Analysis of Recovery Mechanisms for Naturally Fractured Gas-Condensate Reservoirs

Abstract

Abstract The study of depletion performance of naturally-fractured reservoirs has gained wide interest in the petroleum industry during the last few decades and poses a challenge for the reservoir modeler. The presence of a retrograde gas-condensate fluid incorporates an additional layer of complexity to the performance of this class of reservoirs. Upon depletion, reservoir pressure may fall below the dew-point of the hydrocarbon mixture which results in liquid condensation at reservoir conditions. In the case of fractured gas-condensate reservoirs, condensate will first appear in the high-conductivity channels supplied by the fracture network and around the external edges of the matrix blocks which are the zones prone to faster depletion. Even though fracture condensate may have considerable mobility, that is not the case for the liquid formed at the external portions of the matrix. Its presence will hinder the flow of hydrocarbons from the inner portions of the matrix blocks and severely obstruct their recovery. This impairment becomes quite severe for the case of tight, naturally fractured reservoirs where matrix permeabilities may be less than 0.1 md. Since the bulk of hydrocarbon storage resides inside the matrix, it is critical to answer the question whether this trapped gas has been irreversibly lost or not. It is believed that the interplay of Darcian-type flow and Fickian-type flow (multi-mechanistic flow) is the key to answering the questions about depletion performance and ultimate recovery in these reservoirs. This study investigates the recovery mechanisms from a single matrix block surrounded by an orthogonal matrix network, as the fundamental building block for the full-scale system. In this work, we show the dominant flow processes and recovery mechanisms taking place in naturally-fractured gas-condensate reservoirs and describe the depletion performance of these systems, which provides guidance for the development and analysis of this class of reservoirs. Introduction Gas-condensate reservoirs have been the subject of intensive research for many years as they represent an important class of the world's hydrocarbon reserves. In a gas-condensate reservoir, initial reservoir conditions are located between the critical point and cricondenthem of the reservoir fluid, as shown in Figure 1. In general, hydrocarbons in a gas-condensate reservoir are either wholly or predominantly in the vapor phase at the time of discovery. Upon isothermal depletion, once the reservoir pressure falls below the dew-point of the hydrocarbon mixture, a liquid hydrocarbon phase is developed. Appearance of a liquid phase upon vapor expansion (under isothermal conditions) is not possible for pure substances; thus, this behavior is categorized as "retrograde" for this particular type of mixtures. The retrograde liquid may revaporize if depletion continues. The major concern while producing a gas condensate reservoir has to do with the loss of this valuable liquid to the reservoir and the associated impairment in gas productivity. The desirable outcome of a simulation study for gas condensate reservoirs is the development of the best operational production scheme that maximizes recovery with the minimum loss of condensate at reservoir conditions.