Packers and Liner Hangers - George E King Petroleum Engineering

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
Packer Cutaway Drawing
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.
Lock Ring and Mandrel
Slips
Cone
Seal
Inner Mandrel
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.
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
Production Packers
Retrievable
Permanent
Wireline Set
Sealbore
Hydraulic Set
Hydraulic Set
Hydrostatic Set
Single
Differential Set
Dual
Wireline Set
Hydraulic
Mechanical
Single Grip
Double Grip
Multiport
RMC
Mech. Slips
Hyd. Slips
ESP
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
Tension Set - Economical packer used in
production, injection, zone isolation applications
• 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
Weatherford
Retrievable Production Packers
Mechanical - Used in production, injection,
fracturing, zone isolation and remedial applicatuions
• 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
Weatherford
Retrievable Production Packers
Mechanical Used in production, stimulation and
testing
• 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.
Weatherford
Retrievable Packers
Wireline set - Used in production, injection,
fracturing, zone isolation and remedial applications
where wireline setting is preferred
•
•
•
•
•
•
•
•
•
Weatherford
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
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
One-trip applications
• 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
Weatherford
Permanent Seal Bore Packers
Used in one trip production applications
• 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
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
Nitrile Seal or
Viton Seal
Steel spacer
MOLDED SEAL
SINGLE UNIT
Molded Seals:
• Recommended in medium pressure
applications where seal movement out
of the seal bore is anticipated.
Chevron Seals:
Used for higher pressure and
temperature applications.
CHEVRON SEAL
SINGLE UNIT
Weatherford
End spacer
Seal spacer
Middle spacer
Nitrile Seal or
Viton Seal
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.
Holding ability of the inflatable
is always suspect since it does
not have conventional slips.
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.
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.
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.
Baker
Perforation Wash Tool
Used for selective acidizing of perforated
intervals
• 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.
Weatherford
• 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.
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.
Packer Comparisons - from Weatherford
Packer Type
Weatherford Completion Systems
(Bold Items are Preferred Products)
HES
Halliburton
Solid head, Tension Set,
Mechanical, Single Grip
Compression Set, Mechanical,
Single Grip
PAD-1, PADL-1
Compression Set, Double Grip
Packer
Neutral Set, Double Grip Packer
Schlumberger
(Camco)
Baker
Guiberson
AD-1
AL
R-3 Single Grip
Model G
RB
R-4
PR-3
R-3 Double Grip
Hydraulic Set Retrievable
QDG, QDH, Arrowset I-X (&10K), UltraLok, Double Grip
HRP, Hydrow-I, PFH
Dual Hydraulic Set Retrievable
Hydrow IIA
Wireline Set Permanent
Arrowdrill B
Lockset, Max
J-Lok, MS
FH, FHL, FHS
Hydra-Pak
HS, HS-S
A-5
T-2
GT
Model D
F-1
MHS
MH-2
WPL
Perma-Lach
RH
PHL
AHR
RDH
BHD
Wireline Set Permanent Double
Bore
Hydraulic Set Permanent
Arrowdrill DB
Arrowdrill BH
DA, DAB
FA, FAB
SB-3
Hydraulic Set Permanent Double
Bore
Retrievable Seal Bore
Arrowdrill DBH
SAB-3
MHR
Arrow-Pak
VTL (Versa-Trieve)
Hydraulic Set Retrievable Seal
Bore
HPHT Hydraulic Set Retrievable
Hydrow-Pak
Retrieva-D, DB
WS, WSB
SC-1, SC-2
SC-2PAH
G-1, GT-1
H-1, HT-1
PG
PH
PG-1
PH-1
G-10
VHR (Versa-Trieve)
RSB
Compression Set Service Packer
CST, C5, H/D, MSG
HP-1AH, SC-2PAH
HP/HT
EA Retrievamatic
HPHT (Versa-Trieve
Retrievable)
RTTS
Champ III, IV
Compression Set Storm Packer
Tension Set Service Packer
CSTH, DLT
32A, Fullbore Tension
C Fullbore
BV Tension Packer
Tubing Set Retrievable Bridge
Plug
Wireline Set Retrievable Bridge
Plugs
Permanent Bridge Plugs/Cement
Retainer
QDH w/ EQV, TSU
G Lock-Set
3L
RBP-VI
P-1
Mercury N, K-1
EZSV, EZ Drill
EZ Drill SVB
Fas-Drill, HCS
Type A
Quik-Drill
PR-3 Single Grip
Hydrow-Pak
R-4
AWB
BWB
AWS
AWR
MHR
Uni-Packer I
Uni-Packer IV
Uni-Packer II
G-4
Uni-Packer V
SA-3
T Series
SR-2
U-3
CA-3, C Series
SR-1
Uni-Packer VI
G-6, G-16
Uni-Packer VII
G-77
RHS
Uni-XXVII
RHD
SOT-1
KH
Hydro-5
HRP
G, GT
H, HT
Model S
HDCH-V
Hydro-10
HSD
Model HS
Model HSB
M Omegatrieve
Quantum
Omegamatic
R-104
WRP, CE, CE2
PCR, Plugwell, PBP
Packer specifics from Baker
Casing Design Options – think about running and setting packers.
Mixed
weights,
same
grade
Small
diameters at
the top of the
well may
prevent entry
by some
packers.
Mixed
grades
and
weights
Monobore:
mixed
grades,
same
weight
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
Butyl Rubber
Flurocarbon
Nitrile
Fluro-silicone
oil
4
1
1
2
brine
1
1
1
1
H2S
1
4
4
3
CO2
2
2
1
2
1=good, 2=fair, 3=doubtful, 4= unsatisfactory
Much larger data base available online.
Halliburton Energy Services
General Guidelines For Seals
PEEK(2), (4)
Compound
Ryton(2), (4)
Fluorel(3)
Filled
Aflas(3)
Unfilled
Chemraz(3)
Unfilled
350
(177)
350
(177)
450
(232)
350
(177)
15,000
(103)
10,000
(68.9)
15,000
(103)
Service °F
(°C)
(2), (4)
Pressure
psi
(MPa)
Viton(3)
Filled Unfilled
(1)
Neoprene(3)
Filled
Nitrile(3)
Filled
Kalrez(3)
Filled
Teflon(3)
Filled Unfilled
325
(163)
300
(149)
275
(135)
450
(232)
400
(204)
325
(163)
Above
5000
(34.4)
Below
5000
(34.4)
5000
(34.4)
3000
(20.7)
15,000
(103)
15,000
(103)
5000
(34.4)
Environments
H2S
A
A
A
A
A
B
B
NR
NR
A
A
A
CO2
A
A
B
B
A
B
B
C
A
A
A
A
CH4 (Methane)
A
A
A
A
A
A
A
B
B
A
A
A
(Sweet Crude)
A
A
A
A
A
A
A
A
A
A
A
Xylene
A
A
A
C
A
A
A
NR
NR
A
A
A
Alcohols
A
A
C
B
A
C
C
B
A
A
A
A
Zinc Bromide
A
A
A
A
A
A
A
NR
NR
A
A
A
Inhibitors
A
A
NR
A
A
NR
NR
NR
B
A
A
A
Salt Water
A
A
A
A
A
A
A
C
A
B
A
A
Steam
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
Hydrocarbons
A-Satisfactory
NOTE: (1)
B - Little or no effect
C - Swells
D - Attacks
B
C
NR - Not recommended
NT - Not tested
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 V-Packing
(1)
Halliburton Energy Services
General Guidelines For V-Packing
(1)
(1)
Packer Element Selection
Chart
N
START
STEAM/THERMAL
APPLICATION W/NO
HYDROCARBON FLUIDS
Y
N Y
PERMANENT
PACKER DESIGN
N
N
PACKER IN OIL BASE MUD
OVER 24 HOURS BEFORE
SET?
Y
PACKER
IN BROMIDE
N
Y
TEMP
40°F TO
325°F
COMPLETION FLUIDS MORE THAN 36
HOURS BEFORE
SET?
Y
NITRILE ELEMENTS
W/STANDARD METAL BACKUPS
N
Y
TEMP
40°F TO
400°F
NITRILE ELEMENTS W/TEFLON
AND METAL BACKUPS
N
Y
TEMP
100°F TO
400°F
AFLAS ELEMENTS
W/STANDARD METAL BACKUPS
N
Y
TEMP
100°F TO
450°F
AFLAS ELEMENTS W/TEFLON AND
GRAFOIL WIREMESH AND METAL BACKUPS
N
TEMP
GREATER THAN 450°F
Y
N
TEMP
40°F TO
275°F
PACKER
EXPOSED TO
BROMIDES?
RETRIEVABLE
PACKER
DESIGN
CHECK WITH YOUR HALLIBURTON
REPRESENTIVE FOR SPECIAL APPLICATIONS
NITRILE ELEMENTS
W/BONDED GARTER SPRINGS
N
Y
Y
PACKER
ELEMENTS
EXPOSED TO AMINE
CORROSION
INHIBITORS?
N
Y
TEMP
40°F TO
400°F
FLUOREL ELEMENTS
W/BONDED GARTER SPRINGS
N
Y
N
TEMP
100°F TO
400°F
AFLAS ELEMENTS
W/BONDED GARTER SPRINGS
TEMP
GREATER THAN 400°F
CHECK WITH YOUR HALLIBURTON
REPRESENTIVE FOR SPECIAL
APPLICATIONS
Y
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.
TEMP
LESS THAN 550°F
EPDM ELEMENTS WITH BACKUPS
TEMP
GREATER THAN 550°F
CHECK WITH YOUR HALLIBURTON
REPRESENTIVE FOR SPECIAL
APPLICATIONS
N
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?
30
40
50
60
70
80
90
100 110 120 130
0
30
40
50
60
70
80
90
100
110
Tubing
130
Undisturbed
Tbg Fluid
2000
Tbg Fluid
2000
Casing 1
Tubing
Undisturbed
Casing 1
4000
4000
6000
6000
8000
8000
10000
10000
BHST= 122*F
12000
BHST= 125*F
12000
14000
14000
BHTT= 86*F
BHCT= 98*F
16000
16000
Frac job pump rate = 35-BPM
Circulation pump rate = 8-BPM
18000
120
0
18000
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.
One very detrimental action was running a scraper prior to packer
setting. The scraping and surging drives debris into unprotected
perfs.
Effect of Scraping or Milling Adjacent to Open
Perforations
20
% Change in PI
10
Perfs not protected by
LCM prior to scraping
0
-10
1
Perfs protected
by
2
LCM
-20
-30
-40
Short Term PI Change
Long Term PI Change
-50
-60
SPE 26042
Typical Completions
• Single and Dual Zone Completion Types
Single Zone Completion
(Mechanical Packer)
Packer isolates casing from production
• Provides means of well control
• Protects casing above packer from corrosion
• Anchors tubing string
On-Off Sealing Connector
Retrievable Packer
Weatherford
•
•
•
•
Tension Set
Compression set
Wireline Set
Large Variety of
accessories available
Single Zone Completion
(Hydraulic Set Packer)
• Permits Packer setting without tubing
manipulation
–Common in offshore applications where SCSSV
control lines prevent tubing rotation
Flow Coupling
• Allows one-trip installation
Flow Coupling
• With sliding sleeve, allows packer fluid changeHydrostatic Retrievable Packer
out after wellhead is flanged (sliding sleeve not
recommended in every case).
Flow Coupling
Seating Nipple
• Requires tubing plugging device to set packer
Spacer Tube
Sliding Sleeve
Ball Activated Pressure Sub
Perforated Spacer Tube
No-Go Seating Nipple
Wireline Re-Entry Guide
Weatherford
–Wireline plug - preferred
–Drop Ball Seat – debris problem?
Single Zone Completion
(Seal Bore Packers)
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
Weatherford
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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.
Single Zone Completion
(Seal Bore Packers w/Locator Seal Assy.)
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
• 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)
Single Zone Completion
(Polished Bore Receptacle (PBR))
Locator Seal Assembly
• Seal Bore Packer with large upper
bore permits maximum flow area.
• PBR above packer accommodates
tubing trip/movement
Retrievable Packer Bore Receptacle
Anchor Tubing Seal Nipple
Hydraulic Set Seal Bore Packer
Mill-Out Extension
Crossover Sub
Shear-Out Ball Seat Sub
Weatherford
– Shear release locator allows one-trip
installation with Hydraulic set packer
– Large ID suitable for Thru-Tubing
perforating
Single Zone Completion
(Stacked Selective Completion)
Flow Coupling
Sliding Sleeve
Seal Bore Packer
Seal Bore Extension
• Permanent packers are stacked for
multiple zone completion
Tubing Seal Nipples
– Zones are selective flowed or shut-in by
sliding sleeves or ported profiles and plugs
Flow Coupling
Seating Nipple
– Tubing may be anchored or floating
Blast Joint
Polished Nipple
– Blast joints are placed across production
interval to reduce flow-cutting of
production lines
Flow Coupling
Sliding Sleeve
Seal Bore Packer
Seal Bore Extension
Seal Spacer Tube
Tubing Seal Nipples
Spacer Tube
• This type of completion design often has
severe problems with leaking sleeves
and corroded/eroded tubing in the
straddled zone.
No-Go Seating Nipple
Production Tube
Weatherford
Single Zone Completion
(Standard Dual Completion)
Flow Couplings
Seating Nipples
Flow Couplings
Flow Coupling
Sliding Sleeve
Short String Seal Nipple
Dual Hydraulic Retrievable Packer
Flow Coupling
Seating Nipple
Flow Coupling
Ball Activated Pressure Sub
Perforated Spacer Tube
No-Go Seating Nipple
Pinned Collar
Seating Nipple
Blast Joint
Polished Nipple
Sliding Sleeve
Hydraulic Retrievable Packer
Seating Nipple
Ball Activated Pressure Sub
Perforated Spacer Tube
No-Go Seating Nipple
Wireline Re-Entry Guide
Weatherford
• 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