The low porosity, low permeability sands of the Travis Peak (Hosston) of east Texas and north Louisiana are typical examples of tight gas sand reservoirs which may contain significant amounts of natural gas. Evaluation of such tight gas sands by traditional methods, including the interpretation of wireline logging measurements, has frequently proven inadequate in evaluating the parameters essential to the determination of the economic potential of such reservoirs.

A cooperative well program has been developed between the Gas Research Institute (Chicago, Illinois) and several operators in the east Texas, north Louisiana area. Each well is selected based on geologic, economic and engineering factors. Wells selected establish core points before drilling and take approximately two hundred feet of core. Core measurements include routine porosity, permeability, and grain density. Special core analysis includes restored state permeability, porosity, cementation exponent, saturation exponents, Dean Stark water saturations, elastic moduli, cation exchange capacity, and compressional and shear velocities. Routine analysis is performed over each foot of core. Special core analysis is performed on approximately fifty plugs.

Logging services include dual induction spherically focused, long spaced sonic, litho-density, compensated neutron, electromagnetic propagation, micro-log, natural gamma ray spectroscopy, induced gamma ray spectroscopy, and stratigraphic high resolution dipmeter.

Four wells to date have been included in this cooperative well program. Interpretation models based on the integration of petrographic thin section point count, routine and special core analysis, and wireline log data have been developed. An example of the methodology is presented for the evaluation the Clayton Williams, Sam Hughes, #1 well. These models are routinely used for the evaluation of tight gas sand wells in east Texas.

The models employ a simultaneous solution of linear equations based on porosity log response for lithology, a dual water method for water saturations, and a shale corrected crossplot technique for porosity computation. The Waxman-Smits saturation model is explored as well as a method to determine fluid density from the electromagnetic propagation tool. A method for reconstruction of invalid density data based on gamma ray and sonic log response provides necessary corrections to input data. Results are evaluated and compared to core analysis measurements.

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