Wireline Manual

WIRELINE SERVICES

TRAINING MANUAL

WIRELINE SERVICES

VISION Wood Group Wireline Services is a worldwide company dedicated to being the leader in all areas of Wireline Operations. We will set the standards for performance and quality to ensure the satisfaction of our customers. MISSION We are committed to providing our Customers with the best possible solutions for Well Surveillance, Production Enhancement and cost effective Well Intervention. Our goal is to perform this mission without incident to personnel or the environment. MEASURES Of SUCCESS TRIR Below One No Compliance INC’s No Environmental Incidents Retention of long-term customers Maintain high level of Staff Experience Maintain & Improve Equipment Reliability CORE VALUES Value, Care, Protection for our Human Resources Safety and Protection of the Environment Long term Customer Relationships Protection of Customer Assets Quality of our Performance Corporate Citizenship

SECTION 1 WIRELINE SAFETY PRACTICES AND CALCULATIONS

CONTENTS Topic

Page

1.1

SAFETY RULES AND OPERATING PROCEDURES

6

1.2

WORKING SAFELY IN H2S ENVIRONMENTS

11

1.3

FLUIDS, WEIGHTS, PRESSURES, AREAS, VOLUMES

13

ILLUSTRATIONS

Exhibit

Page

1.1

Bolt Tightening

9

1.2.1a

Area (Square)

13

1.2.1b

Area (Square)

13

1.2.1c

Area (Circle)

14

1.2.1d

Area (Diameter Of A Circle)

14

1.2.2a

Volume (Square)

15

1.3.3a

Pressure (Gradient)

17

SECTION 2 PRIMARY WIRELINE EQUIPMENT CONTENTS Topic

Page

2.1

GENERAL

25

2.2

WIRELINE MAINTENANCE

45

2.3

H²S AND CO² ENVIRONMENT AND LINE USE

48

ILLUSTRATIONS Exhibit

Page

2.1

Primary Wireline Equipment

26

2.1a

Chain

28

2.1.2

Load Binder

28

2.1.3

Rope Blocks and Ropes

30

2.1.4

Tree Connection

30

2.1.5a

Bowen Wireline Valve

32

2.1.6

Lubricator

34

2.1.7a

Otis Quick Union

34

2.1.7b

Bowen Quick Union

34

2.1.8

Stuffing Box

36

2.1.9

Grease Seal Stuffing Box

38

2.1.10

Rope Socket

39

2.1.11

Stem

40

2.1.12

Wireline Jar

41

2.1.13

Hay Pulley

42

2.1.14

Wireline Clamp

43

2.1.15

Re-spooling and Transferring Line

46

SECTION 3 WIRELINE TOOLS CONTENTS Topic 3.1 3.2 3.3 3.4 3.5 3.6 3.7 3.8 3.9 3.10 3.11 3.12 3.13 3.14 3.15 3.16 3.17

Page ROPE SIOCKETS STEMS STROKE JARS TUBULAR JARS KNICKLE JARS KNUCKLE JOINTS HYDRAULIC JARS GAUGE CUTTER SCRATCHERS IMPRESSION BLOCK BLIND BOX SWAGING TOOL OR TAPERED GAUGE STAR BIT TUBING END LOCATOR SAND BAILER HYDROSTATIC BAILER FISHING TOOS ILLUSTRATIONS

Exhibit 3.1 3.2a 3.2b 3.3 3.4 3.5 3.6 3.7 3.8 3.9 3.10 3.11 3.12 3.13 3.14 3.15 3.16 3.17 3.17b 3.17c 3.17d 3.17e 3.17f 3.17g

51 53 55 57 58 59 61 63 65 67 67 69 69 70 71 73 75 Page

Rope Socket Stem Weight Vs. Well Head Pressure Steel and Lead Stems Stroke Jars Tubular Jars Knuckle Jars Knuckle Joints Hydraulic Jars Gauge Cutter Scratcher Impression Block Blind Box Swaging Tool or Tapered Gauge Star Bit Tubing End Locator Sand Bailer Hydrostatic Bailer Cutter Bar Sidewall Cutter Snipper Wire Finder Wireline Grab Go-Devil Wire Spear

52 53 54 55 57 58 60 62 64 66 68 68 69 69 70 71 74 76 78 80 82 84 85 86

SECTION 4 PULLING TOOLS CONTENTS Topic

Page

4.1

OTIS “B” PULLING TOOL

89

4.2

OTIS “R” PULLING TOOL (SHEAR UP)

94

4.3

OTIS “GS” RUNNING/PULLING TOOL

95

4.4

OTIS “S” PULLING TOOL (SHEAR DOWN)

99

4.5

CAMCO “J” SERIES PULLING TOOL

101

4.6

CAMCO “PRS” SERIES PULLING TOOL

105

4.7

D & D “PR” & “PR-GS” RUNNING/PULLING TOOL

107

ILLUSTRATIONS Exhibit

Page

4.1

Otis Type “R” Pulling Tool

90

4.2

Otis Type “R” Pulling Tool

93

4.3a

Otis (GS) Running/Pulling Tool

96

4.3b

Otis (GR) Pulling Tool

98

4.4

Otis Type “S” Pulling Tool

100

4.5

Camco “J” Series Pulling Tool

104

4.6

Camco “PRS” Series Pulling Tool

106

4.7a

D & D “PR” & PR-GS” Running/Pulling Tool

108

4.7b

D & D “PR” & PR-GS” Running/Pulling Tool

108

SECTION 5 RUNNING TOOLS CONTENTS Topic 5.1 5.2 5.3 5.4 5.5 5.6. 5.7 5.8 5.9 5.10 5.11 5.12 5.13 5.14 5.15 5.16 5.17

OTIS TYPE “J” RUNNING TOOL OTIS TYPE “C” RUNNING TOOL OTIS TYPE “H” RUNNING TOOL OTIS TYPE “T” RUNNING TOOL OTIS TYPE “SP” RUNNING TOOL OTIS TYPE “W” RUNNING TOOL OTIS TYPE “X” RUNNING TOOL CAMCO KB-2 RUNNING TOOL CAMCO SERIES “D” RUNNING TOOL CAMCO SERIES “Z” RUNNING TOOL CAMCO SERIES “J” RUNNING TOOL CAMCO SERIES “R” RUNNING TOOL CAMCO SERIES “W”RUNNING TOOL BAKER “C1” RUNNING TOOL BAKER “E” RUNNING TOOL BAKER “G” RUNNING TOOL BAKER PRODUCTION

Page 111 112 113 115 117 119 121 125 127 129 131 133 135 137 141 143 146

ILLUSTRATIONS Exhibit 5.1 5.2 5.3 5.4 5.5 5.6 5.7a 5.7b 5.8 5.9 5.10 5.11a 5.11b 5.12 5.13 5.14a 5.14b 5.14c 5.15 5.16 5.17a 5.17b 5.17c

Otis Type “J” Running Tool Otis Type “C” Running Tool Otis Type “H” Running Tool Otis Type “T” Running Tool Otis Type “SP” Running Tool Otis Type “W” Running Tool Otis Type “X” Running Tool Otis Type “X” Running Tool Camco KB-2 Running Tool Camco Series “D” Running Tool Camco Series “Z5” Running Tool with “Z5” Lock Camco Series “J” Running Tool1 Camco Series “J” Running Tool Camco Series “R” Running Tool Camco “WC-1” Running Tool Baker “C-1” Running Tool Baker “W & C Accessories Baker “S” Accessories Baker “E” Running Tool Baker “G” Running Tool Baker Model “A” Shank Baker Model “A & AC” Probes Baker Model “B” Probe

Page 111 112 114 116 118 120 122 124 126 128 130 132 133 134 136 138 139 140 142 144 147 148 149

SECTION 6 MANDREL AND LANDING NIPPLES CONTENTS Topic 6.1 6.2 6.3 6.4 6.5 6.6 6.7 6.8 6.9 6.10 6.11 6.12 6.13 6.14 6.15 6.16 6.17 6.18 6.19

Page OTIS TYPE “B” MANDREL OTIS TYPE “W” AND “C” MANDREL CAMCO TYPE “A” SLIP LOCK BAKER “TS” LOCK OTIS TYPE “D” COLLAR LOCK MANDREL OTIS TYPE “X” AND “R” MANDRELS AND NIPPLES OTIS TYPE “XN”AND “RN” MANDRELS AND NIPPLES OTIS “S” AND “T” MANDRELS AND NIPPLE OTIS “N” MANDREL AND NIPPLE OTIS “J” AND “E” MANDRELS AND NIPPLES CAMCO “C” LOCKS AND “D” NIPPLES CAMCO SERIES “W” NIPPLES CAMCO SERIES “DB” LOCKSAND NIPPLES BAKER “W1” AND “Z” LOCKS BAKER “M” AND “K” LOCKS BAKER “N” AND “L” LOCKS BAKER “S” LOCK WITH “L” AND “F” NIPPLES BAKER TYPE “R’ AND “N” BOTTOM NO-GO NIPPLES BAKER TYPE “F’ AND “J” TOP NO-GO NIPPLES

151 152 157 159 161 163 165 167 170 171 173 177 179 181 183 185 187 189 190

ILLUSTRATIONS Exhibit 6.1 6.2 6.3 6.4a/b 6.5 6.6 6.7 6.8 6.9 6.10 6.11 6.12 6.13 6.14 6.15 6.16 6.17 6.18 6.19

Page Otis Type “B” Mandrel Otis Type “W” and “C” mandrel Camco Type “A” Slip Lock Baker “TS” Locks Otis “D” Collar Lock Mandel Otis “X” and “R” mandrels and Nipples Otis Type “XN” and “RN” Mandrels and Nipples Otis “s” and “T” Mandrels and Nipples Otis Type “N” Mandrel and Nipple Otis “J” and “E” Mandrels and Nipples Camco “C” and “D” Locks Camco “W1” Nipple with Lock in Place Camco “DB” Lock and Nipples Baker “W” and “Z” Locks Baker “M” and “K” Locks Baker “N” and “L” Locks Baker “S1”, S2 Locks and “F” Nipple Baker “”R” and “N” Bottom No-Go Nipples Baker “F” and “J” Top No-Go Nipples

151 154 158 160 162 163 165 168 170 172 174 178 181 182 184 187 188 189 190

GAS LIFT CONTENTS Topic

Page

7.1

WIRELINE TROUBLE SHOOTING METHODS

193

7.2

SIDE POCKET MANDRELS AND KICKOVER TOOLS

197

ILLUSTRATIONS Exhibit

Page

7.1.a 7.1.b 7.1.c

Tubing Gauge

194

Tubing End Locator

194

7.1.d

Collar Stop

194

7.1.e

Tubing Stop

194

7.1.f

Circulation Plug

104

7.2.a

Basic Design Side Pocket Mandrel

197

7.2.b

Kick-Over Tool

198

7.2.c

Camco KBMG Side Pocket Mandrel

199

7.2.d

Orienting Sequence For Valve Installation

200

7.2.e

Gas Lift Equipment Chart

201

CHARTS CONTENTS Exhibit

Page

8.2

Hydrostatic Pressure of Well Fluids at Various Depths

203

8.3

Capacity of Tubing and Casing

204

8.4

Annular Capacities for Well With One String of Tubing

205

8.5

Liquid Gravity, Weight and Gradient Conversion table

206

8.6

Gas Pressure Factors For Various Gas Specific Gravities

208

8.7

Stem Chart

209

8.8

Otis Pulling Tools

210

8.9

Camco Pulling Tools

212

8.10

Wireline String Dimensions Vrs. Tubing Sizes

213

8.11

Pulling and Running Prong Chart

214

8.12

Equalizing Prongs

215

8.13

API Spec For Tubing and Couplings

216

8.14

Tubing Joint Identification

217

8.15

Tubing Make Up Torque Guide

220

8.16

Special Tubing Joints

222

8.17

Removable Locking Devices (Mandrel Assemblies)

224

8.18

Fraction Top Decimal Conversion Charts

225

8.19

Otis “S” and “T” Mandrels and Nipple Chart

227

8.20

Otis “R” and RN” Mandrels and Nipple Chart

229

8.21

Baker Types “F” and “J” No-Go Nipples Charts

230

SECTION 9 EQUALIZING SUBS AND PLUGS CONTENTS

Topic

Page

9.1

APPLICATIONS AND PURPOSES IF EQUALIZING SUBS

233

9.2

TYPE ”B” EQUALIZING SUB

235

9.3

TYPE “D” EQUALIING SUB AND PLUG ASSEMBLY

236

9.4

TYPE ”F” EQUALIZING SUB

237

9.5

TYPE ”H” EQUALIZING SUB

238

9.6

KOBE KNOCK OUT EQUALIZING SUB

239

9.7

TYPE ”S” EQUALIZING SUB

240

9.8

TYPE ”XO” EQUALIZING SUB

241

9.9

TYPE ”X” EQUALIZING SUB

243

9.10

TYPE ”X” EQUALIZING SUB (FOR P PRONG)

244

9.11

TYPE ”X” EQUALIZING SUB OR SUB

245

9.12

TYPES OF PLUGS

247

9.13

TYPE “C” PLUG ASSEMBLY

249

9.14

TYPE “D” PLUG ASSEMBLY

150

9.15

TYPE “E” CIRCULATING PLUG

251

9.16

TYPE “N” TEST TOOL

252

9.17

TYPE “S” TEST TOOL

253

9.18

TYPE ”W” CIRCULATING PLUG

254

9.19

TYPE “T” TEST TOOL

255

9.20

D & D HOLE FINDER

256

9.21

TYPE “S” EQUALIZING VALVE

257

9.22

TYPE “F” EQUALIZING PRONG & VALVE

258

9.23

TYPE “XX” & “RR” PLUG

259

9.24

TYPE “PX” & “PR” PLUG

160

SECTION 9 EQUALIZING SUBS AND PLUGS ILLUSTRATIONS

Exhibit

Page

9.1

Type “X” & “S” Equalizing Thread Connections

234

9.2

Type “B” Equalizing Sub

235

9.3

Type “D” Equalizing Plug Assembly

236

9.4

Type “F” Equalizing Sub

237

9.5

Type “H” Equalizing Sub

238

9.6

Kobe Knock Out Equalizing Sub

239

9.7

Type “S” Equalizing Sub

240

9.8

Type “XO” Equalizing Sub

242

9.9

Type “X” Equalizing Sub For Zone Separation

243

9.10

Type “X” Equalizing Sub For P Prong

244

9.11

Type “X” Equalizing Sub

245

9.12

Applications For Tubing Plugs & Type Recommended

248

9.13

Type “C” Plug Beam Assembly

249

9.14

Type “D” Plug Beam Assembly

250

9.15

Type “E” Circulating Plug

251

9.16

Type “N” Test Tool

252

9.17

Type “S” Test Tool

253

9.18

Type ”W” Circulating Plug

254

9.19

Type “T” Test Tool

255

9.20

D & D Hole Finder

256

9.21

Type “S” Equalizing Valve Assembly

257

9.22

Type “P” Equalizing Prong & Valve

258

9.23

Type “XX” or “RR” Plug Choke

259

9.24

Type “PX” or “PR” Plug Choke

260

SECTION 10 SAFETY VALVES CONTENTS Topic

Page

10.1

HISTORICAL REASONS FOR SAFETY VALVE DESIGN

263

10.2

TYPES OF SUBSURFACE SAFETY VALVES

264

10.3

THE PRESSURE OPERATED SUBSURFACE SAFETY VALVE

268

10.4

THE DIFFERENTIAL TYPE SUBSURFACE SAFETY VALVE

269

ILLUSTRATIONS Exhibit

Page

10.2

Types of Safety Valves and Control Systems

266

10.2.1

Pressure Operated & Differential Type Safety Valves

267

10.3

PB Pressure Operated Valve

268

10.4

Type F Differential Valve

269

SECTION 11 D & D TOOLS CONTENTS Topic

Page

11.1

DDIC AD-2 TUBING PACK-OFF (HIGH FLOW)

272

11.7

DDIC AD-2 TUBING PACK-OFF (HEAVY WALL)

278

11.11

DDIC HOLE FINDER

282

11.13

DDIC PACK-OFF BRIDGE PLUG

284

ILLUSTRATIONS Exhibit

Page

11.1

DDIC Hi Flow Pack-Off

273

11.2

AD-2 Tubing Stops

275

11.3

AD-2 Tubing Pack-Off

276

11.4

AA Stop

277

11.5

GS-PT Pulling & Running Tool

278

11.6

DDIC AD-2 Pack-Off (H.W.)

279

11.7

DDIC AD-2 Stinger & Receptacle

281

11.8

D & D Hole Finder W/ AD-2 Tubing Stop

282

11.9

DDIC Hole Finder

283

11.10

Pack-Off Bridge Plug

284

INTRODUCTION WIRELINE EQUIPMENT HISTORY OF WIRELINE EQUIPMENT Wireline have been is use since the early days of the oil and gas industry. The development of surface equipment for solid wireline operations have been intimately involved in the development of new methods and tools for use in well completion, remedial and work-over operations. Use of wireline includes: depth determination: deviated hole surveys: temperature and pressure surveys: paraffin cutting: following the plug in cementing operations: setting, retrieving and manipulating such devices as chokes, circulating plugs, gauge cutters, swaging tools and safety and gas lift valve. As the oil industry grew from the first shallow well in Titusville, Pennsylvania in 1859 to the first producing well on the Outer Continental Shelf in the Gulf of Mexico in 1947, wireline servicing has grown in complexity.

TRANSPORTING WIRELINE EQUIPMENT The expansion of oil field equipment from dry land to marsh, and offshore locations has required mobilizing wireline equipment for servicing these relatively inaccessible locations. In the early days of solid wireline (slick line) operations, few problems occurred with mobile equipment. Trucks with wireline wrenches, skid-mounted equipment and even fixed units mounted at strategic location provided a means of handling most solid wireline problems. Transporting by truck is now the primary vehicle for land operations. Transporting the wireline equipment to inland water and offshore locations became more difficult because some of the first locations were marshes. Moving the wireline equipment to these locations was made possible by mounting the equipment on speed boats, tugs, or small barges. Today a shallow water spud boat, diesel powered with a built-in hydraulic system that controls the wireline spool as well as the boat spuds, may be used in the bayous, streams, marshes, lakes or even in offshore locations. As the oil development moved offshore, the old methods of transportation changed, as did the equipment. Self-propelled jack-up vessels are ordinarily used for shallow water locations. The jack-up vessel is built on the same principle as a spud barge; however, the spuds are replaced with jack-up vessels. In remote offshore locations, specially designed, skid mounted diesel-powered wireline units (built in combination with hydraulic pumps and motors) are used. The unit is transported to the offshore platform or rig on a supply vessel and lifted onto the platform to perform the work.

1

DEVELOPMENT OF THE POWER SOURCE Since the early days when man used a small hand crank and spool containing a short length of solid wire, many mechanisms have been developed for supplying the power source to operate the wireline spool. When the solid wireline proved to be a practical means of depth determination, and the need for greater depth runs developed, the power source also changed. Many methods of rotating the reel came into use, such as; gasoline engines equipped with speed-reduction devices: diesel engines: electric motors: and hydraulic pumps and motors. Due to fire hazards on offshore locations, a number of operators have restricted the use of sparking power sources and actuating devices. ASSOCIATED SURFACE EQUIPMENT Transporting the wireline and associated equipment to a location is obviously a necessary part of the job. Surface equipment to be used at the well site is likewise an obvious necessity. The surface equipment required to perform wireline operations depends largely on the well pressure and tubing size. The following list of surface equipment may be used in a normal wire-line operation not exceeding 5,000 psi surface pressure and 2-1/ inch I.D. tubing. 1. 2. 3. 4. 5. 6. 7. 8. 9. 10.

Wireline Measuring Device Weight Indicator Reel Systems Floor Blocks and Pulleys Stuffing Box with Blow-out Preventer or Back-Pressure valve Lubricators Quick Unions Blowout Preventer(s) Wireline Valve Gin Pole and Mast

Remember, a certain amount of flexibility must be considered when rigging the surface equipment. The components are named and numbered only for identification by the reader as they are discussed in this chapter. DEVELOPMENT OF THE WIRELINE The earliest wireline used in measuring well depths were flat steel tapes with marked or stamped figures similar to a surveyor’s tape. As well depth increased, obtaining tapes of sufficient length became a problem. Correct depth reading were also a problem because the calibrated tape stretched under load, causing inaccurate measurements. When a flat tape was run in a well under pressure, the stuffing box and packing increases stretching problems.

2

These disadvantages brought about the adoption of the circular wireline for depth measurements and pack-off control. The line was tagged at equal length increments, and the operator kept a record of the amount of line un-spooled and retrieved. Measuring devices with calibrated wheels came into use later because they were convenient to use and provided more accurate measurements. As well depths increased and the loads imposed on measuring lines increased, highstrength steel wireline were developed to minimize wire weight and hoisting equipment size. A small diameter wire was developed that 1) reduces the weight load to a minimum, 2) can be run over small diameter sheaves and wound on a smaller diameter spool or reel without over-stressing by bending, 3) keeps the size of the reel drum to a minimum, and 4) provides a small cross-sectional area for operation under pressure. The most common solid measuring-line diameters currently used are 0.072, 0.082, 0.092, 0.108 and 0.125. Larger tubing I.D.’s have increased the demand for stronger line. One-piece measuring lines are available from the line-drawn mills in standard lengths of 10,000 feet to 30,000 feet. The most popular material for measuring line is improved plow steel because of its high tensile strength, good ductility, and relatively low cost. Cold-drawn improved plow-steel measuring line has an ultimate tensile strength of 230,000 to 240,000 psi. Requirements for well measuring line appear below in API Std., Section 7, Table 7.1

3

In wells where hydrogen sulfide is encountered, improved plow steel lines may be affected by hydrogen embitterment that reduces service life. For service in hydrogen sulfide atmospheres, Type 316 stainless steel was recommended because of its resistance to hydrogen embitterment. New special alloy wire is now recommended. The ultimate strength of stainless-steel measuring line is lower than that of improved steel and its cost is appreciably greater. Because of its lessfavorable ductile properties, it is more susceptible than other lines to cold working, which reduces service life. Stranded or braided line is used when solid measuring line larger than 0.125 inch is needed. This line, previously known in the petroleum industry as “torpedo” or “well-shooter’s” line is available in the following sizes: Size (in.) 3/16” Dyform 7/32” Dyform 1/ 4” Dyform

Maximum Strength (lb.) 5600 6800

4

5

SECTION 1 WIRELINE SAFETY PRACTICES AND CALCULATIONS

CONTENTS Topic

Page

1.1

SAFETY RULES AND OPERATING PROCEDURES

7

1.2

WORKING SAFELY IN H2S ENVIRONMENTS

11

1.3

FLUIDS, WEIGHTS, PRESSURES, AREAS, VOLUMES

13

ILLUSTRATIONS

Exhibit

Page

1.1

Bolt Tightening

9

1.2.1a

Area (Square)

13

1.2.1b

Area (Square)

13

1.2.1c

Area (Circle)

14

1.2.1d

Area (Diameter Of A Circle)

14

1.2.2a

Volume (Square)

15

1.3.3a

Pressure (Gradient)

17

6

WIRELINE SAFETY PRACTICES

1.1

SAFETY RULES AND OPERATING PROCEDURES NOTE In order to work safely and avoid accidents, wirline personnel must follow the important precautions that are detailed in this manual section.

1.

Make sure you completely understand the operation to be preformed and know the hazards of the job and how to protect yourself. If you are not sure, ask the senior wireline operator or your supervisor. A pre-job safety meeting shall be held prior to the beginning of any operation. JSA must be completed, reviewed and revised if work scope changes.

2.

Always wear safety hats, safety shoes, and gloves. Do not wear loose clothing because it may catch in moving equipment and cause an injury. Wear plastic face shields or goggles when assembling hammer-up unions. Wear life jackets any time you are riding a workboat or working in areas where PPE’s are required.

3.

Position the wireline unit as far as possible or practical from the wellhead. Secure unit with chains to keep it from sliding forward and ensure that it is well grounded.

CAUTION On a H2S location, the unit must always be placed upwind of the wellhead. Make sure you have the proper breathing apparatus and a resuscitator. Advise authorities before entering a sour gas location and upon your departure. 4.

Remove all junk and debris between the wireline unit and the wellhead. The work area around the well and to the wireline unit should be flagged so that no one runs into the wireline while work is in progress.

5

During night operations, make sure adequate lighting is provided. CAUTION When working in a dangerous environment, the light fixture must be explosion proof.

7

6.

Do not hammer or climb a lubricator that is subject to pressure. Watch your footing carefully when you must climb on a Christmas tree. Do not grasp any part of the tree for support unless it is properly secured.

7.

Check the pressure gauge and ask the costumer if the pressure shown on the gauge is the maximum well shut-in pressure. Make sure that all surface equipment working pressure certified and exceeds the well shut-in pressure.

8.

Close the wing valve (unless other wise specified) on flowing wells.

CAUTION Always count and remember the turns required to open and close a valve so that you can be sure how many turns are needed to close the master valve completely. 9.

Ensure all wellhead valves are holding pressure. Close the top valve of the wellhead. Never use the master valve except in an emergency.

10.

Close needle valve and remove gauge. Open needle valve and bleed off pressure above the top crown valve. Allow the pressure to bleed off and cautiously disconnect the bleed down hose. Make sure that no pressure is trapped below the needle valve. Consider hydrates in highpressure gas operations. Close the needle valve and purge pressure. Refer to H2S section for recommendations, (page 1-6)

11.

When all pressure is bleed off, leave the bleed-off valve open and disconnect the flange, unibolt or cap, making sure that you do not stand on the part being removed.

8

NOTE To remove a flange safely, unbolt one side of the flange (4 bolts). From the opposite side, keeping a safe distance. Shake the flange to ensure that no pressure is trapped before removing.

CAUTION To remove a unibolt or cap, first loosen the lock bolt, keeping a full nut on same and tapping loose the unibolt to ensure that no trapped pressure is present in the ring grove or below the unibolt before removing.

12.

When the flange, cap, or unibolt has been removed, install the wireline bottom adapter (tree connection). For flange connections, clean and lightly oil the ring joint, then tighten the opposite bolts.

Exhibit 1.1 Bolt Tightening

9

13.

Check the condition of the stuffing box blowout preventer and replace it if it shows excessive wear.

14.

Make the lubricator up and ensure that all O-rings and O-ring groves are clean. String the stuffing box, ensuring that the packing is replaced and the blowout preventer is checked. Tie a wireline knot (.092) with not less then nine rounds and no more that 13. Continue with assembling the stuffing box on the lubricator.

15.

Install pump-in sub and Halco Valve if required or requested.

16.

Install the wireline valve on the tree connection.

17.

If a gin pole is used, ensure that it is installed in a vertically straight position. Confirm the gin pole is properly secured and chained down. Inspect chain hoists or rope falls before using gin pole or “A” frame.

18.

Raise the lubricator so that the bottom is even with the top of the wireline valve. CAUTION To prevent the tools from falling out of the lubricator, be careful not to bump the top if the wireline clamp when picking up the lubricator.

19.

Install the weight indicator and hay pulley at 90 deg. angle from the pulley level to the stuffing box. Connect the tool to be run into the well to the tool string.

20.

To correct wire line measurements to tubing measurements, zero the wireline counter at the Braden head flange or the tubing hanger.

21.

Stab the lubricator to the wireline valve. Ensure the wireline valve is properly positioned.

22.

If the working pressure is above 5000 psi, purge the lubricator or fill it with the recommend fluid to test the same above the shut in tubing pressure before pressuring up the lubricator.

23.

Open the master valve (counting the rounds to know when the pressure enters the lubricator). Continue to slowly open the valve counting the rounds until the valve is fully open and the lubricator is pressurized. CAUTION The lubricator is now under pressure, if a leak is present, shut off the valves, carefully bleed off the pressure, repair the leak and proceed.

10

23.

If the stuffing box leaks apply pressure with a hand pump. When the lubricator holds the pressure, you may continue the operation. CAUTION Never loosen the packing nut under pressure

24.

Perform a pressure test on the lubricator before entering the wellbore. NOTE If the operation is a pressure survey and you intend to stay on bottom for an extended period, clamp the wireline on the lubricator and slack off the line slightly. Put a warning flag on the line to keep personnel from running into it.

25.

Ensure that the tools are in the top of the lubricator when pulling out hole before closing the upper valve. Follow proper lockout/tag-out procedures for wellhead valves.

26.

When bleeding off (purging) the lubricator, operate the bleedoff valve several time to ensure that it does not plug off. CAUTION Never stand in from of a needle valve that is in use when bleeding off well gas and oil.

27.

Upon completion of an operation while rigging down, the wire is normally drawn through the lubricator and stuffing box back to the unit. Ensure that the end of the line is away from all personnel when doing so.

28.

The wireline crew is responsible for any oil spill pertaining to the wireline equipment and operations. Precautions should be made to perform all work with the utmost regard for the prevention of any pollution.

1.2

WORKING SAFELY IN H2S ENVIROMENTS It is the customer’s responsibility to inform WGWS if any H2S is present in any wireline operation. Before beginning H2S operations, WGWS shall provide the necessary training for all personnel involved in the operation.

11

12

1.3

AREAS, VOLUMES, WEIGHTS, PRESSURES AND GRADIENTS Everyone working in the drilling and producing operations in the oilfield must understand the difference between fluid weight and fluid pressure. Even though tables, graphs, and charts are available to provide information, we need to know what the numbers mean and how to calculate them.

1.3.1

AREA Area is a surface enclosed by boundaries. An area is referred to as having so many square yards, or square feet, or square inches. For example, Exhibit 1.2.1a is a rectangle that measures four feet one side and three feet on the other side. If we divide the rectangle up as in Exhibit 1.2.1b, we find there are 12 squares. The rectangle has an area of 12 square feet. We can calculate the area by multiplying the length of the two side of the rectangle together.

Exhibit 1.2.1a

Exhibit 1.2.1b

13

In the oilfield, pipe is round, not rectangle. So we must find the area of a circle (Exhibit 1.2.1c. We can use either the radius or the diameter of a circle to calculate the area. The area of a circle is: A = ∆ x R x R or ∆ x R2 or ¼ x ∆ x D2 R = Radius of a circle D = Diameter of a circle ∆ = 3.14

Exhibit 1.2.1c If D or R is in inches, then the area is in square inches. We also have the situation of the annular area of two circles such as would occur with tubing inside casing (Exhibit 1.2.1d). The annular area can be found by calculating the area of each circle, as described above, and them subtracting the area of the small circle from the area of the big circle. The calculations can be simplified to: A = ¼ v (D2 –d2) D = Diameter of big circle or ID of casing D = diameter of little circle or OD of tubing

Exhibit 1.2.1d 14

Volume is how much a container will hold. How many gallons, or barrels, or cubic feet. The volume of a box (Exhibit 1.2.2a) is calculated by multiplying the height time the width times the length or: V=HxWxL V = 2 x 3 x 4 = cubic feet Another way to get the volume is to start with the area of the bottom. (Exhibit 1.2.2a) represents the bottom of our toolbox since it has the same dimensions. We found the area of the rectangle to be 12 square feet. If we multiply the area of the bottom by the height of the toolbox, we will get the volume. V = A x H = 12 x 2 = 24 cubic feet

Exhibit 1.2.2a

15

Calculating the volume of tubular goods is done the same way. First we calculate the area and then multiply that area by the length.

NOTE In calculating the volume of tubular goods, the diameter and the length must have the same units. That is, if the diameter is inches, then the length should be inches. This becomes a little cumbersome when the length is 5000 feet or 60,000 inches. The easiest things to do is use the diameter in inches and calculate the area in square inches, then divide the area by 144 square inches, which changes it to square feet. Then the volume is obtained by multiplying by the length in feet and the volume is in cubic feet. For example, suppose we want to find the volume of 5000 feet of 2 3/8 inch O.D. tubing. The I.D. of 2 3/8 inch tubing is 1.995 inches. The area is: A = ¼ x (1.995) squared. A - ¼ x 3.14 x 3.980 A = 3.14 square inches Now if we divide 1.124 square inches by 144, we will get the square feet. A - 3.124 144 144

= 0.02169 square feet

Now multiply this area by the length in feet to get the volume. V = A x L - 0.02169 x 5000 V = 108.4 cubic feet The oilfield usually deals with barrels instead of cubic feet. A barrel is 42 gallons or 5.6 cubic feet, so the volume in cubic feet can be converted to barrels by dividing by 5.6 or: 16

V = 108.4 = 19.4 barrels Exhibit 8.2 on page 8-2 in the back of this section has the capacities of most of the various sizes tubing and casing. The capacity is in barrels for 100 feet of pipe. The number of 100 sections to obtain the volume must multiply the capacity shown in the table. Our example of 5000 feet of 2 3/8 inch O.D. tubing, we have fifty sections. The table gives us a capacity of 0.387 barrels per 100 feet. The volume then is: V = 0.387 x 50 – 19.4 barrels When we work with annular volumes, we must use the I.D. of the casing and the O.D. of the tubing. The calculations are made in exactly the same way we did them for tubing. Exhibit 8.3 on page 8-3 in the back of the book lists the annular capacities for more common sizes of casing and tubing. 1.3.3

Weight, Pressure, Gradient There is a lot of confusion with weight, pressure, density, specific gravity, etc. It is very important to know the difference among them and how each is use to calculate the others. Everyone knows the definition of weight. For example, you weight 165 pounds or 190 pounds. A gallon of fresh weights 8.33 pounds. Two gallons weight 16.66 pounds. Bathroom scales tell you how much you weight or any object you place on them. Density is the weight per unit volume. The unit is usually one cubic foot. Density, therefore, is usually expressed in pounds per cubic foot. For example, the density of water is 62.4 pounds per cubic foot or 8.33 pounds per gallon. The drilling industry measures density in pounds per gallon. All mud densities are reported in pounds per gallon.

Specific gravity of a liquid is the ratio of the density of a liquid to the density of fresh water. To say it another, it is the density of the liquid divided by the density of water.

17

If we know the density of a liquid, we can find the specific gravity by dividing the density by 62.4, which is the density of fresh water. For example, if we have a mud that has density of 82 pounds per cubic foot, the specific gravity is:

SG = 82 = 1.314 62.4

If we have the specific gravity of a liquid, we can calculate the density by multiplying by 62.4. Using the example above of a mud with a specific gravity of 1.314, the gravity is:

Density = 1.314 x 62.4 – 82 lb/cu-ft

It is not often we have to determine the weight of a volume of liquid, even so let us see how it is done. Suppose we have a mud tank with the same dimensions an Exhibit 1.3.2a and it is full of 82 pounds per cubic foot mud. How much does the mud weight? We have already determined the mud tank has a volume of 24 cubic feet. So, if we multiply the volume times the density, we will have the weight.

Weight = 24 x 82 – 1968 pounds

Pressure is the force per unit area or weight per unit area. Pressure is usually reported in pounds per square inch. (psi) or in pounds per square feet (psf). A cube of fresh water one foot on a side is one cubic foot of fresh water and weights 62.4 pounds. The pressure of the cube created by the water is 62.4 pounds per square foot. The weight is on the entire area of the bottom.

A = 12” x 12” – 144 square inches

18

To convert the pressure of 62.4 pounds per square foot to pounds per square inch, we must divide by 144 because a square foot contains 144 square inches:

Pressure = 62.4/144 – 0.433 psi

Exhibit 1.3.3a

If you stacked another cubic foot of water on top of the first, as in Exhibit 1.3.3a, the height would now be 2 feet and the total weight would be 2 x 62.4 or 124. Pounds. This total weight is resting on one square foot so the pressure at the bottom is 124.8 pounds per square foot or .0867 pounds per square inch. PSI = 124.8 / 144 By doubling the height of the fluid, we double the pressure.

A pressure gradient is the change in pressure with a change in depth. It is the density and the height of the fluid that determines the pressure. We have just seen that an increase of one foot of depth (or height) of fresh water then, is 0.433 psi per foot of depth. If we have the density of a liquid, we can then calculate the pressure gradient.

19

Pressure Gradient in psi/ft – lb per cu.ft/144 Or Pounds per Gallon x 0.052 Quite often, oil is reported as having certain API gravity. Fresh water was arbitrarily designated as having an API of 10.0 degrees. The relationship between specific gravity and API gravity is described by: Specific Gravity =

141.5 131.5 + API gravity

Or API gravity =

141.5 = Specific Gravity

131.5

Exhibit 8.4, page 8.4 can be used to obtain gradients, densities, gravities, etc Suppose we want to find the pressure at 5000 feet in a well filled with 30 deg. gravity oil. Exhibit 8.4, page 8.4 fives the liquid gradient for this oil as 0.380 psi/ft. Multiply this times the depth to get the pressure. Pressure at 5000’ = 0.380 x 5000 = 1900 psi We can find the pressure another way. Since we have the API graity, we can calculate the specific as follows:

S. G. = 141.5 = 141.5 131.5 + API gravity 131.5 + 30

=

141.5 161.5

=

0.876

Now multiply the specific gravity of the oil times the density of water in pounds per gallon (8.33) to get the density of the oil.

20

Density of oil = 0.876 x 8.33 – 7.30 pounds per gallon Another way of finding the liquid gradient is found by multiplying the density in pounds of the fluid by the constant 0.052. Gradient = 7.30 x 0.052 – 0.387 psi/ft The pressure at 5000 feet = .0380 x 5000 = 1900 psi Exhibit 8.1 page 8-1 in the chart section of the book is a chart for determining the hydrostatic pressure of liquids (depending on the density) at various depths. Enter with the depth and move horizontally to the API gravity for oil and the density for heaver weight fluids, then move up vertically to read the pressure. Gas pressure increases with depth, just like liquid pressure does, but not as much. Calculating the pressure changes of gas with depth is beyond this discussion. Exhibit 8.5, page 8-6 in the book can be used to determine gas pressure at depth. To use the chart, you need to know the depth at which you want to know the pressure, the surface pressure, and the gas gravity. For example, assume you want to know the pressure at 5000 feet, if the surface pressure is 6000 psi and the gas specific gravity is 0.70, Exhibit 8.5 page 8-6 gives a factor of 1.1315 for 5000 feet and a specific gravity of 0.70. Now multiply the facto times the surface pressure. Pressure at 5000 feet = 6000 x 1.1315 = 6789 psi. There will be times when the tubing will have both gas and liquid. This is no problem. The gas will always be on top. It is a matter of calculating the gas pressure on top of the liquid, and then calculate the liquid pressure below the liquid column and then add the two together.

21

For example, what is the pressure at 5000 feet if the surface pressure is 400 psi, the liquid level is 3000 feet, the gas gravity is 0.7 and the liquid is 30 deg, API oil? There is only gas from the surface down to 3000 feet so first calculate the gas pressure at 3000 feet. Use the Exhibit 8.5 page 8-6 for this calculation.

Gas pressure at 3000’ = 1.0770 x 400 – 431 psi

There is only liquid from 3000 feet to 5000 feet. This means the liquid column is 2000 feet (5000-3000). Calculate the liquid pressure for 2000 feet of 30 deg. API oil. Use either Exhibit 8.1 page8-1 or Exhibit 8.4 page 8-4.

Liquid pressure = 0.380 x 2000 = 760 psi

The total pressure at 5000 feet is the sum of these two pressures

Pressure at 5000 feet – 431 + 761 – 1191 psi

There will be times when it will be necessary to determine if the pressure differential between tubing and casing will blow the tools up the hole when you open a side door or pull a gas lift valve. That differential is the difference between the pressure in the tubing and the pressure in the casing at the depth of the side door or gas lift valve

22

23

SECTION 2 PRIMARY WIRELINE EQUIPMENT CONTENTS Topic

Page

2.1

GENERAL

25

2.2

WIRELINE MAINTENANCE

45

2.3

H²S AND CO² ENVIRONMENT AND LINE USE

48

ILLUSTRATIONS Exhibit

Page

8.2

Primary Wireline Equipment

26

2.1a

Chain

28

2.1.2

Load Binder

28

2.1.3

Rope Blocks and Ropes

30

2.1.4

Tree Connection

30

2.1.5a

Bowen Wireline Valve

32

2.1.6

Lubricator

34

2.1.7a

Otis Quick Union

34

2.1.7b

Bowen Quick Union

34

2.1.8

Stuffing Box

36

2.1.9

Grease Seal Stuffing Box

38

2.1.10

Rope Socket

39

2.1.11

Stem

40

2.1.12

Wireline Jar

41

2.1.13

Hay Pulley

42

2.1.14

Wireline Clamp

43

2.1.15

Re-spooling and Transferring Line

46

24

SECTION 2 PRIMARY WIRELINE EQUIPMENT

2.1

GENERAL Primary equipment described in this section includes1, anything that must be attached to the wellhead and 2, the down hole tools needed to perform a standard wireline operation. Each piece of equipment is listed in a numbered paragraph below in the order you would rig it up on a tree. We will discuss the purpose and use of each part individually. Detailed operating instructions for the down hole tolls included here will appear in later sections. 1.

Load Binder and Chain

2.

Telescoping Gin Pole and Pins

3.

Rope Blocks / Chain Hoists

4.

Tree Connections

5.

Wireline Valves

6.

Lubricator

7.

Quick Unions

8.

Hydraulic Stuffing Box

9.

Rope Socket

10.

Stem

11.

Jars

12.

Weight Indicator / Hay Pulley

13.

Wireline Clamp

25

Exhibit 2.1 Primary Wireline Equipment 26

2.1.1

Load Binder and Chain The load binder and chain (Exhibit 1.2.1a and 2.1.1b) are used to attach the telescoping gin pole to the tree. The chain should be 5/16 inch in diameter and 15 feet long. The binder can be either a ratchet or boomer type.

2.1.2

Telescoping Gin Pole and Pins The telescoping gin pole can be two or three sections. The pole is attached to the tree first. The rope blocks are then attached to the top section and then the gin pole is extended. The gin pole pins keep the pole extended, Some wireline companies use a saddle attached to the wirline valve with a clamp. The saddle replaces the lower section of gin pole so that only the upper two sections are needed. Slip-on steps are normally used with this set-up. Using a saddle speeds rigging up because the chain and binder is not needed. However, this method limits the length of the lubricator you can use. Exhibit 2.1.1a shows how the gin pole is attached to the tree. Exhibit 2.1.1b shows the three sections normally used when attaching the gin pole to the tree.

27

28

2.1.3

Rope Blocks, Ropes and Chain Hoists Rope blocks and ropes (Exhibit 2.1.3) are used the raise the lubricator. The rope blocks ratio can be either 3 to1 or 4 to 1. A 150 foot rope is strung through the blocks and dead lined on the upper block, then lopped and back spliced. Chains, hooks and shackles on the lift chain should be checked.

CAUTION Use only spliced knots on the dead line. Take extra care to keep the rope clean of dirt and grease, and not cut the rope. Replace worn rope. 2.1.4

Tree Connection The tree connection (Exhibit 2.1.4) used depends on what type of connection the costumer has to connect on to the top of his tree. When the top of the tree connection is removed, Most trees have a pipe thread that is used to land the tree when completing the well. This thread may be used, depending on the condition, if the tubing pressure is 5000 pounds or less. A connection that adapts to the top of the tree (8 round thread or unibolt) and the bottom of the wireline valve (quick lock connection) should be reliable. A well with pressure greater than 5000 pounds would be considered high pressure and the tree connection would most likely be flange to quick lock.

29

30

2.1.5

Wireline Valve A wireline valve, (Exhibit 2.1.5), isolates well pressure from the lubricator sections without cutting the wireline. It works by closing a set of rubber rams on the wire and bleeding the well pressure above the wireline valve from the lubricator. This procedure is often necessary with fishing wire and tools from the well. The wireline valve is required if the tools are stuck below the surface. If this happens, the wireline valve can be closed and weight bars put into the lubricator above the wireline valve. The rams are then equalized and opened allowing the weight bar to fall release the wire from the stuck tools. The Wood Group normally uses Bowen type of wireline valves,(Exhibit 2.1.5), for all ranges of pressure work.

31

Exhibit 2.1.5 Bowen Wireline Valve

32

2.1.6

Lubricator A lubricator (Exhibit 2.1.6) permits introducing equipment into the pressurized well bore. The lubricator length depends on the well pressure and the length of tools being run down the well bore. The lower section is normally made of 3 ½ inch tubing that has an I.D. of 3 inches. This allows ½ inch more clearance than needed when running a full size flow control (safety valve, plug, etc.).

CAUTION Clearance in the lower section is necessary to allow pressure entering the lubricator when opening the master valve to equalize same without blowing up the flow control in the lubricator. Standard sections of lubricator are approximately 8 feet long. The upper section or sections are normally made of tubing the has an O.D. of 2-7/8 or 3-1/2 inches. This is to accept the weight bars, jars, rope socket, etc needed to go down the well bore in order to perform the work. 2.1.7

Quick Unions Quick unions (Exhibit 2.1.7a) are screwed to the ends of all lubricator sections and are used to connect the lubricator sections together. The quick union holds the well pressure with an O-ring seal. The unions slip into each other, and a large nut is screwed to the female half on the union to hold them together. They are considered safe because they cannot be unscrewed while under pressure. Exhibits 2.1.7a and 2.1.7b shows the different types. Note: No threaded connections shall be used over 5000 PSI.

33

Exhibit 2.1.7a and 2.1.7b Otis and Bowen Quick Unions 34

2.1.8

Stuffing Box The stuffing box (Exhibit 2.1.8) permits running the wireline into a lubricator subjected to well pressure. Slick line sizes up .092 can be used with a standard stuffing box. The stuffing boxes for lines larger then .092 employ a different yoke and a larger upper wheel. This helps keep the bending to a minimum and prevents crystallizing of the wire. Although several types of stuffing boxes are made, the purpose of the parts will be explained to better understand the principals. The drawing shows how a stuffing box works. The wireline runs through the upper shear and enters the upper packing nut. The upper nut is used to compress the upper gland which exerts pressure on the packing and stop the box from leaking while going in and out the well. Different manufactures build the stuffing boxes where some may use more or less packing rings than the other. The important thing to remember is to count the number of rings you remove and put the same number back in when it is necessary to replace them. Below the packing is the lower gland, which guides the wire to the center of the packing to reduce wear on the packing. The lower section of the stuffing box is built to accept a blowout preventer. This blowout preventer is sometimes referred to as a plunger. It will move a short distance up and down. The top of the blowout preventer is a tapped rubber molded onto metal. In the event the packing blows out, the excess flow moves the preventer upward and closes around the wire stopping the flow. Below the preventer and holding it in place is a large nut that acts as a stop for the rope socket to bump up against when coming out the hole. Some stuffing boxes employ a bleed off valve above the preventer for bleeding off purposes.

CAUTION When using high-pressure equipment in a sour gas operation, ensure that the upper and lower glands are of the same material. When a stainless line is used, the upper and lower glands must be rated for sour gas and be of the same material.

35

Exhibit 2.1.8 Bowen Stuffing Box

36

2.1.9

Grease Seal Stuffing Box A grease seal stuffing box (Exhibit 2.1.9) was designed to accommodate the use of various sizes of smooth lay (Stranded Line) under well pressure. This stuffing box uses grease as a sealant. The grease is pumped into the stuffing box under pressure forming a barrier against the wellhead fluids and gas. This completely seals off and lubricates the line. When preparing the stuffing box on location, it is imperative that the flow tubing used in the stuffing be sized for the wire being used. This prevents leakage of grease from the box. The number of flow tubes used depends on the well pressure. The greater the pressure, the more flow tubes are used. It is necessary to add then to the length of the stuffing box to accommodate the extra flow tubes.

CAUTION The exhibit designates the proper place to tie in the connection where the grease is pumped in and also where the excess grease is released to return to the grease barrel. Ensure that they are connected properly.

37

38

2.1.10 Rope Socket The rope socket (Exhibit 2.1.10) on the left features the parts of the rope socket and the wire knot. The rope socket has four parts – body, spring, support, and disc. The top of the rope socket body has a fishing neck that accepts a standard pulling tool. The center is bored to accept wire sizes up to .092. The bottom is threaded inside to accept the stem. The spring acts as a shock absorber and a spacer allowing full relative motion of the rope socket. To assemble the rope socket, the wire is strung through the rope socket body, then the spring and the spring support is strung and the wire is then tied to the disc and wrapped around it. The rope socket and the tool string must be of the same O.D. The total tool string must be the proper size for the minimum I.D. of the tubing. Rope sockets with wedges, at right are utilized for alloy lines and 0.108, 0.125 and all cable lines.

Exhibit 2.1.10 Rope Sockets 39

2.1.11 Stem The stem (Exhibit 2.1.11) is built in various sizes, lengths, outside diameters, and fishing neck sizes. The top is threaded to screw inside a rope socket or another piece of stem. Immediately below the threads is a fishing neck that will accept any standard pulling tool. The stem is solid unless additional weight is necessary. It may be leaded if required.

NOTE Leaded stem is used only for special jobs where limited space is necessary in the lubricator and the extra weight helps to get down the hole. It is never used where heavy jarring may be needed to release your tools. Its construction makes its very weak and it may come apart.

The stem (sinker bar) supplies weight needed for the wireline to drop down the well bore against the pressures encountered in most oil and gas wells. The stems length and size depends on the minimum I.D. of the tubing. Refer to Section 3, Exhibit 3.2b for stem O.D. and weight per foot.

40

2.1.11 Wireline Jars Wireline jars (Exhibit 2.1.12) like stems, have threads and fishing necks on top. Immediately below the fishing neck, the jar body is split. Below it, an opposing piece is also split and the two parts are linked together much like a chain. The bottom of the body is threaded inside to accept running and pulling tools.

Jars are normally used below the stem so that the stem weight will close the jars when an obstruction is encountered. In all phases of wireline operations, jars are needed to manipulate the tools that are lowered and retrieved from the well bore. The only times jars may not be run is when a buttonhole pressure instrument is used.

NOTE Before the pressure instrument is to be run, the tubing must be first be checked out. A tool string with jars and a tool as large or larger is run to the depth that the instrument is to be run.

The jars are used to beat downward on an obstruction. Pulling the line up at the surface until the jars open, then releasing the wireline reel quickly, operates them. The weight of the stem delivery’s an impact on the obstruction. An upward impact can also be delivered by reversing this operation. Because proper jar action is imperative, jars should be inspected for straightness and free movement before they are used.

Exhibit 2.1.12 Wireline jar

41

2.1.13 Hay Pulley The hay pulley (Exhibit 2.1.13) Changes the wireline horizontal direction from the wireline unit to a vertical direction at the wellhead. The hay pulley should be secured to the Christmas tree with the proper chain and checked periodically during the wireline operation.

Exhibit 2.1.13 Hay Pulley

2.1.14 Wireline Clamp 42

The wireline Clamp (Exhibit 2.1.14) is used to secure the wire without damaging it. Although the clamp may be used for various reasons, the main use is the keep the wireline tools from falling out of the lubricator when raising it to an upright position.

Exhibit 2.1.14 Wireline Clamp

CAUTION The wireline clamp is released by bumping the top to open it. The wireline helper as well as the operator should be familiar with this fact and be extra cautious when raising the lubricator above the ground. Bumping the top would release the tool string and could cause injury.

43

2.1.15 Single Line Weight Indicator System (Exhibit 2.1.15) The single line weight indicator system is used to weight wireline tools. It is hydraulically operated requiring no external power source, and is designed to operate within the temperature range of 50 to 150 deg. F (45 deg to 65.5 deg C).

Exhibit 2.1.15 Single Line Weight Indicator System

44

2.2

WIRELINE MAINTENANCE

The following precautions should be observed in using and maintaining wireline properly.

A.

The maximum pull of the line must not exceed its elastic limit (50% of the breaking strength).

B.

After extensive jarring, the wireline should be pulled out and 40 feet or more wire should be cut off and the line retied. All joints on the tool string should be checked for tightness.

C.

The line should be cut or changed in the following cases: 1. When the line no longer tends to form loops with the same diameter as the drum when it is unwound on the ground. 2. When tying a new knot, the line seems soft and breaks easily, but not a clean break. 3. When there are kinks in the line that do not disappear when the line is under tension.

D.

When the line is spooled up at the completion of a job it should cleaned, given a coat of protective oil, and wrapped.

E.

Exhibit 2.2 shows the recommended method for re-spooling or transferring line.

45

Exhibit 2.2 Re-spooling and Transferring Line

2.3

WIRELINE PHYSICAL TOLERANCES Tolerance in diameter: = + .001 inch Elongation (10 inches under elastic limit) Minimum 1.5% Maximum 3.0% Minimum number of twists/8 inches under torque 0.082 inches 26 0.092 inches 23 No. of twists 0.105 inches 21

NOTE When the wire breaks inside the tubing, it falls into a spiral coil inside. Depending on the I.D. of the tubing and the size of the line, the fall back will vary. The following is a general rule of thumb for calculating how much fall back you may find depending on tubing size: 2 3/8 inch tubing, 3 to 6 feet per 1000 feet 2 7/8 inch tubing, 7 to 8 feet per 1000 feet 3 1/2 to 4 inch tubing, 8 to 10 feet per 1000 feet

46

47

2.3

H²S and CO² ENVIRONMENT AND LINE USE

Wireline operations in an H²S or CO² environment create corrosion, excessive temperature and pressures. Therefore, the following lines are recommended:

The use of stainless or alloy lines is recommended when working in H2S and CO2 environments.

48

49

SECTION 3 WIRELINE TOOLS CONTENTS Topic 3.1 3.2 3.3 3.4 3.5 3.6 3.7 3.8 3.9 3.10 3.11 3.12 3.13 3.14 3.15 3.16 3.17

Page ROPE SIOCKETS STEMS STROKE JARS TUBULAR JARS KNICKLE JARS KNUCKLE JOINTS HYDRAULIC JARS GAUGE CUTTER SCRATCHERS IMPRESSION BLOCK BLIND BOX SWAGING TOOL OR TAPERED GAUGE STAR BIT TUBING END LOCATOR SAND BAILER HYDROSTATIC BAILER FISHING TOOS ILLUSTRATIONS

Exhibit 3.1 3.2a 3.2b 3.3 3.4 3.5 3.6 3.7 3.8 3.9 3.10 3.11 3.12 3.13 3.14 3.15 3.16 3.17 3.17b 3.17c 3.17d 3.17e 3.17f 3.17g

51 53 55 57 58 59 61 63 65 67 67 69 69 70 71 73 75 Page

Rope Socket Stem Weight Vs. Well Head Pressure Steel and Lead Stems Stroke Jars Tubular Jars Knuckle Jars Knuckle Joints Hydraulic Jars Gauge Cutter Scratcher Impression Block Blind Box Swaging Tool or Tapered Gauge Star Bit Tubing End Locator Sand Bailer Hydrostatic Bailer Cutter Bar Sidewall Cutter Snipper Wire Finder Wireline Grab Go-Devil Wire Spear 50

52 53 54 55 57 58 60 62 64 66 68 68 69 69 70 71 74 76 78 80 82 84 85 86

SECTION 3 WIRELINE TOOLS

3.1

ROPE SOCKET The knots used in rope sockets (Exhibit 3.1a and 3.1b) to attach the wireline should be selected using these guidelines: A.

Standard Wireline Jobs Use a normal knot consisting of one turn around the disc, then 9 to 13 turns around the line.

B.

Deviated Wells: Use a rope socket with a cone-shaped end, (Exhibit 3.1a), when working out the end on the tubing. Its cone shaped end eases re-entry into the tuning, especially in deviated holes. C. Wedge type rope sockets Wedge type rope sockets shall be used with stainless and alloy lines, 0.108, .0125 and cable lines.

51

52

3.2

STEMS The stem (Exhibit 3.2a) supplies weight needed for the wireline to drop down the well bore against pressure encountered in most wells at entry of the stuffing box. Exhibit 3.2b gives the various sizes, lengths, weights, outside diameters, and fishing neck for solid stems and lead-filled stems.

53

54

3.3

STROKE JARS Jars are always part of the wireline string except when running buttonhole pressure instruments. Stroke jars utilize the weight of the stems (connected immediately above them) to deliver upward or downward jarring controlled by manipulating the wireline at the surface. Jarring impact depends upon the stem weight, stroke length, size and depth of the tools, and the density and viscosity of the fluid in the tubing. It is not recommended using 1 ½ inch O.D. stroke jars in pipe larger than 2 ½ inch I.D. because of possible bowing and buckling. This could cause the two sections to scissor, and prevent the jars from entering restricted openings. This is especially true when the jars are used or in open hole below a string of tubing.

55

56

3.4

TUBULAR JARS Tubular jars are mostly used for jarring in casing during fisting and sand bailing operations.

57

3.5

KNUCKLE JARS Knuckle jars are used to jar wedged stems loose from the tubing when mechanical jars fail. Knuckle jars should not be used routinely, only for emergency operations. Available stokes: 2, 4, 6, 8, and 10 inches

58

3.6

KNUCKLE JOINTS Knuckle joints make the tool string flexible, permitting tools to be run through crooked tubing where they might otherwise be damaged. If crooked tubing is encountered, knuckle joints may be placed between the stem and the jars, and in extremely crooked tubing perhaps between each individual stem. Because heavy jarring may sever the joint’s ball seat, the seat should be inspected before running the knuckle joint in the well. The threads should also be inspected.

59

60

3.7

HYDRAULIC JARS Hydraulic jars are designed for upward jarring only. The are used in wireline work where it is difficult to obtain good jar action with regular mechanical jars, such as in deviated wells, for retrieving mandrels, shifting SSD, swabbing, bailing, and fishing. They require careful maintenance for maximum performance. Sizes available are 1 ¼. 1 ½, 1 ¾, and 2 1/8 inches Mechanical jars run with hydraulic jars permit downward jarring. If the hydraulic jars should fail to function improperly, because of fluid loss or gas entry, the mechanical jars can be used to complete the operation. Do not use the hydraulic jars below the mechanical jars. Hydraulic oil used in Bowen jars should be 10 W 30 lubricating oil. In higher temperature when heavier jarring is desired, the jars may be filled with heavier oil. Completely understanding the problems the equipment operator may encounter in using hydraulic jars is important. He must visualize the operation of a set of jars down-hole while he manipulates the line at the surface. An upward stoke with stroke or tubular jars will be in effective on a fish because of the cushioning effect from attempting to open the hydraulic jars. With the hydraulic jars in the string assembly, only an upward stroke when the hydraulic jars opens is effective on the fish or pulling tool. If the hydraulic jar freeze in the open position, cushioning will occur on the downward stoke. This may be a problem if a shear-down pulling tool is latched on the fish.

61

Exhibit 3.7 Hydraulic Jars

62

3.8

GAUGE CUTTER The gauge cutter is used:

1.

To calibrate the tubing.

2.

To locate reductions and landing nipples

3.

To remove paraffin wax and other deposits from the tubing walls.

63

64

3.9

SCRATCHERS Scratchers are used to scrape the tubing wall, to clean tubing nipples, and to fish small pieces of wireline loose in the tubing. They are used before running a gauge cutter on the event the tubing is full of paraffin wax. Scratchers are manufactured or made from a piece of sucker drill rod with a series of holes along 4 spaced about 1 inch apart in a circle for the length of the scratchier, normally about 18 inches. Pieces of wireline are inserted in these holes. Their lengths depend on the tubing I.D.

65

66

3.10

IMPRESSION BLOCK An impression block, a lead-filled cylinder with a pin through the leaded section to prevent losing the lead, is a useful tool during fishing operations to assert the shape, position and size of the fish. It indicates the type tool necessary for the next run in the well. The impression block must be lowered without knuckle joints to avoid getting a false impression. Drop the block on the obstruction at a moderate rate of speed and immediately retrieve it.

There should at least a 1 /4” of clearance on the inside of the tubing to allow impression block to expand when moving up or down the well bore.

3.11

BLIND BOX The blind box is a service tool used when heavy downward jarring is required. The tool is flat on the bottom and hardened to reduce damage.

67

68

3.12

SWAGING TOOL OR TAPERED GAUGE

The swaging tool is designed to swage out light collapses inside the tubing string. The outside diameter of the swage is equal to the tubing drift I.D. Ensure that there is flow course holes through the swaging tool.

3.13

STAR BIT

The star bit has small blades which make it useful to remove excess cement or salt, or to drive gun debris through the end of the tubing or pipe.

Exhibit 3.13 3.1.4

Broaching Tools: Broaching tools are used to clean obstructions from the tubing walls where an obstruction is present.

69

3.14

TUBING END LOCATOR The tubing end locator is used to locate both the end of the tubing and the bottom of the well bore in one wireline trip. NOTE Never run the tubing end locator without running a tool out the end of the tubing prior to making the tubing end locator run

70

3.15

SAND BAILER Sand bailers are used to remove sand, mud, salt, or small pieces of junk from the tubing or casing, to clean fishing necks or to take samples of the substance on bottom. The well must be shut-in while a bailer is run to avoid flushing out the bailer. To bail, move slowly onto the obstruction, and then move up quickly (repeat at lease 15 times). If the sediment is too hard to be bailer, solvents can be dropped into the well first. In a sand bailing operation, the operator should be aware of the well conditions that may exist. Often the well will bridge over with sand, causing the well to go dead. When this occurs, a pressure loss is noted on the tubing. Pressure should be restored either by filling the tubing with fluid or by pressuring up from another well or another source before excessive bailing is dome. This will keep the sand from rising and possibly covering the bailer and tool string.

71

72

3.16

HYDROSTATIC BAILER Hydrostatic bailers are used when the substance to be bailed cannot be removed by a pump down bailer. This sometimes occurs when small metallic particles become lodged on top of the fishing neck of a locked mandrel. The tool is a cylinder about 5 feet long with a brass shear disc mechanism at the bottom. The cylinder is at atmospheric pressure, sealed off from the well pressure. When the obstruction is reached, downward jarring shears the brass disc cause a tremendous suction at the bottom of the bailer. The bottom of the bailer may be fitted with different sizes and shaped bottoms depending of what the job calls for. Difference disc thickness is available for various well pressures:

CAUTION As the lubricator is bled off to atmospheric pressure, the seal plug of the automatic bleed valve should be forced into the recess of the safety screw If this does not take place, back out the cup point screw a few turns to release the pressure. Then force the bottom non-return steel ball off its seat with a screwdriver to release any trapped pressure in bailer. After pressure is totaled released, the bailer bottom should be free to unscrew. DO-NOT use this type bailer to bail on a soft sand. Because of the tremendous surge of pressure, you will bury it in the sand.

73

74

3.17

FISHING TOOLS No matter how well the wireline equipment is maintained, or how experienced the operator may be, there an occasion when “things” foul up. At this point, a fishing operation is required, and the wireline operator must follow certain procedures to obtain the best results rather than worsening the situation. NOTE District Managers will be contacted before any fishing operation is started. There are several types of fishing tools available for the operators use. Which tools are used depends on the existing condition. Some examples are discussed as follow:

A.

Cutter Bar (Exhibit 3.17a) Example 1: Excessive jarring with the tool string causes the line to crystallize (become brittle) and break at the surface. This leaves the end of the line extending through the top of the lubricator. To resolve this situation, perform the following procedures:

1.

Close the rams of the wireline valve and release the pressure above the rams. Raise the lubricator high enough to:

2.

Install a cutter bar and set it down on the rams. Stab the lubricator, equalize same, and open the rams to drop the cutter bar. NOTE The blind box of the cutter bar should be the correct size to cover the center of the rope socket where the line extends upward: Examples: 2 3/8 inch tubing requires 1 ½ inch O.D. blind box 2 7/8 inch tubing requires 1 ¾ inch O.D. Blind box

3.

Allow enough time for the cutter to travel to the top of the stuck tools and make its cut on the rope socket.

4.

If the line is above the rams, there might enough line to back splice through the stuffing box and the line then tied to the wireline on the reel and pulled out the well. 75

76

5

The old broken line is then removed from the reel on the unit and a new line spooled on. Then the cutter bar is retrieved. The fishing job for the lost tools is then continued with the hope completing the original job plan. Example 2: If the wireline falls below the wireline valve, perform the following: NOTE When a line breaks at the surface or down hole, the line will fall back into the well. It will lie in a spiral on the tubing wall. The lines stiffness will only let it fall a short way down the well. Depending on the size of the line and the I.D. of the tubing, the line will fall a given number of feet. A rule of thumb may be from 8 to 10 feet per thousand feet. Example: If you use 8 feet and the fish is at 10,000 feet, the line will fall back 80 feet from the point where it was broken.

B.

1.

Attach the cutter bar to the fishing tool string with a piece of string.

2.

Lower the cutter bar to a point calculated to be below the end of the broken line.

3.

Snap or jar the fishing tool string quickly so as to break the string and let the cutter bar fall inside the broken line.

Sidewall Cutter (Exhibit 3.17b) This type of line cutter is run with the tool string and can be set at any point in the tubing. The knives overlap a tapered mandrel that cuts the line against the tubing wall. The line can be cut and retrieved in segments, thus reducing the possibility of two lines becoming entangled (especially in deviated wells). It is also possible to pin the cutter knives in a retracted position and drop then in the same manner as the cutter previously discussed. Allow sufficient time for the cutter bar to drop to the stuck tools, the drop a weight bar will shear a pin holding the cutter knives. The knives ride up on the tapered mandrel and cut the line.

77

Exhibit 3.7b Snipper

78

C.

Mechanical Snipper (Exhibit 3.17c) The mechanical snipper is a cutter knife that is actuated upon contact with the rope socket of the tool string.

This tool can be assembled in a reverse or upside down position.

Upside Down Position The tool is used when there is a possibility of the tool cutting the line when fluid or gas lift valve inside pocket mandrels are encountered. The cutter is located at the top of the tool; therefore, a weight bar must be dropped for the tool to cut the line. Using this method, the crimpier is not used, instead, the tool string is used to retrieve the weight bar and cutter after the cut line is retrieved.

79

Snipper 80

D.

Wire Finder (Exhibit 3.17d) The wire finder is cylindrical shaped, internally tapered at the lower end that can be swaged out the scrape the tubing walls. When using this tool, the drift inside diameter of the tubing must be considered because the wire finder will pass through the drift of the tubing and can also pass the end of the line. For example, 2 3/8 inch tubing has a bored I.D. of 1.995 inches, but a drift I.D. of 1.901 leaving a clearance of .094 inches. The wire line most often used .092.

CAUTION Although it may seem impossible to pass the wireline with a wire finder of this type, it is possible and could be critical. Due to its fullest, extra caution should be made preparing and running this tool

81

Exhibit 3.17d Bowen Wire Finder

82

E.

Wireline Grab (Exhibit 3.17e) The wireline grab is used to fish wireline that has been broken in the well. This tool has two flexible legs with pointed barbs inside each leg to latch onto the wire. This tool has prongs of fairly soft steel, and is slightly concaved internally where the barbs are located. When the tool sits down into a coil of wire, jarring down tends to bent the wire inside the legs and the inside barbs latch the line when picking up. Example: Assume the wire is severed at the tool string:

1.

Lower the wireline grab onto the coiled line.

2.

After beating down and kinking the line, the grab catches the end of the kinked line and pulls it up.

3.

The broken line is pulled up above the wireline valve, the rams are closed and the pressure above the valve in the lubricator is released.

4.

Upon raising the lubricator, the end of the line is pulled up enough to allow it to be back strung through the stuffing box. It is then tied to the old line on the reel and pulled out the well.

5.

The old line is taken off the reel and a new line is spooled on. The wireline crew then proceeds to fish the cutter bar and the lost tool string out the well.

83

84

G.

Go-Devil (Exhibit 3.17f) This tool employs a plate that fits into a slot milled into the body of the stem. The bottom is shaped so as to cut the wire when it hits on top of the rope socket of the lost tools. If the tools are tangled or cover with sand, the do-devil allows for another do-devil or a cutter bar to be dropped on it in an effort to cut the line.

85

H.

Spear Type Tool (Exhibit 3.17g) If a ball of wire is too compacted making it impossible to fish with a two prong grab, the center spear is used to pierce the ball of wire and string it out where the two prong grab may be used.

Exhibit 3.17g Spear-Type Too 86

87

SECTION 4 PULLING TOOLS CONTENTS Topic

Page

4.1

OTIS “B” PULLING TOOL

89

4.2

OTIS “R” PULLING TOOL (SHEAR UP)

94

4.3

OTIS “GS” RUNNING/PULLING TOOL

95

4.4

OTIS “S” PULLING TOOL (SHEAR DOWN)

99

4.5

CAMCO “J” SERIES PULLING TOOL

101

4.6

CAMCO “PRS” SERIES PULLING TOOL

105

4.7

D & D “PR” & “PR-GS” RUNNING/PULLING TOOL

107

ILLUSTRATIONS Exhibit

Page

4.1

Otis Type “R” Pulling Tool

90

4.2

Otis Type “R” Pulling Tool

93

4.3a

Otis (GS) Running/Pulling Tool

96

4.3b

Otis (GR) Pulling Tool

98

4.4

Otis Type “S” Pulling Tool

100

4.5

Camco “J” Series Pulling Tool

104

4.6

Camco “PRS” Series Pulling Tool

106

4.7a

D & D “PR” & PR-GS” Running/Pulling Tool

108

4.7b

D & D “PR” & PR-GS” Running/Pulling Tool

108

88

SECTION 4 PULLING TOOLS 4.1

OTIS TYPE “B’ PULLING TOOL This tool is used to pull the same mandrels as the Otis type RB pulling tool. It is also used if a piece of wire is left on top of a fishing neck during a fishing job. By charging the dogs only, two types of pulling tool can be arranged.

It consists of a housing, a connecting sub, a core with a set of three dogs all held in place by a core nut. The dogs pivot against the inside lower edge of the housing. There is approximately 3/8-inch vertical travel of the core within the housing. This relative movement controls the piston and releasing of the dogs. When the core is held in its uppermost position within the housing against the sub by the shear pin, the dogs are forced against the housing by the spring. The lower end of the dogs is in a latching position. The dogs have; however, some elasticity and can move apart to engage the pulling tool flange of the subsurface control. Furthermore, any downward jarring is transmitted through the sub and the core to the mandrel of the subsurface control. Any pull on the line or upward jarring is transmitted to the core and the dogs by the shear pin. It is impossible to shear the pin by a uniform upward pull on the wireline. 89

90

In the event it is difficult to pull the subsurface control, perform a few sharp upward jar strokes to shear the pin. The housing will move up until the core nut stops it. This then raise the pivot point of the dogs above the axis of the dog springs and causes the dogs to move out to the release position. Parts shown on Exhibit 4.1 are: 1.

Housing

5.

Core nut

2

Connecting sub

6.

Shear pin

3.

Core

7.

Spring

4.

Dogs

91

92

4.2

OTIS TYPE “R” PULLING TOOL (SHEAR UP) When this pulling tool is set on top of a pulling flange (large O.D. of fishing neck) and driven down, the lower ends of the dogs move outward allowing the pulling tool to catch it. When the inside lips of the dogs pass the pulling neck, the dogs springs force the lower end of the dogs inward, latching the pulling tool to the pulling flange of the fish.

93

The shear pin will withstand considerable jarring before shearing. If it shears, the energy stored in the cylinder spring acts between the sub and cylinder. This raises the core relative to the cylinder, which in turn, raises the dogs against the force of the dog spring. As the dogs are raised, their tapered upper ends move into the cylinder, forcing their lower ends outward. The pulling tool can be retrieved and refitted with a new shear pin. By changing only the core of the “R” pulling tool, it is possible to obtain an RB, RS or RJ pulling tool.

94

4.3

OTIS “GS” RUNNING/PULLING TOOL When the “GS” is used as a running tool, simply insert the dog and core into the internal fishing neck. The dogs contact the beveled top of the fishing neck and move with respect to the core (compression of spring). When the core recess passes behind the dogs, the dogs retract and engage into the top restriction of the fishing neck. When the dogs are in front of the fishing neck recess, spring action expands the dogs, and the tool is ready to be lowered into the well bore. When the mandrel is landed, downward jarring shears the pin, driving the core down behind the dogs. This allows the dogs to retract (spring holds the core in the down position). Retrieve the tool. When the “GS” is used as a pulling tool, the latching operation is the same as the one detailed here above. If it becomes necessary to shear off the mandrel (case of sticking, etc.) jar down and the tool follows the same operation as used as a running tool. Parts shown on Exhibit 4.3a are: 1.

Dog

4.

Core

2.

Spring

5.

Spring

3.

Shear Pin

95

96

A combination of the “GS” pulling tool and the “GR” Shear up adapter (Exhibit 4.3b) converts the “GS” pulling tool (shear-down) into a shear-up pulling tool. For latching operation, refer to “GS” running/pulling tool. Slight downward jarring is often necessary to latch fish.

CAUTION Never run the “GR” tool with apin inserted as for the “GS” tool. If this pin is installed, it is impossible to shear free in either direction Jarring should pull the fish. In case of difficulty, continued upward jarring will shear the pin, releasing the pulling tool, the spring moves the core down from behind the dogs, allowing them to retract. The are two types of core: 1.

Standard 7/8 inch length below the locking dogs (for “X” mandrel, “D” collar stops and “G” pack-off).

2.

Special 2-11/16 inch length below the locking dogs (for “D” collar lock).

97

98

4.4

OTIS TYPE “S” PULLING TOOL (SHEAR DOWN) The type “S” pulling tool is used to pull various subsurface controls, stems, wireline rope sockets, choke extractors, etc. where extensive jarring is required. The operation of the type “S” is similar to the type “R”, but jarring down will free the tool. The jarring impacts are transmitted to the shear pin by way of the core which contacts the top of the fishing neck. The spring makes the core move up after the pin is sheared. This upward action of the core expands the dogs, which releases the tool.

NOTE The type “S” pulling tool is also used as a running tool for collar stops, pack-off anchor stops and other subsurface controls, However, it is not designed to pull Otis “S” mandrels.

99

100

4.5

CAMCO “J” PULLING TOOL The “J” Camco pulling tool is designed to remove retrievable subsurface devices with outside fishing necks. This tool has collet type dogs with a large latching area. It is also available with different length cores, which make the reach of the tool adaptable for latching mandrels, and locks that require various reach lengths.

The “JU” and “JD” differ only in the direction of shear release: the “JU” for jar up to release and the “JD” for jar down to release. The accompanying specification chart provides the reach data along with the core type necessary. By changing the core only, the “JU” pulling tool can be transformed into:

To transform a pulling tool “JU” (jar -up) into a “JD” (jar-down), change to top and screw a nut assembly on the inner core.

101

102

4.5.1

Latch Operation

A.

When the pulling tool comes over the fishing neck of the mandrel to be retrieved, the dogs are stopped. The skirt travels further down on the weight of the string, because the holding studs of the dogs are free to move up and down in the upper slot of the skirt. The dog spring is compressed. The skirt movement also frees the dog fingers, which are locked in the lower recess of the skirt.

B.

The beveled top edge of the skirt grooves forces the dogs out, so that the pulling tool can engage further down onto the fishing neck, until the core contacts the top of the fishing neck.

C.

A pull on the line moves every thing up but releases the forces acting on the dog spring. The dog spring expands, maintaining the dogs in a down position with respect to the skirt. When passing in front of the fishing neck recess, the dogs can engage into it and catch the fishing neck shoulder. The lower recess of the skirt, which has continued to move up, locks them there.

If difficulties are encountered in pulling the mandrel, jarring operation will free the pulling tool.

With “JU” type, jarring up to shear the pin will allow the strong spring to expand, pushing the skirt downward, releasing the dogs from the fishing neck is a way similar to the latch operation.

With the “JD” type, jarring down makes the core hit the fishing neck and the housing assembly transmits the shocks to the shear pin. The strong spring expands moving up the core, via of the holding studs that is set in the tool skirt. This releases the dogs from the fishing neck.

103

104

4.6

CAMCO “PRS” SERIES PULLING TOOL The “”PRS” (Exhibit 4.6) series pulling tools are specifically designed to pull devices with inside fishing necks. These devices include plungers, pack-offs, collar locks, nipple stops, large bore no-go type locks and any device with a inside fishing neck. The latching sleeve fingers contact and remain at the top of the fishing neck. The eight of the wireline tool string is applied to the mandrel, which moves further down inside the fishing neck, compressing the spring. The fingers are thus free to retract and enter the internal groove of the fishing neck. By pulling up, the tool is latched onto the fishing neck. In case of difficulties in pulling up the tool, jar down and shear. The mandrel is secured to the housing assembly by the ratchet, so that even with the spring fully released, the fingers are free to retract onto the mandrels small O.D. This frees the pulling tool and allows the operator to pull out the hole and re-pin the tool.

105

Exhibit 4.6 106

4.7

D & D “PR” & “PR-GS” RUNNING/PULLING TOOL The D & D “PR” tool (Exhibit 4.7a) is a versatile, releasable bull nose spear. The “PR” tool can be used as either a running or pulling tool. As a running tool, the “PR” can be used to run down hole tools that have straight bore internal fishing necks. Once the flow control being run is in place, the “PR” tool can be sheared to release by jarring down. As a pulling tool, it is versatile, durable and easily released. The “PR” tool can latch and pull flow controls with straight bore internal fishing necks or used to fish debris that has an I.D. to it. Large assortments of different size dogs are available for each size of the “PR” tool. The tool is currently available in 1.600, 1.843, 2.250, 2,700, 3.625 and 4.500 O.D. tool bodies. Converting the tool to a “PR-GS” (Exhibit 4.7b) is achieved by changing the core and the lower dogs. This makes the tool compatible to the Otis GS pulling/running tool. The running and pulling procedures are the same as the “PR” tool. The tool has a couple of advantages over compatible tools. 1.

The PR-GS dogs utilize approximately 90% of the available fish.

2.

The PR-GS has a tapered core that drives the dogs outward as the pull is directed upward., minimizing slippage, which allows it to latch a worn out internal fishing neck.

107

Exhibit 4.7a

Exhibit 4.7b

D&D PR Tool

D&D PR-GS Tool

108

109

SECTION 5 RUNNING TOOLS CONTENTS Topic 5.1 5.2 5.3 5.4 5.5 5.6. 5.7 5.8 5.9 5.10 5.11 5.12 5.13 5.14 5.15 5.16 5.17

OTIS TYPE “J” RUNNING TOOL OTIS TYPE “C” RUNNING TOOL OTIS TYPE “H” RUNNING TOOL OTIS TYPE “T” RUNNING TOOL OTIS TYPE “SP” RUNNING TOOL OTIS TYPE “W” RUNNING TOOL OTIS TYPE “X” RUNNING TOOL CAMCO KB-2 RUNNING TOOL CAMCO SERIES “D” RUNNING TOOL CAMCO SERIES “Z” RUNNING TOOL CAMCO SERIES “J” RUNNING TOOL CAMCO SERIES “R” RUNNING TOOL CAMCO SERIES “W”RUNNING TOOL BAKER “C1” RUNNING TOOL BAKER “E” RUNNING TOOL BAKER “G” RUNNING TOOL BAKER PRODUCTION

Page 111 112 113 115 117 119 121 125 127 129 131 133 135 137 141 143 146

ILLUSTRATIONS Exhibit 5.1 5.2 5.3 5.4 5.5 5.6 5.7a 5.7b 5.8 5.9 5.10 5.11a 5.11b 5.12 5.13 5.14a 5.14b 5.14c 5.15 5.16 5.17a 5.17b 5.17c

Otis Type “J” Running Tool Otis Type “C” Running Tool Otis Type “H” Running Tool Otis Type “T” Running Tool Otis Type “SP” Running Tool Otis Type “W” Running Tool Otis Type “X” Running Tool Otis Type “X” Running Tool Camco KB-2 Running Tool Camco Series “D” Running Tool Camco Series “Z5” Running Tool with “Z5” Lock Camco Series “J” Running Tool1 Camco Series “J” Running Tool Camco Series “R” Running Tool Camco “WC-1” Running Tool Baker “C-1” Running Tool Baker “W & C Accessories Baker “S” Accessories Baker “E” Running Tool Baker “G” Running Tool Baker Model “A” Shank Baker Model “A & AC” Probes Baker Model “B” Probe 110

Page 111 112 114 116 118 120 122 124 126 128 130 132 133 134 136 138 139 140 142 144 147 148 149

SECTION 5 RUNNING TOOLS 5.1

OTIS TYPE “J” RUNNING TOOL The type “J” running tool (Exhibit 5.1) sets types J, E, P, F and L locking mandrels in the corresponding nipples. The subsurface control is held in place on the “J” running tool by two 3/16-inch shear pins inserted through horizontal non-redial grooves. While going down, the dog carrier moves freely up and down along the small I.D. of the running neck of the mandrel. When a no-go nipple is encountered, the subsurface control is moved upward. The dog carrier moves down with respect to the small I.D. of the running neck on the mandrel and the dogs engage in the groove of the nipple. A pull upward of approximately 300 pounds indicates that the mandrel is in place. The pins are sheared by upward jarring. This releases the running tool and allows it to be pulled from the tubing.

111

5.2

OTIS TYPE “C” RUNNING TOOL The type “C” running tool sets type “D” collar stops. The running tool is inserted in the collar stop and pinned to the lower portion of the mandrel. After the desired depth has been reached and the collar located in the tubing string, the collar stop is locked by applying an upward pull on the wireline. Jarring upward sets the collar stop. This cause the pins in the lower portion to shear leaving the stop set in the collar.

112

5.3

OTIS TYPE “H” RUNNING TOOL The type “H” running tool is used for running and setting type “B” chokes, “EB” regulators, “FB and “TB” safety valves, Otis “F” pack-off anchors, collar stops and all Otis equipment using the Otis using the Otis type “B” mandrel assembly.

The “H” running tool (Exhibit 5.3) has spring actuated dogs, which catch on the fishing neck of the slip carrier of the mandrel assembly. A shear pin completely enclosed in the body, housing and secured by the set screw, provides a means for releasing the running tool from the slip carrier after the slips have been set and the mandrel assembly locked in the tubing.

Jarring down forces the slips of the mandrel to firmly grasp on the tubing wall and it shears the pin.

Additional downward jarring moves down the housing and makes the dogs expand and release from the fishing neck, so that the running tool may be pulled from the well.

Parts shown on (Exhibit 5.3) are: 1.

Dogs

2.

Shear Pin

3.

Body

4.

Housing

5.

Set Screw

113

114

5.4

OTIS TYPE “T” RUNNING TOOL This type running tool (Exhibit 5.4) is used to set Otis types S, T, N, and Q mandrels. Part A of the exhibit shows when the mandrel lands in its selected profile, downward jarring shears the diametric pin, pulls the locking mandrel down and releases the running tool dogs.

Pull on the line to make sure the mandrel is locked, as shown in part B. Jar to shear the non-radial shear pins and pull out the running tool as shown in part C.

115

116

5.5

OTIS “SP” RUNNING TOOL The type “SP” running tool (Exhibit 5.5) is used for setting the PS and PT plugs (with pressure equalizing rod) in the S or T mandrel profiles. Its operation is identical to that of the T running tool, however there are 3 differences in design. 1.

The SP can take larger diameter mandrels, since more room is needed to lodge the pressure-equalizing rod. Also the core hole is deeper.

2.

The core hole is not threaded, because threading is not necessary with a plug.

3.

There are only two dogs instead of four.

NOTE Maintain the core in a lower position with an Allen key or a strong screwdriver to enable latching onto the mandrel before placing the pins.

117

118

5.6

OTIS TYPE “W” RUNNING TOOL This type “W” running tool (Exhibit 5.6) sets type W, C, and B slip-type mandrels. The tool consists of a prong weldment with a prong, housing and collet. The collet is designed to seat in an internal recess in the running tool of a type C or W Otis mandrel and is locked in this position by the prong. A shear pin serves to hold the collet in the running position. When the desired setting depth is reached, the tools are picked up to set the slips and expand the rubber on the lower part of the type C mandrel. Upward jarring is used to secure the type C or W mandrel in a locked position and expand the pack-off element. Once set, the pin is sheared in the running tool and the prong withdrawn from behind the collet. This releases the running tool from the mandrel and the tool is retrieved.

119

Exhibit 5.6 Otis Type “W” Running Tool

120

5.7

OTIS “X” RUNNING TOOL (Exhibit 5.7a) 5.7.1

Operating Procedure While going down the hole passing restrictions, the selective dogs compress the spring and collapse. When encountering the top “X” nipple, jar down to shear the top pin, locking the mandrel in place. Jar up to release the running tool to the locking mandrel by shearing the bottom pin. The anchoring dogs are normally retracted since the locking sleeve is in the upper position.

5.7.2

Nipple Selection When running tool is in the selective position the locating / locking keys are retracted allowing the locking mandrel to pass through the upper nipples. When the selected landing nipple has been passed: Move up slowly and read the pull on the weight indicator before the dogs contact the chamfer of the landing nipple. When the locator dogs enter the landing nipple, pull 200 pounds above the weight indicator reading. This makes 5, 13, 1, 11 and 12 move up. Then the locking sleeve slides behind the springs and the keys are in working position (they can, however, still retract since the locking sleeve is partly engaged). At the same time, the spring is compressed and the dogs lock in the lower groove of 13, the 2 – half-discs collapse, disconnecting the sleeve from the core.

5.7.3

Pulling Up Above the Anchoring Point and Running In Again Easy Operation: The dogs are retracted and the keys can still move. 121

122

5.7.4

Anchoring The keys engage corresponding profile of the nipple. Jar downward to shear 16. 5, 13, 3, 17 and 10 move downward, the keys are thus locked in the nipple. On the other hand, the dogs enter the core shoulder and are locked.

5.7.5

Pull Up Pull up to verify anchoring. 5, 13, 3 and 6 move up. Jar up to shear pin and retrieve tool.

NOTE While assembling the running tool, the two half discs are inserted with the chamber facing down.

123

124

5.8

CAMCO “KB2” RUNNING TOOL The KB2 running tool (Exhibit 5.8) is used to set gas lift valves and plugs with lower lock type K1 (ex: valves DK1, BK1, CSK1, GK2, DK02, Etc.) in the KB and KC mandrels. This tool is similar to the type RE, but in the KB2, a diametric brass pin substitutes the non-redial pins. (3/16-inch diameter) This tool also has latching dogs. 5.8.1

Setting The valve is latched by the running tool dogs and lowered into the side pocket. When the valve is seated in the pocket, the running tool skirt rests on top of the pocket before the valve is completely anchored. Downward jarring shears the pin anchors the valve and frees the dogs in the grove. The dogs are maintained in the down position by the lock pin. The running tool is retrievable

NOTE Setting the valves with lock K1 with the running tool KB2 requires an 8” spacer (203.2mm) between the kick-over tool and the running tool. Parts listed in Exhibit 5.8 are: 4.

Shear Pin

5.

Lock Pin

7.

Dogs

8.

Groove

125

126

5.9

CAMCO SERIES “D” RUNNING TOOL The series “D” running tool (Exhibit 5.9) is attached to the “C” or “CS” lock by two non-redial pins. The internal mandrel is held in upper position by the locking dogs, clamped by the no-go ring, which is in a lower position and fixed on the no-go retainer by two thin non-redial pins. 5.9.1

Running In Lower the tool until the no-go ring contacts the no-go nipple type “D”. The dogs are in front of the landing nipple groove.

5.9.2

Anchoring The pins are shear by jarring downward and the no-go retainer moves downward. This frees the internal mandrel and allows the locking dogs to expand. The running tool piston hits the fishing neck shears the two (1/8” diameter) pins. The internal mandrel falls down and forces the locking dogs apart. The ratchet grips the lower part of the mandrel, securing the mandrel in the locked position. To retrieve the running tool, jar upward to shear the two (3/16” diameter) pins. To fish the lock, catch the fishing neck with a Camco (JDC or JUC) pulling tool and jar upward to shear the ratchet.

127

128

5.10

CAMCO SERIES “Z” RUNNING TOOL The Z-5 running tool (Exhibit 5.10) installs Camco type DB in the Camco type DB and 4 inch through 7 inch B6 landing nipples. This running tool has a positive tattle-tale position ring that give positive indication as to whether or not the lock has been set. The Z-5 running tool is used to install Camco Z-5 collar lock mandrel in the tubing string. The SC running installs both the 3-inch and the 4-inch Camco ZC collar lock mandrels in the tubing string. While running in, the stopper dogs, Item 1, are retracted. The tools with the assembly are lowered into the well a few feet below where the lock is to be set. When pulling upward, the assembly, Items 2, 3, 4 and 5, moves up first. When passing the collar recess, the upper chamber on Item 5 forces the stopper dogs into it. Items 2, 3, 4 and 5 continue sliding up until the fingers of the latching enter the upper groove of the body. Furthermore, the elastic ratchet catches onto the strips of the core and maintains 2, 3, 4 and 5 in the upper position. Jar down to shear Item 8, then to shear Item 9. The running tool can be retrieved.

129

130

5.11

CAMCO SERIES “J’ RUNNING TOOLS (Exhibits 5.11a and 5.11b) The JA running tool installs an AK latch with an AK-1 valve in a Camco KA mandrel. The JK running tool installs the BK or the BK-2 latches with valve or E dummy in the K series mandrel. The J running tool runs Otis “S” Mandrels in their appropriate nipples. The JEL running tool installs the ER equalizing dummy in the KB series mandrels. The JDK running tool installs the BK latch in the KC series mandrels exclusively. The JC-3 running tool installs both the R and the RA latches in the MM series mandrels

The type K kick-over tool is positioned to latch the valve or dummy by going pass the mandrel and pulling up slowly. After passing the mandrel coming up, the operator lowers the tools with the setting assembly slowly until the valve or dummy sets in the pocket. Jarring downward drives the valve or dummy down into the pocket until the no-go within the gas-lift mandrel is reached. The cam in the R latch or the ring in the K latch locks in mandrel profile. Upward jarring shears the running tool pin and the running tool is retrieved.

131

132

5.12

CAMCO SERIES “R” RUNNING TOOL The R running tool (Exhibit 5.12) sets the ER1 latch that are used to run BK gaslift valves and RE plugs in KPC mandrels. 5.12.1 Description This tool has two sliding bells. The upper bell has a threaded 15/16 SR fishing neck screwed and secured by a safety shear pin. It also has a pressure-equalizing hole, a hole to insert a lateral locking finger and its spring, and a series of six lateral holes to receive the retaining dogs, which hold the valve. The lower bell caps the ER latch of the valve and holds it by two 1/8” shear pins. The sleeve of the ER latch is maintained in an upper position so that the locking ring is free to move laterally. 5.12.2 Setting With the valve being in its side pocket, the lower end of the running tool hits the top of the collar seat, before the lower part of the valve contacts the chamfer of the seat. Downward jarring shears the pin and pushes the sleeve down, forcing the locking ring of the valve in its groove. On the other hand, the retaining dogs have moved down, in from of a large diameter groove, so that they do not retain the valve anymore. The locking finger is pushed out is spring and prevents the retaining dogs from returning to their initial position. The valve is set. The running tool is retrieved without upward jarring.

133

134

5.13

CAMCO SERIES “W” RUNNING TOOL The WC-1 (Exhibit 5.13) running tools are used to set WB series safety valves and Camco M locks in Camco W series selective landing nipples

NOTE When a Camco MA blanking plug, which is run in a Camco M lock, is to be installed, a W-1 running tool must be used. All other control devices can be run on the WC-1 running tool The W-1 running tool is used to install a Camco MA blanking plug, which is run on a Camco M lock, in a Camco W and WB series selective landing nipples.

NOTE Although the W-1 running tool will set Camco WB series safety valve and Camco M locks in Camco W series selective landing nipples, the preferred tool to use for these operations is the WC-1 running tool

135

Exhibit 5.13 Camco WC-1 Running Tool 136

5.14

BAKER “C1” RUNNING TOOLAND A SHANK (Exhibit 5.14a) The C1 running tool is use to run and land various types of Baker flow control devices and is operated with either a tread protector or locating ring. Dressed with a tread protector: All applications that do not require a no-go on the tool it self. This includes all running of flow control devices equipped with “W”, “Z” and “TS” type locks (Exhibit 5.14a and 5.14b). Flow control devices equipped with type “S” type locks are run with a thread protector except when landing in a sliding sleeve (since the lock could not be positioned in the sliding sleeve rather than in the locking groove. Dressed with a locator ring: The addition of the proper size-locating ring converts the tool to a no-go type running tool. This is used when running flow control devices equipped with type “S” locks for landing in sliding sleeves. It is recommended to use the locating ring when running a flow control device equipped with an type “S” lock, since the no-go feature of the landing ring positively positions the tool.

137

Exhibit 5.14a Pinning Instructions for Baker Model C1 Running Tool

138

Exhibit 5.14b W & Z Type Accessories

139

Exhibit 5.14c Type “S” Accessories Run With Up-Facing Locks Trailing

140

5.15

BAKER “E’ RUNNING TOOL The type E running tool (Exhibit 5.15) is used to selectively run and land flow control devices with model S locks into F or J nipples. 5.15.1 Running In While lowering, the tubing restrictions force the selective dogs to move up, compressing the spring. The selective dogs can collapse into the recess of the core. The anchoring dogs are maintained in a retracted position by the rod. 5.15.2 Nipple Selection Go down below the selected position and move up slowly. The selective dogs contact the lower chamfer of the nipple, they cannot retract since the should of the core is behind them. Observe increase in tension. Go down again and pull to shear pins. The skirt moves down allowing the selective dogs to retract below the shoulder of the core. The rod moves down (spring action), freeing the anchoring dogs. 5.15.3 Anchoring Continue pulling up. The dogs collapse, pass the lower chamfer of the nipple, and then enter into the groove of the nipple. The tool is locked. 5.15.4 Retrieving The Tool Jar up to shear the two tangential pins. Parts shown on Exhibit 5.15 are: 1. 2. 3. 4. 5.

Dog Spring Core Anchoring god Rod

6. 7. 8. 9. 10.

141

Shear pin Shear pin Spring Skirt Non-radial pins

Exhibit 5.15 Baker E Running Tool 142

5.16

BALER TYPE “G” RUNNING TOOL The type “G” pulling tool (Exhibit 5.16) is used to locate any one or all the selective bores contained in a string of tubing while running Baker flow control accessories equipped with “S-1” or “S-2” type lock subassemblies. The tool incorporates a moveable shank, which permits repeated jarring-down without damage to down-facing locks. 5.16.1 Running The S-1 or “S-2” type lock subassembly (with desire flow control device) is shear pinned to the lower end of the body and then attached to the jars and stem. All up-facing locks are run trailing, and all down-faced locks are run retracted.

NOTE The same prong used for the “C-1” running tool is required when running “S-1” or “S-2” type lock subassembly on the “G” running tool. When approaching a selective seal bore, it is advisable to slow down so that the O.D. of the collet will no-go on the seal bore I.D. Impact due to a fast rate of slack off will collapse the collet allowing the tool to drop through either the nipple or sleeve valve. 5.16.2 Operation Jarring down will collapse the big spring, allowing the collet to travel upward relatively to the body. The collet fingers will collapse into the small O.D. off the body permitting the “G” running tool to drop through the seal bore. This operation is repeated at each selective seal bore until the one seal bore that is to receive the desired flow control device is located. 143

144

Exhibit 5.16 Baker Type G Running Tool The following procedure is then applied: 1.

The running tool is located on the selective bore (either a nipple of the L sleeve).

2.

Pick up until up-faced locks are engaged, Jar down shearing the top shear pin withdrawing the shank, and releasing the down facing locks.

3.

Check opening of down-facing locks by jarring through nipple or sleeve.

4.

Jar up, shearing the bottom shear pin and leaving the accessory.

5.

Pull out the hole.

6.

As the tool is being retrieved from the well, the collet will no-go on the bottom of each selective bore. Wireline tension causes the small spring to compress allowing the body to travel up relative to the collet. The collet fingers collapse around the small O.D. of the body, freeing the tool to pass through the nipple or sleeve valve. Rapid retrieval from the well is an additional advantage of the model “G” running tool. Parts shown on Exhibit 5.16 are:

1.

Spring

2.

Collet

3.

Body

4.

Top Shear Pin

5.

Bottom Shear Pin

6.

Spring

145

5.17

BAKER PRODUCTION 5.17.1 Model A Shank (Exhibit 5.17a) In certain lengths, the model A shank is a lock retention device, which when made to the running tool (type C) keeps the down-facing S, TS, W, Z type locks retracted while running in. In certain other lengths, it severs as a crossover from the running tool to the models A and B prongs. 5.17.2 Model A and AC probes (Exhibit 5.17b) The model A probe can carry a prong made to its lower end, in place of the set screw. The model AC probe, not being equipped to carry a prong, should be run in all areas where a prong is required. The model A or AC probe is used to close the up-facing locks on any flow control device having A or TS selective locks. As it penetrates the fishing necks, the blade automatically swivels, byPassing the down-facing locks, and retracting the up-facing locks before the pulling tool latches on. The core extension shoulders against the fishing neck of the accessory when setting or jarring down. 5.17.3 Model B Probe (Exhibit 5.17c) The B probe is used to close the locks on any flow control device having a W or Z (top or bottom no-go) lock. The model B probe retracts the locks before the pulling tool latches on. The flange shoulders against the fishing neck when setting or jarring down.

146

Exhibit 5.17a Model A Shank 147

Exhibit 5.17b 148

Model a and AC probes Exhibit 5.17c Model B Probe 149

SECTION 6 MANDREL AND LANDING NIPPLES CONTENTS Topic 6.1 6.2 6.3 6.4 6.5 6.6 6.7 6.8 6.9 6.10 6.11 6.12 6.13 6.14 6.15 6.16 6.17 6.18 6.19

Page OTIS TYPE “B” MANDREL OTIS TYPE “W” AND “C” MANDREL CAMCO TYPE “A” SLIP LOCK BAKER “TS” LOCK OTIS TYPE “D” COLLAR LOCK MANDREL OTIS TYPE “X” AND “R” MANDRELS AND NIPPLES OTIS TYPE “XN”AND “RN” MANDRELS AND NIPPLES OTIS “S” AND “T” MANDRELS AND NIPPLE OTIS “N” MANDREL AND NIPPLE OTIS “J” AND “E” MANDRELS AND NIPPLES CAMCO “C” LOCKS AND “D” NIPPLES CAMCO SERIES “W” NIPPLES CAMCO SERIES “DB” LOCKSAND NIPPLES BAKER “W1” AND “Z” LOCKS BAKER “M” AND “K” LOCKS BAKER “N” AND “L” LOCKS BAKER “S” LOCK WITH “L” AND “F” NIPPLES BAKER TYPE “R’ AND “N” BOTTOM NO-GO NIPPLES BAKER TYPE “F’ AND “J” TOP NO-GO NIPPLES

151 152 157 159 161 163 165 167 170 171 173 177 179 181 183 185 187 189 190

ILLUSTRATIONS Exhibit 6.1 6.2 6.3 6.4a/b 6.5 6.6 6.7 6.8 6.9 6.10 6.11 6.12 6.13 6.14 6.15 6.16 6.17 6.18 6.19

Page Otis Type “B” Mandrel Otis Type “W” and “C” mandrel Camco Type “A” Slip Lock Baker “TS” Locks Otis “D” Collar Lock Mandel Otis “X” and “R” mandrels and Nipples Otis Type “XN” and “RN” Mandrels and Nipples Otis “s” and “T” Mandrels and Nipples Otis Type “N” Mandrel and Nipple Otis “J” and “E” Mandrels and Nipples Camco “C” and “D” Locks Camco “W1” Nipple with Lock in Place Camco “DB” Lock and Nipples Baker “W” and “Z” Locks Baker “M” and “K” Locks Baker “N” and “L” Locks Baker “S1”, S2 Locks and “F” Nipple Baker “”R” and “N” Bottom No-Go Nipples Baker “F” and “J” Top No-Go Nipples 150

151 154 158 160 162 163 165 168 170 172 174 178 181 182 184 187 188 189 190

SECTION 6 MANDRELS AND LANDING NIPPLES

6.1

6.1.1

6.1.1

OTIS TYPE “B” MANDREL •

Running Tool: W, C or H (H recommended)

•

Pulling Tool RB

•

The type “B” is 1500 pounds designed to hold a differential of 1500 pounds from the bottom up only.

•

It is not recommended to anchor above 1000 feet.

Operation with the “H” Running Tool: 1.

Go down slowly.

2.

Near the anchoring depth, speed up. The running tool slides over the mandrel, which is slowed down by the packing expanded because of the fluid flow. The slips move down over the cone and grip into the tubing. The bulk of the stems supply the necessary shock for setting.

3.

Further jarring down shears the shear pin of the running tool and perfects the anchoring.

Pulling with the “RB” pulling Tool: 1.

The pulling dogs are engaged by jarring down on the top of the mandrel, which moves the fishing neck within reach of the pulling tool.

2.

Upon latching the fishing neck, the mandrel is pulled out the well.

151

152

6.2

OTIS TYPE “W” AND “C” MANDREL The drawing shows the operation of the type W mandrel. The operation of the type C follows the same principle. Running Tool:

W

Pulling Tool:

RB

This type W and C mandrel is designed to hold differential pressure from bottom up only (Max. 1500 psi). It is not to be set above 1000 feet.

153

154

6.2.1

6.2.2

Setting with the Type “W” Running Tool 1.

The anchoring slips slide along the tubing wall during running in the hole.

2.

When the anchoring depth is reached, pull up.

3.

The cone forces the slips to grip the wall of the tubing.

4.

Jarring up shear the pins, which fix the mandrel body and cone together. The body moves up and the lower cone shaped shoulder engages under the packing, sealing off the tubing.

5.

Further upward jarring shears the pins of the pulling tool.

6.

When shearing the pins while jarring upward, the tools are not allowed to set back down on the mandrel.

Pulling with the Type “RB” Pulling Tool

1.

The pulling tool skirt engages onto the mandrel fishing neck, and then the pulling tool core strikes the mandrel body, which moves down.

2.

The pulling tool dogs latch onto the mandrel fishing neck. 3.

The lower cone shaped shoulder moves out of the packing, then the shoulder of the mandrel body catches the cone assembly and moves it down, freeing the slips.

4.

The mandrel then hangs on the fishing neck and is retrieved.

155

OTIS TYPE “W” MANDREL DEMENSIONS

156

6.3

CAMCO TYPE”A” SLIP LOCK Running Tool:

Type A

Pulling Tool:

Type JUC

Designed to hold pressure from the bottom only (Max. 1550 psi) 6.3.1

Setting with the running tool A 1. Go down to the setting depth. 2. Pull up on the line to start anchoring the mandrel slips 3. The jar can then be closed, ready for jarring upward. 4. Jar up to complete the anchoring of the mandrel and to shear the running tool pins. 5. Pull up on the tool string removing the same from well.

6.3.4

Pulling with the “JUC” Pulling Tool 1. The pulling tool core strikes the mandrel body, freeing the slips. 2. The pulling tool engages the mandrel fishing neck. 3. The mandrel can then be pulled.

157

158

6.4

BAKER “TS” LOCK TS1 Lock (Exhibit 6.4a) is used for 1.660 to 3-½ inch tubing 10,000-psi maximum either side. TS2 lock (Exhibit 6.4b) is used for 1.900 to 2.875 inch tubing 10,000 maximum either side. The pressure limitation will be that of the module (normally cup mandrel assemblies) attached to the lock subassembly. The cup mandrel assemblies have a maximum differential rating of 1500 psi.

6.4.1

Setting with the Running Tool “C” The model “A” shank is used with the “C” running tool to control the locks during operation. It is also used as a prong carrier when prongs are required during running operations.

6.4.2

Pulling with the Camco “JUC or JDC” Pulling Tool The model “A” probe is used with the Camco “JUC or JDC” pulling tool when a prong is required. The model “AC” probe is used with a standard pulling tool when a prong is required.

159

160

6.5

OTIS RYPE “D” COLLAR LOCK MANDREL (Exhibit 6.5) Running Tool “D” Pulling Tool “GR” with extended Core. Cannot be unlocked by pressure differential from either side. Rated at 5,000-psi differential.

6.5.1

Setting with the “D” Running Tool In the running position, the setting tool dogs are tied up to the mandrel-locking sleeve. This allows the outer sleeve containing the locking dogs to ride free and to retract the dogs. The assembly is run down about 10 feet below the setting depth. The mandrel with the running tool is then pulled up into the first collar groove. Jarring up once upon entering the collar groove locks the collet lock in an upper position to the sleeve and the packing is expanded. Check the setting by jarring down. Jarring upward shears the pin in the running tool and tools are pulled out the hole.

6.5.2

Pulling With “GR” Pulling Tool (With Extended Core) The “GR” pulling tool is run down and latches the fishing neck of the mandrel and is further used to drive down the locking sleeve and the retaining ring of the dogs. However, this cannot be done if a differential of pressure exists. When the pressures are equalized, the dogs may be retracted and by moving downward, the mandrel is retrieved.

161

162

6.6

OTIS “X” AND “R” MANDRELS AND NIPPLES Type “X”:

Designed for use in standard weight tubing.

Type “R”:

Designed for use in heavy weight tubing.

Running tools:

Types “x” and “R”

Pulling tools:

Type “GS” or “GR”

Setting mandrel “R” with the running tool “R” is the same as for “X”

163

Features of the “XN” and the “RN” mandrels and nipples are: 1. 2. 3. 4. 5. 6.

Pressure held on either side. Type “XN” for standard weight tubing. Type “RN) for heavy weight tubing. Running tool type “X” for “XN” mandrel Running tool “R” for “RN” mandrel Pulling tool “GR” for “XN” and “RN” mandrel

164

6.7

OTIS “XN” AND “RN” MANDRELS AND NIPPLES The type “XN” and “RN” no-go landing nipples and mandrels (Exhibit 6.7) are used in single nipple installations or as the bottom nipple in conjunction with a series of type “X” or type “R” landing nipples. The “XN” no-go nipple is used with the type “X” landing nipple and the type “RN” us used with the type “R” landing nipples. Type Otis “XN” landing nipples have a full opening packing bore, with a locking recess at the top of the nipple and a slightly restricted no-go profile at the bottom. The restricted no-go profile is designed to prevent some wireline tools from being lowered below the tubing where they may be lost. Some other uses include: plugging to hold pressure from above where hydraulic packers are to be set, and where an upper zone has to be squeezed, acidized or tested.

Exhibit 6.7 Otis XN and RN mandrels and nipples

165

GUIDE TO OTIS LANDING NIPPLES

166

6.8

OTIS “S” AND “T” MANDRELS AND NIPPLES Type “S” for regular weight tubing. Type “T” for heavy weight tubing. Running tool “T”. Pulling tool “RS” The selection is made by a combination (nipple + selective keys of the mandrel). There are 5 key selections; therefore the selections are stamped on the keys from I to 5 (no. 1 being the lower one in the completion). The type “T” mandrel differs from the type “S” mandrel because it has a smaller O.D.

6.8.1

Setting the mandrel “S” with the “T” running Tool

1.

While going down, the positioning keys slide along the tubing. The anchoring dogs are pinned up to the running tool and retracted.

2.

When the mandrel passes in front of its “companion nipple”, the positioning keys enter the nipple profile. The mandrel is stopped when the keys set into the matched profile of the nipple. Downward jarring shears the pin of the running tool, thus freeing the dog carrier.

3.

Upward jarring anchors the mandrel. The mandrel is pulled up collapsing the positioning keys and setting the anchoring dogs into the nipple upper profile. Upward jarring shears the two tangential pins of the running tool freeing the running tool and the tools are retrieved.

4. 6.8.2

Pulling the mandrel with a “RS” pulling Tool In order tom make the dogs of the pulling to catch the fishing neck of the mandrel rod, it is necessary to slightly jar down on the mandrel (the pulling tool core hits the mandrel body). The mandrel is thus unlocked and latched and can be retrieved. NOTE The operation of the running tool “T” and the pulling tool “RS” is detailed in the running tool section.

167

Exhibit 6.8 Otis “S” and “T” Mandrels and Nipples 168

GUIDE TO OTIS “S” AND “T” LANDING NIPPLES

169

6.9

SETING AND PULLIMG THE OTIS “N” MANDREL (Exhibit 6.9) This mandrel is non-selective. However, the setting and pulling methods is Identical to those used in the mandrels “S” and “T”. The “N” mandrel has a noGo ring instead of positioning keys.

Exhibit 6.9 Otis “N” Mandrel 170

6.10

OTIS “J” MANDREL AND NIPPLE Type “J” landing nipples The type “J” landing nipples are non-selective type nipples designed with the nogo and locking recess in the upper part of the nipple: this nipple can be used as an alternate to the type “N” nipple. The type “J” landing nipples greatest use is as an alternate to the type “N” landing nipple or as a seating nipple for landing plugs or as a pump seating nipple and is always the lower most nipple in the tubing string. The “J” cannot be used below the “N” nipple, but is frequently installed to land subsurface controls that must have smaller dimensions than the “S” equipment. The type “J” nipple will allow passage of most tubing perforating guns and can be used as a pump-seating nipple. Another use on the short string of a multiple string completion where a full opening nipple is not required. However, due to the mandrel design, type “J” mandrel should not be used when pressure differentials from above will exceed 5,000 psi.

171

Exhibit 6.10 Otis “J” Mandrel and Nipple

172

6.11

CAMCO “C” LOCKSAND “D” NIPPLES A.

B.

C.

Series “C” and “CS” Locks •

No-go type locking mandrels designed to locate in series “D” and “DS” nipples respectively.

•

A relative travel no-go ring ensures positive positioning when the nipple is contacted, thus minimizing wireline time.

•

This lock has a shear release mechanism.

Series “CC” and “CSC” Locks •

A relative travel no-go ring ensures positive positioning in the landing nipple when contacted.

•

The “CC” locking mandrel is used in Camco’s “D” landing nipple.

•

The “CSC” locking mandrel is used in Camco’s “DS” landing nipple.

•

Both the “CC” and “CSC” locking mandrels have a releasing mechanism that feature a collet type detent.

Series “D” Landing Nipples •

The Camco “D” series landing nipples are no-go type designed to run at the last nipple in the tubing string.

•

The packing bore, slightly restricted, will allow passage of wireline service tools, as well as through tubing perforating equipment.

•

The no-go is incorporated on the series “C” locking mandrel and contacts the “D” nipple above the upper packing section.

173

Exhibit 6.11 Camco “C” Lock and “D” Nipple

174

D.

•

The no-go feature allows positive positioning, which reduces wireline time.

•

Each nipple is corrosion resistant.

Series “DS” Landing Nipples • Similar in design to the series “D” nipple. The difference is larger packing bore equivalent to the series “W” nipples. •

E.

The series “DS” nipple receives the “CS” lock.

Setting •

F.

Use the running tool “D”. Pulling

•

Use the pulling tool type “JDC”.

175

176

6.12

CAMCO SERIES “W” LANDING NIPPLES The Camco series “W” landing nipples were designed to eliminate the restriction on number of nipples run per tubing string. They do not require position coding nor sequential order. Therefore, as many nipples as desired may be run in any given well. These nipples are positive for the series “M” landing mandrels.

6.12.1 Features 1.

Completely Selective – no limit on number of nipples per string.

2.

Larger Bore – for maximum production rates

3.

Construction – all landing nipples are constructed of low heat treat alloy steel for use in corrosive environments such as H²S service.

177

Exhibit 6.12 Camco “W-1” Nipple with Lock in Place

178

6.13

CAMCO “DB”LOCKS AND NIPPLES A. Series “DB” Landing Nipples

•

No-go type nipple available in tubing sizes ranging from 4-1/2 “ to 7” O.D.

•

These nipples receive the series “DB” locks.

•

The no-go on the lock body contacts the nipple just above the upper packing section, which gives positive alignment for setting the lock. Several nipples may be run in any tubing string by stair stepping the nipple I.D.

•

Each nipple is designed for corrosive environments.

B.

Series “DB” Locks •

Available in tubing sizes from 4-1/2” to 7” O.D.

•

The no-go is incorporated on the body of the lock and contacts the nipple above the upper packing bore. The no-go dimensions on the locks permit passage through each larger nipple until the desired nipple is located, which assures positive positioning.

•

The “DB” lock is run on a series “Z” running tool.

•

The unique tattle tale device gives indication that the lock is truly located in the upper position.

•

An internal fishing neck obtains large bore.

179

Exhibit 6.13 Camco “DB” Locks and Nipples

180

6.14

BAKER “W” AND “Z” LOCKS The “W” lock is a top no-go that can be set in “F” or “J” nipples or “L” sliding sleeves. •

The “W” is used in 1.660” to 4-1/2” tubing size range and pressure differentials: 2500 psi from bottom up 6000 psi from the top down.

•

The “W2” is used in 1.900” to 3-1/2” tubing size range pressure differentials: 5000 psi from bottom up 10000 psi from the top down.

The “Z” lock bottom no-go that can be set in “R” or “N” nipples. •

The “Z” is used in 1.660 to 4-1/2” tubing size range and pressure differentials: 6000 psi from bottom up 10000 psi from the top down.

•

The “Z2” is used in 1.900” to 3-1/2” tubing size range pressure differentials: 10000 psi either size.

A.

Setting The “C1” running tool equipped with the “A” shank (Refer to section 5, page 5-29).

B.

Pulling Refer to Section 4, page 4-14 for pulling tool “JUC” or “JDC” equipped with a B probe.

181

Exhibit 6.14 Baker “W” and “Z” Locks

182

6.15

BAKER “M” AND “K” LOCKS (INTERNAL FISHING NECKS) The type “N” is a top no-go used in a model “F” or “J” nipple or “L” sliding sleeve. The type “K” is a bottom no-go used in a model “R” or “N” nipple. These locks are lowered and retrieved with an Otis “GS” running/pulling tool and a model “M” probe to hold the plunger in a down position. (Exhibit 6.15)

183

Exhibit 6.15 Baker “M” and “K” Locks

184

6.16

BAKER “N” AND “L” LOCKS (EXTERNAL FISHING NECKS) The type “N” is a top no-go used in a model “F” and “J” sliding sleeve. The type “L” is a bottom no-go used with a model “R” or “N” nipple A.

Setting The model “C1” running tool is used with an “N” shank to run locks. (Exhibit 6.16)

B.

Pulling The lock is pulled with an Otis “RB” pulling tool with an “N” probe to hold the plunger in the down position. (Exhibit 6.16) NOTE The chart below indicates the sizes for running safety valves that only hold pressure from below. The no-go interference is less than for other seal bore sizes, hence, the restriction to pressure from one side only.

185

Exhibit 6.16 Baker “N” and “L” Locks 186

6.17

BAKER “S” LOCK, J AND “F” NIPPLES The lock “S1” is used for 1.660 to 4-1/2 inch tubing and can hold 6000 psi differential pressure either side. The lock “S2” is used for 1.990 to 3-1/2 inch tubing and can hold 10000 psi differential pressure either side. “S1” and “S2” are selective locks for use in model “F” or “J” sealing nipple or a model “L” sliding sleeve.

6.17.1 Setting Used with running tool “E” or “G” or model “C!” with type “A” shank. 6.17.2 Pulling with Otis “RB” or Camco “JUC” or “JDC” pulling tools The model “A” probe is used with standard pulling tools when a prong is required. The model “AC” probe is used with standard pulling tools when a prong is not required. NOTE The operation of the running tool “E” or” G” and “C1” (with “A” shank) is detailed in section 5

187

188

Exhibit 6.17 Baker “S1”, “S2” locks and “F” Nipples

6.18

BAKER TYPE “R” AND “N” BOTTOM NO-GO NIPPLES

Exhibit 6.18 Baker Types “R” and “N” Bottom N0-Go Nipples

189

6.19

BAKER TYPES “F” AND “J” TOP NO-GO NIPPLES

Exhibit 6.19 Baker types “F” and “J” Top No-Go Nipples

190

191

SECTION 7 GAS LIFT CONTENTS Topic

Page

7.1

WIRELINE TROUBLE SHOOTING METHODS

193

7.2

SIDE POCKET MANDRELS AND KICKOVER TOOLS

197

ILLUSTRATIONS Exhibit Page 7.1.a

Tubing Gauge

194

7.1.b

Tubing End Locator

194

7.1.c

Collar Stop

194

7.1.d

Tubing Stop

194

7.1.e

Circulation Plug

194

7.2.a

Basic Design Side Pocket Mandrel

197

7.2.b

Kick-Over Tool

198

7.2.c

Camco KBMG Side Pocket Mandrel

199

7.2.d

Orienting Sequence For Valve Installation

200

7.2.e

Gas Lift Equipment Chart

201

192

SECTION 7 GASLIFT 7.1

WIRELINE TROUBLE SHOOTING METHODS

A wireline unit can be a useful tool when a well looses its capacity to lift the production fluid to the surface. Gas lifting the well may be the answer to producing more fluid from the reservoir. This may be approached in two different ways depending on how the well was completed. In some cases, the design engineer may have foreseen the depletion of the well and prepared the completion string with gas lift mandrels. On the other hand, gas lift mandrels may not have run. The field engineer is responsible for designing the gas lift installation. Several factors determine the placement and setting of the valves in the tubing string. The engineer working with the gas lift supplier works this out. In either case, once the well looses its energy drive or for other reasons, the well quits producing, the wireline unit may be used to establish some facts about why the well is not producing fluid. An example of this is where a well that has been completed without installing gaslift valves or mandrels in the well. When the well quits flowing, the operator may call for a wireline unit to check out the fluid level and possible obstructions in the tubing string. Exhibit 7.1a on page 7-2 pictures a tubing gauge that may be used for this purpose. The tubing gauge may be run to the bottom of the well to see if the perforations are clean. If in doth, a tubing end locator may be run. Exhibit 7.1b on page 7-2 pictures a tubing end locator. This tool is only run after reassurance that the tubing is clear. The locator indicates where the end of the tubing and the bottom of the well is. These measurements are compared with the well schematic to see whether the perforations are clear. If the perforations are clear, the engineer may want to try to gas lift the well. By swabbing the well, a working fluid level may be established. However there are other methods of determining where the well fluids may rise. With a few known factors about the well, calculations may also be used. This gives the engineer an idea about where to punch an orifice and possibly a hole in the tubing to gas lift the well. After the engineer determines where to put the hole, a stop is run and set at that depth. Exhibit 7.1c shows a picture of a collar stop witch may be used providing that the tubing has collars. Exhibit 7.1d shows a picture of a tubing stop that may be set in case the tubing does not have a collars recess. After placing the stop at the level decided upon, a circulating plug should be run on top of it. Exhibit 7.1e shows a picture of a circulating plug. A hole is normal punched right above the circulating plug. Then, the tubing is circulated with a light oil and gas to displace any heavy fluids above to hole. This also keeps any heavy fluids out of the formation.

193

TUBING GAUGE

TUBING END LOCATOR

Exhibit 7.1a

COLLAR STOP

Exhibit 7.1b

TUBING STOP Exhibit 7.1d

CIRCULATING STOP Exhibit 7.1e

194

Exhibit 7.1c

Wireline plays a big part in solving other gas lift problems. You may have a situation where a well shows a decrease in total fluid production and an increase in supply gas usage. In most cases, this indicates a cut gas lift valve or a hole in the tubing. The hole may be located by gas lifting the well and running the following test. A bottom-hole pressure external temperature collar locator survey will identify the amount of flow from each gas lift mandrel or identify if the gas lift is coming from a hole in the tubing. At present, this is the most efficient method for use of new technology in troubleshooting gas lift problems, (see example below). External Temperature Collar Locator Survey

195

August 2003 - Wood Group introduces the Smart Cable Head The Smart Cable Head is a memory instrument small and rugged enough to be included in all slick line tool strings. The SCH eliminates the need for additional calibration runs since the it is designed to make up directly below the rope socket and can easily be included with all routine slick line operations such as bottom checks, gas lift change outs, and plug setting operations. The SCH records CCL, pressure and high-resolution borehole temperature data to non-volatile memory. In the event of a problematic operation, this data can be invaluable for diagnosing the down hole situation, such as correlating the actual depth of the tool string (CCL), identifying non-reported hardware (CCL), identifying leaks (borehole temperature), identifying down hole pressure and fluid levels (pressure). In the case of “normal” operations, the data may indicate problems, which were previously, undiagnosed, such as tubing, packer, or wellhead leaks, behind casing channels, or paraffin problems caused by low temperature. Gas lift design can be updated based on pressure and temperatures recorded at each mandrel. Old completions can be confirmed when well file information is ambiguous. As a diagnostic tool the SCH is an excellent locator of leaks due to the fast sample Frequency (10 samples per second) and high resolution of the CCL and temperature Sensors. Features: • Platinum RTD borehole temperature sensor provides fast response, • High resolution temperature sensing at 10 samples per second • CCL sensor senses changes in metal mass at 10 samples per second • High resolution Piezo-Resistive pressure transducer provides 0.0003% FS resolution and 0.05% FS accuracy • Standard API log format • Compact 1-1/2” diameter x 12” length • Integrated depth encoder system Applications: • Gas lift diagnosis and optimization • Tubing casing communication diagnosis (leak detection) • Depth correlation Pressure transient data acquisition (buildup, drawdown, multipoint)

196

CCL

Borehole Temperature Pressure

Multiple Gas Leaks At GL Mandrel and Nipple

7.2

SIDE POCKET MANDRELS AND KICKOVER TOOLS

The most outstanding development in gas-lift equipment can about in the 1950’s when the Camco Company was formed. The idea of building a mandrel for a gas-lift valve to put inside a tubing string was developed. The mandrel would allow full bore wireline work to take place without restricting the tubing string. It would also allow the operator of the wireline unit to pull and replace any bad valves without pulling the tubing out the well. Exhibit 7.2a Shows a picture of Camco’s Basic Design Side Pocket Mandrels.

Exhibit 7.2a Basic Design Side Pocket mandrels

197

A special wireline tool was also developed to attach to the wireline tool string. It was call a kickover tool. It would allow the wireline operator to be able to latch the pulling tool over the fishing neck of the valve for removal. It was also used for installing the valves. There were several types made. Exhibit 7.2b Shows the first type of Kick-Over Tools

Exhibit 7-2b R Kick-Over Tool K-Kick-over Tool

198

The drilling of directional wells made the development of newer side pocket mandrels and kick-over tools necessary for the continuing success in gas-lift. The Camco developed a side pocket orienting mandrel. This was necessary because the deviation of the directional wells increased. Exhibit 7.2c shows and breakdown of the parts of an Orienting mandrel.

Exhibit 7.2c Camco KBMG Side Pocket Mandrel

199

With the development of the orienting type side pocket came the development of the orienting kick-over tool. The same procedure of going below the mandrel and picking up slowly to located the mandrel and position the kick-over tool is followed as in the old kick-over tool. However, is the case of the orienting kick-over tool, the orienting sleeve build in the top of the mandrel will catch, orient and kick the knuckle bar in position with the pocket to install or remove the valve or dummy. Exhibit 7.2d displaces the orienting kick-over tool at left and the procedure for installing a valve at right.

Exhibit 7.2d Orienting Sequence for Valve Installation

200

Daniels

K.O. Tool

Exhibit 7.2e Gas Lift Equipment Chart

201

SECTION 8 CHARTS CONTENTS Exhibit

Page

8.2

Hydrostatic Pressure of Well Fluids at Various Depths

203

8.3

Capacity of Tubing and Casing

204

8.4

Annular Capacities for Well With One String of Tubing

205

8.5

Liquid Gravity, Weight and Gradient Conversion table

206

8.6

Gas Pressure Factors For Various Gas Specific Gravities

208

8.7

Stem Chart

209

8.8

Otis Pulling Tools

210

8.9

Camco Pulling Tools

212

8.10

Wireline String Dimensions Vrs. Tubing Sizes

213

8.11

Pulling and Running Prong Chart

214

8.12

Equalizing Prongs

215

8.13

API Spec For Tubing and Couplings

216

8.14

Tubing Joint Identification

217

8.15

Tubing Make Up Torque Guide

220

8.16

Special Tubing Joints

222

8.17

Removable Locking Devices (Mandrel Assemblies)

224

8.18

Fraction Top Decimal Conversion Charts

225

8.19

Otis “S” and “T” Mandrels and Nipple Chart

227

8.20

Otis “R” and RN” Mandrels and Nipple Chart

229

8.21

Baker Types “F” and “J” No-Go Nipples Charts

230

202

Exhibit 8.1 Hydrostatic Pressure of Well Fluids at Various Depths 203

Exhibit 8.2 204

Capacity of Tubing and Casing

205

Exhibit 8-3 Annular Capacities for Wells With One Tubing String

Exhibit 8.4 206

Liquid Gravity, Weight and Gradient Conversion Table

Exhibit 8.4 207

Liquid Gravity, Weight and Gradient Conversion Table

Exhibit 8.5 Gas Pressure Factors For Various Gas Specific Gravities 208

Exhibit 8.6 Stem Chart 209

Exhibit 8.7 Otis Pulling Tools 210

Exhibit 8.7 Otis Pulling Tool Pg. 2

211

Exhibit 8.8 Camco Pulling Tools 212

Exhibit 8.9 Wireline String Dimensions Vs. Tubing Sizes 213

Exhibit 8.10 Pulling And Running Prong Chart Pg. 1 214

Exhibit 8.11 Equalizing Prongs Pg. 2 215

Exhibit 8.12 API Specs for Tubing Couplings 216

Exhibit 8.13 Tubing Joint Identification, Pg. 1 217

Exhibit 8.13 Tubing Joint Identification Pg. 2 218

Exhibit 8.13 Tubing Joint Identification, Pg. 3

219

Exhibit 8.14 Tubing Make-Up Torque Guide, Pg.1

220

Exhibit 8.14 Tubing Make-Up Torque Guide, Pg. 2

221

Exhibit 8.15 Special Tubing Joints, Pg 1 222

Exhibit 8.15 Special Tubing Joints, Pg. 2 223

Exhibit 8.16 Removable Locking Devices “Mandrel Assemblies” 224

Exhibit 8.17 Fraction To Decimal Conversion Chart Pg. 1 225

Exhibit 8.17 Fraction To Decimal Conversion Chart Pg. 2

226

Exhibit 8.18 Guide To Otis Landing Nipples Pg.1

227

Exhibit 8.18 Guide To Otis Landing Nipples Pg. 2

228

Exhibit 8.19 Baker Types “F” And “J” Top No-Go Nipples 229

230

SECTION 9 EQUALIZING SUBS AND PLUGS CONTENTS

Topic

Page

9.1

APPLICATIONS AND PURPOSES IF EQUALIZING SUBS

233

9.2

TYPE ”B” EQUALIZING SUB

235

9.3

TYPE “D” EQUALIING SUB AND PLUG ASSEMBLY

236

9.4

TYPE ”F” EQUALIZING SUB

237

9.5

TYPE ”H” EQUALIZING SUB

238

9.6

KOBE KNOCK OUT EQUALIZING SUB

239

9.7

TYPE ”S” EQUALIZING SUB

240

9.8

TYPE ”XO” EQUALIZING SUB

241

9.9

TYPE ”X” EQUALIZING SUB

243

9.10

TYPE ”X” EQUALIZING SUB (FOR P PRONG)

244

9.11

TYPE ”X” EQUALIZING SUB OR SUB

245

9.12

TYPES OF PLUGS

247

9.13

TYPE “C” PLUG ASSEMBLY

249

9.14

TYPE “D” PLUG ASSEMBLY

150

9.15

TYPE “E” CIRCULATING PLUG

251

9.16

TYPE “N” TEST TOOL

252

9.17

TYPE “S” TEST TOOL

253

9.18

TYPE ”W” CIRCULATING PLUG

254

9.19

TYPE “T” TEST TOOL

255

9.20

D & D HOLE FINDER

256

9.21

TYPE “S” EQUALIZING VALVE

257

9.22

TYPE “F” EQUALIZING PRONG & VALVE

258

9.23

TYPE “XX” & “RR” PLUG

259

9.24

TYPE “PX” & “PR” PLUG

160 231

SECTION 9 EQUALIZING SUBS AND PLUGS ILLUSTRATIONS

Exhibit

Page

9.1

Type “X” & “S” Equalizing Thread Connections

234

9.2

Type “B” Equalizing Sub

235

9.3

Type “D” Equalizing Plug Assembly

236

9.4

Type “F” Equalizing Sub

237

9.5

Type “H” Equalizing Sub

238

9.6

Kobe Knock Out Equalizing Sub

239

9.7

Type “S” Equalizing Sub

240

9.8

Type “XO” Equalizing Sub

242

9.9

Type “X” Equalizing Sub For Zone Separation

243

9.10

Type “X” Equalizing Sub For P Prong

244

9.11

Type “X” Equalizing Sub

245

9.12

Applications For Tubing Plugs & Type Recommended

248

9.13

Type “C” Plug Beam Assembly

249

9.14

Type “D” Plug Beam Assembly

250

9.15

Type “E” Circulating Plug

251

9.16

Type “N” Test Tool

252

9.17

Type “S” Test Tool

253

9.18

Type ”W” Circulating Plug

254

9.19

Type “T” Test Tool

255

9.20

D & D Hole Finder

256

9.21

Type “S” Equalizing Valve Assembly

257

9.22

Type “P” Equalizing Prong & Valve

258

9.23

Type “XX” or “RR” Plug Choke

259

9.24

Type “PX” or “PR” Plug Choke

260

232

SECTION 9 EQUALIZING SUBS AND PLUGS 9.1

APPLICATIONS AND PURPOSES OF EQUALIZING SUBS An equalizing sub is placed in a flow control below the packing section. It is run in a safety valve assembly, a separation tool, a side door choke or a plug. Its primary purpose is to have a means of equalizing the pressure differential across the sub by opening a port. This may be done mechanically with a wireline unit or with an outside source of pressure (pump or another well). The method applied depends on the type of equalizing sub or control assembly that is closed. An example of what would occur if the well were shut in due to excessive well flow is: 1.

The well in most cases would have bleed down to separator pressure.

2.

A wireline unit is called out.

3.

The wireline operator should first find out which type of equipment and kind of equalizing sub that is closed. This could be found on a previous wireline report, as it is the responsibility of the operator who set the equipment to write this information down on a field ticket.

4.

By reading the previous operators report, the type of pulling tool and prong that is needed to perform the job is used.

5.

After eliminating the pressure differential, the pulling procedure is routine.

There are two types of thread connections used in conjunction with wireline flow controls. Exhibit 9.1 shows the physical difference in the two. When using the different types of equalizing subs and plugs, it may be necessary to use a crossover to switch threads. Each type of sub comes in different sizes and the I.D. id important.

233

NOTE Whenever an equalizing sub is used, the mandrel bore must be larger than the equalizing sub bore. It would be impossible to reach the sub through the mandrel bore with a prong if the bore is too small. When assembling the unit to set in the well, the operator should always ensure that the device could be equalized. The fowling information should be recorded on wireline reports and field reports when completing the job.

TUBING SIZE – TYPE MANDREL – TYPE SUB - SUB PART NUMBER – FOW CONTROL.

Exhibit 9.1 Type “X” & “S” Equalizing Thread Connections

234

9.2

TYPE “B” EQUALIZING SUB The type B equalizing sub (Exhibit 9.2) was one of the first subs developed. It was designed to run with the first tubing set mandrels such as the “B” mandrel. It has the equivalent I.D. 9.2.1

Installation The sub is run between the locking mandrel and the flow control device and is designated on paper according to the type flow control and then the type locking and sealing device and the equalizing device is named: A “Otis “F” safety valve being the flow control with a “B” locking device with sealing cups (the mandrel) and a “B” equalizing sub (equalizing device) designated: Otis type (FBSV w/ B Sub)

9.2.2

Operating The running or pulling tool prong is ran with the prong screwed into the running tool and extends through the “B” mandrel into the bore of the “B” equalizing sub pushing a button built in the body of the sub outward opening a 1/16 inch port allowing well fluid to flow. Upon removal of the prong, the sub closes.

9.2.3

Purpose Allows well equalization across closed flow control devices.

Exhibit 9.2 Type “B” Equalizing Sub

235

9.3

TYPE “D” EQUALIZING SUB OR PLUG ASSEMBLY The type “D” equalizing sub (Exhibit 9.3) is equivalent to the “B” sub in I.D. Its designation always starts with “D” because it is basically a plug assembly. The type lock is designated last: 9.3.1

Installation The sub is run below the locking and seal device such as: 1. W mandrel – D plug (Type DW Plug) 2. X mandrel – D plug (Type DX Plug)

9.3.2

Operating The running or pulling tool prong is ran with the prong screwed into the running tool and extends through the mandrel into the bore of the “D” equalizing sub pushing a button built in the body of the sub outward opening a 1/16 inch port allowing well fluid to flow. Upon removal of the prong, the sub closes.

9.3.3

Purpose Allows well equalization across closed flow control device.

Exhibit 9.3 Type “D” equalizing Plug Assembly 236

9.4

TYPE “F” EQUALIZING SUB The type “F” equalizing sub (Exhibit 9.4) is equivalent to the “B” equalizing sub on construction; however, instead of one equalizing button, this sub has three buttons. 9.4.1

Installation The sub is run between the locking mandrel and the flow control device and is designated on paper according to the type flow control and then the type locking and sealing device and the equalizing device is named:

3. 4. 9.4.2

B mandrel-F Safety Valve – Designation (FBSU W/F sub) X mandrel-F Sub-H Safety Valve – Designation (HXSV W/F Sub) Operating The running or pulling tool prong is ran with the prong screwed into the running tool and extends through the “B” mandrel into the bore of the “F” equalizing sub pushing a button built in the body of the sub outward opening a 1/16 inch port allowing well fluid to flow. Upon removal of the prong, the sub closes.

9.4.3

Purpose Allows well equalization across closed flow control devices.

Exhibit 9.4 Type “F” Equalizing Sub

237

9.5

TYPE “H” EQUALIZING SUB The type “H” equalizing sub (Exhibit 9.5) is equivalent to the “B” and “F” equalizing subs on construction; however, instead it has a larger I.D. was build to accommodate the “S” mandrel which also has a larger I.D. allowing more flow area through the lock. 9.5.1

Installation The sub is run between the locking mandrel and the flow control device and is designated on paper according to the type flow control and then the type locking and sealing device and the equalizing device is named: 5. 6.

9.5.2

S mandrel-H Sub-H Safety Valve – Designation (HSSV W/H Sub) X mandrel-H Sub-H Safety Valve – Designation (HXSV W/H Sub)

Operating The running or pulling tool prong is ran with the prong screwed into the running tool and extends through the “S” mandrel into the bore of the “H” equalizing sub pushing a button built in the body of the sub outward opening a 1/16 inch port allowing the well fluid to equalize. Upon removal of the prong, the sub closes.

9.5.3

Purpose Allows well equalization across closed flow control devices.

Exhibit 9.5 Type “H” Equalizing Sub 238

9.6

KOBE KNOCK-OUT EQUALIZING SUB The Kobe knock out equalizing sub (Exhibit 9.6) was developed for fast equalizing. Due to the large flow area created when the knock out plug is broken. It is not designed for high differentials from below. It was designed to relieve heavy loads from above such as in dumping overbalanced fluids off a stand in valve. 9.2.4

Installation The sub may be run between the locking mandrel and the check valve assembly. Type “S” Stand In Valve W/Knock out Equalizing Sub.

9.2.5

Operating A pulling tool prong is ran with the prong screwed into the pulling tool and extends through the “S” mandrel onto the top of the knock our plug. Downward jarring shatters the plug allowing the prong to go down far enough for the pulling tool to latch the plug. After equalizing takes place, the stand in valve is removed.

9.2.6

Purpose Allows well equalization across closed flow control devices.

Exhibit 9.6 Knock Out Equalizing Sub 239

9.7

TYPE “S” EQUALIZING SUB The type S equalizing sub (Exhibit 9.7) was originally designed for a type S side door choke assembly. When open, there is a large flow area (four .125 equalizing port holes. 9.7.1

Installation The sub is run in a type S side door choke assembly or as a standard equalizing sub in a plug assembly, such as: 1. 2.

9.7.2

S Mandrel – S Sub – S Packing Mandrel – Designation (S Side Choke W/ S Sub) S Mandrel – S Sub – C Plug Assembly – Designation (CS Plug W/S Sub)

Operating The O-ring donut assembly in the valve housing is pinned in place as pictured in the exhibit. The assembly is lowered into the well into the side door landing nipple. When equalizing the “S” sub, a pulling tool with the proper prong screwed in the bottom of the pulling tool lowered and placed inside to mandrel on top of the donut. Downward jarring shears the pinned donut and moves the donut downward allowing the well fluids to enter and equalize.

9.7.3

Purpose Allows well equalization across closed flow control devices.

Exhibit 9.7 Type “S” Equalizing Sub

240

9.8

TYPE “XO” EQUALIZING SUB The type XO equalizing sub (Exhibit 9.8) was designed after the X and is often referred to as the type X. The only difference is the outer body. The upper portion has a larger O.D. designed as a no-go. Changing the locking dogs on the X mandrel and adding this sub converts it to a “XN”. This sub may be used on selective or non-selective mandrels making it universal. It employers an O-ring seal on a ring and a collet built in one piece that sets in the inner profile on the sub body. 9.8.1

Installation The sub is run between the locking mandrel and the flow control device and is designated on paper according to the type flow control and then the type locking and sealing device and the equalizing device is named:

1. 2. 9.8.2

X Mandrel – XO Sub – Packing Sub Assembly Designation (S Side-door Choke) X Mandel – XO Sub – H Safety Valve Designation – (HXSV W/X Sub) Operating The running tool prong is ran with the prong screwed into the running tool and extends through the “XO” mandrel into the O-ring collet which when assembling is pushed down into the lower portion of the sub opening a fluid bypass. In the procedure of setting the assembly in the desired nipple, the O-ring collet is (Exhibit 9.8) is pulled up positioning the O-ring collet across the portholes. When pulling the pulling tool prong is screwed on the bottom of the pulling tool and the prong runs through the X mandrel and the prong sets on the O-ring collet. Downward jarring pushes the O-ring collet down opening the equalizing ports of the sub.

9.8.3

Purpose Allows well equalization across closed flow control devices.

241

Exhibit 9.8 Type “XO” equalizing Sub

242

9.9

TYPE “X” EQUALIZING SUB The type X equalizing sub (Exhibit 9.9) was designed for zone separation. It is used in between the X mandrel and a packing assembly. The upper zone is flowed through the sub and the lower zone is blanked off with the o-ring collet in place. It is identical in appearance to the X sub. The variable office that is screwed into the bottom of the sub allows slow equalization. 9.9.1

Installation The sub is run between the locking mandrel and the packing assembly. X Mandrel – X Separation Sub – Packing Sub Assembly Designation (S Separation Tool Assembly)

9.9.2

Operating The running tool prong is ran with the prong screwed into the running tool and extends through the “XO” mandrel into the o-ring collet which when assembling is pushed down into the lower portion of the sub opening a fluid bypass. In the procedure of setting the assembly in the desired nipple, the o-ring collet is (Exhibit 9.8) is pulled up positioning the o-ring collet across the portholes. When pulling the pulling tool prong is screwed on the bottom of the pulling tool and the prong runs through the X mandrel and the prong sets on the O-ring collet. Downward jarring pushes the oring collet down opening the equalizing ports of the sub.

9.9.3

Purpose Allows well equalization across closed flow control devices.

Exhibit 9.9 Type “X” Equalizing Sub For Zone Separation 243

9.10

TYPE “X” EQUALIZING SUB FOR TYPE P PRONG) The type X equalizing sub (Exhibit 9.10) also referred to as the X equalizing sub) is unlike the X or the SXO sub. The difference is in the O.D. This sub is built to accept a long prong that plugs the holes of the sub after being placed in the well. This sub could be mistaken for an XO sub because it is identical on the outside appearance. Examine the inside of the sub to determine the difference. 9.10.1 Installation The sub is run below the X locking mandrel. X Mandrel – X Sub For P Prong - Designation (PX Plug) 9.10.2 Operating The assembly is run and installed in the desired nipple. Refer to Section 5 page 5-11 for installation of on X mandrels. The prong shown in (Exhibit 9.10) is run and set inside the sub blanking off the hole in the sub. When attempting to remove the assembly, the prong is pulled first opening the holes in the sub allowing the well to equalize. Then the X mandrel and sub assembly is pulled. 9.10.3 Purpose Allows well equalization across closed flow control devices.

Exhibit 9.10 Type “X” Equalizing Sub For P Prong 244

9.11

TYPE “X” EQUALIZING SUB The type X equalizing sub (Exhibit 9.11) was designed after the X mandrel only. This is the original design for the X sub. The XO sub replaced this sub because it is designed for dual purpose (X & XN no-go). It may be used where it is not necessary to land in a no-go nipple. It is designed for X selective mandrels only. It may be wise to note the number of holes in the sub. Some have two holes and some have four. The one to use depends on the gas passage when equalizing. 9.11.1 Installation The sub is run between the locking mandrel and the flow control device and is designated on paper according to the type flow control and then the type locking and sealing device and the equalizing device is named: 1. 2.

X Mandrel – X Sub Designation – (XX Plug) X Mandel – X Sub – J Safety Valve Designation – (JXSV)

9.11.2 Operating The running tool prong is ran with the prong screwed into the running tool and extends through the “X” mandrel into the O-ring collet which when assembling is pushed down into the lower portion of the sub opening a fluid bypass. In the procedure of setting the assembly in the desired nipple, the O-ring collet is (Exhibit 9.11 is pulled up positioning the O-ring collet across the portholes. When pulling the pulling tool prong is screwed on the bottom of the pulling tool and the prong runs through the X mandrel and the prong sets on the O-ring collet. Downward jarring pushes the O-ring collet down opening the equalizing ports of the sub. 9.11.3 Purpose Allows well equalization across closed flow control devices.

Exhibit 9.11 Type “X” Equalizing sub (Original)

245

246

9.12

TYPES OF PLUGS There are three types of plugs 1.

Plug from below.

2.

Plug form above

3.

Plug from both directions

9.12.1 Plug From Below The plug from below is attached directly to an equalizing sub, which is attached to a locking device. It consists of a spring loaded plug beam assembly, which sits on a ground seat provided in the equalizing sub. A variation of this type seat includes a rubber seal in addition to a metal seal. This type of plugging device is designed so that can be pumped through from above. It is important that fluid bypass be provided when installing this type of plug in fluid, running through a series of landing nipples, or setting in a landing nipple. Fluid bypass eliminates the possibility of a fluid lock and is provided by the use of a running prong. 9.12.2 Plug From Above The plug from above holds pressure only from above and permits flow through it. Its construction has several variations: a ball and seat, valve and seat or rubber-type check valve. 9.12.3 Plug From Both Directions The plug from both directions seals in both directions and is used mostly in separating zones in selective completions. It provides a fluid bypass for running and utilizes a retrieving prong-type equalizing feature. Another type consists of a spring loaded double ball check with a knock out or sliding sleeve type of equalizing feature. Exhibit 9.12 list some applications for the types of plugs

247

Plug From Above

Plug From Below

Plug From Both Directions

1.

Repair Surface Equipment

X

X

2.

Test Tubing By Bleeding Down

X

X

3.

Test Tubing By Pressuring Up

4.

Snubbing Tubing In And Out Well

5.

Set Hydraulic Packer

X

6.

Circulate Above With Fluids

X

7.

Zone Separation In Selective Completions

X X

X X

8.

Fracturing Selective Completions

X

X

9.

Kill Well

X

10.

Move Rig On And Off Location

X

11.

Use As Standing Valve

12.

Package Leakage Test

13.

Acidizing on selective Completions

14.

Wellhead Plugging On Completions

X

X

15.

Wellhead Plugging On Remedial Work

X

X

X

X X X

X

Exhibit 9.12 Applications for Tubing Plugs and Type Recommended

248

9.13

PLUGS FROM BELOW (Type “C” Plug Beam Assembly) The type “C” plug (Exhibit 9.13) is the first plug built to plug from below. It is designed to hold pressure from the bottom only and employs a metal-to-metal seat. 9.13.1 Installation This plug is run below any locking and seal device as follows: 1. 2.

S Mandrel – Designation (CS Plug Assembly) X Mandrel – Designation (CX Plug Assembly)

9.13.2 Running The plug is kept off seat when running it in the well bore with a special length prong. At the setting depth, the plug is set and the prong and running tool retrieved. 9.13.3 Retrieving When retrieving the plug, a prong on a pulling tool is run. The prong enters the mandrel bore and sets on top of the spring loaded equalizing pin. By repeatedly tapping down, the plug is equalized. The type-pulling tool used depends on the type mandrel used above the plug.

Exhibit 9.13 Type “C” Plug Beam Assembly

249

9.14

PLUGS FROM BELOW (Type “D” Plug Beam Assembly) The type “D” plug (Exhibit 9.14) was designed as an improvement over the “C” plug assembly. This is a widely accepted plug for plugging pressure from below it employs a Hycar type seal plus a metal-to-metal seat. 9.14.1 Installation This plug is run below any locking and sealing device as follows: 3. 4.

B Mandrel – Designation (DB Plug Assembly) S Mandrel – Designation (DS Plug Assembly)

9.14.2 Running The running tool depends on the type mandrel or lock needed for the job. The plug is kept off seat when running in the well bore with a special length prong that allows fluid bypass. At the setting depth, the plug is set and the prong and running tool retrieved. 9.14.3 Retrieving When retrieving the plug, a prong on a pulling tool is run. The prong enters the mandrel bore and pushes a button built into the body of the plug which opens a 1/16 inch hole and allows the plug to equalize with the well pressure. The method of retrieval depends on the mandrel or lock needed to perform the job.

Exhibit 9.14 Type “D” Plug Beam Assembly

250

9.15

PLUGS FROM ABOVE (Type “E” Circulating plug) The type “E” circulating plug (Exhibit 9.15) was designed to be set in the tubing on top of a tubing or collar stop. The sealing cup must be expanded while setting the plug to prefect a seal against the tubing wall. NOTE This plug is limited to the pressure differential that may be taken across it because of the sealing cups. 9.15.1 Running The outer sleeve of the plug is pinned allowing fluid bypass when running the plug down the well bore. A type “H” running tool may be used to run the plug. When arrive at the preset stop, downward jarring shears the pin, closing the bypass ports, and forces the seal cup outward against the tubing wall. The pin in the running is also sheared releasing the running from the plug. 9.15.2 Retrieving A type “RS” or a type ”JUS” pulling is used for retrieving to plug. The fishing neck build with the outer sleeve is latched and upward jarring moves the sleeve upward opening the equalizing ports. After equalizing, the plug is pulled out the well.

NOTE It may be necessary to wait a while for the fluid to equalize before pulling the plug. This depends on the load above the plug.

Exhibit 9.15 Type “E” Circulating Plug

251

9.16

PLUGS FROM ABOVE (Type “N” Test Tool) The type “N” test tool (Exhibit 9.16) is used in a no-go nipple which is normally run with the tubing and place at the bottom of the tubing string due to the restricted I.D. The locking and sealing elements are the same as an “S” mandrel. In place of the locator mandrel a no-go sub is used.

NOTE There is a removable restricted port inside the plug assembly. This port must remain in the plug if a high differential of pressure is expected. The dart must be raised to equalize the plug. If the differential is too great, this becomes impossible. 9.2.7

Running A type “H” running tool may be used to run the plug. The tool allows the dart to ride up and off seat, which is necessary for fluid bypass. When arriving at the nipple, the pin in the running tool is sheared releasing the running tool from the plug.

9.2.8

Retrieving A type “RB” or a type ”JUC” pulling is used for retrieving to plug. The fishing neck is latched and upward jarring holds the dart off seat allowing the fluid to drop by until it is equalized.

NOTE WGWS will only run the new style test tool with the release sub. It may be necessary to wait a while for the fluid to equalize before pulling the plug. This depends on the load above the plug.

Exhibit 9.16 Type “N” Test Tool 252

9.17

PLUGS FROM ABOVE (Type “S” Test Tool) The type “S” test tool (Exhibit 9.17) is used in a type “S” landing nipple. The locking and sealing elements are the same as an “N” mandrel. In place of the nogo sub is the locator mandrel. Depending on the position of the nipple the work is planned for, the keys on the locator mandrel are changed to match the nipple profile. . NOTE The design if the nipple and the type packing allow maximum pressure differentials compatible to the pressure rating of the tubing. 9.2.9

Running A type “H” running tool A may be used to run the plug. The tool allows the dart to ride up and off seat, which is necessary for fluid bypass. When arriving at the nipple, the pin in the running tool is sheared releasing the running tool from the plug.

9.2.10 Retrieving A type “RB” or a type ”JUC” pulling is used for retrieving to plug. The fishing neck is latched and upward jarring holds the dart off seat allowing the fluid to drop by until it is equalized.

NOTE WGWS will only run new style “S” test tool with the release sub. It may be necessary to wait a while for the fluid to equalize before pulling the plug. This depends on the load above the plug.

Exhibit 9.17 Type “S” Test Tool 253

9.18

PLUGS FROM ABOVE (Type “W” Circulating Plug) The type “W” circulating plug (Exhibit 9.18) was designed as an improvement of the “E” Circulating plug. The advantages are that it sets and seals immediately. However, the “W” element is limited to the amount of pressure differential it may whole. 9.18.1 Running A type “H” running tool may be used to run the plug. The tool allows the dart to ride up and off seat, which is necessary for fluid bypass. When arriving at the stop, downward jarring shears a pin in the mandrel body and forces the inner mandrel to move downward which seals the type “W” element to the tubing wall. Continued downward jarring shears the pin in the running tool releasing the plug. 9.18.2 Retrieving A type “RB” or a type ”JUC” pulling is used for retrieving to plug. The fishing neck is latched and upward jarring holds the dart off seat allowing the fluid to drop by until it is equalized.

NOTE It may be necessary to wait a while for the fluid to equalize before pulling the plug. This depends on the load above the plug.

Exhibit 9.18 Type “W” Circulating Plug

254

9.19

PLUGS FROM ABOVE (Type “T” Test Tool) The type “T” test tool (Exhibit 9.19) is the latest type test tool to be developed. It is a simple ball check valve arrangement with a V-packing sub. The outside top of the body with the inside fishing neck slide up and down approximately one inch and when in a up position opens large equalizing ports. By attaching a Type “S” locator mandrel on the bottom, it becomes a “ST” test tool. By attaching a no-go sub on the bottom, it becomes a “NT” or a “XNT” test tool. By attaching an “X” selective mandrel below it, it may be used in any “X” nipple at any depth. Another advantage is that any pressure differential may be on top of the plug Opening the tool to drop the fluid is no problem. 9.19.1 Running A type “GS” pulling/ running tool may be used to run the plug. When running in the well, the ball rides up and off seat. The plug may be set in any type nipple depending on the arrangement screwed on the bottom of the “T” test tool. In the case of setting in an “X” nipple it may be necessary to go below the nipple and pull up to set the X Dogs in a positive position and then downward jarring release the running tool. In most other cases, downward jarring after arriving at the desired nipple releases the “GS” tool. 9.19.2 Retrieving A type “GS” pulling tool is used for retrieving to plug. The plug is latched and by jarring upward, the pin in the upper sleeve is sheared moving the sleeve upward equalizing the fluid differential from above.

NOTE It may be necessary to wait a while for the fluid to equalize before pulling the plug. This depends on the load above the plug.

Exhibit 9.19 Type “T” Test Tool

255

9.20

PLUGS FROM ABOVE (D & D Hole Finder) The D & D Hole Finder (Exhibit 9.20 & Exhibit 11.11) is test tool designed to locate holes in the tubing. The test tool or the top portion of the hole (with out the D & D AD-2 Stop is similar to circulating plug. However, this tool used with a D & D AD-2 stop and together is designed to locate a hole in the tubing. If used as a circulating plug, the stop should be run separately to prevent entrapment 9.20.1 Running The hole-finder with the AD-2 stop attached is pinned in a run position with an aluminum pin. Using a “RB” or “JDC” pulling tool, the hole-Finder is run to a depth calculated to be below the leak in the tubing. Snapping the jars in the tool string shears the aluminum pin and activates the stop. Once the stop is activated, the hole finder can only be moved up the hole. 9.20.2 Finding the hole By lowering the weight of the tool string on top of the hole finder the rubber element is expanded and ready to hold pressure. If the pressure dose not hole firm, it can be determined that the leak is above the present depth. The hole finder can be moved up to the next test depth. This cycle is repeated until a depth is reached were the pressure dose hold firm. 9.20.3 Pinpointing the hole The hole finder may be retrieved, redressed and rerun with the same procedure as above to get a closer fix on the leak. NOTE Once pressure is created above the hole-finder it is necessary to equalize it be jarring upward and holding a bind on the line. Ensure against over pressuring the hole-finder.

Exhibit 9.20 D & D Hole Finder

256

9.21

PLUG FROM BOTH DIRECTIONS (Type “S” Equalizing Valve) The type “S” equalizing valve (Exhibit 9.21) is used to control pressure (upward and downward flow). Due to its design, it will not work in a sand condition. It is run with a special running tool prong and a special pulling tool prong 9.21.1 Running The equalizing valve may be screwed below “S” mandrel (SS Plug) or an “N” mandrel (SN Plug) as noted in (Exhibit 9.21), there is two balls on a upper and lower seat with spring holding them on seat. A prong is used below the “T” running tool that keeps the upper ball off seat allowing fluid bypass. After setting procedure is done, the prong is removed moving the upper ball on seat. 9.21.2 Retrieving To pull the equalizing valve, a “RS” pulling tool is used with a special prong is used that lands on top of the assembly. Downward jarring shears the pinned assembly driving the valve housing below the equalizing ports. After equalizing, the plug is latched and removed from the well

Type “S” Equalizing Valve

SS Plug Assembly

SN Plug Assembly

Exhibit 9.21

257

9.22

PLUG FROM BOTH DIRECTIONS (Type “P” Equalizing Prong and Valve) The type “P” equalizing valve (Exhibit 9.22) was designed as an improvement over the type “S” plug. The problems encountered with the “S” type plug were sand and trash filling the mandrel bore. This made it difficult to equalize. The “P” equalizing prong and valve is run together. The equalizing prong stays in place inside the locking mandrel. When equalizing, the prong is pulled, the plug is equalized and then the rest of the assembly is pulled. 9.22.1 Running A type “PS” or a type “P” running tool is used. The running tool is bored out to receive the p prong. It restricts to travel of the prong allowing it to ride off seat for fluid bypass. After setting the plug assembly, the running tool is pullout leaving the prong to ride free to close against an upward or downward differential. 9.22.2 Pulling To remove the plug requires two trips. An overshot is first run and the prong is pulled allowing equalization to take place. The “RS” or a “JUS” pulling tool is used to pull the rest of the plug assembly. Refer to section 6 page 6-17 for pulling procedure.

Type P Equalizing prong and Valve

Type “PS” Plug Choke

Type “PN” Plug Choke Exhibit 9.22 258

9.23

PLUG FROM BOTH DIRECTIONS (Type “XX” or “RR” Plug) The type “XX” or “RR” plug (Exhibit 9.23) consists of three parts; the “X” mandrel, the “X” equalizing sub assembly and the blank that screwed onto the bottom. The only difference in the ‘XX” plug and the “RR” plug is in the O.D. and the wall thickness of the equipment. The “X” Is for standard wall tubing and the “R” is for heavy wall tubing. The running and pulling procedures are the same 9.23.1 Running A type “X” running tool is used to run the plug. The running tool is pinned and preset depending on which nipple job is planned for. A running tool prong is used to keep the donut collet like device in a downward position allowing fluid bypass to go down the hole. The plug is run and set (see running procedure section 5 page 5-11). Upon shearing off the donut collet is pulled upward and seals off the equalizing ports 9.23.2 Pulling A type “GR” pulling tool with an equalizing prong is used to pull the “XX” or “RR” plug. The prong is run inside the “X” mandrel bore and sets on the donut collet. At this time, the pulling tool should be latched onto the mandrel. Downward jarring pushes the donut collet down and opens the equalizing ports. The plug should be completely equalized before any attempt is make to jar upward. After a period of time, the plug may be pulled.

Type “X” or “R” Equalizing Sub

9.24

Type “XX” or “RR” Plug Choke Exhibit 9.23 PLUG FROM BOTH DIRECTIONS (Type “PX” or PR” Plug Choke) 259

The type “PX” plug choke (Exhibit 9.24) is often used in place of the “XX” because of the problem of equalizing the “XX” plug. After a pro-long period with the “XX” plug in the well, any settlement of sand or trash will tend to fill the mandrel bore. This makes equalizing with a prong in side the mandrel difficult. The disadvantage is that it takes two trips the install and two trips to remove to plug. 9.24.1 Running A type “X” running tool is used to run the plug. The running tool is pinned and preset depending on which nipple job is planned for. The “X” mandrel with the equalizing valve housing and cap is run and set. The prong assembly is then run and set with the seals in place across the ports of the equalizing sub. 9.24.2 Pulling To remove the plug requires two trips. A pulling tool is first run and the prong is pulled allowing equalization to take place. The “GR” pulling tool is used to pull the rest of the plug assembly.

Type “PX” Equalizing Prong and Valve

Type “PX” or “PR” Plug Choke Exhibit 9.24

260

261

SECTION 10 SAFETY VALVES CONTENTS Topic

Page

7.2

HISTORICAL REASONS FOR SAFETY VALVE DESIGN

263

7.3

TYPES OF SUBSURFACE SAFETY VALVES

264

7.4

THE PRESSURE OPERATED SUBSURFACE SAFETY VALVE

268

7.5

THE DIFFERENTIAL TYPE SUBSURFACE SAFETY VALVE

269

ILLUSTRATIONS Exhibit

Page

10.2

Types of Safety Valves and Control Systems

266

10.2.1

Pressure Operated & Differential Type Safety Valves

267

10.3

PB Pressure Operated Valve

268

10.4

Type F Differential Valve

269

262

SECTION 10 SAFETY VALVES

10.1

HISTORICAL REASONS FOR SAFETY VALVE DESIGN Although the earliest safety valve was installed to protect the operator’s investment, subsequent developments in safety valve design have come in response to governmental regulations. In the late 1960’s, the United States Geological Survey (USGS) was formed and new guidelines set which prompted development of a new type of safety valve and revamping of surface equipment. The new recommended practices involve down-hole valves, which are controlled from the well surface. Early safety valves were subsurface controlled safety valves. As the laws of the state and federal regulations dictated the safety regulations through out the oil field development, safety valves were developed to meet these regulations. Development of the first safety valves coincided with the completion of the first self-flowing well. It became apparent that a safety device was needed to control well flow if the wellhead became to leak or the flow line ruptured. In the early days of wireline, the safety valve was referred to as a storm choke and the first wireline trucks were called choke trucks. A storm choke was installed only before a storm to protect the well. Another occasion was when a rig move on or off location. In the event something heavy would drop and hit the wellhead, the safety valve would shut in. In that time period, it was not illegal to flow a well without a safety valve. Production was always a big factor as the operators were only concerned with their investment. As the safety in the well bore restricted production, they were removed after the danger was over with. In the state of Louisiana, it became law effective March 16, 1946 that storm chokes were to be installed and kept in service in all offshore wells. However, installation involved down time and lost production. The original safety valves were developed with small flow areas. This in most cases was necessary for proper valve closure in case of mishap. The operators again preferred to leave then out of the wells. In those days, there was no accountability or record keeping as is today.

263

In the late 1960’s when drilling and production operations had reached a high point, several oil spills occurred from loss of well control. Some of the well that caught fire was without safety valves or had defective safety valves installed. It became apparent that something had to be done to protect life and the environment. The federal government became involved and after a short period, inspection teams were formed and safety measurements drawn up. The job of policing the offshore locations were given to United States Geological Survey teams (USGS) The guidelines they enforce consists of regulations and recommendations made up by the American Petroleum Institute (API) Spec 14A, RP 14B in manual 14B. This is coupled with OCS order No. 5. The only safety valves in use prior to these measures were subsurface controlled valves. This type of safety is controlled by well flow. The new recommended practices set forth by API and recognized by OCS Order No. 5 as law by the U.S. government is the installation of surface controlled subsurface safety valves. These valves are set at or below the mud line and controlled from the surface. All safety valves are periodically tested in place or pulled, test and reset. All valves must be capable of being tested in place under existing well flow. Present regulations are found in the Federal Register.

10.2

TYPES OF SUBSURFACE SAFETY VALVES Subsurface safety valves are classified according to the location from where they are controlled: surface controlled or subsurface controlled. All subsurface safety valves have one common purpose: to provide shut-in well protection in the event of an emergency. An emergency is defined as any damage to the surface system of a well, which renders it out of control. The two basic categories are further classified into various types of valves as shown in (Exhibit 10.2) named according to their operation and basic mechanics. A surface controlled valve is one that operates by some controlling signal that originates from the surface. A subsurface controlled valve is one that operates by some pressure change or pressure drop that is sensed from the at-depth environment. 264

10.2.1 Surface Controlled Subsurface Safety Valve (SCSSV) The surface controlled subsurface safety valve (SCSSV) is a device which shuts off well flow in response to a signal from a surface source. Three methods of control are possible: control line (most common), concentric control and casing control. The surface controlled subsurface safety valve (SCSSV) is best described as any device that shut off well flow and can be controlled from the surface either manually or automatically. The valves are either tubing retrievable or wireline retrievable. Either type is acceptable and each offers distinct advantages and disadvantages. The method of control may differ, but the end results are the same. A certain amount of pressure is applied as the control source to keep the valve open. When this pressure is lost, the valve will shut. A. Control Line Method The control line method is used more than any other. A ¼ inch stainless steel control line is attached to the safety valve (nipple or valve) and then to the outside of the tubing string and connected the wellhead. The control must be able to hold 600 pounds of pressure above the wellhead pressure. For all practical purposes, the line should be test to 5000 pounds. This is normally what it may take to keep the valve open. Most of the valves build today are hydraulically operated using a shoulder area to pump open the sleeve. This sleeve operates a ball or flapper, which acts as a sealing medium shutting off the well flow. The valves are run as part of the string (tubing retrievable) or as a nipple assembly in the tubing string (wireline retrievable). B. Other Methods Casing and tubing sizes often dictates which type of valve that is used. Besides the control line method, other types of control are the concentric and casing control. All these installations are discussed in more detail in API RP 14D, Recommended Practice for Design, Installation and Operation of subsurface Safety Valve Systems.

265

Exhibit 10.2 Types of Safety Valve and Control Systems 266

10.2.2 Subsurface Controlled Subsurface Safety Valve (SSCSV) The subsurface controlled subsurface safety valve (SSCSV) is a device that operates to a signal from the at-depth environment. Two types are in use: the pressure operated valve and the differential valve. A subsurface controlled subsurface safety valve (SSCSV) shuts off well by responding to a pressure drop that it senses with-in the at-depth environment. There are two alternative principles in this type of safety valve. However, each involves control by existing well flow. The pressure-operated valve employs a dome and a bellows. The differential valve is controlled with a flow bean and spring tension. Both valves are wireline retrievable . Exhibit 10.2.2 is illustrated drawing of both types of valves showing the basic operation

Exhibit 10.2.2 Pressure Operated (Left) and Differential Safety valves

267

10.3

SUBSURFACE CONTROLLED SUBSURFACE SAFETY VALVE (PRESSURE OPERATED) The pressure operated type of subsurface controlled subsurface safety valve (SSCSV) employers a dome and a bellows. The amount of pressure in the dome depends on the desired closing pressure. When the tubing pressure at the depth of the valve drops below the dome pressure of the valve, the valve closes. Due the large flow area, this valve can produce large volumes of fluid and gas and still maintain safe well control. If the valve should close and the operator wants to put it back in service, he may pressure up on the tubing and overcome the differential on the valve. The valve will reopen. 10.3.1 Installation The valve may be adapted to any mandrel or lock and ran to the desired well depth and place in the nipple or tubing depending on the type mandrel being used. There is no need to run a prong with the assembly, as the safety remains open during the running process. 10.3.2 Pulling Dome pressured SSCSV’s should not be equalized with an equalizing prong to avoid the valve opening and blowing the tools up the hole. If the valve shuts and needs to be equalized before pulling, the operator needs to know the wellhead shut in pressure in order to equalize the well and allow the valve to open. 10.3.3 Checking and Resetting the Valve Initially, the field engineer is responsible for setting up the valve with the proper dome setting. The valve must be sent in to be re-set by an approved vendor. Before setting or after pulling the valve, it may be checked for the proper setting and leakage. A test rack is used to do this.

Exhibit 10.3 Type PB Pressure Operated Valve

268

10.4

SUBSURFACE CONTROLLED SUBSURFACE SAFETY VALVE (DIFFERENTIAL TYPE) The differential type subsurface controlled subsurface safety valve (SSCSV) senses pressure drop across a flow beam.There are several variations of the differential type safety valves. Although they employ different seal devices, such as the flapper, ball or seat on seat, they are all controlled with a flow bean and spaced out spring tension. The valve is often referred to as a velocity valve and is a normally open valve. The flow of the well is directed though the bottom of the valve through a flow beam and up inside a beam extension. The flow beam is attached to the lower seat and governs the amount of fluid and gas that passes through it, acting much like a surface choke. The spring pushes down on the flow beam and lower seat holding the valve open. When the flow beam senses the pressure differential and compresses the preset spring tension, the valve closes. 10.4.1 Installation The valve may be adapted to any mandrel or lock and ran to the desired well depth and place in the nipple or tubing depending on the type mandrel being used. There is no need to run a prong with the assembly, as the safety remains open during the running process. 10.4.2 Pulling If the valve shuts and needs to be equalized, the operator needs to know what type mandrel or lock and what type equaling sub is in the assembly in order to equalize and pull the valve. He may also pressure up on top of the valve and overcome to pressure differential. Once the valve is open, it would not be necessary to use an equalizing prong if the valve should be pulled. 10.4.3 Checking and Resetting the Valve Initially, the field engineer is responsible for setting up the valve with the proper dome setting. He is to furnish to the vendor the proper data needed to calculate and set up the valve. This should be done in the vendors shop. If the valve is pulled out the well on location, it must be sent in to the vendor to repair and reset it before reinstalling in the well. .

Exhibit 10.4 Type F Differential Safety Valve 269

SECTION 11 D & D TOOLS CONTENTS Topic

Page

11.1

DDIC AD-2 TUBING PACK-OFF (HIGH FLOW)

271

11.7

DDIC AD-2 TUBING PACK-OFF (HEAVY WALL)

277

11.11

DDIC HOLE FINDER

282

11.13

DDIC PACK-OFF BRIDGE PLUG

287

ILLUSTRATIONS Exhibit

Page

11.1

DDIC Hi Flow Pack-Off

272

11.2

AD-2 Tubing Stops

274

11.3

AD-2 Tubing Pack-Off

275

11.4

AA Stop

276

11.5

GS-PT Pulling & Running Tool

277

11.6

DDIC AD-2 Pack-Off (H.W.)

278

11.7

DDIC AD-2 Stinger & Receptacle

280

11.8

D & D Hole Finder W/ AD-2 Tubing Stop

281

11.9

DDIC Hole Finder

282

11.10

Pack-Off Bridge Plug

283

270

SECTION 11 D & D TOOLS 11.1

AD-2 TUBING PACK-OFF

I – Purpose:

The D & D AD-2 Tubing Pack-Off was designed to isolate a leak in the Tubing and still allow the well to flow. It is designed to be set and pulled with wireline.

II – Alternatives Uses: 1.) 2.) 3.)

To suspend and pack-off “Gas Lift Mandrels” when the tubing has no other means of “Gas Lift”. To act as the sealing element of Tubing Plugs or Sub-Surface Safety Valves when a landing nipple is not available. As a seal above the screen in “Through Tubing Gravel Packs”.

III – Operation:

To Pack-Off a tubing leak, a complete Pack-Off Assembly must be utilized. These are anchored in position by the use of a Lower and Upper Tubing Stop. The Pack-Off Assemblies are joined together with Spacer Pipe, sealed with a Stinger on the lower side with the pipe screwed into the Upper Pack-Off Assembly.

IV – Running: 1.)

Assuming the tubing leak has been located; Run and Set Lower Tubing Stop below leak with enough distance allowed to set the Lower Pack-Off Assembly below the leak also. (at this point an equalizing Hose should be connected between the Tubing and Casing.) Using Pack-Off Running Tool, Go-In-Hole with the Lower Pack-Off Assembly set down on top of Tubing Stop, jarring sufficiently to set and release the Pack-Off Assy. Using the same Pack-Off Running Tool, Go-In-Hole with the Upper Pack-Off Assy. with spacer pipe and stinger screwed onto bottom. Set the Upper Assy. with pipe and stinger into top of Lower Pack-Off Assy. jarring sufficiently to set and release Pack-Off Assembly. Note: (No more than 10’ of pipe should be screwed onto the Upper Pack-Off Assembly – Due to the weight of the pipe. Should more than 10’ of pipe be needed, then the additional pipe should be run separately using Stingers and Receptacles. Pin Upper Tubing Stop to Running Tool and isolate in wireline lubricator. Pressure up lubricator before opening to well. (This is very important, so that the Pack-Off Assemblies don’t get moved with the pressure equalization.) Go-In-Hole with Tubing Stop. Set on top of Pack-Off and anchor by jarring down to set and release.

2.) 3.)

4.)

271

Note: The Upper and Lower Pack-Off Assemblies are Inter-changeable. These assemblies “SHOULD NEVER” be run upside down so that they can be run together. They have to be run independently of each other. 272

Exhibit

11-1

DDIC Hi-Flow Pack-off

V – Pulling:

1.) Equalize Tubing and Casing. 2.) Retrieve Upper Tubing Stop. 3.) Go-In-Hole with Pack-Off pulling tool. Latch Pack-Off Assembly, jar up to shear pins in Pack-Off, releasing rubber element and pulling free the stinger. P. O. O. H 4.) Go-In-Hole with Pack-Off pulling tool. Latch Pack-Off Assembly, jar up to shear pins in Pack-Off. P.O.O.H. 5.) Retrieve Lower Tubing Stop.

VI – Redress (Disassembly): CLEAN PACK-OFF COMPLETELY WITH SOLVENT 1.) Be sure that shear pins are completely sheared, noted by 1 ½” to 2” of low tube are exposed. If not completely sheared, place bottom half in a vise and put a pulling tool into the fishing neck and jar until sheared. 2.) Loosen the allen screw on the bottom half (2) rounds but not to exceed 2 ½ rounds. 3.) Unscrew the bottom half all the way until the top and bottom halves come apart. You may have to grasp the rubber do-nut to get a good grip on the flow tube. 4.) No disassembly of bottom half required unless set screw is backed out further than explained above. If so, refer to foot note. *** 5.) Remove rubber do-nut from flow tube. 6.) Unscrew expander mandrel from top half (fishing neck). 7.) Remove sheared aluminum pins from top half. 8.) Pull out flow tube. 9.) Remove O-rings from both ends of flow tube and from inside of expander mandrel. 10.) Clean all parts again thoroughly before reassembling. (Reassembly) 1.) 2.) 3.) 4.)

Put new O-rings on both ends of flow tube. Slide flow tube into the top half and push down hard to set the O-ring into place inside the top half. Look through the shear pin holes and see that the flow tube is completely seated before inserting shear pins. Put a new O-ring into the expander mandrel and put some quality thread dope on the treads. 273

5.) 6.) 7.)

Coat the exposed end of the flow tube with some clean light oil, and push the expander mandrel down over the flow tube and screw into place. Slide rubber do-nut down over flow tube. Take the bottom half and screw onto the flow tube until the rubber do-nut is snug with the taper on the expander mandrel. Exhibit 11.2 AD-2 TUBING STOPS 274

8.)

Look through the sight hole, by the set screw, and rotate the bottom half until the milled slot in the flow tube is seen and tighten the set screw down snug but not too tight into the slot. IT IS NOW READY TO RUN.

If the set screw is backed out too far the ratchet nut inside will turn. If this happens, break apart the bottom half and screw the ratchet nut in until it stops, then back off one to two rounds and line up the milled slot in the nut with the set screw and tighten set screw just enough to keep the ratchet nut from turning. When using the new AD-2 Pack-Off several items of : CAUTION SHOULD BE OBSERVED. 1.) When going down the tubing the Wireline Operator should enter the fluid at a slow rate of speed, so as not to set the Pack-Off accidentally. 2.) Only 5’ to 8’ of 1 ½” stem is needed to set Pack-Off. DO NOT JAR EXCESSIVELY. Jar only 3 to 5 times at the most. 3.) When setting the Pack-Off, use and equalizing hose between the tubing and casing to maintain equalization at all times. This is especially important with this Pack-Off due to its holding capabilities. After the top Pack-Off is set pressure up the lubricator before opening the Master Valve. If a differential between tubing and casing is established, before the top anchor stop is in place, the upper PackOff assembly will come up the hole.

PRESSURE RATING: 5,000 psi-wp, 10,000 psi-tp. This pressure rating is based on a correct match between rubber elements and well condition.

Exhibit 11. 3 DDIC HI FLOW PACK-OFF 275

Exhibit 11.4 AA STOP DDIC AD-2 PACK-OFF

276

(HEAVY WALL) PACK OFF INSTRUCTIONS

TO RUN1.) Using wireline, pin AD-2 Stop in run position. RIH w/ AD-2 Tubing Stop using GS P/T to just below desired depth, snapping jars to activate stop. (At this point stop will go no deeper) Pick up on stop until at desired depth, jar down to set stop and shear GS P/T – releasing stop pooh. 2.) Re-pin GS P/T & run ½ section DDIC P.O. w/ Kobe plug in hole. Enter tubing at reduced speed so as not to set accidentally, go down and set on top of AD-2. Jar down to set P.O. and shear GS P/T pooh. 3.) Re-pin GS P/T. Pin AA Tubing Stop in run position, RIH w/ AA Stop using GS P/T- Set down on top of P.O., jar down to set stop and shear GS P/T. pooh. TO PULL1.) Put as much back pressure on top of plug as possible, (fluid if possible), to help in equalizing plug. 2.) To equalize plug, the Kobe button must be broken with equalizing prong. RIH w/ prong on RIT and break Kobe button –allowing well to equalize. 3.) RIH w/ GS P/T and latch AA Tubing Stop- jar up to release–pooh 4.) RIH w/ GS P/T and latch P.O. assembly-jar up to shear and release P.O.-pooh 5.) RIH w/ GS P/T and latch AD-2 Stop-jar up to release stop-pooh.

PR-GS TOOL

Exhibit 11.5

277

Exhibit

11.6

DDIC AD-2 PACK-OFF (H.W.)

278

REDRESSING OF D & D AD-2 PACK-0FF Upper and Lower Pack-Offs are Identical, explanation below refers to one pack-off. Disassembly:

CLEAN PACK-OFF COMPLETELY WITH SOLVENT

1.) Be sure that the shear pins are completely sheared, noted by 1 ½” to 2” of flow tube are

exposed, If not completely sheared, place bottom half in a vise and put a pulling tool into the fishing neck and jar until sheared. 2.) Loosen the allen screw on the bottom half (2) rounds but not to exceed (2 ½) rounds. 3.) Unscrew the bottom half all the way until the top and bottom halves come apart. You may have to grasp the rubber do-nut to get a good grip on the flow tube. 4.) No disassembly of bottom half required unless set screw is backed out further than explained above. If so, refer to foot note *. 5.) Remove rubber do-nut from flow tube. 6.) Unscrew expander mandrel from top half (fishing neck) 7.) Remove sheared Aluminum pins from top half. 8.) Pull out flow tube. 9.) Remove O-rings from both ends of flow tube and from inside of expander mandrel. 10.) Clean all parts again thoroughly before reassembling. Reassembly: 1.) Put new O-rings on both ends of flow tube. 2.) Slide flow tube into the top half and push down hard to set the O-ring into place inside the top half. 3.) Look through the shear pin holes and see that the flow tube is completely seated before inserting shear pins. 4.) Put a new O-ring into the expander mandrel and put some quality thread dope on the threads. 5.) Coat the exposed end of the flow tube with some clean light oil, and push the expander mandrel down over the flow tube and screw into place. 6.) Slide rubber do-nut down over flow tube. 7.) Take the bottom half and screw onto the flow tube until the rubber do-nut is snug with the taper on the expander mandrel. 8.) Look through the sight hole, by the set screw, and rotate the bottom half until the milled slot in the flow tube is seen and tighten the set screw down, snug but not tight, into the slot. IT IS NOW READY TO RUN. **Note: If the set screw is backed out too far the ratchet nut inside will turn. If this happens, break apart the bottom half and screw the ratchet nut in until it stops, then back off one to two rounds and line up the milled slot in the nut with the set screw and tighten set screw just enough to keep the ratchet nut from turning.

279

Exhibit 11.7 DDIC AD-2 Stinger & Receptacle

280

Exhibit 11.8

D & D Hole Finder w/ AD 2 Tubing Stop 281

Exhibit 11.8 DDIC Hole Finder

282

Exhibit 11.9 Pack-Off Bridge Plug

283

3” DDIC PACK-OFF BRIDGE PLUG Running Procedures: 1.) 2.)

G.I.H. with AD-2 Tubing Stop on GS Pulling Tool. Pass the desired setting depth by 10 – 20 ft. Next, stop the wire rapidly, making the jars snap, shearing the pin in the Stop. This will activate the Stop, allowing it to go no further down the well. At this time, pull up the tubing, stopping at the desired depth, jar down to set the stop and release GS Pulling tool. P.O.O.H.

3.)

G.I.H. with ½ section Pack Off with Kobe plug, setting down on AD-2 Stop, jar down to set Pack Off and release GS Pulling Tool. P.O.O.H.

4.)

(Before opening well to lubricator) – Back pressure the lubricator so that “no surge in pressure exists” – possibly moving the plug. G.I.H. with AA Tubing Stop setting on top of Pack-Off. Jar down to set Stop and release GS pulling tool. P.O.O.H. Note: Before bleeding down the tubing pressure, document the static tubing pressure for later equalization.

Pulling Procedures: Back pressure tubing to compensate for the static pressure build-up 1.)

G.I.H. with GS Pulling tool with proper length Equalizing Prong. Set down on top of the AA Tubing Stop. Jar down on Kobe Button – breaking the button, allowing equalization to be verified. Pick up on GS Pulling Tool, if the stop is latched, then the Kobe Button is broken - Jar up to pull Stop . P.O.O.H.

2.) Remove Equalizing Prong from G.S. Pulling Tool. G.I.H. with GS Pulling Tool. Set down on Pack Off to latch. Jar - up to release Pack-Off. P.O.O.H. 3.)

G.I.H. with GS Pulling Tool. Set on AD-2 Stop. Jar up to release Stop. P.O.O.H.

284

4 ½” /5 ½” DDIC PACK-OFF BRIDGE PLUG Running Procedures: 1.)

G.I.H. with AD-2 Tubing Stop on GS Pulling Tool. Pass the desired setting depth by 10 – 20 ft. Next, stop the wire rapidly, making the jars snap, shearing the pin in the Stop. This will activate the Stop, allowing it to go no further down the well. At this time, pull up the tubing, stopping at the desired depth, slack off on the wire causing the stop to set at the proper depth. Jar down to set the stop and release GS Pulling tool. P.O.O.H.

2.)

G.I.H. with ½ section Pack Off with Kobe plug, setting down on AD-2 Stop, jar down to set Pack Off and release GS Pulling Tool. P.O.O.H. NOTE: This step can also be altered to use the standing valve in place of the kobe plug.

3.)

(Before opening well to lubricator) – Back pressure the lubricator so that “no surge in pressure exists” – possibly moving the plug. G.I.H. with AA Tubing Stop setting on top of Pack-Off. Jar down to set Stop and release GS pulling tool. P.O.O.H. Note: Before bleeding down the tubing pressure, document the static tubing pressure for later equalization.

Pulling Procedures: Back pressure tubing to compensate for the static pressure build-up 1.)

G.I.H. with the equalizing bar to either break the kobe equalizer or to shift the equalizer valve on the standing valve. (This depends on what is in the well, the kobe plug or the standing valve).

2.)

G.I.H. with GS Pulling tool with proper core extension. (4” core extension for 4” stop and 5” core extension for 5” stop) Set down on top of the AA Tubing Stop. Jar down on the GS pulling tool–shearing the two 3/16” brass pins, driving the core of the AA Tubing Stop downward. Once the stop core is driven down, the taper lugs are then able to retract, allowing the slips to release since the taper is no longer forcing them outward. Pick up to pull the stop free and P.O.O.H.

3.) Remove the core extension from G.S. Pulling Tool. G.I.H. with GS Pulling Tool. Set down on Pack Off to latch. Jar - up to release Pack-Off. P.O.O.H. 4.)

G.I.H. with GS Pulling Tool. Set on AD-2 Stop. Jar up to release Stop. P.O.O.H.

285

WIRELINE

SERVICES

WGWS Health, Safety & Environment

New Employee Orientation Policy It is the policy of this company that new employees receive orientation and participate in the company’s Safety Programs. In addition, employees will receive any specialized training required to safely and properly perform his/her job duties. It is the employee’s responsibility not to perform any job with which they are not familiar. Wood Group Wireline Services will expect employees to inform supervision of their job knowledge deficiencies. No one knows those deficiencies better than the employee. Responsibility The District manager, will help develop and give assistance to the new employee. He will be responsible to periodically audit the effectiveness and completion of the orientation process. The assigned wireline mentor will be the person primarily responsible for supervising the new employee’s orientation. After the initial orientation the assigned wireline mentor should continually solicit employee feed back on specific training needs and deficiencies. The assigned wireline mentor should also fulfill the following: 1. Reinforce the concepts and practices of the training in day to day operations. 2. Perform Task Safety Observations on new employees at least once per week for a month or longer if needed. It is the responsibility of the new employee to make the Wireline Operator aware of the jobs and task in which they are unfamiliar or not comfortable to perform. No one knows the new employee’s skill level better than the employee. Documentation Training should be documented whenever possible and should include the following: • Name of trainer • Subject • Brief outline of material • Employees name and signature • Date

Page 1

2/16/2004

WIRELINE

SERVICES

WGWS Health, Safety & Environment

Purpose & Guidelines When new employees come to work they immediately begin to form impressions about the company, job, supervision and fellow employees. This impression will be formed by the things said, and sometimes by the things not said. It is important that during this initial period the employee clearly understand the safety policies of the company and his role and expected participation. Like anyone in unfamiliar surroundings, new employees are not likely to fully grasp all of the job requirements and hazards they fact. For many, they lack experience and confidence and may be hesitant to ask for help. For others it’s simply the fact of being in unfamiliar surroundings. Much of the success of the safety effort will be dependent on the employee communicating “what they know and don’t know”. It is imperative the employee understand that it is “OK” to say they do not understand a particular job or task. The alternative is to experience poor job performance or worse yet personal injury. New employees will try to make a good impression. Many will take risks and be hesitant to admit job knowledge deficiencies. Remember over 50% of work place injuries occur to employees who have been employed less than 12 months. It’s not surprising then that 70% of work place fatalities involve new employees in the same 12-month period. Many people often ask where do I start? The answer is really pretty simple. 1. No matter how fast you talk, you cannot cover every rule in one day and you should not try. 2. Ask the employee a series of questions to determine their job knowledge and experience. Remember you have to ask! New employees may be hesitant to admit job knowledge deficiencies. 3. Employees should receive a general hazards orientation and be assigned to a mentor during their probation period. 4. After being assigned to a crew, the assigned wireline mentor should begin to train the employee in job specific standards and work practices. The new employee orientation is designed to provide basic safety knowledge. It will also be a time to reinforce or review information he may know or in some cases not know. Safety awareness and building a foundation for the proper safety attitude is the primary function of this orientation. Remember, the new employee’s attitude will be greatly impacted (positively or negatively) by this initial education.

Page 2

2/16/2004

WIRELINE SERVICES

WGWS Health, Safety & Environment

New Employee Safety Orientation Checklist The first message a new employee should receive is that safety counts. This should be evident by the efforts made to make the employee aware of our safety programs, policies, and practices. This checklist is to be completed on each new hire and must be signed by both the employee and his/her supervisor. The completed form is retained in the employee’s Personnel File. General Yes No N/A Has the employee been introduced to the Safety Department







Has the employee reviewed the WGWS Safety Manual







Does the employee know where safety notices and bulletins are posted?













Has the employee been instructed in Company Emergency & Accident Reporting







Does the employee understand that unsafe conditions are to be reported immediately







Has the employee been instructed in the WGWS Safety Policy & Mission Statement







Has the employee been provided with a copy of the Company Drug & Alcohol Policy







Has the employee been provided with Drug & Alcohol misuse information as per DOT







Does the employee have all of the proper PPE (eyewear, footwear, hard hat, etc.)







Has the employee been instructed in the proper wear and care of PPE







Can the employee read and understand a Material Safety Data Sheet







Does the employee know where the MSDS Manual is kept







Can the employee read and understand product hazard warning labels







Has the employee received Explosives Safety Training?







Has the employee reviewed the Company Disciplinary Program for Safety violations







Has the employee been provided with the Company General Safety Rules







Has the employee received the behavior based safety training – STOP for Employees







Has the employee received HazMat HM-126 transportation training (Awareness)







Has the employee received Marine Safety Training for offshore work (Awareness)







Has the employee completed and signed the WGWS HS&E Manual







Has the employee been instructed to report all accidents & signed WGLS 1606 Accident Reporting & Medical Treatment

Drug and Alcohol Program

Personal Protective Equipment

Hazard Communication

Training

Employee Name (Please Print)

Employee Signature

Date

Supervisor Name (Please Print)

Supervisor Signature

Date

Page 1

2/16/2004

WIRELINE SERVICES

JOB SAFETY AND ENVIRONMENTAL ANALYSIS

Date: 1) ASSIGN THE RIGHT TEAM - Knowledge, Experience, Committed, Confident, Empowered 2) UNDERSTAND THE STEPS / DEFINE THE HAZARDS – What are the hazards? Gather appropriate resources. 3) EXECUTE - Influence, Manage, Lead, Assign Responsibility to Recommended Actions to Reduce / Eliminate Hazards

Team Members (Print Name)

Signature

Job Title

PLATFORM / RIG LOCATION:

Employer

DATE:

PERSON-IN-CHARGE OF JOB (PIC): PROJECT DESCRIPTION: Basic Job Steps

Potential Hazards

Recommended Actions

Responsible Party (Signature)

(List the tasks involved)

(Eliminate or reduce hazards.)

(Who ensures action taken?)

(1). Positioning equipment on deck

(What IF? What could go wrong?) Equipment movement, trip hazard, restricted walk area, struck-by, or against equip.

(2). Rigging up wireline, Lubricator and tool string.

Pinch points, eye injury, back strains; slips trips and falls.

Chain off unit, use caution tape on chain, and hoses; Good communication with crane operator, try to place equip. in open area. Use lubricator stand, Proper PPE when spooling, or cutting wire. Use proper lifting techniques & beware of conditions of weather, oily decks & tools. Keep area clean and use caution tape around work area.

1

WIRELINE SERVICES Basic Job Steps (List the tasks)

JOB SAFETY AND ENVIRONMENTAL ANALYSIS Potential Hazards

Recommended Actions

Responsible Party (Signature)

(What IF? What could go wrong?)

(Eliminate or reduce hazards.)

(Who ensures action is taken?)

(3). Remove tree cap, and install tree connection.

Hydrocarbon releases, bad threads, falls, and high pressure

Confirm swab valve is closed, do not assume anything. Check threads on tree connection, and wellhead. Use stand to work on tree, make sure pressure is off tree cap.

(4). Remove hatch cover, and hoist and stab lubricator on tree.

Strained back, pinch points, struck, by lubricator, open holes, and falls

Get help if needed, use good communication with crane operator. Keep hands clear of lubricator. Use barricade.

(5). Tested Lubricator

High pressure leaks, hoses blow out

Stay clear while testing, use whip check on hoses, and don’t over use Teflon tape.

(6). Stabbing lubricator between trips

Pinch points, struck by lubricator and tools. Falling objects, hydrocarbons releases

Keep hands clear of lub. beware of lubricator swing. Keep containment pans around riser

(7). Rigging down equipment

Slips trips, falls, back strains, stuck by; open hole, stab, or cut by wire

Keep area clean, get help when needed, good comm. Barricade over hole until hatch is install. Pigtail wire after cutting off unit, or stuffing box.

What could go wrong in the job I am about to perform that could result in a fatal injury to my fellow worker or myself?

All

How could my task adversely affect other workers on this platform?

All

What are the major hazards associated with the task at hand?

All

What are we (workers) going to do to mitigate or eliminate the risks we have identified?

All

2

Wood Group Wireline Wins the ChevronTexaco Contractor Outstanding Crew Safety Award

Accepting the award is from left to right: Marvin Culpepper (Belle Chase, LA. Wood Group Operation Manager), Ken Blanchette (ChevronTexaco MP 299 Field Support Team Leader), Scott Girouard (Broussard, LA. Wood Group District Manager), Steve Rees (ChevronTexaco MP 299 Petroleum Engineer), Darlene Herrin (Wood Group Regional Administration Manager), Eric Sirgo (ChevronTexaco MP 299 Asset Manager), Andrea Broussard (Wood Group HSE Administrator), Chuck Crosby (Wood Group Wireline General Manager), Chadd Richard (Wood Group Sales Manager), Mike Herrin (Wood Group Regional Manager) ChevronTexaco’s North America Upstream Gulf of Mexico Business Units recently awarded the Outstanding Crew Safety Award to Wood Group Wireline Services. The award was in recognition of outstanding work and safety performances by Wood Group Wireline service crews located within the Main Pass 299 area for ChevronTexaco. As announced by Doug Lanier with ChevronTexaco at the 1st Annual Contractor Award Luncheon, Wood Group Wireline Crews has consistently demonstrated their commitment to HES while working for ChevronTexaco jobs. All appropriate HES policies and programs were followed and HES processes utilized. These crews participated in meeting with other contractors and/or ChevronTexaco, if applicable. They communicated well with the ChevronTexaco representative and the quality and efficiency of the work completed only reinforces that safety, quality and efficiency can be accomplished together. Employees of Wood Group Wireline, in recognition, of their accomplishment were awarded jackets from Doug Lanier (ChevronTexaco Vice-President – Gulf of Mexico Shelf) and Rhonda Zygocki (ChevronTexaco Corp. Vice-President – Health, Environment and Safety) were Joe Myers, Charles Ellard, Randy Ryder, Chase Sonnier, Jonathan Guidry, Brandon Bergeron, Jason Sonnier, Kevin Labiche, Darren Labiche and Scott Ellard. This core group of employees has also put forth a TEAM effort in setting and accomplishing goals in the MP 299 area for an outstanding accumulation of 422 days and 34,341 man-hours working ‘IFO’ Incident Free Operations so far with even higher numbers being added each day. Company wide the Wireline Division has built some outstanding figures in No Lost Work Days in the lines of safety. Currently the divisions from along the Louisiana Gulf Coast and divisions from South Texas have surpassed a total of 1,174,909 man-hours and 898 days accident free. Mike Herrin, Wood Group Regional Manger stated “that this award is an outstanding symbol of recognition for the focus our employees have worked on continuing our safety efforts. This award is a great motivator for each employee in the field and in management support because it is like a pat on the back for a job well done from our clients. Safety is preached each moment of the day and this award is a reminder to the employees that our clients do recognize a job well done and reward them for it”.