Reservoir Management of the Prudhoe Bay Field
Authors: Simon Andrew D. , Petersen Eric J. 
Published: December 2007

Abstract
The Prudhoe Bay field, the largest oil field in North America, was brought on production in 1977 with the start-up of the Trans-Alaska Pipeline System. Initially, ultimate recovery was estimated to be 9.6 BSTB of hydrocarbon liquids with a maximum oil production rate of 1.6 MMSTB/D. However, due to a sequence of reservoir management decisions and a series of major facility additions, total ultimate recovery is now estimated to be 13 BSTB or more, a 35% increase over initial estimates. This paper discusses the various studies, technology developments, and decisions that led to the plan of development and operation of the field.
Major integrated engineering studies of the surface facility systems and the reservoir displacement processes helped to optimize the reservoir management of the field. Over the course of the past twenty years, major surface facility expansions have occurred, resulting in average gas production of 7.5 Bscf/D, with most produced gas re-injected into and cycled through the reservoir's 30 Tscf gas cap; the world's largest miscible gas EOR project, which will ultimately cover nearly 60,000 acres; and manufacture of more then 80 MSTB/D of NGLs.

Introduction
Discovered in 1968, the Prudhoe Bay Field is a massive sandstone reservoir complex covering over 200 square miles. The "main" portion of the reservoir consists of a large oil rim overlain by a significant gas cap (m&gt;0.6) which, together, contained over 20 BSTB of hydrocarbon liquids and approximately 46 Tscf of free and associated gas originally in place. Almost three decades of study have led to over 16 billion dollars of investments, and the field recently passed its 20th year of operation with cumulative production to date actually exceeding the original estimate of ultimate liquid recovery.
Estimates of recoverable liquids have grown from 9.6 to 13 BSTB or more. Often, such reserve "appreciation" results over time due to better understanding of reservoir volumetrics and/or better than expected production performance.1 Increases at Prudhoe, however, are attributable to sophisticated field development which evolved from an ongoing application and enhancement of technology. Such applications have led to implementation of the world's largest gas cycling and miscible gas EOR projects, and increases in reservoir penetrations relative to the original plan of development by nearly a factor of three (Table 1). Prudhoe's development has required the simultaneous management and exploitation of a wide range of recovery mechanisms to maximize recovery. Accurate performance prediction and understanding of these mechanisms has been paramount for thre major reasons:Small changes translated to large reserve values due to the reservoir quality and size. Hence, the stakes of development decisions were large.The scale of Prudhoe's base infrastructure implied that the magnitude of investment decisions would be large and the lead times required for facility design and construction would be long. Hence, the value of being able to "look ahead" of reservoir performance with confidence was at a premium.Progressive development of a fine-tuned highly integrated facility/reservoir system steadily increased the complexity of evaluating new projects that would potentially disturb an existing balance.