(185k) Laboratory and Simulation Workflow to Model Confined Gas-Flow Alteration in a Source Rock and Its Compositional Dependence

Objectives/Scope: For multistage hydraulically fractured horizontal wells in source-rock reservoirs, production rates during primary depletion and enhanced recovery processes are impacted by small pore sizes of the rock. A novel workflow is presented - for a given source rock, it quantifies the magnitude of gas-mobility alteration due to confinement using laboratory core-plug experiments, and enables reservoir simulation to capture this behavior, including its dependency on gas composition.

Methods/Procedures/Processes: At different pore pressures, new methods in the literature are used to determine permeability of the rock’s matrix only, absent any effects from fractures in the rock. The trendline of these permeabilities vs. pressure can be used to determine the proper value of characteristic pore radius for the Knudsen number, among the large range of pore radii existing in such a rock, by invoking known relations (Helmholtz-von Piotrowski, Beskok-Karniadakis, etc.) in a novel way. The equation is used along with the resulting radius value to provide gas-mobility adjustments as a function of pressure and temperature for each gas component used to represent the in-situ fluids. These adjustment-factor tables are uniquely used to alter existing gas-viscosity tables in the simulator input. Since it is gas resistance-to-flow that is affected as pore-network geometry remains unchanged (because effective confining stress is the same in all tests), gas-flow confinement effects are most rigorously portrayed using the gas viscosity, rather than the rock permeability, which would also apply to adjacent liquids that do not undergo any confinement alteration. Moreover, this method allows the simulator to model the compositional dependence of the confinement effects on gas mobility, a novel capability.

Results/Observations/Conclusions: A workflow is demonstrated using results of new experiments on a source-rock sample to compute effective pore radius, taking into account the gas used in the flow experiment, and the temperature and pressure. A computed table of adjustment factors are shown for each of several typical gas components. Adjusted viscosity tables are then presented. The effect of this method on predicted recovery behavior is addressed.

Applications/Significance/Novelty: This work is novel for 1) its unique method of experimental quantification of the Knudsen number’s characteristic pore radius, enabling proper computation of the gas-mobility adjustment factor; 2) using gas viscosity instead of permeability to capture the degree of gas-mobility alteration owing to confinement; and 3) capturing the compositional dependence of gas-mobility alteration due to confinement in reservoir simulation. Invoked in ensemble, these improvements lead to more rigorous simulation results.