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Technical and economic feasibility of CO2 disposal in aquifers within the Alberta sedimentary basin, Canada
Energy Convers. MgmtVol. 37, Nos 6-8, pp. 1135-1142, 1996 Pergamon
0196-8904(95)00311-8
Copyright 1996 Elsevier Science Ltd Printed in Great Britain. All rights reserved 0196-8904/96 $15.00 ÷ 0.00
T E C H N I C A L AND E C O N O M I C FEASIBILITY OF CO2 DISPOSAL IN A Q U I F E R S W I T H I N T H E A L B E R T A SEDIMENTARY BASIN, CANADA
W.D. GUNTER, STEFAN BACHU and D.H.-S. LAW Alberta Research Council, Edmonton, Alberta, Canada, T6H 5X2. VINOD MARWAHA Environment Canada, Edmonton, Alberta, Canada, T6B 2X3. D.L. DRYSDALE TransAlta Utilities Corporation, Calgary, Alberta, Canada, T2P 2M1. D.E. MACDONALD Alberta Department of Energy, Edmonton, Alberta, Canada, T5K 2G6. T.J. MCCANN T.J. McCann and Associates Ltd., Calgary, Alberta, Canada, T2P 3P4.
- A three year study of the technical and economic feasibility of aquifer disposal of CO2 in the low permeability sedimentary rocks of the Alberta Basin has revealed several new generic concepts that may be applicable to other sedimentary basins throughout the world. High permeability aquifers are not necessarily required for CO2 disposal. Injectivity of CO2 can be maximized by siting disposal wells in targeted or "sweet" zones of locally high permeability surrounded by a low regional scale permeability [1-2]. The low regional permeability forms a "hydrodynamic" or "time" trap for CO2 [1], where the residence time of CO2 in the aquifer is of the order of 105 to l& years. Another type of hydrodynamic trapping in sedimentary basins is produced by the "sponge" or "sink" effect of rebounding shales [3-4]. On a smaller time scale, over hundreds of years, "mineral" or "inert" trapping [5-6] by reaction of the CO2 with basic aluminosilicate minerals will occur in siliciclastic aquifers. Consequently, stratigraphic traps may not be necessary for safe disposal of CO2 in the subsurface. Abstract
Aquifer disposal of CO2 is expensive, on the order of $52/tonne. Although there are many possibilities to reduce CO2 emissions that are more economically attractive, aquifer disposal remains as one of the largest sinks available for CO2 in landlocked areas of the world; and may be utilized if other less expensive options are exhausted.
1. BACKGROUND Canada is working to meet its commitment, made at the Rio convention on climate change in 1992, to stabilize greenhouse gas emissions at the 1990 levels by the year 2000. At the recent UN Environment Conference in Berlin, Canada tabled its National Action Program on Climate Change. This national report [7] outlines several policy and technology options, as well as progress made so far in meeting Canada's goal of stabilization of greenhouse gases. One of its major cornerstone efforts is a Voluntary Challenge and Registry (VCR) Program. The VCR program will challenge industry and governments to voluntarily reduce their emissions and find new sinks for greenhouse gases. 1135
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GUNTER et al.: CO2 DISPOSALIN AQUIFERS 2. CO2 EMISSIONS IN THE ALBERTA SEDIMENTARY BASIN
The Western Canadian Sedimentary Basin (WCSB) is one of the largest sedimentary basins in the world and contains extensive natural resources. The WCSB is comprised of the Alberta Basin and the Williston Basin which extends into the USA. The Alberta Basin is a foreland basin bound by structural features (Fig. 1) and is characterized by a thick succession of Paleozoic, Mesozoic and Tertiary strata, resting on a Precambrian basement, with all the strata dipping gently to the west [8]. This succession reaches its maximum thickness within the Alberta Syncline, immediately to the east of the Canadian Rocky Mountain disturbed belt (Fig. 1). These units in the Rocky Mountains have been extensively thrust faulted and folded. There are several flow systems in the Alberta Basin [4], the most important being the S-SW to N-NE ones in the Paleozoic strata, and the southwestward flow system in the Cretaceous strata in the southwest driven inward by erosional rebound of thick Cretaceous and Tertiary shales. The latter result in hydrodynamic sinks. The Alberta Basin covers an area of 825,000 km2, with a volume of approximately 2 million km 3. Alberta is an energy-rich province of Canada, and a net exporter of energy from the coal, oil and gas reserves contained in the Alberta Basin. Carbon dioxide is one of the predominant greenhouse gases, which is known to contribute to global climate warming. As might be expected, major sources of CO2 point emissions from energy-related industrial activities in Canada are also located in the Alberta Basin. Alberta is the second largest CO2 emitter in Canada. Alberta's emissions of CO2 for the year 1 9 9 0 were 127 MT (megatonnes) as compared to national emissions of 461 MT [9]. A review of the research status of CO2 disposal technologies for Western Canada [ 10] revealed four types of possible CO2 disposal: biological, mineral immobilization, deep ocean disposal and injection into geological formations. Deep ocean disposal is not a practical alternative for reducing CO2 emissions from Alberta-based sources. The biological disposal starts from the idea that CO2 emissions may be offset by CO2 intake by forests. Nevertheless, this option suffers from a lack of credibility in the overall carbon and energy balance, and it is not clear how permanent the C O 2 storage is. Mineral immobilization of CO2 is a possibility for Alberta and it can be achieved by the conversion into carbonates of calcium and/or magnesium rich brines found in close proximity to fossil fuel deposits [ 10-11 ]. However, large amounts of base are needed, with considerable associated costs incurred [10]. In Alberta, CO2 can be injected into closed traps (depleted oil and gas reservoirs) and open traps (deep aquifers). The technology for CO2 capture, purification, compression, transport and injection is well understood by the petroleum industry [12]. Other options being considered are disposal of CO2 in coal seams to displace methane (commonly referred to as "coalbed methane"), and carbon fixing in prairie agricultural soils. In a previous study, the Alberta Oil Sands Technology and Research Authority (AOSTRA) examined the feasibility of removing 50,000 tonnes/day of CO2 from industrial sources by utilizing CO2 in enhanced oil recovery (EOR) operations in Alberta and Saskatchewan [ 13-14]. Throughout the study it became apparent that EOR operations will not necessarily be capable of utilizing all the CO2 envisaged to be removed. The CO2 injected in oil fields begins to be recovered at extraction wells. In this case CO 2 will have to be disposed by other means, of which injection into depleted gas reservoirs or deep aquifers may be the most suitable for Alberta [1]. On a parallel basis, the Saskatchewan Power Corporation has just completed a similar initial feasibility study [15] for reducing emission of CO2 by utilizing it for EOR operations in Saskatchewan. 3. SITING OF DISPOSAL AQUIFERS Trapping of the CO2 is a required condition for COz disposal and occurs in stratigraphic traps, in mineral traps or in hydrodynamic traps in the subsurface. Stratigraphic traps are not considered here because they are local phenomena and are the favored traps ofoii and gas. Normally they are not available to be used for CO2 trapping. Conversely mineral and hydrodynamic traps are ubiquitous to the Alberta Basin and are available for CO2 trapping.
GUNTER et al.: CO2 DISPOSAL IN AQUIFERS
1137
A survey [13] of CO2-emission and potential CO2-utilization sites throughout the Alberta Basin was used as a basis to target aquifers that would be likely candidates for CO2 disposal. Conclusions from examination of the hydrostratigraphy underlying the major power plants at Lake Wabamun, the Novaeor plant at Joffre, the Hanlan-Robb gas plant, the bi-provincial heavy oil upgrader at Lloydminster, and the oil fields at Carson Creek, Pembina and Redwater (Fig. 1) were that the most suitable disposal aquifers were located at lake Wabamun, based on both CO2-source magnitude and aquifer depth. A number of coal-based thermal power plants with a total capacity of more than 4,000 MW are located near Lake Wabamun. The only siliciclastic disposal aquifer in this area, satisfying the depth requirements for CO 2 disposal, is the thin Glaueonitic Sandstone aquifer [16]. A thicker, deeper carbonate aquifer (Nisku) was also chosen for analysis at Lake Wabamun [17]. The injection strategy is to use one well to access both aquifers. ~.d,.-~, ,,,,;.
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Location of major CO2 sources in Alberta and of oil fields with potential for C O 2 utilization in EOR operations [13] with reference to the Alberta Basin. 4. MINERAL TRAPPING OF CO2 IN AQUIFERS
An alternative which has been proposed to a stratigraphic trap is a mineral trap [5,18]. The geoebemical computer codes SOLMINEQ.88 [19] and PATHUBC.80 [20] were used to model water-rock reactions driven by the formation of carbonic acid when CO2 is injected into deep aquifers; and it was found that mineral trapping depends on the mineralogy of the aquifer. Carbonate aquifers were found to be limited in the quantity of CO2 which can be trapped by mineral reaction. The reactions between CO2, water and aquifer solids in the carbonate aquifers can be described in two steps: dissolution of calcite and adsorption of dissolved calcium on clays. The dissolving CO2 is neutralized to form bicarbonate ion due to the buffering action of carbonate dissolution, whereas the effect of ion exchange is to minimize the amount of dissolved calcium. In both cases the amount of reaction is small. Siliciclastic aquifers were predicted to have the best potential for trapping CO2 when they contain an assemblage of basic aluminosilicate minerals such as feldspars, zeolites, illites, chlorites and smectites which consume acid. When reacted with CO2, they break down to form kaolinite and the CO2 is neutralized. Depending on whether the basic aluminosilicate contains an alkali or alkaline earth cation, the formation water evolves in two different ways. For Na/K-bearing minerals, neutralization of the CO2
1138
GUNTER et al.: CO2 DISPOSALIN AOUIFERS
results in development of bicarbonate brines, whereas for Fe/Ca/Mg-bearing minerals, neutralization of CO2 results in precipitation of siderite, calcite or dolomite while the ionic strength of the formation water remains relatively constant. Either reaction path results in substantial trapping and immobilization of CO2, such that there is no possibility of the CO2 reaching the surface. Assessment of the CO2-trapping capability of the Glauconitic Sandstone aquifer has been made [6]. Field time scales were evaluated by geochemical modelling using the code PATHARC.94 and rate data from the literature for the minerals making up the Glauconitic Sandstone. The modelling predicted that in the field, CO2-trapping reactions take a minimum of 100 years to complete after the formation water has equilibrated at the temperature of the Glauconitic Sandstone aquifer (i.e. 54°C) and at the proposed injection pressure of the CO2 (260 bars). Every square kilometer of the Glauconitic Sandstone aquifer could sequester approximately 0.5 MT of CO 2 by these mineral-trapping reactions, once the CO zcharged formation water has swept through. Both the water-rock experiments and modelling [ 16] indicate that geochemical-trapping reactions of CO2 are slow - on the order of tens to hundreds of years, but fast enough to form effective CO2 traps given the long residence time of formation waters in the deep aquifers of the Alberta Basin [1]. Thus, given appropriate formation mineralogy [5], mineral traps can replace stratigraphic traps ensuring that the injected CO2 will be immobilized forever in the subsurface. 5. HYDRODYNAMIC TRAPPING OF COz IN AQUIFERS AND HYDRAULIC SINKS Hydrodynamic trapping was identified as a mechanism of CO2 trapping in the Alberta Basin [1] based on the following analysis. The hydraulic gradients driving the regional flow systems are of the order of 3m/kin or less [21-23]. The examination of hundreds of thousands of core data shows that the regionalscale permeability values are of the order of 1 md (10"15m2, [23-25]). Because these values do not account for fractures in carbonate rocks, it can be assumed that regional scale permeabilities are of the order of 10 to 50 md. The resulting regional-scale velocity of formation waters (Darcy velocity) in these aquifers is, thus, of the order of 1 to 10 cm/year. In reality, the water velocity may be even lower because of downdip buoyancy-driven flow caused by increased salinity, opposing the updip topographically driven flow to the northeast [4,21]. Therefore, once outside the injection-well radius of influence, the dissolved CO2 will travel with extremely slow velocity, with a residence time of the order of a 105 - 106 years. Thus, the deep formations in the Alberta Basin satisfy the requirement of long CO2 residence time. This geological time-scale trapping of CO2 in deep regional aquifers, caused by very low flow velocity, was named "hydrodynamic" trapping [ 1] because it depends on the hydrodynamic regime of formation waters. Regarding the concern of high pressure buildups in low-permeability rocks and possible rock fracturing, leading to CO2 escape through vertical conduits, the idea was advanced [1] that injection should take place in a zone of locally high permeability ("sweet" zone), surrounded by the generally low permeability aquifer, thereby avoiding near-well pressure buildups above the maximum levels imposed by various regulatory agencies. To test the conceptual model of hydrodynamic CO2 trapping in deep aquifers and estimate the capacity of these aquifers to accept and retain CO2, a series of numerical simulations were run for CO2 injection into the Glauconitic Sandstone and Nisku aquifers at the Lake Wabamun site in the Alberta Basin [2, 17]. Even for a homogeneous aquifer with permeabilities as low as 6 md (6xl0"~Sm2), CO2 could be injected at rates of 250 t/d/well in the thin (13m) Glauconitic Sandstone aquifer, and 1,200 t/d/well in the thick (60m) Nisku aquifer. The CO2 injectivity could be greatly increased if injection takes place in a "sweet" zone of high permeability. For example for a local permeability of 100 md (10-13m2),the CO2 injectivity increases with the size of the sweet zone, reaching rates of 520 t/d/well and 2,800 t/d/well for the two aquifers, for sweet zones 2 km in diameter. The numerical simulations have shown that aquifer porosity has little effect on CO2 injectivity, whereas permeability is the parameter exerting most control on injectivity, pressure distribution, flow velocity and CO2 travel distance. The aquifer thickness directly impacts on the volume of injected CO~. Other
GUNTER et
al.:
CO2 DISPOSALIN AQUIFERS
1139
aquifer properties, like formation water temperature and salinity were found to have little effect on COs injection for the range of values characterizing the Glauconitic and Nisku aquifers. The results of the numerical simulations were generalized [2, 17] to allow predictions of the CO2 injeetivity as a function of CO2 mobility for homogeneous aquifers, and the enhancement in CO2 injectivity due to injection in a local high-permeability ("sweet") zone as a function of the permeability of the sweet zone and of the regional-scale aquifer. In addition, thin, isolated aquifers in the Cretaceous and post-Cretaceous sedimentary succession in the southwestern part of the basin near the thrust and fold belt have the additional significant property that the flow of formation water is downdip, basin-inward, toward hydraulic sinks created by shale elastic rebound as a result of Tertiary-to-Recent erosion [22]. Thus, disposal of CO2, or indeed of any other liquid wastes, in these aquifers in this area will lead practically to the permanent capture and retention of CO2 and other wastes (on a geological time scale), as pointed out previously in a theoretical study [3]. 6. OUTLOOK FOR AQUIFER COs-DISPOSAL IN OTHER SEDIMENTARY BASINS The deep aquifers in the Alberta Basin are not unique in their properties and flow characteristics. For example, similar basin-inward flow of formation waters was also observed in a sub-Andean foreland basin in Colombia [26]. Thus, it is expected that other aquifers in various foreland sedimentary basins in the world may exhibit similar characteristics with regard to hydraulic sinks and mineral and hydrodynamic trapping, thus enhancing the advantages of disposing of CO 2 and other waste liquids in deep aquifers. Such foreland basins are found, for example, all along the eastern side of the American Cordillera, from the Rocky Mountains in North America to the Andes Mountains in South America, and adjacent to recently formed mountain ranges like the Alps, the Carpathians and Balkan mountains in Europe, and the Himalaya mountains in India. There are other types of mid-continent sedimentary basins, like the intra-cratonic Williston basin, Michigan and Illinois basins in North America and the Paris and Panonian basins in Europe. The flow of formation waters in deep aquifers in these basins is regional-scale in nature and generally slow (several cm/yr), as in the Alberta basin, being driven by the basin-scale topography [27]. These mid-continent sedimentary basins also offer the opportunity of disposing of CO2 and other liquid wastes by deep injection. On the other hand, intra-montane sedimentary basins may have limited capacity for CO2 disposal because of their generally small size. As for rift and coastal basins forming now, like the Beaufort Basin at the Arctic Ocean, the Gulf coast, and along the Atlantic Ocean, these basins are currently undergoing active compaction and subsidence, resulting in fluid expulsion. The flow of formation waters is not driven laterally by topography, which is nonexistent, but vertically by sediment loading and compaction. Thus, these sedimentary basins are not particularly suitable for the disposal of CO2 or other liquid wastes, unless sedimentary traps exist. 7. ECONOMIC CONSIDERATIONS The economics o f C O 2 capture from pulverized coal-fired power plants, typically about 500MW in size, in Canada and disposal in geological aquifers has been documented in several recent publications [18, 28]. Anticipated capture and compression costs from coal-fired stations in Canada, for use in enhanced oil recovery have also been throughly documented [12]. The overall economics of aquifer disposal of CO2, or for use in EOR, are dominated by capital construction costs for capture, purification and compression technologies. These capital investment costs range from $Cdn. 150M, assuming an Amine capture system in-place [28] to $490M, assuming no existing Amine capture units [12]. Operating costs can add anywhere from Cdn. $30M to $62M/yr - depending upon initial starting point assumptions. The field facilities that would be necessary for an aquifer disposal project from an existing pulverized coalfired station are based on the following assumptions: 500 MW station burning low sulfur coal (0.5%) with no existing flue gas desulfurization or NOx control technology, 30 year life span for the disposal project, 15 disposal wells accepting 1,000 tonnes/day (total 15,000 tonnes/day) into the Alberta Basin. The total capital costs for a metering station, pipeline (30km), drilling of wells, geotechnicai studies, land permitting and other miscellaneous costs are approximately Cdn. $33.2M [18]. Based on the above analysis, it is estimated that total costs would be approximately Cdn. $585M (capture capital - $490M, field capital - $33.2M, and operational costs - $61.5M). Thus, disposal costs are approximately equal to $52 tonne/CO2 ($2.67 mscf).
1140
GUNTER et
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CO2 DISPOSALIN AQUIFERS
On a macro scale, aquifer disposal of CO2 as a greenhouse gas mitigation possibility needs to be understood in the context of other options being examined by utilities in Canada and needs to be assessed in the context of current fiscal and policy regimes. Any CO2 mitigation activity or technology can be classified into one of four possible quadrants shown on Fig. 2. Price comparisons in Fig. 2 are only approximate and arc based mostly on 1993 Cdn. dollars. Individual mitigation activities or projects can have either positive or negative returns on investment and/or positive or negative net reduction in greenhouse gas emissions ("GHG", Fig. 2). Economic studies sort out projects between Quadrants AC and BD, while energy balance and lifecycle emissions studies should sort out projects between Quadrants AB vs. CD. Fig. 2 shows how the aquifer disposal option ranks compared to only a few other options, of many, being examined by industry in Canada. Some options, such as terrestrial storage of frozen COs are prohibitively high in cost and could actually result in a net increase in greenhouse gases. Turning COs into chemicals (Quadrants "A" and "C") can be low cost, is usually economic, may or may not result in a net reduction in greenhouse gases, and is unlikely to dispose of very large quantities of CO2. Use of CO2 for EOR is capable of disposing of large quantities of CO2 and will result in a net reduction in CO2 (Fig. 2), but the overall return on investment (either positive or negative) is highly dependent on factors such as the price of oil, price of CO2, and the individual reservoir characteristics [29]. EOR disposal also has limited capacity in a given field as costs tend to rise with time as less suitable fields are used for disposal. Under the Canadian Voluntary Challenge and Registry Program, industry is primarily looking at mitigation options in Quadrant "A", and in the low cost portion of Quadrant "B". In this context, aquifer disposal is a high cost option - only economic under certain fiscal regimes, but has the potential to dispose of very large quantities of CO2 and result in a real net reduction in greenhouse gases. Positive R e t u m o n I n v e s t m e n t
Positive Return o n I n v e s t m e n t Net Addition of GHG's
Net Reduction of GHG's
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Negative Return o n I n v e s t m e n t Net Reduction of GHG's
Negative Return o n I n v e s t m e n t Net Addition of GHG's
Figure 2 COs mitigation options: order of magnitude costs and disposal/offset potential* 8. SUMMARY AND CONCLUSIONS Low-permeability aquifers, as exist in the Alberta and other basins, can accept and retain large quantities of injected COs for long periods of time, provided that near-well "sweet" zones of high permeability are found, in order to attain high injection rates without reaching pressure limits imposed by rock-fracturing thresholds. The overall results show that injection of C02 in the supercritical state into deep aquifers in sedimentary basins is viable and may be among the best short-to-medium term solutions for preventing large emissions of COs into the atmosphere.
GUNTERet
al.: CO2 DISPOSALIN AQUIFERS
1141
The capacity for the long term aquifer storage of CO 2 in the Alberta Basin is much greater than Alberta's total emissions over the next 30 years. Assuming that the CO2-consuming mineral reactions go to completion, the maximum CO2 disposal capacity of the Glaueonitie Sandstone in the study area of 30x30 kilometers (consisting of 9 townships) is 450 MT of CO2. Assuming the properties of this aquifer extend beyond this arbitrarily defined area, 50 more MT of CO2 could be sequestered for each additional 100 km 2. A 500 MW coal-fired power plant would emit close to 15,000 tonnes/day of CO2. Over the life cycle of the power plant (approximately 30 years), 164 MT of COLwould be produced. Ideally this could be trapped in the Glauconitic Sandstone aquifer within an area of approximately 400 kmL. On a larger scale, total Alberta CO2 (power plant) emissions over a 30 year period are estimated at 2 GT (gigatonnes) of CO2. A recent estimate [I] of the storage capacity of the whole Alberta Basin is 20,000 MT or 20 GT. On an even larger scale, this value of 20 GT of COL storage capacity for aquifers in the Alberta Basin represents approximately 5% of total global estimates of 400+ GT. However we expect global estimates to increase as more detailed aquifer inventories are completed. Hydraulic, hydrodynamic and mineral traps are not restricted to the Alberta Basin but may be found in any deep sedimentary basin with low regional heads and low permeabilities and/or appropriate mineralogy. They offer alternatives to stratigraphic traps which may be not available for CO2 injection if they form hydrocarbon reservoirs. Sedimentary basins around the world provide the appropriate setting for mineral traps, hydraulic sinks, hydrodynamic traps and stratigraphic traps to be operable and thus are ideal candidates for CO2 storage in aquifers. Aquifer disposal of CO 2 will be expensive, due mainly to the cost of CO2 capture, purification and compression, and secondarily due to required field facilities. Although there are many possibilities to reduce CO2 emissions that are more economically attractive, aquifer disposal remains as one of the largest sinks available for CO2 in landlocked areas of the world; and may be utilized if other less expensive options are exhausted. Acknowledgements -The authors wish to express their gratitude to their colleagues (E.H. Perkins, B.W. Wiwchar, Z. Zhou, J.R. Underschultz, L.P. Yuan, M. Berthane, D. Cotterill) for their technical contributions and to the funding agencies and representatives on the management committee who made possible this research work: Alberta Department of Energy (J.K. Kleta), Environment Canada (Don Rose), CANMET (F.M. Mourits), TransAlta Utilities Corporation (M.M. McDonald) and Edmonton Power (Doug Heaton). REFERENCES 1. Bachu, S., Gunter, W.D. and Perkins, E.H., Aquifer disposal of CO2: hydrodynamic and mineral trapping. Energy Conversion and Management, v. 35, p. 269-279 (1994). 2. Law, D.H.-S, and Bachu, S., Hydrogeological and numerical analysis of CO2-disposal in deep aquifers in the Alberta Sedimentary Basin. This Volume (1995) 3. Neuzil, C.E., Groundwater flow in low permeability environments. Water Resources Research, v. 22, p. 1163-1195 (1986) 4. Bachu, S., Synthesis and model of formation water flow in the Alberta Basin. Amer. Ass. Petroleum Geol. Bull., v.79, August issue (1995). 5. Gunter, W.D., Perkins, E.H., and McCann, T.J., Aquifer disposal of CO2-rich gases: Reaction design for added capacity. Energy Conversion and Management 34, p. 941-948 (1993). 6. Perkins, E.H. and Gunter, W.D., Aquifer disposal of CO2-rich greenhouse gases: Modelling of waterrock reaction paths in a siliciclastic aquifer. To be presented at the 8th International Symposium on Water-Rock Interaction, Vladivostok, Russia, August 13-28 (1995). 7. Government of Canada, Canada's national action program on climate change. 42p. (1995). 8. Wright, G.N., McMechan, M.E. and Potter, D.E.G., Structure and Architecture of the Western Canadian Sedimentary Basin. Chapter 3 in Geological Atlas of the Western Canadian Basin, eds. - G. Mossop and I. Shetsen, Canadian Society of Petroleum Geologists and the Alberta Research Council, p.25-40 (1994). 9. Jacques, A.P., Canada's Greenhouse Gas Emissions: Estimates for 1990. Report EPS 5/AP/4. Environment Canada, December (1992).
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GUNTERet al.: CO2 DISPOSALIN AQUIFERS
10. Battelle, R&D Status of Carbon Dioxide Seperation, Disposal and Utilization Technologies". Prepared by Battelle, April (1991). 11. Dunsmor¢, H.E., A Geological Perspective on Global Warming and the Possibility of Carbon dioxide Removal as Calcium Carbonate Mineral. Energy Conversion and Management, Vol. 33, p. 565-572 (1992). 12. Vandenhengel, W. and Miyagishima, W, COs capture and use for EOR in Western Canada 2. COs extraction facilities. Energy Conversion and Management, Vol. 34, p. 1151-1156 (1993). 13. Bailey, R.T. and McDonald, M.M., COs capture and use for EOR in Western Canada 1. General Overview. Energy Conversion and Management, v. 35, p. 1145-1150 (1993). 14. Todd, M.R. and Grand, G.W., Enhanced Oil Recovery using Carbon Dioxide. Energy Conversion and Management, Vol. 34, p. 1157 - 1164 (1993). 15. Cochrane-SNC-Lavalin and Fluor Daniel Canada, Inc., COs Extraction Study, Phase I Report. Prepared for SaskPower. (1994) 16. Gunter, W.D., Bachu, S., Perkins, E.H., Undershultz, J.R., Wiwchar, B., Yuan, UP., Berhane, M. and Cotterill, D., Central Alberta: CO2 disposal into Alberta Basins - Phase II: Hydrogeological and mineralogical characterization of Mannville Group strata in the Lake Wabamun area & waterrock interactions due to COs injection into the Glauconitic Sandstone aquifer. Alberta Geological Survey Open File Report 1994-17, 125 pages + appendices. (1994). 17. Law, D.H.-S., Bachu, S. and Gunter, W.D., COs disposal into Alberta Basin aquifers - PhaselII: Hydrogeological and numerical analysis of CO2-disposal into deep siliciclastic and carbonate aquifers in the Lake Wabamun area. Alberta Geological Survey Open File Report 1995-6, 101 pages + appendices (1995). 18. Gunter, W.D., Perkins, E.H., Bachu, S., Law, D., Wiwchar, B., Zhou, Z. and McCann, T.J., Aquifer disposal of CO2-rich gases in the vicinity of the Sundance and Genesee Power Plants, Phase I: Injectivity, chemical reactions and proof of concept. Alberta Geological Survey Open File Report 1994-16, 116 pages + appendices (1994). 19. Kharaka, Y.K., Gunter, W.D., Aggarwal, P.K., Perkins, E.H. and DeBraal, J.D., SOLMINEQ.88: A computer program for geochemical modelling of water-rock interactions. U.S. Geological Survey, Water Resource Investigation Report 88-4227 (1988). 20. Perkins, E.H., A reinvestigation of the theoretical basis for the calculation of mass transfer in geochemical processes involving aqueous solutions. MSc thesis, University of British Columbia, Vancouver (1980). 21. Hitchon, B., Bachu, S. and Underschultz, J., Regional subsurface hydrogeology, Peace River Arch area, Alberta and British Columbia. I n Geology of the Peace River Arch (S.C. O'Connell and J.S. Bell, eds.). Bulletin of Canadian Petroleum Geology, v. 38(A), p. 196-217, (1990). 22. Bachu S. and Underschultz, J.R., Large-scale underpressuring in the Mississippian-Cretaceous succession, Southwestern Alberta Basin. Amer. Assoc. Petroleum Geol. Bull., v. 79, July issue (1995). 23. Bachu, S. and Underschultz, J.R., Hydrogeology of formation waters, northeastern Alberta basin. American Association of Petroleum Geologists Bulletin, v. 77, p. 1745-1768 (1993). 24. Bachu, S. and Underschultz, J.R., Regional-scale porosity and permeability variations, Peace River Arch area, Alberta, Canada. Amer. Assoc. of Petroleum Geologists Bulletin, v. 76, p. 547-567 (1992). 25. Hitchon, B., Bachu, S., Sauveplane, C.M., Ing, A., Lytviak, A.T. and Underschultz, J.R., Hydrogeological and geothermal regimes in the Phanerozoic succession, Cold Lake area, Alberta and Saskatchewan; Alberta Research Council Bulletin No. 59, 84 p. (1989). 26. Villegas, M.E., Bachu, S., Ramon, J.C. and Underschultz, J.R., Flow of formation waters in the Cretaceous-Miocene succession of the Llanos Basin, Columbia. Amer. Assoc. Petroleum Geol. Bull., v. 78, p. 1843-1862 (1994). 27. Bachu, S. and Hitehon, B., Regional-scale flow of formation waters in the Williston Basin. Amer. Ass. Petroleum Geol. Bull. (in press). 28. IEA, Carbon dioxide disposal in aquifers. IEA Greenhouse Gas R&D Programme, Study No. IEA/93/OE 14 (1993). 29. Padamsey, R. and Railton, J., COs capture and use for EOR in Western Canada 2. Economic results and conclusions. Energy Conversion and Management, vol. 34, p. 1165-1175 (1993).
0196-8904(95)00311-8
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T E C H N I C A L AND E C O N O M I C FEASIBILITY OF CO2 DISPOSAL IN A Q U I F E R S W I T H I N T H E A L B E R T A SEDIMENTARY BASIN, CANADA
W.D. GUNTER, STEFAN BACHU and D.H.-S. LAW Alberta Research Council, Edmonton, Alberta, Canada, T6H 5X2. VINOD MARWAHA Environment Canada, Edmonton, Alberta, Canada, T6B 2X3. D.L. DRYSDALE TransAlta Utilities Corporation, Calgary, Alberta, Canada, T2P 2M1. D.E. MACDONALD Alberta Department of Energy, Edmonton, Alberta, Canada, T5K 2G6. T.J. MCCANN T.J. McCann and Associates Ltd., Calgary, Alberta, Canada, T2P 3P4.
- A three year study of the technical and economic feasibility of aquifer disposal of CO2 in the low permeability sedimentary rocks of the Alberta Basin has revealed several new generic concepts that may be applicable to other sedimentary basins throughout the world. High permeability aquifers are not necessarily required for CO2 disposal. Injectivity of CO2 can be maximized by siting disposal wells in targeted or "sweet" zones of locally high permeability surrounded by a low regional scale permeability [1-2]. The low regional permeability forms a "hydrodynamic" or "time" trap for CO2 [1], where the residence time of CO2 in the aquifer is of the order of 105 to l& years. Another type of hydrodynamic trapping in sedimentary basins is produced by the "sponge" or "sink" effect of rebounding shales [3-4]. On a smaller time scale, over hundreds of years, "mineral" or "inert" trapping [5-6] by reaction of the CO2 with basic aluminosilicate minerals will occur in siliciclastic aquifers. Consequently, stratigraphic traps may not be necessary for safe disposal of CO2 in the subsurface. Abstract
Aquifer disposal of CO2 is expensive, on the order of $52/tonne. Although there are many possibilities to reduce CO2 emissions that are more economically attractive, aquifer disposal remains as one of the largest sinks available for CO2 in landlocked areas of the world; and may be utilized if other less expensive options are exhausted.
1. BACKGROUND Canada is working to meet its commitment, made at the Rio convention on climate change in 1992, to stabilize greenhouse gas emissions at the 1990 levels by the year 2000. At the recent UN Environment Conference in Berlin, Canada tabled its National Action Program on Climate Change. This national report [7] outlines several policy and technology options, as well as progress made so far in meeting Canada's goal of stabilization of greenhouse gases. One of its major cornerstone efforts is a Voluntary Challenge and Registry (VCR) Program. The VCR program will challenge industry and governments to voluntarily reduce their emissions and find new sinks for greenhouse gases. 1135
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GUNTER et al.: CO2 DISPOSALIN AQUIFERS 2. CO2 EMISSIONS IN THE ALBERTA SEDIMENTARY BASIN
The Western Canadian Sedimentary Basin (WCSB) is one of the largest sedimentary basins in the world and contains extensive natural resources. The WCSB is comprised of the Alberta Basin and the Williston Basin which extends into the USA. The Alberta Basin is a foreland basin bound by structural features (Fig. 1) and is characterized by a thick succession of Paleozoic, Mesozoic and Tertiary strata, resting on a Precambrian basement, with all the strata dipping gently to the west [8]. This succession reaches its maximum thickness within the Alberta Syncline, immediately to the east of the Canadian Rocky Mountain disturbed belt (Fig. 1). These units in the Rocky Mountains have been extensively thrust faulted and folded. There are several flow systems in the Alberta Basin [4], the most important being the S-SW to N-NE ones in the Paleozoic strata, and the southwestward flow system in the Cretaceous strata in the southwest driven inward by erosional rebound of thick Cretaceous and Tertiary shales. The latter result in hydrodynamic sinks. The Alberta Basin covers an area of 825,000 km2, with a volume of approximately 2 million km 3. Alberta is an energy-rich province of Canada, and a net exporter of energy from the coal, oil and gas reserves contained in the Alberta Basin. Carbon dioxide is one of the predominant greenhouse gases, which is known to contribute to global climate warming. As might be expected, major sources of CO2 point emissions from energy-related industrial activities in Canada are also located in the Alberta Basin. Alberta is the second largest CO2 emitter in Canada. Alberta's emissions of CO2 for the year 1 9 9 0 were 127 MT (megatonnes) as compared to national emissions of 461 MT [9]. A review of the research status of CO2 disposal technologies for Western Canada [ 10] revealed four types of possible CO2 disposal: biological, mineral immobilization, deep ocean disposal and injection into geological formations. Deep ocean disposal is not a practical alternative for reducing CO2 emissions from Alberta-based sources. The biological disposal starts from the idea that CO2 emissions may be offset by CO2 intake by forests. Nevertheless, this option suffers from a lack of credibility in the overall carbon and energy balance, and it is not clear how permanent the C O 2 storage is. Mineral immobilization of CO2 is a possibility for Alberta and it can be achieved by the conversion into carbonates of calcium and/or magnesium rich brines found in close proximity to fossil fuel deposits [ 10-11 ]. However, large amounts of base are needed, with considerable associated costs incurred [10]. In Alberta, CO2 can be injected into closed traps (depleted oil and gas reservoirs) and open traps (deep aquifers). The technology for CO2 capture, purification, compression, transport and injection is well understood by the petroleum industry [12]. Other options being considered are disposal of CO2 in coal seams to displace methane (commonly referred to as "coalbed methane"), and carbon fixing in prairie agricultural soils. In a previous study, the Alberta Oil Sands Technology and Research Authority (AOSTRA) examined the feasibility of removing 50,000 tonnes/day of CO2 from industrial sources by utilizing CO2 in enhanced oil recovery (EOR) operations in Alberta and Saskatchewan [ 13-14]. Throughout the study it became apparent that EOR operations will not necessarily be capable of utilizing all the CO2 envisaged to be removed. The CO2 injected in oil fields begins to be recovered at extraction wells. In this case CO 2 will have to be disposed by other means, of which injection into depleted gas reservoirs or deep aquifers may be the most suitable for Alberta [1]. On a parallel basis, the Saskatchewan Power Corporation has just completed a similar initial feasibility study [15] for reducing emission of CO2 by utilizing it for EOR operations in Saskatchewan. 3. SITING OF DISPOSAL AQUIFERS Trapping of the CO2 is a required condition for COz disposal and occurs in stratigraphic traps, in mineral traps or in hydrodynamic traps in the subsurface. Stratigraphic traps are not considered here because they are local phenomena and are the favored traps ofoii and gas. Normally they are not available to be used for CO2 trapping. Conversely mineral and hydrodynamic traps are ubiquitous to the Alberta Basin and are available for CO2 trapping.
GUNTER et al.: CO2 DISPOSAL IN AQUIFERS
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A survey [13] of CO2-emission and potential CO2-utilization sites throughout the Alberta Basin was used as a basis to target aquifers that would be likely candidates for CO2 disposal. Conclusions from examination of the hydrostratigraphy underlying the major power plants at Lake Wabamun, the Novaeor plant at Joffre, the Hanlan-Robb gas plant, the bi-provincial heavy oil upgrader at Lloydminster, and the oil fields at Carson Creek, Pembina and Redwater (Fig. 1) were that the most suitable disposal aquifers were located at lake Wabamun, based on both CO2-source magnitude and aquifer depth. A number of coal-based thermal power plants with a total capacity of more than 4,000 MW are located near Lake Wabamun. The only siliciclastic disposal aquifer in this area, satisfying the depth requirements for CO 2 disposal, is the thin Glaueonitic Sandstone aquifer [16]. A thicker, deeper carbonate aquifer (Nisku) was also chosen for analysis at Lake Wabamun [17]. The injection strategy is to use one well to access both aquifers. ~.d,.-~, ,,,,;.
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Location of major CO2 sources in Alberta and of oil fields with potential for C O 2 utilization in EOR operations [13] with reference to the Alberta Basin. 4. MINERAL TRAPPING OF CO2 IN AQUIFERS
An alternative which has been proposed to a stratigraphic trap is a mineral trap [5,18]. The geoebemical computer codes SOLMINEQ.88 [19] and PATHUBC.80 [20] were used to model water-rock reactions driven by the formation of carbonic acid when CO2 is injected into deep aquifers; and it was found that mineral trapping depends on the mineralogy of the aquifer. Carbonate aquifers were found to be limited in the quantity of CO2 which can be trapped by mineral reaction. The reactions between CO2, water and aquifer solids in the carbonate aquifers can be described in two steps: dissolution of calcite and adsorption of dissolved calcium on clays. The dissolving CO2 is neutralized to form bicarbonate ion due to the buffering action of carbonate dissolution, whereas the effect of ion exchange is to minimize the amount of dissolved calcium. In both cases the amount of reaction is small. Siliciclastic aquifers were predicted to have the best potential for trapping CO2 when they contain an assemblage of basic aluminosilicate minerals such as feldspars, zeolites, illites, chlorites and smectites which consume acid. When reacted with CO2, they break down to form kaolinite and the CO2 is neutralized. Depending on whether the basic aluminosilicate contains an alkali or alkaline earth cation, the formation water evolves in two different ways. For Na/K-bearing minerals, neutralization of the CO2
1138
GUNTER et al.: CO2 DISPOSALIN AOUIFERS
results in development of bicarbonate brines, whereas for Fe/Ca/Mg-bearing minerals, neutralization of CO2 results in precipitation of siderite, calcite or dolomite while the ionic strength of the formation water remains relatively constant. Either reaction path results in substantial trapping and immobilization of CO2, such that there is no possibility of the CO2 reaching the surface. Assessment of the CO2-trapping capability of the Glauconitic Sandstone aquifer has been made [6]. Field time scales were evaluated by geochemical modelling using the code PATHARC.94 and rate data from the literature for the minerals making up the Glauconitic Sandstone. The modelling predicted that in the field, CO2-trapping reactions take a minimum of 100 years to complete after the formation water has equilibrated at the temperature of the Glauconitic Sandstone aquifer (i.e. 54°C) and at the proposed injection pressure of the CO2 (260 bars). Every square kilometer of the Glauconitic Sandstone aquifer could sequester approximately 0.5 MT of CO 2 by these mineral-trapping reactions, once the CO zcharged formation water has swept through. Both the water-rock experiments and modelling [ 16] indicate that geochemical-trapping reactions of CO2 are slow - on the order of tens to hundreds of years, but fast enough to form effective CO2 traps given the long residence time of formation waters in the deep aquifers of the Alberta Basin [1]. Thus, given appropriate formation mineralogy [5], mineral traps can replace stratigraphic traps ensuring that the injected CO2 will be immobilized forever in the subsurface. 5. HYDRODYNAMIC TRAPPING OF COz IN AQUIFERS AND HYDRAULIC SINKS Hydrodynamic trapping was identified as a mechanism of CO2 trapping in the Alberta Basin [1] based on the following analysis. The hydraulic gradients driving the regional flow systems are of the order of 3m/kin or less [21-23]. The examination of hundreds of thousands of core data shows that the regionalscale permeability values are of the order of 1 md (10"15m2, [23-25]). Because these values do not account for fractures in carbonate rocks, it can be assumed that regional scale permeabilities are of the order of 10 to 50 md. The resulting regional-scale velocity of formation waters (Darcy velocity) in these aquifers is, thus, of the order of 1 to 10 cm/year. In reality, the water velocity may be even lower because of downdip buoyancy-driven flow caused by increased salinity, opposing the updip topographically driven flow to the northeast [4,21]. Therefore, once outside the injection-well radius of influence, the dissolved CO2 will travel with extremely slow velocity, with a residence time of the order of a 105 - 106 years. Thus, the deep formations in the Alberta Basin satisfy the requirement of long CO2 residence time. This geological time-scale trapping of CO2 in deep regional aquifers, caused by very low flow velocity, was named "hydrodynamic" trapping [ 1] because it depends on the hydrodynamic regime of formation waters. Regarding the concern of high pressure buildups in low-permeability rocks and possible rock fracturing, leading to CO2 escape through vertical conduits, the idea was advanced [1] that injection should take place in a zone of locally high permeability ("sweet" zone), surrounded by the generally low permeability aquifer, thereby avoiding near-well pressure buildups above the maximum levels imposed by various regulatory agencies. To test the conceptual model of hydrodynamic CO2 trapping in deep aquifers and estimate the capacity of these aquifers to accept and retain CO2, a series of numerical simulations were run for CO2 injection into the Glauconitic Sandstone and Nisku aquifers at the Lake Wabamun site in the Alberta Basin [2, 17]. Even for a homogeneous aquifer with permeabilities as low as 6 md (6xl0"~Sm2), CO2 could be injected at rates of 250 t/d/well in the thin (13m) Glauconitic Sandstone aquifer, and 1,200 t/d/well in the thick (60m) Nisku aquifer. The CO2 injectivity could be greatly increased if injection takes place in a "sweet" zone of high permeability. For example for a local permeability of 100 md (10-13m2),the CO2 injectivity increases with the size of the sweet zone, reaching rates of 520 t/d/well and 2,800 t/d/well for the two aquifers, for sweet zones 2 km in diameter. The numerical simulations have shown that aquifer porosity has little effect on CO2 injectivity, whereas permeability is the parameter exerting most control on injectivity, pressure distribution, flow velocity and CO2 travel distance. The aquifer thickness directly impacts on the volume of injected CO~. Other
GUNTER et
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CO2 DISPOSALIN AQUIFERS
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aquifer properties, like formation water temperature and salinity were found to have little effect on COs injection for the range of values characterizing the Glauconitic and Nisku aquifers. The results of the numerical simulations were generalized [2, 17] to allow predictions of the CO2 injeetivity as a function of CO2 mobility for homogeneous aquifers, and the enhancement in CO2 injectivity due to injection in a local high-permeability ("sweet") zone as a function of the permeability of the sweet zone and of the regional-scale aquifer. In addition, thin, isolated aquifers in the Cretaceous and post-Cretaceous sedimentary succession in the southwestern part of the basin near the thrust and fold belt have the additional significant property that the flow of formation water is downdip, basin-inward, toward hydraulic sinks created by shale elastic rebound as a result of Tertiary-to-Recent erosion [22]. Thus, disposal of CO2, or indeed of any other liquid wastes, in these aquifers in this area will lead practically to the permanent capture and retention of CO2 and other wastes (on a geological time scale), as pointed out previously in a theoretical study [3]. 6. OUTLOOK FOR AQUIFER COs-DISPOSAL IN OTHER SEDIMENTARY BASINS The deep aquifers in the Alberta Basin are not unique in their properties and flow characteristics. For example, similar basin-inward flow of formation waters was also observed in a sub-Andean foreland basin in Colombia [26]. Thus, it is expected that other aquifers in various foreland sedimentary basins in the world may exhibit similar characteristics with regard to hydraulic sinks and mineral and hydrodynamic trapping, thus enhancing the advantages of disposing of CO 2 and other waste liquids in deep aquifers. Such foreland basins are found, for example, all along the eastern side of the American Cordillera, from the Rocky Mountains in North America to the Andes Mountains in South America, and adjacent to recently formed mountain ranges like the Alps, the Carpathians and Balkan mountains in Europe, and the Himalaya mountains in India. There are other types of mid-continent sedimentary basins, like the intra-cratonic Williston basin, Michigan and Illinois basins in North America and the Paris and Panonian basins in Europe. The flow of formation waters in deep aquifers in these basins is regional-scale in nature and generally slow (several cm/yr), as in the Alberta basin, being driven by the basin-scale topography [27]. These mid-continent sedimentary basins also offer the opportunity of disposing of CO2 and other liquid wastes by deep injection. On the other hand, intra-montane sedimentary basins may have limited capacity for CO2 disposal because of their generally small size. As for rift and coastal basins forming now, like the Beaufort Basin at the Arctic Ocean, the Gulf coast, and along the Atlantic Ocean, these basins are currently undergoing active compaction and subsidence, resulting in fluid expulsion. The flow of formation waters is not driven laterally by topography, which is nonexistent, but vertically by sediment loading and compaction. Thus, these sedimentary basins are not particularly suitable for the disposal of CO2 or other liquid wastes, unless sedimentary traps exist. 7. ECONOMIC CONSIDERATIONS The economics o f C O 2 capture from pulverized coal-fired power plants, typically about 500MW in size, in Canada and disposal in geological aquifers has been documented in several recent publications [18, 28]. Anticipated capture and compression costs from coal-fired stations in Canada, for use in enhanced oil recovery have also been throughly documented [12]. The overall economics of aquifer disposal of CO2, or for use in EOR, are dominated by capital construction costs for capture, purification and compression technologies. These capital investment costs range from $Cdn. 150M, assuming an Amine capture system in-place [28] to $490M, assuming no existing Amine capture units [12]. Operating costs can add anywhere from Cdn. $30M to $62M/yr - depending upon initial starting point assumptions. The field facilities that would be necessary for an aquifer disposal project from an existing pulverized coalfired station are based on the following assumptions: 500 MW station burning low sulfur coal (0.5%) with no existing flue gas desulfurization or NOx control technology, 30 year life span for the disposal project, 15 disposal wells accepting 1,000 tonnes/day (total 15,000 tonnes/day) into the Alberta Basin. The total capital costs for a metering station, pipeline (30km), drilling of wells, geotechnicai studies, land permitting and other miscellaneous costs are approximately Cdn. $33.2M [18]. Based on the above analysis, it is estimated that total costs would be approximately Cdn. $585M (capture capital - $490M, field capital - $33.2M, and operational costs - $61.5M). Thus, disposal costs are approximately equal to $52 tonne/CO2 ($2.67 mscf).
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CO2 DISPOSALIN AQUIFERS
On a macro scale, aquifer disposal of CO2 as a greenhouse gas mitigation possibility needs to be understood in the context of other options being examined by utilities in Canada and needs to be assessed in the context of current fiscal and policy regimes. Any CO2 mitigation activity or technology can be classified into one of four possible quadrants shown on Fig. 2. Price comparisons in Fig. 2 are only approximate and arc based mostly on 1993 Cdn. dollars. Individual mitigation activities or projects can have either positive or negative returns on investment and/or positive or negative net reduction in greenhouse gas emissions ("GHG", Fig. 2). Economic studies sort out projects between Quadrants AC and BD, while energy balance and lifecycle emissions studies should sort out projects between Quadrants AB vs. CD. Fig. 2 shows how the aquifer disposal option ranks compared to only a few other options, of many, being examined by industry in Canada. Some options, such as terrestrial storage of frozen COs are prohibitively high in cost and could actually result in a net increase in greenhouse gases. Turning COs into chemicals (Quadrants "A" and "C") can be low cost, is usually economic, may or may not result in a net reduction in greenhouse gases, and is unlikely to dispose of very large quantities of CO2. Use of CO2 for EOR is capable of disposing of large quantities of CO2 and will result in a net reduction in CO2 (Fig. 2), but the overall return on investment (either positive or negative) is highly dependent on factors such as the price of oil, price of CO2, and the individual reservoir characteristics [29]. EOR disposal also has limited capacity in a given field as costs tend to rise with time as less suitable fields are used for disposal. Under the Canadian Voluntary Challenge and Registry Program, industry is primarily looking at mitigation options in Quadrant "A", and in the low cost portion of Quadrant "B". In this context, aquifer disposal is a high cost option - only economic under certain fiscal regimes, but has the potential to dispose of very large quantities of CO2 and result in a real net reduction in greenhouse gases. Positive R e t u m o n I n v e s t m e n t
Positive Return o n I n v e s t m e n t Net Addition of GHG's
Net Reduction of GHG's
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Negative Return o n I n v e s t m e n t Net Reduction of GHG's
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Figure 2 COs mitigation options: order of magnitude costs and disposal/offset potential* 8. SUMMARY AND CONCLUSIONS Low-permeability aquifers, as exist in the Alberta and other basins, can accept and retain large quantities of injected COs for long periods of time, provided that near-well "sweet" zones of high permeability are found, in order to attain high injection rates without reaching pressure limits imposed by rock-fracturing thresholds. The overall results show that injection of C02 in the supercritical state into deep aquifers in sedimentary basins is viable and may be among the best short-to-medium term solutions for preventing large emissions of COs into the atmosphere.
GUNTERet
al.: CO2 DISPOSALIN AQUIFERS
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The capacity for the long term aquifer storage of CO 2 in the Alberta Basin is much greater than Alberta's total emissions over the next 30 years. Assuming that the CO2-consuming mineral reactions go to completion, the maximum CO2 disposal capacity of the Glaueonitie Sandstone in the study area of 30x30 kilometers (consisting of 9 townships) is 450 MT of CO2. Assuming the properties of this aquifer extend beyond this arbitrarily defined area, 50 more MT of CO2 could be sequestered for each additional 100 km 2. A 500 MW coal-fired power plant would emit close to 15,000 tonnes/day of CO2. Over the life cycle of the power plant (approximately 30 years), 164 MT of COLwould be produced. Ideally this could be trapped in the Glauconitic Sandstone aquifer within an area of approximately 400 kmL. On a larger scale, total Alberta CO2 (power plant) emissions over a 30 year period are estimated at 2 GT (gigatonnes) of CO2. A recent estimate [I] of the storage capacity of the whole Alberta Basin is 20,000 MT or 20 GT. On an even larger scale, this value of 20 GT of COL storage capacity for aquifers in the Alberta Basin represents approximately 5% of total global estimates of 400+ GT. However we expect global estimates to increase as more detailed aquifer inventories are completed. Hydraulic, hydrodynamic and mineral traps are not restricted to the Alberta Basin but may be found in any deep sedimentary basin with low regional heads and low permeabilities and/or appropriate mineralogy. They offer alternatives to stratigraphic traps which may be not available for CO2 injection if they form hydrocarbon reservoirs. Sedimentary basins around the world provide the appropriate setting for mineral traps, hydraulic sinks, hydrodynamic traps and stratigraphic traps to be operable and thus are ideal candidates for CO2 storage in aquifers. Aquifer disposal of CO 2 will be expensive, due mainly to the cost of CO2 capture, purification and compression, and secondarily due to required field facilities. Although there are many possibilities to reduce CO2 emissions that are more economically attractive, aquifer disposal remains as one of the largest sinks available for CO2 in landlocked areas of the world; and may be utilized if other less expensive options are exhausted. Acknowledgements -The authors wish to express their gratitude to their colleagues (E.H. Perkins, B.W. Wiwchar, Z. Zhou, J.R. Underschultz, L.P. Yuan, M. Berthane, D. Cotterill) for their technical contributions and to the funding agencies and representatives on the management committee who made possible this research work: Alberta Department of Energy (J.K. Kleta), Environment Canada (Don Rose), CANMET (F.M. Mourits), TransAlta Utilities Corporation (M.M. McDonald) and Edmonton Power (Doug Heaton). REFERENCES 1. Bachu, S., Gunter, W.D. and Perkins, E.H., Aquifer disposal of CO2: hydrodynamic and mineral trapping. Energy Conversion and Management, v. 35, p. 269-279 (1994). 2. Law, D.H.-S, and Bachu, S., Hydrogeological and numerical analysis of CO2-disposal in deep aquifers in the Alberta Sedimentary Basin. This Volume (1995) 3. Neuzil, C.E., Groundwater flow in low permeability environments. Water Resources Research, v. 22, p. 1163-1195 (1986) 4. Bachu, S., Synthesis and model of formation water flow in the Alberta Basin. Amer. Ass. Petroleum Geol. Bull., v.79, August issue (1995). 5. Gunter, W.D., Perkins, E.H., and McCann, T.J., Aquifer disposal of CO2-rich gases: Reaction design for added capacity. Energy Conversion and Management 34, p. 941-948 (1993). 6. Perkins, E.H. and Gunter, W.D., Aquifer disposal of CO2-rich greenhouse gases: Modelling of waterrock reaction paths in a siliciclastic aquifer. To be presented at the 8th International Symposium on Water-Rock Interaction, Vladivostok, Russia, August 13-28 (1995). 7. Government of Canada, Canada's national action program on climate change. 42p. (1995). 8. Wright, G.N., McMechan, M.E. and Potter, D.E.G., Structure and Architecture of the Western Canadian Sedimentary Basin. Chapter 3 in Geological Atlas of the Western Canadian Basin, eds. - G. Mossop and I. Shetsen, Canadian Society of Petroleum Geologists and the Alberta Research Council, p.25-40 (1994). 9. Jacques, A.P., Canada's Greenhouse Gas Emissions: Estimates for 1990. Report EPS 5/AP/4. Environment Canada, December (1992).
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10. Battelle, R&D Status of Carbon Dioxide Seperation, Disposal and Utilization Technologies". Prepared by Battelle, April (1991). 11. Dunsmor¢, H.E., A Geological Perspective on Global Warming and the Possibility of Carbon dioxide Removal as Calcium Carbonate Mineral. Energy Conversion and Management, Vol. 33, p. 565-572 (1992). 12. Vandenhengel, W. and Miyagishima, W, COs capture and use for EOR in Western Canada 2. COs extraction facilities. Energy Conversion and Management, Vol. 34, p. 1151-1156 (1993). 13. Bailey, R.T. and McDonald, M.M., COs capture and use for EOR in Western Canada 1. General Overview. Energy Conversion and Management, v. 35, p. 1145-1150 (1993). 14. Todd, M.R. and Grand, G.W., Enhanced Oil Recovery using Carbon Dioxide. Energy Conversion and Management, Vol. 34, p. 1157 - 1164 (1993). 15. Cochrane-SNC-Lavalin and Fluor Daniel Canada, Inc., COs Extraction Study, Phase I Report. Prepared for SaskPower. (1994) 16. Gunter, W.D., Bachu, S., Perkins, E.H., Undershultz, J.R., Wiwchar, B., Yuan, UP., Berhane, M. and Cotterill, D., Central Alberta: CO2 disposal into Alberta Basins - Phase II: Hydrogeological and mineralogical characterization of Mannville Group strata in the Lake Wabamun area & waterrock interactions due to COs injection into the Glauconitic Sandstone aquifer. Alberta Geological Survey Open File Report 1994-17, 125 pages + appendices. (1994). 17. Law, D.H.-S., Bachu, S. and Gunter, W.D., COs disposal into Alberta Basin aquifers - PhaselII: Hydrogeological and numerical analysis of CO2-disposal into deep siliciclastic and carbonate aquifers in the Lake Wabamun area. Alberta Geological Survey Open File Report 1995-6, 101 pages + appendices (1995). 18. Gunter, W.D., Perkins, E.H., Bachu, S., Law, D., Wiwchar, B., Zhou, Z. and McCann, T.J., Aquifer disposal of CO2-rich gases in the vicinity of the Sundance and Genesee Power Plants, Phase I: Injectivity, chemical reactions and proof of concept. Alberta Geological Survey Open File Report 1994-16, 116 pages + appendices (1994). 19. Kharaka, Y.K., Gunter, W.D., Aggarwal, P.K., Perkins, E.H. and DeBraal, J.D., SOLMINEQ.88: A computer program for geochemical modelling of water-rock interactions. U.S. Geological Survey, Water Resource Investigation Report 88-4227 (1988). 20. Perkins, E.H., A reinvestigation of the theoretical basis for the calculation of mass transfer in geochemical processes involving aqueous solutions. MSc thesis, University of British Columbia, Vancouver (1980). 21. Hitchon, B., Bachu, S. and Underschultz, J., Regional subsurface hydrogeology, Peace River Arch area, Alberta and British Columbia. I n Geology of the Peace River Arch (S.C. O'Connell and J.S. Bell, eds.). Bulletin of Canadian Petroleum Geology, v. 38(A), p. 196-217, (1990). 22. Bachu S. and Underschultz, J.R., Large-scale underpressuring in the Mississippian-Cretaceous succession, Southwestern Alberta Basin. Amer. Assoc. Petroleum Geol. Bull., v. 79, July issue (1995). 23. Bachu, S. and Underschultz, J.R., Hydrogeology of formation waters, northeastern Alberta basin. American Association of Petroleum Geologists Bulletin, v. 77, p. 1745-1768 (1993). 24. Bachu, S. and Underschultz, J.R., Regional-scale porosity and permeability variations, Peace River Arch area, Alberta, Canada. Amer. Assoc. of Petroleum Geologists Bulletin, v. 76, p. 547-567 (1992). 25. Hitchon, B., Bachu, S., Sauveplane, C.M., Ing, A., Lytviak, A.T. and Underschultz, J.R., Hydrogeological and geothermal regimes in the Phanerozoic succession, Cold Lake area, Alberta and Saskatchewan; Alberta Research Council Bulletin No. 59, 84 p. (1989). 26. Villegas, M.E., Bachu, S., Ramon, J.C. and Underschultz, J.R., Flow of formation waters in the Cretaceous-Miocene succession of the Llanos Basin, Columbia. Amer. Assoc. Petroleum Geol. Bull., v. 78, p. 1843-1862 (1994). 27. Bachu, S. and Hitehon, B., Regional-scale flow of formation waters in the Williston Basin. Amer. Ass. Petroleum Geol. Bull. (in press). 28. IEA, Carbon dioxide disposal in aquifers. IEA Greenhouse Gas R&D Programme, Study No. IEA/93/OE 14 (1993). 29. Padamsey, R. and Railton, J., COs capture and use for EOR in Western Canada 2. Economic results and conclusions. Energy Conversion and Management, vol. 34, p. 1165-1175 (1993).