Geological, ocean, and mineral C[O.sub.2] sequestration options: a technical review.

SUMMARY

Of the six greenhouse gases (GHG) covered by the Kyoto protocol, carbon dioxide (C[O.sub.2]) is the greatest contributor to Canada's total GHG emissions. Fossil fuel combustion is the main source of anthropogenic C[O.sub.2], and it currently supplies over 85% of the global energy demand. Worldwide, an effort for reduction of C[O.sub.2] emissions alms at increased efficiency of fossil energy usage, development of energy sources with lower carbon content and increased reliability on alternative energy sources such as wind, solar, geothermal and nuclear. However, to meet the objectives of the Kyoto agreement, C[O.sub.2] sequestration methods may be needed. In this review, the methods that we will cover are storage in oil and gas reservoirs, in deep coal seams, in deep saline aquifers, in deep ocean, in salt caverns, and mineral carbonation. Each of these methods has its weaknesses and strengths.

RESUME

Des six types de gaz a effet de serre (GES) dont il est question dans le traite de Kyoto, le gaz carbonique (C[O.sub.2]) est celui qui contribue le plus au emissions totales de GES au Canada. La combustion de carburants fossiles qui repond presentement a 85 % des besoins d'energie de notre monde, constitue la principal source de C[O.sub.2] anthropogenique. L'effort mondial de reduction des emissions de C[O.sub.2] vise a augmenter l'efficacite de l'utilisation des energies fossiles, a developper des sources d'energie contenant moins de carbone ct a augmenter l'apport d'autres sources d'energie comme le vent, le soleil, l'energie geothermique et l'energie nuclealre. Cependant, pour atteindre les objectifs du tralte de Kyoto, on devra peut-etre recourit a des methodes de sequestration du C[O.sub.2] Dans la presente etude retrospective, les methodes considerees sont les suivantes: le stockage dans des reservoirs de petrole et de gaz, dans des couches de charbon en profondeur, dans des aquiferes salins profonds, dans le fond des oceans, dans des cavernes de gisements de sel, ainsi que par carbonatation de mineraux. Chacune de ces methodes presentent des avantages et des inconvenients.

INTRODUCTION

Canada's Kyoto commitments are to reduce its annual greenhouse gas (GHG) emissions levels by 6% relative to its 1990 levels (Environment Canada, 2002). Although Canada contributes only about 3% of total global GHG emissions (Table 1), it is one of the highest per capita emitters (23.6 tonne C[O.sub.2] equivalent per year), largely because of its resource-based economy, cool climate (i.e., the need for heating) and travel distances (Environment Canada 2002). Of the six GHGs covered by the Kyoto protocol, C[O.sub.2] is the greatest contributor to Canada's total GHG emissions (Table 2). Fossil fuel combustion is the main source of anthropogenic C[O.sub.2], and it currently supplies over 85% of the world's energy demand (Fig. 1). The main engineering effort for reduction of C[O.sub.2] emissions is aimed at increased efficiency of fossil energy usage, development of energy sources with lower carbon content, and increased reliance on alternative energy sources such as wind, solar, geothermal and nuclear, it is not likely that the reduction of C[O.sub.2] emissions required to meet targets set by the Kyoto agreement could be met using these measures alone. Thus a need for geological, mineral or deep ocean sequestration of carbon dioxide (C[O.sub.2]) may arise. For the purpose of this paper, the term "C[O.sub.2] sequestration" refers to the capture, separation, transportation and storage of C[O.sub.2]. The storage is expected to be permanent (on the order of thousands to millions of years). Methods of sequestration that are currently being considered by industrialized countries include enhancement of terrestrial carbon sinks (not covered in this study) as well as geological, ocean and mineral sequestration. Each method has its weaknesses and strengths. The methods that we will cover in this review are:

1. Storage in oil and gas reservoirs

2. Storage in deep coal seams

3. Storage in deep saline aquifers

4. Storage in deep ocean

5. Storage in salt caverns

6. Mineral carbonation

Geographic relationships between the main stationary point C[O.sub.2] sources and sinks are an essential piece of the puzzle for C[O.sub.2] sequestration planning, since transportation of the C[O.sub.2] is one of the most important cost factors. Voormeij and Simandl (2003) and Bachu (2001b) have identified the main stationary point sources of C[O.sub.2] emissions and the main potential carbon or C[O.sub.2] sinks for British Columbia and Alberta, respectively.

Physical Properties of Carbon Dioxide

It is important to know the main properties of carbon dioxide in order to understand the different sequestration methods. C[O.sub.2] is an odourless, colourless gas that occurs naturally in the atmosphere at current ambient concentrations of around 370 ppm (0.037%). The effects of high concentrations of C[O.sub.2] on humans and other life forms are beyond the scope of this paper and are summarized by Benson et al. (2002).

Depending on pressure and temperature, C[O.sub.2] can take on three separate phases (Fig. 2). C[O.sub.2] is in a supercritical phase at temperatures greater than 31.1[degrees]C and pressures greater than 7.38 MPa (critical point). Below these temperature and pressure conditions, C[O.sub.2] will be a gas, liquid or a solid. Depending on in situ temperature and pressure, C[O.sub.2] can be stored as a compressed gas or liquid, or in a supercritical (dense) phase.

[FIGURE 2 OMITTED]

C[O.sub.2] STORAGE IN OIL AND GAS RESERVOIRS

Both depleted and active fossil fuel reservoirs are potential storage spaces for C[O.sub.2] in underground formations. For the purpose of this paper, the term "depleted fossil fuel reservoirs" refers to abandoned oil or gas reservoirs. These reservoirs have undergone primary and secondary recovery and C[O.sub.2]-enhanced oil recovery is not currently envisaged to generate positive cash flow. Thus C[O.sub.2] may be injected directly into a depleted or inactive hydrocarbon reservoir without expectation of any further oil or gas production, resulting in the permanent storage of C[O.sub.2]. C[O.sub.2] may also be injected into producing oil and gas reservoirs, where C[O.sub.2]-enhanced oil recovery (EOR) and C[O.sub.2]-enhanced gas recovery (EGR) will offer an economic benefit. Alberta currently has about 26,000 gas pools and more than 8,500 oil pools in various stages of production and completion (Thambimuthu et al., 2003). C[O.sub.2] storage capacity in these reservoirs is estimated at 637 Megatonnes of C[O.sub.2] in depleted oil pools; 2.2 Gigatonnes of C[O.sub.2] in gas caps of approximately 5,000 oil reservoirs and 9.8 Gigatonnes of C[O.sub.2] storage capacity in gas reservoirs that are not associated with oil pools (Thambimuthu et at., 2003). Of the more than 8,500 oil pools in Alberta, 4,273 reservoirs were identified as suitable for C[O.sub.2]- EOR.

Typically, oil reservoirs have undergone a variety of production and injection processes during primary and secondary recovery (e.g. gas, water or steam injection), as described by Jimenez and Chalaturnyk (2003). As a tertiary recovery process, C[O.sub.2] can be injected into the reservoir to improve the mobility of the remaining oil, thereby extending the production life of the reservoir. Injection of C[O.sub.2] into producing gas resercoirs far EGR was previously believed to risk contaminating the natural gas reserve (Stevens et al., 2000). However, recent studies by Oldenburg et al. (2001) and Oldenburg and Benson (2002) suggest that mixing of the C[O.sub.2] and methane (C[H.sub.4]) in a gas reservoir would be limited because of the high density and viscosity of C[O.sub.2] relative to the natural gas. Furthermore, significant quantities of natural gas can be produced by repressurization of the reservoir. It is possible that improved gas recovery could more than offset the cost of C[O.sub.2] capture and injection (Davison et al., 2001).

Depleted Oil and Gas Reservoirs

Following more than a century of intensive petroleum exploitation, thousands of oil and gas fields are approaching the ends of their economically productive lives (Davison et al., 2001). Some of these exhausted fields are potential sites for C[O.sub.2] sequestration. The concept of C[O.sub.2] disposal in depleted oil and gas reservoirs is that the hydrogeological conditions that allowed the hydrocarbons to accumulate in the first place will also permit the accumulation and trapping of C[O.sub.2] in the space vacated by the produced hydrocarbons (Hitchon et al., 1999; Gentzis, 2000). The caprock that prevented the escape of oil and gas over geological time should retain the sequestered C[O.sub.2] for thousands of years (Bachu, 2001a), as long as it is not damaged as a result of overpressure during the C[O.sub.2] injection (van der Meet, 1993), or by the presence of unsealed, improperly completed or abandoned wells (Hitchon et al., 1999). Depleted hydrocarbon reservoirs that are filled with connate water (fully water-saturated reservoirs) offer limited storage capacity. Storage of C[O.sub.2] in water-saturated reservoirs would, in practice, amount to aquifer storage (Bachu, 2000; van der Meer, 2003).

Closed, underpressured, depleted gas reservoirs are excellent geological traps for C[O.sub.2] storage. Firstly, primary recovery of gas fields usually removes as much as 95% of the original gas in place (Bachu, 2001a), creating large storage potential. Secondly, the injected C[O.sub.2] can be used to restore the reservoir to its original pressure (Bachu et al., 2000), thereby preventing possible collapse or man-induced subsidence. Thirdly, the trapping mechanism that retained hydrocarbons in the first place should ensure that C[O.sub.2] does not reach the surface. And lastly, the existing surface and downhole infrastructure used for production of gas may be modified for transportation and injection of supercritical C[O.sub.2]. About 80% of the world's hydrocarbon fields are at depths greater than 800 m (IEA, website), thus meeting the pressure and temperature requirements needed to store C[O.sub.2] as a supercritical fluid (van der Meer, 1993). Spatial association between hydrocarbon production and the presence of reservoirs suitable for C[O.sub.2] sequestration may result in shared infrastructure and reduction of transportation costs. Furthermore, depleted hydrocarbon fields commonly have an established geological database and as such, reservoir characteristics are well known. Currently, the petroleum industry is reluctant to consider storage of C[O.sub.2] in depleted hydrocarbon reservoirs, because abandoned fields will still contain oil and gas resources (U.S. Dept of Energy, 2002), which potentially have economic value if oil prices were to rise enough or new EOR technologies were developed in the future (Davison et al., 2001; Bachu et al., 2000).

Acid gas injection operations in the Western Canada Sedimentary Basin are a useful small-scale analogue for storage of C[O.sub.2] into depleted oil or gas reservoirs. Acid gas is a product of oil and gas processing and consists of a combination of C[O.sub.2] and hydrogen sulphide ([H.sub.2]S). It is either injected into depleted hydrocarbon reservoirs or into saline aquifers for the purpose of reducing atmospheric [H.sub.2]S emissions. The technology used in acid gas injection in terms of transportation, injection and storage may be comparable to that of geological sequestration of C[O.sub.2] (Bachu and Gunter, 2003).

Active Oil Reservoirs

The petroleum industry has been injecting C[O.sub.2] into underground formations for several decades (Gentzis, 2000) to improve oil recovery from light and medium oil reservoirs, even before climate change became an issue (Bachu, 2000). C[O.sub.2] injected into suitable oil reservoirs can improve oil recovery by 10 to 15% of the original oil in place in the reservoir (Davison et at., 2001). When C[O.sub.2] is injected into a reservoir above its critical point (typically a reservoir depth greater than 800 m), the fluid acts as a powerful solvent. If the pressure is high enough and the oil gravity is greater than 25[degrees] API, the C[O.sub.2] and oil become completely miscible (Bachu, 2001a). According to Aycaguer et al. (2001), the miscible flood reduces the oil's viscosity, thereby enabling the oil to migrate more readily to the producing wells (Fig. 3). At lower pressures C[O.sub.2] and oil are not completely miscible, and only a fraction of the C[O.sub.2] will dissolve in the oil. This is known as immiscible displacement and it also enhances oil recovery. C[O.sub.2] enhanced oil recovery is now considered as a mature technology (Gentzis, 2000). Much of the C[O.sub.2] will remain stored in the reservoir, but a significant part ultimately breaks through at the producing well, together with the recovered oil. As a result, the residence time is relatively small, on the order of months to several years (Bachu, 2000). If EOR is the main objective of C[O.sub.2] injection, then the operation is optimized to minimize the cost of C[O.sub.2] used and maximize the oil recovery. An example of this is Pan West Petroleum's Joffre Viking EOR field in Alberta. However, C[O.sub.2] sequestration differs from C[O.sub.2]-EOR: its main objective is to sequester as much C[O.sub.2] in the reservoir as possible and to keep it underground thousands if not millions years (van der Meer, 2003; Benson, 2000).

[FIGURE 3 OMITTED]

A life cycle assessment study on EOR with injection of C[O.sub.2] in the Permian Basin of West Texas (Aycaguer et al., 2001) suggested that the amount of C[O.sub.2] injected, not including recycled C[O.sub.2], may balance the amount of C[O.sub.2] in emissions that ultimately are produced by combustion of the extracted hydrocarbon product. Most of the existing C[O.sub.2]-EOR projects in the world use naturally occurring sources. C[O.sub.2] from natural carbon dioxide reservoirs, where the infrastructure for distribution is already present, provide delivery without major capital costs (Aycaguer et al., 2001) and without processing (Smith, 1998). To help mitigate the release of C[O.sub.2] to the atmosphere, the source of C[O.sub.2] for EOR should come from anthropogenic (man-made) sources. A Canadian study done by Tontiwachwuthikul et al. (1998) on the economics of C[O.sub.2] production from coal-fired power plants concluded that flue gas extraction could be an economically viable C[O.sub.2] supply source for C[O.sub.2]-EOR projects in Western Canada, should oil prices increase substantially.

Canada is the forerunner in the technology of using anthropogenic C[O.sub.2] emissions in a large-scale EOR project at the Weyburn oil field in Saskatchewan. The ongoing project aims at implementing a guideline for geological storage of anthropogenic C[O.sub.2] by EOR (Moberg, 2001; Whittaker and Rostron, 2003). Although natural sources can supply C[O.sub.2] at a lower cost (Bachu, 2000), funding provided for research makes it feasible to use anthropogenic sources. C[O.sub.2] is captured from the Great Plains coal-gasification plant at Beulah, North Dakota, USA and transported through a 320 km pipeline to the Weyburn Pool The injected C[O.sub.2] is 95% pure and initial injection rates are 5000 tons/day (Moberg et al., 2003). The reservoir is located within the Williston Basin and has temperatures near 65[degrees]C and pressures around 14.5 Mpa, which indicate that the injected C[O.sub.2] will likely exist as a supercritical fluid (Whittaker and Rostron, 2003). The C[O.sub.2] from the produced oil will be captured and reinjected into the reservoir so that most of the anthropogenic C[O.sub.2] used for EOR will ultimately be sequestered (Whittaker and Rostron, 2003). An estimated 20 Megatonnes of C[O.sub.2] will be injected over the project life (Moberg et al., 2003). Potential future sources of C[O.sub.2] include the purified flue gas from Saskatchewan coal-fired thermal plants, such as those at Boundary Dam, Poplar River and Shank (Huang, 2001).

C[O.sub.2] STORAGE IN COAL SEAMS

Coal beds are a potential storage medium for C[O.sub.2]. Canada has abundant coal resources; some of them lie at depths too great to be considered for conventional mining. C[O.sub.2] can be injected into suitable coal seams where it will be adsorbed onto the coal and stored in the pore matrix of the coal seams for geological time. Since flue gas, a mixture of C[O.sub.2] and nitrogen ([N.sub.2]) accounts for 80% of C[O.sub.2] emissions in western Canada (Reeve, 2000), an alternative to C[O.sub.2]-only storage is injection of flue gas into coal beds, which may avoid the high cost of C[O.sub.2] separation (Law et al., 2003).

C[O.sub.2]-Enhanced Coalbed Methane Recovery

C[O.sub.2] sequestration in coal seams has the potential to generate cash flow through enhanced coalbed methane (CBM) recovery, a process similar to the practice of C[O.sub.2]-EOR. Recovery of CBM is a relatively well-established technology used in several coalfields around the world (Schraufnagel, 1993; Ivory et al., 2000). A number of companies are looking at producing CBM in Western Canada. Primary CBM recovers about 20 to 60% of the gas in place (Gentzis, 2000; van Bergen and Pagnier, 2001); some of the remaining CBM may be further recovered by C[O.sub.2] enhanced CBM recovery. A study done on the Alberta Sedimentary Basin estimated a potential capacity for C[O.sub.2] sequestration by enhanced CBM recovery at nearly 100,000 Mt (Fig. 4). To put this storage capacity into perspective, C[O.sub.2]-enhanced CBM recovery could potentially sequester Metropolitan Toronto's C[O.sub.2] emissions (City of Toronto, 1991) for more than 3000 years.

[FIGURE 4 OMITTED]

The disposal of C[O.sub.2] in methane-rich coal beds, where applicable, is expected to increase drive pressure and the CBM recovery rate (Hitchon et al., 1999). Thus, injection of C[O.sub.2] should enable more CBM to be extracted, while at the same time sequestering C[O.sub.2]. C[O.sub.2] has a higher affinity with coal, about twice that of methane (Fig. 5), just below the critical point (~7.38 Mpa). In theory, injected C[O.sub.2] molecules displace the adsorbed methane molecules (Wong et al., 2001; Ivory et al., 2000; Hitchon et al., 1999), which desorb from the coal matrix into the cleats (Fig. 6) and flow to the production wells. However, limited data at pressures exceeding the critical point of C[O.sub.2] indicate that the extrapolation of the C[O.sub.2] adsorption curve above 7.38 Mpa is not justified (Krooss et al. 2002) and that we do not really know what is happening above this pressure.

[FIGURE 5-6 OMITTED]

C[O.sub.2]-enhanced CBM production could be achieved by drilling wells into the coal deposits, typically a five-spot pattern, with the centre well as the injector and the four corner wells as the producing wells (Wong et al., 2001). After discharging formation waters from the coal, C[O.sub.2] is injected into the coal seam. C[O.sub.2]-enhanced CBM extraction may achieve up to 72% recovery (Wong et al., 2000). A C[O.sub.2]-enhanced CBM production project terminates at C[O.sub.2] breakthrough in one or more of the production wells (Wong et al., 2001).

Flue gas injection may enhance methane production to a greater degree than C[O.sub.2] alone (Ivory et al., 2000). However, [N.sub.2] has a lower affinity for coal than C[O.sub.2] or methane (Fig. 5). Therefore, injection of flue gas or C[O.sub.2]-enriched flue gas will probably result in rapid nitrogen breakthrough at the producing wells (Macdonald et al., 2003; Law et al., 2003). In such cases, [.sub.2] waste could be reinjected into the coal seam (Wong and Gunter, 1999).

Sequestration of C[O.sub.2] in coal seams, while enhancing CBM recovery, is an attractive option, but the most suitable physical characteristics of the coals for the purpose of C[O.sub.2]-enhanced coalbed methane recovery (ECBM) are largely unknown. Recent studies (Fokker and van der Meet, 2003; Reeves, 2003) have shown that continued injection of C[O.sub.2] in coal beds induces a decrease in the permeability of the cleat system surrounding the injection well area. In general, desorption of methane induces shrinkage of the coal matrix that results in widening of the cleats, thereby allowing the C[O.sub.2] injection rate to increase and methane to flow to the producing well. However, replacement of the methane by the injected C[O.sub.2] is believed to cause the coal matrix to swell. This swelling will partially close the cleat system and reduce permeability. The fracturing and swelling of the coal have opposite effects on the C[O.sub.2] injectivity (Fokker and van der Meet, 2003). One possible solution to achieve an acceptable C[O.sub.2] injection rate would be to allow the gas pressure in the cleat system to exceed the hydraulic fracturing pressure (Fokker and van der Meer, 2003; Shi et al., 2002), essentially fracturing the coal bed in the vicinity of the injection well to enhance permeability. However, if repeated hydraulic fracturing is necessary to maintain connectivity between the well bore and the permeable areas of the coal seam, this may result in over/under burden fracturing (Gale, 2003), and subsequent C[O.sub.2] leakage.

The Alberta Research Council (ARC) has done extensive applied research in the field of CBM and some of the outstanding contributions were published by Wong et al. (2000), Law et al. (2003), and Mavor et al. (2002). There are currently several C[O.sub.2]-ECBM recovery field projects studying sequestration of C[O.sub.2] and flue gas in deep coal seams. These projects range in depth from 760 to 1100 metres:

1. Alberta Research Council under an international project, facilitated by the IEA Greenhouse gas R&D Programme, has established a pilot site at Fenn-Big Valley, Alberta, Canada (Fig. 7). The project is looking at the enhancement of CBM production rates in low permeability CBM reservoirs using mixtures of C[O.sub.2] and [N.sub.2] while sequestering C[O.sub.2] into coal beds (Law et al., 2003; Reeve, 2000; Ivory et al., 2000).

[FIGURE 7 OMITTED]

2. In October 2000 a three-year government-industry project in the San Juan Basin (USA), known as the Coal-Seq project, was launched. The project studies the feasibility of C[O.sub.2]-sequestration in deep, unmineable coal seams using enhanced CBM recovery technology (Reeves, 2003).

3. In November 2001, the RECOPOL project (Reduction of C[O.sub.2] emission by means of C[O.sub.2] storage in coal seams in the Silesian Coal Basin of Poland), funded by the European Commission, started with aims to develop the first European field demonstration of C[O.sub.2] sequestration in subsurface coal seams (van Bergen et al., 2003).

The industrial and scientific community will carefully scrutinize the results from these deep field tests, particularly since they may provide empirical data on C[O.sub.2] adsorption behaviour above its critical point (7.38 MPa).

C[O.sub.2] STORAGE IN DEEP AQUIFERS

Worldwide, deep saline aquifers have larger geological storage capacity than hydrocarbon reservoirs and deep coal seams (Table 3). Deep aquifers are found in most of the sedimentary basins around the world (Bachu, 2001a) and typically contain high-salinity connate water not suitable for human consumption or agricultural use. Deep saline aquifers have been used for injection of hazardous and nonhazardous liquid waste (Bachu et al., 2000) and as such provide viable options for C[O.sub.2] sequestration. Approximately 2% of the total effective volume in a deep aquifer can be made available for C[O.sub.2] storage (van der Meer, 2003; 1993). Thus, from a capacity perspective, deep saline aquifers offer significant potential for C[O.sub.2] storage (Gale, 2003).

Suitable aquifers must be capped by a regional aquitard (e.g. shale), which should not contaln any fractures or uncompleted wells (Bachu et al., 1994). The top of the aquifer must be at a minimum depth of 800 metres (van der Meer, 2003), ensuring that the injected C[O.sub.2] will be stored in supercritical state. A suitable aquifer should have high permeability locally, for injection purposes, but regional-scale permeability should be low, to ensure long-term disposal of C[O.sub.2] (Bachu et al., 1994). When the C[O.sub.2] is injected into an aquifer it will rise up as a result of buoyancy effects and gradually spread out, forming a layer of C[O.sub.2] under the cap rock (Gale, 2003). In the early stages of geochemical reactions, dissolution of C[O.sub.2] into formation water is expected to be the predominant process (Gunter et al., 1997). The surface area of C[O.sub.2] in contact with the formation water will control the rate of dissolution. It is believed that during an injection period of 25 years, between 10 and 25% of the C[O.sub.2] will be dissolved (Gale, 2003). The undissolved portion of the injected C[O.sub.2] will segregate and form a plume at the top of the aquifer as a result of density differences (Bachu, 2001a). The C[O.sub.2] plume will be driven by both hydrodynamic flow and by its buoyancy (Bachu et al., 2000). The greater the density and viscosity differences between the C[O.sub.2] and the formation fluid, the faster the undissolved C[O.sub.2] will separate and flow upwards in the aquifer in a process similar to oil and gas migration (Bachu, 2001a). Thus, C[O.sub.2] should be injected under high pressures to ensure a high density of the C[O.sub.2] and a high C[O.sub.2] solubility rate in formation water.

Injection of C[O.sub.2] into deep, saline aquifers relies on existing technology. Since 1996, Statoil injects about 1 Megatonne of C[O.sub.2] per year into a deep aquifer offshore Norway (Chadwick et al., 2003). Sequestration of the C[O.sub.2] waste, a by-product of natural gas production, saves the company from paying a Norwegian C[O.sub.2] tax (Gentzis, 2000).

Hydrodynamic Trapping

Outside the radius of influence of the injection well, both dissolved and immiscible C[O.sub.2] will travel at the same velocity as the formation water (Gunter et al., 1997), termed hydrodynamic trapping. Regionally, the velocities of formation water in deep aquifers are expected to be around 1 to 10 cm/year (Bachu et al., 1994), suggesting a basinal residence time for C[O.sub.2] of tens to hundreds of thousands of years (Gunter et al., 1997).

Mineral Trapping

The injected C[O.sub.2] may be sequestered permanently by undergoing geochemical reactions with silicate minerals, resulting in carbonate production whereby C[O.sub.2] is fixed as a carbonate mineral (e.g. calcite, dolomite and siderite). This is known as mineral trapping (Bachu et al., 1994; Gunter et al., in press) and is based on a similar rock-weathering reaction as mineral carbonation, which will be discussed in the last section of this paper. The following chemical reaction is an example of mineral trapping of C[O.sub.2]:

(1) Ca[Al.sub.2][Si.sub.2][O.sub.8][Ca-feldspar] +C[O.sub.2]+2[H.sub.2]O=> [Al.sub.2][Si.sub.2][O.sub.5] [(OH).sub.4][kaolinite] + CaC[O.sub.3][calcite]

Experiments carried out to test the validity of mineral trapping of C[O.sub.2], by Gunter et al. (1997), concluded that these reactions are expected to take hundreds of years or more to complete. Because of the long residence time of C[O.sub.2]-charged formation waters within the aquifer, these reactions may eventually trap over 90% of the injected C[O.sub.2] (Gunter et al., 1997). Mineral trapping will not greatly increase the C[O.sub.2] storage capacity of the aquifer; rather its advantage lies in the permanent nature of C[O.sub.2] disposal (Bachu et al., 1994).

DEEP OCEAN DISPOSAL OF C[O.sub.2]

The ocean is the largest sink available for disposal of C[O.sub.2], with a residence time of four to five hundred years (Gentzis, 2000). The oceans contain a stratified thermocline, which is situated between the surface layer and the deep ocean. Its waters circulate between surface and deep layers on varying time scales, from 250 years in the Atlantic Ocean to 1000 years for parts of the Pacific Ocean (Mignone et al., 2003; Ormerod et al., 2002). The atmosphere and the ocean are in contact over 70% of the globe and there is a continuous exchange of inorganic carbon between them. Oceans arc, at the present time, removing about six Gigatonnes of C[O.sub.2]/ year from the atmosphere (Ormerod et al., 2002). Disposing anthropogenic C[O.sub.2] in the deep ocean would accelerate a natural process. C[O.sub.2] could be injected as a liquid below the thermocline at depths greater than 1500 metres and be sequestered either by dissolution in the water column or by formation of C[O.sub.2] hydrates.

Storing C[O.sub.2] by Dissolution

One approach involves transporting liquid C[O.sub.2] from shore by pipeline and then discharging it from a manifold lying on the ocean bottom, forming a droplet plume (Fig. 8). Since liquid C[O.sub.2] is less dense than seawater, the C[O.sub.2] droplets will rise until they are dissolved into the seawater and the C[O.sub.2]-charged solution spreads laterally into the (stratified) surrounding seawater. The dissolved C[O.sub.2] may travel in the thermocline, and eventually (after hundreds of years) circulate back into the atmosphere. The deeper the C[O.sub.2] is injected, the more effectively it is sequestered, but injecting deeper requires more advanced technologies (Ormerod et al., 2002). The oil and gas industry have established technologies to construct vertical risers in deep water and to lay seabed oil and gas pipelines at depths down to 1600 metres (Ormerod et al., 2002), suggesting that this method is technically feasible.

[FIGURE 8 OMITTED]

Alternatively, liquid C[O.sub.2] could be transported by a tanker and discharged from a pipe towed by a moving ship (Fig. 8). The Japanese R&D program for ocean sequestration of C[O.sub.2] is currently in phase II of a large-scale "moving-ship" scheme in the western North Pacific to assess environmental impact and C[O.sub.2]-plume behaviour (Mural et al., 2003). Studies by Ozaki et al. (2001) have shown that C[O.sub.2] injection would be most effective at relatively slower rates (larger droplet size) and at depths greater than 1500 metres. Such a depth is well within the capability of present-day subsea pipeline technology and C[O.sub.2] could be transported by tankers, similar to those used for transportation of liquid petroleum gas (Ormerod et al., 2002).

Storing C[O.sub.2] as Clathrates

Another method for ocean disposal of C[O.sub.2] involves sequestration of C[O.sub.2] at depths in excess of 3000 metres. At these depths, because of the high pressure and low temperatures, C[O.sub.2] exists in the form of a clathrate hydrate, an ice-like combination of C[O.sub.2] and water (Brewer et al., 2000). Pure C[O.sub.2]-hydrate is denser than seawater and will generate a sinking plume, settling on the bottom of the ocean (Brewer et al., 2000). C[O.sub.2] sequestered in this way would form submarine pools in hollows or trenches in the deep sea. Dissolution of C[O.sub.2] into the overlying seawater would be reduced significantly because of formation of the C[O.sub.2]-hydrates. Direct disposal of C[O.sub.2] at great depths is currently not technically feasible, however, it may be possible to send cold C[O.sub.2] (dry ice) from mid-depth to the ocean floor (Aya et al., 2003). With a density greater than seawater, cold C[O.sub.2] will sink to the ocean bottom and be effectively stored. The Monterey Bay Aquarium Research Institute (MBARI) has recently conducted a series of controlled experiments that involve release of cold C[O.sub.2] slurry at depths of 350 to 500 metres (Aya et al., 2003).

Yet another method proposes disposal of C[O.sub.2] as clathrate blocks. Studies on this disposal method confirm that streamlined blocks have higher terminal velocity and thus reach the seabed faster than equidimensional blocks (Guever et al., 1996). As large as 1000 tonnes and shaped like a projectile, these blocks could penetrate into the deep seabed where the solid C[O.sub.2] would physically and chemically interact with the sediments before reacting with the ocean water (Fig. 8). The retention times could, therefore, be significantly increased as compared to the gaseous or liquid C[O.sub.2] disposal methods (Guever et al., 1996). According to the IEA this method is currently not economically feasible (Ormerod et al., 2002).

Further studies on ocean disposal of C[O.sub.2] include fertilizing the oceans with additional nutrients to increase draw-down of C[O.sub.2] from the atmosphere (Ormerod et al., 2002). Addition of nutrients such as nitrates and phosphates or iron may increase production of biological material, thereby drawing down additional C[O.sub.2] from the atmosphere through photosynthesis of the phytoplankton. Should this method prove to be feasible, the fishing industries may benefit from the resulting increase in the fish population, with atmospheric C[O.sub.2] sequestration as a secondary benefit. However the overall impact on the marine ecosystem is not well understood.

All the above-described ocean disposal methods could potentially cause at least a local change in pH of the ocean water. Marine populations are, in general, intolerant to changes in the pH. Thus, because of environmental impacts on the marine ecosystem and associated public disapproval, ocean sequestration of C[O.sub.2] is not currently considered as an attractive option.

STORAGE IN SALT CAVERNS

Salt can be found as evaporite beds or as intrusive (domal or ridge) deposits where salt from a major underlying source has been forced up into overlying formations. The Western Canada Sedimentary Basin contains several regionally extensive salt deposits, contained primarily within strata of the Devonian Elk Point Group (Grobe, 2000). Large cavities are created by solution mining, whereby water is injected into a salt bed or dome and the brine solution is pumped out. These caverns can be up to 5x105 [m.sub.3] in volume (Bachu, 2000), and since salt is highly impermeable (Murck et al., 1996), these spaces could provide a long-term solution to C[O.sub.2] sequestration. The technology has been developed and applied for salt mining and underground storage of liquid petroleum gas (LPG), compressed air and petrochemicals (Bachu, 2000; Crossley, 1998; Istvan, 1983). Solid C[O.sub.2] (dry ice) could also be stored in these repositories, surrounded by thermal insulation to minimize heat transfer and loss of C[O.sub.2] gas (Davison et al., 2001). Although salt and rock caverns theoretically have a large storage capacity, the associated costs are very high and the environmental problems relating to the mined rock and disposal of large amounts of brine are significant (Kolkas-Mossbah and Friedman, 1997). Using current technology, storage of C[O.sub.2] in underground salt caverns is uneconomical.

MINERAL CARBONATION

Based on a natural rock-weathering reaction, mineral carbonation is a sequestration concept whereby C[O.sub.2] is chemically combined in an exothermic reaction with readily available Mg or Ca-silicate minerals to form carbonates (Lackner et al., 1997; O'Connor et al., 2000; Gerdemann et al., 2003). The products are stable on a geologic timescale, potentially storing C[O.sub.2] for millions of years. Mg-silicates are favoured relative to Ca-silicates because they are more widespread, form larger bodies and contaln more reactive material per tonne of rock (Lackner et al., 1997; Kohlmann et al., 2002). A wide variety of Mg-bearing materials, such as enstatite, fly ash and other industrial residues were investigated as potential starting materials for the industrial carbonation process. Recent laboratory tests however, indicate that olivine [(Mg,Fe)Si[O.sub.4]] and serpentine [[Mg.sub.3][Si.sub.2][O.sub.5][(OH).sub.4]] are the most promising raw material (e.g. Lackner et al., 1997; O'Connor et al., 2000). The two reactions below illustrate the basic C[O.sub.2] carbonation principle using olivine and serpentine as examples:

(2) [Mg.sub.2]Si[O.sub.4][olivine]+ 2C[O.sub.2] => 2MgC[O.sub.3][magnesite]+ Si[O.sub.2]

(3) [Mg.sub.3]Si[O.sub.3][(OH).sub.4][serpentine]+ 3C[O.sub.2] => 3MgC[O.sub.3][magnesite]+2Si[O.sub.2] + [H.sub.2]O

In nature, carbonation reactions involving silicates are slow (Kohlmann and Zevenhoven, 2001). A sequestration plant can be visualized as a blender operating at high temperature and pressure conditions (Fig. 9). For industrial C[O.sub.2] sequestration applications, carbonation reactions have to be accelerated. This can be achieved by increasing the surface area of the Mg-silicate (crushing and milling), agitating the slurry (O'Connor et al., 1999; Dahlin et al., 2000) and by adding catalysts (for example, NaCl and NaHC[O.sub.3] and HCl) to the solution/ slurry prior to the carbonation process (Dahlin et al., 2000; Goldberg and Walters, 2003; Jia and Anthony, 2003; Fauth and Soong, 2001; Lackner et al., 1998). Optimization of the carbonation process by controlling temperature and partial pressure of C[O.sub.2] ([P.sub.CO2]) may be also a major factor (O'Connor et al., 1999; Dahlin et al., 2000). In the case of serpentine, an energy-intensive heat pre-treatment (activation-destabilization of the crystal structures) at temperatures of 600 to 650[degrees]C is required (O'Connor et al., 2000). Such pre-treatment removes chemically bound water and increases overall porosity (Gerdemann et al., 2003; Kohlmann et al., 2002; Goldberg and Walters, 2003), thereby enhancing its mineral carbonation potential.

[FIGURE 9 OMITTED]

There is currently no mineral sequestration plant in operation, however members of the Mineral Sequestration Working Group, a multilaboratory team managed by the National Energy Technology Laboratory (NETL) of the Department of Energy (DOE) are developing pilot-scale mineral carbonation units and according to their plan a 10 MW demonstration plant will be operational by 2008 (Goldberg and Wakers, 2003). Their current research includes the design and operation of a first prototype high temperature-high pressure (HTHP) flow loop reactor by the Albany Research Center (Fig. 10), with the aim to develop a transition from batch experiments to continuous operation.

[FIGURE 10 OMITTED]

The mineral sequestration concept is currently incorporated into the design of the coal-fuel electricity generating plant of the Zero Emission Coal Alliance (ZECA), an international consortium of utilities, mining companies, engineering firms and government laboratories; however it may be also applied elsewhere.

Advantages of Mineral Carbonation

Serpentine and olivine are the two most likely silicates that could be used as starting materials in mineral sequestration. Olivine is favoured because it reacts better without the energy-intensive pre-treatment that serpentine requires. In contrast to the previously described methods, once the C[O.sub.2] is locked into a carbonate (a mineral stable on a geological time scale), there is no possibility for an accidental release of C[O.sub.2]. As well, direct carbonation does not lead to problematic by-products (Lackner et al., 1998). Furthermore, should fibrous serpentine tailings (chrysotile) be considered as raw material for the process (e.g. Huot et al., 2003), then mineral sequestration would help dispose of unwanted asbestos waste. Mineral carbonation may, therefore, benefit from public acceptance.

The costs of the C[O.sub.2] disposal could be higher than for the injection of C[O.sub.2] into oil and gas reservoirs or deep coal seams, for example. However, these costs may be reduced if the potential for industrial applications of the product (depending on acceptable purity, grain size, particle shape and chemical properties). Magnesite has a wide variety of industrial applications (Simandl, 2002) and the same applies for silica. The carbonation process may also become a new source of Fe, Mn, Co, Cr and Ni recovered during the breakdown of Mg silicate's crystal structure (Haywood et al., 2001; O'Connor et al., 2000).

Large-scale C[O.sub.2] sequestration into carbonates will require enormous amounts of raw material (Kohlmann et al., 2002). For a typical power plant, the mass flows of fuel and carbonated mineral will be of the same order of magnitude. For example, studies suggests that for a single 500 MW coal-fired power plant, generating approximately 10 000 tons of C[O.sub.2] per day, more than 23 000 to 30 000 tons per day of Mg-silicate ore would be required (Dahlin et al., 2000; O'Connor et al., 2000). Thus, under ideal conditions, coal and Mg-silicate mines should be located close to each other. No shortage of starting material is likely to occur if mineral sequestration becomes a reality and serpentine becomes a workhorse of mineral C[O.sub.2] sequestration (Goff et al., 1997). However, if forsterite (Mg-end member of olivine) is used as starting material, supplies are limited and geographically constrained. In most cases, serpentine is an unwanted by-product of metal and chrysotile mining, but in some locations, this waste may become a sought after commodity when its potential for C[O.sub.2] sequestration is realized. Should mineral sequestration of C[O.sub.2] become an established technology, then new opportunities will arise for potential producers of magnesium silicates and owners of magnesium silicate-rich tailings.

CONCLUSIONS

This paper presents descriptions of the main geological, ocean and mineral C[O.sub.2] sequestration methods that are currently the focus of intensive research by industrialized nations worldwide. At first glance, the most technologically mature methods are storage in active and depleted oil and gas fields, though most of the emphasis lies on maximizing oil and gas recovery rather than sequestration potential. Research relating to injection of C[O.sub.2] into deep coal seams is rapidly advancing, with C[O.sub.2]-enhanced CBM recovery potentially offsetting sequestration costs. Saline aquifers provide huge storage potential in terms of volume for C[O.sub.2] sequestration, but they are much more difficult and expensive to characterize than hydrocarbon reservoirs because of the lack of an existing exploration database. The methods that currently encounter the most resistance from the public are storage in salt caverns and ocean sequestration. Mineral sequestration is the only method that truly disposes of C[O.sub.2] on geological time scale, with a minimum risk for an accidental C[O.sub.2] release.

Table 1 Canada's total C[O.sub.2] emissions for
2000 as compared to global emission
estimates. Numbers for emission levels are
in Megatonnes (Mt) of C[O.sub.2] equivalent
(source: Environment Canada, 2002)

C[O.sub.2] emissions           Mt        %

World total (1999)       23900.00   100.00
Canada total (1990)        601.00     2.51
Canada total (2000)        726.00     3.04
Alberta                    223.00     0.93
Ontario                    207.00     0.87
Quebec                      90.40     0.38
British Columbia            65.90     0.28
Saskatchewan                61.80     0.26
Nova Scotia                 21.50     0.09
Manitoba                    21.40     0.09
New Brunswick               20.20     0.08
Newfoundland                 8.80     0.04
Prince Edward Island         2.10     0.01
North West Territories       1.80     0.01
Yukon                        0.53     0.00

Table 2 Canadian greenhouse gas
emissions. Carbon dioxide (C[O.sub.2]) is
the main contributor to Canada's total
greenhouse gas emissions (source:
Environment Canada, 2002)

Gas                             %

Carbon Dioxide (C[O.sub.2])   78.90%
Methane                       12.40%
Nitrous Oxide                  7.40%
Other (HFCs, PFCs and SF6)     1.30%

Table 3 Global C[O.sub.2] storage capacity of geological reservoirs
(source: IEA Greenhouse Gas R&D Programme, 2001).

Storage option                     Global capacity
                   Gigatonnes C[O.sub.2]   % of Emissions to 2050

Depleted Oil and
  Gas Fields                920                       45
Deep Saline
  Aquifers               400-10,000                 20-500
Unmineable Coal
  Seams                     > 5                      > 1

Figure 1 Global energy demands, showing that fossil fuels supply over
85% of the world's energy (McKee, 2002)

Petroleum                    39%
Coal                         25%
Natural Gas                  22%
Hydro Electric                7%
Nuclear                       6%
Wind, Solar and Geothermal    1%

Notes: Table made from bar graph.

ACKNOWLEDGMENTS

We would like to thank Terry E McCullough of BC Hydro, Barry Ryan, Brian Grant and Derek Brown of British Columbia Ministry of Energy and Mines and Alan Johnson from ZECA Corporation for reviewing the earlier version of this manuscript. The manuscript was greatly improved by incorporating suggestions from Stefan Bachu of Alberta Energy and Utilities Board and Steve Whittaker of Saskatchewan Industry and Resources.

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Danae A. Voormeij (1) and George J. Simandl, (2)

(1) University of Victoria, School of Earth and Ocean Sciences, P.O. Box 3055, STAr CSC, Victoria, BC, Canada, V8W 3P6, [e-mail]

(2)British Columbia Ministry of Energy and Mines and adjunct professor at University of Victoria, PO Box 9333 Stn. Prov. Govt., Victoria, BC, V8W 9N3, [e-mail]

Accepted as revised 22 December 2003