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1 Introduction1.1 CO 2 sequestrationThe process of capturing carbon dioxide (CO 2 ) and storing (sequestering) it into deep saline aquifers isbecoming an important method in reducing global atmospheric emissions of CO 2 (e.g. Michael et al.,2009). Aquifers, which are defined as underground layers of water-bearing permeable rock or unconsolidatedmaterials, are chosen (e.g. Doughty et al., 2007; Schilling et al., 2009; JafarGandomi and Curtis,2011) in preference to depleted hydrocarbon reservoirs (e.g. Arts et al., 2004; White and Johnson, 2009),and deep, unmineable coal seams (e.g. Gale and Freund, 2001), primarily because their potential forCO 2 storage is much greater (IPCC, 2005), but also because of a perception of reduced safety in depletedreservoirs because of poorly-sealed abandoned wells. This report considers only sequestration in salineaquifers. Figure 1.1 illustrates the worldwide prospectivity of sedimentary basins for CO 2 sequestration.Figure North American 1.1: Worldwide capacity, oil distribution and gas reservoirs of are sedimentary estimated basins Figure 1and Sedimentary their prospectivity basins showing suitability for CO as sequestrationto be able to contain ~80 Gt C, saline aquifers between 900sites (IPCC 2005)2 sequestrationand 3300 Gt C, and(aftercoalIPCC,beds about2005).150 Gt C, for a totalof about 1160 to 3500 Gt C (DOE 2007). If these estimatesare correct, there is sufficient capacity to sequester severalMonitoring and verification (M&V) of stored CO remain separate. At conditions expected for sequestration,hundreds of years of emissions. Only time and experience 2 is critical to the success of any sequestration projectCO 2 and water are immiscible. Oil and CO 2 may or may not(e.g. will tell JafarGandomi whether these estimates and Curtis, are correct. 2011). Monitoringbe requires miscible, that depending the subsurface on the composition distribution of the of oil CO and 2In the short term, the biggest challenge is match sequestrationsites to CO 2 sources. For example, the large capacity When the fluids are miscible, the CO 2 eventually displacesthe formation pressure. CO 2 and natural gas are miscible.be observed and tracked. Monitoring techniques need to be able to detect when a minimum thresholdin the oil and volume gas reservoirs and saturation will only become in COavailable when the nearly all of the original fluid. Injection of an immiscible2 has been exceeded, either within a storage reservoir or without.operator declares them depleted or implements enhanced oil fluid bypasses some fraction of the pore space, trappingMonitoringrecovery (EOR)therefore,(ARI 2006).isAacomparisondirect driverof sequestrationof the storagesome process, of the and original mustfluid. be carried With the out limited over the exception lifetime ofcapacity and emissions indicates that some of the greatest dry-gas reservoirs, most sequestration projects will requireof the reservoir (Benson et al., 2004).CO 2 emitters (e.g. in the Ohio River Valley, India, and parts immiscible displacement to one degree or another. Forof China) are located in regions without large sequestration example, although oil and CO 2 are miscible, the water thatDespitecapacities.COOn 2 ’sthetransparencyother hand, Texas,to mosttheextantUS stategeophysicalwith the is methods, almost always there present are many in formations conceivable is not geophysicalmiscible withhighest CO 2 emissions, has extremely large sequestration oil or CO 2 /oil mixtures. Equilibration of CO 2 between oilmeasurements that might be made to map the distribution of COcapacity. CCS will likely begin in regions with large emissionmeasuring sources, large acoustic sequestration impedance capacity, contrasts and opportunities using a seismicand water depends 2 . We might derive COon the composition of 2 distributionsthe oil.byUnder conditionssurvey. Wewheremightthe fluidderivephasesCOare 2 distributionsnot miscible,for combining CO 2 sequestration and EOR. Beyond that,by the pressure needed to inject CO 2 , the rate at which theparticularly measuring the differences case of saline in aquifers densityand using coal gravity beds, the surveys. Such differences could arise from changes inleading edge of the CO 2 plume moves, and the fraction ofpressure,scientific foundationsCOand the potential risks of large-scalethe pore space filled with CO 2 are all governed by multiphaseflow relationships (Bear 1972). For CO 2 sequestra-injection must 2 saturation, or both. We might also derive CObe established.2 distributions by measuring changes in conductivityusing electrical or electromagnetic (EM) surveys.tion, threeSuchparticularly measurementsimportanthaveconsequencesformed thearise basisfromofaSCIeNTIFIC number of prior FUNDAmeNTAlSstudies (Kazemeini et al., 2010; Giese multiphase et al., 2009; flow behavior. SchillingFirst, et al., the 2009; fraction Gasperikovaof the poreOF GeOlOGICAl SeqUeSTRATIONspace that can be filled with CO 2 is limited by the flowdynamics and capillary pressure resulting from interactionPhysical Properties of CO 2of two or more phases. At most, about 30% of the pore space | 1The physical state of CO 2 varies with temperature and pressure,as shown in Figure 4a (Oldenburg 2007). At ambient CO 2 saturation is likely to be even less because of buoyancyis filled with CO 2 during initial displacement. In practice,conditions, CO 2 is a gas, but it becomes liquid at greater and geological heterogeneity, both of which cause portionsdepth. At high temperature, CO 2 is a supercritical fluid of the formation to be bypassed. After injection has stopped,when pressure is high enough. The transition from one CO 2 continues to move and fluid saturation approachesstate to another depends on the geothermal gradient. In equilibrium, which is determined by the capillary pressure