Summary
Offshore drilling continues to be extremely cost intensive, with U.S. $50
million wells not uncommon. This paper discusses one company's experience and
the lessons it learned from a comprehensive analysis of Gulf of Mexico (GOM)
historical data for drilling-performance benchmarking and continuous cost
reduction. Drilling operations were broken down into discrete activities, and
the best times from all the wells---including trouble time---were aggregated to
form the "best composite time" (BCT). The BCT, introduced in recent
papers, was applied, along with learning-curve analysis and other investigative
tools, to examine drilling problems and the lessons learned to capture the best
practices and, thereby, challenge well-planning and construction practices.
The "best composite cost" (BCC), or the monetary equivalent of the
BCT, was also calculated and used for well-cost benchmarking. Correlative
analyses of the wells (i.e., crossplots of drilling events alongside mud-log
data, wireline logs, and geologic data) were used to elucidate major well
problems and abnormal flat times that caused deviations from the BCT.
Correlative analysis also helped explain why some wells were drilled relatively
trouble-free, even in difficult environments.
From a more detailed trouble-time analysis of company-operated wells,
tool/equipment failure was seen as a significant trouble-time component. Major
drilling problems were also found to be mostly well-pressure related (e.g.,
well control, lost circulation, and stuck pipe), supporting increased emphasis
on improved planning and quantification of equivalent circulating density
(ECD), deepwater geopressures, and narrow drilling margins, especially in
ultradeepwater environments. Overall, the company's 2003 trouble time was 26%
of the total drilling time from spud to rig release.
The BCT/BCC methodology is actually one element of "The Ten-Step
Process" discussed exhaustively in Refs. 1 and 2. Applications to two
onshore areas, so far, have shown encouraging results in drilling-cost
reduction. Applications to more-complicated offshore GOM wellbores, cost
components, and narrow geopressure margins are the focus of this paper. The
fields investigated are located in different parts of the GOM (Table 1). For
brevity, results are shown only for the subsalt area of South Timbalier, the
deepwater Green Canyon (GC) area, and the ultradeepwater eastern Gulf of Mexico
(EGOM).
© 2005. Society of Petroleum Engineers
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History
- Original manuscript received:
2 April 2004
- Revised manuscript received:
23 December 2004
- Manuscript approved:
3 February 2005
- Version of record:
15 March 2005
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