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Retrievable Service Tools

Retrievable Service Tools This 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

CHAMP® IV Packer

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.

2-2

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 righthand 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.

HAL12025

Retrievable Service Tools

The CHAMP® IV packer is a hookwallretrievable 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.

CHAMP® IV Packer

Retrievable Service Tools

CHAMP® IV Retrievable Packer Packer OD in. (cm)

Packer ID in. (cm)

End Connections

Nominal Casing Weight lb/ft

3.87 (9.83)

1.80 (4.57)

2 3/8 EU

9.5 - 10.5

4.052 (10.29)

3.75 (9.52)

1.80 (4.57)

2 3/8 EU

11.6 - 13.5

3.98 (10.11)

1.80 (4.57)

2 3/8 8 Rd EU

4.18 (10.61)

1.80 (4.57)

4.55 (11.56)

Minimum Maximum Casing ID Casing ID in. (cm) in. (cm)

Length in. (cm)

Tensile Rating* lb (kg)

Working Pressure psi (MPa)

4.090 (10.39)

100.10 (254.25)

71,200 (32 300)

3.920 (9.95)

4.000 (10.16)

100.10 (254.25)

18 - 20.8

4.156 (10.56)

4.276 (10.86)

2 3/8 8 Rd EU

11.5 - 15

4.408 (11.20)

2.00 (5.08)

2 3/8 EU

13 - 20

4.40 (11.18)

1.80 (4.57)

2 3/8 EU

6 5/8 or 7

5.25 (13.34)

2.00 (5.08)

7

5.65 (14.35)

Burst Pressure* psi (MPa)

Collapse Rating* psi (MPa)

Open Ended

Bull Plugged

Open Ended

Bull Plugged

8,400 (57.92)

10,000 (68.95)

10,000 (68.95)

8,500 (58.61)

8,500 (58.61)

71,200 (32 300)

8,400 (57.92)

10,000 (68.95)

10,000 (68.95)

8,500 (58.61)

8,500 (58.61)

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)

4.560 (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)

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)

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)

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)

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)

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)

4 1/2

5

5 1/2

7 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)

7 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)

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)

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)

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)

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)

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)

8 5/8

9 5/8

10 3/4

11 3/4

13 3/8

Note: Although other sizes may be available, these sizes are the most common. *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

2-3

Retrievable Service Tools

Casing Size in.

CHAMP® IV Non-Rotational Retrievable Packer

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

HAL31838

Retrievable Service Tools

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 Jslot. 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-inhole (RIH) position to the set and pullout-of-hole (POOH) positions simply by lifting or lowering the drillpipe or tubing in the wellbore.

CHAMP® IV Non-Rotational Retrievable Packer

2-4

Retrievable Service Tools

Operation

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 Casing Size in.

Packer 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)

Working Pressure* psi (MPa)

Burst Pressure* psi (MPa)

Collapse Rating* psi (MPa)

5.65 (14.35)

2.37 (6.02)

2 7/8 EUE 3 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 CAS Box × 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)

8.25 (20.96)

2.87 (7.28)

4 1/2 IF Box × 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)

7

9 5/8

*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 Service Tools

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.

CHAMP® V 15K Packer

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.

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

HAL15506

Retrievable Service Tools

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.

• Compatible with other tools— can be run with bridge plugs and drillable tools

CHAMP® V 15K Packer

The CHAMP V 15K packer is ideally suited for horizontal applications due to its limited rotational requirements and integrated bypass valve. Just a quarterturn 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.

2-6

Retrievable Service Tools

Operation 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 Nominal Casing Weight lb/ft

Minimum Casing ID in. (cm)

Maximum Casing ID in. (cm)

Length in. (cm)

3 7/8 CAS

29 - 35

6.004 (15.25)

6.201 (15.75)

2.25 (5.72)

3 7/8 CAS

47.1 - 51.2

6.251 (15.88)

2.25 (5.72)

3 7/8 CAS

39 - 42.8

6.501 (16.51)

Casing Size in.

Packer OD in. (cm)

Packer ID in. (cm)

End Connections

7

5.75 (14.61)

2.25 (5.72)

6.00 (15.24) 6.25 (15.88)

Tensile Rating* lb (kg)

Working Pressure* psi (MPa)

126.94 (322.43)

163,330 (74 085)

6.375 (16.19)

126.94 (322.43)

6.625 (16.83)

126.94 (322.43)

Burst Pressure* psi (MPa)

Collapse Rating* psi (MPa)

Open Ended

Bull Plugged

Open Ended

Bull Plugged

15,000 (103.42)

16,200 (111.69)

16,200 (111.69)

15,000 (103.42)

15,000 (103.42)

163,330 (74 085)

15,000 (103.42)

16,200 (111.69)

16,200 (111.69)

15,000 (103.42)

15,000 (103.42)

163,330 (74 085)

15,000 (103.42)

16,200 (111.69)

16,200 (111.69)

15,000 (103.42)

15,000 (103.42)

7 5/8

Note: Although other sizes may be available, these sizes are the most common. *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

2-7

Retrievable Service Tools

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.

CHAMP® V 15K Non-Rotational Retrievable Packer

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

HAL19242

Retrievable Service Tools

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.

CHAMP® V 15K Non-Rotational Retrievable Packer

2-8

Retrievable Service Tools

Operation

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 Nominal Casing Weight lb/ft

Minimum Casing ID in. (cm)

Maximum Casing ID in. (cm)

Length in. (cm)

3 7/8 CAS (Box) 2 7/8 EUE (Pin)

29 - 35

6.004 (15.25)

6.184 (15.71)

3 7/8 CAS (Box) 3 1/2 IF (Pin)

29.7 - 39

6.625 (16.83)

6.875 (17.46)

Casing Size in.

Packer OD in. (cm)

Packer ID in. (cm)

End Connections

7

5.75 (14.60)

2.00 (5.08)

7 5/8

6.62 (16.18)

2.25 (5.72)

Tensile Rating* lb (kg)

Working Pressure* psi (MPa)

163.84 (416.15)

150,000 (68 038)

163.54 (415.39)

150,000 (68 038)

Burst Pressure* psi (MPa)

Collapse Rating* psi (MPa)

Open Ended

Bull Plugged

Open Ended

Bull Plugged

15,000 (103.42)

16,217 (111.81)

12,603 (86.89)

15,014 (103.51)

11,839 (81.62)

15,000 (103.42)

15,000 (103.42)

11,000 (75.84)

15,000 (103.42)

12,000 (82.74)

Note: Although other sizes may be available, these sizes are the most common. *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

2-9

Retrievable Service Tools

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.

RTTS® Packer • 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.

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.

• 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.

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.

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.

HAL12026

Retrievable Service Tools

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.

RTTS® Packer

• The packer can be set and relocated as many times as necessary with simple tubing manipulation.

2-10

Retrievable Service Tools

RTTS® Retrievable Packer

2 3/8

Packer Main Body OD in. (cm)

Packer ID in. (cm)

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)

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)

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)

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)

2.7 (6.86)

0.62 (1.57)

1 7/8 OD 12 UNS EU × 1.315 10 Rd

9.2 - 10.2

2.5 (6.35)

0.62 (1.57)

1 7/8 OD 12 UNS EU × 1.315 10 Rd

3.18 (8.08)

1.12 (2.84)

3.06 (7.77)

End Connections

Nominal Casing Weight lb/ft

Minimum Casing ID in. (mm)

Maximum Casing ID in. (mm)

Length in. (cm)

Tensile Rating* lb (kg)

Working Pressure psi (MPa)

Burst Rating* psi (MPa)

Collapse Rating* psi (MPa)

Open Ended

Bull Plugged

Open Ended

Bull Plugged

10,000 (68.95)

21,900 (151.00)

11,300 (77.91)

16,900 (116.52)

10,600 (73.08)

38,300 (17 373)

10,000 (68.95)

4,600 (31.72)

4,600 (31.72)

15,200 (104.80)

6,000 (41.36)

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)

3.188 (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)

2.66 (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)

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)

2 11/16 10 UNS × 2 3/8 8 Rd EU

9.5 - 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)

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)

3.89 (9.88)

1.8 (4.57)

3 3/32 10 UNS × 2 3/8 8 Rd EU

9.5

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)

4.25 (10.79)

1.8 (4.57)

3 3/32 10 UNS × 2 7/8 8 Rd EU

11.5 - 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 EU

15 - 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 EU

21.4

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 EU

23.2

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)

2 7/8

3 1/2

4

4 1/2

5

Retrievable Service Tools

2-11

Retrievable Service Tools

Casing Size in.

RTTS® Retrievable Packer

Retrievable Service Tools

Casing Size in.

Packer Main Body OD in. (cm)

Packer ID in. (cm)

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)

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)

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)

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)

5.06 (12.85)

1.9 (4.83)

3 1/2 8 UNS × 2 7/8 8 Rd EU

15 - 23

4.89 (12.42)

1.9 (4.83)

3 1/2 8 UNS × 2 7/8 8 Rd EU

5.65 (14.35)

2.37 (6.02)

5.43 (13.79)

End Connections

Nominal Casing Weight lb/ft

Minimum Casing ID in. (mm)

Maximum Casing ID in. (mm)

Length in. (cm)

Tensile Rating* lb (kg)

Working Pressure psi (MPa)

Burst Rating* psi (MPa)

Collapse Rating* psi (MPa)

Open Ended

Bull Plugged

Open Ended

Bull Plugged

10,000 (68.95)

14,500 (99.97)

7,100 (48.95)

11,600 (79.98)

4,000 (27.57)

84,700 (38 419)

10,000 (68.95)

12,300 (84.81)

5,200 (35.85)

9,800 (67.57)

700 (4.82)

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)

5.365 (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)

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)

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)

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)

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)

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)

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 IF

33.2 - 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)

8.15 (20.7)

3.75 (9.53)

4 1/2 API IF TJ

29.3 53.5

8.535 (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)

5 1/2

5 3/4

6

6 5/8

7

7 5/8

9 5/8

2-12

Retrievable Service Tools

RTTS® Retrievable Packer

10 3/4

Packer Main Body OD in. (cm)

Packer ID in. (cm)

9.3 (23.62)

3.75 (9.53)

4 1/2 API IF TJ

32.75 55.5

9.760 (247.90)

10.192 (258.88)

90.83 (230.71)

444,600 (201 667)

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)

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)

10.2 (25.91)

3.75 (9.53)

4 1/2 API IF TJ

38 - 54

10.880 (276.35)

10.1 (25.65)

3.75 (9.53)

4 1/2 API IF TJ

60 - 71

11.05 (28.07)

3.75 (9.53)

4 1/2 API IF TJ

11.94 (30.33)

3.75 (9.53)

11.5 (29.21)

End Connections

Nominal Casing Weight lb/ft

Minimum Casing ID in. (mm)

Maximum Casing ID in. (mm)

Length in. (cm)

Tensile Rating* lb (kg)

Working Pressure psi (MPa)

Burst Rating* psi (MPa)

Collapse Rating* psi (MPa)

Open Ended

Bull Plugged

Open Ended

Bull Plugged

5,000 (34.47)

13,500 (93.08)

10,800 (74.46)

10,100 (69.64)

10,300 (71.01)

444,600 (201 667)

5,000 (34.47)

13,500 (93.08)

10,800 (74.46)

10,100 (69.64)

10,300 (71.01)

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)

11.150 (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)

10.586 (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)

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)

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)

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)

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)

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)

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)

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)

11 3/4

12 3/4

13 3/8

14

16

18 5/8

20

Retrievable Service Tools

2-13

Retrievable Service Tools

Casing Size in.

RTTS® Circulating Valve

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 lockedopen position. The J-slot in the packer-body drag block (or drag sleeve) must also be placed in the unset position.

HAL12027

Retrievable Service Tools

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.

RTTS® Circulating Valve

When the circulating valve is opened to come out of the hole, the tubing is lowered, turned to the right, and picked up.

2-14

Retrievable Service Tools

RTTS® Circulating Valve Tensile Rating* Burst Rating* lb (kg) psi (MPa)

Collapse Rating* psi (MPa)

OD in. (cm)

ID in. (cm)

End Connections

Length in. (cm)

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 Rd 1.875 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 Rd 1.875 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 EU 2.688 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 EU 3.094 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 EU 3 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 EU 4.156 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)

Retrievable Service Tools

Size in.

*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

RTTS® Safety Joint

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. HAL12029

Retrievable Service Tools

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.

RTTS® Safety Joint

2-16

Retrievable Service Tools

RTTS® Safety Joint OD in. (cm)

ID in. (cm)

End Connections

Length in. (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 EU 2 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)

Retrievable Service Tools

Size in.

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 VonMise'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

Isolator® Retrievable Bridge Plug

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.

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

Applications

• Slips protected from debris below packer elements

Run as a barrier for:

• Built-in concentric bypass

• Temporary abandonment • Change of wellhead/wireline valves • Zonal isolation • Pressure testing in conjunction with retrievable packers • Can also be run as a retrievable packer

• 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

HAL12052

Retrievable Service Tools

The Isolator® retrievable bridge plug (RBP) consists of packer-type sealing elements, mechanical slips, and a ball valve section.

Isolator® Retrievable Bridge Plug

2-18

Retrievable Service Tools

Operation

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 Size in.

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)

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)

10 3/4

*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 Service Tools

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 lefthand rotation is maintained.

Model 3L Retrievable Bridge Plug

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.

2-20

HAL12030

Retrievable Service Tools

The Model 3L retrievable bridge plug consists of packer-type sealing elements, mechanical slips, and a large-area bypass.

Model 3L Retrievable Bridge Plug

Retrievable Service Tools

Model 3L Retrievable Bridge Plug Bridge Plug Main Body OD 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)

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)

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)

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)

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)

5

5 1/2

10 3/4

*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 Service Tools

Casing Size in.

Versa-Set® Retrievable Bridge Plug

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

Versa-Set® Retrievable Bridge Plug 3L Style Receiving Head

2-22

HAL25043

• Simple operation and maintenance

HAL25042

Retrievable Service Tools

The Halliburton Versa-Set® retrievable bridge plug consists of packer-type sealing elements, mechanical slips, and a large area bypass.

Versa-Set® Retrievable Bridge Plug Express Style Receiving Head

Retrievable Service Tools

Operation

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 Number

Casing Size in.

Tool OD in. (mm)

End Connections

Minimum Casing ID in. (cm)

Maximum Casing ID in. (cm)

Tool Length in. (cm)

Tensile Rating* lb (kg)

Working Pressure* psi (MPa)

101492220 3L Head

4 1/2

3.75 (9.53)

Top 2 7/8 8 Rd Bottom 2 3/8 8 Rd

4.00 (10.16)

4.09 (10.39)

97.55 (247.80)

78,500 (36 613)

10,000 (68.95)

101492245 Express Head

4 1/2

3.75 (9.53)

Top 2 3/8 8 Rd Bottom 2 3/8 8 Rd

4.00 (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 Rd

4.78 (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

100012420 100012444

3L Overshot Running Sleeve and Shoe

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 Service Tools

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.

Subsurface Control Valve (SSC)

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.

HAL12034

Retrievable Service Tools

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.

Subsurface Control Valve (SSC)

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.

2-24

Retrievable Service Tools

Subsurface Control Valve (SSC) ID in. (cm)

End Connections

Length in. (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 Service Tools

OD in. (cm)

Subsurface Control Valve II (SSC II)

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.

HAL12053

Retrievable Service Tools

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.

Subsurface Control Valve II (SSC II)

2-26

Retrievable Service Tools

Subsurface Control Valve II (SSC II) OD in. (cm)

6.50 (16.51)

End Connections

Length in. (cm)

Tensile Rating* lb (kg)

Working Pressure* psi (MPa)

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)

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 Service Tools

4.75 (12.06)

ID in. (cm)

Subsurface Control Valve III (SSC III)

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 highstrength 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.

HAL17047

Retrievable Service Tools

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.

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

Subsurface Control Valve III (SSC III)

• 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

2-28

Retrievable Service Tools

Subsurface Control Valve III (SSC III) ID in. (cm)

End Connections

Length in. (cm)

Working Tensile Rating* lb (kg)

Working Pressure* 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)

Retrievable Service Tools

OD in. (cm)

*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)

9.1569.450

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)

Burst Rating* psi (MPa)

Collapse Rating* psi (MPa)

Open Ended

Bull Plugged

Open Ended

Bull Plugged

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)

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)

Burst Rating* psi (MPa)

Collapse Rating* psi (MPa)

Open Ended

Bull Plugged

Open Ended

Bull Plugged

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

PinPoint Injection (PPI) Packer

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.

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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.

HAL12036

Retrievable Service Tools

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.

PinPoint Injection (PPI) Packer

Retrievable Service Tools

Operation

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 Size in.

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)

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)

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)

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)

4 1/2

5

5 1/2

*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

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Retrievable Service Tools

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.

Selective Injection Packer (SIP) Tool

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

HAL12049

Retrievable Service Tools

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.

Selective Injection Packer

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Retrievable Service Tools

Selective Injection Packer (SIP) Tool Casing Size in.

Casing Weight lb/ft

ID in. (cm) 2.992 (7.60) 2.992 (7.60)

4 1/2

5

5 1/2

9.50

4.090 (10.39)

10.50

4.052 (10.29)

11.60

4.000 (10.16)

13.50

3.920 (9.96)

15.10

3.826 (9.72)

11.50

4.560 (11.58)

13.00

4.494 (11.41)

15.00

4.408 (11.20)

18.00

4.276 (10.86)

21.00

4.154 (10.55)

15.50

4.950 (12.57)

17.00

4.892 (12.43)

20.00

4.778 (12.14)

23.00

4.670 (11.86)

13.00

5.044 (12.81)

14.00

5.012 (12.73)

15.50

4.950 (12.57)

17.00

4.892 (12.43)

20.00

4.778 (12.14)

17.00

6.538 (16.61)

20.00

6.456 (16.40)

23.00

6.366 (16.17)

26.00

6.276 (15.94)

29.00

6.184 (15.71)

32.00

6.094 (15.48)

35.00

6.004 (15.25)

38.00

5.920 (15.04)

26.40

6.969 (17.70)

29.70

6.875 (17.46)

33.70

6.675 (16.95)

7

7 5/8 39.00

6.625 (16.83)

29.30

9.063 (23.02)

32.30

9.001 (22.86)

36.00

8.921 (22.66)

40.00

8.835 (22.44)

43.50

8.755 (22.24)

47.00

8.681 (22.05)

9 5/8

Packer Rings* OD in. (cm)

3.03 (7.70)

2.62 (6.65)

4.10 (10.41)

3.78 (9.60)

3.95 (10.03)

3.62 (9.19)

4.60 (11.68)

4.25 (10.79)

4.45 (11.30) 4.31 (10.95)

4.00 (10.16) 3.90 (9.91)

4.98 (12.65)

4.62 (11.73)

4.81 (12.22)

4.42 (11.23)

5.04 (12.80)

4.60 (11.68)

4.98 (12.65)

4.60 (11.68)

4.808 (12.21)

4.60 (11.68)

6.578 (16.71)

6.00 (15.24)

6.416 (16.30)

6.00 (15.24)

6.306 (16.02)

5.75 (14.60)

6.124 (15.55)

5.65 (14.35)

7.055 (17.92)

6.50 (16.51)

6.905 (17.54)

6.35 (16.13)

6.655 (16.90)

6.20 (15.75)

9.113 (23.15)

8.50 (21.59)

8.951 (22.74)

8.50 (21.59)

8.785 (22.31)

8.18 (20.78)

Retrievable Service Tools

9.20 10.20

3 1/2

Cup OD in. (cm)

*Two required These ratings are guidelines only. For more information, consult your local Halliburton representative.

Retrievable Service Tools

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RFC® III Valve

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.

HAL12037

Retrievable Service Tools

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.

RFC® III Valve

• 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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Retrievable Service Tools

RFC® III Valve Length Main Body OD in. (cm)

Retrieving Head OD in. (cm)

2 3/8 - 2 7/8

1.52 (3.86)

.625 (1.59)

No Auxiliary Spring Assemblies in. (cm)

One Auxiliary Spring Assembly in. (cm)

Two Auxiliary Spring Assemblies in. (cm)

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 Service Tools

Casing Size in.

Retrievable Service Tools

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.

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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.

HAL15573

Removable Fracturing Liner

Removable Fracturing Liner

Retrievable Service Tools

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. Straddle and Isolate Lower Zone While Treating or Testing an Upper Zone High Pressure Zone

Spacer Tool Size in.

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 Isolate a High Pressure Zone While Treating a Low Pressure Zone at Lower Depth

Straddle and Isolate a Low Pressure Zone While Treating a High Pressure Zone at Lower Depth

High Pressure Zone

Low Pressure Zone

Low Pressure Zone

High Pressure Zone

HAL16036

Low Pressure Zone

Removable Fracturing Liner

Retrievable Service Tools

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.

Retrievable Service Tools

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Retrievable Service Tools

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Retrievable Service Tools