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Capturing CO2 that would otherwise be emitted to the atmosphere, treating it and compressing it to the point where it can be transported, in most cases represents the greatest component of the additional costs of CCS. This section outlines the current status of development of the various capture technologies and techniques, across the different industries in which CCS can be applied. Further details can be found in a study commissioned for this report by the Electric Power Research Institute (EPRI 2011a) as well as a series of studies produced by the United Nations Industrial Development Organization (UNIDO 2010a, b, c, 2011) as part of a project sponsored by the Institute and the Norwegian Ministry of Petroleum and Energy.
Major technology options for CO2 capture
The main technology options for CO2 capture from fossil fuel usage are:
- post-combustion capture (PCC) from combustion flue gas;
- pre-combustion capture from fuel gases; and
- oxyfuel combustion – the direct combustion of fuel with oxygen.
These three approaches are shown for coal-based power systems in Figure 21.
Figure 21 Technical options for CO2 capture from coal-power plants. Source: EPRI (2011a, p1-1)
PCC can be applied to newly designed fossil fuel power plants, or retrofitted to existing plants. Absorption processes are currently the most advanced of the PCC technologies. The PCC technologies can also be used in other industries including cement, oil refining, and petrochemicals.
Pre-combustion capture in IGCC power plants comprises gasification of the fuel with oxygen or air under high pressure, followed by CO2 removal using an acid gas removal (AGR) process. The resulting hydrogen rich synthesis gas (syngas) is supplied to a gas turbine power block. The pre-combustion capture of CO2 using AGR processes is also practised commercially in oil, gas and chemicals plants.
Oxyfuel combustion is the combustion of fuel with oxygen, instead of air, to eliminate the nitrogen contained in combustion air. The flue gas containing mostly CO2 is cleaned, dried and compressed. In a coal-fired oxyfuel power plant some flue gas is recycled to use in the oxygen-fired boiler, effectively replacing nitrogen from air to keep the temperature at a level acceptable for boiler tube materials.
Within each of the three major capture categories there are multiple pathways using different technologies which may find particular application more favourably in certain climate conditions, locations and fuel types.
Technology readiness level
In this section the term Technology Readiness Level (TRL) will be used to indicate the development level of the technologies described (WorleyParsons et al. 2009). This TRL approach can be particularly useful in tracking the status of individual technologies in the earlier stages of the R&D timeline. The nine TRLs are listed in Table 4.
Table 4 Technology Readiness Levels (TRLs)
|TRL-9||Full-Scale Commercial Deployment|
|TRL-8||Sub-Scale Commercial Demonstration Plant (>25 per cent commercial-scale)|
|TRL-7||Pilot Plant (>5 per cent commercial-scale)|
|TRL-6||Process development unit (0.1-5 per cent of full-scale)|
|TRL-5||Component Validation in relevant environment|
|TRL-4||Laboratory Component Testing|
|TRL-3||Analytical, ‘Proof of Concept’|
|TRL-1||Basic Principles Observed|
The achievement of a given TRL will inform process developers and organisations of the resources required to achieve the next level of readiness. An achievement of TRL-9 indicates that the first successful operation at a scale normally associated with commercial deployment has been achieved. Progressively higher technical and financial risks are required to achieve the TRLs up to and including TRL-9.
It is important to note that the description in TRL-9 of ‘commercial deployment’ refers to the physical scale of deployment (that is, at the scale required in a commercial application). Thus, a technology may reach TRL-9 and be technically mature and still not meet project economic requirements in existing markets. The TRL system does not address the commercial or economic feasibility of deploying the technology (EPRI 2011a).
In this context the TRL classification is not intended to express overall project development risk. This is project specific and progress on first-of-a-kind projects may be influenced by the extent to which sophisticated project proponents have gained confidence in technology components and their ability to integrate these into a viable process. This may mean the project proponent may select a particular technology component with a lower TRL if the project specific business case is better than an alternative technology component with a higher TRL.
Figure 22 summarises the current technical readiness of some of the main capture technologies.
Figure 22 Summary of TRL for capture technologies. Source: EPRI (2011a)
In recent years, ‘full-scale’ coal-fired power plants purchased by utilities have a new capacity exceeding 400MWe and mostly greater than 600MWe. For the purposes of a TRL assessment of advanced coal technology, it is suggested that TRL-9 would be achieved by a power plant in the capacity range 400 to 800MW(net). By this metric, successful operation of Kemper County air blown IGCC with capture (582MW) would achieve TRL-9 for this particular technology, while Boundary Dam (110MWe) using amine based PCC and FutureGen 2.0 (200MWe) using oxy-firing would achieve TRL-8 for these technologies.
These TRLs for carbon capture generally indicate the technologies are in the late development and early demonstration stage overall in relation to power generation, with some applications more advanced than this. By contrast, there is no TRL ranking available for renewable technology. However, an assessment of technology deployment by EPRI indicates that, by way of example, some solar technologies using molten salt are in the late development phase, while concentrating photovoltaics are in the early demonstration phase. Onshore wind (less than 3MW capacity) is a mature technology while large-scale offshore wind technologies using fixed foundations in greater than 30 metres water depth are also in the demonstration phase. Large-scale floating platform offshore wind systems are in very early development.
In natural gas or chemical processing, carbon capture is a mature technology. This maturity is reflected in the number of active industrial projects in the Execute or Operate stage (Figure 23). The less mature status of capture technologies when applied to the power sector is evident, with most projects in the planning stages (Identify, Evaluate or Define).
Figure 23 Applications of capture technologies to LSIPs
Projects in the natural gas or chemical processing industries produce a relatively pure CO2 by-product stream suitable for storage, while power projects carry the significant additional costs of installing capture equipment for separation of CO2 from the combustion gases or synthesis gas.
For power generation no single CO2 capture technology outperforms available alternate capture processes in terms of cost and performance (Finkenrath 2011). The range of applications worldwide, be it for new build or retrofit, for the many types of coal and natural gas fuels, combined with the local geographical, business, commercial, public acceptability and regulatory conditions means that all three methods, appropriately integrated into power generation plants will ultimately be required.
Power sector PCC applications
In the case of coal-based power, a typical PCC process is shown in Figure 24. Coal is combusted in air and the liberated heat is converted to electricity by steam-driven turbines connected to generators. The combustion results in a flue gas mixture which is treated using existing pollution control technologies to reduce or eliminate oxides of nitrogen and sulphur, and ash. A PCC process then aims to selectively separate CO2 from the remaining gas mixture, which can be done at relatively low concentrations, in the range five to 15 per cent. PCC has the advantage in that it can be retrofitted to existing plants, where its end-of-pipe nature provides the potential flexibility to operate without capture if required by market conditions.
Figure 24 Typical post-combustion capture process for power generation. Source: EPRI (2011a, p2-1)
The three main PCC processes are:
- Absorption: the uptake of CO2 into the bulk phase of another material, for example dissolving CO2 molecules into a liquid solution. Virtually all near-term and mid-term PCC processes under development are absorption based.
- Adsorption: the selective uptake of CO2 molecules onto a solid surface. The adsorbent selectively adsorbs CO2 from the flue gas, and is then regenerated by lowering pressure and/or increasing temperature to liberate the adsorbed CO2. A claimed advantage of adsorption is that the regeneration energy should be lower relative to absorption solvents.
- Membranes: the separation of CO2 from flue gas by selectively permeating it through the membrane material. Like adsorbents, membranes are claimed to potentially offer low energy capture processes.
There are currently no LSIPs operational in the power sector utilising PCC technology, although Boundary Dam with PCC is under construction, with planned operation in 2014. While there are no others under construction at this scale there are 16 PCC power projects in the planning stages (Appendix C).
PCC technologies for power generation are derived from commonly available amine absorption processes which are currently at a relatively small scale. Considerable re-engineering and scale-up is needed to apply these commercially. Technologies that can be considered near-term, all utilising the absorption process, have been tested at scale on slipstreams no larger than five to 25MWe from coal-fired power plants.
Adsorbent and membrane technologies promise improved energy consumption, but these are in the earlier phases of development (Figure 25). Adsorption processes for PCC are still in the small-scale kW range of demonstration while little data exists on membrane systems for PCC, for which testing has been conducted at scales less than one tonne per day with results that are not yet publicly available (Freeman and Rhudy 2007; Bhown and Freeman 2008, 2009, 2010).
Figure 25 Post-combustion capture TRL rankings. Source: Data from Freeman and Rhudy (2007) and Bhown and Freeman (2008, 2009, 2010)
The major challenges in PCC and much of the R&D trends revolve around the relatively large parasitic load CCS imposes on a power plant, mainly due to capture and compression. Hence, development of new solvent chemistry, new process designs, and novel power plant integration schemes are largely aimed at reducing the parasitic load of CCS. Early-stage research is also being conducted into more novel chemistries (EPRI 2011a).
Figure 26, incorporating data from EPRI, shows the potential to improve the energy demand from PCC technologies for a new build 595°C power plant using Powder River Basin (PRB) coal with various improvements in solvent regeneration energies of an aqueous amine solvent (Dillon et al. 2010). The final bar shows that increasing the steam temperature to 705°C with an advanced amine solvent increases the net plant efficiency.
Figure 26 Projected performance of post-combustion capture technologies. Source: Dillon et al. (2010) as cited in EPRI (2011a, p4-13)
Efficient integration of PCC into existing power plants to effectively utilise waste heat is a high priority if retrofit is to be viable for older plants. Recent studies show that even for lower efficiency power plants the opportunity exists to significantly reduce parasitic energy use, because the capture process provides a sink for low temperature waste heat which was uneconomic to recover in a power plant without capture. Such modifications utilise existing heat exchange technology and in fact could be applied in near-term demonstration scale projects (Harkin et al. 2010).
There are also process operational challenges. Steam extraction for solvent regeneration reduces flow to the low-pressure turbine with significant power-plant production and operational impact. In addition, water use is increased significantly with the addition of PCC, particularly for water cooled plants. These situations will improve as the energy efficiency of capture improves.
The IEA Greenhouse Gas R&D Programme (IEAGHG) has identified the need to better understand the environmental impact of emissions from PCC. Some absorption based PCC processes use organic bases, amines, in an aqueous solution which react with CO2 present in the flue gas. It is recognised that certain flue gas components form by-products which result in a loss of absorbent and an increase in operating costs. Pre-treatment of the flue gas can limit the absorbent losses. In Europe, it is now recognised that atmospheric emissions from amine based PCC processes must be fully understood and quantified as part of PCC deployment on a large scale, signalling the need for increased research in this area.
For oil refineries, the two most developed technologies likely to be used for emissions reduction from process heaters (and utility boilers) are PCC and oxyfuel combustion. There has been limited development recently regarding PCC in oil refinery applications. In one scenario the 196000 barrel a day Grangemouth refinery in Scotland studied capture of the CO2 emissions from the fired heaters and boilers on the site (UNIDO 2010a).
PCC in cement manufacture is an ‘end-of-pipe’ option that would not require fundamental changes in the clinker-burning process and so could be available for new kilns and in particular for retrofits to existing plants. In addition to absorption and membrane technologies, another area of promise in cement is carbonate which is an adsorption process in which calcium oxide is put into contact with the combustion gas containing CO2 to produce calcium carbonate from which the CO2 is then released to yield calcium oxide, hence closing the loop. This is a technology currently being assessed by the cement industry as a potential retrofit option for existing kilns and in the development of new oxy-firing kilns.
It is understood that pilot projects are being discussed within the cement industry but there have been few public announcements. Research on CCS within the cement sector is still at an early stage, with these activities focused on both post-combustion and oxyfuel combustion capture technologies (UNIDO 2010b).
Pre-combustion capture has application for power generation, oil, gas and chemicals and where not otherwise noted this section references Booras (2011).
Current commercially available pre-combustion CO2 capture processes are based on the use of solvents. There are two major generic types of CO2 removal solvents for pre-combustion capture – chemical and physical. Typically all the solvents can accomplish greater than 90 per cent CO2 removal. Pre-combustion capture of the CO2 under pressure incurs less of an energy penalty (around 20 per cent) than current PCC technology (around 30 per cent) at 90 per cent CO2 capture.
Pre-Combustion Capture Applications
CO2 capture from oil, gas and chemical industries
The oil, gas and chemical industries have been separating CO2 from gas streams for decades at commercial scale. Many of the world’s sources of natural gas contain CO2. In most cases the CO2 must be removed to meet the purity requirements of the gas customers.
Steam methane reforming, autothermal reforming and partial oxidation (with oxygen) are widely used commercially for the production of hydrogen and chemicals such as ammonia and methanol from natural gas, refinery gas, propane, butanes or naphtha. The CO2 can be removed by using commercially available pre-combustion capture solvent processes.
The gasification of coal, petroleum coke and heavy oils with oxygen is in widespread commercial use for the production of chemicals such as ammonia, urea, methanol, dimethyl ether, SNG, gasoline and other transportation fuels. CO2 removal from coal gasification derived synthesis gas (syngas) is a mature commercial process widely practised throughout the world. Again, the CO2 can be removed by using commercially available pre-combustion capture solvent processes.
CO2 capture from IGCC power plants
An IGCC plant is a facility which gasifies carbonaceous material (fossil or biomass or both) to produce a syngas which is sent to a combined cycle gas turbine to generate electricity. The gasification and combined cycle sections are integrated with each other to improve thermal efficiency. There are several IGCC plants in operation in several countries but to date none of them has incorporated CO2 capture.
In an IGCC plant CO2 capture is accomplished by chemically modifying the syngas (using a catalytic process known as a ‘shift’ which produces hydrogen and CO2), then removing CO2 using commercially available pre-combustion capture solvent processes. In the event of a need to vent the CO2, additional purification may be needed to remove other associated substances.
If CO2 capture was to be retrofitted to an IGCC plant that did not envisage the future addition of capture there are additional cost and performance penalties over a new built plant with capture. The extent of cost and performance penalties is highly dependent on the gasification technology and the type of syngas treatment deployed.
For an IGCC plant with capture based on current technology the TRL of the major components is listed in Figure 27. While many of the component technologies are considered mature, there is an underlying need to construct and operate at commercial-scale IGCC facilities with carbon capture to demonstrate the host power-generation technology integrated with capture.
Figure 27 TRL of pre-combustion capture components. Source: EPRI (2011a, p3-5)
Pre-combustion CO2 capture – development pathway
The major thrust in research, development and deployment for IGCC designs with capture is to reduce the energy penalty. While the additional capital cost of capture equipment is not insignificant, it is net power output loss that is the most significant economic detriment of capture addition (EPRI 2011a).
EPRI and the United States DOE have identified a roadmap (Schoff 2011) of IGCC technology developments that can potentially improve the IGCC efficiency (with capture) to a level that matches or exceeds that of the current IGCC technology without capture, as illustrated in Figure 28. Other efficiency improvement paths are possible with other combinations of technology enhancements for a range of different IGCC technologies.
Figure 28 IGCC developments to recover energy losses from CO2 capture. Source: Schoff (2011) as cited in EPRI (2011a, p3-11)
Oxyfuel combustion with CO2 capture
In oxyfuel combustion processes, bulk nitrogen is removed from the air before combustion. The resulting combustion products will have CO2 content up to about 90 per cent (dry basis). If regulations and geochemistry permit, the raw, dehydrated flue gas may be stored directly without the need for further purification. Otherwise, the flue gas impurities (predominantly oxygen, nitrogen and argon) may be removed. The added process equipment consists of equipment largely familiar to power plant owners and operators. No chemical operations or significant on-site chemical inventory is required. As a different technology can be used for final clean up, the incremental cost (per tonne) to capture at least 98 per cent CO2 is lower than the incremental cost to capture 90 per cent CO2. Current information indicates that oxyfuel combustion with CO2 capture is at least competitive with pre and post-combustion CO2 capture and may have a slight cost advantage (EPRI 2011a).
Oxyfuel combustion plants will include the following major component systems:
- Air Separation Unit (ASU) – This system separates oxygen from air and supplies the oxygen for combustion;
- Combustion/Heat Transfer/Gas Quality Control system – The components of this system are nearly the same as components for a corresponding air-fired plant; and
- CO2 Purification Unit (CPU) – The CPU will include a flue gas drying sub-system and compressors. If required, it will also include a partial condensation process to purify the product CO2 and remove impurities to specified levels.
In addition, there will be material handling and thermal power utilisation systems, but these are unlikely to differ significantly from their air-fired counterparts. Plot space requirements are significant for the ASU and CPUs.
Oxyfuel combustion may be employed with solid fuels such as coal, petroleum coke, and biomass, as well as liquid and gaseous fuels. Ultra-low emissions of conventional pollutants can be achieved largely as a fortuitous result of the CO2 purification processes selected, and at little or no additional cost.
Oxyfuel combustion applications and status
Oxyfuel process for power generation
A ‘synthetic air’ approach is generally used for oxyfuel combustion processes proposed for steam-electric power plants. In the synthetic air approach, flue gas is recycled and introduced with oxygen in proportions that mimic the combustion and heat transfer properties of air.
The gross power production (turbo-generator output) from an oxy-fired power plant will be essentially the same as a comparable air-fired power plant. However, the oxy-fired plant will have increased auxiliary power use. This will reduce the net power production (by approximately 23 per cent) and decrease net efficiency compared to an air-fired plant with comparable gross output (EPRI 2011a).
The TRL of oxyfuel component technologies is shown in Figure 29.
Figure 29 TRL for oxyfuel combustion components. Source: EPRI (2011a, p4-10)
The greatest remaining technical challenge is integrating these systems into a complete steam-electric power plant. There is an underlying need to construct and operate an oxyfuel power generation facility with carbon capture at commercial scale to demonstrate the host power generation technology integrated with capture.
Two integrated oxyfuel combustion pilot plants (TRL-7) have been operated over the past two years. Vattenfall has operated a dried lignite-fuelled 30MWth pilot plant at their Schwarze Pumpe power plant in Germany since mid-2009 and Total’s Lacq project in France, an oxy-natural gas 30MWth boiler has been in service since early 2010. Two additional facilities will be brought into service in 2011, the CS Energy conversion of a 30MWe pulverised coal power plant to oxyfuel combustion in Queensland, Australia and CIUDEN’s oxy-coal test facility in Spain that includes a 20MWth oxy-pulverised coal (PC) boiler and a 30MWth oxy-Circulating Fluidised Bed (CFB) boiler (EPRI 2011a).
Five larger scale demonstration plants (TRL-8) are in development worldwide. All of these are in the planning/engineering stages and the decision to proceed to construction has yet to be made (Appendix C).
There are currently no full-scale (TRL-9) oxy-fired projects under development.
Oxyfuel process in other industries
Combustion in process heaters accounts for up to 60 per cent of an oil refinery’s CO2 emissions. For an existing refinery, all heaters and boilers on site would be modified for firing with pure oxygen, produced at a central location, and flue gases from the combustion plants would be initially treated at locations local to the stacks (UNIDO 2010a).
Two different options for oxyfuel technology within the cement industry have been proposed (UNIDO 2010b). Partial capture is based on burning fuel in an oxygen/CO2 environment (with flue gas recycling) in the pre-calciner but not in the rotary kiln in order to recover a nearly pure CO2 stream at the end of one of the dual preheaters. Total capture is based on burning fuel in an oxygen/CO2 environment (with flue gas recycling) in both the pre-calciner and the rotary kiln to produce a nearly pure CO2 stream from the whole process.
Laboratory and process development unit activities are underway to achieve TRL-6 in 2011. Construction and operation of an oxyfuel combustion cement manufacture pilot plant is planned in the 2011–2014 time frame, achieving TRL-7 (UNIDO 2010b).
Oxyfuel combustion future direction/challenges
An oxyfuel combustion power plant is an integrated plant and oxyfuel combustion technology development will require commitment of the whole power plant to the technology. Thus, the technology development path for oxyfuel combustion may be more costly than that for either pre-combustion or post-combustion capture which can be developed on slip streams of existing plants.
While retrofit/repowering schemes have been proposed, it has yet to be shown that they can result in an oxy-fired plant that is lower in cost than an optimised, new-build plant. The large fleet of air-fired power plants in service, however, calls for more study of this option.
Future efficiency improvements to the oxyfuel combustion process for power generation include (EPRI 2011b):
- employing an advanced ultra supercritical steam turbine cycle: 680°C/700°C/352 bar (1256°F/1292°F/5100psia), for an approximately 3.5 percentage point improvement;
- gas pressurised oxyfuel combustion – reduction of recycle fan auxiliary power use and improvement of boiler efficiency, approximately 1.4 percentage point improvement; and
- Chemical Looping Combustion for oxygen separation – dramatic reduction of auxiliary power used in air separation, approximately five percentage point improvement.
These data are shown in Figure 30. However, the benefits of both gas pressurised oxyfuel combustion and chemical looping combustion may be difficult to achieve together. Nonetheless, chemical looping combustion combined with an advanced ultra-supercritical steam turbine cycle may well be more than adequate to make up for the added auxiliary power in the CO2 purification unit and recycle fan. This could result in an oxyfuel combustion plant with near zero emissions of conventional pollutants, up to 98 per cent CO2 capture, and efficiency comparable to the best power plants currently being built (EPRI 2011a).
Figure 30 Oxyfuel combustion developments to recover energy losses from CO2 capture. Source: EPRI (2011a, p4-13)
Other industrial CO2 capture
Most industrial CO2 capture can be accomplished using the previously described pre-, post- and oxyfuel approaches to carbon capture.
However, in the case of iron and steel manufacture, and biochemical biomass conversion, the combination of technologies used in these industries does not neatly fit the strict pre-, post- and oxyfuel carbon capture approaches.
Iron and steel manufacture
There is no simple process available off the shelf that can currently accomplish low emissions in the iron and steel industry (UNIDO 2010c).
Three families of process routes involving carbon capture are being investigated for eventual scale-up to a size suitable for commercial implementation:
- A blast furnace variant, where the top gas of the blast furnace goes through CO2 capture, but the remaining reducing gas is reinjected at the base of the reactor, which is operated with pure oxygen rather than air. This has been called the Top Gas Recycling Blast Furnace (TGR-BF). The CO2-rich stream is sent to storage.
- A smelting reduction process based on the combination of a hot cyclone and of a bath smelter called HIsarna, incorporating some of the technology of the HIsmelt process. The process also uses pure oxygen and generates off-gas which is almost ready for storage.
- A direct reduction process, called ULCORED, which produces Direct Reduced Iron in a shaft furnace, either from natural gas or from coal gasification. Off-gas is recycled into the process after CO2 has been captured, which leaves the plant in a concentrated stream and goes to storage (UNIDO 2010c).
In the nearer term, the TGR-BF technology seems the most promising solution, as existing blast furnaces can be retrofitted to the new technology. Where natural gas is available, ULCORED is an attractive option, but requires the construction of purpose-built new technology shaft kilns. For greenfield steel mills, the HIsarna process will also be an option.
The TGR-BF concept has been tested on a large-scale laboratory blast furnace with positive outcomes. For the ULCORED process, a one tonne per hour pilot is planned to be erected in the next few years by Luossavaara-Kiirunavaara Aktiebolag (LKAB) to fully validate the concept. For the HIsarna process, an eight tonne per hour pilot is to be erected and tested in the course of the ULCOS (Ultra Low CO2 Steelmaking) program.
ULCOS has been running in the European Union (EU) since 2004. There are also other programs addressing this challenge. Along with ULCOS, they are part of the CO2 Breakthrough Program, a forum where the various national and regional research and development programs on identifying breakthrough technologies for steel manufacture can exchange information on their projects.
Biochemical biomass conversion
Biochemical biomass conversion processes, for example fermentation, use living microorganisms to break down the feedstock and produce liquid and gaseous fuels. The CO2-rich off-gases from the fermentation tanks are dried and compressed to facilitate transport and storage. However, CO2 capture and storage from biomass-based industrial sources is a mitigation technology that only receives little interest at present. There has been limited recent development regarding capture in biochemical biomass conversion applications (UNIDO 2011).
A common first generation process to produce bio-ethanol is the fermentation of biomass, where a by-product is a relatively pure stream of CO2. The CO2-rich off-gases are dried and compressed to facilitate transport and storage.
One of the first commercially operated ethanol plants integrated with CCS, and thus biomass-based industrial CO2 capture and storage project, started operation at the Arkalon bioethanol plant in Kansas, United States, during the third quarter of 2009 (UNIDO 2011). A similar pilot project in the United States, managed by the MGSC, is expected to start operation in the second half of 2011. From the same CO2 source as MGSC’s injection test project, the larger scale Illinois-ICCS project commenced construction in 2011, with operation expected in 2013.
Pathway to commercial deployment of capture technologies
Important role of demonstration projects
Capture technologies applied in the current first-of-a-kind demonstration projects in the power industry are as yet far from optimal in their performance. However, it is vital that such projects proceed urgently as they will demonstrate CCS on a commercial-scale operating in an integrated mode, in a real power grid environment and with storage at sufficient scale. Importantly, these will provide an understanding of the economics and performance of commercial scale plants in an overall sense, providing the confidence that will be critical for future widespread deployment of the technology.
Optimisation and enhanced integration, combined with technology improvements, will undoubtedly be necessary to reduce cost and improve performance at a system and component basis. Progress at the commercial CCS demonstration scale has a key role to play in indicating the priority areas to be addressed and in providing the confidence for continued investment in R&D for second and third generation technologies.
If multiple CCS demonstrations with improved technologies and performance are to be achieved at large-scale (TRL-9) by 2020 to address scaling uncertainties and allow commercial deployment to proceed at some time after that, then many technologies need to be approaching the pilot-plant stage (TRL-7) today. Applications of CO2 capture in the power sector appear to be receiving enough funding to achieve pilot-plant scale, but advancing to sub-commercial scale demonstrations and larger will require an order of magnitude greater level of funding. There are very few organisations funding demonstrations at one-tenth to full commercial-scale. While this may not currently be constraining the advancement of improved CCS technologies, it soon will (EPRI 2011a).
Each technology has particular implementation hurdles to overcome. Pre-combustion systems are ‘integrated’ by nature and so operational problems in capture could impact on plant performance through lower reliability and availability. Oxyfuel combustion systems also result in an integrated plant with potentially the same issues as pre-combustion systems. There is also a need to improve boiler design/performance and to have lower-cost processes for oxygen production. Although post-combustion capture can be retrofitted, significantly reducing the capital investment at risk, there is a continuing need to reduce cost and the detrimental impact that the technology has on the performance of the plant. These issues mean that PCC’s application to older subcritical plants may not be appropriate due to the current high energy penalty increasing dispatch costs, thus impacting their capacity factor and reducing consequent revenue. However, the ability to retrofit to newly installed plants or to be installed at high-efficiency plants will be a critical aspect in ensuring that assets are not stranded and are able to operate in an increasingly carbon constrained world.
The emphasis in capture from power plants has been on coal but there is an increasing recognition that CCS will have to be applied to natural gas-fired plants as well. The relatively recently identified increase in worldwide gas reserves (exemplified by shale gas) will mean that there will be a greater use of gas and for longer. If the desired levels of atmospheric CO2 are to be achieved by 2050, CCS will have to be applied to gas-fired power plants as well as those using coal.
Importance of improving performance
Cost reductions for all types of capture remain paramount and key technology development actions are increasingly focused on this issue, both for capital and operating costs. The detrimental impact of capture on the performance of a power plant, combined with the high cost issue, remains another key area to be addressed.
The cost per tonne of CO2 avoided for each of the technology types when applied to power generation with coal is shown in Figure 31. The reference plant used for each case is a commercial supercritical PC plant. The fuel component represents the portion of the CO2 abatement cost attributable to the additional fuel charges necessary to operate carbon capture relative to the reference plant. The figure suggests that a focus on reducing energy loss is warranted, with significant potential improvement possible, particularly for PCC. Given the uncertainties involved, at this stage it is difficult to identify any single technology with a clear cost advantage.
Figure 31 Cost of CO2 avoided for capture technologies. Source: Global CCS Institute analysis
The analysis in this section has been focused on CO2 capture technologies and potential improvements to reduce the energy losses and capital costs associated with capture. However, a major contribution to the reduction of CO2 emissions from fossil based plants will be achieved through increases in the efficiency of the basic technologies of pulverised coal combustion and combustion (gas) turbines. Improving this best-available technology in an efficiency sense, be it component and/or system based, will partially offset the energy impact of capture on the performance of the plant, especially if second and third generation capture technologies are also embraced. Optimisation and integration on a component and system level is a key area which will result in improvements in performance.
For all technologies, there is an underlying need to construct and operate commercial-scale facilities with carbon capture to demonstrate the host power generation technology integrated with capture.
Within pre-combustion capture, there is a need to improve the CO-shift and CO2-capture with new adsorption media, new catalysts and by optimising process integration.
For post-combustion capture, the emphasis needs to be on improving first generation solvents through catalysts and chemical modifications to improve loading efficiency, solvent loss and environmental impacts. In addition, second generation solvents need developing to combine CO2 and SO2 removal. Longer term third generation capture processes are also needed based upon phase change solvents, ionic liquids and adsorption based developments.
For oxyfuel combustion there is a need for more efficient cycles, such as chemical looping for coal and oxy-cycles for gas turbines, and for a reduction in the energy penalty for oxygen production.
CO2 specifications and the impact of impurities need to be better understood as these affect the magnitude of CCS deployed, especially in a hub concept that brings together CO2 from different sources prior to storage.
Consequently, there are development routes for all the three main types of capture. In addition, the ability to retrofit future generation technologies to an existing highly efficient plant that already has capture incorporated but still has substantial residual life will also need to be understood. This would address the minimisation of ‘stranded assets’ within a power company’s portfolio.
Importance of R&D and pilot scale projects in technology development
Small to medium-sized technology demonstration projects, even if not fully integrated, provide a number of benefits that materially support progress of CCS towards commercialisation. These projects are essential to decrease technical uncertainty with modest investment, but also lay the foundation for building the regional familiarity, skills and capacity necessary for the demonstration and deployment of CCS, including:
- on-the-job learning opportunity for technicians, engineers, scientists and managers;
- testing the legal and regulatory system and familiarising regulators with new technologies;
- testing equipment and boundaries in a way that could not be contemplated at large scale;
- providing opportunities for a real-world working relationship when pursued through an industry partnership;
- comparative assessment of the progress of technology development; and
- opportunity for real community engagement.
There is substantial activity being undertaken globally by research organisations, technology providers and industry to test CCS technology at pilot scale under industrial conditions. These projects face significant financial hurdles. This type of R&D is expensive when compared with laboratory scale activities, due to its scale, operating costs, insurance and legal costs. It requires long-term funding, in the order of five to 10 years, with certainty of cash flows, and provision of contingency allowance. These circumstances are not a neat fit with traditional R&D funding models. Long-term funding support for CCS R&D pilot projects is an essential element for technology commercialisation.
Both demonstration at industrial scale and ongoing R&D focused on improvement of component performance is necessary for successful technology evolution. The early demonstration projects will identify unanticipated construction and operating problems through ‘learning by doing’. For these reasons, they are usually conservative in design. While ‘learning by doing’ can result in improvements over time, it may not provide the significant step changes in cost and performance required to make CO2 capture more economically viable (DOE NETL 2010b). R&D complementary to demonstration programs is essential to promote step changes and manage the complexity and risk with new components so that they can contribute to improved performance in the next generation of large-scale CCS projects.