Summary The purpose of this paper is to present the results of a comprehensive-test program conducted with five different sets of deepwater-landing string-handling equipment consisting of both conventional and unconventional technology. A thorough presentation will be made detailing initial testing at elastic loads approaching yield and final high-load testing beyond yield. All stages of the test program will be discussed including original testing protocol, test setup, testing performed, test results, and overall conclusions. This is one of the first standardized-test programs used across five different designs of handling equipment. This overall presentation of the test program is made to identify stress levels associated with the extreme loads that occur when landing very heavy casing strings in deepwater wells. Introduction While landing-string designs have progressed (Breihan et al. 2001; Wilson 1997), the design of the handling equipment, until recently, has been based upon conventional slip technology. This conventional technology (Sathuvalli et al. 2002) and new technology (Simpson et al. 2005) has been studied previously. On the basis of the increasing loads being placed on landing strings and the associated handling equipment, a group of test participants including BHP Billiton, BP, ChevronTexaco, ExxonMobil, Nexen Petroleum, and Oil & Gas Rental Services arranged for Mohr Engineering Division (Mohr), a division of Stress Engineering Services, to perform an array of tests intended to increase the level of knowledge in the industry and help better understand the handling equipment currently in use for landing heavy loads. After developing an overall scope of work and understanding of the requisite testing, the field of handling equipment to be tested was determined to include a variety of designs used with landing-string loads up to 2-million lbm. Five different sets of handling equipment were tested. These included conventional slips referred to as Slip A, Slip B, and Slip C; conventional power slips referred to as Slip D; and an unconventional slipless system (Adams et al. 2002a; Adams et al. 2002b; Adams et al. 2002c; Adams et al. 2003; Adams et al. 2006) referred to as System E. Mohr provided the testing services and coordinated the machining and test-sample preparation required to complete the tests. After testing was completed, Mohr also reviewed and post-processed the data and prepared a majority of the information contained in this paper. The manufacturers were requested to provide handling equipment for this test. After testing, test results for equipment provided were made available to each manufacturer. The main conclusion drawn from this test program was that all handling-equipment/test-sample combinations, except for the modified System E, had locally measured peak strains that were beyond yield at much lower loads than typical landing-string working loads.
During a sidetrack operation out of 9 7/8-in. casing on a deepwater well in Green Canyon Block 243, Gulf of Mexico, unexpected hole conditions were encountered that required the use of an additional casing string. The decision was made to run a 7 5/8 × 9 5/8-in. expandable liner in the 8 1/2 × 9 1/2-in. wellbore. The liner would expand to provide an inside diameter of 7.71 in., allowing space for a 7-in. production liner in the targeted interval. The 6,867-ft liner (pre-expansion length) is currently the world record for the longest expandable liner set to date and presented several challenges for cement job design. The liner would be cemented conventionally before the expansion operation. Expansion time was calculated to be approximately 17 hours, allowing the fluid time for the primary lead cement, with a safety factor, to exceed 19 hours. The tail cement had to exhibit good compressive strength around the shoe track, and the operator specified top of cement (TOC) at 17,000 ft to protect a secondary pay zone. Slurry properties were simulated to meet fluid times required for the liner expansion. Standard API lab tests used for cement testing were modified to accommodate this lengthy operation. The expandable liner was set at 20,605 ft measured depth (MD) and 19,930 ft true vertical depth (TVD) with a maximum hole angle of 36°. The liner was cemented successfully using an extended thickening-time lead slurry mixed at 15.7 lb/gal, followed by a 16.2-lb/gal tail slurry with a shorter pumping time to achieve good strength at the liner shoe. After drilling out the liner, the operator obtained a 16.8-lb/gal equivalent (PPGE) formation integrity test (FIT) and resumed drilling to the target depth. The cement-evaluation log showed excellent bonding behind the expandable liner with TOC at 17,000 ft as planned. Operational details and cement design considerations are provided in the paper. Emphasis is placed on wellbore configuration, expandable installation procedures, and hole preparation, a full understanding of which is the beginning of a successful cement job. Introduction The Aspen field is located in a prolific development area in the Green Canyon Block 243 in 3,000-ft water. This field development has been in progress since 2000 with five major production horizons drilled in the area. Through high-rate production, certain sands have seen some depletion and thus significant pressure regressions have been observed throughout the productive intervals. Operators following proper equivalent circulating density (ECD) management and using synthetic- based drilling fluids with optimized particle-size distributions to maximize the sealing of depleted sand packages have achieved success. This case-history well was a re-entry sidetrack to reach a lower objective known to be in a narrow pore pressure/fracture gradient window because of the pressure-depleted interval. The planned completion program consisted of sidetracking out of the original wellbore through a 10 ¾ × 9 7/8-in. tieback at 14,000 ft and directionally drilling an 8 ½-in. pilot hole to planned TD (Fig. 1). The hole would subsequently be opened to a 9 ½-in. hole size to run a 7 5/8-in. production liner. During the drilling operations through the production interval, wellbore pressures indicated that it would not be possible to continue without encountering significant losses. To still reach lower objectives and complete with a 7-in. production liner, the use of a 7 5/8 × 9 5/8-in. expandable liner installation became critical to the success of the well. Because there were secondary completion objectives behind this installation, it was also critical to obtain a top of cement (TOC) back to 17,000 ft as well.
Dealing with higher than planned pore pressures, slim drilling margins and depleted zones in the same wellbore can quickly compound an already difficult deepwater drilling environment. Current market demands for oil and gas are placing more focus on deepwater development of existing reserves. Operators have had to utilize enabling technologies that are robust enough to address multiple problems to develop deepwater reserves that are difficult to access. This paper describes a recent example of this dilemma when a deepwater operator successfully employed a solid expandable tubular system to isolate both overpressured and depleted sands The solid expandable system facilitated reaching the well objectives with a large hole size for maximize production rates. Over 6,865 ft (2,092m) of 7–5/8 x 9–5/8 in. expandable openhole liner allowed the operator to drill through both overpressured and depleted sands to an intermediate and unplanned casing point. Subsequent drilling operations below the expandable liner enabled the operator to reach the target zone and case the well with a 7 in. flush-joint production liner. Without the expandable installation, the operator would have been restricted to a maximum 5–1/2 in. casing at total depth (TD). Comparatively, 7 in. casing allowed the use of larger completion equipment providing Nexen Petroleum U.S.A., Inc., with significant additional production while reducing the mechanical risks associated with working inside smaller casing. The solid expandable tubular operating envelope provides a robust technology for operators who need a responsive system that addresses conditions proven to hinder drilling objectives. This paper will describe the conditions that led to selecting the solid expandable solution and detail the challenges mitigated with the installation of this record-setting system. In addition, this paper will focus on how solid expandable tubulars are applicable in extremely difficult drilling conditions and also how these tubulars can reduce the risks and costs associated with deepwater drilling. Introduction Deepwater Gulf of Mexico (GoM) was a fitting location for this record-length installation of a solid expandable tubular system from a semi-submersible (Figure 1). With the first expandable system installed in a shelf well just south of Louisiana state waters, the GoM was also the location of the first deepwater installation. The move to deeper water in the GoM was a natural progression for expandables as the technology has become more readily available and reliable for achieving extreme objectives. In its fundamental form, solid expandable technology reduces or eliminates the tapering effect of consecutive casing strings, preserving valuable hole size. An application history compiled since inception in the late 1990s has proven these systems as a technology that enables operators to reach and produce reserves previously unattainable due to drilling conditions and economic constraints. These systems have provided flexibility for well uncertainties and have helped operators reduce well costs with a slimmer well design.1&2 This design approach provides an alternate option to the big-bore well that results in a finite number of casing strings that can be used to reach the production zone. Removing this limiting drilling aspect helps reduce the risk of difficult oil recovery, and operators are reconsidering reserves that are now more attainable.
The purpose of this paper is to present the results of a comprehensive test program conducted with five different sets of deep-water landing string handling equipment consisting of both conventional and unconventional technology. A thorough presentation will be made detailing initial testing at elastic loads approaching yield and final high load testing beyond yield. All stages of the test program will be discussed including original testing protocol, test setup, testing performed, test results, and overall conclusions. This is one of the first standardized test programs used across five different designs of handling equipment. This overall presentation of the test program is made to identify stress levels associated with the extreme loads that occur when landing very heavy casing strings in deep-water wells. Introduction While landing string designs have progressed1, 2, the design of the handling equipment, until recently, has been based upon conventional slip technology. This conventional technology3 and new technology4 has been previously studied. Based upon the increasing loads being placed on landing strings and the associated handling equipment, a group of test participants including BHP Billiton, BP, ChevronTexaco, ExxonMobil, Nexen Petroleum and Oil & Gas Rental Services, Inc. arranged for Mohr Engineering Division, a division of Stress Engineering Services (Mohr) to perform an array of tests intended to increase the level of knowledge in the industry and help better understand the handling equipment currently in use for landing heavy loads. After developing an overall scope of work and understanding of the requisite testing, the field of handling equipment to be tested was determined to include a variety of designs used with landing string loads up to 2,000,000 lbs. Five different sets of handling equipment were tested. These included conventional slips referred to as SLIP A, SLIP B, and SLIP C, conventional power slips referred to as SLIP D and an unconventional slipless5, 6, 7, 8, 9 system referred to as SYSTEM E. Mohr provided the testing services and coordinated the machining and test sample preparation required to complete the tests. After testing was completed, Mohr also reviewed and post-processed the data and prepared a majority of the information contained in this paper. The manufacturers were requested to provide handling equipment for this test. Serial numbers were recorded to verify the handling equipment being tested and each manufacturer performed all inspections and dimensional verifications on equipment provided. After testing, test results for equipment provided were made available to each manufacturer. Each set of handling equipment was tested on instrumented test samples made from a 6.625″ OD × 0.813″ wall S-135 (50.46 ppf) conventional landing string. The test samples were turned on the OD and ID to provide actual dimensions at or very near nominal. Further, the test samples were instrumented with strain gauges, arranged in tri-axial rosettes (hoop, 45° and axial), set on 120° intervals to cover the ID of the entire contact area of the various handling equipment in order to determine the area of greatest strain/stress. The loading plan for the initial elastic test was as follows.
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