Planning and Execution of a Long, Tight Clearance Liner Through a Whipstock Milled Window
Abstract: A long, tight clearance liner was recently installed through a whipstock-milled window in a deepwater well. The length and weight of the liner, coupled with the tight clearances, pushed the limits of current technology. The liner was successfully run through a deep whipstock milled window and cemented at a depth below 24,000'. This paper describes the planning and execution involved in this critical well construction operation. Introduction Installin… Show more
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Industry experience reveals that tar formations can present significant challenges in deep water drilling operations (1–4). In a case where several feet of active tar is present at depth, substantial trouble time often results. Tar can even prevent reaching programmed depth in some cases. These difficulties are further compounded in a high cost environment with limited rig availability where project appraisal and viability can be impacted (5). These events came to pass for Chevron and partners during late 2005 and early 2006 on the ‘Big Foot’ Prospect in the Gulf of Mexico at Walker Ridge Block 29 (see Fig. 1 Walker Ridge Area). Challenges on this sub salt prospect included loop currents, an active hurricane season, and numerous sub-surface issues related to geologic uncertainty, narrow pore pressure/fracture gradient margins, and wellbore stability. This paper will focus primarily on issues related to the tar formation which was encountered below salt, its impact on operational strategy, lessons learned, and steps taken to ultimately achieve the well objectives. Background The ultra deep water drilling unit ‘Cajun Express’ had been mobilized during July 2005 to drill the ‘Big Foot’ exploration well to 27,000' MD in 5,300' of water depth. The first evidence of trouble related to tar occurred while drilling ahead at 19,980' MD with 12 ppg synthetic oil based drilling fluid (SOBM) in a 12–1/4″ hole section. Since there was no prior history of significant tar in this area, the implications of the troublesome zone were not immediately recognized. Tight hole was encountered on a connection and back reaming was employed while circulating to stabilize and clean up the hole. On bottoms up sticky tar was observed ‘blinding’ the shakers and other solids control equipment. A series of oil sands had been drilled over the preceding 800' of open hole with significant gas shows. Even with gamma ray/resistivity logging while drilling (LWD) and mud log data thru the interval the characterization of the bottom 40' of hole containing tar was initially inconclusive. Over subsequent days attempts were made to stabilize the hole with mud weight, short trips, and reaming to enable drilling ahead. Ultimately, however, the hole section was abandoned when it became clear that further drilling, casing, or logging operations below the tar zone were not likely in a reasonable amount of time. Well Objectives and Design The objectives for the ‘Big Foot’ Prospect were developed around the evaluation of Middle Miocene and Eocene/Wilcox targets between 19,000' and 25,000' TVD in Block 29. The directional design was necessitated to penetrate both targets at the desired structural position and included building angle below salt to 30º inclination at a 130 degree azimuth. In addition to the salt section from 8,000' to 12,000' TVD, another salt body to the east overhung the deeper targets. The directional design enabled the structural objectives without having to drill two separate salt intervals. The combination of an overlying salt section, poor seismic resolution, uncertain pore pressure/fracture gradient below salt, and increasing pore pressure below the Miocene dictated a ‘large bore’ casing configuration. (See Wellbore Diagram Fig 2). Geologically comparable offset data was sparse to non-existent, therefore a significant amount of subsurface uncertainty was recognized early in the planning phase. The original Big Foot wellbore reached TD during December 2005 and was announced as a discovery shortly thereafter. The well was drilled and evaluated in 141 days for $70.8 million. The scope of the project with the Cajun was then expanded to incorporate an appraisal sidetrack to the Middle Miocene +/-4,000' north from the original location. The tar interval was encountered while drilling the sidetrack.
Industry experience reveals that tar formations can present significant challenges in deep water drilling operations (1–4). In a case where several feet of active tar is present at depth, substantial trouble time often results. Tar can even prevent reaching programmed depth in some cases. These difficulties are further compounded in a high cost environment with limited rig availability where project appraisal and viability can be impacted (5). These events came to pass for Chevron and partners during late 2005 and early 2006 on the ‘Big Foot’ Prospect in the Gulf of Mexico at Walker Ridge Block 29 (see Fig. 1 Walker Ridge Area). Challenges on this sub salt prospect included loop currents, an active hurricane season, and numerous sub-surface issues related to geologic uncertainty, narrow pore pressure/fracture gradient margins, and wellbore stability. This paper will focus primarily on issues related to the tar formation which was encountered below salt, its impact on operational strategy, lessons learned, and steps taken to ultimately achieve the well objectives. Background The ultra deep water drilling unit ‘Cajun Express’ had been mobilized during July 2005 to drill the ‘Big Foot’ exploration well to 27,000' MD in 5,300' of water depth. The first evidence of trouble related to tar occurred while drilling ahead at 19,980' MD with 12 ppg synthetic oil based drilling fluid (SOBM) in a 12–1/4″ hole section. Since there was no prior history of significant tar in this area, the implications of the troublesome zone were not immediately recognized. Tight hole was encountered on a connection and back reaming was employed while circulating to stabilize and clean up the hole. On bottoms up sticky tar was observed ‘blinding’ the shakers and other solids control equipment. A series of oil sands had been drilled over the preceding 800' of open hole with significant gas shows. Even with gamma ray/resistivity logging while drilling (LWD) and mud log data thru the interval the characterization of the bottom 40' of hole containing tar was initially inconclusive. Over subsequent days attempts were made to stabilize the hole with mud weight, short trips, and reaming to enable drilling ahead. Ultimately, however, the hole section was abandoned when it became clear that further drilling, casing, or logging operations below the tar zone were not likely in a reasonable amount of time. Well Objectives and Design The objectives for the ‘Big Foot’ Prospect were developed around the evaluation of Middle Miocene and Eocene/Wilcox targets between 19,000' and 25,000' TVD in Block 29. The directional design was necessitated to penetrate both targets at the desired structural position and included building angle below salt to 30º inclination at a 130 degree azimuth. In addition to the salt section from 8,000' to 12,000' TVD, another salt body to the east overhung the deeper targets. The directional design enabled the structural objectives without having to drill two separate salt intervals. The combination of an overlying salt section, poor seismic resolution, uncertain pore pressure/fracture gradient below salt, and increasing pore pressure below the Miocene dictated a ‘large bore’ casing configuration. (See Wellbore Diagram Fig 2). Geologically comparable offset data was sparse to non-existent, therefore a significant amount of subsurface uncertainty was recognized early in the planning phase. The original Big Foot wellbore reached TD during December 2005 and was announced as a discovery shortly thereafter. The well was drilled and evaluated in 141 days for $70.8 million. The scope of the project with the Cajun was then expanded to incorporate an appraisal sidetrack to the Middle Miocene +/-4,000' north from the original location. The tar interval was encountered while drilling the sidetrack.
ConocoPhillips pre-drilled wells for the Magnolia tension leg platform (TLP) development in 2003 using a dynamically positioned semi-submersible drilling vessel1. The Magnolia field is located in 4,674 ft of water at Garden Banks (GB) block 783 in the Gulf of Mexico. During the pre-drilling phase, two wells were successfully sidetracked out of 13.625 in. casing in one trip using an extended gage, one trip whipstock system. The first whipstock operation was through cemented pipe and the second was through uncemented pipe, which had communication to a shallower, weak formation. This paper focuses on whipstock operations through uncemented pipe and describes the planning and execution of the first successful attempt at setting a whipstock, milling the window, squeeze cementing the window, and drilling out cement and rathole - all on one trip while using synthetic base mud (SBM). Due to the high spread rate cost of deepwater drilling, every effort is made to reduce critical path time while managing risk and safety. Typical whipstock operations through uncemented casing can require three or more round trips to prepare a window for drilling ahead. On the GB 783 A-4 BP1 well, window milling/cementing operations through uncemented casing were conducted in a single trip. The whipstock was oriented and set at 11,080 ft measured depth (MD) in a 54° angle hole. The window was milled, the assembly pulled above the window, and the openhole squeeze cemented. After waiting on cement to set, the cement was drilled out and a successful formation test achieved. An additional 130 ft of rathole was then drilled with the mills to place the stabilizers on the next drilling assembly below the whipstock. Operations from the start of running the whipstock until the mills were laid down took 2.6 days. A total of 1,861 lbm of metal shavings was safely recovered. This paper highlights 1) whipstock installation and window cutting operations, 2) safety and operational best practices for removing, handling, and monitoring metal cuttings that, if not removed from the hole, can be problematic for subsea blowout preventer (BOP) systems, 3) equipment modification made to mitigate risk for cementing through a milling assembly, and 4) design considerations for achieving a successful squeeze. Introduction The Magnolia TLP development wells were drilled from a dynamically positioned semi-submersible rig, which required using a subsea BOP stack and subsea wellhead equipment. The typical casing program for the wells was 36 in. × 20 in. × 13.625 in. casing strings run to the mudline. The 13.625 in. casing weighs 88.2 lbm/ft and is HCQ-125 grade pipe. A 10.75 in. drilling liner is run to obtain high enough fracture gradient to drill to total depth (TD). An 8.062 in. production liner was then run and hung off in the 10.75 in. drilling liner that also functions as production casing. Both the 10.75 in. drilling liner and the 8.062 in. production liner for the GB 783 A4 well stuck off bottom while being run. Numerous attempts to fish the 8.062 in. liner out of the hole were unsuccessful. In order to have 8.062 in. casing set across the producing zone of the original geologic targets, it was necessary to set a whipstock above the 10.75 in. liner and sidetrack the well. The 13.625 in. casing in the area above the 10.75 in. drilling liner was uncemented in order to prevent potential annular collapse issues. One of the previous wells in the pre-drill program, GB 783 A2 ST3, had sidetracked out of 13.625 in. casing by setting a whipstock. The whipstock was set across a length of casing that had cement in the casing by openhole annulus. A number of "Lessons Learned" were obtained during whipstock operations on the A2 ST3 well. These lessons learned and others from previous deepwater whipstock operations were used to help evaluate the risk and optimize the procedures on the A-4 well.
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