OXY Drilling Practices

DRILLING OPERATIONS MANUAL DRILLING PRACTICES

GENERAL TOPICS

SVP02.DOC SECTION V, PART 2, PAGE i Revision 1, January 1998

2.0 GENERAL TOPICS

2.1 Rig Positioning and Offset Monitoring

2.1.1 Slope Indicators2.1.2 Wear Bushings on Subsea Wellheads2.1.3 Rig Position Indicating Systems (Floating Rigs)2.1.4 Rig Trim (Floating Rigs)

2.2 Drill Pipe

2.2.1 Corrosion2.2.2 Hardbanding2.2.3 Tool Joints2.2.4 Make-up Torque - Drill Pipe2.2.5 Alternating Breaks2.2.6 Allowable Pull2.2.7 Simultaneous Tension and Torque on Drill Pipe

2.3 Drill Pipe and Bottom Hole Assembly Inspection and Specification

2.3.1 Drill String Records2.3.2 Frequency of Inspections2.3.3 Inspection Requirements2.3.4 Used Drill Pipe Marking and Classification

2.4 Prevention of Ingress of Hydrocarbons into Rig Systems

2.4.1 Check Valve Manifold Required2.4.2 Operating Valve Required on Kill Line(s)2.4.3 Flow From Well Must Go Through a Choke2.4.4 Dedicated Bleed-Off Line Required2.4.5 Air and/or Steam Supply During DST to be Independent of Rig

System2.4.6 Check Mud/Gas Separator Operation

2.5 Wellhead Equipment Handling (Offshore)

2.5.1 Shipped in Packing Crates2.5.2 Wellhead and Christmas Tree Tools2.5.3 Steel Ring Gaskets and Elastomeric Seals2.5.4 Transporting Wellhead Equipment on the Rig2.5.5 Vertical Lifts of Wellhead Equipment and Christmas Tree

2.6 Washout Detection


GENERAL TOPICS

SVP02.DOC SECTION V, PART 2, PAGE ii Revision 1, January 1998

2.6.1 Surface Pressure Check2.6.2 Slow Pump Pressure Check2.6.3 Bottom-Hole Assembly Testing2.6.4 Washout Locator Sub and Dart2.6.5 Drill String Test Sub

2.7 Drill Pipe Tally

2.7.1 Measurement on Deck2.7.2 Master Talley Book2.7.3 Daily Check of Pipe Talley2.7.4 Record Depths - Geolograph2.7.5 Daily Check Total Drill Pipe on Location2.7.6 Strap Prior to Fishing2.7.7 Strapping Frequency

2.8 Casing and Tubing Markings

2.8.1 Groups2.8.2 Die Stamp Markings2.8.3 Paint Stencil Markings2.8.4 Color Code Identification2.8.5 Thread Marking - All Groups

2.9 Handling of Casing and Tubing

2.9.1 Shipping2.9.2 Field Inspection2.9.3 Handling Tools2.9.4 Running Procedure2.9.5 Welding on Casing or Tubing

2.10 Certifiable Drilling Equipment

2.11 Stock Rotation and Storage

2.11.1 Elastomeric Materials2.11.2 Casing Hanger Pack-Offs2.11.3 Drill Bits2.11.4 Metallic Goods and Materials


GENERAL TOPICS

SVP02.DOC SECTION V, PART 2, PAGE 1 Revision 1, January 1998

2.0 GENERAL TOPICS

2.1 Rig Positioning and Offset Monitoring

Mobile offshore drilling units (Jack-ups, Semi-submersibles, and Drillships) will be moved asspecified in the Drilling Program.

Upon arrival at the new location, initial rig positioning will be established. Once the rigposition has been fixed over the intended location (e.g., all anchors run and holding onmoored rigs), the well may be spudded. The final rig position is not to be reported until therig position is stable and the final rig and well position is determined by satellite fix.

On moored rigs, to ensure that the rig can be repositioned over the well following any offsetoperation, the mooring lines are to be painted white at a reference location close to the winchhead.

2.1.1 Slope Indicators

In subsea operations, slope indicators are to be fitted to the permanent guide base,blowout preventer stack, and on the last joint of riser above the lower marine riserpackage (LMRP) flex joint. The slope indicator fitted to the permanent guide base isto be positioned on either the port or starboard side of the guide base depending onthe location of the rig's subsea camera winching system. All slope indicators are to bepositioned to permit viewing with the rig's subsea camera.

Inspection of slope indicators is to be performed at least once per tour and reportedon the Occidental and IADC daily drilling reports. The bull's-eye position is to bereported relative to rig heading; for example, 1/2 degree starboard aft.

2.1.2 Wear Bushings on Subsea Wellheads

A wear bushing is to be installed in the wellhead for all operations except the runningof casing or completion equipment. The wear bushing on subsea wellheads is to bepulled and inspected approximately once every seven days as allowed by operationalconsiderations. Results of the inspection are to be reported on the Occidental andIADC daily drilling reports. The report is to detail the depth of any wear, as well aswear orientation relative to rig heading. For example: 1.0 inch groove, full length, at120 degrees from rig heading. In addition, the following practices are to be followed:

A. Two wear bushings will be maintained on each rig with a subsea wellhead atall times, sized for the hole section currently being drilled. The wear bushingsare to be alternated following recovery from the wellhead to permit athorough dimensional inspection by the subsea engineer, wellhead serviceengineer, or drilling supervisor, as appropriate.


GENERAL TOPICS


B. Adequate records are to be maintained on the service history and fieldinspection results of all wear bushings. If a slightly worn wear bushing is tobe re-run, then a means of identifying the location of existing wear must beensured. This can easily be accomplished by filing a small groove on theoutside of the wear bushing at the same orientation as the internal wear.Alternatively, a metal stamp can be used to make an impression on the outsideof the wear bushing to identify wear orientation.

C. Wear bushings are to be recovered without rotation of the tool string. Oncethe wear bushing has cleared the rotary table an orientation mark is to bescribed on the outside of the wear bushing to act as a reference for subsequentdetailed inspection.

D. If inspection of the wear bushing indicates an adverse wear pattern, rigposition is to be adjusted to compensate for this condition. The wear bushingshould then be pulled following the next bit trip to verify that the adverse wearcondition has been corrected.

E. Wear bushings with any appreciable wear are not to be re-installed in awellhead. A replacement wear bushing is to be ordered immediately followingany inspection that reveals excessive wear.

2.1.3 Rig Position Indicating Systems (Floating Rigs)

The rig position indicating system is to be functional at all times once the well hasbeen spudded. One subsea beacon is to be positioned on the seabed and a second unitis to be fitted to the blowout preventer stack. Once the system is operational, rigposition is to be monitored to ensure that lateral offset remains within 1% of waterdepth.

2.1.4 Rig Trim (Floating Rigs)

The rig is to be maintained at a level attitude at all times within the constraintsimposed by weather conditions. The person most keenly aware of rig trim will be thedriller, since incorrect levelling of the rig will adversely effect his ability to engage thekelly bushing in the rotary drive bushing, set the rotary slips, etc. Once the drillerbegins to experience operational difficulties related to rig trim he should endeavor todetermine the cause. The following steps can be used as a guide to problemidentification.


GENERAL TOPICS


A. During severe weather conditions it is likely that the rig is being blown offlocation. Check the acoustic vessel offset position indicating system todetermine the degree of offset, and inspect the bull's-eye located on the lastjoint of riser above the lower marine riser package. If the bull's-eye indicatesa riser angle in excess of 1/2 degree, or if the rig offset is greater than 1% ofwater depth, then the rig's position is to be altered to correct the offsetcondition.

B. If vessel offset is within acceptable limits, then it is possible that the rig is notcorrectly trimmed for the current loading conditions. This problem can be dueto a number of factors including whole mud transfers between pits, movementof deck cargo, bulk material transfers, etc. Check with the control room todetermine if the rig is correctly ballasted for the current loading condition. Ifnot, trim the rig to correct the problem.

It should be noted that indiscriminate use of ballast to solve drill floor problems canresult in inadvertent and excessive wear to drill through equipment, particularlyball/flex joints.

2.2 Drill Pipe

Drill pipe performance properties cannot be maintained without constant attention to properhandling procedures, make-up torque, corrosion, and applied loading - to mention a few. Thissection outlines operational guidelines and procedures that are to be adhered to in order toprolong drill pipe life and minimize in-service failures.

2.2.1 Corrosion

Drilling, completion, and workover fluids can present extremely corrosiveenvironments for drill pipe. In water base drilling fluids, metallic corrosion reactionstypically take place due to the presence of three corrosion agents: gases (hydrogensulfide, oxygen and carbon dioxide), dissolved salts (sodium chloride, potassiumchloride, calcium chloride, etc.), and acids (carbonic acid, formic acid and acetic acid).Wellsite corrosion of drill pipe can be due to any one or a number of these agents. It is imperative that the Drilling Supervisor understand these corrosion environmentsand ensures that appropriate action is being taken to protect the mechanical integrityof the drill string.

In order to limit the effects of corrosion reactions in water base drilling fluids, thefollowing guidelines are to be adhered to:


GENERAL TOPICS


A. If H2S contamination is not anticipated, maintain the pH of the drilling fluidat 9.5 or higher. This will alleviate the general corrosion and pitting corrosionthat takes place due to the presence of dissolved oxygen.

B. If H2S contamination is anticipated, maintain the pH of the drilling fluid at11.0 or greater through additions of caustic and/or lime. Lime is preferred,since for a particular mud density and pH, lime will yield a higher Pm resultingin a greater capacity to react with H2S.

If H2S is detected, scavenge with zinc carbonate at a concentration of 3-5 ppb.or alternate scavengers at recommended dosage. The use of Ironite Spongeis not recommended for high pH water base mud systems unless pilot testingof the mud proves this to be a suitable alternative to zinc carbonate. If IroniteSponge is determined to be acceptable for the mud system in use, then initialtreatment should be based on the results of pilot testing.

In addition, the mud is to be periodically tested for the presence of H2S usinga Garrett gas train or equivalent sulphide analyzer.

C. If the drilling fluid system requires that a low pH be maintained, treat the mudwith a suitable oxygen scavenger and/or corrosion inhibitor. The selection ofa suitable corrosion inhibitor and treatment concentration will be dependenton the mud system in use. Concentrations should be specified only after pilottesting since over-treatment can actually increase the corrosion rate.

D. If the drilling fluid becomes aerated, operate the degasser continuously untilthe condition dissipates. Avoid jetting mud and additives directly into theactive mud system through mixing hoppers. If possible, pre-mix additives ina mixing tank prior to addition to the active system. This will lessen theprobability of entrained air entering the mud pump suction manifold andsubsequently the drill string.

See additional information about H2S in Section V, Part 3, Safety.

2.2.2 Hardbanding

Hardbanding (also called hardfacing) of tool joints is routinely performed to limit thedegree of circumferential wear produced on the tool joint during drilling operations.While hardbanding has been proven to significantly reduce the degree of tool jointwear, it also can produce considerable casing wear, leading to a reduction in casingperformance properties.


GENERAL TOPICS


Care must be exercised in the selection of hardbanding materials and the process ofapplication to tool joints. In all cases, a smooth hardbanding weld, flush with theoutside diameter of the tool joint, should be selected. Flush hardbanding will result ina more uniform load distribution along the length of the tool joint, thereby reducingthe severity of casing wear.

Hardbanding materials are commonly manufactured from three basic types of tungstencarbide: cast-crushed (with sharp corners), sintered and pelletized (resemblingspheres), and sintered crushed (with sharp corners). The size of the tungsten carbideparticles ranges from fine to coarse. Depending upon material composition andwelding process, varying degrees of surface roughness can be achieved.

The Drilling Supervisor should ensure that hardbanded surfaces are smooth and flushwith the outside diameter of the tool joint. Highly abrasive surface finishes are not tobe used in Occidental operations. If new pipe is being used, or pipe that has beenrecently re-hardbanded, every effort should be made to run this pipe in the openholesection as far as is practicable. This will result in a degree of roughness being takenoff the new surface finish and will minimize any adverse impact on casing wear.

2.2.3 Tool Joints

The proper care and handling of drill pipe tool joints will significantly increase theservice life of this equipment and minimize lost time associated with washouts, twist-offs, and other tool joint related drill string failures. The Drilling Supervisor mustensure that the drilling contractor is following generally accepted practices for the useof this equipment. In particular the following guidelines are to be adhered to:

A. New tool joints are to be broken in according to the manufacturer'srecommended break-in procedure. On offshore rigs and high day rate landrigs, breaking in of new tool joints should be done in a shop prior tobeing sent to the rig. Adherence to this break-in procedure is critical to thelong term serviceability of this equipment. Failure to spend the necessary timeto follow the break-in procedure frequently results in material damagerequiring expensive rework. Key elements of the initial break-in procedureshould include:

1. Install thread protectors when picking up or laying down drill pipe.2. Thoroughly clean both the pin and box end threads prior to initial

make-up. This is critically important since most new threads aretreated with a mill grease that is not an acceptable make-up threadcompound. Residual mill grease will adversely effect initial make-upand potentially damage the tool joint. In addition, it is also important


GENERAL TOPICS


that mill grease be removed from all thread protectors to preventsubsequent contamination of thread compound when the pipe is laiddown.

3. Visually inspect thread form and seal areas for shipping damage,including: scratches, gouges, flat spots, etc.

4. Thoroughly coat the threads of BOTH the box and pin with an APIapproved TOOL JOINT thread compound.

Warning: Thread compounds manufactured according to APIBulletin 5A2, Bulletin on Thread Compounds forCasing, Tubing, and Line Pipe, are not to be used.These thread compounds will result in excess make-upfor a given applied torque and are not recommendedfor rotary shouldered connections.

Prior to using a particular thread compound, themanufacturers product specification is to be reviewedto ensure the material composition meets thepreviously mentioned guidelines. In addition, alwaysstart with a NEW dope brush and do not transferbrushes between dissimilar thread compounds.

5. Make-up tool joints slowly. During the break-in period the use of highspeed pipe spinners is not recommended. Preferably, the pipe shouldbe shouldered by hand using a chain tong. Once the tool joint isshouldered, slowly apply make-up torque to the pin, while holdingback-up torque on the box. Alternative procedures requiringmarginally less time will, in most cases, result in subsequent lost timedealing with major problems associated with tool joint damage.

6. Inspect the make-up and break-out tongs prior to use and ensure thatthe insert dies are clean and in good condition.

B. For used drill pipe, the tool joints are to be thoroughly inspected prior toinitial rig acceptance, then periodically, based on service conditions.Inspection is to be performed by an independent inspection service inaccordance with the inspection procedures outlined in API RecommendedPractice 7G, "Recommended Practice for Drill Stem Design and OperatingLimits" and


GENERAL TOPICS


Section V, Part 2.3, "Drill Pipe and Bottomhole Assembly Inspection andSpecification". Alternative inspection procedures may be used conditionalupon prior approval.

C. Prior to make-up, the tool joint is to be coated with an API approved TOOLJOINT thread compound. For used tool joints, it is acceptable to applythread compound to the tool joint box threads and sealing shoulder only.Acceptable thread compounds are to be formulated as given in (1d) above.

D. When stabbing pipe, exercise care to avoid landing the pin end on the sealingface of the box end. This action can produce a low spot on the sealing facewhich could eventually produce a wash-out. On floating rigs, a stabbing guideshould be used to avoid seal area damage.

2.2.4 Make-up Torque - Drill Pipe

For both new and used drill pipe, tool joint make-up torques are specified as apercentage of the torsional yield strength for a particular tool joint. For new drill pipe,the API recommended make-up torque is taken as 50% of the torsional yield strengthfor a connection, while for used pipe the figure is increased to 60%. In all cases thetorsional yield strength for the weaker of the box or pin is used to determine themake-up torque for the connection.

On high torque operations, the make-up torque for NC50 (4-1/2" IF) connections isto be 28-30,000 ft-lbf to prevent downhole make-up while drilling. In general, themake-up torque for other API tool joints is to be in accordance with the APIrecommended make-up torque schedules unless an alternative make-up torque isspecified in the Drilling Program. The API torque schedules are reproduced here inTable 2.1 (when using these tables special attention should be given to the explanatorynotes at the end of Table 2.1). If required, Figure 2.1 can be used for tool jointidentification.

Certain well applications will require the use of higher make-up torques than thosegiven in the API tables. Selection of an appropriate torque under these circumstancesshould be based on the maximum anticipated torque while drilling and the mechanicalcondition and performance properties of the drill string.

TABLE 2.1 RECOMMENDED MINIMUM OD AND MAKE-UP TORQUE OF WELD-ON TYPE TOOL

JOINTS BASED ON TORSIONAL STRENGTH OF BOX AND DRILL PIPE

1 2 3 4 5 6 7 8 9 10 11 12 13

DRILL PIPE DATA NEW TOOL JOINT DATA PREMIUM CLASS CLASS 2

Nom.Size

Nom.Size

TypeUpset

Conn. NewOD

NewID

Make-upTorque

Min.OD

Min BoxShoulder

Make-upTorque

Min.OD

Min. BoxShoulder

Make-upTorque


GENERAL TOPICS


Wt andGrade

ToolJointin.

withEccentric

Wearin.

for Min.OD Tool

ft-lb

ToolJointin.

withEccentric

Wearin.

for Min.OD Tool

ft-lb

in. lb/ft in. in. ft-lb 6 4 3 6 4 3

2_

2_

3½

4.85

6.65

6.65

6.65

6.85

10.40

10.40

10.40

10.40

9.50

13.30

13.30

EU-EEU-EEU-EEU-E

EU-EEU-EIU-EEU-E

EU-XEU-X

EU-GEU-G

EU-EEU-EEU-EEU-E

EU-EEU-EIU-EIU-EEU-EIU-E

EU-XEU-X

EU-GEU-G

EU-SEU-S

EU-EEU-EEU-EEU-E

EU-EEU-EEU-EIU-EEU-E

EU-XEU-XEU-X

NC26(IF)OH

SLH90WO

NC26(IF)OH

PACSLH90

NC26(IF)SLH90

NC26(IF)SLH90

NC31(IF)OH

SLH90WO

NC31(IF)OH

PACNC26(SH)

SLH90XH

NC31(IF)SLH90

NC31(IF)SLH90

NC31(IF)SLH90

NC38(IF)OH

SLH90WO

H90NC38(IF)

OHNC31(SH)

XH

H90NC28(IF)

SLH90

3_3_3¼3_

3_3¼2_3¼

3_3¼

3_3¼

4_3¾3_4_

4_3_3_3_3_4¼

4_4

4_4

4_4_

4¾4½4_4¾

5¼4¾4¾4_4¾

5½5

4¾

1¾222

1¾1¾1_2

1¾1-13/16

1¾1-13/16

2_2-7/162-7/162-7/16

2_2-5/32

1½1¾

2-5/321_

22

22

1_1_

2-11/16333

2¾2-11/162-11/16

2_2-7/16

2¾2-9/162-9/16

3239226225632267

3239314923452563

32393442

32393442

593527938153756

593544093441323956476798

65976613

65976613

84728613

9054593463236667

119249054865259358746

119241016310439

3-5/32b3-1/32b2-31/32b3-5/64b

3-7/32b3-3/32b2-51/64b3-1/32b

3-19/64b3-7/64b

3-21/64b3-9/64b

3-23/32b3-1/2b3-1/2b

3-21/32b

3-27/32b3-41/64b3-1/8P3-3/8B

3-39/64b3-49/64b

3-15/16b3-45/64b

3-63/64b3-3/4b

4-1/8b3-7/8b

4-26/64b4-19/64b4-13/64b4-27/64b

4-37/64b4-17/32b4-13/32b4-1/8P4-3/8b

4-43/64b4-41/64b4-13/32b

3/323/323/323/32

3/327/645/323/32

9/641/8

5/329/64

3/327/643/323/32

5/3211/649/327/329/645/32

13/643/16

7/327/32

19/649/32

1/89/641/81/8

5/323/1663/1619/6413/64

13/6415/647/32

1848184818481848

2431243124312431

30803080

34043404

3135313531353135

449544953441388744954495

56945694

62946294

80928092

5486548654865486

72127212721272127212

913591359135

3_b3b

2-15/16b3-3/64b

3-3/16b3-1/16b2-3/4b

3b

3-1/4b3-1/16b

3-9/32b3-3/32b

3-11/64b3-15/32b3-29/64b3-5/8b

3-51/64b3-37/64b3-1/8P

3-9/16B3-9/16b3-23/32b

3-7/8b3-41/64b

3-59/64b3-11/16b

4-3/64b3-13/16b

4-3/8b4-1/4b4-5/32b4-3/8b

4-17/32b4-31/64b4-23/64b3-63/64b4-5/16b

4-5/8b4-37/64b4-11/32b

3/323/323/323/32

3/323/321/83/32

7/647/64

1/81/8

3/323/323/323/32

1/89/649/327/321/89/64

11/645/32

3/163/16

1/41/4

7/647/643/327/64

1/85/3211/647/3211/64

11/6413/643/16

1625162516251625

2139213921392139

27102710

29952995

2756275627562756

395639563441388739563956

50115011

55395539

71227122

4821482148214821

63446344634463446344

803680368036

TABLE 2.1 (continued)RECOMMENDED MINIMUM OD AND MAKE-UP TORQUE OF WELD-ON TYPE TOOL

JOINTS BASED ON TORSIONAL STRENGTH OF BOX AND DRILL PIPE

1 2 3 4 5 6 7 8 9 10 11 12 13


Nom.Size

Nom.SizeWt

TypeUpsetand

Grade

Conn. NewOD

NewID

Make-up

Torque

Min.ODToolJoint

Min BoxShoulder

withEccentric

Make-upTorquefor Min.OD Tool

Min.ODToolJoint

Min. BoxShoulder

withEccentric




GENERAL TOPICSin. Wear

in.ft-lb in. Wear

in.ft-lb


3½ 13.30

13.30

15.50

15.50

15.50

15.50

11.85

14.00

14.00

14.00

14.00

15.70

15.70

15.70

EU-GEU-G

EU-SEU-SEU-S

EU-E

EU-X

EU-GEU-B

EU-S

IU-EEU-EEU-EEU-E

IU-EIU-EEU-EEU-EIU-E

IU-XIU-XEU-X

IU-GIU-GEU-G

IU-SIU-SEU-S

IU-EEU-EEU-E

IU-XIU-XEU-X

IU-GIU-GEU-G

NC38(IF)SLH90

NC38(IF)SLH90

NC40(4FH)

NC38(IF)

NC38(IF)

NC38(IF)NC40(4FH)

NC40(4FH)

H90NC46(IH)

OHWO

NC40(FH)H90

NC46(IF)OHSH

NC40(FH)H90

NC46(IF)

NC40(FH)H90

NC46(IF)

NC40(FH)H90

NC46(IF)

NC40(FH)H90

NC46(IF)

NC40(FH)H90

NC46(IF)

NC40(FH)H90

NC46(IF)

54¾

555_

5

5

55¼

5½

5½6

5¼5¾

5¼5½6

5½4_

5¼5½6

5½5½6

5½5½6

5¼5½6

5½5½6

5½5½6

2-7/162-9/16

2-1/82-1/82-7/16

2-9/16

2-7/16

2-1/82-9/16

2-1/4

2-13/163-1/4

3-15/323-7/16

2-13/162-13/163-/143-1/42-9/16

2-11/162-13/163-1/4

2-7/162-13/163-1/4

22-13/16

3

2-11/162-13/163-1/4

2-7/162-13/163-1/4

2-7/162-13/163-1/4

1110610439

130111403914965

10163

11106

1301113880

16472

17720168131098314734

117441772016813136407790

128361772016813

150571772016813

181821772019615

128361772016813

150571772016813

150571772016813

4-45/64b4-25/64b

4-55/64b4-5/8b5-1/16b

4-19/32b

4-23/32b

4-25/32b4-63/64b

5-9/64b

4-29/32b4-15/64b

5b5-15/64b

4-27/32b4-31/32b5-5/16b5-1/16b4-31/64b

4-31/32b5-5/64b5-27/64b

5-1/32b5-9/64b5-15/32b

5-7/32b5-9/32b5-39/64b

4-29/32b5-1/64b5-23/64b

5-3/64b5-9/64b5-15/32b

5-7/64b5-3/16b5-17/32b

17/641/4

11/3221/645/16

7/32

9/32

5/169/32

23/64

1/81/89/641/8

13/645/325/3211/6417/64

17/647/327/32

19/641/4

15/64

25/645/165/16

15/643/163/16

5/161/4

15/64

11/3217/6417/64

1009610096

129811298112981

8201

10392

1148611486

14768

7547754775477547

90399039903990399039

114491144911449

126541265412654

162701627016270

100271002710027

127011270112701

140381403814038

4-5/8b4-25/64b

4-25/32b4-17/32b4-31/32b

4-17/32b

4-41/64b

4-45/64b4-29/32b

5-1/16b

4-55/64b5-13/64b4-61/64b5-13/64b

4-51/64b4-59/64b5-17/64b5-1/64b4-27/64b

4-29/32b5-1/64b5-23/64b

4-61/64b5-1/16b5-13/32b

5-1/8b5-13/64b5-17/32b

4-27/32b4-31/32b5-19/64b

4-31/32b5-5/64b5-13/32b

5-1/64b5-1/8b

5-29/64b

15/647/32

5/169/3217/64

3/16

15/64

17/6415/64

5/16

7/647/641/87/64

3/169/649/645/3215/64

15/643/163/16

17/6413/6413/64

11/329/3217/64

13/645/325/32

17/647/3213/64

19/6415/6415/64

88828882

114201142011420

7221

9146

1010910109

12998

6631663166316631

79467946794679467946

100651006510065

111251112511125

143041430414304

881988198819

111701117011170

123461234612346



GENERAL TOPICS

TABLE 2.1 (continued)RECOMMENDED MINIMUM OD AND MAKE-UP TORQUE OF WELD-ON TYPE TOOL

JOINTS BASED ON TORSIONAL STRENGTH OFBOXAND DRILL PIPE

1 2 3 4 5 6 7 8 9 10 11 12 13


Nom.Size

Nom.SizeWt

TypeUpsetand

Grade

Conn. NewOD

NewID

Make-upTorque

Min.ODToolJointin.

Min BoxShoulder

withEccentric

Wearin.


ft-lb

Min.ODToolJointin.

Min. BoxShoulder

withEccentric

Wearin.


ft-lb


4

4½

15.70

13.75

16.60

16.60

16.60

16.60

20.00

20.00

20.00

20.00

22.82

22.82

EU-S

IU-3EU-EEU-EEU-E

IEU-EIEU-EEU-EEU-EIEU-EIEU-E

IEU-XIEU-XEU-XIEU-X

IEU-GIEU-GIEU-GEU-G

IEU-SIEU-SIEU-SIEU-S

IEU-EIEU-EEU-EIEU-E

IEU-XIEU-XEU-XIEU-X

IEU-GIEU-GEU-GIEU-G

EU-SIEU-S

EU-EIEU-E

IEU-XEU-XIEU-X

NC46(IF)

H90NC50(IF)

OHWO

FGH90

NC50(IF)OH

NC38(SH)NC46(XH)

FGH90

NC50(IF)NC46(XH)

FHH90

NC50(IF)NC46(XH)

FHH90

NC50(IF)NC46(XH)

FHH90

NC50(IF)NC46(XH)

FHH90

NC50(IF)NC46(XH)

FHH90

NC50(IF)NC46(XH)

NC50(IF)NC46(XH)

NC50(IF)NC46(XH)

FHNC50(IF)

NC46(XH)

6

66_5¾6_

666_5_5

6¼

666_6¼

666_6¼

6¼66_6¼

666_6¼

666_6¼

666_6¼

6_6¼

6_6¼

6¼6_6¼

3

3¼3¾

3-31/323_

33¼3¾3¾

3-11/163¼

33¼3¼3

33¼3¼3

2½3

3½2¾

33

3_3

2½3

3½2¾

2½3¼3½2½

32¼

3_3

2¼3½2¾

19615

19510188361048217220

17390195101883813636917316997

17390195101883819829

19390195101883819829

22385226292233622463

17390226292061719829

21623195102233622436

21623195102233624815

2785426968

2061719829

24452233622436

b11/16b

5-5/16b5-45/64b5-25/64b5-45/64b

5-27/64b5-3/8b

5-49/64b5-15/32b

5P5-7/16b

5-9/16b5-1/2b

5-57/64b5-9/16b

5-41/64b5-9/16b5-15/16b5-41/64b

5-53/64b5-47/64b6-7/64b5-53/64b

5-17/32b5-15/32b5-55/64b5-17/32b

5-45/64b5-5/8b

6b5-11/16b

5-25/32b5-11/16b6-1/16b5-49/64b

6-17/64b5-63/64b

5-59/64b5-39/64b

5-25/32b6-1/16b5-49/64b

11/32

5/325/3211/645/32

15/643/163/1613/6427/647/32

19/641/41/49/32

11/329/3217/6421/64

7/163/8

23/6427/64

9/3215/6415/6417/64

3/85/1619/6411/32

13/3211/3221/6425/64

7/16½

17/645/16

13/3221/6425/64

18049

10034100341003410034

119491194911949119491100811949

15136151361513615136

16729167291672916729

21509215092150921509

14336143361433614336

18160181601816018160

20071200712007120071

2580625806

1590915909

201512015120151

5-19/32b

5-1/4b5-41/64b5-11/32b5-41/64b

5-23/64b5-21/64b5-23/32b5-27/64b4-23/32b5-3/8b

5-31/64b5-7/16b5-13/16b5-1/2b

5-35/64b5-31/64b5-7/8b

5-35/64b

5-47/64b5-41/64b6-1/64b5-23/32b

5-29/64b5-13/32b5-51/64b5-15/32b

5-39/64b5-17/32b5-59/64b5-39/64b

5-43/64b5-19/32b5-63/64b5-43/64b

6-5/32b5-7/8b

5-27/32b5-33/64b

5-43/64b5-63/64b5-43/64b

19/64

1/81/89/641/8

13/6411/645/323/169/323/16

17/647/3213/641/4

19/641/4

15/649/32

25/6421/645/1623/64

1/413/6413/6415/64

21/6417/6417/645/16

23/6419/6419/6411/32

3/87/16

7/3217/64

23/6419/6411/32

15874

8814881488148814

105021050210502105021050210502

13303133031330313303

14703147031470314703

18904189041890418904

12609126091260912609

15971159711597115971

17653176531765317653

2269622696

1399713997

177301773017730

TABLE 2.1 (continued)



GENERAL TOPICS

RECOMMENDED MINIMUM OD AND MAKE-UP TORQUE OF WELD-ON TYPE TOOLJOINTS BASED ON TORSIONAL STRENGTH OF BOX AND DRILL PIPE

1 2 3 4 5 6 7 8 9 10 11 12 13


Nom.Size

Nom.SizeWt

TypeUpsetand

Grade

Conn. NewOD

NewID

Make-upTorque

Min.ODToolJointin.

Min BoxShoulder

withEccentric

Wearin.


ft-lb

Min.ODToolJointin.

Min. BoxShoulder

withEccentric

Wearin.


ft-lb


4½

5

5½

22.82

22.82

19.50

19.50

19.50

19.50

25.60

25.60

25.60

25.60

21.90

21.90

21.90

21.90

24.70

24.70

24.70

24.70

EU-GIEU-G

EU-S

IEU-EIEU-E

IEU-XIEU-XIEU-X

IEU-GIEU-GIEU-G

IEU-SIEU-S

IEU-EIEU-E

IEU-XIEU-X

IEU-GIEU-G

IEU-S

IEU-E

IEU-XIEU-X

IEU-G

IEU-S

IEU-E

IEU-X

IEU-G

IEU-S

NC50(IF)NC46(XH)

NC50(IF)

5½ FHNC50(XH)

5½ FHH90

NC50(XH)

5½ FHH90

NC50(XH)

5½ FHNC50(XH)

5½ FHNC50(XH)

5½ FHNC50(XH)

5½ FHNC50(XH)

5½ FH

FH

FHH90

FH

FH

FH

FH

FH

FH

6½6¼

6_

76_

76½6_

76½6½

7¼6_

76_

76½

7¼6_

7¼

7

77

7¼

7½

7

7¼

7¼

7½

3¼2½

2¾

3¾3¾

3¾3¼3½

3¾3

3¼

3½2¾

3½3½

3½3

3½2¾

3¼

4

3¾3½

3½

3

4

3½

3½

3

2572424815

31193

3067618838

30676625935223366

3067662923425724

3624131193

3067622336

30667627854

3624131193

38575

27966

3067629593

36241

43585

27966

36241

36241

43585

6-9/64b5-55/64b

6-23/64b

6-13/32b5-59/64b

6-17/32b5-57/64b6-1/16b

6-19/32b5-61/64b6-9/64b

6-25/32b6-23/64b

6-17/32b6-5/64b

6-45/64b6-1/4b

6-25/32b6-11/32b

7b

6-33/64b

6-43/64b6-15/64b

6-3/4b

6-31/32b

6-19/32b

6-3/4b

6-27/32b

7-5/64b

3/87/16

31/64

13/6417/64

17/645/1621/64

19/6411/323/8

25/6431/64

17/6411/32

23/6427/64

25/6415/32

½

17/64

11/3223/64

3/8

31/64

19/64

3/8

27/64

35/64

2227222272

28636

1596415964

202212022120221

223492234922349

2873528735

2030820308

2572425724

2843228432

36555

19652

2489224892

27512

35373

21945

27797

30723

39501

6-3/64b5-3/4b

6-15/64b

6-11/32b5-27/32b

6-15/32b5-13/16b5-63/64b

6-33/64b5-7/8b6-3/64b

6-11/16b6-15/64b

6-15/32b5-63/64b

6-39/64b6-5/32b

6-43/64b6-15/64b

6-7/8b

6-29/64b

6-37/64b6-9/64b

6-21/32b

6-27/32b

6-1/2b

6-21/32b

6-49/64b

6-61/64b

21/643/8

27/64

11/647/32

15/649/3219/64

17/645/1621/64

11/3227/64

15/6419/64

5/163/8

11/3227/64

7/16

15/64

19/645/16

21/64

27/64

1/4

21/64

3/8

31/64

1959619596

25195

1403014030

177711777117771

196411964119641

2525325253

1786317863

2262722627

2500925009

32154

17266

2187021870

24172

31079

19288

24432

27003

34719

1 The use of outside diameters (OD) smaller than those listed in the table may be acceptable on slim Hole (SH) tool joints due to special service requirements.2 Tool joint with dimensions shown has a lower torsional yield ratio than the 0.80 which is generally used.3 Recommended make-up torque for used tool joints is based on 72,000 psi stress.4 In calculation of torsional strengths of tool joints, both new and worn, the bevels of the tool joint shoulders are disregarded. This thickness measurement should be made in the plane of the face

from the ID of the counterbore to the outside diameter of the box, disregarding the bevels.5 Any tool joint with an outside diameter less than the API bevel diameter should be provided with a minimum 1/32" depth x 45_ bevel on the outside and inside diameter of the box shoulder and

outside diameter of the pin shoulder.6 p = pin limited yield. b = box limited yield. P or B indicated that tool joint could not meet 80% of tube torsion yield.× Tool joint diameters specified are required to retain torsional strength in the tool joint comparable to the torsional strength of the attached drill pipe. These should be adequate for all services. Tool

joints with torsional strengths considerably below that of the drill pipe may be adequate for much drilling service.



GENERAL TOPICS

Figure 2.1RECOMMENDED PRACTICE FOR MILL SLOT AND GROOVE METHOD

OF DRILL STRING IDENTIFICATION



GENERAL TOPICS

Since the torsional yield strength of tool joint connections is constantly decreasing dueto wear and corrosion, selection of an appropriate make-up torque must take intoaccount the current strength of a connection. The API has developed a series ofcurves that can be used for determining the torsional yield strength of a connectionbased on its current inside and outside dimensions. These curves are included in APIRP 7G, "Recommended Practice for Drill Stem Design and Operating Limits". Forillustrative purposes the curves for NC38 (3-1/2" IF) and NC50 (4-1/2" IF) are givenin Figures 2.2 and 2.3, respectively. Application of the curves to obtain the torsionalyield strength for a particular box/pin combination can be performed as follows:

A. Select the appropriate curve for the tool joint under consideration. If needed,Table 2.2 can be used as a cross reference for interchangeable tool joints notgiven in the figures.

B. Extend a horizontal line from the tool joint box outside diameter to thetorsional strength curve and read the torsional strength from the upper scale.

C. Extend a vertical line from the tool joint pin inside diameter to the torsionalstrength curve and read the torsional strength from the upper scale.

D. The smaller of the torsional strengths determined in (2) and (3) abovebecomes the estimated torsional strength of the box/pin combination.

E. The make-up torque for the connection can now be determined by multiplyingthe value determined in (4) by an appropriate factor not to exceed 70%.

2.2.5 Alternating Breaks

Alternating breaks in the drill string during trips is an important factor in maintainingthe mechanical integrity of tool joints. By alternating breaks, inspection of the boxand pin is possible, while at the same time allowing for the application of fresh threadcompound. It is Occidental's policy to alternate breaks on successive trips, and it isthe responsibility of the DRILLING SUPERVISOR to ensure that this is beingperformed.

2.2.6 Allowable Pull

The maximum allowable pull on drill pipe is to be based on its current APIclassification and corresponding performance properties. For pipe grades other thenNEW, Table 2.3 should be used to determine the correct API classification. Once theclassification has been established, Table 2.4 can be used to determine performanceproperties.



GENERAL TOPICS

Figure 2.2NC38 (3-1/2" IF) TORSIONAL YIELD AND MAKE-UP



GENERAL TOPICS



GENERAL TOPICSTABLE 2.2

ROTARY SHOULDERED CONNECTION INTERCHANGE LIST

COMMON NAME

STYLE SIZE

PIN BASEDIAMETER(TAPERED)

THREADSPER IN.

TAPERIN./FT.

THREADFORM *

SAME AS ORINTERCHANGES WITH

2_ in. 2.876 4 2 V-0.065(V-0.038 rad)

2_ in. Slim HoleN.C. 26 **

2_ in. 3.391 4 2 V-0.065(V-0.038 rad)

3½ in. Slim HoleN.C. 31 **

3½ in. 4.016 4 2 V-0.065(V-0.038 rad)

4½ in. Slim HoleN.C. 38 **

4 in. 4.834 4 2 V-0.065(V-0.038 rad)

4½ in. Extra HoleN.C. 46 **

Internal

Flush

(I.F.)

4½ in. 5.250 4 2 V-0.065(V-0.038 rad)

5 in. Extra HoleN.C. 50 **; 5½ in. Double Streamline

Full Hole (F.H.) 4 in. 4.280 4 2 V-0.065(V-0.058 rad)

4½ in. Double StreamlineN.C. 40 **

2_ in. 3.327 4 2 V-0.065(V-0.038 rad)

3½ in. Double Streamline

3½ in. 3.812 4 2 V-0.065(V-0.038 rad)

4 in. Slim Hole4½ in. External Flush

4½ in. 4.834 4 2 V-0.065(V-0.038 rad)

4 in. Internal FlushN.C. 46 **

Extra

Hole

(X.H.)

(E.H.)

5 in. 5.250 4 2 V-0.065(V-0.038 rad)

4½ in. Internal FlushN.C. 50 **; 5½ in. Double Streamline

2_ in. 2.876 4 2 V-0.065(V-0.038 rad)

2_ in. Internal FlushN.C. 26 **

3½ in. 3.391 4 2 V-0.065(V-0.038 rad)

2_ in. Internal FlushN.C. 31 **

4 in. 3.812 4 2 V-0.065(V-0.038 rad)

3½ in. Extra Hole4½ in. E

Slim

Hole

(S.H.)

4½ in. 4.016 4 2 V-0.065(V-0.038 rad)

3½ in. Internal FlushN.C. 38 **

3½ in. 3.327 4 2 V-0.065(V-0.038 rad)

2_ in. Extra Hole

4½ in. 4.280 4 2 V-0.065(V-0.038 rad)

4 in. Full HoleN.C. 40 **

Double

Streamline

(DSL)

5½ in. 5.250 4 2 V-0.065(V-0.038 rad)

4½ in. Internal Flush5 in. Extra Hole; N.C. 50 **

26 2.876 4 2 V-0.065 2_ in. Internal Flush2_ in. Slim Hole

31 3.391 4 2 V-0.065 2_ in. Internal Flush3½ in. Slim Hole

38 4.016 4 2 V-0.065 3½ in. Internal Flush4½ in. Slim Hole

40 4.280 4 2 V-0.065 4 in. Full Hole4½ in. Double Streamline

46 4.834 4 2 V-0.065 4 in. Internal Flush4½ in. Extra Hole

Numbered

Conn

(N.C.)

50 5.250 4 2 V-0.065 4½ in. Internal Flush5 in. Extra Hole5½ in. Double Streamline

ExternalFlush (E.F.) 4½ in. 3.812 4 2 V-0.065

(V-0.038 rad)4 in. Slim Hole3½ in. Extra Hole

* Connections with two thread forms shown may be machined with either thread form without affecting gauging or interchangeability.** Numbered connections (N.C.) may be machined only with the V-0.038 radius thread form.



GENERAL TOPICS

For all Occidental operations, the maximum allowable pull on any weight or grade ofdrill pipe is to be limited to 80% of the Hook Load figures given in Table 2.4. Itshould be noted that the figures given in Table 2.4 assume zero torsional loading. Ifthe drill string is subjected to simultaneous torque and tension, a compromise willhave to be made in order to avoid exceeding the minimum yield strength of the pipebody. This is discussed in more detail in the following section.

2.2.7 Simultaneous Tension and Torque on Drill Pipe

Under normal drilling conditions the amount of tension in the drill pipe will not limitthe amount of applied surface torque (for example, rotary torque while drilling).However, there may be circumstances under which it will be operationally necessaryto simultaneously exert high tensile and torsional loads (e.g., while trying to free stuckpipe). Under these conditions the minimum torsional yield strength under tensionshould be calculated to avoid mechanical failure of the pipe. The equation for thiscalculation is as follows:

Ty = 0.096167 x (J/D) x (Ym2 - (P/A)2)½

Where: Ty = Minimum torsional yield strength undertension, ft-1bf

J = Polar moment of inertia, inches4

D = Outside diameter of pipe, inchesYm = Minimum yield strength of pipe, psiP = Total applied tensile load, 1bfA = Cross-sectional area of pipe body, sq-in.

The polar moment of inertia can be calculated as follows:

J = 0.098175 x (D4 - d4)

Where: J = Polar moment of inertia, inches4

D = Outside diameter of pipe, inchesd = Inside diameter of pipe, inches

In the torsional yield strength equation given above, the total applied tensile load (P)should be set equal to the pull exerted on the pipe at surface. The minimum torsionalyield strength (Ty) can then be calculated. The applied torque on the drill pipe shouldthen not exceed 70% of the calculated minimum torsional yield strength (Ty).



GENERAL TOPICS

TABLE 2.3CLASSIFICATION OF USED DRILL PIPE AND USED TUBING WORK STRINGS

(All Sizes, Weights and Grades: Nominal dimension is basis for all calculations)1 2 3 4

PIPE CONDITION PREMIUM CLASS 1Two White Bands

CLASS 2Yellow Band

CLASS 3Orange Band

I. EXTERIOR CONDITIONS

A. OD Wear Wall

B. Dents & Mashes

C. Slip Area Diameter Variations 1. Crushing 2 2. Necking

D. Stress Induced Diameter Variations 1. Stretched

2. String Shot

E. Cuts, Gouges & Corrosion 1. Round Bottom

2. Sharp Bottom Longitudinal

Transverse3

F. Fatigue Cracks 4

Remaining wall not less than80%

Not over 3% of OD

Not over 3% of ODNot over 3% of OD

Not over 3% of ODreductionNot over 3% of ODincrease


Remaining wall not less than80%Remaining wall not less than80% and length not over 10% ofcircumference

None


Not over 4% of OD

Not over 4% of ODNot over 4% of OD

Not over 4% of OD reductionNot over 4% of OD increase


Remaining wall not less than70%Remaining wall not less than80% and length not over 10% ofcircumference

None

Any imperfections or damagesexceeding CLASS 2

None

II. INTERIOR CONDITIONS

A. Corrosive Pitting Wall

B. Erosion & Wear Wall

C. Fatigue Cracks 4

Remaining wall not less than80% measured from base ofdeepest pit


NoneNone None

1. The premium classification is recommended for service where it is anticipated that torsional or tensile limits for Class 2 drill pipe and tubing workstrings will beexceeded. These limits for premium Class and Class 2 drill pipe are specified in Tables 2.4 and 2.6 respectively. Premium Class shall be identified with two whitebands, plus one center punch mark on the 35° sloping shoulder of the tool joint pin (or the 18° sloping shoulder of the pin, if the 18° angle is furnished).

2. Inspection of this condition should be made to detect presence of longitudinal and transverse cracks inside and outside.3. May be ground out along longitudinal axis not to exceed value for round bottom cuts or gouges as shown in i.e. 1 of this table and such grinding to be approximately

faired into outer contour of the pipe. The longitudinal length of grinding in the slip area shall not exceed 1½” for Premium Class or 2½” for Class 2.4. In any classification where fatigue cracks or washouts appear, the pipe will be identified with the red band and considered unit for further drilling service.5. An API RP 7G inspection cannot be made with drill pipe rubbers on the pipe.



GENERAL TOPICS

TABLE 2.4HOOK-LOAD AT MINIMUM YEILD STRENGTH FOR NEW, PREMIUM CLASS

(USED), AND CLASS 2 (USED) DRILL PIPE



GENERAL TOPICS

TABLE 2.4 (continued)HOOK-LOAD AT MINIMUM YEILD STRENGTH FOR NEW, PREMIUM CLASS

(USED), AND CLASS 2 (USED) DRILL PIPE



GENERAL TOPICS

TABLE 2.4 (continued)HOOK-LOAD AT MINIMUM YEILD STRENGTH FOR NEW, PREMIUM CLASS

(USED),AND CLASS 2 (USED) DRILL PIPE



GENERAL TOPICS

2.3 Drill Pipe and Bottom Hole Assembly Inspection and Specification

2.3.1 Drill String Records

CONTRACTOR shall furnish records to show the history of the drill pipe and otherdrill string components owned by CONTRACTOR, including details of age, numberof premium joints remaining out of the original drill-pipe string, total footage drilled,total time stored prior to mobilization, exposure to H2S or CO2, jarring, or acidizing.The records shall also include a summary of number and depth of wells drilled, anytwist offs or washouts experienced in wells drilled with the string, and of directionalwells drilled with the string, including details of well inclinations and maximum doglegseverity encountered.

2.3.2 Frequency of Inspections

A. Within thirty (30) days prior to mobilization of the drilling unit to a single wellprogram or to the first well of a multi-well program, all drill pipe, drill collars,drill-stem subs, tool joints, heavy-wall drill pipe, stabilizers, hole openers,underreamers, drilling jars, roller reamers, and other downhole tools furnishedby CONTRACTOR shall be inspected by a third party inspection company,as outlined herein, at CONTRACTOR's expense, and CONTRACTOR shallprovide OXY with a copy of the third party inspection report. OXY mayrequire that inspections be witnessed by a OXY representative, at OXY'sexpense.

B. Thereafter, all drill pipe furnished by CONTRACTOR and used in hole sincethe last third party inspection shall be inspected after one thousand fivehundred (1,500) rotating hours or thirty thousand (30,000) feet, whicheveroccurs first, by a third party inspection company, as outlined herein, atCONTRACTOR's expense, and CONTRACTOR shall provide OXY with acopy of the third party inspection report.

C. Thereafter, all drill collars, drill-stem subs, tool joints, heavy-wall drill pipe,stabilizers, hole openers, underreamers, drilling jars, roller reamers, and otherdownhole tools furnished by CONTRACTOR shall be inspected after thenumber of rotating hours as given below by a third party inspection company,as outlined herein, at CONTRACTOR's expense, and CONTRACTOR shallprovide OXY with a copy of the third party inspection report.

Frequency of inspections conducted by the CONTRACTOR as directed byOXY (at OXY's expense) may be increased if fatigue failures occur between



GENERAL TOPICS

inspection, and decreased if no failures occur and no cracks are detectedbetween inspections.

D. OXY may require that inspections be witnessed by a OXY representative.

2.3.3 Inspection Requirements

A. Drill Pipe

1. Tube Body:

a. Tube body shall conform to API Class 1 or API PremiumGrade as specified in API-RP-7G (current edition at Contractdate).

b. Require the location and recording of previous inspectionclassification markings. Pipe shall be marked and API colorcoded on each and every inspection. Record size, weight, andgrade of tube body.

c. Inspection to be performed per "Standard DS-1, Drill-StemDesign and Inspection" ("DS-1"), most recent edition.

2. Tool Joint:

a. Tool joint shall match tube body and conform to API Class 1or API Premium Grade as specified in API-RP-7G and APISpecification 7 (current editions at Contract date).

b. Require the recording of manufacturer's markings stenciled atthe base of the pin or on the mill slot showing companysymbol, month welded, year welded, pipe mill, and drill-pipegrade. Tool joints to be API color coded on each and everyinspection. Record size and type of tool joint.

c. Inspection per latest edition of DS-1.

B. Heavy-Wall Drill Pipe

1. Tube Body and Center Wear Pad:Inspection per latest edition of DS-1.



GENERAL TOPICS

TABLE 2.1

Bottom-Hole Assembly Inspection Frequency

Well Depth Rotating Hours

Vertical Holes 0 - 10,000' 400

Vertical Holes 10,000 - 15,000' 300

Vertical Holes >15,000' 200

Directional Holes Adjust hole values based on Table 2.2

TABLE 2.2

Correction Factors for Bottom-Hole Assembly Inspection Frequency

Severity of Use

Wear Category 1 2 3 4

Deviation(degrees)

0 - 5 5 - 10 10 - 20 >20

Dogleg(degrees / 100')

0 - 2 2 - 2.5 2.5 - 3 >3

Torque Normal Above Normal High Very High

CorrectionFactor

1.00 0.90 0.80 0.70

2. Tool Joint:

a. Tool joints shall conform to API Class 1 or API PremiumGrade as specified in API-RP-7G and API Specification 7,(current editions at Contract date). Tool-joint pins shall haveAPI stress-relief groove and tool-joint boxes shall have bore-back feature, both of which shall have antigall coating. Threadroots on 4-1/2 inch HWDP and larger to be cold rolled.

b. Inspection per latest edition of DS-1.C. Drill Collars



GENERAL TOPICS

1. Tube Body:

a. Drill collar outside diameters to conform to the provisions ofAPI Specification 7.

b. Inspection per latest edition of DS-1.

2. Rotary-Shouldered Connection:

a. Rotary-shouldered connection shall conform to API-RP-7Gand API Specification 7 (current edition at Contract date), andshall have a bending strength ratio greater that 2.25 and lessthan 3.50. Bending strength ratio shall be equal to or greaterthan 2.5 for drill collars having outside diameters of 6.125" orlarger and 2.25 or greater for outside diameters less than6.125". Rotary-shouldered pins shall have API stress-reliefgroove, and boxes shall have bore-back feature, both of whichshall have antigall coating. Thread roots on drill collars 6-1/4in. OD and larger to be cold rolled.

b. Inspection per latest edition of DS-1.

D. Drill-Stem Subs

1. Drill-stem subs shall conform to API-RP-7G and API Specification 7and (current editions at Contract date). Record size, type, and BSR ofconnections.

2. All drill-stem subs require dry magnetic particle inspection of entiretool body to detect fatigue cracks.

3. All drill-stem subs shall be inspected per latest edition of DS-1.

Note: All crossover subs should be 60 inches long ±12 inches forsubs 8 inches OD or larger, 48 inches long ±12 inches forother subs to ensure proper stress distribution and correctmakeup torque. Bottleneck crossover subs should have aminimum 24-inch neck.



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E. Stabilizers, Roller Reamers, Hole Openers, Underreamers, Drilling Jars, andOther Downhole Tools

1. Tool Body: Require full-length magnetic particle inspection to detectfatigue cracks.

2. Rotary-Shouldered Connections: All downhole tools connected to drillcollars shall conform to specifications and inspections given for drillcollars elsewhere in this Schedule.

F. General

1. Recut Connections: Must be to manufacturer's original specifications.

2. Additional Ultrasonic Inspection: Ultrasonic Inspection of BHAconnections may be required to supplement wet magnetic particleinspection subsequent to the critical inspection.

3. Non-magnetic drill collars and other non-magnetic BHA Components: Must be inspected for magnetic "hot-spots" at least annually, atCONTRACTOR's expense.

2.3.4 Used Drill Pipe Marking and Classification

Used drill pipe is to be classified as per API Recommended Practice 7G (RP7G),Recommended Practice for Drill Stem Design and Operating Limits.

2.4 Prevention of Ingress of Hydrocarbons into Rig Systems

It is the responsibility of the Drilling Supervisor to ensure that wellsite operations are plannedto prevent the release of hydrocarbons into rig operating systems. This can generally beaccomplished through the use of isolation valves (gate valves and/or check valves) and standalone operating systems (for example, surface well test equipment).

Although thorough planning and well designed operational procedures will normally ensurea high degree of rig safety, it must be stressed that no degree of advance planning can replacethe judgement of the Drilling Supervisor. Only he can ensure that systems have been riggedup or installed to prevent the ingress of hydrocarbons into rig systems.



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For all installations involving the attachment of operational equipment (e.g., BOPs, flow lines,lubricators, etc.) to live wells, the Drilling Supervisor is to personally inspect the final rig-upprior to commencing operations. In general, the following guidelines and instructions are tobe followed closely.

2.4.1 Check Valve Manifold Required

When the rig pumps, cementing pump, or any other pumping equipment is attachedto a well for the purposes of killing the well, stimulation, pressure testing, etc., acheck valve manifold must be installed between the pump and the well. It is theresponsibility of the job supervisor to ensure that the installation of a check valvemanifold has been completed prior to giving approval to work on the well.

The check valve manifold is to be installed as close as practicable to the well toprevent the entry of hydrocarbons into the test line. A typical layout for a check valvemanifold is illustrated in Figure 2.4. Installation of the check valve manifold shouldbe performed according to the following procedure:

A. Close-in the well at the point where the check valve manifold is to be installed.For example, close in the casing head valve if tying into the annulus, or thewing valve, if tying into the wing section.

B. Connect the bleed-off line to a pre-selected bleed-off point. This can be a flareline, test separator, or other suitable discharge point provided the pressure onthe bleed-off line can be reduced to zero.



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If a bleed-off facility is not required, the bleed-off outlet is to be bull-pluggedto prevent the escape of hydrocarbons or pressurized fluids into theatmosphere.

If a bull-plug has been installed and must be removed, open the bull plugneedle valve and remove the plug slowly to ensure that no pressure has beentrapped behind the plug.

C. Pressure test the check valve manifold and all lines between the pump andwellhead valve to 3000 psi or the working pressure rating of the system,whichever is greater. Prior to conducting this pressure test it must be ensuredthat the pressure rating of all system components meets or exceeds theplanned test pressure. Hold test pressure for a minimum of 5 minutes.

D. To ensure the check valve will hold pressure, bleed-off line pressure on thepump side of the check valve and trap test pressure between the wellheadvalve and the check valve. Hold test pressure for a minimum of 5 minutes,then release pressure through bleed-off line.

E. Open the wellhead valve and perform pumping operations as dictated byoperational procedure.

F. If, following the completion of pumping operations, pressure has been trappedon the check valve manifold, close-in the wellhead valve and release trappedpressure to the bleed-off line.

2.4.2 Operating Valve Required on Kill Line(s)

When rigging up to kill a well, any lines installed on the tubing annulus must containat least one operating valve independent of the wellhead gate valves. Under nocircumstances are the wellhead valves to be used as operational valves during the killoperation. These valves are to be set to either the OPEN or CLOSED position.

2.4.3 Flow From Well Must Go Through a Choke

If returns from the well are to be taken up the tubing annulus through a side outlet,flow must be taken through a dedicated valve manifold incorporating a flow controlchoke. On offshore or pad drilling areas, this facility may be provided through the useof an adjoining Christmas tree by tying into the service wing valve. Choking of wellfluids must not be performed with plug valves, gate valves, or any valve for thatmatter.

2.4.4 Dedicated Bleed-Off Line Required



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During well stimulation operations, trapped pressure must be released through adedicated bleed-off line and not to the high pressure kill/test pump. The test line fromthe high pressure pump is to be fitted with a check valve positioned as close aspossible to the tie-in point on the well.

2.4.5 Air and/or Steam Supply During DST to be Independent of Rig System

During drill stem testing operations, the air supply to the burner heads is to befurnished by an independent air compression system complete with self containedpower supply. Under no circumstances is the rig air supply system to be utilized tosupply compressed air to the burner heads. In addition, if a steam heat exchanger isrequired in the production system, supply steam is to be furnished by an independentsteam generator. Under no circumstances is the rig's steam generating system to betied into the well test system.

Air and steam supply to burner heads and steam generators for DSTs and flow testsmust be supplied from air compressors and/or boilers located in "open air" conditions. This is to prevent flowing hydrocarbons from accidentally flowing back through theair and/or steam lines and becoming trapped in an enclosed space.

2.4.6 Check Mud/Gas Separator Operation

The Drilling Supervisor is to inspect the operation of the mud/gas separator prior tospudding any well. It must be ensured that the unit is functioning properly and iscapable of handling choked well fluids under the anticipated worst case well controlconditions for the well being drilled. To aid in the assessment of this equipment, theDrilling Supervisor is to furnish the Drilling Superintendent with a layout drawing ofthe system indicating fluid inlets and outlets, mud discharge point, emergency by-passfacility, pipe work dimensions, etc. Refer to Section VI, Well Control Equipmentand Materials for mud/gas separator design considerations.

2.5 Wellhead Equipment Handling (Offshore)

Wellhead equipment handling in the context of this section shall refer to the shipping, storage,maintenance, lifting, and installation of surface and sub sea wellhead equipment that has beenshipped offshore and is intended for immediate or near term use. Adherence to theprocedures and guidelines detailed below will result in minimum down time due to physicaldamage and enhance the long term serviceability of this equipment.

FIGURE 2.4



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5000 psi WORKING PRESSURE CHECK VALVE MANIFOLD(TYPICAL ARRANGEMENT)



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2.5.1 Shipped in Packing Crates

New surface and subsea wellhead equipment is to be shipped offshore in packingcrates furnished by the original equipment manufacturer. These crates must providesufficient physical support to constrain the particular component. Alternatively, thisequipment may be transported in purpose built transportation frames, providedadequate protection of the assembly is ensured. Exception to these guidelines will beallowed for large subsea wellhead assemblies; however, end connections and sealareas must be adequately protected. In addition, seal areas and bare metallic surfacesare to be protected against corrosion damage with a suitable shipping/storage rustpreventative which will not become fluid and run at a temperature below 150º F. Forcold climates this temperature may be modified as required. Once components reachan offshore location, they are to be removed from the shipping container andinspected for damage and missing parts.

2.5.2 Wellhead and Christmas Tree Tools

Wellhead and Christmas tree running, pulling, and test tools are to be shipped inaccordance with the guidelines outlined above. Upon arrival at an offshore location,this equipment is to be inspected for damage and missing parts, and stored in asuitable location.

2.5.3 Steel Ring Gaskets and Elastomeric Seals

Steel ring gaskets and elastomeric seals (e.g., 0-rings, pack-off seals, etc.) are to beshipped offshore in protective packaging and labeled with identifying part numbersand descriptions. It must be remembered that all elastomeric seals have a finite shelflife and will eventually lose mechanical properties due to atmospheric decomposition.For this reason the storage climate for elastomeric seals must be carefully controlled. It is the responsibility of the drilling supervisor to ensure that seals that have agedbeyond the manufacturers recommended shelf life are not placed into service.

2.5.4 Transporting Wellhead Equipment on the Rig

Wellhead equipment is to be hoisted and installed in a controlled manner. Movementaround the platform or rig will, of course, be accomplished with cranes. This includesplacement on the drill floor or spotting in the moon pool area as required. If airoperated winches are used to lift or skid equipment it must be ensured that the winchis rated to handle the anticipated loading conditions.

2.5.5 Vertical Lifts of Wellhead Equipment and Christmas Tree



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Vertical lifts to remove or install wellhead equipment and Christmas tree assembliesmust be performed with the rig drawworks using purpose designed lifting slings,lifting subs, or running and pulling tools. These heavy lifts are not to be performedusing air operated winches and randomly selected lifting appliances. This applies tosurface as well as subsea equipment. However, in certain cases small lifts may beperformed with an air operated winch provided the winch is rated for the load,suitable lifting appliances are available, and the load can be handled in a controlledmanner.

2.6 Washout Detection

The techniques used for the detection of drill string washouts require the measurement andrecording of surface pressures at predetermined rates PRIOR to the occurrence of a washout.If these measurements have not been performed in advance, the likelihood of early washoutdetection is significantly diminished.

While drilling ahead, the driller should periodically measure the off-bottom pump pressure atthree fixed pump rates. One pressure is to be measured at the full drilling pump rate and twoothers taken at reduced pump rate; for example, 1/2 and 1/4 full rate. The number of pumpstrokes and corresponding standpipe pressures are to be carefully measured and recorded.Ordinarily the slow circulating pressures measured for well control purposes can be used forthe reduced pump rates.

These pressure measurements are to be performed according to the following schedule, ormore frequently if desired.

• Once per tour.

• Following any change in mud properties that would significantly effect standpipepressure; for example, density, PV, YP.

• Following any change in bottom-hole assembly.

Basically, these pressures should be measured according to the schedule establishedfor the measurement of slow circulating pressures.

2.6.1 Surface Pressure Check

If a washout is suspected, immediately proceed with evaluation of the problem. Continued pumping will only aggravate the condition and result in possible parting ofthe drill string.A. If a washout is suspected, stop pumping and pick-up off bottom. Have mud

engineer check mud weight, PV, and YP.



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B. Close the kelly valve and, using one mud pump, pressure test the pumpdischarge manifold, mud line, and standpipe manifold to maximum surfacepumping pressure used while drilling.

C. If the surface lines hold pressure, release test pressure and open kelly valve.Proceed with slow pump pressure checks.

2.6.2 Slow Pump Pressure Check

A. Bring one pump on line and measure standpipe pressure at the previouslyestablished slow circulating rates. Then bring both pumps online and measurethe standpipe pressure at full pump rate.

B. Based on these pressure measurements, the following conclusions can bedrawn:

1. If the mud properties are unchanged, and if the current pump pressureis the same at the lowest rate while decreasing from the previouslymeasured figures at the higher rates, the drill string is probably washedout. For example, the following pressure differences would indicatea washout:

Slowest rate pressure difference = zero psiSecond rate pressure difference = 40 psiFull rate pressure difference = 150 psi

2. If the plastic viscosity (PV) and yield point (YP) are significantly lower(at least 10%) than when the slow pump pressures were initiallymeasured, and there are significant pressure differences at all rates,then the pressure loss is probably due to the change in mud properties.For example, for a 30% reduction in PV and YP, the followingpressure profile would by typical:

Slowest rate pressure difference = 45 psiSecond rate pressure difference = 80 psiFull rate pressure difference = 150 psi

Note: In this case significant pressure differences are measured at theslow rates, whereas this was not true for the washout examplegiven in (a) above.

3. If a mud density decrease has been experienced, the new standpipepressure and reduced circulating pressures can be readily calculatedusing the following expression:



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Pn = (MWn/MWo) x Po

Where: Pn = new pump pressure, psiMWn = new mud density, ppgMWo = old mud density, ppgPo = old pump pressure, psi

This expression will be reasonably correct at all pump rates; however,it is only an approximation. For example, if a 9.5 ppg mud wasreduced by 0.1 ppg to 9.4 ppg, the following pressure differenceswould be typical:

Slowest rate pressure difference = 2 psiSecond rate pressure difference = 12 psiFull rate pressure difference = 44 psi

For greater mud weight reductions the pressure differences would becorrespondingly greater.

2.6.3 Bottom-Hole Assembly Testing

The bottom-hole assembly can be tested for washouts in a manner similar to theprocedure used for testing the entire drill string. Again, it will be necessary to havemeasured the circulating pressures through the BHA while it was being run into thewell.

2.6.4 Washout Locator Sub and Dart

If a washout locator sub has been run in the drill string this device can be used todetermine if a suspected washout is in the drill pipe or BHA. This sub is normally runat the top of the drill collars as the crossover from drill collar to drill pipe threads.However, a second sub could be run in the middle of the drill pipe on deeper wells asa further aid in isolating a washout. The primary advantage of the tool is proving thepressure integrity of the drill pipe, thereby avoiding a wet trip until the drill collars arepulled.

If a washout locator sub is in the drill string, the following procedure and operationalguidelines are to be followed if a washout is suspected.A. Pull drill string wet until hole conditions are acceptable for dropping washout

locator dart (i.e., no tight hole, sticking or other adverse hole conditions).



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B. If necessary, redress washout locator dart. Shear pin setting should be +/-1750 psi. Check condition of O-ring seals and replace as required.

C. Check to be certain the minimum I.D. through the drill string from surface tothe locator sub is at least 3.00" (washout locator dart O.D. = +/- 2.750").Drop washout locator dart and pump tool down drill string as would be donewith a survey barrel. Work pipe as necessary to prevent sticking. Reducepump rate prior to seating dart in locator sub.

D. When dart lands in locator sub, stop pumps, then increase surface pressure insmall increments to 1500 psi. Hold pressure at 1500 psi for 2 - 3 minutes todetermine if washout is above or below locator sub. Based on pressure test,proceed as follows:

1. If drill pipe holds pressure, washout is below locator sub (i.e., thereis no need to pull drill pipe wet since washout in drill string is belowlocator sub). Increase surface pressure to +/- 1750 psi to shear openby-pass sleeve in washout locator dart. Pump slug and POOH tolocator sub following normal tripping procedures. Pull BHA belowlocator sub looking for washout.

2. If drill pipe does not hold pressure, washout is in drill pipe above thelocator sub. DO NOT shear open by-pass sleeve in washout locatordart at this time. POOH wet looking for a washout. Once bad joint hasbeen located, pressure test string again by increasing surface pressurein small increments to 1500 psi. If string holds pressure, increasesurface pressure to +/- 1750 psi to shear open by-pass sleeve inwashout locator dart. Recover dart on slickline using survey barrelretrieving tool. Proceed with normal drilling operations.

2.6.5 Drill String Test Sub

If the drill string is recovered to locate a suspected washout and this operation hasbeen unsuccessful, it may be necessary to run a drill string test sub to locate thewashout. The drill string test sub is made-up to the bottom of the drill string and thepipe is run into the well in stages. At each stopping point, the drill string is pressuretested against the test sub. This operation is repeated until the washout is located.

2.7 Drill Pipe Tally

Accurate dimensional records are to be maintained for the drill pipe and bottom-hole assemblyat all times. This includes measurements of overall length, tool joint O.D. and I.D., and fishing



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neck length. Drilling tools with multiple connections (e.g., jars, turbines, MWD tools, etc.)should be sketched out and dimensioned in sufficient detail to enable selection of appropriatefishing tools in the event of a twist-off.

The number of joints of drillpipe and BHA components on the drilling location must beknown at all times. This may help alleviate drill string tally discrepancies by totaling the drillstring on surface and subtracting this from the total on the location to check the number ofjoints in the hole.

In addition to the drillers tallied depth, the drilling assembly is to be measured in stands priorto commencing the following operations: running casing, logging, and coring. The drill stringshould also be measured in stands anytime there is doubt about the current drilled depth whichcannot be reconciled by review of the drillers tally. All depth corrections are to be noted onthe Occidental and IADC daily drilling reports. In addition, the following guidelines are tobe followed:

2.7.1 Measurement on Deck

When preparing the pipe tally record for a particular well, the length of each joint ofdrill pipe and each BHA component is to be measured on the pipe deck, and thismeasurement, along with the joint serial number, is to be entered in the drill pipe tally.These measurements are to be used for calculating actual drilled depth.

2.7.2 Master Talley Book

The master drill pipe tally book is to be kept in the dog-house and updated by theDriller throughout his shift.

2.7.3 Daily Check of Pipe Talley

A daily check of the drill pipe tally is to be made by the contractToolpusher/Superintendent. The Driller's tally is to be reconciled against the totalnumber of joints of drill pipe on the rig.

2.7.4 Record Depths – Geolograph

When drilling or reaming, connection depths are to be noted on the Geolograph at thetime of the connection.



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2.7.5 Daily Check Total Drill Pipe on Location

The Occidental Drilling Supervisor and contract Toolpusher are to make a dailyphysical inspection of the total quantity of drill pipe on the rig. In addition, they mustboth be informed of any transfers of drill pipe to or from the rig.

2.7.6 Strap Prior to Fishing

The drill string is to be strapped while running in the hole with any fishing tools.

2.7.7 Strapping Frequency

The drill string is to be strapped at least every 10 days, or more frequently if dictatedby operational considerations as outlined above.

2.8 Casing and Tubing Markings

2.8.1 Groups

Casing and tubing is to be marked as per API Spec 5CT. The following is a summaryof the main points of API Spec 5CT. Refer to the API Spec 5CT for furtherinformation.

Group 1 All casing and tubing in grades H, J, K, N.Group 2 All restricted yield strength casing and tubing in grades C & L.Group 3 All high strength casing and tubing in grade P.Group 4 All special service casing in grade Q

2.8.2 Die Stamp Markings

Die stamp markings shall be placed on the outside of the pipe within 12 inches (305mm) from the coupling or box, or externally threaded end, or either end of plain-endpipe.

The sequence of die-stamped markings shall be as follows:

Manufacturer's/Processors name or markSpec 5CTSymbol UF (if applicable) (for unfinished, plain end pipe)Weight per foot (pounds per foot)Grade of pipeProcess of manufacture, except for group 3 (S = seamless, E = electric weld)



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Examples:

A. 7 in 26 lb grade P-110, open hearth ( or electric furnace) =AB CO SPEC 5CT 26 P

B. 2-7/8" 6.4 lb grade P-105, open hearth ( or electric furnace) = AB CO SPEC 5CT UF 6.4P

2.8.3 Paint Stencil Markings

Paint stenciled markings shall be placed on the outside surface of each length of pipestarting not less than 2 feet (0.61 m) from the coupling or box, or externally threadedend, or either end of plain end pipe. For connectors and short length pup joints, therequired paint stencil markings may be placed on a decalcomania attached to theoutside surface within 12 inches (0.30 m) from the end. These markings shall beseparated by a dash or shall be adequately spaced. The sequence of paint-stenciledmarkings shall be as follows, except the length, total weight, and type of threadmarking shall be paint-stenciled on the pipe at a location convenient to themanufacturer or processor.

SizeWeight per foot (pounds per foot)Grade of pipeProcess of manufacture (S = seamless, E = electric weld)Hydrostatic test pressure

For Group 4 the following paint stenciled markings are required in the followingsequence:

Manufacturer's/Processors name or markSpec 5CTSymbol UF (if applicable) (for unfinished, plain end pipe)SizeWeight per foot (pounds per foot)Grade of pipeProcess of manufacture (S = seamless, E = electric weld)Hydrostatic test pressureLength (English and/or metric units)

2.8.4 Color Code Identification



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A. Group 1, Group 3, Group 4. In addition to the required markings as specifiedabove, each length of casing and tubing shall be color coded by one or moreof the following methods.

1. A paint band encircling the pipe at a distance not greater than 2 ft(0.61m) from the coupling or box.

2. A paint band encircling the center of the coupling.

3. Paint entire outside surface of coupling.

4. For pup joints shorter than 6 feet (1.83m) in length, the entire surfaceexcept the threads shall be painted.

The color and number of bands shall be as follows:

a. Grade H-40 No color marking, or black at themanufacturer's option

b. Grade J-55 One bright green band

c. Grade K-55 Two bright green bands

d. Grade N-80 One red band

e. Grade P-105 White

f. Grade P-110 White

g. Grade Q-125 Orange

B. Group 2

1. A paint band or bands encircling the pipe at a distance not greater than2 ft (0.61m) from the coupling or box.

a. Grade C-75 One blue band

b. Grade C-75, 9Cr One blue band and two yellow bands

c. Grade C-75, 13 Cr One blue and one yellow band

d. Grade L-80 One red band and one brown band



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e. Grade L-80, 9Cr One red and one brown and two yellowbands

f. Grade L-80, 13Cr One red and one brown and one yellowband

g. Grade C-90 One purple band

h. Grade C-95 One brown band

2. A paint band or bands encircling the center of the coupling.

a. Grade C-75 One blue band

b. Grade C-90 One purple band

c. Grade C-95 One brown band

3. Paint entire outside surface of coupling. The color shall be as follows:

a. Grade C-75 Blue

b. Grade C-75, 9Cr Blue with two yellow bands

c. Grade C-75, 13Cr Blue with one yellow band

d. Grade L-80 Red with brown band or longitudinalstripe

e. Grade L-80, 9Cr Red with two yellow bands

f. Grade L-80, 13Cr Red with one yellow band

g. Grade C-90 Purple

h. Grade C-95 Brown

4. For pup joints shorter than 6 feet (1.83m) in length, the entire surfaceexcept the threads shall be painted.

C. Special Clearance Couplings. Special clearance couplings shall be painted thecolor indicative of the steel grade from which the couplings are manufactured,and shall also be painted with a black band around the center.



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2.8.5 Thread Marking - All Groups

A. Casing (short round thread) CSG

B. Casing (long round thread) LCSG

C. Casing (buttress thread) BCSG

D. Casing (extreme-line) XCSG

E. Tubing (non-upset) TBG

F. Tubing (external-upset) UP TBG

G. Tubing (integral-joint) IB TBG

Buttress Thread Marking

Unless otherwise specified on the purchase order, the triangle mark in buttress casingmay be replaced with a transverse 3/8" wide white paint band, 3 in. ± long, around thepipe. A 1 in. ± wide, 12 in. long white paint stripe shall be oriented longitudinally ofthe tube, adjacent to the above band to assist in locating the band.

2.9 Handling of Casing and Tubing

The tubular handling procedures outlined in this section are for casing and tubing stringsroutinely used by Occidental. These procedures may be inadequate for critical serviceapplications. Under these circumstances the reader is referred to the Drilling Program forguidance.

2.9.1 Shipping

All casing and tubing is to be handled and shipped with suitable box and pin endthread protectors installed. Once the tubulars have reached the rig site they are to bestacked in layers supported by wooden sills spaced at +/- 10 ft. intervals. If multipleweights and grades of pipe are being used, they should be arranged to accommodatethe planned running order.

2.9.2 Field Inspection

All tubulars are to be visually inspected for thread and/or body damage, drifted, andtallied prior to installation in a well. Thread protectors are to be removed, and thethreads cleaned of thread compound and grease with varsol or other suitable solvent.



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The threads are then to be cleaned with a high pressure jet washing system, followedby high pressure air to remove residual water.

Once the threads are thoroughly clean, a suitable thread compound is to be appliedto both the box and pin ends. If it is necessary to re-install thread protectors prior torunning the pipe in a well, the protectors are to be thoroughly cleaned before use. Anypipe not passing inspection is to be set to one side and appropriately labeled.

Thread damage is to be identified with a 2 inch wide band of red paint appliedadjacent to the pin end or around the box of affected threads. All tubulars are to befull length drifted to API drift specifications (see Table 2.5) unless a special driftdiameter is indicated in the Drilling Program. If a length of pipe will not pass the drifttest, a single 2 inch wide band of green paint should be applied at the point of driftrestriction. All tubulars failing field inspection are to be so noted on the materialsmanifest for return shipment to the Occidental pipe yard.

Table 2.5: API Drift DimensionsDrift

Nominal O.D. Diameter LengthProduct (inches) (inches) (inches)

Casing and Liners 8-5/8 and smaller I.D. - 1/8 6(See note I)

9-5/8 to 13-3/8 I.D. - 5/32 12

16 and larger I.D. - 3/16 12

Tubing 2-7/8 and smaller Refer to Supplemental WellProgram for drift

3-1/2 and larger requirements

I - Not applicable to Extreme-Line casing. Refer to Well Program.



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2.9.3 Handling Tools

Long strings of casing and tubing are to be run using slip type elevators and spiders.The elevators are to be sized to allow for anticipated hole drag and overpullrequirements. Until sufficient string weight is available to use this equipment, collarpull elevators are to be used in conjunction with conventional rotary casing slips anda safety clamp. All slip and elevator assemblies are to be closely inspected by theDrilling Supervisor for wear related damage. Particular attention should be given toinsert die slots and die segments, slip bowl tapers and diameters, and slip wedgetapers. See Figures 2.5 through 2.10 for critical inspection areas.

The pipe is to be picked-up off the cat walk with single joint pick-up elevators sizedfor the casing and coupling being run. It should be noted that single joint pick-upelevators are designed to accommodate not only pipe body diameter, but alsocoupling design. Check to make certain the correct elevators have been supplied. Inaddition, all pipe is to be picked up using quick release thread protectors.

2.9.4 Running Procedure

Casing and tubing is to be run in accordance with the running procedure detailed inthe Supplemental Drilling or Completion Program. The running procedure will specifythe position of completion equipment, pipe weights and grades, and make-up torques,as applicable. In all cases a suitable casing or tubing thread compound is to beapplied.

Thread compounds are to be selected based on the anticipated service conditions andthe type of connection being run. In general, thread compounds meeting therequirements of API Bulletin 5A2, Sixth Edition, "Bulletin on Thread Compounds forCasing, Tubing, and Line Pipe" should be acceptable. If a non-API thread compoundis required, it will be specified in the Drilling Program.

The Drilling Supervisor must ensure that all casing running tools have been properlyrigged-up. This includes the position and orientation of snubbing lines and torquegauges attached to the power tongs. In addition, the rig floor should be organizedand equipped to handle the size of pipe being run. In particular, the following pointsshould be considered:

A. Is the fill-up line conveniently located to allow for pipe filling withoutinterrupting pipe handling operations?

B. Can the make-up tongs be easily moved into position and operated from a safework platform?



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C. Has a hold back line been fitted to restrain large diameter pipe as it is broughtthrough the V-door?

D. Has the work platform been positioned to allow for easy stabbing of tubulars.

E. Is the stabbing board properly positioned and equipped with safety equipment?

F. Is the snub line on the make-up tong the correct length?

G. Has the back-up tong been fitted with the correct size jaws for the casing tobe run?

2.9.5 Welding on Casing or Tubing

Field welding on tubing and other well tubular goods for any reason is notrecommended and should be avoided. The only exception is a welded, slip-on casinghead where proper procedures are followed. This is normally performed on low gradesurface casing using the appropriate pre-heat/post-heat technique.

Welding on high grade casing and casing hangers of N-80 and above is strictlyprohibited in the field. This unnecessary practice can promote premature failure wheninternal, compressive or tensile loads are imposed.

Tack welding casing couplings, float equipment and stage cementing collars toprevent inadvertent back-off on casing grades of K-55, J-55 and lower has beencustomary where welding is deemed non-hazardous; however, this practice is notrequired when alternate preventive methods are available.

Thread locking compounds are recommended and can be used effectively in most allfield environments for coupling integrity and resistance to back off problems. In theinterest of cost saving and reduction of rig time, specific joints can be prepared in asuitable facility prior to sending to the field. In either case, the threads must bethoroughly cleaned, the locking compound applied evenly and the joint immediatelytorqued to the specified value.

2.10 Certifiable Drilling Equipment

Certification requirements vary from location to location. It is outside the scope of thisdocument to cover the certification requirements for each country of operations.



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You must be aware of the certification requirements for your country of operations andyou MUST COMPLY with certification regulations for your local area of operations.

2.11 Stock Rotation and Storage

A planned program of stock rotation is to be followed for all consumable materials with afinite shelf life. This is particularly true for materials incorporating the use of elastomericcompounds.

It is the responsibility of the drilling supervisor to ensure that materials are stored in a suitablelocation and protected from mechanical and atmospheric damage. The following textprovides general guidelines for meeting this requirement.

2.11.1 Elastomeric Materials

Elastomeric materials typically employed in drilling operations include O-ring seals,chevron seals, specialty tool packing elements, pack-off seal elements, packer seals,and cementing plugs. The storage environment is critical to the shelf life and in-service performance of these materials.

Due to their composition, elastomeric materials are in a constant state ofdeterioration, regardless of storage environment. This deterioration process issignificantly accelerated in the presence of adverse atmospheric conditions. Theaging and loss of mechanical properties of any rubber good will be directly effectedby the following factors:

- Direct light, especially sunlight, which contains ultraviolet rays - drasticallyaccelerating the aging process.

- Ozone in the atmosphere, which reacts with elastomers and accelerates aging.For this reason, rubber goods should never be stored in the vicinity ofelectrical equipment due to the presence of Ozone in these areas.

- Heat, which results in the gradual hardening of rubber products, especially inthe presence of Ozone and Oxygen in the atmosphere.

For the above reasons rubber goods are to be stored as follows:

A. Store all rubber goods in a dark place, preferably indoors and away for director indirect sunlight, windows, drafts, and direct artificial lighting.



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B. Store rubber goods in a cool location, preferably maintained at +/- 65º F andaway from heaters, electrical machinery, or any high voltage equipment.

C. Maintain the storage area as dry as possible. Oils, grease, dope, solvents, orother damaging fluids should be stored in a separate location to avoid spillageand/or contamination.

D. Do not store new and used rubber goods in the same package or in a mannerthat will result in direct physical contact. Used materials may have beenexposed to chemicals that would adversely impact the aging process.

E. Store rubber parts in their natural shape. Do not hang O-ring or similarlyshaped seals on nails or hooks.

F. If possible, store rubber goods in sealed containers, or cover with a protectiveshield impervious to temperature or light when storing for long periods.

G. Use rubber goods on a first-in, first-out basis.

H. Do not over-stock rubber goods for offshore use.

2.11.2 Casing Hanger Pack-Offs

In general, casing hanger pack-offs incorporating the use of elastomeric sealingelements are to be stored in accordance with the guidelines given in Part 2.10.1above. However, certain pack-off assemblies may incorporate the use of threadedcomponents which will require application of a protective lubricant to preventthread profile corrosion. In these cases the manufacturer is to be consulted forrecommendation of an acceptable lubricant. Randomly selected lubricants are notto be used due to possible adverse reaction with elastomeric seals.

As with rubber goods, pack-off assemblies are to be used on a first-in, first-outbasis. In addition, these materials are not to be stored at the rig for prolongedperiods of time. The rig environment may significantly reduce the shelf life of thesematerials, leading to possible in-service failure or unnecessary redress charges.



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FIGURE 2.5: ROTARY SLIPS



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FIGURE 2.6: ROTARY SLIPS



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FIGURE 2.7: SLIP SPIDER



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FIGURE 2.8: CASING, TUBING, AND DRILL PIPE ELEVATORS(Slip Type Elevators)



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FIGURE 2.9: CASING, TUBING, AND DRILL PIPE ELEVATORS(Center Latch Elevator)



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FIGURE 2.10: CASING, TUBING, AND DRILL PIPE ELEVATORS(Side Door Elevator)



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2.11.3 Drill Bits

Since most roller cone bits incorporate the use of elastomeric seals, these goods areto be stored in accordance with the guidelines given in 1.9.1 above. This cangenerally be accomplished by leaving the bit in the manufacturer's packaging. Aswith all consumables, drill bits are to be used on a first-in, first-out basis.

Used tricone bits can best be stored for future re-run by application of a protectivecoat of paint, lightly doping the thread profile, and storage in a container similar tothe one furnished when the bit was new. For long term storage the jet nozzles areto be removed and the seal and thread area greased to prevent corrosion. Do notimmerse used tri-cone bits in oil or water baths for any reason. The oil will adverselyeffect the elastomeric seals and water will cause general corrosion of the metallicsurfaces.

Used PDC bits are to be washed down with water and stored in the manufacturersshipping container following application of thread compound to the tool joint. Forlong term storage, the jet nozzles are to be removed and the seal and thread areagreased to prevent corrosion. See Section V, Part 6, Bits and Hydraulics for moreinformation.

2.11.4 Metallic Goods and Materials

Metallic goods and materials include flanges, nipples, bull plugs, valves, ringgaskets, etc. In general, these materials are not to be stored offshore for extendedperiods of time. When required for a specific project, it must be ensured that anyseal areas or bare metallic surfaces are adequately protected against corrosion. Thiscan usually be accomplished by storing the item in the manufacturer's packaging. Ifno protective packaging has been furnished or if the packaging has been opened forcomponent inspection, it must be ensured that any bare metal surfaces are protectedby application of a thin layer of protective grease or other acceptable coating.

OXY Drilling Practices

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