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Geological Sequestration of Anthropogenic Carbon Dioxide in the Western Canada Sedimentary Basin: Suitability Analysis

STEFAN BACHU and S. STEWART

Alberta Geological Survey Alberta Energy and Utilities Board

Abstract Geological sequestration of anthropogenic CO2 is a potential solution to the release into the atmosphere of CO2, a greenhouse gas thought as significantly contributing to the global warming trend observed since the beginning of the industrial revolution. Basically, CO2 can be sequestered in geological media: 1) through enhanced oil recovery (EOR), 2) by storage in depleted oil and gas reservoirs, 3) through replacement by CO2 of methane in deep coal beds (ECBMR), 4) by injection into deep saline aquifers, and 5) by storage in salt caverns. Criteria in assessing the suitability of a sedimentary basin for CO2 sequestration are: a) tectonism and geology, b) the flow of formation waters and geothermal regime, and c) the existence of storage media (hydrocarbon reservoirs, coal seams, deep aquifers and salt structures). Generally, the Western Canada Sedimentary Basin is suitable for CO2 sequestration by all means because it is tectonically stable, it has regional-scale aquifers confined by aquitards or aquicludes, and has oil and gas reservoirs in various stages of depletion, uneconomic coal seams, and extensive salt beds. However, various regions in the basin have different degrees of suitability that range from not suitable along the eastern edge of the basin, to extremely suitable in southwestern and central Alberta. Most major CO2 producers, such as power plants and refineries around Edmonton, are found in regions that are suitable for CO2 sequestration in geological media; however, some, such as the oil sands plants in the Athabasca area, are in regions that are not suitable. This analysis of the suitability of the Western Canada Sedimentary Basin for CO2 sequestration in geological media should provide industry and governments with essential information needed for developing plans and policies in response to climate change effects of anthropogenic greenhouse gas emissions into the atmosphere. Introduction Human activity since the industrial revolution had the effect of increasing atmospheric concentrations of gases with a greenhouse effect, such as carbon dioxide (CO2) and methane (CH4), leading to climate warming and weather changes(1, 2). Because of its relative abundance compared with the other greenhouse gases, CO2 is by far the most important, being responsible for about 64% of the enhanced “greenhouse effect”(1). On a sectoral basis, the energy sector contributes globally the most (45%) to anthropogenic (produced by human activity) effects on climate change(3). The high use of fossil fuels (85% of the world’s energy needs), foreseen to continue well into the future(2, 4), is the major contributor to increased emissions of CO2 into the atmosphere. Thus, a major

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challenge in mitigating anthropogenic (man-made) effects on climate change is the reduction of these emissions. Figure 1 shows Canada’s profile in CO2 emissions by sector and by province. The profile of CO2 emissions in the Western Canada Sedimentary Basin is different from the national and other regions’ profile because the basin is a major North American producer of fossil fuels. In addition, because of the abundance of cheap fossil fuels, mainly coal, the power generation in Alberta and Saskatchewan is thermally based, unlike in the rest of Canada where it is mainly nuclear or hydroelectric. The major CO2 producers in the basin (>100,000 t/yr) and their location are shown in Figure 2. These sources produce ~113 MtCO2/yr in Alberta, ~21 MtCO2/yr in Saskatchewan, ~4 MtCO2/yr in northeastern BC, and ~2 MtCO2/yr in Manitoba (2000 figures). No single category of mitigation measures is sufficient and many of them are mutually dependent, including both a reduction in greenhouse gas emissions and the enhancement of greenhouse gas sinks(5). More costly mitigation approaches need to be considered, foremost among them being CO2 capture and sequestration, whose costs are comparable to those for nuclear or renewable energy options(6). In this context, sequestration is the removal of CO2, either directly from anthropogenic sources, or from the atmosphere, and disposing of it either permanently or for geologically-significant time periods. For landlocked regions, such as the Canadian Prairies, CO2 sequestration in geological media is the best option currently available for the long-term sequestration of CO2

(7). Since fossil fuels and power generation are linked with sedimentary basins(8), geological sequestration has the added advantage of lower overall transportation costs. The technology for gas and oil storage and of deep injection of acid gas and industrial liquid waste is well developed and practiced mainly by the energy industry. Depending on the type of CO2 disposal and trapping mechanism, the residence time may be up to several million years(9, 10). Cost, local environmental issues and public perception may need addressing for large-scale implementation of CO2 sequestration, but these are issues common to all mid- to long-term CO2 sequestration technologies. Geological Sinks for CO2 At normal atmospheric conditions, CO2 is a very stable gas heavier than air. For temperatures >31.1 oC and pressures >7.38 MPa (critical point), CO2 is in a supercritical state, behaving like a gas by filling all the available volume and having a “liquid” density that increases with pressure from 200 to more than 1000 kg/m3 (Figure 3). For conditions below the critical point, CO2 is either a gas or a liquid, depending on temperature and pressure (Figure 3). Thus, knowledge of the geothermal and pressure regimes in a basin is critical for establishing the physical state and density of CO2 at in-situ conditions(11). For depths below both the 31.1oC isotherm and 7.38 MPa isobar, CO2 will be in super-critical state. For shallower depths, CO2 will be in either liquid or gaseous phase, depending on temperature and pressure. Other relevant properties are CO2 solubility in water, which decreases with increasing water salinity, and CO2 affinity to coal, which is almost twice as high as that of methane, a gas abundantly found in coal beds. These properties of CO2

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and various other criteria play a role in the selection of the appropriate means and sites for CO2 disposal and sequestration in geological media. Carbon dioxide is currently used worldwide in more than 70 tertiary enhanced oil recovery (EOR) operations to increase oil mobility and to displace up to 40 % of the residual oil left after primary production and water flooding(12), but the total amount that can ultimately be sequestered in EOR operations is very small compared with CO2 sources(13). Injecting CO2 into coal beds that are too deep or uneconomic for coal mining presents the additional advantage of producing methane (14), as in the San Juan basin(15). Hydrocarbon reservoirs in structural and stratigraphic traps have demonstrated good storage and sealing characteristics over geological time, thus they can be used for CO2 sequestration once a reservoir is depleted and no longer producing. Closed depleted gas reservoirs represent the most straightforward case of CO2 sequestration in geological media, as primary recovery usually removes as much as 95% of the original gas in place and CO2 can be used to re-pressurize the reservoir to its original pressure. However, increasing the pressure beyond the original reservoir pressure could pose problems of reservoir integrity and safety(16). Carbon dioxide can be hydrodynamically trapped(9) in deep aquifers for geological periods of time. This is because of slow spreading away from the injection well and of hydrodynamic dispersion in the aquifer once outside the well radius of influence(17), and of extremely long residence time due to the very low velocity of formation waters(9). Some of the injected CO2 will dissolve in the water and the rest will form a plume that will override at the top of the aquifer(9, 17, 18). Iinjection of CO2 in local flow systems is not recommended because these are shallow, have a relatively short travel time, and have temperatures and pressures at which CO2 is in gaseous phase. Under these conditions, CO2 will most probably override at the top of the aquifers and may escape into the atmosphere at outcrop. In addition, the injected CO2 may contaminate shallow groundwater resources. Sequestration of CO2 by injection into intermediate flow systems is not recommended either because these systems are located at shallow-to-intermediate depths and CO2 will most probably be unstable (may change phase from liquid or supercritical to gas) and may easily override and escape into local flow systems, particularly in areas of cross-formational flow and mixing along unconformities. The injection since 1989 of acid gas, a mixture of CO2 and H2S, into deep saline aquifers and depleted hydrocarbon reservoirs in western Canada(19) represents an example of successful disposal of gases in sedimentary basins. Carbon dioxide could be permanently sequestered in deep aquifers by mineral immobilization, although extremely long periods of time are needed for sequestration through geochemical reactions(9). Storage in salt caverns could also provide a very long-term solution to CO2 sequestration in geological media(20). The technology has already been developed and applied for underground storage of petroleum, natural gas and compressed air(21) or for salt mining. Currently, single salt caverns are up to 5x105 m3 in volume and can store fluids at pressures up to 80% of the fracturing threshold.

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Basin Characteristics with Respect to CO2 Sequestration Several criteria have to be considered when analyzing the suitability of a sedimentary basin for CO2 sequestration(11, 22), which relate to basin tectonism and geology, geothermal and hydrogeological regimes, hydrocarbon potential and basin maturity, and basin infrastructure. The Western Canada Sedimentary Basin is actually comprised of the foreland Alberta basin and of the Canadian part of the intracratonic Williston basin (Figure 2). Both are tectonically and geologically suitable for CO2 sequestration(22) because they are underlain by a stable Precambrian platform, far from areas of tectonic plate convergence characterized by earthquakes and volcanism, orogenic events and extensive faulting. The Cambrian-to-Lower Jurassic succession was deposited during the passive-margin stage of basin evolution and consists of mainly carbonate and evaporitic strata, with a few intervening shales(23). The Upper Jurassic-to-Tertiary strata consist of a succession of regional-scale thin sandstones and thick shales deposited during the foreland stage of basin evolution(23). Temperatures in the basin reach up to 200oC at its deepest in the southwest. The basin is “cold” in the south and “warm” in the north, with corresponding effects on CO2-sequestration suitability and capacity(24). Multi-annual ground-surface temperatures vary from 7oC in the south to <5oC in the north and along the thrust and fold belt(25). Geothermal gradients vary between <20oC/km in southern Alberta (cold basin) and >50oC/km in northern Alberta (warm basin). Accordingly, the depth to the 31.1oC isotherm varies in the basin from more than 1200-1400 m in southern Alberta to less than 700 m in northern Alberta (Figure 4). Because of local anomalies in basement heat flow and of variations in lithology(26), the depth to the 31.1oC isotherm deviates locally from the basin-scale north-south trend of decreasing depth. Along the eastern basin edge, where the basin is shallow, the 31.1oC isotherm is found below the Precambrian crystalline basement (Figure 4). Thus: �� the drilling depth for CO2 sequestration in super-critical state is significantly greater

in southern and central Alberta and in Saskatchewan than in northern Alberta and northeastern British Columbia, and

�� CO2 cannot attain the super-critical state within the shallow sedimentary succession along the eastern edge of the basin in an area that runs from Great Slave Lake in the north, to Fort McMurray, Cold Lake, Saskatoon and Winnipeg in the southeast.

All units from the Devonian to the Upper Cretaceous contain gas and oil reservoirs that, once depleted, can be used for CO2 sequestration. The Cretaceous Mannville, Belly River, Horseshoe Canyon and Scollard strata contain uneconomic coal seams of variable thickness, maturity and quality(27). Coal seams vary in rank with depth from lignitic to bituminous(28, 29), reach up to 6 m in thickness and have a gas content that varies between 2 and 15 m3/t(28). These coals can be used for coalbed methane production and CO2 sequestration(14). Hydrostratigraphically, the carbonate and sandstone units are aquifers, the shales are aquitards and the evaporitic strata are aquicludes. Most deep aquifers are overlain by

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competent, thick, regionally-extensive aquicludes and aquitards such as the Prairie, Ireton, Exshaw-Banff, Colorado and Lea Park, and can be used, depending on location, for CO2 sequestration. Two deep, long-range flow systems are driven in the Alberta basin by basin-scale topography, one north-northwestward from recharge south of Alberta’s border to discharge at the Peace River, and the other northeastward from recharge in northeast British Columbia, across northern Alberta, toward discharge at Great Slave Lake(30) (Figure 5). Past tectonic compression drives the northeastward flow across Alberta in deep Devonian aquifers(30). The flow in deep Paleozoic aquifers in the Williston basin is driven by topography from recharge at outcrop in Montana and South Dakota, to discharge in southwestern Manitoba east of the Manitoba escarpment(31) (Figure 5). The salinity of formation waters increases with depth, reaching up to 350 g/l in the vicinity of salt beds(31-33). The flow of formation waters in Cretaceous aquifers in southwestern Alberta, such as Viking and Cardium, is driven southwestward, downdip, inward, by erosional rebound of the thick intervening shales(29, 32) (Figure 5). The thick intervening shales of the Colorado Group combine with the downdip flow of formation waters to form a powerful hydrodynamic trap for the injected CO2

(32). The flow velocity in these systems is of the order of 10 km/My. Pressures in the basin reach up to 60 MPa in the southwest near the thrust and fold belt. The extensive Middle Devonian salt beds in the basin, used currently for salt mining and LPG storage (Figure 6), can also be used for CO2 sequestration(20). The thick Lower and Upper Lotsberg salts, found in east-central Alberta at depths that range from >2100 m in the west to <500 m in the east, have a purity >90%. The thinner Cold Lake Formation in central-eastern Alberta is found at depths that range from 1600 m in the southwest to <600 m in the northeast south of Fort McMurray. Unlike the Lotsberg and Cold Lake salts, the salt content and purity in the Prairie Formation is highly variable, decreasing westward from as high as >90% along the dissolution edge in northeastern Alberta and central-northern Saskatchewan, to <20% along the western depositional edge. The depth to the top of the Prairie Formation in the area where the salt content is between 40% and 90% (Figure 6) ranges from 2200 m in southwestern Alberta to >200 m in northeastern Alberta. The thickness of the formation varies between <25 m in the south-southwest to >275 m in the north near the salt dissolution edge, where it decreases rapidly to zero along the salt escarpment. The vertical stress induced in these salt beds by the overburden varies, depending on depth, between >50 MPa in the south-southwest, to ~10 MPa in the northeast. Salt caverns are currently used in Alberta and Saskatchewan for LPG and gas storage(34) and for salt production (Figure 6). The density of the liquid and supercritical CO2 at in-situ reservoir or aquifer conditions was calculated based on its dependence on pressure and temperature (Figure 3) for each one of the major 27 stratigraphic units in the Western Canada Sedimentary Basin(23). As a result, the geological space of the basin, defined by strata geometry, temperature and pressure, was transformed into a CO2 space defined by location (geographic coordinates and depth), CO2 state and density(24). Injection of CO2 at depths close to temperature and pressure conditions corresponding to the CO2 phase change will induce the transition to the gaseous phase if it reaches slightly shallower depths. If this occurs, in the absence of

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stratigraphic or structural traps, gas bouyancy will lead to the rapid CO2 raise or flow through the sedimentary column and escape to the surface. In the Alberta basin (Alberta and British Columbia) the position of the 31.1oC isotherm and of the 7.38 MPa isobar shifts westward as a result of basin dip from the northeast to the southwest, until both disappear from the basin in the post-Colorado strata. As expected, the 31.1oC isotherm and the 7.38 MPa isobar generally run approximately parallel to the deformation front in all the units, with local deviations from this trend caused by basement heat flow anomalies and by underpressuring. In any particular unit, west of both the isotherm and isobar, T >31.1oC and p >7.38 MPa, and the injected CO2 will be in supercritical state. In regions between the two where the 31.1oC isotherm is located west of the 7.38 MPa isobar, the injected CO2 will be in a liquid state (T <31.1oC and p >7.38 MPa). In regions east of the isobar (p <7.38 MPa), the injected CO2 will be a gas or a liquid, depending on temperature and pressure, but mostly a gas. In the Williston basin (Saskatchewan and Manitoba), the position of the 31.1oC isotherm and of the 7.38 MPa isobar shifts concentrically southtward until they disappear from the basin in post-Colorado strata. The state of the injected CO2 is similarly dictated by the positions of the 31.1oC isotherm and the 7.38 MPa isobar. Basin Suitability for CO2 Sequestration The basin has reached a mature stage of exploration and production, and generally meets all the conditions for CO2 sequestration in geological media(11, 22). However, it exhibits geographic and stratigraphic differential suitability for CO2 sequestration as a result of the interplay between various basin characteristics. Based on the geological, geothermal and hydrodynamic characteristics of the basin and on the distribution of hydrocarbon reservoirs and of coal and salt beds, the Western Canada Sedimentary Basin can be divided into six different regions (Figure 7) in terms of suitability for and characteristics of CO2 sequestration. Eastern Shallow Edge This region is defined as a broad band along the eastern edge of the basin at the Canadian Shield (Figure 7), and comprises the eastern part of the basin’s portion in the Northwest Territories, northeastern Alberta, central Saskatchewan and most of the basin in Manitoba. This region is not suitable for CO2 sequestration in geological media for the following reasons. 1. Because of the shallow depth, in-situ temperatures are less than or close to 31.1oC and

pressures are <7.38 MPa. Thus, CO2 will always be in gaseous phase in this region. 2. The flow of meteoric water is in shallow, local groundwater flow systems, and that of

connate water is in intermediate and local flow systems, which all discharge along river valleys and along the Precambrian Shield. Thus, CO2 cannot be injected and sequestered in aquifers because of the high potential of the gaseous CO2 overriding at the top of the aquifer and escaping into the atmosphere.

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3. There are no coals in the area except for the very shallow and discontinuous Mannville coals at Firebag near Ft. McMurray that have been mined until recently.

4. There are no hydrocarbon reservoirs, except for the Athabasca area, where bitumen and shallow gas of biogenic origin are found in Mannville strata, and where a few oil reservoirs are found in Devonian Woodbend reefs. Depleted gas reservoirs in the Athabasca area may serve for CO2 sequestration and reservoir repressuring, although the potential in terms of volumes may be small.

Only the Cold Lake and Prairie formation salts in northeastern Alberta, where salt was mined in the past at Ft. McMurray, could serve for cavern sequestration of CO2. The oil sands plants in northeastern Alberta, with current emissions >16 MtCO2/yr, have very limited options for CO2 sequestration, such as: �� injection of CO2 in the carbonate Winnipegosis aquifer, which is overlain by regional

shaly aquitards and the Prairie aquiclude west of the salt dissolution edge; �� storage of CO2 as a liquid at high pressure in mined salt caverns; and �� storage of gaseous CO2 in depleted shallow oil and gas reservoirs in the Woodbend,

Winterburn and Mannville groups. Northern and Southeastern Inner Regions The northern inner region is defined as a broad northwest-southeast trending band immediately west of the Eastern Shallow Edge in northern Alberta (Figure 7), from the Tathlina High to the western part of the Athabasca area. The southeastern inner region is defined as a northwest-southeast trending band from central Saskatchewan to the US-Manitoba border. These regions are characterized by a limited suitability for CO2 sequestration in geological media for the following reasons. 1. The basin is relatively shallow. As a result, temperatures in all Cretaceous strata and

most of the Devonian are <31.1oC, while pressures are generally <7.38 MPa. Thus, CO2 injected in these strata will be mostly in gaseous state.

2. Because of pre-Cretaceous erosion, all deep Devonian aquifers, except for the Winnipegosis, subcrop at the unconformity below the Mannville Group. Thus, CO2 injected in these aquifers will override at the top of the aquifer, and will flow updip and upwards into the Mannville Group, where it will probably be trapped by the regional-scale Colorado aquitard.

3. Major oil reservoirs are in the Devonian in Alberta (e.g., Red Earth) and in the Carboniferous in southwestern Manitoba.

4. Prairie and Cold Lake salt beds are present. Carbon dioxide could be sequestered in oil and gas reservoirs in northern Alberta and southwestern Manitoba, in the deep Winnipegosis aquifer below the confining Prairie salt aquiclude, and in salt caverns.

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Central Inner Region This region covers east-central Alberta and west-central Saskatchewan, and encompasses basically the oil sands and heavy oil belt around the Lloydminster area (Figure 7). This region is reasonably suitable for CO2 sequestration in geological media. The main characteristics are similar to those of the Northern and Southeastern Inner regions (basin shallowness, aquifer characteristics and salt beds). In addition: 1. Oil, heavy oil and gas reservoirs, such as Provost, are abundantly found in the area,

particularly in the Mannville and Viking strata. 2. Mannville coals are present in central-eastern Alberta. Although they are relatively

shallow, they may not have great potential for CO2 injection and CBM production because of low gas content(28) and low permeability, having been buried to more than 2 km depth at the peak of the Laramide orogeny. Upper Cretaceous Belly River coals in central-eastern Alberta are too shallow, close to the surface, and are mined for power generation, so they cannot be considered for CO2 injection.

3. All Devonian salt beds, including the Lotsberg, are present in the area. The best targets for CO2 sequestration are in EOR operations and in depleted oil and gas reservoirs. Aquifer sequestration would be recommended only for the deep Basal Cambrian Sandstone and Winnipegosis aquifers, which are overlain by thick, regional-scale shaly aquitards and halite aquicludes. Injection in Upper Devonian and Cretaceous aquifers is not recommended as long as there are better options available, although it remains a possibility for the future. Storage in salt caverns is also possible. Carbon dioxide storage in coal beds has probably very limited potential. Northwestern Region This region is located north of 55oN (Figure 7) in northwestern Alberta, northeastern British Columbia and the western part of the basin’s portion in the Northwest Territories, covering basically the northwestern part of the Alberta basin. The region is suitable for CO2 sequestration in geological media as a result of the following characteristics. 1. The basin is deep enough, and geothermal gradients are high, such that the 31.1oC

isotherm and the 7.38 MPa isobar are reached at medium depths. All the deep Paleozoic aquifers are confined by shaly aquitards and overlain by the thick Colorado shales. The flow of formation waters in these aquifers is part of a long-range basin-scale system(30).

2. Major oil and gas fields are found in Devonian carbonate reefs, such as Rainbow and Zama in the Elk Point Group, and in Carboniferous, Permian and Triassic platform carbonates.

3. The northern Cold Lake salt is present in the northwest, and the Prairie salt is present in the east.

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In terms of CO2 sequestration, the best targets are in depleted oil and gas reservoirs, and in EOR operations in Devonian to Triassic reservoirs. Aquifer sequestration is possible in Devonian-to-Carboniferous carbonate aquifers. Southern Region This region covers the southern area of the Canadian part of the Williston basin (Figure 7). It is defined from the US border to approximately 51.5oN, and from 112oW in the southeastern corner of Alberta, across southern Saskatchewan, to the US-Manitoba border. This region is suitable for CO2 sequestration in geological media. The main characteristics are as follows. 1. Geothermal gradients in the area are low, such that the 31.1 oC isotherm is reached at

greater depths than in other parts of the basin. 2. The Cambrian and Devonian aquifers are confined by regional-scale, thick aquitards.

Upper Devonian aquifers, such as Winterburn and Wabamun, subcrop at the pre-Cretaceous unconformity north of this region. Carboniferous, Mannville and Viking aquifers are confined by thick Colorado shaly aquitards.

3. Oil reservoirs are found mainly in Carboniferous strata in southeastern Saskatchewan, (e.g., Weyburn and Midale), and in Jurassic and Mannville strata in southwestern Saskatchewan and southeastern Alberta, while gas reservoirs are found mainly in Alberta in the Mannville Group and Viking and Milk River formations.

4. Coal is found in Mannville strata, although not well delineated, and in very shallow Belly River strata in southern Saskatchewan, where it is mined for power generation.

5. High salt content (> 40%) is found in the Prairie Formation. The best targets for CO2 sequestration are EOR operations and in depleted oil and gas reservoirs. Aquifer sequestration is possible in the deep Basal Cambrian Sandstone, Winnipegosis, Beaverhill Lake and Winterburn aquifers. Injection in the Carboniferous, Mannville and Viking aquifers is also possible, but this option should be used after the other options are exhausted. Storage in coal beds and salt caverns does not seem to be a viable option. Southwestern Region This region covers the southwestern part of the Alberta basin from the US border in the south to 55oN in the north, and from the Thrust and Fold Belt in the west to 111-114oW in the east (Figure 7). This region is extremely suitable for CO2 sequestration in geological media for the following reasons. 1. It comprises the basin foredeep, where the greatest depths, more than 5 km, are

attained. Thus, a large thickness of the sedimentary succession is available below the 31.1oC isotherm and the 7.38 MPa isobar.

2. All the aquifers from the basement to the Upper Cretaceous Lea Park Formation shales are confined by regional-scale competent aquitards. The flow of formation waters is driven in long-range regional-scale systems in Cambrian to Lower

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Cretaceous Mannville aquifers. In the western part, the flow in the Viking and Cardium aquifers is driven by erosional rebound in the intervening shales, forming a hydrodynamic trap.

3. There are many oil and gas reservoirs in various stages of depletion. The great majority is at depths for which CO2 would be in supercritical state.

4. Extensive Lower and Upper Cretaceous coals beds are found in Mannville, Belly River, Edmonton and Scollard strata at depths that make them unmineable, with promising potential for CO2 sequestration and CBM production.

5. Salt beds are present in the northeastern part of the region, with salt being mined from the Upper Lotsberg at Fort Saskatchewan.

Most large industrial and energy producers in the Western Canada Sedimentary Basin are located in this region (Figure 2). Fortunately, all means of CO2 sequestration in geological media are available and all are good options with large capacity. Sequestration of CO2 in EOR operations and in depleted oil and gas reservoirs is possible for reservoirs found in the entire sedimentary succession. Sequestration in coal beds and CBM production are possible in Upper Cretaceous-Tertiary coals (Mannville coals are probably too deep and with very low permeability to constitute a sequestration target). Carbon dioxide sequestration is possible in supercritical state in deep Paleozoic aquifers, and in supercritical state, as a liquid or as a gas, depending on depth and location, in the Mannville, Viking and Cardium aquifers. Sequestration in salt caverns is also possible. There are a few CO2 producers that are located in the Rocky Mountain Foothills, west of the deformation front: the cement plants at Exshaw and Waterton, the Jumping Pond and Wildcat Hills gas plants, the pulp mill in Hinton and the power plant in Grand Cache (Figure 2). The geology and hydrodynamic conditions at these sites may or may not be suitable for CO2 sequestration in geological media. Chances are that most probably they are not, because faults and fractures constitute potential flow paths for the injected CO2. Nevertheless, in the case of these CO2 producers, site-specific studies need to be carried out. If no potential for CO2 sequestration is identified at these sites, then the produced CO2 will have to be captured and transported eastward to a suitable injection site in the undeformed part of the basin. Conclusions The Intergovernmental Panel on Climate Change reached the conclusion that “the balance of evidence suggests a discernible human impact on the global climate” caused by anthropogenic greenhouse emissions into the atmosphere, of which CO2 is the most important. Carbon dioxide emissions in the Western Canada Sedimentary Basin increased since 1990 as a result of population growth, economic development and increased activity in the energy sector. Large CO2 producers are the coal-based power generation industry, fossil fuel producers such as oil sands plants, industrial fuel users, the petro-chemical industry, the upstream oil and gas industry, pulp and newsprint mills, and cement and lime plants. These producers constitute major point sources where CO2 can be captured and separated from other combustion gases. Geographically, the major CO2 sources in the basin are found along the foothills (cement and gas plants), near Fort

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McMurray (oil sands plants), in the Lloydminster-Cold Lake area (heavy oil and power plants), in the Edmonton area (refineries, industrial, and petro-chemical, cement and power plants), in southern Saskatchewan (power plants), and in major population centres. A decrease of CO2 emissions can be achieved by a variety of means, first and foremost by improving energy efficiency and conservation. Switching to renewable forms of energy, particularly for power generation, is not an option with a significant impact and future in the Prairie Provinces, while nuclear power generation has no public acceptance. Retrofitting existing plants to use gas instead of coal is very expensive. Thus, CO2 capture and sequestration is probably the best short-to-medium term solution for the reduction of CO2 emissions into the atmosphere. Since ocean sequestration is not an option for the Prairie Provinces, and biomass fixation is uncertain at best, geological disposal of CO2 seems to be the best available option for long-term CO2 sequestration. Carbon dioxide can be sequestered in geological media by utilization in enhanced oil recovery (EOR) operations, displacement of methane in coal beds (ECBMR), storage in depleted oil and gas reservoirs, injection into deep saline aquifers, and storage in salt caverns. Generally, the Western Canada Sedimentary Basin meets the CO2-sequestration criteria related to tectonic setting and geology, geothermal and hydrodynamic regimes, and hydrocarbon potential and maturity. However, the suitability for CO2 sequestration varies in the basin depending on the specific conditions of a particular region. Based on the geological, geothermal and hydrodynamic characteristics of the Western Canada Sedimentary Basin, and on the distribution of hydrocarbon reservoirs and of coal and salt beds, the basin can be divided into seven different regions, each being characterized by specific possibilities in terms of CO2 sequestration in geological media. 1. The Eastern Shallow Edge, running along the Canadian Shield, is not suitable for

CO2 sequestration in geological media because of shallow depth. Very limited possibilities exist for CO2 sequestration in gaseous phase in northeastern Alberta in the Winnipegosis aquifer, in shallow depleted gas reservoirs, and in salt caverns.

2. The Northern and Southern Inner Regions, in northern Alberta and in eastern Saskatchewan-southwestern Manitoba, respectively, have limited suitability because the basin is still relatively shallow with limited hydrocarbon reservoirs and no coal beds. Sequestration options are mainly in Devonian and Carboniferous oil reservoirs.

3. The Central Inner Region, around Lloydminster, is reasonably suitable for CO2 sequestration, mostly as a gas, in EOR operations, in depleted oil and gas reservoirs, in coal beds, and in salt caverns.

4. The Northwestern Region is suitable for CO2 sequestration, mostly in supercritical state, in depleted oil and gas reservoirs and in deep aquifers.

5. The Southern Region, in southeastern Alberta-southern Saskatchewan, is suitable for CO2 sequestration, mostly as a gas, but also as a liquid and in supercritical state, in EOR operations, in depleted oil and gas reservoirs, in coal beds, and in deep aquifers.

6. The Southwestern Region, along the thrust and fold belt in Alberta and including the Edmonton area, is extremely suitable for CO2 sequestration in gaseous, liquid or

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supercritical state in EOR operations, depleted oil and gas reservoirs, coal beds, deep aquifers and salt caverns.

In terms of the major CO2 producers in the Prairie Provinces, it seems that all but the oil sands plants in northeastern Alberta, the pulp mill in Prince Albert and the CO2 producers in Manitoba, have at their disposal a number of options for CO2 sequestration in geological media. The analysis presented herein is based on the basin-scale characteristics of the Western Canada Sedimentary Basin and represents only the first, suitability assessment step(24) on the road toward site selection and operational implementation of CO2 sequestration in geological media in western Canada. The next broad steps in the geoscience-based selection of sequestration sites are: inventory, safety assessment, and capacity determination(24). At the end of this process, industry will be in the position to select specific sequestration sites in the basin, and proceed with engineering design, construction, operation and monitoring of sequestration safety.

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University Press, New York, 331p., 1998. 3. IPCC (Intergovernmental Panel on Climate Change), Climate Change: the IPCC

Response Strategies; Island Press, Washington, D.C., 272 p., 1991. 4. BAJURA, R.A., The role of carbon dioxide sequestration in the long term energy

future; In: Proceedings of the 5th International Conference on Greenhouse Gas Control Technologies (GHGT-5) (eds. D.J. Williams, R.A. Durie, P. McMullan, C.A.J. Paulson and A. Y. Smith), CSIRO Publishing, Collingwood, VIC, AU, p. 52-58, 2001.

5. TURKENBURG, W.C., Sustainable development, climate change, and carbon dioxide removal (CDR); Energy Conversion and Management, Vol. 38S, pp.S3-S12, 1997.

6. HERZOG, H.J., DRAKE, E.M., and ADAMS, E.E., CO2 capture, reuse, and storage technologies for mitigating global climate change; Final Report, DOE No. DE-AF22-96PC01257; Massachussets Institute of Technology, Cambridge, MA, 66p., 1997.

7. BACHU, S., Geological sequestration of anthropogenic carbon dioxide: applicability and current issues; Geological Perspectives of Global Climate Change (eds. L. Gerhard, W.E. Harrison, and B.M.Hanson). AAPG Studies in Geology 47, American Association of Petroleum Geologists, p. 285-304, 2001.

8. HITCHON, B., GUNTER, W.D., GENTZIS, T., and BAILEY, R.T., Sedimentary basins and greenhouse gases: a serendipitous association; Energy Conversion and Management, Vol. 40, pp. 825-843, 1999.

9. BACHU, S., GUNTER, W.D., and PERKINS, E.H., Aquifer disposal of CO2: hydrodynamic and mineral trapping; Energy Conversion and Management, Vol. 35, pp. 269-279, 1994.

10. LINDEBERG, E., and HOLLOWAY, S., The next steps in geo-storage of carbon dioxide; Greenhouse Gas Control Technologies – 5 (eds. B. Eliasson, P.W.F. Riemer and A. Wokaun), Pergamon, Elsevier Science Ltd., Amsterdam, pp. 145-150,, 1999.

11. BACHU, S., Sequestration of CO2 in geological media: criteria and approach for site selection in response to climate change; Energy Conversion and Management, Vol. 41, pp. 953-970, 2000.

12. BLUNT, M., FAYERS, F.J., and ORR, F.M., Carbon dioxide in enhanced oil recovery; Energy Conversion and Management, Vol. 34, pp. 1197-1204, 1993.

13. IEA GHGGP (International Energy Agency Greenhouse Gas R&D Programme), Carbon Dioxide Utilization, 28 p., 1995.

14. GUNTER, W.D., GENTZIS, T., ROTTENFUSSER, B.A., and RICHARDSON, R.J.H., Deep coalbed methane in Alberta, Canada: A fuel resource with the potential of zero greenhouse emissions; Energy Conversion and Management, Vol. 38S, pp. S217-S222, 1997.

15. STEVENS, S.H, KUSKRAA, V.A., SPECTOR, D., and RIEMER, P., CO2 sequestration in deep coal seams: pilot results and worldwide potential; Greenhouse

14

Gas Control Technologies, (eds. B. Eliasson, P.W.F. Riemer and A. Wokaun), Pergamon, Elsevier Science Ltd., Amsterdam, pp. 175-180, 1999.

16. MEER, van der, L.G.H., The conditions limiting CO2 storage in aquifers; Energy Conversion and Management, Vol. 34, pp. 959-966, 1993.

17. LAW, D. H-S., and BACHU, S., Hydrogeological and numerical analysis of CO2 disposal in deep aquifers in the Alberta sedimentary basin; Energy Conversion and Management, Vol. 37, pp. 1167-1174, 1996.

18. GUPTA, N., SASS, B., SMINCHAK, J., NAYMIK, T., and BERGMAN, P., 1999, Hydrodynamics of CO2 disposal in a deep saline formation in the midwestern United States; Greenhouse Gas Control Technologies (GHGT-4) (eds. B. Eliasson, P.W.F. Riemer and A. Wokaun), Pergamon, Elsevier Science Ltd., Amsterdam, pp. 157-162,, 1999.

19. WICHERT, E., and ROYAN, T., Acid gas injection eliminates sulfur recovery expense; Oil and Gas Journal, Vol. 95(17), pp. 67-72, 1997.

20. DUSSEAULT, M., BACHU, S., and DAVIDSON, B., Carbon dioxide sequestration in Alberta salt solution caverns; Solution Mining Research Institute, Fall 2001 Technical Meeting, Albuquerque, NM, Oct. 8-10, 2001.

21. BRADLEY, R.A., WATTS, E.C., and WILLIAMS, E.R., Limiting Net Greenhouse Gas Emissions in the U.S. Vol. 1, Report to the US Congress, US DOE, 1991.

22. BACHU, S., and GUNTER, W.D., Storage capacity of CO2 in geological media in sedimentary basins, with application to the Alberta basin; Greenhouse Gas Control Technologies (GHGT-4) (eds. B. Eliasson, B., P.W.F. Riemer and A. Wokaun), Pergamon, Elsevier Science Ltd., Amsterdam, p 195-200,, 1999.

23. MOSSOP, G.D., and SHETSEN, I., Geological Atlas of the Western Canada Sedimentary Basin, Canadian Society of Petroleum Geologists and Alberta Research Council, Calgary, 514 p., 1994.

24. BACHU, S., Sequestration of CO2 in geological media in response to climate change: Roadmap for site selection using the transform of the geological space into the CO2-phase space; Energy Conversion and Management, Vol. 42, pp. xx-yy, 2001.

25. BACHU, S., and BURWASH, R.A., Regional-scale analysis of the geothermal regime in the Western Canada sedimentary basin; Geothermics, Vol. 20, pp. 387-407, 1991.

26. BACHU, S., Basement heat flow in the Western Canada sedimentary basin; Tectonophysics, Vol. 222, pp.119-133, 1993.

27. SMITH, G.G., CAMERON, A.R., and BUSTIN, R.M., Coal resources of the Western Canada Sedimentary basin; Geological Atlas of the Western Canada Sedimentary Basin (comp. G.D. Mossop and I. Shetsen), Canadian Society of Petroleum Geologists and Alberta Research Council, Calgary, p. 471-481, 1994.

28. DAWSON, F.M., Coalbed Methane: A Comparison Between Canada and the United States; Geological Survey of Canada Bulletin 489, Ottawa, 60 p., 1995.

29. BUSTIN, R.M., Organic maturation of the Western Canadian Sedimentary Basin, International Journal of Coal Geology, Vol. 19, pp. 319-358, 1991.

30. BACHU, S., Flow systems in the Alberta Basin: patterns, types and driving mechanisms; Bulletin of Canadian Petroleum Geology, Vol. 47, pp. 455-474, 1999.

15

31. BACHU, S., and HITCHON, B., Regional-scale flow of formation waters in the Williston basin; American Association of Petroleum Geologists Bulletin, Vol. 80, pp. 248-264, 1996.

32. BACHU, S., Synthesis and model of formation water flow in the Alberta basin, Canada; American Association of Petroleum Geologists Bulletin, Vol. 79, pp. 1159-1178, 1995.

33. BACHU, S., Flow of formation waters, aquifer characteristics, and their relation to hydrocarbon accumulations in the northern part of the Alberta basin; American Association of Petroleum Geologists Bulletin, Vol. 81, pp. 712-733, 1997.

34. CROSSLEY, N.G., Conversion of LPG salt caverns to natural gas storage “ A Transgas experience”; Journal of Canadian Petroleum Technology, Vol. 37(12), pp. 37-47, 1998.

16

List of Figures Figure 1. Canada’s 1997 profile of CO2 emissions: a) by sector, and b) by province. Figure 2. Main characteristics of the Western Canada Sedimentary Basin and location of major CO2 producers. Figure 3. Relevant CO2 characteristics: a) phase diagram, b) density variation. Figure 4. Depth to the 31.1oC isotherm in the Western Canada Sedimentary Basin. Figure 5. Diagrammatic representation of major flow systems in the Western Canada Sedimentary Basin (after 30, 31). Figure 6. Distribution of Devonian salts in the Western Canada Sedimentary Basin and location of salt mines and LPG storage caverns. Figure 7. Suitability of the Western Canada Sedimentary Basin for CO2 sequestration in geological media.

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Figure 1. Canada’s 1997 profile of CO2 emissions: a) by sector, and b) by province.

55°

54°

53°

52°

51°

50°

49°N96°W

98°

100°

126°124°

122°120°

118° 116° 114°

49°

112° 110° 108° 106° 104°102°

62°

61°

60°

59°

58°

57°

56°

55°

54°

53°

52°

51°

50°

126°124°

122°120°

118° 116° 114° 112° 110° 108° 106° 104° 102°100°

98°96°W

62°N

56°

57°

58°

59°

60°

61°

CANADIAN PRECAMBRIAN SHIELD

LakeWinnipeg

LakeAthabasca

Great Slave Lake

Edge of the D

eformed B

asin

0

0

100 200 300

100 200

kilometres

miles

Basin

Boundary

U.S.A.

Mackenzie River

ALBERTA

NORTHWEST

NUNAVUT

BRITISHCOLUMBIA

MANITOBA

TERRITORIES

YUKON

SASKATCHEWAN

Vancouver

Rainbow

GrandeCache Wabamun

GeneseeEdmonton

Battle River

Sheerness

Landis Saskatoon

CoronachEstevan

Fort Nelson

Fort McMurrayMcMahon

Peace River

ChetwyndGrande Prairie

Slave Lake

Kaybob

Hinton

Christina Lake

Foster Creek

Cold LakeWindfall

Whitecourt

Ram River

Caroline

CochraneWildcat Hills

Joffre

Calgary

RedwaterFort SaskatchewanScotford

Boyle

Meadow Lake

Prince AlbertLloydminster

Exshaw

Coleman

Waterton

Empress

Princess Burstall

Medicine Hat

ReginaBelle Plaine Brandon

Sundance

Shand

Selkirk

Pine River

Hanlan

Jumping Pound

Harmattan

Crossfield

Homeglen

Edson

Ile de Chenes

Red DeerLanigan

Minnedosa

Morin-ville

Irma

KerrobertLoreburn

EstlinAlameda

Poplar Hill

Sturgeon

Strathmore

Prentice

Carseland

Cory

Rocanville

Muskeg River

Mackay River

Primose

Winnipeg

Refining and Petrochemicals

Cement or Lime

Fossil Energy Producers(oil sands, gas, compressors)

Newsprint and Pulp Mills

Power Generation

Carbon Dioxide Sources

Keephills

Vulcan

Burnt Timber

ROCK

Y M

OU

NTA

INS

Figure 2. Main characteristics of the Western Canada Sedimentary Basin and location of major CO2 producers.

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Figure 3. Relevant CO2 characteristics: a) phase diagram, b) density variation.

750

750

1000

1000

1000

1000

1000

1000

1000

1250

500

750

1000

10001250

17501500

Tathlina High

Bow

Islan

d

Arc

h

55°

54°

53°

52°

51°

50°

49°N96°W

98°

100°

126°124°

122°120°

118°116° 114°

49°

112° 110° 108° 106° 104°102°

62°

61°

60°

59°

58°

57°

56°

55°

54°

53°

52°

51°

50°

126°124°

122°120°

118° 116° 114° 112° 110° 108° 106° 104° 102°100°

98°96°W

62°N

56°

57°

58°

59°

60°

61°

CANADIAN PRECAMBRIAN SHIELD

LakeWinnipeg

LakeAthabasca

Great Slave Lake

Edge of the Deform

ed Basin

Basin

Boundary

U.S.A.

Mackenzie River

0

0

100 200 300

100 200

kilometres

miles

ROCK

Y M

OU

NTA

INS

Isotherm below thePrecambrian basement

Figure 4. Depth to the 31.1o C isotherm in the Western Canada Sedimentary Basin.

Basin-scale flow

Deep flow systems in Paleozoic strata

Inward flow in Cretaceous strata

55°

54°

53°

52°

51°

50°

49°N96°W

98°

100°

126°124°

122°120°

118° 116° 114°

49°

112° 110° 108° 106° 104°102°

62°

61°

60°

59°

58°

57°

56°

55°

54°

53°

52°

51°

50°

126°124°

122°120°

118° 116° 114° 112° 110° 108° 106° 104° 102°100°

98°96°W

62°N

56°

57°

58°

59°

60°

61°

LakeWinnipeg

LakeAthabasca

Great Slave Lake

Edge of the Deform

ed Basin

Basin

Boundary

U.S.A.

Mackenzie River

0

0

100 200 300

100 200

kilometres

miles

Edmonton

Calgary

Regina

Saskatoon

WinnipegVancouver

Tathlina High

Bow

Islan

d

Arc

h

ALBERTA BASIN

WILLISTON BASIN

CANADIAN PRECAMBRIAN SHIELD

ROCK

Y M

OU

NTA

INS

Figure 5. Diagrammatic representation of major flow systems in the Western Canada Sedimentary Basin (after 30, 31).

Tathlina High

Bow

Islan

d

Arc

h

55°

54°

53°

52°

51°

50°

49°N96°W

98°

100°

126°124°

122°120°

118°116° 114°

49°

112° 110° 108° 106° 104°102°

62°

61°

60°

59°

58°

57°

56°

55°

54°

53°

52°

51°

50°

126°124°

122°120°

118° 116° 114° 112° 110° 108° 106° 104° 102°100°

98°96°W

62°N

56°

57°

58°

59°

60°

61°

CANADIAN PRECAMBRIAN SHIELD

LakeWinnipeg

LakeAthabasca

Great Slave Lake

Edge of the Deform

ed Basin

Basin

Boundary

U.S.A.

Mackenzie River

Ft. McMurray

Redwater

Ft. Saskatchewan Bruderheim

Duvernay Lindberg

Hardisty

HughendenUnity Saskatoon

Esterhazy0

0

100 200 300

100 200

kilometres

miles

Lower Lotsberg

Upper Lotsberg

Cold Lake

Prairie Salts >40%

Salt Mining

LPG Storage

ROCK

Y MO

UN

TAIN

S

Figure 6. Distribution of Devonian salts in the Western Canada Sedimentary Basin and location of salt mines and LPG storage caverns.

55°

54°

53°

52°

51°

50°

49°N96°W

98°

100°

126°124°

122°120°

118° 116° 114°

49°

112° 110° 108° 106° 104°102°

62°

61°

60°

59°

58°

57°

56°

55°

54°

53°

52°

51°

50°

126°124°

122°120°

118° 116° 114° 112° 110° 108° 106° 104° 102°100°

98°96°W

62°N

56°

57°

58°

59°

60°

61°

SASKATCHEWAN

ALBERTA

BRITISHCOLUMBIA

NORTHWEST

NUNAVUT

MANITOBA

TERRITORIESYUKON

NORTHWESTERN REGION

NO

RT

HE

RN

INN

ER

RE

GIO

N

EASTERNSHALLOW EDGE

SOUTHWESTERN REGION

SOUTHERN REGION

SOUTHEASTERN INNER REGION

CANADIAN PRECAMBRIAN SHIELD

LakeWinnipeg

LakeAthabasca

Great Slave Lake

Edge of the Deform

ed Basin

Basin

Boundary

U.S.A.

Mackenzie River

Vancouver

Tathlina High

0

0

100 200 300

100 200

kilometres

miles

CENTRAL INNER REGION

Edmonton

Calgary

Regina

Saskatoon

Winnipeg

ROCK

Y MO

UN

TAIN

S

Figure 7. Suitability of the Western Canada Sedimentary Basin for CO2 sequestration in geological media