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 HicksVP Global Drilling Services

2835 Holmes Rd.Houston, TX 77051Phone: [email protected]

Coating Technical Support

Robert LauerDirector Corrosion Control Solutions


Ryan ChristopherCoating Technical Support


Mike AdamsCoating Technical Sales


Inspection Technical Support

Hilton PrejeanDirector, Inspection Technical Sales


John DorisInspection Technical Sales

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

Hardbanding Technical Support

Mark JuckettHardbanding Product Line Manager


Machine Services Technical Support

Matt SmithGlobal Drilling/Machining Services


US Central Region

Larry LarsonRegional Sales Manager

10222 Sheldon Rd.Houston, TX 77049Phone: [email protected]

Rick JacksonRegional Sales Manager

1515 Poydras Suite 1850New Orleans, LA 70112Phone: [email protected]

US Southeast RegionRocky Mountains

Gary FritzRegional Sales Manager

14112 W. Hwy 80 EOdessa, TX 79765Phone: [email protected]

Les MassolettiArea Sales Manager

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

US West Region California

Jeff HockersmithArea Sales Manager

3003 Fairhaven Suite CBakersfield, CA 93308Phone: [email protected]

Bill KingArea Sales Manager

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

Oklahoma

North Sea

Southeast Asia/Australia

Middle East

RussiaCanada

Ken SkubaRegional Sales Manager

1600, 540 – 5Ave., S.W.Calgary AB T2P 0M2CanadaPhone: [email protected]

Dave WoodRegional Sales Manager

Badentoy Avenue, Badentoy ParkPortlethen, Aberdeen, AB12 4YBUnited KingdomPhone: [email protected]

Southeast Asia/Australia

Joe HabererRegional Sales Manager

39 Gul AvenueSingapore, Singapore 629679SingaporePhone: (65) 6861 [email protected]

Harry HillRegional Sales Manager

JI.Ampera Raya 9-10 CilandakJakarta JawaIndonesiaPhone: [email protected]

Central and South America

Brian Van BurkleoGlobal Drilling Services


Jack DyerRegional VP Operations

PO Box 61490, R/A # 13, Plot MO 0682B S50601 Jebel Ali Free Phone: [email protected]

Vladimir TikhomirovGeneral Manager

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

Europe

Frank EpperleinDirector Coating Operations

Beisenstrasse 32Gladbeck 45964GermanyPhone: +49 (5141) [email protected]

China

Shane PrudhommeCountry Manager

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

Specialty Inspection Services

Chris WatsonSIS GOM Division Manager


Brian Van BurkleoSIS Product Line Specialist

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

Michael SlorachDirector of Operations

161 Pioneer RdSingapore, Singapore 639604SingaporePhone: [email protected]

Africa

Carl SmithVice President

c/0 c/o P.I.C.O., 24 Wadi el Nil Street MaadiCairo, Al QahirahPhone: +2 010 225 [email protected]

Drill Pipe Care and Handling

NOV Tuboscope Drilling Services 2011 www.tuboscope.com 1-713 799-5100 [email protected]

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


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


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.


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


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


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


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


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


Proper vs. Improper Stabbing

Proper Stabbing

Improper Stabbing/Pin Damage

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


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


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!


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


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


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


Hardbanding Services

Hardbanding Evaluation, Identification, and Field Applications

� TCS – 8000

� TCS – Ti

� TCS – Non Mag

� TCS – 8260(Tungsten)


Machine Services

Thread Repair and Refacing

Manufacturing

Tool Joint Rebuilding



� 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


Surveillance Services

Conduct Quality Audits and/or Monitor Project Activ ities

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


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


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.


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.



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.



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



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


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.

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

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

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.

Surface Notching - CORROSION PITTING: General in location

Body wall loss, localized surface notch, stress concentration

Water, oxygen, CO2, H2S, and stress

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

Defective slip component, improper slip handling, excessive connection make-up or breakout, bending pipe in slips

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

Tongs placed on pipe, worn tool joints, improper tong jaws, poor handling

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

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

Excessive spinning chain slip

Proper chain tension, consider use of power pie spinner

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

Circumferential grooves stress concentrator

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


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


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

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

Insufficient make-up torque, damaged shoulders (face)

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

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


Improper trip make-up torque, additional downhole make-up, improper type lubricant producing excessive tension vs. make-up/torque

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 wobble due to insufficient make-up, shoulder fins, false torque, fatigue cracking at thread root, galled threads

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

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


H2S, hydrogen embrttlement, excessive pin tension

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

WEAR: Thin shoulder Reduces torque capacity, belled boxes, reduced shoulder seal area

Crooked pipe, high rotary speeds, abrasive formations

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


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

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

GALLED THREADS Damages mating threads, false torque, improper make-up, connection wobble, leaking shoulder seal, washout, pin break, drop string, lost time

Thread damage, handling without thread protectors, cross threading, worn threads, improper lubrication, dirty connection, defective kelly saver sub

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

SHOULDER FINS Prevents shoulder make-up, false torque, leaking shoulder seal, wash-out, connection wobble, pin break, drop string, lose time

Mating tool joints with different OD's, handling damage

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

HEAT CHECK Tool joint body cracking, wash-out, string separation lost time

Rapid heating due to friction between tool joint and formation, casing whip stock, etc. High rotary speeds, rapid cooling

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

SHOULDER DAMAGE

Leaking shoulder seal, washout, string separation, lost time

Mis-stabbing connection, handling damage, spinning chain between shoulders, improper pipe jacking

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


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.


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.



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.



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.


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.


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"*


Used Drill Pipe Recommendations Cont…



5” 19.50# G-105 NC-50

New API 5DP and RP7G-2

Specifications


Specifications

Recommended Minimum


Thickness .362" .290" .308"

Tool Joint O.D. 6 5/8" 6 3/32" 6 7/32"







5” 19.50# S-135 NC-50

New API 5Dp and RP7G-2

Specifications


Specifications

Recommended Minimum


Thickness .362" .290" .308"

Tool Joint O.D. 6 5/8" 6 5/16" 6 7/16"







5 1/2” 21.90# S-135 FH


Specifications


Specifications

Recommended Minimum


Thickness .361" .289" .307"

Tool Joint O.D. 7 1/2" 6 15/16" 7 1/16"


Box Tong Space 10" 6 5/8" 7 1/8"*





6 5/8” 27.70# S-135 FH


Specifications


Specifications

Recommended Minimum


Thickness .362" .290" .308"

Tool Joint O.D. 8 1/2" 8" 8 1/8"


Box Tong Space 11" 6 5/8" 7 1/8"*

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.


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.



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”.



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.



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.


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.


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.



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.



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.


Inspection Case History

655jts 21,615 5 1/2", 21.90#/ft, S-135 HT-55 TJ -1116826

636jts Accepted 20,988ft

19 Rejected 2.9% 627ft (Cracks)

49jts 1617 2 7/8", 6.85#/ft, S-135, NC 31 TOOL JOINT -1124252

35 jts Accepted 1,155ft

14jts Rejected 28.57% 462ft (Cracks)

568jts 17,906.46ft 5”, 19.50#/ft, S-135, NC 50 TOOL JOINT -1135581

528jts Accepted 16,645.43ft

40jts Rejected 7.04% 1,261.02ft (Cracks)

419 jts 13,825ft 6 5/8", 27.70#/ft, S-135, FH, TOOL JOINT -1154966


5 jts Rejected 12.19% 165ft (Cracks, Washout)

79jts 2,607ft 4 1/2", 16.60#/ft, X-95, NC 46, TJ -1147961


4jts Rejected 20.25% 132ft (Cracks)


Used Drill Pipe Inspection Methods

A.Tool Joints

Condition Recommended Methods Potential Methods Comments

1. OD Reduction Due to Wear

OD Caliper 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.

Snap gauge equally effective

Diameter tape

Steel ruler

2. Shoulder Width OD Caliper

Same as Item 1. above Snap gauge equally effective

Steel ruler

3. Pin Stretch

Thread lead gauge 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.

Profile gauge

Ring gauge

4. Box Swell Steel ruler to check Qc A good steel ruler is used to measure the diameter

of the box counterbore (Qc) and compare against the "as machined" specified diameter.

Profile gauge

Ring gauge

5. Pin Cracking

Wet fluorescent magnetic particle

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.

Dry magnetic particle

Dye penetrant

Straight beam ultrasonic

Electromagnetic scan

6. Box Cracking (Longitudinal)

Wet fluorescent magnetic particle

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.

Dry magnetic particle - if badly scarred by tong dies

Die penetrant

Angle beam ultrasonic

Visual

7. Box Cracking (Transverse)

Wet fluorescent magnetic particle 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.

Dry magnetic particle

Dye penetrant

Straight beam ultrasonic

Visual Electromagnetic scan

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

Visual 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. Hydrostatic pressure test

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

Visual with profile gauge A good visual examination will note damaged threads and the profile gauge will help evaluate thread wear or metal projections present.

Visual


Used Drill Pipe Inspection Methods Cont…

B. Tube Body

Condition Recommended Methods

Potential Methods Comments

1. Bodywall Reduction Due to Wear

Drill pipe wear (snap gauge with ultrasonic thickness gauge)

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.

Gamma-ray scan

OD caliper

Diameter tape

Straight beam ultrasonic scan

2. OD Reduction Due to Stretch

OD caliper 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.

Drill pipe wear (snap) gauge

Diameter tape

3. OD Reduction Due to Mash or Crush

OD caliper

Same as item B.2. above Drill pipe wear (snap) gauge

Diameter tape

4. OD Expansion (String Shot Back-off)

OD caliper Same as item B.2. above

Drill pipe wear (snap) gauge

5. Corrosion Pitting ID Surface

Electromagnetic scan with ultrasonic thickness prove-up 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.

Visual with bright light

Visual with borescope

Angle or straight beam ultrasonic scan

6. Corrosion Pitting OD Surface

Electromagnetic scan with depth gauge and ultrasonic thickness prove-up

Same as item B.5. above Visual

Angle or straight beam ultrasonic scan

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

Electromagnetic scan with MPI prove up 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.

Visual

Angle beam ultrasonic scan


Used Drill Pipe Inspection Methods Cont…

B. Tube Body

Condition Recommended Methods

Potential Methods Comments

8. Cuts and Scars - OD Surface - Longitudinal

Visual with MPI prove-up 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.

Electromagnetic

Angle beam ultrasonic scan

9. Fatigue Cracking OD/ID

Angle beam ultrasonic scan 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.

Electromagnetic scan with MPI Prove-up

Visual with profile gauge

Visual

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)

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

PREMIUM CLASS

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 2

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

SCRAP OR REPAIRABLE FIELD REPAIRABLE

SHOULDER CONDITION (BOX AND PIN)

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 not less than 70% Remaining wall less than 70%

Dents and Mashes OD not less than 97% OD not less than 96% OD less than 96%

Crushing and necking OD not less than 97% OD not less than 96% 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 not less than 97% OD not less than 96% OD less than 96%

String shot OD not more than 103% OD not more than 104% OD more than 104%

External corrosion Remaining wall not less than 80% Remaining wall not less than 70% Remaining wall less than 70%

Longitudinal cuts and gouges

Remaining wall not less than 80% Remaining wall not less than 70% Remaining wall less than 70%

Transverse cuts and gouges


Cracks None b None b None b

Internal Conditions

Corrosion pitting Remaining wall not less than 80% Remaining wall not less than 70% Remaining wall less than 70%

Erosion and internal wall wear


Cracks None b None b None b

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 — —

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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.


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.



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

Cost to Reach

780,000 ft Drilled $ 1,632,000.00 $ 495,040.00

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



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

Footage Purchased 130,000 feet 65,000 feet

Pipe in Service 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



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.”

Copyright 2002, Society of Petroleum Engineers Inc.

This paper was prepared for presentation at the SPE Annual Technical Conference andExhibition held in San Antonio, Texas, 29 September–2 October 2002.

This paper was selected for presentation by an SPE Program Committee following review ofinformation contained in an abstract submitted by the author(s). Contents of the paper, aspresented, have not been reviewed by the Society of Petroleum Engineers and are subject tocorrection by the author(s). The material, as presented, does not necessarily reflect anyposition of the Society of Petroleum Engineers, its officers, or members. Papers presented atSPE meetings are subject to publication review by Editorial Committees of the Society ofPetroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paperfor commercial purposes without the written consent of the Society of Petroleum Engineers isprohibited. Permission to reproduce in print is restricted to an abstract of not more than 300words; illustrations may not be copied. The abstract must contain conspicuousacknowledgment 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.

AbstractCompletion workstrings must endure an extremely hostileenvironment of erosive and corrosive fluids. Today’simproved internal plastic coatings can protect the significantinvestment in drill pipe from erosion/corrosion, as well asminimize completion trouble time caused by pipe debris(scale). An internally coated, Class 2 drill string was used for2½ years to successfully Frac Pack seventeen, highproductivity, Gulf of Mexico Deepwater completions in theGenesis Field. More than 2,000,000 pounds of abrasiveproppant was pumped without a pipe failure.

IntroductionThe completion workstring requirements were reviewedduring the development well planning for the project in 1998.During completion processes, this pipe would be subjected toonly minimal tensile stress and torsion; however, the pipewould need to bear the rigors of numerous Frac Packcompletions. The plan originally included 22 Frac Packcompletions from 16 wells with anticipated surface treatingpressure of up to 10,000 psi (depending on the selectedcompletion string diameter). The planned wells ranged indepth from 12,000’ to 23,000’ and in hole angle from 16° to66°. During each completion, the 6 5/8” drill string would bechanged to a smaller diameter completion workstring todisplace the well to CaCl2/CaBr2 completion fluid, tubingconveyed perforate (TCP) underbalance, pressure surge theperforations, wash sand fill, and Frac Pack. The workstringwould then be sent to a pipe yard to be stored outdoors untilthe 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 usedpipe with an RP7G API-IADC Used Drill Pipe ClassificationSystem rating of Class 2 due to undersized tool joints.1 Someof this pipe was as old as 20 years yet the tubes met PremiumClass standards with ≥80% wall thickness (≥0.290”)remaining. Premium Class tubes have a tensile rating atminimal yield strength of 560,764 lbs and an internal yieldpressure rating at minimum yield strength of 15,638 psi. Thereduction in torsional strength due to the reduced tool jointdiameter was not a concern due to minimal rotation fordrilling cement anticipated. These specifications met theanticipated completion workstring requirements and the rigcontractor was pleased to find commercial use for this drillpipe rather than scrap it for roughly $50 per joint or replacethe tool joints for roughly $700 per set.

An abrasion resistant internal drill pipe coating wasconsidered to combat further internal wall loss due to proppantladen Frac Packs. A wall loss of only 0.036” could downratethe Premium Class tubes to Class 3 (<70% wall) which has noRP7G published rating for tensile forces or internal yieldpressure. The drill pipe would then be scrap pipe.Additionally, the internal coating should minimize internalpipe rust and eliminate the need for acid pickle treatments. Fordeepwater operations, acid pickle treatments cost roughly$10,000 for purchase, transportation, rig time, and disposal.Most importantly, using an internal coating would eliminatethe safety, environmental, and liability risks associated withhandling and disposing of acid.

A liquid-applied, modified epoxy-phenolic internal coatingspecifically formulated for drilling environments wasconsidered for the completion program. Standard industrytests for coating abrasion resistance (Taber Abraser test,ASTM #D 4060) measure a test sample’s weight loss in mgover 1000 cycles of abrasion using a CS-17 wheel with a 1000gm load.2 In 1998, the coating considered for use had results,provided by the supplier, of 47 mg of coating lost / 1000cycles. A bare steel plate was tested to determine the weightloss without a coating; surprisingly, the results were similar(45 mg of metal lost / 1000 cycles). Taber Abraser testinformation, although useful to compare coatings, does notanswer the question of whether a coating will surviverepetitive Frac Pack treatments.

SPE 77687

Case History: Internally Coated Completion Workstring SuccessesRobert D. Pourciau, SPE, ChevronTexaco

2 ROBERT D. POURCIAU SPE 77687

Preliminary Proppant Erosion TestTo qualify the proposed internal coating, an erosion test wasconducted using three, six foot, 4 ½”, 12.75#, L-80, 8rd pupjoints and two couplings. Two of the pup joints were internallycoated to the thickness specification of 5-9 mils (125-250 µm)while one pup joint was bare. The pup joints were placed in aflow loop and 12 ppg, 20/40-mesh ceramic proppantsuspended in frac gel was pumped through the samples at 30barrels per minute. This equates to an internal velocity of 33ft/sec. One of the internally coated pup joints was subjected to200,000 pounds of proppant and the other joint to 750,000pounds. The bare pup joint was tested to 1,000,000 pounds ofproppant.

The pup joints were cut in two-foot section lengths andthen split longitudinally. All three pup joints exhibited ridgesapproximately nine inches from the pin nose on both ends. Itwas assumed this was inherent to the pipe’s manufacturingprocess. All pup joints also exhibited areas of rough metal.Additionally, the internal diameter (ID) of the test loopincreased at the 8rd coupling connection (commonly known asthe “J” area).

After pumping 200,000 lbs. of proppant, the internalcoating exhibited no holidays when tested with a wet spongeat 67 ½ volts DC at 70,000 to 80,000 ohms. This is inaccordance with NACE TM0384-94 holiday standards for filmcoatings (thickness less than 10 mils).3 A “holiday” is acondition of the coating which causes the coating to fail tomeet specified electrical resistance values.4 Holidays can becaused by defects such as thin coating areas, foreign materialon the substrate or imbedded in the coating, coating pinholes,or metallic slivers in the pipe wall. Photo 1 shows the outersurface of the coating (0.4 mils thick), which is darker due tosurface oxidation from the final baking processes, was erodedalong a very thin ridge nine inches from the pin end. Thisexposed the lighter coating material below the oxidizedsurface. Coating thickness for this sample ranged from 5 to 7mils, well within the coating specifications.

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

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

Photo 2 . 750,000 lbs proppant test at 30 BPM

After pumping 1,000,000 lbs. of proppant (Photo 3), thebare pup joint exhibits similar areas of wear near theconnections. These results are consistent with the bare steelTaber Abraser tests. Like the coated joints, the ridges andareas of rough pipe exhibited the most wear.

Photo 3 . 1,000,000 lbs proppant test at 30 BPM

In summary, the coating performed well enough in this testto be used for the planned completion program. Althoughthere were small and infrequent holidays over ~3% of thesurface area after pumping 750,000 lbs of proppant, thecoating served its purpose of minimizing metal exposure andwear (~97% of the area was protected with coating).Numerous laboratory and field case histories document thatpipe with coating holidays or wireline cuts has a lowercorrosion rate than if uncoated.4,5,6,7,8,9

The coating loss for the 750,000-lb. proppant test wasroughly 0.4 mils of the topcoat in some areas and 7 mils in theareas of the holidays. This equates to a maximum coating lossof 65 lbs. (<0.01% by weight of the proppant pumped) for a15,000’ workstring of 5” drill pipe. This coating loss shouldnot cause a measurable reduction of gravel flow capacitybased on industry proppant conductivity tests withcontaminating foreign particles.10

Ridge of 0.4mil oxidized

surface erodedFlow

Direction

Coating is intact

Holidays

FlowDirection

Ridge

Eroded Bare PipeFlow

Direction

SPE 77687 CASE HISTORY: INTERNALLY COATED COMPLETION WORKSTRING SUCCESSES 3

The pup joint’s ridges, rough spots, and connection areasexhibited the most coating wear. These results infer that theirregular internal surface of the second-hand workstring wouldbe susceptible to erosion greater than experienced in the testloop or what would be expected of a newly coated workstring.Also, since the area of most wear was near the connectionprofile change, the planned workstring’s IF connection with2.75” tool joints and 4.276” tubes should be likely to developwear.

Field Results – Well ProductivityWell productivity can be impaired by contaminants whichreduce the formation’s permeability, reduce proppantpermeability, reduce gravel pack screen conductivity, or plugthe perforation tunnels creating extra near-well pressure drop(skin effect). The main contaminants typically present are millscale, iron sulfides, pipe dope, sand, and other fine particleswhich are picked up during storage and transportation.11 TheGenesis wells overcame these damaging contaminants andhave good productivity. The average skin factor is 2.9 and theaverage production rate is 14,000 BOEGPD.

Iron scale and sulfides on the pipe wall are usually treatedwith an acid pickle and pipe dope is usually treated with asolvent just prior to frac packing. Frequently, the pipe dopeprevents the acid from fully contacting and removing thescale. With a coated workstring, all that is needed during thepickle treatment is solvent to remove pipe dope since theinternal coating greatly reduces the iron scale presence. Noacid pickle treatments were needed throughout the 17completions saving $170,000. These savings more than offsetinitial coating costs and any re-coating costs.

Dissolved iron could be a critical factor in formationdamage since precipitation of iron complexes can occur insome brines if dilution with formation waters causes anelevation of pH.12 Iron scale solubilized from downholetubulars introduces dissolved and suspended solids to thecompletion fluid which can create an endless cycle ofcirculation and filtration to reach fluid specifications. Oftenthis remedy is temporary or not effective. The CaCl2/CaBr2completion fluids used did not have any unusual dissolved orsuspended iron problems. This is partially attributed to theinternal workstring coating, coated pits, and coated troughs.

Field Results – Pipe DebrisManaging pipe debris is critical to completion processes. Asan example, pipe debris can indirectly be a safety hazard iflive TCP guns have to be pulled due to a stuck firing bar. Alsofishing 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 throughthe subject workstring without any trouble time caused by pipedebris (scale). The gravel pack tools were thoroughly checkedfor debris following each gravel pack operation and, on only

one occasion, small flakes of coating remnants were recoveredfrom the gravel pack crossover tool. Throughout thecompletion program, the major debris components observedfrom these checks was steel perforating debris and/or cement.

Field Results – ProppantsHigh rate Frac Packs are known to erode surface anddownhole equipment. Proppant mass, concentration, and pumprate must be reviewed and compared with equipment’s ratingswhen designing completions. Equipment should be pressuretested to the maximum anticipated surface treating pressure.

The second-hand 5” drill pipe workstring was used duringthe Frac Packs of all seventeen completions. Stimulationvessels pumped 1.8 MM lbs. of proppant at 10 to 25 BPM anda total of 0.5-MM lbs. of excess proppant was reversed fromthe wells during the completion program. All completionsused ceramic proppant, except one, which used bauxite.Obviously the proppant schedules pumped during thecompletion program were not a constant 12-ppg concentrationlike the abrasion loop tests. Additionally, the workstring hadto endure annular screen outs with peak pressures over 10,000psi 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 flowvelocity is 2.4 times higher than the tube velocity. The tubevelocity ranged from 9.4 to 23.8 fps; whereas, the tool jointvelocity ranged from 22.7 to 57.6 fps and exceeded the flowloop test velocity of 33 fps.

Field Results – Mechanical Abrasion and ImpactIn addition to the abrasion from proppants, the workstringwithstood the mechanical effects of 8 wireline trips tocorrelate completion tools, 8 TCP bar drop operations, andtypical (rough) drill pipe handling.

Both braided electric line and single core slicklineoperations occurred during the completion program. As aresult, roughly 10% of the tool joints have wire line cutsthrough the coating. Photos 4 and 5 show a representativewireline scared coated tool joint and also previously wirelinescared pipe which has been re-coated. A total of 8 wirelinetrips occurred and equate to a maximum possible wirelineexposure of 136,400 ft. Industry and NACE RP0291-91recommended wireline procedures to minimize coatingdamage were not used at Genesis.6,7,13,14,15 Some of theserecommendations include maximum wireline speed of 100feet per minute, no free falling tools, no sharp edge tools,single strand line, and well lubricated slickline. Previousindustry studies indicate that coatings succumbed to wirelineabrasion after 18’-15,000’ of wire was passed across thesamples.7,16,17 Abrasion rates of each coating were related tothe type and condition of the wire, the wire velocity, and theapplied wire force against the coating. Although each joint ofthe workstring was subjected to varying wireline lengths andforces, it is estimated that the footage of wire exposed to thecoating far exceeded any of these industry tests.


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

Photo 4 . Coating is wireline scared

Photo 5 . Boroscope image of well bonded coating overwireline scars

Between wells, the subject workstring was picked up andlaid down in doubles, which creates more bending stress andcoating bondment challenges than handling the pipe in singlejoints. Conventional rotary slips, or four-segmented, spring-loaded slips were set below each box. A spinner was used tomake up the pipe until the sealing surfaces of the IFconnection contacted, and drill pipe piston type four pointcontact power tongs were used to torque the drill pipe tospecifications. Full wrap-around tongs, which are typicallyrecommended for coated pipe, were not used. Theconventional rotary slips have 3 segments (2 columns of dies

per segment) while the spring-loaded slips have 4 segments (2columns of dies per segment) and the elevators are bottlenecktypes. It has been reported that an external dent as small as0.075” deep frequently causes internal coatings to crack7.Since impact damage during pipe handling can result inchipping of the coating at or near the ends of the tool joints ordisbondment of the coating, careful handling procedures aretypically recommended.6,13,15,19 This drill pipe was handled intypical rig fashion without any consideration for the internalcoating (ie: not handled like production tubing or industryguidelines for coated pipe).

Field Results - CorrosionThe workstring was also subjected to corrosive fluids (pipedope solvent, acid, frac gel, and brine) of both low and highpH for extensive periods. All coatings have a measurableresistance to corrosive fluids, which depends upon the fluidtype/concentration and temperature. Coating degradation isirreversible and can be added to during subsequent chemicaland mechanical exposure.6,13,15,16,17

Some coating systems can be damaged by exposure toorganic pipe dope solvents.6,15 The Genesis workstring wasroutinely treated before each Frac Pack with an average of 500gal of d-limonene solvent to remove pipe dope. The pipe dopeand solvent were chosen based on favorable “in-house” pipedope removal tests. The downhole gravel pack tools andsolvent returns were occasionally examined during thecompletion program to ensure proper pipe dope selection andpickle effectiveness. This solvent was pumped and reversedfrom the workstring at a sufficient volume and rate to give 5-10 minutes of contact time. This totals 2.3 hrs of contact timefor the entire completion program.

Roughly 3000 gal of 20% Acetic/Formic stimulation acid,with corrosion inhibitor, was pumped after the pipe pickle andimmediately before each fracture calibration test. This acidwas used to clean the perforations of any HEC remaining fromprevious fluid loss pills or perforating debris sweeps. Thecoating was exposed to this acid for approximately 1 hourduring each treatment (17 hrs for the entire program).

On average, 30,000-gal of high pH (9.0-9.5) borate cross-linked frac fluid was pumped during the preliminary datacalibration test and the Frac Pack of each completion. Fracturefluids are typically high pH in order to properly cross-linkguar polymers and reach the desired fluid viscosity forproppant transport. Exposure time to this high pH gel wasapproximately 2.25 hours during each completion (39 hrs forthe entire program).

The most onerous exposure the workstring endured wasfrom corrosive 5.7-6.7 pH CaCl2/CaBr2 (CaCl2 for onecompletion) during completion operations and while instorage. Visual inspections at the pipe yard revealed a layer ofsalt on the bottom of each joint (Photo 6). This salt evaporateis due to not internally rinsing the pipe and evaporation of the

CoatedWireline

Scars

WirelineScar


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

Photo 6 . Pipe in storage with CaCl2/CaBr2 salt evaporate

The coatings used at Genesis have supplier recommendedcumulative exposure limits of 40 hrs for 15% HCl, 40 hrs for15% Acetic, 40 hrs for 20% NaOH (caustic), and 16 hrs for12% HCl / 3% HF (mud acid). Industry recommendations areto flush coated pipe following corrosive treatments.6,13,15 Thedrill pipe was reverse circulated with a minimum of two drillpipe volumes (~500 bbls.) of completion fluid following eachpipe dope solvent, acid, and Frac Pack treatment.

Field Results - HydraulicsMost engineers do not recognize the hydraulic benefits thatcan be gained by using internally coated workstrings. Thesurface finish of coated workstrings reduces friction due tolower surface roughness, which is beneficial throughoutcompletion operations. Unfortunately, the second-hand 5”workstring was pitted before being coated and there is nohydraulic data that documents the workstring’s roughnessfactor. One can only suppose that coating an extremely rough,pitted workstring should yield hydraulic benefits. It is difficultto calculate the coating’s hydraulic effects due to thesignificant tool joint restrictions and the pitted nature of thepipe.

Systems Analysis indicates ~16% water injection rateincrease can be achieved (Figure 1) at maximum rig pumppressure using 16,000’ (Genesis average) of internally coated5” drill pipe with an absolute roughness of 0.000157” ratherthan using uncoated pipe with an absolute roughness of0.0018”. Similarly, less surface pressure is needed to pumpthrough the coated workstring at any rate.20

During mud displacements to completion fluid, maximumcirculating rate is desired to achieve turbulent flow effects,which help remove mud film and water wet the pipe surfaces

of the workstring and casing. The mud displacements werepumped with the rig pumps in turbulence at 12 to 23 BPM (16BPM average). The displacement rate was influenced by eachwell’s hydrostatic pressure differential when pumpingseawater spacers and by pipe friction. Obtaining maximumflowrates during mud displacements was especially crucial forsome of the deeper wells, which exceeded 20,000 feet withgreater than 67 degrees of hole angle. One such completionwas displaced with only 41% of the hole volume (afterbottoms up) to reach brine clarity specifications of 20 NTU’s.Prior to the short trip, displacement pills were circulated at themaximum rate (15 BPM). In addition to obtaining the cleanestpossible well bore from maximum circulating rate, the reducedpipe friction from a coated workstring could possibly mean thedifference between using the rig pumps to displace the welland incurring costs to use the cement unit due to highersurface pump pressures with uncoated pipe.

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 toreduce circulating bottom hole pressure, and thus reduce fluidlosses when reversing out formation fluids or sand fill. Theadded friction pressure from uncoated pipe creates morebackpressure on the formation and thus more completion fluidlosses. This can be expensive and detrimental to the payinterval’s productivity. The typical fluid volume lost duringthe Genesis perforating process was ~200 bbls per completionzone.

Frac Pack operations obviously benefit from reduced pipefriction. Key Frac Pack design issues are the size of theworkstring and subsequent friction pressure caused from highrate pumping of cross-linked gel and proppant. The workstringmust be designed to ensure adequate flowrates are obtained toachieve desired frac height growth. Surface pressure-reliefequipment is used to avoid the catastrophic failure ofdownhole completion equipment. Pipe friction is usually

DrySal t

Coated 5”

Bare Pipe

16 BPM

25%PumpPress.Difference

Press.Limit

ofRig

Pumps

16% Rate Difference


considered when setting surface pressure relief equipment anddirectly affects the job pump rate.

Workstring Inspection History and ResultsDuring the completion program, no washouts, drill pipefailures (parted pipe), or leaks occurred. In summary, notrouble time was experienced due to workstring problemsduring this challenging completion program. Seven pipeinspections occurred during the program. The focus of eachinspection was the tool joint condition; however, three of theseinspections (initial, mid-program, and final) also checked forwall thickness. The tool joints were visibly inspectedthroughout the program for coating condition and the tubeswere also visibly checked with a video camera and boroscopeon one occasion.

The coated drill pipe was used for the first threecompletions before a tool joint inspection occurred during July1999. During these first three completions, roughly 260 k-lbsof proppant was pumped and 85 k-lbs. was reversed from theworkstring. The original coating was removed from 180 jointsdue to the coating being graded by the coating company as“C” in the tool joints. A coating grade of “C” means that thereare several areas that exhibit chemical and/or mechanicaldamage that has not yet breached the coating surface to thebase metal as well as areas of damage to the base metal. Inminor to moderate drilling and completion environments, acoating grade of “C” would not immediately warrant therecoating of the particular joint.

The 180 joints were re-coated with a newly modifiedliquid-applied, epoxy-phenolic coating which was formulatedfor enhanced abrasion resistance over it’s predecessor withoutlosing any of the chemical resistance or other mechanicalproperties (impact resistance and flexibility). This newlymodified coating, when tested on ASTM #4060 Taber Abraserapparatus yielded an abrasion resistance value of 11 mg ofmaterial lost per 1000 cycles. This analysis indicated that thisnew coating was four times as abrasion resistant as it’spredecessor.

Photos 7-9 show the coating after the ninth completionwas generally intact and well bonded with small areas ofcorrosion. As mentioned earlier, infrequent, wireline scoreswere observed; however, the scores didn’t exhibit significantcorrosion damage and the coating in the surrounding area waswell bonded. During this inspection, 160 joints (26%) wererejected due to tool joint dimensional problems. Only 75 joints(12%) were rejected due to ≥0.036” of tube wall loss from theoriginal ≥80% wall (Premium Class) to <70% wall (Class 3).The rig contractor supplied 269 additional second-hand jointswith the newly formulated, enhanced abrasion resistantcoating as rejected joints were removed from service. Theremaining completions were conducted with this finalcollection of Class 2 drill pipe having both coatings.

Photo 7 . Good coating adhesion, minor corrosion & holidays

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

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

WellCoated

Pits

VideoCamera

Light CoatedIrregularSurface

CoatedSmoothSurface

VideoCameraPrism


A video camera and boroscope were used to inspect the fulllength of 21 joints after the ninth completion (Photos 5, 8,and 9). The results indicated that the tubes were in excellentcondition with isolated blisters and rated as “B” by the coatingcompany. A coating grade of “B” means that there is minorwireline wear and erosion with a few coating chips, unbrokenblisters, and exposed primer. The tool joints and run out areashowed more wear than the tubes with roughly 80% of thejoints rated as “C” and 20% rated as “F”. A coating grade of“F” means that there is severe flaking, blisters, and loose ormissing coating. Since most of the metal surface area (tubearea) was well protected by the coatings, the pipe (which metdimensional specifications) remained in service.

End of Program Representative SamplesAfter the completion program ended, the drill pipe wasinspected for tool joint dimensions and wall thickness. Onlyone joint was rejected for low wall thickness. Additionally, theoperator selected a couple of joints for a closer look. Photo 10shows two representative samples that were cut in (3) three-foot 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 usedthroughout the entire completion program (2,241,615 lbsproppant pumped) and the coating covered 97% of the drillpipe internal surface area based on analysis of therepresentative samples. This coincidentally is the same asduring the 750,000 lb. preliminary proppant test. Significantholidays are observed 2-3 feet from the box ends and a 6”-8”circumference is entirely void of the coating in the upsetrunout area. This wear far exceeds the wear noted throughout

the remainder of the joint and is likely attributed to turbulencefrom flow divergence downstream of the internally restrictedtool joint. This is also the area where slips are set, which canonly make coating bondment more challenging. The tube hasthe largest internal diameter, most surface area, and waspractically fully coated. The pin end has minor areas ofholidays and a lighter coating color in the reduced IDconnection due to surface wear.

The representative sample of the new, improved coatingappeared in much better condition than the original coatingsample. The joints with this new coating were introduced intothe completion string after the third completion due to re-coating 180 joints and after the ninth completion to replacepipe rejects. The pipe with this coating was exposed to a rangeof proppant mass between 941,000 lbs and 1,897,000 lbs. Theimproved abrasion resistance was evident from the excellentcondition of this sample. This improved coating covered99.9% of the internal surface area. Minor ridges of holidaysappear two feet from the box ends in the upset runout area anda 6”-8” circumference in the upset runout area is lightercolored due to coating surface wear. This surface wear,although much less than the original coating’s representativesample, is also likely due to turbulent flow. The tube is wellcoated and the pin end has minor areas of holidays with alighter coating color in the tool joint due to surface wear.

It was the opinion of the rig contractor that the workstringwould not have survived the rigors of the Genesis completionprogram without an internal coating.

Photo 10: Representative Samples After Program was Completed

Frac Pack Pump Direction Significant Wear

Minor WearImproved Coating

Original Coating


ConclusionsBased on the field experience obtained during the completionprogram for the Genesis development, the inspectionsperformed, and the data thoroughly analyzed, the followingconclusions are offered.

1. The internal coatings did not cause skin damage to 17Frac Pack completions (average production rate is14,000 BOEGPD and average skin factor is 2.9)

2. The coatings had a significant unexpected side effectof debris (scale) mitigation, eliminating trouble time.

3. The original liquid-applied, modified epoxy-phenolicinternal coating held up well (97% surface areacoverage) and the improved coating held up better,(99.9% coverage) to: 2.2 MM lbs. proppant, 8 TCPbar drops, 8 wireline runs, 6000 gal of organicsolvent, 56,000 gal of acid, 501,000 gal of high pHfrac fluid, and CaCl2/CaBr2 during 17 Frac Packsover 2 ½ yrs.

4. The coatings protected the pipe and prevented anyintegrity failures during completion work. There wasnever a leak or washout and only 75 joints (12%)were rejected due to wall loss in the tubes.

5. The coatings eliminated the need for acid pickletreatments due to minimizing internal pipe rust. Thiscut the cost to purchase, transport, and dispose ofacid (~$10,000 per well) along with eliminating thesafety, environmental, and liability risks associatedwith handling and disposing of acid.

AcknowledgmentsThe author would like to acknowledge the considerable inputand assistance given by John Champagne, Rick Jackson,Robert Lauer, Charlie Speed, and Bill Snider of TuboscopeInc., David Barbin, Bill Rau, and Larry Hathcock ofChevronTexaco, J.R.Slaten of D.C. International, RonMorrison, Lonnie Mills, David Hinton, and Shelton Lejeune ofNabors Offshore Corporation, David Barton of GlobalCompletion Services, and Bart Waltman of Halliburton.Special recognition goes to Curt Newhouse ofChevronTexaco, and Nabors Offshore Corporation forchampioning the use of coated drill pipe for the Genesisworkstring. Without their efforts to track and inspect theworkstring over the past 2½ years, this paper would not havebeen possible. Tuboscope Inc. and Halliburton are appreciatedfor the preliminary coating erosion tests, documenting welltreatment parameters, monitoring pipe debris in gravel packtools, and the final drill pipe sample analysis at the end of theproject. Finally the author wishes to thank ChevronTexacomanagement for permission to publish this paper.

References1. API RP 7G Fifteenth Edition, January 1, 1995, “Recommended

Practice for Drill Stem Design and Operating Limits”, Tables 4and 5, API, Washington, D.C.

2. ASTM D 4060-81: “Abrasion Resistance of Organic Coatingsby the Taber Abraser” ASTM, Philadelphia, PA.

3. NACE Standard TM0384-94: Holiday Detection of InternalTubular Coatings of Less Than 250 um (10 mils) Dry FilmThickness, NACE International, Houston, TX.

4. Campbell, C.A. III: “Effects Of Holidays Or MechanicalDamage On Internally Plastic Coated Tubulars,” Corrosion/79Paper 257, NACE International, Houston, TX.

5. Roberson, G.R.: “Comparison of Corrosion Rates: Wireline-CutPlastic Coated Oil Well Tubing vs. Wireline-Cut Bare Tubing,”Materials Performance, Vol. 13, No. 12, pp. 26-28, presented aspart of a panel discussion at a meeting of T-1G at Corrosion/74,NACE International, Houston, TX

6. Davis, R.H.: “The Use Of Internal Plastic Coatings To MitigateCO2 Corrosion In Downhole Tubulars,” Corrosion/94 Paper 23,NACE International, Houston, TX.

7. Wolfe, L.H. et al.: “Laboratory Testing Of In-ServicePerformance Parameters Of Internal Pipe Coatings,”Corrosion/92 Paper 333, NACE International, Houston, TX.

8. Byars, H.G.: “Corrosion Control In Petroleum Production,” TPCPublication 5, Second Edition, NACE International, Houston,TX.

9. Roberson, G.R.: “Materials Performance” 13, 12 (1974): p.26.10. Coulter, G.R.: “The Advantages of High Proppant Concentration

in Fracture Stimulation” paper SPE 3298, June, 197211. Nasr-El-Din, H.A. et al.: “Lessons Learned from Acid Pickle

Treatments of Deep/Sour Gas Wells,” paper SPE 73706presented at the 2002 SPE International Symposium andExhibition on Formation Damage Control held in Lafayette,LA., 20-21 February

12. Ali, S.A. and Shelby, D.C.: “Guidelines for Rig-Site Removal ofIron Contamination from Completion Brines”, February 1999,Petroleum Engineer International

13. NACE Standard RP0291-91: Care, Handling, and Installation ofInternally Plastic-Coated Oilfield Tubular Goods andAccessories, Section 7: Operation, NACE International,Houston, TX.

14. Thompson, I. et al.: “Evaluation Of Coating For The ProtectionOf Downhole Production Tubing,” Corrosion/97 Paper 66,NACE International, Houston, TX.

15. Nelson, J.M.: “New Advancements in the Use of Internal PlasticCoating for Enhanced Oil Recovery,” Materials Performance,Vol. 30, No. 12, pp. 27-30, 1991, NACE International, Houston,TX

16. Lewis, R.E. and Barbin, D.K.: “Selecting Internal Coatings ForSweet Oil Well Tubing Service,” Corrosion/99 Paper 15, NACEInternational, Houston, TX.

17. Lewis, R.E. and Barbin, D.K.: “Selecting Internal Coatings ForGas Well Tubulars,” Corrosion/97 Paper 70, NACEInternational, Houston, TX.

18. ASTM D 2794-82: “Resistance of Organic Coatings to theEffects of Rapid Deformation (Impact)” ASTM, Philadelphia,PA.

19. Wells, K.R.: “The Reduction of Coated Tubing Failures in theDickinson Heath Sand Unit, North Dakota,” paper SPE 17525presented at the 1988 SPE Rocky Mountain Regional Meetingheld in Casper, WY., 11-13 May

20. P.E. Moseley and Associates, Inc., “The Well EvaluationModel - 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. TK-34XT 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 TK-34XT product, while the other three joints were externally wrapped with a product called Ryt-Wrap. Ryt-Wrap is a PPS wrap tape that uses an epoxy adhesive agent. While both products provided the needed external protection, the Ryt-Wrap appears to provide added benefit is that is more impact resistant as well as its ability to be

field repaired.

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.


Table 1: Well Completion Information

Well Reservoir BHP, psi BHT, °F Deviation, (°) Top Perf – md

Bottom Perf – md

Top Perf – tvd

Bottom Perf – tvd

Production Type

A-7 E Sand 6,715 165 1 10,125 10,156 9,930 9,961 Gas

A-7 C Sand 4,122 141 25 7,853 8,016 7,658 7,806 Oil

A-2 A Sand 3,425 116 54 7,588 7,723 6,512 6,591 Oil

A-2 A Sand 3,425 116 54 7,313 7,488 6,447 6,493 Oil

A-4 C Sand 4,677 129 31 8,353 8,423 8,036 8,096 Oil

A-4 B Sand 4,343 125 31 7,838 7,934 7,519 7,601 Oil

A-4 A Sand 3,124 113 23 6,449 6,663 6,294 6,373 Oil

A-3 C Sand 4,744 137 25 10,405 10,499 8,138 8,223 Oil

A-3 A Sand 3,316 100 64 7,863 7,953 6,287 6,327 Gas

A-10 B Sand 3,572 107 48 8,853 8,883 6,816 6,836 Gas

A-10 A Sand 3,250 120 67 7,481 7,668 6,170 6,242 Oil

A-10 A Sand 3,212 117 75 7,081 7,218 6,057 6,094 Gas

A-5 A Sand 3,454 121 58 8,750 8,783 6,670 6,688 Oil

A-5 A Sand 3,454 121 58 8,450 8,520 6,531 6,560 Oil

A-9 C Sand 4,116 132 50 8,923 9,011 7,701 7,758 Oil

A-9 B Sand 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


Extending the Life of Used Drill Pipe

An Internal Coating Management Process


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


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”.


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.


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)


Why Recoat Drill Pipe? Cont…

Grade Description Example

Upset Run-out Tube Body

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%.

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.


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. Tool Joint Outside Diameter (OD) 2. Tong Space on Pin Connection 3. Tong Space on Box Connection 4. 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.


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:

USED DRILL PIPE –

INTERNAL PLASTIC COATING CLASSIFICATIONS

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This coating evaluation procedure is an uncontrolled document from NOV Tuboscope and may be used without permission.

Copyright NOV Tuboscope. 2009. All Rights Reserved.

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

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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

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

Figure 3: Wireline Cuts in Coating

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CLASSIFICATIONS:

CLASS 1 (Premium) STATUS: Re-use

• For the ID coating to achieve a class 1 (premium) designation it can contain:

Description:

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

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

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

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

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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.

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Figure 8: Class 2 Coating in the Tool Joint

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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

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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.

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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.

USED DRILL PIPE –


EFFECTIVE DATE

08/09/10

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

USED DRILL PIPE –


EFFECTIVE DATE

08/09/10

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.

USED DRILL PIPE –


EFFECTIVE DATE

08/09/10

PAGE 14 of 17

WORK INSTRUCTION



• 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. NOTE: 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

USED DRILL PIPE –


EFFECTIVE DATE

08/09/10

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

USED DRILL PIPE –


EFFECTIVE DATE

08/09/10

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

USED DRILL PIPE –


EFFECTIVE DATE

08/09/10

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® HARDBANDINGIndustry Leading Tool Joint and Casing Protection

www.nov.comt u boscope@nov. com

THE WORLD LEADER IN HARDBANDINGSINGLE 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.

YOUR SINGLE SOURCE FOR THE MOST COMPREHENSIVE

FIELD-PROVEN HARDBANDING ALLOYS

TCS-8000® REDUCES CASING WEAR

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

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.

WEAR FACTOR

TCS – TITANIUMTCS 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.

PACKAGE OF OILFIELD TUBULAR SERVICES — WORLDWIDE.

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

THE NEXT GENERATION IN HARDBANDING TECHNOLOGY

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.

Screen shot of hardband material analysis

w w w . n o v . c o mw w w . n o v . c o m

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.

[email protected]

One Company . . . Unlimited Solutions

Regional Offices

Central Region Administration10222 Sheldon RoadHouston, Texas 77049Phone: 281 456 8881

Machining Services7505 Upriver RoadCorpus Christi, Texas Phone: 361 289 1525

West Region14112 W. Hwy 80EOdessa, Texas 79765Phone: 432 563 2150

Southeast Region1208 First AvenueHarvey, Louisiana 70058Phone: 504 631 1900

Canada 2201 9th Street Nisku, AB, Canada T9E 7Z7Phone: 780 955 7675

Latin AmericaCorrientes 316 Fifth floor1008 Buenos AiresArgentina Phone: 54 11 4130 1600

Europe Tuboscope Vetco(Deutschland) GmbHP. O. Box 311129231 CelleMaschweg 5, 29227Phone: 49 5141 8020

Far East 39 Gul Avenue Singapore 629679Phone: 65 68612688

CorporateHeadquarters7909 Parkwood Circle DriveHouston, Texas 77036United StatesPhone: 713 375 3700Fax: 713 346 7687

NOV Tuboscope2835 Holmes RoadHouston, Texas 77051United StatesPhone: 713 799 5100

North America SalesHoustonPhone: 281 456 8881

South TexasPhone: 361 854 1167

East TexasPhone: 903 984 8553 DallasPhone: 214 561 8737

Machining ServicesCorpus ChristiPhone: 361 289 1525PearlandPhone: 281 482 9014

Mississippi/AlabamaPhone: 601 428 1555

LouisianaNew OrleansPhone: 504 636 3672LafayettePhone: 337 272 3284Machining ServicesPhone: 337 837 1669

West Virginia / PennsylvaniaPhone: 304 622 1507

Permian BasinPhone: 432 563 2150

CaliforniaPhone: 661 325 8529

OklahomaPhone: 405 478 3400Machining ServicesPhone: 405 677 3386

Rocky MountainsPhone: 303 572 7766

New MexicoPhone: 505 333 2224

CanadaNiskuPhone: 780 955 7675CalgaryPhone: 403 216 5000Red DeerPhone: 403 343 8100Grand PrairiePhone: 780 538 9338

Latin AmericaSalesMexicoPhone: 52 229 201 0035

ArgentinaPhone: 54 11 4130 1624

BrazilPhone: 55 22 2773 0600

ColombiaPhone: 571 644 4510

PeruPhone: 51 1 219 1160

BoliviaPhone: 591 3 355 3500

Eastern Hemisphere SalesGermany, Africa, ItalyPhone: 49 5141 8020

ScotlandPhone: 44 1224 787740

NorwayPhone: 47 56312100

NetherlandsPhone: 31 0 524 525977

RussiaPhone: 7 495 935 86 31

ChinaPhone: 86 21 22168800

IndonesiaJakartaPhone: 62 21 7806265

SingaporePhone: 65 6861 2688

Saudi ArabiaPhone: 966 3 837 8080

OmanPhone: 968 24484070

Abu DhabiPhone: 971 2 6260180

© 2010 National Oilwell Va© 2010 National Oilwell VarcorcoD392001522-MKT-001 Rev. 02

Downhole Solutions

Drilling Solutions

Engineering and Project Management Solutions

Lifting and Handling Solutions

Production Solutions

Supply Chain Solutions

Tubular and Corrosion Control Solutions

Well Service and Completion Solutions



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.


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.

Machine Services

LATIN AMERICALATIN AMERICA

CountryCountry FacilityFacility # of CNC # of CNC MachinesMachines

ToolToolJoint Joint

Build-upBuild-up

Rotary Rotary Shoulder Shoulder

ConnectionConnection

Grant PridecoGrant Prideco®® Licenses Licenses

TTS TTS (PH-6)(PH-6) Sonocord Sonocord

DP2S55DP2S55Smith Smith TSDSTSDS

THS THS (TenarisHydrill)(TenarisHydrill)

Manufacture Manufacture SubsSubsHTHT XTXT

XTMXTM

CTMCTM

GPDSGPDS

TurboTorqueTurboTorque

ArgentinaArgentina *ML 9*ML 9 ••BoliviaBolivia YacuibaYacuiba 11 •• ••BoliviaBolivia YacuibaYacuiba *ML*ML •• ••BrazilBrazil MacaeMacae 22 •• •• •• •• •• •• ••ColombiaColombia Block BogotaBlock Bogota *ML*ML ••ColombiaColombia Cano LimonCano Limon *ML*ML ••ColombiaColombia YopalYopal 11 •• •• •• ••EcuadorEcuador Francisco de Francisco de

Orellana (El Coca)Orellana (El Coca)11 •• ••

EcuadorEcuador Francisco de Francisco de Orellana (El Coca)Orellana (El Coca)

*ML 2*ML 2 ••

MexicoMexico MoralitoMoralito *ML*ML ••MexicoMexico Poza RicaPoza Rica 2 CNC / 2 CNC /

*ML 2*ML 2•• ••

MexicoMexico ReynosaReynosa *ML*ML ••PeruPeru Block 1 ABBlock 1 AB 11 •• •• •• •• ••PeruPeru Block 56/88 Block 56/88

MalvinasMalvinas*ML*ML •• •• •• ••

PeruPeru Block 57 RepsolBlock 57 Repsol *ML*ML •• •• ••PeruPeru Block 58 PetrobrasBlock 58 Petrobras 1 CNC / 1 CNC /

*ML*ML•• •• ••

PeruPeru Block 8 Block 8 *ML*ML •• ••PeruPeru LimaLima 11 •• •• •• •• •• ••PeruPeru TalaraTalara *ML*ML •• •• ••* Manual Lathe* Manual Lathe

www.nov.comwww.tuboscope.com

Machining Services — Latin America, Europe and AsiaLocation Capabilities and Contacts

2835 Holmes RoadPO Box 808 (77001)Houston, Texas 77051United States

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

EUROPE AND ASIAEUROPE AND ASIA

FacilityFacility # of CNC # of CNC MachinesMachines

Tool Joint Tool Joint Build-upBuild-up


ConnectionsConnectionsHTHT XTXT XTMXTM GPDSGPDS TTS (PH-6)TTS (PH-6) Manufacture Manufacture

SubsSubs

Kristiansand, NorwayKristiansand, Norway 11 •• •• ••Aberdeen, ScotlandAberdeen, Scotland 44 •• •• ••Baku, AzerbaijanBaku, Azerbaijan 11 •• •• •• ••* Manual Lathe* Manual Lathe

© 2011 National Oilwell VarcoD392004146-MKT-001 Rev. 02

UNITED STATESUNITED STATES

FacilityFacility# of CNC # of CNC MachinesMachines



ConnectionsConnectionsHTHT XTXT XTMXTM GPDSGPDS TTS (PH-6)TTS (PH-6)

Manufacture Manufacture SubsSubs

Kenai, AKKenai, AK ML*ML* •• ••North Slope, AKNorth Slope, AK 22 •• •• •• •• ••Bakersfield, CABakersfield, CA 22 •• •• •• •• •• •• ••Broussard, LABroussard, LA 77 •• •• •• •• •• •• ••Farmington, NMFarmington, NM 11 •• •• ••Williston, NDWilliston, ND 22 •• •• ••Oklahoma City, OKOklahoma City, OK 77 •• •• •• •• •• •• ••Corpus Christi, TXCorpus Christi, TX 55 •• •• •• •• •• ••Godley, TXGodley, TX 11 •• •• ••Odessa, TXOdessa, TX 11 •• •• ••Pearland, TXPearland, TX 33 •• •• •• •• •• •• ••Kilgore, TXKilgore, TX 11 •• •• ••Bridgeport, WVBridgeport, WV 22 •• •• •• •• •• ••Casper, WYCasper, WY 11 •• •• ••* Manual Lathe* Manual Lathe

Matt Smith: 713 799 5173Matt Smith: 713 799 5173

Bill Hicks: 713 799 4905Bill Hicks: 713 799 4905

CANADACANADA

FacilityFacility # of CNC # of CNC MachinesMachines



ConnectionsConnectionsHTHT XTXT XTMXTM GPDSGPDS TTS (PH-6)TTS (PH-6) Manufacture Manufacture

SubsSubs

Nisku, CanadaNisku, Canada ML*ML* ••Grand Prairie, CanadaGrand Prairie, Canada ML*ML* ••* Manual Lathe* Manual Lathe

Phone: 780 955 7666Phone: 780 955 7666

www.nov.comwww.tuboscope.com

Machining Services — United States and CanadaLocation Capabilities and Contacts

2835 Holmes RoadPO Box 808 (77001)Houston, Texas 77051United States: 713 799 5173 / 713 799 4905Canada: 780 955 7666Western Hemisphere: 1 800 433 0059


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.


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 heavy-weight 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



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.


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.


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.


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%.


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.


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.


Rig Inspection Services Cont…


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.


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.


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.


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.


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.


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.


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.


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.


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.


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


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.


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.


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


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


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)


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.


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.

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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