gas vent, thispressure can be used to operate the injectoras well as to control the vapor recovery unit.

Figure 3. A low-pressure, diaphragm-operated chemical injector.

(courtesy of Arrow Specialty Co.)

Figure 3 shows that the pneumatic gasenters on the left side to operate the largediaphragm, and the chemical enters thechemical injector on the right side of thepicture. This unit is then mounted on sometype of base.

It is easy to compute the force thediaphragm pump will exert in pounds persquare inches using the formula:

Pressure = p x Radius2 x Pressure in lbs.

If the diaphragm is 18 inches across and thegas pressure is 4 ounces, then

Pressure = (3.14) x (9 x 9 inches) x ¼ pound

= (3.14) x (81) x (¼)

= 63.6 pounds per square inch

This is the pressure on the plunger. Sincethe plunger occupies no more than 1/3 of asquare inch, 4 ounces of pressure canproduce tremendous force.

Low pressure pneumatic injectors can beused for as long as they are maintained.There are few parts to replace, and the leasepumper should be able to keep themfunctioning if no mechanical assistance isavailable.

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E1-4. The High-Pressure PneumaticInjector.

The high-pressure pneumatic injector hasmany applications in the oil field other thantreating crude oil. Since it operates underhigh pressure, it is used on flowingwellheads, gas wells, pumping wells, andmany other applications.

A typical high-pressure pneumatic injectoris shown in Figure 4. The two high-pressurebrass cylinders that stick out from the squarecast iron body of the pump contain a soft-faced piston and have a hollow connectingrod. The gas is injected slowly into thespace outside the end of the piston and thispushes it toward the square body. As theopposite piston approaches the end of itsstroke, it engages a reversing valve thatrelieves the pressure from the end that justcompleted its stroke and places pressureagainst the surface of the opposite piston.

Figure 4. Views of a high-pressurepneumatic injector.

(courtesy of Arrow Specialty Co.)

As shown in Figure 5, three speedadjustments are available. The firstadjustment is opening the bent arm of theinlet needle valve handle. This stem has aset nut so that it can be locked at the desiredinlet volume. A second adjustment changesthe hole that has an arm going to theadjustment plate. The third adjustment is to

change a pin that regulates the length of thestroke of the piston.

Figure 5. Adjusting the speed of the high-pressure pneumatic injector.

(courtesy of Arrow Specialty Co.)

When this injector is installed on a flowingoil or gas well that has a bottom hole packerin it where no annulus gas pressure isavailable, a round cylinder similar to thesurge tank used to prevent fluid shock totriplex pumps is installed as a gas volumetank on top of the wellhead. Even whenflowing a high volume of crude oil, enoughgas will break out of the oil being producedand rise in the cylinder to operate theinjection pump.

High-pressure injector pumps are usedextensively in the production of natural gasfor injecting such solutions as tri-ethylglycol (TEG), ethyl glycol (EG), andmethanol.

When using a high-pressure chemicalinjector, the lease pumper should computethe injected volume every few days in orderto ensure that the oil is being correctlytreated.

E-4

E1-5. The Electrical Injector Pump.

The electrically driven chemical pumpusually has fewer problems than the othersystems. It also has the advantage of beingprogrammable by use of the electric clock.Since electricity is required, this system isnot possible or practical for manyinstallations.

For a high-volume tank battery withseveral pieces of equipment driven byelectricity, such as the circulating pump,vapor recovery unit, and the LACT, thechemical injectors can also be electrical(Figure 6).

Figure 6. Views of an electrically drivenhigh-pressure chemical injector.(courtesy of Arrow Specialty Co.)

E1-6. The New Style of Chemical Pumps.

During the past decade, great strides havebeen made in the development of improvedinjector pumps, including the use ofinexpensive computer cards to automaticallycontrol pump volume. Ease of operation,simplicity in style, and low cost have led togrowing sales for these enhanced models,although the older designs are still indemand.

For example, the Gas-O-Matic stylechemical injector discussed in Chapter 13-Chas become very popular during the past fewyears and is capturing much of the market(Figure 7). This system can be powered bygas or air.

Figure 7. Diagram of the Gas-O-Maticinjector valve.

(courtesy of Arrow Specialty Co.)

E-5

E1-7. Barrel Racks and Bulk StorageContainers.

Barrel racks and bulk storage containersalong with accessories like sight gauges andchemical injectors are illustrated in Figures8 and 9.The 55-gallon drum and rack systemremains popular for smaller installations, butin larger fields, a bulk storage container isgenerally installed and filled by a chemicalsupplier. With this system, the lease pumperdoes not have to handle heavy barrels orbecome involved in blending large volumesof chemicals. Also, bulk purchases areusually cheaper than the cost of the drums.

Figure 8. A fiberglass storage tank withknee tub and injector.

(courtesy of Arrow Specialty Co.)

Bulk storage containers can be purchasedin fiberglass, stainless steel, and othermaterials. Fiberglass is the most commonbecause of the low cost and because theamount of chemical remaining can bedetermined at a glance.

Figure 9. Chemical barrel and rack withliquid level gauge and injector.(courtesy of Arrow Specialty Co.)

Chemical tanks, injectors, and the qualityof chemical have been greatly improvedover the past few years and regulations toprotect the lease pumper have also beenmodified.

E-6

The Lease Pumper’s Handbook

Appendix EChemical Treatment

Section 2

SOLVING SPECIAL TREATING PROBLEMS

E2-1. Location, Installation, Operationand Maintenance of Chemical Injectors.

Once the determination has been made touse chemical injection, the lease pumpermust then decide how to stabilize and mountthe injection equipment. Many mechanicalinjectors can be easily mounted on the frontof the pumping unit base (Figure 1).

Figure 1. A mechanical chemical injectormounted directly to the base of the

pumping unit.

When the chemical injector is located onthe ground near a chemical tank, it is usuallyset on a concrete base (Figure 2). If thepump is placed on a board or on a graveledsurface, weeds will soon engulf the wholeinstallation, and it will be difficult to keepclean. When a concrete pad is used, theconcrete should extend at least six inchesbeyond the edges of the chemical injector onall four sides.

Figure 2. Chemical tanks and injectorsset on a concrete base.

E2-2. Treating Oil: A Review.

There are numerous chemical injectordesigns to support the various approaches tochemical injection (Figure 3).

Figure 3. Types of chemical injectors.

E-7

Some of the more common methods oftreating oil include:

Injecting chemical at the wellheaddownhole. This includes injecting thechemical into the annulus and allowing it toflow downhole. By circulating a smallamount of produced liquid from the bleederside of the pumping tee to supplement thevolume of injected chemical, it will reachthe bottom of the hole in a reasonable lengthof time. This procedure is important in:

· Treating crude oil. The treatment willbegin as the injected chemical mixeswith the fluids entering the annulus fromthe formation.

· Treating corrosion and scale. Thistreatment will keep the casing and tubingperforations open, as well as keeping theinside of the tubing and the rod stringclean.

· Injecting paraffin solvent. As the fluidtravels up through the tubing, the meltedparaffin begins to stick to the rods andtubing and accumulate in the well.Paraffin can accumulate and become sostiff and hard that it can support theweight of the rod string, so that the rodsfall slowly on the downstroke. Thehorse head bridle and carrier bar will runout from under the polished rod clampon the downstroke, and this causestremendous shock when the pumpingunit again accepts the rod load.Occasionally hot oil must be injected toallow the paraffin to become a fluidagain and be pumped to the tank battery.This widely used practice can plugperforations and the formation.Chemical treatment has proven to be farsuperior to hot oiling.

Injecting chemical into the flow line. Allthe chemicals injected into the annulus canalso be injected into the flow line to achievethe same goals as achieved downhole.

Injecting chemical at the tank battery.Chemical is injected at the tank battery afterthe header but before the first pressurevessel. The primary purpose in injectingchemical at this point is to treat the oil. Thisis the first location in the system at whichthe injected chemical will treat all of the oilbeing produced.

Dripping chemical into the thief hatch.Dripping chemical into the thief hatch froma gallon bucket with a very small hole in thebottom while circulating the oil willstimulate BS&W removal dramatically. Theaction of circulating without addingchemical will also assist in cleaning the oil.After treatment, the fluids will need asatisfactory amount of settling time, usuallyuntil the following day.

Hot oiling the oil in the tank. Calling out ahot oil unit to treat oil from stripper wells issometimes necessary, but this is anemergency treating procedure and is seldomdone if other solutions can be found. This isbecause the margin of profit is so low thatexpenses may exceed income.

E2-3. Other Treating Procedures ThatHave Not Been Reviewed.

There are many ways of reducing theBS&W level in oil that have not beendiscussed in this manual. A purpose of thissection is to provide information aboutdesigning and implementing additionalinnovative procedures that will assist insolving treating problems. Occasionally

E-8

small changes in the piping may have to bemade and openings and valves installed tomake the tank battery piping arrangementaccommodate an oil treating procedure.

Batch treating down the annulus.Occasionally it will be necessary to addressa downhole problem by batch treating oil,scale, corrosion, or other problems. Figure 4shows one shop-made style of treatingtrailer. The lease pumper can pour in thecorrect amount of chemical, then finishfilling the tank with water or crude oil.Three or more wells can be treated with onetank load.

Figure 4. A chemical tank and pumpmounted on a tandem-axle trailer for

injecting chemical and oil or water intothe annulus.

Batch treating and circulating. Withmany wells, after batch treatment, it may bedesirable to open a circulating line goingfrom the flow line into the annulus. Toallow circulation, the valve from the flowline is opened to permit the produced fluidto fall back to the bottom of the well. Theflow line valve to the tank battery is closedwhile circulating. The lease pumper maycirculate the oil for several hours or someappropriate time, then switch it back to

normal operation. Occasionally, thistreatment may also require a shut-in periodor an overnight circulating treatment. Batchtreatment may be done once a month or onsome set time schedule.

Some lease operators will contract with achemical company to treat and circulate thewells on a regular basis. It takes a veryproductive lease to be able to have theavailable funds to subscribe to this service.

E2-4. Batch Treating the Heater/Treater.

Occasionally, the lease pumper may needto send an extra slug of chemical to the tankbattery to inject extra chemical throughoutthe heater/treater to bring the system backinto balance and treat exceptionally bad oilcreated in the system by some specialactivity such as a well workover.

Chemical must be pumped in at the oilentry opening. Because there are two waysof producing into the vessel the treatmentmust be either from the well or from the tankbattery.Method 1: From the well. There areseveral ways to inject a batch chemicaltreatment from the well. The lease pumperwill add 2-4 quarts of additional chemical tothe heater/treater. A small ½-inch positivedisplacement pump with a hand crank todrive it can be mounted on a small framestand. First, a ½ inch x 3 inch swage isscrewed into the inlet opening using a streetell. With the opening of the swage up and asmall hose connected to the bleeder valve,batch chemical can be injected.

Another method is to install a standingriser ahead of the heater/treater inlet a fewfeet before it enters the vessel. By installinga tee in the running position in the line justahead of the heater/treater, installing anipple and valve pointed up, a 4-foot piece

E-9

of pipe, then a bell reducer on top with aquarter-inch bleed off valve, a surge tankthat also injects chemical is installed.

Method 2: From the tank battery. Someoperators bury a drum behind the tankbattery with only two inches of the topabove ground. Chemical can be poured intothe 2-inch opening, then the barrel filled bya small hose attached to the drain line. Thehose is small enough to reach the bottom ofthe drum to mix the chemical with the oil.

When the level in the drum is almost full,the tank valve is closed and the hoselowered to near the bottom of the drum. Byturning the circulating pump on, thischemically enriched mixture is sucked out ofthe drum and into the line to the tankbattery. The line to the drum is closed andthe tank drain opened long enough tocirculate the chemical into the heater/treater.The pump is then turned off so that thechemical will remain in the heater/treaterlong enough to give it a soak time treatment.

Giving the heater/treater a boost treatmentcan restore much of its treating ability whenit gets overloaded with BS&W. Thissituation occurs when there has been under-treating of the oil over a period of time,especially in the summer when the heat isturned off and the heater/treater is beingused as a three-phase separator or a gunbarrel. By discussing the problem with asupervisor, the lease pumper can probablyfind an economical solution that is possiblewith any battery line arrangement.

E2-5. Treating High Tank Bottoms byCirculating with Pump and Hoses.

Most tank batteries can develop high tankbattery bottoms that interfere with sellingoil. Sometimes circulating tank bottoms

regularly and after selling every tank is notenough. The bottoms build up and the tankof oil cannot be treated low enough.

The drain in a tank should have a lineinside that extends across the tank to alocation near the thief hatch. Otherwise,circulating creates a small clear area at theback while the front still has a 10 inchbottom.

Suitable portable circulating pumps. Theoperator must back the lease pumper’sactions in developing methods for oneperson to treat the bottom of the tanks. Thisis especially true when using a portablecirculating pump that must be moved frombattery to battery by hand loading it into thepickup. Skid pumps are too bulky andheavy. The unit with the 1½” centrifugalpump imounted directly on the motor can belifted with one hand. By placing a swageand union on each opening and a valve oneach hose with both unions facing towardthe pump, the hoses can be hooked up to thetank drain and a stinger line of 1" PVC stuckdown into the tank. By merely closing thetwo valves on the hoses and loosening theunions, the pump may be turned around topump in the opposite direction in a fewminutes.

Stirring high bottoms during treatment.When stirring bottoms during treatment, thelease pumper needs to place the addedchemical in the bottom of the tank at thefront, right into the emulsion. To stir a highbottom, the first thing to do is produce intothe tank long enough that at least 1-2 feet offresh oil is above the emulsion.

The second step is to stand a small PVCline up through the hatch. If the bottom ofthe PVC tube is cut at an angle, it will notseal against the bottom. A quart of chemical

E-10

can then be poured through a funnel into thetube. By placing chemical in severallocations, the chemical is in the bottom ofthe tank, right in the emulsion.With the pump hose connected to the PVC

and inlet pump hose fastened to the tankdrain line, the lease pumper can start thepump and inject the stream of oil directlyinto the bottom emulsion. By moving thebottom of the PVC to new areas and towardthe back of the tank, eight inches ofemulsion will grow by several inches as it isstirred. By stopping the engine and turning itaround occasionally, the emulsion is pulledfrom the front and injected into the back.The lease pumper can also send the oilthrough the heater/treater, and, if necessary,fire up the heater/treater to warm the oil. Ifonly a gun barrel is available with no heat,this vessel will also do a good job in mostsituations. If neither vessel is available, thelease pumper can treat it in both directions,shut it down, leave it, and then bleed off any

separated water the next day and do it again.This is a problem that must be addressedregularly in order to have clean bottoms.Clean bottoms are bottoms with no morethan 5 inches of BS&W.

When a high bottom is accumulated that isdifficult to treat, the lease pumper may haveto sell from the second tank until the first isclean. This may take several treatments withthe pump and the tube down the hatch.

Regardless of the volume of oil that isproduced, chemical is expensive, and oil canbe difficult to treat. After trying variousmethods to treat oil, each try becomes easier.

NOTE: Large volumes of chemicalintroduced into small volumes of BS&Wcan cause a condition known as burned oil.The oil is over-treated and cannot becorrected. The lease pumper must be carefulnot to burn oil when trying to treat bad tankbottoms.

F-i

APPENDIX F

MATHEMATICS

F - 1 Important Conversion FactorsF - 2 Lease Pumper Sample Math ProblemsF - 3 Belts And SheavesF - 4 Multiplication Table

F-ii

F-1

The Lease Pumper’s Handbook

Appendix FMathematics

Section 1

IMPORTANT CONVERSION FACTORS

A mathematical constant is a number that represents the relationship between one value andanother. Perhaps the best known of all constants is pi, often shown as the Greek letter p. Pi isthe relationship between the diameter of a circle and the distance around the outside of the circleor its circumference. The circumference of a circle is approximately 3.14 times its diameter, sopi is equal to 3.14. It does not matter how the circle is measured, the relationship between thecircumference and the diameter will always be 3.14:1. Thus, a circle with a diameter of 1 inchwill have a circumference of about 3.14 inches, while a circle with a diameter of 1 kilometer willhave a circumference of 3.14 kilometers.

Another common use of constants is to convert from one type of measurement system toanother. Because there are 12 inches in 1 foot, it is easy to determine that 108 inches total 9 feetby dividing by the constant 12. Constants can also be used to convert from one system ofmeasurement to another, such as converting between U.S. standard measurements and the metricsystem. For example, there are 39.37 inches in a meter. To convert 5.7 meters to inches, oneneed only multiply 5.7 by 39.37, while converting 144 inches to meters would require dividing144 by 39.37. This value is the constant relationship between inches and meters.

The table below provides a number of useful constants that can be used to convert from onetype of measurement to another, many of which have practical application for lease pumpers.

Multiply By To Obtain

Acres 43,560 Square feetAcres 4047 Square metersAcre feet 7758 BarrelsAcre feet 1233.5 Cubic metersAtmospheres 33.94 Feet of waterAtmospheres 29.92 Inches of mercuryAtmospheres 760 Inches of mercuryAtmospheres 14.7 Pounds per square inchBarrels 5.6146 Cubic feetBarrels 0.15898 Cubic metersBarrels 42 GallonsBarrels 158.9 LitersBarrels per hour 0.0936 Cubic feet per minuteBarrels per hour 0.700 Gallons per minuteBarrels per hour 2.695 Cubic inches per second

F-2

Barrels per day 0.02917 Gallons per minuteCentimeters 0.03281 FeetCentimeters 0.3937 InchesCentimeters of mercury 0.1934 Pounds per square inchCubic centimeters 0.06102 Cubic inchesCubic feet 0.1781 BarrelsCubic feet 7.4805 Gallons (U.S.)Cubic feet 28.32 LitersCubic feet 1728 Cubic inchesCubic feet 0.02832 Cubic metersCubic feet 0.03704 Cubic yardsCubic feet per minute 10.686 Barrels per hourCubic inches per second 28.8 Cubic inches per secondCubic feet per minute 7.481 Gallons per minuteCubic inches 0.00433 GallonsCubic inches 0.0164 LitersCubic meters 6.2897 BarrelsCubic meters 35.314 Cubic feetCubic meters 1.308 Cubic yardsCubic yards 4.8089 BarrelsCubic yards 27 Cubic feetCubic yards 0.7646 Cubic metersFeet 30.48 CentimetersFeet 0.3048 MetersFeet of water @ 60° F 0.4331 Pounds per square inchFeet per second 0.68182 Miles per hourFoot pounds per second 0.001818 HorsepowerGallons (U.S.) 0.02381 BarrelsGallons (U.S.) 0.1337 Cubic feetGallons (U.S.) 231 Cubic inchesGallons (U.S.) 3.785 LitersGallons (U.S.) 0.8327 Gallons (Imperial)Gallons per minute 1.429 Barrels per hourGallons per minute 0.1337 Cubic feet per minuteGallons per minute 34.286 Barrels per dayGrain (Avoirdupois) 0.0648 GramsGrains per gallon 17.118 Parts per millionGrains per gallon 142.86 Pounds per million gallonsGrains per gallon 0.01714 Grams per literGrams 15.432 GrainsGrams 0.03527 OuncesHectare 2.471 AcresHorsepower 550 Foot pounds per secondHorsepower 1.014 Horsepower (Metric)

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Horsepower 0.7457 KilowattsInches 2.54 CentimetersInches 0.08333 FeetInches of mercury 1.134 Feet of waterInches of mercury 0.4912 Pounds per square inchInches of water @ 60°F 0.0361 Pounds per square inchKilograms 1000 GramsKilometers 0.6214 MilesKilowatt 1.341 HorsepowerLiters 1000 Cubic centimetersLiters 61.02 Cubic InchesLiters 0.2642 GallonsLiters 1.0567 QuartsMeters 3.281 FeetMeters 1.094 YardsMiles 5280 FeetMiles 1.609 KilometersMiles per hour 1.4667 Feet per secondOunces (Avoirdupois) 437.5 GrainsOunces (Avoirdupois) 28.3495 GramsParts per million 0.05835 Grains per gallonPounds 7000 GrainsPounds per gallon 453.6 GramPounds per gallon 0.052 Pounds/sq. in/ft of depthPounds per square inch 2.309 Feet of water at 60°FPounds per square inch 2.0353 Inches of mercuryPounds per square inch 0.0703 Kilograms per square cmPounds per square inch 6.8947 KilopascalsQuarts 0.946 LitersSquare centimeters 0.1550 Square inchesSquare feet 0.0929 Square metersSquare kilometer 0.3861 Square milesSquare meters 10.76 Square feetSquare meters 1.196 Square yardsSquare miles 640 AcresSquare miles 2.590 Square kilometersTons (Long) 2240 PoundsTons (Metric) 2205 PoundsTons (Short or Net) 2000 Pounds

Temperature conversionsTemperature Centigrade = 5/9 (Temp. °F - 32)Temperature Fahrenheit = 9/5 (Temp. °C) + 32

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Volume Capacity of PipeGallons per 1000 feet = 40.8 x (I.D. in inches )2

Barrels per 1000 feet = 0.9714 x (I.D. in inches)2

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The Lease Pumper’s Handbook

Appendix FMathematics

Section 2

LEASE PUMPER SAMPLE MATH PROBLEMS

A lease pumper is frequently required to use mathematics in performing various dutiesassociated with the job. Some of these calculations include:

· Gauge tanks.· Daily production.· Oil sold.· Liquids hauled by transport.· Gas produced and sold.· Water produced and injected.· Rod strings pulled and run.· Tubing strings pulled and run.· Quantity of chemicals needed and injected.· Pipe transfers.· Production for well tests.· Percentages, ratios, and proportions in production and waste.· Convert fractions, decimals, and percentages.· Fill in time forms and other records.

Rules of Thumb

From the conversion constants given in Section 1, we find that multiplying the pounds per gallonby the constant 0.052 gives the pressure in pounds per square inch for each foot of depth. Thesevalues can be use to compute the bottom hole pressure based on various columns of liquid.

1. One foot of oil weighs approximately 1/3 pound. If the oil well has a standing column ofoil 3,000 feet high, bottom hole pressure holding the standing valve closed is 1,000pounds.

Example Problem # 1: 35 API gravity oil0.052 x 7.08 pounds per gallon x 3,000 feet = Bottom Hole Pressure of 1,104 pounds.This is 0.368 pounds per foot, which is close to .333 or 1/3 pounds per foot.

2. One foot of saturated salt water weighs approximately ½ pound. If the oil well has astanding column of salt water 3,000 feet high, the bottom hole pressure is 1,500 pounds.

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Example Problem # 2: 10 API gravity fresh water0.052 x 8.33 pounds per gallon x 3,000 feet = Bottom Hole Pressure of 1,300 pounds.Fresh water has a weight of 0.433 pounds per foot, a little under ½ pound per foot.

Example Problem # 3: Nearly saturated salt water weighing 9.4 pounds per gallon0.052 x 9.5 pounds per gallon x 3,000 feet = Bottom Hole Pressure of 1,482 pounds.This salt water has a bottom hole pressure of 0.494 or almost ½ pound per foot.

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The Lease Pumper’s Handbook

Appendix FMathematics

Section 3

BELTS AND SHEAVES

ABBREVIATIONS

D = Diameter of Pump Sheaved = Diameter of Prime Mover SheaveL = Belt LengthSPM = Strokes Per MinuteRPM = Revolutions Per Minute (of Prime Mover for these calculations)R = Pumping Unit Gear Box RatioC = Shaft Center Distance (Prime Mover to Shaft Center of Driven Equipment)

CALCULATIONS.

Use the appropriate formula to determine the unknown value. For example, use the formula

SPM = RPM x dR x D

to determine the number of strokes per minute if the diameters, center distance, and gear box ratioare known. The same formula can be used to determine how SPM will be affected if the pumpsheave diameter (D) is changed.

1. Calculating Belt Length, Full Formula

L = 2C + 1.57 (D + d) + (D - d)24 C

2. Calculating Belt Length, Short Formula (Note: This method is generally satisfactory foroilfield work.)

L = 2C + 1.57 (D + d)

3. To determine the required diameter of the pump sheave to the effect of changing the pumpsheave diameter

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D = RPM x dSPM x R

4. To determine the required diameter of the pump sheave to the effect of changing the pumpsheave diameter

d = SPM x R x DRPM

5. To determine the stokes per minute or the effect on strokes per minute if the RPM, diameters,or gear ratio is changed

SPM = RPM x dR x D

6. To determine the revolutions per minute or the effect on revolutions per minute if the SPM,diameters, or gear ratio is changed

RPM = SPM x R x Dd

7. To determine the gear ratio or the effect on gear ratio if the RPM, diameters, or SPM ischanged

R = RPM x dSPM x D

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The Lease Pumper’s Handbook

Appendix FMathematics

Section 3

Multiplication Table

1 2 3 4 5 6 7 8 9 10 11 12

1 1 2 3 4 5 6 7 8 9 10 11 12

2 2 4 6 8 10 12 14 16 18 20 22 24

3 3 6 9 12 15 18 21 24 27 30 33 36

4 4 8 12 16 20 24 28 32 36 40 44 48

5 5 10 15 20 25 30 35 40 45 50 55 60

6 6 12 18 24 30 36 42 48 54 60 66 72

7 7 14 21 28 35 42 49 56 63 70 77 84

8 8 16 24 32 40 48 56 64 72 80 88 96

9 9 18 27 36 45 54 63 72 81 90 99 108

10 10 20 30 40 50 60 70 80 90 100 110 120

11 11 22 33 44 55 66 77 88 99 110 121 132

12 12 24 36 48 60 72 84 96 108 120 132 144

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The Lease Pumper’s Handbook

GLOSSARY OF PRODUCTION TERMS

This glossary focuses on oilfield production terms. The meanings of most entries are limited toan explanation of the term’s use in oil and gas production and may not include all meanings ofthe word or words. Words found in basic dictionaries are not generally included. Someabbreviations are included.

Abandon. To cease production of a well or the use of a piece of equipment. Also see Plug andAbandon.Abrasion. Wearing away, scuffing, scarring, or scratching action on a surface that can lead topremature failure.Absolute Pressure (PSIA) The pressure of surrounding air; also referred to as ambient airpressure. The second type of pressure is Gauge Pressure (PSIG). See also atmosphericpressure.Absorption. The process of soaking up or holding a liquid, especially water.Accumulator Equipment that stores pressure that can be used to close a blowout preventer on awell in an emergency. Generally, the pressure of nitrogen or hydraulic fluid is used.Acetylene The combustible gas used in an oxygen-acetylene torch.Acid Fracturing. The injection of acid into a limestone formation in an effort to dissolvelimestone so that passages are formed through which oil and gas can enter the wellbore. Alsoreferred to as acidizing.ACT. Automatic Custody Transfer. See Lease Automatic Custody Transfer.Additive. Chemical blended into petroleum products, usually in small amounts, to achieve aspecific purpose.Adjustable Choke. A large needle valve used to control the flow of fluids, usually from aflowing well. The needle or dart of the stem may be opened or closed to change the rate of flow.Adsorption. The accumulation of molecules of gas or liquid on a solid surface in a condensedlayer.Aerobic. Occurring in the presence of oxygen, as in aerobic corrosion.Allocation. The amount of oil and gas that may be produced in a given period of time, usuallydaily and monthly. Similar in meaning to allowable.Allowable. The maximum amount of fluid that the oil regulatory agency allows to be producedin a given period of time, usually expressed as allocation or allowable per day. With stripperwells, the allowable is larger than the well is capable of producing.Alloy. A combination of two or more metals. In a ferrous alloy, such as steel, one of the metalsmust be iron. In a non-ferrous alloy, no iron is included.Ambient Temperature. The temperature of the surrounding air.Amine. A glycerin solution used in gas dehydration units.Anchor. A means of fastening guy lines to the ground. Four anchors are used to guy a wellservicing rig to stabilize the mast.Anaerobic. With atmospheric oxygen absent.

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Annulus. The space down hole in a well between the tubing and the casing. This may also bereferred to as the annular space.Anode. The positive element in a cathodic protection element from which electricity flows andcorrodes. May also be referred to as a sacrificial anode. Used extensively in heater/treaters toprotect against corrosion.AOSC. Association of Oil Well Servicing Contractors, located in Dallas, Texas.ANSI. American National Standards Institute.Antifreeze. An ethylene glycol compound mixed with water to prevent engine cooling systemsfrom freezing.API, American Petroleum Institute. Founded in 1920. Sets drilling and production standards.API Gravity See API Gravity Ratings in Appendix A.Apron Ring. The lowest ring of plates on a tank.Arc Welding. Process for joining two pieces of metal by passing an electric arc between themthrough a rod or continuous wire. The generated heat of the arc melts the rod and metal fusingthem together.Artificial Lift. Methods utilized to lift oil to the surface when bottom hole pressure is too low tocause the oil to flow. Lifting methods include 1) mechanical lift (the pumping unit), 2)centrifugal lift, 3) hydraulic lift, and 4) gas lift.ASME. American Society of Mechanical Engineers.Associated Gas. The natural gas cap that overlies and makes contact with crude oil in areservoir.Atmospheric Pressure. The pressure exerted by the air or atmosphere around us. At sea level,it is approximately 14.7 pounds per square inch but it decreases with increasing altitude. Apressure equal to 14.7 PSI may be referred to as one atmosphere. See also absolute pressure andgauge pressure.Atmospheric Vessels. Vessels that are designed to hold liquids but with a maximum pressure ofonly a few ounces.Atom. The smallest particle of matter and the basic unit of an element, such as oxygen (O), iron(Fe), etc.Back-off. To unscrew.Backpressure. The pressure caused by a restriction of the full flow of oil or gas.Backpressure Valve. A valve designed to regulate the pressure ahead of it. Backpressurevalves are utilized on outlet lines of all pressure vessels.Back-up. A wrench or chain tong utilized on the already tight side when making up connectionsof pipe.Baffles. Plates that control the flow of fluids inside vessels.Ball and Seat. The main parts of the valves in a plunger-type oil well pump.Barrel. The standard measurement in the U.S. oil industry. One barrel contains 42 gallons ofliquid and 5.6146 cubic feet and 0.15898 cubic meters of volume.Barrel Wrench. A friction wrench used in repairing oil well pumps. This special wrenchprevents damaging the barrel in disassembly and re-assembly.Battery. Means group of. A group of tanks and vessels is a tank battery. A group of wells canbe called a well battery, etc.Bbl. Abbreviation for barrel.

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BCPD. Barrels of condensate per day.BCPH. Barrels of condensate per hour.BDPD. Barrels of distillate per day.BDPH. Barrels of distillate per hour.Bean. A positive choke inserted into a line to regulate the flow of fluid from a well. Differentsizes of beans are used to produce different flow rates. Beans are generally measured in sixty-fourths of an inch.Bell Hole. A hole dug beneath a pipeline to provide room for tools or repair procedures. Thepipeline may be buried or on top of the ground.BF. Barrels of fluid.BHP. Bottom hole pressure.Bird Cage or Bird’s Nest. The spreading of the individual wire strands of the end of a wirerope in preparation for running a new rope socket made of babbit or lead.Black Magic. An oil-based drilling and workover fluid.Blank Flange or Blind Flange. A solid disk with bolt holes used to dead end a companionflange.Bleed-down or Bleed-off. To reduce pressure by cracking or throttling or barely opening avalve to release the pressure slowly.Bleeder or Bleeder Valve. The valve on the pumping tee of a pumping well used to checkpump action and to draw samples.Blow Down. The act of removing all pressure from a vessel or line, usually done prior toworking on the system.Blowout. An uncontrolled loss of pressure from a system.Blowout Preventer. A special type of valve installed to prevent a blowout on a drilling orworkover rig. A smaller version is used under a pumping stuffing box to assist in re-packing thebox while under pressure.Blg. Bailing.BO. Barrels of oil.Bob Tail. Any short truck or a truck with the trailer removed.Boilerhouse. The act of guessing at a gauge, pressure reading, etc. instead of observing it.Making up a false report showing work not physically done.Boll Weevil. A term applied to an inexperienced worker.Bolster. A swiveling rack placed on a pipe trailer and a truck bed that can swivel or spin toallow the truck to turn corners without placing the load in a bind.Bomb. Slang term for any tool that is lowered on a wire line to collect information, such astemperature or pressure.Bonnet. The part of a valve that contains the stem packing and the valve stem.Boomer, A load binder used to place tension on a chain to secure or tighten a load to betransported.Boot. A large tubular section of pipe on the side of a wash tank that permits the gas to separatefrom the liquid before the liquid flows down and into the bottom of the vessel. The boot isusually attached to the outside top edge of a tank, and a flume or conductor normally goes downthrough the center.BOP. Blowout preventer.

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BOPD. Barrels of oil per day.Bore. The inside diameter of a casing or an engine cylinder.Bottom-Hole Pressure. The pressure at the bottom of the well in pounds per square inch.Bottom Water. Water in a producing formation that is below the oil and gas in that formation.Bowl. The holding device that the slips fit into when supporting the tubing string in wellservicing.BPD. Barrels per day.BPH. Barrels per hour.Brass. An alloy of copper and zinc. The copper is usually 60% or greater.Bronze. An alloy of tin and copper. May also be referred to as brass.Break Out. To loosen or screw out a made up or tight joint in line pipe, tubing, or sucker rods.BS. Basic sediment. May also refer to BS&W.BS&W. Basic sediment and water.Buck Up. To tighten a thread or connection tight enough that it will not leak under pressure.Bull Headed. Referring to a tee connection in a system where the openings go to the right andthe left. Opposite of running.Bump Down, Bump Bottom, or Tap Bottom. To have a pump hit bottom on the downstrokebecause of excess rod length. Often set this way on purpose. Also refers to firmly seating thepump cups after going into the hole with a replacement pump. May also be done to try tostimulate a pump before pulling.BW. Barrels of water (D = day, H = hour, etc.).Cage. The part of the pump that holds the ball and seat to limit ball movement.Carbon Dioxide (CO2). A heavy poisonous gas that is injected into oil wells to stimulateenhanced recovery because it combines with and thins crude oil.Carbon Monoxide (CO). A heavy poisonous gas given off as a result of combustion in anengine.Cased Hole Completion. Method of finishing a well such that the casing is run all the waythrough the pay zone, then cemented, and perforated. This is the most common type ofcompletion.Casing. Heavy steel pipe that lines the hole. The fixed or cemented string in a well.Casinghead Gas or Oil Well Gas. Associated (from above) and dissolved gas produced alongwith crude oil from the well.Casing Pressure. Gas pressure built up between the casing and the tubing.Cast Iron. Iron made with a small amount of carbon (about 3%). By removing more of thecarbon and making the iron flexible, wrought iron is produced.Cat. A crawler-type tractor.Cathead. A spool-shaped attachment on a winch to which a rope is attached; utilized forhoisting and pulling loads.Cathode. The metal that does not corrode when corrosion occurs.Catline. A hoisting or pulling line operated from a cathead.Cat Walk. The narrow steel walkway near the top of a tank battery.Cat Walk Ladder. The steps leading up to the cat walk.

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Cellar. A hole, usually square, dug before drilling a well to allow working space for thecasinghead equipment and blowout preventer.Centrifugal Lift. The use of a liquid pump and electric motor located on the bottom of thetubing string with rotating stages (impellers and diffusers) above it to lift the liquid to thesurface. Also referred to as Electrical Submergible Pumping.Centrifuge. A shake-out or grind-out machine. Samples of oil in test tubes are placed in themachine and rotated at high speed to settle out BS&W.CFG. Cubic feet of gas.CFGPD. Cubic feet of gas per day.Chase Threads. To straighten and clean machined threads.Cheater. A short length of pipe used to increase the handle length and leverage of wrenches.Choke. A restriction through which the well is produced. A short drilled nipple is often referredto as a Flow Bean or a Positive Choke. An Adjustable Choke is a large, heavy duty NeedleValve that is measured in sixty-fourths of an inch openings.Christmas Tree. The wellhead on a flowing oil well consisting of a master gate, wing gate,and other fittings associated with the tubing. Casing valves are a part of the wellhead.Clean-out Plate, Manhole, or Manway. Various names given to entry openings into vessels.Clip. A U-bolt or similar device used to fasten two strands of a wire rope or cable together.Close Nipple. A very short nipple having threads over its entire length and even shorter than anall-thread. Cannot be used with fittings that have recessed threads or a stabbing bell.CO. Carbon monoxide.Collar or Coupling. Device threaded on the inside used to connect two threaded joints.Come-Along. A tightening device that crawls along a length of chain. Used for tightening guylines on a well servicing rig.Completion. The process of placing a drilled oil well into operation. It includes running thefinal string of casing, cementing it into place, perforating, running tubing, and any specialprocedure needed to prepare the well for production. May also include acidizing or fracing.Computer. A device capable of storing and supplying information, solving problems, andsupplying results from data. Examples are calculators, digital computers, and analog computers.Computer Control. A system where field devices such as switches, valves, gauges, alarms,shut-in devices, etc., are controlled by computerized devices.Computer Program. A procedure or routine for solving problems on a computer.Condensate. A fluid that leaves the formation as a vapor but condenses into a liquid in thetubing or within the surface processing. These liquids can be propane, butane, heavierhydrocarbons used in making gasoline, and may also contain some water. Also called distillateor natural gasoline. Distillate is highly used by refiners for jet fuel, kerosene, diesel fuel, orheating oil.Connate Water. Water contained within the producing formation when it was deposited.Connection. The joining of two or more fittings. Making a connection is a drilling term foradding another joint.Connections. Another term for fittings. See Fittings.Control Panel. Part of an electrical control system that controls the functions of the equipment.CO2. Carbon dioxide.Corrosion. An eating away by degrees of a material.

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Coupon. A small metal strip that may be held in a corrosive system to measure the nature andseverity of the corrosive action.CP. Casing pressure.CPSI. Casing pressure shut in.Crack a Valve. To open a valve a small amount. Oilfield valves are always opened slowly toprevent downstream damage caused by sudden shock before the control equipment has time toreact and normalize.Crater. Slang for equipment failure.Crude Oil. Liquid petroleum as it comes out of the ground. Crude oils range from very light(high in gasolines) to very heavy (high in residual oil). The fluid remains a liquid after pressureis removed.Csg. Casing.Cut Oil or Wet Oil. Oil that contains water.Dead Man. A piece of wood, steel, or concrete that is buried to attach a guy wire for bracing amast, tower, or piece of equipment. Acts as an anchor.Dead Oil. Oil that no longer contains light ends or gas.Dead Well. A well that will not flow.Depletion, A deduction allowed in computing the taxable income from oil and gas wells.Die. A tool used to make or clean male threads. Opposite of tap.Dike or Fire Wall or Escarpment. Earthen mound used to contain sludge from wells duringdrilling or to contain leaks from tanks or vessels.Discovery Well. A wildcat well that discovers or finds a new reservoir.Disposal Well or Injection Well. A well through which produced water is returned tosubsurface formations. A general term that does not indicate if the water is being used for waterflood.Dissolved Gas. Natural gas that is in solution with the crude oil in the formation.Distillate. A term used by refiners to refer to heavier condensates from gas wells that are calledjet fuel, kerosene, diesel fuel, or heating oil. Also used by many in reference to condensate.Dog House. A small building used for keeping lease records, changing clothes, and for generalsupply storage.Dog Leg. A bend in pipe usually to lift a meter higher for convenience. Can also apply to aditch or downhole deviation from absolute vertical in a well.Dope. A lubricant used on threads to promote easier and better make-up and to prevent gaulingof threads. There are many dope compounds for a variety of purposes.Double. Usually refers to two joints of pipe that are standing in the derrick or two sucker rodshung. This speeds up the process of pulling and running pipe.Doughnut. Slang expression for a tubing hanger or ring of wedges that supports a string of pipe.Downcomer. A pipe through which flow is downward.Dozer. A powered machine for earthwork. Short for bulldozer.Dresser Sleeve. A sleeve slid over the ends of two pieces of pipe to join them together to holdpressure without the need for threads.Drifter. A worker who never stays in one place very long.Drip. Small quantities of liquid that condenses out of natural gas. Very flammable anddangerous to handle.

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Dry or Lean Gas. Gas that has been produced without liquids or has been through treatingequipment to remove all or most liquids.Dry Hole. A well that does not find a commercial volume of oil or gas. Sometimes referred toas a duster.Dutchman. A piece of thread that has broken off inside a fitting that must be removed beforethe fitting can be used again.Electrical Submergible Pumping. Use of a centrifugal pump and electrical motor located at thebottom of the tubing string with rotating stages (impellers and diffusers) above it to lift the liquidto the surface.Electrochemical. Chemical changes associated with the flow of electrical current, as incorrosion.Electrolyte. A mixture of soil or liquids capable of conducting an electrical current.Emissions. Gases discharged as waste material.Embrittlement. The loss of strength in a metal losing caused by its absorption of gasses, such ascarbon dioxide or hydrogen sulfide. Stainless steel is used to replace some parts such as boltsand gaskets because it is impervious to embrittlement.Emulsion. The proper name for all of the elements and compounds produced from an oil wellusually in a fluid state. After this fluid goes through a separation process, it is then calledNaturalGas, Crude Oil, and Produced Water. This water is usually salty.Enhanced Recovery. The process of adding a force and chemical reaction into the reservoir tostimulate production and extend the life of the field and the amount of hydrocarbons produced.Et Al. Abbreviation for et alii which is Latin for and others. Used on signs where the ownersare too numerous to be listed.Farm Out. To share drilling rights on leased acreage.Fatigue. Failure of metal due to repeated loading or stress.Female Connection. A connection with internal threads.Fireflooding. The use of high volumes of air that are pumped underground to drive fire throughthe formation to aid in production. Also referred to as in-situ combustion.Fire Wall. A wall of earth built up around an oil tank or tanks to hold the oil in event of tankfailure.First Stage or Primary Recovery. The initial production produced from a well when nothing isadded back into the formation to stimulate future production.Fittings. All of the valves, nipples, tees, unions, ells, etc. used to make up a system of piping.Also called connections.Flange Up. To complete or finish a job.Float. A long flat-bed trailer used to haul oilfield equipment.Flood. A term used in enhanced recovery to indicate that a force is injected in an injection well,travels across the formation. and is produced back from other wells.Flow Line. The line that goes from the wellhead to the tank battery.Flow Splitter A large horizontal three-stage separator where the gas flows into the gas systemand the water, by use of an interface float, is diverted into the water disposal system. The flow ofoil by use of diverter weir gates can be diverted to several heater/treaters so that it can be sloweddown, heated, and treated prior to flowing to the stock tank.

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Flowing Well. A well that has enough bottom hole pressure to flow the fluid from theformation, to the surface and through the production facilities all the way to the tank battery.Fluid. Any substance that can easily change its shape to fit a container. This includes naturalgas, air, crude oil, water, drilling mud, etc.Fluid Level. Distance from the wellhead to the fluid level in the pipe. Because of thedifferences in diameter, it will be different in the tubing and in the casing.Flume. A large pipe that extends down into the center of a wash tank that permits the separationof gas and liquid before the liquid flows down and enters the wash tank at the bottom of thevessel. If the flume is mounted externally on the side of the vessel it is called a boot.Formation. See reservoir.Fracturing or Fracing. Process of opening up the underground formation in the reservoir bypumping in liquids under high pressure to increase the permeability of the formation. Sand maybe pumped in as a propping agent or acid to etch the formation to stimulate production.Frozen. Condition of components in which they will not operate freely, if they will move at all.Also a condition of lines where ice has formed on the inside from expanding gas and themoisture has turned to ice.Ft. Feet.G. Gas.G&O. Gas and oil.Gal. Gallon.Galvanize. To coat a metal with zinc to prevent corrosion.Gas Lift. A process of injecting natural gas into the column of fluid in the tubing string to causethe well to flow the production to the tank battery.Gas/Oil Ratio. The amount of gas produced for each barrel of oil.Gas Processing Plant. A plant strategically located in the oilfield to remove hydrocarbonliquids, primarily butane, propane, and heavy gasolines, before the gas is transported by pipelineto market.Gas Well. A well that produces natural gas. Condensate may also be produced and may be asclear as potable water.Gage. Alternate spelling of gauge.Gauge. Tool used for measuring daily production.Gauge Line. A tool used to measure the amount of fluid in a vessel.Gone to Water. Term applied to a well in which the water production has dramaticallyincreased and almost no oil is being produced.GOR. Gas/oil ratio.Gradient. Pressure drop.Gravity or API gravity. The API standard for measuring the density of a liquid. A specificgravity of 1.0 is equivalent to 10. Degrees API. See comparison chart located in Appendix A.

API gravity = _____141______ - 131.5specific gravity

Grease Book. Slang term for the lease pumper’s daily gauge book.Gun Barrel. Popular slang term for a wash tank, a large three-stage atmospheric separatorutilized to separate crude oil and water. Being large, the fluid goes through it slowly, allowingadditional time for separation.

G-9

Guy Wire or Guy Line. A cable or wire rope used to steady a mast or pole. The load guy linesupports the pulling load, and the wind guys protect the mast from winds.HCl. Hydrochloric acid.Handy. A connection or fitting that can be unscrewed by hand.Hard Hat. A plastic hat worn to protect the head from falling objects. Two styles are common.One has a bill in front while the other has a brim all the way around.Hatch or Thief Hatch. An opening in the top of a tank with a hatch that can be opened to gaugeor test the condition of the produced oil.Headache or Headache Rack. A steel frame mounted on a gin pole truck at the front of the bedto protect the cab when the poles are folded over and also to support the poles when down.Heater/Treater. A large three-stage separator with direct heat. The most common style is about20 feet tall and 6-8 feet in diameter. Most operators try to heat them only in the winter. Manyare pressurized but can be operated with atmospheric pressure.Holiday. A missed or skipped spot when painting or any action where full coverage isimportant.Horizontal Drilling. A procedure of turning the well hole horizontally and drilling a longdistance in the reservoir to increase the well’s potential production.Hot Oiler. A truck with a heating unit that can pump oil through it and heat it to melt paraffinand treat oil to clean it enough to be sold.Hot Tap. To tap a new line into an existing one while the line being tapped is under pressureand not shut it down while the new connection is being made.H2O. Water.H2S. Hydrogen sulfide.H2SO4. Sulfuric acid.HP. Hydrostatic pressure, also horsepower.Hpf. Holes per foot.Hydraulic Lift. A method of pumping oil or water down a well to operate a reciprocatinghydraulic pump to produce the well.Hydrocarbons. Any organic compound made up entirely of hydrogen and carbon. Often calledfossil fuels, it is produced as crude oil and natural gas.Hydrogen Sulfide (H2S). A deadly gas that occurs naturally in crude oil. Has the odor of rotteneggs and can kill quickly in many situations. Heavier than air and settles.Infield Drilling. Drilling in an area that has near-by production.In Situ Combustion. Burning a portion of a reservoir underground with fire to produce hotgases to drive oil to the producing well.Injection Well. A well used to pump fluids underground. It may be a disposal well in a neutralzone to get rid of produced water or in a producing zone to inject gas for pressure maintenance orwater for water flood.Insulating Flange or Union. A flange that contains plastic bolt sleeves, washers, and gasket toinsulate the two halves to break the possibility of electrical current flowing through the pipe.Other styles are available. This is done as a form of cathodic protection.Ion. Electrically charged particle, atom, or radical.Iron. A naturally occurring element. After being processed with one or more metals, it isformed into steel.

G-10

Joint Venture. Arrangement in which two or more parties join together in a petroleum venture.Jack or Pipe Jack. A short slender pipe with short projections to one side and a bottom plate. Itis utilized to support a joint of pipe while it is being made up.Joint. One full length of pipe. This is usually twenty five to thirty two feet.Junk. Equipment or materials that have been retired from service. Occasionally a piece of junkcannot be re-used but has a high salvage value and is not to be confused with scrap, which justhas a weight value. Parts from a junked pumping unit may be used to repair several other similarunits as the need arises.KB Kelly bushing. Point from which drilling measurements are made when measuringdownhole.KCl Potassium chloride. Used in fresh water to prevent formation hydration (swelling) informations that contain shale. Shale is clay that has been compressed until it becomes rock.Kill a Well. Process in which water or oil is pumped down a well in preparation for working itover or making a change in the hook-up. This procedure is carefully calculated to preventdamaging the formation.LACT. See Lease Automatic Custody Transfer.Lead Time. Planning time set aside before a project begins.Lean or Dry Gas. Dry gas from a gas well or gas that has been treated to remove most of theliquids.Lease Automatic Custody Transfer or LACT unit. When oil is sold to a pipeline company, itmay go through a LACT unit to measure the number of barrels, and a sampler aids indetermining gravity, temperature, and BS&W. After the crude oil goes through the backpressurevalve, ownership of the oil is transferred from the production company to the pipeline company.Liquid. State of matter in which a substance fits the shape of its container but its volumeremains almost constant and is not greatly influenced by pressure.Live Oil. Crude oil that still contains light ends and natural gas.Load Binder. Chain or cable used to tie down a load of equipment on a float .Location. The site at which a well is to be or already has been drilled. Normal spacing formedium depth wells is one per forty acres or sixteen per section. There will be more shallowwells per square mile and fewer deep wells.Loop. A circle of pipe placed in a line to absorb changes in the length such as contraction incold weather and expansion in hot weather.LPG or Liquefied Petroleum Gas. Butane, propane, or a mixture of these two fuels.Lubricator. 1. A swab tool holder that is set on top of a well during swabbing. 2. An oilerused to lubricate pistons in a gas compressor or single cylinder horizontal engine.Make a Hand. To be a good, dependable worker.Male Connection. Connection with external threads.Manway, Manhole, or Clean-out Plate. Various names for entry plates into vessels.Marginal Well. An oil or gas well where the production is so limited in relation to productioncosts that the profit is approaching the vanishing point.Master Gate. A large vertical tubing valve on the Christmas tree that is full opening (tools canbe run through it) and can be closed in emergencies. High-pressure gas wells normally have twomaster gates, one mounted directly on top of the other.MCF. Thousand cubic feet.

G-11

Misc. Miscellaneous.Miscible Flood. An enhanced oil recovery procedure involving the injection of solvent followedby a displacing fluid, usually water.MMCF. Million cubic feet.MCFGPD. Thousand cubic feet of gas per day.MI&RU. Move in and rig up. A drilling rig and well servicing abbreviation to explain rigexpense.Multiple Completion. A method in which the well is completed to provide the capability ofproducing hydrocarbons from two, three, or even four different zones at the same time.NaCl. Sodium chloride or salt.Natural Gas. Consists largely of the hydrocarbon methane. Occurs naturally in undergroundreservoirs and is the cleanest burning of all fossil fuels.Nipple. A short piece of threaded pipe. Available in two inch increments up to twelve incheslong. May be seamed or seamless, and low, medium, or high pressure.Non-associated Gas. Natural gas that while in the reservoirs does not contain a significantamount of crude oil.O. Oil.O&G. Oil and gas.Octane Number. A rating of a gasoline’s ability to burn without abnormal knocking. Theoctane number is the percentage of isooctane in the fuel blend.Off Production. A term used to describe the condition of a well that has a production problemor is temporarily shut in for many reasons. Opposite of on production.Offset Well. Well drilled on the next location near another one.Oil. A compound composed of hydrogen and carbon. See also crude oil.Oil Well. A well completed for the purpose of producing hydrocarbons from an undergroundreservoir.Oil Shale. Shale deposits that contain oil. The United States owns huge oil shale depositsprimarily in Colorado, Utah, and Wyoming. The oil is difficult to extract.Old Hand. Someone who is highly experienced at what is being done.On the Line. A term used to describe a stock tank while oil is being sold out of it. It is notuncommon for it to be “on the line” for several days when the gauger does not come every day.On the Pump. A term for a well that has a pumping unit on it.OPEC (Organization of Petroleum Exporting Countries). An association of some theworld’s largest oil producing and exporting countries.Open Hole Completion. Un-cased portion of the hole. The bottom end of the casing stops justabove the oil in the impervious zone and is cemented. The pay zone is then drilled and left asopen hole.Oxidation. Condition of a substance combining chemically with oxygen to form an oxide, orelectrochemically, as the loss of electrons at the anode of a corrosive cell.Parting. Breaking, such as “the rod string parting” (a rod breaking)Pay Zone. The down hole reservoir from which the oil and/or gas is being produced.Permeability. The ability of the reservoir rock to transmit fluid through the porous spaces.This regulates the ability of fluids to move through the reservoir. The rock is impermeable ifthere is no communication between pores. Not to be confused with porosity.

G-12

pH. A symbol used to express the concentration of the hydrogen ion in a solution, such asacidity (0 to 7), or the alkalinity (7 to 14.7). Declining numbers less than 7 indicate increasingacidity, and numbers increasing above 7 indicate increasing alkalinity, with 7 being neutral. pH6 means a concentration of 10-6, 0.000001 and indicates slight acidity.Pig. A scraping tool run through a line to clean out paraffin or other deposits. A rabbit checksthe clearance to see if it is still round, although it will also check for obstructions.Pipe. A general term that includes all forms and classes of pipe. It includes line pipe, tubing,and casing.Pipeline. A transportation system for moving oil and gas from the field to a refinery, although itis also a general word used in referring to many other types of line.Pipeline Oil. Oil clean enough to be sold. This is usually no more than one percent BS&W.Pit or Slush Pit or Overflow Pit. An earth pit with dikes around it, usually rectangular orsquare, with a plastic liner and a net cover.Pit. A depression or the eating away of a metal part caused by corrosion.Plug and Abandon. To stop producing a well, plug the depleted formation, and salvage all pipe,materials, and equipment possible.Plug Back. To shut off the lower formation in a well bore, usually to reduce water production.Polarize. To reduce or retard an electrochemical corrosion reaction by deposition of a corrosionproduct.Polymer. A compound formed by linking one molecule with another to form a very long chain.A process used extensively in enhanced flood recovery.Poor Boy. Descriptive term for any homemade or shop-made substitute or practice usually doneto save money.Plunger Lift. A method of lifting oil to the surface by a plunger and bottom hole gas pressure.Porosity. The percentage that the volume of pore space bears to the total bulk volume. Thisdetermines the amount of space available for the storage of fluids.Positive Choke. A choke with a hole drilled through it to flow the produced fluid through. It isnot adjustable. To change the flow rate, the positive choke must be replaced.Potential Test. A test to determine the maximum rate at which a well can produce oil.Continuous production at this rate may cause serious problems with the well.Power Oil Tank. A tank added into the tank battery system just ahead of the stock tank tosupply oil to be utilized downhole in a hydraulic lift system. In other applications where water isused, this vessel will be located just ahead of the water disposal system to supply water.Ppm. Parts per million.Pressure Maintenance. Injecting gas back into the reservoir to maintain reservoir pressure topush new oil to other wells to be produced.Pressure Regulator. A regulator utilized to control the pressure downstream or after theregulator.Pressure Relief Valve. An automatically opening valve utilized to limit the pressure that can beplaced inside a vessel.Primary or First Stage Recovery. The initial production produced from a well where nothing isadded back into the formation to stimulate future production.Production. The amount of oil, gas, and water produced, or a company that owns oil and/or gasproducing wells and produces oil and/or gas.

G-13

Productivity Test. Producing a well at several different rates or ways to determine the bestmethod of producing the well.Prorationing. Regulating oil and/or gas production to maximize productionPSI. Pounds per square inch.PSIA. Pounds per square inch absolute.PSIG. Pounds per square inch gauge.Pump Off. To pump a well too long or too rapidly so that the liquid level in the well bore orcasing is lowered to the level of the standing valve in the pump.Put on Pump. To install a pumping unit, and all necessary equipment to pump a well.Qts. Quarts.Rabbit. A device run through pipe to check if it is still round or partially plugged, such as casingand tubing before it is run in the hole. A pig is a line cleaner.RB. Rotary bushing.Refining. The manufacture of petroleum products from crude oil by a series of processes intomajor finished products as well as supporting a wide petrochemical industry.Remote Control. A control placed in the field to control and regulate operations in the field.May be changed by remote signal from the office.Reserves. Estimate of already located oil and gas still in the formation that may be produced.Reservoir. An underground formation where oil and gas have accumulated.Reservoir Pressure. The pressure on the well after the well has been shut in for twenty-fourhours.Rich or Wet Gas. Natural gas that contains liquid hydrocarbons in vapor form as produced froman oil or gas well.Riser. A pipe through which fluid moves upward when moving through it.Rock a Well. To alternately remove pressure off the casing and tubing of a well to stimulate itto flow again by itself. The alternate procedure might be to call a swabbing unit.Rod Job. Process of pulling and running rods.Rod. A general term for rods used to pump an oil well, including steel and fiberglass.Round Trip. Act of pulling and running rods or tubing.Running. Making up a tee in a system where one opening points to a side and the othercontinues straight ahead.S. An abbreviation used on fittings to indicate approval for use with steam.Sand Fracture. The injection of oil and sand or water and sand into the well under highpressure to open up the formation to allow the well to produce more hydrocarbons. It may alsobe used in injection wells in order to increase the injection rate or lower the injection pressure.Sanded Up. Condition in which sand has accumulated in the casing of a producing well causingthe tubing or pump to stick in the hole. Sand enters with the produced emulsion but falls to thebottom.Scrap. Material retired from service that has a weight-only value. Not to be confused with junk,which may have a high salvage value.Scraper. A device run in a well on a wire line to check the hole clearance prior to running apacker. It is also the name for a tool used to remove scale or salt bridging.SD. Shut down.SDR. Shut down for repairs.

G-14

Seamless. A term describing pipe made with an extrusion process where the pipe is not welded.Pipe is sold as seamed or seamless. Cheaper pipe is rolled round and parent material welded.Secondary Recovery or Second Stage Recovery. Production in which force is added to theformation. Water flood and pressure maintenance are classified as second stage recovery.Scale. A deposit on a metal. Scale is usually deposited out of water. Often referred to as gyp.Seismic Exploration. Method of prospecting for oil and gas by sending shock or other wavesdown into the earth. A geophone captures these reflections and computers aid in analysis.Separator. A pressurized vessel whose purpose is to separate gas from liquids at the tankbattery.Separator, Two Stage. A separator designed to divide the incoming emulsion. The gas will goout the top, while the oil and water is still combined and the liquid is dumped through a floatcontrolled valve to the next vessel in the system.Separator, Three Stage. A separator designed to separate the emulsion into gas out the top,water into a line off the bottom, and the oil leaving the vessel through the oil line.Shake-Out. A centrifuge that rotates at high speed to settle BS&W to the bottom of the testtube.Sharpshooter. A long, narrow shovel.Sheave. A grooved pulley. May have one to eight or more grooves and belts.Shut In. A well that can produce oil, but the valves are closed. May be shut in for manyreasons.Shut in Pressure. Pressure taken after well has been shut in for twenty-four hours to reachmaximum.SI. Shut in.SIBHP. Shut in for bottom hole pressure test.SICP. Shut in casing pressure.SITP. Shut in tubing pressure.SIP. Shut in pressure.Slack Off. To lower a load or ease up on the tension on a line.Sling. A wire rope loop used to lift heavy loads.Slips. Wedge-shaped toothed pieces of metal that fit inside a bowl and are used to support drillpipe, tubing, or fished broken sucker rods.Slop Tank. A vessel installed to hold very difficult-to-treat oil for a longer period of time whilethe majority of the oil is being sold. Careful utilization of a slop tank can dramatically reducetreating costs without slowing down sales or risk filling the tank battery with oil that cannot besold.Slush Pit, or Pit, or Overflow Pit See pit.Snatch Block. A sheave or pulley where one side can be opened up so a wire line can beinserted.Soft Rope. A three- or four-foot piece of large rope cut off. The small strands are unwoundindividually and utilized to tie many things. These individual strands are called soft rope.Sour and Sweet Crude Oil. Sour crudes usually have more than one percent sulfur and sweetcrudes has less. The sweeter crudes are more valuable.Sour Gas. Gas that contains impurities such as sulfur or hydrogen sulfide.SPE. Society of Petroleum Engineers.

G-15

Skimmer Tank. A tank designed to allow water to flow through it but to skim off any oil thatenters to be retained and added back into the produced oil. Works very similarly to the gunbarrel or wash tank except it is utilized to reclaim very small amounts of oil that would otherwisebe lost into the water disposal system.Spacing. Refers to the number of acres designated for each oil well, such as twenty-acrespacing.Spaghetti. A very small tubing string.Spalling. Condition in which metal breaks up, chips, or flakes away.Specific Gravity. See API reference chart in Appendix A.Stabilized. Condition in which a well is considered has produced long enough that it continuesto produce the same amount in a given period of time, usually one day.Steel. A metal alloy of two or more metals, one of which must be ironStorage Tank. Any tank capable of holding liquids. The word storage is not specific and canbe used in reference to oil, water, or workover mud.Strike Plate. An extra plate of metal attached to the bottom of a tank under the thief hatch toprevent damage to the bottom tank plate caused by the plumb bob on the end of a gauger’s gaugeline.Strip a Well or Stripping Job. Pulling the rods and tubing at the same time.Stripper Well. A well that strips the remaining oil from a reservoir. Efficient operations andconservative lease pumping practices can keep thousands of low-volume wells in profitableoperation. These wells contribute a large percentage of U.S. crude production.Strap aTank. To measure a tank for the purpose of making a chart that shows the tank volumeevery quarter of an inch. This is usually done by the oil purchaser.Submersible Pumping. Procedure in which a pump is installed below the liquid level in a well.The electric motor is on bottom and rotates fluid cups above it to lift the liquid. This manualrefers to this type of pumping as centrifugal lift.Swab. To drop a swabbing tool down the tubing and pull a column of oil to the surface.Swamper. A helper on a truck.Swb. Swabbed.Sweet Crude. Oil that contains no sour impurities.T/ TopTail Chain. 1. A chain put on the end of a rope on a drilling rig used to spin pipe. 2. A chainput on gin poles at the back of the truck and tightened so that the poles cannot fold over on theheadache post.Tailboard. The back edge of the bed of a bob tail truck. It may be rolling (free to roll whilewinching) or welded solid.Tail out Rods. To pull the bottom of a rod out or tail them out when laying them down on arack, or tail them back in when running rods that have been laid down.Take a Strain On. To lift a heavy or awkward load on a wire line gently.Tally. The act of measuring pipe, usually in increments of one hundredth of a foot.Tank. A vessel designed to hold liquid. May be rectangular or round, horizontal or vertical.Tank Battery. A series of vessels and connecting lines designed to separate oil, water, and gas,and flow it into the correct vessel or line destination. A tank battery usually has tanks, but inhigh volume, clean oil may not use any vessels.

G-16

Tanker. An ocean-going ship designed to haul crude oil in bulk from a producing area to arefinery.Tap. 1. To strike lightly. 2. A tool used to cut or clean female threads. Opposite of die.Tap Bottom or Bump Bottom. To allow the pump to hit bottom with each stroke of thepumping unit. Often done deliberately on shallow wells or when trying to stimulate a well thathas stopped producing oil before pulling.Tar Sand. Rock impregnated with tar or heavy crude that cannot be recovered by ordinaryproduction methods.Tbg. Tubing.Telecommunications. The transmission of signals over long distances, such as radio.Telemetry. Use of radio or other methods to transmit field measurements over a distance.Tertiary or Third Stage Recovery. Final oil recovery requiring two or more forces such astemperature and pressure, or chemical and pressure.Thief. A tool utilized to secure liquid samples from the top, center, or the bottom of a tank.Thief Hatch. An opening on the top of a tank with a hatch that can be opened to gauge or test thecondition of the produced oil.Third Stage Recovery, or Tertiary Recovery. Final oil recovery requiring two or more forcessuch as temperature and pressure, or chemical and pressure.Thread Protector. A steel or plastic cover to screw on threads while the pipe is in storage.Tie Down. Secure a load to be hauled prior to moving the vehicle.Tong. A form-fitting wrench used to back up, or make up pipe. Form fitting to prevent egging orcrushing the pipe. Used on the rig floor and in pipe laying tools.TP. Test Pressure.Trip. The action of pulling or running rods or tubing. Pulling and running is called a round trip.Triple. Refers to three joints of pipe stood up in the derrick or three rods hung up together. Thisspeeds up the process of pulling and running rods and pipe.Tubing. Random length upset pipe that is moveable in a well. Fluids are produced through it andit can be pulled when working the well over.Tubing Job. The pulling and running of tubing.Unitize. To produce from a reservoir so that one company operates every well in a pay zonealthough it does not own all of them. The income is prorated according to percentage of unitsowned.Vacuum Truck. A truck with a low-pressure pump that operates with a large diaphragm and areciprocating motion. Can pump thick emulsified oil containing scale and small solid objects.Vapor. A gas that can be compressed into a liquid.Viscosity. The thickness of an oil and the rate that it will pour.Warm Up or Heat Up a Connection. To apply slight heat or pressure, such as a hammer blow,to a connection that is difficult to loosen.Wash Tank or Gun Barrel. A large three-stage atmospheric separator utilized to separate crudeoil and water. Because the tank is large, the fluid goes through it slowly to give it additional timeto separate.Water Disposal Tank. A tank in a battery to receive any produced water.Waterflood. Process of injecting water into an injection well and recovering it from another well.

G-17

Water Leg. A line coming off the tank near the bottom of a vessel that regulates how much oil isretained in the gun barrel or heater/treater.Well. A general term for all petroleum producing wells, but can also include water and injectionwells.Wet or Rich Gas. Natural gas just as it was produced from an oil or gas well, which contains wethydrocarbon vapors.Widow Maker. Any condition or act that is liable to cause death or serious injury to a worker.Wicker. A broken strand of wire on a wire rope. Often common on winch lines.Wildcat. An exploratory well drilled in an area where no previous production is present. Usuallyfive miles or more from producing wells.Winch or Gin-Pole Truck. A bob tail truck with a winch. Medium size winch trucks may havetwo winches, and a large one may even have three.Wiper. A rubber ring or device for wiping rods and tubing clean on the outside while pulling.Wireline. A small diameter wire line used to lower a wide assortment of downhole tools into awell for performing many functions, such as surveys. A general term for downhole lines.Wire Rope. A steel cable composed of steel wires wrapped around a central core to create a lineof great strength and flexibility.Wing Gate. The horizontal gate valve on a Christmas tree. The well is usually controlled fromthis valve, and the master gate is available upon need.WOC. Waiting on cement, a drilling term used for the time spent waiting for cement to set or gethard before resuming the drilling or completion operations.WOG. Water, oil, gas. (Stamped on some fittings)Working Pressure. The pressure at which a piece of equipment is designed to work.Work Over. To solve a downhole problem on a well that is more difficult than basic wellservicing.Wtr. Water.WSP. Working steam pressure. (Stamped on some fittings).Yield Point. The maximum stretch or pull that can be placed on metal and still have it return toits original shape. Used extensively in well servicing, especially when pulling rods.Zone. The downhole area that the well is being produced from. Referred to as pay zone.

G-18

I-1

INDEX

Instructions for Using Index.

CHAPTERS.The beginning number refers to the chapter. The letter that follows identifies the section. Thenumber after the dash refers to the page within that section on which the information begins. Forexample, an entry of 3C-2 indicates that the topic begins on Chapter 3, Section C, Page 2. Theinformation may be continued on following pages.

APPENDIXES.If the topic location begins with a letter, then the reference is located in an appendix. The letterrepresents the appendix and the number tells the page within that appendix on which the topicdiscussion begins. For example, A-9 indicates that the information is located in Appendix A,and is found on page 9.

Air compressors, 11C-2 to 11C-3Air packs, 3B-4 to 3B-6Alcohol, use of, 1A-4Allowables, 5A-1 to 5A-2Alternate day gauging, 12B-5Analyzing daily production, 12C-1 to 12C-5Antifreeze, engines, 11B-5Atmospheric vessels, 10C-1 to 10C-7BLM (Bureau of Land Management), 1B-7Basic sediment & water (BS&W), 10A-3Beam gas compressors, 15B-3Belts, V-Belt, B-16 to B-19Carbon dioxide flood, 15D-2Casing, 4B-3 to 4B-5, 4C-1, D-3

perforations, 4C-1, 17C-1Cathodic protection, 16B-2, 16B-4Centrifugal lift (See also Electrical Submersible Lift), 7A-1 to 7B-2Chemicals,

batch treatment of oil, 13C-4expense, 1B-5injection, 13C-1 to 13C-5treating oil, 13C-1 to 13C-5purpose of chemicals, 13C-1

Chemical pumps, description, E-1 to E-5Christmas tree,

gas wells, 18A-1 to 18A-3Circulating pumps, (See Tank Battery), 10F-5Communications, 1B-1 to 1B-3, 2A-2 to 2A-3

I-2

Company policies, 1A-2 to 1A-6Condensate, 18A-1Contact towers, 18C-2Commingling different pay zones, 12D-3 to 12D-5Corrosion, 16A-1 to 16B-4

at the tank battery, 16B-4 to 16B-5downhole, 16B-3protection, 16B-1 to 16B-5

Daily gauge book (grease book), 19A-4Daily well tests, 14B-2 to 14B-6Dead weight tester, 14D-2Diesel engines, 11B-5Distillate, 18A-1Drilling, an overview, 4A-1 to 4A-5, 4B-1 to 4B-8

cased and open hole completions, 4C-1downhole measurements, 4B-2drilling problems and rods, 4B-6 to 4B-8drillstem tests and drilling breaks, 4B-5horizontal, 15D-2intermediate and tapered strings, 4B-5new wells, 4B-1perforation and completion, 4C-1 to 4C-4records, 19B-1surface string of casing, 4B-4the oil string, 4B-5

Drilling personnel, 4B-1 to 4B-2Drugs, use of, 1A-4,Drum measurements, A-6Electrical submersible pumps, 7A-1 to 7B-2

installation, 7A–3operation, 7B-1to 7B-2

Electrochemical corrosion, 16A-3Electrical

motors, 11A-4peak load requirements, 11A-5

Electricity, 11A-1 to 11-5AC and DC, 11A-5control boxes, 11A-2 to 11A-3lease electrical system, 11A-1 to 11A-2cycles and volts, worldwide, 11A-5safety, 11A-4

Emergency communications, 2B-1Emergency telephone numbers, 2B-2Employee,

I-3

honesty, 1A-4benefits, 1A-2 to 1A-5

Engines, 11B-1, to 11B-6antifreeze, 11B-4gas logs and scrubbers, 11B-5oils and gasoline, 11B-3 to 11B-4two and four cycles, 11B-1

Enhanced recovery, 15A-1 to 15D-4Eye wash stations, 3A-6First stage recovery, 15A-1 to 15A-5Flora and fauna (plants and animals), 2C-4Firearms, carrying them to work, 1C-5Flood, 15C-1Flow lines, 10A-6, 10B-1 to 10B-2Flowing wells, 5A-1 to 5A-8

testing, 14A-1variable and positive chokes, 5A-5 to 5A-7wellheads, 5A-2 to 5A-4

Fracing and acidizing wells, 17E-4Fresh air packs, 3B-4 to 3B-6Gas injection, 15C-3 to 15C-4Gas lift, 9A-1 to 9C-2

conventional mandrels, 9B-1 to 9B-3continuous and intermittent flow, 9C-1 to 9C-2introduction, 9A-1kickover pulling tool, A-5kickover running tool diagrams, A-4side pocket mandrels, 9C-1 to 9C-2system, 9A-3 to 9A-4

Gas, natural,compression, 18D-1dehydration units, 18C-1pipelines, 18D-2treating, 18D-2wells, (See also Gas wells), 18A-1 to 18A-3well safety valves, 18A-3

Gas/oil ratio test, 14B-5Gas well separators,

3 stage horizontal, 18-B-13 stage vertical, 18B-2 to 18B-3

Gas wells, 18A-1 to 18A-3condensate, 18A-1distillate, 18A-1drip pots, 18D-3

I-4

logs and scrubbers, engine, 11B-5safety valves, 18A-2 to 18a-3testing, 18D-2wellheads, 18A-1 to 10A-3

Gas well tank batteries, 18C-4Gauge line, 12B-2 to 12B-3Gauger communications, 13D-2

note jar, 13D-2Gauges and gauge calibration, 14D1 to 14D-3

dead weight tester, 14D-2Gauging daily production, 12B-4Glycol pumps, 18C-2Government agencies, 1B-7Grease book (daily gauge book), 19A-2Gun barrel, 10C-4H2S (See Hydrogen sulfide)Heater/treater, 10B-7 to 10B-9

pressure control valves, 10B-8 to 10B-9Holddowns, 6D-3, 17C-4Horizontal drilling, 15D-2Hydraulic lift, 8A-1 to 8C-3

central power, 8C-1 to 8C-3designing system, 8A-2free pump, 8A-3jet pump, 8A-3 to 8A-4one well system, 8B-1 to 8B-2

Hydrogen sulfide, 3B-1 to 3B-4Individual well tester, 12D-1Insert oil pumps, downhole, 6D-3Kelly bushing measurement, 4B-3Kimray valves, 10B-8 to 10B-9Kolor Kut, 12B-3LACT unit, selling oil, 13D-4Landowner relations, 2C-1Lease

driving to, 2A-1principal meridian, 2A-3

Lease,offices, 2C-8operating expense, 1B-5vehicle, 2A-1 to 2A-3supply expense, 1B-5chemical expense, 1B-5

Lease maintenance, 2C-4 to 2C-8

I-5

cattleguards, 2C-5fences, 2C-5lease pumper maintenance duties, 12E-1 to 12E-3maintenance, 2C-4 to 2C-8pits, 2D-7roads, 2A-2signs, 3A-3 to 3A-5vista and trash accumulation, 2C-6

Lease pumperalcohol, use of, 1A-4carrying firearms to work, 1A-5carrying unauthorized persons in the vehicle, 2A-2day on the lease, 12A-1 to 12A-4dressed for work, 1B-1 to 1B-2drugs, use of, 1A-4good lease pumper, 12A-1job duties, 1A-1lunch time, 1A-2maintenance duties, 12E-1 to 12E-3planning activities, 12A-2 to 12A-4safety equipment, personal, 1B-1 to 1B-2, 3A5-5 to 3A-6schedule of activities, 12A-2 to 12A-4taking unnecessary chances, 3A-2work hours and responsibility, 1A-1 to 1A-2, 2A-3working for more than one operator, 12D-5

Livestock injuries, 2C-2 to 2C-3Lubricators, polished rod, 6C-4Materials transfers, 19C-4 to 19C-5Mechanical lift (See also Pumping units)

overview, 6A-1 to 6A-4how pumping units operate, 6A-2 to 6A-4pump cycles, 6B-2wellheads, 6C-1 to 6C-6

Mineral rights, 2C-1Miscible flood, 15D-1 to 15D-2Natural gas (See Gas, natural)Not enough production, 12C-1 to 12C-4Oil

API gravity, 13A-4 to 13A-5batch chemical treatment, 13C-4hot oiler, 13C-4methods of treating, 13B-1 to 13B-4, 13C1 to 13C-6selling, 13D-1 to 13D-6testing, 13A-1 to 13A-4

I-6

treating, 13A-1 to 13A-2Oil sales system, 10G-1 to 10G-4Oil storage (See also Tank batteries)

temporary storage tanks, 10A-1 to 10A-6Oil well, an overview, 4A-1 to 4A-3, 4B-1 to 4B-5

casing or well heads, 4B-3 to 4B-5hot oiler, 13C-4production curves, 10A-2production from well, 10A-4production records, 19C1 to 19C-6treating chemicals, 13C-1tubing string, 4C-2 to 4C-4

OSHA (Occupational Safety and Health Act), 1B-7Oxygen corrosion, 16A-3Packers, 4B-3, 5A-4, 17C-4Perforations, raising, lowering, and orientation, 15B-4Pickup,

driving habits, 2A-1expense, 2A-1personal use, 2A-1when the vehicle has problems, 2B-1tools, 1B-4

Pipe storage, 19D-2 to 19D-4sizes, D-2upset tubing sizes, D-2

Plunger lift, 5B-1 to 5B-6wellhead arrangements, 5B-2 to 5B-6

Pony rods (See Rods)Potential well tests, 14B-2Pressure maintenance, 15B-3Pressure surveys, well, 14C-1Primary recovery, 15B-1 to 15B-5Principal meridian, 2A-3Productivity testing, 14B-3 to 14b-4PSIA and PSIG, 11C-2Pulling units (See Well servicing units)Pup joints (See Tubing)Pumper, contract services, 1A-3Pumping units (See also Mechanical lift)

belts and sheaves, B-16 to B-20changing adjustments, B-11 to B-15electric and natural gas prime movers, 6B-1historical development, B-1maintenance and servicing, 6B-3 to 6B-6

I-7

setting and assembly, B-6 to B-10sizes and styles, B-1 to B-5wellheads, 6C-1 to 6C-2

Pumps, downhole oil, 6D-1 to 6D-5abbreviations, A-1API sizes, A-2designations, A-1downhole pump problems, 17B-8

Pumping wells, testing, 14A-4Records, 19A-1 to 19D-7

drilling, pipe, and servicing, 19B-1 to 19B-4lease records book, 19A-1 to 19A-2materials transfers, 19D-1 to 19D-6production, 19C-1 to 19C-6

Recordkeeping, 19A-1 to 19D-7forms, A-8 to A-13

Reservoirs, 4A-1 to 4A-3drive mechanisms, 14B-1 to 14B-2

Roads, lease, 2A-2cattleguards, 2C-5maintenance, 2C-4off road travel, 2C-2

Rod rotators, 6C-4Rods, 17B-1 to 17B-8

API ratings, 17B-1downgrading rods, 17B-1 to 17B-2fiberglass rods, 17B-7fishing, 17B-6fishing tools chart, A-15pulling and running rods, 17B-3 to 17B-4running the rods in the hole, 17B-5 to 17-B-6straight and tapered strings, 17B-2tally sheets, 17B-5

Run tickets, 13D-3Safety,

around poisonous gas, 3B-2 to 3B-3equipment, wearing, 3B-4eye wash stations, 3A-6spark-proof tools, 3A-6work habits, 3A-3

Safety valves,gas wells, 18A-3 to 18A-3

Sand lines, 17D-3Satellite tank batteries, 12D-1 to 12D-2

I-8

Scale, 16A-3 to 16A-4Secondary recovery, 15C-1 to 15C-4Selling crude oil. 13D-1 to 13D-6

gauger communications, 13D-2LACT unit, 13D-4 to 13D-5rejection notice, 13D-2run tickets, 13D-3tank seals, 13D-3

Separators,gas wells, 18D-1 to 18D-2pressure control valves, 10B5 to 10B-10two stage, 10B-5 to 10B-7

Sheaves, B-18 to B-19Signs, lease, 3A-3 to 3A-5Slop tank, 13C-5Sour corrosion, 16A-1 to 16A-2Spark-proof tools, 3A-6Steam flood, 15D-3 to 15D-4Stock tank, 10C-5 to 10C-7Storage, materials, 19D-1 to 19D-6Sucker rods (See Rods)Sweet corrosion, 16A-1 to 16A-2Tally sheets,

rods, 17B-5tubing, 17C-4

Tank batteries, 10A-1 to 10A-7alternate day gauging, 12B-5analyzing daily production, 12C-1 to 12C-5atmospheric vessels, 10C-1 to 10C-9chemical injection, 10D-3circulation lines, 10F-1 to 10F-7circulating pump, 10F-5clean tank bottoms, 12A-3commingling different pay zones, 12D-3 to 12D-6construction review, 10H-1 to 10H-3dike, 10C-8emulsion line systems, 10D-2 to 10D-3equalizer line system, 10E-4gas system, high and low pressure, 10C-1 to 10C-2gas wells, 18C-3 to 18C-4gauging daily production, 12B-1 to 12b-5gun barrel, 10C-4 to 10C-5LACT unit, selling oil, 13D-4lease pumper maintenance duties, 12E-1 to 12E-3

I-9

location oil storage, 10A-1 to 10A-2not enough production, 12C-1 to 12C-3oil sales system, 10G-1 to 10G-4pits, 10C-7satellite tank batteries, 12D-1 to 12D-2selling oil, 13D-1 to 13D-6slop tank, 13C-5stock tank, 10C-5 to 10C-7tank charts, 10A-3testing wells, battery preparation, 14A-2 to 14A-3treating oil, 13A-1 to 13A-5, 13B-1 to 13B-4, 13C-1 to 13C-6thiefing and testing oil, 12B-3too much production, 12C-4 to 12C-6vessels, and chart, 10A-5water disposal tanks, 10F-4 to 10F-7

Telephone numbers, 2B-1 to 2B-2Temperature surveys, 14C-1Tertiary recovery, 15D-1 to 15D-4Testing wells (See also Well testing), 14A-1 to 14C-3Thief and thiefing oil, 12B-3Third stage recovery, 15D-1 to 15D-4Too much production, 12C-4 to 12C-6Tools, 1B-4 to 1B-5Treating crude oil, 13A-1 to 13-A-5, 13B-1 to 13B-4, 13C-1 to 13C-6

batch treatment, 13C-4hot oiler, 13C-4

Tubing, 17C-1 to 17C-6diameter and linear measurements, 17C-2 to 17C-3hydrotesting, 17C-5 to 17C-6packers, holddowns, and safety joints, 17C-4perforations, 17C-1problems and solutions, 17C-4 to 17C-5pulling and running tubing, 17C-3safety joints, 17C-4selection of quality, 17C-2tally sheets, 17C-4threads, 17C-2

Unitizing a reservoir, 12D-3 to 12D-4Vacuum, 11C-3Vehicle,

driving habits, 2A-1expense, 2A-1personal use, 2A-1when the vehicle has problems, 2B-1

I-10

tools, 1B-4Vessels, tank battery,

atmospheric, 10C-1 to 10C-8pressurized, 10B-2 to 10B-11

Water disposal tanks, 10F-4Water flood, 15C-1 to 15C-3Well heads

gas wells, 18A-1 to 18A-3pumping wellheads, 6C-1 to 6C-6

Well servicing (See also Rods. See also Tubing), 17A-1 through 17E-4double pole units, 17A-1downhole pump problems, 17B-8mast style units, 17A-2moving and setting up, 17A-2 to 17A-single and double drum units, 17A-2single pole units, 17A-1swabbing, 17D-3

Well servicing records, 17A-3 to 17A-4Well testing, 14A-1 to 14C-3

basic tests, 14A-3 to 14A-4bucket and barrel tests, 14B-6daily well tests, 14B-2 to 14B-3gas / oil ratio, 14B-5normalizing, 14A-2pressure surveys, 14C-1productivity well tests, 14B-3potential tests, 14B-2preparing tank battery, 14A-2 to 14A-3temperature surveys, 14C-1

Well workover, 17E-1 to 17E-4fracing and acidizing wells, 17E-4

Wire lines, 17D-1 to 17D-5Working for more than one operator, 12D-5

The Lease Pumper’s HandbookBeing Written For

Commission On Marginally Producing Oil and Gas WellsState Of Oklahoma

ACKNOWLEDGMENTS

PERMISSION TO INCLUDE ILLUSTRATIONS OR PICTURES OF EQUIPMENT.List of companies who have written and extended permission for illustrations and pictures

to be included in this basic manual where appropriate.

Commission on Marginally ProducingOil & Gas Wells, State of OklahomaUse of Oklahoma Emblem inPublication

ABB Vetco GrayAnchor Systems. Inc.Arrow Specialty Co.Azure Environmental Ltd.Baker SPDBalon ***BestolifeBettisCAC OnixCamcoContinental Emsco Co.Cooper Cameron Valves

-WKM, Orbit, ThornhillCraver, FosterCSP Poly PipeDandy Specialties, Inc.Daniel Instrument and ControlD - JaxDHI Downhole Injection toolsDowning Wellhead EquipmentEchometerFiber Composite CompanyFiberflexFisher ControlsFour J Plunger ****The Foxboro Co.Gates RubberCoGearench

General Electric Industrial SystemsGeophysical Research Corp GRCHarbison FischerHASCO Mfg. Inc.Helicoid InstrumentsITT BartonKimrayKudo IndustriesLact ServiceLufkinMarathon Oil Co. Safety, Iraan TxMaster Pumps and EquipmentMcKay Equipment CompanyMcLean Plunger LiftMcMurry MaccoMine Safety Equipment. MSAMonotech SystemsMurphy, F. W.Natco, National Tank Co.Nordstrom Valves, Inc.Norris DoverOil CountryOil StatesOilfield ImprovementsPermian Production Equipment, Inc,Pipeline Pigging ProductsProduction Control ServicesREDAReed FiberglassRegalSivalls TanksStar Fiberglass SystemsTank Safety Gauge

Tank Bottom SaverVictaulic of AmericaVinson FisherWalker, W.L.Williams/Bethlehem