Spe 170566

IADC/SPE-170566-MS

Advanced Technologies and Practical Solutions for Challenging DrillingApplications

M. J. Jellison, NOV Grant Prideco; A. Chan, Workstrings International

Copyright 2014, IADC/SPE Asia Pacific Drilling Technology Conference

This paper was prepared for presentation at the IADC/SPE Asia Pacific Drilling Technology Conference held in Bangkok, Thailand, 2527 August 2014.

This paper was selected for presentation by an IADC/SPE program committee following review of information contained in an abstract submitted by the author(s).Contents of the paper have not been reviewed by the International Association of Drilling Contractors or the Society of Petroleum Engineers and are subject tocorrection by the author(s). The material does not necessarily reflect any position of the International Association of Drilling Contractors or the Society of PetroleumEngineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the International Associationof Drilling Contractors or 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 IADC/SPE copyright.

Abstract

This paper provides a review of recent technology advancements and addresses practical considerationsassociated with drillpipe and drill stem components for extreme drilling applications. Ultra-high torquedouble-shoulder rotary connections are often employed in these applications. Recent developments andenchantments in these connection designs including new higher strength materials, advanced thread formsand associated improvements in torsional strength and fatigue performance are presented. Deepwaterwells frequently require long, heavy casing strings to achieve the total depth objectives. High capacitylanding strings capable of running these heavy strings with total hook loads approaching 2.5 millionpounds have been successfully developed to address this well design challenge. The paper discusses theengineering solutions implemented to overcome the high forces, slip crushing concerns and materialstrength and toughness considerations for these critical applications.

Due to the dramatic increase in oil prices the industry has seen a re-emergence of deep and ultra-deepdrilling projects that encounter H2S gas. The paper provides an update on the latest sulphide stresscracking (SSC) resistant drillpipe grades including the first fully SSC resistant drill pipe system with SSCresistant friction welds joining the drill pipe tubes and tool joints. Major operators have been using a drillpipe based riser system for intervention and completion work in the waters offshore Brazil, Australia,Africa and other deepwater basins around the world. The paper provides updates on design improvementsof high pressure capacity connectors and advanced materials for these critical riser applications.

Deepwater and other critical wells often encounter abrasive formations, high side loads between thedrill string and bore hole and other conditions that promote drill stem friction heating failures. The paperincludes characteristic features of these failures along with case histories and prevention methods.

IntroductionWells that are in the planning stages today demand drill string technology with capabilities that exceedcurrent connection designs and material performance properties.

Rig rates have risen dramatically, as have the costs for virtually all services, equipment, tools andmaterials used by the energy drilling industry. At the same time, existing wells and reservoirs areexperiencing accelerated decline rates. Our industry must respond to these realities with advanced

technologies that improve efficiency, enabling wells to be drilled more effectively and at acceptable costs.Drill pipe and drill stem materials and connections represent mature technologies. Nevertheless, innova-tions can and are being developed in this important area critical in the quest to exploit more remotehydrocarbon target zones. The third generation double-shoulder connection presented in this paperrepresents one advancement that addresses some of the drilling challenges ahead.

Evolution of Double-Shoulder ConnectionsFirst Generation Double-Shoulder Connections (1st Gen. DSC) were introduced in the early 1980s andwere API rotary-shouldered connections (primarily NC and FH) with a second shoulder added inside thebox member at the pin nose interface. 1st Gen. DSC and API connections shared the same basic designfeatures such as thread form, taper, lead, pitch diameters, etc. while the secondary shoulder provided asimple and straight forward solution that increased the connection torsional yield strength by approxi-mately 40% over the corresponding API connection. The secondary internal shoulder offers an additionalfriction surface and mechanical torque stop. The primary external shoulder serves as the connectionssealing surface precisely as it functions on a standard API rotary-shoulder connection.

As more aggressive drilling programs were implemented, it became clear that 2nd Gen. DSC withhigher torque and more streamlined profiles were required. To achieve performance beyond 1st Gen. DSC,changes to the standard API rotary-shoulder connection design parameters were necessary. 1998 saw theintroduction of 2nd Gen. DSC drillpipe, designed with enhanced thread form to reduce stress concentra-tion, a flatter taper to increase shoulder areas, and tighter tolerances, Figure 1.

The increased torsional capacity of 2nd Gen. DSC is provided by the greater area of the secondaryshoulder, which in turn is achieved by the shallower taper. 2nd Gen. DSC provided approximately 25 to30% more working torque capacity than 1st Gen. DSC or an improvement of approximately 65 to 70%compared to a standard API connection with the same outside and inside diameters. 2nd Gen. DSCstreamlined connection dimensions, enabling one pipe size larger to be run in the same hole sizedramatically improving hydraulic efficiency while maintaining equivalent fishing capability.

Third Generation Double-Shoulder ConnectionSince the introduction of 2nd Gen. DSC, the industrys trend has continued toward deeper and longer reachwell programs, which has dictated the need for drillpipe connections with enhanced mechanical anddimensional characteristics coupled with improved make-up / break-out speeds.

Figure 1Illustration comparing 1st and 2nd Gen. DSC. 2nd Gen. DSCs possess a reduced taper which provides more area at the internal shoulderto supply increased torsional capacity.

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Consequently, a project was commissioned todesign, analyze, laboratory test and field trial theindustrys first 3rd Gen. DSC. A key objective of theproject was to significantly improve connectionmake-up/break-out speeds relative to 2nd Gen.DSCs. Mechanical and hydraulic gains were alsodictated based on the industrys trend toward deeperand further well programs.

Design PhilosophyThe design philosophy for 1st, 2nd and 3rd Gen.DSCs has evolved. One of the primary philoso-phies employed during the development of 3rd Gen.DSCs was the concept of one size does not fit allor one design does not fit all. This philosophysuggests that a thread form optimized for 65/8 in.drill pipe may not be optimized for 23/8 in. drillpipe. In fact, optimized thread forms for each ofthese sizes differ substantially.

5 in. to 57/8 in. drill pipe sizes represent com-mon sizes for offshore, deepwater and higher profileprograms such as ERD. Connection designs focusedon speed of makeup and more streamlined connec-tions for increased hydraulic performance.

For the large 65/8 in. drillpipe size commonlyrun in elevated spread rate projects such as deep andultra-deep water, speed of makeup is a primary design objective. In addition, make-up torques can beexcessive, at times surpassing the capacity of the rig equipment. Design parameters must be balanced toreduce the make-up torque and improve hydraulic performance.

Connection Design3rd Gen. DSCs differ from 1st and 2nd Gen. DSCs in several ways. One of the primary differences is theaddition of a dual-start, twin lead or double-start thread, Figure 2.

Double-start Thread Double-start threads incorporate two threads spaced 180 degrees apart reducingthe number of turns to assemble the connection by 50%, all other things equal. Double-start or multi-startthreads are not new. However, the application of multi-start threads to RSCs is novel, especiallydouble-shoulder RSCs.

Dual-radius Thread Form As the industry continues to move to more streamlined drill pipe connec-tions, the gap in fatigue performance between the connection and the tube can decrease. Fundamentally,a point exists in which a streamlined connection becomes weaker in fatigue than the drillpipe, leading todrillpipe connection fatigue failures. The anticipated improvement in streamlined dimensions for 3rd Gen.DSCs led the design team to evaluate thread forms that produced low peak stresses in the thread roots.The reduction in peak stresses was realized through a dual-radius thread form.

Figure 3 illustrates the dual-radius thread form in comparison to API, 1st and 2nd Gen. DSCs. Threadroot radius is lengthened and radically improved with the dual-radius thread form in the 3rd Gen. DSC.Peak stress analysis and laboratory fatigue testing quantified the performance improvement of thedual-radius. In addition, modified 2nd Gen. DSCs with dual-radius thread forms have been utilized in

Figure 2Illustration comparing scale figures of 3rd Gen. DSC to 2nd

Gen. DSC. All other things equal, the double-start thread form reducesrevolutions from stab to makeup by 50%. Changes in thread taper andpitch further reduce revolutions in total from 13 to 4.

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more than 300 aggressive wells for Chevron Thailand Exploration and Production with field-provensuccess.

Optimized Taper Taper defines the cross sectional area at the secondary shoulder providing the im-proved torsional strength and controls the stabbing depth of the pin to the box impacting make-up andtripping speeds. Tapers were reviewed for each connection size and optimized to best balance the needsof the specific drill pipe size.

Thread Pitch Another controlling factor in the design of a rotary-shouldered connection is the threadpitch. Similar to taper, thread pitch was reviewed for each connection and optimized to best fit the designpriorities of each drill pipe size.

Material Strength API tool joints are produced with specified minimum yield strength (SMYS) of120,000 psi. During development of 3rd Gen. DSCs, the design team chose to capitalize on advancementsin metallurgy and heat treatment techniques for high strength/high toughness steel grades. In particular,a program was commissioned to develop 130,000 psi SMYS tool joints to meet the stringent toughnessrequirements of many proprietary manufacturing specifications.

3rd Gen. DSC represents step-change technology to enable deeper and further wells along with shorterrunning and tripping times during the well construction and completion process. Primary benefits of 3rd

Gen. DSC include: save time, cut costs, increase torque capacity, larger equivalent hydraulic innerdiameters, improve clearance and fishing ability, reduce failure risk and extend life.

The new connections provide increased mechanical performance compared to previous generation hightorque connections while also providing fatigue resistance greater than standard API connections. Theseconnections can facilitate more challenging wells, provide increased cost savings and reduce risk duringthe well construction process.

Landing String DevelopmentDeepwater and ultra-deep water well designs continue to drive the requirement for higher tension capacitylanding strings. Water depth and total depth are increasing and step-outs are being extended. This,combined with the often narrow margin between pore pressure, mud weight and fracture gradient, is

Figure 33rd Gen. DSCs incorporate a unique large dual-radius thread root reducing the peak stress in the thread roots and extending fatigue lifeof the connection.


causing well designers to set more intermediate casing strings and this in turn is pushing large diameter,heavy casing strings to deeper setting depths to maintain hole size and reach the intended hydrocarbontargets.

Initially, casing, liners, and offshore casing strings set in sub-sea wellheads were simply run on the drillpipe that was used to drill the well. As setting loads increased, systems that are more specialized wererequired for running these longer and heavier casing strings in increasing water depths. Initial fit-for-purpose solutions were developed with increased load capacities targeted towards anticipated runningloads for specific areas or projects. During this period, landing strings built from casing were alsoemployed. It quickly became apparent that drill pipe landing strings offered significant advantages:

Rotary-shoulder connections (RSC) are rugged and robust and can withstand multiple make-upand break-out cycles.

Conventional drill pipe handling equipment can be used, which accommodates relatively fast,pick-up, make-up, running and tripping speeds and promote safe operations.

A drill pipe landing string can incorporate connections with tensile capacity that exceeds the pipebody, a desirable design parameter for any landing string.

As ultra-high capacity landing strings were developed; slip-crushing was quickly identified as a majordesign and manufacturing obstacle. With the current slips available, the slip-crushing resistance for thepipe body is less than its axial tensile capacity. To address this issue, a special thick wall section wasprovided in the slip-gripping area. Dual-diameter tool joints were utilized to increase elevator capacity.

To achieve a lifting capacity of 2.5 million pounds, a state-of-the-art landing string assembly isrequired, Figure 4. Five components must be considered in the design process: Pipe body, Heavy wall slipsection (HWSS), Tool joint/RSC and Weld.

The landing string tubular design criteria is based on assuring that the pipe body is the weakestcomponent. The reasoning is that in case of overload, the pipe body would yield instead of the connectionor weld experiencing a catastrophic failure. This is especially important in cases where the slip andelevator capacities exceed the landing string tensile capacity.

Figure 4Components of a state-of-the-art landing string


Pipe bodyThe tensile capacity of the pipe body is defined as the pipe body yield, at the specified minimum yieldstrength, (SMYS), or grade, times the pipe body cross-sectional area. If possible, there is benefit frommatching the landing string pipe diameter to the drill pipe diameter used on the rig, mitigating the needto change pipe handling and make-up equipment.

Early landing string pipe bodies were commonly produced from S-135 grade material, as it was the APIgrade with the highest SMYS, 135 ksi. There are now proven high strength proprietary grades availablewith SMYS of 140 ksi, 150 ksi, and 165 ksi. Use of these grades provides increased lifting capacity ofup to 22%. With current metallurgical technology, pipe with 165 SMYS can be produced with the sameminimum toughness as standard API S-135.

For 65/8-inch diameter V-150 grade pipe, 1.125-inch wall thickness is required for the pipe bodytensile rating at 90% RBW to meet the 2.5-million pound rating. By utilizing a 165,000-psi SMYS pipe,the wall thickness can be reduced to 1.000-inch resulting in a 5 percent decrease in string weight.

Development of UD-165

A drill pipe grade with minimum yield strength of 165 ksi was developed to meet the needs of not onlyhigh-capacity landing strings but also for high-capacity drill strings required for drilling ultra-deep wells,and high strength-to-weight drill strings required to reduce tensile and drag load in ultra-extended reachwells. The UD-165 grade is a refined Cr-Mo-Ni similar to the alloy used for high-toughness (NS-1)S-135T, Z-140 and V-150 grades but with the addition of micro-alloying constituents. Developmentaltesting included small sample fracture and fatigue test, impact test, and full-size field trials.

Heavy-wall slip sectionFor high tensile load applications such as landing operations, slip crushing of the pipe body becomes animportant design consideration. Slip-crushing capacity can be the primary design factor for landing stringssince it is less than the tube tensile capacity. In the deepwater Gulf of Mexico, slip-crushing failures havebeen documented and some have resulted in catastrophic events involving the loss of casing strings to thesea floor. One way to increase slip-crushing capacity is through the pipe design. The HWSS provides athicker wall in the slip-contact area, Figure 5.

Weld strengthThe weld strength is limited by the alloy composition of the two mated components. For the 2.5 millionpound landing string, the expected weld yield strength would be 125,000 psi or higher. The weld area isdefined by the dimensions of the HWSS. The required weld yield strength calculates to 122,657 psi, whichis below the 125,000 psi minimum and therefore is acceptable.

Design of a safe and functional 2.5 million pound landing string was accomplished, although taxingthe limits of manufacturing capabilities.

First Fully Sulfide Stress Cracking Resistant SystemAs the severity of sour drilling applications has increased, the requirement for drill stem materials resistantto sulfide stress cracking (SSC) has accelerated. Sour service drillpipe, traditionally manufactured with

Figure 5The heavy-wall slip section provides increased wall thickness in the slip contact area for increased slip-crushing resistance.


SSC resistant upset tubulars and tool joints, has been available for some time. Sour Service drillpipemetallurgy is not specifically controlled by NACE MR 0175/ISO 15156, however these tubulars and tooljoints are often evaluated in accordance with the standard. The friction welds joining the upset tubularsand tool joints were not resistant to SSC and were not evaluated. This has been acceptable for many sourdrilling applications since the weld is not the mostly highly stressed region of the drillpipe joint andbecause the operator has a certain degree of control over the environment through the drilling fluidproperties and additives. As more severe environments with higher Hydrogen Sulfide (H2S) concentra-tions were identified for exploration and development, it became apparent that a fully SSC resistantdrillpipe system including the friction welds was necessary.

Sour Service DrillpipeThe drillpipe assembly incorporates a tool joint that is typically manufactured from a forging and a frictionweld that attaches the tool joint to the upset of the pipe body. The manufacturing technology for criticalservice drillpipe has evolved significantly in the last several years. Major advances relating to pipespecifically developed for use in areas with significant H2S content have been realized.

Sulfide Stress Cracking (SSC) due to the presence of H2S gas in the downhole drilling environmentshas led to the development of sour service drillpipe, which is engineered to have resistance to SSC. Theweld area of sour service drillpipe has not been SSC tested in the past, and there have been no documentedSSC failures in the weld zone of sour service drillpipe. There are several factors that make an SSC failurein the weld zone of sour service drillpipe unlikely. The region on both sides of the weld has a much largercross-section (1.5 to 2.0 times) than that of the tube. This larger weld area cross-section means the stressexperienced in that area is less by the same proportion. This reduced stress makes the likelihood of failuredue to SSC significantly less likely. It is generally possible during drilling operations to control the wellenvironment and help prevent SSC failure of the drillpipe and weld zone.

On the other hand, the operating environment for some critical sour applications cannot always becontrolled and direct and prolonged exposure to H2S can occur. Consequently, it became apparent that anSSC resistant friction weld was required for these critical sour applications.

Friction-Type Welds and SSC ResistanceDuring friction welding heat is generated by mechanical friction between a rotating tool joint and astationary upset tube. At forging temperatures a lateral force is applied to plastically displace and fuse thecomponents. The weld area is effectively forged, resulting in a high strength weld, Figure 6. The weld areais then austenitized, quenched and tempered to produce a final tempered martensite microstructure.

Friction-type welds present special problems which make it a difficult area for sour service surviv-ability. Hence, careful weld process control and heat treatment are required to produce weld area SSCresistance in friction-type welds.

Figure 6Diagram showing the grain flow in a cross-section of a friction-type weld. The grain flow near the weld line is perpendicular to the flowof grains in the tube and tool joints.


SSC Testing Program andParametersThe XSS-95 weld requirements were developed forcritical sour drilling and drillpipe riser applications.A new patent pending four-point bending test pro-cedure and fixture were developed that employedunpolished samples that closely represent the sur-face finish of the finished product in service, unlikepolished samples typically used in NACE TM-0177testing.

NACE Method A Tensile TestResultsWeld area materials were prepared using the sameproduction environment to be used in manufactur-ing the drillpipe. The weld specimens were subjectto a 30-day (720 hours) NACE Method A tensiletest as shown in Figure 7. In this test the samples areloaded in tension with the fixture shown in Figure 7to a predetermined stress level, and the specimen issubmerged in a solution that is saturated with H2S.The following results were obtained:

Two tests at 85% of engineering weld yield stress 85% of 62 ksi 52.7 ksi in NACE MethodA Solution A of TM0177 were carried out. Both samples survived the 30-day test.

Two tests at 63.8 ksi (70% of Actual Yield Strength (AYS) of 91.1 ksi) in NACE TM02842003Solution B, pH in the range 5.05.5 in 100% H2S. Both samples survived the 30-day test.

The successful completion of these tests demonstrated that the SSC threshold stress for the weld zoneof the XSS-95 drillpipe system exceed the design requirements.

Four-point Bend SSC TestingThe four-point bend test is well suited for use with SSC testing of friction-type welds since the area ofmaximum tensile stress corresponds to the HAZ, which is the area of interest for testing. In addition, thisaccurately reflects the behavior of the weld in the field since the outer surface of the actual weld is usedas the testing surface in an unpolished condition. The test fixture and sample system is unique in that itcan apply and maintain a precise, constant tensile stress on a select area of the friction weld, Figure 8. Thetest fixture assembly is immersed in the test fluid to a level higher than the sample.

Four-point Bend Testing ResultsThe following results were obtained on weld area specimens tested using the four-point bending testfixture and unpolished specimens as described previously Solution B of NACE specification TM0284with the pH during the test in the range 5.05.5 for a 30-day test in 100% H2S:

Three tests at 63.8 ksi (70% of the AYS of 91.1 ksi) were carried out with all three samplessurviving the 30-day test.

Three tests at 72.9 ksi (80% of the AYS of 91.1 ksi) were carried out with all three samplessurviving the 30-day test.

Figure 7NACE Tensile Test (Method A) fixture and test sample. Testconsists of a sample loaded in tension to a specified stress level whilesubmerged in a solution that is saturated with H2S. Test duration is 720hours.


These results with unpolished samples further demonstrated that the drillpipe production and process-ing steps developed during this project achieved the goal of producing an SSC resistant friction weld.

ApplicationsThe first applications for the fully SSC resistant drillpipe were for drillpipe risers offshore Brazil. The firstproduction of 65/8 in., 0.500 in. wall thickness, 95 ksi minimum specified yield strength pipe wascompleted in January 2011. Approximately 15,300 ft of pipe was manufactured for deployment as twodrillpipe riser (DPR) systems. The DPR replaces a conventional completion riser system and offerssignificantly shorter subsea tree and tubing hanger running times. This system has been designed toovercome problems associated with conventional completion risers which are very expensive, timeconsuming and require a great deal of rig deck space. These problems increase with water depth andbeyond 3,000 ft become extremely challenging.

Downhole Heating FailuresDownhole friction generated heating failures are another problem experienced in a number of deepwaterdrilling applications. Directional drilling followed by long, potentially high-angle, deviated sections canpromote high side loads between the drillpipe and wellbore and can quickly create conditions conduciveto downhole heating.

The consequences of downhole heating can be severe often resulting in axial separation of thedrillstring creating potential well control safety issues, costly fishing jobs and other remedial efforts.

In one failure mode, the drillpipe is heated above a critical transformation temperature accompanied bya rapid decrease in tensile strength. Subsequently, the component fails under tension loading, well belowthe axial strength rating of the drillstring. Another failure mode has been documented where the pipeparted in a purely brittle fashion. These fractures occurred as direct consequence of the steel being heatedto very high temperatures (1,300 F and above), followed by rapid cooling (quenching) by the drillingfluid resulting in very brittle, low toughness steel.

Three conditions are required for the production of friction heating: side loading, rotation and sufficientcoefficient of friction between the surfaces. These conditions are met in several ways, including but notlimited to: rotating in too severe a dog-leg, continued rotation while in a stuck situation, drilling in an

Figure 8Four point bend test fixture with weld area sample. Load is applied through the action of a bolt and controlled with a load cell (load celldisplay shown).


interval that has a high number of wellbore trajec-tory corrections and when formation sloughing orinsufficient mud flow that fails to remove cuttings(packing off) occurs.

Identification FeaturesField observations assisted by magnetic particle in-spection, if available can identify downhole heatingas a likely failure cause. Metallographic and micro-scopic image analyses are not possible in the field;however, they are necessary to conclusively deter-mine that failure was the result of downhole heating.Below is a checklist of the main features of adownhole heating failure for use in the field duringa failure analysis:

1. Smooth shiny surfaces from friction wear.These surfaces are often black or blue due tooxides that form under high temperatures,Figure 9.

2. Blackened and charred ID surfaces near thelocation of the failure or thick blackenedsludge formed by burning of drilling fluids.

3. Exaggerated necking and elongated neckingof the region near failure. A normal separa-tion failure will produce some necking butdoes not create exaggerated necking withoutassistance from high heating.

4. Flat fracture faces. Although not alwaysstrictly caused by conversion of the steel tountempered martensite or other brittle tran-sition phases, when this occurs along withother visual evidence of downhole heatingthen downhole heating should be suspected.

Downhole overheating failures typically occur in or around the transition area between the tool jointand drillpipe upset or HWDP tube (18 or 35 shoulder area) since this area can get caught by a ledge,keyseat or other wellbore obstruction during drilling operations.

Mitigation MethodsAs discussed, friction heating failures are the result of excessive side loading while rotating with sufficientcoefficient of friction between the drill stem and the formation and/or casing. In general, efforts to mitigateany of these three conditions will enhance the drill stems resistance to friction heating failures. Someoperational examples that should be considered are provided below:

1. Minimize time, rotational speed and string tension during backreaming, especially when formationkeyseats, cuts, ledges or other downhole conditions are preventing axial pipe movement.

2. Avoid string rotation in keyseats, cuts and ledges or when the drillstring is axially stuck andpacked off.

Figure 9Shiny friction wear and black oxide are visible on a tool jointpin that failed due to downhole heating.

Figure 10Charred and packed drilling fluid filled the ID of the lowerfracture piece from the Case History.


3. Avoid pulling it upwards and rotating it atthe same time when lost returns are ob-served.

4. Minimize doglegs and dogleg severity espe-cially in the upper portion of the wellbore.

5. Utilize drilling fluids with low coefficientsof friction.

6. Utilize friction reducing tools such as drill-pipe rubbers and non-rotating drillpipe pro-tectors in areas of the drill stem where highside loading exists. Utilize raised hardband-ing on drillpipe and HWDP tool joints.

7. Minimize drilling RPM and drill stemweight.

Case HistoryAlthough not from a deepwater application, thiscase history involves an extreme example of down-hole friction generated heating in 5 in. 19.50 lb/ftZ-140 drillpipe. The authors have analyzed many downhole heating related failures over the years in bothdeepwater drilling and other critical applications. The case history represents the most severe case ofdownhole heating studied in all those years. The well was located in the Eagle Ford Shale play of SouthTexas. The vertical section of the well to approximately 11,000 ft had been drilled and drilling continuedin the lateral section. The drillpipe became stuck at approximately 12,000 ft MD in the lateral section, andthe well packed off while backreaming. Next the rigs started working the pipe up and down and applyingboth right and left hand torque to 18,000 ft-lb. The pipe separated, and the drillpipe above the fish wasrecovered. Subsequently, a difficult and time consuming fishing job was conducted that resulted in thepipe fracturing a second time near the BHA. Approximately 25 of drillpipe and the BHA were left in thehole at around 13,000 ft.

A detailed metallurgical investigation of the three fracture specimens (top and bottom of the upperfracture and top of the lower fracture) was conducted. The evidence indicating downhole frictiongenerated heating as the cause of both failures was overwhelming and dramatic:

Drastically altered microstructures and material properties in and around the failure locations.

Figure 11Heat check cracking was present in all three specimens from the Case History. This is a photograph from the lower separation.

Figure 12The strange fracture shape, similar to a soft serve ice creamcone, resulted from the high temperature that lowered the materialsstrength and made it malleable.


Clear signs of frictional wear and scoring on OD surfaces. Severely charred/blackened drilling fluid remains inside the drill pipe, Figure 10. Multiple areas exhibiting heat checking, Figure 11.

The upper fracture was brittle in nature. In this case, the pipe was stuck and packed-off with drillingfluid circulation cut off from the a localized area. As the pipe was rotated and worked up and down withaxial force this packed-off section heated up to temperatures exceeding 1,400 F. Subsequently, the heatedsection was exposed to drilling fluid that rapidly cooled or quenched the pipe in an uncontrolled mannerresulting in a very brittle material that was prone to failure. The materials microstructure in the area ofthe failure included untempered martensite and pearlite, had areas of high hardness (up to 55 HRC) andquench cracks.

The lower failure is shown in Figure 12. This fracture is ductile in nature and appears to have occurredwhile the drillpipe steel was at a highly elevated temperature. The high temperature reduced the materialsstrength and made the material highly ductile or malleable resulting in the strange appearance of thefracture similar to an inverted soft serve ice cream cone, Figure 12. The ID of the tube was completelypinched off by the twisting that occurred during the separation process. Figure 13. The tube had charredand compacted drilling fluid filling its ID. The steel microstructures present in this specimen indicate thatthe piece was heated above its critical temperature of 1,400 F. This case history clearly represents theserious consequences that can quickly result from downhole heating incidents.

ConclusionsThis paper provides a review of recent technology advancements and addresses practical considerationsassociated with the drill string for extreme deepwater drilling applications. The increasing trend to drillchallenging wells in deeper water with longer reach, higher angle and deeper targets seems likely tocontinue. Engineers and other professionals involved in drilling the demanding wells of the future willrequire more advancement in drill pipe and drill stem components. Creative solutions are required tocontinue to overcome the various challenges faced by the oil and gas industry as we work to producecrucial energy supplies for society today and future generations.

Figure 13The inside diameter of the section of the tube had blackened residuals throughout its length up to and including the area that had beentwisted and compressed.


References1. Jellison, M.J., Hassmann, S.P., Snapp, D.: New Developments in Drill Stem Rotary Shoulder

Connections, paper IADC/SPE 62785 presented at the 2000 IADC/SPE Asia Pacific DrillingTechnology Conference, Kuala Lumpur, 1113 September 2000.

2. Chandler, R.B., Muradov, M., Jellison, M.: Drill Faster, Deeper and Further with Ultra-HighTorque, Third Generation Double-Shoulder Connections, paper SPE/IADC 105866 presented atthe 2007 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 2022 February 2007.

3. Brock, J.N., Sanclemente, L.W.: 2,500,000 Pound Landing String Challenges: Have WeReached the Limit of todays Technology? paper OTC 20823 presented at the 2010 OffshoreTechnology Conference, Houston, 36 May 2010.

4. Jellison, M., Hehn, L., Moreira, J.R.F., Joia, C.J.B.M., Wyble, K., Christen. B.: InnovativeMetallurgy and Advanced Connection Technology Deliver First Sulfide Stress Cracking ResistantIntervention Riser System with Quick Running Capability, paper IBP2017_10 presented at the2010 Rio Oil & Gas Expo and Conference, Rio de Janeiro, 1316 September 2010.

5. NACE MR0175/ISO 151562 Petroleum and natural gas industries Materials for use inH2S-containing environments in oil and gas production, 2003.

6. NACE TM02842003 Standard Test Method, Evaluation of Pipeline and Pressure Vessel Steelsfor Resistance to Hydrogen-Induced Cracking, 2003.

7. Jellison, M., Brock, J., Muradov, M., Morgan, D.: Shale Play Drilling Challenges: Case Historiesand Lessons Learned, paper SPE/IADC 163447 presented at the 2013 SPE/IADC DrillingConference and Exhibition, Amsterdam, 57 March 2013.

SI METRIC CONVERSION FACTORS

ft 3.048* E 01 m

in. 2.54* E 00 cm

lb 4.448 222 E 00 N

F (F32)/1.8 C

*Conversion factor is exact.


Advanced Technologies and Practical Solutions for Challenging Drilling ApplicationsIntroductionEvolution of Double-Shoulder ConnectionsThird Generation Double-Shoulder ConnectionDesign PhilosophyConnection DesignDouble-start ThreadDual-radius Thread FormOptimized TaperThread PitchMaterial Strength

Landing String DevelopmentPipe bodyDevelopment of UD-165Heavy-wall slip sectionWeld strength

First Fully Sulfide Stress Cracking Resistant SystemSour Service DrillpipeFriction-Type Welds and SSC ResistanceSSC Testing Program and ParametersNACE Method A Tensile Test ResultsFour-point Bend SSC TestingFour-point Bend Testing ResultsApplicationsDownhole Heating FailuresIdentification FeaturesMitigation MethodsCase HistoryConclusionsReferences

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