Abstract

Coreflooding experiments have been performed using 1 metre long, sandstone cores and a synthetic, six component (C1, C2, C3, C5, C8 and C16) gas condensate fluid, with a dewpoint close to 4,500 psia. The efficiency of equilibrium gas injection for the mobilisation of liquid condensate has been examined under both high and low interfacial tension (IFT) conditions. The volume of liquid recovered and the composition of both phases have been monitored throughout each experiment and the results used to validate a compositional simulator.

Under conditions of maximum liquid dropout and high IFT (sigma .92 mN/m), an average of 6.5% volume of liquid condensate was mobilised in an equilibrium gas injection in a horizontal core, resulting in reduced recovery of the heavier components of the fluid. An improved recovery of 17.2% was obtained in the vertical injection.

Under conditions of low IFT (sigma .04 mN/m) however, 24.1% of the liquid was recovered during injection in a horizontal core and 51.6% of liquid was recovered with vertical injection, giving a much increased yield of the heavier ends.

The recovery efficiency in a straight depletion on a horizontal core to abandonment pressure averaged 18.8%. This is much lower than for the low tension gas injection.

These results are in agreement with other recent studies concerning the influence of IFT and the effects of gravity on gas condensate flow.

Introduction

The significant feature of a gas condensate reservoir is that when the pressure within the formation is reduced below the dewpoint, the fluid separates into a liquid and vapour phase. Thus, a decrease in pressure has caused a change from gas to liquid. This is exactly the reverse of the behaviour one would expect and is known as retrograde condensation. As reservoir pressure declines during production, the reservoir fluid can be visualised as undergoing four state changes:

  1. Single phase gas saturation in which a only gas flows towards the well,

  2. Two-phase saturation with mobile gas and immobile liquid,

  3. Two-phase flow with simultaneous flow of liquid and gas, and

  4. Steady-state saturation in which the liquid dropout is matched by liquid production, resulting in a stable profile.

As pressure drops and production continues, the zones of two-phase saturation, two-phase flow, and steady-state saturation continue to increase.

In the region near the wellbore, the pressure gradient becomes much steeper, resulting in a higher liquid/gas ratio. Depending on the critical liquid saturation and gas flowrate, the liquid saturation may build up very quickly to hinder the flow of gas. In extreme cases the increasing liquid build-up near the well can cause production to cease altogether.

Of particular significance is the irreversible phenomenon that is exhibited by the accumulated condensate [1]. Although a pressure buildup would indicate a revaporisation based on PVT properties, the condensate mass accumulation near the wellbore and the reservoir pressure gradient precludes reverse fluid migration into the reservoir. The expanding zone of liquid accumulation results in permanent damage and the recovery of flow rate will not be realised in a drawdown following a pressure buildup.

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An Integrated Full-Field Compositional Simulation of an Offshore Deepwater Development

26784

Olsen, O.T. Mobil Exploration Norway Inc., Cohen, M.F. Nagarajan, N.R. Mobil E and P Technical Center

SPE Members

Copyright 1993, Society of Petroleum Engineers, Inc.

This paper was prepared for presentation at the Offshore European Conference held in Aberdeen, 7-10 September 1993.

This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. 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. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836 U.S.A. Telex 163245 SPEUT.

Abstract

This paper describes technical enhancements to an existing compositional reservoir simulator, and the improved simulation results achieved in a full field simulation study of the Smorbukk Sor Field. The paper also describes a multi-discipline approach in the execution of a simulation study, and the cooperation between Mobil's U.S. technical center and a European affiliate.

The technical enhancements made to Mobil's compositional simulator PEGASUS were (a) improved interfacial tension corrections to relative permeability in miscible flooding, (b) a variable bubble-point and composition with depth function based upon chemical equilibrium, and (c) application of the Babu-Odeh analytical horizontal well model. These features were not available in compositional reservoir simulators at the time the study was conducted.

The interfacial tension correction for miscible flooding provided production performance predictions that could be used with confidence in the evaluation and selection of the optimum production mechanism for the Smorbukk Sor field. The variable composition with depth correlation demonstrated that a gas cap is not likely to exist considering the measured bubble point gradient. The horizontal well model function confirmed that improved productivity could be achieved with fewer development wells, thus contributing to the selection of the most cost effective development scheme.

The primary purpose of the study was to compare the impact of gas and water injection on ultimate recovery and production performance. Secondary objectives were to determine maximum productivity with the fewest number of production wells, and to maximize recovery at peak production. While simulation results marginally favored water injection, gas injection was considered the preferred production mechanism because of gas disposal considerations.

Introduction

The Smorbukk Sor Field was discovered in 1985 and is located in the Haltenbanken area off the coast of Mid-Norway, in approximately 300 meters water depth. Statoil is the license operator, and partners are Agip, Mobil, Neste, Norsk Hydro and Total. Reserve estimates range from 25 to 32 million sm 3 oil and gas liquids and 22 to 31 billion sm gas.

During discussions by license partners on the development plan of Smorbukk Sor Field, Mobil identified several reservoir management issues which required further study. Mobil initiated a full field simulation study to evaluate, among other things, the viability of water injection as a production mechanism and the validity of using a black oil model to evaluate miscible gas injection. The results of the study were shared with the operator, thereby contributing to the evaluation of field development alternatives.

The overall objective of the reservoir simulation study was to provide reliable input data for the technical and economic evaluation of the Smorbukk Sor development project. The need for the best possible production performance predictions was critical in reducing development risk and maximizing the economics of the project.

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