Packers and Liner Hangers • Basic Overview • Applications and Selections of Packers • Setting Criteria and procedures
Packers and Liner Hangers
• Basic Overview
• Applications and Selections of Packers
• Setting Criteria and procedures
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.
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
• Isolate between zones
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
compressed & extruded to the casing wall.
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.
Packer Considerations
• Force on an area
Remember, it’s a
force balance. Area down =
casing ID - tube OD
Area up =
tube x-section +
casing ID - tube OD
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
Specific Packer Examples
• Packer Examples
– Retrievables
– Seal bores
– Inflatables
– Wash Tools
Retrievable Packers
• Expected to be retrieved
• More prone to leaks
• Need an equalizing port
• Release mechanism must be possible with
well design
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
Weatherford
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
Weatherford
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
Weatherford
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
Weatherford
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
– Debris on top of packer can stick assembly
Unprotected seals below the packer may
allow seal swelling by gas and fluids,
causing seals to roll off if the stinger is
pulled out.
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.
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.
Weatherford
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
Weatherford
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
Weatherford
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
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.
Weatherford
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
Weatherford
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.
– Large diameter applications.
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
retrieval.
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.
• 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
Weatherford
Packer Seals Packer Slips
Lawrence Ramnath - Trinidad
A hydraulic set packer.
Note the lower slips set by
movement of the mandrel
and upper slips set by
piston action.
Slips – Liner hanger
J-Slot on a liner hanger.
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
Packer Comparisons - from Weatherford
Packer specifics from Baker
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
packers.
Production Packers
• Purposes
– Casing protection from fluids or pressures
– Separation of zones
– Subsurface pressure and fluid control
– Artificial lift support equipment
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
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.
Seal Bore Packer to Tubing Connections
Seal Bore
Extensions
(SBE)
Polished
Bore
Receptacle
(PBR)
Tubing
Sealbore
Receptacle
(TSR)
Seal Assembly Locator Types
Locator Anchor
Latch
Snap Latch
A “stinger” or seal
assembly that is run on the
end of tubing and “stings”
into the polished bore
receptacle (PBR) of the
packer.
Stinger Seal Materials
• Single or mixture of elastomers
• seal design variance
• seals usually protect the slips from
corrosive fluids.
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.
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)
Halliburton Energy Services General Guidelines For V-Packing
(1)
Halliburton Energy Services General Guidelines For V-Packing
(1)
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.
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.
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
Temperature, length change
DL = CLDT
Where:
DL = length change
C = expansion coeff. for steel = 6.9x10-6/oF
L = length of tubing
DT = average temp change, oF
Temperature, Force change
• F = 207 DTa As
• Where:
F = temperature induced force
DTa = change in average temp of tubing, oF
As = cross sectional area of tubing
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 separate calculation. Bottom string first.
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
BHTT= 86*F
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 210oF to
100oF during a Frac job? L = 8000 ft.
– Assume locator is shouldered but no downward
force is applied.
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?
How much temperature increase
is spent lifting the 15,000 lb?
• F = 207 x DT2 x 2.59 in2
DT2 = 15000 / (207 x 2.59) = 28oF
Then: 110 - 28 = 82oF
DL = 6.9 x 10-6 x 8000 x 82 = 4.52 ft
What about those other factors?
• Buckling, Piston, Ballooning - Use a
computer program - better yet, use a couple
of them (different assumptions).
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
CO2 operations.
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.
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
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
• How can it be equalized if it has to be pulled?
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 be slightly off depth after disconnecting).
Job Checks
• Drop back and gently tag packer with
setting tool to confirm depth.
• Log back up a few collars.
Packer Setting Guidelines
• Drift
• Scraping
• Casing Support
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
diameter and length of packer.
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 protected.
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.
Effect of Scraping or Milling Adjacent to Open
Perforations
-60
-50
-40
-30
-20
-10
0
10
20
1 2
% C
ha
ng
e in
PI
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.
Typical Completions
• Single and Dual Zone Completion Types
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
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
Weatherford
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 NipplePerforated Spacer Tube
Crossover Sub
Seating Nipple
Wireline Re-Entry Guide
Weatherford
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
Weatherford
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
Weatherford
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
Weatherford
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 CouplingBall 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
Weatherford