Halliburton Energy Services

Tools and Testing

Product Specification
Catalog
Specification Sheets

Tools and Testing

Product Specification Sheets

Table of Contents
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 SROTM Tool System
TTT-TD94-034 RS Valve
*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.

Table of Contents Continued

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.

HALLIBURTON

Description
The CHAMP packer is a hookwall-retrievable 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.

Easy to relocate in multiple zones in a

single trip for treating, testing, or squeezing

Concentric bypass valve allows larger

bypass flow area.

Used with a retrievable bridge plug to

straddle zones during various operations.

Each tool assembly includes a J-slot mechanism, mechanical slips, packer elements,
hydralic slips, and a bypass. Round, pistontype slips are used in the hydraulic holddown 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 accidentally opening a conventional bypass during
circulation around the bottom of 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 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.

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.

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.

Features and Benefits

Used in highly deviated wells or where
pipe manipulation is difficult

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.

Bypass can be opened by picking straight

up (no torque required)

CHAMP III
Packer

CHAMP PACKER

CHAMP Packer Specifications

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.)

CHAMP IV
Packer

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

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.

TTT-TD94-001

1994 Halliburton Energy Services

Printed in USA

HALLIBURTON

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.
Features and Benefits
May be locked closed when packer is
unset to reverse fluid around bottom of
packer

Full opening through tool allows tubingtype 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 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 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

RTTS CIRCULATING VALVE

RTTS Circulating Valve Specifications

3

Casing Size

2 /8 in.

4 /2 to 5 in.

7 to 7 /8 in.

8 /8 to 13 /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 /8 EUE

2 /8 EUE

4 /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)

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, Lames
formulas with Von-Mises Distortion Energy Theor y 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.

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.

TTT-TD94-002

1994 Halliburton Energy Services

Printed in USA

HALLIBURTON

Description
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.

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.

The design of the RTTS safety joint makes

unintentional operation difficult.

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.

Features and Benefits

Positive sequence of operation helps
prevent premature release

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.

Tools above it can be retrieved when

string is stuck

RTTS
Safety Joint

RTTS Safety Joint

RTTS Safety Joint Specifications

1

7 in to

8 /8 in. to

2 /8 in.

4 /2 in.
to 5 in.

7 /8 in.

13 /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 /8 EUE

2 /8 EUE

4 /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)

Casing Size

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

The values of tensile, burst, and collapse strength are calculated using new tool conditions, Lames
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.

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.

TTT-TD94-003

1994 Halliburton Energy Services

Printed in USA

HALLIBURTON

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 equipment, 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 intermediate 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.

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 sufficient 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 procedure 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.

Features and Benefits

Saves rig time

Operates easily

SSC Valve

SSC VALVE

SSC Valve
(Subsurface Control) Specifications
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

Length
in. (cm)

46.33
(117.68)

52.26
(132.74)

51.76
(131.47)

Tensile Rating*
lb (kg)

218,300
(99,000)

332,600
(150,900)

598,000
(271,200)

Working Pressure**
psi (kPa)

9,300
(64,200)

6,100
(42,100)

10,000
(69,000)

Shipping Weight
lb (kg)

119
(54)

210
(95)

320
(145)

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 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.

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.

TTT-TD94-004

1994 Halliburton Energy Services

Printed in USA

HALLIBURTON

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 mechanism, 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 mechanism on 3 1/2-in. packer bodies while larger
packer sizes (4 in.) use drag blocks. Automatic J-slot sleeves are standard equipment
on all packer bodies.
The circulating valve, if used, is a lockedopen/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 Jslot 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 displaced with cement.
Features and Benefits
Full-opening design of the packer
mandrel bore allows large volumes of
fluid to pump through the tool. Tubingtype 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 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 the
tubing is lowered, rotated to the right, and
picked up.

RTTS
Packer

RTTS PACKER

RTTS Packer Specifications

3

Casing Size

2 /8 in.

5 in.

7 in.

9 /8 in.

13 /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 /8 EUE

2 /8 EUE

4 /2 IF

4 /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

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)

Min. Casing
Drift ID
in. (cm)

These are common sizes. Available in sizes 2 3/ 8 in. to 20 in.

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 representative.

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.

TTT-TD94-005

1994 Halliburton Energy Services

Printed in USA

HALLIBURTON

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.
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

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.

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 approximately in line with the groove on the retrieving 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. Nominal drillpipe weight is required above the
valve to reattach the overshot during retrieval. Sufficient pipe weight is required
below the packer to set the packer elements.
The pipe weight also keeps the valve open.

SSC II Valve

SSC II Valve Specifications

3

Casing Size

4 /4 in.

6 /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 /2 IF X
5

4 /32 8 UNS

4 /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)

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 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.

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.

TTT-TD94-006

1994 Halliburton Energy Services

Printed in USA

HALLIBURTON

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 pressuretest a workstring. The EZ DRILL SV provides 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 perforations 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 unobstructed fluid flow.
EZ DRILL SV squeeze packers can be set on
electric wireline. If the EZ DRILL SV mechanical setting tool is used, the packer can
be set on drillpipe or tubing.

Features and Benefits

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 packers 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

EZ DRILL SV
Squeeze Packer

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 drag-block or dragspring 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

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 /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)

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)

Max. Tool
Min.
Max.
OD
Casing ID Casing ID
in. (cm)
in. (cm)
in. (cm)

Length
in. (cm)

EZ DRILL SV Squeeze Packer

Pressure Specifications
Maximum Recommended
Pressure Differential*
psi (kPa)
Maximum

Externally Applied Interally Applied

Nominal
Recomm ended
(Across Packer (Packer Mandrel
Casing Size Tem perature
Rubbers)
Burst)
F (C)

3 /2
4

With Load
Transfer
Device

Without Load
Transfer
Device

350
(177)

10,000
(69,000)

10,000
(69,000)

30,000
(13,608)

10,000
(4,536)

350
(177)

10,000
(69,000)

7,000
(48,263)

80,000
(36,287)

30,000
(13,608)

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)

4 1/2 HW
4 1/2
5
5 1/2
6
6 5/8
7
7 5/8

EZ DRILL SV
Squeeze Packer
with Bridging Plug

Maximum Recommended
Weight on Packer**
lbm (kg)

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.

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
event shall Halliburton be liable for special, incidental, indirect, punitive or consequential damages.

TTT-TD94-007

1994 Halliburton Energy Services

Printed in USA

HALLIBURTON

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

Features and Benefits

Permits passage of wireline tools through
full-opening bore

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.

Requires no pipe rotation to operate

FUL-FLO
Hydraulic Circulating
Valve

FUL-FLO HYDRAULIC CIRCULATING VALVE

FUL-FLO Hydraulic
Circulating Valve Specifications
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 Connections

2 3 /8 EUE

2 7/8 EUE

3 1/2 IF
3 7/8 CAS

3 7/8 CAS

Length*
in. (cm)

79.79
(202.67)

80.69
(204.95)

83.72
(212.65)

83.09
(211.05)

Tensile Rating**
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 (cm 2)

1.27
(8.19)

1.17
(7.55)

1.28
(8.26)

1.28
(8.26)

Number of Ports

Shipping Weight
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 representative.

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.

TTT-TD94-008

1994 Halliburton Energy Services

Printed in USA

HALLIBURTON

Description
The Model 3L packer-type, retrievable bridge
plug consists of packer-type sealing elements, mechanical slips, and a large-area
bypass.
The sealing elements are less susceptible to
damage while running in the hole because
they are not in contact with the casing. When
set, the Model 3L bridge plug does not move
up or down the casing, regardless of pressure
reversals.
This plug can be run alone on tubing or can
be run below the RTTS or CHAMP 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.

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 overshot 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.

Features and Benefits

Rugged, packer-type sealing elements

Wide range of pressure and temperature

limitations

Simple operation

Model 3L
Bridge Plug

MODEL 3L BRIDGE PLUG

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 /8 EUE

2 /8 EUE

2 /8 EUE

2 /8 EUE

2 /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)

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

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.

TTT-TD94-010

1994 Halliburton Energy Services

Printed in USA

H A L L I B U RT O N

Description
The PPI (Pinpoint Injection) packer is a
retrievable, treating, straddle packer that
features 1-ft spacing between packer elements. 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 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 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 stimulation 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 established, right-hand torque is held until the
mechanical slips on the tool are set and can
start taking weight.

PPI (PINPOINT INJECTION) PACKER

PPI Packer

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.

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.

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

After all perforations have been treated, the

packer is released and reset above the
perforations, and the RFC valve and removable 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.

PPI (Pinpoint Injection) Packer Specifications

1

Casing Size

4 in.

5 in.

5 /2 in.

7 in.

9 /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 /8 EUE

Nominal
Casing Weight
lb/ft
Min. Casing
Drift ID
in. (cm)

2 /8 EUE

9.5 to 11.6 11.5 to 13.0

(24.13 to
(29.21 to
29.46)
33.02)

2 /8 EUE

2 /8 EUE

4 /2 IF

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)

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)

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 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.

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.

TTT-TD94-012

1994 Halliburton Energy Services

Printed in USA

HALLIBURTON

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

Features and Benefits

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 communication 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.

PR FAS-FIL Valve

PR FAS-FIL VALVE

PR FAS-FIL Valve Specifications

7

3 in.

3 /8 in.

4 /8 in.

6 /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

Casing Size

39.5
(100.3)

3 /2 IF

4 IF

42.7
(108.5)

43.1
(109.5)

Length
in. (cm)

39.2
(99.6)

Tensile Rating*
lb (kg)

160,500
(72,800)

Burst Rating*
psi (kPa)

11,700
(80,700)

8,500
(58,600)

7,600
16,500
(52,400) (113,900)

Collapse Rating*
psi (kPa)

15,200
(104,900)

11,900
(82,100)

13,300
(91,800)

225,100 284,000 567,000

(102,100) (128,900) (257,200)

13,300
(91,800)

The values of tensile, burst, and collapse strength are calculated with new tool
conditions, Lames 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.

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.

TTT-TD94-013

1993 Halliburton Energy Services

Printed in USA

HALLIBURTON

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 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.

Features and Benefits

Provides free travel in string to reciprocate tools

Slip Joint

SLIP JOINT

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.

** 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 representative.

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.

TTT-TD94-014

1994 Halliburton Energy Services

Printed in USA

HALLIBURTON

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.
Features and Benefits
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

BIG JOHN Jar Specifications

Nominal Tool Size

5 in.
HighPressure

5 in.

4 /8 in.

3 /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 /8 CAS

3 /2 IF
7

3 /8 CAS

3 /2 IF
7

3 /8 CAS

3 /8 8 N

2 /8 EUE

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.

** 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.

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.

TTT-TD94-015

1994 Halliburton Energy Services

Printed in USA

HALLIBURTON

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 workstring causes the outer components

to move down and begin the setting motion.

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.

Additional right-hand rotation moves the

setting tools outer components futher
downward to unlock the upper mandrel from
the drag blocks, which moves the setting
tools outer components upward. This
movement allows the lower mandrel to
extend down far enough to operate the
squeeze packer sliding valve. The disengagement 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.

Features and Benefits

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 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.

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

EZ DRILL MECHANICAL SETTING TOOL

EZ DRILL Mechanical Setting Tool Specifications

1

Casing Size
Maximum Tool OD
Drag-Spring Type
in. (cm)
Maximum Tool OD
Drag-Block Type
in. (cm)
Minimum Tool ID
in. (cm)
Overall Length
Drag-Spring Type
in. (cm)
Overall Length
Drag-Block Type
in. (cm)
Tensile Strength*
lb

6 /8 in.

9 /8 in.

to 8 /8 in.

to 13 /8 in.

4.35
(11.05)

5.53
(14.05)

7.00
(17.78)

3.56
(9.04)

5.65
(14.35)

0.87
(2.21)

1.13
(2.87)

1.62
(4.11)

67.57
(171.63)

71.30
(181.10)

81.91
(208.05)

86.46
(219.61)

71.30
(181.10)

130,000

139,000

4 /2 in.
to 6 in.

316,000

These are common sizes. Available in 3 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.
These ratings are guidelines only. For more information, consult your local Halliburton
representative.

EZ DRILL SV
Drag-Spring
Setting Tool

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.

TTT-TD94-016

1994 Halliburton Energy Services

Printed in USA

HALLIBURTON

Description
The PR MULTI-SERVICE valve is a fullopening, 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 perforations before a stimulation treatment, sandcontrol 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.
Features and Benefits
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 MULTISERVICE valve also contains locking dogs
that lock the ball in the fully open position.
After the valves have been opened, circulation 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
Valve, Top

PR MULTI-SERVICE VALVE

PR MULTI-SERVICE Valve Specifications

7

Size

3 /8 in.

4 /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

2 /8 EUE

Length
in. (cm)

3 /8 TJ
1

3 /8 TJ
1

3 /2 IF

3 /2 IF

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, Lames 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

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.

TTT-TD94-017

1994 Halliburton Energy Services

Printed in USA

HALLIBURTON

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 temperature, 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.
Features and Benefits
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
400F 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, highpressure wells to reduce the operating
pressure.

Operation
The LPR N tester valve is composed of a ballvalve section, a power section, and a metering 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 hydrostatic 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 increased to a predetermined safe pressure

LPR N TESTER VALVE

LPR N
Tester Valve

below the operating pressure of the circulating 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 pressure 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 /8 CAS

2 /8 EUE

2 /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)

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

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.

TTT-TD94-024

1994 Halliburton Energy Services

Printed in USA

HALLIBURTON

Description
The Lubricator/Retainer is a tubing-retrievable 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 installed 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 lubricator 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.

Features and Benefits

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 selectively 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 unlatching by relieving 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

Lubricator/Retainer
Valve

valve to open the ball. This routing bleeds the

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

OD
in. (cm)

Lubricator Valve
Normally Open
10.75
(27.31)

Retainer Valve
Normally Open
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

H2 S

H2 S

Temperature Range
F (C)

0 to 350
(-18 to 177)

0 to 350
(-18 to 177)

Type

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 infor mation, consult your
local Halliburton representative.

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.

TTT-TD94-025

1994 Halliburton Energy Services

Printed in USA

HALLIBURTON

Description
The Subsea Test Tree (SSTT) is used as a
temporary master valve during well testing
from a floating drilling vessel. It is installed
in the blowout preventer (BOP) stack at the
ocean floor.
The SSTT consists of two full-opening/
normally closed safety valves and a latchrelease connection.
The valve section contains two tubing
closures. Each closure operates independently of one another, and each relies on a
single hydraulic source to hold it open. A
normally closed flapper valve and a ball
valve are closed by a nitrogen charge-assisted
spring force. The nitrogen charge forces the
ball to sever wireline or coiled tubing if it is
present. A short time delay between the
nitrogen charge and ball/flapper closure
allows severed wireline or coiled tubing to be
pulled clear of the flapper before closure.
The latch section consists of a latch to the
valve section, a flapper-operating piston, and
molded seals.
The latch section is designed to quickly
release the handling string from the SSTT in
case of an emergency. It can also be used to
quickly and easily reconnect to the valvecontrol system and re-establish hydraulic
connections. It also re-establishes the connection to the handling string and the tubing
string left in the hole. The latch can be
operated by hydraulic pressure from the
surface, or it can be operated by right-hand
tubing rotation in the event of hydraulic
failure of the latch line.

Features and Benefits

Releases quickly from the handling string
in case of emergency

Functions as a safety device

Maintains pump-through features at all

times

Operation
Below the SSTT, a slick joint gives a sealing
point for the pipe rams of the BOP, and a
fluted hanger supports the weight of the
tubing on the wear bushing. The BOP ram
sealing on the slick joint must be above the
choke or kill line. This placement ensures
surface monitoring of annulus pressure and
permits circulation to be established at any
time to kill the well in an emergency. The
SSTT maintains pump-through features at all
times.
The SSTT contains a dual set of internal
dynamic seals. The first set keeps well fluids
within the SSTTs bore. If the first set of seals
fail, the well fluids flow into the balance line,
causing the SSTT to close. The fluid in the
balance line is a signal to the operator that
something is wrong. The operator maintains
full control to continue the test or shut the
valves. In the unlikely event that the second
set of seals fail, the system is designed to shut
in automatically, regardless of operator
control. The SSTT continues to function as a
safety device.
A four-hose bundle transmits hydrauliccontrol pressure from the surface to the SSTT.
The first hose is connected to one side of the

SUBSEA TEST TREE

Subsea Test Tree

ball and flapper pistons to control the opening of the downhole valves. The second hose
is connected to the balance side of the ball
and flapper pistons. It supplies hydrostatic
balance to help close downhole valves. It also
provides additional force to sever wireline or
coiled tubing. The third hose is connected to

the latch at the top of the SSTT and is used to

quickly release or relatch from the handling
string. The fourth hose controls a subsurface
safety valve located below the SSTT and
injects chemicals downhole or into the SSTT
bore.

Subsea Test Tree

OD
in. (cm)

13.00
(33.02)

13.00
(33.02)

ID
in. (cm)

3.00
(7.62)

2.75
(6.99)

End Connections

4 1/2 to 4 AC

5 to 4 AC

Latched Length
in. (cm)

67.45
(171.32)

71.9
(182.63)

Unlatched Length
in. (cm)

45.9
(116.59)

51.4
(130.56)

Tensile Rating*
lb (kg)

400,000
(181,000)

400,000
(181,000)

Working Pressure**
psi (kPa)

10,000
(69,000)

15,000
(103,500)

Service

H2S

H2S

Temperature Range
F (C)

0 to 300
(-18 to 149)

0 to 300
(-18 to 149)

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.

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.

TTT-TD94-027

1994 Halliburton Energy Services

Printed in USA

HALLIBURTON

Description
The TST (tubing string testing) valve is a fullopening valve used to pressure-test the
drillstem test string while running in the
hole. The valve is operated after it is stung
into a permanent packer or after a retrievable
packer is set. The TST valve requires a
differential pressure between the annulus
and the tubing to shear.
The TST valve can also be used for pipe
flexing if it is run below an annulus pressureresponsive circulating valve.
The TST valve consists of

flapper valve and spring

shear pin section

locking dogs

Features and Benefits

Flapper valve requires only 4 psi to open

Testing string can be pressure tested as

many times as required as it is run in the
hole

Valve shear rating can be predetermined

at 500 psi increments

Valve can also be used for pipe flexing

While the test string is stationary, a spring

keeps the flapper valve closed.
After the test-string pressure test is complete,
the tool is sheared when annulus pressure is
applied to the predetermined shear- pin
rating. (The shear rating can be adjusted in
500 psi increments to shear from 500 to 6,000
psi differential.) When the pins shear, the
mandrel moves up and pushes the flapper
open, allowing the locking dogs to engage.
The tool is then fully open.
The tool works on differential pressure
between annulus and tubing. Failure to shear
initially on application of annulus pressure is
not critical. The process of drawing the well
down also creates a pressure differential that
helps the tool shear.
When used for pipe flexing, the TST valve is
run below an annulus pressure-responsive
circulating valve, such as the APR A valve.
The string is pressured up against the flapper
valve as many times as required. The circulating valve is sheared after flexing operations are complete, and the string is pulled
out dry.

Operation
When the TST flapper valve opens, it allows
the test string to fill up. The shear pins hold
the mandrel in place. The drillstring can be
pressure tested as many times as required as
it is run in the hole.

TST Valve

TST VALVE

TST Valve

OD
in. (cm)

5.03
(12.78)

3.90
(9.91)

ID
in. (cm)

2.28
(5.79)

1.80
(4.57)

End Connections

3 7/8 CAS

2 7/ 8 CAS

Length
in. (cm)

48.00
(121.92)

44.67
(113.46)

Tensile Rating*
lb (kg)

369,000
(188,000)

249,000
(113,000)

Working Pressure**
psi (kPa)

15,000
(103,000)

15,000
(103,000)

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.

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.

TTT-TD94-028

1994 Halliburton Energy Services

Printed in USA

H A L L I B U RT O N

Description
The EZ DRILL SVB squeeze packer has a
brass mandrel that is stronger and more
ductile than the cast-iron mandrel in EZ
DRILL SV squeeze packers. As a result, the
packer can absorb greater tensile and impact
loads and greater internal pressures. The
brass mandrel is as easily drilled as the castiron mandrel of the EZ DRILL SV squeeze
packer.
The valve arrangement improves performance in high-temperature and highpressure areas, especially when the valve is
cycled repeatedly. The valve also performs
well when it is cycled under conditions in
which fluid cannot be held static, especially
when there is pressure or flow from below.
The slips of the EZ DRILL SVB squeeze
packer allow the packer to be set in all
grades of casing up to V150.

Features and Benefits

Controls flow and pressure differential
in either direction

Allows pressure testing of workstring

Runs in quickly

Sets in a wide range of casing grades

Contains rugged brass mandrel, improved slips, and improved sliding

valve seals

Can be set on wireline, tubing, and

drillpipe

Can be set mechanically or hydraulically

Operation
Once the packer is lowered to its setting
depth, the steel hose and swivel are hooked
to the drillpipe. During circulation, the
packer is worked up and down through the
casing to clear debris from the packer and
packer seat.
The packer is rotated a specified number of
clockwise turns immediately after circulation
stops. Right-hand rotation moves the setting
sleeve downward to unlatch the lock ring
and set the top packer slips.
Before the workstring can be pulled out, a
series of applied pulls and hesitations are
used until the tension sleeve parts. These
pulls and hesitations allow the packer rubber
to better expand and contact the casing ID.
A pressure of 2,000 psi can be applied below
the packer as it sets to help 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 the slips and packer element set
tighter.
The setting tool is then pulled above the
packer, and the drillpipe is rotated to release
the setting tool. The workstring can then be
freely rotated as it comes out of the hole,
uninhibited by dragblock or dragspring
interference.

EZ DRILL SVB
Squeeze Packer

EZ DRILL SVB SQUEEZE PACKER

EZ DRILL SVB
Squeeze Packer Specifications
Size*
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)

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
(9.93)

4.18
(10.62)

25.1
(63.8)

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
(64.3)

6
6 5/8
7
7 5/8
7 3 /4
9
9 5/8
9 3 /4
9 7/8
10 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
(16.41)

31.6
(80.3)

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
(92.5)

9 5/8

These are the most common sizes. Other sizes may be available.
These ratings are to be used as guidelines only. For more information, consult your local Halliburton
representative.

EZ DRILL SVB Squeeze Packer Pressure Specifications

Maximum Recommended
Pressure Differential*
psi (kPa)
Nominal
Casing Size
in.

Maximum
Internally
Externally Applied
Recommended
Applied
(Across Packer
Temperature*
(Packer Mandrel
Rubbers)
F (C)
Burst)

4 1/2 HW
4 1/2
5
5 1/2
6
6 5/8
7
7 5/8

Maximum Recommended
Weight on Packer**
lbm (kg)
With Load
Transfer
Device

Without Load
Transfer
Device

425
(218)

10,000
(68,948)

10,000
(68,948)

80,000
(36,287)

20,000
(9,072)

425
(218)

10,000
(68,948)

10,000
(68,948)

100,000
(45,359)

40,000
(18,144)

8 5/8
9 5/8

350
(177)

10,000
(68,948)

10,000
(68,948)

100,000
(45,359)

40,000
(18,144)

10 3 /4 HW
10 3/4
11 3 /4 HW
11 3/4

300
(149)

7,500
(51,711)

10,000
(68,948)

100,000
(45,359)

50,000
(22,680)

13 3 /8 HW
13 3/8

250
(121)

5,000
(34,474)

10,000
(68,948)

100,000
(45,359)

50,000
(22,680)

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 applied
hydraulic forces.

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.

TTT-TD94-029

1994 Halliburton Energy Services

Printed in USA

HALLIBURTON

Description
The Model 2 RTTS packer is a full-opening/
hookwall packer with round hydraulic slips.
Developed for testing, treating, and squeeze
cementing operations, the packer is available
in sizes from 7 in. to 20 in. The Model 2
RTTS packer includes a packer assembly, a
criculating valve assembly, and an optional
safety joint assembly.
Features and Benefits
The full-opening feature allows large
volumes of fluid to be pumped with a
minimum pressure drop. It also allows
the use of through-tubing perforating
guns.

The Model 2 RTTS packer is operated in

the same manner as the original RTTS
packer. It can be used with regular RTTS
circulating valves or with Model 2 RTTS
circulating valves.
Each packer has a J-slot mechanism,
mechanical slips, and a packing element.
A hydraulic hold-down mechanism is
also included to help prevent the tool
from being pumped up the hole. All
Model 2 RTTS packers are assembled
with drag blocks and automatic J-slot
sleeves.

Operation
Mechanical slips must be free to run in the
hole. To verify that the slips are free, the tool
is allowed to hang free. The drag body is
worked up and down several times. Mechanical slips should move in and out freely.
The circulating valve is in the locked-open
position to run in the hole. The drag body Jslot is also in the locked position.
Because backup slippage tends to set the
mechanical slips on the packer and close the
circulating valve, slippage should be mini-

mized. The inadvertent closure of the

circulating valve is indicated by tubing
running over.
If a closure occurs, the tubing is lowered,
turned to the right, raised a few feet, and
turned to the left. This procedure returns the
circulating valve to the open position.
When ready for operation, the tool is run in
slightly below the required setting position. It
is then lifted to setting position and rotated
several turns to the right.
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. Pipe movement is then
stopped, and the torque is relieved as the
tool is rotated to the left at approximately
1
/2 turn/1,000 ft of depth.
With left-hand torque applied, the tubing is
lowered until the correct weight is on the
packer. The tool is then in position to proceed with the formation breakdown, squeeze
cementing, or swabbing operation.
After the operation is complete, the pressure
is equalized at the packer and the tubing is
lifted without rotation. The circulating valve
is in the closed position to establish reverse
circulation around the packer.
Before the circulating valve can be opened
and removed from the hole, the tubing must
be lowered, turned to the right, and pulled
out of the hole.
During an emergency, the tension sleeve is
parted to release the optional safety joint.
Right-hand rotation is required to back out
the nut that releases the joint. While righthand torque is held on the tubing, the workstring is pulled up and down until the safety
joint is released.

MODEL 2 RTTS PACKER

Model 2 RTTS
Packer

Model 2 RTTS Packer Specifications

3

Casing Size

2 /8 in.

5 in.

7 in.

9 /8 in.

13 /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

5.735
(14.567)
5.329
(13.536)

7.886
(20.030)
8.341
(21.186)

12.071
(30.660)
11.627
(29.533)

6.538
(16.607)
5.920
(15.037)

8.835
(22.441)
9.063
(23.020)

12.715
(32.296)
12.347
(31.361)

4.335
(11.011)
3.896
(9.896)
4.141
(10.518)
4.670
(11.862)
4.044
(10.272)
4.408
(11.196)

Min. Casing
Drift ID
in. (cm)

1.864
(4.735)

Max. Casing ID
in. (cm)

1.995
(5.067)

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. The packer is available in sizes 5 5/ 8 in. to 20 in.
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 representative.

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.

TTT-TD94-032

1994 Halliburton Energy Services

Printed in USA

HALLIBURTON

Model E SRO Tool System

Description
The Model E SRO (surface readout) tool
system consists of the following:

a fully open string of drillstem testing

(DST) tools

an SRO valve or barrel

an SRO probe assembly

The SRO valve assembly becomes an integral

part of the testing string and is located just
above the tester valve.
The SRO probe assembly is run in on wireline after the toolstring is in place and the
packer is set. It is then lowered into the SRO
valve and latched into place. Connected to
the wireline is a pressure transducer that
senses reservoir pressure and transmits the
data to the Reservoir Evaluation System
software for monitoring throughout the DST.
The Model E SRO tool system provides the
operator with real-time reservoir data and
evaluation at any point during DST operations. Because the tests are in real time,
treatments can be designed based on the
actual reservoir conditions and reactions.
This system improves results in a DST, and
saves rig time if further investigation is
unnecessary.
The Model E SRO can be run with an annulus-pressure operated tool such as the LPR N
tester, or it can be run with a weight-operated
FUL-FLO HYDRO-SPRING tester.

Operation
The packer is set after the DST workstring is
lowered into the hole and positioned. The
wireline operator lowers the probe containing the temperature and pressure transducers
into the hole on single conductor wireline.
Once the probe weight has been slacked off,
the operator pulls up on the wireline to latch
the probe in place. Approximately 800 lb of
pull above the probe handling weight is
required to open the sliding sleeve on the
SRO valve assembly. A sudden pressure
change is a better indication that the probe
latched and the valve opened. Following this
pressure change, the wireline is clamped at
the lubricator, and the tester valve is opened
for the initial flow test.
When the DST is completed, the wireline is
unclamped at the lubricator, and wireline
weight is slacked off (all tension plus the
probe weight). When the wireline is picked
up again, the probe disengages from the SRO
valve assembly and can be removed from the
hole.
After the SRO probe and wireline are removed from the hole, a circulating valve
opens, and the workstring fills, permitting
reverse circulation for removal of the DST
recovery fluid. The packer is unseated, and
the DST string is removed from the wellbore.

Model E SRO
Tool System

Tools, Testing and TCP

Model E SRO Specifications

OD
in. (cm)

5.06
(12.85)

ID
in. (cm)

1.875
(4.76)

End Connections

3 1/2 IF
3 7/8 CAS

Length
in. (cm)

162.35
(412.37)

Tensile Rating*
lb (kg)

342,000
(155,000)

Burst Rating*
psi (kPa)

10,500
(75,000)

Collapse Rating*
psi (kPa)

13,000
(90,000)

Flow Area
in. (cm)

3.14
(20.25)

Shipping Weight
lb (kg)

595
(270)

The values of tensile, burst, and collapse strength are calculated with new tool
conditions, Lames formula for burst and collapse strength, and stress area calculations for tensile strength. Pressure rating is defined as differential pressure at the tool.
(Differential pressure is the difference in pressure between the casing annulus and
tool ID.)
These ratings are guidelines only. For more infor mation, consult your local Halliburton
representative.

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 event shall Halliburton be liable for special, incidental, indirect, punitive or consequential damages.

TTT-TD94-033

1994 Halliburton Energy Services

Printed in USA

HALLIBURTON

RS Valve
Description
The RS valve is a reversing and spotting
valve operated by the pressure differential
between the workstring ID and the annulus.
It can be opened and closed as many times as
necessary.

tool can be used to spot stimulation fluids or

a cushion of fluid or nitrogen. This position
is also used to drain the workstring while
pulling out of the hole. The only flow
permitted in the spotting position is from the
workstring ID to the annulus.

The RS valve may also function as a backup

circulating valve in deteriorated mud conditions.

After five cycles, the tool shifts to the reverse

position when the internal pressure is released. In this position, the recovered fluid
can be reverse-circulated out of the well, and
the mud can be conditioned. In the reverse
position, the valve only permits flow from
the annulus to the workstring ID.

Features and Benefits

This tool can be used to

Fill the workstring while running in

Spot a cushion

Reverse the workstring

Spot treating fluids

Reverse and drain the workstring while

pulling out of the hole

Operation
To cycle the tool, a 500-psi minimum pressure
differential must be placed across the tool.
Higher internal pressure followed by higher
annulus pressure is one cycle.
When the internal pressure is increased to
500 psi above the annulus, the tool shifts to
the spotting position. In this position, the

To close the tool, 500-psi differential is placed

across the tool by either increasing annulus
pressure or releasing the workstring ID
pressure.
The closed or reverse positions are used
while the RS valve is run in. In the closed
position, the workstring can be pressure
tested and manually filled with cushion fluid.
In the reverse position, the workstring
automatically fills during run in. The tool
can be cycled to pressure test the tubing.
Once the tool is at bottom, the cushion can be
spotted throughout the tool. This procedure
saves rig time and is safer than manually
filling the workstring.

RS Valve

Tools, Testing and TCP

RS Valve Specifications
OD
in. (cm)

5.03
(12.78)

ID
in. (cm)

2.28
(5.79)

End Connections

3 /2 IF
7
3 /8 CAS

Length
in. (cm)

169.96
(431.70)

Tensile Rating*
lb (kg)

339,000
(153,000)

Burst Rating*
psi (kPa)

18,500
(128,000)

Collapse Rating*
psi (kPa)

15,500
(107,000)

Circulating
Flow Area
in. (cm)

0.97
(6.28)

Number of Ports

30

The values of tensile, burst, and collapse strength are calculated with new tool
conditions, Lames formula for burst and collapse strength, and stress area calculations for tensile strength. Pressure rating is defined as differential pressure at the tool.
(Differential pressure is the difference in pressure between the casing annulus and tool
ID.)
These ratings are guidelines only. For more infor mation, consult your local Halliburton
representative.

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 event shall Halliburton be liable for special, incidental, indirect, punitive or consequential damages.

TTT-TD94-034

1994 Halliburton Energy Services

Printed in USA

HALLIBURTON

Rupture Disk FUL-FLO Sampler

Description
The rupture disk FUL-FLO sampler is a fullopen, full-bore sleeve sampler for use on
drillstem tests. The sampler is controlled by
a rupture disk that is operated by annulus
pressure.
Features and Benefits
Time-delay feature allows the sample to
be trapped after a preset time. Different
metering cartridges can be used to vary
the closing time.

Full-open capabilities are retained after

the tool has trapped its sample.

Several samplers can be run on a test to

allow sampling at different times.

Operation
The FUL-FLO sampler is controlled by a
pressure-operated rupture disk and has a
sample mandrel with a built-in differential
area. To catch a sample, annulus pressure is
increased to a predetermined level, the
rupture disk in the sampler breaks, and the
mandrel traps the sample.
When the rupture disk breaks, the differential
area of the sample mandrel is exposed to an
air chamber on one side and hydrostatic
pressure and applied annulus pressure on the
other. This results in the sample mandrel
moving up and trapping the sample. When
the sample mandrel reaches the top of its
stroke, it is locked in place by a set of locking
dogs.
The 1,200-cc sample chamber allows a
sufficient sample for two 500-cc PVT analyses
with additional volume for lines, valves, etc.
A piston in the sample chamber can be
pumped up to drain the sample without the
need to use mercury.

Rupture Disk
FUL-FLO Sampler

Tools, Testing and TCP

Rupture Disk Sampler Specifications

OD
in. (cm)

5.03
(12.78)

3.90
(9.91)

ID
in. (cm)

2.28
(5.79)

1.80
(4.57)

End Connections

3 1/2 IF
3 7/8 CAS

2 /8 CAS

Length*
in. (cm)

82.00
(208.28)

131.00
(332.74)

Tensile Rating**
lb (kg)

411,000
(186,000)

202,000
(91,000)

Burst Rating**
psi (kPa)

15,000
(103,000)

15,000
(103,000)

Collapse Rating**
psi (kPa)

15,000
(103,000)

15,000
(103,000)

Sample Volume
cc

1,200

1,200

Without time delay feature.

** The values of tensile, burst, and collapse strength are calculated

with new tool conditions, Lames formula for burst and collapse
strength, and stress area calculations for tensile strength.
Pressure rating is defined as differential pressure at the tool.
(Differential pressure is the difference in pressure between the
casing annulus and tool ID.)
These ratings are guidelines only. For more information, consult
your local Halliburton representative.

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 event shall Halliburton be liable for special, incidental, indirect, punitive or consequential damages.

TTT-TD94-036

1994 Halliburton Energy Services

Printed in USA

HALLIBURTON

Description
The Model 2 RTTS circulating valve is a
locked-open valve that serves as both a
circulating valve and a bypass valve. It is
held closed by internal pressure and/or pipe
weight.
A straight J-slot in the circulating valve
allows it to be used with a straight J-slot in
the packer assembly. This combination
eliminates the need to rotate the tubing to
close the circulating valve or reset the packer
after the tubing has been displaced with
cement. When the Model 2 RTTS circulating
valve is used, the lower pin on the packer
must be removed and replaced with the
proper port mandrel.

If a closure occurs, the tubing is raised a few

feet and turned to the left. This procedure
returns the circulating valve to the open
position.
The circulating valve is left in the closed
position during formation breakdown,
squeeze cementing, or swabbing operations.
After the operation is complete, the pressure
is equalized at the packer and the tubing is
lifted without rotation. The circulating valve
is in the open position.

Operation
The straight J-slot holds the circulating valve
in the locked-open position while it is run in
the hole. Because slippage of the backups
tends to set the mechanical slips on the
packer and close the circulating valve,
slippage should be minimized. The inadvertent closure of the circulating valve is indicated by the tubing running over.

Model 2 RTTS
Circulating Valve

MODEL 2 RTTS CIRCULATING VALVE

Model 2 RTTS Circulating

Valve Specifications

Casing Size

8 /8 to 20 in.

OD
in. (cm)

6.50
(16.52)

ID
in. (cm)

2.40
(6.10)

End Connections

4 1/2 IF

Length
in. (cm)

52.50
(133.43)

Tensile Rating*
lb (kg)

271,900
(122,980)

Burst Rating*
psi (kPa)

10,000
(68,940)

Collapse Rating*
psi (kPa)

10,000
(68,940)

Shipping Weight
lb (kg)

350
(159)

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, Lames formulas with Von-Mises
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.

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.

TTT-TD94-037

1994 Halliburton Energy Services

Printed in USA

HALLIBURTON

Wellhead Isolation Tool

Description
The Wellhead Isolation Tool isolates the
wellhead from exposure to treating fluids
and pressures. The isolation tool contains a
seal element and mandrel that are inserted
through the existing wellhead bore and
tubing hanger into the production tubing.
The seal element and mandrel configuration
allow treating fluids to be pumped through
the WIT directly into the production tubing.
Tubing pressure activates the tool by energizing the sealing element.
The simple and economic Wellhead Isolation
Tool is ideal for breakdown treatments and
fracturing jobs. Sand-laden fracturing fluids,
however, are very erosive at high velocities,
and some care must be exercised to maintain
reliability of the tool. Erosion rates vary
considerably with different fluids. A working
guideline is 125 ft/sec. This guideline is a
generalization and is recommended as a safe
working maximum unless a very specific and
carefully controlled set of conditions is
known.
The Wellhead Isolation Tool can be used to
upgrade the working pressure limits of well
systems for many stimulation requirements.
Though no special adjustments are required
to the wellhead tubing system, treating

conditions should be designed within tool

limitations, and the customary precautions of
working with a live well should be carefully
followed.
Features and Benefits
Independent hydraulic system provides
positive control and greater reliability
while mandrel is being inserted into
tubing.

Patented internal configuration minimizes erosion in tubing.

Design provides redundant safety

control.

Procedures
The tool is installed and removed without the
well being killed. The assembly is attached to
the wellhead, and the mandrel is extended
completely through the wellhead to seal in
the tubing body. The mandrel cup-type
sealing element can be adapted to fit various
tubing sizes and weights. Attachment of the
tool assembly to the tree is best made by
flanges rather than threaded adapters.
For increased safety and more positive
sealing, a mechanical lock is used to hold the
mandrel securely in place.

Wellhead Isolation
Tool

Tools, Testing and TCP

Wellhead I solation Tool S pecifications

Tubing/Casing

Tool

Weight
R ange
lb

Working
Pressure
psi

S troke
Length
in.

Mandrel I D
in.

3 1/ 4
4.7
6.5 to 8.7

15,000
15,000
15,000

36.0
36.0
36.0

1.06
1.06
1.06

4.7
6.5 to 10.7

15,000
15,000

35.8
35.8

1.31
1.31

4.7
6.5 to 10.7

15,000
15,000

48.0
48.0

1.31
1.31

6.5 to 8.7
9.2 to 15.8

15,000
15,000

44.0
44.0

1.57
1.57

4.0
9.2 to 15.8
9.5 to 11.6
15.5 to 20

10,000
10,000
8,000
5,500

44.0
44.0
44.0
44.0

1.75
1.75
1.75
1.75

6.5 to 8.7
9.2 to 15.8

15,000
15,000

60.0
60.0

1.57
1.57

6.5
9.2 to 10.2
12.95 to 17

20,000
15,000
20,000

60.0
60.0
60.0

1.57
1.57
1.57

6.5 to 8.7
9.2 to 15.8

20,000
20,000

60.0
60.0

1.31
1.31

9.2
9.5 to 13.4
9.5 to 15.1
18 to 20
15.5 to 23
23 to 32
39

15,000
15,000
15,000
15,000
15,000
11,000
10,000

60.0
60.0
60.0
60.0
60.0
60.0
60.0

1.87
1.87
2.25
2.25
2.25
2.25
2.25

15.5 to 26
17 to 32
29,7 to 33.7
43 to 61

15,000
10,000
9,000
6,000

80.0
80.0
80.0
80.0

3.00
3.00
3.00
3.00

9.5 to 15.1
18 to 20
15.5 to 20
17 to 32

15,000
12,000
12,000
7,500

60.0
60.0
60.0
60.0

2.87
2.87
2.87
2.87

S iz e
in.
2 1/ 16

#1-A

2 3/ 8
2 7/ 8

#1-B

#1-D

#4-A

2 3/ 8
2 7/ 8
2 3/ 8
2 7/ 8
2 7/ 8
3 1/ 2
2 7/ 8

#4-B

3 1/ 2
4 1/ 2
5 1/ 2

#2-A

#2-B

#2-C

2 7/ 8
3 1/ 2
2 7/ 8
3 1/ 2
2 7/ 8
3 1/ 2
3 1/ 2
4

#2-E

4 1/ 2
5
5 1/ 2
7
7 5/ 8

#2-F

5 1/ 2
7
7 5/ 8
9 5/ 8

#2-G

4 1/ 2
5
5 1/ 2
7

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

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 event shall Halliburton be liable for special, incidental, indirect, punitive or consequential damages.

TTT-TD94-063

1994 Halliburton Energy Services

Printed in USA

HALLIBURTON

Round Mandrel 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. The round
mandrel slip joint is more reliable and less
costly than the hex mandrel slip joint.
A slip joint has these functions:

Provides free travel in the string to

reciprocate tools without unseating the
packer

Provides a variable-length joint to allow

expansion and contraction of pipe during
testing or stimulation

located throughout the pipe string. The

number of slip joints required depends on
ocean heave and the amount of expected
contraction and expansion.
Features and Benefits
The top of the mandrel slip joint has a
4 -in. drill collar profile for easy handling with the rig elevators and slips.

The slip joint maintains its full tensile

rating when collapsed and locked.

The slip joint can be locked in the closed

position for handling, which reduces the
risk of damage to the lifting/sealing
mandrel.

Keeps vertical movement of the drilling

vessel from disturbing tool placement

The round mandrel slip joint is internally

pressure- and volume-balanced.

Helps space out the testing string when

the subsea tree is landed

Provides a constant weight on the packer

during testing or stimulation

The string can be picked up with the slip

joint locked; the slip joint can then be
unlocked before it is run into the hole.

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 also available.
When multiple slip joints are run, they are
normally connected together rather than

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.
A pressure test can be performed on the
entire 5-ft length of the sealing mandrel OD.

Round Mandrel
Slip Joint

Tools, Testing and TCP

Round Mandrel Slip Joint Specifications

Casing Size*

5 in.

OD
in. (cm)

5.03
(12.78)

ID
in. (cm)

2.31
(5.87)

End Connections

3 /8 CAS

Length**
in. (cm)

180.00
(457.20)

Tensile Rating
lb (kg)

225,000
(102,000)

Working Pressure
psi (kPa)

15,000
(103,000)

Shipping Weight
lb (kg)

550
(250)

This is the most common size. Other sizes may be available.

** Add 60.00 in. (152.40 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 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.

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 event shall Halliburton be liable for special, incidental, indirect, punitive or consequential damages.

TTT-TD94-064

1994 Halliburton Energy Services

Printed in USA

HALLIBURTON

Description
The FasDrill Squeeze Packer is a poppetvalve cement retainer for remedial cementing
operations conducted within a range of 50F
to 250F. It is manufactured with minimal
ferrous metal content, making it extremely
easy to drill out.
This squeeze packer is rated to 5,000 psi
differential and can be set on electric wireline, on tubing, or on drillpipe. Its one-way
poppet valve checks cement backflow from
below the packer but does not restrict fluid
movement from above. Maximum allowable
weight on the packer after setting is 20,000
lb. The maximum flow rate is 3 bbl/min.
The FasDrill Bridge Plug is used similarly to
a conventional permanent bridge plug.
Design specifications are for applications
with temperatures up to 250F and pressures
up to 5,000 psi differential from either
direction.
Features and Benefits
Made from composites and a packer set,
giving it minimal ferrous metal content

Used as a cement retainer in squeeze

cementing operations on land-based or
offshore rigs, in vertical or deviated wells

Used as a bridge plug in multi-zone

stimulation treatments

Saves rig time and reduces casing

damage caused by long drillout
processes

Drills out with conventional tri-cone or

with junk-mill bits

Operation
Like the EZ DRILL Squeeze Packer, the
FasDrill Squeeze Packer is operated by
inserting the operating mandrel, or stinger,
into the packer bore. This operation allows
the stinger to seal the workstring and distribute weight to the slips and packer rubbers.
As much weight as possible is set on the
packer to ensure a tighter fit (up to the
maximum allowable pipe weight).
Hydraulic forces can occur that add or
subtract weight to/from the packer during
the job. Hydraulic calculations must be
completed before using the packer to ensure
against overloading or pumping out of the
packer.
FasDrill Bridge Plugs can be set on tubing, on
drillpipe, or with conventional tools, such as,
electric wireline. An adapter kit is required
for setting tools.

FasDrill Squeeze
Packer

FASDRILL SQUEEZE PACKER AND BRIDGE PLUG

F a s D ri l l S p e c i fi c a ti o n s
C a s i n g S i ze

/2 in .

7 in .

/2 in .

OD
i n . (c m )

3 .66
(9 . 3 0 )

4 .37
(1 1 . 1 0 )

5 .5
(1 3 . 9 7 )

M in im u m ID
i n . (c m )

3 .92
(9 . 9 6 )

4 .67
(1 1 . 8 6 )

5 .92
(1 5 . 0 4 )

M a xim u m ID
i n . (c m )

4 .09
(1 0 . 3 9 )

5 .04
(1 2 . 8 0 )

6 .46
(1 6 . 4 1 )

N o m in a l
C as in g W eig h t
l b (k g )

9 .5 to 13 .5
(4 . 3 1 t o 6 . 1 2 )

1 3 to 23
(5 . 9 t o 1 0 . 4 )

2 0 to 38
(9 . 0 7 t o 1 7 . 2 4 )

M a xim u m Pres su re
D i ffe r e n ti a l
p s i (k P a )*

5 ,00 0
(3 4 , 4 7 0 )

5 ,00 0
(3 4 , 4 7 0 )

5 ,00 0
(3 4 , 4 7 0 )

T e m p e ra tu re R a n g e
F (C )

5 0 to 25 0
(1 0 t o 1 2 1 )

5 0 to 25 0
(1 0 t o 1 2 1 )

5 0 to 25 0
(1 0 t o 1 2 1 )

M a xim u m W e ig h t
o n Pa ck er
l b (k g )

2 0,0 00
(9 , 0 7 2 )

2 0,0 00
(9 , 0 7 2 )

3 0,0 00
(1 3 , 6 0 8 )

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 Hallibur ton
representative.

FasDrill
Bridge Plug

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.

TTT-TD94-073

1994 Halliburton Energy Services

Printed in USA

H A L L I B U RTO N

Centrifugal Transfer Pumps

Description
Transfer pumps are used to transfer
crude oil from the test tanks to a
pipeline or storage tank or to
supply oil to a crude oil burner for
disposal.
Transfer pumps may be driven
electrically or by diesel or gas
engines. Electric drivers are preferred in offshore situations with
ample power. Diesel drivers are
normally used on land locations
when the pump can be placed away
from the well test equipment.

Features and Benefits

These transfer pumps
Can use either a electric, diesel,
or gas driver for maximum
flexibility
Is on an oilfield skid
Uses mechanical pump seals, the
most reliable type of seals

The pumps are horizontal, endsuction centrifugal pumps with

mechanical seals. They supply oil to
the burner when there is not
enough pressure for the well
effluent to atomize and burn
cleanly through the burner. They
may also be used to reinject the
effluent into the flowlines after
flowing through the production test
units.

Operation
Centrifugal pumps deliver a
constant pressure without the
pulsations that occur with pistontype pumps. Centrifugal pumps do
not over pressure themselves if a
downstream valve is accidentally
closed. They will automatically
bypass the liquid.

Diesel Pump

The units can be controlled manually, by using high/low level

switches in the stock tanks or by
means of a level controller and a
system of control valves. Controls
always include a pneumatic shutdown to simplify tying into the
Emergency Shutdown System.
Transfer pumps are ideal for
transferring oil or water on location
They are designed for corrosive
service.
Electric Pump

TOOLS AND TESTING

Centrifugal Transfer Pump

Description

Electric Transfer Pump

Class I Div. I GRP D

Electric Transfer Pump

Class I Div. I GRP D

Diesel Transfer Pump

Motor

125 Horsepower
444 T Frame TEFC
Explosion Proof
Class F Insulation
1.15 Service Factor
460 volt 3 Phase
60 Hz 3600 RPM

150 Horsepower
445TS Frame TEFC
Explosion Proof
Class F Insulation
1.15 Service Factor
460 volt 3 Phase
60 Hz 3600 RPM

Detroit 4-53
125 Horsepower
@ 2500 RPM

Controls

Nordic Soft Start Controller

External Reset
NEMA 7/9 Enclosure
Separate Field Termination

Nordic Soft Start Controller

Vernier Throttle
External Reset
Manual and Emergency Kill
NEMA 7/9 Enclosure
Sentinel Low Oil Pressure
Separate Field Termination High Coolant Temperature

Sunflo Model P3-BPJ

Sunflo Model P3-DPJ
Dean Model PH-30
Horizontal Pump
Horizontal Pump
Horizontal Pump
3550 Input RPM
2550 Input RPM
3560 Input RPM;
8272 Output RPM;
8075 Output RPM;
375 psi (2585 kPa)
350 psi (2413 kPa)
350 psi (2413)
Maximum Suction Pressure
Maximum Suction Pressure Maximum Suction Pressure
565 psi (3895 kPa)
2160 psi (14893 kPa)
2160 psi (14893)
Maximum Case Pressure
Maximum Case Pressure
Maximum Case Pressure

Centrifugal Pump

Maximum Temperature
F (C)

-20 (-29) Ambient

to 250 (121)Maximum
Fluid Temperature

-20 (-29) Ambient

to 250 (121)Maximum
Fluid Temperature

-20 (-29) Ambient

to 250 (121)Maximum
Fluid Temperature

Pump Inlet
in.

3 300# FF Flange

3 600# RF Flange

3 600# RF Flange

Pump Outlet
in.

1-1/2 300# FF Flange

2 600# RF Flange

2 600# RF Flange

Performance

With Water:
10,000 bbl/d @ 300 psi
With Oil:
10,000 bbl/d @ 255 psi

With Water:
10,000 bbl/d @ 500 psi
With Oil:
10,000 bbl/d @ 425 psi

With Water:
6,000 bbl/d @ 505 psi
With Oil:
10,000 bbl/d @ 400 psi

Service

H2S*

H2S*

H2S*

Skid Length
in. (cm)

77
(196)

77
(196)

97
(246)

Skid Width
in. (cm)

48
(122)

48
(122)

44
(112)

Skid Height
in. (cm)

60
(152)

60
(152)

60
(152)

Skid Weight
lb (kg)

4,000
(1814)

5,000
(2268)

6,000
(2722)

*Meets requirements of NACE MR-01-75

Note: Other sizes and configurations are available to meet the needs of most applications.
These ratings are guidelines only.
For more information, consult your local Halliburton representative.

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.

TT-221

1994 Halliburton Energy Services

Printed in USA

H A L L I B U RTO N

STE/Choke Manifold
Description
Chokes are throttling valves that
allow operators to control the
wellstream. Chokes are capable of
withstanding erosion resulting from
the very high velocities occurring at
and immediately downstream from
the orifice.
The Choke Manifold allows operators to limit erosion to the replaceable parts within the choke.
The standard HES choke manifold
is a five-valve, component design
with a full-bore flow path through
the manifold allowing total bypass
of the choke control. On one side of
the bypass, an adjustable choke
allows more flexible control for
wellbore cleanup rates. On the
other side is a positive choke to
give more accurate flow control for
predetermined fluids for various
test procedures. By using the
valving and adjustable choke, the
operator can change the positive
choke without having to stop
operations or affect test objectives.

Offers a lower overall redress cost

because of its component design
Allows more options during
cleanup with its bypass through
the manifold
Meets applicable industry standards (API 6A) and can be thirdparty certified as required
Operation
The choke allows the operator
control by enabling progressive
manual, powered, or fixed control
of the wellstream by opening,
closing, or selecting an orifice.
Chokes help maintain critical flow,
even while changing choke size.
Critical flow occurs when the

pressure downstream of the choke

is one-half or less than the pressure
upstream. In this case, the flow rate
through the choke depends only on
variations of the upstream pressure
and on choke setting. Changes in
downstream pressure within the
critical flow range do not affect the
rate of flow through the choke.
Noncritical flow occurs when the
downstream pressure is more than
one-half the upstream pressure. In
this case, changing the pressure will
affect the flow rate through the
choke. The critical flow should
always be maintained across the
chokes. The choke manifold should
be placed as close as possible to the
production equipment.

Features and Benefits

The Choke Manifold
Features dual chokes, one adjustable and one positive, to help
maintain a constant flow rate,
which improves test data quality
Is designed for easy maintenance
during operations, which saves
rig time and overall cost of test
Choke Manifold

TOOLS AND TESTING

Choke Manifold
Working Pressure
psi (kPa)

5,000 (34475)

10,000 (68950)

15,000 (103425)

15,000 (103425)

Service

H2S*

H2S*

H2S*

H2S*

Chokes

Cameron Type H2
3-1/8 5000
2 in Max Orifice
One Adjustable
One Positive

Cameron Type H2
3-1/16 10000
2 in Max Orifice
One Adjustable
One Positive

Cameron Type H2
2-9/16 15000
2 in Max Orifice
One Adjustable
One Positive

Cameron Type H2
3-1/16 15000
2 in Max Orifice
One Adjustable
One Positive

Valves

Cameron Type FC
3-1/8 in. 5000

Cameron Type FC
3-1/16-in. 10000

Cameron Type FC
2-9/16 in. 15000

Cameron Type FC
3-1/16 in. 15000

Flanges
in.

3-1/8 API 6 Bx 5000

3-1/16 API 6 Bx 10000

2-9/16 API 6 Bx 15000

3-1/16 API 6 Bx 15000

Studs

A320 GR L7
NACE Class II

A320 GR L7
NACE Class II

A320 GR L7
NACE Class II

A320 GR L7
NACE Class II

Tee

w/ Fluid Cushion Target

w/ Fluid Cushion Target

w/ Fluid Cushion Target

w/ Fluid Cushion Target

Crossovers

3-1/8 API 6 Bx
Weco Fig 1002 Union
One Wing Half
One Thread Half
w/ Ported Blank Plug

3-1/16 API 6 Bx
Weco Fig 1502
One Wing Half
One Thread Half
w/ Ported Blank Plug

2-9/16 API 6 Bx
Weco Fig 2202
One Wing Half
One Thread Half
w/ Ported Blank Plug

3-1/16 API 6 Bx
Weco Fig 2202
One Wing Half
One Thread Half
w/ Ported Blank Plug

Operating
Temperatures
F (C)

-20 (-29) Ambient

-20 (-29) Ambient
-20 (-29) Ambient
-20 (-29) Ambient
to 250 (121.1) Maximum to 250 (121.1) Maximum to 250 (121.1) Maximum to 250 (121.1) Maximum
Fluid Temperature
Fluid Temperature
Fluid Temperature
Fluid Temperature

Skid Length
in. (cm)

102
(259)

102
(259)

96
(244)

102
(259)

Skid Width
in. (cm)

72
(183)

73
(185)

72
(183)

73
(185)

Skid Height
in. (cm)

41
(104)

41
(104)

39
(99)

45
(114)

Skid Weight
lb (kg)

5,200
(2359)

5,600
(2540)

5,700
(2586)

6,500
(2948)

*Meets requirements of NACE MR-01-75

Note: Other sizes and configurations are available to meet the needs of most applications.

These ratings are guidelines only.

For more information, consult your local Halliburton representative.

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.

TT-222

1994 Halliburton Energy Services

Printed in USA

H A L L I BU R TO N

STE/Indirect Fired Heaters

Description
Indirect fired heaters are used to
heat the well production after it
flows out of the wellhead and
before the separation process.
Heaters used for well testing
usually use water or glycol as the
transfer medium. These heaters can
reheat the process fluid after it is
cooled by the pressure drop expansion across the choke.

Reduce viscosity of oil to improve

burner efficiency

It may become necessary to heat the

well production during testing
operations for several reasons:

Is available for gas, diesel, and

electric for maximum flexibility

Prevent hydration
Improve separation of oil/water
emulsions and foaming oils by
reducing surface tension and
viscosity
Dissolve paraffin and asphaltines
to prevent deposits from forming
on the interior components of the
separation equipment

Features and Benefits

Features a split-coil design, which
allows more efficient thermal
conductivity and reduced pressure drop through the coil
package
Has a portable, modular design

Has a bypass manifold, which

helps during cleanup by reducing
damage to coils during cleanup
Has built-in control and safety
shutdowns as an integral part of
the design
Meets applicable industry standards
Can be third-party certified in
compliance with requirements

Indirect Fired Heater

TOOLS AND TESTING

Operation
Indirect gas or diesel fired heaters
consist of a large, low-pressure tank
that contains water or glycol heated
by a gas or diesel burner in a fire
tube. The fluid to be heated passes
through high-pressure flow tubes or
coils, which are installed in the tank
and covered by water or glycol. The
coils make several passes inside the
tank to give the largest amount of
surface area possible for heat
transfer.
All Halliburton heaters incorporate
a split coil design with preheat and
post heat coils. The preheat coils
heat the well effluent before it
passes through a choke. The post
heat coils reheat the well effluent
after it has passed through the
choke.

Indirect Fired Heater

Capacity
BTU/hr

1 MM

2 MM

2 MM

3 MM

3 MM

Pressure Rating
psi (kPa)

5,000
(34475)

5,000
(34475)

10,000
(68950)

5,000
(34475)

10,000
(68950)

Preheat Coils

12-3XXH

14-3XXH

14-4.5 x 2.5

18-3XXH

18-4.5 x 2.5

Rating
psi (kPa)

5,000
(34475)

5,000
(34475)

10,000
(68950)

5,000
(34475)

10,000
(68950)

Postheat Coils

6-3XH

8-3XH

8-3XXH

10-4XH

8-4XH

Rating
psi (kPa)

2,000
(13790)

2,000
(13790)

5,000
(34475)

2,000
(13790)

2,000
(13790)

Choke
psi (kPa)

2 in.
2 in.
2 in.
2 in.
2 in.
5,000 (34475) 5,000 (34475) 10,000 (68950) 5,000 (34475) 10,000 (68950)

Service

H2S*

H2S*

H2S*

H2S*

H2S*

Heater OD
in. (cm)

48
(122)

60
(152)

60
(152)

72
(183)

60
(152)

Skid Length
in. (cm)

192
(488)

288
(732)

288
(732)

359
(912)

359
(912)

Skid Width
in. (cm)

60
(152)

90
(229)

90
(229)

96
(244)

96
(244)

Skid Height
in. (cm)

72
(183)

120
(305)

120
(305)

114
(289)

114
(289)

Skid Weight
lb (kg)

15,000
(6804)

20,000
(9072)

23,000
(10433)

25,000
(11340)

25,000
(11340)

*Meets the requirements of NACE MR-01-75

Note: Other sizes and configurations are available to meet the needs of most applications.
These ratings are guidelines only.
For more information, consult your local Halliburton representative.

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.

TT-224

1994 Halliburton Energy Services

Printed in USA

H A L L I BU R TO N

STE/SurfaceTestTree
Description
HES test trees are designed to meet
the requirements of individual well
testing operations. They can be
adapted with a crossover to various
sizes of tubing or drillpipe.
The test tree consists of a central
body containing
Four gate valves
Safety actuators as required
Swivel to allow tubing rotation
for manipulating downhole
equipment without turning the
test tree
Lower master valves for complete
surface test tree isolation
Chemical injection subs to allow
injection of hydrate inhibitors,
foam, or emulsion breakers as
needed
Each tree is supplied with a lifting
sub to allow rig elevators to raise
and lower the tree in the derrick.
Wing blocks are attached to the tree
to enable flexible flow lines to be
connected to the surface tree.
The test trees are available in
10,000- and 15,000-psi working
pressure models. The HES Surface
Test Tree configuration has a tensile
rating of 400,000 lb at maximum
working pressure.

Features and Benefits

The Surface Test Tree
Features stiff joints to allow the
installation to be freestanding
above the rig floor if desired

The manual wing valve is normally

used for kill line connection,
circulating procedures, or stimulation.

Meets applicable industry standards for added safety

Can be third-party certified in
accordance with requirements

Operation
The safety system can be as simple
as a manual pump, or it can be
controlled automatically by emergency shutdown (ESD) pilots
throughout the testing equipment.
The test tree has a normally closed
flow valve that is controlled by a
hydraulic actuator, which can be
tied into an ESD system with
manual or various degrees of
automation.
It also contains a check valve that
can be fitted to the kill valve. The
check valve is designed to prevent
well effluents from flowing back
through the kill line to the pumps,
which allows the kill valve to be left
open during testing operations.
The tree's swab valve and top
connection allow slickline, electric
line, coiled tubing, and other
operations if the BOPs and lubricator on top of the test tree are
adapted.

TOOLS AND TESTING

Surface Test String

Surface Test Tree

Description
in.

3-1/16 10,000 STT

2-9/16 15,000 STT

3-1/16 15,000 STT

Valves

Cameron Type FC
3-1/16 in. 10,000

Cameron Type FC
2-9/16 in. 15,000

Cameron Type FC
3-1/16 in. 15,000

Service

H2S*

H2S*

H2S*

Working Pressure
psi (kPa)

10,000
(68950)

15,000
(103425)

15,000
(103425)

End Connections
in.

5.75 - 4 Stub Acme Box 5.75 - 4 Stub Acme Box 5.75 - 4 Stub Acme Box

Flanges
in.

3-1/16 API 6 Bx 10,000

2-9/16 API 6 Bx 15,000

3-1/16 API 6 Bx 15,000

Studs

A320 GR L7
NACE Class II

A320 GR L7
NACE Class II

A320 GR L7
NACE Class II

Wing Tee

w/ Fluid-Filled Target

w/ Fluid-Filled Target

w/ Fluid-Filled Target

Crossovers
in.

3-1/16 API 6 Bx X Weco 3-1/16 API 6 Bx X Weco 2-9/16 API 6 Bx X Weco

Fig 1502 Union
Fig 2202 Union
Fig 2202 Union

Lift Eye
in. (mm)

3 (76) dia hole x 1.5 (38) 3 (76) dia hole x 1.5 (38) 3 (76) dia hole x 1.5 (38)
thick x pin thread
thick x pin thread
thick x pin thread

Lift Sub
in.

5.75 - 4 Stub Acme

pin x pin

Operating
Temperature
F (C)

-20 (-29) Ambient

Temperature
250 (121) Maximum
Fluid Temperature

Check Valve
in.
Surface Chemical
Injection Valve
in.
Swivel
in.

5.75 - 4 Stub Acme

pin x pin

5.75 - 4 Stub Acme

pin x pin

-20 (-29) Ambient

-20 (-29) Ambient
Temperature
Temperature
250 (121) Maximum Fluid 250 (121) Maximum Fluid
Temperature
Temperature

3-1/16 10,000 API 6 Bx 2-9/16 15,000 API 6 Bx

Flange
Flange

3-1/16 15,000 API 6 Bx

Flange

5.75 - 4 Stub Acme

pin x box

5.75 - 4 Stub Acme

pin x box

5.75 - 4 Stub Acme

pin x box

5.75 - 4 Stub Acme

pin x box

5.75 - 4 Stub Acme

pin x box

5.75 - 4 Stub Acme

pin x box

Lower Master Valve

in.

5.75 - 4 Stub Acme

pin x box
10,000 psi MAWP

5.75 - 4 Stub Acme

pin x box
15,000 psi MAWP

5.75 - 4 Stub Acme

pin x box
15,000 psi MAWP

Stiff Joints
in.

5.75 - 4 Stub Acme

box x pin
10,000 psi MAWP

5.75 - 4 Stub Acme

box x pin
15,000 psi MAWP

5.75 - 4 Stub Acme

box x pin
15,000 psi MAWP

Tensile Rating
lb (kg)

400,000 (181437)
@ MAWP

400,000 (181437)
@ MAWP

400,000 (181437)
@ MAWP

*Meets requirements of NACE MR-01-75

Note: Other sizes, configurations, and pressure ratings are available for most applications
**Maximum Allowable Working Pressure

These ratings are guidelines only.

For more information, consult your local Halliburton representative.

Upper Test String

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.

TT-225

1994 Halliburton Energy Services

Printed in USA

H A L L I B U RTO N

STE/Test Tank
Description
The HES pressurized test tank is
used to store produced liquids
before they are disposed. It can also
be used as an additional stage of
separation.
Test tanks are manufactured for
various volumes, and they may be
made with twin compartments.
They are made with the necessary
inlet and outlet piping and safety
relief system where required. They
have a manway for internal inspection and debris removal. Where
required, the tanks have the necessary skid mounts for vertical or
horizontal storage.
Pressure-containing tanks range
from 50 to 250 psi working pressure. The tanks keep the necessary
backpressure on the transfer pump
for production disposal systems.
Pressure integrity of the tank is also
important during H2S production
since no venting to the atmosphere
occurs under normal conditions.
The pressurized test tank can be
used as a second-stage, two-phase
separator with the addition of
necessary gas, fluid meter, and
control valving. The test tank is
very effective where a longer
retention time is needed for good
separation of gas and fluids.

Features and Benefits

This test tank
Is pressurized, so no gases are
vented to atmosphere near the
well test equipment
Allows a higher operating
pressure, which allows higher
rates and pressures when the tank
is used as an additional stage of
separation.
Is shipped in a standard ISO
shipping container envelope,
which reduces shipping costs
Features magnetic level indicators
for increased safety and convenience (No glass).
Can be third-party certified in
accordance with requirements
Operation
This test tank was designed to
operate at 250 psi maximum
allowable working pressure. The
skid and frame are made of box
beam rather than I-beam for
durability and safety.
Tanks can be either pressurized or
atmospheric. The pressurized tank
provides a closed system when well
testing.

TOOLS AND TESTING

Test Tank

Test Tank
Capacity
bbl

100

100
calibration

100

100
Dual 50 bbl

50

50
Heli-Lift

Pressure Rating
psi (kPa)

250 (1723)

250 (1723)

50 (344)

50 (344)

50 (344)

Atmospheric

Vessel Size
in. x ft (cm x m)

84 x 14
(213 x 4.3)

84 x 14
(213 x 4.3)

84 x 14
(213 x 4.3)

84 x 14
(213 x 4.3)

84 x 14
(213 x 4.3)

Rectangular

Service

H2S*

H2S*

H2S*

H2S*

H2S*

H2S*

Skid Length
in. (cm)

114
(290)

114
(290)

96
(244)

108
(274)

96
(244)

125
(318)

Skid Width
in. (cm)
Skid Height
in. (cm)

96
(244)
239
(607)

96
(244)
239
(607)

96
(244)
240
(610)

96
(244)
240
(610)

96
(244)
180
(457)

67
(170)
91
(231)

Skid Weight
lb (kg)

28,000
(12701)

15,000
(6804)

15,000
(6804)

10,000
(4536)

3,800
(1724)

Inlet

4 in.-600#

28,000
(12701)
3 in.-600#
(2)

3 in.-600#

3 in.-600#

3 in.-600#

Gas Outlet

4 in.-150#

3 in.-150#

4 in.-150#

4 in.-150#

4 in.-150#

Oil Outlet

3 in.-150#

4 in.-600#
(2)

4 in.-600#

4 in.-600#

4 in.-600#

Bypass

4 in.-600#

4 in.-600#

3 in.-600#

3 in.-600#

3 in.-600#

Drain

2 in.-150#

2 in.-150#
(2)

2 in.-150#

2 in.-150#

2 in.-150#

Relief

6 in.-150#

6 in.-150#

4 in.-150#

4 in.-150#

4 in.-150#

Compartment

*Meets the requirements of NACE MR-01-75

Note: Other sizes and configurations are available to meet the needs of most applications.

These ratings are guidelines only.

For more information, consult your local Halliburton representative.

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.

TT-226

1994 Halliburton Energy Services

Printed in USA

H A L L I B U RTO N

U-Shaped Burner Boom

Description
Booms are used to extend the Sea
Emerald crude oil burner and gas
flare a set distance from an offshore
rig to allow the safe burning of the
produced hydrocarbons. The boom
is a portable U-shaped truss assembly. The kingpost attaches to the rig
structure and is braced with three
back struts. Vertical suspension
cables and horizontal wind-stay
cables support the boom, so a rig
crane is not needed for support.
The length of the boom depends on
anticipated flow rates.
A boom is used to avoid exposing
property and personnel to excessive
radiation levels from the combustion process. The U-shaped configuration helps provide added security
for personnel using the boom.

Features and Benefits

The U-boom
Is modular and is available in
three lengths: 60, 90, or 120 ft
Is lightweight, which reduces the
crane capacity requirement and
simplifies installation
Features a boom attachment point
at the kingpost designed to easily
accept the boom into a u-shaped
slot, which reduces and simplifies
installation time
Has integral air, water, and vent
lines to reduce weight and piping
congestion
Provides a protected walkway for
added safety

U-Shaped Burner Boom

TOOLS AND TESTING

Operation
Booms are typically installed on
either side of an offshore rig. The
well test piping typically includes a
manifold to divert flow to the
downwind side for safe operation.
In addition to the oil and gas lines,
there are water, air, vent, and pilot
gas lines.

Well Test Booms

Boom Length
ft (m)

60 (18.3)

90 (27.4)

120 (36.6)

Boom Weight
lb (kg)

7,674 (3481)

11,511 (5221)

15,348 (6962)

Design Loading

Lines

1,000 lb Burner

Type

Size

Nominal Pressure

100 mph Wind

Oil

3-in. Sch 80

1,440 psi

1 G Vertical Load

Gas Flare

4-in. Sch 80

995 psi

1/2 G Transverse Load

Vent (2)

4-in. Sch 80

To Atm.

1/2 G Longitudinal
Load

Water

3-in. Sch 80

525 psi

Spare (2)

3-in. Sch 80

To Atm.

Air

3-in. Sch 80

150 psi

These ratings are guidelines only.

For more information, consult your local Halliburton representative.

Burner Boom Assembly

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.

TT-227

1994 Halliburton Energy Services

Printed in USA

HALLIBURTON

Description
The LT-20 Swivel is a heavy-duty swivel
designed to rotate either with or without the
drillpipe weight hanging on it. It can be used
with standard UNITEST TREE surface
equipment and has equivalent strength and
pressure ratings. Because this swivel can be
rotated with pipe weight hanging on it, it is
suitable for offshore operations where pipe
weight is not supported by slips during
rotation.

Operation
Normally, the swivel is installed above the
standard master valve to allow the drillpipe
to rotate without having to break surface
flowline connections. Maximum recommended loads for the standard service LT-20
Swivel, based on bearing strength, are listed
in Table 1. Maximum recommended loads for
the sour-gas service LT-20 Swivel, based on
yield strength, are listed in Table 2.

Table 1
Internal Pressure
psi (mPa)

Maximum Recommended Load

lb (kg)
540, 000
(244,900)

5,000
(34.5)

477,000
(216,400)

10,000
(68.9)

415,000
(188,200)

15,000
(103.4)

352,000
(159,900)
Table 2

Internal Pressure
psi (mPa)

Maximum Recommended Load

lb (kg)
484,000
(219,500)

5,000
(34.5)

421,300
(191,100)

10,000
(68.9)

358,700
(162,700)

LT-20 SWIVEL

LT-20 Swivel

LT-20 Swivel Specifications

OD
in. (cm)

10.25
(26.035)

13.37
(33.960)

10.25
(26.035)

ID
in. (cm)

3.0
(7.62)

3.0
(7.62)

2.68
(6.807)

Connections

4.375 in. - 6
Stub Acme
Pin x Box

5.75 in. - 4
Stub Acme
Pin x Box

4.375 in. - 6
Stub Acme
Pin x Box

Tensile Rating*
lb (kg)

484,000 lb/0 psi

421,300 lb/5,000 psi
358,700 lb/10,000 psi
352,000 lb/15,000 psi

400,000 lb at
Max WP

540,000 lb/0 psi

477,000 lb/5,000 psi
415,000 lb/10,000 psi
352,000 lb/15,000 psi

Working Pressure**
psi (kPa)

10,000
(69,000)

15,000
(103,000)

15,000
(103,000)

Service

H2S***

H2 S***

H2 S***

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.)
*** Meets requirements of NACE MR-01-75.
These ratings are guidelines only. For more information, consult your local Halliburton representative.

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.

TT-234

1994 Hallibur ton Energy Services

Printed in USA

H A L L I B U RTO N

Description
The UNITEST TREE is a suite of surface
control equipment that uses a safety device to
help control the flow of oil or gas from a well.
When necessary, fluid may be pumped
through the UNITEST TREE surface control
equipment for subsurface pressure control.
The equipment can also be used for swabbing
operations.

A lightweight (10,000-psi working

pressure) master valve and a heavyweight (15,000 psi) master valve are
available.

The equipment has one standard manifold that fits all manifold housings.

All valves are quick-opening and seal

against high-pressure oil and gas.

UNITEST TREE equipment is available for

either type S (regular gas) or type SG for H2S
(sour gas) service. Type S parts have received
a standard heat treatment. Type SG parts
have received a modified heat treatment and/
or special materials that make them suitable
for sour gas service.

All LT-20 adapters and nipples adapt to

the UNITEST TREE equipment to provide
various thread selections.

Features and Benefits

All subassemblies are interchangeable,
and master valves can be stacked.

The manifold housing and the master

valve have been separated and made into
two components.
Swivel, nonswivel, and safety types of
manifold housing are available.

Operation
The UNITEST TREE subassemblies common
4 3/8-in. - 6 stub Acme thread (male or female)
allow component interchange. The flow tee
and master valve are separate components.
Therefore, a master valve can be run with or
without a swivel, and master valves can be
stacked in tandem.
A remote-controlled safety valve can be
installed in place of or in tandem with the
flow tee and can provide a way to close in a
well at the surface from a remote location.

UNITEST TREE EQUIPMENT

Lift Nipple Specifications

Working Pressure
psi (kPa)

15,000
(103,000)

Service

Bar Drop Device

Specifications
Working Pressure
psi (kPa)

10,000
(69,000)

Service

SG

Access Valve Specifications

Working Pressure
psi (kPa)

10,000
(69,000)

Service

SG

Remote-Controlled Safety
Valve Specifications
Working Pressure
psi (kPa)

10,000
(69,000)

Service

SG

Pressure-Balanced Swivel
Specifications

Flow Tee Specifications

Working Pressure
psi (kPa)

10,000
(69,000)

Service

SG

Working Pressure
psi (kPa)

10,000
(69,000)

Service

SG

Testing Manifold
Specifications
Working Pressure
psi (kPa)

10,000
(69,000)

Weight
lb (kg)

560
(254.01)

Service

SG

Master Valve Specifications

Working Pressure
psi (kPa)

10,000
(69,000)

Makeup Length
in. (cm)

22.25
(56.515)

Service

SG

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. Hallibur ton'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 EQ UIPMENT, PRODUCTS, MATERIALS OR SER VICES IS IN NO WAY GUARANTEED. In no event shall Hallibur ton be
liable for special, incidental, indirect, punitive or consequential damages.

TT-235

1994 Halliburton Energy Services

Printed in USA

HALLIBURTON

Description
The A-Model Downhole Shut-In Tool is a
wireline retrievable tool consisting of two
separate assemblies: a wireline-set locking
receptacle assembly and an electric wireline
shut-off prong. The locking receptacle
assembly is set in the tubing and provides a
downward stop, locking engagement, and
sealing bore for the descending shut-off
prong. When the two assemblies are successfully united, the operator manipulates the
shut-off prong valve to control well flow.
Using an electrical wireline and a pressure
gauge, the downhole shut-in tool significantly improves reservoir data accuracy and
reduces testing time by eliminating the
wellbore storage effect.

Features and Benefits

Operation
A standard lock mandrel, an adapter, and a
locking sub make up the locking receptacle
assembly. The lock mandrel can be of any
variety designed to lock into the profile
nipple in the tubing string.

A-Model Downhole
Shut-In Tool

A-MODEL DOWNHOLE SHUT-IN TOOL

A-Model Downhole
Shut-In Tool Specifications
Casing Size

2 3 /8 in.

2 7/8 in.

3 1/2 in.

Prong OD
in. (cm)

1.844
(4.68)

2.25
(5.72)

2.69
(6.83)

Lock Sub ID
in. (cm)

0.828
(2.10)

1.172
(2.98)

1.486
(3.77)

Lock Sub OD
in. (cm)

1.766
(4.49)

2.188
(5.58)

2.615
(6.64)

Length
in. (cm)

68.6
(174.24)

69.1
(175.51)

73.1
(185.67)

Closing Force
lb (kg)

300
(135.6)

350
(158.2)

450
(203.4)

Release Force
lb (kg)

450
(203.4)

500
(226.0)

550
(248.6)

Working Pressure*
psi (kPa)

10,000
(69,000)

10,000
(69,000)

10,000
(69,000)

Temperature Range
F (C)

32 to 325
(0 to 163)

32 to 325 32 to 325
(0 to 163) (0 to 163)

Flow Area
in.2 (cm2)

0.23
(1.49)

0.60
(3.88)

1.09
(7.04)

Service

H2S

H2 S

H2S

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

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.

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.

TT-236

1994 Hallibur ton Energy Services

Printed in USA

HALLIBURTON

Description
The Anchor Pipe Safety Joint is used to
remove the drillpipe and the tools above the
safety joint when the anchor pipe is stuck
and the drillpipe can be rotated. The safety
joint is run between the packer and anchor
pipe.
The safety joint can be adapted to any multipacker operation in which the possibility of
sand bridging exists, such as for tests in
casing with a straddle packer or when sandladen fluids used for stimulation are placed
in perforations between packers.

In addition, use of the Anchor Pipe Safety

Joint eliminates the time required to wash
over the packer when only the anchor pipe is
stuck.
Operation
The Anchor Pipe Safety Joint releases only
when string weight has been neutralized at
the location of the safety joint and right-hand
rotation is applied to the testing string. Righthand rotation backs out the threaded nut at
the top of the case, separating the two safety
joint components.

ANCHOR PIPE SAFETY JOINT

Anchor Pipe Safety Joint Specifications

3

Size

3 /4 in.

5 in.

OD
in. (cm)

3.75
(9.525)

5.0
(12.7)

ID*
in. (cm)

0.75
(1.905)

1.50
(3.81)

Makeup Length
in. (cm)

46.66
(118.52)

48.00
(121.92)

Top Thread
Connection

2 /8 IF Tool
Joint-Female

Bottom Thread
Connection

2 /8 IF Tool
Joint-Male

3 /2 FH Tool
Joint-Female
1

3 /2 FH Tool
Joint-Male

* This is not a fullbore tool. This ID reflects the flow passage diameter
through the tool.

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.

TT-237

1994 Hallibur ton Energy Services

Printed in USA

HALLIBURTON

Description
BV (balanced valve) retrievable bridge plugs
consist of the following:

Cup and packer sealing elements

Two sets of hookwall slips

Pressure-balanced bypass

The two-piece cup arrangement provides the

advantage of a reinforced or backup seal.
Two sets of hookwall slips use a dual wedge
arrangement to help anchor the tool against
pressure from either direction. The bypass
provides a large fluid passage to help run or
remove the plug.
This plug can be run alone on tubing or
below an RTTS or CHAMP packer. The
plug is run in the hole, set, and released from
the tubing or packer. It is left in place until
the tubing or packer is relatched to it; then
the bypass valve is opened, and the slips are
released. The plug may then be moved to a
different location and reset or be removed
from the well.
Features and Benefits
Pressure-balanced bypass valve

Positive indication when plug is released

from overshot

Ease of operation

Operation
During the setting process, the plug is run to
the necessary depth and slacked off a few
feet. Next, the tubing is rotated to the right
and tubing weight is set down.
When the bridge plug is released, right-hand
torque is applied after the tool begins to take
weight. The tubing is then raised to disengage the pins in the overshot and to close the
bypass.
During standard retrieval operations, the
tubing is lowered until it begins to take
weight to engage the overshot. The bypass is
then opened to equalize pressure. Left-hand
torque is applied to the tubing while it is
picked up to retrieve the plug or to move and
reset the plug.
For the bridge plug to be retrieved on tubing,
an overshot must first be attached to the
tubing and run into the hole until it reaches
the top of the sand or other solids. The sand
must then be reversed out and the tubing
must be engaged with the bridge plug.
Finally, the tubing must be picked up to
remove the plug from the well. This same
procedure is followed for wireline retrieval,
except the sand is not reversed out above the
tool.

BV Retrievable
Bridge Plug

BV RETRIEVABLE BRIDGE PLUG

BV Retrievable Bridge Plug Specifications

Casing Size*

4 1/2 in.

5 1/2 in.

7 in.

8 5/8 in.

9 5/8 in.

OD
in. (cm)

3.75
(9.53)

4.60
(11.68)

5.95
(15.11)

7.35
(18.67)

8.20
(20.83)

End Connections

2 3 /8 EUE

2 7/8 EUE
2 3/8 EUE

2 7/8 EUE

4 1/2 IF
3 1/2 UN

4 1/2 IF
3 1/2 UN

Length
in. (cm)

61.77
(156.90)

62.84
(159.62)

63.52
(161.34)

63.85
(162.18)

70.43
(178.90)

Tensile Rating**
lb (kg)

71,200
(32,300)

71,200
(32,300)

71,200
(32,300)

61,100
(27,700)

61,100
(27,700)

Working Pressure
psi (kPA)

10,000
(69,000)

8,000
(55,200)

6,000
(41,400)

5,000
(34,500)

5,000
(34,500)

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.

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.

TT-238

1994 Hallibur ton Energy Services

Printed in USA

HALLIBURTON

Description
Instream carriers carry as many as four
pressure or temperature gauges in the flow
stream to monitor downhole conditions
while maintaining a full opening through the
tools.
The carriers are designed to carry 1-in.
diameter electronic or mechanical gauges.
Recorders are suspended on the inside of the
running case, which has cushioning devices
to protect the gauges from shock.

Features and Benefits

Permits unrestricted flow through the
tools

Allows wireline operations to be run

Facilitates a faster response to temperature changes

Instream Gauge
Carrier

INSTREAM GAUGE CARRIER

Instream Gauge Carrier Specifications

OD
in. (cm)

8.00
(20.32)

5.85
(14.86)

5.50
(13.97)

5.50
(13.97)

5.00
(12.70)

ID
in. (cm)

3.65
(9.27)

2.25
(5.72)

2.25
(5.72)

2.00
(5.08)

1.90
(4.83)

End Connections

5 1/2 CAS
3 in. VAM
5 in. VAM

3 1/2 IF
3 7/8 CAS

3 1/2 IF
3 7/8 CAS

3 1/2 IF
3 7/8 CAS

3 1/2 IF
3 7/8 CAS

Length
in. (cm)

164.8
(418.59)

93.2
(236.73)

93.2
(236.73)

92.6
(235.20)

92.6
(235.20)

Tensile Rating*
lb (kg)

667,000
(302,000)

450,000
(204,000)

303,000
(137,000)

342,000
(15,500)

277,000
(125,500)

Burst Rating*
psi (kPa)

9,500
(65,500)

16,000
(110,000)

12,000
(82,500)

15,000
(103,000)

11,000
(75,500)

Collapse Rating*
psi (kPa)

10,500
(72,000)

13,500
(93,000)

11,000
(75,500)

13,000
(89,500)

10,000
(69,500)

Number of Gauges

The values of tensile, burst, and collapse strength are calculated with new tool conditions, Lames
formula for burst and collapse strength, and stress area calculations for tensile strength. Pressure
rating is defined as differential pressure at the tool. (Differential pressure is the difference in pressure
between the casing annulus and tool ID.)
These ratings are guidelines only. For more information, consult your local Hallibur ton representative.

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.

TT-239

1994 Hallibur ton Energy Services

Printed in USA

HALLIBURTON

Description
The J-Model downhole shut-in tool uses a
tubing-retrievable bypass receptacle and an
electric-wireline-retrievable J-latch shutoff
prong. The bypass receptacle is a large-bore
valve that also serves as a locking receptacle
for the shutoff prong. The shutoff prong is
attached to a surface readout gauge for realtime downhole information and operates the
downhole shut-in tool assembly. The tool
reduces testing time by eliminating wellbore
storage effect.

Equalizing pressure

Conducting pressure to the gauge

Features and Benefits of the Bypass

Receptacle
The downhole shut-in tools bypass receptacle can be run in by these methods:

The diagram shows how the prong can be

used for three buildups and three flow
periods. If more are required, the prong can
be reinserted without retrieval, allowing as
many cycles as required. If fewer cycles are
required, the tool can be shut to be retrieved
after the first or second shut-in. A simple Jlatch mechanism serves as the counter.

Below the packer on the tubing end

Above the packer

By slickline means (locked into a 3.813-in.

ID or larger landing nipple)

The receptacle is closed by applying wireline

tension through the shutoff prong. The valve
is closed by moving a metal-to-metal seal
through the flow path to protect the more
easily flow-damaged elastomeric seal that
follows it. The receptacle operates smoothly
to protect the sensitive surface readout (SRO)
gauge attached to it.

The prong is landed and locked into the

bypass assembly on electric wireline. The
SRO gauge is threaded onto the top of it and
is always monitoring pressure below the
prong. The prong contains spring-loaded
keys that lock into the bypass receptacle and
hold it there until the indexing feature of the
tool allows it to be removed. The diagram
below describes the indexing function.

The prong also incorporates a shear sub to

enable the sensitive pressure gauge to be
retrieved undamaged if problems are encountered while retrieving the prong. Jars
can then be used safely. Memory gauges can
also be hung on a shock absorber below the
prong for additional data gathering.

To reopen the valve once it is closed, the

tension of the wireline must be slacked off.
This reopens the valve in the prong and
equalizes the pressure across the tool. Once
the pressure has been reduced to about 100
psi, the bypass receptacle reopens by its own
spring force.

J-Model Downhole
Shut-In Tool

Features and Benefits of the Shutoff Prong

The shutoff prong has three purposes:

Engaging the bypass valve

The shutoff prongs indexing function allows the prong

to be used for three buildups and three flow periods.

J-MODEL DOWNHOLE SHUT-IN TOOL

J-Model Downhole Shut-In Tool Specifications

Type

Tubing
Retrievable

OD
in. (cm)

5.00
(12.7)

5.00
(12.7)

3.80
(9.65)

ID
in. (cm)

2.25
(5.72)

2.109
(5.36)

2.25
(5.72)

End Connections

3 1/2 10.3 CS

3 1/2 10.3 CS

N/A

Length
in. (cm)

60.0
(152.4)

60.0
(152.4)

38.5
(97.79)

Tensile Rating*
lb (kg)

233,000
(105,000)

233,000
(105,000)

N/A

Working Pressure**
psi (kPa)

10,000
(69,000)

10,000
(69,000)

10,000
(69,000)

Service

H2 S

H2S

H2S

Temperature Range
F (C)

32 to 325
(0 to 163)

32 to 325
(0 to 163)

32 to 325
(0 to 163)

Prong OD
in. (cm)

2.297
(5.83)

2.156
(5.48)

2.257
(5.73)

Prong Flow Area

in. (cm)

0.785
(5.07)

0.650
(4.2)

0.785
(5.07)

Total Flow Area

in. (cm)

2.50
(16.15)

2.70
(17.44)

2.50
(16.15)

Tubing
Wireline
Retrievable Retrievable

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

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.

TT-240

1994 Hallibur ton Energy Services

Printed in USA

HALLIBURTON

Description
The Pump-out Disc/Reversing valve allows
removal of free oil or gas in the pipe (minimizing fire hazard) while removing the tools
from the hole. The valve is used to circulate
and condition drilling fluid when necessary.
As the drillpipe is removed from the hole, the
reversing valve serves as a drain allowing
fluids in the pipe to drain into the hole.
All Pump-out Disc/Reversing valves have a
5/8-in. diameter opening for reverse circulating after the disc is ruptured.

Features and Benefits

The valve can be run in or below drill
collars closer to the testing tools in cases
where the small inside diameter of
collars might interfere with the passage
of an impact-type reversing sub bar.

The valve requires only hydraulic

pressure to open the reversing port,
particularly important in a crooked hole.

The valve can be run below a restriction

in the string, such as a Slip Joint Safety
Valve.

The valve eliminates the need for a Bar

Drop Sub in the surface control equipment.

Operation
The Pump-out Disc/Reversing Valve may be
placed at any point in the string above the
other tools and is in the closed position as the
tools are run into the hole.
To open the reversing port, the disc is ruptured by applying internal pressure at least
1,200 psi above hydrostatic pressure. This
ruptures the disc and opens a 5/ 8-in. diameter
port for reverse circulating.
Discs will withstand external pressure up to
10,000 psi.
Note: it is important that the grooved side of
the disc be turned toward the outside of the
valve body.

PUMP-OUT DISC/REVERSING VALVE

Pump-Out Disc/Reversing Valve Specifications

Sizes

3 1/2 in.

4 in.

4 1/2 in.

5 in.

ID
in. (cm)

2.12
(5.38)

2.62
(6.65)

2.75
(6.99)

2.75
(6.99)

OD
in. (cm)

5
(12.7)

6
(15.24)

5.75
(14.61)

6.75
(17.15)

Length
in. (cm)

12
(30.48)

12
(30.48)

12
(30.48)

12
(30.48)

Thread Description

3 1/2 API
Full Hole

4 Hughes
H-90

4 1/2 API
Full Hole

5 Hughes
H-90

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.

TT-241

1994 Hallibur ton Energy Services

Printed in USA

HALLIBURTON

Description
The Remote-Controlled Safety Valve is used
when surface equipment is located high
above the rig floor or when, for any reason, it
is desirable to control a well from a remote
location during testing.

open the remote-controlled device. Table 1

lists external opening pressures required for
various well surface pressures.
When the surface temperature is below 32F,
the cold temperature seal must be used.

Features
Allows well control from a remote
location while testing is performed

Opens with application of fluid or gas

pressure

Operation
The valve is normally closed but can be
opened by application of fluid or gas pressure. It will remain open as long as external
pressure is maintained. Release of the
pressure allows a heavy spring and internal
well pressure acting over a small differential
area to close the safety valve. Well pressure
then helps keep the sliding valve closed.
Any well pressure at the surface that is acting
over the differential area inside the safety
valve also affects the pressure required to

Table 1
Surface Pressure
psi (mPa)

Opening Pressure*
psi (mPa)

2,500
(17.2)

530
(3.65)

5,000
(34.5)

705
(4.86)

7,500
(51.7)

880
(6.07)

10,000
(68.9)

1,055
(7.27)

15,000
(103.4)

1,405
(9.69)

* Fluid or gas pressure is applied through the inlet plug.

Remote-Controlled
Safety Valve
Table 2
Internal Pressure

Maximum
Recommended Load

0 psi
(0 MPa)

484,000 lb
(219,500 kg)

5,000 psi
(34.5 MPa)

421,300 lb
(191,100 kg)

10,000 psi
(68.9 MPa)

358,700 lb
(162,700 kg)

REMOTE-CONTROLLED SAFETY VALVE

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.

TT-242

1994 Hallibur ton Energy Services

Printed in USA

HALLIBURTON

Description
The Above-Packer Bourdon Tube (BT)
running case positions a pressure recorder
above the packer. Pressure is recorded
directly from the flow stream.
The Anchor Shoe Blanked-Off BT running
case is used when a gauge is run below the
packer. It becomes a part of the anchor pipe
and provides support for the packer.
The gauge is blanked-off from the flow
stream; however, it records annulus pressure
transmitted through the holes in the inner
case.
Similar running cases without the anchor
shoe feature can be run at any point in the
anchor above the shoe joint.
A correlation between the Above-Packer
pressure recording and the Blanked-Off
gauge recording can verify suspicion of
plugging or other questionable events.

Features and Benefits

The above-packer running case supports
the pressure recorder that records
flowing pressure during a test.

The blanked-off running case provides

support for the packer.

The blanked-off running case supports a

gauge that is blanked-off from the flow
stream but records annulus pressure from
fluid passing through the perforations in
the inner case.

Operation
The Above-Packer BT running case positions
a pressure recorder above the packer. The
above-packer pressure recorder is supported
in the center of the running case. It permits
formation fluid to flow through the case and
around the recorder. Pressure is recorded
directly from the flow stream.
The Anchor Shoe Blanked-off BT case is
perforated to provide entrance of formation
fluid during the test. The gauge, which is
held in the inner case, is blanked-off from the
flow stream. The gauge records annulus
pressure transmitted through the holes in the
inner case. It can then provide a formation
pressure reading even if the perforations are
plugged and the upper gauge shows no
pressure buildup.

PRESSURE-RECORDER RUNNING CASES

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.

TT-243

1994 Hallibur ton Energy Services

Printed in USA

HALLIBURTON

Description
The VR Safety Joint is a compact, right-hand
safety joint used in the drillstem-testing
string. It is run immediately above the packer
assembly to ensure that a minimum number
of tools are left in the hole if it becomes
necessary to break the safety joint. The tools
bypass feature acts as an auxiliary to the
HYDRO-SPRING Tester bypass to allow
fluid to pass through the packer while the
workstring is being pulled out of the hole.
A spline and lug arrangement, joining the
male and female parts of the left-hand safety
joint thread, lock to prevent unintentional
back-off from the tool during normal manipulation of the drillpipe during testing.
Because of the spline and lug configuration,
the slips must be dropped in place before the
drillpipe is lowered after every stand of pipe
is pulled out of the hole.
The 3-in. and 3 7/8-in. VR Safety Joints have
an additional back-off limiter to prevent
premature release of the tool. A sleeve
secured with four 2,700-lb shear pins limits
the upward travel of the nut if it accidentally
backs off. Therefore, before the safety joint
can be completely backed off, approximately
10,000 lb must be set down to shear the pins.
This requirement allows the sleeve to move
out of the way, allowing complete back-off.
The sleeve is splined to the head and retains
the broken shear pin pieces.

Operation
The VR Safety Joint allows the operator to
back off or completely disengage from the
tool string if the testing string becomes stuck
below the safety joint. The safety joint is
backed off the testing string by vertical pull
and right-hand rotation. The operator should
be able to feel free travel (at least 8.3 in.) of
the safety joint mandrel by moving the pipe
up and down. Free travel may be greater
than 8.3 in. because of the change in pipe
length during up and down strokes caused
by hole drag. The pipe should be marked at
the upper and lower limits of the mandrel
travel. The complete break of the safety joint
thread must be made with the mandrel in the
upper position of the travel. A slight strain on
the pipe is helpful.
The safety joint is completely disengaged
after the pipe is moved up and down through
the stroke of the mandrel (marked on the
pipe) while right-hand torque is held on the
pipe. The tool size determines how many
cycles/rotations are required to disengage
the tool. On the 3-in. and 3 7/8-in. sizes,
approximately 10,000-lb pressure must be set
down on the second to fourth turns to shear
the pins on the limiter sleeve.
When the safety joint thread has been disengaged, all parts of the tool except the case
and seat may be retrieved on the drillpipe
under proper well conditions. The case, with
a space provided for fishing contact, is left at
the top of the fish.

Features and Benefits

Back-off limiters prevent premature
release of the tool.

The safety joint helps ensure that a

minimum number of tools are left in the
hole if the tool string becomes stuck
below the joint.

VR SAFETY JOINT

VR Safety Joint

VR Safety Joint Specifications

Size

1 3 /4 in.

3 in.

3 7/8 in.

5 in.

OD
in. (cm)

1.78
(4.521)

3.03
(7.696)

3.88
(9.855)

5.00
(12.700)

ID
in. (cm)

0.37
(0.940)

0.50
(1.270)

0.75
(1.905)

1.00
(2.540)

Makeup Length
in. (cm)

30.33
(77.038)

31.88
(80.975)

30.32
(77.013)

33.40
(84.836)

Top Thread
Connection

1.05 EUE 10 RD 2 1/2 10 N-3

Tubing-Female
Male

3 1/8 8 N-3
Female

3 1/2 FH Tool
Joint-Female

Bottom Thread
Connection

1.05 EUE 10 RD 2 1/2 10 N-3

Tubing-Male
Female

3 1/8 8 N-3
Male

3 1/2 FH Tool
Joint-Male

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.

TT-244

1994 Hallibur ton Energy Services

Printed in USA

HALLIBURTON

Description
The Hollow Plug Impact Reversing Sub is
used in the more difficult operations where
depth and high-pressure differential across
the plug sometimes make it difficult to open
a conventional reversing sub. It allows
removal of free oil or gas in the pipe (minimizing the risk of fire) while the tool is
coming out of the hole. It is also used to
circulate and condition the drilling fluid
when necessary.
Reversing subs have four main body parts:
body, impact plug, plug seat, and plug
retainer. Two sizes of Hollow Plug Impact
Reversing Subs and one heavy-duty plug are
used for all body sizes. One hollow plug
provides a 5/8-in. diameter opening for
reverse circulating after the plug is broken.
Another hollow plug provides a 3/4-in.
diameter opening after the plug is broken.
An optional 3/4-in. ID heavy-duty hollow
plug is available for extreme conditions.
Hollow impact plugs will withstand differential pressure to 10,000 psi, internally and
externally.

Features and Benefits

Hollow plug impact subs do not touch
the opposite wall of the sub body even
when high pressure differentials downhole tend to force the plug against the
opposite wall.

Hollow plug impact subs open easily at

high pressure differentials.

After the hollow plug is broken, the

reversing port is open without a plug
part to come into the test string, eliminating the possibility of the part lodging
against the fluted drop bar before it has
time to fall past the sub.

Operation
The Hollow Plug Impact Reversing Sub may
be run at any point in the string above the
other tools. To open the reversing port it is
necessary to break off the end of the hollow
plug. The hollow plug can be broken at any
time by dropping a fluted drop bar into the
pipe.

HOLLOW PLUG IMPACT REVERSING SUB

Hollow Plug Impact Reversing Subs

OD
in. (cm)

5.0
(12.7)

5.75
(14.605)

6.5
(16.51)

ID
in. (cm)

2.25
(5.715)
2.12
(5.385)

2.75
(6.985)

6.87
(17.450)

Tool Joint Threads

3 1/2 in. API

4 1/2 in. API
Internal Flush
Full Hole
4 in. Hughes
H-90
3 1/2 in. API
4 1/2 in. Hughes
Full Hole
Acme Streamline

Length
in. (cm)

12
(30.48)

12
(30.48)

12
(30.48)

Weight
lb (kg)

51
(23.13)
52
(23.59)

65
(29.48)

89
(40.37)

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.

TT-245

1994 Hallibur ton Energy Services

Printed in USA