Tight oil production has increased dramatically and contributed to 61% of total US oil production in 2018. However, recovery factors for primary depletion with multistage fractured wells are low, typically less than 10%. Gas huff-n-puff emerges as a promising technique to push the recovery factor beyond 10% in tight oil reservoirs, based on laboratory studies, simulation and field pilot tests. A CO2 huff-n-puff pilot was implemented in the Midland Basin, and data collected demonstrated significant incremental oil recovery, but with higher than expected water-cut rise.
To understand the excessive water production, a compositional model was built. Eight pseudo-components were used to match the PVT lab results of a typical oil sample in the Wolfcamp shale. A lab scale model was established in our simulator to match the results of gas huff-n-puff experiments in cores, where key parameters were identified and tuned. A half-stage model consisting of five fractures was built, where stress-dependent permeability was represented by compaction tables. Then a sensitivity analysis was conducted to understand the roles of different mechanisms behind the abnormal high water-cut phenomenon on this scale. Our simulation results have shown that initial water saturation, IFT-dependent relative permeability, reactivation of water-bearing layers, and re-opening of unpropped hydraulic fractures may all affect water-cut after gas injection. Among them, re-opening of unpropped hydraulic fractures was the most critical one.
Data from a pilot test imply substantial water production after gas injection, which may impede oil production, but the underlying mechanisms are poorly understood. A numerical model is developed to study possible mechanisms for high water-cut pilot results. This study also intends to quantify the impact of high water cut on cyclic gas injection.