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Physical and Chemical Characteristics of Potential Seal Strata in Regions Considered for Demonstrating Geological Saline CO2 Sequestration

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Physical and Chemical Characteristics of Potential Seal Strata in Regions Considered for Demonstrating Geological Saline CO2 Sequestration Environ Earth Sci DOI 10.1007/s12665-011-0911-5 ORIGINAL ARTICLE Physical and chemical characteristics of potential seal strata in regions considered for demonstrating geological saline CO2 sequestration Craig A. Griffith • David A. Dzombak • Gregory V. Lowry Received: 2 April 2010 / Accepted: 4 January 2011 Ó Springer-Verlag 2011 Abstract Capture and geological sequestration of CO2 Keywords Carbon sequestration Á Saline formations Á from energy production is proposed to help mitigate cli- Mineralogy Á Seal integrity Á Caprock geology mate change caused by anthropogenic emissions of CO2 and other greenhouse gases. Performance goals set by the US Department of Energy for CO2 storage permanence Introduction include retention of at least 99% of injected CO2 which requires detailed assessments of each potential storage There exists a concern for the growing accumulation of site’s geologic system, including reservoir(s) and seal(s). atmospheric greenhouse gases levels adversely impacting The objective of this study was to review relevant basin- the global climate, particularly from anthropogenic sour- wide physical and chemical characteristics of geological ces of CO2 (Solomon et al. 2007). Most of the anthro- seals considered for saline reservoir CO2 sequestration in pogenic sources of CO2 are derived from large point the United States. Results showed that the seal strata can sources, especially electricity production and industrial exhibit substantial heterogeneity in the composition, source (e.g., cement production), with estimates of global structural, and fluid transport characteristics on a basin emissions reaching 28 Gigatonnes (Gt) in 2005 and pro- scale. Analysis of available field and wellbore core data jected to reach 40.4 Gt in the year 2030 (McArdle and reveal several common inter-basin features of the seals, Lindstrom 2008; Doman et al. 2009). Carbon capture and including the occurrence of quartz, dolomite, illite, calcite, storage (CCS) is a viable mitigation option to abate this and glauconite minerals along with structural features increase of atmospheric CO2, and saline CO2 sequestra- containing fractures, faults, and salt structures. In certain tion has emerged as a promising storage option (Metz localities within the examined basins, some seal strata also et al. 2005). serve as source rock for oil and gas production and can be Deep saline formations appear to have the largest subject to salt intrusions. The regional features identified in potential capacity among the various geological options, this study can help guide modeling, laboratory, and field with estimates for their storage potential ranging from studies needed to assess local seal performances within the 3,300 to 12,600 Gt in North America alone (US Depart- examined basins. ment of Energy et al. 2008a). CO2 storage in deep saline formations also has the potential for stable, permanent chemical sequestration of at least some of the injected CO2 C. A. Griffith (&) Á D. A. Dzombak Á G. V. Lowry due to mineral precipitation from chemical interactions of Department of Civil and Environmental Engineering, the injected CO with the brine and reservoir rock (Benson Carnegie Mellon University, 5000 Forbes Ave, 2 Pittsburgh, PA 15213, USA et al. 2005). e-mail: cgriffi[email protected] In 2003, the US Department of Energy (US DOE) ini- D. A. Dzombak tiated the Regional Carbon Sequestration Partnership pro- e-mail: [email protected] grams (RCSPs) to determine the operational and technical G. V. Lowry issues faced in geologically sequestering CO2 in various e-mail: [email protected] regions of the United States (Litynski et al. 2009;US 123 Environ Earth Sci Department of Energy et al. 2009). Each of the regional characteristics that could be relevant to CO2 storage within partnerships is exploring the demonstration of CO2 the basins. Regions investigated in this study included the sequestration in saline reservoirs. Some potential large and northern Gulf Coast, Cincinnati Arch, Colorado Plateau– pilot-scale projects are located within the Gulf Coast, north Arizona, and the Paradox, Illinois, Michigan, and Cincinnati Arch, Colorado Plateau–north Arizona, Wyo- Appalachian basins. Potential seal(s) within the Gulf Coast, ming Thrust Belt, and in the San Joaquin, Unita, Paradox, Illinois, and Paradox Basins were examined in detail for Williston, Illinois, Michigan, and Appalachian Basins their structural, physical, and mineralogical features (Fig. 1) (Litynski et al. 2008, 2009). (Fig. 1). These RCSP demonstration projects are being devel- oped to meet a goal of 99% storage permanence by selecting the demonstration sites following detailed site Seal characteristics for geological CO2 storage assessments coupled with comprehensive site-specific risk assessments (US Department of Energy et al. 2007a, 2009). The ability for a geological seal to retard fluid flow depends Containment of the CO2, along with potential the co-con- on its intrinsic transport properties, which include flow taminant H2S, at each of these sites relies on both the through its primary and secondary porosity. Primary and storage reservoir units as well as the overlying seal rock secondary porosity account for fluid transport through the strata within the geological system (Smith et al. 2009a, b). rock matrix and fault/fracture networks, respectively. The These storage and seal strata can occur broadly throughout effectiveness of seal rocks in trapping CO2 depends on how the basins, and hence can represent potential units for the combination of these intrinsic properties, along with storage beyond the specific sites that have been assessed. A geomechanical and geochemical factors associated with better understanding of the physical and chemical proper- CO2 injection, affect the overall integrity of the seal ties of the storage and seal formation can reduce the risk, (Benson et al. 2005). uncertainty, financial costs, and stakeholder concerns Transport of supercritical CO2 or CO2-saturated brine associated with future commercial CCS projects (Eccles through the primary porosity of seal rock depends on: et al. 2009). capillary entry pressure, permeability, relative CO2–brine The objective of this study was to review available permeability, porosity, and effective diffusion rate through information on the physical and chemical characteristics of fluid-saturated pore space (Hildenbrand et al. 2002; Schl- some geological seal strata within candidate basins con- omer and Krooss 1997). Capillary forces determine the sidered for CO2 sequestration in the US, and to identify capacity of a seal to inhibit flow of a non-wetting phase Fig. 1 Map showing some of the saline basins explored for CO2 sequestration in the US and Canada, with highlighted geological basins and tectonic structures explored in this study 123 Environ Earth Sci through the seal until the pressure of the underlying phase geological seals within the candidate basins (or geologic (such as supercritical CO2) exceeds the capillary entry structures) were surveyed to determine their mineral pressure. Once capillary entry pressure is exceeded, per- characteristics. The dominant mineralogy of the candidate meability and relative permeability will control fluid geological seals is described in stratigraphic order in transport. The rate of fluid transport through the primary Table 1, along with the corresponding storage reservoirs, porosity of the seal rock will depend on the formation’s basin, and geographical location. Based on available data, permeability and thickness, and the fluid pressure in the six seal formations were examined in detail with respect to storage zone and overlying stratum (Schlomer and Krooss their mineralogy, physical, and structural features. The 1997). geological seal strata studied include the formations Transport of CO2 through the secondary porosity of seal immediately overlying the storage reservoirs, as well as rock is generally considered to be of three basic types some of the secondary and tertiary confining units. (Bruant et al. 2002): (1) leakage through poorly sealed or Seal formations examined in detail included: the Gothic failed injection well casing, or improperly abandoned wells and Chimney Rock shales within the Paradox Basin in (Gasda et al. 2004); (2) leakage through pre-existing dis- Utah; the Tuscaloosa Marine Shale and Selma Group solution channels (Kemp 2003); and (3) lateral or vertical within the northern region of the Gulf Coast, particularly in migration of CO2 along faults or fractures (Streit and Hillis Mississippi; the Eau Claire and Mount Simon shale inter- 2004). With respect to the last point, fluid movement along beds within the Illinois Basin, in Illinois. The reported faults or fractures depend on several factors. These factors mineral and physical characteristics of these six seals are include: geometry, fluid pressures within faulted areas, presented in Tables 2 and 3, respectively. In addition, state of stress on pre-existing faults, connectivity of faults structural features and other hydrogeological traits within or fractures, and hydraulic communication between strati- the regions were also examined for their potential influence graphic units (Watts 1987; Aydin 2000; Jones and Hillis on CO2 storage. 2003). Faults can act as a potential barrier or be trans- The data collected for the depth, thickness, lithology, missive due to damage surrounding the fault area or to mineralogy, permeability, porosity, organic content, geo- increased permeability from interlaid sediments (Aydin mechanical properties, and structural
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