Nanoscale grain boundary channels in fracture cement enhance flow in mudrocks

Hydrocarbon production from mudrock or shale reservoirs typically exceeds estimates based on mudrock laboratory permeability measurements, with the difference attributed to natural fractures. However, natural fractures in these reservoirs are frequently completely cemented and thus assumed not to contribute to flow. We quantify the permeability of nanoscale grain boundary channels with mean apertures of 50–130 nm in otherwise completely cemented natural fractures of the Eagle Ford Formation and estimate their contribution to production. Using scanning electron imaging of grain boundary channel network geometry and a digital rock physics workflow of image reconstruction and direct flow modeling, we estimate cement permeability to be 38–750 nd, higher than reported permeability of Eagle Ford host rock (~2 nd) based on laboratory measurements. Our results suggest that effective fracture‐parallel mudrock permeability can exceed laboratory values by upward of 1 order of magnitude in shale reservoirs of high macroscopic cemented fracture volume fraction. Key Points Completely cemented fractures contain connected nanoscale pores Nanoscale porosity in cement exists in the form of grain boundary channels Fracture cement permeability exceeds reported host rock permeability