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 Kansas Geological Survey Open-file Report 2002-9 |
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| Porosity and gamma log readings were used to calculate permeability for each sand body at each well. Selection of the log-linear permeability-porosity correlation was based on the average gamma log reading across a sand body. For high porosity values, the above correlations project permeabilities in excess of 1 darcy. The maximum permeability measured on Morrow core plugs, from the Minneola Unit, was around 250 md. A permeability cut-off of 500 md was used when the K (permeability) calculated from the correlations exceeded 500 md. |
Equations of generalized capillary pressures were constructed
based on the relationships evident from the entry pressures in
air-mercury capillary pressure curves, the shape of these curves,
and from saturations evident in air-brine capillary pressure analysis.
The relationships between increasing entry pressure, “irreducible”
wetting phase saturations, and the capillary pressure curvature
(reflecting increasing heterogeneity in pore-throat sizes) with
decreasing permeability were utilized to develop equations that
would predict the capillary pressure curve using permeability
as the independent variable.
Corey-type correlations were developed to generate oil-water and
gas-oil relative permeability curves (5 sets) for rocks with different
permeabilities - 3 md, 10 md, 30 md, 100 md and 300 md.
Minneola wells have no historic record of water production during the primary phase. It was, therefore, assumed that the initial Sw, obtained from wireline log analysis, at each producing sand in each well was close to or equal to Swi (irreducible water saturation). Each sand body at each well was initially assigned a relative permeability-capillary pressure set, from amongst the 5 sets, such that Swi value from the set corresponded closely with log-derived Sw.
The reservoir simulation study was conducted in two phases. In the first phase, primary production was history matched. The decline in reservoir pressure could be modeled when a gas-cap was assumed to exist at the onset of field production. The process of matching primary production enabled estimation of the initial distribution of oil and gas saturation in the reservoir. During the second phase, the secondary field production under water injection was matched. This process helped to delineate the permeability variation, existing laterally and vertically, in the reservoir sands. Current fluid levels were available for most wells. Oil production was input for each well and the simulator calculated both the gas and water production. The simulator-calculated flowing bottom hole pressure was matched with the fluid column recorded at the corresponding well.
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Last updated March 2002
http://www.kgs.ku.edu/PRS/Poster/2002/2002-9/P3-01a.html