Pressure data integration contributes significantly to proper reservoir management in dry-gas reservoirs. In this study, we used wellbore and surface pressure data to determine the range of Original Gas in Place (OGIP) and perform production predictions for a large dry-gas reservoir. We developed a process to integrate and process wireline, wellhead, and gas-lines pressure data, resulting in a comprehensive set of static reservoir pressure and dynamic information on well by well basis. Then, we built numerical reservoir simulation models for several geologic interpretations, and performed history matches for the 28 years of field life. The selection of models with high-quality history matches defined the range of OGIP for this field to be from 5.0 to 5.6 Tscf. Productivity Index (PI) and non-Darcy coefficient for each well were obtained from well-test interpretation. Determination of best wellbore flow correlation was accomplished by using wireline dynamic gradients. Surface flow correlations were derived from gas line pressure and production data. The successfully history matched reservoir models were coupled with the calibrated wellbores and surfaces lines. These integrated models were used to forecast production for low, mid and high OGIP values and for various development alternatives.
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