Summary ConocoPhillips is developing the Magnolia field with a Tension Leg Platform (TLP) in 4,674 ft of water at Garden Banks (GB) block 783 in the Gulf of Mexico (GOM) (see Fig. 1). The field was discovered in 1999, and appraisal wells were drilled in 2000 and 2001. The well-construction strategy included drilling six additional development wells from a mobile offshore drilling unit (predrilling) before the installation of the TLP. Drilling the new wells consisted of two phases: batch-setting all six wells through 20-in. casing, followed by deepening the wells to a total depth (TD). The wells targeted multiple zones resulting in complex, designer directional wells with 50° to 60° maximum hole angles. This paper examines the application of drilling best practices used to deepen the wells to TD after batch-setting operations were complete (Eaton et al. 2005). To minimize drilling costs while deepening the wells to TD, project goals were to eliminate trouble time; minimize combined drilling, circulating and tripping time per interval; maximize simultaneous activities; and reduce the number of trips necessary to drill the well. The goal of achieving Best-in-Class performance requires detailed planning, documenting, and implementing of results and lessons learned; effective communications; equipment quality control; and implementation of a team environment with all the companies involved in the drilling program. The complex high-angle wells require employing extended reach best practices to balance on-bottom drilling performance with the ability to effectively clean the hole to enable trouble-free tripping of the bottomhole assembly (BHA), running of casing, and obtaining primary cement jobs. The best practices discussed in this paper include changes made to improve rotary steerable reliability; simultaneous drilling and under reaming BHA design (Eaton et al. 2001); hole cleaning; and torque and drag monitoring. The paper also discusses activities that reduced the number of required trips and activities conducted out of critical path, such as moving the subsea blowout preventor (BOP) from wellhead to wellhead with an innovative BHA, a BHA to run and retrieve wear bushings, subsea guidebase installation by way of a winch and remote operated vehicle (ROV), off-critical-path makeup of BHA components, and drillstring management. Introduction The Magnolia field will be produced from eight wells with dry trees connected to the TLP. Drilling the three exploration/appraisal wells from the same seabed pattern enabled the wells to be used as TLP production wells. The well-construction strategy included drilling the development wells to TD from a mobile offshore drilling unit (MODU) before the installation of the TLP. The "predrilled" wells are then completed using a smaller, lighter completion rig installed on the TLP. This reduces the cost of the TLP because of the lighter deck loads requirements vs. those needed for a full sized drilling rig. The predrilled wells also gathered subsurface data before the TLP completion program and accelerated the production by predrilling the wells to TD.
Abstract. The purpose of this study is to investigate the unloading behavior of molybdenum at shock pressures approaching the melt regime, particularly in the vicinity of a previously reported solid-solid transition. Symmetric impact experiments were conducted using a two-stage light gas gun and VISAR diagnostic system to examine molybdenum's behavior up to pressures of 305 GPa. The approach required compensating for the wave interaction due to the low impedance LiF window, but provided detailed information regarding the release state and comparison of the measured sound speeds support the existence of the phase transition. This paper describes the strategy, experimental method, and corresponding results which are used to draw conclusions about the dynamic behavior of molybdenum at high pressure.
ConocoPhillips is developing the Magnolia field with a Tension Leg Platform (TLP) in 4674 ft of water at Garden Banks (GB) block 783 in the Gulf of Mexico (GOM), see Figure 1. The field was discovered in 1999 and appraisal wells were drilled in 2000 and 2001. The well construction strategy included drilling six additional development wells from a mobile offshore drilling unit (pre-drilling) prior to the installation of the TLP. Drilling the new wells consisted of two phases; batch setting all six wells through 20 in. casing followed by deepening the wells to total depth (TD). The wells targeted multiple zones resulting in complex, designer directional wells with 50°-60° maximum hole angles. This paper examines the application of drilling best practices that were used to deepen the wells to TD after batch-setting operations were complete1. To minimize drilling costs while deepening the wells to TD, project goals were to eliminate trouble time; minimize combined drilling, circulating and tripping time per interval; maximize simultaneous activities; and reduce the number of trips necessary to drill the well. The goal of achieving Best- In-Class performance required detailed planning, documenting and implementing results and lessons learned, effective communications, equipment quality control, and implementation of a team environment with all the companies involved in the drilling program. The complex high angle wells required employing extended reach best practices to balance on-bottom drilling performance with the ability to effectively clean the hole to allow trouble free tripping of the bottom hole assembly (BHA), running of casing, and obtaining primary cement jobs. The best practices discussed in this paper include changes made to improve rotary steerable reliability; simultaneous drilling and under reaming BHA design2; hole cleaning; and torque and drag monitoring. The paper will also discuss activities that reduced the number of required trips and activities that were conducted out of critical path such as moving the subsea BOP from wellhead to wellhead with an innovative bottom hole assembly (BHA), BHA run and retrieve wear bushings, subsea guidebase installation via a winch and ROV, off critical path make-up of BHA components, and drill string management. Introduction The Magnolia field was discovered in 1999 with the drilling of the GB 783 #1 well. The GB 783 #2 well was drilled in 2000 as a directional appraisal well with a subsequent geologic sidetrack and a bypass hole to obtain whole cores. The GB 783 #3 well was drilled in 2001, also a directional appraisal well, followed by sidetracks of the GB 783 #1 well and the GB 783 #3 well. Drilling all three wells from the same seabed pattern allowed them to be utilized as TLP production wells. The Magnolia Project and Asset teams were formed in 2001 and project sanction was obtained in December 2001. Detailed engineering conducted in 2002 in preparation for the pre-drilling program included formation of the Magnolia development drilling team, selection of the rig and third party services, wellhead selection, casing design and procurement, directional planning in conjunction with the subsurface team, preparation of detailed procedures, completion planning, and interface planning with the project team. The Magnolia field will be produced from eight wells with dry trees connected to the TLP. The well construction strategy included drilling the wells to TD from a mobile offshore drilling unit (MODU) prior to the installation of the TLP. The "pre-drilled" wells would then be completed using a smaller, lighter completion rig installed on the TLP. This reduces the cost of the TLP due to the lighter deck loads requirements verses those needed for a full sized drilling rig. The pre-drilled wells also gathered subsurface data prior to the TLP completion program and accelerated the production by pre-drilling the wells to TD.
ConocoPhillips is developing the Magnolia field with a Tension Leg Platform (TLP) in 4,674 ft of water at Garden Banks block 783 in the Gulf of Mexico. The wells are completed using dry trees from the TLP. The production casing for each well consists of an 8.062 in. liner set near the base of a 10.75 in. liner. The 10.75 in. liner is tied back to the subsea wellhead. The subsea wellhead is tied back to the TLP with an 11.75 in. production riser. To minimize heat loss in the produced fluid above the mudline, the production riser × tubing annulus is filled with low-pressure nitrogen. Completion brine is left in the well below the mudline. Two of the eight wells did not have cement behind the 10.75 in. liner hanger polished bore receptacle (PBR), leaving a trapped annulus. Results from annular pressure build-up programs and finite element analysis (FEA) of the PBR tieback stem configuration, indicated that the combination of increased annular pressure due to temperature heat up during production along with the reduced hydrostatic pressure of the nitrogen in the annulus could cause a collapse failure of the 10.75 in. liner hanger PBR. Since the tieback string had been run and cemented, it was not possible to access the annulus behind the liner hanger PBR by conventional means. A number of potential solutions to address the problem were considered: scab liner, expandable casing, perforate and squeeze annulus, low heat-transfer gel instead of nitrogen, and high-density brine. This paper will discuss the analysis of the potential collapse issue of the liner hanger PBR, the potential solutions, and implementation of the solution on the actual wells. Introduction The wells at the Magnolia field were pre-drilled using a dynamically positioned semi-submersible in 2002- to 20031, 2. After installing the Magnolia TLP in August 2004, a 2,000 horsepower platform rig, the MODS 201, was installed upon the TLP to complete the seven wells that had been pre-drilled. The eighth well required drilling the production interval to total depth (TD) and was scheduled to be the last well to be completed. The wells are dry-tree completions back to the TLP with direct vertical access. Following installation of the platform rig, two 11.75 in. outer diameter (OD) production risers were installed. The first two wells were then completed to begin production from the platform. The remaining six production risers were subsequently run in a batch program followed by completing the remaining pre-drilled wells. First production from the platform occurred on 12 December 2004. Completion designs for the wells had been developed during a two-year planning period from 2002- to 2004. Final detailed planning for the wells was completed in Jan. - Jul. 2004. Prior to installing the MODS 201 aboard the Magnolia TLP, a two-week onshore integration test was conducted. The platform rig, a new build, was commissioned and then the integration test conducted. During the integration test, most of the normal completion operations were simulated to identify any equipment handling issues and familiarize the rig crews with the equipment. It also allowed any potential problems to be identified at a low cost and allowed time to make any potential changes that were identified. During the final completion planning in early 2004, it was identified that two of the intermediate drilling liners did not have cement across the liner lap. There was concern that the two wells might be candidates for potential annular collapse issues under production conditions. Annular pressure problems have been experienced during production at at least one deepwater GOM development3, which led to a more detailed investigation of the potential problem.
TX 75083-3836 U.S.A., fax 1.972.952.9435. AbstractConocoPhillips is developing the Magnolia field with a Tension Leg Platform (TLP) in 4,674 ft of water at Garden Banks block 783 in the Gulf of Mexico. The wells target multiple zones resulting in complex directional wells with 50°-60° maximum hole-angles. The wells are completed using dry trees from the TLP and are producing primarily from massive, fine-grained, Pleistocene-aged reservoirs.These reservoirs require sand-control to prevent sand production at the expected drawdowns planned during the life of the wells. To help ensure high rate, long life completions, the producing zones are frac-packed. The average perforated interval during the initial completion program was 310 ft with a maximum perforated interval of 571 ft.The typical production casing string for the wells consists of 10-3/4 in. casing with an 8-1/16 in. production liner. Drift diameter through the tapered production casing is 9-1/2 in. and 6-1/2 in. respectively. The 6-1/2 in. drift diameter allows using common size screens and packers. The wells are generally completed with a 4-1/2 in. x 3-1/2 in. tapered tubing string.Premium screens with shunt tubes are used on the wells due to the long deviated intervals.The "frac-pack" stimulation treatments are pumped at rates of 27 to 40 bbl/min with a viscoelastic surfactant carrier fluid. Washpipe conveyed downhole pressure and temperature gauges and radioactive tracers are used to help analyze the treatment results.This paper will discuss screen selection philosophy in silt/very fine sand reservoirs, carrier fluid selection, perforation strategy, and ability to frac across shale intervals. The paper will also cover the effectiveness of achieving a frac-pack with premium screens with shunt tubes, based upon downhole pressure, temperature, radioactive tracer information, and revised operational practices that resulted in zero to negative skin completions across long, perforated intervals that continue to produce sand free after extreme reservoir depletion.
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