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.
© 2006. Society of Petroleum Engineers
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History
- Original manuscript received:
18 November 2004
- Revised manuscript received:
27 June 2006
- Manuscript approved:
10 July 2006
- Version of record:
20 December 2006
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