Characterization of Frac Fluid-Induced Damage to Tight Sandstone Reservoir Matrix by Nuclear Magnetic Resonance

Abstract Reducing frac fluid-induced damage represents a significant research topic, while there is a notable absence of suitable method for evaluation of fracturing fluid damage to tight reservoir matrix. This paper proposed a novel method for investigating frac fluid-induced damage to tight sandstone reservoir matrix in Western Qaidam Basin. Furthermore, performance of various fracturing fluids and damage to several reservoirs by these fracturing fluids were assessed, providing technical support for fracturing fluid optimization. Firstly, equivalent fluid permeability of rock samples from several reservoirs were determined. Then, rock samples were saturated by brine after vacuum pumping and pressurization. Nuclear magnetic resonance (NMR) tests were conducted before and after centrifugation, respectively, to obtain pore structure characteristic parameters, such as saturated porosity and effective porosity. Rock permeability prediction model was established based on the correlation between pore structure characteristic parameters and equivalent fluid permeability. After that, rock samples were saturated by fracturing fluid to simulate damage process. NMR tests were conducted before and after centrifugation, respectively, to obtain pore structure characteristic parameters after damage. Experimental results indicate that the reservoir cores are predominantly characterized by micro-scaled pores, exhibiting low porosity and permeability. The porosity ranges from 2.42% to 4.93%, while permeability varies between approximately 0.0013 mD and 0.2081 mD. The irreducible fluid saturation of core samples from different blocks shows significant variation, with a maximum of 79.58% and a minimum of 21.49%. Among the pore structure parameters, movable fluid saturation, effective porosity, and the FFI/BVI ratio demonstrate relatively strong correlations with equivalent liquid permeability, with correlation coefficients of 0.7072, 0.8362, and 0.7194, respectively. In contrast, water-saturated porosity, T2 geometric mean (T2g), and T2 spectrum cutoff time exhibit weaker correlations with equivalent liquid permeability, with correlation coefficients of 0.4948, 0.3828, and 0.2055, respectively. By selecting effective porosity (φe) to modify the classical permeability prediction model, the predictive accuracy of the revised model is significantly improved. After exposure to fracturing fluid damage, the water-saturated porosity and movable fluid saturation of the cores generally decrease, while irreducible fluid saturation increases due to fracturing fluid retention, leading to varying degrees of permeability reduction. The maximum damage rate reaches 89.8%, while the minimum is −680%. Overall, the anti-salt polymer fracturing fluid generally causes more severe damage to the cores compared to slickwater. Method proposed in this paper can realistically simulate the damage process of fracturing fluid to tight sandstone reservoir matrix and effectively evaluate the permeability damage by fracturing fluid, addressing the issue that fluid could not flow through the whole rock sample while using core flooding to simulate fracturing fluid damage process. Additionally, this method can be applied to evaluate fracturing fluids damage on other tight reservoirs, such as shale.