A New Method for Determining a Well's In-Place Hydrocarbons From a Pressure Buildup Test

Abstract

Abstract A method for estimating in-place hydrocarbons from pressure buildup tests has been derived and applied to actual well test data. Four examples utilizing this new method are presented and compared with in-place hydrocarbon estimates determined by other methods. In addition, a derivative application of the method is described for calculating stabilization tune of gas wells which have well-defined production-pressure decline curves from which reliable estimates of gas in place can be made. The method presented in this article is not based on new theory; the calculations can easily be done on a slide rule or a desk calculator, and most of the various reservoir parameters which are commonly determined from well logs or core analysis are not required. Introduction Most routine approaches for gas-in-place determinations require that years of pressure-production data be available before original pore volume estimates, based on log interpretation, can be verified. The original volumetric reserves estimates can often vary by a factor of two or more from results obtained by actual production data. Unfortunately, most significant economic decisions must be made early in the life of a well, often before reliable reserves information is available. In the case of oil wells. the original oil-in-place volume may never be verified from production decline curves unless these are supplemented with period: c bottom-hole pressure tests and material balance determinations are made. Hydrocarbon pore volume estimates require values for porosity, water saturation, drainage area and reservoir thickness. Porosity, water saturation and reservoir thickness can be obtained from well logs; however, they are normally applicable to only the vicinity adjacent to the wellbore. Generally, gas-bearing reservoirs are heterogeneous and erroneous reserve estimates may be caused by assuming various parameters constant throughout the reservoir. Gas reservoirs are normally drilled on much wider spacing than oil reservoirs and, as a result, core and well log data are assumed representative of a relatively larger area in a gas reservoir. Hydrocarbon pore volume estimates for each new well usually assume the drainage area to be equal to the well's unit acreage even if the well is far removed from the center of the unit. Pressure transients which result from drawdown, buildup, fall-off or interference tests contain much quantitative information about the well and the reservoir. Proper analysis of these tests permits the engineer to determine wellbore damage, effective capacity (kh), static reservoir pressure, distance to boundaries or flow restrictions, reservoir size and stabilization characteristics. Carefully followed well test procedures and methods of analysis can also result in reliable pore volume estimates. A method was derived by Park Jones' for determining the reservoir limits from a buildup test. By combining the reservoir limits radius with well log parameters, it is possible to determine oil or gas reserves. The new method developed in this article, and illustrated by examples from field tests, does not require various well log parameters. The gas in place determined from buildup tests agrees remarkably well with volumetric calculations based on well log and geological interpretations. The method has also been adapted for use in determining oil in place from buildup tests on oil wells. One example of this application is presented which also agrees closely with the amount of oil in place determined volumetrically by the operator of the well. The calculations can easily be made on a desk calculator and none of the various well log parameters are required. Development of Equations The most commonly used equations in unsteady-state analysis are those developed by Muskat, van Everdingen and Hurst and Horner. Many authors have investigated and accepted these equations as valid. JPT P. 859ˆ