types of completion

TYPES OF COMPLETION Contents

Page

Introduction .................................................. 1 Single Zone Completions Retrievable Packer ............................ 4 Seal-bore Packer ............................... 5 Packer-Tail-Pipe Attached ................. 6 Casing Seal Receptacle .................... 7 Multiple Zone Completions 2 Zones 1 Packer .............................. 8 2 Zones 2 Packers ............................ 9 3 Zones 3 Packers ............................ 10 4 Zones 4 Packers ............................ 11 Liner Completions Casing Seal Receptacle .................... 12 CSR and Seal-bore Packer ............... 13

Contents

Page

Special Service and Remedial Completions Sand Control ..................................... 14 Inhibitor Injection (1) .......................... 15 Inhibitor Injection (2) .......................... 16 Waterflood (1) .................................... 17 Waterflood (2) .................................... 18 Thermal Completion .......................... 19 Remedial–Scab Liner ........................ 20 Completion Examples Monobore Producer/Injector .............. 21 7 x 5-1/2-in. Produce/Injector ............ 22 Gas Injector ....................................... 23

Introduction

Note: Artificial lift completions, by their nature, require special consideration and the consideration of several detailed design factors. A description of artificial lift systems including configuration examples are shown in Section 5.

• Tubing removal – almost every well will require the tubing string to be removed at some point during its life. This process requires the well to be killed, preferably with minimal invasion of wellbore or kill fluid into the producing formation.

An oil or gas well completion should fulfill the technical requirements for the various phases which exist throughout the life of the well or reservoir, e.g., initial production, treatment/stimulation, artificial lift, workover and abandonment. However, in order to fulfill basic safety and economic requirements of any installation some compromise may be necessary.

• Safety – safety is considered in two principal areas, (i) the provision of a production safety valve to prevent uncontrolled production, (ii) the provision of a means of circulating, i.e., the tubing string, to enable well kill operations to be conducted.

As the performance of wells, and therefore completions, have become more closely scrutinized, the basic design and component selection process has evolved. This evolutionary process has taken account of the following principal factors.

• Production control – for example, the addition of completion components to control flow (nipples and profiles), allow circulation (sliding sleeves) or flexibility in production (side pocket mandrels. The illustrations in Figure 1 through 4 show the basic types of wellbore construction. Figures 1 through 8 show the development of tubing completions.

• Casing protection – i.e., protection against erosion and corrosion which could ultimately jeopardize the integrity of the wellbore.

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• No downhole flow control or isolation possible

• Production zone(s) hydraulically isolated by casing cement

• Unsupported producing formation

• More options for selective treatment and isolation

Fig. 1. Open-hole production.

Fig. 2. Casing production.

• Similar to casing production but with savings associated with shorter casing string and smaller hole diameter through reservoir

• Dictated by formation type, selectivity of treatment and subsequent isolation is difficult

Fig. 4. Gravel packed wellbore.

Fig. 3. Liner production.

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• Well kill capability through circulation around packer once unset

• Well kill capability but with no control of annular fluid level and possible exposure to corrosion

• Casing string protected from corrosion and production stresses by inhibited packer fluid

Fig. 6. Basic packer production.

Fig. 5. Open-ended (suspended) tubing production.

As with basic packer production but with:

As with basic packer production but with:

• Downhole isolation (plug) capability

• Downhole isolation (plug) capability above and below the packer

• Facility for downhole instruments (gauges)

• Circulation capability through the sliding sleeve without unsetting packer. • Production safety valve

Fig. 7. Packer with perforated tailpipe.

Fig. 8. Packer with nipples, sliding sleeve and safety valve.

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Modern completion designs vary considerably but can be categorized into general completion types. The following section illustrates most of the more common completion types. However, in some circumstances, completions may fall into two or more of the categories shown, e.g., multiple-zone sand control completion.

Single Zone Completions

Name Single Zone – Retrievable Packer Recovery/Function Primary recovery Frequency of Usage Common Operational Advantages Flow coupling • Fully retrievable completion – no permanent components.

Sliding sleeve Flow coupling

• Packer can be set with well flanged up – sliding sleeve allows circulation of kick-off or perforating fluids.

Hydrostatic retrievable packer

• Thru-tubing perforation possible where size permits. Flow coupling Seating nipple Spacer tube Hydro-trip pressure sub Perforated spacer tube

• Tail-pipe facility for pressure and temperature gauges – located in no-go nipple below perforated spacer. This protects instruments from turbulence during high production rates.

No-Go nipple

Operational Disadvantages

Wireline entry guide

Fig. 9. Single zone completion – retrievable packer.

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Name Single Zone – Seal-bore Packer Recovery/Function Primary recovery Frequency of Usage Common Operational Advantages • Seal-bore packer set on electric line or tubing. • On-off connector and tubing anchor allows tubing to be retrieved while leaving the packer and tailpipe in place. • Tailpipe can be plugged before the tubing is removed to protect formation from kill fluid or workover fluids.

Production tubing

• Tailpipe can be retrieved with tubing if required. Operational Disadvantages On-off connector Tubing anchor Seal-bore packer Seating nipple Spacer tube Seating nipple Perforated spacer tube No-Go nipple Wireline entry guide

Fig. 10. Single zone completion – seal bore packer.

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Name Packer-Tail-Pipe Atached Recovery/Function Primary recovery Frequency of Usage Less Common Production tubing Operational Advantages • Tailpipe permanently attached to packer. • Tailpipe plug isolates formation during workover/tubing retrieval. • Permits safe thru-tubing perforating. • Block and kill system facilitates the killing and control of high-pressure, high volume wells.

Block and kill system

Operational Disadvantages

Sliding sleeve Tubing anchor Seal-bore packer Millout extension Crossover Flow coupling Seating nipple Spacer tube Flow coupling No-go seating nipple Perforated spacer tube Crossover sub Seating nipple Wireline entry guide

Fig. 11. Single zone completion – packer with tailpipe attached.

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Control line Name Single Zone – CSR

Flow coupling Safety valve and nipple

Recovery/Function Primary recovery

Flow coupling

Frequency of Usage Infrequent – old design Operational Advantages • Tailpipe retrievable separately. • Protective sleeve run in CSR during primary and remedial cementing operations • Expansion joint allows for tubing movement.

Expansion joint

• Safety valve run and retrieved on wireline.

Sliding sleeve

• Circulation of well fluid/kill fluid facilitated by sliding sleeve.

Shearout anchor/tubing seal assembly

Operational Disadvantages Casing seal receptacle Seating nipple Retrievable tailpipe hanger

Seating nipple Perforated spacer tube No-go seating nipple Spacer tube Wireline entry guide

Fig. 12. Single zone completion – casing seal receptacle.

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Multiple Zone Completions

Name Multiple Zone – Seal-bore Packer Recovery/Function Primary recovery Flow coupling Seating nipple

Frequency of Usage Uncommon

Blast joint

Operational Advantages • Separate or commingled flow through single production tubing string.

Polished nipple Flow coupling

• Upper zone may be produced through the annulus. • Blast joint protects tubular integrity across perforated intervals.

Flow coupling

• On-off connector and tubing anchor allows tubing to be retrieved with lower interval isolated.

Sliding sleeve

• Seating and polished nipples above and below the blast joint provide for contingency repair in the event of blast joint deterioration.

On-off sealing connector

Flow coupling Spacer tube

Anchor tubing seal assembly Seal-bore packer

• Sliding sleeve or the on-off connector facilitates circulation of well fluids and kill fluid.

Spacer tube

Operational Disadvantages No-go seating nipple • Upper zone produced through casing.

Wireline entry guide

• Lack of casing protection.

Fig. 13. Multiple zone completion – two zones, one packer.

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Flow coupling Seating nipple Flow coupling

Name Multiple Zone – Multiple Packers Recovery/Function Primary recovery

Flow coupling Sliding sleeve Flow coupling

Frequency of Usage Uncommon Operational Advantages

Dual hydrostatic retrievable packer

• Independent production through two tubing strings.

Flow coupling Seating nipple Flow coupling Hydro-trip pressure sub

• Both packers are fully retrievable. • Tailpipe instrument facility in both strings.

Perforated spacer tube

• Thru-tubing perforation possible on bottom zone.

No-go seating nipple Pinned collar

• Blast joint protection Operational Disadvantages

Seating nipple

• Complex downhole design and configuration.

Blast joint Polished nipple

• Multiple packer system retrieval can be difficult to release.

Sliding sleeve Hydrostatic retrievable packer

Seating nipple Hydro-trip pressure sub Perforated spacer tube No-go seating nipple Spacer tube Wireline entry guide

Fig. 14. Multiple zone completion – two zones, two packers.

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Name Multiple Zone – Multiple Packers Recovery/Function Primary recovery

On-off sealing connector

Frequency of Usage Uncommon

Retrievable packer

Operational Advantages • Several zones produced through one tubing string. • Flow controlled by wireline retrievable choke/check valves.

By-pass sliding sleeve with choke/check valve in place

• By-pass sliding sleeve prevents communication during service work.

Retrievable packer

• Up to five zones have been produced using this method. Operational Disadvantages • Complex downhole design and configuration. • Multiple packer retrieval can be difficult to release. By-pass sliding sleeve with choke/check valve in place

• Co-mingled flow limits reservoir management options.

Retrievable packer

No-go seating nipple with choke/ check valve in place

Fig. 15. Multiple zone completion – three zones, three packers.

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Flow coupling Name Multiple Zone – Multiple Packers

Seating nipple Sliding sleeve

Recovery/Function Primary recovery Frequency of Usage Uncommon

Dual hydrostatic retrievable packer

Operational Advantages Shear-out safety joints

• Four zone selective production system, two at a time, with the lower two zones alternating or commingled through the long string.

Seating nipple, polished nipple and blast joints Sliding sleeve Safety connector

• Upper zone produced through the short string with remaining zone being produced through either the short or long string.

Dual string retrievable packer

Operational Disadvantages Shear-out safety joint No-go seating nipple

• Complex downhole design and configuration (System contains 28 major downhole components).

Sliding sleeve

• Multiple packer retrieval can be difficult to release.

Tubing seal nipples

• Flow capabilities may limit reservoir management options.

Seal-bore packer Seating nipple Polished nipple Siding sleeve Tubing seal nipples Seal-bore packer No-go seating nipple

Fig. 16. Multiple zone completion – four zones, four packers.

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Liner Completions

Name Liner Completion – CSR Recovery/Function Primary recovery Production tubing

Frequency of Usage Becoming more common Operational Advantages • Simplest liner-type hook-up. • CSR replaces packer function. • Sliding sleeve permits well fluid or kill fluid circulation. • Tailpipe retrieved with production tubing

Sliding sleeve

Operational Disadvantages

Fluted locator sub Liner hanger

Tubing seal nipple Casing seal receptacle Seating nipple Spacer tube No-go seating nipple

Wireline entry guide

Fig. 17. Liner completion – casing seal receptacle.

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Name Liner Completion – CSR and Seal-bore Packer Recovery/Function Primary recovery Frequency of Usage Uncommon

Production tubing

Operational Advantages • Liner lap/top is permanently isolated. Sliding sleeve

• Fluid circulation through sliding sleeve.

Locator tubing seal assembly

• Tailpipe can be plugged to allow retrieval of tubing string with the producing zone isolated.

Seal-bore packer Seal-bore extension Tubing seal nipple

Operational Disadvantages

Fluted locator sub Liner hanger

Tubing seal nipple Casing seal receptacle Seating nipple Spacer tube No-go seating nipple Wireline entry guide

Fig. 18. Liner completion – casing seal receptacle and seal-bore packer.

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Special Service and Remedial Completions

Production tubing

Name Sand Control Recovery/Function Primary recovery Frequency of Usage Common (regional)

Gravel-pack packer and production seal assembly

Operational Advantages • Tools and gravel placed using a service tool and tubing workstring. • Gravel squeezed into perforation tunnels.

Ported housing

• Production tubing stung-in to production seal assembly. Operational Disadvantages • Can constrain future reservoir or wellbore treatments

Primary screen

Lower tell-tale

Sump packer and lower seal assembly

Fig. 19. Special service completion – sand control – gravel pack.

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Name Inhibitor Injection

Small diameter injection line

Recovery/Function Primary/Secondary

Flow coupling

Frequency of Usage Uncommon (field requirements)

Seating/injection nipple Flow coupling

Operational Advantages • Side-pocket mandrel injection permits protection inside production tubing above the packer. • Injection nipple and small diameter injection line is suitable for shallow injection requirements. Operational Disadvantages Side-pocket mandrel with injection valve Anchor tubing seal assembly Seal-bore packer

No-go seating nipple Wireline entry guide

Fig. 20. Special service completions – inhibitor injection (1).

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Name Inhibitor Injection Recovery/Function Primary/Secondary Frequency of Usage Uncommon (field requirements) Operational Advantages • Parallel flow tube and seal-bore packer enables inhibitor to be pumped down short string, through the packer body and into annulus below the packer. • All flow-wetted completion components are exposed to inhibitor fluid. • Inhibitor controlled by surface injection rate. Operational Disadvantages Check valve assembly Sliding sleeve Anchor parallel flow tube

Seal-bore packer

No-go seating nipple Wireline entry guide

Fig. 21. Special service completions – inhibitor injection (2).

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Name Waterflood Recovery/Function Primary/Secondary Frequency of Usage Common (offshore) Operational Advantages

Upper injection zone

• Two injection zones treated with both flow control regulators located at surface. • Totally separate injection systems. Operational Disadvantages • Casing string exposed to injection pressures Flow coupling Sliding sleeve Flow coupling

Retrievable packer

Wireline entry guide

Lower injection zone

Fig. 22. Special service completions – waterflood (1).

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Name Waterflood Recovery/Function Primary/Secondary

Retrievable packer

Frequency of Usage Common (offshore) Operational Advantages Downhole flow regulator

• Injection efficiency in thick zones is improved by using multiple injection points

Upper injection zone

• Downhole flow regulation prevents premature break-through between intra-zonal sections. Operational Disadvantages Retrievable packer

• Limited control on each zone.

Downhole flow regulator Intermediate injection zone

Retrievable packer

Downhole flow regulator Lower injection zone

Fig. 23. Special service completions – waterflood (2).

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Name Steamflood Recovery/Function Heavy crude – special application Frequency of Usage Limited application Operational Advantages • Packer incorporates an integral expansion/slip joint assembly Seating nipple

• Side-pocket mandrel allows insulation material to becirculated into annulus

Side-pocket mandrel

Operational Disadvantages • Design critical – hostile environment for materials and elastomers.

Double-grip thermal packer

Expansion mandrel

Fig. 24. Special service completions – steam injection.

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Name Steamflood Recovery/Function Heavy crude – special application Frequency of Usage Limited application Operational Advantages • Packer incorporates an integral expansion/slip joint assembly Seating nipple

• Side-pocket mandrel allows insulation material to becirculated into annulus

Side-pocket mandrel

Operational Disadvantages • Design critical – hostile environment for materials and elastomers.

Double-grip thermal packer

Expansion mandrel

Fig. 25. Special service completions – steam injection.

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Completion Examples Monobore completion (general)

Monobore completion characteristics Safety valve and associated nipples

• Seamless integration of completion components (in ideal conditions) • Component ID equal or greater than production tubing • Designed to facilitate through tubing well intervention • Designed to minimize pressure drops for optimized production

Packer/hanger with stingin seals

Landing profile for plugs or flow control devices

Liner

Fig. 26. Completion example – 5-1/2-in. monobore completion

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7 x 5-1/2-in. Produce/Injector

Safety valve control line and downhole gauge line 10-3/4-in. casing

Flow coupling Safety valve Flow coupling

7-in. tubing Permanent downhole gauge 7-in. nipple 7-in. to 5-1/2-in. tubing crossover Slick plug landing joint Expansion joint 5-1/2-in. tubing Stinger assembly 9-5/8-in. casing Permanent packer Seating nipple Slick plug landing joint

Liner top packer and tieback seal assembly Collar locator sub 5-1/2-in. liner

Fig. 27. Completion example – 7-in.x5-1/2-in. oil producer or water injector.

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Gas Injector

Safety valve control line

10-3/4-in. casing

Flow coupling Safety valve Flow coupling

7-in. tubing

7-in. nipple 7-in. to 5-1/2-in. tubing crossover Slick plug landing joint Expansion joint 5-1/2-in. tubing Stinger assembly 9-5/8-in. casing Permanent packer Seating nipple Slick plug landing joint

Liner top packer and tieback seal assembly Collar locator sub 5-1/2-in. liner

Fig. 28. Completion example – 7-in.x5-1/2-in. gas injector.

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