.png){kind=icon}
.png){kind=icon}
Return
Field-Scale Simulation of CO2 Water-Alternating-Gas Enhanced Oil Recovery in a Mature Waterflooded, Low-Permeability, and Highly Heterogeneous Reservoir
.png){kind=icon}
OA
AI
Y
X
M
W
DOI：10.3390/pr14162585.png)
.png){kind=icon}
Original request for help.png){kind=icon}
Share.png){kind=icon}
Save
Abstract
En 中文
Water flooding in low-permeability, highly heterogeneous reservoirs often causes a rapid increase in water cut and inefficient pressure maintenance because injected water preferentially flows through high-permeability channels. In this study, a field-scale compositional simulation model was established to evaluate CO2 water-alternating-gas (WAG) enhanced oil recovery in a mature waterflooded reservoir in the Daqing Oilfield. The model was constrained by geological data, experimentally tuned pressure–volume–temperature (PVT) behavior, relative-permeability measurements, and slim-tube tests. The minimum miscibility pressure (MMP) of the CO2-oil system was estimated to be 19.8 MPa. An 187-month production history was matched using field oil rate, water production, water cut, and reservoir-pressure data. At the current development stage, the reservoir has an oil recovery of 23.6%, an average water cut of 61.34%, and an average reservoir pressure of approximately 6.9 MPa. A 30-year prediction was then performed to compare continued water flooding with several CO2-WAG development strategies. Sensitivity analyses were conducted for the pressure-restoration level, pre-injection fluid, well-pattern conversion, slug size, and gas/water slug-size ratio. Continued water flooding increased the final oil recovery to only 28.4% and resulted in a water cut of 92.8%. Sequential scenario screening identified a best-performing case among the tested scenarios, consisting of CO2 pre-injection to restore the average reservoir pressure to 11 MPa, conversion to a staggered line-drive well pattern, a slug size of 0.025 PV, and a gas/water slug-size ratio of 1:1. Under this sequentially selected case, the end-of-forecast oil recovery reached approximately 57.24%, which was the highest value among the cases evaluated in this study and was 28.84 percentage points higher than continued water flooding. The predicted recovery is conditional on the adopted geological, relative-permeability, EOS, and history-matching assumptions. Because the designed average reservoir pressure is below the measured MMP and local pressure above the MMP was not demonstrated, the modeled process is consistently interpreted as immiscible CO2-WAG. The predicted recovery improvement is interpreted as being associated with pressure support, gas-mobility control, improved sweep efficiency, and compositional CO2–oil interactions represented by the model, including CO2 dissolution, oil swelling, and viscosity reduction. The contribution of this work is a field-scale, experimentally constrained workflow for selecting CO2-WAG operating parameters in mature waterflooded low-permeability reservoirs; CO2 storage performance should be quantified separately in future work. This study provides an experimentally constrained and history-validated field-scale workflow for identifying a best-performing CO2-WAG operating case among the tested scenarios in mature waterflooded low-permeability reservoirs.
Keywords:
numerical simulation
enhanced oil recovery
CO<sub>2</sub>-WAG
low-permeability reservoir
reservoir heterogeneity
immiscible WAG
history matching
Journal
IF:
2.8
Papers:
6.6K
Citations:
3.7W
Organization
Cited Papers