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Page 1: Storm Packer

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

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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

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CS

4

5

6

7

7

8

9

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1

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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

Page 4: Storm Packer

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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

Page 5: Storm Packer

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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

Page 6: Storm Packer

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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

Page 7: Storm Packer

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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

Page 8: Storm Packer

Retrievable

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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

Page 9: Storm Packer

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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

Page 10: Storm Packer

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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

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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

Page 12: Storm Packer

Retrievable

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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

Page 13: Storm Packer

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

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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

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27

RTTS®Circulating Valve

2-14 Retrievable Service Tools

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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.

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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

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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.

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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

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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.

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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

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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.

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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

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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

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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

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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.

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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

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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.

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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

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(SSC III)

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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.

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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.

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PinPoint Injection

(PPI) Packer

2-30 Retrievable Service Tools

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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.

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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

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Selective Injection Packer

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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.

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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.

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RFC® IIIValve

2-34 Retrievable Service Tools

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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.

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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.

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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

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