The advancement of technology in producing tight gas sands requires rock property measurements involving the flow of fluids in cores. The purpose of this paper is to present measurements of absolute permeability, total porosity, capillary pressure, and gas relative permeability on several Travis Peak cores. Even though such measurements are difficult to obtain, the resulting values are needed to accurately model gas flow in such reservoirs.
A transient test method developed in the early portions of this research has been used to measure absolute permeability and total porosity as a function of net stress. The net stress on the cores was increased to simulate the depletion of the reservoir pressure, and the results can be used to observe the effect of formation compressibility on permeability and porosity.
A study of gas slippage was performed using the transient test method. Several parameters, including gas molecular weight, net stress, and flow rate, were varied to determine their relationship with gas slippage. It was found that gas slippage can be affected by the slot-pore geometry found in highly cemented, low permeability formations.
Since water is pumped into low permeability formations during stimulation treatments, two-phase rock property measurements are important if one wishes to model the effects of the water upon gas recovery. The measurement of capillary pressure and gas relative permeability have been investigated in this study.
The ultracentrifuge presents a practical method for determining capillary pressures in low permeability cores. Several cores were run and the capillary pressure data are presented. Saturation equilibrium was determined by monitoring each centrifuge speed over a 24 hour period. An analysis of the continuity of the displaced phase has also been performed.
A new method recently developed in this research has been used to measure the gas relative permeability and water saturation simultaneously. The new method presents a rapid means of generating the entire gas relative permeability curve. The results from two Travis Peak cores are presented.
In summary the results of these measurements on absolute permeability, total porosity, capillary pressure, and relative permeability present a description of the rock properties for studying fluid flow in a typical tight gas formation. The system of measurements can be performed on any low permeability core on a routine bases.
The need for studies of reservoir cores for the advancement of technology in the petroleum industry has been well established. Measured values of permeability and porosity can be used to define the flow characteristics of a formation. In low permeability reservoirs, relative permeability and capillary pressure are necessary to properly design drilling and stimulation programs. Flow characteristics, such as permeability and gas slippage, and the parameters that effect these flow characteristics must be measured accurately. From these results, mathematical models and relationships can be improved to better simulate the flow of fluids in low permeability reservoirs.