Impact of Temperature on Fluid-Rock Interactions During CO2 Injection in Depleted Limestone Aquifers: Laboratory and Modelling Studies
- Farhana Jaafar Azuddin (Group Research & Technology, PETRONAS Institute of Petroleum Engineering, Heriot-Watt University) | Ivan Davis (Institute of Petroleum Engineering, Heriot-Watt University) | Mike Singleton (Institute of Petroleum Engineering, Heriot-Watt University) | Sebastian Geiger (Institute of Petroleum Engineering, Heriot-Watt University) | Eric Mackay (Institute of Petroleum Engineering, Heriot-Watt University) | Duarte Silva (Institute of Petroleum Engineering, Heriot-Watt University)
- Document ID
- Society of Petroleum Engineers
- SPE International Conference on Oilfield Chemistry, 8-9 April, Galveston, Texas, USA
- Publication Date
- Document Type
- Conference Paper
- 2019. Society of Petroleum Engineers
- 5.4 Improved and Enhanced Recovery, 5.5.8 History Matching, 5 Reservoir Desciption & Dynamics, 5.4 Improved and Enhanced Recovery, 5.2.2 Fluid Modeling, Equations of State, 1.6 Drilling Operations, 5.2 Fluid Characterization, 5.5.2 Core Analysis, 5.4.2 Gas Injection Methods
- Thermal Impact, CO2 Sequestration, Carbonate Reservoir, Geochemical Reactivity
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When CO2 is injected into an aquifer, the injected CO2 is generally colder than the reservoir rock; this results in thermal gradients along the flow path. The temperature variation has an impact on CO2 solubility and the kinetics of any mineral reactions. Core flood experiments and associated reactive transport simulations were conducted to analyse thermal effects during CO2 injection in a dolomitic limestone aquifer and to quantify how CO2 solubility and mineral reactivity are affected.
The experiments were conducted by injecting acidified brine into an Edwards Limestone core sample. A back pressure of 400 psi and injection rates of 30 mL/hr and 300 mL/hr were used. A range of temperatures from 21 °C to 70 °C were examined. Changes in the outlet fluid composition and changes in porosity and permeability were analysed. A compositional simulation model was used to further analyse the experiments. The simulations were history-matched to the experimental data by changing the reactive surface area and the kinetic rate parameter. The calibrated model was then used to test the sensitivity to CO2 injection rate and temperature.
The impact of temperature on CO2-induced mineral reactions was observed from changes in mineral volume, porosity and permeability. The reaction rate constants estimated from the outlet solution concentrations are much lower than existing data for individual minerals. The estimated specific surface areas for carbonate minerals are in reasonable agreement with published values. The numerical investigations showed that at the lower temperatures, despite the reaction rates being slower, the solubility of the minerals was higher, and so as a result of these competing effects, moderately elevated calcium and magnesium concentrations were observed in the effluent. At higher temperatures, the solubilities of the minerals were lower, but now the reactions rates were higher, so similar effluent concentrations could be achieved. However, at higher flow rates, characterized by a lower Damköhler number, the residence times were shorter, and so lower effluent concentrations were observed. Additionally, the solubilities of calcite and dolomite varied to different extents with temperature, and so the calcium to magnesium molar ratio in the effluent brine increased with increasing temperature.
The change in mineral composition during CO2 injection varies between the near well zone and the deeper reservoir. Near the well where the temperatures will be lower, solubilities are elevated, but the kinetic reaction rates and residence times will be lower, somewhat limiting dissolution. Deeper in the aquifer the solubilities will be reduced and residence times will be longer, enabling an equilibrium to be established. Modelling is thus required to connect these flow regimes.
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