Fine Characterization of Pore Structure to Study the Migration and Retention Behavior of Fracturing Fluids in Normal Pressure Shale Gas Reservoirs: A Case Study of Longmaxi Formation in the Pengshui Area

Summary The Pengshui area, recognized for its normal pressure shale gas reservoirs, exhibits complex fluid migration behaviors due to a high proportion of small-pore porosity and significant microscale effects. These factors result in distinctive production characteristics, such as longer dewatering cycles, higher flowback rates, and reduced well production capacity, compared with overpressured shale gas reservoirs. In this study, we explore the migration and retention behaviors of fracturing fluid concerning lithofacies and pore structure differences, emphasizing the flowback process following fracturing. Laboratory simulation experiments were performed on 12 Longmaxi shale samples from the PY-1 well, categorized by petrographic phases, total organic carbon (TOC) content, and mineral composition. Pore structures were examined using various methods, including X-ray diffraction, field-emission scanning electron microscopy (SEM), nuclear magnetic resonance (NMR), low-temperature nitrogen adsorption, and high-pressure mercury injection. The results indicated that the shale samples from the PY-1 well could be divided into two lithofacies—clay-rich siliceous shale and mixed-siliceous shale. The clay-rich siliceous shale displayed narrow fissure porosity, while the mixed-siliceous shale featured organic micropores and microcracks. Pore structure characterization revealed that the clay-rich siliceous shale developed a “tree-like” mesopore network, facilitating fluid migration, while the mixed-siliceous shale had a “micropore-microcrack” network that promotes fluid retention. The permeability and porosity of these samples were classified as medium, with high permeability attributed to the extensive fractures in the PY-1 well. Simulating the flowback process, we demonstrate that fracturing fluid was distributed across the entire pore size range due to capillary pressure differences, with pressure transmission generating new fractures at proximal fracture faces and enhancing connectivity. Micropores, particularly in mixed-siliceous shale, adsorbed water and competed with methane for adsorption. The findings also indicated that the pore structures in clay-rich siliceous shale were more sensitive to pressure changes, making them susceptible to Jamin’s effect, whereas mixed-siliceous shale, with its lower connectivity, showed less variation in water content under pressure fluctuations but exhibited greater adsorption capacities. This study offers insights into the role of lithofacies and pore structure in the migration and retention behaviors of fracturing fluid.