Limited storage and recovery of adsorbed gas in shale reservoirs - Insights from experiments and production modeling

Abstract

Gas in thermally mature shale reservoirs is considered to exist as adsorbed volume in organic matter and free gas within pores and voids in natural fractures. Gas in-place is derived from summation of aforementioned volumes. Although industry has adopted laboratory-based adsorption isotherms, quantification is still uncertain and questions on recoverability still linger. This study reevaluated in-place adsorbed gas and post-stimulation recovery. Two proprietary laboratories, using small and large mesh sizes, generated different adsorption isotherms for comparable samples of a Middle East source rock. In addition, review of published experimental studies led to the realization that confining pressures as those in situ were seldomy replicated and derived isotherms exhibited wide variability. A hypothetical scenario, using benchmarked adsorption isotherms illustrated impacts of unreliable adsorbed volume quantification on total gas in-place. From analysis of well production for three shales, matrix transient linear flow persisted for extended periods without indicating influence of boundaries. The flow regime is often matched by considering only free gas porosity. Using a sector model with 1.0 nanodarcy (nD) system permeability in reservoir simulation, a considerable proportion of the adopted grid remained above a benchmarked average critical desorption pressure after long-term post-stimulation drainage. Thus, desorption could be of limited significance in shale production if the flow model was appropriate. This study illustrated uncertainties in traditional concepts for shale gas storage and recovery. Realistic quantification of in-place adsorbed gas was found to require tailoring of laboratory protocols to account for crushed sample sizes and confinement that should match subsurface conditions such as effective vertical stress.