Abstract

After a gas well is hydraulically fractured, the relative permeability of the reservoir to gas may be reduced when fracturing fluid invades the pay zone. This phenomenon reduces the well's potential productivity and is more potential productivity and is more pronounced in low permeability gas pronounced in low permeability gas reservoirs. Efficient clean-up for this fracturing fluid is thus essential in gas reservoirs. As the first step toward this objective, this paper will study the effect of fracturing fluid clean-up using a numerical simulator for gas-water fractured reservoirs.

This study proves that the dimensionless fracture conductivity FCD, (2) dimensionless fracture length, xf/xe, and (3) the formation capillary pressure, Pc, affect the rate and pattern of the Pc, affect the rate and pattern of the clean-up process. It also shows that the pattern of clean-up can cause misinterpretation pattern of clean-up can cause misinterpretation of post-frac pressure analysis tests. A better understanding of the clean-up pattern promotes correct analysis of pressure tests.

This paper also snows that the optimum fracture conductivity necessary to clean up the formation may be much higher than that necessary to produce the reservoir. Thus, the fracture parameters, especially for tight gas reservoirs, should be designed so a fracturing treatment will yield enough conductivity for efficient clean-up of fracturing fluid.

Pressure build-up data are simulated and the resulting synthetic data are analyzed to study the effect of clean-up on the calculation of reservoir and fracture parameters.

Introduction

Hydraulic fracturing is used routinely to stimulate tight gas formations. Without the proper stimulation treatment, a tight gas reservoir may not be produced at optimum conditions, or it may not be economically produced at all. It is very important to design a proper stimulation treatment to optimize production or profit.

A fracturing treatment usually involves the injection of a large volume of proppant laden fluid into a hydraulically induced fracture in the reservoir. As injection continues, the fracture enlarges and part of the fluid leaks into the porosity of the rock. After the total treatment porosity of the rock. After the total treatment volume has been pumped, fluid loss will continue while the pressure in the fracture dissipates. Imbibition may cause treatment fluid to penetrate even deeper into the formation after the fluid pressure in the fracture has equalized with the pressure in the fracture has equalized with the pore pressure of the reservoir. pore pressure of the reservoir. P. 221