Simulation of high water cut in tight oil reservoirs during cyclic CO2 injection

Abstract Tight oil contributed to 64% of total US oil production in 2019. However, recovery factors (RF) in tight oil reservoirs are low, typically less than 10% after primary depletion. Based on numerous published studies, gas huff-n-puff emerges as the most promising technique to push the RF beyond 10%. A recent pilot in the Wolfcamp shale confirmed the effectiveness of CO 2 huff-n-puff, however a higher than expected water cut was also observed during the puff stage. A compositional modeling framework was hence implemented to investigate the reasons as well as the impact of such phenomenon. To the best of our knowledge, it is the first time that such abnormal water cut behavior has been modeled for tight oil reservoirs. The fluid PVT and lab-scale model were established and tuned to obtain the critical inputs for the compositional model. A half-stage model of five fractures was then established as a base case, representing a typical completion design in this region. Its results demonstrated an improved oil RF from 7.96% of depletion to 12.16% after six cycles of CO 2 huff-n-puff, and the improvement factor was 1.53 which matches the published results of gas injection in unconventional reservoirs. Based on a comprehensive literature review, several possible mechanisms on abnormal water cut behaviors were identified including underestimation of initial water saturation, interfacial tension (IFT) dependent relative permeability due to miscibility, reactivation of water-bearing layers, and re-opening of unpropped hydraulic fractures. Sensitivity studies indicated that re-opening of unpropped hydraulic fractures might be the most plausible cause. The simulated excessive water production was found to reduce the RF to 11.02% in contrast to a RF of 12.16% of the base case, marking water management as a vital direction for future research.