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Chapter 5: Underground geological storage 227 table 5.3 Types of data that are used to characterize and select geological CO2 storage sites. • Seismic profiles across the area of interest, preferably three-dimensional or closely spaced two-dimensional surveys; • Structure contour maps of reservoirs, seals and aquifers; • Detailed maps of the structural boundaries of the trap where the CO2 will accumulate, especially highlighting potential spill points; • Maps of the predicted pathway along which the CO2 will migrate from the point of injection; • Documentation and maps of faults and fault; • Facies maps showing any lateral facies changes in the reservoirs or seals; • Core and drill cuttings samples from the reservoir and seal intervals; • Well logs, preferably a consistent suite, including geological, geophysical and engineering logs; • Fluid analyses and tests from downhole sampling and production testing; • Oil and gas production data (if a hydrocarbon field); • Pressure transient tests for measuring reservoir and seal permeability; • Petrophysical measurements, including porosity, permeability, mineralogy (petrography), seal capacity, pressure, temperature, salinity and laboratory rock strength testing; • Pressure, temperature, water salinity; • In situ stress analysis to determine potential for fault reactivation and fault slip tendency and thus identify the maximum sustainable pore fluid pressure during injection in regard to the reservoir, seal and faults; • Hydrodynamic analysis to identify the magnitude and direction of water flow, hydraulic interconnectivity of formations and pressure decrease associated with hydrocarbon production; • Seismological data, geomorphological data and tectonic investigations to indicate neotectonic activity. potential CO2-water-rock reactions that could weaken the seal rock or increase its porosity and permeability. in situ stresses, pore fluid pressures and pre-existing fault orientations and their frictional properties (Streit and Hillis, 2003; Johnson et al., 2005). These estimates can be made from conventional well and seismic data and leak-off tests, but the results can be enhanced by access to physical measurements of rock strength. Application of this methodology at a regional scale is documented by Gibson-Poole et al. (2002). Methods have been described for making field-scale measurements of the permeability of caprocks for formation gas storage projects, based on theoretical developments in the 1950s and 1960s (Hantush and Jacobs, 1955; Hantush, 1960). These use water-pumping tests to measure the rate of leakage across the caprock (Witherspoon et al., 1968). A related type of test, called a pressure ‘leak-off’ test, can be used to measure caprock permeability and in situ stress. The capacity of a seal rock to hold back fluids can also be estimated from core samples by mercury injection capillary pressure (MICP) analysis, a method widely used in the oil and gas industry (Vavra et al., 1992). MICP analysis measures the pressures required to move mercury through the pore network system of a seal rock. The resulting data can be used to derive the height of a column of reservoir rock saturated by a particular fluid (e.g., CO2) that the sealing strata would be capable of holding back (Gibson-Poole et al., 2002). When CO2 is injected into a porous and permeable reservoir rock, it will be forced into pores at a pressure higher than that in the surrounding formation. This pressure could lead to deformation of the reservoir rock or the seal rock, resulting in the opening of fractures or failure along a fault plane. Geomechanical modelling of the subsurface is necessary in any storage site assessment and should focus on the maximum formation pressures that can be sustained in a storage site. As an example, at Weyburn, where the initial reservoir pressure is 14.2 MPa, the maximum injection pressure (90% of fracture pressure) is in the range of 25–27 MPa and fracture pressure is in the range of 29–31 MPa. Coupled geomechanical-geochemical modelling may also be needed to document fracture sealing by precipitation of carbonates in fractures or pores. Modelling these will require knowledge of pore fluid composition, mineralogy, The efficacy of an oil or gas field seal rock can be characterized by examining its capillary entry pressure and the potential hydrocarbon column height that it can sustain (see above). However, Jimenez and Chalaturnyk (2003) suggest that the geomechanical processes, during depletion and subsequent CO2 injection, may affect the hydraulic integrity of the seal rock in hydrocarbon fields. Movement along faults can be produced in a hydrocarbon field by induced changes in the pre- production stress regime. This can happen when fluid pressures are substantially depleted during hydrocarbon production (Streit and Hillis, 2003). Determining whether the induced stress changes result in compaction or pore collapse is critical in assessment of a depleted field. If pore collapse occurs, then it might not be possible to return a pressure-depleted field to its original pore pressure without the risk of induced failure. By having a reduced maximum pore fluid pressure, the total volume of CO2 that can be stored in a depleted field could be substantially less than otherwise estimated. 5.4.1.3 Geomechanical factors affecting site integrity 5.4.1.4 Geochemical factors affecting site integrity The mixing of CO2 and water in the pore system of the reservoir rock will create dissolved CO2, carbonic acid and bicarbonate ions. The acidification of the pore water reduces the amount of CO2 that can be dissolved. As a consequence, rocks that buffer the pore water pH to higher values (reducing the acidity) facilitate the storage of CO2 as a dissolved phase (Section 5.2). The CO2-rich water may react with minerals in the reservoir rock or caprock matrix or with the primary pore fluid. Importantly, it may also react with borehole cements and steels (see discussionPDF Image | CARBON DIOXIDE CAPTURE AND STORAGE
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