Abstract Over the past 20 yr, the concept of storing or permanently storing (i.e., sequestering) carbon dioxide (CO 2 ) in geological media has gained increasing attention as part of the important technology option of carbon capture and storage (CCS) within a portfolio of options aimed at reducing anthropogenic emissions of greenhouse gases to the earth’s atmosphere (International Energy Agency [IΕΑ], 2004 , 2008 ; Pacala and Socolow, 2004 ; Intergovernmental Panel on Climate Change [IPCC], 2005 , 2007 ; Socolow, 2005 ; Balat and Öz, 2007 ; Bryant, 2007 ; National Energy Technology Laboratory [NETL], 2008 ). Research programs focusing on the establishment of field demonstration projects are being implemented worldwide to investigate the safety, feasibility, and permanence of CO 2 geological sequestration. The number of potential geological sinks for sequestration of CO 2 , such as depleted oil and gas reservoirs, deep-saline reservoirs (brine-filled formations), and deep, unmineable coalbeds, is shrinking. The technology to use these sinks is in various phases of applicability and implementation, with CO 2 sequestration in enhanced oil recovery being the most mature and economically feasible and CO 2 sequestration in coal beds in conjunction with enhanced coalbed methane recovery being still in the demonstration phase. Currently, the most significant barrier to the implementation of geological sequestration lies in the high cost of CO 2 capture, but major challenges also still exist in defining and identifying sinks with the necessary capacity in proximity to major CO 2 sources as well as identifying, mitigating, and remediating

Abstract Coal, oil, and natural gas currently supply about 85% of the world’s energy needs. Unfortunately, the burning of these fossil fuels is the major source of anthropogenic carbon dioxide, which is also the main greenhouse gas released to the atmosphere. One promising means by which to reduce CO 2 emissions, and so the atmospheric buildup of CO 2 , is geosequestration. Geosequestration, also known as carbon capture and storage (CCS), involves the long-term storage of CO 2 in deep subsurface geological reservoirs. Geosequestration comprises several steps that include the capture of CO 2 , the transport of CO 2 , the injection of CO 2 into suitable reservoirs, and finally, the storage and monitoring of the CO 2 that has been introduced into the reservoir. Geological input into the evaluation of storage sites, including injection, storage, and monitoring and verification of volumes and movement of CO 2 plumes, is critical for acceptance of CCS technologies. Detailed characterization and realistic modeling of reservoir and seal properties, as well as of rock and fault integrity, will permit a more viable analysis of risks associated with the subsurface containment of injected CO 2 . Geosequestration can be a significant factor in the portfolio of CO 2 emissions reduction strategies because by reducing CO 2 emissions while still allowing for the continued use of fossil fuels, geosequestration buys time for the transition to renewable energy sources.

Abstract Carbon dioxide (CO 2 ) sequestration in coal seams represents one (of only two) geological sequestration option that has the potential to yield a value-adding byproduct (enhanced coalbed methane [ECBM] recovery) to mitigate sequestration costs (the other being enhanced oil recovery [EOR]). Although the global pervasiveness of coal seams and their substantial adsorption capacity for CO 2 would suggest they represent a significant sequestration opportunity, the infancy of the technology as well as concerns over future coal minability has tempered sequestration capacity estimates. These two issues, an incomplete understanding of the interactions between CO 2 and coal (and the implications that derive therefrom, such as knowing what are the most appropriate geological environments for sequestration, what are the best well development strategies, how should wells be operated, etc.) and the potential future minability of coal (i.e., what exactly is a deep, unminable coal that will not be developed at some future date), represent the major obstacles to widespread acceptance of coal seams as a viable carbon sequestration option. The largest CO 2 -ECBM field test was performed by Burlington Resources (now ConocoPhillips) at the Allison unit in the San Juan Basin from 1995 to 2001. In this pilot test, approximately 336,000 t of CO 2 was injected into four wells completed in the Fruitland coal. Improvement in ECBM recovery was predicted, and the ability of the coal to adsorb and retain CO 2 was demonstrated. Smaller two-well and single-well tests have also been performed in Poland, Japan, Canada, and China. These are primarily government-funded demonstration projects with the primary objective of testing carbon sequestration technology. Additional field tests with similar objectives are also currently (as of this writing) in the planning stages as part of the U.S. Department of Energy’s (DOE) Regional Carbon Sequestration Partnership program. Economic analysis suggests that the CO 2 -ECBM process can be profitable in some cases. Besides the obvious importance of infrastructure costs and energy prices to economic performance, a key technical factor is the ability to maintain high CO 2 injection rates into the coal seams, which is a challenge because CO 2 tends to swell coal, thus reducing permeability and injectivity. Overcoming this challenge, via the identification of the most favorable reservoir environments, the best project development strategies, appropriate operating practices, etc., represents a critical milestone toward the widespread acceptance of the technology.

Abstract Germany is the largest emitter of CO 2 in the European Union. Many of the large point sources are inland, farther away from the coast, so that CO 2 capture and storage can only become a widely applied option if suitable onshore storage sites can be found. Apart from storage capacity, storage safety and possible leakage rates are critical factors that influence the available storage potential. Although companies are willing to start storage projects in Germany soon, no legal or regulatory basis exists yet. Storage options that have been discussed for Germany include aquifers, natural gas and oil reservoirs, abandoned coal mines and unminable coal seams, abandoned potassium mines, mineralization, and injection into the sea. Pros and cons of the different options are described below. Aquifers and natural gas fields are considered to be the most realistic storage options for a near-term use. Oil fields will provide only local opportunities. Coal might be an option for the future. Potassium mines, the sea, and mineralization are not considered to be safe, economical, or acceptable options. Although the storage capacity of the gas fields can be estimated fairly accurately, the presumably larger capacity of deep saline aquifers is much more difficult to estimate. The problems of capacity estimates for single structures and Germany as a whole are discussed. To date, only a few regional assessments of storage options have been made. A consistent evaluation of underground structures and their potential suitability for CO 2 storage is under way in a joint undertaking by the federal and state geological surveys and the hydrocarbon industry. An important task in this mapping project is the definition of criteria that can be used for site evaluation, comparison, ranking, and selection of sites. These criteria must be based on information generally available from standard underground information (well reports, logs, seismic profiles) and should include the selection and use of common default values for uncertainty estimates in cases when data are missing, e.g., sweep efficiencies or aquifers without information from drilling. The common methods for capacity estimation need to be applicable to different regions.

Abstract The Colorado Geological Survey is a participant in the Southwest Regional Partnership on Carbon Sequestration project. The primary goal of the project is to determine an optimum strategy for minimizing greenhouse gas intensity in the southwestern United States. The Southwest Regional Partnership is led by the New Mexico Institute of Mining and Technology and comprises a large diverse group of expert organizations and individuals specializing in carbon sequestration science and engineering, as well as public policy and outreach. In 2000, carbon dioxide (CO 2 ) emissions in Colorado exceeded 83.5 mmt (92 million tons) and are projected to increase by 2.4% per year through 2025. Nearly 76% of these emissions results from activities in the utility and transportation sectors. Power generation in the state relies primarily on coal, and as a result, 38 mmt (42 million tons) of CO 2 , or 46% of the total emissions in Colorado, is emitted from power plants in the utility sector. These stationary point sources afford the possibility of capture and separation of CO 2 for transport to and storage at nearby sinks. The remaining 54% of Colorado’s emissions result from the transportation, industrial, residential, and commercial sectors. Although CO 2 sink potential is widely distributed across the state, characterization efforts focused on seven pilot study regions defined on the basis of maximum diversity in potential sequestration options relatively close to large CO 2 sources. Using both geologic and mineralization options, carbon storage capacity within these regions is an estimated 653 billion t (720 billion tons). With the availability of suitable technology, the pilot areas have the potential of providing a long-term storage solution based on 2000 CO 2 emission levels. The highest CO 2 sequestration capacity potential for Colorado lies within the oil, gas, coalbed, and saline aquifer reservoirs of the Denver, Cañon City, Piceance, and Sand Wash basins. Further site-specific investigations are required to determine both the technical and economic feasibility of implementing carbon storage projects in any one of these areas.

Abstract The use of crude oil-bearing strata as geological sinks for sequestration of carbon dioxide (CO 2 ) includes a value-added component for recovering new oil from existing oil fields that have undergone primary and/or waterflood production. Carbon dioxide has been used in enhanced oil recovery (EOR) for more than two decades in the Permian Basin of west Texas. This CO 2 experience suggests that following water flooding with CO 2 flooding produces an additional 10% of original oil in place (OOIP) or an additional 25% beyond total oil produced during the primary and water flooding phases. The Midwest Geological Sequestration Consortium has studied the CO 2 EOR potential of the Illinois Basin in Illinois, Indiana, and Kentucky. Oil has been produced from this basin for more than a century, to date yielding a cumulative production of 4.3 billion of an estimated 14.1 billion bbl of OOIP. The consortium’s study focuses on three topics regarding the potential of CO 2 flooding in Illinois Basin fields. The first is evaluation of oil recovery potential employing geological, geostatistical, and reservoir models built for specific geological settings. The second is estimation of total hydrocarbon available to CO 2 flooding, requiring an updated estimate of the basinwide OOIP. The third is calculation of the total volume of carbon that could be sequestered by such programs and the volume of additional hydrocarbon recovery that might reasonably be expected. Using west Texas experience as a guideline, reservoir modeling results suggest that 0.86–1.3 billion bbl of oil may be recoverable from the Illinois Basin using CO 2 EOR. Along with this incremental oil recovery, an estimated 154,000–485,000 tons of CO 2 can be sequestered simultaneously.

Abstract The carbon dioxide (CO 2 ) sequestration capacities of selected oil fields in the Williston Basin, Powder River Basin, and Denver-Julesberg Basin in the northern Great Plains region of North America were estimated as part of the Plains CO 2 Reduction (PCOR) Partnership regional characterization. The estimates were developed using readily available reservoir characterization data obtained from the petroleum regulatory agencies and/or geological surveys from the oil-producing states and provinces of the PCOR Partnership region. Reconnaissance-level sequestration capacities were calculated using two methods depending on the nature of the readily available reservoir characterization data for each field. Maximum storage capacities were estimated for reservoirs where detailed data on original oil in place, cumulative production, reservoir thickness, porosity, temperature, pressure, and water saturation were available. The initial reconnaissance-level estimates indicate that more than 1100 oil fields within the three basins have a capacity to sequester nearly 10 billion tons of CO 2 , with the potential to produce more than 2 billion bbl of incremental oil through CO 2 -flood enhanced oil recovery activities.

Abstract Existing subsurface data and data from core and logs in a new CO 2 pilot injection test well drilled in northern lower Michigan were used to evaluate the geological carbon sequestration (GCS) potential in Upper Silurian to Middle Devonian saline reservoir and cap-rock units in the Michigan Basin. The Core Energy-State Charlton #4-30 well, Otsego County, Michigan, was drilled as part of ongoing Midwest Region Carbon Sequestration Partnership (MRCSP) phase II studies to investigate GCS potential in these units in the Michigan Basin. Significant GCS potential is recognized in porous dolomite of the Upper Silurian, Bass Islands Group in the new well. Cherty strata of the Bois Blanc Formation are also present in the #4-30 well but may lack suitable injectivity for consideration of GCS. Argillaceous limestone in parts of the superjacent Amherstburg Formation in the test well contains minimal porosity and permeability and constitutes an excellent cap-rock unit in the area. Regional consideration of the Bass Islands sequestration target interval indicates substantial GCS potential throughout most of the Michigan Basin. Preliminary estimates of regional GCS storage capacity range from 1.34 billion metric tonnes at 2% displacement storage efficiency to 6.7 billion metric tonnes of CO 2 at 10% storage efficiency in the study area. These displacement storage capacities equate to approximately 288–1440 t of CO 2 per hectare (117–583 t/ac) given the regional estimates of average thickness and porosity in the target interval used here. Significant drilling fluid loss into the target injection interval observed during drilling of the State Charlton #4-30 well of about 3.2 m 3 /hr (20 bbl/hr) demonstrates substantial injectivity in the pilot test well. Considering the fluid loss during drilling and measurements of conventional petrophysical properties in the injection target, the proposed CO 2 injection test volume of 10,000 t could fill the target interval in an area of at most 35 ha (86 ac) in the subsurface, depending on displacement storage volume efficiency assumptions. These preliminary assumptions and simple calculations indicate that the CO 2 injection plume for the injection test would extend no more than 600 m (1970 ft) away from the borehole in all directions. Preliminary reservoir simulations, using other assumptions, suggest a substantially less extensive invasion of the target interval during the injection test.

Abstract Mature coalbed methane reservoirs are prospective as major sinks for anthropogenic CO 2 , and injection of CO 2 shows promise for increasing coalbed methane reserves through enhanced recovery. Assessment of the carbon sequestration and enhanced recovery potential of coal in the Black Warrior basin indicates that numerous geological variables, including stratigraphy, structure, hydrology, geothermics, and coal quality, have a strong impact on the quantity of carbon that can be sequestered. Key variables affecting the feasibility of sequestration and enhanced recovery in the Black Warrior basin include (1) the distribution of mineable coal, (2) the distribution of formation water saline enough for underground injection, and (3) the distribution of structural compartments with sufficient reservoir continuity to host multiple five-spot well patterns. Within the developed coalbed methane fields, the feasible CO 2 sequestration potential is estimated to be 166 Bscm (5.9 Tscf), or 341 MMt, which can facilitate long-term sequestration of CO 2 emissions from coal-fired power plants. The potential for enhanced coalbed methane recovery in this area is estimated to be between 16 and 30 Bscm (0.6 and 1.1 Tscf), and realization of this potential would expand proven coalbed methane reserves by more than 30%.

Abstract The Illinois Basin (Indiana, Illinois, and western Kentucky) holds substantial Pennsylvanian coal resources of high volatile bituminous rank, but much of this resource is considered to be too deep or too thin for economic mining. Sequestration of CO 2 within the unminable parts of these coalbeds is one of the geological options considered for future isolation of CO 2 . The remaining coal resource in the basin is newly estimated for this study at 413 billion t (455 billion tons) of which 142 billion t (157 billion tons) (or 34.5%) meets the minable criteria of being less than 305 m (1000 ft) deep and greater than 1.1 m (3.5 ft) thick. Thus, 271 billion t (298 billion tons) are potentially available as a CO 2 sequestration reservoir. The estimated CO 2 storage capacity of the unminable coals in the Illinois Basin is 3.63 billion t (4 billion tons). In addition to storing CO 2 , these coals are also targets for enhanced coalbed methane production, with an estimated volume of 6.68 tcf (189 billion m 3 ) of recoverable methane. For the coals studied, the adsorption capacities for CO 2 are three to six times greater than for methane (CH 4 ). Experiments demonstrate that swelling and shrinkage of the Illinois Basin coals after injection of CO 2 are considerable, indicating the possibility of permeability damage following CO 2 injection. Key parameters that influence gas adsorption capacities were mapped for the Danville, Hymera, Herrin, Springfield, Survant, Colchester, and Seelyville coal members, including thickness, depth, elevation, moisture and ash, vitrinite reflectance, and temperature and pressure.

Abstract In gas shales, natural gas occurs both as free gas in intergranular and fracture porosity and as an adsorbed phase onto the surfaces of clays and organic matter, analogous to natural gas storage in coalbeds. The adsorption capacity of shales from Kentucky, Indiana, and West Virginia was estimated using drill cuttings and sidewall cores to determine both CO 2 and CH 4 adsorption isotherms. Elemental capture spectroscopy logs were analyzed to investigate possible correlations between adsorption capacity and mineralogy. The maturity of the shale was characterized using average random vitrinite reflectance data yielding values ranging from 0.78 to 1.59 (upper oil to wet gas and condensate hydrocarbon maturity values). Total organic carbon (TOC) content ranges from 0.69 to 14%. Calculated CO 2 adsorption capacities at 2.75 MPa range from a low of 0.4 m 3 /t (14.1 ft 3 /t) to more than 4.2 m 3 /t (148.3 ft 3 /t). A direct linear correlation between measured TOC and the adsorption capacity of the shale has been determined; CO 2 adsorption capacity increases with increasing TOC. Data also suggest that CO 2 is preferentially adsorbed (5.3:1) and would displace CH 4 , leading to a potential method for enhancing natural gas recovery in gas shales. Initial estimates of the volume of CO 2 sequesterable in the shale based on these data indicate a capacity of as much as 25 billion t in the deeper and thicker parts of the Devonian shales across Kentucky. Discounting the uncertainties in reservoir volume and injection efficiency, these results indicate that gas shales could provide a potentially large geologic sink for CO 2 . Moreover, the extensive occurrence of gas shales in Paleozoic and Mesozoic basins across North America makes them an attractive regional target for economic CO 2 storage and enhanced natural gas production.

Abstract A regional-scale, digital geologic model was created for carbon sequestration planning in the Michigan and north-central Appalachian sedimentary basins. This regional model and database include well data (picks) from more than 85,000 locations, structure and isopach maps for target and confining rock layers, and oil- and gas-field boundaries with production and petrophysical data. This model confirms the wide range of sequestration options available in the seven-state region. Target sequestration layers include coal and shales rich in organic matter (for CO 2 -enhanced methane recovery) and sandstones and carbonates with sufficient porosity to support enhanced oil recovery and disposal in saline formations. Maps created for this study are compared to those from previous compilations to illustrate advances in geologic understanding and to identify topics for future research. In addition, the utility of the Geographic Information System database in planning and decision support is presented through maps used to select study sites and through the use of the new structure and isopach models in sequestration capacity estimates. These derived products demonstrate that the study region has many promising sequestration targets with the combined capacity to contain hundreds of years of CO 2 production emitted from coal-burning power plants and other point industrial sources.

Abstract Asignificant number of large CO 2 emitters are located in central Alberta, Canada, including four coal-fired power plants in the Wabamun Lake area, with cumulative annual emissions in the order of 30 million metric tons CO 2 . To help industry and regulatory agencies in selecting and permitting sites for CO 2 storage, proper characterization is essential, covering the principal aspects of CO 2 storage: capacity, injectivity, and confinement. The sedimentary succession in the Wabamun Lake area southwest of Edmonton was identified as a potential CO 2 storage site because it would minimize transportation needs and costs from the large CO 2 sources in the vicinity. A wealth of data on stratigraphy and lithology; fluid compositions; rock properties; and geothermal, geomechanical, and pressure regimes were used to create and characterize a comprehensive three-dimensional model of the deep saline aquifers in the area that could be CO 2 storage targets. These aquifers have sufficient capacity to accept and store large volumes of supercritical CO 2 at the appropriate depth and are overlain by thick confining shale units. Initial calculations and modeling of CO 2 injection into the Devonian Nisku carbonate aquifer suggest that dissolution and residual saturation of CO 2 limit the lateral CO 2 plume spread considerably. Hypothetical injection of 12.5 million tonnes/yr of CO 2 for 30 yr would result in a maximum plume spread of less than 15 km (9 mi) in diameter. However, multiple injection wells would be needed to inject this large amount of CO 2 to maintain bottomhole injection pressures below the rock-fracturing threshold.

Abstract In the eastern mid-continent United States, the Cambrian Mt. Simon Sandstone is a likely deep-saline reservoir target for CO 2 sequestration. The overlying Cambrian–Ordovician Knox carbonate section will be an important part of the confining interval for the Mt. Simon, as much of the Knox is dominated by dense (<0.01 md), well-cemented dolomites with little or no permeability. The Knox, however, does contain discrete zones of porosity and permeability and is locally an important oil and gas producer, as well as gas storage unit. The Knox needs to be considered in any sequestration project in the region because in some localities carbonate and sandstone zones within the unit have better reservoir characteristics than the underlying Mt. Simon or overlying St. Peter Sandstone. An example of such a locality is the DuPont waste-injection site at Louisville, Kentucky, where a thick Mt. Simon section was tested and then abandoned in favor of a fractured, vuggy dolomite facies in the overlying lower Knox with an injectivity rate as high as 568 liters per minute (150 gallons per minute). Thick, dense carbonates of the Knox enveloped the reservoir effectively sealing the porous and permeable zones within the same stratigraphic unit. This is not an exceptional circumstance because several deep tests of Cambrian–Ordovician clastics in the region have encountered tight sandstone in the target horizon but vuggy and fracture porosity in overlying Knox carbonates. Analyses of known Knox enhanced oil recovery operations, waste-injection wells, and gas storage fields illustrate that liquids and gases can be effectively and safely retained within Knox reservoirs. However, porous and permeable zones within the units that constitute the local reservoirs are discontinuous and heterogeneous, and data describing the detailed characteristics of these reservoirs are sparse. More deep subsurface data are needed to better characterize the Knox and similar carbonates in other regions for their use as potential carbon sequestration reservoirs. Some of these data are currently being collected through the U.S. Department of Energy’s Carbon Sequestration Regional Partnership programs.

Abstract Deep, saline, water-bearing reservoirs offer the greatest potential for geological sequestration of large volumes of CO 2 . In the Midwestern United States, the deepest most significant saline reservoir is the Cambrian Mt. Simon Sandstone. The Mt. Simon Sandstone is commonly used for natural gas storage in relatively shallow parts of the Illinois Basin. By analogy, the data from these storage projects indicate that the unit is a heterogeneous reservoir with a large potential sequestration capacity. The Mt. Simon Sandstone consists of fine to coarse sandstone with some interbeds of gray shale. Laterally discontinuous shale and siltstone interbeds in the Mt. Simon Sandstone may serve as baffles to disrupt the vertical migration of the buoyant CO 2 . Fluid-flow modeling of CO 2 injection into the Mt. Simon reservoir suggests that inferred discontinuous flow barriers actually increase the potential storage capacity by increasing the volume of the contacted reservoir. Fluid-flow modeling of the Manlove gas storage field in Champaign County, Illinois, depicts a buildup of CO 2 saturation followed by lateral migration of CO 2 to a vertical pathway that connects the intrareservoir units. Vertical migration then continues upward until the migrating CO 2 is sealed beneath another impermeable or low-permeability shale interbed. The Eau Claire Formation, which directly overlies the Mt. Simon Sandstone, provides the primary seal that may ultimately prevent CO 2 migration into shallower formations. The Mt. Simon Sandstone underlies most of Illinois, Michigan, Iowa, Indiana, and Ohio and has a maximum gross thickness greater than 790 m (2600 ft). However, the Mt. Simon Sandstone is relatively thin or absent above some localized basement paleotopographic high areas because of either nondeposition or erosion. These paleotopographic high areas are inferred from geophysical logs and two-dimensional and three-dimensional seismic reflection data. In addition to changes on the Precambrian surface caused by paleotopography, exploratory drilling for potential Mt. Simon CO 2 storage reservoirs must contend with the combination of variations in paleotopography and reservoir pinch-outs as well as variations in structural closure. The Mt. Simon Sandstone underlies one of the largest concentrations of coal-fired power plants in the world and is therefore one of the most significant potential carbon storage resources in the United States. The Mt. Simon Sandstone has a potential sequestration capacity of between 27 and 109 billion metric tonnes of CO 2 . However, the potential for the Mt. Simon Sandstone as an effective reservoir for geological sequestration cannot be realized without an understanding of its complex internal stratigraphy and the relationship of structural configuration to paleotopography.

Abstract Future fossil-fuel-based energy production facilities may include carbon management strategies as part of their overall operational plans. Geologic formations, such as saline systems, oil fields, and coal seams, appear to have significant capacity to store carbon dioxide (CO 2 ), provided that they have adequate porosity, permeability, temperature and pressure conditions, and competent seals. As part of the conceptual design phase of a proposed near-zero emission coal-fired power plant in southwestern North Dakota, the Broom Creek Formation was identified as a potential sink for large-scale CO 2 sequestration. The Pennsylvanian–Permian Broom Creek Formation is a laterally extensive sandstone at the top of the Minnelusa saline aquifer system, which is capped by the Opeche Formation, an anhydritic shale. A wide variety of previously generated data, including well logs, core analysis, water analysis, and other published data, were used to conduct a detailed characterization of an area of the Broom Creek Formation in the immediate vicinity of the proposed power plant location. These data were used to estimate injection rates and predict plume size and migration tendencies. The results of the exercise suggest that a minimum of 50 mmt of CO 2 could be stored in an area no larger than 15 mi 2 (2.5 km 2 ) over an injection period of 30 yr. This case study describes an approach that can be applied to conduct reconnaissance-level, site-specific characterizations of geologic formations for the purpose of large-scale CO 2 sequestration.

Abstract The widespread Western Interior Plains aquifer system of the central United States provides a significant potential for sequestration of CO 2 in a deep saline formation. In Kansas, several severely depleted Mississippian petroleum reservoirs sit at the top of this aquifer system. The reservoirs are primarily multilayered shallow-shelf carbonates with strong water drives. Fluid flow is strongly influenced by natural fractures, which were solution enhanced by subaerial karst on a Mississippian–Pennsylvanian regional unconformity. We show that three-dimensional (3-D) seismic volumetric reflector curvature attributes can reveal subtle lineaments related to these fractures. Volumetric curvature attributes applied to a 3-D seismic survey over a Mississippian oil reservoir in Dickman field, Ness County, Kansas, reveal two main lineament orientations, N45°E and N45°W. The northeast-trending lineaments parallel a down-to-the-north fault at the northwestern corner of the seismic survey and have greater length and continuity than the northwest-trending lineaments. Geologic analysis and production data suggest that the northeast-trending lineaments are related to debris-, clay-, and silt-filled fractures that serve as barriers to fluid flow, whereas the northwest-trending lineaments are related to open fractures that channel water from the underlying aquifer. The discrimination of open versus sealed fractures within and above potential CO 2 sequestration reservoirs is critical for managing the injection and storage of CO 2 and for evaluating the integrity of the overlying seal. Three-dimensional seismic volumetric curvature helps to locate fractures and is a potentially important tool in the selection and evaluation of geologic sequestration sites.

Abstract The Texas Gulf Coast is an attractive target for carbon storage. Stacked sandstone and shale layers provide large potential storage volumes and defense-in-depth leakage protection. Two types of traps are important in the initial sequestration stages: (1) closed structural and stratigraphic traps analogous to oil and gas traps, and (2) open traps where the residual saturation trail of capillary trapping is the main active mechanism. Leakage pathways of primary concern are wellbores and faults. Both could produce a direct connection to the atmosphere. However, most faults do not reach the surface, leaving abandoned wellbores the main focus of a risk analysis. Other leakage pathways, such as a closed trap overflowing through spill points or a seal failure, can be accommodated by the capillary trapping mechanism. The effectiveness of this mechanism depends on the level of heterogeneity of the formations. Determining formation heterogeneity is the second emphasis of any risk analysis in the Texas Gulf Coast. This chapter focuses on the Tertiary section of the Texas Gulf Coast and describes statistics on the hundreds of thousands of boreholes (age, depth, status) drilled in the area and on the shape and size of closed and open traps, which were measured from proprietary structural maps. The chapter also incorporates information about growth-fault distribution and discusses efficiency of capillary trapping. The implications for carbon storage are then derived (e.g., stay away from salt domes and their capture zone; inject mostly deeper than the majority of abandoned wells).

Abstract The petrophysical properties of cap rocks and intraformational barriers can constrain the CO 2 containment volumes of potential geosequestration sites. Characterization of regional seals and intraformational barriers requires an understanding of the seal capacity of the cap rock or barrier. Seal capacity is the capillary pressure (or column height) at which a trapped fluid commences to leak or move through a seal rock. Seal rocks are effective because of very fine pore and pore-throat sizes that result in low porosities and permeabilities, which in turn generate high capillary threshold pressures. These high threshold pressures, together with wettability and interfacial tension (IFT) properties, determine the final column height that a seal can hold. A review is presented on the function of wettability and IFT in the geological storage of CO 2 and its effect on seal capacity (CO 2 column height) with respect to capillary pressure, the potential for the movement of CO 2 through the seal, and the effect on reservoir storage volumes. Mercury injection capillary pressure analysis has been used extensively in the petroleum industry to determine the effectiveness of the top seal in relation to hydrocarbon column height retention. With the burgeoning interest in geological storage of CO 2 , this technology can be applied to establish the suitability of a top seal for containment of CO 2 ; however, the function of IFT and wettability in the CO 2 -water-rock systems is not well understood. How supercritical CO 2 (scCO 2 ) affects these two properties is unclear, especially as the waterfront becomes saturated with scCO 2 and may eventually become miscible with the scCO 2 at reservoir conditions. To date, literature shows that the wettability and IFT of the CO 2 -water-rock system may be more significant than in the hydrocarbon-water-rock systems and that calculated CO 2 column heights based on nonwetting assumptions could result in column heights being as much as 50% less than otherwise predicted.