Dual and Multiple Stacked Completions

Dual and Multiple Stacked Completions

• Many reasons to separate, solid arguments to commingle anytime it is possible.

• Look at alternative methods of producing the pay zones.

• Multiple completions are a method (good?) of accelerating rate.

8/25/2015 1 George E. King Engineering

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Objective

• The objective of this presentation is to increase awareness of and preparedness in the necessary technology and techniques required to successfully design and manage dual completion production and water injection wells in all environments including gaslift and waterfloods.


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Literature Lessons

• Successful design and operation of dual completion wells is possible, but it requires a set philosophy to keep both strings on line. Operation also requires a consistent approach to the sensing, maintenance, operation and workover of both strings in a well, regardless of how well one string of the dual is performing.

• This slide set conveys best practices of the operations and workovers in dually completed wells and offers recommendations for information sensing, diagnostics, operation and maintenance. A premium is placed on techniques that can keep wells on line without intrusive and expensive workovers.

• When designing dual completions, identification of primary and secondary analogue fields has value. This helps with operational performance prediction, risk assessment and workover frequency prediction.


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Operational Points

• Typical characteristic is that frequently only one side of a dual is producing, especially with gas lifted duals.

– The problem is that operators are hesitant to workover a well when one side is flowing, even when the other side is dead or severely limited.

• Arco Indonesia: of 200 dually completed strings in the area, only 120 strings are flowing. Problems with communication and lack of effective lift

keep the other strings severely curtailed or totally off-line.

• Conoco: a third of their gas lifted dual strings do not produce. • Amoco: better performance, but not many duals are lifted on both sides.


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Committment

• Dual completions, especially dually completed wells on gas lift take an inordinate amount of diagnostics, maintenance and workovers to keep both sides of the well producing. An understanding and a commitment to the level of maintenance necessary to keep both duals on line is necessary when dual completions are considered. If the commitment is not present to order workovers when only one string in a dual well is flowing, then the cost of a dual completion has been compromised and single completions are viewed as cheaper and less risky.


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Typical Dual Failures

• Pressure build-up occurred in 19% of the producers and 45% of the injectors.4

• Communication between the two strings, due to failure of some component of the completion, occurred in 10% of both the injectors and the producers.

– Pressure communication between the strings has been traced to sliding sleeve leakage (sliding sleeve in the long string segment between the packers) and to damage to the primary string between the packers (erosion)


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Other Dual Problems

• Tubing obstruction (various causes) to wireline tools in 2-3/8” tbg occurred in 14% of the producers and 5% of the injectors. The problem is buckling in the smaller tubing, restricting passage of wireline tools.

• No problems were encountered in the other tubing sizes. No problems were reported in wells with no upper or dual packer.


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Packer selection is straight forward – hydraulic set is preferred – definitely not rotation.


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A shoot and flow dual completion using TCP guns and hydraulic set packers.

Dual TCP

Limited Wireline abilities - can set isolation plugs.

Problems - multiple packer set (can test) - multiple gun fire (hard to check).


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Magnetic Orienting Device - Application

• Orients perforating guns when there are two or more strings of tubing in the hole

• The tool magnetically detects the location of the other strings

• For stainless steel casing, via slickline, place a metal rod in the “other” string and run MOD as normal.

2 8/25/2015 25 George E. King Engineering

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• Tool string consists of; – Upper Centralizer - Non Rotating

– Collar Locator

– Motor Assembly

– Middle Centralizer, Rotating

– MOD Sensor Section

• Magnetic Generator

• Magnetic Reciever

• Lower Centralizer, Rotating – Gun Adapter Sub

• Specifications (Halliburton); – O.D. = 1 11/16 inch

– Pressure = 18,000 psi

– Length = 12.15 feet

– 350 degree F

– 1/4 revolution / min 3 8/25/2015 26

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Applicable Gun Systems

• Guns will be shot centralized

• Sizes: 1 11/16” & larger; HSC RTG or Expendable gun system

– recommended system

• Gun is shot centralized

• Maximum performance needed to insure adequate penetration

• In tubing the tool / guns maintain a relatively straight orientation. In casing the bottom part of the gun could be out of alignment and make it difficult for the motor to turn the gun. A centralizer could be placed on the gun bull plug.

• Other expendable or strip guns systems, can be used, but gun twist is a possibility.


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Tool Operation • Tool indicates the direction of the

largest ferrous-metal mass

• Dual String of Tubing, no casing, in Open Hole

– Low ferrous mass = High Reading

– High ferrous mass = Low Reading

• Casing around the tubing causes the log response to reverse.

– A function of pounds/foot rather that pipe

sizes.

– Select fire switches cannot be used.

Pipe

String

B

Pipe

String

A

Motor

Assembly

Magnetic

Generator

Magnetic

Receiver

Perforations


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Halliburton MOD Log • Dual string of tubing in Open Hole

• High metal mass = Low Reading

• Low metal mass = High Reading

• Gun aligned away from reciever

• Casing causes reversal of the above

• Make at least two rotations to confirm orientation

• Detonate the gun IMMEDIATELY upon confirming pipe / gun orientation (delay can “build” stretch into depth)

• 20 foot maximum gun length HSC

• 10 foot for strip systems

• 20° max well deviation

360° Rotation

360° Rotation

Start

Min Reading

Max Reading

Stop


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Additional Equipment

• Shock sub - absorbs shock from perforating gun

• Drop off sub when perforating “old” tubing or when corrosive fluids are present in the field or area.

• If well deviations between 10° and 20 ° then two upper centralizers required.


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360°

360° Stop

Stop

1 2

1 2

360°

360°

Stop

Stop

Stop

What happens here?

360°

360°

1 2

Stop

Stop

Stop Direction of

Perforating


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Dual Completion With

“Wraparound” Gun Guide

CN02292 Source - Halliburton 8/25/2015 33 George E. King Engineering

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Dual Completion With

“Dual” Gun Guide

CN04922 Source - Halliburton 8/25/2015 34

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Workovers in Handil Duals

• Perforating: including reperforating existing zones and adding new zones.

• Pipe Cut-Off: removing nipples, tailpipe and severing strings.

• Positioning and orientation tools: magnetic positioning device and powered orienting tool or mechanical orienting device - all allow determination of proximity of another string when perforating.

• Isolating Undesirable Communication between zones or leaks in the strings. Cement, silicate, and gel isolating materials have been evaluated.

• Workover preparation: including wireline gauging, setting plugs,

• Information gathering: pressure, etc.

• Lift: repair and maintenance of lift system

• Temporary well abandonment


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Workover Criteria

• Reserve base and expected net increase

• Location of O/W contact

• Formation quality assessment

• Production history for each zone

• Reservoir pressure

• Well condition


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Best Practices (includes some design comments)

• allow significant flexibility for changing well conditions. (This, plainly stated, means that more gas lift valves be run to give adequate design room for the changing conditions of the field. Attempting to cut the cost of the CAPEX through reduction of the number of gas lift valves is not a solid engineering decision.)

• The gas lift valves must be selected specifically for dual string operation from a single annulus.

• Wireline and CT entry into the strings depends on straight tubing. Buckling loads should be avoided.

• Seals must be stable at temp. and press. with all fluids.


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Best Practices

• The use of sliding sleeves are not suggested for use in the long string below the dual packer. If communication is needed, perforation punchers are suggested.

• A profile in the long string just below the dual packer is required to test for communication between the strings when leaks are suspected. Profiles at the bottom of each string are recommended to assist in reservoir pressure and other monitoring and isolation operations.

• Fluid placement downhole can be significantly improved, both in accuracy of placement and overall stimulation effect, by utilizing coiled tubing, rather than bull heading.

• Force, load and temperature balances for the wells during the initial well design must take into account the extremes of pressure and temperature expected during stimulation and workovers.


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Best Practices

• Perforated sections of tubing above the nipple profiles (placed there to flow while pressure gauges are hung in the profiles at the end of the tubing) reduce the options of pressuring up or allowing flow to assist in removing a tool stuck in the profile. Perforated housings made into the tool body above the head will allow by-pass flow, but will also allow the perforated area to be blanked off when the plug was pulled.

• The end of the tail pipe in the upper zone should be run as close as possible to the top of the upper zone. Operations with wireline in the upper zone are very limited and at very high risk beyond the end of tubing. Coiled tubing should not be run more than a few feet beyond the end of tubing in the upper zone.


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Dual Completions Operational Overview

• Scope and Objectives

• General Findings

• Analogue Fields


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Objective

• The most difficult part of dual completion operation is the ability to successfully manage dual completion production and water injection wells in gaslift and waterflood environments. This can only be accomplished by surveillance and intervention operations. This can be achieved through a dedication to accessing, collecting and evaluating industry information.


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Scope

• The information collected here was collected from sources including:

– BP networks

– Service and equipment supply companies

– Literature sources

– Industry search contacts and papers

– Operators of wells with dual completions


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Deliverables

• Identification of analogue fields, both within and outside BP, with regard to surveillance, remedial well work and non-rig workovers in dual completion wells in gas-lift waterflood situations.

• Identification of full suite of surveillance and intervention operations to be considered

• Review of each operation in dual completion wells, including consideration of relevant industry experience, approximate existing and future technology.

• Outline risks & consequences associated w/ best practices

• Key contacts, centers of expertise & references


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Summary

• Successful operation of dual completion wells and recovery of reserves in a prudent manner is possible, but it requires a set philosophy to keep both strings on line. Operation also requires a consistent approach to the sensing, maintenance, operation and workover of both strings in a well, regardless of how well one string of the dual is performing.

• This report conveys best practices of the operations and workovers in dually completed wells and offers recommendations for information sensing, diagnostics, operation and maintenance. A premium is placed on techniques that can keep wells on line without intrusive and expensive workovers.

• Primary and secondary analogue fields have been identified, with the specific intent of assisting in operational performance prediction, risk assessment and workover frequency prediction. No one field was a perfect match, but several fields offer information that will assist in operation of this field.


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Operational Points

• Typical characteristic is that frequently only one side of the dual is producing, especially with gas lifted duals.

– problem is that operators are hesitant to workover a well when one side is flowing, even when the other side is dead or severely limited

• Arco Indonesia: of 200 dually completed strings in the area, only 120 strings are flowing. Problems with communication and lack of effective lift

keep the other strings severely curtailed or totally off-line.

• Conoco: a third of their gas lifted dual strings do not produce. • Amoco heritage: better performance, but not many duals are lifted on

both sides.


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Committment

• Dual completions, especially dually completed wells on gas lift take an inordinate amount of diagnostics, maintenance and workovers to keep both sides of the well producing. An understanding and a commitment to the level of maintenance necessary to keep both duals on line is necessary when dual completions are considered. If the commitment is not present to order workovers when only one string in a dual well is flowing, then the cost of a dual completion has been compromised and single completions are viewed as cheaper and less risky.


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Wilson and Barrilleaux

Type of Completion Average Cum. Prod

BO per ft of perfs

Single 7,900

Dual 6,300

Numbers are conservative. Many of the duals are newer wells and are still producing.


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Wilson and Barrilleaux

Type of Completion Avg. Max Production Rate,

BOPD per ft of perfs

Single 18

Dual 17


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Handil Field D, Indonesia - Learnings

• Strings producing more than 500 BLPD should not be produced under intermittent flow. The slugging and surging of this type flow will disturb the flow behavior of other wells on the same flow line.

• Lift using annular flow via a macaroni string is preferred in some cases where a better flow stability and minimization of slugs can be achieved.

• Wells that are easily accessible to wireline workovers are at an advantage for dual gas lift, given the need for frequent trouble shooting


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Handil Learnings

• Gas lift via the macaroni technique was avoided for strings with flow potentials of over 1500 BLPD.

• Annular gas lift for strings producing less than 500 BLPD was inefficient.

• Intermittent gas lift using annular lift techniques (especially on the aforementioned high rate wells) have a detrimental impact on other wells on the same flow line.


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Handil Learnings

• In the range of 500 to 1500 BLPD, both techniques are usable, showing only about a 10% loss compared to single string per well lift. Production loss origins are specific pressure losses in the completion

• Consumption of gas lift gas, which was limited for the project, was nearly equal for the two techniques on a barrel of fluid lifted.

• Cost of operation of the systems was significantly different. The costs reflected initial system cost and maintenance/workovers (These costs were circa 1980 – relative expense should be similar.)

Gas Lift System Cost ($US) per day of String Operation

Dual Annular Gas Lift 25

Macaroni Lift 400


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Typical Dual Failures

• Pressure build-up occurred in 19% of the producers and 45% of the injectors.4

• Communication between the two strings, due to failure of some component of the completion, occurred in 10% of both the injectors and the producers.

– Pressure communication between the strings has been traced to sliding sleeve leakage (sliding sleeve in the long string segment between the packers) and to damage to the primary string between the packers.4

– The damage to the long string was from corrosion/erosion.


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Other Dual Problems

• Tubing obstruction (various causes) to wireline tools in 2-3/8” tbg occurred in 14% of the producers and 5% of the injectors (Indonesia and GoM)

• No problems were encountered in the other tubing sizes. No problems were reported in wells with no upper or dual packer.


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Before Corrections After Corrections

Type Population Wells Percent Population Wells Percent

Producers 257 37 14% 53 1 2

Injectors 250 12 5 10 0 0

Well Failures and Cures

Tubing Obstructions


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Before Corrections After Corrections

Type Population Wells Percent Population Wells Percent

Producers 257 48 19 53 1 2

Injectors 250 112 45 10 0 0

Well Failures and Cures

Annulus Leaks


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Workovers in Handil Duals

• Perforating: including reperforating existing zones and adding new zones.

• Pipe Cut-Off: removing nipples, tailpipe and severing strings.

• Positioning and orientation tools: magnetic positioning device and powered orienting tool or mechanical orienting device - all allow determination of proximity of another string when perforating.

• Isolating Undesirable Communication between zones or leaks in the strings. Cement, silicate, and gel isolating materials have been evaluated.

• Workover preparation: including wireline gauging, setting plugs,

• Information gathering: pressure, etc.

• Lift: repair and maintenance of lift system

• Temporary well abandonment


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Workover Criteria

• Reserve base and expected net increase

• Location of O/W contact

• Formation quality assessment

• Production history for each zone

• Reservoir pressure

• Well condition


GEKEngineering.com

Best Practices (includes some design comments)

• allow significant flexibility for changing well conditions. (This, plainly stated, means that more gas lift valves be run to give adequate design room for the changing conditions of the field. Attempting to cut the cost of the CAPEX through reduction of the number of gas lift valves is not a solid engineering decision.)

• The gas lift valves must be selected specifically for dual string operation from a single annulus.

• Wireline and CT entry into the strings depends on straight tubing. Buckling loads should be avoided.

• Seals must be stable at temp. and press. with all fluids.


GEKEngineering.com

Best Practices

• The use of sliding sleeves are not suggested for use in the long string below the dual packer. If communication is needed, perforation punchers are suggested.

• A profile in the long string just below the dual packer is required to test for communication between the strings when leaks are suspected. Profiles at the bottom of each string are recommended to assist in reservoir pressure and other monitoring and isolation operations.

• Fluid placement downhole can be significantly improved, both in accuracy of placement and overall stimulation effect, by utilizing coiled tubing, rather than bull heading.

• Force, load and temperature balances for the wells during the initial well design must take into account the extremes of pressure and temperature expected during stimulation and workovers.


GEKEngineering.com

Best Practices

• Perforated sections of tubing above the nipple profiles (placed there to flow while pressure gauges are hung in the profiles at the end of the tubing) reduce the options of pressuring up or allowing flow to assist in removing a tool stuck in the profile. Perforated housings made into the tool body above the head will allow by-pass flow, but will also allow the perforated area to be blanked off when the plug was pulled.

• The end of the tail pipe in the upper zone should be run as close as possible to the top of the upper zone. Operations with wireline in the upper zone are very limited and at very high risk beyond the end of tubing. Coiled tubing should not be run more than a few feet beyond the end of tubing in the upper zone.


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Dual and Multiple Stacked Completions

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