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 Saline formations from energy production is proposed to help mitigate cli- Mineralogy Seal integrity 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 (&) D. A. Dzombak 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, Plateau– pilot-scale projects are located within the Gulf Coast, north Arizona, and the Paradox, Illinois, Michigan, and Cincinnati Arch, –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 within the in (Gasda et al. 2004); (2) leakage through pre-existing dis- ; the Tuscaloosa Marine 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 features of the rock 2000). The state of stress on pre-existing faults in seal rock seals were drawn from US DOE regional partnership along with the degree of connectivity and hydraulic com- reports, peer reviewed journals, state and federal geological munication determines if the rock strength may be sus- survey open reports, and university theses containing ceptible to mechanical failure due to CO2 injection, geological data within the regions and vicinity of the pro- resulting in reactivation of pre-existing faults or generation posed demonstration sites. There were limited data avail- of new fractures (Jones and Hillis 2003; Streit and Hillis able to describe the subsurface mineral and physical 2004). properties of the seals. When subsurface data were not Mineralogy of the seal rock is important because of the available, data from equivalent outcrop units were used to potential for alteration of the rock matrix or fault-interlaid- describe the geological strata. The abundance of each sediments due to exposure to supercritical CO2 or CO2- mineral among the seal units was not quantified since some saturated brine. Of concern would be the presence of of the sources only provided uncalibrated or relative minerals susceptible to dissolution by an acidic CO2-satu- amounts. However, the presence or absence of minerals in rated brine that lead to CO2 transport through creation of the seal units was documented in a profile, based on permeable zones or lenses (Benson et al. 2005), and/or available information (Fig. 2). The mineralogical profile fluid flow along fractures and faults present in the seal identified minerals most likely to be involved with rock–

(Schlomer and Krooss 1997; Aydin 2000; Fisher and Knipe brine–CO2 interactions. 2001; Bailey et al. 2006). CO2 transport and the overall Plan view maps of the Northern Gulf Coast Province physical properties of a seal may be affected by the pres- and Illinois Basin (including surrounding states) were ence of soluble mineral phases occurring in clusters, frac- generated with GIS shapefiles given from the respective tures, faults, or within the cement of the seal rock strata state geological surveys, the SECARB, and MGSC regio- (Aydin 2000; Li et al. 2006, 2007; Cunningham and Fadel nal partnerships. The plan view map of the Paradox Basin 2007). was redrawn and spatially georeferenced from literature sources. Site-specific data used by the US DOE regional part- Methods nerships for determining the expected performance of each seal, at their respective localities, were not addres- Several regions of the US are being considered for saline sed. Site-specific analysis was beyond the scope of this

CO2 sequestration. Primary, secondary, and tertiary study. 123 123 Table 1 Basins, localities and generalized lithology, depth, thickness, and dominant mineralogy of geological seals considered by the US DOE for saline CO2 sequestration (in Fig. 1) Geologic Geological storage reservoir Geological seal structure (state), Formation Depth (m) Thickness Formation Depth (m) Thickness (m) Lithology Dominant minerals county (m)

Colorado Kaibab 5121 4.61 Chinle- 1601 3521 Reddish brown siltstone, course Matrix of quartz, feldspar, illite with Plateau Moenkopi 2 , swelling claystone, silty chlorite for Moenkopi with 30–400 3–6 (Northern Coconino 5171 1691 limestone cements of quartz, calcite, Arizona) dolomite, hematite; sandstone 100–3002 Montmorillonitic clay for Chinle3, 6 Cedar Mesa 8241 4011 Organ-rock 6861 1391 Red, poorly sorted, fine-grained Clays with kaolinite-illite, kaolinite, 9 sandstone 20–2002 Shale 30–3002 sandstone, siltstone, mudstone, and illite ; cements of calcite and iron claystone with upper contact a fine- oxide8; outcrops vary in smectite Redwall 1,3981 1661 grained sandstone and lower concentration7 limestone 2 150–300 contact micaceous siltstone7, 8 1. Coconno Tapeats 1,9781 1011 Muav 1,7911 1871 Dolomitic siltstone, glauconitic Framework of monocrystalline County sandstone 2 limestone– 2 mudshale, hematitic sandstone, quartz, glauconite, orthoclase 50–80 100–250 10, 11 2. Apache Bright Angel aphanitic limestone (feldspar), hematite. Cement of County Shale silica, hematite, calcite, and dolomite. Matrix negligible. Clays include illite, kaolinite, and chlorite11 Gulf Coast Midway Shale 1,463–2,07312 244–30512 Argillaceous rock with marine, gray Quartz, calcite, pyrite, (Mississippi) Formation (Jackson Co.) calcareous, and bentonitc shales; montmorillonite, mixed layer illite/ 15 with chalk, marl marine clay, smectite15, 16 – 305 (Adams 12–15 Co.) siltstones and limestone beds Selma Group 1,676–2,37712 30512 (Jackson Chalky marl containing thin beds of Framework of conglomerate (Selma Co.) glauconitic sand and sandstone, calcareous fragments of quartz, Chalk) 14, 17 sandy clay13, 14 calcite/aragonite. Matrix of quartz, – 107–251 14 (Adams Co.) glauconite . Clays include equal amounts of kaolinite, illite, montmorillonite16 3. Jackson Lower 2,62112 5812 Tuscaloosa 2,339–2,48418 137–14518 Fine-grained shales and mudstones12 Mineral composition unknown but County Tuscaloosa Marine occurs within similar marine 4. Adams (Massive 3,10921 15–2721, 22 Shale 3,005–3,12421 11421 environment of the ‘‘Stringer’’ sand County sand) member of the Massive Sand. Shale composed of quartz, kaolinite, illite, hematite, and siderite19. Marine shale equivalent to unnamed upper member of Coker nio at Sci Earth Environ formation composed of quartz, calcite, hematite, kaolinite, muscovite, montmorillonite20 nio at Sci Earth Environ Table 1 continued Geologic Geological storage reservoir Geological seal structure (state), Formation Depth (m) Thickness Formation Depth (m) Thickness (m) Lithology Dominant minerals county (m)

Michigan Lucas 670–89723 229–24423, 24 Dolomite with interbedded anhydrite Dolomite with cementation of Basin Formation and salt, limestone, minor anhydrite25, 26 . Dolomite, calcium (Michigan) sandstone beds. Richfield member sulfate (anhydrite), , calcite24 has porous dolomite24 5. Otsego Bois Blanc- 853–97527; 10727;2223 Amherstberg 897–97223 7623 Dark-brown to black limestone or Calcite, dolomite, anhydrite24 County Sylvania 1,049–1,07123 group dolomite with nodules of anhydrite sandstone27; and small amounts of chert23, 24 Bass Island Dolomite23 Paradox Ismay 1,707–1,76828 40–6128 Gothic Shale 1,707–1,76828 6129 Hard black shales with dolomitic Cements of calcite and dolomite with Basin claystone with varying amounts of plagioclase feldspar, siderite, (Utah) organic matter30 pyrite, clay size quartz, illite– 29 smectite, chlorite, chlorite– 6. San Juan Desert Creek Chimney 9–12 30 County Rock Shale smectite, muscovite, illite . Fracture filling anhydrite and halite29 Appalachian Hamilton 1,617–2,01733,b 6–4133,b Limy black shales interbedded with Illite, chlorite, kaolinite, illite– 34, Basin Group/ \1534 gray–green shales and siltstone smectite, illite–chlorite, calcite, (Ohio) Marcellus 35 quartz35 shale31, 32 Oriskany 1,805–1,81532 1032 Onondaga/ 1,701–1,71933a 1833,a Limestone and chert containing Microcrystalline quartz, calcite, sandstone Huntersville zones of quartz sandstone and dolomite, pyrite, glauconite33, 34, 36 Chert siltstone with phosphatic and formation31, glauconitic zones at base34, 36 32 Middle Saline 2,053–2,14832 9532 Salina Group– 1,951–2,25632 30532 213–24437 Salina Group relatively continuous Halite, anhydrite/gypsum, dolomite, Carbonate Tonoloway with halite, anhydrite/gypsum, illite/smectite, and chlorite/ (C-Unit) formation32, dolomite and gray-green–brown smectite in dolomite and 37 shale units38, 39 . Grades to anhydrite38, 40 Tonoloway in West Virginia with more limestone members37 7. Belmont Medina Group 2,501–2,52232 2132 Lockport 2,256–2,37732 12232 62–14441 Argillaceous dolomite, limestone, Dolomite42 County (‘‘Clinton’’) Dolomite and shale42 Cincinnati Mt. Simon 975–1,06743 9143 Eau Claire 823–97543 15243; 86–19044, In the Cincinnati Arch region, it Quartz, dolomite, calcite, feldspar– Arch sandstone 45 consists of green, gray and red potassium, albite, anorthite (?), (Kentucky) shales with minor finely crystalline glauconite, other clay minerals dolomite, micaceous and (?)47,48 123 8. Boone County glauconitic siltstones, and thin limestone beds45, 46 123 Table 1 continued Geologic Geological storage reservoir Geological seal structure (state), Formation Depth (m) Thickness Formation Depth (m) Thickness (m) Lithology Dominant minerals county (m)

Illinois Basin Eau Claire 1,982 – 91–15250; In the Illinois Basin it consists of Quartz, dolomite, potassium feldspar (Illinois) 1,75349,c 152–21350, 51 silty, argillaceous dolomitic with glauconite and illite main clay sandstone northward, shale minerals in shale subfacies52, 53 eastward, dolomite westward51–53 . Siltstones, shales interbedded with dolomite. Shale interval is regionally persistent near sites53 9. Fayette Mt. Simon 2,134–2,28649 396–53349, Mt. Simon 2,134–2,28649 \15255 Beds of red and green micaceous Illite, quartz, and potassium County sandstone 54 shale shale51 feldspar53 d 10. Coles interbeds County 11. Macon County ? Unsure mineral type a Depth and thickness estimated from core sample intervals in Marshall County, West Virginia b Depth and thickness estimated from core sample intervals in Marshal and Wetzel County, West Virginia c Inferred from description in partnership report d Within the top 152 m of Mt. Simon formation 1 US Department of Energy et al. (2006a), 2 Shirley et al. (2006), 3 Cadigan and Stewart (1971), 4 Repenning et al. (1969), 5 Cadigan (1971), 6 Schultz (1963), 7 Lewis and Trimble (1959), 8 Witkind et al. (1963), 9 Rudd (2005), 10 McKee (1982), 11 Martin (1985), 12 US Department of Energy et al. (2006c), 13 Cushing et al. (1964), 14 Tarbutton (1979), 15 Reeves (1991), 16 Pryor and Glass (1961), 17 Braunstein (1950), 18 US Department of Energy et al. (2007c), 19 Watkins (1985), 20 Bergenback (1964), 21 US Department of Energy et al. (2007e), 22 Beebe and Curtis (1968), 23 US Department of Energy et al. (2008e), 24 Landes (1951), 25 Park (1987), 26 Sullivan (1986), 27 US Department of Energy et al. (2006b), 28 US Department of Energy et al. (2008b), 29 Tuttle et al. (1996), 30 Tromp (1995), 31 Ryder et al. (2007), 32 US Department of Energy et al. (2008c), 33 Repetski et al. (2005), 34 Milici and Swezey (2006), 35 Hosterman and Whitlow (1983), 36 Ozol (1963), 37 Smosna et al. (1977), 38 Oinonen (1965), 39 Tomastik (1997), 40 Hluchy and Reynolds (1989), 41 Farmerie and Coogan (1995), 42 Brett et al. (1995), 43 US Department of Energy et al. (2008d), 44 Rupp et al. (2006), 45 Drahovzal et al. (1992), 46 Becker et al. (1978), 47 Wickstrom et al. (2005), 48 Harris et al. (2004), 49 US Department of Energy et al. (2006d), 50 Tetra Tech (2007), 51 Willman et al. (1975), 52 KunleDare (2005), 53 Finley (2005), 54 US Department of Energy et al. (2007d), 55 Nicholas et al. (1987) nio at Sci Earth Environ Environ Earth Sci

Table 2 Mineral data of geological seals considered for saline CO2 sequestration in the Paradox Basin, Gulf Coast, and Illinois Basin Characteristic Geological seal formations Paradox Basin Gulf Coast Illinois Basin Gothic and Chimney Tuscaloosa Selma Mt. Simon Shale Eau Claire Rock shale Marine Shale Group interbeds

Major mineral components ([20 wt%) Quartz 20–40%1, 2 2–33%3 [20%9 18–24%5 10–33%5 [20%4 [20%6 Carbonates 20–30%2, 7 –––– 15–37%8 Crystalline carbonate cement – 39–45%3 8–58%3 –– Calcite [20%7 – [20%9 –– Low-magnesium calcite – – [20%10, 11 –– Manganese calcite – – [20%10 –– Argillaceous calcilluite – – 14–87%3 –– Dolomite [20%7 – – – 3.6–26%5 [20%6 K-feldspar – – – 19–20%5 20–37%5 Na-feldspar/plagioclase [20%7 –––– Siderite [20%7 [20%4 –– – Hematite – [20%4 –– – Pyrite [20%7 –––– Halite [20%7 –––– Clays *33 wt%7 1–68%3 –– – Kaolinite – 19–100%12 1–96%12 –– (av: 57%, (av: 37%, n: 12)12,b n: 111)12,b [20%4 Illite [20%7 0–81%12 1–85%12 36–41%5 5.5–51%5 (av: 34%, (av: 23%, 82–83%5,a 57–91%5,a n: 12)12,b n: 111)12,b [20%6 [20%4 Illite/smectite [20%7 –––– Glauconite – – 8–28%3 – [20%6 [20%9 Montmorillonite – 0–28%12 0–92% –– (av: 9%, (av: 40%, n: 12)12,b n: 111)12,b Muscovite – 1–22%3 [20%9 –– Chlorite [20%7 – – – 0.5–3.4%5 6.4–39%5,a Chorite/smectite [20%7 –––– Minor mineral components (\20 wt%) Quartz – – 1–9%3 –– Feldspar – 1–8%3 \20%9 –– K-feldspar \20%7, 13 ––– \20%6 Na-feldspar/plagioclase \20%7, 13 – \20%9 1.2–2.5%5 0.8–3.3%5 Nepheline – – \20%9 –– Clinozoisite – – \20%9 –– Calcite – – – 0.7–2.4%5 0.7–2.0%5 Dolomite – – \20%9 1.2–3.4%5 –

123 Environ Earth Sci

Table 2 continued Characteristic Geological seal formations Paradox Basin Gulf Coast Illinois Basin Gothic and Chimney Tuscaloosa Selma Mt. Simon Shale Eau Claire Rock shale Marine Shale Group interbeds

Halite \20%7, 13,c –––– Sylvite \20%7,c –––– Sinjarite \20%7,c –––– Tachyhydrite \20%7,c –––– Anhydrite \20%13,c –––– Gypsum \20%13 – \20%9 –– Apatite (fluorapatite) \20%13 –––– Hornblende – – \20%9 0.4–0.5%5 0.2–0.4%5 Hematite – – \20%9 –– Pyrite \20%7, 13,c – \20%9 0.1–0.5%5 0–1.7%5 Marcasite – – 0.1–0.5%5 0.6–3.2%5 Mixed lattice clay – – \20%12 –– Expandable clays – – 1–1.4%5 1.1–1.6%5,a 0.3–3.2%5; 1.1–2.6%5,a Kaolinite – – – 5–7.4%5 10%5,a 0.3–1.5%5; 1.5–3%5,a; \ 20%6 Chlorite – 1–10%3 \ 20%4 \20%9, 12 2–4.1%5 5.2–6.6%5,a \20%6 Glauconite – 1–15%3 –– – Margarite – – \20%9 –– Sericite – – \20%9 –– Organic content Oil (%vol) – 0.7–4.314 –– – Total organic carbon (TOC) 0.5–11%2 0.2–1.1%15 1.2–1.8%16 –– 0.5–13%1 Total Inorganic Carbon (TIC) – 0.1–3.2%15 –– – av average of dataset, n number of samples analyzed, – data not available a Amounts present in clay size fraction b Average of several formations comprising the outcrop equivalent of the TMS and Selma Group in Mississippi, Tennessee, Kentucky, Illinois, Missouri, and Arkansas c Also vein and fracture filling minerals 1 Raup and Hite (1992), 2 Nuccio and Condon (1996), 3 Bergenback (1964), 4 Watkins (1985), 5 Finley (2005), 6 KunleDare (2005), 7 Tromp (1995), 8 Hite and Lohman (1973), 9 Tarbutton (1979), 10 Czerniakowski et al. (1984), 11 Scholle (1977), 12 Pryor and Glass (1961), 13 Tuttle et al. (1996), 14 John et al. (1997), 15 Miranda and Walters (1992), 16 Bingham and Savrda (2006)

Results and discussion six potential seals within the Gulf Coast, Paradox, and Illinois Basins are presented in Tables 2 and 3, respec- The lithology and dominant mineral characteristics of tively. The mineral data presented in Table 2 are divided several potential seal formations are presented in Table 1. into major and minor mineral components. Here, we define The minerals listed were identified by petrographic and major minerals as those present in more than 20 weight% X-ray diffraction (qualitative and quantitative) analysis. of the rock, and minor minerals as those present in less than For each basin or geologic structure listed in Table 1 the 20 weight% of the rock. Figure 2 presents a profile of the reservoir and seal formations are listed in stratigraphic minerals found within the seal strata. order covering each proposed site(s), with the overlying seal rock adjacent to the storage reservoir(s) and the sub- Common mineralogy sequent seals positioned above. Formation depth and thickness in Table 1 and 3 are in the vicinity of proposed Table 1 and Fig. 2 reveal that calcite, quartz, dolomite, demonstration site(s). Detailed mineral and physical data of illite, feldspar (potassium or sodium), glauconite, and

123 nio at Sci Earth Environ Table 3 Physical data of geological seals considered for saline CO2 sequestration in the Paradox Basin, Gulf Coast, and Illinois Basin with statistical data given when available Characteristic Geological seal formations

Paradox Basin Gulf Coast Illinois Basin

Gothic and Chimney Rock shale Tuscaloosa Marine Shale Selma Group Mt. Simon Shale Eau Claire interbeds

Depth (m) 1,707–1,7681 2,339–2,4843,a ; 1,676–2,3775 2,134–2,2866,7 1,982–1,7536,7,e 3,005–3,1244,b Thickness (m) 611; 9–128 137–1453,a ; 3055; 107–2519,10 \15211 91–15212; 152–21312,13 1143,b ; 152–2444,c Porosity (%) 1014f ; 2.3–8.04 9–4516; – 0.4–1518 (av: 7.7 ± 2.9, 18 1.6–4.115 31–4117 n: 119) Vertical permeability, 39.16–36.8614,f 42.51–40.2119,g 42.62–40.2120,f,g 41.0021,h 41.0021,h ; 41.46–35.2818 2 18 -ln[kv](m) (av: 39.8 ± 1.94, n: 37) Horizontal permeability, 39.16–36.8614,f ; 44.32–44.1215 39.16–37.374 (av: -, n:110)4 \37.55–32.5016; 28.3211,h 28.1711,h ; 28.92–25.2623,h,i 2 23,h,i -ln[kh](m) (av: 44.21 ± 0.09, n: 4)15 28.00–23.6922,g (av: 25.24 ± 1.08, 36.59–34.6617; (av: 27.16 ± 0.84, n: 46) 22,g n: 33) 26.40–24.4027,g ; 29.05–25.4022,g (av: 26.87 ± 1.28, n: 7)22,g Compressive strength, r 166–31115 (av: 247 ± 55, n: 7)15 –– (MPa)d Poission’s Ratio, md 0.24–0.3315 (av: 0.27 ± 0.04, n: 7)15 –– Young’s Modulus, E (MPa)d 38,562–56,6131 (av: 47,315 ± 6,447, –– n: 7)15 Basin areal extent (km2) 28,49024 15,281–119,1394, 25 155,00026

av average of dataset, n number of samples analyzed, – data not available a Jackson County, Mississippi b Adams County, Mississippi c Pike County, Mississippi to Washington Parish, Louisiana d Static mechanical properties determined on 7 sample cores under 24.31–24.97 MPa effective confining pressure, cores from depths of 1,791–1,840 m e Inferred from description in partnership report f Modeled values for groundwater transport simulation g Permeability calculated with water kinematic viscosity, 1.0 x 10-6 m2/s (T = 22°C, P = 0.1 MPa) h Permeability calculated with water kinematic viscosity, 1.1 x 10-6 m2/s, from test well (T = 16.8°C, P = 5.8 MPa) i Estimated from Eau Claire transmissivity data using Eau Claire isopach data of Willman et al. (1975)

123 1 US Department of Energy et al. (2008b), 2 US Department of Energy et al. (2007c), 3 US Department of Energy et al. (2007e), 4 John et al. (1997), 5 US Department of Energy et al. (2006c), 6 US Department of Energy et al. (2006d), 7 US Department of Energy et al. (2007d), 8 Tuttle et al. (1996), 9 Tarbutton (1979), 10 Braunstein (1950), 11 Nicholas et al. (1987), 12 Tetra Tech (2007), 13 Willman et al. (1975), 14 White et al. (2002), 15 Bereskin and McLennan (2008), 16 Scholle (1977), 17 Holston et al. (1989), 18 KunleDare (2005), 19 Planert and Sparkes (1985), 20 Brahana and Mesko (1988), 21 Schicht et al. (1976), 22 Slack and Darden (1991), 23 Visocky et al. (1985), 24 Raup and Hite (1996), 25 US Department of Energy et al. (2007b), 26 McBride and Nelson (1999), 27 Boswell et al. (1965) Environ Earth Sci

Fig. 2 Frequency of predominant minerals reported among candidate geological seals for saline CO2 sequestration in the US

kaolinite were among the most common minerals reported Paradox Basin, Utah for the geological seal formations in the basins evaluated. Due to the variation in reporting methods, mixed layer The Paradox Basin near the ‘four corners’ (Utah, Arizona, clays, though documented with less frequency, are likely to Colorado, and New Mexico) is being considered by the have higher occurrence among the seals, particularly illite. Southwest Regional Partnership for potential saline CO2 The thermodynamic and kinetic reaction characteristics of sequestration demonstration (Fig. 3). One potential dem- these common minerals, especially the clay minerals, under onstration site is near Bluff, Utah, in San Juan County, relatively high reservoir conditions (e.g., salinity, pressure within the southern ‘Blanding sub-basin’ of the Paradox of CO2, temperature) are not well understood (Marini Basin. It is primarily an enhanced oil recovery (EOR) 2007). Based on the current literature of the weathering operation, that would involve the injection of behavior of these common minerals, including a few 450,000–750,000 tons of CO2 into the Ismay and Desert experiments at elevated pressures of CO2, the carbonates Creek zones within the Paradox formation, located at are more susceptible to CO2 attack than the clay or silica depths of 1,707–1,768 m, with an additional 20,000 tons minerals. The reactions depend on the formation water into a saline reservoir formation beneath the oil reservoirs chemistry, temperature, and pressure ranges (Marini 2007). (Litynski et al. 2008; US Department of Energy et al. However, a few experiments with glauconite show that its 2006e). rate of dissolution, in the presence of either acidic or basic solutions, is faster than a generalized illite and comparable Geology to some carbonates (Fernandez-Bastero et al. 2005; Marini 2007). The lack of thermodynamic and kinetic data on the The target reservoir and geological seals for CO2 saline reactions of the common seal mineral phases with injected sequestration lie within the Upper sediments

CO2, under reservoir conditions, implies the need for the of the Paradox formation, in the Paradox Basin. The Par- dissolution rates of these identified minerals to be exam- adox Basin is a large elongate, northwest–southeast ined under such conditions. trending structural depression developed during the Middle The characteristics of candidate seal rocks for saline to Upper Pennsylvanian (Desmoinesian) period. It covers 2 CO2 sequestration throughout the Gulf Coast, Paradox, and an area of approximately 28,500 km ; its boundaries are Illinois Basins are examined in detail in the next section. defined by the limit of the halite deposits in the Paradox

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Fig. 3 Plan view map showing the major folds and faults in and around the Paradox Basin with the demonstration site location called out. Modified from Nuccio and Condon (1996) with additions from Freeman et al. (2008); Huffman and Condon (1993); Johnson (1959); Johnson and Nuccio (1993)

formation, which can thicken up to 4,300 m (Hite 1968; cut by approximately nine regional sets of extension joints, Raup and Hite 1992). The Paradox formation is part of the extending from Middle Pennsylvanian to ages Hermosa Group and contains 29–33 ‘‘cycles’’ or beds of sediments (Grout and Verbeek 1997). The joints extend halite separated by a sequence of clastic and penesaline over 250 km within the region with widths up to 1,000 m interbeds (Hite 1960). The EOR and proposed saline CO2 (Grout and Verbeek 1997). Joints typically run parallel or sequestration operation both use the Gothic and Chimney sub-parallel to the graben-bounding normal faults present in Rock shales for geological seals, though it is unclear how the Fold and Fault Belt and are nearly perpendicular to the Gothic shale serves as a geological seal for the Ismay bedding throughout the basin, regardless of bedding incli- reservoir zone. The Ismay, Desert Creek, Gothic, and nation (Grout and Verbeek 1997). Faults around Lisbon Chimney Rock cycles within the Paradox formation are Valley have a N60°–65°W orientation with a dip of 88°NW contained within the traditionally named ‘Ismay–Desert and strike angles of N21°E and N35°E (Grout and Verbeek Creek Interval,’ which comprise the first five of these 1997). Fault zone sediment displacement affecting geo- cycles (Tuttle et al. 1996; Hite 1960). The Gothic and logical seals can range from 1,200 to 1,500 m (Grout and Chimney Rock shales are cycles 3 and 5, respectively, Verbeek 1997). The Blanding sub-basin, however, is rela- within the ‘Ismay–Desert Creek Interval’, with the shale tively un-deformed (McClure et al. 2003). beds occurring near the center of each cycle (Raup and Hite 1992; Tuttle et al. 1996) (see Fig. 4). Seal lithology

Folds and faults The Gothic and Chimney Rock shale cycles, as well other evaporitic cycles of the Paradox formation, undergo lateral The Paradox Basin has extensive and numerous folds and as well as vertical lithologic facies changes across the faults that can affect the structure of the seal and reservoir Paradox Basin (Hite 1960; Hite and Lohman 1973; Tuttle formations in certain geographical locations. Major struc- et al. 1996). In the Blanding sub-basin, near the basin tural features of the Paradox Basin include the Middle margins and shelf, the Gothic and Chimney Rock shale Pennsylvanian Age -cored collectively cycles contain a sequence of dominantly marine limestone known as the Paradox ‘Fold and Fault Belt’ to the north and with a succession of argillaceous and calcareous black shale the ‘Blanding sub-basin’ to the south-southwest (Fig. 3) (Tuttle et al. 1996; Hite 1960; Wengerd and Matheny 1958; (McClure et al. 2003; Grout and Verbeek 1997) The anti- Wengerd and Strickland 1954). The Gothic and Chimney clines in the Fold and Fault Belt trend N40°–55°W and are Rock shale cycles near Bluff, Utah, grade laterally into beds

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Fig. 4 Cross section (AA0)of Fig. 3 depicting the lithofacies of the Pennsylvanian age sediments throughout the Paradox Basin in relation to CO2 injection. Modified after Huntoon (1988) and Tuttle et al. (1996). Dark horizontal lines represent seal units

of halite with successive interbeds of anhydrite, silty Chimney Rock shale more dolomitic (Hite et al. 1984; dolomite, black shale, dolomite, and anhydrite in the Tromp 1995). The carbonates also act as cementing agents northern regions of the basin (Hite and Buckner 1981; Raup between clay minerals in the shales (Tromp 1995; Tuttle and Hite 1992; Tuttle et al. 1996; Hite and Lohman 1973; et al. 1996). XRD analyses of the clay minerals in the Wengerd and Matheny 1958; Wengerd and Strickland vicinity of the demonstration site show the mixed layer 1954) (Fig. 4). The black shales within the Gothic and illite–smectite and chlorite–smectite to be predominant in Chimney Rock cycles are persistent throughout the Paradox the Chimney Rock shale and Gothic shale, respectively Basin, whereas the halite beds can reach up to (Tromp 1995) (see Table 2). 70–80 weight% of the cycle rock composition (Hite and Lohman 1973). Seal physical properties The mineral characteristics of the Gothic and Chimney Rock black shales are described in Tables 1 and 2. Whole There are limited data on the physical properties of the rock petrographic analysis show that the Gothic and Gothic and Chimney Rock shales, where most of the phys- Chimney Rock shales in the Paradox Basin are approxi- ical data lies in the northern regions of the Paradox Basin mately 1/3 silt and clay-sized quartz, 1/3 carbonates, and (Table 3). Porosity values range from 1.6 to 4.1% with 1/3 clay minerals and organic material (Tromp 1995). horizontal permeability ranging from 5.7 to 7 9 10-20 m2 at X-ray diffraction (XRD) analyses of sample cores from San depths of 1,800–1,838 m (Bereskin and McLennan 2008). Juan County show quartz, illite, dolomite, calcite, pyrite, Table 3 also includes geomechanical properties and mod- chlorite, siderite, and plagioclase (sodium feldspar) to be eled values used for simulation of the vertical and horizontal major minerals in the seal rock near the Utah demonstra- permeability (White et al. 2002; Bereskin and McLennan tion site (Tromp 1995; Tuttle et al. 1996). Throughout the 2008). At depths of 1,791–1,840 m, compressive stress Paradox Basin, vein-filling minerals in fractures and mico- ranged from 166 to 311 MPa, with a Young’s modulus range fractures of the seal rocks include: calcite, anhydrite, pyr- of 38,562–56,613 MPa, and a Poisson’s ratio range of ite, halite, and rare halides like sylvite, sinjarite, and 0.24–0.33 (Bereskin and McLennan 2008). tachyhydrite (Tromp 1995; Tuttle et al. 1996). The car- The seal strata are generally characterized by high bonates are 15–40% by weight, and are divided equally porosity and low permeability, except where fracturing between dolomite and calcite, with the Gothic shale being exists (Hite and Lohman 1973; White et al. 2002; Bereskin more calcareous in the vicinity of the test site and the and McLennan 2008). To the north in the ‘Fold and Fault 123 Environ Earth Sci

Belt’, fractures in the seal rock rocks are numerous and Gulf Coast Province of North America, Mississippi widespread with geometrically complex network patterns and can range from hairline (0.01) to 3.6 cm in width, with The northern region of the Gulf Coast is being studied by strike angles of N21°E (Hite and Lohman 1973; Grout and the Southeast Regional Carbon Sequestration Partnership Verbeek 1997). (SECARB) for possible demonstration of saline CO2 The black Gothic and Chimney Rock shales are rela- sequestration. Two field demonstration sites are being tively uniform (i.e., no folds or unconformities) in the investigated in Mississippi: one at Plant Daniel in Jackson Blanding sub-basin, but contain fractures in some locations County, the other within Cranfield oil field in Adams within the sub-basin (Tuttle et al. 1996; McClure et al. County (Fig. 5). Both sites share the same CO2 storage 2003). For example, a description from a core sample of reservoir and seal units where the proposed storage for- the Gothic shale (cycle 3) from the West Water Creek well mation is the Lower Tuscaloosa Massive Sand formation No. 1 in San Juan County, Utah (about 25 km from the test (LTMS) with the Tuscaloosa Marine Shale (TMS) as the site) reported ‘‘massive fractures or veins filled with sul- caprock and the Selma Group and Midway shale serving as fides and sulfate minerals’’ (Tuttle et al. 1996). Elsewhere secondary and tertiary seals, respectively (US Department in the Blanding sub-basin, the fractures are also described of Energy et al. 2008f; Litynski et al. 2008). The LTMS is as having veins filled with sulfate or carbonate minerals proposed to store up to 3,000 short tons at Plant Daniel in near the limestone contact (Tuttle et al. 1996). Jackson County and up to 2.25 Mt over 1.5 years of natural The Gothic and Chimney Rock shales have been and anthropogenic CO2 at Cranfield, in Adams County, at assessed as good source rocks for potential oil and natural depths exceeding 2,200 and 3,000 m, respectively (US gas production in Utah and Colorado (Nuccio and Condon Department of Energy et al. 2006c, US Department of 1996; Schamel 2006). Characteristics that make them Energy et al. 2007f). In this study, only the TMS and Selma potentially good source rocks include: total organic carbon Group seals are examined in detail. (TOC) values ranging from \0.5 to 13%, hydrocarbon- yielding potential (S1 ? S2) values of [2.0 mg hydrocar- Geology bon/g sample, organic matter of Type II and III kerogen, and sufficient thermal maturity, i.e., production index (PI) The target reservoir and geological seals for CO2 saline and vitrinite values, throughout most of the basin (Hite sequestration lie within the Upper Cretaceous Gulfian sedi- et al. 1984; Nuccio and Condon 1996). There is also strong ments of the northern region of the Gulf Coast Province of lateral variability in organic matter within the two shales, North America (Fig. 5). The northern region of the Gulf apparently associated with the lateral facies changes of the Coast Province of North America covers a total area of formations (Van Buchem et al. 2000). Regions within the approximately 750,000 km2 with the LTMS and associated Paradox Basin where the Gothic and Chimney Rock black seals covering 120,000 km2 (Ryder and Ardis 2002;US shales are enclosed by thick beds of halite are thought to Department of Energy et al. 2007b). The northern Gulf Coast entrap potentially more natural gas versus oil (Schamel includes parts of Florida, Alabama, Mississippi, Louisiana, 2006). Texas, Arkansas, Tennessee, Kentucky, Missouri, and Illi- In summary, the Gothic and Chimney Rock shales nois (Murray 1961; Ryder and Ardis 2002). Broadly speak- undergo significant physical and chemical changes across ing, the Upper Cretaceous System of the coastal province the Paradox Basin. Features relevant to CO2 storage form a syncline filled with vast amounts of sediment include: regionally extensive units with high porosity and accompanied by folding, faulting, intrusions of igneous rock, low permeability; variation in lithology, mineralogy, and and with regional uplifts along the axis of the trough. The thickness (9–61 m); and the presence of filled fractures overall dip of the sediments within the syncline are seaward, throughout the basin. The lithology of the Gothic and where the degree and slope are being modified by vertical Chimney Rock shales across the basin changes from pri- warping, fault and fracture systems of varying magnitude, marily carbonates in the south, to salt and anhydrite cycles and by igneous and salt emplacements (Murray 1961). in the north. Naturally occurring fractures in the seals are documented mostly in the northern, with some in the Folds and faults southern, regions of the basin, ranging from ‘‘hairline’’ to ‘‘massive’’ (Hite and Lohman 1973; Tuttle et al. 1996). The Folds and uplifts, in certain localities across the northern fractures are filled with carbonates, halides, anhydrite, and Gulf Coast region, may alter seal and storage strata. Mur- pyrite (Tuttle et al. 1996; Tromp 1995). Numerous faults ray (1961) describes the structural and stratigraphic geol- transect the Paradox formation in the northern region and ogy of the Northern Province of the Gulf Coast with major are mainly associated with the anticlines within the ‘Fold features occurring in southern Mississippi that include: the and Fault Belt’ (Grout and Verbeek 1997). Wiggins Uplift, Monroe Uplift, Jackson Dome, and La 123 Environ Earth Sci

Salle Arch (Fig. 5). The folds generally trend northwest– Pickens-Gilbertown can range from 150 to 300 m. The southeast with the Wiggins Uplift having bifurcating lobes: Jackson-Mobile graben is another fault zone in the sur- the Wiggins to the northwest and the Hancock rounding region affecting Cretaceous sediments (see ridge to the south. The Wiggins Uplift is associated with Fig. 5). Both the Pickens-Gilbertown and the Jackson- complex and pronounced faults of thick early – Mobile have similar characteristics, with varying degrees Tertiary age sediments. It is not clear if the faults influence of sediment displacement and associated strata, possibly Cretaceous age sediments, which contain the storage res- complexly warped and faulted. ervoir and seal units (Murray 1961). Both the Monroe Uplift and the Jackson Dome are known to affect the Other structural features storage and seal sedimentary strata. The Monroe Uplift is offset by emplacement of relatively large igneous masses Numerous salt structures exist along the Northern Province with pronounced angular unconformities. The Jackson of the Gulf Coast (Murray 1961) (see Fig. 5). The is an uplift that has thick, tilted, and truncated strata structures can occur as piercements (spikes) or large overlain with an angular unconformity. The La Salle Arch elongated masses in which the enclosing sedimentary strata is a gently dipping structure affecting all Tertiary strata, can exhibit upwarping and thinning of beds adjacent to the with Gulfian and Comanchean strata to a possibly lesser salt rock. Normal faulting is typically associated with salt extent. The La Salle arch is generally not associated with piercements, but can have multiple offset faults and frac- any appreciable faulting (Murray 1961). tures penetrating adjacent sediment strata. This is the case The major fault systems in Mississippi are the Pickens- for the Tuscaloosa formation in the Jasper and Lincoln Gilbertown graben and the Jackson-Mobile fault systems counties of Mississippi (Murray 1961). (Murray 1961). The Pickens-Gilbertown penetrates and displaces surface to subsurface strata, including the Cre- Seal lithology taceous LTMS, TMS, and Selma Group sediments. It is a gulfward trending concave system of normal faults Figure 6 shows the lateral facies changes of the Tuscaloosa extending 1,610 km relatively uninterrupted through the Marine Shale (TMS) and Selma Group as they grade Northern Gulf Coast Province, having faults upward and inland across Mississippi and the Northern 8,000–12,900 km wide running parallel or sub-parallel to Gulf Coast Province towards Arkansas and Tennessee. the regional strike (see Fig. 5). The regional strike ranges The TMS is a fissile, fine-grained, dark-gray micaceous from NW30° to 40°SE, with dip angles ranging from 35° to shale with minor interbeds of calcareous, glauconitic sand- 70° gulfward. Sediment displacement associated with the stone with some argillaceous limestone lentils, laminated

Fig. 5 Plan view map showing the major folds and faults within the Northern Gulf Coast Province, with potential saline CO2 sequestration demonstration sites called out

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Fig. 6 Cross section (AA0)of Fig. 5 depicting the lithofacies of the Upper Cretaceous, Gulfian sediments throughout the eastern region of Northern Gulf Coast province in relation to CO2 injection. Modified from Murray (1961) and Tarbutton (1979). Seal units highlighted in gray

claystone, mudstones, and calcareous siltstone (Braunstein anomalously high geothermal and hydrostatic pressure 1950). Tables 1 and 2 lists petrographic data taken from gradients which can result in significant variability in fluid thin-sections and cores in Alabama near the outcrop of the properties. Most of the permeability data for the TMS were equivalent Coker-Eoline formation, and from the shales of given in N. Mississippi with hydraulic conductivity that the ‘‘Stringer’’ member of the Lower Tuscaloosa (Cushing were converted to intrinsic permeability assuming a normal et al. 1964) (see Fig. 6). The TMS is predominantly com- geothermal and hydrostatic gradient with an average posed of quartz, kaolinite, illite, hematite, and siderite based kinematic water viscosity of 1.0 x 10-6 m2/s (Slack and on point-counts of thin-section and qualitative X-ray dif- Darden 1991; Brahana and Mesko 1988). Vertical perme- fraction (XRD) (Pryor and Glass 1961; Bergenback 1964; ability was estimated to range from 3.4 to 34 9 10-19 m2, Watkins 1985). based on well testing of confining beds within the Gordo The Selma Group contains chalks, chalky marl, and and Coker formations in Alabama (Planert and Sparkes limestone members. Tables 1 and 2 show manganese, 1985). The Gordo and Coker formation are the surface- ferrous, and magnesium carbonates within the limestone equivalent to the subsurface Upper Tuscaloosa and TMS members and kaolinite, montmorillonite, illite, and glau- (Planert and Sparkes 1985; Strom and Mallory 1995) (see conite within the marl members. Mineralogy of the Selma Fig. 6). Horizontal permeability of the TMS at depths Group was compiled from semi-quantitative XRD data on greater than 3,500 m range from 1 to 6 9 10-18 m2 in samples near the surface in Alabama, Tennessee, Ken- southeast Louisiana (John et al. 1997). In northern Mis- tucky, Illinois, Missouri, and Arkansas, and qualitative sissippi at shallower depths, the horizontal permeability of XRD, thin-section, and insoluble residue analyses on the TMS ranges from 7 to 520 9 10-13 m2, based on the equivalent formation core samples from central to east Gordo and Coker formations (Slack and Darden 1991). The Texas (Pryor and Glass 1961; Bergenback 1964; Scholle thickness of the TMS varies from 114 to 244 m across 1977; Czerniakowski et al. 1984). southwest Mississippi and central Louisiana, and from 137 to 145 m in the Jackson County, Mississippi area (John Seal physical properties et al. 1997; US Department of Energy et al. 2006c). Few data were available for permeability and porosity of Few data were available on the permeability and porosity the Selma Group in southern Mississippi. Table 3 has the of the TMS in southern Mississippi. Table 3 lists the vertical permeability estimated to be similar to TMS with thickness, porosity, and permeability available for the TMS range from 3.1 to 34 9 10-19 m2 (Brahana and Mesko within the northern Gulf Coast Province. Porosity ranged 1988). Horizontal permeability range from \0.5 to from 2.3 to 8% based on a report in the Gillsburgh Oil field 100 9 10-16 m2, in Texas, where the Austin Group is the adjacent to Adams County (John et al. 1997). Mississippi, Selma Group equivalent (Scholle 1977). In northern Mis- and other states along the Gulf Coast, have localities with sissippi, the horizontal permeability ranges from 2.4 to

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93 9 10-13 m2 (Slack and Darden 1991). In Alabama, the primary seal with the shale interbeds of the Mount Simon -16 2 horizontal permeability is in the order of 1 to 9 x 10 m modeled to further restrict flow of CO2 (Finley 2005;US (Holston et al. 1989). The porosity of the Selma Group Department of Energy et al. 2006d, 2008g). The Mount ranged from 9 to 45% in Texas and Alabama, with 31–41% Simon sandstone is capable of storing 10,000–1,000,000 t in some areas in Alabama, and is depth dependent (Scholle of CO2 in Illinois, at depths ranging from 2,130 to 2,290 m 1977; Holston et al. 1989). (US Department of Energy et al. 2006d, 2008g; Litynski The TMS and Selma Group are oil and gas source et al. 2008; Litynski et al. 2009). Additional geological formations within certain localities in Mississippi and seals include the Maquoketa formation and the New other regions along the Gulf Coast (Beebe and Curtis Albany Shale, 910–1,130 m above the Eau Claire, 1968; Scholle 1977; Condon and Dyman 2006; John et al. respectively (Finley 2005). In this study, only the upper 1997). The TMS contains significant amounts of ther- member of the Mount Simon and the lower members of the mally mature total organic carbon ([0.5%) and has Knox group (the Eau Claire and the Ironton–Galesville reports of oil production in southwest Mississippi (Mir- sandstone) were examined in detail. anda 1988; Miranda and Walters 1992; John et al. 1997; Mancini 2005) (see Table 2). Fractures are noted in TMS Geology core samples from Lincoln, and Amite County and were associated with oil production (John et al. 1997). The The proposed sites, storage reservoir, and geological seals

Selma Group has significant gas production in certain for CO2 saline sequestration in Illinois lie within the horizons in south central Mississippi, and in east Texas age sediments of the Illinois Basin (Figs. 7, 8). (Condon and Dyman 2006; Beebe and Curtis 1968; The Illinois Basin is a spoon-shaped, asymmetrical shallow Scholle 1977). structural depression that trends northwest–southeast and In summary, the TMS and Selma Group undergo covers an area of 155,000 km2, with the deepest part of the significant physical and chemical changes across the basin (4,570 m) near the intersection of Illinois, Indiana, northern Gulf Coast region. In particular to Mississippi and Kentucky (McBride 1998; Finley 2005). Regional (and adjacent states), changes that could be relevant to slopes reverse direction at the borders of the arches and saline reservoir CO2 storage include: thick (114–305 m), domes, and the basin’s sediments are overlapped by the regionally extensive units with variations in lithology, Mississippi Embayment to the south where it is complexly permeability, and porosity; the presence of fractures and faulted, and subjected to seismic reactivation, as it salt piercements; and, oil and gas production from the approaches the New Madrid Rift System and the Rough seal rocks in the southwest areas of Mississippi. Perme- Creek Graben (Willman et al. 1975; McBride and Nelson ability of the TMS and Selma Group varies significantly 1999) (see Fig. 7). along the Gulf Coast. Between south and north Missis- sippi, the horizontal permeability of the TMS and Selma Folds and faults Group can increase up to six orders of magnitude with up to ten orders of magnitude difference between their There are numerous folds in Illinois Basin. In Illinois, vertical and horizontal permeabilites. Lithology of the Major features include the late –early Penn- TMS and Selma Group changes from predominantly sylvanian Du Quoin monocline, Louden, La Salle ‘Antic- shale and chalk, respectively, in southern Mississippi to linorium’ (LSA) and Clay City anticlines (see Fig. 7). sandstone in northern regions of Mississippi, Alabama, These folds extend over 400 km in the region and are and Tennessee. north-trending, asymmetrical anticlines and monoclines that are elongated and branched (McBride 1998). Their Illinois Basin, Illinois folding, particularly the Clay City anticline, can affect the entire Paleozoic sediments, including the storage and The Illinois Basin is being studied by the Midwest Geo- geological seal(s) (McBride and Nelson 1999). logical Sequestration Consortium (MGSC) for possible Associated faults beneath several anticlines and mono- saline CO2 sequestration demonstration projects. In Illi- clines within the Fairfield sub-basin have normal, high- nois, three potential sites are being investigated: the Lou- angle reverse, and antithetic faults with dip angles ranging den and Mattoon oil fields, and the Archer Daniels Midland from 60° to 75° (McBride 1998; McBride and Nelson Company (ADM) ethanol plant (Litynski et al. 2008, 1999). Sediment displacement associated with faults along 2009). They are located in Fayette, Coles, and Macon the Du Quoin monocline range from 30 to 50 m (McBride County, respectively. All of these sites proposed to inject and Nelson 1999). The Cottage Grove fault system is a

CO2 into the reservoir and use the major fault system in the Fairfield sub-basin that contains a overlying , of the Knox group, as the series of transgressional reverse faults that form a strike– 123 Environ Earth Sci

Fig. 7 Plan view map showing the major folds and faults within the Illinois Basin, with potential saline CO2 sequestration demonstration sites called out

Fig. 8 Cross section (AA0)of Fig. 7 depicting the lithofacies of the Cambrian age sediments throughout Illinois in relation to CO2 injection. Modified from Willman et al. (1975). Seal unit highlighted in gray

slip zone that affects the entire Paleozoic strata and Pre- are thousands of feet apart), along with the indication of cambrian basement (McBride and Nelson 1999) (see having strike–slip components that could provide a struc- Fig. 7). High-resolution seismic studies show that these tural fabric capable of seismic reactivation (McBride 1998; faults transect primary, secondary, and tertiary seals (which McBride and Nelson 1999).

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Other structural features permeability ranged from 1 9 10-18 to 4.8 9 10-16 m2 and porosity from 0.4 to 15% (KunleDare 2005; Schicht Seismic activity exists within the New Madrid Seismic et al. 1976). Data were gathered from core samples in Zone (NMSZ), located in the southern region of Illinois at Henderson County, Illinois and estimated from flow-net the border of Kentucky and Wisconsin (see Fig. 7). The analysis. Horizontal permeabilities were estimated across NMSZ is a structurally complex zone of faults associated multiple wells in northern Illinois, ranging from 2.8 x 10-13 with a long history of reactivation (McBride 1998; to 1.1 x 10-11 m2 (Nicholas et al. 1987; Visocky et al. McBride and Nelson 1999). Earthquakes are spatially 1985). Thickness of the Eau Claire ranges from 60 to associated with the extension of the NMSZ to the La Salle 300 m throughout Illinois, and 152–213 m near potential Anticlinorium (LSA) and Wasbash Valley Fault System demonstration localities (Finley 2005; Willman et al. (WVFS) in the Fairfield sub-basin of the Illinois Basin 1975). (McBride 1998; McBride and Nelson 1999). No permeability or porosity data for the Mount Simon shale interbed layers were available in southern Illinois. Seal lithology However, in northern Illinois, the shale interbed layers were tested to give a permeability of 5.1 9 10-13 m2,in The Eau Claire formation undergoes significant lateral Table 3, where the shaley interbeds behave effectively as a lithologic facies changes in the Illinois Basin. Figure 8 hydraulic confining unit for water movement from the shows that the Eau Claire trends from a sandstone or sandy Mont Simon aquifer (Visocky et al. 1985; Nicholas et al. dolomite in northern Illinois to a siltstone or shale in 1987). Initial modeling done by the MGSC has indicated central Illinois, to a mixture of dolomite and limestone near that the shaley interbeds of the upper segment of the Mount the Missouri border, where it is a relatively pure dolomite Simon could inhibit CO2 migration in southern Illinois but (Willman et al. 1975; Finley 2005). In Macon County, are not likely to be used as a separate, effective seal (Finley regional cross-sections show the Eau Claire to have a 2005). The thicknesses of the Mount Simon shale intervals persistent shale interval above the Mount Simon sandstone. are reported to be 150 m with individual shale beds as thin The siltstone facies contain clay seams and laminae and is as 4.6 m thick (Nicholas et al. 1987; Willman et al. 1975). commonly interbedded with very dark green to black shale The areal extent and continuity of the Mount Simon shale (Willman et al. 1975; Finley 2005). Table 2 lists qualitative intervals are not known (Nicholas et al. 1987; Finley 2005). and quantitative X-ray diffraction (XRD) data from two In the Illinois Basin, the Eau Claire is generally locations in Illinois that shows that the Eau Claire, by described as being an effective seal for successful natural volume percent, is dominantly illite, quartz, and dolomite, gas storage projects in the Mount Simon (Finley 2005). with glauconite or chlorite also being a major component in However, there is evidence of gas migration into overlying some reports (KunleDare 2005; Finley 2005). formations in certain localities where the Mount Simon is The shale interbeds in the upper segments of the Mount cut by at least four faults (Finley 2005).

Simon formation are present at the sites considered for Possibly relevant to CO2 storage in the northern areas of storage, and are considered a confining unit for ground- Illinois, is the observation of saline water movement into water movement in northern Illinois (Nicholas et al. 1987; the Ironton–Galesville aquifer from adjacent aquifers, Finley 2005). The shale interbeds are lithologically including the Mount Simon (Visocky et al. 1985; Nicholas described as red and green micaceous shales with illite, et al. 1987). The movement of water into the Ironton– quartz, and potassium feldspar as dominant minerals (see Galesville from the Mount Simon through the Eau Claire Table 2) (Finley 2005). confining unit, as well as other adjacent aquifers, was documented via well tests and measurements of conduc- Seal physical properties tivity, temperature, and chloride. The influx of water appears to have been induced by excessive pumping of Few data are available on the permeability and porosity of Ironton–Galesville aquifer around the Chicago area in the Eau Claire in southern Illinois. The thickness, porosity, northern Illinois (Visocky et al. 1985; Nicholas et al. 1987). vertical and horizontal permeability of the Eau Claire are In summary, the physical and chemical characteristics of reported in Table 3. Some permeability data were reported the Eau Claire vary across the Illinois Basin. Features as hydraulic conductivity and transmissivity data, which relevant to saline CO2 sequestration include its use for were converted to intrinsic permeability using Eau Claire current, successful natural gas storage projects; regionally isopach data of Willman et al. 1975 and assuming a water extensive units with variations in thickness and lithology; kinematic viscosity of 1.1 x 10-6 m2/s derived from a test existence of faults throughout the southern region of the well in Lake County, Illinois (T = 16.8, P*5.8 MPa) basin; seismic activity in the NMSZ; and, brine movement (Nicholas et al. 1987; Visocky et al. 1985). Vertical through the seal in localities near Chicago. The 123 Environ Earth Sci characteristic behavior of the Mount Simon shale interbeds and interconnectivity. Detailed site-specific data are nee- across the Illinois Basin is unclear. However, within ded to assess the influence of fractures, lithologic changes, northern Illinois, available reports indicate that the shale and variable permeability and porosity at any particular site interbeds behave as an effective hydraulic confining unit with the basin. (Nicholas et al. 1987). Faults and fault zones are common within each of the regions examined. The influence of fault proximity, extent of deformation, and fluid conductivity on seal strata per- Summary and conclusions formance at a potential site within the Gulf Coast, Paradox or Illinois Basin merits investigation. The goal of this study was to review available information Proposed seal formations in Mississippi and Utah are on the physical and chemical features of geological seal considered source rocks for oil and gas production in some strata within some candidate basins considered for saline areas within the two regions. The potential effects of

CO2 sequestration in the US and present characteristics that recovery operations on the performance of the seals used could be relevant to CO2 storage. Several seal strata were for potential CO2 storage, in those localities, need to be examined for their dominant mineral phases in their investigated. Related efforts on enhanced oil recovery lithology. Based on available data, a subset of these seal could provide insight into the integrity of the seals that strata also were examined for their structural features and previously served as oil and gas source formations. physical properties. There exist other regional features that could be relevant

The main conclusions are: (1) seal formations are to CO2 storage. For instance, the salt piercements and regionally extensive, and are generally thick with low domes found within the Gulf Coast and Paradox Basin permeability; (2) common minerals among the seal for- could affect seal integrity due to the offset faulting and mations include quartz, illite, dolomite, calcite, and glau- fractures frequently associated with them. In the Illinois conite; (3) there is substantial spatial variability in the Basin, excessive pumping of overlying aquifers near composition, thickness, and fluid transport properties of the metropolitan areas may affect CO2 transport at shallower seal formations within the basins; (4) fractures and faults depths. Knowing where these features exist can aid in penetrate seal strata throughout the basins examined, determining the most favorable site(s) for demonstrating highlighting the importance of site-specific evaluations in CO2 sequestration, where the extent and manner in which the selection of a storage reservoir; (5) some of the seal these geological phenomena influence seal performance rock strata are oil and gas sources; and (6) each basin has would be determined by site-specific studies. unique regional features that could be relevant to CO2 This review of physical and chemical characteristics of storage, such as the presence of salt piercements, previous the seal rock formations overlying candidate saline reser- seismic activity and infringement on water resource aqui- voirs has highlighted features that merit focused attention fers in certain localities. The significance of these features when investigating candidate sites for long-term CO2 with regards to site-specific seal integrity is currently the storage within these selected basins. The common char- focus of investigations conducted by the US DOE regional acteristics identified in this study regarding heterogeneity partnerships. in seal composition, physical attributes, and regional Understanding the reactive behavior of minerals in rock structural features can help guide modeling, laboratory, and cements and matrices with CO2 and brine, under relevant field studies for site-specific assessments. temperatures, pressures, and salinities, is necessary to understand the extent of chemical alterations within can- Acknowledgments This research was funded by the US Depart- didate seals. The data compiled in Tables 1, 2, and 3 are ment of Energy through the Student Career Experience Program (SCEP), and the Minority Mentoring and Internship Program useful for modeling basin-wide CO2 transport and deter- (MMIP). The authors benefited from various discussions with mining the kinds of minerals that merit special attention in researchers, project managers, principal investigators, and industry the lab and field investigations. partners of the Regional Carbon Sequestration Partnerships (RCSPs), Seal strata examined are generally thick, ranging from 6 and with geologists at state agencies. The authors are also grateful to Dann Burton for drawing the cross-sectional views. to 352 m in the areas examined, and generally exhibit low permeability. The seals are not continuous or uniform in lithology throughout the regions examined, having lateral facies changes, fractures, and spatial variability in thick- References ness, permeability, porosity, and other physical properties Aydin A (2000) Fractures, faults, and hydrocarbon entrapment, that could impact seal performance within certain areas of migration and flow. Mar Pet Geol 17:797–814 the candidate basins. Fractures reported in seal strata are Bailey WR, Underschultz J, Dewhurst DN, Kovack G, Mildren S, not fully characterized and have unknown regional extent Raven M (2006) Multi-disciplinary approach to fault and top 123 Environ Earth Sci

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