Estimation of Remaining Reserves Post-Dry Gas Infusion in Cracked Formations Utilizing an Enhanced Material Balance Formula

Abstract The fractured reservoir variety boasts a dual-pore structure, with the matrix pores serving as the primary storage compartment and the fracture network acting as the principal pathway for fluid movement. Conventional recovery techniques like depletion or waterflooding tend to leave behind a substantial amount of unrecoverable crude oil trapped within the matrix. However, gas injection is a strategy that not only adeptly sustains reservoir pressure but also creates a two-phase interaction that repels the crude oil, thereby enhancing its recovery rate. In the last few years, this method has increasingly gained traction and is now widely implemented in the exploitation of fractured reservoirs. In recent years, the gas injection technique has increasingly gained traction and been implemented in fractured oil reservoir development. Given the presence of highly permeable fractures and a tightly packed matrix, the spatial arrangement of the reservoir and the characteristics of the fluids within it are incredibly intricate. Moreover, the introduction of gas from external sources alters the high-pressure physical behavior of these fluids, rendering the conventional material balance equations inadequate for dealing with such sophistication. To accurately depict the post-injection scenario in fractured reservoirs, this study constructs a revised material balance equation tailored for these conditions, leveraging the conservation of matter principle. It incorporates the dual porosity medium concept, taking into account the impact of reservoir porosity changes due to stress, the gravitational stratification, and the self-absorption effects of capillary forces. The data suggests that the presence of fissures significantly increases the sensitivity of reservoir core porosity to stress. This sensitivity, along with gravitational differentiation, plays a pivotal role in estimating the reserves of a reservoir. However, the sensitivity to porosity stress takes precedence, and failing to account for it can lead to an overestimation of the reservoir’s capacity. The degree of influence of each influence factor is compression coefficient>stress sensitivity>dry gas solubility>gravity differentiation>capillary force seepage. The recalibrated formula yields projections that align more closely with the empirical data, enabling the distinct quantification of reserves within both the matrix and the fracture network. This advancement enhances the precision of our predictions and lays a solid foundation for the optimized exploitation of such reservoirs, thereby holding immense practical value.