Sedimentary Rock Compressibility Related to Porosity Under Hydrostatic Loading: New Approach with Uniaxial Corrections

Abstract

Rock compressibility has great influence in the original oil in place estimation, history matching, and production forecasting. The majority of the reservoir engineers consider the compressibility as a constant throughout the life of a field, but it is well known that rock compressibility is pressure and porosity dependent. During the life of an oil field, the pore pressure decreases with oil production, which increases the net pressure over the reservoir which induces changes in porosity and in compressibility. Neglect compressibility variation may induce several errors during reservoir simulation. To reduce errors, and to provide a simple and easy procedure for calculation of rock compressibility, this paper presents the correlation between rock compressibility and porosity under hydrostatic confining test, as well as the corrections made to translate unrealistic hydrostatic data into more representative uniaxial data. The measurements were developed in 5 sandstones and 5 carbonate rocks with a diversified range in porosity and rock strength to obtain results more capable to describe any other set of data. The results of the corrections were then plotted against porosity and a new general equation was derived from the plots through data fitting. The new equation proved to be very representative, but it faced an issue related to the inverse problem. To fix the problem, the Poisson ration was applied to the general equations to capture the mechanical characteristics of the rocks. The results showed that rock compressibility has a direct relation to porosity. Further, the conversion factors displayed high efficiency in the translation from hydrostatic data to uniaxial data, and hydrostatic compressibility may increase the errors during estimation of the volume of original oil in place by a factor of 1E+6 STB. Also, the error in the volume of OOIP calculated using CpA and CpAc varies from 0,22% to 0,05%, and the difference between CpA (converted) and CpAc (estimated) is around ±1,8%. Therefore, this work aims to correct the sedimentary rock compressibility obtained under hydrostatic compressional tests and establish a new relationship between compressibility and porosity. These procedures focus on the reduction of laboratory analysis, increase the quality of reservoir forecasting and reservoir monitoring.