Improving well performance and associated project economics in oil resource plays rely on developing reservoir characterization capabilities. The need for understanding pore-scale geometry in low porosity low permeability reservoirs has only recently become of importance owing to the now commerciality of these reservoirs through the enabling technology of multi-stage fracture stimulation in horizontal wells.

Conventional laboratory analysis of multi-phase flow in low porosity low permeability systems becomes unpractical with reduced permeability. However, from conventional reservoir characterization, deriving relative permeability from pore structure models utilizing capillary pressure measurements is possible with modern high pressure mercury capillary pressure equipment. Applicability of this method was successfully evaluated by history matching, using numerical simulation, dependent on capillary pressure derived relative permeability and compared to field production in the Bakken formation in North Dakota.

Other useful results from the combination numerical simulation and field production data study include the prediction and observation of an elevated yet constant producing gas oil ratio during the linear flow period (prior to boundary dominated flow.) This observation prevents incorrect recombination ratios for fluid characterization when flowing pressure is below saturation pressure and also prevents faulty calculations of formation volume factor and saturation pressure. Furthermore, the elevated constant production gas oil ratio may be used itself to predict relative permeability.