Abstract

A history match for gas and water production from Travis Peak Formation in the Eastern Texas Basin using our numerical simulator was performed, In our simulator, unlike dual porosity models, we used one general equation for both fracture and matrix, and variable computational cells. This enabled us to reduce the size of the computational cell close to fracture size which is closer to real situations in the gas reservoirs, and in turn, we believe our prediction is more accurate and reliable. Other advantages of our approach are:

  • the flow equations in the fracture are not oversimplified, and

  • the fracture system is not restricted to network of fractures.

Gas and water production predicted using our modified program agreed well with 30 days of production data from SFE No. 1 in Travis Peak formation. The effect of permeability, porosity, capillary pressure, viscosity of fracturing fluid, the level of invasion of pressure, viscosity of fracturing fluid, the level of invasion of formation by fracturing fluid and presence of single and multiple fractures on production were studied, Our calculation showed that interfacial forces between gas, water and porous medium are the most sensitive parameter effecting the enhancement of the gas production. Furthermore, the increase in overall mobility of the production. Furthermore, the increase in overall mobility of the porous medium of reservoir due to presence of the fractures does porous medium of reservoir due to presence of the fractures does not have significant effect on production in comparison with the location and distribution of the fractures.

Introduction

Among the unconventional resources of gas, tight sand reserves have drawn a significant amount of attention for economical gas recovery using massive hydraulic fracturing. Sharer and O'Shea (1986) estimated that over 500 trillion cubic feet of natural gas may be recoverable from low permeability sandstones located in the Western and Eastern United States. Although there is a large potential for development of these resources; however, significant potential for development of these resources; however, significant stimulation is required to attain feasible production capabilities. The use of massive hydraulic fracturing, at present, is the most promising technique for optimum production.

Tight gas sands are characterized by macroscopic features such as high capillary pressures, low porosity, high irreducible wetting phase saturation, and low permeability (less than 1 md or 987 × 10-6 phase saturation, and low permeability (less than 1 md or 987 × 10-6 m2). Economic production of gas from the rock matrix generally requires that flow to the well bore be aided by natural or induced fracture systems. However, the production rate is still set by the rate of flow of gas from the matrix into the fracture system. Therefore, a knowledge of fluid flow in the matrix is required. Although there are several experimental studies in the literature for flow properties in tight sand such as: Walls et al. (1982), Chowdiah (1986), Seoder (1986), Arastoopour et al. (1990), Soeder (1989), and Soeder and Chowdiah (1988). However, there is need for more experimental results to determine the behavior of naturally and hydraulically fractured tight sand formations.

In the literature there are only a few studies regarding the theoretical analysis of single and multiphase flow in tight sand formations, Newberg and Arastoopour (1986) and Chowdiah and Arastoopour (1983) and Arastoopour and Semrau (1988) are among the first who developed a mathematical model to describe transient flow of gas through low permeability tight sand media, Holditch et al. (1988) developed a computer simulator to describe flow behavior in tight reservoirs of Travis Peak formation. Parallel to Holditch's et al. development of reservoir simulator for tight sand reservoir we modified Black Oil Applied Simulation Tool, BOAST (Keplinger et al. 1982), for two-phase flow of gas and water in low permeability tight sand reservoirs under production. Our modified program is capable of describing flow of gas and water in a tight sand reservoir, as well as a tight sand reservoir with high permeability of fractured layers.

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