Optimal Control of Injection/Extraction Wells for the Surface Dissolution CO2 Storage Strategy
- Qing Tao (U. of Texas at Austin) | Steven Lawrence Bryant (U. of Texas at Austin)
- Document ID
- Carbon Management Technology Conference
- Carbon Management Technology Conference, 7-9 February, Orlando, Florida, USA
- Publication Date
- Document Type
- Conference Paper
- 2012. Carbon Management Technology Conference
- 5.10.1 CO2 Capture and Sequestration, 5.1.2 Faults and Fracture Characterisation, 1.7.5 Well Control, 5.2.1 Phase Behavior and PVT Measurements, 6.5.7 Climate Change, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 5.4 Enhanced Recovery, 5.5 Reservoir Simulation, 5.1.1 Exploration, Development, Structural Geology, 5.4.2 Gas Injection Methods, 1.8.5 Phase Trapping, 4.3.4 Scale, 3 Production and Well Operations
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Implementing geological carbon sequestration at large scale to mitigate anthropogenic emissions involves the injection of CO2 into deep brine-filled structures. An alternative to injecting CO2 as a buoyant phase is to dissolve it into brine extracted from the storage formation, then inject the CO2-saturated brine into the storage formation. This "surface dissolution?? strategy eliminates the risk of buoyant migration of stored CO2 and mitigates the extent of pressure elevation during injection. The CO2 concentration front shape when it reaches the saturation pressure contour defines the maximum areal extent of CO2- saturated brine and hence the aquifer utilization efficiency.
Heterogeneity of the aquifer reduces the utilization efficiency. We illustrate by comparing utilization efficiency in homogeneous permeability field with that in uncorrelated and correlated heterogeneous fields under same well control. The example cases yield reductions of the utilization efficiency by 9% and 15% of aquifer pore volume respectively.
We develop an optimal control strategy of the injection/extraction wells to maximize the utilization efficiency for heterogeneous aquifers. We propose two objective functions: one intends to improve the areal sweep by minimizing the mismatch between CO2 concentration front and saturation pressure contour; the other directly formulates the utilization efficiency while penalizing zones that contain gas phase CO2. Both approaches significantly improve the aquifer utilization efficiency by delaying the arrival time of CO2 front to saturation pressure contour. In the uncorrelated heterogeneous field, the utilization efficiency is improved by 3% of the aquifer pore volume. In the correlated heterogeneous field, the improvement on utilization efficiency is 9%.
Heterogeneity plays an important role in determining the location of saturation pressure contour within the storage formation. We propose an optimal well placement strategy by placing line-drive injectors in high permeability zone and extractors in low permeability zone, so that the saturation pressure contour is closer to the extractors and thus increases the aquifer utilization efficiency. Illustration on the correlated heterogeneous field shows an improvement of utilization efficiency by 5% using optimal well placement and another 9% combining with the optimal control of injection/extraction rates. A straightforward implication of the optimal well placement is that hydraulically fracturing the injectors improves the aquifer utilization efficiency by increasing the linear nature of the pressure contours.
Large scale geological storage is a key technology to reduce anthropogenic emissions of CO2. Safe storage of CO2 in a brinebearing formation is attributed to dissolution, structural and residual phase trapping (Ennis-King and Paterson, 2002; IEA, 2004; IPCC, 2005; Kumar et al., 2005). Injection of supercritical CO2 into deep structures, however, imposes the following risks: 1) The buoyancy of CO2 increases the potential for leakage along geological and human introduced discontinuities, such as fault and leaky wellbores (Pruess, 2004; Huerta et al., 2009; Tao et al., 2010); 2) The pressure elevation in the formation due to injection of CO2 restricts storage rates, possibly quite severely (Luo and Bryant, 2010), and injection above the threshold rate may induce fracturing of the storage formation and possibly seismic activity; 3) Contamination of ground water resources might occur due to CO2 migration. These risks directly result in higher monitoring and insurance costs.
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