Evaluation of permeability damage in tight sandstone from hydroxypropyl guar fracturing fluids after prolonged exposure

Hydraulic fracturing fluids used in tight gas wells may remain in the formation for extended periods before flowback because of operational and environmental constraints. This prolonged shut-in period can increase the potential for additional formation damage. This study evaluated the long-term impact, up to 6 months, of a hydroxypropyl guar-based (HPG) cross-linked fracturing fluid on the permeability of Scioto tight sandstone under high-temperature reservoir conditions. It represents one of the first systematic investigations of such extended fluid exposure durations. Core flooding experiments were conducted to determine the initial and regained permeability after thermal aging at 145 °C for 1, 3, and 6 months. FTIR, XRD, and TGA analyses were performed on the dried unbroken fluid, broken fluid, and recovered residue to characterize polymer degradation and the formation of inorganic solids. The core flooding results showed limited permeability impairment after the initial cleanup, reaching up to 11%. However, the results indicate a progressive decline in regained permeability with longer aging periods, with the loss becoming partly irreversible and reaching an additional 38% after 6 months under the tested conditions. SEM–EDX analysis showed that carbon and oxygen were the dominant elements in all samples, while boron was detected at every fluid stage and in the residue. XRD confirmed that the residue consisted mainly of boron-bearing solids (B₂O₃/HBO₂) together with amorphous polymeric material. Treatment of the residue with HCl at 145 °C for 40 h substantially reduced the amount of insoluble material, leaving mainly large coarse particles within two dominant size ranges, from several hundred to about 1,000 µm and around 2,000 µm, with only a minor fraction below 100 µm. Although these particles were much larger than the pore throats of tight sandstone, their size distribution in fractured formations may provide adequate coverage to mitigate damage associated with large residue clumps. Overall, the findings suggest that prolonged fluid contact promotes the accumulation of persistent inorganic residues that impair permeability, while high-temperature HCl treatment dissolves most of the residue mass, indicating a potential mitigation route whose effect on core permeability recovery remains to be verified.