TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractConocoPhillips (COPC) is developing the Magnolia field with a Tension Leg Platform (TLP) in 4674 feet of water at Garden Banks (GB) block 783 in the Gulf of Mexico (GOM). The field was discovered in 1999 and appraisal wells were drilled in 2000 and 2001. Field development approval was obtained in 2001. The approved depletion plan and well construction strategy included drilling and casing wells prior to the installation of the TLP (pre-drilling), pre-completing and testing one well during the pre-drilling program, and completing the remaining wells from a completion rig installed on the TLP.The GB783 A2ST3BP1 well was successfully drill-stem tested (DST) from the Ensco 7500 dynamically positioned (DP) semi-submersible drilling vessel in June 2003 as part of the Magnolia field development. The pre-completion and DST operations overcame a number of challenges which included the frac-packing of a thick, fine-grained interval, and well testing from a DP semi-submersible drilling rig while simultaneously transferring produced hydrocarbons to a transportation barge moored to the rig.The objectives of the pre-completion/DST were to plan and execute the operations safely, validate the sand control design, determine well performance and reservoir properties, and verify the effectiveness of the completion procedures prior to the TLP rig completion program. This paper will focus on the extensive planning process and the operational aspects of performing a DST in a deepwater environment.
ConocoPhillips is developing the Magnolia field with a Tension Leg Platform (TLP) in 4674 ft of water in Garden Banks (GB) block 783 in the Gulf of Mexico. Three wells were drilled at the eventual TLP site to discover and appraise the field prior to sanction of the development plan. Field development plans required drilling an additional six wells at the TLP site where a shallow water flow (SWF) zone is present. The development plan included batch drilling and casing the SWF interval prior to deepening any of the wells to total depth. The Magnolia batchset program was successfully conducted in 2002 using the Ensco 7500 dynamically positioned semi-submersible drilling vessel. The six well batchset program was drilled at less than the Authority For Expenditure (AFE) cost estimates with zero lost workday cases. The batch set program included jetting 36 in. casing to 246 ft below mudline (BML), directionally drilling a 26 in. hole to 3264 ft BML while building hole angles up to 17°, and running and cementing 20 in. casing with verified cement returns to the mudline. The SWF sand interval was drilled and cased without "Top Setting" a cemented casing string above the SWF zone. Although individual exploratory wells have been drilled and cased without top setting casing previously, the Magnolia field is the first deepwater field with a SWF zone to be developed in this manner. Pre-planning for the SWF zone addressed directional drilling issues, water base mud (WBM) design, cement formulation and placement procedures, and logistic supply to the drilling rig. Each well required three 89 ft joints of 36 in. casing, 81 joints of 20 in. casing, 40,730 bbls of blended WBM, and 6,760 ft3 of cement. Five supply vessels were used to provide logistic support for the operation. This paper will focus on the extensive planning process and the operational aspects of performing a batchset drilling program through a SWF sand in a deepwater environment. Introduction The well construction strategy for the Magnolia development wells included drilling the wells from a mobile offshore drilling unit (MODU) to total depth (TD) 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 reduced the cost of the TLP due to the lighter deck loads than those needed for a full sized drilling rig and accelerated the production from the pre-drilled wells. The detailed planning and procurement of equipment for the pre-drilling program began in early 2002, immediately after project sanction. Remaining well construction personnel that were not already in place were selected and began planning the pre-drilling program. The completion design and pore pressure model determined the casing plan that was incorporated into the overall well design. Installing the 36 in. structural and 20 in. conductor casing strings for the development wells in a batch set mode at the beginning of the pre-drilling program was selected for the following reasons.Isolating the SWF sand with 20 in. casing and cement for all the wells before deepening any of the wells to TD would greatly reduce the cost impact if a SWF occurred that compromised the TLP site.Quickly capture efficiencies of repetitive activities by the drilling crews from the batch setting of the 36 in. and 20 in. casing strings. Taking advantage of coming down the learning curve quickly leads to significant cost savings.1The risk of a SWF occurring would be reduced since the rig crew would better understand and carry out the proposed plan of all six wells in a one month period versus drilling through the SWF zone once every six to eight weeks.To allow "leap-frogging" the subsea BOP between subsea wellheads during the pre-drilling program thus saving the cost and time of a round trip of the marine drilling riser and subsea BOP for every well.
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.
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