sonatrachs problem well analysis

8/11/2019 Sonatrachs Problem Well Analysis

1/42

Development Phase

September October 2005abalt solutions limited - 2005

INTRODUCTION TO HYDROCARBON EXPLOITATION

Introduction to Hydrocarbon Exploitation

2005 Abalt Solutions Limited. All rights reserved

Problem Well Analysis

Pratap Thimaiah

Problem

WellAnalysis


Problem Well Analysis

Surveillance

Getting Started

What is a problem well?

Inflow restrictions

Outflow restrictions

Reservoir Problems

Artificial Lift

Mechanical Failures

Sand Control

Re-completions

Plug and Abandonment

Workover Economics


2/42

Development Phase



Problem

WellAnalysis


Surveillance

Monitoring of the asset to optimally recover the oil and gasreserves in a timely fashion through safe and profitable

operations

Critical for the future profitability of the field

Entire Business UnitAnalysis

Identification of well problemsor

field problems

Problem Definition

Production and operating cost problems

Problem Analysis

- Continue to produce well's) with no change,

- Collect additional data,- Workover and/or stimulation,- Equipment change,- Operations procedures changes),- Re-completion,- Pressure maintenance,

- Enhanced recovery operation, or- Shut-in and abandonment

Solutions

Generation

Reservoir A

Reservoir B

Reservoir C

Reservoir D

Problem

WellAnalysis


Getting Started

Essential data must be in hand like:

Well test plots

Daily production plots

Wellbore diagram

Base open-hole log

Production plot, oil, gas, water, and GOR. Exponential decline.Log-log plot of two well tests shows wellbore storagereduction with downhole shut-in

Plot of the bottom-hole flow rate and pressure

recorded during a drawdown test

Schlumberger

Schlum berger


3/42

Development Phase



Problem

WellAnalysis


Getting Started

Wellbore diagram

Must include both the measuredand true vertical depths oftubulars, perforations, packers,and all subsurface equipment.

Outer diameter and internaldiameters of each item.

Tight spots

Junk in hole

Potential problem areas Reference elevation

Type connection in the wellheadfor production logging described

Schlumberger

Typical deepwater well completion

Problem

WellAnalysis


Getting Started

Base Openhole Log

Open perforations must beshown for each well.

Cased hole gamma ray

and porosity log could beof help.

Casing collar depths and

any radioactive markerdepths should always be

shown at the properdepths on the base log.

GOC and WOC should beshown when available.

GRC0 150

SPCMV-160 40

ACAL6 16

ILDC0.2 200

SNC0.2 200

MLLCF0.2 200

RHOC1 .9 5 2 .9 5

CNLLC0.45 -0.15

DTus/f150 50

001) BONANZA 1

10700

10800

10900


4/42

Development Phase



Problem

WellAnalysis


Problem Well Defined


Problem

WellAnalysis


Problem Well Defined


Low oil or gas production

High GOR

High water cut

Mechanical problems

Should be differentiated from a reservoirproblem


5/42

Development Phase



Problem

WellAnalysis


Inflow Restrictions

Wellbore plugging

Perforation restrictions

Formation Damage

Scale deposit in Tubing

Potentially damaging fines

Problem

WellAnalysis


Inflow Restrictions

Such damage may be indicated by:

Production well tests

Pressure build-up and drawdown tests

Comparison with offset wells

Analysis of production history Effect of wellbore damage on productivity

Difference between pressure drawdown in undamaged and

damaged reservoirs. 50% of p occurs in last 15 ft.

pressure

Damage zone


6/42

Development Phase



Problem

WellAnalysis


Inflow Restrictions

Procedure in surveillance for problem wells:

If the monthly production test rate has decreased morethan 10 percent from normal decline retest the wellimmediately.

Review adjacent wells for abnormal decline. If a number ofwells in an area have significant declines, the problem maybe reservoir related.

Check the well for mechanical problems; especially if onartificial lift.

Check for wellbore fill-up.

Check for changes in backpressure or operating procedures.

Consider the need for production logs or pressure surveysto confirm damage.

If damage is confirmed, take corrective action. Use caution on stimulation if near gas-oil or water-oil contacts

Recommend bold action for low rate wells

Use some restrain on high rate wells, however they may offerthe highest potential again.

Problem

WellAnalysis


Wellbore Plugging

Flow restrictions in the wellbore is often formation fill or scale.

For flowing or gas lifted wells, provided the tubing is open-ended, where there is fill across the formation, a coiled tubingunit are commonly used for cleanout.

For pumping wells it may be necessary to pull the tubing before

clean-out.

Inorganic scale in the wellbore and perforation is a commonproblem that can easily reduce production.

Sodium chloride salt

Calcium carbonate

Gypsum

Barium and strontium chloride


7/42

Development Phase



Problem

WellAnalysis


Perforation Restrictions

Cause by perforation plugging or inadequate perforations

Considerable effort should be made on completion toensure that the perforations are open and undamaged

Avoid loss of dirty water of dirty water into the formationwhich may plug both the perforations and the formationpores.

Solutions range from re-perforation, wash the

perforations, surge the formation, or to even fracture theformation.

Problem

WellAnalysis


Formation Damage

Impairment of well productivity or injectivity

due to

Plugging within the perforations

Formation pores adjacent to the wellbore

Fractures communicating with the wellbore

The procedure to follow:

Determine the degree of well damage (skin)

Causes of damage

Approach to alleviate the damage


8/42

Development Phase



Problem

WellAnalysis


Formation Damage

Paraffin or Asphaltene Plugging

Emulsion Blocks

Water blocking

Fine Particles

Problem

WellAnalysis


Outflow Restrictions

Increase the backpressure

Limit drawdown

Reduce production

Some cases:

Tubing smaller than optimum will cause extra

friction losses

Larger than optimum will increase slippage and

may cause the well to load up and die.

On a pumping well, to small a tubing may restrict

the lift equipment or cause friction, which willincrease lift energy requirements.


9/42

Development Phase



Problem

WellAnalysis



Inflow and outflow performance curves canhelp determine if a tubing size change is

justified.

Well system analysis. Node selected at perforation outlet

Problem

WellAnalysis



The production well test should report the wellhead pressure. If

it is relatively high, and outflow analysis should be undertaken.

If the pressure has recently increased, then possible

plugging in the outflow system should be checked.

If the pressure is normally high, the investigate why it ishigh.

Are there any gas sales pressure limitations?

Are there compressors that require a fixed suction pressure?

Can it be economically lowered?

What is the pressure drop between the wellhead and the

separator?

Is there a surface choke on the well and what is its size?

On pumping wells, is the annulus vented into the flowline?

Are there any downhole restrictions?


10/42

Development Phase



Problem

WellAnalysis


Reservoir Problems

Low reservoir permeability

Low reservoir pressure

Water production problems

Gas problems in gas wells

High Viscosity Oil

Problem

WellAnalysis



May be an overall reservoir characteristic or limited to aspecific area.

Should be considered along with other causes of lowproductivity.

Usually well productivity declines rapidly as fluids nearthe wellbore are produced.

Production tests may aid in differentiating between lowpermeability and formation damage.

Matrix acidizing of low permeability undamagedreservoirs can only provide a small productivity increase.


11/42

Development Phase



Problem

WellAnalysis



Effect of matrix acidizing an undamaged well.

Problem

WellAnalysis


Low reservoir pressure

Should be documented by periodic subsurface measurements.

Dominant reservoir drives in a particular reservoir should be

considered and how these drive mechanisms are associatedwith the real or apparent well problem being investigated.

Prior to considering workover of wells in a low or partiallypressure-depleted oil reservoir, an effective artificial lift shouldbe planned.

Pressure maintenance or an enhanced recovery programme isusually the best long range approach to increase productionrate and oil or gas recovery from partially pressure-depleted

reservoirs.


12/42

Development Phase



Problem

WellAnalysis


Low Reservoir Pressure

Typical pressure-production history for variousreservoir-drive mechanisms.

Problem

WellAnalysis



May result from:

Natural water drive or Waterflood, aggravated byfingering or conning.

Extraneous sources including casing leaks orcementing failures.

Fracturing or acidizing into adjacent water zonesor to below the water-oil contact.


13/42

Development Phase



Problem

WellAnalysis



Water encroachment is normal in a water drive reservoir. Three

water-oil contacts may usually be defined in oil wells:

Lower water-oil contact

Producing water-oil contact

Completion water-oil contact

Problem

WellAnalysis



Fingering

Water conning

Water channelling

Conning of WaterIrregular water encroachment in heterogeneousreservoir can result in early water breakthrough.


14/42

Development Phase



Problem

WellAnalysis


Cements

Resins and hard set chemicals

Gel treatments

Swelling chemicals & particulates

Relative permeability modifiers

Water Production- Chemical Control Techniques

Problem

WellAnalysis


Quick reference guide-Treatment options for excess water



15/42

Development Phase



Problem

WellAnalysis


Cement solutions

Casing & tubing leaks

Channels behind casing

If primary cement job fails

Squeeze cementing


Problem

WellAnalysis


Resins and other hard set chemicals

Low viscosity chemical mixtures that set up as

solid or hard inert plastic.

Resins are phenolic or epoxy base types.

Used in casing patches Plug off cement channels and perforations



16/42

Development Phase



Problem

WellAnalysis


Gel treatments

Low viscosity chemical mixtures that stiffen atvarying degrees of temperatures.

Reduce or totally block a channel or high-permeability rock matrix zone through whichexcess water is flowing into wellbore.

Carried out by mechanically isolating only thezone, fractures or perforations that are thesource

Heavy metal cross linkers such as Chrome oraluminium based


Problem

WellAnalysis




17/42

Development Phase



Problem

WellAnalysis


Placement Techniques

Bullheading

Mechanical packer placement

Chemical packer placement

Dual injection

Iso-flow placement

Transient placement

Problem

WellAnalysis


Bullheading

Injection of chemicals

through existingTubulars.

Used only when it is

determined thataqueous injectionfluids will only enterthose waterproducing zones that

are shut-in



18/42

Development Phase



Problem

WellAnalysis


Mechanical/Inflatable Packer

Selective zones areisolated using packers.

In complex situations, itmaybe necessary toisolate perforations thatare producing oil fromboth above and below thezone- Inflatable DualPacker System

Chemical Packers In gravel packed or open

hole completions wheremechanical packerscannot be used.


Problem

WellAnalysis


Dual Injection Placement Compatible fluids are injected down the

tubing and also annulus.

Packers, bridge plugs, chemical plugs andother mechanical isolation means can beused.

Efficient placement

To protects critical perforations inhydrocarbon zones-Non-sealing fluidcompatible with formation is used.



19/42

Development Phase



Problem

WellAnalysis


Isoflow Placement Alternative to dual injection

system.

Chemicals are directed intoselected intervals whileprotecting hydrocarbonproducing or bearing zonesby simultaneous injection ofnon-sealing formationcompatible fluid.

Gamma ray logging tools are

used to locate and track fluidinterface.

Suited for both wells withnegative surface pressuresand static fluids when shutin.


Problem

WellAnalysis


Inner Liners

Patches

Packers

Sliding sleeves

Plugs

Water Production- Mechanical Techniques


20/42

Development Phase



Problem

WellAnalysis


Casing cladding

Thermally set compositematerials used to formpatches to fix damageTubulars.

Using inflatable systems tocarry composite materialsinto the well.

Materials are usuallythermally setting resins andcarbon fibres built into asleeve wrapped around thedevice.

Once device is opposite the

area to be treated, device isinflated to push compositesleeve into place movingupwards.

After inflation, the sleeve isheated to harden andconform to casing.

Electric resistors provideheating.


Problem

WellAnalysis


Packer straddle

Its a combination

of packers, slidingsleeves and othertools to isolateexcess waterproduction zones

or areas ofdamaged pipe.



21/42

Development Phase



Problem

WellAnalysis


Bridge Plugs

Run and set toplug off waterentering thebottom of well or

perforations.

Essentially plugs-

off remainder ofwell or tubing

from the point ofsetting all theway to bottom of

the well.


Problem

WellAnalysis


Gas problems in Oil wells

The primary sources of gas in oil wells are:

Gas dissolved in the oil

Primary or secondary gas caps which may expand, and

Gas flow from zones or reservoirs above or below the oil zone

Normal GOR behaviour corresponding to the drive mechanism for any

particular reservoir must be considered in problem well analysis.

Characteristic gas-oil performance for various reservoir-drive mechanisms


22/42

Development Phase



Problem

WellAnalysis


Gas problems in oil wells

Gas flow from zones above or below the oilzone may be due to:

Casing leaks

Poor cement job

Natural or induced fractures communicating withgas zone

Gas flow due to channel behind the casing

Reservoir with a gas cap

Problem due to gas conning

Problem due to gas cap expansion

Problem

WellAnalysis


High Viscosity Oil

High viscosity is sometimes defined as oil with less than16 API gravity. Viscosities grater than 200 cp often causeserious flowing and pumping problems.

Thermal stimulation may be applicable, howevereconomics should be carefully reviewed.

It the well tubing, casing, cement job, and packerinstallation has not been designed to withstand hightemperature steam, thermal stimulation may causesevere mechanical damage to the well.

Alternative to Thermal Stimulation of the Reservoir canbe considered.


23/42

Development Phase



Problem

WellAnalysis


Artificial Lift

Most wells will probably require some sort of artificial lift before

abandonment to increase drawdown and thus production.

Selection

Revenue due to oil and gas production

Operating costs, and

Initial capital costs

Factors contributing to economics of

artificial lift systems

Problem

WellAnalysis


Sucker Rod PumpingWalking Beam

Pitman Arm

Saddle Bearing

Horsehead

Bridle

Hanger

Ladder

Wrist

PinCrank Arm

Counterweight

Prime

MoverBrake

Lever

Base

Samson

Post

Equalizer

Bearing

Brake

Cable

Polished Rod

Stuffing Box Seal

Flow Line

Flow Tee

Rod String

Downhole Pump

Production Tubing

Production Casing

Drawings Courtesy of Lufkin Industries, Inc. Lufkin, Texas


24/42

Development Phase



Problem

WellAnalysis


Sucker Rod Pumping

Analysis:

Check the well test production rates. Is the rate limited by thepump displacement.

If the well cannot be pumped off, or pumped down to a low intakepressure with the existing equipment on the well, determine if a

larger unit is justified.

If the well is pumped off, use time cycle to alter displacement tomatch formation inflow.

If test rates suddenly decline on a well, check for mechanicalproblems.

If decline in test rate is not a mechanical problem, then formation

damage, fill in annulus or perforation plugging may be the problem. Gas interferences is a common problem on many pumping wells.

Where feasible vent the gas up the annulus and pump the oil andwater up the tubing.

Corrosion and scale are often major problems in pumping wells.

Paraffin deposition is another common problem.

Problem

WellAnalysis


Gas Lift

Continuous Flow

Intermittent liftGas Lift Systems

Injected

gas

Injected

gas

Continuous gas lift Intermittent gas lift


25/42

Development Phase



Problem

WellAnalysis


Gas Lift

Liquid

Gas entry

TubingCasing

Production

Gas in

Liquid

TubingCasing

Gas in

Production

Annular gas injection Tubing gas injection

Problem

WellAnalysis


Gas Lift Surveillance and OperatingProblems

Good well tests are essential to gas lift operation.

Periodic flowing pressure bottom-hole pressure surveys arerecommended.

Temperature surveys are often beneficial for both designpurposes and troubleshooting.

Sonic devices can be used to shoot fluid levels in the annulus ofgas lifted wells.

To produce at maximum rates, the injection gas depths shouldbe at maximum depths.

If there is a decrease in production test rate, the data shouldbe carefully reviewed.

In intermittent gas lift there are additional producing problemsto consider.

Check the flowing wellhead test pressures. High back pressureis normally very detrimental to gas lift operations.


26/42

Development Phase



Problem

WellAnalysis


Electrical Submersible Pumping

Perfs.

Seal

Pump intake

Pump

Tubing

Check valve (optional)

Drain valve (optional)

Casing

MotorPothead

Motor flat splice

Motor flat cable

Primary cable

Production

WellheadJunction

box

Motor

controller

Transformers

Problem

WellAnalysis


ESP Motor Problems

Major causes of motoroverheating

Overloading

Well pumped off

Gas locked

Stuck pump

Lack of cooling tubing or casing leak, scale,

motor laying against thecasing

Bearing

Motor thrust bearing

components & complete


27/42

Development Phase



Problem

WellAnalysis


Problems with ESP's

Cable failure (generally due to fluids penetrating the covering)

Protector leakage (fluids may contact motor)

Too much free gas

Burnt motor can be caused by:

Contact with fluids due to protector leakage

Poor fluid circulation around motor for cooling

Corrosion of motor housing

Pump failure can be caused by

Solids

Pumping at rates/pressures outside of designed range

Problem

WellAnalysis


Identifying problems with ESPs

May notice gradual increase in power usage and gradualdecrease in flow rate as indicators of pump problems

Power spikes and frequent automatic shut-downs mayindicate electrical leakages or other problems

Check for solids in fluid

Tubing, cable, and pump must be pulled to find exactcause of a problem. Spool required to handle cable

Pump, seal, motor, and cable must be sent tomanufacturer for testing in order to locate the exactproblem


28/42

Development Phase



Problem

WellAnalysis


Electrical Submersible Pumping

Requires a rather precise design

Good operating practices

Careful equipment selection and repair

Reliable field electrical system

Stable operating conditions, and onlymoderately high temperatures for successful

operation over well life

Selection of the electrical cable should provide

five years or longer trouble-free operating life. ESP are adversely affected by free-gas, sand,

scale, and corrosion.

Problem

WellAnalysis


ESP Surveillance and Analysis

Well production test are the basic surveillance

method

A pump size should be chosen that will not

pump the well off. Minimum pump intake

pressures of 250 psig may be feasible, but 500psig is a more realistic design.

Electrical problems are common and mustreceive prompt attention. Good lighting

protectors are essential in many areas.


29/42

Development Phase



Problem

WellAnalysis


Hydraulic Pump and Jet System

Power fluid

Pump tubing

Casing

NozzleProduction inlet

chamber

Throat

Diffuser

Combinedfluid return

Well production

Jet pump

Problem

WellAnalysis


Hydraulic Pump and Jet System

Engine

Pump

Power fluidinjection

Power fluid return

Production

(A)Closed power

fluid system

Engine

Pump

Production and returnPower fluid

injection

(B)Open power

fluid system

Production andreturn

Pump

Engine

Power fluid injection

(C)

Open powerfluid system

(free pump)


30/42

Development Phase



Problem

WellAnalysis


Hydraulic Pump and Jet Systems

The user has several options in the design andinstallation of hydraulic reciprocating pumps:

Individual well units, or a central system

Standard fixed pumps, or free pumps

Open, or closed power oil systems, and

Vented, or non-vented gas systems

Clean power fluid, normally oil, is essential togood pump runs.

Problem

WellAnalysis


Hydraulic Pumping Surveillance

Well production tests are the primary means ofsurveillance. The test data includes the oil, water and,gas rates plus the injection power fluid rate and pressureand the wellhead pressure.

A significant decline in production rate my result from

formation damage (skin) or be from inadequate pumpdisplacement, pump wear, pump gas interferenceproblems, or leaks.

Leaks are more likely in hydraulic systems sincepressures are higher and there is more exposure due tothe use of power oil lines and power fluid tubing.


31/42

Development Phase



Problem

WellAnalysis


Mechanical Failure in Wells

Different types of mechanical failures can causeloss of production and/or increase costs in well

operation. More common problems are:

Primary cement channelling

Casing, tubing, and packer leaks,

Artificial lift equipment, and

Well equipment, like wellheads, subsurfacevalves, sliding sleeves, etc.

Problem

WellAnalysis


Sand Control

Wells that sand-up or produce more than 0.1

percent sand are often good candidates forsand control.


32/42

Development Phase



Problem

WellAnalysis


Unconsolidated Consolidated

Zero strength Very very weak Very weak Consolidated

Dry sand Damp sand Weakly-cemented Stronger cement

Sand Control

Problem

WellAnalysis


In weak but consolidated formations:

Stage 1

Failure

Stage 1

FailureStage 2

Transportation

Stage 2

Transportation

Failure of reservoir

rock due to shear stresses (failure of

bonds between grains)

Transportation offailed material due to

flow

Sand Control


33/42

Development Phase



Problem

WellAnalysis


Overburden

Friction

Differential Stresses

Cementing Material

Degree of Consolidation

Fluid Viscosity

Production Velocity

Water Production

Factors Affecting Sand Production

Problem

WellAnalysis


Failure may occur

due to:

Non uniformlateral loading asrock is produced.

High axialcompressive loaddue to slumping ofthe overlyingcasing-bearing

formation.

Sand Problems-Casing / Liner Collapse


34/42

Development Phase



Problem

WellAnalysis


Sand production can cause erosion in both surface and downhole

equipment such as :

Downhole

Blast Joints

Chokes

Gas lift Equipment

Elbows / Tees

Standing Valves

Pumps

Valves

Metering Devices Circulating sleeves

Flanges

Nipples

Wellhead

Tubular

Sand Problems- Erosion

Problem

WellAnalysis


Bridges may form in casing

or tubing and obstruct wellflow.

They must be removed by

bailing or washing with

concentric strings. If bridging is severe sand

control will be required.

Sand Problems- Erosion


35/42

Development Phase



Problem

WellAnalysis


Sand Control Methods

Restrictive Production Rate

In Situ Consolidation

Resin Coated Gravel

Gravel Pack

Screens - Natural Sand Packing (OH)

Expandable Sand Screens

Problem

WellAnalysis


Restrictive Production Rate Some weak formations have enough

strength to produce sand-free at lowrates.

Selective perforations placed in thestrongest formation (based on logs)

Rock properties may change during theproduction (i.e., water production).

In Situ Consolidation Resin material is pumped into the

formation.

Furan Resin glues formation grain-grain into a consolidated structure

Compressive strength >1,000 psi with60-75% retained permeability.



36/42

Development Phase



Problem

WellAnalysis


Resin Coated Gravel Proppant ( Gravel ) is pre-

coated with resinmaterial.

Particles are mixed withviscous gel and pumpedinto the formation.

Particles are contactedgrain-to-grain.

Temperature + H2O fusesthe particles together intoa consolidated permeable,drillable network.

Resin

Formation

Unconsolidated

Gravel


Problem

WellAnalysis


Natural Sand Packing (Screens) Installation of a screen system (no particles) in cased or open hole.

Main horizontal completion option.

Screen system can be :

slotted liner

pre-pack screen

wire wrapped Annular is eventually filled with formation sand.



37/42

Development Phase



Problem

WellAnalysis


Slotted liners One of the older methods of sand control.

They are tubing sections with a series of slots cut through the tubingwall in an axial orientation.

The slot width is designed to initiate inter-particle bridging across the

slot. It was originally considered that it should be twice the diameter ofthe 10 percentile sand grains .

There are two types of slot available, keystone and straight


Problem

WellAnalysis


Wire Wrapped There are three main types of wire-

wrap screen; rod-based screens, pipe-

based slip-on and pipe-based direct

build screens.

Normally made from triangular shaped

wrap wire

The gap between the edges of the

wrap wire is sufficient to allow quite

large sand grains to pass through.


p


38/42

Development Phase



Problem

WellAnalysis


Pre-packed screens Similar configuration to the wire

wrap but use a different filteringmedia.

A layer of resin-coated gravel is

placed around the internalscreen assembly and is

supported by a shroud or

external screen.

The thickness of the filtering

medium layer, and hence theoutside diameter of the screen

depends on the specific well

requirements.

Limitations in mechanical

strength


Problem

WellAnalysis


Premium screens

typically an all-metal design, with a metal mesh filtration media anda protective outer metal shroud.

The metal mesh can be either a metal weave or metal fibres orpowder particles embedded within a square metal mesh.

The apertures (called pore throats) generally very from 60 micronto 300 micron.

The concept is that the mesh will prevent the larger sand particlesfrom travelling through and allow the formation fines to pass.

Premium screens are typically run in long horizontals, often behindgravel packs and have similar sand control properties to pre-packscreens.



39/42

Development Phase



Problem

WellAnalysis


Gravel pack The annulus between the

wellbore and a sand controlscreen (wire wrapped, orpremium) is filled with gravelthat is sized to prevent sandfrom the formation passingthrough the pack.

Gravel packing in open-hole(EGP External Gravel Pack) isuseful for preventing annularflow and controlling sand inheterogeneous formations.

Gravel packing in cased-holes

(IGP Internal Gravel Pack) isuseful for protecting the sandscreens from erosion flow. Afterthe liner is run and perforated,the sand face completion isrun. The perforations may thenbe washed and the GP packerset.


Problem

WellAnalysis


Frac pack Improve the productivity of

a well by creating a short,wide fracture close to thewellbore.

A proppant is placed insidethe fracture that will bothhold open the fracture andcontrol sand production.

Frac packs are also termedhigh permeability fractures(HPF)

In Frac packing the fracturestend to be shorter but muchwider.

Typical frac pack crackwidths can be 1 inch orpotentially larger.

The lengths vary dependingon the design and areusually in the region of 20 to50 feet.

Fracture filled

with gravel

/proppant

wellbore packed

with screen in

wellbore

Wellbore free of

equipment

Fracture filled

with resin coated

gravel /proppant



40/42

Development Phase



Problem

WellAnalysis


ESS (ExpandableSand Screens)


Problem

WellAnalysis



41/42

Development Phase



Problem

WellAnalysis


Re-completion

Can be avoided by careful planning and anticipation of

problems on the initial well completion.

The usual workover procedure for changing zones or reservoirsin perforated casing completion is merely to squeeze cementand re-perforate in the new zone in the reservoir.

In open hole, it may be necessary to deepen or plug back, or tocement a liner and selectively perforate a specific zone in the

reservoir.

Changing the producing interval in both single and multiplecompletions are relatively simple operations if the operation

can be carried out through-tubing.

Problem

WellAnalysis


Plug and Abandonment

Most zones or reservoirs must be eventually plugged andabandoned.

Most governmental regulating bodies have specificguidelines that must be followed.

Careful considerations should be given to all optionsbefore plugging a well.

If a well is no longer economical to produce, has no useas a service well, or has no use as a service well, or hasserious mechanical conditions, then immediate stepsshould be taken to plug and abandon the zone.


42/42

Development Phase


Problem

WellAnalysis


Workover Economics

The team concept is a significant factor inoptimizing creative skill and imagination in:

Fact finding

Analysis

Experimentation

Job execution, and

Evaluation of results

Considering workover on programme basis

Profitability analysis

sonatrachs problem well analysis

Documents