kdp well test procedures manual

J. Keemink @2009 Page 1

WELL TESTING

PROCEDURES


TABLE OF CONMTENTS 1. INTRODUCTION 2 1.1. Purpose of the manual 7 1.2. Objectives 2 1.3. Drilling Installations 3 1.4. UPDATING, AMENDMENT, CONTROL & DEROGATION 4 2. TYPES OF PRODUCTION TEST 5 2.1. Drawdown 5 2.2. Multi-Rate Drawdown 5 2.3. Build-up 5 2.4. Deliverability 5 2.5. Flow-on-Flow 6 2.6. Isochronal 6 2.7. Modified Isochronal 6 2.8. Reservoir Limit 6 2.9. Interference 6 2.10. Injectivity 6 3. GENERAL ROLES AND RESPONSIBILITIES 13 3.1. Responsibilities and Duties 13

3.1.1. Company Drilling and Completion Supervisor 14 3.1.2. Company Junior Drilling and Completion Supervisor 14 3.1.3. Company Drilling Engineer 14 3.1.4. Company Production Test Supervisor 14 3.1.5. Company Well Site Geologist 15 3.1.6. Contractor Toolpusher 15 3.1.7. Contract Production Test Chief Operator 15 3.1.8. Contractor Down-hole Tool Operator 15 3.1.9. Wire-line Supervisor 15 3.1.10. Company Stimulation Engineer 15 3.1.11. Company Reservoir Engineer 15

3.2. Responsibilities And Duties On Short Duration Tests 16 3.2.1. Company Drilling and Completion Supervisor 16 3.2.2. Company Junior Drilling and Completion Supervisor 16 3.2.3. Company Well Site Geologist 16 3.2.4. Well Testing Personnel 16

4. WELL TESTING PROGRAM 17 4.1. Contents 17 5. SAFETY BARRIERS 18 5.1. Well Test Fluid 18 5.2. Mechanical Barriers - Annulus Side 19

5.2.1. SSTT Arrangement 19 5.2.2. Safety Valve Arrangement 21

5.3. Mechanical Barriers - Production Side 22 5.3.1. Tester Valve 22 5.3.2. Tubing Retrievable Safety Valve (TRSV) or (SSSV) 23

5.4. Casing Overpressure Valve 23


6. TEST STRING EQUIPMENT 24 6.1. General 24 6.2. Common Test Tools Description 29

6.2.1. Beveled Mule Shoe 29 6.2.2. Perforated Joint/Ported Sub 29 6.2.3. Gauge Case (Bundle Carrier) 29 6.2.4. Pipe Tester Valve 29 6.2.5. Retrievable Test Packer 29 6.2.6. Circulating Valve (Bypass Valve) 29 6.2.7. Pipe Tester Valve 30 6.2.8. Safety Joint 30 6.2.9. Hydraulic Jar 30 6.2.10. Down-hole Tester Valve

30 6.2.11. Single Operation Reversing Sub 30 6.2.12. Multiple Operation Circulating Valve 30 6.2.13. Drill Collar 31 6.2.14. Slip Joint 31 6.2.15. Crossovers 31

6.3. High Pressure Wells 31 6.4. Sub-Sea Test Tools Used On Semi-Submersibles 31

6.4.1. Fluted Hanger 31 6.4.2. Slick Joint (Polished Joint) 31 6.4.3. Sub-Sea Test Tree 31 6.4.4. Lubricator Valve 32

6.5. Deep Sea Tools 32 6.5.1. Retainer Valve 32 6.5.2. Deep Water SSTT 32

7. SURFACE EQUIPMENT 33 7.1. Test Package 33

7.1.1. Flow head Or Surface Test Tree 33 7.1.2. Coflexip Hoses And Pipe work 33 7.1.3. Data/Injection Header 34 7.1.4. Choke Manifold 34 7.1.5. Steam Heater and Generator 35 7.1.6. Separator 35 7.1.7. Data Acquisition System 36 7.1.8. Gauge/Surge Tanks And Transfer Pumps 36 7.1.9. Diverter Manifolds, Burners and Booms 37

7.2. Emergency Shut Down System 38 7.3. Accessory Equipment 39

7.3.1. Chemical Injection Pump 39 7.3.2. Sand Detectors 39 7.3.3. Crossovers 40

7.4. Rig Equipment 40 7.5. Data Gathering Instrumentation 40

7.5.1. Laboratory and Instrument Manifold Equipment 40 7.5.2. Separator 41 7.5.3. Surge Or Metering Tank 41 7.5.4. Steam Heater 41


8. BHP DATA ACQUISITION 42 8.1 Gauge Types 42

8.1.1. Quartz Crystal Gauge 42 8.1.2. Capacitance Gauge 42 8.1.3. Strain Gauge 42 8.1.4. Bourdon Tube Gauge 43

8.2. Gauge Installation 43 8.2.1. Tubing Conveyed Gauges 43 8.2.2. Gauge Carriers 43 8.2.3. SRO Combination Gauges 44 8.2.4. Wire-line Conveyed Gauges 44 8.2.5. Memory Gauges Run on Slick line 44 8.2.6. Electronic Gauges Run on Electric Line 45

9. PERFORATING SYSTEMS 9.1. Tubing Conveyed Perforating 9.2. Wire-line Conveyed Perforating 9.3. Procedures For Perforating 10. PREPARING THE WELL FOR TESTING 10.1. Preparatory Operations For Testing

10.1.1. Guidelines For Testing 7ins Liner Lap 10.1.2. Guidelines For Testing 95/8ins Liner Lap 10.1.3. General Technical Preparations

10.2. Brine Preparation 10.2.1. Onshore Preparation of Brine 10.2.2. Transportation and Transfer of Fluids 10.2.3. Recommendations 10.2.4. Rig Site Preparations 10.2.5. Well And Surface System Displacement To Brine 10.2.6. Displacement Procedure 10.2.7. On-Location Filtration And Maintenance Of Brine

10.3. Down-hole Equipment Preparation 10.3.1. Test tools

10.4. TUBING PREPARATION

10.4.1. Tubing Connections 10.4.2. Tubing Grade 10.4.3. Material 10.4.4. Weight per Foot 10.4.5. Drift 10.4.6. Capacity 10.4.7. Displacement 10.4.8. Torque 10.4.9. AGIP (UK) Test String Specification 10.4.10. Inspection 10.4.11. After Testing/Prior To Re-Use 10.4.12. Tubing Movement

10.5. Landing String Space-Out 10.5.1. Landing String space-Out Procedure


10.6. GENERAL WELL TEST PREPARATION 10.6.1. Crew Arrival on Location 10.6.2. Inventory of Equipment Onsite 10.6.3. Preliminary Inspections

10.7. Pre Test Equipment Checks 10.8. Pressure Testing Equipment

10.8.1. Surface Test Tree 11. TEST STRING INSTALLATION 11.1. General 11.2. TUBING HANDLING 11.3. RUNNING AND PULLING 11.4. Packer And Test String Running Procedure 11.5. Running the Test String with a Retrievable Packer 11.6. Running a Test String with a Permanent Packer 12. WELL TEST PROCEDURES 12.1. Annulus Control And Pressure Monitoring 12.2. Test Execution 13. WELL TEST DATA REQUIREMENTS 13.1. General 13.2. Metering Requirements 13.3. Data Reporting 13.4. Pre-Test Preparation 13.5. Data Reporting During the Test 13.6. Communications 14. SAMPLING 14.1. Conditioning The Well 14.2. Down-hole Sampling 14.3. Surface Sampling

14.3.1. General 14.3.2. Sample Quantities 14.3.3. Sampling Points 14.3.4. Surface Gas Sampling

14.4. Surface Oil Sampling 14.5. Sample Transfer And Handling 14.6. Safety

14.6.1. Bottom-hole Sampling Preparations 14.6.2. Rigging Up Samplers to Wire-line 14.6.3. Rigging Down Samplers from Wire-line 14.6.4. Bottom hole Sample Transfer And Validations 14.6.5. Separator/Wellhead Sampling 14.6.6. Sample Storage

15. WIRE-LINE OPERATIONS 16. HYDRATE PREVENTION 17. NITROGEN OPERATIONS


18. OFFSHORE COILED TUBING OPERATIONS 19. WELL KILLING ABANDONMENT 19.1. Routine Circulation Well Kill

19.1.1. Circulation Well Kill Procedure 19.2. Bullhead Well Kill

19.2.1. Bullhead Kill procedure 19.3. Temporary Well Kill For Disconnection On Semi Submersibles 19.4. Plug And Abandonment/Suspension Procedures 19.5. Plug and Abandonment General Procedures 20. HANDLING OF HEAVY WATER BRINE


1. INTRODUCTION The main objective when drilling a well is to test and evaluate the target formation. The normal method of investigating the reservoir is to conduct a well test. There are two types of well test methods available: 1) Drill Stem Test (DST).

The scope is to define the quality of the formation fluid. Where drill pipe/tubing in combination with down hole tools is used as a short term test to evaluate the reservoir. The formation fluid may not reach or only just reach the surface during the flowing time.

2) Production Test.

The scope is to define the quality and quantity of the formation fluid. Many options of string design are available depending on the requirements of the test and the nature of the well. Many designs of well testing strings are possible depending on the requirements of the test and the nature of the well and the type of flow test to be conducted but basically it consists of installing a packer tailpipe, packer, safety system , down hole test tools and a tubing or drill pipe string then introducing a low density fluid into the string in order to enable the well to flow through surface testing equipment which controls the flow rate, separates the fluids and measures the flow rates and pressures. A short description of the types of tests which can be conducted and generic test string configurations for the various drilling installations, as well as the various down hole tools available, surface equipment, pre-test procedures and test procedures are included in this section. Well test specific wire line and coiled tubing operations are also included.

1.1. PURPOSE OF THE MANUAL

The purpose of the manual is to guide technicians and engineers, involved in Companys worldwide activities, through the Procedures and the Technical Specifications which are part of the Corporate Standards. Such Corporate Standards define the requirements, methodologies and rules that enable to operate uniformly and in compliance with the Corporate Company Principles. This, however, still enables each individual Affiliated Company the capability to operate according to local laws or particular environmental situations. The final aim is to improve performance and efficiency in terms of safety, quality and costs, while providing all personnel involved in Drilling & Completion activities with common guidelines in all areas worldwide where Company operates.

1.2. OBJECTIVES

The test objectives must be agreed by those who will use the results and those who will conduct the test before the test program is prepared. The Petroleum Engineer should discuss with the geologists and reservoir engineers about the information required and make them aware of the costs and risks involved with each method. They should select the easiest means of obtaining data, such as coring, if possible. Such inter-disciplinary discussions should be formalized by holding a meeting (or meetings) at which these objectives are agreed and fixed. The objectives of an exploration well test are to:

Conduct the testing in a safe and efficient manner.

Determine the nature of the formation fluids.

Measure reservoir pressure and temperature.

Interpret reservoir permeability-height product (kh) and skin value.

Obtain representative formation fluid samples for laboratory analysis.

Define well productivity and/or injectivity.


Investigate formation characteristics.

Evaluate boundary effects. 1.3. DRILLING INSTALLATIONS

Well tests are conducted both onshore and offshore in either deep or shallow waters. The drilling units from which testing can be carried out include:

Workover Rigs Land Rigs Swamp Barges

Jack-Up Rigs Semi-Submersible Rigs Drill Ships ONSHORE The preferred method for testing on a land rig installation necessitates the use of a permanent/retrievable type production packer, seal assembly and a conventional flow head or test tree with the test string hung of in the slips. In wells where the surface pressure will be more than 10,000psi the BOPs will be removed and testing carried out with a tubing hanger/tubing spool and a Xmas tree arrangement. This requires all the necessary precautions of isolation to be taken prior to nippling down the BOPs OFFSHORE The preferred method for testing from a floating rig is by using a drill stem test retrievable packer. However where development wells are being tested, the test will be conducted utilizing a production packer and seal-bore assembly so that the well may be temporarily suspended at the end of the test. When testing from a Semi-submersible the use of a Sub-Sea Test Tree assembly is mandatory. It consists of hanger and slick joint which positions the valve/latch section at the correct height in the BOP stack and around which the pipe rams can close to seal of the annulus. The valve section contains two fail-safe valves, usually a ball and flapper valve types. At the top of the SSTT is the hydraulic latch section which contains the operating mandrels to open the valves and the latching mechanism to release this part of the tree from the valve section in the event that disconnection is necessary.


1.4. UPDATING, AMENDMENT, CONTROL & DEROGATION This is a live controlled document and, as such, it will only be amended and improved by the Corporate Company, in accordance with the development of Companys Division and Affiliates operational experience. Accordingly, it will be the responsibility of everyone concerned in the use and application of this manual to review the policies and related procedures on an ongoing basis. Locally dictated derogations from the manual shall be approved solely in writing by the Manager of the local Drilling and Completion Department (D&C Dept.) after the District/Affiliate Manager and the Corporate Drilling & Completion Standards Department in Companys Head Office have been advised in writing. The Corporate Drilling & Completion Standards Department will consider such approved derogations for future amendments and improvements of the manual, when the updating of the document will be advisable.

2. TYPES OF PRODUCTION TEST 2.1. DRAWDOWN

A drawdown test entails flowing the well and analyzing the pressure response as the reservoir pressure is reduced below its original pressure. This is termed drawdown. It is not usual to conduct solely a drawdown test on an exploration well as it is impossible to maintain a constant production rate throughout the test period as the well must first clean-up. During a test where reservoir fluids do not flow to surface, analysis is still possible. This was the original definition of a drill stem test or DST.

2.2. MULTI-RATE DRAWDOWN A multi-rate drawdown test may be run when flow rates are unstable or there are mechanical difficulties with the surface equipment. This is usually more applicable to gas wells but can be analyzed using the Odeh-Jones plot for liquids or the Thomas-Essi plot for gas. It is normal to conduct a build-up test after a drawdown test. The drawdown data should also be analyzed using type curves, in conjunction with the buildup test.

2.3. BUILD-UP A build-up test requires the reservoir to be flowed to cause a drawdown then the well is closed in to allow the pressure to increase back to, or near to, the original pressure which is termed the pressure build-up or PBU. This is the normal type of test conducted on an oil well and can be analyzed using the classic Horner Plot or superposition. From these the permeability-height product, kh, and the near wellbore skin can be analyzed.


On low production rate gas wells, where there is a flow rate dependant skin, a simple form of test to evaluate the rate dependant skin coefficient, D, is to conduct a second flow and PBU at a different rate to the first flow and PBU. This is the simplest form of deliverability test described below.

2.4. DELIVERABILITY A deliverability test is conducted to determine the wells Inflow Performance Relation, IPR, and in the case of gas wells the Absolute Open Flow Potential, AOFP, and the rate dependant skin coefficient, D. The AOFP is the theoretical fluid rate at which the well would produce if the reservoir sand face was reduced to atmospheric pressure. This calculated rate is only of importance in certain countries where government bodies set the maximum rate at which the well may be produced as a proportion of this flow rate. There are three types of deliverability test:

Flow on Flow Test.

Isochronal Test.

The Modified Isochronal Test.

2.5. FLOW-ON-FLOW

Conducting a flow-on-flow test entails flowing the well until the flowing pressure stabilizes and then repeating this at several different rates. Usually the rate is increased at each step ensuring that stabilized flow is achievable. The durations of each flow period are equal. This type of test is applicable to high rate gas well testing and is followed by a single pressure build up period.

2.6. ISOCHRONAL

An Isochronal test consist of a similar series of flow rates as the flow-on-flow test, each rate of equal duration and separated by a pressure build-up long enough to reach the stabilized reservoir pressure. The final flow period is extended to achieve a stabilized flowing pressure for defining the IPR.

2.7. MODIFIED ISOCHRONAL

The modified isochronal test is used on tight reservoirs where it takes a long time for the shut-in pressure to stabilize. The flow and shut-in periods are of the same length, except the final flow period which is extended similar to the isochronal test. The flow rate again is increased at each step.


2.8. RESERVOIR LIMIT A reservoir limit test is an extended drawdown test which is conducted on closed reservoir systems to determine their volume. It is only applicable where there is no regional aquifer support. The well is produced at a constant rate until an observed pressure drop, linear with time, is achieved. Surface readout pressure gauges should be used in this test. It is common practice to follow the extended drawdown with a pressure build-up.

The difference between the initial reservoir pressure, and the pressure to which it returns, is the depletion. The reservoir volume may be estimated directly from the depletion, also the volume of produced fluid and the effective isothermal compressibility of the system. The volume produced must be sufficient, based on the maximum reservoir size, to provide a measurable pressure difference on the pressure gauges, these must therefore be of the high accuracy electronic type gauges with negligible drift.

2.9. INTERFERENCE

An interference test is conducted to investigate the average reservoir properties and connectivity between two or more wells. It may also be conducted on a single well to determine the vertical permeability between separate reservoir zones. A well-to-well interference test is not carried out offshore at the exploration or appraisal stage as it is more applicable to developed fields. Pulse testing, where the flow rate at one of the wells is varied in a series of steps, is sometimes used to overcome the background reservoir pressure behavior when it is a problem.

2.10. INJECTIVITY

In these tests a fluid, usually seawater offshore is injected to establish the formations injection potential and also its fracture pressure, which can be determined by conducting a step rate test. Very high surface injection pressures may be required in order to fracture the formation. The water can be filtered and treated with scale inhibitor, biocide and oxygen scavenger, if required. Once a well is fractured, which may also be caused by the thermal shock of the cold injection water reaching the sand face, a short term injection test will generally not provide a good measure of the long term injectivity performance. After the injectivity test, the pressure fall off is measured. The analysis of this test is similar to a pressure build-up, but is complicated by the cold water bank.


3. GENERAL ROLES AND RESPONSIBILITIES Well testing is potentially hazardous and requires good planning and co operation/coordination between all the parties involved. The most important aspect when planning a well test, is the safety risk assessment process. To this end, strict areas of responsibilities and duties shall be defined and enforced, detailed below.

3.1. RESPONSIBILITIES AND DUTIES

The following Companys/Contractors personnel shall be present on the rig: o Company Drilling and Completion Supervisor. o Company Junior Drilling and Completion Supervisor. o Company Drilling Engineer. o Company Production Test Supervisor. o Company Well Site Geologist. o Contractor Toolpusher. o Contract Production Test Chief Operator. o Contractor Down-hole Tool Operator. o Wire-line Supervisor (slick-line & electric line ). o Tubing Power Tong Operator. o Torque Monitoring System Engineer.

Depending on the type of test, the following personnel may also be required on the rig during the Well test: o Company Reservoir Engineer.

3.1.1. Company Drilling and Completion Supervisor

The Company Drilling and Completion Supervisor retains overall responsibility on the rig during testing operations. He is assisted by the Company Production Test Supervisor, Drilling Engineer, Well Site Geologist and Company Junior Drilling and Completion supervisor. When one of the above listed technicians is not present, the Company Drilling and Completion Supervisor, in agreement with Drilling and Completion Manager and Drilling Superintendent, can perform the test, after re-allocation of the duties and responsibilities according to the Well Test specifications. If deemed necessary he shall request that the rig be inspected by a Company safety expert prior to starting the well test.

3.1.2. Company Junior Drilling and Completion Supervisor

The Company Junior Drilling and Completion Supervisor will assist the Company Drilling and Completion Supervisor in well preparation and in the test string tripping operation. He will cooperate with the Company Production Test Supervisor to verify the availability of down-hole drilling equipment, to carry out equipment inspections and tests and to supervise the Down-hole Tool Operator and the Contractor Production Chief Operator. In co-operation with the Drilling Engineer, he will prepare daily reports on equipment used. In the absence of the Company Junior Drilling and Completion Supervisor, his function will be performed by the Company Drilling and Completion Supervisor.

3.1.3. Company Drilling Engineer

The Drilling Engineer will assist the Company Drilling and Completion Supervisor in the well preparation and in the test string tripping operation. He will co-operate with the Company Production Test supervisor to supervise the down-hole tool Operator and the


Contractor Production Chief Operator. He shall be responsible for supplying equipment he is concerned with (down-hole tools) and for preliminary inspections. He shall provide Contractor personnel with the necessary data, and prepare accurate daily reports on equipment used in cooperation with the Company Junior Drilling and Completion Supervisor.

3.1.4. Company Production Test Supervisor

The Company Production Test Supervisor is responsible for the co-ordination and conducting of the test. This includes well opening, flow or injection testing, separation and measuring, flaring, wire-line, well shut in operations and all preliminary test operations required on specific production equipment. In conjunction with the Reservoir Engineer, he shall make recommendations on test program alterations whenever test behavior is not as expected. The final decision to make any program alterations will be taken by head office. The Company Production Test Supervisor will discuss and agree the execution of each phase of the test with the Company Drilling and Completion Supervisor. He will then inform rig floor and test personnel of the actions to be performed during the forthcoming phase of the test. He will be responsible for co-ordination the preparation of all reports and telexes, including the final well test report. He is responsible for arranging the supply of all equipment necessary for the test i.e. surface and down hole testing tools, supervising preliminary inspections as per procedures. He will supervise contract wire-line and production test equipment operators, as well as the down-hole tool operator and surface equipment operators. He will be responsible in conjunction with the Company Well site Geologist for the supervision of perforating and cased hole logging operations, as per the test program. The Company Production Test Supervisor is responsible for the preparation of all reports, including the final field report previously mentioned.

3.1.5. Company Well Site Geologist

The Well Site Geologist is responsible for the supervision of perforating operations (for well testing) cased hole logging when the Company Production Test Supervisor is not present on the rig. If required he will co operate with the Company Production Test Supervisor for the test interpretation and preparation of field reports.

3.1.6. Contractor Toolpusher

The Toolpusher is responsible for the safety of the rig and all personnel. He shall ensure that safety regulations and procedures in place are followed rigorously. The Toolpusher shall consistently report to the Company Drilling and Completion supervisor on the status of drilling contractors material and equipment.

3.1.7. Contractor Production Test Chief Operator

The Production Test Chief Operator shall always be present to co-ordinate and assist the well testing operator and crew. He will be responsible for the test crew to the Company Production Test Supervisor and will draw up a chronological report of the test.

3.1.8. Contractor Down-hole Tool Operator

The down-hole tool operator will remain on duty, or be available, on the rig floor from the time the assembling of the BHA is started until it is retrieved. He is solely responsible for down-hole tool manipulation and annulus pressure control during tests.


On Semi-Submersibles the SSTT operator will be available near the control panel on the rig floor from the time when the SSTT is picked up until it is laid down again at the end of the test. During preliminary inspections of equipment, simulated test (dummy tests), tools tripping in and out of the hole and during the operations relating to the well flowing (from opening to closure of tester ), he will report to the Company Production Test Supervisor.

3.1.9. Wire-line Supervisor

The Wire-line Supervisor will ensure all equipment is present and in good working order. He will report directly with the Company Production Test Supervisor.

3.1.10. Company Stimulation Engineer

If present on the rig, the Stimulation Engineer will assist the Company Production Test Supervisor during any stimulation operations. He will provide the Company Production Test Supervisor with a detailed program for conducting stimulation operations, including the deck layout for equipment positioning, chemical formulations, pumping rates and data collection. He will monitor the contractors during the stimulation to ensure the operation is performed safely and satisfactorily. The Stimulation Engineer will also provide the Company Production Test Supervisor with a report at the end of the stimulation operation.

3.1.11. Company Reservoir Engineer

If present on the rig, the Reservoir Engineer shall assist the Company Production Test Supervisor during the formation testing operation. His main responsibility is to ensure that the required well test data is collected in accordance to the program and for the quality of the data for analysis. He will provide a quick look field analysis of each test period and on this basis he will advise on any necessary modifications to the testing program.

3.2. RESPONSIBILITIES AND DUTIES ON SHORT DURATION TESTS

As a general rule the only company personnel present on the rig shall be the Company Drilling and Completion Supervisor, the Company Junior Drilling and Completion Supervisor and the well site Geologist, the Company Drilling Manager/Superintendent shall evaluate, in each individual case, the opportunity of providing a company Drilling Engineer. The responsibilities and duties of the Company Drilling and Completion Supervisor and Well Site Geologist will be as follows:

3.2.1. Company Drilling and Completion Supervisor

The Company Drilling and Completion Supervisor retains overall responsibility on the rig during testing operations assisted by the Company Junior Drilling and Completion Supervisor and the well site Geologist. He is responsible for the co-ordination of testing operations, well preparation for tests, shut-in of the well, formation clean out, measuring, flaring and wire-line operations. The Company Drilling and Completion Supervisor is responsible for the availability and inspection of the testing equipment. He shall supervise the contractor Production Chief Operator, Wire-line Operator and Production Test Crew, as well as the Down-hole Tool Operator and Surface Tool Operator.

3.2.2. Company Junior Drilling and Completion Supervisor

The Company Junior Drilling and Completion Supervisor shall assist the Company Drilling and Completion Supervisor to accomplish his duties. He shall also prepare accurate daily reports on equipment used.


3.2.3. Company Well Site Geologist The Well Site Geologist is responsible for the supervision of perforating operations and for cased hole logging operations. He is responsible for the final decision making to modify the testing program, whenever test behavior would be different than expected. He shall draw up daily and final reports on the tests and is responsible for the first interpretation of the test.

3.2.4. Contractor Personnel

For the allocation of responsibilities and duties of contractors Personnel (Toolpusher, Production Chief Operator, Down-hole Tool Operator), refer to long test responsibilities.

4. WELL TESTING PROGRAM When the rig reaches Total Depth (TD) and all the available data is analyzed, the company Reservoir/Exploration Departments shall provide the Company Drilling/Production and Engineering departments with the information required for planning the well test (type, pressure, temperature of formation fluids, intervals to be tested, flowing or sampling test, duration of test, type of completion fluid, type and density of fluid against which the well will be opened, type of perforating gun and number of shots per foot, use of coiled tubing stimulation, etc.). The Drilling, Production and Engineering departments shall then prepare a detailed testing program verifying that the testing equipment conforms to these procedures. The duty of the Engineering Department is also to make sure that the testing equipment is available at the rig in due time. Company and contractor personnel on the rig shall confirm equipment availability and program feasibility, verifying that the test program is compatible with general and specific rules related to the drilling unit. Governmental bodies of several countries lay down rules and regulations covering the entire drilling activity. In such cases , prior to the start of testing operations a summary program shall be submitted for approval to national agencies, indicating well number, location, objectives, duration of test and test procedures. Since it is not practical to include all issued laws within the company general statement the company (Drilling, Production, Engineering departments and rig personnel) shall verify the consistency of the present procedures to suit local laws, making any modifications that would be required. However, at all times, the most restrictive interpretation shall apply.

4.1. CONTENTS

The program shall be drawn up in order to acquire all necessary information taking into account two essential factors:

The risk to which the rig and personnel are exposed during testing.

The cost of the operation. A detailed testing program shall include the following points: 1) A general statement indicating the well status, targets to be reached, testing procedures as

well as detailed safety rules that shall be applied, should they differ from those detailed in the current procedures.

2) Detailed and specific instructions covering well preparation, completion and casing perforating system, detailed testing program field analysis on test data and samples, mud program and closure of the tested interval.


5. SAFETY BARRIERS Barriers are the safety system incorporated into the structure of the well and the test string design to prevent uncontrolled flow of formation fluids and keep well pressures off the casing. It is common oilfield practice to ensure there are at least two tested barriers in place or available to be closed at all times. A failure in any barrier system which means the well situation does meet with this criteria, then the test will be terminated and the barrier replaced, even if it entails killing of the well to pull the test string. To ensure overall well safety, there must be sufficient barriers on both the annulus side and the production or tubing side. Some barriers may actually contain more than one closure mechanism but are still classified as a single barrier such as the two closure mechanism in a SSTT, etc. Barriers are often classified as primary, secondary and tertiary. This section describes the barrier systems which must be provided on well testing operations.

5.1. WELL TEST FLUID

The fluid which is circulated into the wellbore after drilling operations is termed the well test fluid and conducts the same function as a completion fluid and may be one and the same if the well is to be completed after well testing. It provides one of the functions of a drilling fluid, with regards to well control, in that it density is designed to provide a hydrostatic overbalance on the formation which prevents the formation fluids entering the wellbore during the times it is exposed to the test fluid during operations. The times that the formation may be exposed to the test fluid hydrostatic pressure are when:

A casing leak develops.

The well is perforated before running the test string.

There is a test string leak during testing.

A circulating device accidentally opens during testing.

Well kill operations are conducted after the test. During the testing operation when the packer is set and the well is flowing, the test fluid is only one of the barriers on the annulus side. The test fluid density will be determined form log information and calculated to provide a hydrostatic pressure, generally between 100-200psi, greater than the formation pressure. completion. As the test fluid is usually a clear brine for damage prevention reasons, high overbalance pressures may cause severe losses and alternatively, if the overbalance pressure is too low, any fluid loss out of the wellbore may quickly eliminated the margin of overbalance. When using low overbalance clear fluids, it is important to calculate the temperature increase in the well during flow periods as this decreases the density. An overbalance fluid is often described as the primary barrier during well operations. A modern test method used on wells which have high pressures demanding high density test fluids which are unstable an extremely costly, is to design the well test with an underbalanced fluid which is much more stable and cheaper. In this case there will be one barrier less than overbalance testing. This is not a problem providing the casing is designed for the static surface pressures of the formation fluids and that all other mechanical barriers are available and have been tested.

5.2. MECHANICAL BARRIERS - ANNULUS SIDE

On the annulus side, the mechanical barriers are:

Packer/tubing envelope.

Casing/BOP pipe ram/side outlet valves envelope.


Therefore, under normal circumstances there are three barriers on the annulus side with the overbalance test fluid. If one of these barriers (or element of the barrier) failed then there would still be two barriers remaining. An alternate is when the BOPs are removed and a tubing hanger spool is used with a Xmas tree. In this instance the barrier envelope on the casing side would be casing/hanger spool/side outlet valves. The arrangement of the BOP pipe ram closure varies with whether there is a surface or subsea BOP stack. When testing from a floater, a SSTT is utilized to allow the rig to suspend operations and leave the well location for any reason. On a jack-up, a safety valve is installed below the mud line as additional safety in the event there is any damage caused to the installation (usually approx. 100m below the rig floor). Both systems use a slick joint spaced across the lower pipe rams to allow the rams to be closed on a smooth OD.

5.2.1. SSTT Arrangement

A typical SSTT arrangement is shown in figure 5.a. The positioning of the SSTT in the stack is important to allow the blind rams to be closed above the top of the SSTT valve section providing additional safety and keeping the latch free from any accumulation of debris which can effect re-latching. Note: The shear rams are not capable of cutting the SSTT assembly unless a safety shear joint is installed in the SSTT across the shear ram position. Figure 5.A - SSTT Arrangement

5.2.2. Safety Valve Arrangement

On jack-ups where smaller production casing is installed, the safety valve may be too large in OD (7-8ins) to fit inside the casing. In this instance a spacer spool may be added between the stack and the wellhead to accommodate the safety valve. This is less safe than having the valve positioned at the mud line as desired


5.3. MECHANICAL BARRIERS - PRODUCTION SIDE On the production side there are a number of barriers or valves which may be closed to shutoff well flow. However some are solely operational devices. The barriers used in well control are: Semi-submersible string - Latched 1) Tester valve 2) SSTT 3) Surface test tree. Semi-submersible string - Unlatched 1) Tester valve 2) SSTT.

Jack-Up 1) Tester valve 2) Safety valve 3) Surface test tree.

Land well 1) Tester valve 2) Safety valve 3) Surface test tree.

5.3.1. Tester Valve

The tester valve is an annulus pressure operated fail safe safety valve. It remains open by maintaining a minimum pressure on the annulus with the cement pump. Bleeding off the pressure or a leak on the annulus side closes the valve. The tester may have an alternate lock open cycle device and it is extremely important that this type of valve is set in the position where the loss of pressure closes the valve. It is unsafe to leave the tester valve in the open cycle position as in an emergency situation there may not be sufficient time to cycle the valve closed. The tester valve may be considered as the primary barrier during the production phase.


5.3.2. Tubing Retrievable Safety Valve (TRSV) or (SSSV) This is a valve normally installed about 100m below the wellhead or below the mud line in permanent on-shore and off-shore completions respectively. This type of valve can also be installed inside the BOP for well testing as an additional down-hole barrier on land wells or on jack-up rigs, see figure 5.b for the various configurations of BOP stacks combinations relating to the production casing size. Due to the valve OD (7-8ins) available today in the market, its use with 7 production casing is only possible by installing a spacer spool between the tubing spool and the pipe rams closed on a slick joint directly connected to the upper side of the valve itself. A space of at least two meters between pipe rams and top of tubing spool is required. The valve OD must be larger than the slick joint to provide a shoulder to prevent upward string movement. A small size test string with a 5.25ins OD safety valve can be used with 7ins casing, as indicated. In all cases the valve is operated by hydraulic pressure through a control line and is fail safe when this pressure is bled off. The slick joint body has an internal hydraulic passage for the control line. The safety valve can be considered the secondary barrier during production.

5.4. CASING OVERPRESSURE VALVE A test string design which includes an overpressure rupture disk, or any other system sensible to casing overpressure, should have an additional single shot down-hole safety valve to shut off flow when annulus pressure increases in an uncontrolled manner. This additional safety feature is recommended only in particular situations where there are very high pressures and/or production casing is not suitable for sudden high overpressures due to the test string leaking. This valve is usually used with the single shot circulating valve which is casing pressure operated and positioned above the safety valve, hence will open at the same time the safety valve closes. This allows the flow line to bleed off the overpressure.

6. TEST STRING EQUIPMENT 6.1. GENERAL

The well testing objectives, test location and relevant planning will dictate which is the most suitable test string configuration to be used. Some generic test strings used for testing from various installations are shown. In general, well tests are performed inside a 7ins production liner, using full opening test tools with a 2.25ins ID. In larger production casing sizes the same tools will be used with a larger packer. In 5-51/2ins some problems can be envisaged: availability, reliability and reduced ID limitations to run W/L. tools, etc. smaller test tools will be required, but similarly, the tools should be full opening to allow production logging across perforated intervals. For a bare-foot-test, conventional test tools will usually be used with a packer set inside the 95/8ins casing.


If conditions allow, the bottom of the test string should be 100ft above the top perforation to allow production logging, re-perforating and/or acid treatment of the interval. In the following description, tools which are required both in production tests and conventional tests are included. The list of tools is not exhaustive, and other tools may be included. However, the test string should be kept as simple as possible to reduce the risk of mechanical failure. The tools should be dressed with elastomers suitable for the operating environment, considering packer fluids, prognosed production fluids, temperature and the stimulation program, if applicable. The tools must be rated for the requested working pressure (in order to withstand the maximum forecast bottom-hole/well head pressure with a suitable safety factor).

Fig. TCP Guns Fig. Retrievable Packer Fig. Bridge Plug 6.2. COMMON TEST TOOLS DESCRIPTION

6.2.1. Beveled Mule Shoe If the test is being conducted in a liner the mule shoe makes it easier to enter the liner top. The beveled mule shoe also facilities pulling wire-line tools back into the test string. If testing with a permanent packer, the mule shoe allows entry into the packer bore.

6.2.2. Perforated Joint/Ported Sub

The perforated joint or ported sub allows wellbore fluids to enter the test string if the tubing conveyed perforating system is used. This item may also be used if wire-line retrievable gauges are run below the packer.


6.2.3. Gauge Case (Bundle Carrier) The carrier allows pressure and temperature recorders to be run below or above the packer and sense either annulus or tubing pressures and temperatures.

6.2.4. Pipe Tester Valve

A pipe tester valve is used in conjunction with a tester valve which can be run in the open position in order to allow the string to self fill as it is installed. The valve usually has a flapper type closure mechanism which opens to allow fluid bypass but closes when applying tubing pressure for testing purposes. The valve is locked open on the first application of annulus pressure which is during the first cycling of the tester valve.

6.2.5. Retrievable Test Packer

The packer isolates the interval to be tested from the fluid in the annulus. It should be set by turning to the right and includes a hydraulic hold-down mechanism to prevent the tool from being pumped up the hole under the influence of differential pressure from below the packer.

6.2.6. Circulating Valve (Bypass Valve)

This tool is run in conjunction with retrievable packers to allow fluid bypass while running in and pulling out of hole, hence reducing the risk of excessive pressure surges or swabbing. It can also be used to equalize differential pressures across packers at the end of the test. It is automatically closed when sufficient weight is set down on the packer This valve should ideally contain a time delay on closing, to prevent pressuring up of the closed sump below the packer during packer setting. This feature is important when running tubing conveyed perforating guns which are actuated by pressure. If the valve does not have a delay on closing, a large incremental pressure, rather than the static bottom-hole pressure, should be chosen for firing the guns

6.2.7. Pipe Tester Valve

A pipe tester valve is used in conjunction with a tester valve which can be run in the open position in order to allow the string to self fill as it is installed. The valve usually has a flapper type closure mechanism which opens to allow fluid bypass but closes when applying tubing pressure for testing purposes. The valve is locked open on the first application of annulus pressure which is during the first cycling of the tester valve.


6.2.8. Safety Joint Installed above a retrievable packer, it allows the test string above this tool to be recovered in the event the packer becomes stuck in the hole. It operates by manipulating the string (usually a combination of reciprocation and rotation) to unscrew and the upper part of the string retrieved. The DST tools can then be laid out and the upper part of the safety joint run back in the hole with fishing jar to allow more powerful jarring action.

6.2.9. Hydraulic Jar

The jar is run to aid in freeing the packer if it becomes stuck. The jar allows an over-pull to be taken on the string which is then suddenly released, delivering an impact to the stuck tools.

6.2.10. Down-hole Tester Valve The down-hole tester valve provides a seal from pressure from above and below. The valve is operated by pressuring up on the annulus. The down-hole test valve allows down-hole shut in of the well so that after-flow effects are minimized, providing better pressure data. It also has a secondary function as a safety valve.


6.2.11. Single Operation Reversing Sub

Produced fluids may be reversed out of the test string and the well killed using this tool. It is actuated by applying a pre-set annulus pressure which shears a disc or pins allowing a mandrel to move and expose the circulating ports. Once the tool has been operated it cannot be reset, and therefore must only be used at the end of the test. This reversing sub can also be used in combination with a test valve module if a further safety valve is required. One example of this is a system where the reversing sub is combined with two ball valves to make a single shot sampler/safety valve.

6.2.12. Multiple Operation Circulating Valve

This tool enables the circulation of fluids closer to the tester valve whenever necessary as it can be opened or closed on demand and is generally used to install an under-balance fluid for brining in the well. This tool is available in either annulus or tubing pressure operated versions. The tubing operated versions require several pressure cycles before the valve is shifted into the circulating position. This enables the tubing to be pressure tested several times while running in hole. Companys preference is the annulus operated version.

6.2.13. Drill Collar

Drill collars are required to provide a weight to set the packer. Normally two stands of 4-3/4ins drill collars (46.8lbs/ft) should be sufficient weight on the packer, but should be regarded as the minimum.

6.2.14. Slip Joint

These allow the tubing string to expand and contract in the longitudinal axis due to changes in temperature and pressure. They are non-rotating to allow torque for setting packers or operating the safety joint.

6.2.15. Crossovers

Crossovers warrant special attention They are of the utmost importance as they connect every piece of equipment in the test string which have differing threads. If crossovers have to be manufactured, they need to be tested and fully certified. In addition, they must be checked with each mating item of equipment before use.

6.3. HIGH PRESSURE WELLS

If the SBHP >10,000psi a completion type test string and production Xmas tree is recommended to test the well.

6.4. SUB-SEA TEST TOOLS USED ON SEMI-SUBMERSIBLES The sub-sea test tree (SSTT) assembly includes a fluted hanger, slick joint, and sub-sea test tree.

6.4.1. Fluted Hanger The fluted hanger lands off and sits in the wear bushing of the wellhead and is adjustable to allow the SSTT assembly to be correctly positioned in the BOP stack so that when the SSTT is disconnected the shear rams can close above the disconnect point. 6.4.2. Slick Joint (Polished Joint)

The slick joint (usually 5ins OD) is installed above the fluted hanger and has a smooth (slick) outside diameter around which the BOP pipe rams can close and sustain annulus pressure for DST tool operation or, if in an emergency disconnection, contain annulus pressure. The slick joint should be positioned to allow the two bottom sets of pipe rams to


be closed on it and also allow the blind rams to close above the disconnect point of the SSTT.

6.4.3. Sub-Sea Test Tree

The SSTT is a fail-safe sea floor master valve which provides two functions; the shut off of pressure in the test string and; disconnection of the landing string from the test string due to an emergency situation or for bad weather. The SSTT is constructed in two parts; the valve assembly consisting of two fail safe closed valves and; a latch assembly. The latch contains the control ports for the hydraulic actuation of the valves and the latch head. The control umbilical is connected to the top of the latch which can, under most circumstances be reconnected, regaining control without killing the well. The valves hold pressure from below, but open when a differential pressure is applied from above, allowing safe killing of the well without hydraulic control if unlatched.

6.4.4. Lubricator Valve

The lubricator valve is run one stand of tubing below the surface test tree. This valve eliminates the need to have a long lubricator to accommodate wire-line tools above the surface test tree swab valve. It also acts as a safety device when, in the event of a gas escape at surface, it can prevent the full unloading of the contents in the landing string after closing of the SSTT. The lubricator valve is hydraulic operated through a second umbilical line and should be either a fail closed or; fail-in-position valve. When it is closed it will contain pressure from both above and below.

6.5. DEEP SEA TOOLS

6.5.1. Retainer Valve The retainer valve is installed immediately above the SSTT on tests in extremely deep waters to prevent large volumes of well fluids leaking into the sea in the event of a disconnect. It is hydraulic operated and must be a fail-open or fail-in-position valve. When it is closed it will contain pressure from both above and below. It is usually run in conjunction with a deep water SSTT described below.

6.5.2. Deep Water SSTT

As exploration moves into deeper and remote Subsea locations, the use of dynamic positioning vessels require much faster SSTT unlatching than that available with the normal hydraulic system on an SSTT. The slow actuation is due to hydraulic lag time when bleeding off the control line against friction and the hydrostatic head of the control fluid. This is overcome by use of the deepwater SSTT which has an Electro-Hydraulic control system. The Hydraulic deep water actuator is a fast response controller for the deepwater SSTT and retainer valve. This system uses hydraulic power from accumulators on the tree controlled electrically from surface (MUX). The fluid is vented into the annulus or an atmospheric tank to reduce the lag time and reducing closure time to seconds. If a program required deepwater test tools, the tool operating procedures would be included in the test program.

7. SURFACE EQUIPMENT This sub-section contains the list of surface equipment and the criteria for use.

7.1. TEST PACKAGE


7.1.1. Flow head Or Surface Test Tree

Modern flow heads are of solid block construction, i.e. as a single steel block, as opposed to the earlier modular unit which was assembled from various separate components. Irrespective of the type, both should contain:

1) Upper Master Valve for emergency use only.

2) Lower Master Valve situated below the swivel for emergency use only.

3) Kill Wing Valve on the kill wing outlet connected to the cement pump or the rig manifold.

4) Flow Wing Valve on the flow wing outlet, connected to the choke manifold, which is the ESD actuated valve.

5) Swab Valve for isolation of the vertical wire-line or coil tubing access.

6) Handling Sub which is the lubricator connection for wire-line or coiled tubing and is also for lifting the tree.

7) Pressure Swivel which allows string rotation with the flow and kill line connected.

On floating rigs, with the rig at its operating draft, the flow head should be positioned so that it is at a distance above the drill floor which is greater than the maximum amount of heave anticipated, plus an allowance for tidal movement, i.e. 5ft and a further 5ft safety margin. Coflexip hoses are used to connect from the flow head kill wing and flow wing to the rig manifold and the test choke manifold. A permanently installed test line is sometimes available which leads from the drill floor to the choke manifold location.

7.1.2. Coflexip Hoses And Pipework

Coflexip hoses must be installed on the flow head correctly so as to avoid damage. They must be connected so that they hang vertically from the flow head wings. The hoses should never be hung across a wind wall or from a horizontal connection unless there is a pre-formed support to ensure they are not bent any tighter than their minimum radius of 5ft. Hoses are preferred to chiksan connections because of their flexibility, ease of hook up and time saving. They are also less likely to leak due to having fewer connections. On floaters, they connect the stationary flow head to the moving rig and its permanent pipe work.


Permanently installed surface lines should be used with the minimum of temporary connections supplied from the surface testing contractor. Ideally these temporary connections should be made-to-measure pipe sections with welded connections, however chiksans can be used but must be tied down to the deck. Additional protection can be given by installing relief valves in the lines. Is now common practice to have a relief valve on the line between the heater and the separator to cater for any blockage downstream which may cause over-pressure in the line. If there is further risk from plugging of the burner nozzles by sand carry-over, then consideration should be given to installing further relief valves downstream of the separator to protect this lower pressure rated pipe work. Note: Ensure that the Coflexip hoses are suitable for use with corrosive brines.

7.1.3. Data/Injection Header This item is usually situated immediately upstream of the choke. The data/injection header is merely a section of pipe with several ports or pockets to mount the following items:

Chemical injection

Wellhead pressure recording

Temperature recording

Wellhead pressure recording with a dead weight tester

Wellhead sampling

Sand erosion monitoring

Bubble hose.

Most of the pressure and temperatures take off points will be duplicated for the Data Acquisition System sensors.

7.1.4. Choke Manifold The choke manifold is a system of valves and chokes for controlling well flow and usually has one adjustable and one fixed choke. Some choke manifolds may also incorporate a bypass line. The valves are used to direct the flow through either of the chokes or the bypass. They also provide isolation from pressure so that the choke changes can be made.

A well shall be brought in using the adjustable or variable choke. This choke should never be fully closed against well flow. The flow should then be redirected to the appropriately


sized fixed choke for stable flow conditions. The testing contractor should ensure that a full range of fixed chokes are available in good condition. Due to the torturous path of the fluids through the choke, flow targets are positioned where the flow velocities are high and impinge on the bends. Ensure these have been checked during the previous refurbishment to confirm they were still within specification.

7.1.5. Steam Heater And Generator

Heat is required from the steam heater, or heat exchanger, to:

Prevent hydrate formation on gas wells

Prevent wax deposition when testing high waxy, paraffin type crudes

Break foams or emulsions

Reduce viscosity of heavy oils.

For use on high flow rate wells, a 4ins bore steam heater should be used to reduce high back pressures. The heat required to raise a gas by 1oF can be estimated from the formula: 2,550 x Gas Flow (mmscf/day) x Gas Specific Gravity (air = 1.000), BTU/hr/oF The heat needed to raise an oil by 1oF can be estimated from: 8.7 x Oil Flow (bbls/day) x Oil Density (gms/cm3), BTU/hr/oF Always use the largest steam heater and associated generator that space or deck loading will allow as the extra output is contingency for any serious problem which may arise. The rig steam generator will not usually have the required output and therefore diesel-fired steam generator in conjunction with the steam heat exchanger should be supplied by the surface test contractor.

7.1.6. Separator

The test separator is required to:

Separate the well flow into three phases; oil, gas and water

Meter the flow rate of each phase, at known conditions

Measure the shrinkage factor to correct to standard conditions

Sample each phase at known temperature and pressure. The standard offshore separator is a horizontal three phase, 1,440psi working pressure unit. This can handle up to 60mmscf/day of dry gas or up to 10,000bopd and associated gas at it working pressure Other types of separator, such as the vertical or spherical models and two phase units may be used. Gas is metered using a Daniels or similar type orifice plate gas meter. The static pressure, pressure drop across the orifice plate and the temperature are all recorded. From this data the flow rate is calculated. The liquid flow rates are measured by positive displacement or vortex meters. The oil shrinkage factor is physically measured by allowing a known volume of oil, under controlled conditions, to de-pressurize and cool to ambient conditions. The shrinkage factor is the ambient volume, divided by the original volume. The small volume, however, of the shrinkage meter means that this is not an accurate measurement. The oil flow rate is corrected for any volume taken up by gas, water, sand or sediment. This volume is calculated by multiplying the combined volume by the BS&W


measurement and the tank/meter factor. Oil meters are calibrated onshore but it is also necessary to divert the oil flow to a gauge tank for a short period to obtain a combined shrinkage/meter factor as the meter calibration is subject to discrepancy with varying oil gravity and viscosity. The separator relief system is calibrated onshore and should never be function tested offshore, hence the separator should only be tested to 90% of the relief valve setting. It is important that the separator bypass valves, diverter valves for the vent lines leading from the separator relief valve, rupture disc or back-up relief valve, are checked for ease of operation.

7.1.7. Data Acquisition System It is now common custom to use computerized Data Acquisition Systems (DAS) on offshore well tests. However, it is essential that manual readings are still separately recorded for correlation of results and contingency in the event of problems occurring to the system. These systems can collect, store and provide plots of:

Surface data

Down-hole data from gauges

Memory gauge data. The main advantage of DAS is that real time plots can be displayed at the well site for troubleshooting. Another advantage is that all of the surface (and possibly down-hole) data is collected into one system and can be supplied on a floppy disk for the operator to analyze and subsequently prepare well reports.

7.1.8. Gauge/Surge Tanks And Transfer Pumps

A gauge tank is an atmospheric vessel whereas a surge tank is usually rated to 50psi WP and is vented to the flare. A surge tank is essential for safe working if H2S production is anticipated. Therefore, surge tanks should always be used on wildcat wells and gauge tanks used only in low risk situations. Tanks are used for checking the oil meter/shrinkage factors and for measuring volumes at rates which are too low for accurate flow meter measurement. They usually have a capacity of one hundred barrels and some with twin compartments so that one compartment can be filled while the other is pumped to the burner via the transfer pump. Tanks can also be used for collecting large atmospheric samples of crude for analysis or used as a secondary separator for crudes which require longer separation times. Some tanks can have special features such as steam heating elements for heavy/viscous oil production tests etc.

7.1.9. Diverter Manifolds, Burners and Booms


Burner heads are mounted on the end of the booms which are usually installed on opposing sides of the rig to take maximum advantage of wind direction changes, i.e. to keep at least one burner heading downwind. The oil and gas flowlines, including the tank and relief vent lines, from the test area to the booms, must have diverter manifolds for directing flow to the leeward boom. Most recent designs of burners are promoted as green or clean type burners. This is indicative of them being less polluting to the environment by having superior burning technology. Although still not ideal their ability is much improved over previous models. The burner has a ring of atomizers or nozzles which break up the flow for complete combustion. This is assisted by pumping air into the flow stream. Rig air must not be used for this purpose as there is a risk of hydrocarbons leaking back into the rig air system. Two portable air compressors, one as back-up, are required, suitably fitted with check valves. It is recommended that the air compressors are manifolded together to provide a continuous supply of air in the event of a compressor failure. Green style burners are very heavy users of air and consideration must be given for deck space for additional air compressors. Water must be pumped to the burner head which forms a heat shield in the form of a spray around the flare to protect the installation from excessive heat. It also aids combustion and cools the burner head. Water must also be sprayed on the rig to keep it cool and special attention must be given to the lifeboats. It is now normal for a rig to have a permanent spray system installed and water may be provided by the rig pumps. The burners have propane pilot lights which are ignited using a remote spark ignition system. For heavy/viscous oil tests a large quantity of propane may be required. If this is the case, mud burners should be requested, as they are specially designed to handle oil-based mud. They can also better handle the clean-up flow. Alternatively, diesel can be spiked in at the oil manifold using the cement pumps to assist combustion but, if there is only partial combustion, carry over can cause pollution. Oil slicks can also be ignited and be a hazard to the rig. If a heavy/viscous oil production test is planned, sufficient gauge tanks should be on hand to conduct a test without flaring the oil. Figure 7.A - Surface Equipment Layout


7.2. EMERGENCY SHUT DOWN SYSTEM The Emergency Shut Down (ESD) system is the primary safety system in the event of an uncontrolled escape of hydrocarbons at surface. The system consists of a hydraulically or pneumatically operated flow head flow wing valve, control panel and a number of remotely air operated pilot valves. When a pilot or the main valve in the panel is actuated, it causes a loss of air pressure in turn dropping out the main hydraulic valve which releases the pressure from the flow head ESD valve actuator. The push button operated pilot valves are strategically placed at designated accessible areas where the test crew and/or rig crew can actuate them by pushing the button when they observe


an emergency situation. Other pilots may be high or low pressure actuated pilots installed at critical points in the system to protect equipment from over-pressure or under-pressure which would indicate an upstream valve closure, blockage or leak etc. The system is also actuated if a hose is cut or melted by heat from a fire, also releasing the air pressure.

7.3. ACCESSORY EQUIPMENT

7.3.1. Chemical Injection Pump The main chemicals that are injected into the production flow are hydrate inhibitors, de-foamers, de-emulsifiers and wax inhibitors. The chemicals are injected by an air driven chemical injection pump at, either the data/injection header, flow head or at the SSTT/subsurface safety valve. Chemicals must be supplied with toxicological and safety data sheets as per regulations.

7.3.2. Sand Detectors Sonic type sand detectors can be installed at the data/injection header upstream of the choke if sand production is expected to cause erosion. These devices operate by detecting the impingement of sand on a probe inserted into the flow stream. The accuracy is reasonable in single phase gas flow but less consistent in multi-phase flow. The simplest approach to sand detection is to take frequent BS&W sample at the data/injection manifold to monitor for sand production. If the flow rates are low, samples taken from the high side of flow line might incorrectly show little or no sand, therefore a suitable sample point must also be available on the low side of the manifold. Samples should then be collected from both points. The problem with this method is determining if the sand is causing erosion or not. An erosion coupon or probe can also be installed on the manifold which will indicate if erosion is occurring. When sand production is anticipated on a test, sand traps should be employed. These large, high pressure vessels would be situated upstream of the choke manifold and remove the sand before it reaches the higher velocity flow rates at the choke. Control of the flow rate also can prevent erosion by keeping it below the point where sand is lifted up the wellbore to surface; however, this inflicts severe limitations on the test design. Erosion can eventually cause:

Reduced pipe wall thickness and cutting of holes in pipe work, including valves and chokes.

Damaging (sandblasting) the separator and filling it with sand.

Cutting out of burner nozzles.

Sanding up the well and possibly plugging of down-hole test tools.

7.3.3. Crossovers Crossovers warrant special attention They are of the utmost importance as they connect every piece of equipment in the test string which have differing threads. If crossovers have to be manufactured, they need to be tested and fully certified. In addition, they must be checked with each mating item of equipment before use.

7.4. RIG EQUIPMENT The main items of rig equipment used for testing, such as the permanent pipe work and water spray system have been addressed previously. However, it is essential that all the necessary rig


equipment which is to be used, has been checked. This includes the rig water pumps, cement pumps, mud pumps and the BOPs. The BOP rams must be dressed in accordance with the test program. Also there are some smaller items of equipment required which must be made available. These include; long bails for rigging up equipment above the flow head, rabbits for drifting the tubulars, TIW type safety valves with crossovers, tongs and other pipe-handling equipment, accurate instrumentation for monitoring annulus pressure, etc.

7.5. DATA GATHERING INSTRUMENTATION

This section describes the instrumentation required for measuring flow rates, pressures, temperatures, gas and fluid properties which is listed below:

7.5.1. Laboratory and Instrument Manifold Equipment

Hydrometer for measuring gravity of produced liquids.

Manometer for calibrating DP meters.

Shrinkage tester to allow the calculation of production in stock tank barrels.

Dead-weight tester for pressure gauge checking and calibration.

Gas gravity meter to measure gas gravity.

Centrifuge for determining BS&W content.

Selection of pressure gauges.

Draeger tubes for measuring H2S and CO2 concentrations.

Chemical injection pump.

Surface pressure recorder.

Water composition analysis test kit.

Vacuum pump for evacuating sample containers.

Down-hole sampling kit.

Hydrometer Deadweight Tester Gas Gravity Meter Pressure Gauges

Draeger Pump & Tubes Chemical Injection Pump Recorder Temperature Gauges

Some instrumentation is mounted on the test equipment such as:


7.5.2. Separator Oil flow meters on both separator oil lines.

Gas flow meter.

Thermometers.

Pressure gauges.

7.5.3. Surge Or Metering Tank

Sight glasses and graduated scales.

Thermometer.

Pressure Gauge.

7.5.4. Steam Heater

Temperature controller.

Other special instrumentation must be listed in the specific test program.

8. BHP DATA ACQUISITION The two of the most important parameters measured during well testing are down-hole pressures and temperatures. This data is obtained from BHP gauges installed as close to the perforations as is practicable. BHP gauges are either mechanical or electronic type gauges. The mechanical BHP gauge is rarely used today as it accuracy does not generally meet the demands of engineers for modern analysis. It does still have uses on high temperature wells where the temperature is above the limit of electronic gauges or when simple low cost surveys are required; for instance, to obtain bottom hole pressure before a workover. They are cheaper due to the lower gauge purchase cost and because it is not necessary to have a gauge specialist to run them. The electronic gauge is used in most circumstances and there are a number of different models on the market with a wide range of accuracy and temperature specifications to meet various test demands. It is critical to ensure that the gauge selected is fit for purpose as some of the higher accuracy gauges are more susceptible to damage like the crystal gauge and also more expensive. The criteria used should be to select the most robust and cost competitive gauge which meets the test requirements. Currently there are three basic types of pressure sensors used in electronic gauges available: Quartz Crystal, Capacitance, and Strain. The electronic gauge can operate through an electric cable for surface read out in real time but more generally is run with an memory section which stores the data electronically on chips. The early gauges had a very limited storage capacity of around 2.5K data points but this has dramatically increased where gauges now have up to 500K. They can also be programmed to change the sampling speed at various times and/or on pressure change

points in the test. Both mechanical and electronic types of gauges are listed below in order of decreasing accuracy. 8.1.1. Quartz Crystal Gauge

The principle of the gauge is the change in capacitance of the sensor crystal when pressure is applied. The gauge has two quartz crystals, one sensor and one reference crystal. The change in capacitance of the sensor crystal is measured by the change in frequency of an oscillating circuit. The resultant frequency is converted to a pressure. This type of gauge is the most accurate available. Poor temperature resolution used to be the Achilles heel of the crystal gauge but modern gauges have overcome this problems by having the temperature sensor built into the crystal assembly. The tool is comparatively delicate because of the fragility of the crystals.


8.1.2. Capacitance Gauge

The principle of this gauge is similar to the quartz crystal gauge. The difference is that a quartz substrate is used instead of a crystal. The gauge accuracy is between that of the quartz and the strain gauge but is much more robust than the crystal gauge. It did not suffer from poor temperature resolution like the earlier crystal gauges as the temperature sensor is an integral part of the pressure diaphragm.

8.1.3. Strain Gauge The strain gauge principle works on the deflection of a diaphragm. Pressure acting one side of the diaphragm causes the deflection which is measured and translated into pressure. The accuracy of the gauge is lower than the quartz or the capacitance. This type of gauge is extremely robust and is not affected by temperature changes.

8.1.4. Bourdon Tube Gauge This is a mechanical gauge and was the first type of pressure gauge and is very robust. The most common manufacturers were Amerada and Kuster. The well pressure elastically deforms a Bourdon tube, the deflection of which is scribed directly on a time chart. After recovery of the chart it is read and translated into pressure. Charts can be read with hand operated chart reader or electronically by a computerized chart reader. The gauge accuracy is much lower than any of the electronic gauges.

8.2. GAUGE INSTALLATION As pointed out in the previous section, the gauges should be installed as deep as possible in the well in order to obtain pressure and temperature data as near to formation conditions as possible. On a well test this can be done by one of two methods: tubing conveyed or on wire-line.

8.2.1. Tubing Conveyed Gauges

The normal means of running gauges on the test string is in gauge carriers but other SRO systems have been developed to obtain data from down-hole gauges without having to pull the string. This is an advancement in technology which means the data can be verified before curtailing the test. This is extremely useful in very tight reservoirs where the end of the flow or build up periods is difficult to predict and determine. In these tools the gauges are mounted in a housing which is ported to below the tester valve.

8.2.2. Gauge Carriers Gauges may be placed in gauge carriers, which are installed in the test string as it is being run and are retrieved at the end of the test when the string is pulled. A minimum of two gauge carriers with at least four gauges should be run. Depending upon the test string design, they may be installed above the packer sensing tubing pressure or possibly with one below the packer to sense pressure as close as possible to the reservoir. Irrespective of the position relative to the packer, they must be run below the tester valve to obtain build up data. Below packer gauges are of simpler design as they are not pressure containing or require porting to the tubing. Each carrier should contain at least two gauges, and at least two of the total should be of the capacitance type of gauge. By running at least one carrier above a retrievable type packer, some data can be retrieved if the packer becomes stuck by backing the string off at the safety joint. Also, the packer absorbs some shock from tubing conveyed guns providing protection for the upper gauges.


8.2.3. SRO Combination Gauges Systems which allow the databanks of the gauges run in the upper gauge case to be read have been developed. The disadvantages of the SRO system are thus eliminated as the gauges may be read continually or periodically. However is not good practice to run the interrogating tool until the well has been cleaned up. In the early days, these systems proved to be very unreliable but great advances have since been made. The latest systems use tried and proven tester valves for the down-hole closure which are ported to above the valve to a bank of memory gauges or transducers. The tool gathers and stores the data until the interrogation tool is run by electric line into the memory section housing where it can communicate with the memory section to download the data. These data are usually transmitted through an inductive coupling or similar type device. Obviously the tool must be run during a shut-in period. It is advisable that the tool is not stationed in the well, i.e. latched into the housing, during flow periods unless absolutely necessary. This reduces the risk from becoming stuck due to sand production or the wire getting cut through flow erosion.

8.2.4. Wire-line Conveyed Gauges

There are two systems for running memory gauges using wire-line techniques. The first is to place a nipple below the perforated tailpipe and to run and set the gauges in this nipple prior to performing the test. The second method is to use an SRO electronic gauge run and positioned in the well on electric line which gives a real time direct readout of parameters at surface. A version of this method can provide build up data in conjunction with a down-hole shut-in tool, similar to the SRO systems described earlier, except they use wire tension to open and close a separate shut-in mechanism, usually a sliding sleeve type device.

8.2.5. Memory Gauges Run on Slick-line A number of memory gauges, usually three but can be as many a physically possible, may be run in on slick-line and set in a nipple positioned below the perforated joint. The advantages of this system are that the well may be shut-in down-hole, eliminating after flow effects. Also the gauges may be recovered, e.g. after the first build-up, and the data interpreted before completing the test. This system should be considered in wells producing fluids which are corrosive to the electric line, and where long exposure is to be avoided. Gauges are generally run with a shock absorber to avoid damage from shock during the trip or when setting the wire-line BHP gauge hanger.

8.2.6. Electronic Gauges Run on Electric Line Gauges may be run on electric line to give a real-time readout of data at surface. This is called surface readout (SRO). In some versions the well must be shut-in at surface confusing the build-up data with after flow effects. However, there are now systems which allow the well to be shut-in down-hole and still have SRO. The disadvantages of this method are that the electric line must remain in the hole during the test, unless using a SRO combination tool described above. Considerable difficulty may be encountered in landing this type of tool in its receptacle after perforating the well. The tool is not robust enough to be landed before perforating and debris may obstruct the nipple after the initial flow. It is highly desirable to clean up the well before running this type of equipment.

9. PERFORATING SYSTEMS


Two methods are currently used to perforate wells: wire-line conveyed guns or tubing conveyed guns. Tubing conveyed perforating is the Companys preferred method for well test operations, as the zones to be tested can be perforated underbalanced in one run, with large charges. However, under some circumstances wire-line conveyed guns may still be preferred. Both methods are described in the following sections. The type of explosive to be used is dependant mainly on the bottom hole temperature and the length of time the guns are likely to be on bottom before firing (Refer to the Completion Manual-Perforating Section)

9.1. TUBING CONVEYED PERFORATING

With this method the guns are run in the hole on the bottom of well testing string. Therefore, the guns and charge size can be maximized for optimum perforation efficiency and long perforation intervals can be fired in a single run. If required, a bull nose can be installed on the bottom of guns to allow the test string to enter liner tops. Various methods of detonation can be utilized, depending on well conditions.

9.2. WIRE-LINE CONVEYED PERFORATING

There are two alternatives when perforating using wire-line conveyed guns: casing guns or through-tubing guns. In both cases depth control is provided by running a Casing Collar Locator (CCL) above the guns and the guns are fired by electrical signal. Casing guns are large diameter perforators which cannot be run through normal tubing size. Therefore they must be used prior to run the test string and in overbalance conditions. Through-tubing guns are small diameter guns run through the test string. They can be used to perforate under-balance, reducing the risk of damaging the formation with brine or mud invasion immediately after perforating. The largest gun which can be safety run through the standard test tools (2.25ins ID) is a 111/16.


Fig. Tubing Conveyed Perforating Fig. Wireline Perforating 9.3. PROCEDURES FOR PERFORATING

Procedures to be observed when perforating a production casing/liner are the following: a) Operations involving the use of explosives shall only be performed by Contractor's

specialized personnel in charge for casing perforation. The number of person involved shall be as low as possible. Only the Contractor's operator is allowed to control electric circuits, to load and unload guns.

b) Nobody else, except for Contractor's operators, is allowed to remain in the hazardous area during gun loading and tripping in and out of the hole.

c) Explosives shall be kept on the rig for the shortest possible time and during such time they shall be stored in a designated locked container, marked with international recognized explosive signs.

d) Any remainder at the end of the test shall be returned to shore. e) Maximum care shall be taken during transportation, loading and back-loading of explosive.

Explosive and detonators shall always be transported and stored in separate containers. This also applies to defective detonators which have been removed from a misfired gun. Transportation of primed gun is not allowed; explosive shall be transported unarmed.

f) Explosive should never be stored in the vicinity of other hazardous materials, e.g. flammable or combustible liquids, compressed gases and welding equipment.

g) Precise record must be kept of all explosives received, stowed or off-loaded.


h) Warning signals shall surround the hazardous area where explosives are used. i) As an electric potential could trigger the detonators, any source of such potential shall be

switched off to avoid premature detonation. Such sources include any radio transmitter (including crane radios) and welding equipment.

The Company Drilling and Completion Supervisor shall collect all portable radios inside company office in order to avoid any possibility of untimely use. Radio silence shall be observed while guns are being primed and while primed guns are above seabed.

j) The following shall be advised prior to radio silence being in force:

Stand by vessel.

Helicopter operations.

Company Shore Base.

Other nearby installations. k) In the event of uncontrollable sources of potential such as thunderstorms, operations

involving the use of explosive shall be suspended. The only exception to the precaution mentioned above is the SAFE (Slapper Activated Firing Equipment) which can be operated, under any weather condition, during radio transmissions and welding operations.

l) Inspections shall be done to make sure that no electric field is generated between the well and the rig (max. allowable potential difference is 0.25 V). In the event this voltage is exceeded, all sources of electrical energy must be switched off (this may preclude perforating at night).

m) When the casing is perforated before running the DST string, mud level in the well shall be visually monitored.

n) When the casing is perforated before running the DST string, the well must be filled with a fluid whose density shall be equal to the mud weight used for drilling, unless reliable information would indicate a formation pressure allowing for a lower density.

o) The same principle applies for the weight of the fluid in the tubing/casing annulus when perforating after the DST string has been run.

p) The first casing perforation shall be performed in daylight. Subsequent series of shots can be carried out at any time.

10. PREPARING THE WELL FOR TESTING

This section describes the operations necessary to prepare the well for well testing. 10.1. PREPARATORY OPERATIONS FOR TESTING

10.1.1. Guidelines For Testing 7ins Liner Lap 1) While waiting on cement, test the BOP stack according to the Company Well Control

Policy Manual procedures. Pull out of the hole with the test tool. 2) Run a 6ins bit/mill and clean out the 7ins liner to the landing collar (PBTD). The

drilling program must allow for sufficient rat hole to enable TCP guns to be dropped off, if required.

3) Run a cement bond/correlation log from PBTD to top of 7ins liner. 4) Run in hole with 95/8ins packer assembly and perform positive and negative tests on

liner lap as per the Company Drilling and Completion Supervisors instructions. As a guideline, conduct a positive test of the liner lap by applying approximately 400psi pressure. Ensure that the burst rating of the 95/8ins casing is not exceeded. Displace the required amount of fluid from the drill pipe with base oil to give an approximate drawdown on the liner lap and liner of 500psig in excess of maximum drawdown pressure planned for the individual wells. Set the packer and monitor the well head


pressure for influx for 1hr. If the liner lap or liner is found to be leaking then a remedial cementing program will be advised.

10.1.2. Guidelines For Testing 95/8ins Liner Lap

1) While waiting on cement, test the BOP stack according to the Company Well Control Policy Manual procedures. Pull out of the hole with the test tool.

2) Run a 81/2ins bit/mill and clean out the 95/8ins casing to the landing collar (PBTD). The drilling program must allow for sufficient rat hole to enable TCP guns to be dropped off, if required.

3) Run a cement bond/correlation log from PBTD to ab

kdp well test procedures manual

Documents

valve bypass valve

lubricator valve

retainer valve

pipe tester valve

test fluid

test package

company junior drilling

hole tester valve