Use of Dynamic Data and a New Material-Balance Equation for Estimating Average Reservoir Pressure, Original Gas in Place, and Optimal Well Spacing in Shale Gas Reservoirs

Abstract

Summary The average reservoir pressure is a key parameter in material-balance calculations, but its determination is challenging when dealing with shales because of their low and ultralow permeabilities. This paper presents an easy-to-reproduce methodology for calculating the average reservoir pressure from flowing data, and its use in a new material-balance equation (MBE) that considers the simultaneous contribution of free, adsorbed, and dissolved gas. The procedure developed in this paper uses a modified gas-compressibility factor (Z′) introduced in the new MBE. Because Z′ accounts for the combined effect of free, adsorbed, and dissolved gas, then total original gas in place (OGIP) can be determined from extrapolation of the MBE straight line to an average reservoir pressure equal to zero. Drainage area can be estimated on the basis of calculated OGIP and volumetric equations. As such, the methodology offers the potential to help improve well spacing in shale gas reservoirs in such a way that no stranded gas is left in the reservoir, or that excess wells are not drilled in the field. This can help to improve recoveries from shales by assisting in the determination of the optimal number of wells needed to drain a given play efficiently. In conventional reservoirs, a well is shut in, and the average reservoir pressure is determined from the corresponding pressure-buildup test. But, for the case of unconventional shale gas reservoirs, shutting the wells in is unacceptable because of the long time it would require for estimating average reservoir pressure. The methodology developed in this paper for shale gas reservoirs circumvents this problem by using dynamic data. Production data from multistage hydraulically fractured horizontal wells completed in a Canadian shale gas reservoir are used for testing the effectiveness of the new methodology. Comparison of typical well-spacing values vs. the drainage area calculated with the new methodology leads to the conclusion that, probably, only 40% of the gas is being drained efficiently. The novelty of this work relies on the development of a methodology for calculating average reservoir pressure, OGIP, drainage area, and optimal well spacing in shale reservoirs through the combination of dynamic data and a new MBE that considers simultaneously the effects of free, adsorbed, and dissolved gas.