TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractWith water depths increasing to over 10,000 feet, offshore well depths exceeding 34,000 feet and extended reach targets pushing out over 35,000 feet; operators are deepening the setting depths of larger diameter and heavier casing strings. These offshore designs require landing strings with hoisting capacity approaching 2-million pounds. These requirements have exceeded the limits of previous tubular manufacturing and handling capabilities. This paper documents the design, development, manufacture and deployment of a 2-million pound landing string system to meet these requirements. The system incorporates three components: pipe, elevators and slips. The 6 5/8-inch, heavy wall, 150-ksi yield strength pipe incorporates an innovative thick-walled section in the slip contact area for resistance to slip crushing loads and a uniquely designed dual-diameter tool joint to increase elevator capacity. Slips were specially engineered to equalize radial and axial loads, increase the slip-to-pipe contact area, and optimize the contact angle to minimize the crushing loads on the pipe body. Combined with 1,000-ton elevators, the system utilizes conventional rig-up and operating procedures. The design criteria developed for landing string applications and the solutions to the unique manufacturing challenges associated with the heavy wall, high strength pipe are presented. In addition, laboratory and case studies are presented for landing operations, some with axial tension loads approaching 1.75-million pounds.SI to Metric Conversion feet ('): ft. = 3.048 E -01 m inches ("): in. = 2.54 E 00 cm 1,000-pounds per square inch: ksi = 6.894757 E 03 kPa pounds: lb. = 4.448222 E 00 N pounds per foot: ppf = 1.4594 E 01 N/m pounds per square inch: psi = 6.894757 E 00 kPa
Two million pound landing strings have been successfully manufactured and deployed. However, operators are setting larger diameter and heavier casing to ever-increasing depths requiring landing strings with increased setting capacity. Drilling rigs, top drives and associated equipment with capacity of 1,250 tons are in use. Landing strings with 2,500,000 pound capacity will be required by the drilling industry. This paper describes the design challenges of developing and manufacturing a 2.5 million pound landing string.To meet the design objectives, 6-5/8 inch 150,000 psi yield strength pipe would require wall thickness of nearly 1-1/8 inches. To provide the required tensile capacity and decreased string weight, a new high-strength pipe with 165,000 psi specified minimum yield strength was developed. Slip-crushing resistance and elevator capacity requirements challenged existing manufacturing limits requiring unique designs and new high-strength materials in the slip-contact area.The 6-5/8" FH connection is a popular choice for landing strings. However, these higher load requirements have reached the limitations of the connection's ability to maintain shoulder engagement, provide a sealing mechanism, and maintain stress levels in the torque shoulder and counterbore below yield. Unique connection modifications and higher strength tool joints were required to meet performance objectives. SI to Metric Conversionfeet ('): ft. = 3.048 E -01 m foot pound (ft-lbs): = 1.35582 N-m inches ("): in. = 2.54 E 00 cm 1,000-pounds per square inch: ksi = 6.894757 E 03 kPa pounds: lb. = 4.448222 E 00 N pounds per foot: ppf = 1.4594 E 01 N/m pounds per square inch: psi = 6.894757 E 00 kPa degrees Fahrenheit(F): = 1.4 degrees Centigrade (C) +32 ft-lbs = foot pounds
This paper describes this first commercial deployment of a third-generation double-shouldered, double-start, rotary connection run on the Discoverer Deep Seas drill ship at Walker Ridge 678 in 7,016 feet of water. The 5–7/8 inch OD, 26.30 ppf, S-135, Range-2 drill string was used to drill the planned 28,000 feet vertical well. Lessons learned and future recommendations are presented. New developments in drilling tubulars are rapidly evolving and represent enabling technologies for the industry's continued advancement of drilling deeper, further and more cost-effective wells. The current trend to drill offshore in deeper waters, longer extended reach wells and record setting ultra-deep wells continues. Some operators have wells of 40,000 to 45,000 TMD in the planning stages. In response to this need, the development of third generation, ultra-high torque connections were developed and released in 2006. These third generation double-shouldered connections are the industry's first family of connections designed to meet the specific and different needs of each pipe size. The thread form is a doublestart thread that reduces the number of revolutions to assemble the connection by 50%. The thread form also provides a unique dual-radius thread root that offers a step-change improvement in fatigue resistance. The new connection provides increased mechanical and hydraulic performance compared to earlier high-performance connections while also providing fatigue performance greater than standard API connections. These connections can facilitate more challenging wells, provide increased cost savings and reduce risk during the well construction process. Conservative estimates suggest that the new connections will save approximately 7–1/2 hours in cumulative trip time for a 20,000 foot well. Introduction The first third-generation double-shouldered rotary connection was announced and released on September 25, 2006 at the SPE Annual Technical Conference and Exhibition. At that time market activity had created an extended backlog of 14–16 months for new drill pipe production delaying the first deployment until early December of 2007. Since the industry first began rotary drilling, wells have continued to be more challenging: greater total depth, further extended reach, in deeper water, in areas with increased environmental sensitivity, and through various formation challenges in order to reach hydrocarbon targets. Drill string components have evolved, as well, enabling operators to meet these challenges. The development of rotary-shouldered connections has also had an impact on rig operations. This paper will review the evolution of rotary-shouldered connection with emphasis on the effects of operations on the rig floor. The first deployment of the third-generation double-shouldered rotary connection will be covered in detail with focus on the effect of the connection features on drill stem running operations. A primary benefit of using the third-generation double-shouldered rotary connection is the increased speed of make-up and breakout compared with the second generation connection. Rig time savings on the first deployment will be evaluated and expected saving for future operations forecasted. Finally, connection damage and repair cost resulting from the deployment will be evaluated.
The term ЉsourЉ is used to refer to drilling environments containing hydrogen sulfide (H 2 S). In sour wells, H 2 S causes sulfide stress cracking (SSC) in carbon low-alloy steels under tensile stress. A form of hydrogen embrittlement, SSC causes sudden, brittle fracture in drillpipe. To combat the effects of H 2 S exposure, sour service drillpipe has been manufactured to meet IRP Volume 1 -Critical Sour Drilling specifications. IRP requires 75 ksi (SS75), 95 ksi (SS95), or 105 ksi (SS105) tubes with all three grades using 110 ksi SMYS tool joints for use in sour operations. However, these lower yield strength IRP grades have limited load capacity which restricts drilling parameters such as total depth (TD) and margin of overpull.Using advanced steel heat treatment methods, a 125 ksi SMYS grade sour service drillpipe has been developed. The 125 ksi tube is mechanically incompatible with the standard 110 ksi IRP sour service grade tool joint because of the large difference in yield strength between the two components. Therefore, a new class of sour service tool joint with an SMYS of 120 ksi was required for the 125 ksi sour service tube. This new higher yield strength tool joint needs to meet the same level of SSC-resistance as the 110 ksi IRP tool joint, i.e., pass testing in solution A method A of NACE TM0177 (100% H 2 S @pH ϭ 2.7, 720 hour test) at a testing stress of 65% of SMYS. Like the high yield strength 125 ksi tube, advanced heat treatment methods were required to achieve SSC-resistance in the higher yield strength tool joint.A second application for the 125 ksi drillpipe is as an offshore drillpipe-based intervention riser for non-sour wells. Currently, 105 ksi drill pipe grades are often used but increased demands on load capacity (up to 1,000 kips) makes the 125 ksi drillpipe an attractive alternative. The 125 ksi drillpipe also meets recommended hardness limitations placed on offshore risers in specification API RP 17G (Recommended Practice for Completion/Workover Risers).This paper introduces an SSC-resistant 125 ksi drillpipe with SSC-resistant 120 ksi tool joints and presents the results of NACE TM0177 testing of this new technology. The new 125 ksi drillpipe will allow for increased load capacity over IRP SS105 ksi grade drillpipe in drilling environments with moderate to low concentrations of H 2 S. In addition, it can serve as an improved substitute over 105 ksi drillpipe-based offshore intervention risers due to its increased load capacity and controlled hardness.
Tubulars with gas-tight, rotary-shouldered connections are used as the conduit between the surface vessel (rig) and subsea wellheads in deepwater operations. Requiring no specialized tools and using standard rig equipment, they provide a fast, safe, and cost effective way to run completion landing strings and intervention pipe. Tubulars for these operations must provide a large internal drift diameter to allow for clearance of the wellhead crown plug and installation of completion components. These strings have been limited to 6-5/8 in. pipe allowing for a maximum drift diameter of 5-1/2 in., which is insufficient to run and retrieve the wellhead crown plugs of many large ID subsea trees. Trees with larger crown plugs require operators to use casing tubulars increasing deployment time, requiring casing running crews, incurring higher repair costs and time, thereby increasing overall costs. A completion landing string (CLS) was developed using a 7-5/8 in. pipe and a built-for-purpose, large drift, gas-tight, pressure-rated, rotary-shouldered connection (7-5/8 CLS). This new connection technology optimized the outside diameter and make-up torque to be compatible with the iron roughnecks and pipe handling equipment of the current Gulf of Mexico rigs. Product development and performance validation is detailed with a special emphasis on the enabling connection technology. The paper expands on manufacturing challenges and design choices made to assure ease of rig operations, including modifications to slips and elevators. Finite element analysis (FEA) and physical testing to validate performance are described. Steps taken before the initial deployment to assure compatibility with the rig equipment are explained. Finally, the paper will show data from the offshore field trials and initial deployments. Lessons learned are shared. This industry-first, purpose–built, gas-tight completion and intervention tubular provides 6-1/8 in. internal drift diameter and can be safely deployed using conventional pipe make-up and handling equipment reducing overall cost.
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