Determining and Averaging Gas Reservoir Pressures
- R.E. Doyle (Shell Oil Co.) | T.S. Young (Shell Oil Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- March 1969
- Document Type
- Journal Paper
- 249 - 250
- 1969. Society of Petroleum Engineers
- 5.6 Formation Evaluation & Management
- 7 in the last 30 days
- 503 since 2007
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The results of this study indicate that the nearest fit to a linear gas material balance plot (the best estimate of initial gas in place) is obtained by correcting the estimated average well pressure for asymmetrical drainage effects, then weighting the individual average pressures by the pore volume drained by each well. A significant error may result in the estimated gas in place if geometric effects or asymmetrical drainage for the individual wells is not considered. This study is confined to one of the major Wilcox gas condensate sandstone reservoirs under the Sheridan field, Colorado County, Tex. Production is from 29 irregularly spaced wells located in the central two-thirds of the reservoir. The last one-fourth of the production period under consideration was influenced production period under consideration was influenced by transient drainage effects.
Production acceleration caused a sustained period of transient pressure behavior that resulted in an erratic plot of the ratio of average pressure/gas deviation (P/Z) vs cumulative production. By contrast, the gas material balance curve should be linear for a volumetric reservoir and should not be affected by transient flow if average reservoir pressure can be determined accurately. The pressures used to prepare this performance curve were based on radial flow assumptions and rate weighting techniques.
Similar material balance curves were prepared by estimating the pore volume and area for each well from the linear or semisteady-state portions of pressure-time plots. These data resulted in three pressure-time plots. These data resulted in three additional P/Z plots: geometrically corrected; pressure weighted by both Pore volume and production rates; and a pore volume weighted pressure based on radial drainage.
Three indicators were used to measure the effectiveness of the four techniques: the magnitude of the standard deviation; a comparison of the extrapolated and actual initial pressure; and the shape of the performance curve in the anomalous region. The first performance curve in the anomalous region. The first two of these indicators are presented in Table 1 and the third is illustrated graphically in Fig. 1.
It is apparent that volumetrically weighting the individual average well pressures is superior to rate weighting for either method of determining average pressure. This is to be expected since wells draining pressure. This is to be expected since wells draining this reservoir have different rates of pressure decline due to variable extent of formation damage and asymmetrical well drainage geometry. In addition, it is clear that smaller standard deviations result if the effects of asymmetrical (non-radial) drainage are considered.
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