Validation of a New and Cost Effective Technique to Estimate Reservoir Pressure and Permeability in Low-Permeability Reservoirs

Abstract

This paper presents the mathematical basis for a new and cost effective method to estimate reservoir pressure and effective water permeability in low permeability reservoirs. This method, called Baseline/Calibration, has been successfully tested in the Wamsutter field. This approach, which is an alternative to time-consuming DFIT tests and conventional pressure buildup tests, requires injection of water in multiple short stages. Sandface pressure and flow rate are analyzed to estimate reservoir pressure and permeability. We derived analytical expressions which provide a mathematical basis for this method. The analytical formulation assumes piston-like displacement of reservoir fluids with injected water in a water-invaded region and conventional transient flow of gas outside this region. We validated the analytical model and the proposed test-interpretation technique with a numerical simulation model. In addition, we analyzed flow rate and pressure data from a field trial performed in the Almond formation of the Wamsutter field. The results of numerical simulation and the field trial of this method verified that our method accurately determines reservoir pressure with short injection tests. Measurements of reservoir pressure and in-situ reservoir permeability are important for variety of reasons including estimation of ultimate recovery, production forecasting, and optimization of depletion planning. However, conventional well tests methods, another potential source of these properties, are often impractical in unconventional reservoirs because of the long shut-in times required. Introduction Estimation of reservoir properties such as pressure, in-situ permeability, and closure pressure is important for variety of reasons including ultimate recovery estimates, production forecasting, and optimization of depletion planning (Adams et al., 2012). Even though well-known conventional well testing methods may be applicable in principle in unconventional reservoirs, they are often impractical because of long shut-in times (Jin et al., 2013). The industry has previously lacked a practical, cost effective method to estimate formation pressure and permeability. Several methods are currently in use to obtain initial reservoir pressure, pi, and permeability, k, in tight gas reservoirs. The most common method to estimate formation properties in unconventional reservoirs is the Diagnostic Fracture Injection Test (DFIT). The DFIT is used to estimate reservoir pore pressure, transmissibility, and the state of stress in the rock strata in unconventional reservoirs (Cramer and Nguyen, 2013). Two types of analyses are performed in DFIT: beforeclosure and after-closure analysis. There are several benefits for conducting a diagnostic fracture injection test. Formation geomechanical properties, minimum in-situ stress, and fracture closure pressure can be estimated using “before-closure analysis” (Soliman et al., 2013). Moreover, initial reservoir pressure and transmissibility can be determined using “after-closure analysis”. After-closure analysis requires the dominant reservoir pressure profile to be in the pseudo-radial or bilinear flow regime. However, reaching bilinear or pseudo-radial flow regime to estimate