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

• Capture Systems
• Capture Technologies
• Cost of Capture
• Capture R&D Needs

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Capture Systems

In any discussion on technology the subject can be divided along a number of lines. In this section the discussion starts with the larger integrated systems in which specific technologies are applied, followed by a deeper discussion of each technology. This split discussion is most prominent for the capture component, because of the variety of technological options for separating and capturing CO₂.

The most promising CO₂ capture systems are often classified under four types: post-combustion systems, pre-combustion systems, oxy-fuel combustion systems and industrial processes (see Figure 9). Post-combustion refers to a system that captures CO₂ from a flue gas after the fuel (whether fossil or biomass) has been combusted in air. Pre-combustion is a process where the fuel source is gasified to create syngas, a mixture of hydrogen and carbon monoxide. The carbon monoxide then undergoes a shift reaction to generate hydrogen and CO₂ which can then be captured prior to combusting the gas mixture. In oxy-fuel systems the fuel is combusted in an oxygen enriched environment rather than simply air. The exhaust mixture of CO₂ and water in an oxy-fuel system can be easily separated to produce high purity CO₂ streams. Certain industrial processes, such as cement manufacturing and hydrogen production, utilize chemical reactions that generate CO₂ emissions. Natural gas processing involves the separation and capture of naturally occurring CO₂ that flows to the surface during gas production. Each of the four capture systems has its own merits and challenges, and each has a number of technology needs which are discussed in a subsequent section.

Post-combustion Systems

When capturing CO₂ from a typical air-fired combustion unit after the burning process has taken place, it is referred to as post-combustion capture. Any industry that generates thermal electricity as part of its process (either by using fossil fuels or biomass) is a primary opportunity for post-combustion. More than 90 percent of industrial facilities today use conventional process heaters and industrial utility boilers in which post-combustion systems could be tagged-on to existing facilities. The disadvantage of these systems is that typical flue gas streams have CO₂ concentrations of 20 percent or less. Although the CO₂ can be separated using membranes or cryogenics, these are costly endeavours, and only absorption (using chemical solvents like amines) is commercially viable today.

The challenge for post-combustion capture systems is to develop new designs for commercial-scale applications in large industrial facilities. Specifically, there is a need for improved solvents which could significantly reduce both the high energy penalty and capital cost of post-combustion capture. Amine scrubbing capture processes require lots of heat for solvent regeneration which contributes to the energy penalty. Because the process operates at atmospheric pressure, a lot of energy is needed to compress the CO₂ for transportation. Parasitic losses for thermal power plants that use amine scrubbing ranges between 10 and 30 percent of the total power the plant would generate if CO₂ capture were not included (IEA, 2004b). This energy penalty translates into a noticeable impact on electricity prices.

Other needed technologies for post-combustion systems are energy efficiency and integrated pollutant controls, waste management processes and CO₂ separation technologies (both for retrofits and for new facilities). The control technologies include combined CO₂/sulphur oxide (SOx) removal systems for multi-pollutant capture. Additional work is needed to improve instrumentation and controls, new process integration methods and tools to conserve in-plant energy use. A final area of focus is on the co-production of other useful industrial by-products, such as fertilizer, ash and gypsum.

Pre-combustion Systems

Pre-combustion capture systems basically involve de-carbonizing the fuel source prior to combustion, a process that is widely used in the manufacture of hydrogen and fertilizer (IPCC, 2005). The fuel source can be converted to a syngas, which consists mostly of a mixture of carbon monoxide (CO) and hydrogen. This conversion can be done using gasification, partial oxidation or steam reforming technology. Gasification is most often used for solid fuels, partial oxidation for liquids, and steam reforming for gases. Then the CO is converted into CO₂ through a shift conversion process which also produces a stream of hydrogen. The most valuable by-product of pre-combustion is the hydrogen, and as the world shifts towards a hydrogen-based economy it will become even more valuable as a fuel source for transportation or distributed generation.

Compared to other combustion processes, the incremental energy penalty of pre-combustion capture is low at 6 percent (IEA, 2003); because of the relatively favourable CO₂ concentrations in the process (which range from 15 to 80 percent) and the high pressure involved (IPCC, 2005). Both factors make the separation and compression of CO₂ in pre-combustion systems relatively efficient.

Pre-combustion systems are costly and questions exist regarding the reliability of using gasification technology on low-rank Canadian coals such as the sub-bituminous and lignite coals in western Canada.

Shift converters weren't made for fuels like coal, and process-related ash particles will result in system damage. Other problems include hot gas clean-up and the issues related to pure hydrogen-fired turbines. While integrated gasification combined cycle (IGCC) technology (gasification technology) has been commercially demonstrated in other settings around the world, it has yet to be proven technically feasible using Canada's variety of low rank coals.

Therefore, second generation IGCC concepts are needed; ones that incorporate improved membrane processes for the water gas shift reaction and for hydrogen/CO₂ separation. These concepts will need to include more energy efficient CO₂ and multi-pollutant capture processes that apply to low rank coals. Ultimately, a pilot-scale gasification facility is needed so that industrial operators conducting research on new configurations (specifically designed for heat, power and hydrogen production) can test their new designs in an economic setting. IGCC technology, optimized for generating power in Canada, would enable the roll-out of a whole new fleet of power generation facilities across the country (CCTRM, 2005).

Oxy-fuel Combustion Systems

Oxy-fuel is an emerging approach to post-combustion capture, whereby the combustion process takes place in an oxygen enriched setting which results in low-emissions fossil fuel combustion. Removing nitrogen from the air, and then combusting the input fuel in an oxygen-rich environment, results in a highly concentrated flue gas stream (with greater than 80 percent CO₂) which can be further concentrated using physical gas purification techniques such as cryogenic separation.

This concentrated flue gas stream is one of the primary benefits of oxy-fuel combustion. A second advantage stems from the absence of nitrogen which results in the virtual elimination of nitrogen oxide (NOx) emissions. An overall systemic advantage is the reduced size of the entire process, due to the reduced volumes of both the input and exit gases, both of which translate into reduced capital and operating costs.

A variant of oxy-fuel technology, oxy-fuel recycling, can be used to control flame temperatures by recycling a portion of the exit flue gas into the oxygen input gas prior to combustion. By diluting the oxygen in the input gas it is possible to achieve conventional flame and heat transfer characteristics, thus potentially allowing the technology to be retrofit into current power plants. Another emerging variant is hydroxy-fuel combustion, which again provides an opportunity to moderate process temperatures by facilitating the combustion process in an oxygen and steam environment.

The greatest challenge facing oxy-fuel today is to lower the energy penalty (and therefore the cost penalty) involved in producing oxygen, which ranges from 8 to 30 percent (or perhaps even higher) of the total fuel cost depending on the fuel source and process used (Dillon, 2004). The U.S. Department of Energy is working on improved ion transport membrane (ITM) systems, which are meant for low-cost, large-scale oxygen production. Success would result in a key enabling technology that significantly reduces the energy penalty involved in producing oxygen.

Another important challenge is that current design configurations and materials are unable to operate at the high temperature ranges for oxy-fuel combustion; however, CO₂ or steam recycling may mitigate this issue. A final issue is the need to reduce the total energy consumption for CO₂ separation and compression. However, this issue is not unique to oxy-fuel, as all four capture systems face this problem.

While oxy-fuel will assist in reducing the size, number and cost of the units required to produce energy, and will make emissions capture easier, its full potential is unlikely to be realized until new high-temperature materials become available for combustors and boilers. CETC-O is working on oxy-fuel combustion systems, and is collaborating with partners who are developing super alloys and other advanced materials. The E.U.'s Thermie Program on advanced materials is working on materials that will be used in future applications of oxy-fuel combustion, as well as in ultra-supercritical pulverized coal and natural gas systems.

Early-stage commercial demonstrations are needed for oxy-fuel and/or hydroxy-fuel recycle systems, through which researchers could conduct the work needed to better define the science around oxy-fuel combustion, and develop new equipment, design principles and energy system process configurations.

Industrial Processes

The separation of CO₂ from flue gases has been a common practice in certain industries, such as natural gas processing, and hydrogen and fertilizer production, for over 60 years. The current practice is most often to separate the CO₂ and simply vent any unused portion to the atmosphere. Therefore, the concept of CO₂ separation using industrial processes is not new, unlike the concept of capturing those emissions for environmental reasons.

For industries like upstream natural gas processing, and hydrogen and fertilizers manufacturing, flue gas streams often contain greater than 90 percent CO₂. Consequently, many of these opportunities only require compression technology to pressurize the flue gas for transportation. This advantage makes these capture opportunities some of the most economic today. As noted previously, fertilizer manufacturing (of products such as ammonia and urea) is considered one of the best early opportunities for commercial CO₂ capture today, and approximately 13 MtCO₂e/yr could be captured from this industry now (IPCC, 2005).

CO₂ concentrations in natural gas varies by region, with almost no CO₂ in Siberian gas and up to 70 percent in some Indonesian fields; the global average for natural gas is 1–2 percent CO₂ (IEA, 2004). Natural gas in Canada can contain anywhere from no CO₂ up to 36 percent. Therefore, the opportunity of capturing CO₂ from natural gas processing facilities varies by location.

Other opportunities in the fuel supply industries include oil refineries, hydrogen production and gasification facilities. However, because of the variety of oil refining processes used worldwide, it is impossible to characterize the industry and to indicate the total potential for CCS. That being said, oil refining is one of the largest emitting industries worldwide, thus opportunities do exist. Hydrogen is considered by many to be the transportation fuel of the future, and hydrogen production (using other fossil fuels as the feedstock) offers the potential to capture CO₂ emissions from the transportation industry by capturing it where the fuel is produced. As already discussed, gasification is another option for producing hydrogen in a synfuel mix which also contains CO which could be converted to CO₂ for transport to a suitable storage site.

Other high quality industrial sources of CO₂ include cement, steel and pulp and paper, where average CO₂ concentrations of the flue gases generally exceed 20 percent. CO₂ concentrations from cement production are higher than those from conventional furnaces because more than half of the CO₂ comes from an essential chemical reaction used in cement production (IEA, 2004). Substantial amounts of CO₂ could be captured during direct iron production (DIP), a process used in regions with a lot of stranded gas (such as the Middle East). Paper mills and ethanol plants both recover 'black liquor' (the remaining lignin fraction) from industrial processes and use it to generate energy. These facilities are a source of CO₂ emissions that, if captured and stored, may result in the neg-emissions noted earlier, depending on the sustainability of the fuel source.

Some new technologies are needed for applications in existing facilities, to better enable the capture of high concentration streams in the existing capital stock. As well, better process integration is needed for CO₂ capture technologies which in many cases could make a big difference in the capture economics. A lack of information on the application of solvent scrubbing or oxy-fuel combustion in industries like cement, glass and metals is a critical gap. If implemented appropriately, industrial processes could be some of the first areas to produce low-cost and very pure CO₂ streams for CCS.

Final Systems Discussion

A critical question that arises when discussing any of the previous capture systems: what is the role of developing technology for new plant designs versus retrofits to existing applications? For North America, this question is less important because of the age of existing capital stock. Many North American thermal power plants are reaching their economic lifetime and new plants need to be built. Therefore, an opportunity arises in that any new facilities could be designed to accommodate the addition of CCS technology when it becomes available in the future (to be capture-ready).

Oxy-fuel is often discussed as a future retrofit option for coal-fired facilities in Canada and elsewhere. However, the Canadian Clean Power Coalition (CCPC) recently conducted an extensive study which indicated that retrofitting Canada's existing facilities today would result in an incremental cost increase of 1.5 to 2.7 cents Canadian per kWh of electricity produced (CCPC, 2004). As a result, the CCPC has decided that retrofits using oxy-fuel are not an economically viable option for coal-fired facilities in Canada, and that Canada may instead wish to deal with CO₂ emissions from power generation by making sure that any new facilities or brown-field installations use new clean coal technology (CCTRM, 2005).

The same situation may be true in other Canadian industries. While the thought of applying new technology to existing facilities may appear to be a good option, it is often easier and more economic to focus on any new facilities being built to be CO₂ capture-ready, especially in cases like the oil sands where new infrastructure is being built at an unprecedented rate. This does not imply ignoring the niche opportunities that exist in industry today (such as the hydrogen and fertilizer manufacturing facilities), rather it implies setting some criteria to help prioritize and decide on what opportunities to pursue first.

When prioritizing, it is important to understand the counter-intuitive situation that exists today — the best candidates for CO₂ capture are generally the most efficient plants in operation. Older and inefficient facilities generally emit low CO₂-concentration flue gas streams, thus making capture very difficult. While CCS is seen by some as a means of reducing emissions from the most polluting old fossil fuel plants, a better environmental and economic outcome would result from using CCS in the most up-to-date and modern facilities being built today. Despite the fact that so many emissions come from low concentration sources, these should not be the top priority. Rather, the top priority should be to capture emissions from existing high concentration sources and from any new facilities that are built as the capital stock turns over.

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Capture Technologies

Table 13: The Spectrum of Capture Technologies

Category of Capture	Specific Technologies
Absorption	Physical Absorption
	Chemical Absorption  (amine, hindered amine and inorganic)
Adsorption	Pressure Swing Adsorption
	Temperature Swing Adsorption
	Electric Swing Adsorption
	Vacuum Swing Adsorption
Membranes	Gas Absorption
	Gas Separation
	Water Gas Shift Membrane Reactor
Cryogenics Separation	Compression and Refrigeration

The capture technologies discussed below are broadly classified under the four categories: absorption, adsorption, membranes and cryogenic separation. Table 13 illustrates these and some specific technologies under each category. Many of these technologies have been in use in industrial processes for years. Chemical absorption was developed more than 60 years ago to remove CO₂ from impure natural gas streams. Solvent scrubbing processes are widely used to separate CO₂ in hydrogen and fertilizer plants. Many facilities use solvents to recover pure CO₂ for food processing and chemical manufacturing.

The technology selected for any given capture system depends on many factors which include the partial pressure of the CO₂ in the gas stream, the extent of CO₂ recovery required, the purity of the desired CO₂ product, sensitivities to impurities in the system (such as acid gases and particulates), the cost of additives needed to prevent corrosion (where applicable), capital and operating costs of the process and potential environmental impacts. Because these factors determine the choice of technology used, they are also considered important design principles that must be considered when developing new technology.

Absorption

Both chemical and physical absorption are widely used to separate CO₂ from flue gases in the oil and gas and chemical industries. The process generally involves a repetitive cycle of absorbing CO₂ followed by regenerating it upon removal.

Chemical absorption uses organic or inorganic aqueous solutions to attract the CO₂ and form weakly bonded intermediate compounds. Organic amines are the most commonly used chemical solvents, and different ones are selected based on their reaction rates, equilibrium absorption characteristics, and sensitivities with respect to solvent stability and corrosion factors. The target gas stream also affects appropriate amine selection. The three most commonly used amine groups include primary amines like monoethanol-amine and diglycol-amine, secondary amines like diethanol-amine, di-isopropyl-amine, and tertiary amines like triethanol-amine and methyl-diethanol-amine. Hindered amines are another class of organic amines that typically have an amino group attached to an alkyl group. Inorganic chemical solvents include potassium carbonate, sodium carbonate and aqueous ammonia, with potassium carbonate being the most commonly used. The Benfield process is a solvent scrubbing process that uses hot potassium carbonate as the solvent. The CO₂ is regenerated using a stripping process in which the CO₂-rich chemical solvent is heated to desorb the CO₂ from the chemical solvent.

Physical solvents have been used in ammonia production for years and are ideally suited for CO₂ removal under high vapour pressures. They are considered suitable for pre-combustion systems like IGCC, where the CO₂ partial pressure is quite high as a result of the shift conversion. Physical solvents form a weaker bond to CO₂ than chemical solvent. This is their inherent advantage in that all that is needed to regenerate the CO₂ is a reduction in system pressure or an increase in temperature. Specific physical solvent technologies include cold methanol which is used in the Rectisol process, dimethylether or polyethylene glycol which is used in the Selexol process, propylene carbonate used in the Fluor process, and n-methyl-2pyrollidone. The Rectisol process has been used in the past to treat syngas, hydrogen and town gas streams. A coal gasification plant in North Dakota uses this process to capture 5000 t/d of CO₂, which is then shipped to Weyburn, Saskatchewan, via pipeline for use in EnCana's CO₂-EOR project.

Adsorption

Adsorption is a process of selective separation of gases in a flue stream, which takes advantage of the intermolecular forces that exist between certain gases and the surfaces of solid materials. Adsorption rates depend on factors like temperature, partial pressure, surface forces and adsorbent pore size. The process employed when using adsorption technology is similar to absorption in that a repeat cycle of adsorption is followed by the regeneration of the adsorbed gas.

When using adsorption for CO₂ capture, a flue gas stream is fed onto a bed of solids (often sieves arranged as packed beds or spherical particles) which selectively adsorb the CO₂ while allowing other gases to pass through. When a bed is CO₂-saturated, the feed gas is switched to another clean adsorption bed and the saturated bed undergoes the regeneration process. The switch from adsorption to regeneration is induced by changing the physical parameters in the environment. In pressure swing adsorption (PSA) the CO₂ is regenerated by reducing the system pressure. In temperature swing adsorption (TSA) it is regenerated using a temperature increase. Two variants of adsorption technology under development today include electric swing adsorption (ESA) and vacuum swing adsorption (VSA).

The simplicity of the technology is driving considerable research in this area, and ESA in particular holds the most promise for future compact solid state CO₂ capture technology. In the future, adsorption may play another important role in CCS. Coal's preference to bond with CO₂ instead of methane is the dynamic driving much of the research around CO₂-ECBM recovery.

Membranes

Membranes are basically barrier films that allow for the selective and specific permeation of different gases. Selectivity depends on system parameters and on gas conditions and therefore different membranes are being designed for the variety of roles in capture systems. For example, membranes are being developed to capture CO₂ during the downstream shift conversion in gasification systems. In post-combustion systems, membranes are used to capture CO₂ from low concentration flue gases. Other membranes are being developed for oxygen separation in oxy-fuel systems, such as the ITM technology being developed in the U.S..

Two basic membrane types are being considered for CO₂ capture: gas separation and gas absorption membranes. The first group rely on the variations in physical and/or chemical interactions between different gases and the membrane material, with the intent being one component passing through the membrane faster than another (thus driving the separation process). This technique relies on the diffusivity of gas molecules, and taking advantage of different pressures on either side of the membrane. Various versions of gas separation membranes are available today including ceramic, polymeric and ceramic/polymeric hybrids. The second group, gas absorption membranes, are micro-porous solid membranes which act as contacting devices between gas flow and liquid flow. While flue gases flow on one side of a membrane, an absorptive liquid is used on the other side to selectively attract certain components. In this case, it is the absorption liquid (not the membrane) that drives the selectivity.

Cryogenic Separation

Cryogenics is a science that takes advantage of the critical pressures and temperatures of specific elements and compounds in a mixture. Through careful manipulation of the pressure and temperature (using compression and refrigeration) it is possible to separate specific gases from a mixed gas stream either through liquefaction or distillation.

Cryogenics is commonly used today for the purification of CO₂ in gas streams that already have high CO₂ concentrations (greater than 70 percent CO₂) (Gupta and Pearson, 2005). Cryogenics is advantageous in that it enables the direct production of liquid CO₂, which makes transportation more cost-effective. However, cryogenics is unsuitable for dilute CO₂ streams because of the amount of energy needed, whether for compression or refrigeration. The most promising applications for cryogenics in CCS are in the separation of CO₂ in high partial pressure gases (such as pre-combustion systems), or in oxy-fuel recycle systems where the input gas has a high CO₂ concentration.

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Cost of Capture

The cost to capture CO₂ in Canada depends very much on the industrial application being discussed, and in fact, is generally a function of the CO₂ concentration of the flue gas stream being processed. Benfield (or amine) processes, oxy-fuel capture or pre-combustion capture options (in an IGCC facility) can be the least costly means of CO₂ capture today. Generally speaking, capturing CO₂ from low concentration flue gas streams, such as natural gas combined cycle or pulverized coal combustion facilities is most costly.

It is estimated that most post-combustion capture systems would cost between (CDN) $50 and $70/tCO₂ captured (this includes compression costs) (Thambimuthu, 2004). The cost for pre-combustion ranges anywhere from (CDN) $20 to $50/tCO₂ captured, and the cost for oxy-fuel is anywhere from (CDN) $13 to $80/tCO₂ captured (Thambimuthu, 2004). The current cost of each of these technologies, in actual fact, is probably near the bottom end of these ranges, as the upper ends are somewhat of an artefact of historical cost estimates. The lowest cost opportunities are in the niche applications discussed earlier, the hydrogen and fertilizer facilities where Benfield processes or other technologies are used today. While these cost ranges give an indication as to the best technologies to pursue in terms of capture cost-effectiveness, it is important to remember that it is the overall economics of a project that will ultimately determine the technological choice. In addition, the deployment of cost-effective infrastructure and systems requires large upfront capital investments, which are not necessarily reflected in the previous cost estimates.

The cost of adding capture, transportation and storage to a typical coal-fired power plant in Canada (of which capture would account for the majority of the cost) would result in almost a 50 percent increase in power production costs. If the original cost to produce power were (CDN) ¢4.5/kWh then the cost to produce the same power and capture the emissions would be nearly ¢7/kWh.

In most cases, building a facility to be capture-ready (as described earlier) is a costly endeavour and it would require a significant price signal (for CO₂ emissions) to cause industry to begin building these plants. The prospect of such a price signal plays heavily on the technological choice for new power plants today because with no incentive to reduce GHG emissions, pulverized coal technology is the economic choice. However, in a carbon-constrained world the choice changes, and the IPCC indicates that a price signal of (USD) $25 to 30/tCO₂ may be enough to induce the development and deployment of CCS technology (IPCC, 2005) (note that some cost figures are in U.S. dollars because the source documents report costs in U.S. dollars).

A very important factor to keep in mind is that capture is generally the most costly of the three CCS components but that it also has the most room for cost reductions. Reductions in the order of 25 to 30 percent (with the potential for 50 percent reductions for certain applications) are expected over the next two decades (IPCC, 2005). These reductions can be attributed to the learning effect of working with the capture technology — a phenomenon whereby the unit cost of a technology reduces over time, driven by R&D resulting in new processes, learning-by-doing, efficiency gains in equipment manufacturing, standardization of equipment and economies of scale (IEA, 2004). In immature technology areas, such as CO₂ capture, the learning effect can be very high.

Capture Risks

Technical risk is an important consideration in the cost of any endeavour. Risks associated with CCS are generally characterized as global (those that impact the ultimate objective of global emissions reductions) and local (those that are site specific and often more immediately impact human health, ecosystems or water quality) (IPCC, 2005).

The risks associated with capture tend to be more local in nature, such as catastrophic equipment failure with the release of CO₂ into the local environment. While large concentrations of CO₂ may be damaging, it would require exposure concentrations of CO₂ greater than 7 to 10 percent (by volume of air) to constitute a dangerous level, and the risk posed by such a release is comparable or less than that of other industrial activities, and is considered to be manageable (IPCC, 2005). A CO₂ release is less risky than the release of other flammable or toxic fluids used in other industrial processes. Most CO₂ capture risks can be dealt with using current approaches, and the cost associated with managing such risks are relatively small compared to the cost of capture.

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Capture R&D Needs

A number R&D gaps have been identified for CO₂ capture technology, which lead to a number of critical R&D needs. The following sections summarize these needs for Canadian industry by type of capture system.

Post-combustion

Research and development related to post-combustion systems would include system integration of heat and power requirements for the inclusion of capture in the process cycle. Integrated secondary air pollutant and waste management control technologies for such things as NOx, SOx, mercury and fine particulates are needed. Low-cost solvents are required, with improved stability, and which are corrosion and degradation resistant. Improved contactors and mass transfer systems (such as membranes or membrane/solvent technologies) for large-scale applications of CO₂ capture are needed. Improved solid sorbent technologies are also needed. Moderate temperature and pressure hybrid technologies should also be considered for CO₂ separation.

Pre-combustion

There is a need for modular test facilities for assessing advanced gasification, reformation, carbonation and hydrogen separation processes for Canadian circumstances. The scale of these tests need to be large enough to evaluate advanced capture concepts such that the results can be scaled up to applications at a commercial scale Such test equipment could help study the optimization of gasification systems integrated with CO₂ capture. Such systems will enable the conversion of Canada's abundant bitumen, low rank coals and other solid fuel sources into useful energy.

Specific technological needs include advanced physical solvent contactors that can be scaled-up for commercial capture applications. High-temperature membrane reactors are needed for combined steam reforming (or water-gas shift reactions) and hydrogen separation. Solid sorbent enhanced reaction systems are needed for CO₂ separation and steam reforming. Hybrid systems for CO₂ separation from hydrogen are needed, as are new hydrogen-fired boilers and process heaters. Integrated hot gas clean-up systems are needed for removing impurities such as hydrogen sulphide (H₂S), carbonyl sulphides (COS), hydrogen cyanide (HCN), ammonia (NH₃), particulates, heavy metals and alkali.

A final need is systems integration of capture technologies to pre-combustion facilities with overall process efficiencies in mind, whether it be for steam reforming or partial oxidation of natural gas.

Oxy-fuel

System integration and cycle development is needed for oxy-fuel based combustion of fossil fuels, whether it is in Rankine, Brayton or combined cycles, or whether it is used in fuel cells. This entails a better understanding of the combustion, heat transfer and pollution forming behaviours of pure oxygen, oxy-fuel recycle or hydroxy-fuel recycle combustion.

Specific technological needs include optimized recycle flows in combustors, process heaters and boilers. High-temperature tolerant combustors, process heaters, boilers, compressors and turbo-machinery are needed for oxy-fuel recycle and hydroxyl-fuel recycle, but more importantly for oxygen-rich combustion. There is also a need for oxy-fuel fired process heaters with a common header for CO₂ capture in integrated chemical complexes. Improved cycles and methods are needed for CO₂ compression cooling and separation in the presence of trace concentrations of other impurities. Novel integrated multi-emissions control technology is needed for CO₂, NOx, SOx, mercury and fine particulates.

Improved and lower energy penalty cryogenic air separation processes are needed to supply oxygen for oxy-fuel combustion. Another option is low energy penalty adsorption or low temperature membrane technology for oxygen production. Finally, novel ion (or oxygen) transport membrane technology would be useful for oxygen separation.

Industrial Processes

The understanding of process chemistry for a variety of industrial processes could be improved and provide insight into increasing CO₂ concentrations in industrial flue gases. Further, process modelling and systems integration for CO₂ capture would be useful. In particular, such modelling and integration in oil refineries, oil sands operations and petrochemical manufacturing would be beneficial for Canadian industry.

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