Impact of WAG Design on Calcite Scaling Risk in Coupled CO-EOR and Storage Projects in Carbonate Reservoirs
- Hydra Rodrigues (Heriot-Watt University) | Eric Mackay (Heriot-Watt University) | Daniel Arnold (Heriot-Watt University)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Simulation Conference, 10-11 April, Galveston, Texas, USA
- Publication Date
- Document Type
- Conference Paper
- 2019. Society of Petroleum Engineers
- 5.2 Fluid Characterization, 5.5 Reservoir Simulation, 7.2.1 Risk, Uncertainty and Risk Assessment, 5.8.7 Carbonate Reservoir, 5.3.2 Multiphase Flow, 5.3.4 Reduction of Residual Oil Saturation, 4.3.4 Scale, 5.4 Improved and Enhanced Recovery, 5.4 Improved and Enhanced Recovery, 7 Management and Information, 7.2 Risk Management and Decision-Making, 5.2.2 Fluid Modeling, Equations of State, 5.2.1 Phase Behavior and PVT Measurements, 5 Reservoir Desciption & Dynamics, 5.8 Unconventional and Complex Reservoirs
- WAG, Optimization, CCUS, Reactive transport, EOR
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WAG (Water-Alternating-Gas) schemes have been applied in Brazilian carbonate reservoirs aiming to minimize residual oil saturation and gas flaring by recycling CO2 naturally being produced alongside hydrocarbon gas. However, applying WAG injection in highly reactive and heterogeneous carbonate rocks can potentially create severe scaling problems. This work develops a reactive transport simulation-based workflow to evaluate the impact of key WAG design parameters on oil recovery, scale deposition risk and CO2 storage to support multi-objective decision-making.
Compositional simulations of WAG scenarios were performed as part of a sensitivity study followed by statistical analysis in order to quantify to what extent the outcomes of interest are sensitive to variations on four WAG design parameters: WAG ratio, CO2 concentration in the injection gas stream, injection rate and solvent slug-size. We established an Equation-of-State (EoS) using PVT data, a representative geochemical model and well constrains designed to control production of injected fluids. Scale risk was assessed by calcite changes around the wells, precipitation in well tubing and surface facilities, and water breakthrough.
Results of this study showed that values of calcite rate constant (Ksp) and reactive surface area (A0) assigned in numerical simulations can impact relative calcite changes in the reservoir. Using reactive surface areas from BET studies of crushed rocks can lead to prediction of unrealistic amounts of calcite dissolution. Cases with lower values of (Ksp×A0) appeared to be more numerically stable and more consistent with dissolution/precipitation rates of silicate minerals. Simulation results also suggested that calcite dissolution close to injection wells and precipitation in production wells and surface facilities become more severe as CO2 concentration in injection gas and WAG ratio increases. Based on the design variables and reservoir conditions studied, the most to least crucial factors affecting oil recovery were: CO2 concentration in the injection gas stream, injection rate, WAG ratio and solvent slug-size. From a storage perspective, the impact of the design variables had considerably more impact, with the most influential factor being again CO2 concentration in the injection gas stream, followed by WAG ratio, injection rate and solvent slug-size. Optimization study results suggested that low WAG ratio values combined with low to intermediate gas slug sizes could result in superior profitability and CO2 storage outcomes for this pilot.
Ultimately, we demonstrate the importance of integrating multiphase miscible displacement with geochemical reactions while modeling complex CO2-EOR in carbonate reservoirs and address how key design parameters impact our desired outcomes, knowledge that promotes a more robust decision-making framework.
|File Size||2 MB||Number of Pages||28|
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