work over

1Workover

WorkoverWorkover

2Workover

Course Aim

To introduce the candidate to the various methods of killing a production well safely with minimum formation damage.

To introduce the candidate to the various methods of killing a production well safely with minimum formation damage.

3Workover

Course Objectives

At the end of the course the candidate should be able to:

State the various reasons for killing a producing well prior to workover.

Identify the common methods of killing a producing well.

Identify the most appropriate method of killing a producing well.

List the well and reservoir parameters, and the various stages necessary to generate a well kill plan.

Perform hydrostatic calculations. Construct a well kill graph. Generate a procedure for killing a production well. Knowledgeably discuss problems in production well

kill and identify appropriate solutions.

At the end of the course the candidate should be able to:

State the various reasons for killing a producing well prior to workover.

Identify the common methods of killing a producing well.

Identify the most appropriate method of killing a producing well.

List the well and reservoir parameters, and the various stages necessary to generate a well kill plan.

Perform hydrostatic calculations. Construct a well kill graph. Generate a procedure for killing a production well. Knowledgeably discuss problems in production well

kill and identify appropriate solutions.

4Workover

Reasons for Workover

The main reasons for performing a workover are:

Increase production by bringing other productive zones on stream.

Eliminate excessive water or gas production. Maintain control of oil, water, and gas in

various zones or layers in stratified reservoirs. Remove obstructions to flow e.g. blockage

with sand, wax, or asphaltene. Enhance production through well stimulation. Repair mechanical failure of the completion

components.

The main reasons for performing a workover are:

Increase production by bringing other productive zones on stream.

Eliminate excessive water or gas production. Maintain control of oil, water, and gas in

various zones or layers in stratified reservoirs. Remove obstructions to flow e.g. blockage

with sand, wax, or asphaltene. Enhance production through well stimulation. Repair mechanical failure of the completion

components.

5Workover

Failures that require a full workover program are:

TRSV failure or leak.Casing, Tubing, or Packer leak.Casing or Tubing collapse.Cement failure.Gas lift system failure or inefficiency.ESP or Hydraulic Pump failure.Recovery of Fish unable to be recovered by

conventional methods.

Failures that require a full workover program are:

TRSV failure or leak.Casing, Tubing, or Packer leak.Casing or Tubing collapse.Cement failure.Gas lift system failure or inefficiency.ESP or Hydraulic Pump failure.Recovery of Fish unable to be recovered by

conventional methods.

Some mechanical failures of the completion can be repaired by Wireline or Coiled Tubing techniques.

Some mechanical failures of the completion can be repaired by Wireline or Coiled Tubing techniques.

Reasons for Workover

6Workover

Definition of Barrier

Define the term Well Barrier.Define the term Well Barrier.

7Workover

Well Barriers

Closed BarriersProduction Side Annulus Side

Wireline StuffingBox/Riser Envelope

Packer-TubingSystem

Grease InjectionHead/Riser Envelope

Tubing Hanger Tubing Head Spool

Coiled TubingStrippers/Riser

Envelope

Coiled Tubing CheckValves

SnubbingStrippers/Riser

Envelope

Snubbing StringCheck Valves

8Workover

Well Barriers

Closeable BarriersProduction Side Annulus Side

Xmas Tree Valves Casing Head SpoolOutlet valves

BOP Rams Tubing Hanger OutletValves

Annular Preventers

Shear-Seal Valves

Sub-Surface SafetyValves (?????)

Annulus Safety Valves(?????)

9Workover

Well Barriers

Additional BarriersProduction Side Annulus Side

Wireline Plugs

Tubing HangerPlugs

Packer Plugs

Bridge Plugs

Cement Plugs

Ice Plugs Ice Plugs

Additional downhole barriers may be installed either as a backup to a failed mechanical barrier or for the removal of the Xmas Tree.

Additional downhole barriers may be installed either as a backup to a failed mechanical barrier or for the removal of the Xmas Tree.

10

Workover

Additional Barrier

11

Workover

Additional Barrier

12

Workover

Additional Barrier

13

Workover

Barrier Philosophy

During well operations when surface primary pressure control equipment (Xmas Tree, BOPs, LMV repairs) is to be removed it will be Operating Companys policy to isolate the reservoir or formation with at least two independently tested barriers.

Where possible more than two barriers are preferred.

The same policy will apply to both the tubing and the annulus.

During well operations when surface primary pressure control equipment (Xmas Tree, BOPs, LMV repairs) is to be removed it will be Operating Companys policy to isolate the reservoir or formation with at least two independently tested barriers.

Where possible more than two barriers are preferred.

The same policy will apply to both the tubing and the annulus.

More than one barrier of each type is acceptable.More than one barrier of each type is acceptable.

At least one barrier below the sea bed.At least one barrier below the sea bed.

14

Workover

Barrier Philosophy

Barriers

Unperforated, cemented and pressure tested casing.

Unperforated cemented and tested liner with liner lap tested.

Wireline plug integrity tested using well pressure from below or pressure tested from above.

Permanent or retrievable bridge plug integrity tested using well pressure from below or pressure tested from above.

Cement plug verified by pressure or integrity testing.

Pressure tested tubing hanger seals (annulus barrier).

Pressure tested packer/PBR seals and tubing string (annulus barrier).

Kill weight fluid with well monitored, confirmed to be full of fluid, and static.

Possible Additional Barriers

Newly integrity tested SCSSV which will remain closed throughout.

BPV.

Integrity tested annulus safety valve (annulus barrier).

Barriers

Unperforated, cemented and pressure tested casing.

Unperforated cemented and tested liner with liner lap tested.

Wireline plug integrity tested using well pressure from below or pressure tested from above.

Permanent or retrievable bridge plug integrity tested using well pressure from below or pressure tested from above.

Cement plug verified by pressure or integrity testing.

Pressure tested tubing hanger seals (annulus barrier).

Pressure tested packer/PBR seals and tubing string (annulus barrier).

Kill weight fluid with well monitored, confirmed to be full of fluid, and static.

Possible Additional Barriers

Newly integrity tested SCSSV which will remain closed throughout.

BPV.

Integrity tested annulus safety valve (annulus barrier).

15

Workover

Barrier Philosophy

During well operations when part of the surface pressure control equipment is temporarily removed (e.g. wireline stuffing box, coiled tubing stuffing box, braided line grease tubes) at least two barriers will be in place or one barrier and the facility for closure of an additional containment device in the event of an emergency.

During well operations when part of the surface pressure control equipment is temporarily removed (e.g. wireline stuffing box, coiled tubing stuffing box, braided line grease tubes) at least two barriers will be in place or one barrier and the facility for closure of an additional containment device in the event of an emergency.

Barriers will be integrity tested before removal of any equipment.

Barriers will be integrity tested before removal of any equipment.

On Sub-Sea Wells, the facility must exist to bleed off sub-sea riser pressure below a surface barrier in the event of an emergency, after closure of a

sub-sea valve.

On Sub-Sea Wells, the facility must exist to bleed off sub-sea riser pressure below a surface barrier in the event of an emergency, after closure of a

sub-sea valve.

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Workover

Barrier Philosophy

Barriers (in addition to relevant barriers specified previously)

Closed wireline BOP rams.

Closed coiled tubing BOP rams.

Double coiled tubing check valves previously pressure tested.

Closed drilling BOP rams.

Closed shear-seal BOPs.

Possible Containment Devices

Cutting Xmas Tree for wireline.

Cutting LRP valve for wireline or coiled tubing (sub-sea operations).

Coiled Tubing BOPs.

Shear Seal BOPs.

Drilling BOPs.

Wireline BOPs (extra set).

Barriers (in addition to relevant barriers specified previously)

Closed wireline BOP rams.

Closed coiled tubing BOP rams.

Double coiled tubing check valves previously pressure tested.

Closed drilling BOP rams.

Closed shear-seal BOPs.

Possible Containment Devices

Cutting Xmas Tree for wireline.

Cutting LRP valve for wireline or coiled tubing (sub-sea operations).

Coiled Tubing BOPs.

Shear Seal BOPs.

Drilling BOPs.

Wireline BOPs (extra set).

17

Workover

Testing Barriers

All devices which remain in place during well operations and which may then be used

as barriers or containment devices (e.g. drilling BOPs, wireline BOPs) will be

pressure tested before use as directed by Operating Company Philosophy.

All devices which remain in place during well operations and which may then be used

as barriers or containment devices (e.g. drilling BOPs, wireline BOPs) will be

pressure tested before use as directed by Operating Company Philosophy.

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Workover

Testing Barriers

The lowermost mechanical barrier in a live well will always be integrity tested against the well pressure it is designed to hold back.

Testing under these circumstances will be to bleed off the pressure in the tubing and then monitor for pressure build up for 30 minutes.

The lowermost mechanical barrier in a live well will always be integrity tested against the well pressure it is designed to hold back.

Testing under these circumstances will be to bleed off the pressure in the tubing and then monitor for pressure build up for 30 minutes.

This lowermost barrier may also be tested from above to some pressure above the wellbore pressure underneath.

This lowermost barrier may also be tested from above to some pressure above the wellbore pressure underneath.

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Workover

Testing Barriers

The next barrier should be tested from above to avoid trapping pressure underneath with no means of bleeding off.

The next barrier should be tested from above to avoid trapping pressure underneath with no means of bleeding off.

Note: Pressure testing Pump Open Plugs from above may be limited by the shear pin rating.

Note: Pressure testing may also be limited by the pressure rating of a wireline lock mandrel to pressure from above.

Note: Pressure testing Pump Open Plugs from above may be limited by the shear pin rating.

Note: Pressure testing may also be limited by the pressure rating of a wireline lock mandrel to pressure from above.

20

Workover

Workover

A typical completion string has many components and sometimes is designed with an incomplete knowledge of the likely conditions for the full life of the well.

Equipment may fail for a number of reasons including:

Effects of pressure.

Effects of thermal stress.

Applied and induced mechanical loading.

Corrosion failure (O2, CO2, H2S, Acids).

Erosion.

A typical completion string has many components and sometimes is designed with an incomplete knowledge of the likely conditions for the full life of the well.

Equipment may fail for a number of reasons including:

Effects of pressure.

Effects of thermal stress.

Applied and induced mechanical loading.

Corrosion failure (O2, CO2, H2S, Acids).

Erosion.

It is also important to distinguish two types of failure:

Catastrophic failure implying a safety concern, e.g. a tubing leak.

Inability to function with no immediate safety concerns, e.g. gas lift valve failure.

It is also important to distinguish two types of failure:

Catastrophic failure implying a safety concern, e.g. a tubing leak.

Inability to function with no immediate safety concerns, e.g. gas lift valve failure.

21

Workover

Workover

Failure of completion equipment may dictate two courses of action:

1) Repair or removal and replacement.

2) Abandon the well in cases where due to safety implications the well is not salvageable.

Failure of completion equipment may dictate two courses of action:

1) Repair or removal and replacement.

2) Abandon the well in cases where due to safety implications the well is not salvageable.

The consequences of a component failure depends upon its integration with the completion string and its replacement may require:

Removal and replacement by means of wireline or coiled tubing without having to kill the well.

Removal and replacement of the Xmas Tree. Partial or full removal and replacement of the completion string.

Other remedial work.

The consequences of a component failure depends upon its integration with the completion string and its replacement may require:

Removal and replacement by means of wireline or coiled tubing without having to kill the well.

Removal and replacement of the Xmas Tree. Partial or full removal and replacement of the completion string.

Other remedial work.

22

Workover

Workover

It may not always be possible, or desireable, to perform a workover immediately, if for example, the means are not readily available. In this case the well may be:

Shut in, if there is no safety problem; e.g. this may be the case of high water cut.

Temporarily suspended, if there is a safety problem, such as a tubing leak. This involves installing the required number of fluid and mechanical barriers so that the well is rendered safe.

Abandoned, if the problem is so severe that it is not safe or economical to perform a workover. This may occur if there are major well performance problems or irretrievable junk in the well. In this case permanent barriers such as cement plugs will be placed in the well.

It may not always be possible, or desireable, to perform a workover immediately, if for example, the means are not readily available. In this case the well may be:

Shut in, if there is no safety problem; e.g. this may be the case of high water cut.

Temporarily suspended, if there is a safety problem, such as a tubing leak. This involves installing the required number of fluid and mechanical barriers so that the well is rendered safe.

Abandoned, if the problem is so severe that it is not safe or economical to perform a workover. This may occur if there are major well performance problems or irretrievable junk in the well. In this case permanent barriers such as cement plugs will be placed in the well.

23

Workover

Workover Programs

Typical Workover Program Contents1) Well history.

2) Current status of the well.

3) Completion details.

4) Proposed workover procedure, including:

Well Kill.

Installation of barriers.

Removal of Xmas Tree and completion.

Installation of BOPs.

Cleaning the well.

Running new completion.

Removing the BOPs.

Re-Installing the Xmas Tree.

Typical Workover Program Contents1) Well history.

2) Current status of the well.

3) Completion details.

4) Proposed workover procedure, including:

Well Kill.

Installation of barriers.

Removal of Xmas Tree and completion.

Installation of BOPs.

Cleaning the well.

Running new completion.

Removing the BOPs.

Re-Installing the Xmas Tree.

24

Workover

Workover Programs

From a well control perspective we would want to have specific information on the following:

From a well control perspective we would want to have specific information on the following:

Information Reason

Pore pressure ofexposed formations

Kill fluidrequirements

Fracture pressure of theexposed formations

BullheadingRequirements

Permeability of exposedformations

Kill fluidspecifications

Accessibility of tailpipelanding nipples

Barriersconsiderations

Integrity of packer andtubing hanger

Procedures to controlthe well

Current wellhead annulipressure info

Procedures to controlthe well

Hydrate formation Procedures to controlthe well

25

Workover

Workover Programs

From an operational point of view the following should be considered:

Disposal of contaminants. Prevalence/likelihood of H2S and LSA scale.

Personnel protection.

All pressure control equipment, i.e. risers, BOPs, etc should:

Be rated to at least the maximum anticipated surface pressure.

Be suited to the working environment.

Allow passage of all toolstrings.

From an operational point of view the following should be considered:

Disposal of contaminants. Prevalence/likelihood of H2S and LSA scale.

Personnel protection.

All pressure control equipment, i.e. risers, BOPs, etc should:

Be rated to at least the maximum anticipated surface pressure.

Be suited to the working environment.

Allow passage of all toolstrings.

26

Workover

Well Control Problems During Workover

The following are typical causes of well control problems during workover.1) Different workover philosophies within the same company for different fields can lead to subtle changes in procedures, which in turn can lead to errors.

2) In some cases there is no test of mechanical barriers from below the barrier.

3) Attempting to remove a toolstring from a well having insufficient length or riser to isolate the formation to depressurise the system.

4) Brine densities can be affected considerably by downhole pressures and temperatures; this is particularly hazardous where a low overbalance margin exists.

The following are typical causes of well control problems during workover.1) Different workover philosophies within the same company for different fields can lead to subtle changes in procedures, which in turn can lead to errors.

2) In some cases there is no test of mechanical barriers from below the barrier.

3) Attempting to remove a toolstring from a well having insufficient length or riser to isolate the formation to depressurise the system.

4) Brine densities can be affected considerably by downhole pressures and temperatures; this is particularly hazardous where a low overbalance margin exists.

27

Workover

Workover Example

Object - to remove a permanent packer from a well

Object - to remove a permanent packer from a well

28

Workover

BARRIER ENVELOPE IN PLACE Casing Packer Tubing Hanger Xmas Tree

Normal Production

29

Workover

BARRIERS IN PLACE Kill wt brine in tubing and annulus Plug in tailpipe BPV in tubing hanger

WELL CONTROL CONSIDERATIONS Check for gas migration Check annulus dead Cause of surface pressure, thermal effects

or well not dead Do not exceed tubing or csg specs

Well Killed and Barriers In Place for Tree Removal

30

Workover


Tree Removal, BOP Installed

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Workover

WELL CONTROL CONSIDERATIONS Check for trapped pressure before removing

tbg hanger lockdown bolts Consider the SCSSV Make final checks for annulus pressure Enough kill wt material on board

BARRIERS IN PLACE Kill wt brine in tubing and annulus

WHILST PULLING Perform regular flow checks Keep the hole full Trapped pressure

Plugs removedTubing hanger lockdownBolts removed

Prepare to Pull Tubing

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Workover

WELL CONTROL CONSIDERATIONS Perform regular flow checks Monitor hole fill on trip tank Minimise time on the bank

BARRIERS IN PLACE Kill wt brine

Tubing Removed, Wearbushing Installed

33

Workover

WELL CONTROL CONSIDERATIONS Keep accurate trip record Gains or losses after packer broken through Surging whilst RIH with mill Swabbing whilst POOH Run wearbushing prior to RIH with mill

BARRIERS IN PLACE Kill wt brine in tubing

Milling the Packer

34

Workover

RU wireline on THROTInstall plug in tailpipeSet packerTest tubingSet hangerTest annulus between packer and hanger

WELL CONTROL CONSIDERATIONSWHILST RUNNING TUBING Perform regular flow checks Keep the hole full Surging RIH slowly Check tubing burst pressure before testing Test hanger seal integrityBEFORE RUNNING Consider the SCSSV Enough kill wt material on board

BARRIERS IN PLACE WHENRUNNING TUBING Kill wt brine in tubing and annulus

Running New Completion

35

Workover

WELL CONTROL CONSIDERATIONS

PRIOR TO ND BOP Leak-off test tubing Check annulus pressures


Plugs Run Prior to Nipple Down BOP

36

Workover

RU wireline, pull plugsReturn well to production


BOP Removed and Tree Replaced

37

Workover

BARRIER ENVELOPE IN PLACE Casing Packer Tubing Hanger Xmas Tree

Sub-Sea Well Normal Production

38

Workover

BARRIERS IN PLACE WHILST RUNNINGWORKOVER PACKAGE Tree valves

Tree Cap Pulled, Sub-Sea Workover Riser Installed

39

Workover

WELL CONTROL CONSIDERATIONSDURING KILL Check for gas migration Check annulus dead Source of surface pressure Thermal effects or well not dead Do not exceed tubing or csg specs

BARRIERS IN PLACE Kill wt brine in tubing and annulus Plug in tailpipe 2 x BPV in tubing hanger

Well Killed and Barriers in Place Prior to Removing Tree

40

Workover


Tree Removed and BOP Riser Installed - THROT Engaged

41

Workover

WELL CONTROL CONSIDERATIONSPRIOR TO PULLING Check for trapped pressure before

removing tbg hgr lockdown bolts Consider the SCSSV Make final checks for annulus pressure Enough kill wt material on boardDURING PULLING Perform regular flow checks Keep the hole full Trapped pressure

BARRIERS IN PLACE Kill wt brine in tubing and annulus

Plugs Removed, Prepare to Pull Tubing on THROT

42

Workover

WELL CONTROL CONSIDERATIONS Perform regular flow checks Monitor hole on trip tank


Tubing Removed

43

Workover

WELL CONTROL CONSIDERATIONS Keep accurate trip record Gains or losses after packer breakthrough Surging whilst RIH with mill Swabbing whilst POOH Run wearbushing prior to RIH


Milling the Packer

44

Workover

WELL CONTROL CONSIDERATIONSWHILST RUNNING TUBING Perform regular flow checks Keep hole full monitor on trip tank Surging RIH slowly Check tubing burst pressure before testingBEFORE RUNNING TUBING Pull wearbushing Consider the SCSSV Enough kill wt material on board

BARRIERS IN PLACE WHEN RUNNING TUBING Kill wt brine in tubing and annulus

RU wireline on dual running stringInstall plug in tailpipeSet packerTest tubingSet and test hanger

New Tubing Run on THROT

45

Workover

WELL CONTROL CONSIDERATIONS Leak-off test tubing


Plugs Run Prior to ND BOP

46

Workover


RU wireline Pull plugsPull workover packageReturn well to production

BOP and Drilling Riser Pulled, Tree Run on Workover Package

47

Workover

Hydrostatic Pressure (Liquids)

In terms of pressure gradient:In terms of pressure gradient:

)ft(DepthVerticalTrueD

)ft/psi(GradientessurePrG

TV

TVDGP

=

In terms of specific gravity:In terms of specific gravity:

gravitySpecificSG

TVD433.0SGP

=

In terms of density in lbs/gal:In terms of density in lbs/gal:

)gal/lb(density

TVD052.0P

=

48

Workover

Hydrostatic Pressure (Liquids)

Conversion of API gravity to specific gravity:Conversion of API gravity to specific gravity:

API5.1315.141SG +=

49

Workover

Hydrostatic Pressure (Gases)

In terms of pressure gradient:In terms of pressure gradient:


)ft/psi(GradientessurePrGasG

TV

TVDGP

=

In terms of gas correction factors:In terms of gas correction factors:

)F(reTemperatruAbsoluteT

FactorDeviationGasz


GravitySpecificGas

)psia(essurePrSurfaceSP

TV

TVS Tz4.53

DexpPP

=

50

Workover

Hydrostatic Pressure (Gases)

In terms of the gas correction factor Cf:In terms of the gas correction factor Cf:

FactorCorrectionfC

fS

TVS

CPP

Tz4.53DexpPP

=

=

51

Workover

Gas Correction Factors

52

Workover

Methods of Well Kill

Kill Method Description

Bullheading Kill fluid pumped into thetubing at surface.

Tubing contents displaced intothe formation.

ForwardCirculation

Kill fluid pumped into tubing atsurface.

Tubing contents displaced intothe annulus through a deep setcirculation point.

Annulus contents displaced todisposal system.

Lubricate andBleed

A controlled volume of killfluid pumped into the tubing atsurface.

After an appropriate time,pressure is bled off at surfacedown to a predetermined value.

Reverse Circulation Kill fluid pumped into theannulus.

Annulus contents displaced intothe tubing through a deep setcirculation point.

Tubing contents displaced todisposal system at surface.

53

Workover

Bullheading Well Kill

Volume Pumped into Tubing (bbls)

Surf

ace

Tubi

ng P

ress

ure

(psi

)

54

Workover

Forward Circulation Well Kill

Delayed till later ! ! !Delayed till later ! ! !

55

Workover

Lubricate and Bleed Well Kill

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Workover

Reverse Circulation Well Kill

Well Status before SSD is open.

57

Workover

Well Status after SSD is open.

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Workover

Well Status with SSD open and THP bled down.

59

Workover

Well Status when THP reaches zero.

60

Workover

Well Status with gas out of tubing, oil at surface.

61

Workover

Well Status when annulus is full.

62

Workover

Well Status when tubing is full of heavy brine.

63

Workover

Well Status when annulus is full of kill brine.

64

Workover

Reverse Circulation Well Kill Graph Example

Volume Pumped into Annulus (bbls)

Surf

ace

Tubi

ng P

ress

ure

(psi

)

65

Workover

Forward Circulation/Reverse Circulation Comparison

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Bullheading

Advantages - as compared to reverse circulation.

Duration of pumping operation short. Lower cost.

Easier to perform with less personnel.

No environmental pollution.

Advantages - as compared to reverse circulation.

Duration of pumping operation short. Lower cost.

Easier to perform with less personnel.

No environmental pollution.

Disadvantages

No protection from damaging fluids and debris. Higher tubing pressures.

Pumping operations may cause accidental fracture of the formation.

Cannot kill all wells (especially tight formations and some gas wells).

Disadvantages

No protection from damaging fluids and debris. Higher tubing pressures.

Pumping operations may cause accidental fracture of the formation.

Cannot kill all wells (especially tight formations and some gas wells).

67

Workover

Reverse Circulation

Advantages

Reservoir fluids are excluded from the A annulus. Fluid densities should keep reservoir fluids segregated in the tubing during pumping operations.

Formation may be protected.

Tubing and casing pressures are lower during pumping operations.

Can kill all wells if the mechanical condition of the tubing and casing is appropriate.

Advantages

Reservoir fluids are excluded from the A annulus. Fluid densities should keep reservoir fluids segregated in the tubing during pumping operations.

Formation may be protected.

Tubing and casing pressures are lower during pumping operations.

Can kill all wells if the mechanical condition of the tubing and casing is appropriate.

Disadvantages

A annulus debris may make a tailpipe tubing plug irretrievable.

Duration of pumping operations may be long.

Higher cost.

Disadvantages

A annulus debris may make a tailpipe tubing plug irretrievable.

Duration of pumping operations may be long.

Higher cost.

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Workover

Well Preparation

Well must be closed in to stabilise

bottomhole pressure.

Inspect and service the Xmas Tree.

Consider the Sub-Surface Safety Valve.

Isolate well control from all external

sources (except PSD).

Stress analysis.

Well must be closed in to stabilise

bottomhole pressure.

Inspect and service the Xmas Tree.

Consider the Sub-Surface Safety Valve.

Isolate well control from all external

sources (except PSD).

Stress analysis.

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Workover

Information Required for a Well Kill

Reservoir Parameters Completion Parameters

Static ReservoirPressure

Survey Data

TVD Formation Annulus Volume

Permeability Tubing Volume

Skin Factor TVD Circulation Ports

Injection Pressure MAASP

Fracture Pressure Static Fluid Gradients

TVD Fluid Interfaces

Annulus Fluid Gradient

Kill Fluid Gradient

SITHP

SIAHP

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Workover

Methods of Equalisation of Pressure

All wells and well completions are unique and hence there is no standard method for killing a production

well.

All wells and well completions are unique and hence there is no standard method for killing a production

well.

The following identifies some of the techniques that may be used for pressure equalisation at the depth of a circulation device prior to pumping operations:

1) Pressurise the tubing or annulus by pumping a compatible fluid.

2) Pressurise the tubing by utilising pressure from another well.

3) Lubricate and bleed the tubing or the annulus.

Note: The method used will be dependent on the fluids present in the tubing or the annulus.

Note: The conditions of constant bottomhole conditions may still be applicable.

The following identifies some of the techniques that may be used for pressure equalisation at the depth of a circulation device prior to pumping operations:

1) Pressurise the tubing or annulus by pumping a compatible fluid.

2) Pressurise the tubing by utilising pressure from another well.

3) Lubricate and bleed the tubing or the annulus.

Note: The method used will be dependent on the fluids present in the tubing or the annulus.

Note: The conditions of constant bottomhole conditions may still be applicable.

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Pump(s)

appropriately pressure rated

known output volume per pump stroke

relief valve

Surface Lines


Choke adjustable

Check Valves

Pressure Gauges appropriately calibrated

Fluid Disposal System

Mixing Tanks

Reserve Tanks

Kill Fluid

Chemical Additives

Well Intervention Equipment

Pump(s)


known output volume per pump stroke

relief valve

Surface Lines


Choke adjustable

Check Valves

Pressure Gauges appropriately calibrated

Fluid Disposal System

Mixing Tanks

Reserve Tanks

Kill Fluid

Chemical Additives

Well Intervention Equipment

Equipment Required for Well Kill Operations

72

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Equipment Required for Well Kill Operations

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Golden Rules for Planning a Well Kill

1) Obtain relevant well and reservoir data.

2) Decide on the best method to kill the well.

3) Determine the kill fluid density appropriate to the formation pressure to kill the well.

4) Generate a kill graph.

5) If possible, simulate the well kill.

6) Generate a well kill procedure identifying fluid, equipment, and personnel requirements, expected pressures, and safety requirements (barriers).

1) Obtain relevant well and reservoir data.

2) Decide on the best method to kill the well.

3) Determine the kill fluid density appropriate to the formation pressure to kill the well.

4) Generate a kill graph.

5) If possible, simulate the well kill.

6) Generate a well kill procedure identifying fluid, equipment, and personnel requirements, expected pressures, and safety requirements (barriers).

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Golden Rules When Performing a Well Kill

1) Conduct an awareness and safety meeting for all personnel involved.

2) Prepare the well.

3) Pressure test all surface equipment.

4) Check fluid density and volume.

5) Commence operations as per the kill procedure.If Reverse Circulation is used:

equalise over circulation device increase pump rate slowly to the rate. surface choke must be adjusted to regulate the THP. returns to be monitored. pump the appropriate volume of kill fluid.

6) Check that the well is dead.

1) Conduct an awareness and safety meeting for all personnel involved.

2) Prepare the well.

3) Pressure test all surface equipment.

4) Check fluid density and volume.

5) Commence operations as per the kill procedure.If Reverse Circulation is used:

equalise over circulation device increase pump rate slowly to the rate. surface choke must be adjusted to regulate the THP. returns to be monitored. pump the appropriate volume of kill fluid.

6) Check that the well is dead.

work over

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