Estimation of in situ hydrocarbon saturation of porous rocks from borehole measurements of spontaneous potential

Abstract

It has been previously shown that Nernst’s equation is not reliable for the interpretation of spontaneous potential (SP) measurements acquired in hydrocarbon-bearing rocks. We have examined whether the difference between borehole SP measurements and Nernst-equation predictions could be used to estimate in situ hydrocarbon saturation of porous rocks. For this purpose, a new petrophysical model and a mechanistic finite-difference algorithm for simulating SP borehole measurements in the presence of mud-filtrate invasion are used to establish the limits of detectability of hydrocarbon saturation using only SP logs. We find that the optimal conditions for the detection of hydrocarbon saturation from SP borehole measurements are when (1) capillary forces dominate the process of mud-filtrate invasion, (2) the matrix-pore interface region, known as the electrical double layer, has a relevant impact in the diffusion of counterions, and (3) the electrolyte concentration of drilling mud is greater than that of formation water. We also determine why high values of the endpoint of the water relative permeability favor the detection of hydrocarbon-saturated rocks with the SP log. Using measurements acquired in three key wells within a mature and active hydrocarbon field, three blind tests find that our petrophysical model together with the mechanistic SP simulation algorithm enable the estimation of hydrocarbon saturation from SP borehole measurements without the need for resistivity logs or porosity calculations. The estimation is reliable when the volumetric concentration of shale is negligible, the pore network structure is constant throughout the reservoir, and radial invasion profiles are similar to those observed in the calibration key wells.