DST Tools Catalog

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Tools and Testing

Product Specification

Catalog

Halliburton Energy Services

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TTT-TD94-001 Champ

®

_Packer

TTT-TD94-002 RTTS Circulating Valve

TTT-TD94-003 RTTS Safety Joint

TTT-TD94-004 SSC Valve

TTT-TD94-005 RTTS Packer

TTT-TD94-006 SSC II Valve

TTT-TD94-007 EZ Drill

®

_{SV Squeeze Packer}

TTT-TD94-008 Ful-Flo

®

_{Hydraulic Circulating Valve}

TTT-TD94-010 Model 3L Bridge Plug

TTT-TD94-012 PPI (Pinpoint Injection) Packer

TTT-TD94-013 PR Fas-Fil Valve

TTT-TD94-014 Slip Joint

TTT-TD94-015 Big John

®

_{Hydrauclic Jar}

TTT-TD94-016 EZ Drill

®

_{Mechanical Setting Tool}

TTT-TD94-017 PR Multi-Service Valve

TTT-TD94-024 LPR N Tester Valve

TTT-TD94-025 Lubricator/Retainer Valve*

TTT-TD94-027 Subsea Test Tree*

TTT-TD94-028 TST Valve

TTT-TD94-029 EZ Drill

®

_{SVB Squeeze Packer}

TTT-TD94-032 Model 2 RTTS Packer

TTT-TD94-033 Model E SRO

TM

_{Tool System}

TTT-TD94-034 RS Valve

Tools and Testing

Product Specification Sheets

*These items are capital items. All other items are considered expensed items.

Note: This catalog in incomplete and does not contain all of the Tools and Testing Product

Specification Sheets.

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TTT-TD94-036 Rupture Disk FUL-FLO

®

_Sampler

TTT-TD94-037 Model 2 RTTS Circulating Valve

TTT-TD94-063 Wellhead Isolation Tool

TTT-TD94-064 Round Mandrel Slip Joint

TTT-TD94-073 Fasdrill Squeeze Packer and Bridge Plug

TT-221 Centrifugal Transfer Pumps*

TT-222

STE/Choke Manifold*

TT-224

STE/Indirect Fired Heaters*

TT-225

STE/Surface Test Tree*

TT-226

STE/Test Tank*

TT-227

U-Shaped Burner Boom*

TT-234

LT-20 Swivel*

TT-235

Unitest Tree Equipment

TT-236

A-Model Downhole Shut-In Tool*

TT-237

Anchor Pipe Safety Joint

TT-238

BV Retrievable Bridge Plug

TT-239

Instream Gauge Carrier

TT-240

J-Model Downhole Shut-In Tool*

TT-241

Pump-Out Disc/Reversing Valve

TT-242

Remote-Controlled Safety Valve

TT-243

Pressure-Recorder Running Cases

TT-244

VR Safety Joint

TT-245

Hollow Plug Impact Reversing Sub

*These items are capital items. All other items are expense items.

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HALLIBURTON

CHAMP

®

_PACKER

Description

The CHAMP®_{packer is a} hookwall-retriev-able packer with a concentric bypass. As it is lowered into the hole, the bypass is held open by a J-slot that also controls setting the packer. When the packer is set, the bypass is held closed by a balancing piston activated by tubing pressure.

Each tool assembly includes a J-slot mecha-nism, mechanical slips, packer elements, hydralic slips, and a bypass. Round, piston-type slips are used in the hydraulic hold-down mechanism to help prevent the tool from being pumped up the hole. The bypass allows fluids to pass around the bottom of the tool during reverse-out. This design helps eliminate problems associated with acciden-tally opening a conventional bypass during circulation around the bottom of the packer. Circulation around the CHAMP 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

• Bypass can be opened by picking straight up (no torque required)

• Easy to relocate in multiple zones in a single trip for treating, testing, or squeez-ing

• Concentric bypass valve allows larger bypass flow area.

• Used with a retrievable bridge plug to straddle zones during various operations.

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 half turn is required. However, in deep or deviated holes, several turns with the rotary may be neces-sary. To maintain position, the right-hand torque must be held until the mechanical slips on the tool are set and can start taking weight. Pressure applied below the packer forces the hydraulic hold-down slips against the casing to help prevent the packer from being pumped up the hole. A straight upward pull opens the bypass and releases the packer. The concentric bypass valve is balanced to tubing surface pressure, which helps prevent the bypass from being pumped open. Straight upward pull on the tubing string opens the bypass and unsets the packer.

CHAMP III Packer

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Casing Size† 4 1/2 in. 5 1/2 in. 7 in. 9 5/8 in. 13 3/8 in. OD in. (cm) 3.75 (9.52) 4.55 (11.56) 5.87 (14.91) 7.80 (19.81) 11.94 (30.33) ID in. (cm) 1.80 (4.57) 2.00 (5.08) 2.37 (6.02) 2.87 (7.29) 3.75 (9.52) End Connections 2 3_/

8 EUE 2 3/8 EUE 2 7/8 EUE 4 1/2 IF 4 1/2 IF

Nominal Casing Weight lb/ft 9.5 to 10.5 11.6 to 13.5 13 to 20 20 to 23 17 to 38 20.3 to 53.5 40 to 71.8 48 to 72 72 to 98 Min. Casing Drift ID in. (cm) 3.920 (9.957) 3.799 (9.649) 4.649 (11.808) 4.457 (11.321) 5.723 (14.536) 8.313 (21.115) 7.991 (20.297) 12.179 (30.935) 11.826 (30.038) Max. Casing ID in. (cm) 4.090 (10.389) 4.500 (11.430) 5.044 (12.812) 4.778 (12.136) 6.538 (16.607) 9.063 (23.020) 8.835 (22.441) 12.715 (32.296) 12.347 (31.361) Length in. (cm) 92.49 (234.92) 90.46 (229.77) 98.85 (251.08) 117.23 (297.76) 141.84 (360.27) Tensile Rating* lb (kg) 68,300 (31,000) 88,800 (40,300) 148,500 (67,300) 387,900 (175,900) 651,300 (295,400) Working Pressure** psi (kPa) 8,400 (57,900) 8,400 (57,900) 10,000 (69,000) 10,000 (69,000) 7,500 (51,700) Shipping Weight lb (kg) * 289 (131) 375 (170) 926 (420) *

† These are the most common sizes. Other sizes may be available.

* The tensile strength value is calculated with new tool conditions. Stress area calculations are used to calculate tensile strength.

** Pressure rating is defined as the differential pressure at the tool. (Differential pressure is the difference in pressure between the casing annulus and the tool ID.)

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

CHAMP IV Packer

Sales of Halliburton products and services will be in accord solely with the terms and conditions contained in the contract between Halliburton and the customer that is applicable to the sale.

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HALLIBURTON

RTTS CIRCULATING VALVE

Description

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.

• May be locked closed when packer is unset to reverse fluid around bottom of packer

• Full opening through tool 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 opera-tions, 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 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 dis-placed with cement.

The RTTS circulating valve may be run directly above the packer body or farther 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 locked position.

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

RTTS Circulating Valve

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RTTS Circulating Valve Specifications

Casing Size† 2 3/8 in. 4 1/2 to 5 in. 7 to 7 5/8 in. 8 5/8 to 13 3/8 in.

OD in. (cm) 1.68 (4.27) 3.60 (9.14) 4.87 (12.37) 6.12 (15.54) ID in. (cm) 0.68 (1.73) 1.80 (4.57) 2.37 (6.02) 3.00 (7.62)

End Connections 1.05 10 RD 2 3/8 EUE 2 7/8 EUE 4 1/2 IF

Length in. (cm) 18.42 (46.8) 32.2 (81.8) 32.9 (83.6) 38.4 (97.4) Tensile Rating* lb (kg) 32,500 (14,700) 85,700 (38,800) 142,700 (64,700) 311,400 (141,200) Burst Rating* psi (kPa) 32,000 (227,700) 16,800 (115,900) 15,200 (104,900) 18,100 (124,900) Collapse Rating* psi (kPa) 29,500 (203,500) 11,500 (79,300) 14,100 (97,300) 16,600 (114,500) Shipping Weight lb (kg) 15 (7) 59 (27) 109 (50) 195 (88)

* The values of tensile, burst, and collapse strength are calculated with new tool conditions, Lame’s formulas with Von-Mise’s Distortion Energy Theor y for burst and collapse strength, and stress area calculations for tensile strength.

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HALLIBURTON

RTTS Safety Joint

Description

The RTTS Safety Joint is an optional emer-gency backoff device. The safety joint re-leases 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.

• Positive sequence of operation helps prevent premature release

• Tools above it 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.

After the tension sleeve has parted, the safety joint is released by right-hand torque while the workstring is rotated a specified number of cycles.

RTTS Safety Joint

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RTTS Safety Joint Specifications Casing Size† 2 3/8 in. 4

1 /2 in. to 5 in. 7 in to 7 5/8 in. 8 5/8 in. to 13 3/8 in. OD in. (cm) 1.81 (4.60) 3.68 (9.35) 5.00 (12.70) 6.12 (15.54) ID in. (cm) 0.68 (1.73) 1.90 (4.83) 2.44 (6.20) 3.12 (7.92)

End Connections 1.05 10 RD 2 3/8 EUE 2 7/8 EUE 4 1/2 IF

Length in. (cm) 24.3 (61.7) 38.5 (97.8) 39.9 (101.4) 42.7 (108.5) Tensile Rating* lb (kg) 36,000 (16,300) 95,000 (43,000) 164,000 (74,000) 301,000 (136,100) Burst Rating* psi (kPa) 9,600 (66,200) 11,500 (79,000) 12,000 (82,000) 13,700 (113,000) Collapse Rating* psi (kPa) 23,200 (160,100) 11,500 (79,000) 10,900 (75,100) 10,400 (71,700) Shipping Weight lb (kg) 14 (31) 68 (31) 124 (56) 224 (102)

* The values of tensile, burst, and collapse strength are calculated using new tool conditions, Lame’s formulas with Von-Mises Distortion Energy Theory for burst and collapse strength, and stress area calculations for tensile strength.

These ratings are to be used as guidelines only. For more information, consult your local Halliburton representative.

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H A L L I B U R T O N

SSC VALVE

Description

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 equip-ment, such as blowout preventers, must be repaired. The valve eliminates 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 weight of the drillpipe. The packer seals inside the casing (surface pipe or intermedi-ate casing string) and the SSC valve seals the inside diameter of the drillpipe. Because the SSC valve includes a backoff connection, the drillpipe above it can be removed and reconnected when operations are resumed. 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.

• Saves rig time • Operates easily

• Tests blowout preventers during drilling operation

• Increases safety of rig crew

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 suffi-cient drillpipe weight below the RTTS 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 proce-dure closes the SSC valve.

After the valve is closed, the separated drillpipe can be removed from the well and the blowout preventers can be closed for temporary well abandonment.

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SSC Valve

(Subsurface Control) Specifica tions

Casing Size† 3.72 in. 4.75 in. 6.125 in. OD in. (cm) 3.72 (9.45) 4.75 (12.01) 6.25 (15.87) ID in. (cm) 1.00 (2.54) 1.25 (3.18) 2.00 (5.08) End Connections 2 7 /8 10 EUE 3 1 /2 EUE 4 1 /2 IF Le ngth in. (cm) 46.33 (117.68) 52.26 (132.74) 51.76 (131.47) Te nsile Rating* lb (kg) 218,300 (99,000) 332,600 (150,900) 598,000 (271,200)

Working Pre ssure** psi (kPa) 9,300 (64,200) 6,100 (42,100) 10,000 (69,000) Shipping Weight lb (kg) 119 (54) 210 (95) 320 (145)

** Pressure rating is defined as differential pressure at the tool. (Differential pressure is the difference in pressure between the casing annulus and the tool ID.)

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HALLIBURTON

RTTS PACKER

Description

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 mecha-nism, mechanical slips, packer elements, and hydraulic slips. Large, heavy-duty slips in the hydraulic hold-down mechanism help prevent the tool from being pumped up the hole. Drag springs operate the J-slot mecha-nism on ≤3 1_/₂_{-in. packer bodies while larger} packer sizes (≥4 in.) use drag blocks. Auto-matic 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 in the packer body. This combination eliminates the need to turn the tubing to close the circulating valve or rest the packer after the tubing has been dis-placed with cement.

• 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

• 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 half turn is required. However, in deep or deviated holes, several turns with the rotary may be neces-sary. 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, estab-lishing reverse circulation around the lower end of the packer. The circulating valve is opened for coming out of the hole when the tubing is lowered, rotated to the right, and picked up.

RTTS Packer

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RTTS Packer Specifications

Casing Size† 2 3/8 in. 5 in. 7 in. 9 5/8 in. 13 3/8 in.

OD in. (cm) 1.81 (4.60) 4.06 (10.31) 5.75 (14.61) 8.25 (20.96) 11.94 (30.33) ID in. (cm) 0.60 (1.52) 1.80 (4.57) 2.40 (6.10) 3.75 (9.52) 3.75 (9.52)

End Connections 1.05 10 RD 2 7/8 EUE 2 7/8 EUE 4 1/2 IF 4 1/2 IF

Nominal Casing Weight lb/ft 4.6 11.5 to 13 23 15 to 18 17 to 38 38 to 49.5 40 to 71.8 29.3 to 53.5 48 to 72 72 to 98 Min. Casing Drift ID in. (cm) 1.864 (4.735) 4.335 (11.011) 3.896 (9.896) 4.141 (10.518) 5.735 (14.567) 5.329 (13.536) 7.886 (20.030) 8.341 (21.186) 12.071 (30.660) 11.627 (29.533) Max. Casing ID in. (cm) 1.995 (5.067) 4.670 (11.862) 4.044 (10.272) 4.408 (11.196) 6.538 (16.607) 5.920 (15.037) 8.835 (22.441) 9.063 (23.020) 12.715 (32.296) 12.347 (31.361) Length in. (cm) 34.34 (87.22) 45.98 (116.79) 52.10 (132.33) 77.58 (197.05) 96.99 (246.35) Tensile Rating* lb (kg) 28,400 (12,900) 79,800 (36,200) 158,200 (71,700) 444,600 (201,700) 651,300 (295,400) Working Pressure** psi (kPa) 10,000 (69,000) 10,000 (69,000) 10,000 (69,000) 10,000 (69,000) 7,500 (51,700) Shipping Weight lb (kg) 35 (16) 98 (44) 216 (98) 652 (296) 1,290 (585) † These are common sizes. Available in sizes 2 3_/

8 in. to 20 in.

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H A L L I B U R T O N

SSC II VALVE

Operation

To temporarily abandon a well being drilled, it is customary to pull the drillpipe up into a stabilized section of hole or casing. An RTTS or CHAMP® _{packer is installed with an SSC II} valve above the packer. The SSC II valve is picked up to the extended position while the operator makes sure the overshot is approxi-mately in line with the groove on the retriev-ing neck.

The tools are run in the hole until the packer and SSC II valve are at a safe depth (below the mudline for storm abandonment). To set the packer, the operator picks up the toolstring, torques to the right, and slacks off. The packer supports the weight of the drillpipe below. The operator then sets 1,000 to 2,000 lb on the valve. The ball valve can then be pressure tested from the top if required.

To release from the SSC II valve, the operator picks up 1,000 lb greater than the string weight above the valve, torques to the right, and sets down until the torque is relieved and the lugs are completely disengaged. The workstring is rotated a specified number of turns to the right and picked up slowly. The retrieved drillpipe is then removed from the well and the blowout preventers are closed.

To resume normal operations, the operator makes up the overshot on the drillpipe using a centralizer assembly if necessary. The blowout preventers are then opened. Nomi-nal drillpipe weight is required above the valve to reattach the overshot during re-trieval. Sufficient pipe weight is required below the packer to set the packer elements. The pipe weight also keeps the valve open.

Description

The Sub Surface Control (SSC II) valve is a combination valve and back-off joint. This valve is used to close in a well that is being drilled without the drillpipe being pulled. This capability is especially useful in offshore operations when storms are expected or when it is necessary to work on surface equipment, such as blowout preventers. The SSC II valve eliminates the hazard of leaving pipe standing in the derrick during a storm and saves time.

A hookwall packer, such as the RTTS, is used with the SSC II valve to support the weight of the drillpipe. The packer seals inside the casing (surface pipe or intermediate casing string), and the SSC II valve uses a ball valve to seal the inside diameter of the drillpipe. Because the SSC II valve includes a back-off connection, the drillpipe above it can be removed and reconnected when operations are resumed.

• Requires only right-hand rotation to release the workstring from the valve • Requires no rotation to reattach the

workstring to the valve

• Operates easily in an emergency • Increases safety of rig crew

• Allows the operator to open and close the valve to check for pressure buildup before unsetting the packer

• Circulate large volumes of drilling fluids to recondition mud system before the packer and valve are removed and normal drilling operations are resumed.

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SSC II Valve Specifications

Casing Size† 4 3/4 in. 6 1/2 in.

OD in. (cm) 4.75 (12.06) 6.50 (16.51) ID in. (cm) 1.80 (4.57) 2.25 (5.72) End Connections 3 1 /2 IF X 4 5/32 8 UNS 4 1/2 IF Length in. (cm) 114.4 (290.5) 123.2 (313.0) Tensile Rating* lb (kg) 186,900 (84,800) 517,400 (223,700) Working Pressure** psi (kPa) 10,000 (69,000) 10,000 (69,000) Shipping Weight lb (kg) 500 (227) 827 (375)

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H A L L I B U R T O N

EZ DRILL

®

_{SV SQUEEZE PACKER}

Description

The EZ DRILL SV is a drillable packer that is primarily used for squeeze cementing It can also be used as a bridge plug or to pressure-test a workstring. The EZ DRILL SV pro-vides effective setting and sealing even under high pressures and temperatures. This tool can be run in quickly and drilled out easily.

The EZ DRILL SV squeeze packer can achieve a positive set and seal, regardless of pressure direction because the packer elements, slips, and other components are specially designed to set and seal high pressures, yet offer little resistance to drillout.

The packers’ small diameter permits them to be used in a wider range of casing sizes and weights. This feature also permits more clearance with casing ID, which lessens danger of premature setting.

The EZ DRILL SV has a sliding-sleeve valve that allows the tool to function like a bridge plug until the squeeze operation. The pressure-balanced, sliding-sleeve valve maintains squeeze pressure on the perfora-tions when closed.

Operated by pipe reciprocation, the valve seals the packer against fluid movement in either direction. Sliding the valve down to open allows fluid movement through the tool. Side ports in the tool allow unob-structed fluid flow.

EZ DRILL SV squeeze packers can be set on electric wireline. If the EZ DRILL SV me-chanical setting tool is used, the packer can be set on drillpipe or tubing.

• Controls flow and pressure differential from either direction

• Can be used to pressure-test workstring • Converts to top-drilling bridge plug • Sets mechanically or on wireline • Can be set in wider ranges of casing

grades

• Can be run in the hole quickly

Operation

When the packer is run to setting depth, the steel hose and swivel are hooked to the top of the drillpipe and circulation begins. The packer is worked up and down during circulation through the pipe or tubing to clear debris from packer and packer seat. The workstring is rotated the specified clockwise turns immediately after circulation is stopped. Right-hand rotation moves the setting sleeve downward to unlatch the lock ring and set the top packer slips.

To complete the setting procedure, a series of applied pulls and hesitations are used until the tension sleeve parts. These pulls and hesitations allow the packer rubbers to better expand and contact the casing ID.

Pressuring up to 2,000 psi below the packer as it is being set helps set the top packer slips. The pressure is released before the tension sleeve parts to prevent damage to the packer’s internal seal. After the tension sleeve parts, the maximum permissible tubing weight is applied on the packer to

help set the slips and packer element tighter. EZ DRILL SV Squeeze Packer

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The setting tool is then pulled above the packer, and the workstring is rotated to release the setting tool. The workstring can then be freely rotated as it comes out of the

hole, uninhibited by block or drag-spring interference. This feature is available on all Halliburton setting tools.

EZ DRILL®

SV

Squeeze Packer Specifications Sizes in. Casing Size in. Casing Weight lb/ft Max. Tool OD in. (cm) Min. Casing ID in. (cm) Max. Casing ID in. (cm) Length in. (cm) 3 1 /2 3 3 1/2 4 4 1 /2 Line pipe 9.20 to 10.30 16.50 to 19.00 26.50 2.69 (6.83) 2.89 (7.34) 3.24 (8.23) 33.1 (84.07) 4 1/2 4 4 1 /2 4 3/4 5 5 1 /2 Line pipe 9.50 to 13.50 16.00 20.30 to 24.20 36.40 3.66 (9.30) 3.91 (99.3) 4.18 (10.62) 25.1 (63.75) 5 1 /2 5 5 1/2 5 3 /4 7 Line pipe 13.00 to 23.00 22.50 to 25.20 64.10 4.37 (11.10) 4.67 (11.86) 5.04 (12.80) 25.4 (64.52) 7 6 6 5 /8 7 7 5 /8 7 3/4 Line pipe 17.00 to 24.00 20.00 to 38.00 45.30 to 55.30 53.52 5.50 (13.97) 5.90 (14.99) 6.46 (16.91) 31.6 (80.26) 9 5/8 9 9 5 /8 9 3 /4 9 7/8 10 3 /4 34.00 to 40.00 29.30 to 70.30 59.20 62.80 91.00 7.75 (19.69) 8.20 (20.83) 9.06 (23.01) 36.4 (92.46) 13 3/8 13 13 3 /8 13 1/2 13 5 /8 14 40.00 to 50.00 48.00 to 76.60 81.40 88.20 92.68 to 119.38 11.68 (29.67) 12.28 (31.19) 12.71 (32.28) 36.4 (92.46) 16 16 16 Line pipe 65.00 to 109.00 13.96 (35.46) 14.61 (37.11) 15.25 (38.74) 41.7 (105.92) 20 20 94.00 to 208.00 17.24 (43.79) 17.94 (45.57) 19.12 (48.56) 45.6 (115.82)

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EZ DRILL SV Squeeze Packer

with Bridging Plug * Maximum temperature and pressure capabilities shown are based on laboratory test results. These values

should not be considered as absolute when using this tool in actual service because of variations in well conditions.

These variations must be considered when using this data.

** Weight on the packer must never exceed these values. Weight on the packer includes applied string weight and any hydraulic forces applied.

NOTE: Impact loads can greatly reduce these weight ratings.

EZ DRILL® SV Squeeze Packer Pressure Specifications Maximum Recommended Pressure Differential* psi (kPa) Maximum Recommended Weight on Packer** lbm (kg) Nominal Casing Size† Maximum Recomm ended Tem perature °F (°C) Externally Applied (Across Packer Rubbers) Interally Applied (Packer Mandrel Burst) With Load Transfer Device Without Load Transfer Device 3 1 /2 4 350 (177) 10,000 (69,000) 10,000 (69,000) 30,000 (13,608) 10,000 (4,536) 4 1/2 HW 4 1 /2 5 5 1 /2 6 350 (177) 10,000 (69,000) 7,000 (48,263) 80,000 (36,287) 30,000 (13,608) 6 5 /8 7 7 5/8 350 (177) 10,000 (69,000) 8,000 (55,158) 100,000 (45,359) 40,000 (18,144) 8 5/8 350 (177) 10,000 (69,000) 8,000 (55,158) 100,000 (45,359) 40,000 (18,144) 9 5 /8 350 (177) 10,000 (69,000) 9,000 (62,052) 100,000 (45,359) 50,000 (22,680) 10 3 /4 HW 10 3 /4 11 3 /4 HW 11 3/4 300 (149) 7,500 (51,711) 9,000 (62,052) 100,000 (45,359) 50,000 (22,680) 13 3/8 HW 13 3/8 250 (121) 5,000 (34,474) 9,000 (62,052) 100,000 (45,359) 50,000 (22,680) 16 20 200 (93) 2,500 (17,237) 6,000 (41,369) 100,000 (45,359) 50,000 (22,680)

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Halliburton warrants only title to the products, supplies and materials and that the same are free from defects in workmanship and materials. THERE ARE NO

WARRANTIES, EXPRESSED OR IMPLIED OF MERCHANTABILITY, FITNESS OR OTHERWISE WHICH EXTEND BEYOND THOSE STATED IN THE IMMEDIATELY PRECEDING SENTENCE. Halliburton's liability and Customer's exclusive remedy in any cause of action (whether in contract, tort, breach of

warranty or otherwise) arising out of the sale or use of any products, supplies or materials is expressly limited to the replacement of such products, supplies or materials on their return to Halliburton or, at Halliburton's option, to the allowance to the Customer of credit for the cost of such items. ACHIEVEMENT OF

PARTICULAR RESULTS FROM THE USE OF HALLIBURTON EQUIPMENT, PRODUCTS, MATERIALS OR SERVICES IS IN NO WAY GUARANTEED. In no

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H A L L I B U R T O N

FUL-FLO

®

_{HYDRAULIC CIRCULATING VALVE}

Description

The FUL-FLO®_{hydraulic circulating valve} serves as a bypass around the packer or as a circulating valve to circulate a well after testing.

When run below a closed valve, the tool serves as a bypass around the packer and helps relieve pressure buildup below the closed valve when it is stung into a produc-tion packer.

When run above a closed valve, the tool can be used as a circulating valve when the workstring is picked up.

• Permits passage of wireline tools through full-opening bore

• Requires no pipe rotation to operate

Operation

Bypass ports close when weight is set down and reopen when weight is lifted.

A hydraulic metering system provides a 2- to 3-min delay in closing after weight is applied. This delay allows the RTTS packer to be set or the test string to be stung into a permanent packer before bypass ports close. The ports reopen without a time delay.

During stimulation work, the latching piston adds an additional downward force on the circulating sleeve to help keep the valve closed.

Operation of the valve is the same whether it is used as a circulating valve or as a bypass. No torque is required. Weight is applied to close the tool, and the workstring is picked up to reopen it.

FUL-FLO Hydraulic Circulating

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FUL-FLO® Hydraulic Circula ting Valve Specifica tions Casing Size† 3 in. 3 7

/8 in. 4 5 /8 in. 5 in. OD in. (cm) 3.06 (7.77) 3.90 (9.91) 4.68 (11.89) 5.03 (12.78) ID in. (cm) 1.25 (3.18) 1.80 (4.57) 2.25 (5.71) 2.03 (5.16)

End Conne ctions 2 3/8 EUE 2 7 /8 EUE 3 1 /2 IF 3 7/8 CAS 3 7/8 CAS Le ngth* in. (cm) 79.79 (202.67) 80.69 (204.95) 83.72 (212.65) 83.09 (211.05) Te nsile Ra ting** lb (kg) 134,000 (61,000) 164,000 (74,000) 261,000 (118,000) 261,750 (118,118) Working Pressure*** psi (kPa) 10,000 (69,000) 10,000 (69,000) 10,000 (69,000) 15,000 (103,000) Flow Area in.2 (cm2 ) 1.27 (8.19) 1.17 (7.55) 1.28 (8.26) 1.28 (8.26) Numbe r of Ports 4 6 4 4 Shipping We ight lb (kg) 140 (64) 230 (104) 348 (158) 375 (170)

† These are the most common sizes. Other sizes may be available. * Add 3.00 in. (7.52 cm) for extended length.

** The tensile strength value is calculated with new tool conditions. Stress area calculations are used to calculate tensile strength.

*** Pressure rating is defined as differential pressure at the tool. (Differential pressure is the difference in pressure between the casing annulus and the tool ID.)

These ratings are guidelines only. For more information, consult your local Halliburton representa-tive.

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H A L L I B U R T O N

MODEL 3L BRIDGE PLUG

Description

The Model 3L packer-type, retrievable bridge plug consists of packer-type sealing ele-ments, 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®_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.

● Rugged, packer-type sealing elements

● Wide range of pressure and temperature limitations

● Simple operation

Operation

The plug is run a few feet below 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 over-shot and allows the tubing to pull free. The bridge plug is retrieved by lowering the tubing until 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.

Model 3L Bridge Plug

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Model 3L Bridge Plug Specifications

Casing Size† 4 1/2 in. 5 1/2 in. 7 in. 9 5/8 in. 10 3/4 in. OD in. (cm) 3.73 (9.47) 4.60 (11.68) 5.75 (14.61) 8.15 (20.70) 9.40 (23.88) ID in. (cm) 1.25 (3.18) 1.25 (3.18) 1.25 (3.18) 2.50 (6.35) 2.50 (6.35)

End Connections 2 3/8 EUE 2 3/8 EUE 2 3/8 EUE 2 3/8 EUE 2 3/8 EUE Nominal Casing Weight lb/ft 9.5 to 13.5 13 to 20 23 17 to 38 29.3 to 53.5 55.5 to 81 32.75 to 51 Min. Casing Drift ID in. (cm) 3.791 (9.629) 4.651 (11.814) 4.398 (11.171) 5.787 (14.699) 8.240 (20.930) 9.008 (22.880) 9.503 (24.138) Max. Casing ID in. (cm) 4.090 (10.389) 5.044 (12.812) 4.670 (11.862) 6.538 (16.607) 9.063 (23.020) 9.760 (24.790) 10.192 (25.888) Length in. (cm) 109.15 (277.24) 89.43 (227.15) 89.43 (227.15) 106.18 (269.70) 106.18 (269.70) Tensile Rating* lb (kg) 65,200 (29,600) 65,200 (29,600) 65,200 (29,600) 117,700 (53,400) 117,700 (53,400) Working Pressure** psi (kPa) 10,000 (69,000) 10,000 (69,000) 10,000 (69,000) 10,000 (69,000) 7,500 (51,700) Shipping Weight lb (kg) 227 (103) 248 (112) 355 (161) 851 (386)

** Pressure rating is defined as differential pressure at the tool. (Differential pressure is the difference in pressure between the casing annulus and the tool ID.) This is the maximum recommended differential pressure across the packer elements.

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H A L L I B U R T O N

PPI (PINPOINT INJECTION) PACKER

Description

The PPI (Pinpoint Injection) packer is a retrievable, treating, straddle packer that features 1-ft spacing between packer ele-ments. This spacing helps 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. EUE} tubing for spacer if intervals greater than 1 ft are required.

A typical PPI packer toolstring could consist 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 retriev-able 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.

• 1-ft spacing exists between packer elements (6-in. spacing is available in 5 1_/

2- and 7-in. sizes)

• RTTS packer reliability built into the PPI packer

• Bypass valve closes when weight is applied to set the packers

• Bypass valve opens to equalize pressure across the bottom packer element as the packer is raised to another setting location

• Adapters allow for spacing greater than 1-ft spacing

• Packer provides more thorough stimula-tion of the producing interval

• 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

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 half turn is required. However, in deep or deviated holes, several turns with the rotary could be necessary. Once the setting position is estab-lished, right-hand torque is held until the mechanical slips on the tool are set and can start taking weight.

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After the tools are run in the well and bottom perforations are located, the retrievable plug or ball and the RFC 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 perfo-rations 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.

After all perforations have been treated, the packer is released and reset above the perforations, and the RFC valve and remov-able plug are retrieved with a sandline overshot.

The well can then be swabbed or a larger stimulation treatment can be performed. If a ball is used to blank off the bottom packer, the well can be swabbed with the ball in place.

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PPI (Pinpoint Injection) Packer Specifications

Casing Size† 4 in. 5 in. 5 1/2 in. 7 in. 9 5/8 in.

OD in. (cm) 3.18 (8.08) 4.25 (10.80) 4.55 (11.56) 5.75 (14.61) 8.25 (20.96) ID in. (cm) 0.81 (2.04) 1.50 (3.81) 1.50 (3.81) 1.50 (3.81) 1.50 (3.81)

End Connections 2 3/8 EUE 2 7/8 EUE 2 7/8 EUE 2 7/8 EUE 4 1/2 IF

Nominal Casing Weight lb/ft 9.5 to 11.6 (24.13 to 29.46) 11.5 to 13.0 (29.21 to 33.02) 13 to 20 (33.02 to 50.80) 17 to 38 (43.18 to 96.52) 29.3 to 53.5 (74.42 to 135.89) Min. Casing Drift ID in. (cm) 3.244 (8.24) 4.355 (11.062) 4.641 (11.788) 5.735 (14.567) 8.341 (21.186) Max. Casing ID in. (cm) 3.548 (9.012) 4.670 (11.862) 5.044 (12.812) 6.538 (16.607) 9.063 (23.020) Length in. (cm) 56.77 (144.20) 64.01 (162.59) 64.41 (163.60) 73.06 (185.57) 111.02 (282.00) Tensile Rating* lb (kg) 73,900 (33,500) 86,700 (39,300) 135,500 (61,500) 191,800 (87,000) 511,100 (231,800) Working Pressure** psi (kPa) 10,000 (69,000) 10,000 (69,000) 10,000 (69,000) 10,000 (69,000) 10,000 (69,000) Shipping Weight lb (kg) 140 (64) 160 (73) 170 (77) 300 (136) 787 (358)

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H A L L I B U R T O N

PR FAS-FIL VALVE

Description

The PR (pressure-responsive) FAS-FIL valve runs in the workstring with its ports open to allow the drillpipe to fill up above a closed valve.

A typical workstring for formation surging with the PR FAS-FIL valve consists of the following (from top to bottom):

1. Drillpipe to surface 2. PR FAS-FIL valve

3. PR MULTI-SERVICE valve (top) 4. Surge chamber

5. PR MULTI-SERVICE valve (lower) 6. CHAMP®_{III packer}

• Operates without pipe manipulation • Saves rig time compared to conventional

methods of filling workstring • Permits through-tubing operations

through full-opening ID

Operation

As the toolstring is run in the hole, the open ports in the PR FAS-FIL valve allow annulus fluid to fill the drillpipe. The valve is set to close at a predetermined hydrostatic pressure just before the packer reaches the required setting depth. This operating pressure can be varied depending on conditions and customer requirements.

The proper number of pins are installed in the shear set for the required operating pressure of the valve. The shear pins resist the force generated by annulus pressure acting across a differential area in the power section of the tool. When the resistant force is overcome, the pins shear, and the sealing mandrel moves upward across the ports in the ported

adapter. The ports are straddled by seals on the sealing mandrel, blocking fluid communi-cation from the annulus to the drillpipe. As the mandrel completes its upward travel, a set of locking dogs falls into position. Once the ports are closed, they cannot be opened until the tool has been redressed.

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PR FAS-FIL Valve Specifications

Casing Size 3 in. 3 7/8 in. 4 5/8 in. 6 1/8 in.

OD in. (cm) 3.06 (7.77) 3.90 (9.91) 4.68 (11.63) 6.12 (15.54) ID in. (cm) 1.00 (2.54) 1.80 (4.57) 2.25 (5.71) 3.00 (7.62)

End Connections 2 3/8 EUE 2 7/8 EUE 3 1/2 IF 4 IF

Length in. (cm) 39.2 (99.6) 39.5 (100.3) 42.7 (108.5) 43.1 (109.5) Tensile Rating* lb (kg) 160,500 (72,800) 225,100 (102,100) 284,000 (128,900) 567,000 (257,200) Burst Rating* psi (kPa) 11,700 (80,700) 8,500 (58,600) 7,600 (52,400) 16,500 (113,900) Collapse Rating* psi (kPa) 15,200 (104,900) 11,900 (82,100) 13,300 (91,800) 13,300 (91,800)

* 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.

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H A L L I B U R T O N

SLIP JOINT

Description

A slip joint accepts the movement associated with ocean heave or temperature change without allowing the movement to disturb the placement of downhole tools.

A slip joint operates by balancing its volume. As the slip joint stretches and increases its internal volume, a differential piston within the slip joint allows the same volume of fluid into the pipe. The net result is no change in internal volume.

Each slip joint has 5 ft of travel but can be combined with other slip joints to provide additional travel. An optional slip joint with 42 in. of travel is available.

When multiple slip joints are run, they are normally connected together rather than located throughout the pipe string. The number of slip joints required depends on ocean heave and the amount of expected contraction and expansion.

• Provides free travel in string to recipro-cate tools

• Provides a variable-length joint to allow expansion and contraction of pipe during testing or stimulation

• Keeps vertical movement of drilling vessel from disturbing tool placement • Helps space out the testing string when

the subsea tree is landed

Operation

The weight of the toolstring (excluding tools, anchor, and traveling blocks) is used to determine the location of the slip joint. Once the necessary packer setting weight is shown on the weight indicator, the slip joint is placed into the string.

When multiple slip joints are used, the top joint makes its complete travel, then the next joint down makes its travel, and so on. The weight indicator may show a slight bump as each slip joint reaches the end of its travel.

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Slip Joint Specifications

Casing Size† 3 in. 3 7/8 in. 5 in.

OD in. (cm) 3.06 (7.77) 3.90 (9.91) 5.03 (12.78) ID in. (cm) 1.00 (2.54) 1.80 (4.57) 2.31 (5.87) End Connections 2 3 /8 EUE 2 7 /8 EUE 3 7 /8 CAS Length in. (cm) 117.59* (298.68) 152.96 (388.52) 180.00 (457.20) Tensile Rating** lb (kg) 146,000 (66,000) 147,000 (67,000) 225,000 (102,000) Working Pressure*** psi (kPa) 10,000 (69,000) 8,000 (55,000) 15,000 (103,000) Shipping Weight lb (kg) 122 (55) 309 (140) 550 (250)

† These are the most common sizes. Other sizes may be available. * Add 42.00 in. (106.68 cm) for extended length.

***Pressure rating is defined as differential pressure at the tool. (Differential pressure is the difference in pressure between the casing annulus and the tool ID.) These ratings are guidelines only. For more information, consult your local Halliburton representative.

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H A L L I B U R T O N

Description

The BIG JOHN® _{jar is included as part of a} toolstring to help remove stuck tools. The jar helps free a stuck tool by resisting a pull on the workstring. When the workstring is stretched by the pull, tension in the jar is released and an upward impact is delivered to the stuck tool.

• Design of the hydraulic system ensures long life with little maintenance • Rig time is reduced

• Jar can be recocked rapidly • Jar time delay is adjustable

• Amount of pull to trip the jar can be varied within the limits of the time-delay system

Operation

The temporary resistance that powers the jar is provided by a hydraulic time-delay system. Resistance is released when the metering sleeve inside the jar moves into a bypass section of the outer case. This action allows the special hydraulic oil to bypass rapidly. The time delay required to release the temporary resistance varies in relation to the weight of the pull. For example, a light pull requires more time for release than a hard pull.

When tools below the jar are stuck, a steady pull applied to the jar creates an upward impact blow to the string. The jar can be recocked when the string is set down.

BIG JOHN

®

_{HYDRAULIC JAR}

BIG JOHN Hydraulic Jar

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BIG JOHN® Jar Specifications Nominal Tool Size

5 in. High-Pressure

5 in. 4 5/8 in. 3 7/8 in.

OD in. (cm) 5.03 (12.77) 5.03 (12.77) 4.63 (11.76) 3.90 (9.91) ID in. (cm) 2.00 (5.03) 2.30 (5.84) 2.25 (5.72) 1.25 (3.18)

End Connections 3 7/8 CAS

3 1/2 IF 3 7/8 CAS 3 1/2 IF 3 7/8 CAS 2 7/8 EUE 3 1/8 8 N Length* in. (cm) 62.63 (159.1) 62.98 (160.0) 60.00 (152.4) 60.00 (152.4) Tensile Rating** lb (kg) 294,000 (128,000) 226,000 (102,000) 242,000 (110,000) 190,000 (86,000) Working Pressure*** psi (kPa) 17,000 (131,000) 15,000 (103,000) 13,000 (90,000) 15,000 (103,000) Shipping Weight lb (kg) 265 (120) 192 (87) 170 (77)

* Add 10.00 in. (25.4 cm) for extended length.

*** Pressure rating is defined as the differential pressure at the tool. (Differential pressure is the difference in pressure between the casing annulus and the tool ID.)

These ratings are guidelines only. For more information, consult your local Halliburton represen-tative.

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H A L L I B U R T O N

EZ DRILL

®

_{MECHANICAL SETTING TOOL}

Description

The EZ DRILL®_{mechanical setting tool sets} and operates all EZ DRILL squeeze packers. This setting tool is run on tubing or drillpipe and is operated by workstring rotation and reciprocation.

The load transfer feature of the tool limits the amount of string weight that can be applied to the sliding valve. This feature ensures that the packer mandrel is placed in compression rather than in tension, making the tool more resistant to breakage.

• Acts as a load transfer device

• Provides positive indication when packer is set

• Allows tubing or drillpipe to be rotated as the tool comes out of the hole

Operation

The drag blocks/springs contact the well casing to restrict the rotation of the outer components while the right hand rotation of

the workstring causes the outer components to move down and begin the setting motion. The right-hand rotation unlatches the packer lock ring and sets the top slips. An upward pull on the workstring completely sets the packer and releases it from the setting tool. Additional right-hand rotation moves the setting tool’s outer components futher

downward to unlock the upper mandrel from the drag blocks, which moves the setting tool’s outer components upward. This movement allows the lower mandrel to extend down far enough to operate the squeeze packer sliding valve. The disengage-ment also causes the setting tool to become freewheeling, so the workstring can be rotated out of the hole without causing excessive wear on the setting tool drag blocks/springs.

The setting tool will not cycle again until it has been redressed with the setting sleeve properly locked in place and the keys have been returned to their grooves.

EZ DRILL SV Drag-Block Setting Tool

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EZ DRILL® Mechanical Setting Tool Specifications Casing Size† 4 1 /2 in. to 6 in. 6 5/8 in. to 8 5/8 in. 9 5/8 in. to 13 3/8 in. Maximum Tool OD Drag-Spring Type in. (cm) 4.35 (11.05) 5.53 (14.05) 7.00 (17.78) Maximum Tool OD Drag-Block Type in. (cm) 3.56 (9.04) 5.65 (14.35) Minimum Tool ID in. (cm) 0.87 (2.21) 1.13 (2.87) 1.62 (4.11) Overall Length Drag-Spring Type in. (cm) 67.57 (171.63) 71.30 (181.10) 81.91 (208.05) Overall Length Drag-Block Type in. (cm) 86.46 (219.61) 71.30 (181.10) Tensile Strength* lb 130,000 139,000 316,000

† These are common sizes. Available in 3½ in. through 20 in. sizes.

* The value of tensile strength is calculated with new tool conditions. Stress area calculations are used to calculate tensile strength.

EZ DRILL SV Drag-Spring Setting Tool

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H A L L I B U R T O N

PR MULTI-SERVICE VALVE

Description

The PR MULTI-SERVICE valve is a full-opening, annulus-pressure operated valve for use in cased holes. This tool can be run as a surge valve or backpressure valve. Top and bottom PR MULTI-SERVICE valves are run at the same time to form a surge chamber. This surge helps clean debris from the perfora-tions before a stimulation treatment, sand-control treatment, or flow test.

Potential for a sudden pressure surge is provided when two multi-service valves are spaced apart in the tubing string to form an atmospheric air chamber. When the bottom ball valve is opened, solids forced into the perforations are swept into the air chamber by the fluid stage.

• Requires no pipe manipulation to operate

• Achieves more effective surge because of the instant ball opening

• Creates the required air chamber volume by spacing valves

• Allows circulating or spotting of well fluid when surging is complete • Permits through-tubing operations

through full-opening ID

Operation

As PR MULTI-SERVICE valves are run into a well, the ball valves are in a closed position, and atmospheric air is trapped between the valves. The bottom ball valve is opened by the operating piston, which has one side exposed to the annulus pressure above the packer and the other side exposed to pressure below the packer.

After the packer has been set, pressure applied to the annulus moves the piston downward to pull the ball into the open position. The locking dogs drop into a groove, keeping the ball in the fully open position.

As long as the tubing pressure is equal to or greater than the annulus pressure, the top valve is kept closed when the lower valve is operated.

Before the top valve can be opened, tubing pressure must be relieved while the annulus pressure is maintained. The top PR MULTI-SERVICE valve also contains locking dogs that lock the ball in the fully open position. After the valves have been opened, circula-tion can occur with the packer unseated. Opening pressure is controlled by shear pins. The number and type of shear pins can be adjusted to raise or lower the operating pressure.

PR MULTI-SERVICE

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PR MULTI-SERVICE Valve Specifications Size 3 7/8 in. 4 5/8 in. 5 in.

OD in. (cm) 3.90 (9.91) 4.68 (11.89) 5.03 (12.78) ID in. (cm) 1.80 (4.57) 2.00 (5.08) 2.25 (5.72) End Connections ₂7 /8 EUE 3 7/8 TJ 3 1/2 IF 3 7/8 TJ 3 1/2 IF Length in. (cm) 49.66 (126.14) 60.25 (153.04) 59.37 (150.80) Tensile Rating* lb (kg) 229,600 (104,100) 354,100 (67,600) 341,800 (155,000) Burst Rating* psi (kPa) 8,500 (58,600) 9,800 (67,600) 8,700 (60,000) Collapse Rating* psi (kPa) 7,900 (54,500) 11,300 (78,000) 8,600 (59,300)

* 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.

PR MULTI-SERVICE

Valve, Bottom

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H A L L I B U R T O N

Description

The LPR N tester valve is a full-opening, annulus-pressure operated valve. It measures multiple closed-in pressures in cased holes where pipe manipulation is restricted and a full-opening string is required.

The nitrogen chamber is charged at the surface to a selected pressure determined by surface temperature, bottomhole tempera-ture, and bottomhole pressure.

If the intended test requires a permanent packer that uses a stinger mandrel or seal nipple, a variety of Halliburton bypass tools are available, depending on field application, to help ensure that the formations and downhole equipment are protected from excessive pressure buildup.

• The ball valve operates independently of internal pressure changes, such as with acidizing or fracturing operations. • Drastic temperature changes, such as in

acidizing operations, have little effect on the tool.

• Advanced materials and processes provide a unique metal-to-metal seat for exceptional gas-holding capabilities. • The LPR N tester valve has been through

an extensive 5-day qualification testing at 400°F and 15,000 psi burst and collapse pressures.

• An open feature allows the operator to run the LPR N tester in the hole with the ball valve opened or closed.

• Fluids can be spotted or circulated through the LPR N tester with the packer unseated.

• A double nitrogen chamber can be added to the LPR N for use in deep, hot, high-pressure wells to reduce the operating pressure.

Operation

The LPR N tester valve is composed of a ball-valve section, a power section, and a meter-ing section.

The ball-valve section seals the pressure to perform the required test. It is turned by operating arms. The power section has a floating piston that is exposed to the hydro-static pressure on one side and exposed to pressurized nitrogen on the other side. With the packer set, pump pressure applied to the annulus moves the piston downward, activates the operating arms, and opens the ball valve. When the annulus pressure is released, pressurized nitrogen returns the piston upward, closing the ball.

After the surface equipment is properly installed, the packer is set, and the rams are closed, pressure is applied to the annulus, using rig pumps to operate the LPR N tester. To begin testing, pump pressure is applied to the annulus to a predetermined pressure and held for 10 minutes to pressurize the nitrogen chamber. After pressure has been metered through the metering cartridge, pressure in the nitrogen chamber will be slightly less than combined hydrostatic and pump pressure in the annulus. This helps ensure that the ball valve stays open during testing or treating operations.

The closing force may be increased on wells with an extremely high flow rate and wells producing a large amount of sand. Before the tool is closed, the annulus pressure is

in-creased to a predetermined safe pressure LPR N Tester Valve

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circulat-ing valve and held for 10 minutes. This procedure creates additional closing force when the annulus pressure is released. Releasing the annulus pressure as quickly as possible closes the ball valve. A minimum of

10 minutes is needed to allow excess closing pressure in the nitrogen chamber to equalize before annulus pressure is reapplied. It is best to use the highest safe operating pres-sure to obtain maximum closing force.

LPR N Tester Valve OD in. (cm) 5.03 (12.78) 3.90 (9.91) 3.06 (7.77) ID in. (cm) 2.25 (5.72) 1.80 (4.57) 1.12 (2.84)

End Connections 3 7/8 CAS 2 7/8 EUE 2 1/4 CAS

Length in. (cm) 191.30 (485.90) 197.88 (502.62) 172.11 (437.16) Tensile Rating* lb (kg) 367,000 (167,000) 219,000 (99,000) 119,000 (54,000) Working Pressure** psi (kPa) 15,000 (103,000) 9,300 (64,100) 12,000 (83,000)

** Pressure rating is defined as differential pressure at the tool. (Differential pressure is the difference in pressure between the casing annulus and tool ID.)

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H A L L I B U R T O N

LUBRICATOR/RETAINER VALVE

Description

The Lubricator/Retainer is a tubing-retriev-able valve. Its function as a lubricator or retainer is determined by its placement in the subsea well-testing string. The valve is a normally open ball valve that is operated from the surface by control lines.

When used as a lubricator valve, it is in-stalled at a predetermined depth beneath the drill floor. The valve and the workstring above it serve as a lubricator for wireline tools. This installation replaces the need for surface-mounted lubricators.

In the lubricator position, the valve can also be used to prove the integrity of the lubrica-tor section by pressure testing from above. When used as a retainer valve, it is installed directly above the Subsea Test Tree (SSTT) near the ocean floor. Its primary function is to help prevent well effluents that would be trapped in the handling string if a controlled unlatch from the SSTT occurred.

In the retainer position, the valve can also be used to prove the integrity of the handling string before the well is brought on line.

• Can be used as a lubricator valve to lubricate wireline tools

• Can be used as a retainer valve to control well pressure from the handling string to the SSTT

• Holds pressure from below and selec-tively seals from above

Operation

The three hydraulic ports in the valve are the ball-control line, the ball-balance line (lock line), and the SSTT-latch line (vent line). With no pressure on the ball-control line or balance line, the ball is forced open by springs. When hydraulic pressure is applied to the ball-control line, it helps the springs keep the valve open during flow. When pressure to the ball-control line is released and pressure is applied to the ball-balance line, the operating piston is forced upward, compressing the springs and rotating the ball to the closed position.

Differential pressure directly affects the operation of the valve. Differential pressure from below causes the valve to seal without continued pressure to the ball-balance line. If a differential pressure from above the ball is applied, the balance-line pressure must be at least 60% of the pressure above the ball for the valve to hold and seal. Otherwise, the ball rotates open.

When the valve is used as a retainer valve, the third hydraulic line is attached to the SSTT latch line and to a bleed-off valve installed in the retainer valve. If the latch line is pressured to unlatch the SSTT, the bleed-off valve vents the pressure trapped between the closed retainer valve and the SSTT. This venting action facilitates unlatch-ing by relievunlatch-ing the pressure-induced load on the SSTT latch.

The lubricator/retainer valve seals are arranged so that well pressure from a leaking seal is routed to the control chamber of the

Lubricator/Retainer Valve

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pressure in the handling string from the surface all the way to the SSTT.

If one of these seals develops a leak when the valve is closed, the operating piston

un-couples from the ball mechanism at the snap ring. The ball remains closed for safety purposes. The snap ring can be resnapped when balance line pressure is applied.

Lubricator/Retainer Valve Type Lubricator Valve

Normally Open Retainer Valve Normally Open OD in. (cm) 10.75 (27.31) 10.75 (27.31) ID in. (cm) 3.00 (7.62) 2.75 (6.99) End Connections 4 1_/ 2 - 4 ACME 5 - 4 ACME Length in. (cm) 71.44 (181.46) 74.64 (189.59) Tensile Rating* lb (kg) 400,000 (181,000) 400,000 (181,000) W orking Pressure** psi (kPa) 10,000 (69,000) 15,000 (103,500) Service H2S H2S Temperature Range °F (°C) 0 to 350 (-18 to 177) 0 to 350 (-18 to 177)

** Pressure rating is defined as the differential pressure at the tool. (Differential pressure is the difference in pressure between the casing annulus and the tool ID.

These ratings are guidelines only. For more infor mation, consult your local Halliburton representative.