Canada's CO₂ Capture and Storage TRM 
Technology Pathways: Storage Technology

• Storage Systems
• Cost of Storage
• Storage R&D Needs

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Storage Systems

Although storage is one of the last steps in the CCS process it is one of the first to be considered when developing a strategy to roll-out CCS infrastructure and systems. There is no benefit to capturing CO₂ unless it can be stored and thus the total storage capacity and its location is an important constraint on how much CO₂ can actually be managed.

An important consideration becomes the type of storage media being used. CO₂ can be injected into porous geological formations such as sedimentary basins, but igneous and metamorphic rocks are ill-suited because of their fractured nature and lack of the needed porosity and permeability.

Other options for storage include terrestrial mineralization and ocean storage. Mineralization is prohibitively costly because of the large (and visible) environmental footprint it would leave due to mining operations. Further, most regions that have the serpentinite or other reactive deposits are far from CO₂ sources. Therefore, this would entail transporting CO₂ from places like the WCSB and Ontario to locations in British Columbia or Quebec.

Ocean storage refers to two options being discussed today. The first is dissolution in sea water, which simply means putting the CO₂ into solution in the ocean water column (IEA, 2004). The second choice is to store liquid CO₂ at depths of greater than 4000 m (IEA, 2004). Ocean storage is the most controversial of the options being considered primarily because of the relative immaturity of the technology and the resulting uncertainty and lack of knowledge of the potential environmental impacts of CO₂ in ocean ecosystems. Pilot projects in both Hawaii and Norway have been cancelled because of public opposition (IEA, 2004).

As a result, geological storage is the primary option being discussed in Canada today. The primary mechanisms for geological CO₂ storage include:

• Volumetric traps:
  Sites where free-phase and un-dissolved CO₂ is trapped in pore spaces and is prevented from seeping to the surface by physical or hydrodynamic barriers (in oil and gas reservoirs and deep saline aquifers). Volumetric traps also include man-made cavities such as salt caverns and mine shafts.
• Residual traps:
  In places where CO₂ has migrated through a formation, a portion of the gas is retained in the pore space as a result of capillary forces. Thus, a portion of the gas is trapped by forces other than a simple physical cap rock.
• Solution traps:
  Where CO₂ is either in solution in the formation fluids, or forms ionic bonds with the fluids, such as in the water or oil that saturates the pore space within a rock formation.
• Adsorption:
  Options where the CO₂ bonds with formation rocks that contain organic material, such as coal or shale.
• Mineral traps:
  Sites where the CO₂ precipitates out as a carbonate mineral. Such reactions can occur when CO₂-charged formation fluids react with other formation minerals.

The first two of these geological storage options traps the CO₂ in its free phase, the next two entail a geochemical trapping mechanism, and the final option relies on a chemical process to govern the fixation. Most geological storage options (with the exception of adsorption) are most efficient at a depth of 800 m or more, where the CO₂ stays in its dense phase because of formation pressure. Compressed fluids are pumped (or injected) down a borehole, which raises the formation pressure and results in the CO₂ entering the pore space that was formerly occupied by formation fluids. The spread or migration of CO₂ within a formation is controlled by factors like buoyancy, diffusion, dissolution and mineralization (IPCC, 2005).

Much of the current discussion of geological storage in Canada is on the selection of appropriate storage sites, which comes down to one of two options: value-added or non-value-added opportunities.

Value-Added Storage

Value-added storage is often considered to be the best use for captured CO₂ because of the added benefits beyond simply storing the CO₂. The first and most obvious benefit is using CO₂ for enhanced hydrocarbon recovery. The timing for using CCS in the WCSB is good because the maturity of the basin dictates a need for enhanced recovery methods. In addition, the geological trapping mechanisms in these reservoirs are known to have held gases and liquids (which include CO₂) in formation for millions of years. Production of these hydrocarbons has created substantial capacity to store CO₂ in what have already proven to be permanent storage sites.

Enhanced Oil Recovery

Only a portion of an oil reserve can be recovered using conventional methods, and as a result a variety of enhanced recovery techniques have been developed such as water flooding (waterflood), solvent flooding and gas flooding (which uses stranded gas or CO₂). When CO₂ is injected into a pool, it mixes with, and dissolves into, the crude oil which causes the hydrocarbon to swell thus reducing its viscosity, which results in more oil flowing to the well. Even when CO₂ doesn't go into solution, the result is still increased reservoir pressure which helps sweep oil towards the production well. CO₂ enhanced oil recovery (CO₂-EOR) can result in additional recoveries of 8 to 15 percent of the total resource in place, which translates to an average reservoir experiencing a 50 percent increase in recoverable reserves (IEA, 2004).

Up to half of the injected CO₂ flows back to the surface with the produced oil; the rest remains trapped in the reservoir. Any produced CO₂ is typically re-captured and re-injected. This production, capture and re-injection cycle has been considered an economic benefit in the past, because it reduces the volume of CO₂ required for a project. However, if one of the goals is to store GHG emissions long-term it may become more cost-effective to leave as much CO₂ in the ground as possible on the first pass. Because this was never the original intent of using CO₂-EOR, the technology will need re-engineering to co-optimize oil production and CO₂ storage.

CO₂-EOR is already a common practice and is in use in seventy-four operating projects in the U.S. Combined, these projects inject up to 30 MtCO₂e annually, with only 3 Mt coming from industrial sources, and the remainder coming from natural underground sources. The main reason for this use of natural CO₂ over industrial CO₂ is the low cost of natural sources, which highlights the need for more cost-effective capture technology to separate CO₂ streams at industrial facilities. An important change to current practice is the increasing attractiveness of these industrial sources, driven by the global desire to reduce CO₂ emissions.

Both commercial CO₂-EOR projects operating in Canada today (EnCana's Weyburn Project and Penn West's Joffre Project) derive CO₂ from industrial sources. The Joffre project is nearing its end of life, but the Weyburn project is still relatively new. Weyburn injects 2 MtCO₂e/yr, with half of the CO₂ being recycled resulting in a net long-term storage of 1 MtCO₂e/yr. If Weyburn produces for the next twenty years it will store 30 MtCO₂ in total (20 MtCO₂e net — when project-related emissions are accounted for). When fully depleted, the reservoir will have much more available storage capacity, but filling this will require the injection of CO₂ for storage purposes only.

At least five new pilot CO₂-EOR projects are at various stages of development in Canada. However, the current cost of CO₂ is high, and until it becomes more available (like a commodity) this innovative practice will only grow incrementally. If the cost of CO₂ were sufficiently low, CO₂-EOR could potentially be applied to many major oil fields worldwide making the potential market for CO₂-EOR technology enormous.

Enhanced Gas Recovery

As natural gas pools near the end of their productive lives, gas recovery factors decline and compressors, pumps and other equipment must work just as hard to produce less gas. It's possible that there are significant economic advantages to injecting CO₂ into gas reservoirs during these last productive years to produce the remaining recoverable reserves in less time and without significantly contaminating the resource. CO₂ is denser than natural gas in any of the phases (solid, liquid, supercritical or gas), and thus it would be expected to flow down a reservoir thereby pushing the gas up (IEA, 2004). However, this option for enhanced recovery is still highly speculative, and it still needs to be tested and proven in actual applications. Low permeability reservoirs may provide some of the first applications because the anticipated benefits of CO₂ enhanced natural gas recovery (CO₂-ENGR) may be most prominent in these settings.

An opportunity often discussed for CO₂-ENGR is using it in past conventional EOR projects where stranded natural gas liquids were often injected into oil pools to enhance recovery. Significant amounts of this injected gas remain in formation throughout the WCSB, which in theory could be recovered using CO₂-EOR today. At a future time, with the right combination of high natural gas prices and low CO₂ prices, it may be economic to re-open these projects and produce the injected natural gas liquids using CO₂-ENGR.

At present, a number of barriers stand in the way of CO₂-ENGR in Canada. First, CO₂ is far too expensive to run these projects economically today. Second, conventional production typically recovers up to 90 percent of the available gas in a reservoir, and CO₂-ENGR mainly helps in speeding up the recovery process with limited potential to increase overall recovery factors. While faster recovery is an economic advantage, it is not as valuable as increased recovery factors. Third, CO₂-ENGR has yet to be applied anywhere in the world and the technology is still in the conceptual stage (IEA, 2004). Other potential issues are the unknown effects of CO₂ mixing with hydrocarbon gases, and the potential for early CO₂ breakthrough to producing wells. More work is needed to develop, demonstrate and commercialize this technological opportunity.

Enhanced Coalbed Methane Recovery

Coal beds (or coal seams) naturally contain gases including methane, which can occur in varying amounts depending on depth (normally at 300 to 1500 m), and how much methane has already seeped to the surface. The methane sits adsorbed onto coal surfaces and occurs as a free gas in the fractures and cleats, with an undisturbed coal seam containing up to 25 m³ of methane per tonne of coal (IEA, 2004). While this technology is only being developed, expectations for its success are very high.

The U.S. has been producing coalbed methane (CBM) using primary production methods for more than two decades. Daily production levels in the U.S. exceed 28 Mm³, which comes from some 6000 wells. The Canadian CBM industry is in its infancy, but growing rapidly, and CO₂ enhanced CBM recovery (CO₂-ECBM) techniques may significantly improve conventional recovery factors, which often range between 40 and 50 percent depending on the resource and the recovery method used (IEA, 2004). These factors will increase to more than 90 percent using CO₂-ECBM, and to 100 percent in deep seams that have good permeability. This is because the methane has a lower affinity to coal than CO₂, and therefore, by injecting CO₂ into coal beds, it is naturally adsorbed onto coal surfaces, thus freeing up the methane for production (IPCC, 2005).

Laboratory analysis indicates that two to ten times as much CO₂ can be adsorbed by coal as methane, thus the storage potential is large. If the coal is deep enough and remains undisturbed, the CO₂ can be stored for thousands of years. However, much of the experience with CO₂-ECBM is at the R&D and applied R&D stages. In fact, this is still a very immature and unproven technology area.

Some specific issues that need to be addressed to prove the technical and economic feasibility of CO₂-ECBM include work on coal swelling caused by the adsorbed CO₂ which decreases the permeability of the formation. Another issue is the diffusion rates of gas to and from the coal and into the cleats. Brackish water production is another issue in some commercial CBM operations, notably in the U.S.. The cost of drilling injection wells, and the environmental impacts and footprint, are issues because of the large number of wells needed for CBM production, which will only be exacerbated when using CO₂-ECBM.

One of the largest problems is in resource characterization and in identifying the specific coal seams that are best suited for CO₂-ECBM. For example, the reservoir needs to be both horizontally and vertically homogeneous (with minimal faulting and folding), permeability needs to be at least 1 to 5 millidarcies, methane content needs to be sufficiently high with the coal at a depth of between 300 and 1500 m.

Acid Gas Injection

As already noted, many natural gas fields around the world have high CO₂, H₂S and other associated gas concentrations. Deep sour gas pools in the WCSB have large quantities of both H₂S and CO₂. Traditionally these gases were separated from the produced natural gas, with the CO₂ being vented to the atmosphere and the H₂S being processed and stored as sulphur for eventual sale. In 1990, certain Canadian natural gas plants were granted regulatory approval to inject acid gas (the combination of H₂S and CO₂) back into the deep geological formations near where it originated. In many cases, this acid gas injection is the most cost-effective and environmentally sound way of dealing with the H₂S, as it eliminates the need for costly sulphur recovery facilities and is a less energy-intensive way of handling the acid gas.

Today, more than 40 of the 60+ global acid gas projects in operation are located in Alberta and British Columbia, and these projects currently store up to 1 Mt of CO₂ annually in Canada (IEA, 2004). A lot can be learned from acid gas projects because they are some of the only commercial scale analogues for geological CO₂ storage. Much can be learned about the fate of CO₂ and its interaction with formation substances. Regulation already exists for acid gas injection and storage, and many parallels and learning, can be drawn from this process when developing CO₂ storage regulation.

Gas over Bitumen

An issue currently being discussed is the potential adverse impact of producing natural gas in contact with bitumen (and vice versa) in the WCSB. It may be possible for CO₂ to play a role in re-pressuring formations where one resource has been removed, which might enable production of the remaining resource. This potential opportunity is still being explored in the laboratory and is only at the pre-field test stage today.

Temporary Storage

Underground caverns, especially from salt or potash mines, provide some capacity to temporarily store CO₂. In western Canada, depleted oil and gas reservoirs or other porous media are used for the temporary storage of natural gas. This storage will play an important role in balancing pipeline pressures in a CO₂ transportation system. Such storage can also help ensure a steady supply of CO₂, by acting as a strategic buffer or reserve. In many ways, this is the same role that natural gas hubs play today. Because of the experience and knowledge that already exists regarding temporary natural gas storage, little research seems necessary on temporary CO₂ storage.

Non-Value-Added Storage

The storage options that generally don't provide an economic benefit other than simply storing the CO₂ are referred to as non-value-added opportunities. Until a significant cost is associated with CO₂, emissions these non-value-added opportunities will remain uneconomic in Canada. Even in a carbon constrained world, value-added opportunities are most appealing. However, if certain constraints make value-added storage too costly (for example, if impure emissions sources require significant cleaning and conditioning prior to injection), the opposite may hold true, and simply storing the CO₂ may be most cost-effective. As a result, the timing to develop these opportunities depends heavily on future climate change policy and on emissions reduction crediting. Regardless, there is general recognition of the need to improve the understanding of non-value-added storage opportunities (IEA, 2004).

Depleted Oil and Gas Pools

Depleted oil and gas pools and (some day soon) coal seams, provide empty pore space that can be reoccupied by CO₂. A sliding scale is used to distinguish between operating and depleted oil and gas pools, and depending on a number of dynamics (such as fossil fuel prices and the physical nature of the reservoir), an abandoned pool may operate again at a future point in time.

Like many of the value-added options, depleted pools afford project operators the advantage of knowing the geological formations being used. In places like the WCSB, the geology is very well understood and the traps and formations are known to have held gases and other liquids for millions of years. In addition, a lot of depleted capacity already exists in mature basins like the WCSB. Depleted gas fields have more potential, simply because they are larger in size than oil fields, there are many more of them, and the recovery factor for gas is much higher than for oil. Spare capacity in undeveloped fields like the Atlantic and Beaufort-Mackenzie Basins will become available as oil and gas is produced.

Any technical issues related to these formations are similar to those noted earlier for CO₂-EOR or CO₂-ENGR.

Deep Saline Aquifers

A saline aquifer can refer to any one of a number of sedimentary rock types saturated with saline, non-potable water, from which the water can be drawn, and into which fluids can be injected (IEA, 2004). Aquitards are rock layers in which water can exist, but from which water cannot be produced, because the permeability is to low to allow water to flow at an acceptable rate. An aquiclude is a rock with almost zero permeability. All three of these formations play a role in deep CO₂ injection, with aquifers providing the pore space for storage, and aquitards and aquicludes providing the physical trapping mechanisms.

Deep saline aquifers provide the greatest volumetric potential for storage anywhere in the world (refer back to the 1000 to 10 000 Gt noted previously). Saline aquifers run deep under all 68 Canadian sedimentary basins, and provide access to storage opportunities in many parts of the country.

Statoil's Sleipner Project, which is 250 km off the coast of Norway in the North Sea, is the first commercial-scale project dedicated to CO₂ storage in a deep saline aquifer. The Sleipner natural gas production field provides approximately 1 MtCO₂e/yr for storage in the aquifer (IEA, 2004). Since 1996, the site has not experienced any CO₂ leakage, and the project is proving technically feasible (IEA, 2004). The entire project will store some 20 MtCO₂ in its lifetime, although the total storage capacity is hundreds of times larger (IPCC, 2005).

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Cost of Storage

Storage is typically the least costly of the three CCS components. The main drivers of the cost of storage include geographic considerations (onshore versus offshore storage), reservoir depth and other reservoir characteristics (such as injection capacity). Storage costs can range between (CDN) $3 and $9/tCO₂ in Canada (Thambimuthu, 2004). The cost of monitoring (which is discussed below) is not known for Canada specifically, but is estimated by the IPCC (2005) to be (USD) $0.1 to $0.3/tCO₂. When CO₂ is used for enhanced hydrocarbon recovery, the economics can change significantly, and in many cases can provide a net benefit. As already noted, the deployment of cost-effective infrastructure and systems requires upfront capital investments which must also be accounted for in the economic analysis.

Storage Risks

The storage component of CCS poses a new set of risks that tend to be: global in the sense that any seepage would diminish the effect of storage by increasing the amount of CO₂ that escapes to the earth's atmosphere; and, local in that CO₂ may leak and contaminate other energy, mineral resources and groundwater (and may harm vegetation and life depending on leak rates and concentrations). While there is little experience with geological storage, closely related industrial experience and scientific knowledge can serve as the basis for risk management (IPCC, 2005). The identification of potential escape pathways for leakage and/or seepage (as illustrated in Figure 10) is an important step in this, and any other risk assessment.

Evidence from engineered and natural comparisons, and from models to date, indicate that up to 99 percent of CO₂ injected into a geological formation is "very likely" to be retained for over 100 years; that 99 percent is "likely" to be retained over 1000 years if the formation is appropriately selected and the project well managed (IPCC, 2005). In most of these sites, the majority of CO₂ will gradually be immobilized by the many trapping mechanisms noted previously.

However, it is important to recognize that a small amount of CO₂ will leak (and perhaps even seep to the surface) and strict requirements like zero leakage/seepage are unnecessarily restrictive. Studies to date indicate that an allowable rate of seepage of up to 0.1 percent/yr would still result in an effective outcome when dealing with GHG emissions reductions (IEA, 2004). This rate is not an indication of what the research community anticipates the actual rate to be; rather it is considered an upper bound (or tolerance level) for the earth to deal with slow and steady CO₂ seepage to the atmosphere, considering the need to maintain atmospheric GHG concentrations below a certain level. Regardless, a variety of storage monitoring programs and response plans are needed, and appropriate technologies are required to minimize the impacts of each kind of underground leak, or seep to the earth's surface.

Of course, it must also be recognized that there are places where geological CO₂ storage should probably not take place, such as places that experience high seismic activity. As was noted in The Oportunities, this is one of many criteria used to select sites for CCS activities.

Storage Monitoring Options

Short and long-term monitoring options are required to ensure that any gases injected into a geological formation do not return to the atmosphere, cause environmental damage or pose safety concerns. Monitoring is also needed to provide the data for calculating net emissions balances to which any emissions reduction credits will be tied. Because these credits will have a monetary value and environmental attributes associated with them, they will need to be substantiated and proven to be representative of actual storage taking place, using some sort of measurement and verification protocol based on accurate monitoring. Because of the different monitoring needs, a number of technologies are proposed for operation, verification and environmental requirements.

An operator will need to monitor any project for regulatory purposes (operational monitoring), which will likely include checking injection rates and CO₂ recycle and re-injection rates in the case of enhanced recovery processes. In addition, the project operator may have their own (and more specific) monitoring needs since good information leads to better project management and optimized performance. Operational monitoring is initiated during the injection phase of the project and is concerned primarily with the underground migration of the CO₂ injected, and the associated emissions when running the project.

Verification (or scientific) monitoring is done for research purposes, to improve the understanding of the complex processes that occur at injection sites. Verification monitoring is needed to learn how CO₂ migrates and either reacts or adsorbs in rock formations; it is a major focus in all research, pilot, demonstration and commercial projects today. Another element of research is minimizing leakage into other formations and seepage to the surface, and includes developing models that enhance the predictive power of science today.

Table 14: Monitoring Technologies for Different Timeframes

Risk	Years
	0.1 to 1	1 to 10	10 to 100	100 to 1000
Source: Chalaturnyk and Gunter, 2000
Seepage	Aircraft	Aircraft	Aircraft	Aircraft
	Soil gas	Soil gas	Soil gas
	In situ Tracers	In situ Tracers	In situ Tracers	In situ Tracers
Leakage	3D-seismic	3D-seismic	3D-seismic	3D-seismic
	Tilt meter	Tilt meter	Tilt meter	Tilt meter
	Pressure	Pressure	Pressure
	In situ tracers	In situ tracers	In situ tracers
	Logs	Logs	Logs
	Passive seismic	Passive seismic	Passive seismic
Migration	3D-seismic	3D-seismic	3D-seismic	3D-seismic
	Passive seismic	Passive seismic	Passive seismic
	X-well seismic	X-well seismic	X-well seismic
	Tilt meter	Tilt meter	Tilt meter	Tilt meter
	Pressure	Pressure	Pressure
		Injected tracers	Injected tracers
	In situ Tracers	In situ Tracers	In situ Tracers
	Logs	Logs	Logs
		Injection rates

Environmental monitoring is meant as a safeguard against health, safety and other environmental risks, and is generally focused on CO₂ seepage — the movement of injected CO₂ towards the earth's surface where it can interact with the biosphere. Depending on the risk level of the project, aspects of environmental monitoring may be similar to operational monitoring. Since leakage or seepage may occur anytime during a project, or long after the project has ceased, environmental monitoring doesn't end when the injection stops.

Researching, testing and continuously refining these monitoring, measurement and verification (MMV) technologies is essential to ensuring that the CO₂ is properly stored and neither leaks from the storage unit nor seeps to the earth's surface. Table 14 lists some technologies being discussed for monitoring CO₂ movement over different timeframes. Many technologies are either costly or require further development to be used in commercial applications. Current field experience can help in determining which of these technologies can deliver the needed information for scientific learning, operational excellence and environmental integrity.

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Storage R&D Needs

A number of priorities have been identified for research spanning all aspects of geological storage (again based on identified gaps), and the following are suggestions for an overarching CO₂ storage R&D framework for Canada.

Storage Integrity

The top priority for storage research is the confirmation that CCS is a safe, reliable and environmentally beneficial practice for long-term CO₂ storage (the order of thousands of years). The issue here is the possibility of leakage from the containment unit (the geological formation) or seepage from underground to the earth's surface, and although it seems likely that well-engineered sites in optimal locations pose a very small risk of significant leakage or seepage, in actual fact, this assertion is very difficult to prove. Scientific evidence and field experience are both needed to improve technologies and practices for geological storage.

Site Identification and Characterization

Sites need to first be identified on a broad scale, using the basic information available. Selected sites should be evaluated using several basic criteria. First, in broad terms, there needs to be sufficient capacity to store the desired amount of captured CO₂. In fact, the amount of available storage capacity will be a factor in how much CO₂ can actually be captured. Second, the selected storage sites will collectively need to be capable of injecting the CO₂ at the supply rate. Third, the confining properties of the storage site (meaning, the ability of the storage sites to actually hold CO₂ long-term), such as its ability to avoid CO₂ leakage within the subsurface or seepage to the earth's surface, is an important criterion. Safety is another consideration, as any sites that are considered to be unsafe will be rejected. The economics of the various storage options are the ultimate deciding factor for which sites to pursue and in what relative order. The parameters for this last criterion (economics) change with time because of technological maturation, and because of changes to fiscal regimes, incentives and penalties.

After the top candidate sites are selected, they need to be characterized in detail regarding their geology, faults and fractures (if there are any present), internal architecture, mineralogy and geochemistry, fluids contained in the pore space, pressure and geothermal regimes, stresses and geomechanical properties, flow of contained fluids, and the number and type of wells penetrating the storage unit. Numerical models need to be run to evaluate the long-term fate of injected CO₂ in the candidate sites. Potential natural or man made leakage pathways (such as fracture systems, abandoned wells or mine shafts) should be better understood, and a review of historic well-drilling practices in Canada would help develop an understanding of the stability of well casings and cement, and the bonds between casing, cement and rock formations.

Canadian Storage Capacity

Further study is needed to improve existing knowledge of the potential source sites and storage basins in Canada because of the regional distribution of CO₂ emissions, and the asymmetry in storage opportunities across the county.

The largest CO₂ emitting provinces are Alberta and Ontario, each with more than 200 MtCO₂e/yr. Two thirds of the Alberta emissions are from large, stationary sources (which are suitable for CCS), while most of Ontario's emissions are from transportation. Saskatchewan and northeast British Columbia represent two other candidate regions in terms of CO₂ sources, with the Atlantic Provinces providing smaller opportunities.

On the storage side, potential in the WCSB (which extends from northeast British Columbia to Manitoba) is in the order of hundreds of megatonnes in the existing and depleted oil reservoirs, several thousand megatonnes in existing and depleted gas reservoirs, 1000 to 2000 megatonnes in coal beds, and tens to hundreds of giga tonnes in deep saline aquifers. In the Atlantic Provinces there is some potential for storage in onshore coal beds (once the technology is proven), offshore oil and gas reservoirs and deep saline aquifers, but all of these opportunities need to be evaluated. In addition, there are opportunities for smaller more local storage in parts of British Columbia, Ontario and Quebec; however, there is little current knowledge of any of these options. Only the depleted and existing oil and gas reservoirs in the WCSB, and recently the coal beds in Alberta, have been thoroughly studied.

An important research area may simply be to gain a better understanding of the economics of all storage options, value-added and non-value added. It is possible that some deep aquifer projects may be less costly overall if the systemic cost savings of straight storage are fully realized.

Tag-on Opportunities

To develop infrastructure is often more costly than tagging it on (or appending it) to existing infrastructure opportunities. Surface facilities and equipment for compression or liquefaction, and the subsequent injection and monitoring of CO₂ will be costly. As well, unless the source and storage sites are near each other, transportation is expensive. Therefore, a sensible approach for development of such infrastructure and systems is to reduce costs by having governments, research communities and industry work together to maximize synergies through collaborative efforts, and by tagging research and science projects onto existing commercial opportunities. This tag-on approach was used for the Weyburn CO₂-EOR project and will be used for the CO₂ Sequestration and Methane Production Project (CSEMP), as well as Penn West's new CO₂-EOR project.

The benefits of tag-on projects are many-fold. The sites (such as compressor stations, field production centres, and pipeline facilities) are often fully serviced and staffed, and may already have the necessary resources to undertake the actual storage and monitoring activities. In the case of oil and gas production sites, a lot of information and expertise exists on-site which would be helpful when developing reservoir and storage engineering approaches, and when identifying best practices to optimize the dual goals of petroleum recovery and long-term CO₂ storage. In addition, site specific reservoir expertise can be used to develop mitigation strategies for potential CO₂ leakage and seepage. Existing commercial sites also have practices and procedures, standards and protocols that can be used to address safety, environmental and other risks.

Assessment Approaches and Expertise

Experts around the world are working to develop better risk assessment tools and approaches for CCS, and many Canadians are leading the way. Resident expertise in the petroleum exploration and production sectors, including hands-on experience with acid gas injection and CO₂-EOR, has contributed to developing this expertise. Canada has been very involved in developing an international collaborative mechanism and in sharing its expertise with international research organizations. However, more work is needed, and therefore the effort should continue.

Making integrated evaluation tools on geological storage available would be useful for decision-makers. When assessing storage options from a business perspective, useful parameters for an integrated tool would include rate of return, project value and CO₂ credit value. From a policy perspective, parameters might include emissions reductions calculators, tax and royalty calculators. Such integrated evaluative models and tools are not currently available, but components of them do exist. These tools should be based on sound engineering design drawn from petroleum reservoir experience, be capable of generating credible results, and should include a wide range of options that are useful to both industry and government.

International Collaboration

The international community is already engaged in developing CCS technology, and Canada is very involved in both the IEA's Greenhouse Gas R&D Programme and the Carbon Sequestration Leadership Forum. Canada also houses the International Test Centre for Carbon Dioxide Capture (ITC) at the University of Regina and the IEA Weyburn CO₂ Monitoring and Storage Project in Weyburn. Canada has world research facilities at the CANMET Energy Technology Centre in Ottawa (CETC-O). The CBM Technology/CO₂ Sequestration Project (in China) is another example of Canada's efforts to work with international partners on CCS. Collaborative efforts like these have dual benefits of helping Canadians learn from the experience of other researchers, project operators and policymakers, while reinforcing Canada's own knowledge capacity and ability to contribute to international capacities. This international collaboration applies to all aspects of CCS technology development (not just to storage).

A great deal could also be learned through selective bilateral relationships with countries that are active in CCS research and demonstrations. Such arrangements could include international missions, joint participation in research and monitoring projects, or even the exchange or secondment of experts.

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