TYPES OF COMPLETION
ContentsContents Page 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
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 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.
• 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
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)
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.
Single Zone Completions
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.
Fig. 10. Single zone completion – seal bore packer. 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 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
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 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.
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 Name Single Zone – CSR Recovery/Function Primary recovery Frequency of Usage Infrequent – old design Operational Advantages • 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.
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 Multiple Zone Completions
Name
Multiple Zone – Seal-bore Packer Recovery/Function
Primary recovery Frequency of Usage Uncommon
Operational Advantages
• 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.
Operational Disadvantages
• Upper zone produced through casing. • Lack of casing protection.
Name
Multiple Zone – Multiple Packers Recovery/Function
Primary recovery Frequency of Usage Uncommon
Operational Advantages
• 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 Operational Disadvantages
• 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
Fig. 15. Multiple zone completion – three zones, three packers. Name
Multiple Zone – Multiple Packers Recovery/Function
Primary recovery Frequency of Usage Uncommon
Operational Advantages
• 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.
Operational Disadvantages
• 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
Fig. 16. Multiple zone completion – four zones, four packers. Name
Multiple Zone – Multiple Packers Recovery/Function
Primary recovery Frequency of Usage Uncommon
Operational Advantages
• 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.
Operational Disadvantages
• 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
Fig. 17. Liner completion – casing seal receptacle. Liner Completions Name Liner Completion – CSR Recovery/Function Primary recovery 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
Operational Disadvantages
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
Fig. 18. Liner completion – casing seal receptacle and seal-bore packer. 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.
Operational Disadvantages
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
Fig. 19. Special service completion – sand control – gravel pack. Special Service and Remedial Completions
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. Operational Disadvantages
• 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
Fig. 20. Special service completions – inhibitor injection (1). Name Inhibitor Injection Recovery/Function Primary/Secondary Frequency of Usage
Uncommon (field requirements) Operational Advantages
• 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.
Operational Disadvantages
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
Fig. 21. Special service completions – inhibitor injection (2). 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
Wireline entry guide No-go seating nipple Seal-bore packer Anchor parallel flow tube Sliding sleeve
Fig. 22. Special service completions – waterflood (1). 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. Operational Disadvantages
• Casing string exposed to injection pres-sures
Wireline entry guide Retrievable packer Flow coupling Sliding sleeve Flow coupling Upper injection zone
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 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.
Operational Disadvantages • Limited control on each zone.
Fig. 24. Special service completions – steam injection. Name
Steamflood
Recovery/Function
Heavy crude – special application Frequency of Usage
Limited application Operational Advantages
• Packer incorporates an integral expan-sion/slip joint assembly
• Side-pocket mandrel allows insulation material to becirculated into annulus Operational Disadvantages
• Design critical – hostile environment for materials and elastomers.
Double-grip thermal packer
Expansion mandrel Seating nipple Side-pocket mandrel
Fig. 25. Special service completions – steam injection. Name
Steamflood
Recovery/Function
Heavy crude – special application Frequency of Usage
Limited application Operational Advantages
• Packer incorporates an integral expan-sion/slip joint assembly
• Side-pocket mandrel allows insulation material to becirculated into annulus Operational Disadvantages
• Design critical – hostile environment for materials and elastomers.
Double-grip thermal packer
Expansion mandrel Seating nipple Side-pocket mandrel
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 Completion Examples
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
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
Slick plug landing joint
7-in. to 5-1/2-in. tubing crossover 7 x 5-1/2-in. Produce/Injector
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
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
Slick plug landing joint 7-in. nipple
7-in. to 5-1/2-in. tubing crossover Gas Injector