Effect of Fracturing Fluid Properties on the Flowback Efficiency of Marine and Continental Transitional Shale Gas Reservoirs in Ordos Basin

The characteristics of marine–continental transitional shale reservoirs and the performance parameters of fracturing fluids, such as pH and mineralization, play a crucial role in influencing the flowback efficiency of these fluids. Excessive retention of fracturing fluids within the reservoir can lead to a significant decrease in permeability, thereby diminishing gas well productivity. This study investigates shale samples sourced from the marine–continental transitional shale formation in the eastern Ordos Basin, along with field-collected fracturing fluid samples, including formation water, sub-formation water, distilled water, inorganic acids, and organic acids, through flowback experiments. The results show that: (1) the flowback rate of shale fracturing fluids exhibits a positive correlation with salinity, with low-salinity fluids showing a dual effect on clay mineral hydration. These fluids increase the pore volume of the sample from 0.003 cm3/g to 0.0037 cm3/g but also potentially reduce permeability by 31.15% to 99.96%; (2) the dissolution effects of inorganic and organic acids in the fracturing fluids enhance the flowback rate by 16.42% to 22.25%, owing to their chemical interactions with mineral constituents; (3) in the development of shale gas reservoirs, it is imperative to carefully devise reservoir protection strategies that balance the fracture-inducing effects of clay mineral hydration and expansion, while mitigating water sensitivity damage. The application of acid preflush, primarily including inorganic or organic acids, in conjunction with the advanced fracturing techniques, can enhance the connectivity of shale pores and fractures, thereby improving fracture conductivity, increasing the flowback rate of fracturing fluids, and ensuring sustained and high gas production from wells.