Determination of Archie's cementation exponent for shale reservoirs; an experimental approach

Archie's equation has been widely used in well-log interpretations for the fluid saturation calculation from electrical resistivity measurements. Though constrained standard Archie parameters are accepted in sandstone and carbonate reservoirs, the same parameters are more complex to define in Shales. Indeed, the use of standard Archie parameters on shale reservoirs proved to be inaccurate due to the heterogeneities and ultra-tight nature of those formations, and also the excessive conductivity exerted by the strong Cation Exchange Capacity (CEC) property of clays particle surfaces. This study aims to determine Archie's cementation exponent (m) from two Australian shales (oil-shale and gas shale with a maximum of 60% clay content) with the minimization of the CEC effect using high saline pore fluid. The shales were first fully saturated under hydrostatic pressure for about two weeks before conducting electrical resistivity and Nuclear Magnetic Resonance (NMR) laboratory measurements. The resistivity measurements were conducted under ambient conditions, though a small 50 psi axial pressure was added to improve sample-electrode surface contact, and under 2800 psi confining pressure to simulate the reservoir condition. NMR was measured in ambient conditions only to compute the effective porosity (excluding clay bound water volume), and to detect potential residual oil after oil removal treatment. The oil cleaning process enhances the development of micro-fractures but their effects are negligible on the NMR effective porosity (<5%). The results indicated that Archie m is stress-dependent averaging around 2.48 in ambient conditions and increasing to 2.70 in reservoir conditions, an 11% increase that is similar in both oil- and gas-shales. However, Archie m is systematically higher in oil shales despite oil cleaning (m > 3) and lower in gas shales (m < 2.55).