Field-Scale Modeling of Deep Coalbed Methane Productivity of the No. 8 Coal Seam in the Ordos Basin

Abstract

Deep coalbed methane (DCBM), also named coal rock gas (CRG), has emerged as an important unconventional gas resource in China and worldwide. Compared to conventional coalbed methane reservoirs, deep coal seams exhibit more complex gas transport behavior due to the coupled effects of adsorption–desorption, matrix diffusion, and stress-dependent permeability. The DCBM production characteristics remain insufficiently understood. In this study, we developed a numerical reservoir model to evaluate the productivity potential of DCBM reservoirs. The hydraulic fracturing process is explicitly modeled to capture the influence of remaining fracturing fluids on fracture conductivity and stimulated reservoir volume development. We calibrated permeability evolution with effective stress through history matching. The production behavior of a single horizontal well is analyzed. We conducted sensitivity analyses to determine the impacts of Langmuir parameters, diffusion coefficients, gas content, and free-gas fraction on production performance. In addition, the effects of horizontal well length, well spacing, and row spacing on estimated ultimate recovery (EUR) are investigated. Our results show that hydraulic fracturing enhances fracture conductivity mainly within the stimulated reservoir volume (SRV), while pressure propagation outside the SRV remains limited. For a single horizontal well, cumulative gas production reaches 6646 × 104 m3 after 14 years. Free gas contributes about 65% of first-year production, whereas adsorbed gas becomes dominant later, accounting for 57% of the final EUR. Well-pattern optimization suggests an optimal well spacing of 350–400 m. Under 400 m well spacing and 100 m row spacing, the interference rate is only 2.1%, with an average EUR of 6485 × 104 m3 per well. The results provide practical guidance for production forecasting and development optimization of DCBM reservoirs.