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Retrievable
ServiceT
ools
Retrievable Service ToolsThis section contains information about running, setting, and
operating Retrievable Service Tools and related accessories.
Halliburton is dedicated to providing top-quality equipment
and service. Halliburton maintains strict standards and well
documented processes and procedures to help ensure
excellence and dependability in our Retrievable Service Tools
equipment. No matter what your downhole situation, you can
count on your Halliburton representative to look beyond the
tool and develop a low-cost solution that can produce savings
far greater than any difference in tool cost.
Retrievable Service Tools 2-1
Retrievable
ServiceT
ools
CHAMP® IV Packer
The CHAMP® IV packer is a hookwall-
retrievable packer with a concentric
bypass. As the tool is lowered into the
hole, a J-slot holds the bypass open and
controls the setting of the packer. When
the packer is set, a balancing piston
activated by tubing pressure holds the
bypass closed.
Each tool assembly includes a J-slot
mechanism, mechanical slips, packer
elements, hydraulic slips, and a bypass.
Round, piston-like slips used in the
hydraulic holddown mechanism
prevent the tool from being pumped up
the hole. The bypass allows fluids to
pass around the bottom of the tool
when it is removed from the hole. This
design eliminates accidentally opening
a conventional bypass during
circulation around the bottom of
the packer.
Circulation around the CHAMP IV
packer is not interrupted if the packer
element temporarily seals
unintentionally as when it passes
through points of interference in
the casing.
The CHAMP IV packer is well suited to
tubing conveyed perforating
applications where the firing head
assembly is easily incorporated into the
CHAMP IV packer. The CHAMP IV
packer is ideally suited for horizontal
applications due to its limited rotational
requirements and integrated circulating
valve. Just a quarter-turn is required at
the tool to set the packer and close the
circulating valve. A straight upward pull
opens the circulating valve and unseats
the packer.
Features and Benefits
• Used in highly deviated wells or
where pipe manipulation is difficult
• Picking the packer straight up (no
torque required) opens the bypass
• Can be easily relocated in multiple
zones during a single trip for treating,
testing, or squeezing
• Concentric bypass valve allows a
larger bypass flow area
• Can be used with a retrievable bridge
plug for straddling zones during
various operations
• Ideal for applications where positive
circulation below the packer is
required such as in drillstem testing,
TCP applications using tailpipe for
shallow service, and as liner tools
Operation
The tool is run slightly below the
necessary setting position. If the packer
is to be set, it must be picked up, and
right-hand rotation must be applied so a
quarter-turn can be obtained at the tool.
In deep or deviated holes, several turns
with the rotary may be necessary. For
the position to be maintained, the right-
hand torque must be held until the
mechanical slips on the tool are set and
can begin taking weight.
Pressure applied below the packer forces
the hydraulic holddown slips against the
casing to prevent the packer from being
pumped up the hole.
The concentric bypass valve is balanced
to the tubing surface pressure, which
prevents the bypass from being pumped
open with tubing pressure. Straight,
upward pull on the tubing string opens
the bypass and unsets the packer.
HA
L1
20
25
CHAMP® IV Packer
2-2 Retrievable Service Tools
Retrievable
ServiceT
ools
CS
4
5
6
7
7
8
9
1
1
1
No*T st
CHAMP® IV Retrievable Packer
asingizein.
Packer OD
in. (cm)
Packer ID
in. (cm)
End Connections
Nominal Casing Weight
lb/ft
MinimumCasing IDin. (cm)
Maximum Casing IDin. (cm)
Lengthin. (cm)
Tensile Rating*lb (kg)
Working Pressurepsi (MPa)
Burst Pressure*psi (MPa)
Collapse Rating*psi (MPa)
Open Ended
Bull Plugged
Open Ended
Bull Plugged
1/2
3.87(9.83)
1.80(4.57) 2 3/8 EU 9.5 - 10.5 4.052
(10.29)4.090
(10.39)100.10
(254.25)71,200
(32 300)8,400
(57.92)10,000(68.95)
10,000(68.95)
8,500(58.61)
8,500(58.61)
3.75(9.52)
1.80(4.57) 2 3/8 EU 11.6 - 13.5 3.920
(9.95)4.000
(10.16)100.10
(254.25)71,200
(32 300)8,400
(57.92)10,000(68.95)
10,000(68.95)
8,500(58.61)
8,500(58.61)
5
3.98(10.11)
1.80(4.57) 2 3/8 8 Rd EU 18 - 20.8 4.156
(10.56)4.276
(10.86)100.10
(254.25)71,200
(32 300)8,400
(57.92)10,000(68.95)
10,000(68.95)
8,500(58.61)
8,500(58.61)
4.18(10.61)
1.80(4.57) 2 3/8 8 Rd EU 11.5 - 15 4.408
(11.20)4.560
(11.58)100.80
(256.03)71,200
(32 300)8,400
(57.92)10,000(68.95)
10,000(68.95)
8,500(58.61)
8,500(58.61)
1/2
4.55(11.56)
2.00(5.08) 2 3/8 EU 13 - 20 4.778
(12.14)5.044
(12.81)99.04
(251.56)88,900
(40 324)7,000
(48.26)7,000
(48.26)7,000
(48.26)11,400(78.60)
9,300(64.12)
4.40(11.18)
1.80(4.57) 2 3/8 EU 20 - 23 4.670
(11.86)4.778
(12.14)100.10
(254.25)71,200
(32 300)8,400
(57.92)10,000(68.95)
10,000(68.95)
8,500(58.61)
8,500(58.61)
5/8or 7
5.25(13.34)
2.00(5.08) 2 7/8 8 Rd EU
6 5/8: 23 - 32
7:41 - 49.5
5.540(14.07)
5.820(14.78)
91.42(232.21)
88,800 (40 300)
10,000 (68.95)
12,100 (83.43)
8,600(59.29)
11,500(79.29)
9,300(64.12)
7 5.65(14.35)
2.37(6.02)
2 7/8 EU (Optional adapters:3 1/2 IF
3 7/8 CAS)
17 - 38 5.920(15.04)
6.538(16.61)
98.85(251.08)
148,600 (67 404)
10,000 (68.95)
12,400 (85.50)
9,200(63.43)
10,600(73.08)
10,600(73.08)
5/8 6.35(16.13)
2.37(6.02)
2 7/8 8 Rd EU (Optional adapters:
3 7/8 CAS,2 7/8 PH6,3 1/2 IF)
20 - 39 6.625(16.83)
7.125(18.10)
98.88(251.16)
148,500(67 358)
10,000 (68.95)
12,400(85.50)
9,200(63.43)
10,600(73.08)
10,600(73.08)
3/4 6.16(15.65)
2.37(6.02)
2 7/8 EU (Optional adapters: 3 1/2 IF
3 7/8 CAS)
46.1 6.560(16.66)
6.560(16.66)
98.85(251.08)
148,500(67 358)
10,000 (68.95)
12,400(85.50)
9,200(63.43)
10,600 (73.08)
8,700(59.98)
5/8
7.04(17.88)
2.62(6.65) 3 7/8 CAS 44 - 56 7.313
(18.58)7.625
(19.37)123.80
(314.45)215,640(97 813)
7,000 (48.26)
13,700(94.46)
13,700(94.46)
12,900(88.94)
12,970(89.43)
6.75(17.14)
2.37(6.02) 3 7/8 CAS 58.7 - 68.1 7.001
(17.78)7.251
(18.42)123.80
(314.45)313,600
(142 247)7,000
(48.26)13,700(94.46)
13,700(94.46)
12,900(88.94)
12,970(89.43)
5/8
8.15(20.70)
2.87(7.29) 4 1/2 IF 36 - 53.5 8.535
(21.68)8.921
(22.66)129.59
(329.16)341,900
(155 083)7,000
(48.26)8,700
(59.98)8,700
(59.98)10,100(69.64)
10,100(69.64)
7.80(19.81)
2.87(7.29) 4 1/2 IF 58.4 - 71.8 8.125
(20.64)8.435
(21.42)121.60
(308.86)341,900
(155 083)7,000
(48.26)8,700
(59.98)8,700
(59.98)10,100(69.64)
10,100(69.64)
0 3/4
9.07(23.04)
3.00(7.62) 4 1/2 IF 55.5 - 80.8 9.250
(23.50)9.760
(24.79)125.87
(319.71)524,600
(237 955)5,000
(34.47)8,300
(57.22)8,300
(57.22)8,100
(55.84)8,100
(55.84)
8.85 (22.48)
3.00 (7.62) 4 1/2 IF 85.3 9.156
(23.26)9.156
(23.26)128.87
(327.33)506,200
(229 608)8,000
(55.16)8,270
(57.02)9,100
(62.74)8,100
(55.84)9,100
(62.74)
1 3/4 10.40(26.42)
3.00(7.62) 4 1/2 IF 38 - 71 10.586
(26.89)11.150(28.32)
125.80(319.53)
524,600(237 955)
5,000 (34.47)
8,300(57.22)
8,300(57.22)
8,100(55.84)
8,100(55.84)
3 3/8
11.94(30.33)
3.75(9.52) 4 1/2 IF 54.5 - 72 12.347
(31.36)12.615(32.04)
146.21(371.37)
651,300(295 424)
3,000 (20.68)
12,300(84.81)
12,300(84.81)
9,300(64.12)
8,900(61.36)
11.50(29.21)
3.75(9.52) 4 1/2 IF 72 - 98 11.937
(30.32)12.347(31.36)
146.21(371.37)
651,300(295 424)
3,000 (20.68)
12,300(84.81)
12,300(84.81)
9,300(64.12)
8,900(61.36)
te: Although other sizes may be available, these sizes are the most common.he values of tensile, burst, and collapse strength are calculated with new tool conditions, Lame's formulas with Von-Mise's Distortion Energy Theory for burst and collapserength, and stress area calculations for tensile strength. These ratings are guidelines only. For more information, consult your local Halliburton representative.
Retrievable Service Tools 2-3
Retrievable
ServiceT
ools
CHAMP® IV Non-Rotational Retrievable Packer
The CHAMP® IV non-rotational packer
is ideal for deepwater extended reach
situations where getting enough torque
down hole to manipulate the toolstring
can be a major challenge. This tool has
the same basic features as the standard
CHAMP IV packer with the added
feature that it does not require rotation
to set. The CHAMP IV non-rotational
packer consists of a hookwall
retrievable packer with a concentric
bypass and a continuous indexing J-
slot. This J-slot allows the packer to be
run in the casing, set, and unset without
applying any rotation to the workstring.
The packer can cycle from the run-in-
hole (RIH) position to the set and pull-
out-of-hole (POOH) positions simply
by lifting or lowering the drillpipe or
tubing in the wellbore.
Each assembly includes an indexing
J-slot mechanism, mechanical slips,
packer elements, hydraulic slips, and a
concentric bypass. Round, piston-type
slips are used in the hydraulic
holddown mechanism to help prevent
tool from being pumped up the hole.
A J-slot position locking mechanism
keeps the packer in the RIH
configuration until the desired depth is
reached and the locking mechanism is
deactivated. The position locking
mechanism is deactivated by the use of
a rupture disk which is set to rupture at
a predetermined pressure. The
deactivation pressure can be either
wellbore hydrostatic at a certain depth
or pump pressure applied to the
annulus at surface. The locking
mechanism allows the packer to be run
on jointed pipe without cycling through
the positions in the J-slot as each joint
of pipe is being made up at the surface.
The concentric bypass allows fluids to
circulate around the bottom of the tool
when it is removed from or moved up
hole in the wellbore. Therefore,
circulation as the packer assembly is
passed through tight spots where
packer elements may unintentionally
achieve a temporary seal remains
interrupted. The bypass valve is also
designed to be pressure balanced with
applied pressure. This prevents the
unintentional opening of the bypass
during treatment applications.
Features and Benefits
• Easily operated in extended reach or
highly deviated wellbores
• Requires no rotation to set packer—
picking the packer straight up (no
torque required) opens the bypass
• Assembly will not set until the
hydrostatic at a pre-determined
depth is reached or annulus pressure
is applied
• Can be easily relocated to multiple
zones during a single trip for treating,
testing, or squeezing
• Concentric bypass allows a larger
bypass flow area with positive
circulation below packer and tailpipe
• 400°F (204.4°C) temperature rating
• Service environment—immersion in
various well fluids including
hydrocarbons dilute HCL, sour gas,
salt water, and CO2
CHAMP® IVNon-Rotational
Retrievable Packer
HA
L3
18
38
2-4 Retrievable Service Tools
Retrievable
ServiceT
ools
Operation
Run the packer to the desired setting depth. Burst the rupture
disk with wellbore hydrostatic pressure or applied annulus
pressure. This disengages the locking mechanism and allows
the packer assembly to cycle through the different positions
in the J-slot.
Pick up 1 to 2 ft at the tool to cycle the lugs through the
continuous J-slot from the RIH position to the
POOH position.
Lower the workstring back down to set the packer. The
downward movement cycles the lugs from the POOH
position to the set position in the continuous J-slot. Continue
to travel downward to set weight as needed to seal the
elements, permitting a minimum of 2 minutes before
applying pressure differential across the elements.
If the packer does not take weight, the locking mechanism
may not have been disengaged. Apply a safe amount of
pressure to the annulus to assist in disengagement of
the lock.
To unset the packer, relieve any surface pressure and simply
pick up the workstring to open the bypass valve. This
equalizes pressure around the packer elements and allows
them to relax. Once pressure is equalized, continue to lift the
workstring to completely unset the packer assembly. The
packer assembly can then be repositioned in the wellbore or
pulled out of the hole.
CHAMP® IV Non-Rotational Retrievable Packer
CasingSize in.
Packer OD
in. (cm)
Packer IDin. (cm)
End Connections
Nominal Casing Weight
lb/ft
MinimumCasing IDin. (cm)
Maximum Casing IDin. (cm)
Lengthin. (cm)
Tensile Rating*lb (kg)
Working Pressure*psi (MPa)
Burst Pressure*psi (MPa)
Collapse Rating*
psi (MPa)
7
5.65(14.35)
2.37(6.02)
2 7/8 EUE3 7/8 CAS 26 - 35 6.004
(15.25)6.538
(16.61)96.73
(245.6)148,600(67 403)
10,600(73.08)
12,400(85.50)
10,600(73.08)
6.00(15.24)
2.30(5.84)
3 7/8 CASBox × Pin 26 6.276
(15.94)6.276
(15.94)148.96(366.9)
131,900(59 829)
10,000(68.95)
10,800(74.45)
10,300(71.02)
9 5/8
8.25(20.96)
2.87(7.28)
4 1/2 IFBox × Pin
29.3 - 53.5
8.535(21.68)
8.921 (22.66)
169.52(430.6)
345,000(156 489)
8,700(59.98)
8,700(59.98)
10,000(68.95)
7.80 (198.1)
2.87(7.28)
4 1/2 IF Box × Pin
58.4 - 71.8
8.125 (20.64)
8.435 (21.42)
169.52 (430.6)
345,000 (156 489)
7,500 (51.71)
10.771 (74.26)
10.181 (70.19)
*The values of tensile, burst, and collapse strength are calculated with new tool conditions, Lame's formulas with Von-Mise's Distortion Energy Theory for burst and collapse strength, and stress area calculations for tensile strength. These ratings are guidelines only. For more information, consult your local Halliburton representative.
Retrievable Service Tools 2-5
Retrievable
ServiceT
ools
CHAMP® V 15K Packer
The CHAMP® V 15K packer is a 15K
HPHT hookwall-retrievable packer
with a concentric bypass. The
CHAMP V 15K packer is constructed
with higher grade materials, and
elastomers are supported with backup
rings, including element package. As
the tool is lowered into the hole, a J-slot
holds the bypass open and controls
setting of the packer. When the packer
is set, a balancing piston activated by
tubing pressure holds the bypass closed.
Each tool assembly includes a J-slot
mechanism, mechanical slips, packer
elements, hydraulic slips, and a bypass.
Round, piston-type slips are used in the
hydraulic holddown mechanism to help
prevent the tool from being pumped up
the hole. The CHAMP V 15K packer
has additional holddown mechanisms
to help keep it in place because of the
higher loads. The bypass allows the
fluids to pass around the bottom of the
tool when it is removed from the hole.
This design helps eliminate accidental
opening of a conventional bypass
during circulation around the bottom of
the packer.
Circulation around the packer is not
interrupted if the packer element
temporarily seals unintentionally as
when it passes through points of
interference in the casing.
The CHAMP V 15K packer is ideally
suited for horizontal applications due to
its limited rotational requirements and
integrated bypass valve. Just a quarter-
turn is required at the tool to set the
packer and close the bypass valve. A
straight upward pull opens the bypass
and unseats the packer.
Features and Benefits
• Used in highly deviated wells or
where pipe manipulation is difficult
• Picking the packer straight up (no
torque required) opens the bypass
• Easily relocated in multiple zones
during a single trip for treating,
testing, or squeezing
• Concentric bypass valve allows a
larger bypass flow area
• Ideal for HPHT testing, tubing
conveyed perforating, or stimulation
applications
• High strength construction—
extremely durable and reliable
• Long drag blocks—will not function
casing attachments, i.e., mechanical
slips (MSC)
• Tungsten carbide slips allow multiple
sets in the hardest casings
• Ported mandrel circulating valve
for high volume, high velocity
circulation
• Compatible with other tools—
can be run with bridge plugs and
drillable tools
HA
L1
55
06
CHAMP® V15K Packer
2-6 Retrievable Service Tools
Retrievable
ServiceT
ools
CaSi
d
)
7 )
)
No*Thcol e.
Operation
The tool is run slightly below the necessary setting position.
If the packer is to be set, it must be picked up, and right-hand
rotation must be applied so a quarter-turn can be obtained at
the tool. In deep or deviated holes, several turns with the
rotary may be necessary. For the position to be maintained,
the right-hand torque must be held until the mechanical slips
on the tool are set and can begin taking weight.
Pressure applied below the packer forces the hydraulic
holddown slips against the casing to prevent the packer
from being pumped up the hole.
The concentric bypass valve is balanced to the tubing surface
pressure, which prevents the bypass from being pumped open
with tubing pressure. Straight, upward pull on the tubing
string opens the bypass and unsets the packer.
CHAMP® V 15K Retrievable Packer
singizen.
Packer OD
in. (cm)
Packer ID
in. (cm)
End Connections
Nominal Casing Weight
lb/ft
MinimumCasing IDin. (cm)
Maximum Casing IDin. (cm)
Lengthin. (cm)
Tensile Rating*lb (kg)
Working Pressure*psi (MPa)
Burst Pressure*psi (MPa)
Collapse Rating*psi (MPa)
Open Ended
Bull Plugged
Open Ended
Bull Plugge
7 5.75(14.61)
2.25(5.72) 3 7/8 CAS 29 - 35 6.004
(15.25)6.201
(15.75)126.94
(322.43)163,330(74 085)
15,000(103.42)
16,200(111.69)
16,200(111.69)
15,000(103.42)
15,000(103.42
5/8
6.00(15.24)
2.25(5.72) 3 7/8 CAS 47.1 - 51.2 6.251
(15.88)6.375
(16.19)126.94
(322.43)163,330(74 085)
15,000(103.42)
16,200(111.69)
16,200(111.69)
15,000(103.42)
15,000(103.42
6.25(15.88)
2.25(5.72) 3 7/8 CAS 39 - 42.8 6.501
(16.51)6.625
(16.83)126.94
(322.43)163,330(74 085)
15,000(103.42)
16,200(111.69)
16,200(111.69)
15,000(103.42)
15,000(103.42
te: Although other sizes may be available, these sizes are the most common.e values of tensile, burst, and collapse strength are calculated with new tool conditions, Lame's formulas with Von-Mise's Distortion Energy Theory for burst and lapse strength, and stress area calculations for tensile strength. These ratings are guidelines only. For more information, consult your local Halliburton representativ
Retrievable Service Tools 2-7
Retrievable
ServiceT
ools
CHAMP® V 15K Non-Rotational Retrievable Packer
The CHAMP® V 15K non-rotational
packer is ideal for deepwater extended
reach situations where getting enough
torque down hole to manipulate the
toolstring can be a major challenge. The
CHAMP V 15K non-rotational packer
consists of a hookwall retrievable packer
with a concentric bypass and a
continuous indexing J-slot.
This packer is constructed with higher
grade materials, and elastomers are
supported with backup rings, including
element package. The J-slot allows the
packer to be run in the casing, set, and
unset without applying any rotation to
the workstring. The packer can cycle
from the run-in-hole position to the set
and pull-out-of-hole positions simply
by lifting or lowering the drillpipe or
tubing in the wellbore.
Each assembly includes an indexing
J-slot mechanism, mechanical slips,
packer elements, hydraulic slips, and a
concentric bypass. Round, piston-type
slips are used in the hydraulic holddown
mechanism to help prevent the tool
from being pumped up the hole. The
CHAMP V 15K non-rotational packer
has additional holddown mechanisms
to help keep it in place because of the
higher loads.
A J-slot position locking mechanism
keeps the packer in the run-in-hole
configuration until the desired depth is
reached and the locking mechanism is
deactivated. The position locking
mechanism is deactivated by the use of a
rupture disk which is set to rupture at a
predetermined pressure. The
deactivation pressure can be either
wellbore hydrostatic at a certain depth
or pump pressure applied to the annulus
at surface.
The locking mechanism allows the
packer to be run on jointed pipe without
cycling through the positions in the
J-slot as each joint of pipe is being made
up at the surface.
The concentric bypass allows fluids to
circulate around the bottom of the tool
when it is removed from or moved up
hole in the wellbore. Therefore,
circulation as the packer assembly is
passed through tight spots where
packer elements may unintentionally
achieve a temporary seal remains
interrupted. The bypass valve is also
designed to be pressure balanced with
applied pressure. This prevents
unintentional opening of the bypass
during treatment applications.
Features and Benefits
• Easily operated in extended reach or
highly deviated wellbores
• Requires no rotation to set the packer
• Assembly will not set until the
hydrostatic at a pre-determined
depth is reached or annulus pressure
is applied
• Can be easily relocated to multiple
zones during a single trip for treating,
testing, or squeezing
• Concentric bypass allows a larger
bypass flow area with positive
circulation below packer and tailpipe
• Rated up to 15,000 psi (103.42 MPa)
working pressure with a temperature
rating of 400°F (204.4°C)
• Service environment—immersion in
various well fluids including
hydrocarbons dilute HCL, sour gas,
salt water, and CO2
CHAMP® V 15KNon-Rotational
Retrievable Packer
HA
L1
92
42
2-8 Retrievable Service Tools
Retrievable
ServiceT
ools
CaSi
d
)
7 )
No*Thcol e.
Operation
Run the packer to the desired setting depth. Burst the rupture
disk with wellbore hydrostatic pressure or applied annulus
pressure. This disengages the locking mechanism and allows
the packer assembly to cycle through the different positions in
the J-slot.
Pick up 1 to 2 ft at the tool to cycle the lugs through the
continuous J-slot from the RIH position to the
POOH position.
Lower the workstring back down to set the packer. The
downward movement cycles the lugs from the POOH
position to the set position in the continuous J-slot.
Set the desired amount of weight on the packer. If the packer
does not take weight, the locking mechanism may not have
been disengaged. Apply a safe amount of pressure to the
annulus to assist in disengagement of the lock.
To unset the packer, relieve any surface pressure and simply
pick up the workstring to open the bypass valve. This
equalizes pressure around the packer elements and allows
them to relax. Once pressure is equalized, continue to lift the
workstring to completely unset the packer assembly. The
packer assembly can then be repositioned in the wellbore or
pulled out of the hole.
CHAMP® V 15K Non-Rotational Retrievable Packer
singizen.
Packer OD
in. (cm)
Packer ID
in. (cm)
End Connections
Nominal Casing Weight
lb/ft
MinimumCasing IDin. (cm)
Maximum Casing IDin. (cm)
Lengthin. (cm)
Tensile Rating*lb (kg)
Working Pressure*psi (MPa)
Burst Pressure*psi (MPa)
Collapse Rating*psi (MPa)
Open Ended
Bull Plugged
Open Ended
Bull Plugge
7 5.75 (14.60)
2.00 (5.08)
3 7/8 CAS (Box)
2 7/8 EUE (Pin)
29 - 35 6.004 (15.25)
6.184 (15.71)
163.84 (416.15)
150,000 (68 038)
15,000 (103.42)
16,217 (111.81)
12,603 (86.89)
15,014 (103.51)
11,839(81.62
5/8 6.62 (16.18)
2.25 (5.72)
3 7/8 CAS (Box)
3 1/2 IF(Pin)
29.7 - 39 6.625 (16.83)
6.875 (17.46)
163.54 (415.39)
150,000 (68 038)
15,000 (103.42)
15,000 (103.42)
11,000 (75.84)
15,000 (103.42)
12,000(82.74
te: Although other sizes may be available, these sizes are the most common.e values of tensile, burst, and collapse strength are calculated with new tool conditions, Lame's formulas with Von-Mise's Distortion Energy Theory for burst and lapse strength, and stress area calculations for tensile strength. These ratings are guidelines only. For more information, consult your local Halliburton representativ
Retrievable Service Tools 2-9
Retrievable
ServiceT
ools
RTTS® Packer
The RTTS® packer is a full-opening,
hookwall packer used for testing,
treating, and squeeze cementing
operations. In most cases, the tool runs
with a circulating valve assembly.
The packer body includes a J-slot
mechanism, mechanical slips, packer
elements, and hydraulic slips. Large,
heavy-duty slips in the hydraulic
holddown mechanism help prevent the
tool from being pumped up the hole.
Drag springs operate the J-slot
mechanism on 3 1/2-in. (88.9-mm)
packer bodies, while larger packer sizes
4-in. (101.6 mm) use drag blocks.
Automatic J-slot sleeves are standard
equipment on all packer bodies.
The circulating valve, if used, is a
locked-open/locked-closed type that
serves as both a circulating valve and
bypass. The valve automatically locks in
the closed position when the packer
sets. During testing or squeezing
operations, the lock prevents the valve
from being pumped open. A straight
J-slot in the locked-open position
matches with a straight J-slot (optional)
in the packer body. This combination
eliminates the need to turn the tubing to
close the circulating valve or reset the
packer after the tubing has been
displaced with cement.
Features and Benefits
• The full-opening design of the
packer mandrel bore allows large
volumes of fluid to pump through
the tool. Tubing-type guns and
other wireline tools can be run
through the packer.
• The packer can be set and relocated
as many times as necessary with
simple tubing manipulation.
• Tungsten carbide slips provide
greater holding ability and improved
wear resistance in high-strength
casing. Pressure through the tubing
activates the slips in the hydraulic
holddown mechanism.
• An optional integral circulating valve
locks into open or closed position
during squeezing or treating
operations and opens easily to allow
circulation above the packer.
Operation
The tool is run slightly below the
desired setting position to set the packer
and is then picked up and rotated
several turns. If the tool is on the
bottom, only a quarter-turn is actually
required. However, in deep or deviated
holes, several turns with the rotary may
be necessary. To maintain position, the
right-hand torque must be held until the
mechanical slips on the tool are set and
can start taking weight.
The pressure must be equalized across
the packer to unset it. As the tubing is
picked up, the circulating valve remains
closed, establishing reverse circulation
around the lower end of the packer. The
circulating valve is opened for coming
out of the hole when tubing is lowered,
rotated to the right, and picked up.
HA
L1
20
26
RTTS®Packer
2-10 Retrievable Service Tools
Retrievable
ServiceT
ools
C
RTTS® Retrievable Packer
asingSizein.
Packer Main Body OD
in. (cm)
Packer ID
in. (cm)
End Connections
Nominal CasingWeight
lb/ft
MinimumCasing IDin. (mm)
Maximum Casing IDin. (mm)
Lengthin. (cm)
Tensile Rating*lb (kg)
Working Pressurepsi (MPa)
Burst Rating*psi (MPa)
Collapse Rating*psi (MPa)
Open Ended
Bull Plugged
Open Ended
Bull Plugged
2 3/8 1.81(4.60)
0.6(1.52)
1.050 OD 10 Rd EU 4.6 1.995
(50.67)1.995
(50.67) 35.46 (90.07)
28,700 (13 018)
10,000 (68.95)
21,900 (151.00)
11,300 (77.91)
16,900 (116.52)
10,600 (73.08)
2 7/8
2.22(5.64)
0.75 (1.91)
1 7/8 OD 10 Rd EU × 1.315 OD
6.5 2.441 (62.00)
2.441 (62.00)
22.44 (57.00)
38,300 (17 373)
10,000 (68.95)
4,600 (31.72)
4,600 (31.72)
15,200 (104.80)
6,000 (41.36)
2.1(5.33)
0.6 (1.52)
1.050 OD 10 Rd EU 7.9 - 8.7 2.259
(57.38)2.323
(59.00)35.46
(90.07)63,800
(28 940)10,000 (68.95)
11,200 (77.22)
7,000 (48.26)
25,100 (173.06)
6,600 (45.50)
3 1/2
2.93(7.44)
0.62(1.57)
1 7/8 OD 12 UNS EU × 1.315 10 Rd
5.7 3.188 (80.98)
3.188 (80.98)
32.53(82.63)
63,800 (28 940)
10,000 (68.95)
11,200 (77.22)
7,000 (48.26)
25,100 (173.06)
6,600 (45.50)
2.7(6.86)
0.62 (1.57)
1 7/8 OD 12 UNS EU × 1.315 10 Rd
9.2 - 10.2 2.66 (67.60)
2.728 (69.29)
32.53(82.63)
63,800 (28 940)
10,000 (68.95)
11,200 (77.22)
7,000 (48.26)
25,100 (173.06)
6,600 (45.50)
2.5(6.35)
0.62(1.57)
1 7/8 OD 12 UNS EU × 1.315 10 Rd
13.3 2.764 (70.21)
2.764 (70.21)
32.53 (82.63)
63,800 (28 940)
10,000 (68.95)
11,200 (77.22)
7,000 (48.26)
25,100 (173.06)
6,600 (45.50)
4
3.18(8.08)
1.12 (2.84)
2 11/16 10 UNS ×
2 3/8 8 Rd EU9.5 - 11.6 3.428
(87.07)3.548
(90.12)52.68
(133.81)74,000
(33 566)10,000 (68.95)
10,000 (68.95)
10,000 (68.95)
15,000 (103.42)
13,300 (91.70)
3.06(7.77)
0.865 (2.2)
2 11/16 10 UNS × 1 7/8 8 Rd
drillpipe (male)
12.5 - 15.7
3.240 (82.30)
3.382 (85.90)
50.30 (127.76)
63,200 (28 667)
10,000 (68.95)
9,600 (66.19)
9,600 (66.19)
17,600 (121.35)
10,600 (73.08)
4 1/2
3.89(9.88)
1.8(4.57)
3 3/32 10 UNS ×
2 3/8 8 Rd EU9.5 4.090
(103.89)4.154
(105.51)51.85
(131.70)77,100
(34 972)10,000 (68.95)
14,400 (99.28)
5,200 (35.85)
10,200 (70.33)
700 (4.82)
3.75(9.53)
1.8 (4.57)
3 3/32 10 UNS ×
2 3/8 8 Rd EU
11.6 - 13.5
3.920 (99.57)
4.000 (101.60)
51.85 (131.70)
77,100 (34 972)
10,000 (68.95)
14,400 (99.28)
5,200 (35.85)
10,200 (70.33)
700 (4.82)
3.55(9.02)
1.51 (3.84)
2 11/16 10 UNS ×
2 3/8 8 Rd EU
15.1 - 18.1
3.754 (95.35)
3.826 (97.18)
48.93 (124.28)
107,100 (48 580)
10,000 (68.95)
20,100 (138.58)
2,500 (17.23)
16,200 (111.70)
600 (4.13)
5
4.25 (10.79)
1.8(4.57)
3 3/32 10 UNS ×
2 7/8 8 Rd EU11.5 - 13 4.494
(114.15)4.670
(118.62)48.10
(122.17)84,700
(38 419)10,000 (68.95)
12,900 (88.94)
5,200 (35.85)
9,800 (67.57)
700 (4.82)
4.06 (10.31)
1.8 (4.57)
3 3/32 10 UNS ×
2 7/8 8 Rd EU15 - 18 4.276
(108.61)4.408
(111.96)48.10
(122.17)84,700
(38 419)10,000 (68.95)
10,800 (74.46)
5,200 (35.85)
9,800 (67.57)
700 (4.82)
3.89(9.88)
1.8 (4.57)
3 3/32 10 UNS ×
2 3/8 8 Rd EU21.4 4.090
(103.89)4.154
(105.51)51.85
(131.70)77,100
(34 972)10,000 (68.95)
14,400 (99.28)
5,200 (35.85)
10,200 (70.33)
700 (4.82)
3.75(9.53)
1.8(4.57)
3 3/32 10 UNS ×
2 3/8 8 Rd EU23.2 4.044
(102.7)4.044
(102.7)51.85
(131.70)77,100
(34 972)10,000 (68.95)
14,400 (99.28)
5,200 (35.85)
10,200 (70.33)
700 (4.82)
Retrievable Service Tools 2-11
Retrievable
ServiceT
ools
5 1/2
4.55 (11.56)
1.8 (4.57)
3 1/2 8 UNS × 2 3/8 8 Rd EU 13 - 20 4.778
(121.36)5.044
(128.12)48.50
(123.19)133,200 (60 419)
10,000 (68.95)
14,500 (99.97)
7,100 (48.95)
11,600 (79.98)
4,000 (27.57)
4.38 (11.13)
1.8 (4.57)
3 3/32 10 UNS × 2 7/8 8 Rd EU 20 - 23 4.670
(118.62)4.778
(121.36)48.10
(122.17)84,700
(38 419)10,000 (68.95)
12,300 (84.81)
5,200 (35.85)
9,800 (67.57)
700 (4.82)
4.25 (10.79)
1.9 (4.83)
3 1/2 8 UNS × 2 7/8 8 Rd EU 23 - 26 4.494
(114.15)4.670
(118.62)48.10
(122.17)84,700
(38 419)10,000 (68.95)
12,900 (88.94)
5,200 (35.85)
9,800 (67.57)
700 (4.82)
5 3/4 4.89 (12.42)
1.9 (4.83)
3 1/2 8 UNS × 2 7/8 8 Rd EU 14 - 18 5.100
(129.54)5.365
(136.27)48.61
(123.47)133,200 (60 419)
10,000 (68.95)
14,000 (93.76)
7,100 (48.95)
11,600 (79.98)
4,000 (27.57)
6
5.06 (12.85)
1.9 (4.83)
3 1/2 8 UNS × 2 7/8 8 Rd EU 15 - 23 5.240
(133.10)5.524
(140.31)48.50
(123.19)133,200 (60 419)
10,000 (68.95)
14,500 (99.97)
7,100 (48.95)
11,600 (79.98)
4,000 (27.57)
4.89 (12.42)
1.9 (4.83)
3 1/2 8 UNS × 2 7/8 8 Rd EU 20 - 26 5.100
(129.54)5.365
(136.27)48.61
(123.47)133,200 (60 419)
10,000 (68.95)
14,000 (93.76)
7,100 (48.95)
11,600 (79.98)
4,000 (27.57)
6 5/8
5.65 (14.35)
2.37 (6.02)
3 7/8 CAS or 4 5/32 8 UNS ×
2 7/8 IF, 3 7/8 CAS
2 7/8 8 Rd EU
17 - 20 5.920 (150.37)
6.538 (166.07)
54.22 (137.72)
158,200 (71 758)
10,000 (68.95)
15,300 (105.49)
8,800 (60.67)
10,100 (69.64)
4,500 (31.02)
5.43 (13.79)
1.9 (4.83)
3 1/2 8 UNS × 2 7/8 8 Rd EU 24 - 32 5.675
(144.15)5.921
(150.39)48.50
(123.19)133,200 (60 419)
10,000 (68.95)
14,600 (100.66)
7,100 (48.95)
11,600 (79.98)
4,000 (27.57)
7
5.65 (14.35)
2.37 (6.02)
3 7/8 CAS or 4 5/32 8 UNS ×
2 7/8 IF, 3 7/8 CAS,
2 7/8 8 Rd EU
17 - 38 5.920 (150.37)
6.538 (166.07)
54.22 (137.72)
158,200 (71 758)
10,000 (68.95)
15,300 (105.49)
8,800 (60.67)
10,100 (69.64)
4,500 (31.02)
5.25 (13.34)
2 (5.08)
3 1/2 8 UNS × 2 7/8 8 Rd EU 49.5 5.540
(140.72)5.920
(150.37)48.50
(123.19)133,200 (60 419)
10,000 (68.95)
14,000 (93.76)
7,100 (48.95)
11,600 (79.98)
4,000 (27.57)
7 5/8
6.35 (16.13)
2.37 (6.02)
4 5/32 8 UNS ×2 7/8 8 Rd EU
3 1/2 IF, 3 7/8 CAS
20 - 39 6.625 (168.28)
7.125 (180.98)
54.22 (137.72)
158,200 (71 758)
10,000 (68.95)
12,600 (86.87)
8,800 (60.67)
10,100 (69.64)
4,500 (31.02)
6.16 (15.64)
2.37 (6.02)
4 5/32 8 UNS × 2 7/8 8 Rd EU
3 1/2 IF
29.7 - 45.3
6.430 (163.32)
6.901 (175.29)
54.22 (137.72)
158,200 (71 758)
10,000 (68.95)
14,700 (101.35)
8,800 (60.67)
10,100 (69.64)
4,500 (31.02)
7 3/4 6.16 (15.64)
2.37 (6.02)
4 5/32 8 UNS × 2 7/8 8 Rd EU
3 1/2 IF33.2 - 50 6.430
(163.32)6.901
(175.29)54.22
(137.72)158,200 (71 758)
10,000 (68.95)
14,700 (101.35)
8,800 (60.67)
10,100 (69.64)
4,500 (31.02)
8 5/8 7.31 (18.57)
3.00 (7.62) 4 1/2 API IF TJ 24 - 49 7.511
(190.78)8.097
(205.66)89.29
(226.80)237,200
(107 592)10,000 (68.95)
13,500 (93.08)
6,300 (43.43)
9,700 (66.88)
2,600 (17.92)
9 5/8
8.15 (20.7)
3.75 (9.53) 4 1/2 API IF TJ 29.3 -
53.58.535
(216.79)9.063
(230.20)90.03
(228.68)444,600
(201 667)7,500
(51.71)13,500 (93.08)
10,800 (74.46)
10,100 (69.64)
10,300 (71.01)
7.8 (19.81)
3.00 (7.62) 4 1/2 API IF TJ 40 - 71.8 8.125
(206.38)8.835
(224.41)89.29
(226.80)237,200
(107 592)7,500
(51.71)14,000 (93.76)
6,300 (43.43)
9,700 (66.88)
2,600 (17.92)
RTTS® Retrievable Packer
CasingSizein.
Packer Main Body OD
in. (cm)
Packer ID
in. (cm)
End Connections
Nominal CasingWeight
lb/ft
MinimumCasing IDin. (mm)
Maximum Casing IDin. (mm)
Lengthin. (cm)
Tensile Rating*lb (kg)
Working Pressurepsi (MPa)
Burst Rating*psi (MPa)
Collapse Rating*psi (MPa)
Open Ended
Bull Plugged
Open Ended
Bull Plugged
2-12 Retrievable Service Tools
Retrievable
ServiceT
ools
C
10 3/4
9.3 (23.62)
3.75 (9.53) 4 1/2 API IF TJ 32.75 -
55.59.760
(247.90)10.192
(258.88)90.83
(230.71)444,600
(201 667)5,000
(34.47)13,500 (93.08)
10,800 (74.46)
10,100 (69.64)
10,300 (71.01)
8.85 (22.48)
3.75 (9.53) 4 1/2 API IF TJ 55.5 - 81 9.250
(234.95)9.760
(247.90)90.58
(230.07)444,600
(201 667)5,000
(34.47)13,500 (93.08)
10,800 (74.46)
10,100 (69.64)
10,300 (71.01)
8.85 (22.48)
3.50 (8.89)
5 1/4 CAS × XT57
71.1 - 85.3
9.156 (232.56)
9.450 (240.03)
110.28 (280.11)
1,036,319 (470 066)
5,000 (34.47)
12,088 (83.34)
6,600 (45.50)
12,825 (88.43)
1,900 (13.10)
11 3/4
10.2 (25.91)
3.75 (9.53) 4 1/2 API IF TJ 38 - 54 10.880
(276.35)11.150
(283.21)92.27
(234.37)444,600
(201 667)5,000
(34.47)13,500 (93.08)
10,800 (74.46)
10,100 (69.64)
10,300 (71.01)
10.1 (25.65)
3.75 (9.53) 4 1/2 API IF TJ 60 - 71 10.586
(268.88)10.772
(273.61)92.27
(234.37)444,600
(201 667)5,000
(34.47)13,500 (93.08)
10,800 (74.46)
10,100 (69.64)
10,300 (71.01)
12 3/4 11.05 (28.07)
3.75 (9.53) 4 1/2 API IF TJ 57 - 81 11.5
(292.10)11.884
(301.85)92.27
(234.37)444,600
(201 667)5,000
(34.47)11,900 (82.05)
10,800 (74.46)
10,100 (69.64)
10,300 (71.01)
13 3/8
11.94 (30.33)
3.75 (9.53) 4 1/2 API IF TJ 48 - 72 12.347
(313.61)12.715
(322.96)101.36
(257.45)651,300
(295 425)3,000
(20.68)12,500 (86.18)
9,200 (63.43)
10,700 (73.77)
8,800(60.67)
11.5 (29.21)
3.75 (9.53) 4 1/2 API IF TJ 72 - 98 11.937
(303.20)12.347
(313.61)101.36
(257.45)651,300
(295 425)3,000
(20.68)12,500 (86.18)
9,200(63.43)
10,700 (73.77)
8,800(60.67)
12.0 (29.21)
3.75 (9.53) 4 1/2 API IF TJ 48 - 72 12.347
(313.61)12.715
(322.96)132.29
(336.01)1,204,000 (546 125)
8,000 (55.16)
18,600 (128.24)
11,900(82.04)
17,000 (117.21)
11,300(77.91)
14 11.94 (30.33)
3.75 (9.53) 4 1/2 API IF TJ 82.5 12.876
(327.05)12.876
(327.05)101.36
(257.45)651,300
(295 425)3,000
(20.68)12,500 (86.18)
9,200(63.43)
10,700 (73.77)
8,800(60.67)
16
14.43 (36.65)
3.75 (9.53) 4 1/2 API IF TJ 55 - 65 15.250
(387.35)15.376
(390.55)113.93
(289.38)651,300
(295 425)2,500
(17.24)8,900
(61.36)7,900
(54.46)6,000
(41.37)5,000
(34.47)
14.18 (36.02)
3.75 (9.53) 4 1/2 API IF TJ 75 - 109 14.688
(373.07)15.124
(384.15)113.93
(289.38)651,300
(295 425)1,500
(10.34)8,900
(61.36)7,900
(54.46)6,000
(41.37)5,000
(34.47)
13.62 (34.59)
3.75 (9.53) 4 1/2 API IF TJ 109 - 146 14.188
(360.38)14.688
(373.07)113.93
(289.38)651,300
(295 425)2,500
(17.24)13,100 (90.32)
7,900(54.46)
10,000 (68.95)
5,000(34.47)
18 5/8 16.87 (42.85)
3.75 (9.53) 4 1/2 API IF TJ 78 - 118 17.336
(440.33)17.855
(453.52)114.71
(291.36)651,300
(295 425)2,500
(17.24)8,900
(61.36)6,700
(46.19)6,400
(44.13)4,300
(29.64)
20
17.87 (45.39)
3.75 (9.53) 4 1/2 API IF TJ 94 - 133 18.730
(475.74)19.124
(485.75)114.71
(291.36)651,300
(295 425)2,500
(17.24)8,900
(61.36)6,700
(46.19)6,400
(44.13)4,300
(29.64)
17.25 (43.82)
3.75 (9.53) 4 1/2 API IF TJ 169 - 204 18.000
(457.20)18.376
(466.75)114.71
(291.36)651,300
(295 425)2,500
(17.24)8,900
(61.36)6,700
(46.19)5,400
(37.23)4,300
(29.64)
RTTS® Retrievable Packer
asingSizein.
Packer Main Body OD
in. (cm)
Packer ID
in. (cm)
End Connections
Nominal CasingWeight
lb/ft
MinimumCasing IDin. (mm)
Maximum Casing IDin. (mm)
Lengthin. (cm)
Tensile Rating*lb (kg)
Working Pressurepsi (MPa)
Burst Rating*psi (MPa)
Collapse Rating*psi (MPa)
Open Ended
Bull Plugged
Open Ended
Bull Plugged
Retrievable Service Tools 2-13
Retrievable
ServiceT
ools
RTTS® Circulating Valve
The RTTS® circulating valve is a locked-open/locked-closed
valve that serves as both a circulating valve and bypass. The
clearance between the RTTS packer (or any hookwall packer)
and the casing ID is relatively small. To reduce the effect of
fluid-swabbing action when the tool is run in or pulled out of
the hole, a packer bypass is generally used.
Features and Benefits
• The valve can be locked closed when the packer is unset to
reverse fluid around the bottom of the packer.
• The tool’s full opening allows tubing-type guns and other
wireline equipment to pass.
Operation
The RTTS circulating valve is automatically locked in the
closed position when the packer is set. During testing and
squeezing operations, the lock helps prevent the valve from
being pumped open. A straight J-slot in the locked-open
position can be used with the straight J-slot (optional) in the
packer body. This combination eliminates the need to turn
the tubing to close the circulating valve or reset the packer
after the tubing has been displaced with cement.
The RTTS circulating valve may be run directly above the
packer body or further up the workstring.
When placed in the hole, the valve must be in the locked-
open position. The J-slot in the packer-body drag block (or
drag sleeve) must also be placed in the unset position.
When the circulating valve is opened to come out of the hole,
the tubing is lowered, turned to the right, and picked up.
HA
L1
20
27
RTTS®Circulating Valve
2-14 Retrievable Service Tools
Retrievable
ServiceT
ools
RTTS® Circulating Valve
Size in.
ODin. (cm)
IDin. (cm)
EndConnections
Lengthin. (cm)
Tensile Rating*lb (kg)
Burst Rating*psi (MPa)
Collapse Rating*
psi (MPa)
2 3/8 1.68(4.27)
0.68(1.73) 1.05 10 Rd 18.42
(46.80)31,900
(14 451)11,600(79.97)
9,900(68.25)
2 7/8 2.15(5.46)
1.00(2.54)
1.315 10 Rd1.875 12 Rd
19.15(48.64)
37,500(17 009)
8,100(55.84)
7,800(53.77)
3 1/2 2.37(6.01)
1.00(2.54)
1.315 10 Rd1.875 12 Rd
20.08(51.00)
52,500(23 813)
10,000(68.95)
12,400(85.49)
4 3.06(7.77)
1.50(3.81)
2 3/8 EU2.688 10 UN
39.76(100.99)
92,200(41 821)
8,100(55.84)
13,700(94.45)
4 1/2 - 5 3.60(9.14)
1.80(4.57)
2 3/8 EU3.094 10 UN
32.20(81.80)
85,000(38 505)
10,100(69.63)
10,700(73.77)
5 1/2 - 6 5/8 4.18(10.62)
1.99(5.05)
2 3/8 EU3 1/2 8 UN
31.90(81.03)
150,700(68 356)
10,000(68.95)
14,200(97.91)
7 - 7 5/8 4.87(12.37)
2.44(6.19)
2 7/8 EU4.156 8 UN
32.90(83.6)
148,800(67 606)
10,000(68.95)
10,200(70.32)
8 5/8 - 20 6.12(15.54)
3.00(7.62) 4 1/2 IF TJ 38.40
(97.40)311,400
(141 200)10,500(72.39)
12,400(85.49)
*The values of tensile, burst, and collapse strength are calculated with new tool conditions, Lame's formulas with Von-Mise's Distortion Energy Theory for burst and collapse strength, and stress area calculations for tensile strength. These ratings are guidelines only. For more information, consult your local Halliburton representative.
Retrievable Service Tools 2-15
Retrievable
ServiceT
ools
RTTS® Safety Joint
The RTTS® safety joint is an optional emergency backoff
device. The safety joint releases the workstring and tools
above the packer if the packer becomes stuck during
operations.
The design of the RTTS safety joint makes unintentional
operation difficult.
Features and Benefits
• Positive sequence of operation helps prevent
premature release.
• Tools above the safety joint can be retrieved when string
is stuck.
Operation
The RTTS safety joint is run immediately above the
RTTS packer so that the greatest number of tools above the
packer may be removed.
Before the safety joint can be used, a tension sleeve located
on the bottom of the lug mandrel must first be parted by
pulling up on the workstring. This tension sleeve must be
considered whenever additional tools or workstring is run
below the packer. Excessive weight can cause unexpected
parting of this sleeve during the tool make up process.
After the tension sleeve has parted, the safety joint is released
by right-hand torque while the workstring is reciprocated a
specified number of cycles.
HA
L1
20
29
RTTS®Safety Joint
2-16 Retrievable Service Tools
Retrievable
ServiceT
ools
RTTS® Safety Joint
Size in.
ODin. (cm)
IDin. (cm)
EndConnections
Lengthin. (cm)
Tensile Rating*lb (kg)
Burst Rating*psi (MPa)
Collapse Rating*
psi (MPa)
2 3/8 1.81(4.60)
0.68(1.73) 1.05 10 Rd 24.30
(61.70)32,000
(14 500)9,600
(66.20)15,500
(106.90)
2 7/8 2.15(5.46)
1.00(2.54) 1.315 - 10 Rd 25.46
(64.66)24,300
(11 022)5,000
(34.47)9,800
(67.56)
3 1/2 2.37(6.01)
0.75(1.90) 1.315 - 10 Rd 22.72
(57.70)65,700
(29 801)12,200(84.11)
17,400(119.96)
4 3.34(8.48)
1.50(3.81) 2 3/8 EU 38.68
(98.24)92,100
(41 775)13,900(95.83)
12,900(88.94)
4 1/2 - 5 3.68(9.35)
1.90(4.83) 2 3/8 EU 38.50
(97.8)88,600
(40 272)9,900
(68.28)11,100(76.56)
5 1/2 - 6 5/8 4.06(10.31)
2.00(5.08)
2 3/8 EU2 7/8 EU
38.60(98.04)
127,400(57 789)
10,200(70.33)
13,000(89.63)
7 - 7 5/8 5.00(12.70)
2.44(6.20) 2 7/8 EU 39.90
(101.40)148,800(67 500)
12,300(84.80)
10,900(75.10)
8 5/8 - 13 3/8 6.12(15.54)
3.12(7.92) 4 1/2 IF TJ 42.70
(108.50)271,900
(123 600)13,800(95.17)
10,400(71.70)
Note: These are the most common sizes. Other sizes may be available.*The values of tensile, burst, and collapse strength are calculated with new tool conditions, Lame's formulas with Von-Mise's Distortion Energy Theory for burst and collapse strength, and stress area calculations for tensile strength. These ratings are guidelines only. For more information, consult your local Halliburton representative.
Retrievable Service Tools 2-17
Retrievable
ServiceT
ools
Isolator® Retrievable Bridge Plug
The Isolator® retrievable bridge plug
(RBP) consists of packer-type sealing
elements, mechanical slips, and a ball
valve section.
The sealing elements are less
susceptible to damage while running in
the hole because they are not in contact
with the casing. When set, the Isolator
RBP does not move up or down the
casing, regardless of pressure reversals.
The plug can be run alone on tubing or
can be run below the RTTS® or
CHAMP® IV packer. The tool is run in
the hole, set, and released from the
tubing or packer. It remains in place
until the tubing or packer is relatched,
the ball valve is opened, and the slips
are released.
Applications
Run as a barrier for:
• Temporary abandonment
• Change of wellhead/wireline valves
• Zonal isolation
• Pressure testing in conjunction with
retrievable packers
• Can also be run as a retrievable
packer
Features and Benefits
• Rugged packer-type sealing
elements
• Enhanced safety for relief of
trapped pressure
• Wide range of pressure and
temperature limitations
• “Hammer-down” feature to
assist unsetting
• Pump-through capabilities with
overshot connected
• Simple operation
• No torque buildup during setting
and retrieving
• Liner-lock function
• Positive indication when plug is
released from overshot
• Slips protected from debris below
packer elements
• Built-in concentric bypass
• Full-flow ID
• NACE SG 175
• Can hang drillpipe below
• 4 3/4-in. drill collar profile for safety
on rig
• Some sizes available with ISO 14310
V0 rating
Isolator®Retrievable Bridge Plug
HA
L1
20
52
2-18 Retrievable Service Tools
Retrievable
ServiceT
ools
Operation
The plug is run a few feet below a specified depth and picked
up to the predetermined setting depth. The tubing is rotated
to the left, and the tubing weight is set down while the left-
hand rotation is maintained.
The bridge plug is released as the tubing is rotated left and the
tubing is pulled up. This action moves the lugs in the overshot
out of the J-slot in the retrieving head and allows the tubing to
pull free.
The bridge plug is retrieved when the tubing is lowered and
the overshot engages the J-slot in the plug retrieving head.
Any trapped pressure below the bridge plug is designed to be
relieved at this stage. Right-hand rotation is applied, the
tubing is pulled up, and the mechanical slips are retracted to
release the bridge plug.
Isolator® Retrievable Bridge Plug
Casing Sizein.
Bridge Plug Main Body
OD in. (cm)
Bridge Plug ID
in. (cm)
End Connections
Nominal Casing
Weight lb/ft
Minimum Casing ID in. (cm)
Maximum Casing ID in. (cm)
Length in. (cm)
Tensile Rating* lb (kg)
Working Pressure Rating*
psi (MPa)
9 5/8 8.15 (20.7)
1.83(4.65) 3 7/8 in. CAS 29.3 - 53.5 8.535
(21.68)9.063
(23.02)235.44
(598.02)190,000(86 183)
7,500(51.71)
10 3/4
9.40(23.88)
1.83(4.65) 3 7/8 in. CAS 32.75 - 55.5 9.760
(24.79)10.192(25.89)
235.44(598.02)
190,000(86 183)
7,500(51.71)
8.85(22.48)
1.83(4.65) 3 7/8 in. CAS 60.7 - 80.8 9.250
(23.50)9.660
(24.54)235.44
(598.02)190,000(86 183)
7,500(51.71)
*The values of tensile, burst, and collapse strength are calculated with new tool conditions, Lame's formulas with Von-Mise's Distortion Energy Theory for burst and collapse strength, and stress area calculations for tensile strength. These ratings are guidelines only. For more information, consult your local Halliburton representative.
Retrievable Service Tools 2-19
Retrievable
ServiceT
ools
Model 3L Retrievable Bridge Plug
The Model 3L retrievable bridge plug consists of packer-type
sealing elements, mechanical slips, and a large-area bypass.
The sealing elements are less susceptible to damage while
running in the hole because they are not in contact with the
casing. When set, the Model 3L bridge plug does not move up
or down the casing, regardless of pressure reversals.
This plug can be run alone on tubing or can be run below the
RTTS or CHAMP IV packer. The tool is run in the hole,
set, and released from the tubing or packer. It remains in place
until the tubing or packer is relatched, the bypass valve is
opened, and the slips are released.
Features and Benefits
• Rugged, packer-type sealing elements
• Wide range of pressure and temperature limitations
• Simple operation
Operation
The plug is run a few feet below a specified depth and
picked up to the predetermined setting depth. The tubing is
rotated, and the tubing weight is set down while left-hand
torque is maintained.
The bridge plug is released as left-hand torque is held on the
tubing, and the tubing is pulled up. This action moves the lugs
on the retrieving head out of the J-slot in the overshot and
allows the tubing to pull free.
The bridge plug is retrieved when the tubing is lowered and
the overshot engages the lugs on the plug-retrieving head.
Right-hand torque is applied and the tubing is pulled up. It
may be necessary to apply weight if pressure is trapped
below the tool. As the torque is applied and the tubing is
pulled up, the bypass ports open, and the mechanical slips
are retracted to release the bridge plug.
HA
L1
20
30
Model 3LRetrievable Bridge Plug
2-20 Retrievable Service Tools
Retrievable
ServiceT
ools
Model 3L Retrievable Bridge Plug
Casing Size in.
Bridge Plug Main Body
OD in. (cm)
EndConnections
Nominal Casing
Weight lb/ft
Minimum Casing ID in. (cm)
Maximum Casing ID in. (cm)
Length in. (cm)
Tensile Rating* lb (kg)
Working Pressure Rating*
psi (MPa)
4 1/2 3.75(9.53)
2 7/8 in. 8 Rd EU × 2 3/8 in. 8 Rd EU 9.5 - 13.5 3.920
(9.96)4.090
(10.39)109.16
(277.27)65,200
(29 574)10,000(68.95)
5
4.35(11.05)
2 7/8 in. 8 Rd EU × 2 3/8 in. 8 Rd EU 11.5 4.560
(11.58)4.778
(12.14)89.43
(227.15)65,200
(29 574)10,000(68.95)
4.25(10.79)
2 7/8 in. 8 Rd EU × 2 3/8 in. 8 Rd EU 13 - 15 4.408
(11.20)4.494
(11.42)89.43
(227.15)65,200
(29 574)10,000(68.95)
3.93(9.98)
2 7/8 in. 8 Rd EU × 2 3/8 in. 8 Rd EU 18 - 21.4 4.126
(10.48)4.276
(10.86)89.43
(227.15)65,200
(29 574)10,000(68.95)
5 1/2
4.60(11.68)
2 7/8 in. 8 Rd EU × 2 3/8 in. 8 Rd EU 13 - 20 4.778
(12.14)5.044
(12.81)89.43
(227.15)65,200
(29 574)10,000(68.95)
4.35(11.05)
2 7/8 in. 8 Rd EU × 2 3/8 in. 8 Rd EU 20 - 23 4.560
(11.58)4.778
(12.14)89.43
(227.15)65,200
(29 574)10,000(68.95)
6 5/8 5.43(13.79)
2 7/8 in. 8 Rd EU × 2 3/8 in. 8 Rd EU 24 - 32 5.675
(14.42)5.921
(15.04)89.43
(227.15)65,200
(29 574)10,000(68.95)
7 5.65(14.35)
2 7/8 in. 8 Rd EU × 2 3/8 in. 8 Rd EU 17 - 38 5.920
(15.04)6.538
(16.61)89.44
(227.18)65,200
(29 574)10,000(68.95)
7 5/8 6.35(16.13)
2 7/8 in. 8 Rd EU × 2 3/8 in. 8 Rd EU 20 - 39 6.625
(16.83)7.125
(18.10)89.43
(227.15)65,200
(29 574)10,000(68.95)
8 5/8 7.04(17.88)
3 1/2 in. API IF TJ × 2 3/8 in. 8 Rd EU 49 - 56 7.313
(18.58)7.511
(19.08)108.83
(276.43)117,800(53 433)
10,000(68.95)
9 5/8 8.15(20.70)
4 1/2 in. API IF TJ × 2 3/8 in. 8 Rd EU 29.3 - 53.5 8.535
(21.68)9.063
(23.02)106.18
(269.70)117,800(53 433)
10,000(68.95)
10 3/4
9.40(23.88)
4 1/2 in. API IF TJ × 2 3/8 in. 8 Rd EU 32.75 - 55.5 9.760
(24.79)10.192(25.89)
106.18(269.70)
117,800(53 433)
7,500(51.71)
8.85(22.48)
4 1/2 in. API IF TJ × 2 3/8 in. 8 Rd EU 60.7 - 80.8 9.250
(23.50)9.660
(24.54)106.18
(269.70)117,800(53 433)
7,500(51.71)
*The values of tensile, burst, and collapse strength are calculated with new tool conditions, Lame's formulas with Von-Mise's Distortion Energy Theory for burst and collapse strength, and stress area calculations for tensile strength. These ratings are guidelines only. For more information, consult your local Halliburton representative.
Retrievable Service Tools 2-21
Retrievable
ServiceT
ools
Versa-Set® Retrievable Bridge Plug
The Halliburton Versa-Set® retrievable bridge plug consists of
packer-type sealing elements, mechanical slips, and a large
area bypass.
The sealing elements are compression set and less susceptible
to damage while running in the hole. The bridge plug can be
conventionally set with tubing, wireline setting tool,
Halliburton 2.5-in. OD DPU® downhole power unit, or
hydraulically set with a BP hydraulic setting tool.
Since it requires rotation to unset, the Versa-Set bridge plug
must be retrieved on jointed tubing. It can be reset as required
on tubing even if set initially with wireline.
The Versa-Set bridge plug can be run alone or below the
RTTS® or CHAMP® packer when run on tubing. The tool is
run in the hole, set, and released from the tubing or packer. It
remains in place until the retrieving head is reattached, the
bypass valve is opened, and the slips are released.
Features and Benefits
• Rugged packer sealing elements
• Sets with tension or compression
• Conventional tubing, wireline, or hydraulic set
• Internal mandrel bypass offers option to use model 3L
retrieving head and overshot
• For shallow applications, the BV retrieving head and
overshot may be used to allow equalizing pressure prior
to releasing the upper slips
• Sequential release of upper slips
• Rated 10,000 psi at 350°F
• Cost effective to purchase and maintain
• Simple operation and maintenance
Versa-Set® Retrievable Bridge Plug
3L StyleReceiving Head
HA
L2
50
42
HA
L2
50
43
Versa-Set® Retrievable Bridge Plug
Express StyleReceiving Head
2-22 Retrievable Service Tools
Retrievable
ServiceT
ools
Operation
The plug is run a few feet below the specified setting depth
and picked up to the predetermined setting depth. The
tubing is rotated, and weight is set down while left-hand
torque is maintained.
The bridge plug is released as weight is set down while
holding left-hand torque in the tubing. After weight is
applied to compress the elements, the tubing is pulled up.
This action moves the lugs out of the J-slot and allows the
tubing to pull free.
The bridge plug remains in place until the retrieving head
is reattached, the bypass valve is opened, and the slips
are released.
The Versa-Set® bridge plug (3L style) is retrieved when the
tubing is lowered and the overshot engages the lugs on the
retrieving head. Right-hand torque is applied and as the
tubing is pulled up, the mandrel bypass ports open and
equalize pressure. The mechanical slips are retracted to
release the bridge plug. It may be necessary to apply weight if
pressure is trapped below the tool.
The Versa-Set bridge plug (Express style) is retrieved when
the tubing is lowered and the overshot lugs engage the
retrieving head. The upper equalizing valve opens and
pressure is equalized. Right-hand torque is applied and as the
tubing is pulled up, the mechanical slips are retracted, and
the bridge plug is released.
Versa-Set® Retrievable Bridge Plug
Part NumberCasing
Sizein.
Tool ODin. (mm)
EndConnections
MinimumCasing IDin. (cm)
MaximumCasing IDin. (cm)
ToolLengthin. (cm)
Tensile Rating*lb (kg)
WorkingPressure*psi (MPa)
1014922203L Head 4 1/2 3.75
(9.53)Top 2 7/8 8 Rd
Bottom 2 3/8 8 Rd4.00
(10.16)4.09
(10.39)97.55
(247.80)78,500
(36 613)10,000(68.95)
101492245Express Head 4 1/2 3.75
(9.53)Top 2 3/8 8 Rd
Bottom 2 3/8 8 Rd4.00
(10.16)4.09
(10.39)97.55
(247.80)78,500
(36 613)10,000(68.95)
101624115 Express Head 5 1/2 4.60
(11.68)Top 2 3/8 8 Rd
Bottom 2 7/8 8 Rd4.78
(12.14)4.95
(12.57)97.55
(247.80)78,500
(36 613)10,000(68.95)
*The values of tensile, burst, and collapse strength are calculated with new tool conditions, Lame's formulas with Von-Mise's Distortion Energy Theory for burst and collapse strength, and stress area calculations for tensile strength. These ratings are guidelines only. For more information, consult your local Halliburton representative.
Setting Adapter Kits and Redress Kits
Part Number Description
101005353 Adapter Kit – Express Head Setup to Baker 10
101005383 Adapter Kit – Express Head Setup to BP Hydraulic Setting Tool
101492239 Adapter Kit – 3L Head Setup to Baker 10
101550314 Redress Kit – Express to Baker 10 or BP Hydraulic Setting Tool
101550325 Redress Kit – 3L Setup to Baker 10
Retrieving Kits
Part Number Description
101005440 Express Overshot Retrieving Kit
1000124203L Overshot Running Sleeve and Shoe
100012444
Spring Compression for Wireline Set
Part Number Description
101396812 Spring Compression Tool
101550134 Spring Compression Spacer for 3L Head Setup
101550133 Spring Compression Spacer for Express Head Setup
Retrievable Service Tools 2-23
Retrievable
ServiceT
ools
Subsurface Control Valve (SSC)
The subsurface control valve (SSC) is a combination valve and
backoff joint used to close in a well being drilled without the
drillpipe being pulled. This capability is especially useful in
offshore operations when storms are expected or when
surface equipment must be repaired. The valve helps
eliminate the hazard of leaving pipe standing in the derrick
during a storm and saves time.
Usually a hookwall packer, such as the RTTS® packer, is
used with the SSC valve to support the drillpipe weight.
The packer seals inside the casing (surface pipe or
intermediate casing string), and the SSC valve seals the
drillpipe ID. Because the SSC valve includes a backoff
connection, the drillpipe above it can be removed and
reconnected when operations resume.
When the tool is operated from a floater-type rig, a bumper
sub or slip joint should be inserted in the drillpipe above the
SSC valve.
Features and Benefits
• Saves rig time
• Operates easily
• Tests wireline valves during drilling operation
Operation
For temporary abandonment, the drill bit is pulled up into a
stabilized hole or casing. An RTTS packer with an SSC valve
is then installed on the drillpipe.
The toolstring is then run into the hole until the RTTS packer
and SSC valve have sufficient drillpipe weight below the RTTS
packer to set the packer elements and a sufficient depth is
reached (below the mud line for storm abandonment). The
packer is set. The drillpipe is rotated to the left to release the
seal mandrel from the SSC valve. (The weight of the pipe
above the SSC must be supported from the surface while
rotating.) This procedure closes the SSC valve.
After the valve is closed, the separated drillpipe can be
removed from the well, and the wireline valves can be closed
for temporary well abandonment.
Subsurface Control Valve
(SSC)
HA
L1
20
34
2-24 Retrievable Service Tools
Retrievable
ServiceT
ools
Subsurface Control Valve (SSC)
ODin. (cm)
IDin. (cm)
End Connections
Lengthin. (cm)
Tensile Rating*lb (kg)
Working Pressure*psi (MPa)
3.72(9.45)
1.00(2.54) 2 7/8 EU 46.57
(118.28)218,300(99 000)
9,300(64.12)
4.75(12.06)
1.25(3.17) 3 1/2 IF TJ 64.78
(164.54)332,600
(150 900)6,100
(42.06)
6.25(15.87)
2.00(5.08) 4 1/2 IF TJ 64.01
(162.58)598,000
(271 200)10,000(68.95)
*The values of tensile, burst, and collapse strength are calculated with new tool conditions, Lame's formulas with Von-Mise's Distortion Energy Theory for burst and collapse strength, and stress area calculations for tensile strength. These ratings are guidelines only. For more information, consult your local Halliburton representative.
Retrievable Service Tools 2-25
Retrievable
ServiceT
ools
Subsurface Control Valve II (SSC II)
The subsurface control valve II (SSC II) is a combination ball
valve and backoff joint that allows operators to close in a well
that is being drilled without having to pull the workstring.
This capability is especially useful in offshore operations
when storms are expected or when surface equipment must
be repaired. The valve helps eliminate the hazard of leaving
pipe standing in the derrick during a storm.
Usually a hookwall packer, such as the RTTS® packer, is used
with the SSC II valve to support the weight of the workstring.
The packer seals inside the casing (surface pipe or
intermediate casing string), and the SSC II ball valve seals the
workstring ID. Because the SSC II valve includes a backoff
connection, the workstring above it can be removed and
reconnected when operations resume.
When the tool is operated from a floater-type rig, a bumper
sub or slip joint should be inserted in the workstring above
the SSC II valve.
Features and Benefits
• Requires only right-hand rotation to release the workstring
from the valve
• Requires no rotation to reattach the workstring to the valve
• Easy to operate in an emergency
• Full-flow ID
By opening and closing the valve, the operator can check for
pressure buildup before unsetting the packer.
The SSC II valve can circulate large volumes of drilling fluids
to recondition the mud system before the packer and valve are
removed and normal drilling operations resume.
SubsurfaceControl Valve II
(SSC II)
HA
L1
20
53
2-26 Retrievable Service Tools
Retrievable
ServiceT
ools
Subsurface Control Valve II (SSC II)
ODin. (cm)
IDin. (cm)
End Connections
Lengthin. (cm)
Tensile Rating*lb (kg)
Working Pressure*psi (MPa)
4.75(12.06)
1.80(4.57) 3 1/2 IF TJ 126.05
(320.16)186,900(84 105)
10,000(68.95)
1.50(3.81) 3 1/2 IF TJ 133.37
(338.76)302,449
(137 188)10,000(68.95)
6.50(16.51)
2.25(5.71) 4 1/2 IF TJ 133.99
(340.33)485,200
(218 340)10,000(68.95)
*The values of tensile, burst, and collapse strength are calculated with new tool conditions, Lame's formulas with Von-Mise's Distortion Energy Theory for burst and collapse strength, and stress area calculations for tensile strength. These ratings are guidelines only. For more information, consult your local Halliburton representative.
Retrievable Service Tools 2-27
Retrievable
ServiceT
ools
Subsurface Control Valve III (SSC III)
The subsurface control valve III (SSC III) is a combination
ball valve and backoff joint used with a unique retrieving
head that allows operators to close in a well that is being
drilled without having to pull the workstring. This capability
is especially useful in offshore operations when storms are
expected or when surface equipment must be repaired. The
valve reduces the hazard of leaving all pipes standing in the
derrick during a storm.
The Halliburton SSC I and SSC II valves usually utilize a
hookwall packer, such as the RTTS® packer. To take advantage
of the SSC III valve high load capabilities, a special high-
strength RTTS packer was designed to be used in conjunction
with the SSC III valve to support the workstring weight. The
packer seals inside the casing (surface pipe or intermediate
casing string), and the SSC III ball valve seals the workstring
ID. Because the SSC III valve includes a new retrieving head
as the backoff connection, the workstring above it can easily
be removed and reconnected when operations resume.
When the tool is operated from a floater-type rig, a bumper
sub or slip joint should be inserted in the workstring above
the SSC III valve.
By opening and closing the valve, the operator can check for
pressure buildup before unsetting the packer. The SSC III
valve can circulate large volumes of drilling fluids to
recondition the mud system before the packer and valve are
removed and normal drilling operations resume.
Features and Benefits
• Helps reduce rig costs and personnel exposure time
• Easy to operate in an emergency
• High strength 1.0 MM lb working capacity valve
and packer
• 8,000 psi working pressure, ball valve type storm valve
with 3.50 in. ID
• Full-flow ID
• Enhances safe and reliable innovation
– Positive re-latch system with no partial re-engagements
– Unique overshot for non-rotating detachment (1/4 turn
required at the tool)
– Right-hand torque to set and detach with auto re-attach
HA
L1
70
47
SubsurfaceControl Valve III
(SSC III)
2-28 Retrievable Service Tools
Retrievable
ServiceT
ools
Subsurface Control Valve III (SSC III)
ODin. (cm)
ID in. (cm)
EndConnections
Length in. (cm)
WorkingTensile Rating*
lb (kg)
WorkingPressure*psi (MPa)
8.50 (21.59)
3.50 (8.89)
6 5/8 FH Box × 5 1/4 CAS
181.3 (460.5)
1,000,000 (453 592)
8,000 (55.16)
*Please consult your Halliburton representative to determine maximum hang-off and pressure test requirements.
10 3/4-in. High-Strength RTTS® Packer
Casing Range
in.
Maximum OD
in. (cm)
Minimum ID in. (cm)
Overall Length in. (cm)
Makeup Length in. (cm)
Tensile Rating* lb (kg)
Maximum Hanging Weight lb (kg)
Burst Rating*psi (MPa)
Collapse Rating*psi (MPa)
Open Ended
Bull Plugged
Open Ended
Bull Plugged
9.156-9.450
9.00(22.86)
3.50(8.89)
110.28 (280.11)
103.03(261.70)
1,036,319(470 066)
850,000(385 553)
12,088(83.34)
6,666(45.96)
12,825(88.43)
1,941(13.38)
*The values of tensile, burst, and collapse strength are calculated with new tool conditions, Lame's formulas with Von-Mise's Distortion Energy Theory for burst and collapse strength, and stress area calculations for tensile strength. These ratings are guidelines only. For more information, consult your local Halliburton representative.
13 3/8-in. High-Strength RTTS® Packer
Casing Range
in.
Maximum OD
in. (cm)
Minimum ID in. (cm)
Overall Length in. (cm)
Makeup Length in. (cm)
Tensile Rating* lb (kg)
Maximum Hanging Weight lb (kg)
Burst Rating*psi (MPa)
Collapse Rating*psi (MPa)
Open Ended
Bull Plugged
Open Ended
Bull Plugged
12.25 - 12.5 12.00(30.48)
3.50(8.89)
132.29(336.01)
127.29(323.32)
1,204,766 (546 472)
1,000,000(453 592)
18,651(128.59)
11,963(82.48)
17,063(117.65)
11,345(78.22)
*The values of tensile, burst, and collapse strength are calculated with new tool conditions, Lame's formulas with Von-Mise's Distortion Energy Theory for burst and collapse strength, and stress area calculations for tensile strength. These ratings are guidelines only. For more information, consult your local Halliburton representative.
Retrievable Service Tools 2-29
Retrievable
ServiceT
ools
PinPoint Injection (PPI) Packer
The PinPoint Injection (PPI) packer is a
retrievable, treating, straddle packer
that features 1-ft spacing between
packer elements. This spacing helps to
ensure that the maximum number of
perforations within a long producing
interval can be broken down to accept
stimulation fluids uniformly. Once the
entire zone has been broken down
individually, a massive treatment can be
performed more effectively.
During assembly, the PPI packer
conversion kit is installed between the
RTTS® hydraulic slip body and the
RTTS packer mandrel. This kit contains
all parts required to convert an RTTS
packer to a PPI packer except RTTS
packer rings and the spacer ring
required for the upper packer element.
Adapters are provided to run 2 7/8-in.
(7.00 cm) EU tubing for spacer if
intervals greater than 1 ft (30.48 cm)
are required.
A typical PPI packer toolstring consists
of the following tools (top to bottom):
1. RFC® retrievable fluid control valve
2. RTTS circulating valve
3. PPI packer
4. Collar locator
The PPI packer has a straight J-slot
drag block body. The collar locator, if
used, can be run either above or below
the PPI packer. The RFC valve retains
acid used to break down perforations in
the tubing as the PPI packer is moved
to the next setting point.
Fluid passage through the center of the
bottom packer is closed off with the
retrievable plug or ball included in the
conversion kit. The retrievable plug or
ball can be run in place with the PPI
packer or can be dropped from the
surface after the tools have been run in.
After the RFC valve is removed, the
retrievable plug passes through the
RFC valve seats. If a ball is used, it must
be reversed out or brought out with
the toolstring.
Features and Benefits
• 1-ft (30.48-cm) spacing exists
between packer elements; 6-in.
(15.24-cm) spacing is available in
4 1/2-, 5 1/2-, and 7-in. sizes.
• RTTS packer reliability is built into
the PPI packer.
• The bypass valve closes when weight
is applied to set the packers.
• The bypass valve opens to equalize
pressure across the bottom packer
element as the packer is raised to
another setting location.
• Adapters allow for spacing intervals
greater than 1 ft.
• The packer provides more thorough
stimulation of the producing interval.
• The tool allows for collection of more
detailed formation data for planning
the main treatment.
• Treatments can be performed
through the same tool with one trip
in the hole.
HA
L1
20
36
PinPoint Injection
(PPI) Packer
2-30 Retrievable Service Tools
Retrievable
ServiceT
ools
Operation
The tool is run slightly below the required setting position to
set the packer and is then picked up and rotated several turns.
If the tool is on the bottom, only a quarter-turn is required.
However, in deep or deviated holes, several turns with the
rotary could be necessary. Once the setting position is
established, right-hand torque is held until the mechanical
slips on the tool are set and can start taking weight.
After the tools are run in the well and bottom perforations
are located, the retrievable plug or ball and the
RFC® III valve (if not run in with the tools) are dropped.
The lowest perforations are straddled, broken down, and
injected with treatment fluid. As the packer is moved up
the casing, the operator selectively straddles each set of
perforations in 1-ft intervals. The bypass is opened to allow
pressure to equalize across the bottom packer. Usually 1 bbl
of acid is injected in each set of perforations. If perforations
communicate above the top of the packer before 1 bbl of
acid is displaced, injection is stopped, the packer is moved,
and the excess is injected into the next set of perforations.
PinPoint Injection (PPI) Packer
Casing Sizein.
Packer Main Body OD in. (cm)
Packer ID in. (cm)
End Connections
Nominal Casing
Weight lb/ft
Minimum Casing ID in. (cm)
Maximum Casing ID in. (cm)
Length in. (cm)
Tensile Rating* lb (kg)
Burst Rating*
psi (MPa)
Collapse Rating*
psi (MPa)
4 3.18(8.08)
.805(2.04)
2 11/16 in. 10 UNS × 2 3/8 in. 8 Rd EU 9.5 - 11.6 3.428
(8.71)3.548(9.01)
68.70(174.50)
74,000(33 566)
10,000(68.95)
15,000(103.42)
4 1/2
3.89(9.88)
1.50(3.81)
3 3/32 in. 10 UNS × 2 3/8 in. 8 Rd EU 9.5 4.090
(10.39)4.154
(10.55)69.91
(177.57)77,100
(34 972)14,400(99.28)
10,200(70.33)
3.75(9.53)
1.50 (3.81)
3 3/32 in. 10 UNS × 2 3/8 in. 8 Rd EU 11.6 - 13.5 3.920
(9.96)4.000
(10.16)69.91
(177.57)77,100
(34 972)14,400(99.28)
10,200(70.33)
5
4.25(10.79)
1.50 (3.81)
3 3/32 in. 10 UNS × 2 7/8 in. 8 Rd EU 11.5 - 13 4.494
(11.42)4.670
(11.86)66.13
(167.97)84,700
(38 419)12,900(88.94)
9,800(67.57)
4.06(10.31)
1.50(3.81)
3 3/32 in. 10 UNS × 2 7/8 in. 8 Rd EU 15 - 18 4.276
(10.86)4.408
(11.20)66.39
(168.63)84,700
(38 419)10,800(74.46)
9,800(67.57)
3.89(9.88)
1.50(3.81)
3 3/32 in. 10 UNS × 2 3/8 in. 8 Rd EU 21.4 4.090
(10.39)4.154
(10.55)69.91
(177.57)77,100
(34 972)14,400(99.28)
10,200(70.33)
5 1/2
4.55(11.56)
1.50 (3.81)
3 1/2 in. 8 UNS × 2 7/8 in. 8 Rd EU 13 - 20 4.778
(12.14)5.044
(12.81)66.52
(168.96)133,200(60 419)
14,500(99.97)
11,600(79.98)
4.25(10.79)
1.50 (3.81)
3 3/32 in. 10 UNS × 2 7/8 in. 8 Rd EU 11.5 - 13 4.494
(11.42)4.670
(11.86)66.13
(167.97)84,700
(38 419)12,900(88.94)
9,800(67.57)
6 5/8 5.65(14.35)
1.50 (3.81)
4 5/32 in. 8 UNS × 2 7/8 in. 8 Rd EU 17 - 20 5.920
(15.04)6.538
(16.61)73.06
(185.57)158,200(71 758)
15,300(105.49)
10,100(69.64)
7 5.65(14.35)
1.50 (3.81)
4 5/32 in. 8 UNS ×2 7/8 in. 8 Rd EU 17 - 38 5.920
(15.04)6.538
(16.61)73.06
(185.57)158,200(71 758)
15,300(105.49)
10,100(69.64)
7 5/8 6.35(16.13)
1.50 (3.81)
4 5/32 in. 8 UNS ×2 7/8 in. 8 Rd EU 20 - 39 6.625
(16.83)7.125
(18.10)73.06
(185.57)158,200(71 758)
12,600(86.87)
10,100(69.64)
8 5/8 7.31(18.57)
1.50(3.81) 4 1/2 in. API IF TJ 24 - 49 7.511
(19.08)8.097
(20.57)110.77
(281.36)237,200
(107 592)13,500(93.08)
9,700(66.88)
9 5/8 8.15(20.7)
1.50(3.81) 4 1/2 in. API IF TJ 29.3 - 53.5 8.535
(21.68)9.063
(23.02)111.07
(282.12)444,600
(201 667)13,500(93.08)
10,100(69.64)
*The values of tensile, burst, and collapse strength are calculated with new tool conditions, Lame's formulas with Von-Mise's Distortion Energy Theory for burst and collapse strength, and stress area calculations for tensile strength. These ratings are guidelines only. For more information, consult your local Halliburton representative.
Retrievable Service Tools 2-31
Retrievable
ServiceT
ools
Selective Injection Packer (SIP) Tool
The selective injection packer (SIP) tool has opposing cups
that isolate perforations for chemical treatments or
perforation washing. Normal spacing between the cups is
1 ft; however, spacing can be expanded if required.
Some methods, such as a ball-and-seat or ball valve, must be
used to close off the center opening below the tool and force
treating or washing fluid through ports between the cups.
A concentric bypass built into the SIP tool allows pressure to
equalize from the annulus above to the annulus below the
bottom cup. Fluid goes through the bypass, under the tool,
and can push the ball up.
Circulating valves have been designed especially for use with
SIP tools. These ball-drop valves require approximately
1,350 psi (93.08 MPa) pressure to open.
A basic SIP toolstring consists of the following items (bottom
to top):
• A ball-and-seat arrangement or optional ball valves that
close off the bottom of the tubing below the SIP tool
assembly
• The SIP tool assembly
• A reversing valve that drains the tubing when tools are
removed from the well (either a ball-drop circulating valve
or an RTTS®-type circulating valve)
• A treating packer and/or RFC® III valve, either of which is
useful in chemical treatment processes
HA
L1
20
49
Selective Injection Packer
2-32 Retrievable Service Tools
Retrievable
ServiceT
ools
Selective Injection Packer (SIP) Tool
Casing Size in.
Casing Weight
lb/ft
IDin. (cm)
Cup ODin. (cm)
Packer Rings* OD
in. (cm)
3 1/29.20 2.992 (7.60)
3.03 (7.70) 2.62 (6.65)10.20 2.992 (7.60)
4 1/2
9.50 4.090 (10.39)
4.10 (10.41) 3.78 (9.60)10.50 4.052 (10.29)
11.60 4.000 (10.16)
13.50 3.920 (9.96)3.95 (10.03) 3.62 (9.19)
15.10 3.826 (9.72)
5
11.50 4.560 (11.58)4.60 (11.68) 4.25 (10.79)
13.00 4.494 (11.41)
15.00 4.408 (11.20)4.45 (11.30)4.31 (10.95)
4.00 (10.16)3.90 (9.91)18.00 4.276 (10.86)
21.00 4.154 (10.55)
5 1/2
15.50 4.950 (12.57)4.98 (12.65) 4.62 (11.73)
17.00 4.892 (12.43)
20.00 4.778 (12.14)4.81 (12.22) 4.42 (11.23)
23.00 4.670 (11.86)
13.00 5.044 (12.81)5.04 (12.80) 4.60 (11.68)
14.00 5.012 (12.73)
15.50 4.950 (12.57)4.98 (12.65) 4.60 (11.68)
17.00 4.892 (12.43)
20.00 4.778 (12.14) 4.808 (12.21) 4.60 (11.68)
7
17.00 6.538 (16.61)6.578 (16.71) 6.00 (15.24)
20.00 6.456 (16.40)
23.00 6.366 (16.17) 6.416 (16.30) 6.00 (15.24)
26.00 6.276 (15.94)6.306 (16.02) 5.75 (14.60)
29.00 6.184 (15.71)
32.00 6.094 (15.48)
6.124 (15.55) 5.65 (14.35)35.00 6.004 (15.25)
38.00 5.920 (15.04)
7 5/8
26.40 6.969 (17.70) 7.055 (17.92) 6.50 (16.51)
29.70 6.875 (17.46)6.905 (17.54) 6.35 (16.13)
33.70 6.675 (16.95)
39.00 6.625 (16.83) 6.655 (16.90) 6.20 (15.75)
9 5/8
29.30 9.063 (23.02)9.113 (23.15) 8.50 (21.59)
32.30 9.001 (22.86)
36.00 8.921 (22.66)8.951 (22.74) 8.50 (21.59)
40.00 8.835 (22.44)
43.50 8.755 (22.24)8.785 (22.31) 8.18 (20.78)
47.00 8.681 (22.05)
*Two requiredThese ratings are guidelines only. For more information, consult your local Halliburton representative.
Retrievable Service Tools 2-33
Retrievable
ServiceT
ools
RFC® III Valve
The RFC® III valve (retrievable fluid-control valve) controls
the amount of fluid pumped into a formation, allowing
treatment of a completed well without the tubing being
pulled. The valve is preset to operate at a specific pressure and
allows precise amounts of fluid to be pumped through tubing
into a formation.
The RFC III valve may be used for a variety of purposes
including:
• Scale removal
• Chemical treatment
• Acidizing with jet tools on long openhole intervals or
multiple sets of perforations.
Features and Benefits
• Stacking springs in parallel allows for a full range of
closing pressures from 1,500 to 7,100 psi.
• A hardened ball and seat to minimize fluid cutting issues
with traditional types of valves.
• The RFC valve can be run into a well without the tubing
being pulled.
• It can be run in and retrieved on a sandline, or it can be
dropped in the tubing.
• If the shoe and the seal ring are changed, one tool can be
used in either 2 3/8-in. EUE or 2 7/8-in. EUE tubing.
• When used in low fluid-level wells, the RFC III valve keeps
expensive chemicals in place in the tubing.
• It can be used to wash openhole sections below the tubing.
• The valve allows removal of the final displacement fluid
after a treating job without subjecting the formation to the
displacement fluid.
• An adjustable operating pressure feature in the tool allows
controlled opening for various depths and fluid weights.
• It can be used separately or in conjunction with packers or
Hydra-Jet™ tools.
• Should scale or other downhole conditions cause difficulty
with the tool, it can be removed and replaced without the
tubing string being pulled.
HA
L1
20
37
RFC® IIIValve
2-34 Retrievable Service Tools
Retrievable
ServiceT
ools
RFC® III Valve
Casing Sizein.
Main BodyOD
in. (cm)
Retrieving Head OD in. (cm)
Length
No Auxiliary Spring Assemblies
in. (cm)
One Auxiliary Spring Assemblyin. (cm)
Two Auxiliary Spring Assemblies
in. (cm)
2 3/8 - 2 7/8 1.52(3.86)
.625(1.59)
46.08 (117.04)
58.28(148.03)
70.48(179.02)
These ratings are guidelines only. For more information, consult your local Halliburton representative.
Retrievable Service Tools 2-35
Retrievable
ServiceT
ools
Removable Fracturing Liner
Halliburton’s removable fracturing liner
is a unique concept in tool design and
function. It is designed to help isolate,
straddle, blank-off, and contain one or
more sets of casing perforations so that
treating or stimulation fluids may be
diverted to other open perforations
either above or below the tool. The
advantages of this versatile tool are:
• The liner, even with 200 to 300 ft or
more of spacer, is easy to run, set, and
retrieve—saves rig time and helps
reduce well preparation expense.
• The liner provides a rapid and
efficient method of temporarily
sealing off perforations for multiple
zone stimulation programs.
• The liner may be used under most
conditions to fracture, treat, or
production test two or more zones
selectively without the aid of a bridge
plug and/or packer.
• Liner, spacer, and auxiliary setting
tools have an unrestricted ID which
permits high injection rates down
casing, annulus, and tubing with very
little friction loss through tool.
• The liner permits down-casing
treatment of multiple zones, often
needs no additional pack-off, and
runs on tubing or drillpipe.
The Halliburton removable fracturing
liner consists of three sections: an
upper sealing element, long standard
OD tubular spacer, and a lower sealing
element. Both the upper and lower
sections are equipped with two flexible
swab-type cups mounted back-to-back
in such a manner that one or the other
functions as a packer which provides a
seal when a pressure differential exists
across the tool section.
The upper sealing section is equipped
with a drag spring assembly and a J-slot
locking and setting arrangement that is
attached to heavy duty slips which
support the liner assembly while it
straddles the perforated section that is
to be temporarily isolated. The upper
and lower sections are separated by the
straddling spacer. The length of the
spacer is not critical but should be
chosen so that it will adequately
straddle the perforations to be blanked
off in the well with sufficient overlap
that will allow both upper and lower
sections of the tool to be in contact with
good sound casing. In addition, the
liner tool is equipped with a pressure
equalization port between the upper
and lower sets of cups. The port
functions with the setting mechanism;
it is open while the tool is being run,
closed when the liner is set across the
perforations, and is reopened when the
liner is unseated for removal. The liner
may be set on tubing or drillpipe by
means of a setting retrieval adapter.
Upon reaching the setting depth, the
tubing is rotated with right-hand
torque, and slack-off weight is applied
to release the slips and allow them to
move outward and contact the wall of
the casing. The adapter is provided with
a full-bore opening. The adapter, after it
is disengaged from the top section of
the liner, will permit fracturing or
stimulation operations to be conducted
through both annulus and tubing
string. However, if another tool such as
a packer or other service work is
required up the hole, or it is desired to
fracture through the casing, the tubing
may be removed from the well without
disturbing the liner.
HA
L1
55
73
RemovableFracturing Liner
2-36 Retrievable Service Tools
Retrievable
ServiceT
ools
After the removable fracturing liner has served its purpose, it
may be withdrawn by using the tubing or drillpipe string
equipped with the setting retrieving adapter. The adapter is
designed to automatically latch into the upper section of the
liner while simultaneously equalizing the pressure above,
below, and between the sealing cups. After latching, left-hand
torque will release the slips and permit removal of the liner
from the well.
Where pressure limitations of the casing and anticipated
breakdown pressures of the formation are critical, the liner
may be used in conjunction with other service tools such as
packers, bridge plugs, etc.
Removable Fracturing Liner
Tool Size in.
Spacer
OD in. (mm)
ID in. (mm)
4 1/2 2 7/8(72.9)
2.44(62)
5 1/2 3 1/2(88.9)
3.00(76.2)
7 5(127)
4.50(114.3)
Straddle and IsolateLower Zone WhileTreating or Testing anUpper Zone
High Pressure Zone
Low Pressure Zone
Straddle and Isolatea High PressureZone While Treatinga Low PressureZone at Lower Depth
High Pressure Zone
Low Pressure Zone
Straddle and Isolatea Low Pressure ZoneWhile Treating a HighPressure Zone atLower Depth
Low Pressure Zone
High Pressure Zone
HA
L1
60
36
Retrievable Service Tools 2-37
Retrievable
ServiceT
ools
2-38 Retrievable Service Tools