Predicting Oil Recovery Under Uncertainty for Huff ‘n’ Puff Gas Injection: A Field Case Study in the Permian Basin

The extent and size of the fracture network connected to the wellbore are among the most uncertain parameters for multifractured horizontal wells. The uncertainty has a profound impact on production under primary depletion and has an even bigger impact on the recovery during huff ‘n’ puff (HnP) gas injection. In this paper, we quantify the uncertainty in reservoir properties and enhanced oil recovery (EOR) for a pair of wells in the Permian basin. In addition, we report on the lessons learned from modeling a field pilot HnP project involving four cycles using reservoir simulation. We create a base sector model for two wells completed in Wolfcamp B and C formations, where fractures are incorporated using an embedded discrete fracture model. For each well, we identify 13 uncertain parameters (describing fracture properties and compaction, initial conditions, and relative permeability). We use a Bayesian assisted-history-matching (AHM) method to match primary production data. Our study emphasizes the critical role of grid refinement for the accurate depiction of the gas-injection process by comparing three models with varying grid sizes. Additionally, we study the impact of molecular diffusion on oil and gas recovery using different diffusion coefficients. Another significant factor is the dynamic nature of the fracture network during cyclic injection, as indicated by evidence of communication between the wells. This makes the accessible fracture area during injection highly uncertain. To address interwell interference, we incorporate an additional fracture network activated during injection. To manage the uncertainty of active fracture area, we created four scenarios within the literature range, approximately 0.5, 1, 2, and 4 million ft2 per stage, and tuned their properties to match historical HnP data. The production predictions from the AHM solutions were extended beyond the initial four HnP cycles to provide probabilistic forecasts. We demonstrate that grid refinement has a minimal effect on production under primary depletion but significantly influences HnP recovery. We attribute this disparity to numerical dispersion, which causes the artificial mixing of gas in the large gridblocks, leading to an overly optimistic recovery. Activating the molecular-diffusion mechanism results in a negligible impact on the recovery in our case. The contribution of molecular diffusion becomes noticeable only when diffusion coefficients exceed ten times the reported values. This leads us to conclude that molecular diffusion is of second-order importance compared with advection and can generally be neglected in our case. This finding should not be generalized to all shale formations. In reservoirs characterized by lower permeability and fluids with higher diffusion coefficients, molecular diffusion could still play a crucial role. We highlight that the contacted-fracture area, which is often underestimated in the reservoir simulation practice, is a critical factor for accurate modeling. Production for 37 filtered AHM solutions is extended under the four scenarios with variable fracture surface areas. Based on our analysis, we report that the HnP results in an average of 76% improvement in oil recovery compared with natural depletion. © 2024 Society of Petroleum Engineers.