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Abstract

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 multi-faceted 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 Technical Workshops focused on well integrity, demonstrating its increasing importance. However, there is notably little well integrity related literature in the SPE paper library (see references 1-4 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, internal company policies and incorporating “lessons learned” from local incidents. This paper focuses on the operational and well intervention phases of a wells 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 data management system used to monitor the well integrity system status is reviewed.

Introduction

BP Exploration (Alaska) Inc. (BPXA) is the operator of the Prudhoe Bay field, located on the north slope of Alaska. There are approximately 1330 wells in the field including 416 gas lift, 591 natural flow and 323 injectors. Wells produce at rates up to 10,000 BFPD and 100,000 MCFPD. Gas injection wells inject at up to 250 MMCFD. Tubing sizes vary between 3-1/2” to 7” to accommodate the range of rates. Shut-in tubing pressure on natural flow wells is 2400 psi. 20% CO2 concentrations are in the produced gas, resulting in the extensive use of corrosion resistant alloys for well tubulars. A 2000 psi gas lift system pressure is available, resulting in up to 2000 psi shut in pressure on gas lifted wells and the potential for up to 2000 psi of pressure on well annuli. The primary producing formation is consolidated and sand control is not required. Both a waterflood and enhanced oil recovery project using enriched gas are being conducted. Figure 1 illustrates a typical completion and the nomenclature used in Alaska to identify the various annuli. Note API RP90 recommends a format of “A”, “B”, “C”, etc. for naming annuli. Alaska systems have used “IA”, “OA”, OOA” since field startup.