Petrophysical Evaluation of Shale Gas Reservoirs: A Field Case Study of Marcellus Shale

Abstract

AbstractSuccessful petrophysical evaluation and stimulation treatments with horizontal drilling and hydraulic fracturing enable the economic development of shale gas reservoirs. Detailed evaluation of shale gas reservoirs before and after stimulation treatments is a prerequisite to increase efficiency and effectiveness of shale gas development. Determination of organic maturity, porosity and original gas in place remains a challenge using traditional petrophysical models due to the complex pore networks and ultra-low permeability of shale. On the basis of a petrophysical model for shale gas reservoirs (Passey et al., 2010), we propose an integrated approach for petrophysical evaluation using analyses of lithology, porosity, fluid saturation, organic maturity, geomechanical properties and initial gas in place.Our petrophysical model for shale gas reservoirs is partitioned into organic matter, clay and non-clay minerals in the solids, adsorbed and free gas, together with capillary-bound, clay-bound and mobile water in the pore space. Vitrinite reflectance is computed in relation to the level of organic maturity (LOM) and kerogen density. Total organic carbon (TOC) is calculated using the Passey method (Passey et al., 1990). Effective porosity of shale gas reservoirs is calculated from algebraic expressions for solid and fluid fractions of the petrophysical model. Compressional and shear slowness logs are used to evaluate the geomechanical properties. Initial gas in place is calculated from free gas and adsorbed gas with porosity, fluid saturation, areal extent, thickness, adsorbed gas storage and organic matter.The methods are successfully applied to a field case in Marcellus shale. TOC (wt.%) calculated by (sonic-density)/resistivity overlay methods for Marcellus Shale are 9.73% and 6.32%, respectively. TOC correlates directly to porosity and adsorbed gas in place occupied within the organic matter. For Marcellus shale, average density and sonic porosities are 6.25% and 3.46%, respectively. The comparison of Young's modulus and the minimum in-situ stress values between Marcellus shale and adjacent formations are used for the determination of the stimulation interval in the Marcellus Formation. Sonic and density logging suggest 2.22 BCF and 4.10 BCF as technically recoverable reserves with an 8% recovery factor. These results from Marcellus shale provide an improved understanding of economic development of unconventional reservoirs.