Analytical Models To Select an Effective Saline Reservoir for CO2 Storage
- Abhishek Kumar Gupta (University of Texas at Austin) | Steven Lawrence Bryant (U. of Texas at Austin)
- Document ID
- Society of Petroleum Engineers
- SPE Annual Technical Conference and Exhibition, 19-22 September, Florence, Italy
- Publication Date
- Document Type
- Conference Paper
- 2010. Society of Petroleum Engineers
- 5.4.2 Gas Injection Methods, 4.1.2 Separation and Treating, 4.1.5 Processing Equipment, 5.4 Enhanced Recovery, 5.8.6 Naturally Fractured Reservoir, 1.8.5 Phase Trapping, 5.1.2 Faults and Fracture Characterisation, 5.10.1 CO2 Capture and Sequestration, 5.2 Reservoir Fluid Dynamics, 5.1.1 Exploration, Development, Structural Geology, 5.5 Reservoir Simulation, 5.3.2 Multiphase Flow, 2.4.3 Sand/Solids Control, 2.2.2 Perforating, 5.2.1 Phase Behavior and PVT Measurements
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Geological sequestration of CO2 in deep saline reservoirs is one of the ways to reduce its continuous emission into the atmosphere to mitigate the greenhouse effect. The selection among prospective saline reservoirs can be expedited by developing some analytical correlations which can be used in place of reservoir simulation study for each and every saline reservoir. Such correlations can reduce the cost and time for commissioning a geological site for CO2 sequestration.
The efficiency of a CO2 sequestration operation depends on risks associated with storage, several of which can be estimated by i) the time the plume takes to reach the top seal; ii) maximum lateral extent of the plume and iii) the percentage of mobile CO2 present at any time. A database has been created from a large number of compositional reservoir simulations for different reservoir parameters including porosity, permeability, permeability anisotropy, reservoir depth, thickness, dip and perforation interval. We use a dimensionless ratio of gravity to viscous forces to formulate different correlations with the factors that contribute to sequestration efficiency. We update a previously reported correlation for time to hit the top seal and develop a new correlation for the maximum lateral extent of the plume using a newly created database for different reservoir and operating properties. A correlation for percentage of mobile CO2 during the buoyancy dominated post injection period is also developed.
We find that normalizing the maximum lateral extent by a characteristic length yields a reasonable correlation with the gravity number. This characteristic length is determined as the maximum lateral distance traveled by plume at any time assuming constant sand face velocity. The correlation confirms that low gravity number allows the plume to travel laterally due to high viscous forces while a high gravity number allows it to move faster in vertical direction due to strong gravity forces. The change in mobile CO2 after injection ends also correlates well with gravity number. We normalize the change in mobile CO2 fraction (or, equivalently, the change in trapped CO2 fraction) after the end of injection by a characteristic CO2 saturation. The characteristic saturation is obtained by considering the volume filled by vertical, buoyancy-driven movement through the area associated with the maximum plume extent.
The correlations reproduce almost all simulation results within a factor of two, and this is adequate for rapid ranking or screening of prospective storage reservoirs.
The continuous emission of CO2 into the atmosphere has increased its concentration from 280 ppm by volume in pre-industrial times (1970) to 387 ppm by volume at present. Geological sequestration of CO2 in deep saline reservoirs is a viable option to restrict this rapidly increasing CO2 concentration in the atmosphere. Large deep saline aquifers, which are not underground sources of potable water, are present in different sedimentary basins around the world. The current paradigm for geologic sequestration of CO2 envisions injection in supercritical state to reduce the volume needed for storage and to avoid adverse
effects of CO2 separating into liquid and gas phases in the injection system. The trapping mechanisms which contribute to secure CO2 storage include structural or stratigraphic trapping beneath the top seal, residual phase trapping in which CO2 is trapped as residual gas saturation when water imbibes back into CO2 plume after the injection, local capillary trapping when CO2 is trapped at or above residual saturation in regions within a heterogeneous formation (Saadatpoor et al., 2010), dissolution into formation brine (solubility trapping) and precipitation of carbonate minerals (mineral trapping) .
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