6.3 Key challenges to large-scale demonstration of capture

Commercial-scale demonstration of capture requires demonstration of capture technologies at increasing TRLs, up to a level of 9, and then integrating that capture technology into a power station. Beyond this, the challenges associated with capture technologies are predominantly commercial. Reducing the costs of capture will require ongoing innovation through the development of new capture technologies and developing systems for integrating capture plants into a power plant.


The 2012 project survey of LSIPs has highlighted that only two projects moved to the Execute stage since the 2011 project survey. This slow progress of projects reaching FID and commencing construction can have a negative impact on continued investment in RD&D for second and third-generation capture technologies.

Optimisation and enhanced integration, combined with technology improvements, will undoubtedly be necessary to reduce cost and improve performance on a system and component basis. Progress at the commercial CCS demonstration scale has a key role in indicating the priority areas to be addressed and in providing the confidence and drivers for continued investment in RD&D for second and third generation technologies.

For all technologies, there is an underlying need to construct and operate commercial-scale facilities with carbon capture to demonstrate the host power generation or host industrial technology integrated with the capture. This will allow industry to become familiar with the technology and gain confidence that commercial-scale capture is achievable.


Improvements in the cost of capture are required and this will require ongoing research and development focused on improving component performance and developing new capture processes (e.g. improved membranes, TRL-4+).

Progress of CO2 capture in the power sector is currently aimed at achieving process development at the unit scale. Advancing to pilot and sub-commercial scale demonstrations (and larger) will be slow and will require an order of magnitude greater level of funding.

Furthermore, the early commercial-scale demonstration projects will inevitably identify unexpected construction and operating problems (through ‘learning by doing’). However, such learning by doing may not lead to the significant changes in cost and performance required to make CO2 capture more economically viable (NETL 2010). RD&D at smaller scale (TRL-4 and 5), which is complementary to demonstration programs, is essential to promote step changes in performance/operability and manage the complexity and risk with new components; only in this way can they contribute to improved performance in the next generation of commercial-scale CCS projects.

Ongoing support to develop new technologies and to develop these technologies to pilot and demonstration scale is required to achieve the desired large cuts in capture costs.


Southern Company operates the National Carbon Capture Center (NCCC) which is located near Wilsonville, Alabama, in the US (Figure 55). The NCCC, majority funded by the US DOE, is located adjacent to the Plant Gaston pulverised coal power plant which has a KBR Transport Reactor designed to operate as either a 2 t p/h coal gasifier or combustor in either air-blown or oxygen-blown operating modes (NETL 2008b).

The facility is a highly flexible test centre for pre- and post-combustion capture technologies where developers evaluate pre-commercial innovative system components in an integrated process at commercially relevant process conditions involving real process streams sourced from large-scale power plants and related processes. ‘Test-bays’ with all services (such as steam, water, purge gases, and power) to support technologies for testing have also been developed so as to reduce the costs for technology developers to test their technologies at process development unit scale. The facility is large enough to produce commercially representative data while remaining sufficiently small for economic operation.

The US DOE maintains a database of approximately 300 promising technologies (at required TRL) as candidates for testing at NCCCNCCC is also a neutral test site for carbon capture (it does not hold onto IP for carbon capture if it arises during technology development testing). Such hosting facilities are essential to minimise costs for technology development and scale-up.

FIGURE 55 Test facility for amine solvents at NCCC

Photo courtesy of Southern Company.


Project integration is a key challenge for CCSA large proportion of proposed industrial-scale projects include power-related projects that extend the scope of project integration. These project proponents may or may not have experience or expertise in all of that scope, particularly the storage components.

In a workshop in November 2011 held by the Global CCS Institute and the CSLF, it was highlighted that the focus of the first large-scale CCS demonstration plants in the power sector should be on ‘making CCS work at scale’ and that real innovation and integration was something for next-of-a-kind projects. In such projects, integration and experience could drive down the costs of CCS, but for now it is important to strike the right balance between plant operation and integration. In particular, CCS industry experts identified that more work is needed in the following areas:

  • integration/regeneration of plant heat (and cooling) in the CO2 capture process;
  • integration of environmental control systems (SOx, NOx, and CO2 removal) to maximise efficiency;
  • improvement of options for operational flexibility, while ensuring CCS system reliability;
  • impacts of CO2 compositions and impurities for CCS operations (in particular for transportation systems); and
  • understanding the scale-up risks of CO2 capture processes.

It was also emphasised that one of the keys to successful project integration is to facilitate effective collaboration and communication between the various entities involved in the project. Identifying the project team and ‘getting them all in the same tent’ is key for successful project integration. In the case of oxyfuel technology, for example, the industrial gas companies and the power companies have different design philosophies that need to come together in a project.

It is expected that flexible operation of coal-fired power plants with CO2 capture will be required in many electricity systems; however, current knowledge in public literature is limited.

It is very likely that different CO2 capture technologies will have different impacts on plant performance, and there is a trade-off between flexibility, costs, and efficiency (IEAGHG 2012b). CCS may impose additional constraints on the flexible operation of power plants, but in general there are ways of overcoming these limitations. There are some instances when a plant with CO2 capture may be able to ramp up its net power output more quickly and produce more peak generation than a plant without capture (IEAGHG 2012b).

Post-combustion capture with aqueous solvents can be undertaken, with relatively few changes, to an industry-standard pulverised coal fired power plant with air combustion. The majority of integration modifications required for post-combustion capture involve integration with the turbine part of the power station. Current demonstration projects have been designed to demonstrate capture, and only a secondary focus has been on efficiency. During start-up, the CO2 absorber could be operated using lean solvent from a storage tank, and the CO2-rich solvent from the absorber would be stored and fed to the regenerator later. This would enable a natural gas combined cycle or pulverised coal fired power plant with CO2 capture to start up and change load as quickly as a plant without capture (IEAGHG 2012b). The practicality of CO2 solvent storage has been discussed with some leading technology suppliers, with these companies all confirming the technical feasibility of storing solvent (IEAGHG 2012b). The solvent storage tanks are conventional sized tanks as used at oil refineries, but they are nevertheless large (IEAGHG 2012b). Plants could be built with a wide range of storage volumes, solvent regenerator sizes, and peak power generation capacities; selecting the optimum would be a difficult commercial decision (IEAGHG 2012b).

Southern Company and MHI are now undertaking operating flexibility (plant-ramping) trials at Plant Barry in Alabama, US. These studies will provide design and dynamic modelling information necessary to design the next generation of larger scale carbon capture plants; these will be capable of flexible commercial-scale operation and meet dynamic performance requirements for power generation (Southern Company 2012).

An important operating option for oxyfuel power plants could be storage of oxygen in liquid or gaseous form. This interim storage option could be important in improving plant ramp rates by adding to oxygen production rates (higher than those possible with only an air separation unit), (Chalmers 2010). Liquid oxygen storage would typically be included for a safe change-over from oxygen to air firing, and in the case of an air separation unit trip, no additional liquid oxygen storage would be needed to satisfy the ramp rate. From an economic perspective this is expected to be a relatively attractive option for short-term peak power generation (IEAGHG 2012b).

The flexibility of IGCC plants without capture is relatively poor. Hence, the addition of capture is not expected to reduce the flexibility. It seems likely that the most practical options for providing operating flexibility at these plants will involve interim storage of hydrogen (or syngas in cases where CO2 capture is not used). It is expected that increased integration could improve efficiency, but would reduce flexibility (Chalmers 2010).

Compressed CO2 could be stored at capture plants to reduce the variability of flows of CO2 to transport and storage (if this is found to be necessary). Buffer storage of CO2 would enable a smaller capacity CO2 pipeline to be built, but this would constrain the ability of the power plant to operate at continuous full load, which may not be commercially attractive (IEAGHG 2012b).

While the current focus is on demonstrating capture, more practical project experience is required to integrate capture and power generation. This experience will lead to the development of more efficient systems by investigating ways where capture and power generation can operate more flexibly and more efficiently (in line with the operational requirements of the power plant).


To reduce CO2 emissions from existing and new power plants, amine-based post-combustion capture technology is considered a crucial part of the CCS chain. The use of amine-based solvents is the most advanced of the post-combustion options, and it is therefore well positioned for use in demonstration projects and future commercial plants.

However, the amine-based liquid absorbents used in these processes degrade slowly. As a result of side reactions between the amine and components present in the flue gas components, a wide range of reaction by-products are formed. At present, the knowledge about the type and level of components being emitted by the post-combustion process is limited. In recent years, concerns have been raised about the nature of the emissions, either on their own or following chemical reaction in the atmosphere (Mitch 2002).

Additionally, technology providers are developing improved amines for post-combustion capture application. These technology providers are seeking to protect their intellectual property by keeping their improved amine formulations confidential. This conflicts with the regulatory approvals process for carbon capture systems in many jurisdictions, which require the nature of emissions from post-combustion capture systems (as well as the composition of post-combustion capture solvents) to be released into the public domain.

As post-combustion capture moves towards large-scale demonstration, this topic has received considerable attention (especially in Europe and Norway). Although academic studies are increasing, there is a considerable lack of validated information in the public domain, especially that involving IP-protected improved amines. This knowledge gap constitutes a potential deployment risk to amine-based post-combustion capture CCS.

In order to assist regulators in the regulatory approval of amine-based post-combustion capture projects (including those using IP-protected amine solvents), the Global CCS Institute and Australia’s Commonwealth Scientific Industrial Research Organisation (CSIRO) are undertaking a site-based peer-reviewed amine solvent post-combustion carbon capture case study – using results from the Loy Yang Power Station in Victoria – to assist in the development of a regulatory framework or standard and in development of best practices using a well described amine-based post-combustion capture process.


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 renewed focus on unconventional gas, such as coal seam gas and shale gas, will mean that there will be a greater use of gas, and for longer. This has two implications for CO2 emissions. Firstly, more gas processing plants will be constructed producing high CO2 flue gases, and secondly more gas turbines will be built for power generation. Capture from gas turbines has not received much attention due to the low concentration of CO2 in the flue gases when using natural gas. Nevertheless, 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.

In a recent report on carbon capture from gas-fired power generation, it was established that adding post-combustion capture reduces the thermal efficiency of a natural gas combined cycle plant by 7–8 per cent, increases the capital cost by about 80–120 per cent, and increases the cost of electricity by about 30–40 per cent (IEAGHG 2012a).

Recycling part of the cooled flue gas to the gas turbine compressor inlet would increase the CO2 concentration in the feed to the CO2 capture unit, which could increase the thermal efficiency by about 0.3 per cent and reduce the cost of electricity by up to 8 per cent. IEAGHG has acknowledged that this study could be extended to assess a combination of high-efficiency proprietary solvents and flue gas recycling (IEAGHG 2012a).