Pore-Pressure-Prediction Model Investigates Hydrocarbon Generation

Abstract

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 2021-5410, “A New Pore-Pressure-Prediction Model for Naturally Fractured Shales and Stacked Plays: The Effect of Active Hydrocarbon Generation—A Powder River Basin Case Study,” by Daniel Orozco and Roberto Aguilera, SPE, University of Calgary. The paper has not been peer reviewed. _ The authors introduce a physics-based method for explicit pore-pressure prediction in naturally fractured shale petroleum reservoirs. Failing to account for the actual cause of overpressure leads to underestimation of the pore pressure at depth. This is particularly important in shales that have not yet reached pressure equilibrium because of fluid expansion caused by currently active or recent-in-geologic-time hydrocarbon generation. Background The work flow is tested with data from the Powder River Basin, but it should be extendable to other shales worldwide. The approach should prove particularly useful in those undeveloped plays with limited or no regional experience, as in the case of the Cretaceous La Luna shale in Colombia. The computer code for running the pore-pressure work flow described in the complete paper was written in open-source Python programming language. The script makes extensive usage of different Python libraries. The complete paper includes a substantive section devoted to a discussion of hydrocarbon generation as an overpressure mechanism in shales. Overpressure by fluid expansion in low-permeability rocks occurs when the volume of pore fluids increases with little change in porosity and at a rate that does not allow the effective dissipation of fluids. The fluid-expansion mechanisms include clay dehydration, smectite-illite transformation, hydrocarbon maturation, and oil cracking. The magnitude of overpressure from fluid expansion depends on the rate of volume change, which is rather slow for the burial rates and temperature gradients observed in most basins. It follows that, in unconventional basins that encompass source rocks with high organic content and very low matrix permeabilities, the maturation of kerogen to oil and gas and oil cracking have the potential to create high-magnitude overpressure. An important aspect of overpressuring caused by hydrocarbon generation is that it has the potential to create natural “hydraulic” fractures. The most-likely explanation for the basinwide occurrence of overpressuring in the Rocky Mountains is the thermal generation of oil and gas. Role of the Biot Coefficient Researchers have demonstrated that the Biot coefficient is equal to the quotient of the change in permeability with pore pressure (at constant confining pressure) over the change in permeability with confining pressure (at constant pore pressure). The authors write that previous work indicates that any deformations in fluid-saturated rocks are exclusively the result of variations on the Biot’s (not Terzaghi’s) effective stress. Because effective stress governs rock deformation, it follows that, whatever the mechanism causing the rock deformation, it should be accounted for and properly explained by the inclusion of the appropriate in-situ Biot coefficient. This statement is the cornerstone of the pore-pressure-prediction work flow.