4- Types of Completion

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TYPES OF COMPLETION

Contents

Contents Page Page

Introduction ... 1

4.1 Single Zone Completions 4.1.1 Retrievable Packer ... 4

4.1.2 Seal-bore Packer ... 5

4.1.3 Packer-Tail-Pipe Attached ... 6

4.1.4 Casing Seal Receptacle ... 7

4.2 Multiple Zone Completions 4.2.1 2 Zones 1 Packer ... 8

4.2.2 2 Zones 2 Packers ... 9

4.3 Liner Completions 4.3.1 Casing Seal Receptacle ... 12

4.3.2 CSR and Seal-bore Packer ... 13

4.4 Special Service and Remedial Completions 4.4.1 Sand Control ... 14 4.4.2 Inhibitor Injection (1) ... 15 4.4.3 Inhibitor Injection (2) ... 16 4.4.4 Waterflood (1) ... 17 4.4.5 Waterflood (2) ... 18 4.4.6 Thermal Completion ... 19 4.4.7 Remedial–Scab Liner ... 20 4.5 Completion Examples 4.5.1 Monobore Producer/Injector ... 21 4.5.2 7 x 5-1/2-in. Produce/Injector ... 22 4.5.3 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 sys-tems including configuration examples are shown in Sec-tion 5.

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

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

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

• 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 produc-ing formation.

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

• Production control – for example, the addition of comple-tion components to control flow (nipples and profiles), allow circulation (sliding sleeves) or flexibility in produc-tion (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.

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• No downhole flow control or isolation possible

• Unsupported producing formation

Fig. 1. Open-hole production.

• Production zone(s) hydraulically isolated by casing cement • More options for

selective treatment and isolation

Fig. 2. Casing production.

Fig. 3. Liner production. Fig. 4. Gravel packed wellbore.

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

• Dictated by formation type, selectivity of treat-ment and subsequent isolation is difficult

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

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

Fig. 6. Basic packer production.

• Well kill capability through circulation around packer once unset

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

Fig. 7. Packer with perforated tailpipe. Fig. 8. Packer with nipples, sliding sleeve and safety valve.

As with basic packer produc-tion but with:

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

through the sliding sleeve without unsetting packer. • Production safety valve As with basic packer production

but with:

• Downhole isolation (plug) capability

• Facility for downhole instru-ments (gauges)

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Fig. 9. Single zone completion – retrievable packer.

Sliding sleeve Flow coupling Flow coupling

Hydrostatic retrievable packer

Seating nipple Spacer tube

Wireline entry guide No-Go nipple

Perforated spacer tube Hydro-trip pressure sub Flow coupling

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.

4.1 Single Zone Completions 4.1.1

Name

Single Zone – Retrievable Packer

Recovery/Function

Primary recovery

Frequency of Usage

Common

Operational Advantages

• Fully retrievable completion – no perma-nent compoperma-nents.

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

• Thru-tubing perforation possible where size permits.

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

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Fig. 10. Single zone completion – seal bore packer. 4.1.2

Name

Single Zone – Seal-bore Packer

Primary recovery

Common

• Seal-bore packer set on electric line or tubing.

• On-off connector and tubing anchor al-lows 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.

• Tailpipe can be retrieved with tubing if required.

Operational Disadvantages

Production tubing

Wireline entry guide No-Go nipple

Perforated spacer tube Seating nipple Spacer tube Seating nipple Seal-bore packer Tubing anchor On-off connector

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

Wireline entry guide Seating nipple

Perforated spacer tube Crossover sub

No-go seating nipple Flow coupling Spacer tube Seating nipple Flow coupling Crossover Millout extension Seal-bore packer Tubing anchor Sliding sleeve Block and kill system Production tubing 4.1.3 Name Packer-Tail-Pipe Atached Recovery/Function Primary recovery Frequency of Usage Less Common Operational Advantages

• Tailpipe permanently attached to packer. • Tailpipe plug isolates formation during

work-over/tubing retrieval.

• Permits safe thru-tubing perforating. • Block and kill system facilitates the killing

and control of high-pressure, high volume wells.

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

Seating nipple

Casing seal receptacle Flow coupling

Safety valve and nipple Flow coupling

Expansion joint

Sliding sleeve

Shearout anchor/tubing seal assembly

Retrievable tailpipe hanger

Perforated spacer tube No-go seating nipple Spacer tube

Wireline entry guide Seating nipple Control line 4.1.4 Name Single Zone – CSR Recovery/Function Primary recovery Frequency of Usage

Infrequent – old design

• Tailpipe retrievable separately.

• Protective sleeve run in CSR during pri-mary and remedial cementing operations • Expansion joint allows for tubing

move-ment.

• Safety valve run and retrieved on wireline. • Circulation of well fluid/kill fluid facilitated

by sliding sleeve.

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

Anchor tubing seal assembly On-off sealing connector

Wireline entry guide No-go seating nipple Spacer tube Seal-bore packer Flow coupling Flow coupling Sliding sleeve Spacer tube Flow coupling Flow coupling Seating nipple Blast joint Polished nipple

4.2 Multiple Zone Completions 4.2.1

Name

Multiple Zone – Seal-bore Packer

Primary recovery

Uncommon

• Separate or commingled flow through single production tubing string.

• Upper zone may be produced through the annulus.

• Blast joint protects tubular integrity across perforated intervals.

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

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

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

• Upper zone produced through casing. • Lack of casing protection.

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4.2.2 Name

Multiple Zone – Multiple Packers

Primary recovery

Uncommon

• Independent production through two tub-ing strtub-ings.

• Both packers are fully retrievable. • Tailpipe instrument facility in both strings. • Thru-tubing perforation possible on

bot-tom zone.

• Blast joint protection

• Complex downhole design and configura-tion.

• Multiple packer system retrieval can be difficult to release.

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

Pinned collar

Blast joint

Wireline entry guide Spacer tube

No-go seating nipple Perforated spacer tube Hydro-trip pressure sub Seating nipple

Hydrostatic retrievable packer Sliding sleeve

Polished nipple Seating nipple No-go seating nipple Perforated spacer tube Hydro-trip pressure sub Flow coupling

Seating nipple Flow coupling

Dual hydrostatic retriev-able packer Flow coupling Sliding sleeve Flow coupling Flow coupling Flow coupling Seating nipple

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Fig. 15. Multiple zone completion – three zones, three packers. 4.2.3

Name

Primary recovery

Uncommon

• Several zones produced through one tub-ing strtub-ing.

• Flow controlled by wireline retrievable choke/check valves.

• By-pass sliding sleeve prevents commu-nication during service work.

• Up to five zones have been produced using this method.

• Complex downhole design and configura-tion.

• Multiple packer retrieval can be difficult to release.

• Co-mingled flow limits reservoir manage-ment options.

Retrievable packer

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

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

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

Retrievable packer On-off sealing connector

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Fig. 16. Multiple zone completion – four zones, four packers. 4.2.4

Name

Primary recovery

Uncommon

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

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

• Complex downhole design and configura-tion (System contains 28 major downhole components).

• Multiple packer retrieval can be difficult to release.

• Flow capabilities may limit reservoir man-agement options.

Dual string retrievable packer Safety connector

Sliding sleeve Flow coupling

Siding sleeve Polished nipple

No-go seating nipple Tubing seal nipples Seal-bore packer Seating nipple Tubing seal nipples Seal-bore packer Sliding sleeve No-go seating nipple Shear-out safety joint Shear-out safety joints

Seating nipple, polished nipple and blast joints

Dual hydrostatic retrievable packer

Sliding sleeve Seating nipple

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Fig. 17. Liner completion – casing seal receptacle. 4.3 Liner Completions 4.3.1 Name Liner Completion – CSR Recovery/Function Primary recovery Frequency of Usage

Becoming more common

• Simplest liner-type hook-up. • CSR replaces packer function.

• Sliding sleeve permits well fluid or kill fluid circulation.

• Tailpipe retrieved with production tubing

No-go seating nipple

Wireline entry guide Spacer tube

Seating nipple

Casing seal receptacle Tubing seal nipple Liner hanger Fluted locator sub Sliding sleeve Production tubing

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Fig. 18. Liner completion – casing seal receptacle and seal-bore packer. 4.3.2

Name

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

• Liner lap/top is permanently isolated. • Fluid circulation through sliding sleeve. • Tailpipe can be plugged to allow retrieval

of tubing string with the producing zone isolated.

Liner hanger Fluted locator sub Production tubing

Wireline entry guide No-go seating nipple Spacer tube

Seating nipple

Casing seal receptacle Tubing seal nipple Tubing seal nipple Seal-bore extension Seal-bore packer

Locator tubing seal assembly Sliding sleeve

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Fig. 19. Special service completion – sand control – gravel pack. 4.4 Special Service and Remedial Completions

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

• Tools and gravel placed using a service tool and tubing workstring.

• Gravel squeezed into perforation tunnels.

• Production tubing stung-in to production seal assembly.

• Can constrain future reservoir or wellbore treatments

Production tubing

Lower tell-tale

Sump packer and lower seal assembly

Ported housing

Primary screen Gravel-pack packer and production seal assembly

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Fig. 20. Special service completions – inhibitor injection (1). 4.4.2 Name Inhibitor Injection Recovery/Function Primary/Secondary Frequency of Usage

Uncommon (field requirements)

• Side-pocket mandrel injection permits protection inside production tubing above the packer.

• Injection nipple and small diameter injec-tion line is suitable for shallow injecinjec-tion requirements.

Wireline entry guide No-go seating nipple

Anchor tubing seal assembly Seal-bore packer

Side-pocket mandrel with injection valve

Flow coupling

Seating/injection nipple Flow coupling

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Fig. 21. Special service completions – inhibitor injection (2). 4.4.3 Name Inhibitor Injection Recovery/Function Primary/Secondary Frequency of Usage

Uncommon (field requirements)

• 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.

Wireline entry guide No-go seating nipple Seal-bore packer Anchor parallel flow tube Sliding sleeve

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Fig. 22. Special service completions – waterflood (1). 4.4.4 Name Waterflood Recovery/Function Primary/Secondary Frequency of Usage Common (offshore) Operational Advantages

• Two injection zones treated with both flow control regulators located at surface. • Totally separate injection systems.

• Casing string exposed to injection pres-sures

Wireline entry guide Retrievable packer Flow coupling Sliding sleeve Flow coupling Upper injection zone

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

Lower injection zone Downhole flow regulator Retrievable packer

Intermediate injection zone Downhole flow regulator Retrievable packer

Retrievable packer

Upper injection zone Downhole flow regulator

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

• Injection efficiency in thick zones is im-proved by using multiple injection points • Downhole flow regulation prevents pre-mature break-through between intra-zonal sections.

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Fig. 24. Special service completions – steam injection. 4.4.6

Name

Steamflood

Heavy crude – special application

Limited application

• Packer incorporates an integral expan-sion/slip joint assembly

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

• Design critical – hostile environment for materials and elastomers.

Double-grip thermal packer

Expansion mandrel Seating nipple Side-pocket mandrel

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Fig. 25. Special service completions – steam injection. 4.4.7

Name

Steamflood

Heavy crude – special application

Limited application

• Packer incorporates an integral expan-sion/slip joint assembly

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

• Design critical – hostile environment for materials and elastomers.

Double-grip thermal packer

Expansion mandrel Seating nipple Side-pocket mandrel

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

Safety valve and associated nipples

Packer/hanger with sting-in seals

Landing profile for plugs or flow control devices

Liner

4.5 Completion Examples

4.5.1 Monobore completion (general)

Monobore completion characteristics • 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

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Fig. 27. Completion example – 7-in.x5-1/2-in. oil producer or water injector. Expansion joint Stinger assembly Permanent downhole gauge Flow coupling Safety valve Flow coupling

Safety valve control line and downhole gauge line

Permanent packer

Seating nipple

Slick plug landing joint

Liner top packer and tie-back seal assembly

Collar locator sub 10-3/4-in. casing 7-in. tubing 5-1/2-in. tubing 9-5/8-in. casing 5-1/2-in. liner 7-in. nipple

7-in. to 5-1/2-in. tubing crossover

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Fig. 28. Completion example – 7-in.x5-1/2-in. gas injector. Expansion joint Stinger assembly Flow coupling Safety valve Flow coupling

Safety valve control line

Permanent packer

Seating nipple

Liner top packer and tie-back seal assembly

Collar locator sub 10-3/4-in. casing

7-in. tubing

5-1/2-in. tubing 9-5/8-in. casing

5-1/2-in. liner

Slick plug landing joint 7-in. nipple

7-in. to 5-1/2-in. tubing crossover