New Model Predicts CO2 Flooding Stability for Enhanced Oil Recovery and Carbon Storage

Breakthrough in Reservoir Engineering Modeling

Engineering researchers have developed a novel dimensionless group model that reportedly enables simple yet effective evaluation of gas-oil interface stability during CO2 gas cap flooding operations, according to recent findings published in Scientific Reports. The model, derived from extensive comparative analysis, is said to provide accurate assessment of gas displacement front stability for immiscible gas flooding in fault block reservoirs, offering both theoretical insights and practical decision-making tools for field applications.

Breakthrough in Reservoir Engineering Modeling
Key Factors Influencing Flooding Stability
Crude Oil Density: A Positive Correlation
Viscosity Challenges and Solutions
Gas Density and Injection Rate Impacts
Field Applications and Implications

Key Factors Influencing Flooding Stability

The research identifies multiple critical parameters affecting what analysts term the “artificial gas cap immiscible stable gas flooding number.” Sources indicate these factors include crude oil density, crude oil viscosity, gas density, gas viscosity, gas injection rate under formation conditions, strata dip, relative permeability, and air permeability in the stratigraphic direction. According to the report, understanding these relationships provides crucial insights for optimizing both enhanced oil recovery (EOR) and carbon storage operations.

Crude Oil Density: A Positive Correlation

Contrary to conventional expectations, the relationship between crude oil density and flooding stability demonstrates unexpected characteristics, researchers suggest. Under constant conditions, analysis reportedly reveals a linear relationship where increasing crude oil density corresponds to improved gas displacement front stability. The study states that higher density crude oils enhance buoyancy gradients, gravity gradients, and capillary force gradients, promoting gravitational differentiation that causes crude oil to sink while injected gas rises to form an effective gas cap.

Field data from the West Hackberry Oilfield, where values consistently exceeded 4.5, indicated stable gas displacement fronts, while the Yanling Oilfield pilot region and fault block reservoirs in central and eastern China showed values below 1.0, suggesting instability and gas breakthrough. However, in all cases, increasing crude oil density gradually improved front stability, according to the findings.

Viscosity Challenges and Solutions

The research demonstrates a power function relationship between crude oil viscosity and flooding stability, with higher viscosity leading to reduced stability of the gas displacement front. Experimental data reportedly showed that higher viscosity oil (1.277 mPa·s) resulted in gas breakthrough after only 0.122 pore volumes of injected gas, achieving 53.72% displacement efficiency. This represented a 3.26% improvement over lower viscosity oil (0.695 mPa·s), but came with stability challenges.

Analysts suggest that significant viscosity differences between injected gas and crude oil can lead to viscous fingering phenomena, reducing sweep volume and displacement efficiency. The report indicates that artificial CO2 gas cap flooding is more appropriate for low-viscosity reservoirs, where reduced mobility ratios help suppress viscous fingering and extend stable production periods.

Gas Density and Injection Rate Impacts

The study reveals that injected gas density exhibits a direct correlation with flooding stability, with higher density gases leading to continuous deterioration of the gas displacement front. Researchers note that low-density gases create substantial density differences with crude oil, enhancing gravitational differentiation effects that drive gas toward reservoir tops or inclined structure upper sections, forming secondary gas caps that effectively target attic oil.

Gas injection rates demonstrate a power function relationship with stability, according to the analysis. Lower injection rates of 0.01056 m/d delayed gas breakthrough to 0.237 pore volumes, achieving 67.59% displacement efficiency, while higher rates of 0.02630 m/d resulted in earlier breakthrough at 0.166 pore volumes and reduced efficiency of 56.98%. The report states that slower injection extends stable production periods and improves both development effectiveness and carbon storage.

Field Applications and Implications

The research utilized average geological and development data from multiple oilfields, including the West Hackberry Oilfield, Yanling Oilfield pilot region, and various fault block reservoirs in central and eastern China following water flooding development. These case studies reportedly demonstrate the model’s practical applicability for reservoir selection and field operation planning.

Engineering analysts suggest this approach offers multiple benefits, including suppression of viscous fingering, maintenance of stable displacement fronts, effective targeting of bypassed oil in water-flooded areas, extended efficient production periods, improved displacement and sweep efficiency, and enhanced CO2 sequestration potential. The dimensionless group model provides what sources describe as a valuable correlation tool for evaluating displacement stability in immiscible gas flooding operations, particularly important for carbon capture, utilization, and storage (CCUS) applications in depleted reservoirs.