Fluid storage capacity measurements of core plugs in the laboratory consider pore volume as a function of effective stress. The latter is equal to applied confining pressure – n × applied pore pressure. However, the results are often reported as a function of difference in the applied pressures, because the effective stress coefficient (n) is an unknown. This creates confusion during the interpretation of laboratory data and leads to added uncertainties in the analysis of the storage capacity of the samples under in-situ conditions.
In this paper, we present a new laboratory method that allows simultaneous prediction of the sample pore volume, the coefficient of isothermal pore compressibility, and the effective stress coefficient. These quantities are necessary to predict the fluid storage as a function of effective stress. The method requires two stages of gas (helium) uptake by the sample under confining pressure and pore pressure and measures pressure-volume data. Confining pressure is always kept larger than the equilibrium pore pressure, but their values at each stage are changed arbitrarily. The analysis is simple and includes simultaneous solutions of two algebraic equations including the measured pressure-volumedata.
The model is validated by taking the reference pore volume near zero stress. The reference volume predicted matches with that measured independently using the standard helium porosimeter. For sandstone, shale, and carbonate samples, the estimated pore compressibility is, on average, 10−6 psi−1. The effective stress coefficient is higher than unity and is a linear function of the ratio of the applied pressure values. We present a new graphical method that predicts the Biot coefficient (α) of the rock sample, a fundamental quantity used during the strain calculations that indicates the tendency of the rock to deform volumetrically. A new fundamental rule is found between the applied pressure difference and the effective stress: σe/α = pc − pp. Interestingly, the predicted Biot coefficient values for the shale samples show values between 0.46 and 1.0. This indicates that features of the shale sample, such as mineral variability, fine-scale lamination, and fissility, come into play during the fluid storage measurements.