2011Global Drilling Services (2)

Table of Contents Contacts

Section 1

Drill Pipe Care and Handling

Section 2

Inspection Services

Section 3

Coating Services

Section 4

Hardbanding Services

Section 5

Machine Services

Section 6

Specialty Inspection Services

Section 7

Appendix

Section 8

Global Drilling Services Bill Hicks VP Global Drilling Services 2835 Holmes Rd. Houston, TX 77051 Phone: 713-799-4905 [email protected]

Coating Technical Support Robert Lauer Director Corrosion Control Solutions

Ryan Christopher Coating Technical Support

2835 Holmes Rd. Houston, TX 77051 Phone: 713-799-4571 [email protected]


Mike Adams Coating Technical Sales 2835 Holmes Rd. Houston, TX 77051 Phone: 713-799-5121 [email protected]

Inspection Technical Support Hilton Prejean Director, Inspection Technical Sales

John Doris Inspection Technical Sales


2835 Holmes Rd. Houston, TX 77051 Phone: 713-799-8198 John.Doris@nov,com

Hardbanding Technical Support

Machine Services Technical Support

Mark Juckett Hardbanding Product Line Manager

Matt Smith Global Drilling/Machining Services



Oklahoma

US Central Region

Bill King Area Sales Manager

Larry Larson Regional Sales Manager

3216 Aluma Valley Dr. Oklahoma City, OK 73121 Phone: 405-478-3400 [email protected]

10222 Sheldon Rd. Houston, TX 77049 Phone: 713-456-6106 [email protected]

Rocky Mountains

US Southeast Region

Les Massoletti Area Sales Manager

Rick Jackson Regional Sales Manager

410 17th Street Suite 1350 Denver, CO 80202 Phone: 303-572-7766 [email protected]

1515 Poydras Suite 1850 New Orleans, LA 70112 Phone: 504-636-3672 [email protected]

US West Region

California

Gary Fritz Regional Sales Manager

Jeff Hockersmith Area Sales Manager

14112 W. Hwy 80 E Odessa, TX 79765 Phone: 432-563-2150 [email protected]

3003 Fairhaven Suite C Bakersfield, CA 93308 Phone: 661-325-8529 [email protected]

Europe

North Sea

Frank Epperlein Director Coating Operations

Dave Wood Regional Sales Manager

Beisenstrasse 32 Gladbeck 45964 Germany Phone: +49 (5141) 8020 [email protected]

Badentoy Avenue, Badentoy Park Portlethen, Aberdeen, AB12 4YB United Kingdom Phone: 713-799-4917 [email protected]

Canada

Russia

Ken Skuba Regional Sales Manager

Vladimir Tikhomirov General Manager

1600, 540 – 5Ave., S.W. Calgary AB T2P 0M2 Canada Phone: 403-303-346 [email protected]

15A Leninsky Prospect 7th Floor Moscow, Russia 119071 Phone: +7 495 287 2636 [email protected]

Southeast Asia/Australia

Southeast Asia/Australia

Joe Haberer Regional Sales Manager

Harry Hill Regional Sales Manager

39 Gul Avenue Singapore, Singapore 629679 Singapore Phone: (65) 6861 2688 [email protected]

JI.Ampera Raya 9-10 Cilandak Jakarta Jawa Indonesia Phone: 713-799-5130 [email protected]

Central and South America

Middle East

Brian Van Burkleo Global Drilling Services

Jack Dyer Regional VP Operations


PO Box 61490, R/A # 13, Plot MO 0682B S50601 Jebel Ali Free Phone: +971-4-811-0210 [email protected]

China

Africa

Shane Prudhomme Country Manager

Carl Smith Vice President

Floor 10-12, Building #10, Lvzhou Center, Lane 162 Putuo, Shanghai Shi 200333 China Phone: +86 21 2216 8800 ext 6100 [email protected]

c/0 c/o P.I.C.O., 24 Wadi el Nil Street Maadi Cairo, Al Qahirah Phone: +2 010 225 9008 [email protected]

Specialty Inspection Services Brian Van Burkleo SIS Product Line Specialist

Chris Watson SIS GOM Division Manager

2835 Holmes Rd. Houston, TX 77051 Phone: (65) 6264 3400 [email protected]


Michael Slorach Director of Operations 161 Pioneer Rd Singapore, Singapore 639604 Singapore Phone: 713-799-4900 [email protected]

Drill Pipe Care and Handling

Why You Need a Care and Handling Management Program?

DRILL PIPE IS YOUR SINGLE LARGEST INVESTMENT TAKE CARE OF IT! INCREASE THE RETURN ON YOUR INVESTMENT REDUCE COSTLY FAILURES WHILE INCREASING SAFTEY CONSERVE CAPITAL ENHANCE YOUR COMPANY IMAGE WITH YOUR CUSTOMERS

NOV Tuboscope Drilling Services 2011

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Thread Protectors

Plastic Thread Protectors o Plastic protectors stay on the connection o Plastic protectors will cushion impact and protect the sealing shoulder Leave on protectors until making up the connection o Plastic protectors eliminate the problem of galvanic corrosion

*We recommend not using metal protectors as they can increase the potential for corrosion and thread galling


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Proper Storage of Drill Pipe Improper Storage

Proper Storage

*Proper storage of drill pipe is extremely important; not to prevent damage to the drill pipe, but also from a safety standpoint. Drill pipe should be layered with at least three runners allowing enough room for a forklift blade to be inserted without damaging the pipe. Sturdy racks are to be used to secure the drill pipe.


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Proper Transportation

Load and Secure Drill Pipe Correctly for Transportation

Make sure spacer boards are aligned to distribute weight properly When securing drill pipe use straps near the spacer boards to keep drill pipe from bowing


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Proper Lifting of Drill Pipe

Never use hooks in the end of the pipe for movement Use straps/slings spaced properly to avoid excessive bending Use spreader bar *Hooks and rods can mechanically damage both the internal coating and the I.D. surface


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Initial Make-Up Procedures

Proper initial make-up is probably the most important factor affecting the life of the tool joint connections Check torque gauge and make sure it is working properly Clean and dry each connection Dope threads and sealing shoulders with a good quality, clean, tool joint thread compound Stab connection and make-up SLOWLY Connection make-up is typically to 80% of the manufacturers torque Breakout and spin out SLOWLY Wipe off connections and inspect threads and shoulders for damage Re-dope threads and sealing shoulders Stab connection and make-up SLOWLY Connection make-up is typically to 90% of the manufacturers torque


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Clean and Visual of Tool Joint Threads and Shoulder

Use solvent to thoroughly clean threads and wipe dry with a clean rag

Inspect carefully for burrs or nicks on the shoulder or threads – Damaged connections should never be run in the hole


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Tool Joint Compound

Be sure to use the correct compound Never under any circumstances use casing and tubing lubricant Always Make Sure to Keep Contaminants Out!

Use a round stiff bristle brush to apply compound to tool joint threads and shoulders


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Proper vs. Improper Stabbing

Proper Stabbing

Improper Stabbing/Pin Damage

*Running drill pipe with sealing shoulder/pin damage could cause a washout


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Proper Make and Break

Always monitor your rotary speed and torque Keep in mind that when making up your drill string that over torque could be just as detrimental as under torque

Result of under/over torque – Pin swedge box swell and cracked threads


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Preventing Corrosion and Stress Risers

Keep Your Slips and Tongs Maintained

Stop the movement of the drill pipe and then carefully set the slips. Improper use of slips can cause slip cuts on the drill pipe O.D. which creates stress risers. Slips are Not Brakes!


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Preventing Corrosion and Stress Risers Always rinse O.D. and I.D. of Drill Pipe with Water

Use wipers to remove fluid and Contaminants from O.D. of pipe

Wash out I.D. to remove corrosive Drilling fluids


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Inspection

Used Drill Pipe Inspection Techniques Electromagnetic Inspection Evaluation of tube body for imperfections Defects – ID/OD tube body fatigue cracking Defects – ID/OD tube body corrosion pitting Defects – Tube body wall thickness changes Ultrasonic End Area Inspection Shear Wave o Detection of fatigue cracks in upset runout Compression Wave o Detection of corrosion pitting in upset runout o Detection of wall reduction in upset runout

85% OF DRILL PIPE FAILURES OCCUR IN UPSET RUNOUT


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Internal Plastic Coatings

Drill Pipe Coatings TK-34, TK-34XT, and TK-34P Corrosion Protection and Evaluations o Extended Life Hydraulic Improvement o Increase Flow Mitigate Deposits o Diameter Restriction


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Hardbanding Evaluation, Identification, and Field Applications TCS – 8000 TCS – Ti TCS – Non Mag TCS – 8260(Tungsten)


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Machine Services

Thread Repair and Refacing

Manufacturing

Tool Joint Rebuilding


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Specialty Inspection Services Rig Components o NDT Testing Derrick/Mast Inspection o API 4G Cat III & IV o Bolt Torque Critical Load Path Inspection Lifting Gear Inspection o Pad Eyes o Slings o Lifting Subs Rope Access DROPS Survey Offshore Rig Maintenance


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Surveillance Services

Conduct Quality Audits and/or Monitor Project Activities Services Include: Mill Surveillance

Review of Vendor Personnel Qualification Records

Monitoring Material In-Process

Witness of Factory Acceptance Tests, Run Tests, Load Tests, Hydrostatic Tests

Verification of Product Traceability

Document Review of Materials

Final Verification of Finished Products

Verification of Packaging and Marking

Witness of Loading and Offloading Activities


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Remember You Can Help Increase Safety and Protect Assets by………

Transporting and Storing Pipe Properly (Racking with Protectors) Cleaning and Lubricating (Thread Compound) Making Up the Drill Stem to Correct Torque Cleaning Pipe by Rinsing with Water Keeping Your Pipe Inspected Checking the Drill Pipe Coating and Hardbanding Maintaining Your Rig


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Drill Pipe Care and Handling Transportation and Storage of the Drill String When storing or loading pipe for transportation; load the pipe with pins facing same direction and spacer stripping lined up vertically and use chocks to secure the load from rolling. If pipe is being transported; snugly secure the load with straps lined up with the spacer stripping to prevent bowing of the drill pipe. When lifting drill pipe use a sling and spreader bar to support the pipe in two places. Never use hooks or metal rods. These can damage the ID of the drill pipe and the internal coating. Be sure of That Tool Joint Thread Compound Always use a tool joint thread compound. Never use API modified. Keep Contaminates Out of Tool Joint Compound Keep the lid on the container when not in use. Contaminates have a detrimental effect on compound performance. Gritty contaminates can damage/gall threads. Use Dope on Your Connections Thread compound prevents corrosion pitting in the threads. This will save money by not having to re-cut tool joint threads. Thread compound is less expensive compared to re-cutting threads. Proper Dope Application Be sure to work the thread compound brush completely around the threads on the box and pin. Ensure 360 degree coverage before making up the joint.


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Drill Pipe Care and Handling Cont… Proper Dope Application – Tool Joint Shoulders Be sure to apply thread compound on the sealing shoulders on both the box and pin. Improper dope application can result in serious thread and sealing shoulder damage that require costly repairs. Thread Protectors Always keep thread protectors on drill pipe tool joint connections. This will prevent impact damage as well as keep thread compound on the threads. We recommend the heavy-duty plastic thread protectors: 1. They will stay on the drill pipe connections unlike steel and flimsy plastic. 2. They cushion impact on the connections unlike steel and flimsy plastic. 3. They prevent galvanic corrosion unlike steel protectors. Thread Protectors – Leave on When Picking Up and Laying Down Drill Pipe Do not remove thread protector until ready to stab into the lower joint. Replace the thread protector before the drill pipe is lowered back down through the V-door. Drill pipe threads and sealing shoulders could be damaged as the drill pipe is raised or lowered through the V-door. As a rule, leave thread protectors on the drill pipe at all times when it is not in the hole. Please Use Drill Pipe Jacks or Other Handling Systems Do not use hammers, etc. to set drill pipe back into the stands.


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Drill Pipe Care and Handling Cont… Proper Stabbing is Critical Improper stabbing can result in severe damage to sealing shoulders and threads. This can result in costly washouts in the connections. Replace Worn Drill Pipe Wipers Drill Pipe Wipers perform a valuable service by cleaning corrosive drilling fluids from the OD surface of drill pipe. OD corrosion pitting is a stress riser and many cracks originate in the bottom of a corrosion pit. Cracks result in washouts and twist-offs. Change the wipers when they show wear. Rinse Drill Pipe OD and ID When possible, rinse the OD and ID of drill pipe to remove corrosive drilling fluids. The potential for OD corrosion increases when drill pipe is on racks with drilling fluids still caked on the OD. Drill Pipe Rubbers If drill pipe rubbers are being used, be sure to move them to different spots on the drill pipe. If left in one place, corrosive drilling fluids are trapped resulting in extensive OD pitting. Slip Maintenance Keep a continuous surveillance on the condition of the slip dies. If a die is worn, replace all of the dies, not just the worn die. If only the worn die is replaced, it could cause bi-axial loading on the drill pipe resulting in slip damage. Never use slips as a break.


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Drill Pipe Care and Handling Cont… Check the Hardband Condition Continuously check the condition of the hardbanding on the tool joints. When the hardbanding is worn flush with the tool joint, it is time to rehardband the tool joint. Hardbanding is much less expensive than tool joint build-up. Check Condition of the Shoulder Faces and Bevels The shoulders are the seals of drill pipe. Damaged shoulder faces will not seal resulting in washouts. Check Straightness of Drill Pipe Crooked drill pipe will result in rapid tube body and tool joint wear. The easy way to check straightness is to roll the joint of drill pipe slowly on the rack. It will wobble if not straight. Check Condition of Internal Coating Internal coating can extend the life of drill pipe. However, coating will wear out over time. When coating no longer protects the ID surface of the drill pipe, the pipe is a candidate for re-coating. Never Use Steel Rods or Hooks to Move Drill Pipe Slip Damage Slip damage is a series of transverse notches in the drill pipe. These notches are stress risers that result in cracks. Cracks cause washouts and twist-offs. Do Not Use Chains Do Not Use Spinners


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Drill Pipe Care and Handling Cont… Use Brass vs. Steel Hammer We do not recommend hammering on drill pipe however if checking fluid levels in drill pipe is necessary, use a brass hammer. Steel hammers make indentions, which are stress risers. This can result in washouts and twist-offs. Tong Die Maintenance Tong Die condition should be continuously monitored for the same reasons as slip dies. Positioning of Tongs Always use tongs and back-up tongs. The tongs should always be placed on the tool joint and not the tube body. The rotary table is not a tong. Monitor Rotary Speed and Torque Proper rotary speed and torque can prevent costly failures. For example, under-torque frequently results in washouts in the connection. Over-torque can result in transverse cracks in the threads due to increased stress. Improper rotary speed increases stress on drill pipe. Racking of Drill Pipe Drill pipe should never be stacked improperly. It is a safety issue as well as a damage issue. Drill pipe should be stacked on either racks or sills with wood boards separating each layer. For range 2 drill pipe, there should be three boards with one in the center and the other two halfway down toward each end. Good chocks should be used to secure the drill pipe. Never pyramid stack drill pipe Never use drill pipe tubs


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Drill Pipe Care and Handling Tips - Tubebodies Problem

Usual Effect

Probable Cause

Possible Correction

WASHOUT: Usually occurs near pin end upset taper or in area from lower part of slip area to box end upset taper.

Hole in pipe, drop in mud pressure, string separation, lost time

Surface notching, cyclic stressing, fatigue cracking

Minimize surface notching, reduce stress level, avoid critical rotary speed. Move bottom hole pipe up hole on trips, taper transition zone, use shock subs, use heavy weight drill pipe between drill pipe and drill collars.

TWIST OFF: Usually occurs near pin end upset taper or in area from lower part of slip area to box end upset taper

String separation, fishing job, lost time

Surface notching, cyclic stressing, fatigue cracking

Minimize surface notching, reduce stress level, avoid critical rotary speed. Move bottom hole pipe up hole on trips, taper transition zone, use shock subs, use heavy weight drill pipe between drill pipe and drill collars.

FATIGUE CRACKING: Predominately found near pin end upset taper and in area from box end upset taper to lower part of slip area. Surface Notching CORROSION PITTING: General in location

Wash out, twist off, string separation, lost time, pipe loss

Cyclic stressing, surface notches (corrosion, cuts, etc.), hydrogen embrittlement

Body wall loss, localized surface notch, stress concentration

Water, oxygen, CO2, H2S, and stress

Dampen stress, avoid critical rotary speed, minimize surface notching, move bottom hole pipe up hole on trips, use shock subs, prevent H2S in flow. Use lowest strength pipe where possible. Minimize rate of change in hole deviation. Maintain mud pH above 9.5, plastic coating, inhibitors, oxygen scavengers, clean pipe ID & OD, dampen stress, monitor with corrosion test rings

Suface Notching - SLIP CUTS: Located in slip area

Transverse surface notch, stress concentrator

Pipe turning in slips, defective slips/bowl, improper slip handling

Use back-up tong for make-up and breakout, use care when spinning pipe with rotary, improve slip/bowl maintenance, use care while setting slips

Surface Notching - SLIP AREA MASH: Located in slip area

Surface impression, stress concentrator

Improve slip/bowl maintenance and use care while setting slips

Surface Notching TONG CUTS: Usually found in an area over and just above pin end upset

Multiple surface notches, stress concentrators

Defective slip component, improper slip handling, excessive connection make-up or breakout, bending pipe in slips Tongs placed on pipe, worn tool joints, improper tong jaws, poor handling

Surface Notching CHAIN CUTS: Usually found in area over and just above pin end upset

Circumferential grooves (notch) at pin and upset area stress concentrators, cold worked metal Circumferential grooves stress concentrator

Excessive spinning chain slip

Proper chain tension, consider use of power pie spinner

Corrosion/erosion at ends of drill pipe/casing protector - Poor mud drain/cleaning at protector end

Periodically move or remove protector, clean pipe at ends and under protector

Surface Notching RUBBER CUT EXTERNAL RING CORROSION: Usually found in an area approximately 2 feet above pin end tool joint


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Place tongs only on tool joint diameter, use correct tong jaws, use sharp tong dies

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Drill Pipe Care and Handling Tips – Tubebodies Cont… Problem

Usual Effect

Probable Cause

Possible Correction

Surface Notching HAMMER MARKS: Usually found on the tube in areas near the pin and box end tool joints

Localized surface notch, cold worked metal

Tapping pipe to check fluid level on trip out

Use brass tipped hammer, tap pipe lightly

SLIP AREA CRUSHING: Located in slip area

Slip area OD/ID reduction, longitudinal splits in slip area, body wall thinning

Abrupt setting of slips, defective slip/bowl maintenance, improper slip size

Stop pipe movement before setting slips, check slip-to-pipe fit, improve maintenance, use only correct slip size

NECKING: Usually located near either or both upsets

Reduce pipe OD/ID reduction, longitudinal splits in slip area, body wall thinning

Stuck pipe, over pull (stretch), excessive hook load

Avoid sticking pipe and avoid over pulling

EXPANSION: Usually located above the pin and below the box which had been backed off. Referred to as string shot

Expanded OD/ID split pipe or tool joint

Stuck pipe, internal explosion for back off

Avoid sticking pipe, minimize explosive force. Be sure explosive is placed in tool joint area, carefully inspect pipe before re-use

COLLAPSE: Usually begins near tube center, often travels toward both ends

Flattens tube, circulation block, string separation

Excessive OD pressure, drill stem test, OD wear, ID erosion

Minimize OD wear, keep pipe straight, and prevent ID erosion with plastic coating

O.D. WEAR: Usually appears in center third of pipe body

Body wall thinning, reduced tensile capacity, reduced cross section, reduced collapse resistance

Abrasive formations, crooked pipe, deviated hole, high rotary speeds

Straighten pipe, minimize hole deviation/rate of change, avoid critical rotary speeds


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Drill Pipe Care and Handling Tips – Tool Joints Problem

Usual Effect

Probable Cause

Possible Correction

WASHOUT

Erosion of shoulder (face) seal and threads, mud pressure loss, string separation, lost time

Apply proper make-up torque per tool joint class, remove shoulder damage by refacing if possible; recut connection; remove shoulder fins by beveling shoulder; keep thread protectors installed while picking up, laying down, handling, transporting, or storing pipe; clean threads and shoulders before make-up; use care when tripping pipe; use only pipe jack tool with wide area contact

DRY OR MUDDY CONNECTION

Leaking shoulder (face) seals

Leaking shoulder (face) seals, damaged shoulder (face) seals, insufficient make-up torque, galled threads producing excessive shoulder standoff, shoulder fins rolled between seals, high spots on shoulder - (false makeup torque), excessive shoulder removal by refacing, stretched pin threads, dirty threads and shoulders, mis-stabbing connection, improper jacking of stands in standback area Insufficient make-up torque, damaged shoulders (face)

GALLED SHOULDER

Loss of shoulder seal, excessive shoulder to shoulder standoff, false make-up torque, unstable connection (wobble)

Insufficient lubrication on shoulders, insufficient make-up torque, shoulder fins, high spots on shoulder

Apply rotary tool joint compound to shoulders when doping connection, remove shoulder fins by beveling shoulder, remove high spots by refacing. Apply proper make-up torque per tool joint class.

PIN BREAK: Cup type failure


Apply proper make-up torque per tool joint class, minimize additional downhole make-up, use recommended rotary tool joint compound

PIN BREAK: Flat fracture type failure


PIN BREAK: Flat fracture type failure when torques and make-up are known to be satisfactory WEAR: Thin shoulder


Improper trip make-up torque, additional downhole make-up, improper type lubricant producing excessive tension vs. makeup/torque Pin wobble due to insufficient make-up, shoulder fins, false torque, fatigue cracking at thread root, galled threads H2S, hydrogen embrttlement, excessive pin tension

Reduces torque capacity, belled boxes, reduced shoulder seal area


Apply proper make-up torque per tool joint class, remove shoulder damage by refacing if possible; recut connection; remove shoulder fins by beveling shoulder.

Apply proper make-up torque per tool joint class, repair shoulder fins, repair galled threads

Control H2S in flow, reduce stress level if possible, remove string from service for period of time, inspect tool joint threads

Crooked pipe, high rotary speeds, abrasive formations

Straighten pipe, reduce rotary speeds where possible, apply hardfacing to box end tool joint where possible

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Drill Pipe Care and Handling Tips – Tool Joints Cont… Problem

Usual Effect

Probable Cause

Possible Correction

BELLED BOXES

Distorted connections, loss of shoulder seal, will not mate properly with another connection, split body

Improper make-up torque, additional downhole make-up, thin tool joints, improper thread lubricants

Maintain tool joint OD, apply proper make-up torque per tool joint class, minimize additional downhole make-up torque, use only recommended rotary tool joint compound, recut box

STRETCHED PINS

Distorted connections, loss of shoulder seal, will not mate properly with another connection, possible pin break Damages mating threads, false torque, improper make-up, connection wobble, leaking shoulder seal, washout, pin break, drop string, lost time Prevents shoulder make-up, false torque, leaking shoulder seal, washout, connection wobble, pin break, drop string, lose time Tool joint body cracking, wash-out, string separation lost time

Improper make-up torque, additional downhole make-up, improper thread lubricants

Apply proper make-up torque per tool joint class, minimize additional downhole make-up, use only recommended rotary tool joint compound, recut pin

Thread damage, handling without thread protectors, cross threading, worn threads, improper lubrication, dirty connection, defective kelly saver sub Mating tool joints with different OD's, handling damage

Handle pipe only with thread protectors, use care in stabbing and make-up, recut worn threads, use only recommended rotary tool joint compound, clean connections before use, repair or replace kelly saver sub

GALLED THREADS

SHOULDER FINS

HEAT CHECK

SHOULDER DAMAGE

Leaking shoulder seal, washout, string separation, lost time


Rapid heating due to friction between tool joint and formation, casing whip stock, etc. High rotary speeds, rapid cooling Mis-stabbing connection, handling damage, spinning chain between shoulders, improper pipe jacking

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Match tool joint OD's if possible, remove fins by refacing and beveling, handle pipe only with thread protectors

Reduce rotary speeds through tight areas, minimize tool-joint-to-formation contact

Use care when tripping pipe, handle pipe only with thread protectors, use only pipe jack with wide area contact

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A Guide to Users Visual Examination of Drill Pipe Straightness Roll a few lengths to evaluate straightness. Crooked pipe could be indicative of high stress drilling or rough handling of pipe in previous operations. Drill pipe which is kinked near the slip area may be indicative of over torque or “hard to break” connections. Running crooked drill pipe can cause abnormal abrasive wear to the tube body and tool joints and can contribute to unusual vibration in the drill string. Tool Joint Diameter Caliper a representative number of tool joints to determine outside diameter. Check some tool joints on both ends, but concentrate attention to box tool joints. Box tool joint O.D. wear will have a direct affect on the drill string torque capacity. Tool Joint Type There are many different tool joint dimensional combinations available for different drill pipe diameters, weight/foot and grades. A significant amount of high strength drill pipe may have “non standard” tool joint attached. The tool joint/pipe combination available may, or may not, satisfy the expected stress parameters for the well to be drilled. Tool Joint Condition Look for dry torque shoulders and/or threads. Leaking connections wash away thread compound Look at the color of the thread compound (dope). The color of 40% to 60% zinc based compound is usually grey. Use of other compounds may affect stress at given torques in a tool joint and can contribute to box belling, pin stretch and cracking. Check a few torque shoulders for galling, or fluid washes, across the shoulder face. As a minimum, tool joints should have a slight bevel around the outer edge of both pin and box shoulders.


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A Guide to Users Visual Examination of Drill Pipe Cont… A significant flare to the box torque shoulder can be an indication of possible connection over torquing which could result in belled boxes or stretched pins. A dark ring around the outer edge of the tool joint shoulders (sealing-surface) can be an indication of under torqued connections. Under torqued connections contribute to “wobble” between pin and bow tool joints causing excessive thread flank wear, galling and possible cracking in the pin threads. Shorter than normal tool joint length is usually indicative of “re-worked” threads and torque shoulder. Logic dictates that minimum length of the non-hardbanded surface should be somewhat longer that the longest tong die used. Check general appearance of tong die marks on the pin and box tool joint body. A significant absence of tong die marks on the box tool joint is indicative of the use of only one (1) tong during make-up and break out operations. That practice can cause deep transverse scars in the slip area or result in under torque connections. Excessively deep tong die marks can be indicative of over torquing or hard to break connections. Raised metal, resulting from excessively deep tong die marks can contribute to casing wear. Tool Joint Hardfacing (Hardbanding) Chrome alloy or palletized tungsten carbide hardfacings are frequently applied to tool joint boxes to enhance wear resistance. Hardfacings typically applied to new tool joints, at the manufacturing plant, are typically applied 3/32” proud (raised) to the outside of tool joint surface. Careful, but, objective consideration should be given to the presence of hardfaced tool joints and possible casing wear. Smooth or field worn hardfacings do less damage to the casing than hardfacings with a rough finish. Obviously, hardfaced tool joints are intended to be run in open hole where the tool joint works against the surface of the well bore. Tool Joint Welding Date Check the tool joint welding date stamps located on the pin base adjacent to the torque shoulder. See API RP7G-2 for the information available for this procedure.


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A Guide to Users Visual Examination of Drill Pipe Cont… Tool Joint Mill Slot and Groove Marking Compare the mill slot and groove markings with API RP7G-2 illustrations to confirm drill pipe weight and grade. Be aware, however, that such markings are not standardized in the industry. Thread Protectors Check for presence of tool joint thread protectors. Absence of protectors may be indicative of damaged tool joint threads and shoulders. Tube Body Outside Surface When rolling several lengths of drill pipe to check straightness, observe the general outside condition of the tube body. Look for deep transverse cuts in the slip area, mashes at any location, or evidence of sharp notches anywhere on the surface. Outside surface pitting on drill pie is uncommon unless the pipe has been stored in humid climates. If outside surface pitting is present, it is usually more evident within the outer one third (1/3) of the tube length at each end. If the pipe has drill pipe/casing protectors installed, or shows evidence of protectors having once been installed, check carefully for corrosion damage on the pipe surface where the protector would normally be positioned. Tube Body Inside Surface Use a bright light to observe the inside surface of several drill pipe lengths. Look for heavy mud scale deposits. Thick, dried mud scale flaking from the tube surface can plug small jet nozzles. Mud scale on the pipe surface tends to retain moisture and accelerates corrosion pitting damage. Most drill pipe is internally plastic coated to reduce damage to the I.D. surface from corrosion pitting. Presence of plastic coating, in good condition, helps reduce accumulation of mud scale. Plastic coating generally has a slick, shiny finish and its condition is relatively easy to evaluate with a bright light.


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A Guide to Users Visual Examination of Drill Pipe Cont… The corrosion control is reasonable if between 70% to 80% of the tube surface between opposite upset runouts is covered with well-bonded plastic coating. Large sections of dis-bonded coating not only reduce the percent of surface protection but flaking coating can be a plugging concern. It is difficult to accurately evaluate inside surface pitting damage, in drill pipe, by visual examination from the pipe end. Presence of coating or mud scale tends to hide the pitted condition. If heavy scale is present, or if pitting can be seen, a more thorough inspection should be performed. Other Helpful Information If drill pipe has been exposed to severe hydrogen sulfide (H2S) the surface of the pipe will sometimes have a dark green to black color appearance a few days after exposure. Ask for information about performance history of the string. Sometimes good data is kept regarding accumulated footage drilled, rotating hours, and failure and damage records, etc. Determine when drill pipe was last inspected and what type of inspection services, and specifications were applied. Match the inspection report documents with the pipe in question. The report should reflect when the inspection was performed and the number of lengths serviced. Corresponding length numbers and service date markings are steel die stenciled on the pin end tool joint 35° taper adjacent to the upset and should match information on the inspection report.


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Transportation and Storage of the Drill String Pipe that is being moved on a truck or rail car should be placed with all pins facing the same end. The load of pipe should be snugly chained down to prevent the joints from hitting one another and damaging the tool joints or the pipe itself. When drill pipe reaches the rig, the truck should be placed so that when the pipe is unloaded, the boxes will face the rig side of the rack. The pipe should be unloaded carefully, making sure that the pipe protectors are on securely. For unloading, a sling and a spreader bar for supporting the pipe in two places should be strung from the gin pole. Support in two places is necessary for keeping the pipe under control and preventing it from bending. A snub line should be tied around the load to help control it and to keep the pipe parallel to the stack on the truck as it is rolled onto the ramp. The pipe rolling onto the ramp must also be prevented from crashing into the pipe already on the rack. The first tier of pipe on racks at the drilling site should be at least 12 inches from the ground to ensure good ventilation. Supports properly spaced should be provided to hold up the middle of the pipe and keep it from sagging. Wooden strips of equal thickness should be inserted between layers of pipe over the support areas to keep the weight evenly distributed on the bottom layer of pipe. Ten feet is the maximum recommended height for stacks of drill pipe on the ground, five tiers are the maximum on the rig itself. From the time that pipe is first delivered to the rig, a record should be kept on it. The record should show expected and actual life of the pipe, type of service given, and any unexpected or severe circumstances to which the string has been subjected.


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Used Drill Pipe Recommendations

Recommended Minimum Dimensional Requirements Prior to Recoating Drill Pipe Tubes or Rebuilding Tool Joints

4 ½” 16.60# S-135 NC-46

New API 5DP and RP7G-2 Specifications

Used API RP7G-2 and DS-1 Specifications

Recommended Minimum Specifications

Tube Body Wall Thickness

.337"

.270"

.286"

Tool Joint O.D.

6 1/4"

5 25/32"

5 29/32"

Pin Tong Space

7"

4 9/16"

6"

Box Tong Space

10"

6 1/8"

7"*


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Used Drill Pipe Recommendations Cont…


5” 19.50# G-105 NC-50

New API 5DP and RP7G-2 Specifications




.362"

.290"

.308"

Tool Joint O.D.

6 5/8"

6 3/32"

6 7/32"

Pin Tong Space

7"

4 19/32"

6"

Box Tong Space

10"

6 1/8"

7"*


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5” 19.50# S-135 NC-50

New API 5Dp and RP7G-2 Specifications




.362"

.290"

.308"

Tool Joint O.D.

6 5/8"

6 5/16"

6 7/16"

Pin Tong Space

7"

4 3/4"

6"

Box Tong Space

10"

6 1/8"

7"*


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5 1/2” 21.90# S-135 FH





.361"

.289"

.307"

Tool Joint O.D.

7 1/2"

6 15/16"

7 1/16"

Pin Tong Space

8"

5 7/32"

6"

Box Tong Space

10"

6 5/8"

7 1/8"*


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6 5/8” 27.70# S-135 FH





.362"

.290"

.308"

Tool Joint O.D.

8 1/2"

8"

8 1/8"

Pin Tong Space

8"

5 7/8"

6"

Box Tong Space

11"

6 5/8"

7 1/8"*


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Inspection Services

Inspection Services Why should drill pipe be inspected? Drill pipe is the work horse of down hole tubular strings, it rotates the drill bit, provides a conduit to carry drilling mud down to lubricate the drill bit and pushes the mud up its outer surface carrying bottom hole shavings to the top of the hole. Drill pipe is subjected to cyclic stresses in tension, compression, torsion and bending. Tension and bending are the most critical of these. Bending and rotation produce an alternation between states of compression and tension at localized points in the drill pipe such as the transition zone and the slip area where 85% of failures occur. Continuous drilling is the goal, to meet that only premium pipe should be used and all others removed from service. The growing cost of new drill pipe, extended deliveries, continuous changing market, costly down time associated with failures are several reasons why drill pipe is re-inspected often. The Tuboscope drill pipe maintenance program has been designed to provide you with a drill string ready for service. The benefit to you from Tuboscope inspection services is the assurance defective pipes were identified avoiding catastrophic failures that could lead to loss of the whole drill string or worst the total well. Tuboscope employs proper inspection techniques to identify which pipe is suitable for further service, limited service or to be removed from service and discarded. Inspections performed on drill pipe have detected alarming defects:

Damaged threads resulting from under-torque Damaged shoulders from improper care and handling Slip cuts from poor die maintenance and worn-out handling equipment Bent tubes from exceeding rotation and weight on bit Fatigue cracks often caused by cyclic stressing and down hole environments like hydrogen, H2S, salts and extreme temperatures

Tuboscope’s inspection in conjunction with care and handling practices has extended the life of drill pipe up to 1 million feet drilled. Your drilling crews play an important part in extending the life of the drill string you depend on with proper work habits, it’s essential. Tuboscope has partnered with thousands of customers saving them millions by performing state-of-the-art inspections recovering usable pipe and drastically offsetting capital cost with the delay of new drill pipe purchases.


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Inspection Services Cont… TH Hill Drill Pipe Inspection Program Summary DS-1™ Category 1 Tool Joint – Visual Connection The tool joint connection is examined to determine grade, condition of seal, threads, hardfacing, bevel, box swell and pin stretch. Tube Body – Visual The inside and outside surfaces are examined to determine general; conditions.

DS-1™ Category 2 Tool Joint – Visual Connection The tool joint connection is examined to determine grade, condition of seal, threads, hardfacing, bevel, box swell and pin stretch. Tool Joint – Dimensional 1 The dimensional measurement of the tool joint O.D., I.D., box shoulder width, tong space, box swell. Tube Body – Visual The inside and outside surfaces are examined to determine general; conditions. Tube Body - O.D. Gauge The tube body outside diameter is mechanically gauged from upset to upset to determine abrasive wear or mechanical damage. Tube Body – Ultrasonic Wall Thickness Minimum remaining body-wall is determined at point of maximum wear by utilizing ultrasonic wall measurements.

DS-1™ Category 3 Tool Joint – Visual Connection The tool joint connection is examined to determine grade, condition of seal, threads, hardfacing, bevel, box swell and pin stretch. Tool Joint – Dimensional 1 The dimensional measurement of the tool joint O.D., I.D., box shoulder width, tong space, box swell. Tube Body – Visual The inside and outside surfaces are examined to determine general; conditions.


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Inspection Services Cont… Tube Body - O.D. Gauge The tube body outside diameter is mechanically gauged from upset to upset to determine abrasive wear or mechanical damage. Tube Body – Ultrasonic Wall Thickness Minimum remaining body-wall is determined at point of maximum wear by utilizing ultrasonic wall measurements. Tube Body – Electromagnetic 1 An electromagnetic inspection performed on the tube body utilizes an active longitudinal D.C. magnetic field and a detector unit which travels the length of the pipe body. Magnetic flux disturbances caused by transverse or three-dimensional defects such as fatigue cracks or corrosion pits are detected and recorded.

DS-1™ Category 4 Tool Joint – Visual Connection The tool joint connection is examined to determine grade, condition of seal, threads, hardfacing, bevel, box swell and pin stretch. Tool Joint – Dimensional 2 Additional to Dimensional 1 box counterbore depth, box counterbore diameter, bevel diameter, box seal width and pin neck length. Tube Body – Visual The inside and outside surfaces are examined to determine general; conditions. Tube Body - O.D. Gauge The tube body outside diameter is mechanically gauged from upset to upset to determine abrasive wear or mechanical damage. Tube Body – Ultrasonic Wall Thickness Minimum remaining body-wall is determined at point of maximum wear by utilizing ultrasonic wall measurements. Tube Body – Electromagnetic 1 An electromagnetic inspection performed on the tube body utilizes an active longitudinal D.C. magnetic field and a detector unit which travels the length of the pipe body. Magnetic flux disturbances caused by transverse or three-dimensional defects such as fatigue cracks or corrosion pits are detected and recorded. Tube Body – MPI Slip/Upset Dry magnetic particles are applied to the outside surface of the slip and upset area to detect transverse and three-dimensional flaws. From pin shoulder out to 36” / box shoulder out to 48”.


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Inspection Services Cont… DS-1™ Category 5 Tool Joint – Visual Connection The tool joint connection is examined to determine grade, condition of seal, threads, hardfacing, bevel, box swell and pin stretch. Tool Joint – Dimensional 2 Additional to Dimensional 1 box counterbore depth, box counterbore diameter, bevel diameter, box seal width and pin neck length. Tool Joint – Backlight Connection Wet fluorescent magnetic particles are applied to the connection surface under hood and the outside surface of the box looking for heat checking. Tube Body – Visual The inside and outside surfaces are examined to determine general; conditions. Tube Body - O.D. Gauge The tube body outside diameter is mechanically gauged from upset to upset to determine abrasive wear or mechanical damage. Tube Body – Electromagnetic 2 An electromagnetic inspection system utilizing an active longitudinal D.C. magnetic field and a gamma wall gauge (note; FLUT1 or EMI1 with UT wall reading may be substituted).

Tube Body – MPI Slip/Upset Dry magnetic particles are applied to the outside surface of the slip and upset area to detect transverse and three-dimensional flaws. From pin shoulder out to 36” / box shoulder out to 48”. Tube Body – UT Slip/Upset Area An ultrasonic shear-wave technique is used to inspect the critical, high-stress upset run-out and adjacent tube body end areas for transverse fatigue cracks.

DS-1™ Category HDLS (Heavy Duty Landing String) Tool Joint – Visual Connection The tool joint connection is examined to determine grade, condition of seal, threads, hardfacing, bevel, box swell and pin stretch. Tool Joint – Dimensional 2 Additional to Dimensional 1 box counterbore depth, box counterbore diameter, bevel diameter, box seal width and pin neck length.


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Inspection Services Cont… Tool Joint – Backlight Connection Wet fluorescent magnetic particles are applied to the connection surface under hood and the outside surface of the box looking for heat checking. Tool Joint - Traceability To verify an individual number is traced to its mill certificate and material test reports. Tube Body – Visual The inside and outside surfaces are examined to determine general; conditions. Tube Body - O.D. Gauge The tube body outside diameter is mechanically gauged from upset to upset to determine abrasive wear or mechanical damage. Tube Body – Ultrasonic Wall Thickness Minimum remaining body-wall is determined at point of maximum wear by utilizing ultrasonic wall measurements. Tube Body – FLUT 2 An ultrasonic inspection performed on the tube body utilizes the shear wave and compression wave techniques to inspect in longitudinal, transverse and oblique directions to include wall thickness measurements. Tube Body – MPI Slip/Upset Dry magnetic particles are applied to the outside surface of the slip and upset area to detect transverse and three-dimensional flaws. From pin shoulder out to 36” / box shoulder out to 48”. Tube Body – UT Slip/Upset Area An ultrasonic shear-wave technique is used to inspect the critical, high-stress upset run-out and adjacent tube body end areas for transverse fatigue cracks. Tool Body - Traceability To verify an individual number is traced to its mill certificate and material test reports.


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Used Drill Pipe Inspection Services SONOSCOPE® Inspection - Standard Rack The SONOSCOPE inspection evaluates service-induced defects in the used drill pipe tube body to API RP7G-2, DS-1 or customer specifications: 1. Each length is numbered sequentially on the pin-end tool joint shoulder. The month and year of inspection and the Tuboscope “T” service mark are also stenciled on the shoulder. 2. The full length outside diameter of the tube body is gauged to determine the area of maximum O.D. wear. 3. The pipe body is examined full length for visible cuts, mashes, gouges and other defects; close attention is given to the slip area. 4. Ultrasonic spot measurements are taken at the area of maximum O.D. wear to establish minimum wall thickness. 5. The SONOSCOPE electromagnetic inspection is performed on the tube body. SONOSCOPE inspection equipment utilizes an active longitudinal D.C. magnetic field and a detector unit which travels the length of the pipe body. Magnetic flux disturbances caused by transverse or three-dimensional defects such as fatigue cracks or corrosion pits are detected and recorded. 6. A magnetic particle inspection is performed on the critical upset areas to detect O.D. fatigue cracks. 7. The tube body is classified and identified in accordance with API RP7G-2 or customer specifications.

Critical Upset Area Inspection Ultrasonic End Area Inspection The Tuboscope ultrasonic end area unit, utilizes the ultrasonic shear-wave technique to inspect the critical, high-stress upset run-out and adjacent tube body end areas for transverse fatigue cracks. Then the ultrasonic compression wave technique is employed to detect pitting and measure wall thickness.


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Used Drill Pipe Inspection Services Cont… Tool Joint Inspection Tool Joint O.D. Measurement The outside diameter of the tool joint is measured to API RP7G-2 or customer specifications to classify the tool joint O.D. reduction due to abrasive wear. Tool Joint Shoulder (Face) Visual Examination Tool joint shoulders are cleaned and visually examined for galls, nicks, washes, fins and other damage which would affect the pressure holding capacity and stability of the tool joint. The tool joint is also checked for bevel condition. Tool Joint Welding Date/Grade Mark Examination To determine pipe age, grade, weight per foot and possible tool joint rework, the pin base is visually examined for tool joint manufacturers’ markings. Tool Joint Shoulder (Face) Width Measurement A mechanical gauge is used to measure pin and box tool joint shoulder width, including bevel, in accordance with API RP7G-2 or customer specifications. Tool Joint Clean and Visual Examination Tool joint threads and shoulders are cleaned and visually examined for thread and shoulder damage and bevel condition. Check Tool Joint Pin Stretch - (with profile gauge) The tool joint pin is cleaned, and threads are visually compared to a hand-held thread profile gauge. Check Tool Joint Pin Stretch - (with mechanical lead gauge) The tool joint pin is cleaned, and thread lead is measured with a dial indicator gauge to determine presence and amount of pin stretch. Check Tool Joint Box Swelling A measurement is taken across the box inside counter-bore and compared to API Spec 5DP dimension Qc for possible indications of box swelling.


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Used Drill Pipe Inspection Services Cont… Dry Magnetic Particle Tool Joint Inspection, Type I Pin and box threads, shoulders and the box O.D. surface are cleaned as required. Dry magnetic particles are applied to detect transverse cracking in pin thread roots and to detect longitudinal cracking on the box O.D. surface. Threads and shoulders are visually examined for damage. Dry Magnetic Particle Tool Joint Inspection, Type II Pin and box threads and shoulders are cleaned as required. Dry magnetic particles are applied to detect transverse cracking in pin and box thread roots. Threads and shoulders are visually examined for damage. Wet Fluorescent Magnetic Particle Tool Joint Inspection, Type I Pin and box threads, shoulders and the box O.D. surface are cleaned as required. Wet fluorescent magnetic particles are applied to detect transverse cracking in pin thread roots and to detect longitudinal cracking on the box O.D. surface. Threads and shoulders are visually examined for damage. Wet Fluorescent Magnetic Particle Tool Joint Inspection, Type II Pin and box threads and shoulders are cleaned as required. Wet fluorescent magnetic particles are applied to detect transverse cracking in pin and box thread roots. Threads and shoulders are visually examined for damage.

Tube Body Inspection Sonoscope Buggy Inspection An electromagnetic inspection performed on the tube body utilizes an active longitudinal D.C. magnetic field and a detector unit which travels the length of the pipe body. Magnetic flux disturbances caused by transverse or three-dimensional defects such as fatigue cracks or corrosion pits are detected and recorded. Ultrasonic Full Body Inspection An ultrasonic inspection performed on the tube body utilizes the shear wave and compression wave techniques to inspect the critical, high-stress areas for transverse fatigue cracks, corrosion, pitting, erosion and measures wall thickness. The multi-channel inspection heads travel the length of the pipe body acquiring real time data.


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Used Drill Pipe Inspection Services Cont… Tube Body Mechanical O.D. Gauging The tube body outside diameter is mechanically gauged from upset to upset to determine abrasive wear or mechanical damage. Minimum remaining body-wall is determined at point of maximum wear by utilizing ultrasonic wall measurements. Determine Minimum Cross Sectional Area (CSA) Ultrasonic wall measurements are utilized to determine minimum and average pipe body-wall. Cross sectional area is computed at the point of maximum O.D. reduction with minimum remaining wall. Dry Magnetic Particle Slip Area Inspection Dry magnetic particles are applied to the outside surface of the slip area to detect O.D. transverse cracking. Wet Fluorescent Magnetic Particle Slip Area Inspection Wet fluorescent magnetic particles are applied to the outside surface of the slip area to detect transverse cracking.

Special Services Heavyweight Drill Pipe Magnetic Particle Inspection - End Areas Only Pin and box threads and shoulders are cleaned and examined for visual damage or imperfections. Magnetizing equipment is utilized to induce a longitudinal magnetic field. Magnetic particles are applied to the thread surface to detect transverse cracks. Heavyweight Drill Pipe Magnetic Particle Inspection - Tool Joint and Center Wear Pad Taper Areas Only Magnetizing equipment is utilized to induce a magnetic field into the upset taper and adjacent tube body. Magnetic articles are employed to detect transverse cracks on the outside surface. Drill Collars, Kellys, Stabilizers, Subs and Core Barrels Ultrasonic, electromagnetic, mechanical-optical and/or magnetic particle inspections are employed as required to locate defects in these items.


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Inspection Case History

655jts

21,615

5 1/2", 21.90#/ft, S-135 HT-55 TJ -1116826

636jts

Accepted

19

Rejected

49jts

1617

35 jts

Accepted

14jts

Rejected

568jts

17,906.46ft

528jts

Accepted

40jts

Rejected

419 jts

13,825ft

414jts

Accepted

5 jts

Rejected

12.19%

79jts

2,607ft

4 1/2", 16.60#/ft, X-95, NC 46, TJ -1147961

75jts

Accepted

4jts

Rejected

20,988ft 2.9%

627ft

(Cracks)

2 7/8", 6.85#/ft, S-135, NC 31 TOOL JOINT -1124252 1,155ft 28.57%

462ft

(Cracks)

5”, 19.50#/ft, S-135, NC 50 TOOL JOINT -1135581 16,645.43ft 7.04%

1,261.02ft

(Cracks)

6 5/8", 27.70#/ft, S-135, FH, TOOL JOINT -1154966 13,662ft 165ft (Cracks, Washout)

2,475ft 20.25%


132ft (Cracks)

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Used Drill Pipe Inspection Methods A.Tool Joints Condition

Recommended Methods Potential Methods OD Caliper

1. OD Reduction Due to Wear

Snap gauge equally effective Diameter tape

2. Shoulder Width

Steel ruler OD Caliper Snap gauge equally effective Steel ruler Thread lead gauge

3. Pin Stretch

Profile gauge Ring gauge Steel ruler to check Qc

4. Box Swell

Profile gauge Ring gauge Wet fluorescent magnetic particle Dry magnetic particle

5. Pin Cracking

Dye penetrant Straight beam ultrasonic

6. Box Cracking (Longitudinal)

Electromagnetic scan Wet fluorescent magnetic particle Dry magnetic particle - if badly scarred by tong dies Die penetrant Angle beam ultrasonic Visual Wet fluorescent magnetic particle

7. Box Cracking (Transverse)

8. Torque Shoulder Damage (Scars, Galls or Washes)

Dry magnetic particle Dye penetrant Straight beam ultrasonic Visual Electromagnetic scan Visual Hydrostatic pressure test

9. Thread Damage (Wear, Scars, Galls or Washes)

Visual with profile gauge Visual


Comments A typical practice is to visually locate the diameter showing eccentric wear and apply the caliper or gauge at that diameter. Otherwise, if an eccentric condition is not evident the caliper or gauge is applied at several locations around the tool joint.

Same as Item 1. above A thread profile gauge is often used for locating stretched pins but provides no quantitative measurement. A thread lead gauge will reveal amount of stretch. A good steel ruler is used to measure the diameter of the box counterbore (Qc) and compare against the "as machined" specified diameter. Wet fluorescent magnetic particle is the generally preferred application because the particle size is smaller than dry particle and more sensitive to fine, tight cracks. Wet MPI is much faster than dye penetrant and therefore more cost effective. Ultrasonic applications are occasionally being employed but coupling problems along with false signals and misinterpretations are frequent. Same as item A.5. Tool joint box cracking is usually associated with overtorquing and / or box swelling. Therefore, cracking in box tool joint on drill pipe will be oriented in the longitudinal direction and predominately on the OD surface.

Same as item A.5. Pin and box tool joints assembled in a typical drill string are quite stiff and resist bending forces. The bend effect is commonly focused at the transition point of the drill pipe upset where cracking typically occurs. Transverse cracking is not typical to drill pipe box tool joints. Visual examination is the most effective and practical method in this case. Tool joints, even in good condition, are difficult to seal against pressure test plugs without high make-up torques applied. A good visual examination will note damaged threads and the profile gauge will help evaluate thread wear or metal projections present.

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Used Drill Pipe Inspection Methods Cont…

B. Tube Body Condition

Recommended Methods Potential Methods Drill pipe wear (snap gauge with ultrasonic thickness gauge) Gamma-ray scan

1. Bodywall Reduction Due to Wear

OD caliper Diameter tape Straight beam ultrasonic scan OD caliper

2. OD Reduction Due to Stretch

Drill pipe wear (snap) gauge Diameter tape

3. OD Reduction Due to Mash or Crush 4. OD Expansion (String Shot Back-off)

5. Corrosion Pitting ID Surface

OD caliper Drill pipe wear (snap) gauge Diameter tape OD caliper Drill pipe wear (snap) gauge Electromagnetic scan with ultrasonic thickness prove-up Visual with bright light Visual with borescope Angle or straight beam ultrasonic scan

6. Corrosion Pitting OD Surface

7. Cuts, Gouges, and scars - OD Surface Transverse

Comments

Bodywall reduction resulting from abrasive wear is typically located in the center 1/3 of the tube. The pipe body, from some distance towards each end, is generally protected by the tool joint with its large diameter. Therefore, simple caliper like the OD gauge is effective in locating the worn area. The amount of remaining bodywall should be determined by the use of an ultrasonic thickness gauge. Used drill pipe is typically somewhat crooked and / or coated with a drilling scale mud on the OD surface; therefore, full length ultrasonic or gamma-ray scan may be difficult to accurately perform. Initial stretching of drill pipe length generally occurs at a point near the upset runout. An OD caliper is most effective in comparing the pie diameter at the point of suspected stretch with adjacent pipe body or, by indirect measurement, with a steel ruler.

Same as item B.2. above

Same as item B.2. above Corrosion pitting damage occurs in a variety of geometric configurations, Electromagnetic scanning is the most effective application for locating the pitted area. Remaining bodywall must be determined by use of a straight beam ultrasonic thickness gauge. Angle beam ultrasonic application can be adversely affected by pitting configuration and other conditions.

Electromagnetic scan with depth gauge and ultrasonic thickness prove-up Same as item B.5. above

Visual Angle or straight beam ultrasonic scan Electromagnetic scan with MPI prove up Visual Angle beam ultrasonic scan


Cuts, gouges and similar scars in the transverse configuration are the most detrimental relative to fatigue crack development. Electromagnetic scan with magnetic particle prove-up gives satisfactory results.

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Used Drill Pipe Inspection Methods Cont…

B. Tube Body Condition

Recommended Methods Potential Methods Visual with MPI prove-up

8. Cuts and Scars - OD Surface - Longitudinal

Electromagnetic Angle beam ultrasonic scan

Comments Cuts, gouges, and similar scars in the longitudinal configuration are considerably less detrimental relative to fatigue crack development. Longitudinal cuts or gouges, therefore, must be quite large or deep to cause concern. As a result, visual detection with magnetic particle prove-up gives satisfactory results.

Angle beam ultrasonic scan 9. Fatigue Cracking OD/ID

Electromagnetic scan with MPI Prove-up Visual with profile gauge

The ultrasonic method requires a couplant. The electromagnetic method is considerable less affected by thin coatings of drilling mud scale and other outside surface irregularities commonly present on drill pipe.

Visual


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Color codes for the tube appear on the tube body near pin end. Tool joint classification color codes appear on the tool joint (either box or pin). Shoulder condition color codes appear adjacent to the threads (either box or pin).

PIPE BODY CLASSIFICATION (NEAR PIN END AT 18” AND 2” WIDE BAND)

PREMIUM CLASS Permanent markings for classification of drill pipe body (all classes contain a unique number stamped on the 35° slope).

CLASS 2

See reverse side for Table B.18 of API RP 7G-2. It explains exterior and interior conditions, identified by inspection, which leads to these color codes on the tube body.

CLASS 3

SCRAP

TOOL JOINT CLASSIFICATION (BOX AND PIN)

A single white band is often painted in actual field practice to indicate premium class.

PREMIUM CLASS

Refer to Table D.6 in API RP 7G-2 for minimum width of box shoulder, identified by Inspection, that leads to these classification color codes.

CLASS 2

CLASS 2 SHOULDER CONDITION (BOX AND PIN)

SCRAP OR REPAIRABLE

FIELD REPAIRABLE

Table B.18 — Classification of Used Drill Pipe Classification Condition

Premium Class: Two White Bands

Class 2: One Yellow Band

Class 3: One Orange Band

Exterior Conditions OD Wear

Remaining wall not less than 80%


Remaining wall less than 70%

Dents and Mashes

OD not less than 97%


OD less than 96%

Crushing and necking



OD less than 96%

Slip area, cuts and gauges

Depth not more than 10% of average adjacent wall ª, and remaining wall less than 80%

Depth not more than 20% of average adjacent wall ª, and remaining wall less than 80% for transverse (70% for longitudinal)

Depth more than 20% of average adjacent wall ª, or remaining wall less than 80% for transverse (70% for longitudinal)

Stretching



OD less than 96%

String shot

OD not more than 103%

OD not more than 104%

OD more than 104%

External corrosion




Longitudinal cuts and gouges




Transverse cuts and gouges




Cracks

None b

None b

None b

Corrosion pitting




Erosion and internal wall wear




Cracks

None b

None b

None b

Internal Conditions

ª Average adjacent wall is determined by measuring the wall thickness on each side of the cut or gouge adjacent to deepest penetration. b

In any classification where cracks and washouts appear, the pipe is identified with a red band and considered unfit for further drilling service.

Table D.6 — Drill Pipe and Tool-Joint Color Code Identification

Tool Joint and Drill Pipe Classification

Number and Color of Bands

Tool-joint condition

Color of Bands

Premium Class

Two White

Scrap or shop repair

Red

Class 2

One Yellow

Field repairable

Green

Class 3

One Orange

—

—

Scrap

One Red

—

—

Coating Services

Veracruz, Mexico Macae, Brazil Sheldon North Coating Plant, Houston, TX

Nisku, Alberta, Canada Edmond, Oklahoma Batam, Indonesia Amelia North, Louisiana Amelia South, Louisiana Berlaimont, France Gladbeck, Germany Port Lethon, Scotland West Little York, Houston, TX Houma, Louisiana - Custom Odessa, TX - Fiberglass Liner Odessa, TX - Rod Coating/OD Tubular HHTCC Qingxian HHTCC Jiangyin Oman Liner and Wrap Plant Abu Dhabi, United Arab Emirates

Plant Highway 90 Houston, TX Navasota, TX Midland, TX

47'

24"

48'

48' 48'

14" 16"

24"

63' 46' 48' 48' 48' 48' 44' 48' 47' 20'

14" 10" 16" 16" 12" 13 3/8" 20" 14" 12"

®

All TK®

2" - 24" TBD TBD

Expansion Locations

All TK All TK® TK-Liner, Fiberline All TK®

1 1/2" - 12" > 1 1/2" 2 3/8-9 5/8 all rod sizes 2 1/16-4in pipe 2 3/8" - 14" 2 3/8" - 16" Liner 2 3/8" - 9 5/8" 2" - 24"

1" - 14" 1 1/2"-10" 1" - 16" 1.9" - 16" 1-1/2" - 12" 2" - 13 3/8"

Sizes 1 1/2" - 13 3/8" 1 1/2" - 16" 2 3/8" - 15"

Liquid

None None All TK® All TK® TK-Liner, TK-Fiberline TK-750R, 316 SS, TK-505 (OD)

All TK® All TK® ® All TK All TK® All TK® All TK®

Maximum OD Length Coatings ® All TK 13 3/8" 46' All TK® 16" 48' 15" 48' TK®-2, 7, 34, 34XT ®

Powder Coatings

All TK®

®

All TK All TK® Tubo-Wrap All TK®

TK-15,70,99 ® All TK except 800 All TK® except 800 All TK® TK®-34P,216, 34, 34XT TK®-34P, 216, 236 ® TK -34P, 216,236 All TK® except 99 All TK®

None ® TK -15, 70, 505 TK®-99 All TK® except 800

TK -99

Coating Services Location Capabilities and Contacts

2" - 24"

2 3/8" to 14" 2 3/8" to 16" 2 3/8" - 20" 2" - 24"

2 3/8" - 3 1/2" 1 1/4" - 7" 1.9" - 14" 1 1/2" - 4 1/2" 2" - 16" 2" - 16" 1- 1/2" - 5" 2" - 13 3/8" 2" - 20" 2" - 14" 1 1/2" - 12" > 1 1/2" 2 3/8" - 9 5/8"

Sizes 1 1/2" - 7"

Coating Services Since most drilling muds are water-based, they are capable of causing extensive corrosion pitting due to entrained salts and from CO2 and H2S picked up from the formation. Aggravating this problem is the oxygen that is picked up as the mud circulates through the shaker and mud pit, which increases the mud’s corrosive nature. Secondly, most significant corrosion can occur if the pipe is not properly prepared for storage on the surface. Corrosion can exacerbate the stresses that severe drilling operations inflict upon your drill pipe, leading to the rapid development of fatigue cracks and ultimately catastrophic downhole pipe failure such as washouts or twist offs. Tuboscope’s internal plastic drill pipe coatings offer protection through the entire drill string. Preventing excessive corrosion on the internal of the pipe is the first step in minimizing the stress concentrations that can lead to pipe failure. Reduction in loss of the wall thickness also further extends the life of that drill pipe asset. In addition to corrosion protection, the reduced surface roughness of the internal coating versus the bare steel pipe can minimize pump pressures required to provide sufficient fluid flow or can allow for a greater volume of fluid to be circulated at the same pressures. This reduced surface roughness also plays a key part in the internal coatings ability to mitigate the deposit of scales, minimizing the need for costly chemical treatments and eliminating the fear of the damage that can be caused my dislodged agglomerations of scale. A clean internal surface can protect against formation contamination and maintains the hydraulic efficiency. Tuboscope currently offers three different internal coatings for drill pipe applications: TK®-34, TK-34XT and TK-34P. All three systems have the ability to drill into formations up to 400°F (204°C) provided circulation is maintained. TK-34, the original drill pipe coating, has been used successfully for over 35 years in a wide variety of drilling applications. It is formulated to maximize flexibility while still retaining corrosion resistance over a wide pH range. TK-34XT is the first drill pipe coating developed specifically for abrasion resistance. The durability of this system is three times greater than other drill pipe coatings on the market. TK-34P is Tuboscope’s powder drill pipe coating solution. It offers superior H2S and chemical resistance in a variety of environments. As drilling environments get more aggressive and as asset replacement costs dictate the maximization of its usable life, Tuboscope can provide solutions to ensure success.


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Coating Services Cont… Used Drill Pipe Coating As the demand and overall cost for drill pipe continues to increase, maximizing the usable life out is paramount. With the vast majority of new drill pipe being internally coated for benefits such as corrosion resistance, hydraulic improvement and scale mitigation, the recoating of used drill pipe to further ensure these benefits is beginning to become a more common practice. Frequent coating evaluations are recommended to improve the longevity of the drill string and ensuring the coating if fit for service at hand.


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Coating Services Cont… Case History #1 Onshore Drilling Contractor Uses Drill Pipe Maintenance to Extend Drill String Life As the pipe ages, and the coating either becomes sufficiently mechanically damaged or finally succumbs to the environment, its benefits can be reduced. An onshore drilling contractor has practiced drill pipe maintenance for many years, which has included a recoating program. Prior to using any internal coating on their drill pipe, they would expect approximately 180,000 to 200,000 foot of drilled hole with bare pipe prior to having to downgrade the string and pick up a new one. When examining one of their recent successes after their implementation of an internal plastic coating maintenance program, this contractor was able to drill 27 wells totaling 257,652 ft of total hole prior to recoating the string. The pipe was then recoated and went on to drill an additional 55 wells and a grand total of 781,101 ft of total hole drilled. Inspection results showed 6 double white premium class, 241 yellow band, and 30 orange band joints. This particular operator drills with joints that are yellow band or better which means that 247 out of 277 joints were still usable in daily operations after over 780,000 foot drilled. Below is a table outlining the economic benefit that was achieved by the implementation of a recoating program for used drill pipe for this contractor. 4 1/2" 16.6# X-95 Drill Pipe Bare Drill Pipe

Coated Drill Pipe

Number of Joints

340

340

Cost of Pipe/jt

$ 1,200.00

$ 1,200.00

Cost to Coat/ft

$-

$ 4.00

Coating Applied

0

2

Cost of Initial Pipe

$ 408,000.00

$ 451,520.00

$ 1,632,000.00

$ 495,040.00

Cost to Reach 780,000 ft Drilled

Tuboscope’s drill pipe maintenance program was able to save this drilling contractor $1,136,960 for this particular application.


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Coating Services Cont… Case History #2 Field History of Bare and Coated Drill Pipe

A Summary of Nippon Steel investigation of washouts in drill pipe dated May 95:

Coated Pipe

Bare Pipe

130,000 feet

65,000 feet

2 years

1 year

Washouts to Date

0

22

Estimated Cost Associated with Washouts

0

$2,200,000

Cost of Failed or Replacement Pipe

0

$66,000

Total Cost of Failure

0

$2,266,000

Footage Purchased Pipe in Service


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Coating Services Cont… Case History #3 Outline of SPE Paper # 77687 – Case History: Internally Coated Completion Workstring Successes

The coated string was composed of 5”, 19.50#/ft, S-135, 4 ½” IF drill pipe some of which was 20 years old and was classified as Class 2 due to undersized tool joints. o A wall loss of 0.036” could downrate the Premium Class tubes to Class 3, making the pipe scrap. Preliminary proppant erosional tests exposed the TK-34 to 750,000 pounds of 12 ppg, 20/40 mesh ceramic proppant to 30 barrels per minute, equating to a velocity of 33 ft/sec. o “Although there were small and infrequent holidays over ~3% of the surface area, the coating served its purpose of minimizing metal exposure and wear (~97% of the area was protected with coating).” “No acid pickling treatments were needed throughout the 17 completions saving $170,000. These savings more than offset initial coating costs and any re-coating costs. This cut the cost to purchase, transport, and dispose of the acid along with eliminating the safety, environmental, and liability risks associated with handling and disposing the acid.” “Most engineers do not recognize the hydraulic benefits that can be gained by using internally coated workstrings.” o A 16% water injection rate increase was modeled and it was determined that less surface pressure is needed to pump through the coated workstring at any rate. o “In addition to obtaining the cleanest well bore from the maximum circulation rate, the reduced pipe friction from a coated workstring could possibly mean the difference between using the rig pumps to displace the well and incurring costs to use the cement unit due to higher surface pump pressures with uncoated pipe.” o “The added friction pressure from uncoated pipe creates more backpressure on the formation and thus more completion fluid losses.” “This drill pipe was handled in typical rig fashion without any consideration for the internal coating.” “No trouble time was experienced due to workstring problems during this challenging completion program.” “It was the opinion of the rig contractor that the workstring would not have survived the rigors of the Genesis completion program without an internal coating.”


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SPE 77687 Case History: Internally Coated Completion Workstring Successes Robert D. Pourciau, SPE, ChevronTexaco

Copyright 2002, Society of Petroleum Engineers Inc. This paper was prepared for presentation at the SPE Annual Technical Conference and Exhibition held in San Antonio, Texas, 29 September–2 October 2002. This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

Abstract Completion workstrings must endure an extremely hostile environment of erosive and corrosive fluids. Today’s improved internal plastic coatings can protect the significant investment in drill pipe from erosion/corrosion, as well as minimize completion trouble time caused by pipe debris (scale). An internally coated, Class 2 drill string was used for 2½ years to successfully Frac Pack seventeen, high productivity, Gulf of Mexico Deepwater completions in the Genesis Field. More than 2,000,000 pounds of abrasive proppant was pumped without a pipe failure. Introduction The completion workstring requirements were reviewed during the development well planning for the project in 1998. During completion processes, this pipe would be subjected to only minimal tensile stress and torsion; however, the pipe would need to bear the rigors of numerous Frac Pack completions. The plan originally included 22 Frac Pack completions from 16 wells with anticipated surface treating pressure of up to 10,000 psi (depending on the selected completion string diameter). The planned wells ranged in depth from 12,000’ to 23,000’ and in hole angle from 16° to 66°. During each completion, the 6 5/8” drill string would be changed to a smaller diameter completion workstring to displace the well to CaCl2 /CaBr2 completion fluid, tubing conveyed perforate (TCP) underbalance, pressure surge the perforations, wash sand fill, and Frac Pack. The workstring would then be sent to a pipe yard to be stored outdoors until the next completion operation occurred in roughly one month. After reviewing the alternatives, the rig contractor’s 5”, 19.50#/ft, S-135, 4 ½” IF drill pipe was selected for the

completion string. This workstring was a collection of used pipe with an RP7G API-IADC Used Drill Pipe Classification System rating of Class 2 due to undersized tool joints.1 Some of this pipe was as old as 20 years yet the tubes met Premium Class standards with ≥80% wall thickness (≥0.290”) remaining. Premium Class tubes have a tensile rating at minimal yield strength of 560,764 lbs and an internal yield pressure rating at minimum yield strength of 15,638 psi. The reduction in torsional strength due to the reduced tool joint diameter was not a concern due to minimal rotation for drilling cement anticipated. These specifications met the anticipated completion workstring requirements and the rig contractor was pleased to find commercial use for this drill pipe rather than scrap it for roughly $50 per joint or replace the tool joints for roughly $700 per set. An abrasion resistant internal drill pipe coating was considered to combat further internal wall loss due to proppant laden Frac Packs. A wall loss of only 0.036” could downrate the Premium Class tubes to Class 3 (<70% wall) which has no RP7G published rating for tensile forces or internal yield pressure. The drill pipe would then be scrap pipe. Additionally, the internal coating should minimize internal pipe rust and eliminate the need for acid pickle treatments. For deepwater operations, acid pickle treatments cost roughly $10,000 for purchase, transportation, rig time, and disposal. Most importantly, using an internal coating would eliminate the safety, environmental, and liability risks associated with handling and disposing of acid. A liquid-applied, modified epoxy-phenolic internal coating specifically formulated for drilling environments was considered for the completion program. Standard industry tests for coating abrasion resistance (Taber Abraser test, ASTM #D 4060) measure a test sample’s weight loss in mg over 1000 cycles of abrasion using a CS-17 wheel with a 1000 gm load.2 In 1998, the coating considered for use had results, provided by the supplier, of 47 mg of coating lost / 1000 cycles. A bare steel plate was tested to determine the weight loss without a coating; surprisingly, the results were similar (45 mg of metal lost / 1000 cycles). Taber Abraser test information, although useful to compare coatings, does not answer the question of whether a coating will survive repetitive Frac Pack treatments.

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ROBERT D. POURCIAU

Preliminary Proppant Erosion Test To qualify the proposed internal coating, an erosion test was conducted using three, six foot, 4 ½”, 12.75#, L-80, 8rd pup joints and two couplings. Two of the pup joints were internally coated to the thickness specification of 5-9 mils (125-250 µm) while one pup joint was bare. The pup joints were placed in a flow loop and 12 ppg, 20/40-mesh ceramic proppant suspended in frac gel was pumped through the samples at 30 barrels per minute. This equates to an internal velocity of 33 ft/sec. One of the internally coated pup joints was subjected to 200,000 pounds of proppant and the other joint to 750,000 pounds. The bare pup joint was tested to 1,000,000 pounds of proppant. The pup joints were cut in two-foot section lengths and then split longitudinally. All three pup joints exhibited ridges approximately nine inches from the pin nose on both ends. It was assumed this was inherent to the pipe’s manufacturing process. All pup joints also exhibited areas of rough metal. Additionally, the internal diameter (ID) of the test loop increased at the 8rd coupling connection (commonly known as the “J” area). After pumping 200,000 lbs. of proppant, the internal coating exhibited no holidays when tested with a wet sponge at 67 ½ volts DC at 70,000 to 80,000 ohms. This is in accordance with NACE TM0384-94 holiday standards for film coatings (thickness less than 10 mils).3 A “holiday” is a condition of the coating which causes the coating to fail to meet specified electrical resistance values.4 Holidays can be caused by defects such as thin coating areas, foreign material on the substrate or imbedded in the coating, coating pinholes, or metallic slivers in the pipe wall. Photo 1 shows the outer surface of the coating (0.4 mils thick), which is darker due to surface oxidation from the final baking processes, was eroded along a very thin ridge nine inches from the pin end. This exposed the lighter coating material below the oxidized surface. Coating thickness for this sample ranged from 5 to 7 mils, well within the coating specifications.

Ridge of 0.4 mil oxidized surface eroded

Flow Direction

Coating is intact

Photo 1. 200,000 lbs proppant test at 30 BPM

SPE 77687

After pumping 750,000 lbs. of proppant (Photo 2), the coating generally is lighter colored. This indicates some wear of the 0.4 mil thick oxidized outer layer of the coating. The coating also exhibited 9 small holidays within 9” from both pin ends and from the pin noses. The pin nose is exposed to the flow through the 8rd connection and coating thickness in the areas of no holidays again ranged from 5 to 7 mils.

Holidays Flow Direction Photo 2. 750,000 lbs proppant test at 30 BPM After pumping 1,000,000 lbs. of proppant (Photo 3), the bare pup joint exhibits similar areas of wear near the connections. These results are consistent with the bare steel Taber Abraser tests. Like the coated joints, the ridges and areas of rough pipe exhibited the most wear.

Ridge Flow Direction

Eroded Bare Pipe

Photo 3. 1,000,000 lbs proppant test at 30 BPM In summary, the coating performed well enough in this test to be used for the planned completion program. Although there were small and infrequent holidays over ~3% of the surface area after pumping 750,000 lbs of proppant, the coating served its purpose of minimizing metal exposure and wear (~97% of the area was protected with coating). Numerous laboratory and field case histories document that pipe with coating holidays or wireline cuts has a lower corrosion rate than if uncoated.4,5,6,7,8,9 The coating loss for the 750,000-lb. proppant test was roughly 0.4 mils of the topcoat in some areas and 7 mils in the areas of the holidays. This equates to a maximum coating loss of 65 lbs. (<0.01% by weight of the proppant pumped) for a 15,000’ workstring of 5” drill pipe. This coating loss should not cause a measurable reduction of gravel flow capacity based on industry proppant conductivity tests with contaminating foreign particles.10

SPE 77687

CASE HISTORY: INTERNALLY COATED COMPLETION WORKSTRING SUCCESSES

The pup joint’s ridges, rough spots, and connection areas exhibited the most coating wear. These results infer that the irregular internal surface of the second-hand workstring would be susceptible to erosion greater than experienced in the test loop or what would be expected of a newly coated workstring. Also, since the area of most wear was near the connection profile change, the planned workstring’s IF connection with 2.75” tool joints and 4.276” tubes should be likely to develop wear. Field Results – Well Productivity Well productivity can be impaired by contaminants which reduce the formation’s permeability, reduce proppant permeability, reduce gravel pack screen conductivity, or plug the perforation tunnels creating extra near-well pressure drop (skin effect). The main contaminants typically present are mill scale, iron sulfides, pipe dope, sand, and other fine particles which are picked up during storage and transportation.11 The Genesis wells overcame these damaging contaminants and have good productivity. The average skin factor is 2.9 and the average production rate is 14,000 BOEGPD. Iron scale and sulfides on the pipe wall are usually treated with an acid pickle and pipe dope is usually treated with a solvent just prior to frac packing. Frequently, the pipe dope prevents the acid from fully contacting and removing the scale. With a coated workstring, all that is needed during the pickle treatment is solvent to remove pipe dope since the internal coating greatly reduces the iron scale presence. No acid pickle treatments were needed throughout the 17 completions saving $170,000. These savings more than offset initial coating costs and any re-coating costs. Dissolved iron could be a critical factor in formation damage since precipitation of iron complexes can occur in some brines if dilution with formation waters causes an elevation of pH.12 Iron scale solubilized from downhole tubulars introduces dissolved and suspended solids to the completion fluid which can create an endless cycle of circulation and filtration to reach fluid specifications. Often this remedy is temporary or not effective. The CaCl2 /CaBr2 completion fluids used did not have any unusual dissolved or suspended iron problems. This is partially attributed to the internal workstring coating, coated pits, and coated troughs. Field Results – Pipe Debris Managing pipe debris is critical to completion processes. As an example, pipe debris can indirectly be a safety hazard if live TCP guns have to be pulled due to a stuck firing bar. Also fishing stuck tools (wireline, packers, gravel pack washpipe, etc) can get quite costly. At Genesis, 8 wireline trips, 8 TCP bar drop operations, and 24 ball drop packer setting jobs were conducted through the subject workstring without any trouble time caused by pipe debris (scale). The gravel pack tools were thoroughly checked for debris following each gravel pack operation and, on only

3

one occasion, small flakes of coating remnants were recovered from the gravel pack crossover tool. Throughout the completion program, the major debris components observed from these checks was steel perforating debris and/or cement. Field Results – Proppants High rate Frac Packs are known to erode surface and downhole equipment. Proppant mass, concentration, and pump rate must be reviewed and compared with equipment’s ratings when designing completions. Equipment should be pressure tested to the maximum anticipated surface treating pressure. The second-hand 5” drill pipe workstring was used during the Frac Packs of all seventeen completions. Stimulation vessels pumped 1.8 MM lbs. of proppant at 10 to 25 BPM and a total of 0.5-MM lbs. of excess proppant was reversed from the wells during the completion program. All completions used ceramic proppant, except one, which used bauxite. Obviously the proppant schedules pumped during the completion program were not a constant 12-ppg concentration like the abrasion loop tests. Additionally, the workstring had to endure annular screen outs with peak pressures over 10,000 psi and the excess proppant had to be reversed from the wells. Both of these events are sometimes forceful and agonizing. Due to significant internal restrictions, the tool joint flow velocity is 2.4 times higher than the tube velocity. The tube velocity ranged from 9.4 to 23.8 fps; whereas, the tool joint velocity ranged from 22.7 to 57.6 fps and exceeded the flow loop test velocity of 33 fps. Field Results – Mechanical Abrasion and Impact In addition to the abrasion from proppants, the workstring withstood the mechanical effects of 8 wireline trips to correlate completion tools, 8 TCP bar drop operations, and typical (rough) drill pipe handling. Both braided electric line and single core slickline operations occurred during the completion program. As a result, roughly 10% of the tool joints have wire line cuts through the coating. Photos 4 and 5 show a representative wireline scared coated tool joint and also previously wireline scared pipe which has been re-coated. A total of 8 wireline trips occurred and equate to a maximum possible wireline exposure of 136,400 ft. Industry and NACE RP0291-91 recommended wireline procedures to minimize coating damage were not used at Genesis.6,7,13,14,15 Some of these recommendations include maximum wireline speed of 100 feet per minute, no free falling tools, no sharp edge tools, single strand line, and well lubricated slickline. Previous industry studies indicate that coatings succumbed to wireline abrasion after 18’-15,000’ of wire was passed across the samples.7,16,17 Abrasion rates of each coating were related to the type and condition of the wire, the wire velocity, and the applied wire force against the coating. Although each joint of the workstring was subjected to varying wireline lengths and forces, it is estimated that the footage of wire exposed to the coating far exceeded any of these industry tests.

4

ROBERT D. POURCIAU

The TCP bar drop process occurred 8 times and involved dropping a 1¼” x 10’ steel detonating bar weighing 35 lbs. inside the workstring from the surface. Roughly 650 ft of the workstring was dry (air cushion) and the remainder of the workstring was liquid filled during this operation. This bar must certainly make quite an impact with each restricted tool joint since every well was directionally drilled. During previous industry tests, numerous coatings were checked for impact resistance using ASTM D 2794-82 and most had an impact resistance of 30-300 in-lbs. before cracking or chipping.16,18

SPE 77687

per segment) while the spring-loaded slips have 4 segments (2 columns of dies per segment) and the elevators are bottleneck types. It has been reported that an external dent as small as 0.075” deep frequently causes internal coatings to crack7 . Since impact damage during pipe handling can result in chipping of the coating at or near the ends of the tool joints or disbondment of the coating, careful handling procedures are typically recommended.6,13,15,19 This drill pipe was handled in typical rig fashion without any consideration for the internal coating (ie: not handled like production tubing or industry guidelines for coated pipe). Field Results - Corrosion The workstring was also subjected to corrosive fluids (pipe dope solvent, acid, frac gel, and brine) of both low and high pH for extensive periods. All coatings have a measurable resistance to corrosive fluids, which depends upon the fluid type/concentration and temperature. Coating degradation is irreversible and can be added to during subsequent chemical and mechanical exposure.6,13,15,16,17

Wireline Scar

Photo 4. Coating is wireline scared

Coated Wireline Scars

Photo 5. Boroscope image of well bonded coating over wireline scars Between wells, the subject workstring was picked up and laid down in doubles, which creates more bending stress and coating bondment challenges than handling the pipe in single joints. Conventional rotary slips, or four-segmented, springloaded slips were set below each box. A spinner was used to make up the pipe until the sealing surfaces of the IF connection contacted, and drill pipe piston type four point contact power tongs were used to torque the drill pipe to specifications. Full wrap-around tongs, which are typically recommended for coated pipe, were not used. The conventional rotary slips have 3 segments (2 columns of dies

Some coating systems can be damaged by exposure to organic pipe dope solvents.6,15 The Genesis workstring was routinely treated before each Frac Pack with an average of 500 gal of d-limonene solvent to remove pipe dope. The pipe dope and solvent were chosen based on favorable “in-house” pipe dope removal tests. The downhole gravel pack tools and solvent returns were occasionally examined during the completion program to ensure proper pipe dope selection and pickle effectiveness. This solvent was pumped and reversed from the workstring at a sufficient volume and rate to give 510 minutes of contact time. This totals 2.3 hrs of contact time for the entire completion program. Roughly 3000 gal of 20% Acetic/Formic stimulation acid, with corrosion inhibitor, was pumped after the pipe pickle and immediately before each fracture calibration test. This acid was used to clean the perforations of any HEC remaining from previous fluid loss pills or perforating debris sweeps. The coating was exposed to this acid for approximately 1 hour during each treatment (17 hrs for the entire program). On average, 30,000-gal of high pH (9.0-9.5) borate crosslinked frac fluid was pumped during the preliminary data calibration test and the Frac Pack of each completion. Fracture fluids are typically high pH in order to properly cross-link guar polymers and reach the desired fluid viscosity for proppant transport. Exposure time to this high pH gel was approximately 2.25 hours during each completion (39 hrs for the entire program). The most onerous exposure the workstring endured was from corrosive 5.7-6.7 pH CaCl2 /CaBr2 (CaCl2 for one completion) during completion operations and while in storage. Visual inspections at the pipe yard revealed a layer of salt on the bottom of each joint (Photo 6). This salt evaporate is due to not internally rinsing the pipe and evaporation of the

SPE 77687


water from the completion fluid during outdoor storage. The coating was exposed to this brine downhole for a cumulative exposure time of roughly one year. The workstring was usually externally (not internally) rinsed before being sent to a pipe yard for storage outdoors (total time ~1.5 years).

Dry Salt

of the workstring and casing. The mud displacements were pumped with the rig pumps in turbulence at 12 to 23 BPM (16 BPM average). The displacement rate was influenced by each well’s hydrostatic pressure differential when pumping seawater spacers and by pipe friction. Obtaining maximum flowrates during mud displacements was especially crucial for some of the deeper wells, which exceeded 20,000 feet with greater than 67 degrees of hole angle. One such completion was displaced with only 41% of the hole volume (after bottoms up) to reach brine clarity specifications of 20 NTU’s. Prior to the short trip, displacement pills were circulated at the maximum rate (15 BPM). In addition to obtaining the cleanest possible well bore from maximum circulating rate, the reduced pipe friction from a coated workstring could possibly mean the difference between using the rig pumps to displace the well and incurring costs to use the cement unit due to higher surface pump pressures with uncoated pipe.

Coated 5”

Photo 6. Pipe in storage with CaCl2 /CaBr2 salt evaporate The coatings used at Genesis have supplier recommended cumulative exposure limits of 40 hrs for 15% HCl, 40 hrs for 15% Acetic, 40 hrs for 20% NaOH (caustic), and 16 hrs for 12% HCl / 3% HF (mud acid). Industry recommendations are to flush coated pipe following corrosive treatments.6,13,15 The drill pipe was reverse circulated with a minimum of two drill pipe volumes (~500 bbls.) of completion fluid following each pipe dope solvent, acid, and Frac Pack treatment. Field Results - Hydraulics Most engineers do not recognize the hydraulic benefits that can be gained by using internally coated workstrings. The surface finish of coated workstrings reduces friction due to lower surface roughness, which is beneficial throughout completion operations. Unfortunately, the second-hand 5” workstring was pitted before being coated and there is no hydraulic data that documents the workstring’s roughness factor. One can only suppose that coating an extremely rough, pitted workstring should yield hydraulic benefits. It is difficult to calculate the coating’s hydraulic effects due to the significant tool joint restrictions and the pitted nature of the pipe. Systems Analysis indicates ~16% water injection rate increase can be achieved (Figure 1) at maximum rig pump pressure using 16,000’ (Genesis average) of internally coated 5” drill pipe with an absolute roughness of 0.000157” rather than using uncoated pipe with an absolute roughness of 0.0018”. Similarly, less surface pressure is needed to pump through the coated workstring at any rate.20 During mud displacements to completion fluid, maximum circulating rate is desired to achieve turbulent flow effects, which help remove mud film and water wet the pipe surfaces

5

16% Rate Difference

Bare Pipe

16 BPM 25% Pump Press. Difference

Press. Limit of Rig Pumps

Figure 1. Systems analysis of water injection through 16,000’ of coated and bare 5” drill pipe During perforating work, lower pipe friction is desired to reduce circulating bottom hole pressure, and thus reduce fluid losses when reversing out formation fluids or sand fill. The added friction pressure from uncoated pipe creates more backpressure on the formation and thus more completion fluid losses. This can be expensive and detrimental to the pay interval’s productivity. The typical fluid volume lost during the Genesis perforating process was ~200 bbls per completion zone. Frac Pack operations obviously benefit from reduced pipe friction. Key Frac Pack design issues are the size of the workstring and subsequent friction pressure caused from high rate pumping of cross-linked gel and proppant. The workstring must be designed to ensure adequate flowrates are obtained to achieve desired frac height growth. Surface pressure-relief equipment is used to avoid the catastrophic failure of downhole completion equipment. Pipe friction is usually

6

ROBERT D. POURCIAU

SPE 77687

considered when setting surface pressure relief equipment and directly affects the job pump rate. Workstring Inspection History and Results During the completion program, no washouts, drill pipe failures (parted pipe), or leaks occurred. In summary, no trouble time was experienced due to workstring problems during this challenging completion program. Seven pipe inspections occurred during the program. The focus of each inspection was the tool joint condition; however, three of these inspections (initial, mid-program, and final) also checked for wall thickness. The tool joints were visibly inspected throughout the program for coating condition and the tubes were also visibly checked with a video camera and boroscope on one occasion. The coated drill pipe was used for the first three completions before a tool joint inspection occurred during July 1999. During these first three completions, roughly 260 k-lbs of proppant was pumped and 85 k-lbs. was reversed from the workstring. The original coating was removed from 180 joints due to the coating being graded by the coating company as “C” in the tool joints. A coating grade of “C” means that there are several areas that exhibit chemical and/or mechanical damage that has not yet breached the coating surface to the base metal as well as areas of damage to the base metal. In minor to moderate drilling and completion environments, a coating grade of “C” would not immediately warrant the recoating of the particular joint. The 180 joints were re-coated with a newly modified liquid-applied, epoxy-phenolic coating which was formulated for enhanced abrasion resistance over it’s predecessor without losing any of the chemical resistance or other mechanical properties (impact resistance and flexibility). This newly modified coating, when tested on ASTM #4060 Taber Abraser apparatus yielded an abrasion resistance value of 11 mg of material lost per 1000 cycles. This analysis indicated that this new coating was four times as abrasion resistant as it’s predecessor. Photos 7-9 show the coating after the ninth completion was generally intact and well bonded with small areas of corrosion. As mentioned earlier, infrequent, wireline scores were observed; however, the scores didn’t exhibit significant corrosion damage and the coating in the surrounding area was well bonded. During this inspection, 160 joints (26%) were rejected due to tool joint dimensional problems. Only 75 joints (12%) were rejected due to ≥0.036” of tube wall loss from the original ≥80% wall (Premium Class) to <70% wall (Class 3). The rig contractor supplied 269 additional second-hand joints with the newly formulated, enhanced abrasion resistant coating as rejected joints were removed from service. The remaining completions were conducted with this final collection of Class 2 drill pipe having both coatings.

Well Coated Pits

Photo 7. Good coating adhesion, minor corrosion & holidays

Video Camera Light

Coated Irregular Surface

Photo 8. Video camera image of well adhered coating to irregular pipe surface

Video Camera Prism

Coated Smooth Surface

Photo 9. Video camera image of well coated, smooth tube

SPE 77687


A video camera and boroscope were used to inspect the full length of 21 joints after the ninth completion (Photos 5, 8, and 9). The results indicated that the tubes were in excellent condition with isolated blisters and rated as “B” by the coating company. A coating grade of “B” means that there is minor wireline wear and erosion with a few coating chips, unbroken blisters, and exposed primer. The tool joints and run out area showed more wear than the tubes with roughly 80% of the joints rated as “C” and 20% rated as “F”. A coating grade of “F” means that there is severe flaking, blisters, and loose or missing coating. Since most of the metal surface area (tube area) was well protected by the coatings, the pipe (which met dimensional specifications) remained in service. End of Program Representative Samples After the completion program ended, the drill pipe was inspected for tool joint dimensions and wall thickness. Only one joint was rejected for low wall thickness. Additionally, the operator selected a couple of joints for a closer look. Photo 10 shows two representative samples that were cut in (3) threefoot sections. The pipe was cut 3 ft. from each end and 3 ft. was cut from the center tube area (not pictured). In summary, the joints with the original coating were used throughout the entire completion program (2,241,615 lbs proppant pumped) and the coating covered 97% of the drill pipe internal surface area based on analysis of the representative samples. This coincidentally is the same as during the 750,000 lb. preliminary proppant test. Significant holidays are observed 2-3 feet from the box ends and a 6”-8” circumference is entirely void of the coating in the upset runout area. This wear far exceeds the wear noted throughout

7

the remainder of the joint and is likely attributed to turbulence from flow divergence downstream of the internally restricted tool joint. This is also the area where slips are set, which can only make coating bondment more challenging. The tube has the largest internal diameter, most surface area, and was practically fully coated. The pin end has minor areas of holidays and a lighter coating color in the reduced ID connection due to surface wear. The representative sample of the new, improved coating appeared in much better condition than the original coating sample. The joints with this new coating were introduced into the completion string after the third completion due to recoating 180 joints and after the ninth completion to replace pipe rejects. The pipe with this coating was exposed to a range of proppant mass between 941,000 lbs and 1,897,000 lbs. The improved abrasion resistance was evident from the excellent condition of this sample. This improved coating covered 99.9% of the internal surface area. Minor ridges of holidays appear two feet from the box ends in the upset runout area and a 6”-8” circumference in the upset runout area is lighter colored due to coating surface wear. This surface wear, although much less than the original coating’s representative sample, is also likely due to turbulent flow. The tube is well coated and the pin end has minor areas of holidays with a lighter coating color in the tool joint due to surface wear. It was the opinion of the rig contractor that the workstring would not have survived the rigors of the Genesis completion program without an internal coating.

Original Coating

Frac Pack Pump Direction

Significant Wear

Improved Coating

Minor Wear Photo 10: Representative Samples After Program was Completed

8

ROBERT D. POURCIAU

Conclusions Based on the field experience obtained during the completion program for the Genesis development, the inspections performed, and the data thoroughly analyzed, the following conclusions are offered. 1.

2. 3.

4.

5.

The internal coatings did not cause skin damage to 17 Frac Pack completions (average production rate is 14,000 BOEGPD and average skin factor is 2.9) The coatings had a significant unexpected side effect of debris (scale) mitigation, eliminating trouble time. The original liquid-applied, modified epoxy-phenolic internal coating held up well (97% surface area coverage) and the improved coating held up better, (99.9% coverage) to: 2.2 MM lbs. proppant, 8 TCP bar drops, 8 wireline runs, 6000 gal of organic solvent, 56,000 gal of acid, 501,000 gal of high pH frac fluid, and CaCl2 /CaBr2 during 17 Frac Packs over 2 ½ yrs. The coatings protected the pipe and prevented any integrity failures during completion work. There was never a leak or washout and only 75 joints (12%) were rejected due to wall loss in the tubes. The coatings eliminated the need for acid pickle treatments due to minimizing internal pipe rust. This cut the cost to purchase, transport, and dispose of acid (~$10,000 per well) along with eliminating the safety, environmental, and liability risks associated with handling and disposing of acid.

Acknowledgments The author would like to acknowledge the considerable input and assistance given by John Champagne, Rick Jackson, Robert Lauer, Charlie Speed, and Bill Snider of Tuboscope Inc., David Barbin, Bill Rau, and Larry Hathcock of ChevronTexaco, J.R.Slaten of D.C. International, Ron Morrison, Lonnie Mills, David Hinton, and Shelton Lejeune of Nabors Offshore Corporation, David Barton of Global Completion Services, and Bart Waltman of Halliburton. Special recognition goes to Curt Newhouse of ChevronTexaco, and Nabors Offshore Corporation for championing the use of coated drill pipe for the Genesis workstring. Without their efforts to track and inspect the workstring over the past 2½ years, this paper would not have been possible. Tuboscope Inc. and Halliburton are appreciated for the preliminary coating erosion tests, documenting well treatment parameters, monitoring pipe debris in gravel pack tools, and the final drill pipe sample analysis at the end of the project. Finally the author wishes to thank ChevronTexaco management for permission to publish this paper.

SPE 77687

References 1.

2. 3.

4.

5.

6.

7.

8.

9. 10. 11.

12.

13.

14.

15.

16.

17.

18.

19.

API RP 7G Fifteenth Edition, January 1, 1995, “Recommended Practice for Drill Stem Design and Operating Limits”, Tables 4 and 5, API, Washington, D.C. ASTM D 4060-81: “Abrasion Resistance of Organic Coatings by the Taber Abraser” ASTM, Philadelphia, PA. NACE Standard TM0384-94: Holiday Detection of Internal Tubular Coatings of Less Than 250 um (10 mils) Dry Film Thickness, NACE International, Houston, TX. Campbell, C.A. III: “Effects Of Holidays Or Mechanical Damage On Internally Plastic Coated Tubulars,” Corrosion/79 Paper 257, NACE International, Houston, TX. Roberson, G.R.: “Comparison of Corrosion Rates: Wireline-Cut Plastic Coated Oil Well Tubing vs. Wireline-Cut Bare Tubing,” Materials Performance, Vol. 13, No. 12, pp. 26-28, presented as part of a panel discussion at a meeting of T-1G at Corrosion/74, NACE International, Houston, TX Davis, R.H.: “The Use Of Internal Plastic Coatings To Mitigate CO2 Corrosion In Downhole Tubulars,” Corrosion/94 Paper 23, NACE International, Houston, TX. Wolfe, L.H. et al.: “Laboratory Testing Of In-Service Performance Parameters Of Internal Pipe Coatings,” Corrosion/92 Paper 333, NACE International, Houston, TX. Byars, H.G.: “Corrosion Control In Petroleum Production,” TPC Publication 5, Second Edition, NACE International, Houston, TX. Roberson, G.R.: “Materials Performance” 13, 12 (1974): p.26. Coulter, G.R.: “The Advantages of High Proppant Concentration in Fracture Stimulation” paper SPE 3298, June, 1972 Nasr-El-Din, H.A. et al.: “Lessons Learned from Acid Pickle Treatments of Deep/Sour Gas Wells,” paper SPE 73706 presented at the 2002 SPE International Symposium and Exhibition on Formation Damage Control held in Lafayette, LA., 20-21 February Ali, S.A. and Shelby, D.C.: “Guidelines for Rig-Site Removal of Iron Contamination from Completion Brines”, February 1999, Petroleum Engineer International NACE Standard RP0291-91: Care, Handling, and Installation of Internally Plastic-Coated Oilfield Tubular Goods and Accessories, Section 7: Operation, NACE International, Houston, TX. Thompson, I. et al.: “Evaluation Of Coating For The Protection Of Downhole Production Tubing,” Corrosion/97 Paper 66, NACE International, Houston, TX. Nelson, J.M.: “New Advancements in the Use of Internal Plastic Coating for Enhanced Oil Recovery,” Materials Performance, Vol. 30, No. 12, pp. 27-30, 1991, NACE International, Houston, TX Lewis, R.E. and Barbin, D.K.: “Selecting Internal Coatings For Sweet Oil Well Tubing Service,” Corrosion/99 Paper 15, NACE International, Houston, TX. Lewis, R.E. and Barbin, D.K.: “Selecting Internal Coatings For Gas Well Tubulars,” Corrosion/97 Paper 70, NACE International, Houston, TX. ASTM D 2794-82: “Resistance of Organic Coatings to the Effects of Rapid Deformation (Impact)” ASTM, Philadelphia, PA. Wells, K.R.: “The Reduction of Coated Tubing Failures in the Dickinson Heath Sand Unit, North Dakota,” paper SPE 17525 presented at the 1988 SPE Rocky Mountain Regional Meeting held in Casper, WY., 11-13 May

20. P.E. Moseley and Associates, Inc., “The Well Evaluation Model - WEM For Windows”Houston, TX.

Matterhorn: A Case Study The Use of Internal/External Plastic Coatings in Completion Processes Tuboscope’s TK-34XT internal plastic coating has provided for enhanced benefits in corrosion control, hydraulic improvement, scale control, and wear mitigation in drilling and completion environments. Introduction In 1999 Tuboscope developed TK-34XT. TK34XT is a liquid applied epoxy phenolic coating that is a basic modification of the existing TK-34 product. TK-34, introduced in 1960, is the original drill pipe coating used in the market. As the industry progressed and completion operations involved more abrasive fluids and more corrosive chemicals, improvements were needed. TK-34XT met these needs by providing 4 times the abrasion resistance of the original TK-34*. In 2002, SPE published a paper (SPE 77687) written by Robert Pourciau with ChevronTexaco, which outlines the use of internal plastic coatings for completion operations. This case study outlines further operations performed by Total on the Matterhorn project that validate previous claims. Pipe Dynamics For this phase of the Matterhorn project, two different tubing sizes were needed. First was a 4 ½” WTS 6, 15.5# P-110 with a Hydril PH6 connection, and second was a 3 ½” WTS 6, 12.95# P-110 with a Hydril PH6 connection, both internally coated with TK-34XT. It should also be noted that the pipe was used material and had a defined level of surface corrosion and pitting prior to coating. Job Execution The information provided in Table 1 and Table 2, documents the severity of the work performed with this completion string. To date, there have been 17 completions performed in which a total of 57,270 gallons of 10% acetic acid has been pumped in addition to 1,679,008 pounds of 30/50 EconoProp being injected. The majority of this work was performed in wells with deviations from 23° to a maximum of 75°, thus showing

the flexibility of this particular coating system. With all that has been performed through this string, the pipe never needed to be acid pickling, because the surface characteristics of the coating material mitigated deposit formation. One of the side benefits from scale deposit mitigation is that there is a reduced concern about scale particulates coming lose from the pipe surface and can plug in screens, the formation or in the tubulars. Inspection Results The main purpose of the internal coating is to protect the steel and in turn extend its effective life. To minimize potential steel failure, periodic inspections are performed. These inspections include electromagnetic inspection of the pipe body as well as a magnetic particle inspection on the tooljoints. The results of these inspections indicate that of the 307 joints analyzed, 285 joints were premium class, 18 joints were premium class but required re-cutting of the threads and seals, and 4 joints were red band rejects due to dents, gouges, and cracks. These results are particularly impressive considering this pipe was made up and broken out a total of 150 times. After completion of the described processes, not one joint was downgraded due to general corrosion or wall loss from the internal surface of the pipe. External Coating Performance During the course of this work, 6 joints were pulled from the string to have external coating applied at the request of Total. The reasons behind this request was the desire to minimize rust scale which causes a delays in rig time due to the need to clean the external surface. Three of the joints were externally coating with the TK34XT product, while the other three joints were externally wrapped with a product called RytWrap. Ryt-Wrap is a PPS wrap tape that uses an epoxy adhesive agent. While both products provided the needed external protection, the RytWrap appears to provide added benefit is that is more impact resistant as well as its ability to be

Photo of used Ryt-Wrap on the rig Contact Information Please contact Jose Piedras TOTAL E&P USA, Inc. (e-mail: [email protected]) or via phone: (713) 647-3379 for more details regarding the Matterhorn completion process for this Sub-sea well. For more information regarding internal plastic coating capabilities, please contact Robert Lauer Tuboscope (e-mail: [email protected]) or via phone: (713) 799-4571.

field repaired.


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Table 1: Well Completion Information Well

Reservoir

A-7

E Sand

A-7

C Sand

A-2

A Sand

A-2

A Sand

A-4

C Sand

A-4

B Sand

A-4

A Sand

A-3

C Sand

A-3

A Sand

A-10

B Sand

A-10

A Sand

A-10

A Sand

A-5

A Sand

A-5

A Sand

A-9

C Sand

A-9

B Sand

BHP, psi

BHT, °F

6,715

165

4,122

Deviation, (°)

Top Perf – md

Bottom Perf – md

Top Perf – tvd

Bottom Perf – tvd

Production Type

1

10,125

10,156

9,930

9,961

Gas

141

25

7,853

8,016

7,658

7,806

Oil

3,425

116

54

7,588

7,723

6,512

6,591

Oil

3,425

116

54

7,313

7,488

6,447

6,493

Oil

4,677

129

31

8,353

8,423

8,036

8,096

Oil

4,343

125

31

7,838

7,934

7,519

7,601

Oil

3,124

113

23

6,449

6,663

6,294

6,373

Oil

4,744

137

25

10,405

10,499

8,138

8,223

Oil

3,316

100

64

7,863

7,953

6,287

6,327

Gas

3,572

107

48

8,853

8,883

6,816

6,836

Gas

3,250

120

67

7,481

7,668

6,170

6,242

Oil

3,212

117

75

7,081

7,218

6,057

6,094

Gas

3,454

121

58

8,750

8,783

6,670

6,688

Oil

3,454

121

58

8,450

8,520

6,531

6,560

Oil

4,116

132

50

8,923

9,011

7,701

7,758

Oil

3,601

116

60

7,543

7,620

6,951

6,992

Gas

Table 2: Well Pumping Data Well

Reservoir

Acid Volume gal

Frac Fluid

Rate, bpm

Proppant Pumped, lbs

Treating Pressure, psi Avg / Max

A-7

E Sand

1,000

Spectra G 2500

18

48,503

3,900 / 6,200

A-7

C Sand

3,360

YF120LG

25

134,369

2,500 / 5,500

A-2

A Sand

6,500

YF120LG

25

152,394

1,800 / 4,000

A-2

A Sand

8,000

YF120LG

25

116,584

1,300 / 7,060

A-4

C Sand

2,500

Spectra G 2000

15

58,566

2,300 / 7,800

A-4

B Sand

3,400

Spectra G 2500

20

99,959

2,800 / 3,600

A-4

A Sand

4,360

YF120LG

25

161,132

2,000 / 5,000

A-3

C Sand

3,500

Spectra G 2500

24

92,304

4,000 / 4,300

A-3

A Sand

6,000

YF120LG

21

70,375

1,900 4,750

A-10

B Sand

750

Viking 20

10

63,391

1,400 / 4,600

A-10

A Sand

6,000

YF115

25

200,742

2,100 / 4,629

A-10

A Sand

6,000

YF115

25

140,000

2,000 / 4,800

A-5

A Sand

825

Viking 20

8

25,190

1,900 / 4,700

A-5

A Sand

1,750

Viking 20

14

103,259

1,800 / 3,600

A-9

C Sand

1,700

Viking 20

22

111,097

2,500 / 4,000

A-9

B Sand

1,625

Viking 20

20

101,143

1,700 / 3,350


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Extending the Life of Used Drill Pipe An Internal Coating Management Process


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Why Recoat Drill Pipe? Drill Pipe is the single most expensive consumable (asset) a Drilling Contractor will purchase over the life of a drilling rig. One solution to increasing the life of Drill Pipe is through an internal coating management process. Extending the useful life of drill pipe will reduce the frequency and need to purchase new tubulars. More than 85% of all drill pipe is internally coated. The internal coating is designed to protect the pipe from corrosive environments during the drilling and work over process. So why is it when drill pipe coating starts to show signs of deterioration through extended use do we not recoat it? Simply speaking, most drilling contractors and operators are not aware that used drill pipe can be recoated. Tuboscope has been providing internal coatings for tubing, casing, drill pipe and line pipe for more than 60 years. The TK product line of internal coatings have been formulated and tested to provide value added benefits towards protecting these tubulars from corrosion, erosion, scale and wax deposition, and to enhance the material performance of bare steel. Maintaining the integrity of the internal coating, through an internal coating management process will: -

Extend the useful life of the drill pipe Reduce down hole failures normally resulting in zero rate Conserve capital expenditure requirements Improve hydraulic efficiency


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Why Recoat Drill Pipe? Cont…

The following Case Histories are provided to show the positive effects of an internal coating management process. In this first Case History a drilling contractor compared a new string of internally coated 4 ½” drill pipe to a new string of bare (non-coated) drill pipe. The comparison was done in order to determine the total cumulative drilled feet with each string until the string was downgraded from “Premium” condition. The results of this test are shown in the following table.

DRILLING PERFORMANCE (Case History – Coated Drill Pipe) # of Joints Coated

Feet Drilled

Cumulative Feet Drilled

# of Joints Graded Premium

New Pipe (Coated)

279

210,000

210,000

279 (100%)

Recoat #1

279

249,672

459,672

246 (89%)

Recoat #2

246

158,328

618,000

181 (65%)

Recoat #3

181

332,000

950,000

Majority Downgraded

Note: A new string of bare drill pipe (same size, weight and grade) was used by the same operator in the same field and the majority was downgraded after drilling less than 200,000 cumulative feet. The drill pipe in this case history was 4 ½”.


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Why Recoat Drill Pipe? Cont… In this next Case History the contractor wanted to use an existing string of 5” drill pipe for workover operations instead of purchasing a new string for this purpose. For more information please refer to SPE document SPE 77687. The used string was first inspected and only those joints meeting premium condition were selected for recoating. The pipe was recoated with Tuboscope TK-34XT coating product. The photo shown below is after:

17 Frac Pack Completions using more than 2,000,000 lbs of proponent 136,000 ft of wireline operations 8 TCP bar drops 24 ball drop packer setting jobs No acid pickling required

The Case Histories mentioned above are only two examples of how an effective internal coating management process can extend the useful life of drill pipe. Now let’s look at the management process in detail.


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Why Recoat Drill Pipe? Cont… Internal Coating Management Process Selecting the pipe for recoating is obviously the first step in the process, but how do we determine which pipe is suitable for recoating. Which pipe is suitable for recoating? In every Tuboscope tubular inspection process and all inspections carried out in accordance with T. H. Hill DS-1, NS-1, NS-2, or API RP 7G, the condition of the internal coating is given to the customer as part of the inspection report. The internal coating is graded based on visual examinations. Prior to evaluating the internal coating the pipe must undergo the following preparation. 1. Pipe to be visually inspected shall be cleaned internally, preferably with high-pressure water jetting equipment. Removal of drilling mud, chemical residues, dust and dirt, and other visible contaminants is required. NOTE: Water blast pressure should not exceed 5,000 psi. 2. The pipe I.D. is dried with compressed air to remove residual water prior to visual inspection. 3. To help determine fitness for purpose, Classes A, B, C, and F have been established to provide guidelines for evaluating the condition of the coating. 4. Photographs showing the varying conditions of the Classifications are recommended for training inspectors and can be used to assist in the decision process. (See following page for photographs and detailed information)


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Why Recoat Drill Pipe? Cont… Example

Grade

Description

Grade “A”

Light erosion and wear, no chipping, no coating loss, or new coating.

Grade “B”

Minor wireline wear and erosion with a few chips, unbroken blisters, and exposed primer. Coating loss is less than 5%.

Grade “C”

Small hard flakes and ruptured blisters, heavy wireline wear, and erosion. Coating loss is between 5% and 15%.

Grade “F”

Severe flaking, blisters, loose or no coating. Coating loss greater than 15%.

Upset Run-out

Tube Body

Note: The primary concern of any coating evaluation should be placed first on the condition of the coating in the upset and run out zone at the pin and box end. These transition areas are subject to the most wear and abrasion during wireline trips and high pressure pumping environments. According to a studied carried out by API, most pipe failures occur in these transitional areas.

Rule of Thumb: The use of Grade “C” pipe in normal drilling operations is acceptable. However, the coating should be re-inspected after each use. Only Grade “A” and “B” pipe should be used in deep, high temperature, high pressure Gas wells with significant amounts of CO2 and/or H2S. Where the pipe is to be used for conveying highly corrosive chemicals such as in frac jobs, it is recommend that the coating have a minimum grade of “B”. This pipe should be monitored and re-evaluated after each job or every time the pipe is laid down.


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Why Recoat Drill Pipe? Cont… Once the pipe has been evaluated for its internal coating condition and those not meeting the minimum usable requirements are set aside, it is now time to determine if the pipe meets the recommended minimum dimensional requirements. It would not be economical to recoat pipe where the tool joint dimensions or remaining wall thickness do not allow for additional continued service. In addition to routine inspection, it is recommended that the following four (4) dimensional checks be made on each length to determine recoating suitability. 1. 2. 3. 4.

Tool Joint Outside Diameter (OD) Tong Space on Pin Connection Tong Space on Box Connection Minimum Wall Thickness of Tube Body.

Now that the pipe has been selected for recoating based on the Coating Grade and Dimensional Properties, it is time to determine the best internal coating material for the application; your local Tuboscope representative can assist you with this process. Selecting the Coating Material Over the years Tuboscope has developed several internal coating materials designed to protect and improve the performance of drill pipe while exposed to different environments. Protection against H2S, CO2, and other corrosive elements commonly encountered during drilling and performance enhancement for flow (hydraulic) improvement is the most common. The Tuboscope TK product lines for drill pipe coating include: TK-34

Epoxy Phenolic Liquid Coating designed for corrosion protection and improved hydraulic efficiency.

TK-34XT

Epoxy Phenolic Liquid Coating designed for corrosion protection, improved hydraulic efficiency and superior abrasion resistance.

TK-34P

Epoxy Novolac Powder Coating designed for high temperature, high pressure, sweet and sour drilling environments, H2S, CO2, corrosion protection, improved hydraulic efficiency and abrasion.

Contact your local Tuboscope representative for additional specifications and test reports on the above TK products.


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Why Recoat Drill Pipe? Cont… Where can I get my pipe recoated? Tuboscope operates 17 pipe coating plants throughout the world and these plants are all capable of coating new and used tubulars. In South-East Asia the coating plant is located in Batam, Indonesia. Your local Tuboscope representative will assist you with complete door to door service if required. What happens to my pipe when it arrives at the coating plant? The following coating process is applied to every joint of drill pipe. The process may very depending on the coating material applied and the condition of the used pipe upon arrival. 1. The pipe is received at one of our regional pipe coating plants 2. The pipe is racked and placed in an oven for thermal cleaning (≈750°F) 3. The pipe is internally blasted to a NACE#1 white finish (Aluminum oxide) 4. A thin film primer is applied on the pipe ID surface 5. The primer is baked to its curing stage 6. The internal coating is applied to the pipe ID surface 7. The coating is baked to its curing stage 8. The coating thickness is measured and quality controls checks are made 9. Thread compound is applied and clean protectors are installed 10. External liquid corrosion inhibitor is applied to the OD pipe surface 11. The pipe is racked and bundled for delivery Recoated Drill Pipe ready for delivery:


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EFFECTIVE DATE 08/09/10

USED DRILL PIPE – INTERNAL PLASTIC COATING CLASSIFICATIONS

PAGE 1

of 17

WORK INSTRUCTION

SCOPE:

To provide a general guideline for evaluating the condition of internal plastic coatings in used drill pipe.

RECOMMENDATIONS: 1. Pipe to be visually inspected shall be cleaned internally, preferably with high pressure water jetting equipment. Removal of drilling mud, chemical residues, dust and dirt, and other visible contaminants is required. Debris generated from the water blast step should be visually inspected to see if any coating became disbonded during the process. NOTE:

Water Blast should not exceed 15,000psi pressure. Recommend use of a commercially available 360° nozzle. Do not use a pencil point nozzle.

2. The pipe I.D. is dried with compressed air to remove residual water prior to visual inspection. 3. To help determine fitness for purpose, Classes 1, 2, 3, and 4 have been established to provide guidelines for evaluating the condition of the coating. 4. Several tools will be needed to perform the coating inspection: a. High intensity light (alternatively, a mirror can be used to capture the sunlight if the evaluation is taking place outside and there is a sufficient amount of sun) b. A hinged mirror capable of extending into the ID of the pipe for a visual evaluation of the internal upset run-out c. A knife to be used to test the adhesion around areas of damaged coating 5. Photographs showing the varying conditions of the Classifications are recommended for training inspectors and can be used to assist in decisions. The classifications are broken down further by three areas of concern within the drill pipe: (1) the tool joint, (2) the upset run-out, and (3) the tube body. The effects of corrosion are more severe in the upset run-out area as well as the tube body. The tube body is the part of the pipe that has the thinnest steel and will therefore see a corrosion pit or body wall loss failure first. The upset run-out, while having areas of thicker steel than the tube body, is the area that This coating evaluation procedure is an uncontrolled document from NOV Tuboscope and may be used without permission. Copyright NOV Tuboscope. 2009. All Rights Reserved.



PAGE 2

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WORK INSTRUCTION sees much higher stress due to the several changes in geometry. A pit in the upset run-out is a starting point of a stress crack which can then lead to a wash-out. For these reasons, more concern is taken with minimal coating damage in these areas. 6. Coating loss in the tool joint, up to 100%, is not always in and of itself sufficient reason for down grade. However, if coating loss in tool joint is creeping into the “run out” area, this area needs to be thoroughly evaluated for coating adhesion as outlined in this guide. 7. The benefits of a comprehensive used drill pipe coating inspection program are to ultimately extend the useful life of the pipe and prevent premature failures caused by pitting type corrosion in the critical transition area (weld line and internal upset area). PICTORIAL DESCRIPTION OF DEFECTS

Figure 1: Blistered Coating This coating evaluation procedure is an uncontrolled document from NOV Tuboscope and may be used without permission. Copyright NOV Tuboscope. 2009. All Rights Reserved.



PAGE 3

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WORK INSTRUCTION

Figure 2: Coating Delaminating (Peeling) away from an area of damage

Figure 3: Wireline Cuts in Coating

This coating evaluation procedure is an uncontrolled document from NOV Tuboscope and may be used without permission. Copyright NOV Tuboscope. 2009. All Rights Reserved.



PAGE 4

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WORK INSTRUCTION CLASSIFICATIONS: CLASS 1 (Premium) Description:

STATUS:

•

Re-use

For the ID coating to achieve a class 1 (premium) designation it can contain: o Minor abrasion and scrapes down the tube and in the critical transition area. The metal substrate cannot be exposed in any of the areas of abrasion. o No corrosion products (rust or scale) are present in the tube or transition area. o I.D. Coating is not blistering or delaminating (peeling off).

Figure 4: Class 1 (Premium) in the Tool Joint




PAGE 5

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WORK INSTRUCTION

Figure 5: Class 1 (Premium) in the Upset Run-out




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WORK INSTRUCTION

Figure 6: Class 1 (Premium) in the Tube Body.

Figure 7: Internal camera view of Class 1 coating in the tube body




PAGE 7

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WORK INSTRUCTION

CLASS 2

STATUS:

Re-use

Description:

•

• •

•

•

Wireline and tool damage to the coating in the tooljoints is normal and acceptable to a 25% loss of coating film. Using a knife, test the adhesion of the coating around the area of damage to ensure that significant coating undercreep is not present. If undercreep is present, take measures to remove loosely adhered coating The I.D. coating in the tube body and the upset run-out contains limited wire line cuts and tool damage. Presence of surface corrosion (rust) is visible, but no significant pitting is present. In addition, there should be no serious underfilm (undercreep) corrosion present. This can be determined by using a knife to pry at the coating around the area of damage. Coating removed from this area that has evidence of rust attached to the underside of the coating is evidence of underfilm corrosion. If underfilm corrosion is present, this joint will be downgraded to a minimum of Class 3. Overall there can be coating loss of 5% or less in the tube body (with no more than 3% being confined to one area). In the upset run-out, limited cuts and scrapes can be present, but there is minimal coating loss in this area (less than 2%). In the areas of coating loss, there should be no evidence of corrosion pitting taking place. If need be use a Boroscope to more closely evaluate coating condition in the tube body. Even though there are areas of mechanical damage down to the metal substrate, the coating shows no signs of blistering or delaminating (peeling off). As with the determination of underfilm corrosion, coating delamination can be determined by obvious peeling of the coating around areas of damage or by the use of a knife to check adhesion around the area of damage. Coating that is easily removed constitutes delamination.




PAGE 8

of 17

WORK INSTRUCTION

Figure 8: Class 2 Coating in the Tool Joint




PAGE 9

of 17

WORK INSTRUCTION

Figure 9: Damage caused during the re-hardbanding of used drill pipe can lead to coating degradation, but in the tool joint, coating loss is less of a concern




PAGE 10

of 17

WORK INSTRUCTION

Figure 10: Class 2 Internal Up-set Run-out. Note the damage in the tool joint coating bleeding into the upset-runout.

Figure 11: Class 2 Tube Body. Note pinhole areas of coating damage and minor indication of rust on the left.




PAGE 11

of 17

WORK INSTRUCTION CLASS 3

STATUS:

Re-use/Re-coat

Description:

• • • • • •

The I.D. coating in the tube body contains wireline cuts and tool damage. Underfilm corrosion is present but physical removal is not severe and only exposes a minimal amount of steel. Coating loss is 15% or less in the tube body (with no more than 8% confined to one area of the pipe). Damage to the transition area (upset run-out) is observed but coating loss is less than 15% and the onset of pitting type corrosion has not yet occurred. I.D. coating is not blistering or delaminating (peeling off). Coating that is blistered or showing signs of delamination will automatically downgraded to Class 4. Damage to the coating in the tooljoints is normal and coating loss of up to 60% is acceptable. Ensure that coating showing signs of delamination are added to the lost coating to generate an accurate percentage of coating damage.

NOTE:

Re-use of this pipe in normal drilling operations is acceptable. However, the coating should be re-inspected after each well drilled or completed.

NOTE:

Re-coating of this class pipe should be considered in deep, high temperature, high pressure wells (especially directional wells) with significant amounts of CO2 and/or H2S, or for use in workover/completion operations.

NOTE:

Water Blast can be used to dislodge any coating that may have been loosened due to long term exposure to the environment.




PAGE 12

of 17

WORK INSTRUCTION

Figure 12: Class 3 Tool Joint. Note that the coating has been breached in several areas, but there is no peeling.

Figure 13: Class 3 - Damage to the upset run-out viewed with a hinged mirror




PAGE 13

of 17

WORK INSTRUCTION

Figure 14: Class 3 Tube Body. Note the several areas of coating loss down to bare steel, there is no peeling of the coating in those areas.

CLASS 4

STATUS:

Re-coat

Description:

• •

Moderate to severe coating damage in the tube body and transition area with severe underfilm corrosion observed during the adhesion testing at areas of coating damage. Coating loss in the tube body is 16% or more with the onset of pitting corrosion.




PAGE 14

of 17

WORK INSTRUCTION

• • •

NOTE:

Coating loss in the transition area is 16% or more with the onset of pitting corrosion. I.D. coating shows evidence of blistering and delamination (peeling).

Up to complete tool joint coating loss. 100% loss of coating in the tool joint is not an immediate rejection. Further evaluation of the upset runout and tube body should be the final determining factor on the rejection of a joint.

Figure 15: Class 4 Tool Joint. Note the extensive loss of internal coating and the presence of pitting corrosion




PAGE 15

of 17

WORK INSTRUCTION

Figure 16: The presence of blisters indicates coating degradation which can be caused by excessive temperature, chemical exposure, and/or the coating reaching the end of its useful life




PAGE 16

of 17

WORK INSTRUCTION

Figure 17: Class 4 Internal Upset Run-out. Note the extensive loss of coating, the presence of underfilm corrosion and the presence of pitting corrosion.

Figure 18: Coating damage in the tool joint that propagates from the tool joint, through the upset run-out and into the tube body leading to a Class 4 rating This coating evaluation procedure is an uncontrolled document from NOV Tuboscope and may be used without permission. Copyright NOV Tuboscope. 2009. All Rights Reserved.



PAGE 17

of 17

WORK INSTRUCTION

Figure 19: Class 4 Tube Body. Note the peeling of the coating around the areas of damage and the blistering beginning to form.

Figure 20: Delamination of the coating in the tube body automatically drops the joint to a Class 4



® TCS HARDBANDING Industry Leading Tool Joint and Casing Protection

THE WORLD LEADER IN HARDBANDING SINGLE SOURCE NOV® Tuboscope® is the only oilfield hardbanding service company that offers a single source for wire manufacture, new pipe application, and reapplications worldwide. GLOBAL REACH With 80 mobile units strategically located in 25 countries, TCS Hardbanding is available in major oilfield markets around the world.

FIELD-PROVEN HARDBANDING ALLOYS TCS-8000® REDUCES CASING WEAR With drilling costs on the rise, protecting your investment

WEAR FACTOR

in drill pipe and casing is more important than ever. NOV Tuboscope is committed to providing the best combination of tool joint wear and casing protection with our TCS hardbanding product line. NOV Tuboscope’s original, trouble-free TCS-8000 hardbanding alloy is specially designed and formulated to protect casing. The overlay is visually crack free and can withstand multiple reapplications. TUNGSTEN CARBIDE Tungsten carbide is the original drill pipe hardfacing protection. NOV Tuboscope still applies various mesh sizes of crushed and spherical tungsten that is extremely effective on bottom hole assemblies which normally operate in open hole environments.

FULL FIELD APPLICATION CAPABILITY WHEN AND WHERE YOU NEED IT Combining qualified personnel with our mobile equipment turns your drill site into our work site. NOV Tuboscope cuts the time necessary to get you back up and running by delivering hardbanding services on new or used drill pipe and heavy weight/drill collars when and where you need it. In addition to the application of our proprietary hardbanding, we have the capability to apply most competitive hardband products.

www.nov.com t u b o s c o p e @ n o v. c o m

YOUR SINGLE SOURCE FOR THE MOST COMPREHENSIVE

THE NEXT GENERATION IN HARDBANDING TECHNOLOGY TCS – TITANIUM TCS Titanium is formulated to provide high stress abrasion resistance along with unmatched resistance to cracking and spalling. Titanium carbides on their own are approximately 40% harder than tungsten carbide.

The TCS Titanium

microstructure exhibits smooth round particles, which help prevent galling problems on metal-to-metal contact. This combination gives a superb balance between abrasion and crack sensitivity which results in both reduced tool joint wear and casing wear. BENEFITS •

Superior casing wear protection

•

Most crack-free product on the market

•

Extremely low coefficient of friction

•

Extended tool joint life

•

High stress abrasion resistance

•

No shielding gas required

•

Unlimited reapplication in the field

•

Superior adhesion properties mean non-spalling

Screen shot of hardband material analysis HARDBAND IDENTIFICATION Hardbanding cannot be accurately identified visually — and record keeping is not always exact — making reapplication difficult due to material dissimilarities. Drilling operations can be interrupted and in extreme cases, casing failure may occur. NOV Tuboscope offers precise, immediate onsite hardband identification using a hand-held x-ray fluorescence analyzer. Accurate identification of hardbanding can eliminate costly downtime by determining non-casing friendly hardbands or hardbanding with potential reapplication issues.

PACKAGE OF OILFIELD TUBULAR SERVICES — WORLDWIDE.

Regional Offices Central Region Administration 10222 Sheldon Road Houston, Texas 77049 Phone: 281 456 8881 Machining Services 7505 Upriver Road Corpus Christi, Texas Phone: 361 289 1525 West Region 14112 W. Hwy 80E Odessa, Texas 79765 Phone: 432 563 2150

Corporate Headquarters 7909 Parkwood Circle Drive Houston, Texas 77036 United States Phone: 713 375 3700 Fax: 713 346 7687 NOV Tuboscope 2835 Holmes Road Houston, Texas 77051 United States Phone: 713 799 5100

Southeast Region 1208 First Avenue Harvey, Louisiana 70058 Phone: 504 631 1900 Canada 2201 9th Street Nisku, AB, Canada T9E 7Z7 Phone: 780 955 7675 Latin America Corrientes 316 Fifth floor 1008 Buenos Aires Argentina Phone: 54 11 4130 1600 Europe Tuboscope Vetco (Deutschland) GmbH P. O. Box 3111 29231 Celle Maschweg 5, 29227 Phone: 49 5141 8020 Far East 39 Gul Avenue Singapore 629679 Phone: 65 68612688

North America Sales Houston Phone: 281 456 8881

Latin America Sales Mexico Phone: 52 229 201 0035

South Texas Phone: 361 854 1167

Argentina Phone: 54 11 4130 1624

East Texas Phone: 903 984 8553

Brazil Phone: 55 22 2773 0600

Dallas Phone: 214 561 8737

Colombia Phone: 571 644 4510

Machining Services Corpus Christi Phone: 361 289 1525 Pearland Phone: 281 482 9014

Peru Phone: 51 1 219 1160

Mississippi/Alabama Phone: 601 428 1555

Eastern Hemisphere Sales Germany, Africa, Italy Phone: 49 5141 8020

Louisiana New Orleans Phone: 504 636 3672 Lafayette Phone: 337 272 3284 Machining Services Phone: 337 837 1669

Norway Phone: 47 56312100

Permian Basin Phone: 432 563 2150

Russia Phone: 7 495 935 86 31

California Phone: 661 325 8529

China Phone: 86 21 22168800

Oklahoma Phone: 405 478 3400 Machining Services Phone: 405 677 3386

Indonesia Jakarta Phone: 62 21 7806265

Canada Nisku Phone: 780 955 7675 Calgary Phone: 403 216 5000 Red Deer Phone: 403 343 8100 Grand Prairie Phone: 780 538 9338

Engineering and Project Management Solutions

Scotland Phone: 44 1224 787740

Netherlands Phone: 31 0 524 525977

New Mexico Phone: 505 333 2224

Drilling Solutions

Bolivia Phone: 591 3 355 3500

West Virginia / Pennsylvania Phone: 304 622 1507

Rocky Mountains Phone: 303 572 7766

Downhole Solutions

Lifting and Handling Solutions

Production Solutions

Singapore Phone: 65 6861 2688 Saudi Arabia Phone: 966 3 837 8080 Oman Phone: 968 24484070

Supply Chain Solutions

Abu Dhabi Phone: 971 2 6260180

National Oilwell Varco has produced this brochure for general information only, and it is not intended for design purposes. Although every effort has been made to maintain the accuracy and reliability of its contents, National Oilwell Varco in no way assumes responsibility for liability for any loss, damage or injury resulting from the use of information and data herein. All applications for the material described are at the user’s risk and are the user’s responsibility. All brands listed are trademarks of National Oilwell Varco.

Tubular and Corrosion Control Solutions

Well Service and Completion Solutions

One Company . . . Unlimited Solutions tubosco pe@n ov.com

w w w. n o v. c o m

© 2010 National Oilwell Va Varco rco D392001522-MKT-001 Rev. 02

Hardbanding Services NOV Tuboscope is the global leader in drill pipe tool joint refurbishment. Our continuous research into new alloys as overlay materials supports customers today and raises the benchmark for tool joint wear protection tomorrow. Our TCS Hardbanding alloys help ensure tool joint integrity, crack resistance, and a lack of spalling in the overlay material. Let us help you further increase productivity, lower costs, and gain greater reliability from your drill strings with alloys capable of expanding tool joint protection to a wider range of downhole applications. All “casing friendly” hardbands basically consist of two groups: Chromium Carbides and Niobium Carbides. Most but not all exhibit some type of stress cracking as a normal part of application. Usually the hardness of the material dictates the severity of the crack patterns. These cracks can and sometimes do permeate into the parent metal of the tool joint and cracking hardband material is prone to spalling, or chunks of material separating from the hardbanding. All hardbanding eventually wears during normal drilling operations and ease of reapplication is the key to any premium hardband material. Some material requires complete removal prior to reapplication which includes transportation of the drill string to a facility with removal capabilities and removal is costly and time consuming. Also, reapplication over cracked hardbanding is problematic due to contaminants such as drilling fluids becoming trapped in the cracks and the time frame for preparation of cracking material is therefore lengthened. Today’s hardbandings consist of various complex alloys which may or may not be metallurgically compatible. There have been many confirmed cases of failed attempts at “field or rig-site” reapplication. For this reason, it is critically important for the pipe owner to maintain traceability of the type of hardbanding in use. Failure to do this can only lead to costly and time consuming repairs at some point down the road. In todays market conditions of extended reach drilling we are seeing more eccentric wear on hardbanding due to drilling with mud motors. The pipe does not rotate as it normally would which causes the hardband to wear on one side due to drag while transitioning the work string in and out of the well. Cases where the hardbanding is worn flush on one side of the tool joint and still proud on the other are common. In this case, the side that still has raised or proud hardbanding remaining must be ground or machined flush prior to reapplication. TCS-8000 With drilling costs on the rise, protecting your investment in drill pipe and casing is more important than ever. NOV Tuboscope is committed to providing the best combination of tool joint wear and casing protection with our TCS hardbanding product line. NOV Tuboscope’s original, trouble-free TCS-8000 hardbanding alloy is specifically designed and formulated to protect casing. The overlay is virtually crack free and can withstand multiple reapplications.


www.tuboscope.com

1-713 799-5100

[email protected]

Hardbanding Services Cont… Tungsten Carbide Tungsten carbide is the original drill pipe hardfacing protection. NOV Tuboscope still applies various mesh sizes of crushed and spherical tungsten that is extremely effective on bottom hole assemblies which normally operate in open hole environments. TCS-Titanium TCS Titanium is formulated to provide high stress abrasion resistance along with unmatched resistance to cracking and spalling. Titanium carbides on their own are approximately 40% harder than tungsten carbide. The TCS Titanium microstructure exhibits smooth round particles, which help prevent galling problems on metal-to-metal contact. This combination gives superb balance between abrasion and crack sensitivity which results in both reduced tool joint wear and casing wear. Benefits

Superior casing wear protection Most crack-free product on the market Extremely low coefficient of friction Extended tool joint life High stress abrasion resistance No shielding gas required Unlimited reapplication in the field Superior adhesion properties mean non-spalling

Full Field Application Capability Combining qualified personnel with our mobile equipment turns your drill site into our work site. NOV Tuboscope cuts the time necessary to get you back up and running by delivering Hardbanding services on new or used drill pipe and heavy weight/drill collars when and where you need it. In addition to the application of our proprietary hardbanding, we have the capability to apply the most competitive hardband products. Hardband Identification Hardbanding cannot be accurately identified visually and record keeping is not always exact, making reapplication difficult due to material dissimilarities. Drilling operations can be interrupted and in extreme cases, casing failure may occur. NOV Tuboscope offers precise immediate onsite hardband identification using a hand-held x-ray fluorescence analyzer. Accurate identification of hardbanding can eliminate costly downtime by determining non-casing friendly hardbands or hardbanding with potential reapplication issues.


www.tuboscope.com

1-713 799-5100

[email protected]

Machine Services

Machining Services — Latin America, Europe and Asia Location Capabilities and Contacts LATIN AMERICA Grant Prideco® Licenses TurboTorque

Rotary Shoulder Connection

GPDS

Tool Joint Build-up

TTS (PH-6)

Sonocord DP2S55

Smith TSDS

Bolivia

Yacuiba

1

•

•

Bolivia

Yacuiba

*ML

•

•

Brazil

Macae

2

•

• •

•

• •

Colombia

Block Bogota

*ML

•

Colombia

Cano Limon

*ML

•

Colombia

Yopal

1

•

• •

Ecuador

Francisco de Orellana (El Coca)

1

•

•

Ecuador

Francisco de Orellana (El Coca)

*ML 2

•

Mexico

Moralito

*ML

•

Mexico

Poza Rica

2 CNC / *ML 2

•

Mexico

Reynosa

*ML

•

Peru

Block 1 AB

1

•

Peru

Block 56/88 Malvinas

*ML

•

•

•

Peru

Block 57 Repsol

*ML

•

•

•

Peru

Block 58 Petrobras

1 CNC / *ML

•

Peru

Block 8

*ML

•

Peru

Lima

1

•

•

Peru

Talara

*ML

•

•

Argentina

*ML 9

•

HT

CTM

# of CNC Machines

XTM

Facility

XT

Country

THS Manufacture (TenarisHydrill) Subs

•

•

•

•

•

•

• •

•

• •

•

•

•

• •

* Manual Lathe

EUROPE AND ASIA Facility

# of CNC Machines

Tool Joint Build-up

Rotary Shoulder Connections

HT

XT

Kristiansand, Norway

1

•

•

•

Aberdeen, Scotland

4

•

•

•

Baku, Azerbaijan

1

•

•

•

* Manual Lathe

www.nov.com www.tuboscope.com 2835 Holmes Road PO Box 808 (77001) Houston, Texas 77051 United States

Mexico: +52 229 201 0001 Latin America: +54 11 4130 1600 Norway: +47 5631 2100 Scotland: +44 1224 780600 Azerbaijan: +994 12488 2513

XTM

GPDS

TTS (PH-6)

Manufacture Subs

•

Machining Services — United States and Canada Location Capabilities and Contacts UNITED STATES Facility

# of CNC Machines

Tool Joint Build-up


HT

XT

XTM

GPDS

TTS (PH-6)

Manufacture Subs

ML*

•

North Slope, AK

2

•

•

•

Bakersfield, CA

2

•

•

•

Broussard, LA

7

•

•

•

Farmington, NM

1

•

•

•

Williston, ND

2

•

•

•

Oklahoma City, OK

7

•

•

•

•

Corpus Christi, TX

5

•

•

•

•

Godley, TX

1

•

Odessa, TX

1

•

Pearland, TX

3

•

•

•

Kilgore, TX

1

•

•

•

Bridgeport, WV

2

•

•

•

Casper, WY

1

•

Kenai, AK

•

• • •

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

• •

•

•

•

•

• •

•

•

* Manual Lathe Matt Smith: 713 799 5173 Bill Hicks: 713 799 4905 CANADA Facility

# of CNC Machines

Tool Joint Build-up


Nisku, Canada

ML*

•

Grand Prairie, Canada

ML*

•

HT

XT

XTM

GPDS

TTS (PH-6)

Manufacture Subs

* Manual Lathe Phone: 780 955 7666

www.nov.com www.tuboscope.com 2835 Holmes Road PO Box 808 (77001) Houston, Texas 77051 United States: 713 799 5173 / 713 799 4905 Canada: 780 955 7666 Western Hemisphere: 1 800 433 0059

© 2011 National Oilwell Varco D392004146-MKT-001 Rev. 02

Machine Services Machine shops perform an important service in the drill pipe industry. A drill pipe string is arguably the most expensive asset on the drilling rig and should have the longest service life possible. Our Machine shops are capable of extending the life of drill pipe by re-threading, re-cutting and building up worn down tool joints. Early in 2005, Tuboscope made a commitment to add threading and tool joint rebuilding to the current product line and targeted strategic regions for growth. Currently Tuboscope has 38 CNC’s (computer numerical control) machines running worldwide with more to come in the near future. This division of Tuboscope offers three core services: • • •

Thread Repair Sub Manufacturing Tool Joint Rebuilding

One of the most common problems with drill pipe is thread damage. In addition to normal wear, threads on the tool joints are easily damaged by transportation of the pipe or lack of care and handling on the drilling site. Alignment is critical and the drill pipe must be centered properly for make-up with the next connection. When drill pipe connections are not properly lined with one another, stabbing damage to the threads can occur. Damaged threads compromise the entire drill string. This failure takes time, effort and money to fix. All of which can be easily avoided by re-cutting damaged threads and seals. There are three main types of thread damages: • • •

Over Torque Galling Cross Threading (not properly aligned while making up)

With the new technology of horizontal and directional drilling, tool joints wear down faster due to the constant rubbing against casing. Rebuilding undersized tool joints when the tube body of the pipe still in good condition is a good way to save money by extending the pipe service life compared to purchasing new pipe. Tuboscope’s Machine Shops help customers worldwide to extend the life of their drill pipe by returning the drill stem components back to drilling-ready condition.


www.tuboscope.com

1-713 799-5100

[email protected]

Machine Services Cont… Threading Our Machine Shops are capable of performing thread repair services on rotary shouldered connections and proprietary connections including Grant Prideco, VAM, Texas Steel & Conversion and Command Energy. Grant Prideco has licensed Tuboscope to cut proprietary connections that consist of the HT, XT and XTM connections. Tuboscope is also capable of providing repair services on premium connections of tubing. Sub Manufacturing Tuboscope is licensed under API Spec. 7 to manufacture of downhole tools such as crossover subs, bit subs, saver subs, etc. A full line of sub stock with mill certification is inventoried at all locations. All machine shop employees are trained in accordance with API and we maintain a full time quality assurance department. Tool Joint Build Up This is a unique process used to restore worn drill pipe tool joints, drill collars and heavyweight drill pipe to original specifications and extend service life. All tool joints are heat treated, turned to finished OD, brinell tested, inspected with black light and re-cut to specified connection determined by customer. A full time quality assurance department is maintained to provide the best product in the industry. The rebuilding process includes: • • •

• • • • •

Hardband removal, done with plasma arc machine Preheating the tool joint to a minimum of 350 Degrees F. Rebuilding the tool joint 1/8th inch larger than the finished specification o Area will be filled using Lincoln 802 Flux and 325 Wire. o 145-175 Degree water will be circulated through pipe once arc is struck. Stress relieving; 1,100 Degrees F for 65-85 minutes, depending on the product Turning the OD of the tool joint to the final specification Inspecting the rebuilt tool joint; including hardness testing, black light inspection and dimensions Threading the box and pin connections Inspecting the threads


www.tuboscope.com

1-713 799-5100

[email protected]

Specialty Inspection Services

Specialty Inspection Services NOV Tuboscope Specialty Inspection Services is a company providing a comprehensive package of Construction, Inspection, Repair, Maintenance(IRM) and Operational Service to the Oil and Gas, Marine and General Industry. Our services are used by Rig Contractors, International Oil Companies, Oilfield Services Companies and Oilfield Equipment Manufacturers in Asia, Australia, Brazil, Russia, Central Europe, West Africa and the Middle East. Acquired by National Oilwell Varco in late 2009, SSI was established in 1993 as an OCTG and NDT Inspection Company. It soon expanded into Derrick construction and the full range of repair, upgrading and maintenance activities, worldwide. Our business today focuses on Derrick Services, Rope Access, Load Testing, Lifting Gear Inspection, NDT Inspection, Oilfield Equipment Maintenance, and Tubular Inspection & Inventory Control. NOV Tuboscope Specialty Inspection Services offers a unique and complete package of inspection, maintenance and repair disciplines catering to most if not all of rig contractors' requirements. Today, NOV Tuboscope Specialty Inspection Services is the leading Rope Access Inspection, Maintenance, and Repair (IRM) Services Company and Derrick Building specialist with a record of over 100+ derricks constructed in the last 15+ years.


www.tuboscope.com

1-713 799-5100

[email protected]

Rig Inspection Services Hoisting and Lifting Equipment Surveys NOV Tuboscope Specialty Inspection Services provides comprehensive inspection of all hoisting and lifting gear aboard FPSOs and Drilling Units; the equipment is inspected to the latest vendor , API, BS and European guidelines as well as LOLER 98 (UK Statutory Instrument No.2307) and LEEA. All the equipment, from the largest cranes to the smallest shackles and slings, are registered in our portable database reporting system to ensure a systematic and thorough traceability process. The database tracks the equipment by identification number, description, safe working load, test date and certificate number, and any previous inspection history. Our clients can sign into our website with their password to view the results of the survey on-line and we provide printed and CD-ROM versions of the report for off-line viewing and archival. You may search the website for equipment by survey result and other criteria or browse the scroll-down user friendly screens. NOV Tuboscope Specialty Inspection Services is a one-stop service provider for the inspection of Drill Tools and Pipe-handling equipment, Derrick inspection and Special Periodic Surveys. Lifting Gear Inspectors NOV Tuboscope Specialty Inspection Services uses experienced LEEA trained inspectors to conduct the lifting equipment surveys. We hold LEEA training periodically throughout the year to ensure our inspectors are fully competent and are up to date with code of practices and latest recommended practices. LEEA Team Card Initiative NOV Tuboscope Specialty Inspection Services has adopted the LEEA Team Card Initiative http://www.leea.co.uk/html/the-team-card/ all of our inspectors conducting lifting equipment surveys carry a Team Card with them displaying their qualification levels. NOV Tuboscope Specialty Inspection Services currently has in excess of 20 LEEA Team Card holders conducting inspections.


www.tuboscope.com

1-713 799-5100

[email protected]

Rig Inspection Services Cont… NDT Inspection Services NOV Tuboscope Specialty Inspection Services specializes in Non-Destructive Testing on all types of equipment. Our inspectors are proficient in all of the following disciplines: • Magnetic Particle Inspection • Dye Penetrant Inspection • Visual Inspection • Eddy Current Inspection • Ultrasonic Inspection • Radiography Inspection • Wall Thickness Inspection • Hardness Testing • Close up Video Inspection • Welding Inspection • Material Identification & Mechanical Testing

Load Testing NOV Tuboscope Specialty Inspection Services can inspect, test and certify all types of lifting appliances on location. We are a member of LEEA in the UK and follow the latest LOLER guidelines. Load Testing is carried out by competent inspectors who, in addition to being LEEA / NSL approved, are certified to ASNT Level II in MPI / ET. Whenever possible, we provide Eddy Current Inspection on welded padeyes and other welded components thus saving time in preparation. Padeye Load Testing NOV Tuboscope Specialty Inspection Services can load test padeyes from 250 KG through to 200t using our hydraulic jacking kits. The load testing can also be conducted on hard to reach locations such as under the crown by using our rope access qualified inspectors.


www.tuboscope.com

1-713 799-5100

[email protected]

Rig Inspection Services Cont… Crane Load Testing NOV Tuboscope Specialty Inspection Services has its own range of Water Weights for crane load testing. They come in 12t and 35t capacities and can be combined to achieve larger proof loads. The Water Weights can be used to load test offshore cranes including pedestal cranes, gantry cranes and BOP hoists. The Water Weights can be filled and emptied in a controlled and gradual manner. Lifeboat Load Testing NOV Tuboscope Specialty Inspection Services carries a full complement of mini waterbags that can be used to load test lifeboats. The system NOV Tuboscope Specialty Inspection Services uses can be controlled (filled and emptied) remotely, meaning that personnel do not have to be inside the lifeboats during the load testing. NOV Tuboscope Specialty Inspection Services has also used the mini water bags to load test gangways to IMO standards. In addition NOV Tuboscope Specialty Inspection Services regularly performs load testing of lifeboat, life raft and FRC davits. Tailored Load Testing Should you require a piece of equipment to be load tested that is not listed above please contact us and we would be happy to offer a proposal to suit your individual needs. Load Cells We use calibrated load cells ranging from 30t, 50t, 75t through to 150t allowing for an accuracy of +/-1%.


www.tuboscope.com

1-713 799-5100

[email protected]

Rig Inspection Services Cont… Offshore Container Certification NOV Tuboscope Specialty Inspection Services can inspect offshore containers and their associated lifting sets to BS EN 12079 and DNV 2.7-1 standards. Offshore containers come in many different forms from freight containers to gas cylinder racks. Our inspectors are trained to recognize the different types of offshore containers and inspect them accordingly to BS EN 12079 and DNV 2.7-1. NOV Tuboscope Specialty Inspection Services will highlight any non-conformities ensuring that the offshore containers can travel to their location without problem. NOV Tuboscope Specialty Inspection Services can also inspect and test offshore containers according to client specifications as we understand there are many different requirements owners have to meet. NOV Tuboscope Specialty Inspection Services conducts a full range of load testing services on offshore containers at our workshop; we can also provide this service at other locations if required. Fabrication NOV Tuboscope Specialty Inspection Services can fabricate offshore containers in accordance with BS EN 12079 and DNV 2.7-1 at our fabrication facility. Please contact us for more information on this service. Modification and Conversion NOV Tuboscope Specialty Inspection Services also modifies standard ISO shipping containers so they comply with BS EN 12079 and DNV 2.7-1 (pending acceptance from DNV). Offshore containers that don’t meet international standards can be modified so that they comply with the correct standards. If you need a container to be converted to DNV 2.7-1 standard please contact us for more information.


www.tuboscope.com

1-713 799-5100

[email protected]

Rig Inspection Services Cont… Dropped Objects Survey With ever increasing emphasis towards the prevention of dropped objects, spreading throughout the industry, the need for more vigilance and awareness of your workplace and surrounding environment is an essential requirement. NOV Tuboscope Specialty Inspection Services over the cause of many years has been constantly working to combat dropped objects incidents. In an effort to provide our clients with a better and safer working environment, we have developed web based reporting software for Dropped Objects Surveys which is used by our inspectors to compile an inventory of all potential drops items in the work area. The reporting software includes listing the risk category, location, fastening / secondary retaining method and recommended corrective actions. For ease of identification, each inventory item is coupled with a photographic illustration. NOV Tuboscope Specialty Inspection Services is currently using this software for a number of major Drilling Companies operating around the globe. Our software has been further developed and adapted to suit our client’s individual requirements and management systems. When combined, our Derrick Structural Inspection software and Inspection Book Format provides an all round solution in the identification, recording, monitoring and rectification of potential dropped object scenarios. Areas covered in the program, subject to client requirements: • Derrick Structure • Traveling Equipment • Sub Structure / Moonpool • Deck Cranes • Gantry Cranes • Knuckle boom Cranes • Jack House and Legs • Raised Catwalks and Conveyors • Communication Masts • Fixed Third Party Equipment • Accommodation & Rig Compartments The program also incorporates a corrective action section, where defective items can be extracted in categories of risk, recommended remedial action entered and date recorded when an item is closed out. Recording or tracking the corrected items is easily facilitated due to the online accessibility to our web based reporting system. The inspection reports can be accessed online from our web server by authorized clients. Reports can be printed directly or the Spreadsheet data can be extracted in various formats, including excel and pdf, for insertion in to the clients Maintenance Management System and also for ease of use and distribution.


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Rig Inspection Services Cont…


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Rig Inspection Services Cont… Inspection Book The Inspection Book is a web application with the purpose of setting up maintenance procedures for the periodic rig inspection of potential Dropped Objects. An Independent Dropped Objects Survey is conducted onboard initially to identify equipment and items mounted in the derrick, cranes or other areas at height that have the potential of becoming DROPS hazards. The intention is to consolidate a list of inspection criteria for common items or “Equipment Families” found on a rig such as flood-lights, sheaves, safety gates and so forth. Each piece of equipment or item will then have specific instructions on how that piece of equipment is to be inspected by the rig crews. The Inspection Book provides the end user with a systematic approach to Preventive Dropped Objects Inspections which consist of the following: • Description and Inspection frequency of the Area to be inspected • Photograph of the item to be inspected • A photo id number to be used in conjunction with the rig Maintenance System • Description and location of the item to be inspected • Primary and Secondary retaining methods • Inspection procedure • Condition Pass/Fail • Comments section The Inspection Book is set out in easy to follow steps that provide rig personnel with simple and straight forward instructions on how to inspect the rig for potential Dropped Objects. The end user will be able to identify conditions such as correct Primary and Secondary fastening methods and the condition of the equipment due to damage or deterioration. The Inspection frequency control is set for each item in weekly, monthly, quarterly and so forth to ensure a regular routine check for potential Dropped Objects. The Inspection Books are grouped by Areas and colour coded accordingly for easier identification. Each respective Inspection Book can be uploaded in either Excel or PDF for insertion into the rig Maintenance System or alternatively printed, plasticized and kept at the specific area for use by the rig crew. Special Periodic Surveys NOV Tuboscope Specialty Inspection Services can conduct "Special Periodic Surveys" on vessels for their intermediate or five-yearly classification requirement or for ad-hoc certification. We are approved by the major classification agencies such as ABS, DNV and Lloyd's as an approved service provider for all Hull Thickness Gauging. Our inspectors are experienced and professional as we ensure they are trained and proficient in current techniques and standards.


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Rig Inspection Services Cont… Workscope The work scope may be grouped into three areas: • Top Side Structural Survey • Jack-up Leg Structural Survey • UWILD - Underwater Inspection in Lieu of Dry Docking Top Side Survey The work scope includes surveys of the hull, tanks, deck, leg well areas, legs etc. Leg Survey In addition to Visual Inspection, we will conduct Non-Destructive Testing on all critical joints and members to detect internal faults to certify the vessel as required by the authorities. UWILD Underwater Inspection using MPI and Eddy Current. NOV Tuboscope Specialty Inspection Services are partners with Master-Tech Diving Services for underwater inspection, thereby providing a complete spectrum of inspection above and below sea level.

High Pressure Pipework Thickness Gauging NOV Tuboscope Specialty Inspection Services are approved by the major classification agencies such as ABS, DNV & Lloyd's to conduct Thickness Gauging on low or high pressure pipe work. We can measure the residual thickness of structures in critical areas like bends or flow constrictions, by Ultrasonic Thickness Gauging and at the same time we can check all related equipment like accumulator bottles and air receivers to enable repair or replacement planning. Incidentally, the highest deterioration usually occurs near bends or flow constrictions, so thorough and professional checks are a must.


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Rig Inspection Services Cont… Wall Thickness Gauging can be conducted together with other periodic surveys such as Derrick Inspections or Lifting Gear Surveys.

Hull Structural Thickness Gauging NOV Tuboscope Specialty Inspection Services are approved by the major classification agencies such as ABS, DNV and Lloyd's as an approved service provider for all Hull Thickness Gauging, which may be required by the five-yearly classification requirements for vessels or for ad-hoc certification. Using rope access, a safe, effective and fast way to gain access to inspection points without having to erect scaffolding, we then start the process of conducting visual inspections and non destructive testing (NDT) on all critical joints and members to detect internal faults in order to certify the vessel, as required by the authorities. The IACS guidelines call for a qualified surveyor to be on board to witness the procedure; our inspectors are experienced professionals who understand the surveyor's requirements and work with the surveyor to promote teamwork, ensure quality and to facilitate a safe and effective inspection process.


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Rig Inspection Services Cont… Preventative Maintenance Infrared Thermography Survey (ITS) Infrared Thermography helps to maintain equipment, improve work safety and control manufacturing costs. Our thermography inspectors can help you locate nascent problems earlier than can be seen or found on the ships or drilling rigs; which are mostly invisible without infrared thermography equipment. NOV Tuboscope Specialty Inspection Services ITS surveys and reports provide a comprehensive list of all areas and a detailed explanation of any "hot-spot" findings, plus report and recommend corrective solutions. All findings are supported by thermal image showing temperature scale and location of the problem area, as well as standard photographic images as an easy location reference. ITS Demonstration • • • • • • • • •

Circuit Breakers Substations Switchgear Power Distribution Panels High Tension Buses Termination Lugs Lighting Panels Transformers Motor Control Panels

NOV Tuboscope Specialty Inspection Services focuses on electrical inspections using the latest state of the art SATIR equipment. Our thermographers are trained and experienced in infrared scanning. Our cutting edge technology from SATIR produces detailed imagery of the highest quality. We provide thorough and comprehensive reports on the exact cause of problems that threaten your electrical systems with expensive downtime. EX Surveys NOV Tuboscope Specialty Inspection Services specialists provide a comprehensive site survey that includes an in depth audit of current; or preparation of new, hazardous area zone drawings and an in depth inspection of equipment compliance. Survey reports include a comprehensive EX register, updated zone drawings and recommendation for rectification of all non-compliances recorded.


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Rig Inspection Services Cont… Noise Surveys Elevated noise levels and, therefore exposure to it, is an unnecessary health hazard which not only damages hearing but leads to physical stress, mental fatigue and potentially, accidents at work. Prevent it with NOV Tuboscope Specialty Inspection Services noise surveys. The environmental impact of noise pollution is a well-known factor in land-zoning, for example during airport development or expansion, or when industrial sites are planned/developed next to population centres. Clients, government bodies, non-governmental organisations (NGO's) and the public have grown to expect good environmental practices from businesses. Environmental pollution can affect corporate reputation, leading to lost opportunity or market share decline. NOV Tuboscope Specialty Inspection Services conducts noise surveys on land and offshore. Our reports rank the intensity, frequency, nature, duration, source and timing of the noise at various locations in a site, prioritizing hazards and quantifying variances which should be addressed. We can help you design a quieter workplace for a more productive workforce and an enlightened public image.

Vibration Surveys An increasingly popular non intrusive method on equipment inspection. Where variances in specific equipments oscillation can be interpreted by SSI personnel with the aim of potentially redefining repair intervals, reducing operational costs, flagging potential premature equipment failure and more.


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Rig Inspection Services Cont… Lighting Surveys NOV Tuboscope Specialty Inspection Services specialists provide experienced personnel to map out rig areas and highlight where light levels are insufficient for safe operation, or where current lighting is not performing as designed. With detailed reports and drawings provided for rectification.


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Derrick Services Derrick Erection, Outfitting, and Installation NOV Tuboscope Specialty Inspection Services is the leading derrick specialist with vast experience in derrick and mast erection, repair, modification, maintenance, inspection, outfitting & equipment installation. The company, over the last 15+ years, have been responsible for the full turn-key packages of 100+ new build derrick projects, from the full erection to outfitting of accessories, piping, electrical installation and all types of drilling equipment. We are recognized as an approved rig building service provider to many major rig contractors, shipyards and derrick manufacturers. NOV Tuboscope Specialty Inspection Services has maintained its excellence by successfully completing and delivering new build derrick projects on schedule, not only on home soil in Singapore but also in various overseas locations around the world, including West Africa, South Korea, Azerbaijan, India, Brazil & China. We have full time experienced Rig-building crews always available alongside Project Managers and field Supervisors, with experience in the derrick industry dating back over the last 25 years.


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Derrick Services Cont… Decommissioning Whether you need to remove a redundant or decommissioned derrick, or simply upgrading to a higher capacity structure, we have the capabilities to fulfill your needs. NOV Tuboscope Specialty Inspection Services have decommissioned derricks both onshore and offshore, using either heavy lift barges for single and upgraded or multiple lifts or by utilising our floating Gin-pole to remove small pieces where cranes are not available or appropriate or where cost efficient methods are called for. NOV Tuboscope Specialty Inspection Services are also able to mobilise at extremely short notice in the case of a decommissioned derrick where it is necessary to remove the twisted derrick structure and Top Drive before the well control personnel can seal the well. NOV Tuboscope Specialty Inspection Service’s expertise in this field enables the entire operation to be successfully and safely executed.


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Derrick Services Cont… Derrick Inspection NOV Tuboscope Specialty Inspection Services has developed, and are constantly updating their derrick inspection reporting software. The program is designed to compliment the standard API Recommended Practice for Use and Procedures for Inspection, Maintenance and Repair of Drilling and Well Servicing Structures (API RP4G). Unlike other Inspection companies, NOV Tuboscope Specialty Inspection Services are active derrick builders and offer offshore maintenance and refurbishment services. Our inspectors are experienced Rig-builders with the ability to highlight actual or potential defects likely to effect the integrity of the derrick or present hazards to operating personnel. Our Inspection criteria range from API Category 1 to API Category IV with Rope Access Personnel qualified in MPI, PT, ECI, and UT to ASNT and PCN International Industry Standards we are able to comply with the full Category IV inspections. As a company that not only builds derricks but inspects them too, we can first identify any actual or potential defects, provide comprehensive corrective recommendations and then carry out any repairs or replace parts as required - all on one site. NOV Tuboscope Specialty Inspection Services is proud to be a member of the International Association of Drilling Contractors IADC.


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Derrick Services Cont… Drilling Equipment Installation NOV Tuboscope Specialty Inspection Services has over the years handled the installation of most types of drilling equipment from various OEM suppliers, such as National Oilwell, Varco and Maritime Hydraulics. Installation includes all hydraulic and pneumatic service piping, electrical installation and terminations.

Electrical Installation and Pipework NOV Tuboscope Specialty Inspection Services provides installation services for all types of derrick related equipment including electrical and pipework system. Derrick Electrical Installation Our Rope Access Electricians are experienced in all aspects of work including: • CCTV & Talk-Back Systems • Drilling Equipment Terminations • Light Circuits, JB's & Fixtures • Satellite & Antenna Systems • Top Drive Service Loop / 440V Supply • Tray Installation & Cable Pulling Derrick Pipework Installation All forms of pipe work and pipe work inspection can be catered for: high and low pressure lines, welding, NDT inspection and radiography inspection: • Degassers / Vent Lines • Mud & Cement HP Standpipes • Hydraulic Service Lines • Pneumatic Pressure Systems • Fire Deluge & Sprinkler Systems • Instrumentation


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Derrick Services Cont… Design, Engineering, and Fabrication NOV Tuboscope Specialty Inspection Services can provide coded welders with rope access skills for the fabrication of steel structures. Design Our partners Paramode provide design consultancy for Stabbing Boards approved by the major agencies such as Lloyd's Register, DNV and ABS. Alternatively, we can fabricate to your own design drawings, or the OEM's i.e. fingerboards Our projects include but are not limited to: Paramode Stabbing Board Projects • Transocean: Harvey ward • Transocean: Trident 17 • Diamond Offshore: Ocean Sovereign - Derrick Interface survey / design done by NOV Tuboscope Specialty Inspection Services Engineering NOV Tuboscope Specialty Inspection Services have engineering capabilities for the design and fabrication of racking boards, wind walls, piping and other derrick accessories such as vent lines etc. Fabrication With our strong team of coded welders and rope-access welders, we are able to deploy to any international location for large or small fabrication projects.


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Derrick Services Cont… Floating Pole Operations NOV Tuboscope Specialty Inspection Services offers Specialized Lifting & Erection Services using: Floating Ginpole Technology The Ginpole is a simple but effective method of decommissioning or erecting derricks in certain situations where no suitable dock or barge cranes are available and is a cost effective alternative. Ginpole Technology has been around for many years and is available in different designs and capacities to suit specific requirement. Originally the Ginpole was designed to assemble small masts and communication towers. However, over the years it has been used in the offshore oil and gas industry for other tasks: The Ginpole method for erecting or de-commissioning derricks is an alternative to heavy lift cranes as it is self-elevating and has no height restrictions. Today with increased demand for more challenging installations, the Ginpole is still proving to be a worthy asset to the offshore construction industry.


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Derrick Services Cont… Guide Tracks Surveys and Alignment On a derrick, the travelling gear moves vertically on guide rails to feed the drill pipe during drilling. Regular maintenance of the guide rails to ensure correct alignment is vital to maintain continuous operations. NOV Tuboscope Specialty Inspection Services regularly carries out Guide track alignments; from installation, survey & final alignment on the new build derricks we have erected, to field repairs, replacement, modifications and alignment checks on existing tracks. Surveys are carried out using either a TOPCON, GPT-3100N series, Reflectorless Total Station, a rotating laser, or laser detectors and measuring devices, depending on specific operating conditions.

Rig Building Crews NOV Tuboscope Specialty Inspection Services has full time crews (Expatriate & Local) of Specialist Rig-builders located in different regions around the world, from Far East Asia to Europe, from Russia to the South Americas. All of the team members are multi-skilled, in that they are qualified IRATA trained rope access technicians, Levels 1 - 3, trained in every aspect of derrick / steel erection and each team member has their own individual trade. In general our crews would consist of the following, but can be adjusted to suit the requirements of the individual projects: • Rope Access / Rig-Builder - Supervisors • Rope Access / Rig-Builder - 6G Welders • Rope Access / Rig-Builder - Pipe Fitters • Rope Access / Rig-Builder – Electricians


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Derrick Services Cont… Rig Upgrades and Maintenance NOV Tuboscope Specialty Inspection Services carries out derrick maintenance and upgrade work scopes onshore and offshore anywhere in the world. NOV Tuboscope Specialty Inspection Services can provide a one stop option for all your repair or upgrade requirements from Survey, Design and Fabrication to final Installation. Recent projects include the Sedco Express where an additional Mini Derrick, Crown and Guide Rail assembly was added to the original structure. Installation was carried out offshore without the use of support cranes. Further examples of past projects include Guide tracks, Finger boards & Degasser lines. Other Maintenance & Upgrade Services Other maintenance and upgrade services include but are not limited to the following: • Winterization and Heat Shielding Installation • Steel Replacement & Repair • Bolt Change-outs • Derrick Washing, Blasting & Painting • Lighting System Replacement • Top Drive Upgrades • Derrick Beef-ups • Derrick removal • Derrick Life Enhancement • Derrick Extensions • Dolly Track Replacement • Racking Board design, fabrication & installation • Casing Stabbing Board fabrication & Installation • Wind Wall design, fabrication & Installation • Wind Wall Stenciling • Vent Line design, fabrication & Installation • Crown removal, servicing, inspection assembly & installation


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Derrick Services Cont… Weather Protection or Heat Shielding NOV Tuboscope Specialty Inspection Services has undertaken full derrick installation of weatherproofing cladding and heat-shielding on many projects, from Stainless Steel solid panels to Fabric- and Gauze-type Heat shielding. We are Asia's exclusive agents for: • Galebreaker, suppliers of High Temperature Resistant, Fabric Cladding & Heat Shielding • MechTool, suppliers of Stainless Steel (solid or perforated) Cladding & Heat Shielding Our projects include but are not limited to: • Transocean Parameswara • Transocean 136 • Transocean Galveston Key • ACG Central, East, West & DWG projects in Baku, Azerbaijan • Sakhalin II LUN-A & PA-B projects in SHI, Korea • Ensco 51, installation of temporary Fabric Heatshields • APEXINDO Jack Up SOEHANAH (Design & Engineering of supporting steel work including supply & installation of fabric cladding offshore) • Scorpion Offshore Drilling Company Jack Up Courageous (Design, Engineering, supply and Installation)


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Rope Access Rope Access Inspection Services NOV Tuboscope Specialty Inspection Services are specialists in Rope Access, a safe, reliable and effective technique to reach inaccessible areas. Rope Access is more versatile than gondolas or cranes, more efficient than scaffolding and can eliminate unnecessary downtime. All NOV Tuboscope Specialty Inspection Services Rope Access Operations are carried out by highly skilled IRATA trained technicians under the direct close supervision of an IRATA level 3 supervisor. At all times the company adheres to the recommendations as published in the new IRATA International Code of Practice. NOV Tuboscope Specialty Inspection Services, Singapore, is an Operator Member of IRATA which is a global trade association of member only rope access companies. Inspection and Maintenance Services Our Inspectors are qualified in NDT with specialized experience in structural and equipment assessment and our expertise is sought to install a variety of high-rise equipment and provide the regular in-situ inspection and maintenance. Rope Access Rigging and Installation of New Equipment Most of our Rope Access personnel are either Welding, Electrical or High Pressure Pipework tradesmen, or qualified NDT inspectors. Our expertise has been called on to install a variety of high-rise equipment and provide the regular in-situ maintenance and inspection, that are necessary for safe and lawful operation. Rope Access Shot Blasting, Water Blasting, Painting & Stenciling External coatings provide protection against fungus, moisture, corrosion and internal deterioration. Neglected paintwork is often a precursor to more serious problems. NOV Tuboscope Specialty Inspection Services offers a range of services to maintain the coatings of vessels, derricks, towers, buildings and other structures. Where appropriate, we provide shot-blasting and water-jetting to clean and prepare the surfaces prior to priming and painting. NOV Tuboscope Specialty Inspection Services specialized in wind wall logo stenciling.


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Rope Access Cont… Rope Access Welding, Fabrication & Repairs Our Rope Access personnel include experienced coded welders, Ex- electrical and high pressure pipework tradesmen and competent riggers. Whether you need to replace a fixture, make repairs or add a modification to an existing structure, NOV Tuboscope Specialty Inspection Services has the expertise to accommodate your needs. We can handle all aspects of a project from planning, design and fabrication, to installation and final testing. NOV Tuboscope Specialty Inspection Services provides fully engineered heat shielding solutions for masts or derricks.


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Appendix

Disclaimer National Oilwell Varco has produced this book for general information only, and it is not intended for design purposes. Although every effort has been made to maintain the accuracy and reliability of its contents, National Oilwell Varco in no way assumes responsibility for liability for any loss, damage or injury from the use of information and data herein.

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