Summary
This paper discusses the well-integrity-management system used at the
Prudhoe Bay field located in Alaska. The focus is on systems and processes
implemented to manage the well operations and-interventions phase of a well’s
life. Well integrity is a multifaceted discipline, spanning a well’s life from
design to abandonment. The engineering aspects of well integrity have received
increasing attention in recent years as public scrutiny and resultant
regulatory requirements have evolved. The issue of sustained casing pressure
(SCP) on the annulus of a well has also shaped current
well-integrity-practices. There have been several recent applied-technology
workshops focused on well integrity, demonstrating its increasing importance.
However, there is notably little well-integrity-related literature in the SPE
paper library (see Michel 1995; Attard 1991; Soter et al. 2003; and Bourgoyne
et al. 1999 for a listing of relevant papers).
The well-integrity-management system used at Prudhoe Bay has been evolving
since field startup in 1977. Extensive experience has resulted in the design
and management of systems to ensure safe operations; compliance with industry
standards, regulatory-agency requirements, and internal company policies; and
incorporating “lessons learned” from local incidents. This paper focuses on the
operational and well intervention phases of a well’s life and discusses
evolution of the well-integrity-management system. Current operating practices
are reviewed using BP’s “7 Elements of Well Integrity” categorization. Finally,
the dat- management system used to monitor the well-integrity-system status is
reviewed.
Introduction
BP Exploration (Alaska) (BPXA) is the operator of the Prudhoe Bay field,
located on the North Slope of Alaska. There are approximately 1,330 wells in
the field including 416 gas lift, 591 natural flow, and 323 injectors. Wells
produce at rates to 10,000 BFPD and 100,000 Mcf/d. Gas-injection wells inject
at up to 250 MMcf/d. Tubing sizes vary between 31/2 and 7-in. to accommodate
the range of rates. Shut-in tubing pressure on natural flow wells is 2,400 psi.
20% CO2 concentrations are in the produced gas, resulting in the extensive use
of corrosion-resistant alloys for well tubulars. A 2,000-psi gas lift system
pressure is available, resulting in approximately 2,000 psi shut-in pressure on
gas lifted wells and the potential for 2,000 psi pressure on well annuli. The
primary producing formation is consolidated and sand-control is not required.
Both a waterflood and an enhanced-oil-recovery project using enriched gas are
being conducted. Fig. 1 illustrates a typical completion and the nomenclature
used in Alaska to identify the various annuli [American Petroleum Institute
(API) RP90 recommends a format of “A”, “B”, “C” for naming annuli].
Alaska systems have used “IA”, “OA”, and “OOA” since field startup.
Well integrity is defined in the NORSOK Standard D-010 (2004) (developed by
the Norwegian petroleum industry) as the “Application of technical, operational
and organizational solutions to reduce risk of uncontrolled release of
formation fluids throughout the life cycle of a well.” This is a highly
effective definition and has been adopted by BPXA. It succinctly summarizes
major facets of a well-integrity program.
- It recognizes technical solutions are only one part of the
toolkit—operational and organizational tools should also be evaluated and used
as appropriate.
- The objective is to reduce the risk of formation-fluid release. This
includes both releases to atmosphere and to subsurface formations.
- It covers all phases of a well’s life, from initial design to abandonment,
and during well operations and service work.
© 2008. Society of Petroleum Engineers
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History
- Original manuscript received:
7 July 2006
- Meeting paper published:
24 September 2006
- Revised manuscript received:
10 October 2007
- Manuscript approved:
10 October 2007
- Version of record:
20 May 2008
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