March 30, 2017 | Author: Mohammed Al-Mislimmawwy | Category: N/A
Download 2011Global Drilling Services (2)...
Table of Contents Contacts
Section 1
Drill Pipe Care and Handling
Section 2
Inspection Services
Section 3
Coating Services
Section 4
Hardbanding Services
Section 5
Machine Services
Section 6
Specialty Inspection Services
Section 7
Appendix
Section 8
Global Drilling Services Bill Hicks VP Global Drilling Services 2835 Holmes Rd. Houston, TX 77051 Phone: 713-799-4905
[email protected]
Coating Technical Support Robert Lauer Director Corrosion Control Solutions
Ryan Christopher Coating Technical Support
2835 Holmes Rd. Houston, TX 77051 Phone: 713-799-4571
[email protected]
2835 Holmes Rd. Houston, TX 77051 Phone: 713-799-5130
[email protected]
Mike Adams Coating Technical Sales 2835 Holmes Rd. Houston, TX 77051 Phone: 713-799-5121
[email protected]
Inspection Technical Support Hilton Prejean Director, Inspection Technical Sales
John Doris Inspection Technical Sales
2835 Holmes Rd. Houston, TX 77051 Phone: 713-799-5553
[email protected]
2835 Holmes Rd. Houston, TX 77051 Phone: 713-799-8198 John.Doris@nov,com
Hardbanding Technical Support
Machine Services Technical Support
Mark Juckett Hardbanding Product Line Manager
Matt Smith Global Drilling/Machining Services
2835 Holmes Rd. Houston, TX 77051 Phone: 713-799-5428
[email protected]
2835 Holmes Rd. Houston, TX 77051 Phone: 713-799-5173
[email protected]
Oklahoma
US Central Region
Bill King Area Sales Manager
Larry Larson Regional Sales Manager
3216 Aluma Valley Dr. Oklahoma City, OK 73121 Phone: 405-478-3400
[email protected]
10222 Sheldon Rd. Houston, TX 77049 Phone: 713-456-6106
[email protected]
Rocky Mountains
US Southeast Region
Les Massoletti Area Sales Manager
Rick Jackson Regional Sales Manager
410 17th Street Suite 1350 Denver, CO 80202 Phone: 303-572-7766
[email protected]
1515 Poydras Suite 1850 New Orleans, LA 70112 Phone: 504-636-3672
[email protected]
US West Region
California
Gary Fritz Regional Sales Manager
Jeff Hockersmith Area Sales Manager
14112 W. Hwy 80 E Odessa, TX 79765 Phone: 432-563-2150
[email protected]
3003 Fairhaven Suite C Bakersfield, CA 93308 Phone: 661-325-8529
[email protected]
Europe
North Sea
Frank Epperlein Director Coating Operations
Dave Wood Regional Sales Manager
Beisenstrasse 32 Gladbeck 45964 Germany Phone: +49 (5141) 8020
[email protected]
Badentoy Avenue, Badentoy Park Portlethen, Aberdeen, AB12 4YB United Kingdom Phone: 713-799-4917
[email protected]
Canada
Russia
Ken Skuba Regional Sales Manager
Vladimir Tikhomirov General Manager
1600, 540 – 5Ave., S.W. Calgary AB T2P 0M2 Canada Phone: 403-303-346
[email protected]
15A Leninsky Prospect 7th Floor Moscow, Russia 119071 Phone: +7 495 287 2636
[email protected]
Southeast Asia/Australia
Southeast Asia/Australia
Joe Haberer Regional Sales Manager
Harry Hill Regional Sales Manager
39 Gul Avenue Singapore, Singapore 629679 Singapore Phone: (65) 6861 2688
[email protected]
JI.Ampera Raya 9-10 Cilandak Jakarta Jawa Indonesia Phone: 713-799-5130
[email protected]
Central and South America
Middle East
Brian Van Burkleo Global Drilling Services
Jack Dyer Regional VP Operations
2835 Holmes Rd. Houston, TX 77051 Phone: 713-799-4900
[email protected]
PO Box 61490, R/A # 13, Plot MO 0682B S50601 Jebel Ali Free Phone: +971-4-811-0210
[email protected]
China
Africa
Shane Prudhomme Country Manager
Carl Smith Vice President
Floor 10-12, Building #10, Lvzhou Center, Lane 162 Putuo, Shanghai Shi 200333 China Phone: +86 21 2216 8800 ext 6100
[email protected]
c/0 c/o P.I.C.O., 24 Wadi el Nil Street Maadi Cairo, Al Qahirah Phone: +2 010 225 9008
[email protected]
Specialty Inspection Services Brian Van Burkleo SIS Product Line Specialist
Chris Watson SIS GOM Division Manager
2835 Holmes Rd. Houston, TX 77051 Phone: (65) 6264 3400
[email protected]
2835 Holmes Rd. Houston, TX 77051 Phone: 713-799-5165
[email protected]
Michael Slorach Director of Operations 161 Pioneer Rd Singapore, Singapore 639604 Singapore Phone: 713-799-4900
[email protected]
Drill Pipe Care and Handling
Why You Need a Care and Handling Management Program?
DRILL PIPE IS YOUR SINGLE LARGEST INVESTMENT TAKE CARE OF IT! INCREASE THE RETURN ON YOUR INVESTMENT REDUCE COSTLY FAILURES WHILE INCREASING SAFTEY CONSERVE CAPITAL ENHANCE YOUR COMPANY IMAGE WITH YOUR CUSTOMERS
NOV Tuboscope Drilling Services 2011
www.tuboscope.com
1-713 799-5100
[email protected]
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
NOV Tuboscope Drilling Services 2011
www.tuboscope.com
1-713 799-5100
[email protected]
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.
NOV Tuboscope Drilling Services 2011
www.tuboscope.com
1-713 799-5100
[email protected]
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
NOV Tuboscope Drilling Services 2011
www.tuboscope.com
1-713 799-5100
[email protected]
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
NOV Tuboscope Drilling Services 2011
www.tuboscope.com
1-713 799-5100
[email protected]
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
NOV Tuboscope Drilling Services 2011
www.tuboscope.com
1-713 799-5100
[email protected]
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
NOV Tuboscope Drilling Services 2011
www.tuboscope.com
1-713 799-5100
[email protected]
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
NOV Tuboscope Drilling Services 2011
www.tuboscope.com
1-713 799-5100
[email protected]
Proper vs. Improper Stabbing
Proper Stabbing
Improper Stabbing/Pin Damage
*Running drill pipe with sealing shoulder/pin damage could cause a washout
NOV Tuboscope Drilling Services 2011
www.tuboscope.com
1-713 799-5100
[email protected]
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
NOV Tuboscope Drilling Services 2011
www.tuboscope.com
1-713 799-5100
[email protected]
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!
NOV Tuboscope Drilling Services 2011
www.tuboscope.com
1-713 799-5100
[email protected]
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
NOV Tuboscope Drilling Services 2011
www.tuboscope.com
1-713 799-5100
[email protected]
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
NOV Tuboscope Drilling Services 2011
www.tuboscope.com
1-713 799-5100
[email protected]
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
NOV Tuboscope Drilling Services 2011
www.tuboscope.com
1-713 799-5100
[email protected]
Hardbanding Services
Hardbanding Evaluation, Identification, and Field Applications TCS – 8000 TCS – Ti TCS – Non Mag TCS – 8260(Tungsten)
NOV Tuboscope Drilling Services 2011
www.tuboscope.com
1-713 799-5100
[email protected]
Machine Services
Thread Repair and Refacing
Manufacturing
Tool Joint Rebuilding
NOV Tuboscope Drilling Services 2011
www.tuboscope.com
1-713 799-5100
[email protected]
Specialty Inspection Services Rig Components o NDT Testing Derrick/Mast Inspection o API 4G Cat III & IV o Bolt Torque Critical Load Path Inspection Lifting Gear Inspection o Pad Eyes o Slings o Lifting Subs Rope Access DROPS Survey Offshore Rig Maintenance
NOV Tuboscope Drilling Services 2011
www.tuboscope.com
1-713 799-5100
[email protected]
Surveillance Services
Conduct Quality Audits and/or Monitor Project Activities Services Include: Mill Surveillance
Review of Vendor Personnel Qualification Records
Monitoring Material In-Process
Witness of Factory Acceptance Tests, Run Tests, Load Tests, Hydrostatic Tests
Verification of Product Traceability
Document Review of Materials
Final Verification of Finished Products
Verification of Packaging and Marking
Witness of Loading and Offloading Activities
NOV Tuboscope Drilling Services 2011
www.tuboscope.com
1-713 799-5100
[email protected]
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
NOV Tuboscope Drilling Services 2011
www.tuboscope.com
1-713 799-5100
[email protected]
NOV Tuboscope Drilling Services 2011
www.tuboscope.com
1-713 799-5100
[email protected]
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.
NOV Tuboscope Drilling Services 2011
www.tuboscope.com
1-713 799-5100
[email protected]
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.
NOV Tuboscope Drilling Services 2011
www.tuboscope.com
1-713 799-5100
[email protected]
Drill Pipe Care and Handling Cont… Proper Stabbing is Critical Improper stabbing can result in severe damage to sealing shoulders and threads. This can result in costly washouts in the connections. Replace Worn Drill Pipe Wipers Drill Pipe Wipers perform a valuable service by cleaning corrosive drilling fluids from the OD surface of drill pipe. OD corrosion pitting is a stress riser and many cracks originate in the bottom of a corrosion pit. Cracks result in washouts and twist-offs. Change the wipers when they show wear. Rinse Drill Pipe OD and ID When possible, rinse the OD and ID of drill pipe to remove corrosive drilling fluids. The potential for OD corrosion increases when drill pipe is on racks with drilling fluids still caked on the OD. Drill Pipe Rubbers If drill pipe rubbers are being used, be sure to move them to different spots on the drill pipe. If left in one place, corrosive drilling fluids are trapped resulting in extensive OD pitting. Slip Maintenance Keep a continuous surveillance on the condition of the slip dies. If a die is worn, replace all of the dies, not just the worn die. If only the worn die is replaced, it could cause bi-axial loading on the drill pipe resulting in slip damage. Never use slips as a break.
NOV Tuboscope Drilling Services 2011
www.tuboscope.com
1-713 799-5100
[email protected]
Drill Pipe Care and Handling Cont… Check the Hardband Condition Continuously check the condition of the hardbanding on the tool joints. When the hardbanding is worn flush with the tool joint, it is time to rehardband the tool joint. Hardbanding is much less expensive than tool joint build-up. Check Condition of the Shoulder Faces and Bevels The shoulders are the seals of drill pipe. Damaged shoulder faces will not seal resulting in washouts. Check Straightness of Drill Pipe Crooked drill pipe will result in rapid tube body and tool joint wear. The easy way to check straightness is to roll the joint of drill pipe slowly on the rack. It will wobble if not straight. Check Condition of Internal Coating Internal coating can extend the life of drill pipe. However, coating will wear out over time. When coating no longer protects the ID surface of the drill pipe, the pipe is a candidate for re-coating. Never Use Steel Rods or Hooks to Move Drill Pipe Slip Damage Slip damage is a series of transverse notches in the drill pipe. These notches are stress risers that result in cracks. Cracks cause washouts and twist-offs. Do Not Use Chains Do Not Use Spinners
NOV Tuboscope Drilling Services 2011
www.tuboscope.com
1-713 799-5100
[email protected]
Drill Pipe Care and Handling Cont… Use Brass vs. Steel Hammer We do not recommend hammering on drill pipe however if checking fluid levels in drill pipe is necessary, use a brass hammer. Steel hammers make indentions, which are stress risers. This can result in washouts and twist-offs. Tong Die Maintenance Tong Die condition should be continuously monitored for the same reasons as slip dies. Positioning of Tongs Always use tongs and back-up tongs. The tongs should always be placed on the tool joint and not the tube body. The rotary table is not a tong. Monitor Rotary Speed and Torque Proper rotary speed and torque can prevent costly failures. For example, under-torque frequently results in washouts in the connection. Over-torque can result in transverse cracks in the threads due to increased stress. Improper rotary speed increases stress on drill pipe. Racking of Drill Pipe Drill pipe should never be stacked improperly. It is a safety issue as well as a damage issue. Drill pipe should be stacked on either racks or sills with wood boards separating each layer. For range 2 drill pipe, there should be three boards with one in the center and the other two halfway down toward each end. Good chocks should be used to secure the drill pipe. Never pyramid stack drill pipe Never use drill pipe tubs
NOV Tuboscope Drilling Services 2011
www.tuboscope.com
1-713 799-5100
[email protected]
Drill Pipe Care and Handling Tips - Tubebodies Problem
Usual Effect
Probable Cause
Possible Correction
WASHOUT: Usually occurs near pin end upset taper or in area from lower part of slip area to box end upset taper.
Hole in pipe, drop in mud pressure, string separation, lost time
Surface notching, cyclic stressing, fatigue cracking
Minimize surface notching, reduce stress level, avoid critical rotary speed. Move bottom hole pipe up hole on trips, taper transition zone, use shock subs, use heavy weight drill pipe between drill pipe and drill collars.
TWIST OFF: Usually occurs near pin end upset taper or in area from lower part of slip area to box end upset taper
String separation, fishing job, lost time
Surface notching, cyclic stressing, fatigue cracking
Minimize surface notching, reduce stress level, avoid critical rotary speed. Move bottom hole pipe up hole on trips, taper transition zone, use shock subs, use heavy weight drill pipe between drill pipe and drill collars.
FATIGUE CRACKING: Predominately found near pin end upset taper and in area from box end upset taper to lower part of slip area. Surface Notching CORROSION PITTING: General in location
Wash out, twist off, string separation, lost time, pipe loss
Cyclic stressing, surface notches (corrosion, cuts, etc.), hydrogen embrittlement
Body wall loss, localized surface notch, stress concentration
Water, oxygen, CO2, H2S, and stress
Dampen stress, avoid critical rotary speed, minimize surface notching, move bottom hole pipe up hole on trips, use shock subs, prevent H2S in flow. Use lowest strength pipe where possible. Minimize rate of change in hole deviation. Maintain mud pH above 9.5, plastic coating, inhibitors, oxygen scavengers, clean pipe ID & OD, dampen stress, monitor with corrosion test rings
Suface Notching - SLIP CUTS: Located in slip area
Transverse surface notch, stress concentrator
Pipe turning in slips, defective slips/bowl, improper slip handling
Use back-up tong for make-up and breakout, use care when spinning pipe with rotary, improve slip/bowl maintenance, use care while setting slips
Surface Notching - SLIP AREA MASH: Located in slip area
Surface impression, stress concentrator
Improve slip/bowl maintenance and use care while setting slips
Surface Notching TONG CUTS: Usually found in an area over and just above pin end upset
Multiple surface notches, stress concentrators
Defective slip component, improper slip handling, excessive connection make-up or breakout, bending pipe in slips Tongs placed on pipe, worn tool joints, improper tong jaws, poor handling
Surface Notching CHAIN CUTS: Usually found in area over and just above pin end upset
Circumferential grooves (notch) at pin and upset area stress concentrators, cold worked metal Circumferential grooves stress concentrator
Excessive spinning chain slip
Proper chain tension, consider use of power pie spinner
Corrosion/erosion at ends of drill pipe/casing protector - Poor mud drain/cleaning at protector end
Periodically move or remove protector, clean pipe at ends and under protector
Surface Notching RUBBER CUT EXTERNAL RING CORROSION: Usually found in an area approximately 2 feet above pin end tool joint
NOV Tuboscope Drilling Services 2011
www.tuboscope.com
Place tongs only on tool joint diameter, use correct tong jaws, use sharp tong dies
1-713 799-5100
[email protected]
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
NOV Tuboscope Drilling Services 2011
www.tuboscope.com
1-713 799-5100
[email protected]
Drill Pipe Care and Handling Tips – Tool Joints Problem
Usual Effect
Probable Cause
Possible Correction
WASHOUT
Erosion of shoulder (face) seal and threads, mud pressure loss, string separation, lost time
Apply proper make-up torque per tool joint class, remove shoulder damage by refacing if possible; recut connection; remove shoulder fins by beveling shoulder; keep thread protectors installed while picking up, laying down, handling, transporting, or storing pipe; clean threads and shoulders before make-up; use care when tripping pipe; use only pipe jack tool with wide area contact
DRY OR MUDDY CONNECTION
Leaking shoulder (face) seals
Leaking shoulder (face) seals, damaged shoulder (face) seals, insufficient make-up torque, galled threads producing excessive shoulder standoff, shoulder fins rolled between seals, high spots on shoulder - (false makeup torque), excessive shoulder removal by refacing, stretched pin threads, dirty threads and shoulders, mis-stabbing connection, improper jacking of stands in standback area Insufficient make-up torque, damaged shoulders (face)
GALLED SHOULDER
Loss of shoulder seal, excessive shoulder to shoulder standoff, false make-up torque, unstable connection (wobble)
Insufficient lubrication on shoulders, insufficient make-up torque, shoulder fins, high spots on shoulder
Apply rotary tool joint compound to shoulders when doping connection, remove shoulder fins by beveling shoulder, remove high spots by refacing. Apply proper make-up torque per tool joint class.
PIN BREAK: Cup type failure
String separation, fishing job, lost time
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
String separation, fishing job, lost time
PIN BREAK: Flat fracture type failure when torques and make-up are known to be satisfactory WEAR: Thin shoulder
String separation, fishing job, lost time
Improper trip make-up torque, additional downhole make-up, improper type lubricant producing excessive tension vs. makeup/torque Pin wobble due to insufficient make-up, shoulder fins, false torque, fatigue cracking at thread root, galled threads H2S, hydrogen embrttlement, excessive pin tension
Reduces torque capacity, belled boxes, reduced shoulder seal area
NOV Tuboscope Drilling Services 2011
Apply proper make-up torque per tool joint class, remove shoulder damage by refacing if possible; recut connection; remove shoulder fins by beveling shoulder.
Apply proper make-up torque per tool joint class, repair shoulder fins, repair galled threads
Control H2S in flow, reduce stress level if possible, remove string from service for period of time, inspect tool joint threads
Crooked pipe, high rotary speeds, abrasive formations
Straighten pipe, reduce rotary speeds where possible, apply hardfacing to box end tool joint where possible
www.tuboscope.com
1-713 799-5100
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Drill Pipe Care and Handling Tips – Tool Joints Cont… Problem
Usual Effect
Probable Cause
Possible Correction
BELLED BOXES
Distorted connections, loss of shoulder seal, will not mate properly with another connection, split body
Improper make-up torque, additional downhole make-up, thin tool joints, improper thread lubricants
Maintain tool joint OD, apply proper make-up torque per tool joint class, minimize additional downhole make-up torque, use only recommended rotary tool joint compound, recut box
STRETCHED PINS
Distorted connections, loss of shoulder seal, will not mate properly with another connection, possible pin break Damages mating threads, false torque, improper make-up, connection wobble, leaking shoulder seal, washout, pin break, drop string, lost time Prevents shoulder make-up, false torque, leaking shoulder seal, washout, connection wobble, pin break, drop string, lose time Tool joint body cracking, wash-out, string separation lost time
Improper make-up torque, additional downhole make-up, improper thread lubricants
Apply proper make-up torque per tool joint class, minimize additional downhole make-up, use only recommended rotary tool joint compound, recut pin
Thread damage, handling without thread protectors, cross threading, worn threads, improper lubrication, dirty connection, defective kelly saver sub Mating tool joints with different OD's, handling damage
Handle pipe only with thread protectors, use care in stabbing and make-up, recut worn threads, use only recommended rotary tool joint compound, clean connections before use, repair or replace kelly saver sub
GALLED THREADS
SHOULDER FINS
HEAT CHECK
SHOULDER DAMAGE
Leaking shoulder seal, washout, string separation, lost time
NOV Tuboscope Drilling Services 2011
Rapid heating due to friction between tool joint and formation, casing whip stock, etc. High rotary speeds, rapid cooling Mis-stabbing connection, handling damage, spinning chain between shoulders, improper pipe jacking
www.tuboscope.com
Match tool joint OD's if possible, remove fins by refacing and beveling, handle pipe only with thread protectors
Reduce rotary speeds through tight areas, minimize tool-joint-to-formation contact
Use care when tripping pipe, handle pipe only with thread protectors, use only pipe jack with wide area contact
1-713 799-5100
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A Guide to Users Visual Examination of Drill Pipe Straightness Roll a few lengths to evaluate straightness. Crooked pipe could be indicative of high stress drilling or rough handling of pipe in previous operations. Drill pipe which is kinked near the slip area may be indicative of over torque or “hard to break” connections. Running crooked drill pipe can cause abnormal abrasive wear to the tube body and tool joints and can contribute to unusual vibration in the drill string. Tool Joint Diameter Caliper a representative number of tool joints to determine outside diameter. Check some tool joints on both ends, but concentrate attention to box tool joints. Box tool joint O.D. wear will have a direct affect on the drill string torque capacity. Tool Joint Type There are many different tool joint dimensional combinations available for different drill pipe diameters, weight/foot and grades. A significant amount of high strength drill pipe may have “non standard” tool joint attached. The tool joint/pipe combination available may, or may not, satisfy the expected stress parameters for the well to be drilled. Tool Joint Condition Look for dry torque shoulders and/or threads. Leaking connections wash away thread compound Look at the color of the thread compound (dope). The color of 40% to 60% zinc based compound is usually grey. Use of other compounds may affect stress at given torques in a tool joint and can contribute to box belling, pin stretch and cracking. Check a few torque shoulders for galling, or fluid washes, across the shoulder face. As a minimum, tool joints should have a slight bevel around the outer edge of both pin and box shoulders.
NOV Tuboscope Drilling Services 2011
www.tuboscope.com
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A Guide to Users Visual Examination of Drill Pipe Cont… A significant flare to the box torque shoulder can be an indication of possible connection over torquing which could result in belled boxes or stretched pins. A dark ring around the outer edge of the tool joint shoulders (sealing-surface) can be an indication of under torqued connections. Under torqued connections contribute to “wobble” between pin and bow tool joints causing excessive thread flank wear, galling and possible cracking in the pin threads. Shorter than normal tool joint length is usually indicative of “re-worked” threads and torque shoulder. Logic dictates that minimum length of the non-hardbanded surface should be somewhat longer that the longest tong die used. Check general appearance of tong die marks on the pin and box tool joint body. A significant absence of tong die marks on the box tool joint is indicative of the use of only one (1) tong during make-up and break out operations. That practice can cause deep transverse scars in the slip area or result in under torque connections. Excessively deep tong die marks can be indicative of over torquing or hard to break connections. Raised metal, resulting from excessively deep tong die marks can contribute to casing wear. Tool Joint Hardfacing (Hardbanding) Chrome alloy or palletized tungsten carbide hardfacings are frequently applied to tool joint boxes to enhance wear resistance. Hardfacings typically applied to new tool joints, at the manufacturing plant, are typically applied 3/32” proud (raised) to the outside of tool joint surface. Careful, but, objective consideration should be given to the presence of hardfaced tool joints and possible casing wear. Smooth or field worn hardfacings do less damage to the casing than hardfacings with a rough finish. Obviously, hardfaced tool joints are intended to be run in open hole where the tool joint works against the surface of the well bore. Tool Joint Welding Date Check the tool joint welding date stamps located on the pin base adjacent to the torque shoulder. See API RP7G-2 for the information available for this procedure.
NOV Tuboscope Drilling Services 2011
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A Guide to Users Visual Examination of Drill Pipe Cont… Tool Joint Mill Slot and Groove Marking Compare the mill slot and groove markings with API RP7G-2 illustrations to confirm drill pipe weight and grade. Be aware, however, that such markings are not standardized in the industry. Thread Protectors Check for presence of tool joint thread protectors. Absence of protectors may be indicative of damaged tool joint threads and shoulders. Tube Body Outside Surface When rolling several lengths of drill pipe to check straightness, observe the general outside condition of the tube body. Look for deep transverse cuts in the slip area, mashes at any location, or evidence of sharp notches anywhere on the surface. Outside surface pitting on drill pie is uncommon unless the pipe has been stored in humid climates. If outside surface pitting is present, it is usually more evident within the outer one third (1/3) of the tube length at each end. If the pipe has drill pipe/casing protectors installed, or shows evidence of protectors having once been installed, check carefully for corrosion damage on the pipe surface where the protector would normally be positioned. Tube Body Inside Surface Use a bright light to observe the inside surface of several drill pipe lengths. Look for heavy mud scale deposits. Thick, dried mud scale flaking from the tube surface can plug small jet nozzles. Mud scale on the pipe surface tends to retain moisture and accelerates corrosion pitting damage. Most drill pipe is internally plastic coated to reduce damage to the I.D. surface from corrosion pitting. Presence of plastic coating, in good condition, helps reduce accumulation of mud scale. Plastic coating generally has a slick, shiny finish and its condition is relatively easy to evaluate with a bright light.
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A Guide to Users Visual Examination of Drill Pipe Cont… The corrosion control is reasonable if between 70% to 80% of the tube surface between opposite upset runouts is covered with well-bonded plastic coating. Large sections of dis-bonded coating not only reduce the percent of surface protection but flaking coating can be a plugging concern. It is difficult to accurately evaluate inside surface pitting damage, in drill pipe, by visual examination from the pipe end. Presence of coating or mud scale tends to hide the pitted condition. If heavy scale is present, or if pitting can be seen, a more thorough inspection should be performed. Other Helpful Information If drill pipe has been exposed to severe hydrogen sulfide (H2S) the surface of the pipe will sometimes have a dark green to black color appearance a few days after exposure. Ask for information about performance history of the string. Sometimes good data is kept regarding accumulated footage drilled, rotating hours, and failure and damage records, etc. Determine when drill pipe was last inspected and what type of inspection services, and specifications were applied. Match the inspection report documents with the pipe in question. The report should reflect when the inspection was performed and the number of lengths serviced. Corresponding length numbers and service date markings are steel die stenciled on the pin end tool joint 35° taper adjacent to the upset and should match information on the inspection report.
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Transportation and Storage of the Drill String Pipe that is being moved on a truck or rail car should be placed with all pins facing the same end. The load of pipe should be snugly chained down to prevent the joints from hitting one another and damaging the tool joints or the pipe itself. When drill pipe reaches the rig, the truck should be placed so that when the pipe is unloaded, the boxes will face the rig side of the rack. The pipe should be unloaded carefully, making sure that the pipe protectors are on securely. For unloading, a sling and a spreader bar for supporting the pipe in two places should be strung from the gin pole. Support in two places is necessary for keeping the pipe under control and preventing it from bending. A snub line should be tied around the load to help control it and to keep the pipe parallel to the stack on the truck as it is rolled onto the ramp. The pipe rolling onto the ramp must also be prevented from crashing into the pipe already on the rack. The first tier of pipe on racks at the drilling site should be at least 12 inches from the ground to ensure good ventilation. Supports properly spaced should be provided to hold up the middle of the pipe and keep it from sagging. Wooden strips of equal thickness should be inserted between layers of pipe over the support areas to keep the weight evenly distributed on the bottom layer of pipe. Ten feet is the maximum recommended height for stacks of drill pipe on the ground, five tiers are the maximum on the rig itself. From the time that pipe is first delivered to the rig, a record should be kept on it. The record should show expected and actual life of the pipe, type of service given, and any unexpected or severe circumstances to which the string has been subjected.
NOV Tuboscope Drilling Services 2011
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Used Drill Pipe Recommendations
Recommended Minimum Dimensional Requirements Prior to Recoating Drill Pipe Tubes or Rebuilding Tool Joints
4 ½” 16.60# S-135 NC-46
New API 5DP and RP7G-2 Specifications
Used API RP7G-2 and DS-1 Specifications
Recommended Minimum Specifications
Tube Body Wall Thickness
.337"
.270"
.286"
Tool Joint O.D.
6 1/4"
5 25/32"
5 29/32"
Pin Tong Space
7"
4 9/16"
6"
Box Tong Space
10"
6 1/8"
7"*
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Used Drill Pipe Recommendations Cont…
Recommended Minimum Dimensional Requirements Prior to Recoating Drill Pipe Tubes or Rebuilding Tool Joints
5” 19.50# G-105 NC-50
New API 5DP and RP7G-2 Specifications
Used API RP7G-2 and DS-1 Specifications
Recommended Minimum Specifications
Tube Body Wall Thickness
.362"
.290"
.308"
Tool Joint O.D.
6 5/8"
6 3/32"
6 7/32"
Pin Tong Space
7"
4 19/32"
6"
Box Tong Space
10"
6 1/8"
7"*
NOV Tuboscope Drilling Services 2011
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Used Drill Pipe Recommendations Cont…
Recommended Minimum Dimensional Requirements Prior to Recoating Drill Pipe Tubes or Rebuilding Tool Joints
5” 19.50# S-135 NC-50
New API 5Dp and RP7G-2 Specifications
Used API RP7G-2 and DS-1 Specifications
Recommended Minimum Specifications
Tube Body Wall Thickness
.362"
.290"
.308"
Tool Joint O.D.
6 5/8"
6 5/16"
6 7/16"
Pin Tong Space
7"
4 3/4"
6"
Box Tong Space
10"
6 1/8"
7"*
NOV Tuboscope Drilling Services 2011
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Used Drill Pipe Recommendations Cont…
Recommended Minimum Dimensional Requirements Prior to Recoating Drill Pipe Tubes or Rebuilding Tool Joints
5 1/2” 21.90# S-135 FH
New API 5Dp and RP7G-2 Specifications
Used API RP7G-2 and DS-1 Specifications
Recommended Minimum Specifications
Tube Body Wall Thickness
.361"
.289"
.307"
Tool Joint O.D.
7 1/2"
6 15/16"
7 1/16"
Pin Tong Space
8"
5 7/32"
6"
Box Tong Space
10"
6 5/8"
7 1/8"*
NOV Tuboscope Drilling Services 2011
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Used Drill Pipe Recommendations Cont…
Recommended Minimum Dimensional Requirements Prior to Recoating Drill Pipe Tubes or Rebuilding Tool Joints
6 5/8” 27.70# S-135 FH
New API 5Dp and RP7G-2 Specifications
Used API RP7G-2 and DS-1 Specifications
Recommended Minimum Specifications
Tube Body Wall Thickness
.362"
.290"
.308"
Tool Joint O.D.
8 1/2"
8"
8 1/8"
Pin Tong Space
8"
5 7/8"
6"
Box Tong Space
11"
6 5/8"
7 1/8"*
NOV Tuboscope Drilling Services 2011
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Inspection Services
Inspection Services Why should drill pipe be inspected? Drill pipe is the work horse of down hole tubular strings, it rotates the drill bit, provides a conduit to carry drilling mud down to lubricate the drill bit and pushes the mud up its outer surface carrying bottom hole shavings to the top of the hole. Drill pipe is subjected to cyclic stresses in tension, compression, torsion and bending. Tension and bending are the most critical of these. Bending and rotation produce an alternation between states of compression and tension at localized points in the drill pipe such as the transition zone and the slip area where 85% of failures occur. Continuous drilling is the goal, to meet that only premium pipe should be used and all others removed from service. The growing cost of new drill pipe, extended deliveries, continuous changing market, costly down time associated with failures are several reasons why drill pipe is re-inspected often. The Tuboscope drill pipe maintenance program has been designed to provide you with a drill string ready for service. The benefit to you from Tuboscope inspection services is the assurance defective pipes were identified avoiding catastrophic failures that could lead to loss of the whole drill string or worst the total well. Tuboscope employs proper inspection techniques to identify which pipe is suitable for further service, limited service or to be removed from service and discarded. Inspections performed on drill pipe have detected alarming defects:
Damaged threads resulting from under-torque Damaged shoulders from improper care and handling Slip cuts from poor die maintenance and worn-out handling equipment Bent tubes from exceeding rotation and weight on bit Fatigue cracks often caused by cyclic stressing and down hole environments like hydrogen, H2S, salts and extreme temperatures
Tuboscope’s inspection in conjunction with care and handling practices has extended the life of drill pipe up to 1 million feet drilled. Your drilling crews play an important part in extending the life of the drill string you depend on with proper work habits, it’s essential. Tuboscope has partnered with thousands of customers saving them millions by performing state-of-the-art inspections recovering usable pipe and drastically offsetting capital cost with the delay of new drill pipe purchases.
NOV Tuboscope Drilling Services 2011
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Inspection Services Cont… TH Hill Drill Pipe Inspection Program Summary DS-1™ Category 1 Tool Joint – Visual Connection The tool joint connection is examined to determine grade, condition of seal, threads, hardfacing, bevel, box swell and pin stretch. Tube Body – Visual The inside and outside surfaces are examined to determine general; conditions.
DS-1™ Category 2 Tool Joint – Visual Connection The tool joint connection is examined to determine grade, condition of seal, threads, hardfacing, bevel, box swell and pin stretch. Tool Joint – Dimensional 1 The dimensional measurement of the tool joint O.D., I.D., box shoulder width, tong space, box swell. Tube Body – Visual The inside and outside surfaces are examined to determine general; conditions. Tube Body - O.D. Gauge The tube body outside diameter is mechanically gauged from upset to upset to determine abrasive wear or mechanical damage. Tube Body – Ultrasonic Wall Thickness Minimum remaining body-wall is determined at point of maximum wear by utilizing ultrasonic wall measurements.
DS-1™ Category 3 Tool Joint – Visual Connection The tool joint connection is examined to determine grade, condition of seal, threads, hardfacing, bevel, box swell and pin stretch. Tool Joint – Dimensional 1 The dimensional measurement of the tool joint O.D., I.D., box shoulder width, tong space, box swell. Tube Body – Visual The inside and outside surfaces are examined to determine general; conditions.
NOV Tuboscope Drilling Services 2011
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Inspection Services Cont… Tube Body - O.D. Gauge The tube body outside diameter is mechanically gauged from upset to upset to determine abrasive wear or mechanical damage. Tube Body – Ultrasonic Wall Thickness Minimum remaining body-wall is determined at point of maximum wear by utilizing ultrasonic wall measurements. Tube Body – Electromagnetic 1 An electromagnetic inspection performed on the tube body utilizes an active longitudinal D.C. magnetic field and a detector unit which travels the length of the pipe body. Magnetic flux disturbances caused by transverse or three-dimensional defects such as fatigue cracks or corrosion pits are detected and recorded.
DS-1™ Category 4 Tool Joint – Visual Connection The tool joint connection is examined to determine grade, condition of seal, threads, hardfacing, bevel, box swell and pin stretch. Tool Joint – Dimensional 2 Additional to Dimensional 1 box counterbore depth, box counterbore diameter, bevel diameter, box seal width and pin neck length. Tube Body – Visual The inside and outside surfaces are examined to determine general; conditions. Tube Body - O.D. Gauge The tube body outside diameter is mechanically gauged from upset to upset to determine abrasive wear or mechanical damage. Tube Body – Ultrasonic Wall Thickness Minimum remaining body-wall is determined at point of maximum wear by utilizing ultrasonic wall measurements. Tube Body – Electromagnetic 1 An electromagnetic inspection performed on the tube body utilizes an active longitudinal D.C. magnetic field and a detector unit which travels the length of the pipe body. Magnetic flux disturbances caused by transverse or three-dimensional defects such as fatigue cracks or corrosion pits are detected and recorded. Tube Body – MPI Slip/Upset Dry magnetic particles are applied to the outside surface of the slip and upset area to detect transverse and three-dimensional flaws. From pin shoulder out to 36” / box shoulder out to 48”.
NOV Tuboscope Drilling Services 2011
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Inspection Services Cont… DS-1™ Category 5 Tool Joint – Visual Connection The tool joint connection is examined to determine grade, condition of seal, threads, hardfacing, bevel, box swell and pin stretch. Tool Joint – Dimensional 2 Additional to Dimensional 1 box counterbore depth, box counterbore diameter, bevel diameter, box seal width and pin neck length. Tool Joint – Backlight Connection Wet fluorescent magnetic particles are applied to the connection surface under hood and the outside surface of the box looking for heat checking. Tube Body – Visual The inside and outside surfaces are examined to determine general; conditions. Tube Body - O.D. Gauge The tube body outside diameter is mechanically gauged from upset to upset to determine abrasive wear or mechanical damage. Tube Body – Electromagnetic 2 An electromagnetic inspection system utilizing an active longitudinal D.C. magnetic field and a gamma wall gauge (note; FLUT1 or EMI1 with UT wall reading may be substituted).
Tube Body – MPI Slip/Upset Dry magnetic particles are applied to the outside surface of the slip and upset area to detect transverse and three-dimensional flaws. From pin shoulder out to 36” / box shoulder out to 48”. Tube Body – UT Slip/Upset Area An ultrasonic shear-wave technique is used to inspect the critical, high-stress upset run-out and adjacent tube body end areas for transverse fatigue cracks.
DS-1™ Category HDLS (Heavy Duty Landing String) Tool Joint – Visual Connection The tool joint connection is examined to determine grade, condition of seal, threads, hardfacing, bevel, box swell and pin stretch. Tool Joint – Dimensional 2 Additional to Dimensional 1 box counterbore depth, box counterbore diameter, bevel diameter, box seal width and pin neck length.
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Inspection Services Cont… Tool Joint – Backlight Connection Wet fluorescent magnetic particles are applied to the connection surface under hood and the outside surface of the box looking for heat checking. Tool Joint - Traceability To verify an individual number is traced to its mill certificate and material test reports. Tube Body – Visual The inside and outside surfaces are examined to determine general; conditions. Tube Body - O.D. Gauge The tube body outside diameter is mechanically gauged from upset to upset to determine abrasive wear or mechanical damage. Tube Body – Ultrasonic Wall Thickness Minimum remaining body-wall is determined at point of maximum wear by utilizing ultrasonic wall measurements. Tube Body – FLUT 2 An ultrasonic inspection performed on the tube body utilizes the shear wave and compression wave techniques to inspect in longitudinal, transverse and oblique directions to include wall thickness measurements. Tube Body – MPI Slip/Upset Dry magnetic particles are applied to the outside surface of the slip and upset area to detect transverse and three-dimensional flaws. From pin shoulder out to 36” / box shoulder out to 48”. Tube Body – UT Slip/Upset Area An ultrasonic shear-wave technique is used to inspect the critical, high-stress upset run-out and adjacent tube body end areas for transverse fatigue cracks. Tool Body - Traceability To verify an individual number is traced to its mill certificate and material test reports.
NOV Tuboscope Drilling Services 2011
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Used Drill Pipe Inspection Services SONOSCOPE® Inspection - Standard Rack The SONOSCOPE inspection evaluates service-induced defects in the used drill pipe tube body to API RP7G-2, DS-1 or customer specifications: 1. Each length is numbered sequentially on the pin-end tool joint shoulder. The month and year of inspection and the Tuboscope “T” service mark are also stenciled on the shoulder. 2. The full length outside diameter of the tube body is gauged to determine the area of maximum O.D. wear. 3. The pipe body is examined full length for visible cuts, mashes, gouges and other defects; close attention is given to the slip area. 4. Ultrasonic spot measurements are taken at the area of maximum O.D. wear to establish minimum wall thickness. 5. The SONOSCOPE electromagnetic inspection is performed on the tube body. SONOSCOPE inspection equipment utilizes an active longitudinal D.C. magnetic field and a detector unit which travels the length of the pipe body. Magnetic flux disturbances caused by transverse or three-dimensional defects such as fatigue cracks or corrosion pits are detected and recorded. 6. A magnetic particle inspection is performed on the critical upset areas to detect O.D. fatigue cracks. 7. The tube body is classified and identified in accordance with API RP7G-2 or customer specifications.
Critical Upset Area Inspection Ultrasonic End Area Inspection The Tuboscope ultrasonic end area unit, utilizes the ultrasonic shear-wave technique to inspect the critical, high-stress upset run-out and adjacent tube body end areas for transverse fatigue cracks. Then the ultrasonic compression wave technique is employed to detect pitting and measure wall thickness.
NOV Tuboscope Drilling Services 2011
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Used Drill Pipe Inspection Services Cont… Tool Joint Inspection Tool Joint O.D. Measurement The outside diameter of the tool joint is measured to API RP7G-2 or customer specifications to classify the tool joint O.D. reduction due to abrasive wear. Tool Joint Shoulder (Face) Visual Examination Tool joint shoulders are cleaned and visually examined for galls, nicks, washes, fins and other damage which would affect the pressure holding capacity and stability of the tool joint. The tool joint is also checked for bevel condition. Tool Joint Welding Date/Grade Mark Examination To determine pipe age, grade, weight per foot and possible tool joint rework, the pin base is visually examined for tool joint manufacturers’ markings. Tool Joint Shoulder (Face) Width Measurement A mechanical gauge is used to measure pin and box tool joint shoulder width, including bevel, in accordance with API RP7G-2 or customer specifications. Tool Joint Clean and Visual Examination Tool joint threads and shoulders are cleaned and visually examined for thread and shoulder damage and bevel condition. Check Tool Joint Pin Stretch - (with profile gauge) The tool joint pin is cleaned, and threads are visually compared to a hand-held thread profile gauge. Check Tool Joint Pin Stretch - (with mechanical lead gauge) The tool joint pin is cleaned, and thread lead is measured with a dial indicator gauge to determine presence and amount of pin stretch. Check Tool Joint Box Swelling A measurement is taken across the box inside counter-bore and compared to API Spec 5DP dimension Qc for possible indications of box swelling.
NOV Tuboscope Drilling Services 2011
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Used Drill Pipe Inspection Services Cont… Dry Magnetic Particle Tool Joint Inspection, Type I Pin and box threads, shoulders and the box O.D. surface are cleaned as required. Dry magnetic particles are applied to detect transverse cracking in pin thread roots and to detect longitudinal cracking on the box O.D. surface. Threads and shoulders are visually examined for damage. Dry Magnetic Particle Tool Joint Inspection, Type II Pin and box threads and shoulders are cleaned as required. Dry magnetic particles are applied to detect transverse cracking in pin and box thread roots. Threads and shoulders are visually examined for damage. Wet Fluorescent Magnetic Particle Tool Joint Inspection, Type I Pin and box threads, shoulders and the box O.D. surface are cleaned as required. Wet fluorescent magnetic particles are applied to detect transverse cracking in pin thread roots and to detect longitudinal cracking on the box O.D. surface. Threads and shoulders are visually examined for damage. Wet Fluorescent Magnetic Particle Tool Joint Inspection, Type II Pin and box threads and shoulders are cleaned as required. Wet fluorescent magnetic particles are applied to detect transverse cracking in pin and box thread roots. Threads and shoulders are visually examined for damage.
Tube Body Inspection Sonoscope Buggy Inspection An electromagnetic inspection performed on the tube body utilizes an active longitudinal D.C. magnetic field and a detector unit which travels the length of the pipe body. Magnetic flux disturbances caused by transverse or three-dimensional defects such as fatigue cracks or corrosion pits are detected and recorded. Ultrasonic Full Body Inspection An ultrasonic inspection performed on the tube body utilizes the shear wave and compression wave techniques to inspect the critical, high-stress areas for transverse fatigue cracks, corrosion, pitting, erosion and measures wall thickness. The multi-channel inspection heads travel the length of the pipe body acquiring real time data.
NOV Tuboscope Drilling Services 2011
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Used Drill Pipe Inspection Services Cont… Tube Body Mechanical O.D. Gauging The tube body outside diameter is mechanically gauged from upset to upset to determine abrasive wear or mechanical damage. Minimum remaining body-wall is determined at point of maximum wear by utilizing ultrasonic wall measurements. Determine Minimum Cross Sectional Area (CSA) Ultrasonic wall measurements are utilized to determine minimum and average pipe body-wall. Cross sectional area is computed at the point of maximum O.D. reduction with minimum remaining wall. Dry Magnetic Particle Slip Area Inspection Dry magnetic particles are applied to the outside surface of the slip area to detect O.D. transverse cracking. Wet Fluorescent Magnetic Particle Slip Area Inspection Wet fluorescent magnetic particles are applied to the outside surface of the slip area to detect transverse cracking.
Special Services Heavyweight Drill Pipe Magnetic Particle Inspection - End Areas Only Pin and box threads and shoulders are cleaned and examined for visual damage or imperfections. Magnetizing equipment is utilized to induce a longitudinal magnetic field. Magnetic particles are applied to the thread surface to detect transverse cracks. Heavyweight Drill Pipe Magnetic Particle Inspection - Tool Joint and Center Wear Pad Taper Areas Only Magnetizing equipment is utilized to induce a magnetic field into the upset taper and adjacent tube body. Magnetic articles are employed to detect transverse cracks on the outside surface. Drill Collars, Kellys, Stabilizers, Subs and Core Barrels Ultrasonic, electromagnetic, mechanical-optical and/or magnetic particle inspections are employed as required to locate defects in these items.
NOV Tuboscope Drilling Services 2011
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Inspection Case History
655jts
21,615
5 1/2", 21.90#/ft, S-135 HT-55 TJ -1116826
636jts
Accepted
19
Rejected
49jts
1617
35 jts
Accepted
14jts
Rejected
568jts
17,906.46ft
528jts
Accepted
40jts
Rejected
419 jts
13,825ft
414jts
Accepted
5 jts
Rejected
12.19%
79jts
2,607ft
4 1/2", 16.60#/ft, X-95, NC 46, TJ -1147961
75jts
Accepted
4jts
Rejected
20,988ft 2.9%
627ft
(Cracks)
2 7/8", 6.85#/ft, S-135, NC 31 TOOL JOINT -1124252 1,155ft 28.57%
462ft
(Cracks)
5”, 19.50#/ft, S-135, NC 50 TOOL JOINT -1135581 16,645.43ft 7.04%
1,261.02ft
(Cracks)
6 5/8", 27.70#/ft, S-135, FH, TOOL JOINT -1154966 13,662ft 165ft (Cracks, Washout)
2,475ft 20.25%
NOV Tuboscope Drilling Services 2011
132ft (Cracks)
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Used Drill Pipe Inspection Methods A.Tool Joints Condition
Recommended Methods Potential Methods OD Caliper
1. OD Reduction Due to Wear
Snap gauge equally effective Diameter tape
2. Shoulder Width
Steel ruler OD Caliper Snap gauge equally effective Steel ruler Thread lead gauge
3. Pin Stretch
Profile gauge Ring gauge Steel ruler to check Qc
4. Box Swell
Profile gauge Ring gauge Wet fluorescent magnetic particle Dry magnetic particle
5. Pin Cracking
Dye penetrant Straight beam ultrasonic
6. Box Cracking (Longitudinal)
Electromagnetic scan Wet fluorescent magnetic particle Dry magnetic particle - if badly scarred by tong dies Die penetrant Angle beam ultrasonic Visual Wet fluorescent magnetic particle
7. Box Cracking (Transverse)
8. Torque Shoulder Damage (Scars, Galls or Washes)
Dry magnetic particle Dye penetrant Straight beam ultrasonic Visual Electromagnetic scan Visual Hydrostatic pressure test
9. Thread Damage (Wear, Scars, Galls or Washes)
Visual with profile gauge Visual
NOV Tuboscope Drilling Services 2011
Comments A typical practice is to visually locate the diameter showing eccentric wear and apply the caliper or gauge at that diameter. Otherwise, if an eccentric condition is not evident the caliper or gauge is applied at several locations around the tool joint.
Same as Item 1. above A thread profile gauge is often used for locating stretched pins but provides no quantitative measurement. A thread lead gauge will reveal amount of stretch. A good steel ruler is used to measure the diameter of the box counterbore (Qc) and compare against the "as machined" specified diameter. Wet fluorescent magnetic particle is the generally preferred application because the particle size is smaller than dry particle and more sensitive to fine, tight cracks. Wet MPI is much faster than dye penetrant and therefore more cost effective. Ultrasonic applications are occasionally being employed but coupling problems along with false signals and misinterpretations are frequent. Same as item A.5. Tool joint box cracking is usually associated with overtorquing and / or box swelling. Therefore, cracking in box tool joint on drill pipe will be oriented in the longitudinal direction and predominately on the OD surface.
Same as item A.5. Pin and box tool joints assembled in a typical drill string are quite stiff and resist bending forces. The bend effect is commonly focused at the transition point of the drill pipe upset where cracking typically occurs. Transverse cracking is not typical to drill pipe box tool joints. Visual examination is the most effective and practical method in this case. Tool joints, even in good condition, are difficult to seal against pressure test plugs without high make-up torques applied. A good visual examination will note damaged threads and the profile gauge will help evaluate thread wear or metal projections present.
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Used Drill Pipe Inspection Methods Cont…
B. Tube Body Condition
Recommended Methods Potential Methods Drill pipe wear (snap gauge with ultrasonic thickness gauge) Gamma-ray scan
1. Bodywall Reduction Due to Wear
OD caliper Diameter tape Straight beam ultrasonic scan OD caliper
2. OD Reduction Due to Stretch
Drill pipe wear (snap) gauge Diameter tape
3. OD Reduction Due to Mash or Crush 4. OD Expansion (String Shot Back-off)
5. Corrosion Pitting ID Surface
OD caliper Drill pipe wear (snap) gauge Diameter tape OD caliper Drill pipe wear (snap) gauge Electromagnetic scan with ultrasonic thickness prove-up Visual with bright light Visual with borescope Angle or straight beam ultrasonic scan
6. Corrosion Pitting OD Surface
7. Cuts, Gouges, and scars - OD Surface Transverse
Comments
Bodywall reduction resulting from abrasive wear is typically located in the center 1/3 of the tube. The pipe body, from some distance towards each end, is generally protected by the tool joint with its large diameter. Therefore, simple caliper like the OD gauge is effective in locating the worn area. The amount of remaining bodywall should be determined by the use of an ultrasonic thickness gauge. Used drill pipe is typically somewhat crooked and / or coated with a drilling scale mud on the OD surface; therefore, full length ultrasonic or gamma-ray scan may be difficult to accurately perform. Initial stretching of drill pipe length generally occurs at a point near the upset runout. An OD caliper is most effective in comparing the pie diameter at the point of suspected stretch with adjacent pipe body or, by indirect measurement, with a steel ruler.
Same as item B.2. above
Same as item B.2. above Corrosion pitting damage occurs in a variety of geometric configurations, Electromagnetic scanning is the most effective application for locating the pitted area. Remaining bodywall must be determined by use of a straight beam ultrasonic thickness gauge. Angle beam ultrasonic application can be adversely affected by pitting configuration and other conditions.
Electromagnetic scan with depth gauge and ultrasonic thickness prove-up Same as item B.5. above
Visual Angle or straight beam ultrasonic scan Electromagnetic scan with MPI prove up Visual Angle beam ultrasonic scan
NOV Tuboscope Drilling Services 2011
Cuts, gouges and similar scars in the transverse configuration are the most detrimental relative to fatigue crack development. Electromagnetic scan with magnetic particle prove-up gives satisfactory results.
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Used Drill Pipe Inspection Methods Cont…
B. Tube Body Condition
Recommended Methods Potential Methods Visual with MPI prove-up
8. Cuts and Scars - OD Surface - Longitudinal
Electromagnetic Angle beam ultrasonic scan
Comments Cuts, gouges, and similar scars in the longitudinal configuration are considerably less detrimental relative to fatigue crack development. Longitudinal cuts or gouges, therefore, must be quite large or deep to cause concern. As a result, visual detection with magnetic particle prove-up gives satisfactory results.
Angle beam ultrasonic scan 9. Fatigue Cracking OD/ID
Electromagnetic scan with MPI Prove-up Visual with profile gauge
The ultrasonic method requires a couplant. The electromagnetic method is considerable less affected by thin coatings of drilling mud scale and other outside surface irregularities commonly present on drill pipe.
Visual
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Color codes for the tube appear on the tube body near pin end. Tool joint classification color codes appear on the tool joint (either box or pin). Shoulder condition color codes appear adjacent to the threads (either box or pin).
PIPE BODY CLASSIFICATION (NEAR PIN END AT 18” AND 2” WIDE BAND)
PREMIUM CLASS Permanent markings for classification of drill pipe body (all classes contain a unique number stamped on the 35° slope).
CLASS 2
See reverse side for Table B.18 of API RP 7G-2. It explains exterior and interior conditions, identified by inspection, which leads to these color codes on the tube body.
CLASS 3
SCRAP
TOOL JOINT CLASSIFICATION (BOX AND PIN)
A single white band is often painted in actual field practice to indicate premium class.
PREMIUM CLASS
Refer to Table D.6 in API RP 7G-2 for minimum width of box shoulder, identified by Inspection, that leads to these classification color codes.
CLASS 2
CLASS 2 SHOULDER CONDITION (BOX AND PIN)
SCRAP OR REPAIRABLE
FIELD REPAIRABLE
Table B.18 — Classification of Used Drill Pipe Classification Condition
Premium Class: Two White Bands
Class 2: One Yellow Band
Class 3: One Orange Band
Exterior Conditions OD Wear
Remaining wall not less than 80%
Remaining wall 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
Remaining wall not less than 80%
Remaining wall not less than 80%
Remaining wall less than 80%
Cracks
None b
None b
None b
Corrosion pitting
Remaining wall not less than 80%
Remaining wall not less than 70%
Remaining wall less than 70%
Erosion and internal wall wear
Remaining wall not less than 80%
Remaining wall not less than 70%
Remaining wall less than 70%
Cracks
None b
None b
None b
Internal Conditions
ª Average adjacent wall is determined by measuring the wall thickness on each side of the cut or gouge adjacent to deepest penetration. b
In any classification where cracks and washouts appear, the pipe is identified with a red band and considered unfit for further drilling service.
Table D.6 — Drill Pipe and Tool-Joint Color Code Identification
Tool Joint and Drill Pipe Classification
Number and Color of Bands
Tool-joint condition
Color of Bands
Premium Class
Two White
Scrap or shop repair
Red
Class 2
One Yellow
Field repairable
Green
Class 3
One Orange
—
—
Scrap
One Red
—
—
Coating Services
Veracruz, Mexico Macae, Brazil Sheldon North Coating Plant, Houston, TX
Nisku, Alberta, Canada Edmond, Oklahoma Batam, Indonesia Amelia North, Louisiana Amelia South, Louisiana Berlaimont, France Gladbeck, Germany Port Lethon, Scotland West Little York, Houston, TX Houma, Louisiana - Custom Odessa, TX - Fiberglass Liner Odessa, TX - Rod Coating/OD Tubular HHTCC Qingxian HHTCC Jiangyin Oman Liner and Wrap Plant Abu Dhabi, United Arab Emirates
Plant Highway 90 Houston, TX Navasota, TX Midland, TX
47'
24"
48'
48' 48'
14" 16"
24"
63' 46' 48' 48' 48' 48' 44' 48' 47' 20'
14" 10" 16" 16" 12" 13 3/8" 20" 14" 12"
®
All TK®
2" - 24" TBD TBD
Expansion Locations
All TK All TK® TK-Liner, Fiberline All TK®
1 1/2" - 12" > 1 1/2" 2 3/8-9 5/8 all rod sizes 2 1/16-4in pipe 2 3/8" - 14" 2 3/8" - 16" Liner 2 3/8" - 9 5/8" 2" - 24"
1" - 14" 1 1/2"-10" 1" - 16" 1.9" - 16" 1-1/2" - 12" 2" - 13 3/8"
Sizes 1 1/2" - 13 3/8" 1 1/2" - 16" 2 3/8" - 15"
Liquid
None None All TK® All TK® TK-Liner, TK-Fiberline TK-750R, 316 SS, TK-505 (OD)
All TK® All TK® ® All TK All TK® All TK® All TK®
Maximum OD Length Coatings ® All TK 13 3/8" 46' All TK® 16" 48' 15" 48' TK®-2, 7, 34, 34XT ®
Powder Coatings
All TK®
®
All TK All TK® Tubo-Wrap All TK®
TK-15,70,99 ® All TK except 800 All TK® except 800 All TK® TK®-34P,216, 34, 34XT TK®-34P, 216, 236 ® TK -34P, 216,236 All TK® except 99 All TK®
None ® TK -15, 70, 505 TK®-99 All TK® except 800
TK -99
Coating Services Location Capabilities and Contacts
2" - 24"
2 3/8" to 14" 2 3/8" to 16" 2 3/8" - 20" 2" - 24"
2 3/8" - 3 1/2" 1 1/4" - 7" 1.9" - 14" 1 1/2" - 4 1/2" 2" - 16" 2" - 16" 1- 1/2" - 5" 2" - 13 3/8" 2" - 20" 2" - 14" 1 1/2" - 12" > 1 1/2" 2 3/8" - 9 5/8"
Sizes 1 1/2" - 7"
Coating Services Since most drilling muds are water-based, they are capable of causing extensive corrosion pitting due to entrained salts and from CO2 and H2S picked up from the formation. Aggravating this problem is the oxygen that is picked up as the mud circulates through the shaker and mud pit, which increases the mud’s corrosive nature. Secondly, most significant corrosion can occur if the pipe is not properly prepared for storage on the surface. Corrosion can exacerbate the stresses that severe drilling operations inflict upon your drill pipe, leading to the rapid development of fatigue cracks and ultimately catastrophic downhole pipe failure such as washouts or twist offs. Tuboscope’s internal plastic drill pipe coatings offer protection through the entire drill string. Preventing excessive corrosion on the internal of the pipe is the first step in minimizing the stress concentrations that can lead to pipe failure. Reduction in loss of the wall thickness also further extends the life of that drill pipe asset. In addition to corrosion protection, the reduced surface roughness of the internal coating versus the bare steel pipe can minimize pump pressures required to provide sufficient fluid flow or can allow for a greater volume of fluid to be circulated at the same pressures. This reduced surface roughness also plays a key part in the internal coatings ability to mitigate the deposit of scales, minimizing the need for costly chemical treatments and eliminating the fear of the damage that can be caused my dislodged agglomerations of scale. A clean internal surface can protect against formation contamination and maintains the hydraulic efficiency. Tuboscope currently offers three different internal coatings for drill pipe applications: TK®-34, TK-34XT and TK-34P. All three systems have the ability to drill into formations up to 400°F (204°C) provided circulation is maintained. TK-34, the original drill pipe coating, has been used successfully for over 35 years in a wide variety of drilling applications. It is formulated to maximize flexibility while still retaining corrosion resistance over a wide pH range. TK-34XT is the first drill pipe coating developed specifically for abrasion resistance. The durability of this system is three times greater than other drill pipe coatings on the market. TK-34P is Tuboscope’s powder drill pipe coating solution. It offers superior H2S and chemical resistance in a variety of environments. As drilling environments get more aggressive and as asset replacement costs dictate the maximization of its usable life, Tuboscope can provide solutions to ensure success.
NOV Tuboscope Drilling Services 2011
www.tuboscope.com
1-713 799-5100
[email protected]
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.
NOV Tuboscope Drilling Services 2011
www.tuboscope.com
1-713 799-5100
[email protected]
Coating Services Cont… Case History #1 Onshore Drilling Contractor Uses Drill Pipe Maintenance to Extend Drill String Life As the pipe ages, and the coating either becomes sufficiently mechanically damaged or finally succumbs to the environment, its benefits can be reduced. An onshore drilling contractor has practiced drill pipe maintenance for many years, which has included a recoating program. Prior to using any internal coating on their drill pipe, they would expect approximately 180,000 to 200,000 foot of drilled hole with bare pipe prior to having to downgrade the string and pick up a new one. When examining one of their recent successes after their implementation of an internal plastic coating maintenance program, this contractor was able to drill 27 wells totaling 257,652 ft of total hole prior to recoating the string. The pipe was then recoated and went on to drill an additional 55 wells and a grand total of 781,101 ft of total hole drilled. Inspection results showed 6 double white premium class, 241 yellow band, and 30 orange band joints. This particular operator drills with joints that are yellow band or better which means that 247 out of 277 joints were still usable in daily operations after over 780,000 foot drilled. Below is a table outlining the economic benefit that was achieved by the implementation of a recoating program for used drill pipe for this contractor. 4 1/2" 16.6# X-95 Drill Pipe Bare Drill Pipe
Coated Drill Pipe
Number of Joints
340
340
Cost of Pipe/jt
$ 1,200.00
$ 1,200.00
Cost to Coat/ft
$-
$ 4.00
Coating Applied
0
2
Cost of Initial Pipe
$ 408,000.00
$ 451,520.00
$ 1,632,000.00
$ 495,040.00
Cost to Reach 780,000 ft Drilled
Tuboscope’s drill pipe maintenance program was able to save this drilling contractor $1,136,960 for this particular application.
NOV Tuboscope Drilling Services 2011
www.tuboscope.com
1-713 799-5100
[email protected]
Coating Services Cont… Case History #2 Field History of Bare and Coated Drill Pipe
A Summary of Nippon Steel investigation of washouts in drill pipe dated May 95:
Coated Pipe
Bare Pipe
130,000 feet
65,000 feet
2 years
1 year
Washouts to Date
0
22
Estimated Cost Associated with Washouts
0
$2,200,000
Cost of Failed or Replacement Pipe
0
$66,000
Total Cost of Failure
0
$2,266,000
Footage Purchased Pipe in Service
NOV Tuboscope Drilling Services 2011
www.tuboscope.com
1-713 799-5100
[email protected]
Coating Services Cont… Case History #3 Outline of SPE Paper # 77687 – Case History: Internally Coated Completion Workstring Successes
The coated string was composed of 5”, 19.50#/ft, S-135, 4 ½” IF drill pipe some of which was 20 years old and was classified as Class 2 due to undersized tool joints. o A wall loss of 0.036” could downrate the Premium Class tubes to Class 3, making the pipe scrap. Preliminary proppant erosional tests exposed the TK-34 to 750,000 pounds of 12 ppg, 20/40 mesh ceramic proppant to 30 barrels per minute, equating to a velocity of 33 ft/sec. o “Although there were small and infrequent holidays over ~3% of the surface area, the coating served its purpose of minimizing metal exposure and wear (~97% of the area was protected with coating).” “No acid pickling treatments were needed throughout the 17 completions saving $170,000. These savings more than offset initial coating costs and any re-coating costs. This cut the cost to purchase, transport, and dispose of the acid along with eliminating the safety, environmental, and liability risks associated with handling and disposing the acid.” “Most engineers do not recognize the hydraulic benefits that can be gained by using internally coated workstrings.” o A 16% water injection rate increase was modeled and it was determined that less surface pressure is needed to pump through the coated workstring at any rate. o “In addition to obtaining the cleanest well bore from the maximum circulation rate, the reduced pipe friction from a coated workstring could possibly mean the difference between using the rig pumps to displace the well and incurring costs to use the cement unit due to higher surface pump pressures with uncoated pipe.” o “The added friction pressure from uncoated pipe creates more backpressure on the formation and thus more completion fluid losses.” “This drill pipe was handled in typical rig fashion without any consideration for the internal coating.” “No trouble time was experienced due to workstring problems during this challenging completion program.” “It was the opinion of the rig contractor that the workstring would not have survived the rigors of the Genesis completion program without an internal coating.”
NOV Tuboscope Drilling Services 2011
www.tuboscope.com
1-713 799-5100
[email protected]
SPE 77687 Case History: Internally Coated Completion Workstring Successes Robert D. Pourciau, SPE, ChevronTexaco
Copyright 2002, Society of Petroleum Engineers Inc. This paper was prepared for presentation at the SPE Annual Technical Conference and Exhibition held in San Antonio, Texas, 29 September–2 October 2002. This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.
Abstract Completion workstrings must endure an extremely hostile environment of erosive and corrosive fluids. Today’s improved internal plastic coatings can protect the significant investment in drill pipe from erosion/corrosion, as well as minimize completion trouble time caused by pipe debris (scale). An internally coated, Class 2 drill string was used for 2½ years to successfully Frac Pack seventeen, high productivity, Gulf of Mexico Deepwater completions in the Genesis Field. More than 2,000,000 pounds of abrasive proppant was pumped without a pipe failure. Introduction The completion workstring requirements were reviewed during the development well planning for the project in 1998. During completion processes, this pipe would be subjected to only minimal tensile stress and torsion; however, the pipe would need to bear the rigors of numerous Frac Pack completions. The plan originally included 22 Frac Pack completions from 16 wells with anticipated surface treating pressure of up to 10,000 psi (depending on the selected completion string diameter). The planned wells ranged in depth from 12,000’ to 23,000’ and in hole angle from 16° to 66°. During each completion, the 6 5/8” drill string would be changed to a smaller diameter completion workstring to displace the well to CaCl2 /CaBr2 completion fluid, tubing conveyed perforate (TCP) underbalance, pressure surge the perforations, wash sand fill, and Frac Pack. The workstring would then be sent to a pipe yard to be stored outdoors until the next completion operation occurred in roughly one month. After reviewing the alternatives, the rig contractor’s 5”, 19.50#/ft, S-135, 4 ½” IF drill pipe was selected for the
completion string. This workstring was a collection of used pipe with an RP7G API-IADC Used Drill Pipe Classification System rating of Class 2 due to undersized tool joints.1 Some of this pipe was as old as 20 years yet the tubes met Premium Class standards with ≥80% wall thickness (≥0.290”) remaining. Premium Class tubes have a tensile rating at minimal yield strength of 560,764 lbs and an internal yield pressure rating at minimum yield strength of 15,638 psi. The reduction in torsional strength due to the reduced tool joint diameter was not a concern due to minimal rotation for drilling cement anticipated. These specifications met the anticipated completion workstring requirements and the rig contractor was pleased to find commercial use for this drill pipe rather than scrap it for roughly $50 per joint or replace the tool joints for roughly $700 per set. An abrasion resistant internal drill pipe coating was considered to combat further internal wall loss due to proppant laden Frac Packs. A wall loss of only 0.036” could downrate the Premium Class tubes to Class 3 (
