Magnolia Deepwater Development – Striving for Best in Class Drilling Performance

Abstract

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.