Reservoir Characterization to Inexpensively Evaluate the Exploitation Potential of a Small Morrow Incised Valley-fill Field

Kansas Geological Survey
Open-file Report 2002-9

Core Petrophysical Properties


Fundamental reservoir rock properties needed for reservoir simulation included: porosity, permeability, pore volume compressibility, capillary pressure, oil-water imbibition relative permeability, and gas-oil relative permeability. To calibrate wireline log-measured water saturations with capillary pressure-predicted saturations, Archie cementation and saturation exponent data were also measured and used in log analysis. The project integrated new data and routine and advance core analysis data from previous Morrow investigations. Two Morrow core were available from the Minneola Unit and full-diameter core analysis data were previously measured by commercial laboratories for four wells in the unit. Porosities from these cores and well wireline-logs were used to map and assign gridcell porosities. To understand the relationship between rock lithofacies and petrophysical properties and obtain data for advanced reservoir properties, core plugs were obtained from the two cores. Measured properties were analyzed and integrated to develop general reservoir property models that could be used in construction of a reservoir simulation model and assignment of gridcell properties in the simulator.

General Morrow Petrophysics and Lithofacies

Integration of geology and core analysis for the Morrow Sandstone in southwest Kansas provides an understanding of lithologic controls on petrophysical properties, equations relating petrophysical variables, and guidelines for predicting hydrocarbon producibility in estuarine Morrow Sandstone reservoirs. In previous investigations (Butois et al, 1999; Byrnes , 2000,2001) fifteen estuarine and marine lithofacies have been identified. In general, petrophysical properties are closely tied to lithofacies and interpreted depositional environments. Routine porosity values range from 0 to 22% with in situ porosities averaging 92% of routine values. Fluvial and upper estuarine channel facies exhibit maximum porosity and permeability. Capillary pressure properties of Morrow Sandstone samples differ significantly between lithofacies. At 100 ft of oil column height above free water level, fluvial and upper estuary channel deposits exhibit water saturations below 25% while estuary mouth, restricted tidal flat, and upper shoreface deposits generally exhibit values greater than 50%. Lower shoreface and deeper water deposits generally display water saturations greater than 90%. Water saturations for all facies increase with decreasing permeability. In situ permeabilities range from 0.0001 to 200 millidarcies. Highest porosity and permeability values were measured in the fluvial and upper estuary channel sandstones. Extensive clay drapes, bioturbation, and increasing silt content result in significant decrease in permeability in tidal flat and marine facies. Permeability can be log-linearly correlated with porosity with each facies exhibiting a unique sub-parallel trend. The Archie cementation exponent averages near m=1.81 for fluvial and upper estuary channel facies and is approximately m=2.00 for many of the other facies.

(From Allen and Posamentier, 1994)

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Last updated March 2002