Abstract

In waterflooded reservoirs, it is still possible to recover a significant amount of residual oil by enhanced oil recovery. Immiscible water-alternating-gas (WAG) injection is one of the well-established methods for improving oil recovery. However, the mechanism of three-phase flow in the process has not been well understood and prediction of the three-phase permeability has been highly uncertain.

This paper presents the results of immiscible WAG injection in a water-wet micromodel. During immiscible gas injection after an initial waterflood, gas moved through the residual oil paths, and residual oil was pushed either toward the production end of the model or into previously waterflooded channels. Breakthrough of gas occurred at about 0.25 PV for the micromodel used in this work. Further gas injection beyond the breakthough volume increased oil recovery only very slightly. When water was injected following gas injection, it flowed through channels that were created in the initial waterflood. Most of these residual oil that had been pushed into these waterflooded channels by the previous gas injection was produced. The mechanism of gas, oil, and water flow during immiscible WAG injection was analyzed. The observations and analysis provide insight into the flow behavior of a three-phase system in the immiscible WAG process, which is important in the modeling of the process.

Introduction

A problem with gas injection (both miscible and immiscible) is the inherently unfavorable mobility ratio and the resulting poor volumetric sweep in reservoirs. Injection of gas as slugs alternated with water slugs, water-alternating-gas (WAG), is the common practice presently used for controlling gas mobility. The WAG technique is indeed a combination of two oil recovery processes: gas injection and waterflood. However, the use of the combination of the two processes has resulted in some problems that have perplexed the industry since the pilot test studies were implemented in the early 1970s.

In the immiscible gas injection process, the portion of the injected gas dissolved in the oil reduces the oil viscosity. In addition to reducing viscosity, the dissolved gas also swells the oil, so for a given fixed residual oil saturation, less stock tank oil remains after a waterflood. These two mechanisms have been demonstrated by numerous laboratory PVT and coreflood tests. Laboratory coreflood experiments also showed that the free gas displacement is a very important mechanism for immiscible gas injection. Analysis of results from a tertiary CO2 injection field test revealed that incremental oil production by immiscible CO2 injection has two components.1 The first is an instantaneous response, probably resulting from gas displacing oil that was not being displaced by water. The second component is the long-term effect caused by viscosity reduction, swelling, and relative permeability alteration. The mechanism of instantaneous response, i.e., a sharp increase in the oil production rate during a CO2 slug injection, is still not well understood. Spival et al.1 also realized that N2 contained in the CO2 stream is a complicating factor that reduces the solubility of CO2 in the oil and, on the other hand, may decrease the residual oil saturation by being trapped in the reservoir.

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