Reservoir Simulation of a Collapsing Gas Saturation Requiring Areal Variation In Bubble-Point Pressure
Authors: Steffensen R.J. , Sheffield M. 
Published: December 2007

This paper was prepared for the 3rd Numerical Simulation of Reservoir Performance Symposium of the Society of Petroleum Engineers of AIME, to be held in Houston, Tex., Jan. 10–12, 1973. Permission to copy is restricted to an abstract of not more than 300 words. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.

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This paper describes modifications to a conventional three-phase, two-dimensional reservoir simulator which are invoked in waterflood studies when a gas saturation is collapsed at pressures below the initial bubble-point pressure (Pb). These pressures become the new Pb values, and modified oil fluid property data are used for pressures above property data are used for pressures above the new Pb. The necessity of such modifications is demonstrated by an example problem.

Introduction

The development sequence for many oil reservoirs is primary depletion followed by waterflooding. As reservoir pressures decline below the saturation pressure during primary production, gas is evolved from the oil. When production, gas is evolved from the oil. When water injection is initiated, the downward pressure trend is reversed - at least in some pressure trend is reversed - at least in some portions of the field. The pressure rise due portions of the field. The pressure rise due to injection causes the free gas to go back into solution in the oil. But gas availability may be limited, since much of the gas previously evolved may have been removed from a previously evolved may have been removed from a given region by production and/or migration. Also, part of the remaining gas may be displaced ahead of the oil bank during the waterflood. Thus in part or all of the reservoir, the available free gas will be "collapsed" (i.e., displaced and/or put back into solution) at pressures below the original bubble-point pressure. In these regions, Pb will become a function of position and time. This situation occurs in many waterfloods. Reference 1 indicates that, typically, a pressure increase of 10 to 20 percent is sufficient pressure increase of 10 to 20 percent is sufficient to collapse all of the gas trapped in the oil bank.

For pressures above the new Pb, the original fluid property data for the oil are no longer applicable. Thus simulation of such injection projects requires detection of these variable bubble-point situations, plus special handling of fluid property data thereafter.

A conventional (i.e., constant Pb) three-phase, two-dimensional reservoir simulator has been modified to provide these features. The new simulator, called a variable bubble-point model, has been used in extensive studies of more than ten waterfloods, mainly in West Texas reservoirs.