Conventional laboratory methods for obtaining relative permeability in oil and gas shales are difficult if even possible to obtain. Insight can be gained from high pressure mercury injection and the relative permeability obtained there from using pore throat models. An integrated approach between relative permeability derived from core laboratory pore throat models with production analysis allowed us to generate new type curves that can be used with field production to determine Brooks Corey wetting phase exponents.

A procedure utilizing laboratory mercury injection capillary pressure on core samples from the Bakken reservoir is used to generate a distribution of wetting phase saturation exponents and residual wetting phase saturations for numerical simulation model input. Model output is normalized by the time and cumulative oil production at the onset of boundary dominated flow to generate type curves that can be used to successfully history match field production in the Bakken formation in North Dakota.

A new type curve has been developed in which oil production and transition from linear to boundary dominated flow are the two requirements needed to derive oil-gas relative permeability. The median of wetting phase saturation exponents for the Middle Bakken formation ranges between values of 2.3-2.6.

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.) Several consequences of this result allows selection of proper application of decline curve analysis techniques, properly determine initial solution gas oil ratio for fluid characterization, and indication of relative permeability prior to the onset of boundary dominated data.

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