Steady-state two-phase relative permeability upscaling in synthetic and X-ray computerized tomography (CT) coal cores is performed with a three-dimensional (3D) reservoir simulator using an automated control procedure to drive a series of steady-state fractional flows. A clear understanding of relative permeability in coal is important for coalbed methane reservoir management from pore scale to sales point, as it is valuable for helping forecast production. Automation control enables greater continuity between physical corefloods and the numerical upscaling of the same coreflood procedure. Absolute permeability is computed for primitive synthetic core types using the reservoir simulator and is compared to an analytical formulation to validate the use of the simulator solution for core scale property determination.
Relative permeability was computed for synthetic cores considering several scenarios: fracture geometry/abundance (parallel vs. intersecting), rock-type matrix distribution (homogeneous vs. heterogeneous), ratios of matrix-to-fracture permeability (high vs. low), and injection rate conditions [capillary limit (CL) vs. viscous limit (VL)]. Additionally, injection rate conditions were evaluated in the upscaled relative permeability of an X-ray CT segmented composite coal core. Analysis of the upscaled relative permeability curves in the composite and synthetic cores illustrated the impact of each scenario on upscaling relative permeability and suggests that selected characteristics of unconventional cores can potentially be used to delineate parameter dependence in a manner similar to rock type volume fraction and ordering in conventional cores. The consistency of the developed upscaled results with previous studies confirms the applicability of automated process control in core scale multiphase upscaling using a commercial reservoir simulator at varied injection rates and upscaling conditions.