Safe Storage of CO2 in Deep
Saline Aquifers
Coalbeds
Oiland gas reservoir
Saline aquifer
CO2 dissolved in form ation w ater CO2 plum e R O B E R T G . B R UA N T, J R . , A N D R E W J . G U S WA , MICHAEL A. CELIA, AND CATHERINE A. PETERS
Long-term underground storage of CO2 is an attractive mitigation option, but leaks may have environmental consequences.
ver the past 420,000 years, global average atmospheric CO2 concentrations have fluctuated narrowly between 180 and 280 parts per million by volume (ppmv), but since the Industrial Revolution, CO2 concentrations have increased to ~370 ppmv. This increase is believed to be contributing to rising mean global temperatures (1, 2). Average annual global anthropogenic CO2 emissions during the 1990s were ~27 GtCO2/yr (1 GtCO2 = 109 metric tons of CO2 = 1012 kg of CO2 = 0.27 GtC). The Intergovernmental Panel on Climate Change estimates that under a “business-as-usual” energy scenario, global emissions will reach ~77 GtCO2/yr by 2100, and the average atmospheric CO2 concentration will reach ~750 ppmv (2). To stabilize atmospheric CO2 concentrations at 550 ppmv, which is approximately twice preindustrial concentrations, global emissions must be continuously reduced so that by 2050, global emissions are 15 GtCO2/yr less than the business-as-usual projection, and by 2100, emissions are 50 GtCO2/yr less (2, 3). To achieve these substantial emission reductions, there are several available options: improve energy conversion and efficiency of fossil fuels, shift energy production to low-carbon or noncarbon fuel sources, enhance uptake by terrestrial and marine biomass, or capture and subsequently store CO2 from stationary point sources. Of these options, carbon capture and storage is considered the best choice for near-term reduction of stationary point-source CO2 emissions from power generation, iron and steel production, cement manufacture, and oil and natural gas production and refining—which collectively contribute approximately one-third to total global CO2 emissions (4–8). Moreover, of the several CO2 storage possibilities proposed, including injection into deep oceans, depleted oil reservoirs, and unminable coal seams, storage in deep saline aquifers appears to hold the most combined promise in terms of storage capacity, proximity to emission sources, and state-of-the-art technology (4, 5, 8–10).
ADAPETED FROM AN ILLUSTRATION BY DAN MAGEE, ALBERTA GEOLOGICAL SURVEY
O
Aquifer storage capacity Deep saline aquifers associated with sedimentary basins have little foreseeable economic or societal benefit as a drinking or agricultural water supply because of their depth and high concentrations of dissolved solids (11–13). Additionally, these aquifers are often close to stationary point-source CO2 emission sites, especially in the United States (4, 8–10, 14–16). © 2002 American Chemical Society
The worldwide CO2 storage capacity of deep saline aquifers has been estimated to range from 100 to 10,000 GtCO2 (7, 14, 17, 18). This range is based on analyses by Koide et al., Hendriks and Blok, and other researchers (19–21). These analyses differ in their assumptions about volumes of sedimentary basins, aquifer characteristics, CO2 storage density, and technological and economic constraints. With respect to the state of the stored CO2, the capacity estimates fall into two categories: The first assumes CO2 remains as a separate fluid phase, while the second assumes all CO2 dissolves in the brine. Initial simulation studies have shown that a relatively small fraction of an aquifer will be filled with separate-phase CO2 because of hydrodynamic and buoyancy effects (22). If it is assumed that all of the CO2 is dissolved in the brine, which will occur eventually as a result of interphase mass transfer even if CO2 is injected as a separate fluid phase, the solubility constrains the capacity. We believe it is meaningful at this point to define CO2 storage capacity solely on the basis of physical parameters, that is, volumes and solubilities, such that capacity is the maximum amount of CO2 that can be stored in an aquifer by solubilization. The areal extent of worldwide sedimentary basins, not including those located under offshore seabeds, is ~70 million km2 (19, 20). Assuming an average useful formation thickness of 200 m and an average aquifer porosity of 10%, the available volume is ~1.4 million km3. Assuming a CO2 solubility of 40 kg/m3, the available global storage capacity is ~56,000 GtCO2 (11, 19). Each of the parameters used in this calculation might reasonably be considered to have an uncertainty factor of 2. For example, an average aquifer porosity of 20% is also a reasonable estimate. Taking this uncertainty into consideration, we estimate the global storage capacity of land-based deep saline aquifers to be between 10,000 and 200,000 GtCO2. Filling this capacity would account for hundreds to thousands of years of CO2 emissions. Several of the published capacity estimates, which account for technological and economic constraints, are considerably smaller, ranging between 200 and 500 GtCO2 (19–21). Although these constraints must ultimately be included in decision analyses, they are highly uncertain and require significant additional research. Technology transfer from current subsurface injection activities may provide insight into technological and economic factors affecting capacity. JUNE 1, 2002 / ENVIRONMENTAL SCIENCE & TECHNOLOGY
I
241 A
Relevant industrial activities include CO2 use in enhanced oil and coalbed methane recovery, subsurface storage of natural gas, and subsurface acid gas (CO2/H2S mixtures) and hazardous waste injection (6, 23–30). In addition, much can be learned from recent field-scale injection of CO2 into a deep offshore saline aquifer (25, 31). Even with this large potential capacity, a major obstacle to subsurface CO2 storage in deep saline aquifers is demonstrating that safety and environmental protection can be assured. Verification of long-term CO2 residence in receptor formations and quantification of possible CO2 leaks are required for proper assessment of environmental and societal risk (6, 7).
Nature of stored CO2
At ambient ground-surface temperature (25 °C) and pressure (0.1 MPa), CO2 is a gas with a density of 1.8 kg/m3. (The density of air under these conditions is 1.2 kg/m3.) Assuming a geothermal gradient of 30 °C/km and a pressure gradient of 10.5 MPa/km, CO2 can be stored as a supercritical fluid at injection depths greater than ~800 m, as shown in Figure 1 (4, 9, 13, 15). The density of supercritical CO2, ~260 kg/m3 at 800 m depth, permits far greater quantities of CO2 to be stored per unit volume than as a gas at shallower depths (32). FIGURE 1
CO2 solubility decreases with increasing temperature and salinity, and increases with increasing pressure. At ground-surface conditions, the solubility of CO2 in pure water is ~1.7 kg CO2/m3. At the higher temperature and pressure conditions at 800-m depth, the solubility of CO2 in formation waters with 15% total dissolved solids by mass is ~35 kg/m3 (32, 34). Low groundwater flow velocities, often on the order of 1–10 cm/yr, should limit lateral movement of dissolved CO2 in these systems, a process referred to as hydrodynamic trapping (5, 15). CO2 and its aqueous-phase derivatives may react with aquifer solids and subsequently be stored as precipitated and adsorbed phases. These processes are collectively known as mineral trapping (4, 7, 35). For example, reactions with silicate minerals can form calcium, magnesium, and iron carbonate precipitates. Assuming long-term CO2 storage, these slow reactions may proceed to an appreciable extent (6, 35). Injected fluids may range from near-pure CO2 to mixtures with significant fractions of constituents such as H2S, SOx, and NOx. Deep injection of acid gas mixtures, derived from raw natural gas, is already taking place in the United States and Canada. For example, strict limits on sulfur emissions in Alberta, Canada, and low demand for elemental sulfur have lead to subsurface injection of 360 KtH2S/yr and 565 KtCO2/yr (1 Kt = 103 metric tons) as acid gas mixtures, according to 1999 statistics (12, 29).
A schematic of CO2 injection
Tendency to escape
An injection well passes ~800 m below the land surface through a confining layer. CO2 is injected as a supercritical fluid, some of which dissolves in the brine and some of which is trapped in precipitated mineral phases.
Even with receptor formations of adequate capacity, some of the injected CO2 is expected to leak. Figure 2 shows some potential CO2 escape routes (5, 9, 14). Even with detailed subsurface characterization, leaks cannot be ruled out in some formations because of the buoyancy of the separate-phase CO2, the induced pressure gradients from injection, and the variable nature of strata serving as barriers to upward migration. CO2 leaking from receptor formations may intercept shallow aquifers, surface water bodies, and the land surface. Subsurface and surface manifestations of CO2 leaks would be dictated, in part, by whether the release is dispersed or localized and whether the release rate is catastrophic or chronic, as well as the geologic and hydrologic character of confining strata.
Injection well Confining layer(s) ~800 m
Supercritical CO2
Dissolved CO2
Aquifer solids Supercritical and dissolved CO2
Precipitated minerals
Receptor formation
At 800-m depth, water with 15% total dissolved solids by mass has a density of ~1100 kg/m3 (4, 13, 16, 33). This density difference generates buoyancy forces that drive injected CO2 upward. Conventional wisdom, supported by preliminary numerical simulations, suggests that supercritical CO2 should be injected into formations with overlying layers of lowpermeability strata serving as confining layers to vertical migration (13, 22). This is referred to as stratigraphic trapping (4). CO2 dissolved in formation waters is not subject to upward buoyant migration, and this dissolution of CO2 is sometimes referred to as solubility trapping. 242 A
I
ENVIRONMENTAL SCIENCE & TECHNOLOGY / JUNE 1, 2002
Impacts of leaks At low concentrations, CO2 is not directly hazardous to human health, but may detrimentally alter environmental processes. Vertical migration of leaking CO2 will be accompanied by dissolution into shallower aquifer waters. Dissolved CO2 hydrolyzes to form carbonic acid, which can alter pH. Because pH is a master variable in water-mediated chemical and biological reactions, a pH shift may cause undesirable changes in geochemistry, water quality, and ecosystem health. Examples include mobilization of toxic metals, leaching of important biological nutrients, and modification of proton gradients across biological membranes. Although less likely, a sudden catastrophic release scenario must be considered. An abrupt release of a large quantity of CO2 could pose a serious threat to
humans and ecosystems. For example, at Mammoth Mountain in eastern California, surface CO2 emissions of magmatic origin have been occurring since the early 1990s (see sidebar on the next page). The resulting elevated CO2 concentrations have killed ~0.6 km2 of coniferous forest, and early signs of human asphyxia were reported in affected areas (36, 37 ). In a more dramatic episode, more than 1700 people died of asphyxiation on August 21, 1986, as a result of a limnic eruption of CO2 from Lake Nyos in the northwest province of Cameroon (38). Catastrophic releases are unlikely for CO2 injected into deep saline aquifers and probably would occur only as a result of a “blowout” of an injection well or existing well in the vicinity, or a seismic disturbance. Such risks can be minimized through proper design, operation, and monitoring of the injection process; detailed cataloging of the locations and use history of existing wells in the injection vicinity; and avoidance of seismically active areas. Another possible environmental problem related to CO2 injection is displacement of brines into overlying aquifers, with concomitant potential to contaminate potable water supplies. Brine management strategies may be needed to direct displaced brine to sites where impact would be minimized. Alternatively, produced brine may be used to strategically control CO2 migration through hydraulic manipulation, for example, reinjecting brine above CO2 receptor aquifers to increase confining pressures.
Regulation and monitoring Effective CO2 injection programs will require comprehensive rules and regulations for injection operations, as well as monitoring. A regulatory framework should be designed that assures no significant environmental damage, but this probably can be accomplished allowing for some CO2 leakage. The U.S. Underground Injection Control (UIC) program, which already exists to regulate deep-well injection of hazardous and nonhazardous waste, could, in principle, serve as a regulatory model for CO2. UIC regulations mandate prescreening of injection sites and adherence to rigorous well construction, injection, and monitoring protocols so that injected waste does not contaminate potable water supplies. However, because the potential for vertical migration of CO2 is greater than for most currently injected wastes, which are typically dense liquids, and because some amount of CO2 leakage may be environmentally and politically acceptable, significant modifications to the UIC framework would be necessary. Tsang et al. compared the storage issues of CO2 and hazardous wastes and suggested specific regulatory elements for subsurface CO2 injection, including site selection based on integrity of the confining layers, potential for geochemical reactions involving CO2, and monitoring plans for CO2 leaks (30). Long-term monitoring protocols will be needed to identify possible leaks and quantify leakage rates. Pressure, tracer, seismic, electrical, and magnetic methods have been used in the oil and gas industries for reservoir and fluid characterization. Although some of these methods are being applied for deep-
subsurface CO2 imaging, their overall performance and dependability remains uncertain (39). Near the land surface, there is potential for direct chemical detection. However, CO2 is odorless, colorless, and tasteless below concentrations of 10–20% by volume, so it would likely escape human senses (37 ). Substantial effort is needed to develop appropriate methods for leak detection in both shallow and deep zones.
FIGURE 2
Potential pathways for CO2 leakage from deep saline aquifers Localized vertical migration may be driven by large pressure gradients near the injection well. Lateral migration occurs as CO2 moves around the edges of the confining layers. Significant seepage may occur through natural and induced fractures and faults in the confining layers and through existing wells. Atmosphere
Surface ecosystems
Potable water Seepage through fractures, faults, wells
Localized vertical migration Confining layer(s)
Injected
Lateral migration
CO2
Research considerations Although design and implementation of subsurface storage schemes require the expertise of hydrologists, geologists, and petroleum engineers, the overall consideration of safe geologic CO2 storage is even more of an interdisciplinary effort. Environmental scientists and engineers and policy experts must also be involved to address the various societal and environmental issues related to large-scale CO2 storage and leakage. The following is an outline of a multifaceted, multiscale approach to research. Modeling. Robust numerical simulators of multiphase flow and multicomponent transport coupled with geomechanics, geochemistry, and heat transfer are needed to predict CO2 migration and fate, formation responses to injection, and surface expressions of leaks. These models must accurately represent processes over a wide range of spatial and temporal scales, and successfully integrate short-term injection with longer-term transport and reaction. Much of the work in this area has centered on extending and coupling existing models (13, 40). Recently, researchers at the Lawrence Berkeley National Laboratory initiated a broad effort to comJUNE 1, 2002 / ENVIRONMENTAL SCIENCE & TECHNOLOGY
I
243 A
An example of a natural CO2 release
ADAPTED FROM REFERENCE (37)
Mammoth Mountain is a geologically young, dormant volcano located on the Long Valley Caldera in eastern California. From 1990 to 1994, reports of anomalous tree deaths along the mountain flanks and symptoms of earlystage human asphyxia prompted U.S. Geological Survey (USGS) studies of magmatic CO2 emissions in the area (36, 37). Soil−gas surveys conducted by the USGS in the mid1990s revealed CO2 concentrations ranging from >1% to >95% by volume in an ~0.6 km2 area of dead coniferous forest (see inset photo). For comparison, background CO2 soil−gas concentrations were 10% are toxic to humans), atmospheric circulation dilutes CO2 concentrations well below adverse health levels 1 to 2 m above the ground surface in outdoor settings.
Horseshoe Lake
Tree-kil areas
Tree-killareasassociated w ith magma-derived CO2 releasesatM ammoth M ountain in California are noted.
pare models with the goal of stimulating research in this area and improving the dissemination of knowledge (41). Subsurface inventories. Detailed and accessible summaries of basin-, regional-, and local-scale geology and hydrology are important for rapid identification of suitable receptor formations. Relevant information to characterize candidate aquifers includes depths, geometries, rock lithology and mineralogy, hydrodynamics, water composition, in situ stresses and seismic risk, geothermal regimes, mineral and petroleum deposits, and locations of wells (4, 9). Efforts in the United States have already begun with the Midcontinent Interactive Digital Carbon Atlas and Regional Database and surveys by the Bureau of Economic Geology at the University of Texas–Austin, both of which focus on deep-receptor formations (10). Shallow subsurface zones should also be character244 A
I
ENVIRONMENTAL SCIENCE & TECHNOLOGY / JUNE 1, 2002
ized because of the potential consequences associated with leaks for shallow aquifers and soils. Experimental investigations. Determination of pathways and rates for reactions between CO2 and mineral and aqueous phases is necessary to estimate the magnitude of mineral and solubility trapping in target formations, and to estimate how these reactions may in turn affect porosity, permeability, and reservoir integrity (42). This work must also consider CO2 interaction with well materials, such as casings and cements, to address potential material degradation and associated CO2 leakage. Additionally, effects of elevated CO2 concentrations on surface and near-surface biogeochemistry must be determined to assess risks to human and ecosystem health. Such experimental research should also consider the effects of other possible constituents in the injected CO2 stream, including H2S, SOx, and NOx.
Monitoring. Investigation of the use of geophysical techniques and other advanced measurement technologies for subsurface CO2 plume delineation must continue. Remote sensing techniques, bioassays, and water quality analyses also may be explored for near-surface monitoring of injection sites and for detection of leaks (37 ). Additives to the injected CO2, similar to mercaptans for natural gas, may also be considered to aid leak detection. Natural analogues. Studying natural analogues, such as Mammoth Mountain, may uncover information about short- and long-term CO2 migration pathways and associated geochemical, aquatic, and biological impacts. Much can also be learned from examining deep subsurface formations with naturally high concentrations of CO2. Field-scale projects. Controlled field-scale injections are necessary to better understand well completion and injection procedures, interactions of CO2 with geologic media, migration pathways, deep and shallow monitoring techniques, and performance of site-specific numerical modeling exercises (6, 25). One such field-scale project is already under way off the coast of Norway in the Sleipner Vest Field in the North Sea (25, 31, 39, 43). Injection of approximately 1 Mt CO2/yr (1 Mt = 106 metric tons) into the 800-m-deep Utsira sandstone formation is being seismically monitored to track the subsurface movement of the CO2 plume. Ongoing acid gas injection operations in the United States and Canada offer further opportunities for field studies.
Acknowledgments The authors acknowledge British Petroleum and Ford Motor Co. for their support of the Carbon Mitigation Initiative at Princeton University. The authors also acknowledge Dr. Stefan Bachu of the Alberta Geological Survey, who offered helpful insights during the preparation of this manuscript, and Dr. C. D. Farrar of the U.S. Geological Survey, who provided the image of Mammoth Mountain. Finally, we acknowledge the anonymous reviewers whose comments were helpful in the final preparation of the manuscript.
References (1) Falkowski, P.; et al. Science 2000, 291, 291–296. (2) Albritton, D. L.; Meira Filho, L. G. Climate Change 2001: The Scientific Basis; Contribution of Working Group I to the Third Assessment Report of the Intergovernmental Panel on Climate Change Technical Summary; IPCC: Geneva, Switzerland, 2001. (3) Wigley, T. M. L.; Richels, R.; Edmonds, J. A. Nature 1996, 379, 240–243. (4) Bachu, S.; Gunter, W. D.; Perkins, E. H. Energy Convers. Mgmt. 1994, 35, 269–279. (5) Bachu, S. Aquifer Disposal of Carbon Dioxide: Hydrodynamic and Mineral Trapping—Proof on Concept, Hitchon, B., Ed.; Geosciences Publishing: Sherwood Park, Alberta, Canada, 1996. (6) Carbon Sequestration Research and Development; DOE/SC/FE-1; Office of Science, Office of Fossil Energy, U.S. Department of Energy: Washington, DC, 1999. (7) Davison, J.; Freund, P.; Smith, A. Putting Carbon Back in the Ground, IEA Greenhouse Gas R&D Programme: Gloucestershire, United Kingdom, 2001. (8) Herzog, H. J. Environ. Sci. Technol. 2001, 35, 148A–153A. (9) Bachu, S. Energy Convers. Mgmt. 2002, 43, 87–102. (10) Hovorka, S. D.; et al. Sequestration of Greenhouse Gases in Brine Formations, Bureau of Economic Geology: Austin,
(11) (12) (13) (14) (15) (16)
(17)
(18) (19) (20) (21) (22) (23) (24) (25) (26) (27) (28) (29) (30) (31) (32) (33) (34) (35) (36)
(37)
(38) (39) (40) (41)
(42)
(43)
TX; www.beg.utexas.edu/environqlty/co2seq/dispslsaln. htm (accessed April 2002). Koide, H.; Takahashi, M.; Tsukamoto, H.; Shindo, Y. Energy Convers. Mgmt. 1995, 36, 505–508. Longworth, H. L.; Dunn, G. C.; Semchuck, M. Soc. Pet. Eng. J. 1995, 35584, 181–192. Weir, G. J.; White, S. P.; Kissling, W. M. Transport in Porous Media 1996, 23, 37–60. Bergman, P. D.; Winter, E. M. Energy Convers. Mgmt. 1995, 36, 523–526. Holloway, S.; van der Straaten, R. Energy Convers. Mgmt. 1995, 36, 519–522. Gupta, N.; Sass, B.; Sminchak, J.; Naymik, T.; Bergman, P. Greenhouse Gas Control Technologies; Riemer, P., Eliasson, B., Wokaun, A., Eds.; Elsevier Science: New York, 1999. Omerod, W. Carbon Dioxide Disposal from Power Stations, IEA Greenhouse Gas R&D Programme: Gloucestershire, United Kingdom, 1994. Beecy, D. J.; Kuuskraa,V. A. Environ. Geosci. 2001, 8, 152–159. Koide, H.; Tazaki, Y.; Noguchi, Y.; Nakayama, S.; Iijima, M.; Ito, K.; Shindo, Y. Energy Convers. Mgmt. 1992, 33, 619–626. Hendriks, C. A.; Blok, K. Energy Convers. Mgmt. 1995, 36, 539–542. Hendriks, C. A.; Blok, K. Energy Convers. Mgmt. 1993, 34, 949–957. van der Meer, L. G. H. Energy Convers. Mgmt. 1995, 36, 513–518. Blunt, M.; Fayers, F. J.; Orr, F. M., Jr. Energy Convers. Mgmt. 1993, 34, 1197–1204. Holt, T.; Jensen, J.-I.; Lindeberg, E. Energy Convers. Mgmt. 1995, 36, 535–538. Hanisch, C. Environ. Sci. Technol. 1999, 33, 66 A–70 A. Bachu, S. Energy Convers. Mgmt. 2000, 41, 953–970. Wong, S.; Gunter, W. D.; Mavor, M. J. Soc. Pet. Eng. J. 2000, 59785, 1–8. Wichert, E.; Royan, T. Soc. Pet. Eng. J. 1996, 35585, 193–200. Connock, L. Sulphur 2001, 272, 35–41. Tsang, C.-F.; Benson, S. M.; Kobelski, B.; Smith, R. E. Environ. Geol. 2002, in press. Baklid, A.; Korbøl, R. Soc. Pet. Eng. J. 1996, 36600, 43–51. Sterner, S. M.; Pitzer, K. S. Contrib. Mineral. Petrol. 1994, 117, 362–374. McCain, W. D., Jr. Soc. Pet. Eng. J. Reservoir Eng. 1991, 6, 266–272. Enick, R. M.; Klara, S. M. Chem. Eng. Comm. 1990, 90, 23–33. Gunter, W. D.; Perkins, E. H.; Hutcheon, I. Appl. Geochem. 2000, 15, 1085–1095. Farrar, C. D.; Sorey, M. L.; Evans, W. C.; Howle, J. F.; Kerr, B. D.; Kennedy, B. M.; King, C.-Y.; Southon, J. R. Nature 1995, 376, 675–678. Farrar, C. D.; Neil, J. M.; Howle, J. F. U.S. Geological Survey Water-Resources Investigations Report, WRI98-4217; U.S. Geological Survey: Sacramento, CA, 1999; pp. 1–17. Freeth, S. J.; Kay, R. L. F. Nature 1987, 325, 104–105. Gale, J.; Christensen, N. P.; Cutler, A.; Torp, T. A. Environ. Geosci. 2001, 8, 160–165. Battistelli, A.; Calore, C.; Pruess, K. Geothermics 1997, 26, 437–464. Pruess, K.; Tsang, C.-F.; Law, D.; Gunter, B. Intercomparison of Simulation Models for CO2 Disposal in Underground Storage Reservoirs; LBNL-47353; Lawrence Berkeley National Laboratory: Berkeley, CA, 2000. Sass, B.; Gupta, N.; Sminchak, J. Greenhouse Gas Control Technologies; Riemer, P., Eliasson, B., Wokaun, A., Eds.; Elsevier Science: New York, 1999. Korbøl, R.; Kaddour, A. Energy Convers. Mgmt. 1995, 36, 509–512.
Robert G. Bruant, Jr., is a research associate, Michael A. Celia is a professor, and Catherine A. Peters is an associate professor in the Program in Environmental Engineering and Water Resources, Department of Civil and Environmental Engineering, Princeton University, Princeton, N.J. Andrew J. Guswa is an assistant professor in the Picker Engineering Program, Smith College, Northampton, Mass. JUNE 1, 2002 / ENVIRONMENTAL SCIENCE & TECHNOLOGY
I
245 A
