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Abstract: Variations in Cementation Exponent (m) and Fracture Porosity, Permian Delaware Mountain Group Sandstones, Reeves and Culberson Counties, Texas

Markus D. Thomerson, Marion D. Arnold, George B. Asquith

To calculate accurate volumetric oil reserves in the Permian Delaware Mountain Group, reliable values for cementation exponent (m) are required in addition to the other reservoir parameters.

The porosity in these siltstone and very fine-grain sandstone reservoirs is intergranular and therefore the cementation exponent should be approximately 2.0. However, crossplots of core derived porosity vs. the formation resistivity factor (Fr) indicate an average cementation exponent (m) of 1.80. The lower cementation exponent is a result of minor amounts of fracture porosity. Comparison of the Delaware Mountain Group porosity vs. the Fr crossplot with the laboratory data of Rasmus (1987), reveals a similar decrease in Fr with a decrease in porosity due to the presence of a 1% fracture porosity.

The lower cementation exponent (1.80) results in the calculation of substantially lower water saturations, which increases the amount of volumetric oil reserves. Analysis of three zones in the Bell Canyon and Cherry Canyon formations of the Delaware Mountain Group using standard methods of calculating water saturation resulted in volumetric oil reserves (based on 40 ac drainage) of 1.37 to 1.42 million bbl. However, using a cementation exponent of 1.80 resulted in volumetric oil reserves of 1.55 million bbl. The 9% to 13% increase in volumetric oil reserves from only three zones in the Bell Canyon and Cherry Canyon formations illustrates the critical importance of combining core analysis with log analysis when doing volumetric reserve calculations.

AAPG Search and Discovery Article #90980©1994 AAPG Southwest Section Meeting, Ruidoso, New Mexico, April 24-26, 1994