SPE 97565 Designer Casing for Deepwater HPHT Wells Richard A. Miller, SPE, Viking Engineering; Michael L. Payne, SPE, BP; and Peter Erpelding, SPE, Viking Engineering Copyright 2005, Society of Petroleum Engineers Inc. This paper was prepared for presentation at the 2005 SPE Applied Technology Workshop on High Pressure / High Temperature Sour Well Design held in The Woodlands, TX, U.S.A., 17 – 19 May 2005. This paper was selected for presentation by an SPE Program Committee following review of information contained in a proposal 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 a proposal of not more than 300 words; illustrations may not be copied. The proposal 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 Deepwater high pressure, high temperature (HPHT) drilling environments present difficult challenges to well engineers. Typical deepwater pore pressure and fracture gradient profiles result in a narrow drilling window that can lead to seven to nine casing points. The high cost of these wells demands a high rate completion for economic payback, which defines the size of the production casing and liners. Drilling casings are restricted by the standardized 18-3/4” through bore diameter dictated by high pressure wellhead housings, blowout preventers, and riser systems. Furthermore, high pressures require thick wall casing, especially if sour service materials are specified. Satisfying all of these pressure and geometrical constraints requires some unconventional practices. Current and emerging technologies offer several ways to address this design dilemma. Riser-less drilling can be an effective way to delay running the high pressure wellhead, allowing for additional large diameter casing seats. Dual gradient drilling is a concept that can decrease the number of required casing points. Solid expandable liners provide a way to add or push casing points without the geometry impact of a conventional string. Managed pressure drilling may also show promise for eliminating a seat. However, heavy reliance on these new technologies may run counter to the guiding principle of keeping HPHT wells as simple and reliable as possible. This paper presents the concept of using conventional oil country tubular goods (OCTG) in unconventional sizes to increase the number of available casing points in deepwater wells. The method has several advantages in the areas of performance and reliability compared with the previously listed technologies. The decades of industry experience with conventional OCTG make the technology especially appropriate for containing high pressures and sealing off trouble formations.
Related issues such as manufacturing lead time, costs, connections, and hangers are discussed. Several HPHT examples are included to illustrate the trade-offs with other design options. Introduction Typical Gulf of Mexico deepwater exploration wells have the following design constraints: • 7 – 9 casing seats • An 8-1/2” minimum hole size at TD • An 18-3/4” wellhead bore Some prospects are further complicated by having more than 9 casing points. Also, many completion engineers would argue that an 8-1/2” hole is a bare minimum. A representative schematic is shown in Figure 1. The schematic includes two sour service C-110 production liners and provisions for a production tieback. However, designing these production tubulars becomes a non-trivial task as pressures and temperatures increase. For example, the 9-7/8” production liner has an API minimum internal yield pressure (MIYP) of 12,180 psi. A casing of the same outside diameter and sour service C-110 material but a nominal 15,000 psi rating requires a nominal wall thickness of 0.770”, resulting in a drift diameter of 8.179”. This adversely impacts the subsequent bottom hole size and the lower completion. This thick wall 9-7/8” can be used for a production tieback at the expense of tubing and safety valve size. The top portion of the tieback is commonly telescoped larger to accommodate the safety valve and bypass lines, but a 10-3/4” C-110 casing with a 15,000 psi MIYP has a drift diameter less than 9”. If field economics require a high rate 5-1/2” or larger tubing completion, then the well could be built from the inside out. The 9-7/8” production liner grows to 10-3/4” and the tieback has 11-3/4” casing at the top. However, these production tubulars do not easily fit inside the drilling casings of Figure 1. The drilling casing could also increase in diameter, but eventually the strings become too large to fit inside a standard 18-3/4” wellhead and blowout preventer. Further complications arise if the drilling casings have inadequate pressure ratings. Tight clearances afford little room to increase wall thickness. Finally, the standard wellbore does not include a conventional contingency seat to combat adverse hole conditions or to address stability issues in a highly deviated development wellbore. The standard casing program of Figure 1 has accommodated deepwater Gulf of Mexico exploration for
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many years. It has become apparent that a non-standard approach is required to develop some of the deepwater HPHT targets. Enabling Technologies Several developing technologies may enable solutions to the deepwater HPHT design challenge. These options are briefly mentioned to highlight opportunities and challenges, not to provide an exhaustive review of status or viability. Solid Expandable Liners. A vast number of papers have publicized the development of expandable casing.1,2,3 The promise of gaining a casing seat without dropping hole size has encouraged a rapid acceptance of the technology. The growing experience base has led to a better understanding of how to use these products and improve job reliability. Expandables could significantly ease the deepwater HPHT design challenge by providing more clearance for conventional OCTG strings. However, several lingering obstacles prevent expandables from becoming the clear alternative for deepwater HPHT casing design. Connection integrity has been an issue from the beginning. Expandable casing connectors have difficulty passing focused laboratory tests, let alone the more rigorous industry standard ISO 136794. Post-expansion collapse ratings are low, and very little post-expansion mechanical data is available to establish reliable performance ratings. Operational difficulties can substantially increase rig time. Large diameter expandables have limited running lengths. Finally, the cost of expandable tubulars is about seven times the cost of conventional OCTG. Continued improvements to expandable technology are expected, but these challenges bring pause to relying on expandables to solve today’s deepwater HPHT casing design dilemma. Dual Gradient Drilling. Typical deepwater drilling prospects have narrow windows between pore pressure and fracture gradient. The long water column impacts the magnitude of pressures when measured as a gradient relative to the rig. Dual gradient drilling is a method to reduce a portion of the fluid gradient in the drill string annulus.5,6 In this manner, a heavier mud can be used to control bottom hole pressures without subjecting weaker up-hole formations to the same equivalent mud weight. Riser-less “pump and dump” drilling is a special case of dual gradient drilling where the annulus fluid column is sea water down to the mudline and weighted mud in the drilled hole. The benefit of dual gradient drilling is a wider margin between pore pressure and fracture gradient when mapped to an equivalent mud weight basis with respect to the mudline. The wider window allows longer open hole sections and fewer casing seats. The additional clearance can accommodate larger or higher pressure strings, thereby solving the deepwater HPHT design dilemma. However, dual gradient drilling with full well control equipment is an unproven technology. There are several technology gaps to solve, and the high up-front cost of rig conversion is an impediment to field-testing the concept. Additionally, if dual gradient drilling is selected as the enabling technology for deepwater HPHT, an equipment
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failure and subsequent conversion to conventional drilling will result in a significantly smaller bottom hole size. Managed Pressure Drilling. Managed pressure drilling (MPD) applies to any technique of controlling annular pressures while drilling. Technically, the dual gradient drilling described earlier is a type of MPD. Other types of MPD use a rotating control device to drill ahead with closed and pressurized mud returns7 or using an equivalent circulating density (ECD) reduction tool8,9 to reduce the impact of fluid friction while circulating. The biggest benefit of MPD is to extend hole sections by either drilling underbalanced or by limiting annular pressures at weaker uphole formations. The longer hole sections may enable fewer casing points, thereby loosening the constraints on the deepwater HPHT design dilemma. However, though forms of MPD are commonplace on land rigs, these technologies are largely unproven in the deepwater environment. The ECD reduction tool may improve hole stability and extend hole intervals, but well control risks may be higher and the tool has a detrimental impact on rig hydraulics. Significant tool development is required to gain what may be only an incremental benefit to well design. Designer Muds. Recent work in creating specialty muds shows promise for strengthening the wellbore, allowing higher mud weights without losing returns.10 The designer muds have been used to drill through highly depleted sands without cutting mud weight. This “stress cage” technology may be extended to strengthen weak casing shoes, enabling longer hole sections and reducing the number of casing seats. However, the technology is new and needs considerable work to be applied on a continuous basis. Since bridging solids must be kept in the system, there are limits on mud cleaning, and drilled solids content will build. The technique requires controlled drilling rates which can be difficult to maintain in directional hole sections. It may be challenging to maintain the stress cage across several lithologies. Designer muds appear to be highly beneficial for specific limited loss formations, but they may not be sufficient to solve the deepwater HPHT design dilemma. Custom OCTG. Purpose built casing strings are hardly new. The API casing tables contain sizes that were once unique, such as 7-3/4” 46.10 ppf and 11-3/4” 65.00 ppf, and they lack many items that are commonly used, such as 9-7/8” 62.80 ppf and 13-5/8” 88.20 ppf. Sizes, weights, and grades have been developed to address specific well needs, such as the 12-1/8” 90.0 ppf C-110 x 10-3/4” 73.0 ppf C-110 x 10” 72.0 ppf Q-125 intermediate casing used at Erskine, the first HPHT well in the North Sea.11 There appears to be little news when it comes to custom OCTG. The familiarity of custom OCTG is its strongest argument for using odd sizes to solve the deepwater HPHT design dilemma. Drilling clearances and pressure ratings can be precisely optimized across all strings. An additional casing seat can be squeezed into the program, or special sizes can be built to accommodate higher pressures. There are a few challenges in using custom sizes, primarily in the area of pressure isolation. Liner hangers and seals
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become critical, as do cement jobs through tight clearances. The benefits and challenges of custom OCTG will be further explored in detail. The Case for Custom OCTG Designer casing strings are proposed as an alternative to the technologies listed above. There is little new in the area of custom casing. Special sizes and grades have been built for decades. It is the familiarity of custom OCTG that makes it most appropriate for deepwater HPHT well design, where the priorities are to keep it simple and make it reliable. When considering custom OCTG, it is essential to recognize the benefits of an established system: 1. OCTG is a mature, well understood technology. 2. There is a wealth of reliability data to support downhole performance. 3. Industry standards comprehensively govern the manufacturing and inspection of OCTG. 4. Custom connections can be extended from existing designs, which simplifies acceptance qualification. 5. Custom OCTG is compatible with liner drilling. Strings can be drilled in place. Similarly, liner rotation can greatly increase the chance of getting the liner to the bottom and assists cement placement. Upgrade Pressure Ratings. The wellbore shown in Figure 1 has proven useful for Gulf of Mexico deepwater exploration. It has its limitations when considering high rate HPHT or extreme HPHT completions. Figure 2 is a modification of the exploration well design. The same 22” and 18” strings are used, but the 16” casing is run back to the mudline and upgraded to an MIYP of 10,680 psi. Below the 16” intermediate casing are two custom liners sized to provide a half inch clearance between the outside diameter and the previous casing drift diameter. The drilling / production liner is upgraded to the heaviest wall 10-3/4” that maintains an 8-1/2” drift. The wellbore in Figure 2 uses designer strings to accomplish the following: • 8-1/2” hole on bottom • Production tubulars with an 18,000+ psi MIYP • 5-1/2” tubing • 9-3/8” upper tieback drift (for a safety valve) • Clearance outside the tieback for syntactic foam to mitigate annular pressure build-up (APB)12 The same features could be accomplished by running an expandable 13-3/8” x 16” liner below the 16” and then covering it with a conventional 13-3/8” drilling liner. The question becomes one concerning preferences: • Proven, reliable OCTG technology versus emerging expandable technology • Lower cost versus higher cost • Higher performance versus lower performance • Shorter rig time versus longer rig time Add a Shoe Below 18”. Designer strings could also be used to add a shoe to the standard exploration casing program. Figure 3 shows a configuration that adds a shoe below the 18” casing. The 16” drilling liner is replaced by two custom sizes,
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a 16-3/8” liner and a 15” liner. The liners represent a trade-off between wall thickness for pressure ratings and ease of cutting connections vs. running clearances. Each liner and the subsequent 13-5/8” casing have a 0.387” clearance between the casing outside diameter and the previous casing drift. This clearance is greater than running 11-7/8” inside 13-5/8” (0.375”). The two liners each have a 0.400” wall thickness for ease in cutting threads. A similar geometry could be achieved by running a 16” liner and a 13-3/8” x 16” expandable liner. However, the custom OCTG liners have improved internal pressure ratings – 4,700 psi for the 16-3/8” and 5,130 psi for the 15” versus 3,420 psi for the expandable liner. The 15” has a drift diameter of 14.012” versus only 13.811” for the expandable liner, thus the expandable may not accommodate a subsequent 13-5/8” string. These advantages for the custom OCTG liners are in addition to the general benefits listed earlier. Add a Shoe Below 16”. As a final example, custom OCTG is used to add a shoe below the 16”. The wellbore in Figure 4 has the same strings through the 16”. A custom 14-1/4” liner is sized to provide 0.500” clearance between its outside diameter and the previous 16” drift. The subsequent intermediate casing has the same 13-5/8” at the top, but the bottom is a custom 12-3/4” pipe sized to give similar ratings as the 13-5/8” while maintaining an 11.504” drift for the subsequent custom 11” liner. A 9-3/8” drilling liner is also included in this wellbore. 9-3/8” is a good example of a size that was once custom but is now becoming more common. This wellbore does not have clear geometric advantages versus one that uses expandable liners. An expandable 13-3/8” x 16” liner could replace the custom 14-1/4” and the intermediate casing could then be 13-5/8” x 13-3/8”. The custom 11” liner provides significantly higher performance ratings as compared to an expandable 11-3/4” x 13-3/8” liner. The three examples shown here are not intended to be an exhaustive list of how purpose-built strings can solve deepwater HPHT design issues. Rather, they are shown to raise awareness of the benefits of custom OCTG. Ideally, the well design should start with a completion sized according to reservoir inflow performance, and then judiciously optimize the remaining space between wall thickness for performance, and clearance for running and cementing. Critical Components for Custom OCTG Previous industry experience has demonstrated that rolling custom OCTG is easily achievable. Cutting threads on custom sizes is also a normal practice. A key, critical component for using designer casing sizes is a liner hanger that seals pressure, either by itself or with a subsequent liner top packer. The current state of these related components is briefly described. Custom Pipe Sizes. Custom OCTG can be manufactured using either a Seamless (S) or Electric Resistance Weld (ERW) process. The seamless process involves piercing a hot cylindrical billet of steel, and then running it through a series of sizing mandrels to produce the finished product. The ERW process involves forming the tube from a coil of flat plate
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steel, and then welding the seam formed by the two edges. Both methods have distinct advantages and disadvantages. For the ERW process, two methods are used to produce non-standard OCTG. If sufficient tonnage is required, the coils are trimmed to the proper circumference and the tubes formed using the ERW process. Tooling and set-up charges for custom hot finished OCTG can be significant. In addition, depending on the mill schedule, lead times of 6-9 months are required to produce the new tooling. For smaller tonnage requirements, hot finished pipe of a standard size is cold drawn to the required diameter and wall thickness. The tube is then heated followed by quenching and tempering. Although the cold drawing process is more involved, it is the most cost effective process for smaller orders since new tooling is not required. As an added benefit, lead times for production are much shorter. The steel market is highly volatile and strongly influenced by the forces of supply and demand. With this in mind, the average price for a custom OCTG order in mid-2004 was $1.20/lb for P-110 and $1.30/lb for Q-125. This represented a premium when compared to standard sized casing but significantly less than the cost of expandable casing. Connections. Connections can be threaded on tubulars with wall thickness as low as 0.400” without forming the pipe ends. For casing diameters greater than 16”, additional wall thickness (≈0.425”) is required. To help ensure that casing will meet drift requirements, steel mills generally roll casing very close to the upper limits of the +1% API OD tolerance. The variability in the actual measured OD between various mills can lead to threading difficulties on thin wall pipe. In order to overcome this hurdle, connection manufacturers typically swage (expand) the box and (crimp) the pin on tubulars that have a diameter to wall thickness (D/t) ratio greater than 30. Swaging allows the connection manufacturer to place the material where it is needed for threading. Although the actual swage creates a box OD that is 3-5% greater than the nominal casing diameter, the swage is machined down and the maximum box OD is typically less than 1% over actual pipe body. Connection performance for a swaged connection on custom OCTG is very similar to that of OCTG in standard sizes. The tension efficiency is about 70% and the compression efficiency ranges from 50-70% when compared to the pipe body. These ratings are more than adequate for service conditions applied to drilling liners. Connection development costs for drilling liner service range from no cost for an existing design to $100,000 for development of an entirely new slim line connection with a metal seal. This does not include physical testing, which, depending on qualification requirements can range from $25,000 to $50,000 or more for each connection. FEA models can reduce the amount of physical testing required to finalize the design. Custom connections can be developed with lead times of four months or less when the size is a close extension of an existing design. Gage equipment takes about 6 weeks to procure, as can the forming tools required to swage the connection.
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Conventional Liner Hangers. The liner hanger industry has some difficulty providing conventional liner hanger and liner top packer systems that can be used for casing strings with radial clearances of 0.25” or less. There is very little room to house the required components while providing reasonable tension and differential pressure ratings. Achieving liner hanger/packer systems for casing strings with radial clearances of 0.25” is not insurmountable, as 11-3/4” x 13-3/8” 72 ppf liner hanger/packer systems are well established in deep water well design. The liner hanger and differential pressure ratings available for the 11-3/4 x 13-3/8 72 liner hanger/packer systems (approximately 800 kip and 5000 psi) can also be expected for the 13-3/4” x 16” 128.6 ppf and 12-1/4” x 13-3/4” 58.2 ppf custom liner hanger designs shown in Figure 2. Development of a custom hanger may take a year for detailed design, prototyping, testing, and manufacture. It is critical that liner hangers are fully rotatable. This feature allows the liner to be rotated or even drilled in place provided that a high torque connection is cut on the base pipe. Rotation will also help with cement placement and pressure isolation. The next generation of conventional liner hanger systems represents a focused effort to improve the design and functionality of existing liner hanger technology. The key improvement is the use of a hydraulic setting tool to set the slips and packer components. Since the hydraulic setting cylinder is placed inside the setting tool, the setting mechanism does not require a hydraulic setting cylinder on the liner hanger itself. This results in a liner hanger where the minimum internal yield and collapse ratings are not constrained by cylinder dimensional limitations. This new system has also eliminated many of the potential pitfalls found in current conventional designs. These include: elimination of all elastomers in the liner hanger itself, elimination of ports in the liner hanger body, elimination of shear screws in the liner hanger, and the elimination of the requirement for a lower pack-off. Each of these features contributes to an overall higher system reliability expected for HPHT wells. Development of these next generation hangers may take 10 to 18 months for detailed design, prototyping, testing, and manufacture. Expandable Liner Hangers. Expansion of the hanger into the base casing is a relatively new technology that provides a promising solution for hanging liners in tight clearances. An expandable hanger provides many benefits where other technologies fail. These include low clearance and high load applications. This technology has an added benefit in that the hanger and packer are all part of the same tool. This greatly simplifies the entire process, thus increasing the overall reliability of the hanger system. The expandable liner hanger can be run with either mechanical or hydraulic running tools. The hanger expansion is accomplished by radially expanding an inner sleeve against the casing from the top-down and is designed such that the elastic recovery of the inner sleeve is less than the elastic recovery of the casing. In addition, the expansion design insures that the base casing is never taken past its elastic limit.
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The primary seal is the metal-to-metal interference developed between the expandable hanger and the base casing. A bonded elastomer can also be incorporated as a backup seal to the primary metal seal, but is not required. Expandable hangers are new, and approximately 80 have been run in conjunction with conventional OCTG pipe. These include: 5” x 7” and 7” x 9-5/8” size hangers. The hangers can be rotated, allowing this technology to be compatible with casing drilling. Larger sizes are still being developed at an R&D level. Development costs run approximately $200,000 for each size with lead-times of 6 months for detailed design, prototyping, testing, and manufacture. Clearances and Isolation Seals. Tight clearances have been pushed for years.13 11-7/8” casing with flush connections have been routinely run inside 13-3/8” and 13-5/8” casing. This example of a 0.375” diametrical clearance between casing OD and the previous drift is used as a minimum benchmark. Open hole running clearances are improved by drilling oversized holes, a common practice in the Gulf of Mexico. The enlarged hole increases the chance for a good cement job and the corresponding pressure isolation. A fully-rotatable liner hanger is key to assisting cement placement. In addition, a couple of emerging technologies may provide alternatives to conventional cement and liner top packers. Swell packers may provide a way to seal the liner top without requiring clearance for mechanical devices. Polymer shut-offs may provide zonal isolation without the placement risk of a cement job through tight clearances. These technologies are not considered hinge factors for making custom OCTG work, but they could become useful options for improving pressure integrity. Conclusions Deepwater HPHT well design is a challenge to fit enough casing seats between the constraints of an 18-3/4” wellhead and BOP and the bottom hole size required for a high rate completion. Custom OCTG represents an enabling technology for solving the deepwater HPHT design challenge. • OCTG is a mature, well understood technology • Custom sizes have been used for decades • There is nothing special about rolling custom pipe • Connections are an extension of proven designs • Liner hanger development is critical • Custom OCTG does not preclude development of other technologies such as liner drilling Other technologies such as managed pressure drilling, designer muds, and expandable liners, may also provide ways to satisfy the well design challenge. However, these technologies are at various stages of development and carry significant risks and increased costs. To expedite development, qualification and sourcing of custom OCTG, deep water operators should work towards a short list of the most leverage-able sizes in order to encourage vendors to bring these products to the market.
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Nomenclature APB API D/t ECD ERW FEA HPHT ISO kip MIYP MPD OCTG OD psi S t TD
Annular Pressure Build-up American Petroleum Institute Outside Diameter to Wall Thickness Ratio Equivalent Circulating Density Electric Resistance Weld Casing Finite Element Analysis High Pressure High Temperature The International Organization for Standardization One Thousand Pounds Force Minimum Internal Yield Pressure Managed Pressure Drilling Oil Country Tubular Goods Outside Diameter Pounds Force Per Square Inch Seamless Casing Wall Thickness Total Depth
Acknowledgements The authors would like to thank the management of BP for permission to prepare this paper and present the subject material. References 1.
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Filippov, Andrei, Robert Mack, Lance Cook, Patrick York, Lev Ring, and Terry McCoy, “Expandable Tubular Solutions”, SPE 56500 presented at the 1999 SPE Annual Technical Conference, Houston, 3-6 October. Dupal, Kenneth K, Donald B. Campo, John E. Lofton, Don Weisinger, Lance Cook, Michael D Bullock, Thomas P. Grant, and Patrick L. York, “Solid Expandable Tubular Technology – A Year of Case Histories in the Drilling Environment”, SPE 67770 presented at the SPE/IADC Drilling Conference, Amsterdam, 27 February-1 March, 2001. Gusevik, Rune and Randy Merritt: “Reaching Deep Reservoir Targets Using Solid Expandable Tubulars”, SPE 77612 presented at the 2002 SPE Annular Technical Conference, San Antonio, Texas 29 September-2 October. ISO 13679 Procedures for Testing Casing and Tubing Connections, First Edition, 2002-12-15. Schumacher, J.P., J.D. Dowell, L.R. Ribbeck, and J.C. Eggemeyer, “Planning and Preparing for the First Subsea Field Test of a Full-Scale Dual-Gradient Drilling System”, SPE 80615, SPE Drilling & Completion Volume 17 Number 4, 2002, pp. 194-199. Judge, Robert A., and Ricky Thethi: “Deploying Dual Gradient Drilling Technology on a Purpose-Built Rig for Drilling Upper Hole Sections”, SPE 79808 presented at the SPE/IADC Drilling Conference in Amsterdam, 19-21 February 2003. Hannegan, Don: “Managed Pressure Drilling in Marine Environments – Case Studies”, SPE 92600 presented at the SPE/IADC Drilling Conference in Amsterdam, 23-25 February 2005. Bern, P.A., Dave Hosie, R.K. Bansal, Donald Stewart, and Bradley Lee, “A New Downhole Tool for ECD Reduction”, SPE 81642 presented at the IADC/SPE Underbalanced Technology Conference in Houston, 25-26 March 2003.
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9.
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Bern, P.A., W.K. Armagost, and R.K. Bansal: “Managed Pressure Drilling with the ECD Reduction Tool”, SPE 89737 presented at the SPE Annual Technical Conference, Houston, 26-29 September 2004. Aston, M.S., M.W. Alberty, M.R. McLean, H.J. de Jong, and K. Armagost, “Drilling Fluids for Wellbore Strengthening”, SPE 87130 presented at the IADC/SPE Drilling Conference, Dallas, 2-4 March 2004. Elliott, G.S., R.A. Brockman, and R.M. Shivers III: “HPHT Drilling and Completion Design for the Erskine Field”, SPE 30364 presented at Offshore Europe 95 in Aberdeen, 5-8 September 1995. Payne, M.L., P.D. Pattillo, U.B. Sathuvalli, R.A. Miller, and R. Livesay, “Advanced Topics for Critical Service Deepwater Well Design”, presented at Deep Offshore Technology, Marseille, 19-21 November 2003. Barker, J.W.: “Wellbore Design with Reduced Clearance Between Casing Strings”, SPE 37615, presented at the SPE/IADC Drilling Conference in Amsterdam, 4-6 March 1997.
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36” 28” 22” 224.0 ppf (1.000” wall) X-80 18” 117.0 ppf (0.625” wall) N-80
16” 97.0 ppf (0.575” wall) P-110
13-5/8” 88.20 ppf (0.625” wall) HCQ-125
11-7/8” 71.80 ppf (0.582” wall) P-110
9-7/8” 62.80 ppf (0.625 wall) C-110
7” 38.0 ppf (0.540” wall) C-110 Figure 1 – Typical Gulf of Mexico deepwater exploration casing program with production liner and tieback.
36” 28” 22” 224.0 ppf (1.000” wall) X-80 18” 117.0 ppf (0.625” wall) N-80 11-3/4” ppf 126.20 (1.109” wall) C-110 x 10-3/4” ppf 108.70 (1.047” wall) C-110 16” 128.6 ppf (0.781” wall) Q-125
13-3/4” 58.20 ppf (0.400” wall) P-110
12-1/4” 51.60 ppf (0.400” wall) P-110
10-3/4” 108.70 ppf (1.047” wall) C-110
7” 42.70 ppf (0.625” wall) CRA-125 Figure 2 – Exploration well upgraded to accommodate 18,000 psi production tubulars and a 5-1/2” completion.
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36” 28” 22” 224.0 ppf (1.000” wall) X-80 18” 93.54 ppf (0.500” wall) N-80
16-3/8” 69.6 ppf (0.400” wall) P-110 15” 63.6 ppf (0.400” wall) P-110
13-5/8” 88.20 ppf (0.625” wall) HCQ-125
11-7/8” 71.80 ppf (0.582” wall) P-110
9-7/8” 62.80 ppf (0.625 wall) C-110
7” 38.0 ppf (0.540” wall) C-110 Figure 3 – Exploration well modified to add a casing seat below the 18”.
36” 28” 22” 224.0 ppf (1.000” wall) X-80 18” 117.0 ppf (0.625” wall) N-80
16” 97.0 ppf (0.575” wall) P-110
14-1/4” 60.4 ppf (0.400” wall) P-110
13-5/8” 88.20 ppf (0.625” wall) Q-125 x 12-3/4” 72.5 ppf (0.545” wall) Q-125
11” 54.5 ppf (0.475” wall) Q-125 9-3/8” 39.00 ppf (0.400” wall) HCQ-125E
7” 38.00 ppf (0.540” wall) C-110 Figure 4 – Exploration well modified to add a casing seat below the 16”.
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