Halliburton Packer Information [1].pdf

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(1)

Packers and Liner Hangers

• Basic Overview

• Applications and Selections of Packers

• Setting Criteria and procedures

(2)

What is a Packer?

• A packer is a tool used to form an annular seal

between two concentric strings of pipe or between

the pipe and the wall of the open hole.

• A packer is usually set just above the producing

zone to isolate the producing interval from the

casing annulus or from producing zones elsewhere

in the wellbore.

• Separates fluid types (or ownership), protects

against pressures and corrosion.

(3)

Why are packers used?

• Tubing and packer used to isolate zone of interest

- can be removed for repair.

• Packers act as downhole valve for press control.

• Packer can be a temporary plug to seal off the

zone while work is done up the hole.

• Subsurface safety valves used with packers for

downhole shut-in.

• Focus flow

(4)

Lock Ring and Mandrel Slips

Cone Seal

Inner Mandrel

Packer Cutaway Drawing

Ability to effectively set a packer depends on having a clean, non corroded set point and

reaching the set point without fouling the slips or failing other components.

As the packer sets, the inner mandrel moves up,

driving the cone underneath the slips, pushing them into the casing wall. The sealing element is

(5)

Packers and Liner

Hangers

Mechanical isolation methods

Two examples:

1. An external casing packer (ECP) set to seal the annulus between the surface or protection string and the inner, production string

2. A conventional packer set near the end of the tubing, that isolates the inner annulus from the tubing.

(6)

Packer Considerations

• Force on an area

Remember, it’s a

force balance.

Area down =

casing ID - tube OD

Area up =

tube x-section +

(7)

Packer Types & Selection

Hydraulic Set Wireline Set Retrievable Permanent Production Packers Sealbore Hydraulic Multiport Mechanical Hydraulic Set Wireline Set Differential Set Hydrostatic Set Double Grip Single Grip ESP RMC Dual Single Hyd. Slips Mech. Slips Schlumberger

(8)

Specific Packer Examples

• Packer Examples

– Retrievables

– Seal bores

– Inflatables

– Wash Tools

(9)

Retrievable Packers

• Expected to be retrieved

• More prone to leaks

• Need an equalizing port

• Release mechanism must be possible with

well design

(10)

Retrievable Packers

• Compact

• Simple J slot control for set and release

• Shear ring secondary release

• Right-hand safety joint emergency release

• Rocker type slips

• Can be set shallow

Tension Set - Economical packer used in

production, injection, zone isolation applications

(11)

Retrievable Production Packers

• Rotation set and release

• Can be set with tension or compression

• Tubing can be landed in tension, compression or neutral • Models rated up to 10,000 psi

• Pressure equalization needed prior to upper slip release • Secondary shear release required

Mechanical - Used in production, injection,

fracturing, zone isolation and remedial applicatuions

(12)

Retrievable Production Packers

• Compression set

• RH rotation required to set, (LH option usually available)

• Available with or without Hydraulic hold down buttons for differential pressure from below

• By-pass needed for equalization of pressure, and for running and retrieval without surging/swabbing the well.

Mechanical Used in production, stimulation and testing

(13)

Retrievable Packers

• Can act as a bridge plug prior to production

• Connect to tubing via On/Off Tool with blanking plug • Tubing can be landed in tension, compression or neutral • Slips above and below the elements

• Triple element pack off system • Pressures to 10,000 psi

• Fluid bypass needed for pressure equalization • Retrieved on tubing

• Secondary shear release needed

Wireline set - Used in production, injection,

fracturing, zone isolation and remedial applications where wireline setting is preferred

(14)

Seal Bore Packers

• Allow tubing movement; however:

– Too much contraction can pull seals out of PBR

– Seals can “bond” to the seal bore over long

time at higher temperatures

(15)

Unprotected seals below the packer may allow seal swelling by gas and fluids, causing seals to roll off if the stinger is pulled out.

(16)
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Deep Completions

• Most typical is permanent packer with a

PBR (arrangement depends on personal

preferences, individual well configurations

and intended operations).

• Seal assembly length dependent not only on

normal operations, but also fracturing, kill

and expected workovers.

(18)

Seal Bore Packers

• High pressure & temperature ratings available • Multiple packing elements available

• Short units are desirable for use in tight doglegs (>5o) and high

(>8o/100ft) departure angles

• Ability to set on wireline or with a hydraulic setting tool • Rotationally locked units needed for mill-ability

• Share Seal Assemblies with permanent seal bore packers

• Critical metallurgical and seals (O-rings, etc) should be isolated from wellbore fluids by main elements.

(19)

Retrievable Seal Bore Packer

• Hydraulic set version retrievable seal bore

packer available for one-trip installations

• Seal assembly is run in place for one trip

installation

• Available with large upper seal bore to

maximize ID

• Rotationally locked components

One-trip applications

(20)

Permanent Seal Bore Packers

• Seals run in place for one trip setting

• A metal back-up system can be specified to

casing ID to prevent element extrusion

• Elastomer and materials available for

hostile environments

Used in one trip production applications

(21)

Packer Considerations

• Select seals for full range of expected

temperatures, pressures, and fluids.

• A back-up system is need around the main seal to

prevent seal extrusion at high temps and pressure.

• Examine slip design to help avoid premature

setting during movement through viscous fluids,

doglegs and rough treatment

(22)

Seal Bore

Packers

Molded Seals:

• Recommended in medium pressure applications where seal movement out of the seal bore is anticipated.

Nitrile Seal or Viton Seal Steel spacer Seal spacer End spacer Nitrile Seal or Viton Seal Middle spacer MOLDED SEAL SINGLE UNIT CHEVRON SEAL SINGLE UNIT Chevron Seals: Used for higher pressure and

temperature applications.

(23)

Seal Bore Packer

Accessories

• Tubing Anchor and Locator Assemblies • Seal Units and Spacer Tubes

• Seal Bore and Mill-Out Extensions • Packer Couplings and Bottoms

• Pump-out, Screw-out, and Knock-out Bottoms

(24)

Inflatable Packers and Plugs

• Reasons to run and inflatable.

– Need to set beneath a restriction.

– Need to set in open hole.

– In non-standard casing.

– Setting in multiple sizes of pipe on same run.

– Where larger run-in and retrieval clearances are

needed.

(25)

Inflatable Setting Considerations

The inflatable packer offers a way to set a seal in a larger area below a

restriction.

The quality of the seal depends on how much the packer must expand over initial diameter, the length of the slide (placement run), the

differential pressure it must hold, what fluid is used for inflation and the conditions in the area in which it is set.

Holding ability of the inflatable is always suspect since it does not have conventional slips.

When deflating an inflatable packer, allow time (1 hr?) for relaxation of the elements. The elements never shrink back to initial diameter – allow about 30% increase in diameter for

(26)

Baker

Inflatables rely on expansion of an inner rubber bag that pushes steel cables or slats against the wall of the pipe or the open hole. The only gripping ability is generated by the friction of the steel against the pipe or open hole. This is critically dependent on the inflation pressure and the exterior slat or cable design. For a

permanent seal, place several bailers of cement on top of the inflatable.

(27)

• Heavy Duty reinforced casing cups

• Spacing between cups adjustable from 12” to any length by addition of standard tubing pup joints

• Large internal bypass

• Cup wear from casing burrs can be significant and may reduce seal, especially in long zones. • The number of successful resets depends on

casing conditions, pressures, slide length (running), temperature and deviation.

Successful resets run from about 5 to over 20.

Used for selective acidizing of perforated intervals

Perforation Wash Tool

(28)

Packer Seals Packer Slips

(29)

A hydraulic set packer. Note the lower slips set by movement of the mandrel and upper slips set by

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HES Schlumberger (Camco) Packer Type

Weatherford Completion Systems

(Bold Items are Preferred Products) Baker

Halliburton Guiberson

Solid head, Tension Set, Mechanical, Single Grip

PAD-1, PADL-1 AD-1

AL

RB R-4

Uni-Packer I SA-3 T Series Compression Set, Mechanical,

Single Grip

PR-3 Single Grip R-3 Single Grip

Model G R-4 Uni-Packer IV Uni-Packer II G-4 SR-2 U-3 CA-3, C Series Compression Set, Double Grip

Packer

PR-3 R-3 Double Grip MHS

MH-2

Uni-Packer V SR-1 Neutral Set, Double Grip Packer QDG, QDH, Arrowset I-X (&10K),

Ultra-Lok, Double Grip

Lockset, Max J-Lok, MS WPL Perma-Lach Uni-Packer VI G-6, G-16 SOT-1 KH Hydraulic Set Retrievable

HRP, Hydrow-I, PFH FH, FHL, FHS Hydra-Pak HS, HS-S RH PHL AHR Uni-Packer VII G-77 RHS Hydro-5 HRP Dual Hydraulic Set Retrievable Hydrow IIA A-5

T-2 GT RDH BHD Uni-XXVII RHD Hydro-10 HSD Wireline Set Permanent Arrowdrill B Model D

F-1 AWB BWB AWS G, GT H, HT Model S Wireline Set Permanent Double

Bore

Arrowdrill DB DA, DAB

FA, FAB

AWR G-1, GT-1 H-1, HT-1 Hydraulic Set Permanent Arrowdrill BH SB-3 MHR PG

PH

Model HS Hydraulic Set Permanent Double

Bore

Arrowdrill DBH SAB-3 MHR PG-1

PH-1

Model HSB Retrievable Seal Bore Arrow-Pak Retrieva-D, DB

WS, WSB SC-1, SC-2

VTL (Versa-Trieve) G-10 M Omegatrieve Quantum Hydraulic Set Retrievable Seal

Bore

Hydrow-Pak SC-2PAH VHR (Versa-Trieve) RSB

HPHT Hydraulic Set Retrievable Hydrow-Pak HP-1AH, SC-2PAH HP/HT

HPHT (Versa-Trieve Retrievable) Compression Set Service Packer CST, C5, H/D, MSG EA Retrievamatic RTTS

Champ III, IV

HDCH-V Omegamatic Compression Set Storm Packer CSTH, DLT

Tension Set Service Packer 32A, Fullbore Tension C Fullbore BV Tension Packer R-104 Tubing Set Retrievable Bridge

Plug

QDH w/ EQV, TSU G Lock-Set 3L RBP-VI P-1

Wireline Set Retrievable Bridge Plugs

WRP, CE, CE2

Permanent Bridge Plugs/Cement Retainer

PCR, Plugwell, PBP Mercury N, K-1 EZSV, EZ Drill

EZ Drill SVB Fas-Drill, HCS

Type A Quik-Drill

(33)
(34)

Monobore: mixed grades, same weight Mixed grades and weights Mixed weights, same grade

Casing Design Options – think about running and setting packers.

Small

diameters at the top of the well may

prevent entry by some

(35)

Production Packers

• Purposes

– Casing protection from fluids or pressures

– Separation of zones

– Subsurface pressure and fluid control

– Artificial lift support equipment

(36)

Packer Considerations

• Seal stability

– pressure, temperature, fluid reaction

• Force balance and direction

– slip direction

• resists upward motion, downward or both ways) • tension, compression, mechanical or hydraulic set

(37)

Allowing Tubular Movement

• Usually incorporate a PBR - polished bore

receptacle, for a “stinger” or seal assembly

to slide through.

• Shoulder out on the PBR - if it can move, it

will eventually leak.

• Seals must match operating extremes as

well as general conditions.

(38)

Seal Bore Packer to Tubing Connections

Seal Bore Extensions (SBE) Polished Bore Receptacle (PBR) Tubing Sealbore Receptacle (TSR)

(39)

Seal Assembly Locator Types

Locator Anchor

Latch

(40)

A “stinger” or seal

assembly that is run on the end of tubing and “stings” into the polished bore

receptacle (PBR) of the packer.

(41)

Stinger Seal Materials

• Single or mixture of elastomers

• seal design variance

• seals usually protect the slips from

corrosive fluids.

(42)

Tubing Seal Stability

Seal Material

oil

brine H2S CO2

Butyl Rubber 4 1 1 2

Flurocarbon 1 1 4 2

Nitrile 1 1 4 1

Fluro-silicone 2 1 3 2

1=good, 2=fair, 3=doubtful, 4= unsatisfactory

Much larger data base available online.

(43)

A-Satisfactory B - Little or no effect C - Swells D - Attacks NR - Not recommended NT - Not tested NOTE: (1) This information provides general guidelines for the selection of seal materials and is provided for informational purposes only. Seal Specialists with Halliburton Energy Services should be consulted for the actual selection of seals

for use in specific applications. Halliburton Energy Services will not be liable for any damage resulting from the use of this information without consultation with Halliburton Seal Specialists. (2) Contact Technical Services at Halliburton Energy Services - Dallas for service temperature and pressure.

(3) Back-Up Rings must be used.

(4) There could be a slight variation in both temperature and pressure rating depending on specific equipment and seal designs.

Halliburton Energy Services

General Guidelines For Seals

(1)

PEEK (2), (4) Ryton Fluorel (3) Aflas (3) Chemraz (3) Viton (3) Neoprene (3) Nitrile (3) Kalrez (3) Teflon (3)

Filled Unfilled Unfilled Filled Unfilled Filled Filled Filled Filled Unfilled

350 350 450 350 325 300 275 450 400 325 (177) (177) (232) (177) (163) (149) (135) (232) (204) (163) Above Below 15,000 10,000 15,000 5000 5000 5000 3000 15,000 15,000 5000 (103) (68.9) (103) (34.4) (34.4) (34.4) (20.7) (103) (103) (34.4) A A A A A B B NR NR A A A A A B B A B B C A A A A A A A A A A A B B A A A A A A A A A A B C A A A A A A A C A A A NR NR A A A A A C B A C C B A A A A A A A A A A A NR NR A A A A A NR A A NR NR NR B A A A A A A A A A A C A B A A A A NR A A NR NR NR NR NR B B Diesel A A A NR A A A B B A A A (2), (4) Compound Service °F (°C) Pressure psi (MPa ) Environments H 2 S CO 2 CH 4 (Methane) Hydrocarbons (Sweet Crude) Xylene Alcohols Zinc Bromide Inhibitors Salt Water Steam (2), (4)

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Halliburton Energy Services

(45)

Halliburton Energy Services

(46)

Packer Element Selection

Chart

NITRILE ELEMENTS W/BONDED GARTER SPRINGS NITRILE ELEMENTS W/TEFLON AND METAL BACKUPS

AFLAS ELEMENTS W/STANDARD METAL BACKUPS

AFLAS ELEMENTS W/TEFLON AND GRAFOIL WIREMESH AND METAL BACKUPS

CHECK WITH YOUR HALLIBURTON REPRESENTIVE FOR SPECIAL APPLICATIONS TEMP

GREATER THAN 450°F

FLUOREL ELEMENTS W/BONDED GARTER SPRINGS

AFLAS ELEMENTS W/BONDED GARTER SPRINGS

CHECK WITH YOUR HALLIBURTON REPRESENTIVE FOR SPECIAL APPLICATIONS

EPDM ELEMENTS WITH BACKUPS

CHECK WITH YOUR HALLIBURTON REPRESENTIVE FOR SPECIAL APPLICATIONS Y Y Y Y Y Y Y Y N N N N N N N N START STEAM/THERMAL APPLICATION W/NO HYDROCARBON FLUIDS NITRILE ELEMENTS W/STANDARD METAL BACKUPS

Y Y Y Y Y N N N N N Y PERMANENT PACKER DESIGN

PACKER IN OIL BASE MUD OVER 24 HOURS BEFORE

SET?

PACKER IN BROMIDE COMPLETION FLUIDS MORE THAN 36

HOURS BEFORE SET? TEMP 40°F TO 325°F TEMP 40°F TO 400°F TEMP 100°F TO 400°F TEMP 100°F TO 450°F RETRIEVABLE PACKER DESIGN TEMP 40°F TO 275°F TEMP 100°F TO 400°F TEMP GREATER THAN 400°F TEMP LESS THAN 550°F TEMP GREATER THAN 550°F PACKER ELEMENTS EXPOSED TO AMINE CORROSION INHIBITORS? PACKER EXPOSED TO BROMIDES? TEMP 40°F TO 400°F N N (1)

NOTE: (1) This information provides general guidelines for the selection of seal materials and is provided for informational purposes only. Seal Specialists with Halliburton Energy Services should be consulted for the actual selection of seals for use in specific applications. Halliburton Energy Services will not be liable for any damage resulting from the use of this information without consultation with Halliburton Seal Specialists.

(47)

Forces and Length Changes

• Temperature:

• Piston Effect:

• Ballooning

• Buckling:

A tubing movement calculator is the best method, but the difficulty is in knowing accurate temperature changes and pressure changes.

(48)

Is it Force or Length Change?

• No packer - tube suspended and not touching well

bottom - length change

• Tube landed on packer - incr. force with

increasing temp, shortening possible with cooling

after downward force absorbed.

• Latched tubing - no movement, only forces

• Tube stung through - length changes unless

locator is shouldered

• If tube set in tension or compression, effects of

temp depends on initial force and DT

(49)

Temperature, length change

D

L = CL

DT

Where:

D

L = length change

C = expansion coeff. for steel = 6.9x10

-6

/

o

F

L = length of tubing

(50)

Temperature, Force change

• F = 207

DT

a

A

s

• Where:

F = temperature induced force

DT

a

= change in average temp of tubing,

o

F

(51)

What Temperature is Average?

• If no circulation - assume all tubing is same

as injected fluid temperature. (worst case)

• If circulation is allowed, all but top few

joints will be unaffected by injected fluid

temp. - no temp change. (v. slight effect)

• Injected fluid temp? - source dependent!

• In dual packer - treat each packer as a

(52)

Temperatures in the Well?

Circulating or High Rate Injection?

0 2000 4000 6000 8000 10000 12000 14000 16000 18000 30 40 50 60 70 80 90 100 110 120 130 Tubing Tbg Fluid Casing 1 Undisturbed

Circulation pump rate = 8-BPM

BHST= 122*F BHCT= 98*F 0 2000 4000 6000 8000 10000 12000 14000 16000 18000 30 40 50 60 70 80 90 100 110 120 130 Undisturbed Tbg Fluid Tubing Casing 1

Frac job pump rate = 35-BPM

BHST= 125*F

(53)

Problem

• Temperature Effect Only

– Is a 6 ft seal assembly (effective seal length)

enough to keep the tubing from unseating when

the average temperature falls from 210

o

F to

100

o

F during a Frac job? L = 8000 ft.

– Assume locator is shouldered but no downward

force is applied.

(54)

Problem

• Temperature Effect Only

DL = 6.9 x 10

-6

x 8000 x 110

DL = 6.1 ft unseats!

What if 15,000 lb downward force were

applied to the tubing before the temperature

change?

(55)

How much temperature increase

is spent lifting the 15,000 lb?

• F = 207 x

D

T

2

x 2.59 in

2

D

T

2

= 15000 / (207 x 2.59) = 28

o

F

Then: 110 - 28 = 82

o

F

(56)

What about those other factors?

• Buckling, Piston, Ballooning - Use a

computer program - better yet, use a couple

of them (different assumptions).

(57)

Temperature Extremes

• The extremes of temperature change (higher

than normal) are usually seen in operations

involving cyclic thermal processes.

• Lower than normal temperatures may be

seen in permafrost, sea floor penetrating and

CO

2

operations.

(58)

Setting the Packer

• Chances of setting packers go up sharply

when a casing scraper is run. (Remember

the burrs on the perforations?)

• The quantity of debris turned loose from the

casing wall is often severe! (Tens of

pounds worth!) Watch the formation

damage.

(59)

Packer Set Point Requirements

Avoid setting packer in the

same joint where previous packers have been set.

Avoid doglegs, fault

locations or high earth stress zones

Adequate cement and bond

required behind pipe at packer set point

Caliper casing above and

through the packer set point

Clearance between packer

and casing at set point is

within rated range of packer

Avoid zones of high

corrosion, either internal or external.

Remove burrs from pipe

above packer set point

Remove debris (dope, mill

scale, mud, cement, etc.) on casing wall (fills slip teeth)

Well pressures are within

range of packer at set point

Pipe alloy compatible with

setting slips (hardness of casing relative to packer slips)

Slip design & contact area

acceptable for slip holding

Weight applied to packer

can be transferred to formation

(60)

Information Required Before

Setting Packer or Plug

• Wellbore drawing with all diameters • Last TD tag – rerun?

• Doglegs and deviations

• Viscosity of fluid in wellbore

– Calculate running speed vs. surge/swab.

• Copy of reference logs

• Where have other packers been set (avoid that joint) • Set point requirements

(61)

Job Checks

• Measurements from CCL to a packer

reference point.

• Run in hole at about 100 fpm, slowing at ID

restrictions.

• Using CCL/GR, log up and correlate depths

• Set packer – look for line weight reduction

• Disconnect and log up a few collars (may

(62)

Job Checks

• Drop back and gently tag packer with

setting tool to confirm depth.

(63)

Packer Setting Guidelines

• Drift

• Scraping

(64)

Drift the Casing

• Casing ID requirements above the set point

• Casing ID requirements below the set point

• Check the drift to deepest point with drift of

(65)

Clean/Scrape The Casing?

• Removal of perforation burrs minimizes elastomer

seal damage

• Removal of cement, mud, pipe dope and mill scale

minimize debris that can fill the slips.

• Scraping casing can increase packer setting

success

• Scraping casing can also produce some severe

formation damage if perforations are not

(66)

Casing Scraper – Designed to knock off perforation burrs, lips in tubing pins, cement and mud sheaths, scale, etc. It cleans the pipe before

setting a packer or plug.

The debris it turns loose from the pipe may damage the

formation unless the pay is protected by a LCM or plug.

(67)
(68)

Effect of Scraping or Milling Adjacent to Open Perforations -60 -50 -40 -30 -20 -10 0 10 20 1 2 % C ha ng e i n P I

Short Term PI Change Long Term PI Change

Perfs not protected by LCM prior to scraping

Perfs protected by LCM

SPE 26042

One very detrimental action was running a scraper prior to packer setting. The scraping and surging drives debris into unprotected perfs.

(69)

Typical Completions

(70)

Single Zone Completion

(

Mechanical Packer)

Retrievable Packer On-Off Sealing Connector

Packer isolates casing from production

• Provides means of well control

• Protects casing above packer from corrosion

• Anchors tubing string

Tension Set Compression set Wireline Set Large Variety of accessories available Weatherford

(71)

Single Zone Completion

(

Hydraulic Set Packer)

• Permits Packer setting without tubing manipulation

–Common in offshore applications where SCSSV control lines prevent tubing rotation

• Allows one-trip installation

• With sliding sleeve, allows packer fluid change-out after wellhead is flanged (sliding sleeve not recommended in every case).

• Requires tubing plugging device to set packer

–Wireline plug - preferred

–Drop Ball Seat – debris problem?

Flow Coupling Sliding Sleeve Flow Coupling

Hydrostatic Retrievable Packer

Flow Coupling Seating Nipple Spacer Tube

Ball Activated Pressure Sub Perforated Spacer Tube No-Go Seating Nipple

Wireline Re-Entry Guide

(72)

Single Zone Completion

(

Seal Bore Packers)

• Dependable

• Low failure frequency

• Generally permit larger flow ID’s

• Available as Permanent or Retrievable

• Production string may be anchored or floating, depending on tubing movement requirements (anchored or shouldered is highly recommended) • Packer may be plugged, can be used as temporary

or permanent bridge plug

• Permanent packers removed by milling operations • Retrievable Seal Bore Packers are removed in

separate trip with retrieval tool – provided seals will release.

Annulus Activated, Block and Kill Valve

Sliding Sleeve Seal Bore Packer Mill-Out Extension Crossover Sub Flow Coupling Seating Nipple Spacer Tube Flow Coupling No-Go Seating Nipple Perforated Spacer Tube Crossover Sub Seating Nipple Wireline Re-Entry Guide

(73)

Single Zone Completion

(Seal Bore Packers w/Locator Seal Assy.)

• Locator unit atop Seal Bore Extension allows tubing movement from press and temp changes:

– Frac or Acid Stimulation

– Production extremes and shut-in

• Seals available to match environment:

– Temperature Range – Pressure Conditions – Fluid Environment

• Works well with tubing conveyed perforating (TCP)

Sliding Sleeve Flow Coupling Locator Seal Assembly Seal Bore Packer Seal Spacer Tube Seal Bore Extension Tubing Seal Nipples Production Tube

Spacer Tube Flow Coupling Seating Nipple Perforated Spacer Tube No-Go Seating Nipple

(74)

Single Zone Completion

(Polished Bore Receptacle (PBR))

• Seal Bore Packer with large upper

bore permits maximum flow area.

• PBR above packer accommodates

tubing trip/movement

– Shear release locator allows one-trip installation with Hydraulic set packer – Large ID suitable for Thru-Tubing

perforating

Locator Seal Assembly

Retrievable Packer Bore Receptacle Anchor Tubing Seal Nipple Hydraulic Set Seal Bore Packer Mill-Out Extension

Crossover Sub

Shear-Out Ball Seat Sub

(75)

Single Zone Completion

(Stacked Selective Completion)

• Permanent packers are stacked for

multiple zone completion

– Zones are selective flowed or shut-in by sliding sleeves or ported profiles and plugs – Tubing may be anchored or floating

– Blast joints are placed across production interval to reduce flow-cutting of

production lines

• This type of completion design often has

severe problems with leaking sleeves

and corroded/eroded tubing in the

straddled zone.

Flow Coupling Sliding Sleeve Seal Bore Packer Seal Bore Extension Tubing Seal Nipples

Flow Coupling Seating Nipple Blast Joint Polished Nipple Flow Coupling Sliding Sleeve Seal Bore Packer Seal Bore Extension Seal Spacer Tube Tubing Seal Nipples Spacer Tube No-Go Seating Nipple Production Tube

(76)

Single Zone Completion

(

Standard Dual Completion)

• Permits independent production of

each zone

• Flanged-up completion for safety

• Fully retrievable completion (both

packers) for remedial access

• Or, the bottom packer may be a

permanent packer which serves as

a locator for spacing out the

completion

Flow Couplings Seating Nipples Flow Couplings Flow Coupling Flow Coupling Sliding Sleeve

Short String Seal Nipple

Dual Hydraulic Retrievable Packer Seating Nipple

Flow Coupling

Ball Activated Pressure Sub

Ball Activated Pressure Sub Perforated Spacer Tube

Perforated Spacer Tube No-Go Seating Nipple

No-Go Seating Nipple Pinned Collar Seating Nipple Blast Joint Polished Nipple Sliding Sleeve

Hydraulic Retrievable Packer Seating Nipple

Wireline Re-Entry Guide

Figure

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References

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