--> Abstract: Predicting Fault-Fluid Behavior and Reducing Development Risks in the Prudhoe Bay Field, Alaska, by Graham Dudley, Richard Fox, Robert Krantz, Stephen Lewis, Philip Cerveny, Russell Davies, Rob Knipe, Dana Coffield, and Dalton Lockman; #90914(2000)

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Graham Dudley1, Richard Fox2, Robert Krantz3, Stephen Lewis2, Philip Cerveny4, Russell Davies5, Rob Knipe6, Dana Coffield7, Dalton Lockman8
(1) BP Amoco UTG, Sunbury-on-Thames, Middlesex, United Kingdom
(2) BP Amoco, Anchorage, AK
(3) Arco Alaska Inc, Anchorage, AK
(4) Petrotechnical Resources of Alaska, Anchorage, AK
(5) ARCO, Plano, TX
(6) Rock Deformation Research, University of Leeds, Leeds, United Kingdom
(7) Alberta Energy Company International, Calgary, AB
(8) Exxon, Anchorage, AK

Abstract: Predicting fault-fluid behavior and reducing development risks in the Prudhoe Bay field, Alaska

The remaining 3.5 billion barrels of reserves at Prudhoe Bay lie in complex parts of the reservoir. 5400 seismic scale normal faults offset strata and locally alter permeability. Faults act as seals and compartmentalize the reservoir; they also act as conduits that induce massive mud losses while drilling. Loss volumes and costs increased dramatically during the 1990's as horizontal drilling intersected more faults. During 1998, trouble time costs linked to lost circulation topped $5 million. Drillers developed a "risk-avoidance" strategy that put significant reserves at risk.

In late 1997 partners committed to an integrated structural analysis of fault behavior, with the goal of predicting and mitigating fault-related risks. During the first phase we reprocessed seismic, compiled a database of faults and observed fluid behavior, completed structural logging of core, analyzed in-situ stress distribution, and looked at fault styles and timing. From these components we produced a set of critical risk factors and a process for fault analysis. Early in 1999, geologists and drilling engineers integrated procedures. Since then, all targets involving faults receive structural risk analysis as a primary component of well planning. Current best practices include seismic coherency, fault juxtaposition and SGR, and local kinematic-dynamic analysis integrated with loss circulation histories. The final well plans selectively avoid faults or cross them at points of minimal risk.

Results in 1999 show significant improvement, both in reduced drilling trouble and costs and in strategies for dealing with faults. The new procedures allow us access to reserves otherwise lost.

AAPG Search and Discovery Article #90914©2000 AAPG Annual Convention, New Orleans, Louisiana