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Bechtel National (Reston, VA) have undertaken a FEED study for retrofitting a 2x2x1 natural gas-fired gas turbine combined cycle power plant with post-combustion carbon capture (PCC) for CO2 storage/utilization. The comprehensive programme of work covers the integration of the retrofitted carbon capture and compression plant to the combined cycle power plant, together with the detailed design of an amine-based conventional absorber-stripper scrubbing system with a non-proprietary solvent, 35% w/w MEA. Supporting studies have analysed options for single- and two-stage thermal reclaiming and also examined discrepancies between process modelling packages and the possible scope for alternative trade-offs between capital and operating costs. Given that modelling alone cannot predict commercially-important factors such as solvent management costs a long-term pilot test programme is strongly recommended, with outline details supplied for pilot size and the testing period.

The UK Carbon Capture and Storage Research Centre co-ordinates a programme of research covering all aspects of CCS in support of basic science and UK government efforts on energy and climate change. This paper will present progress and ‘lessons learned’ from the Centre's activities, with a particular focus on the development and use of pilot scale facilities and encouraging industrial and other stakeholder engagement in research. It will also highlight key features of an extensive programme of international engagement activities undertaken by the Centre, identifying added value for both the UK CCS community and global development of CCS.

With the introduction of more and more renewables into the electricity system, pressure is mounting on the thermal power plants to operate in more flexible ways. In order to capture maximum emissions at the lowest cost, capture plants integrated with the power plants has to follow the operational regimes of the parent power plant. Therefore, capture plants has to be flexible enough to deal with the load variations on the power plants to meat grid demands.\ud \ud \ud A test campaign has been carried out at the PACT 1tpd CO2 capture pilot plant to investigate capture plant flexibility in relation to power plant load variations. Monoethanolamine (40 wt.%) solvent was used to capture CO2 from gas turbine representative flue gases containing around 5% CO2. Pressurised Hot Water (PHW) is used to regenerate the solvent in the reboiler. Four Capture plant flexibility scenarios i.e. start-up, minimum stable generation, no-stripping and over-stripping, are investigated. No-stripping tests were performed to mimic the unavailability of steam for stripping over varied periods of time by stopping PHW flow to the reboiler. The results indicate that Specific Reboiler Duty (SRD) increased by 8.7 % when the PHW stoppage time was 30 min.. Longer the PHW stoppage time, the longer it takes to recover the capture plant to the original steady state and higher the difference between the steady state capture efficiency and the average capture efficiency over the test period.\ud \ud \ud For over-stripping tests, stripper pressure was reduced to 0.4 barg from the original value of 0.5 barg for a varied period of time followed by no-stripping. It was observed that longer the over-stripping period, longer the recovery time. The results indicates that SRD increased by 36 % when the over-stripping time was increased to an hour.\ud \ud \ud In conclusion, it is possible to maintain 90 % overall capture efficiency, if the solvent is over-stripped for a long enough period, but reboiler duty will be increased. Optimisation of the capture process under these scenarios would be required in order to achieve a commercially-optimised balance i.e. minimum increase in SRD costs while achieving a capture efficiency that also minimises CO2 emission costs.

Post combustion CO2 capture using amines is one of the most well understood processes. The most widely used and studied solvent for this purpose is 30 % Monoethanolamine (MEA). The main issue with the process is the use of energy for stripping CO2 out of the solvent. It is anticipated that higher concentrations of MEA can capture a higher amount of CO2 and thus reduce energy consumption but may also result in a worsening of the environmental emissions due to potential increase in corrosion and solvent degradation. In order to study the impact of 40 % MEA (as opposed to 30 % MEA) on the capture plant performance, a test campaign was carried out at the Pilot Scale Advanced Capture Technology (PACT) facilities of the UK Carbon Capture and Storage Research Centre (UKCCSRC) using 30 % and 40 % MEA. The absorber (9 m height ×0.3 m dia.) is packed with 28 sections (6.5 m) of Mellapak CC3 structured packing. The absorption column temperature profile is measured by 10 RTDs installed around 48 cm apart along the column length. The performance of the capture plant in terms of reboiler duty, capture efficiency, loading capacity and liquid to gas ratio is evaluated at different operating conditions. It has been found that specific reboiler duty using 40 % MEA drops by up to 14 % as compared to that with 30 % MEA under similar test conditions. It has also been observed that the process is very sensitive to reboiler temperature and slight changes in reboiler temperature can have a significant impact on the plant performance. Moreover, similar energy and capture performance can be achieved at different reboiler temperatures with right combination of temperature and pressure in the reboiler/stripper. Corrosion rate was found to be higher with 40 % MEA than 30 % MEA. Solvent degradation rate and solvent carry over has also indicated slightly higher levels for 40 %. Water wash was shown to be effective in recovering most of the MEA from the flue gas.

Combustion of individual particles of different woody and agricultural residue biomass have been studied under a laboratory scale rapid-heating apparatus. Particles used were in the size range of 300–1400 mm and weight 0.5–7 mg. A wire mesh element is used to radiatively heat the particle to 1200–1400 K. The apparatus allows a high-speed camera to record the combustion of the individual particles directly. Examination of the resulting video images showed a sequential combustion of volatile matter followed by burn-out of the remaining char for all fuels. Analysis identified differences and patterns in burnout time, combustion behavior and the evolution of char size and shape transformations. Heterogeneous behavior was observed between the different biomass samples and also among particles within some of the samples. Particles with initial prolate (fibrous) shapes have been observed to become more equant (quasi-spherical) during combustion. Measurement of the particle dimensions during its combustion extracted from the images of the high speed recording have allowed evaluation of the size and shape changes to be mapped. Particle size and shape appears to change only slightly during devolatilization and swelling was rarely observed. Following devolatilization, during the remaining char combustion, more pronounced changes in the size and shape of the particle are apparent. In most cases the shrinking char becomes more rounded as the char particle partially melts and contracts due to surface tension. This transformation is more distinct in some of the biomass samples. Profiles and images of the different fuels examined are presented.

A number of commercial-scale projects are currently progressing towards final investment decisions and several studies continue to report that substantial, global deployment of CCS can be expected by the 2050. As CCS technology moves towards widespread commercial-scale deployment, developing ‘fit for purpose’ research capacity that is able to effectively support the development of CCS technology and policy is a significant challenge. A number of exciting opportunities are available to help meet this challenge though. For example, national centres such as the UK CCS Research Centre (UKCCSRC) aim to effectively accelerate capacity building and also ensure that there are excellent opportunities for CCS researchers and practitioners to share their learnings and identify next steps for CCS development. The UKCCSRC was established in spring 2012 with initial core funding provided by £10 M from the Engineering and Physical Sciences Research Council (EPSRC) as part of the Research Councils UK Energy Programme and £2.5 M in match funding from Centre partners. This is complemented by £3.3 M in additional funding from the UK Department of Energy and Climate Change (DECC) to establish new capital facilities that will support innovative research. The Centre is ‘virtual’ providing strong links between around 250 academic researchers based at over 40 UK universities and research institutes and also linking them with over 100 industry and other stakeholder Associate members. In addition there are over 200 Early Career Researchers (ECRs). The UKCCSRC also operates the CCS Community Network, which is a collective of over 500 engineering, technological, natural, environmental, social and economic members with CCS interests. The Network facilitates knowledge exchange on all aspects of CCS R&D and aims to be accessible to anyone interested in contributing to research and innovation in CCS. The UKCCSRC has developed approaches that will allow it to meet the key strategic challenge of understanding ‘real world’ CCS deployment issues, so that the future impact of ongoing research and human and infrastructure capacity development in CCS can be maximised, as much as possible in advance of full-chain CCS deployment and certainly following on rapidly afterwards.

This work considers the potential value in the additional flexibility of CCS post-combustion power plants gained by varying the operating CO2 capture level. The continuous relationship between CO2 capture level and the specific electricity output penalty is illustrated, and a new methodology is proposed for maximising net plant income through optimising the operating capture level. This methodology allows the plant to respond to electricity prices, fuel prices, and carbon reduction incentives including CO2 prices and premium payments for low carbon electricity. The implications for flexible operation under different market scenarios are qualified, and the indicative value to plant operators is determined.

A techno-economic analysis of a natural gas combined cycle (NGCC) integrated with MEA-based CO 2 capture with an advanced configuration is carried out. Sequential supplementary firing in the Heat Recovery Steam Generator (HRSG) is combined with a supercritical combined cycle for the purpose of increasing CO 2 production for Enhanced Oil Recovery (EOR) at a competitive levelised cost of electricity. Supercritical steam conditions with a double reheat in the steam cycle are used to largely improve performance and take full advantage of sequential supplementary firing in the HRSG. Sequential supplementary firing increases the flue gas temperature throughout the Heat Recovery Steam Generator (HRSG) by burning additional fuel at different stages to maximise the use of oxygen available in the flue gas exiting the gas turbine. The positive impact on the post combustion capture plant size and energy requirements for solvent regeneration are attractive for markets with cheap natural gas, and where the emphasis on capital cost reduction is important. This study then investigates the effect of fuel prices and capital costs for this configuration and compares it with a typical combined cycle integrated with MEA-based CO 2 capture. A case study for Mexico is presented, at a range of gas prices where these modifications would be attractive, with a tentative target of $40/tCO 2 .

The inherent nature of electricity necessitates a permanent balance between generation and demand in electricity systems. This has obvious implications for the operation of CCS power plants in decarbonised electricity systems with inflexible nuclear and variable renewable supply. The low variable costs of nuclear and some intermittent renewable technology allow them to run as base-load generators and shift fossil fuel plants from base-load to midmerit plants. CCS power plants can be expected to increasingly operate in ways to balance variations, sometimes simultaneously, in the production of some intermittent renewable technologies and variations in electricity demand, resulting in more frequent ramping and start/stop cycles. As a result, they may also operate over a wide output range to maintain the quality and security of electricity supply by providing ancillary services, e.g. capacity and energy reserve, to the electricity network. This work characterises the operating envelope, the performance and the corresponding compressed CO2 flow of coal power plants for a range of loads, with or without voluntary by-pass of the capture unit. Optimised part-load operating strategies provide novel insights into the additional capabilities of CCS power plants specifically designed for enhanced operating flexibility.

It is likely that a significant number of existing pulverised coal-fired power plants will be retrofitted with post-combustion capture as part of a global rollout of carbon capture and storage. Previous studies have demonstrated that the energy penalty for post-combustion carbon dioxide (CO2) capture can be greatly minimised by effective integration of the capture system with the power cycle. Nevertheless, the power output of the site is, in most cases, reduced and the volume of electricity sales would drop. For other plants, the existing steam cycle may not be able to be integrated effectively for steam extraction, or space and access around/to the steam cycle may be impossible. As an alternative to steam extraction, it is possible to retrofit existing coal plants with a gas turbine combined cycle plant (CCGT) to maintain, or even increase, the site power output. The gas turbine can be integrated to the existing coal plant in various ways to supply all the heat, or a fraction of the heat, and the power required for the capture systems. An important consideration is whether carbon emissions from both, the combined cycle and the retrofitted coal plant are captured, or from the latter only. This paper examines these different options for carbon capture retrofits to existing coal plant and presents a novel configuration with the sequential combustion of gas turbine flue gas in the existing coal boiler while capturing carbon emissions from the combustion of coal and natural gas.

This article examines the economic factors that may be important in determining the overall performance of coal plants retrofitted with an additional gas turbine combined heat and power cycle. A comparison is made with an integrated retrofit where steam is extracted from the power cycle.

Rapidly training researchers involved in carbon capture and storage (CCS) and advancing fundamental understanding of the entire chain is vital to achieve CCS deployment in a timescale aligned with global emission reduction targets. This paper introduces a number of initiatives that are building UK CCS capacity, focussing on activities involving the academic community such as the UK CCS Research Centre (www.ukccsrc.ac.uk) and a number of postgraduate training programmes. These and other examples illustrate the benefits associated with academic-industry collaboration, as well as providing valuable opportunities to accelerate development of suitably trained people and CCS technology in an academic context.

China has been building at least 50 gigawatt (GW) of new coal-fired power plants every year since 2004. In the absence of CO 2 capture ready (CCR) designs, a large fraction of new coal power plants built in the next decade could face ‘carbon lock-in’. Building on the existing engineering and economic literature on CO 2 capture ready, the aim of this study is to understand the opportunities and challenges in implementing CCR in China. In early 2010, opinion-leaders perceptions towards implementing CCR in Guangdong with two empirical phases are presented: an online consultation of 31 respondents (out of a sample of 82), three face-to-face focus group discussions including 16 officials from five power plants and two oil companies in the Guangdong province. A majority of respondents in the online survey were engineers. The survey results are compared with an earlier study of stakeholders’ views on demonstrating CCS in China, conducted in April 2009 as part of the EU–UK–China Near Zero Emissions Coal initiative (NZEC) project.

Despite the importance of the accurate measurement of vapour–liquid equilibria (VLE) data, the reported values, even for well-studied systems such as MEA–H2O–CO2, are scattered. This work centres on the development of an experimental method to measure accurately the VLE of various aqueous amine systems. A static-analytic type of VLE apparatus has been constructed and employed to measure the VLE of CO2 in aqueous monoethanolamine and 2-amino-2-methyl-1-propanol. Gas chromatography was used to analyse the liquid phase compositions. The setup has been validated against literature data for 30 mass% MEA (monoethanolamine) at T = 313 and 393 K and was shown to be capable of generating reliable and repeatable data. New measurements for 30 mass% aqueous AMP (2-amino-2-methyl-1-propanol) solutions are also presented at temperatures between 313 and 393 K and a total pressure range of 23–983 kPa. A quasi-chemical model has been employed to interpret the experimental data for the MEA–H2O–CO2 and AMP–H2O–CO2 systems. The average absolute deviation (ΔAAD) between model prediction and experimental data is within 7%.

A qualitative assessment of the early opportunities for capturing carbon dioxide from advanced gasification plants, and of design guidelines for carbon capture ready gasification plants in China, is conducted to investigate current development in coal gasification. The assessment first illustrates the development of different types of gasification technology in China. Capturing carbon dioxide from high concentration stationary emission points could be seen as an early opportunity for carbon capture demonstration. The large scale CTL plants and chemical plants installed with advanced entrained flow gasifier should be considered as early opportunity for CCS in China. However, given that the total amount of emissions and the scale of emission sources are relatively small at those plants compared with conventional coal fired plant, the potential emission reduction is very limited.

Amine and other liquid solvent CO2 capture systems capture have historically been developed in the oil and gas industry with a different emphasis to that expected for fossil fuel power generation with post-combustion capture. These types of units are now being adapted for combustion flue gas scrubbing for which they need to be designed to operate at lower CO2 removal rates – around 85–90% and to be integrated with CO2 compression systems. They also need to be operated as part of a complete power plant with the overall objective of turning fuel into low-carbon electricity. The performance optimisation approach for solvents being considered for post-combustion capture in power generation therefore needs to be updated to take into account integration with the power cycle and the compression train. The most appropriate metric for solvent assessment is the overall penalty on electricity output, rather than simply the thermal energy of regeneration of the solvent used. Methodologies to evaluate solvent performance that have been reported in the literature are first reviewed. The results of the model of a steam power cycle integrated with the compression system focusing on key parameters of the post-combustion capture plant – solvent energy of regeneration, solvent regeneration temperature and desorber pressure – are then presented. The model includes a rigorous thermodynamic integration of the heat available in the capture and compression units into the power cycle for a range of different solvents, and shows that the electricity output penalty of steam extraction has a strong dependence on solvent thermal stability and the temperature available for heat recovery. A method is provided for assessing the overall electricity output penalty (EOP), expressed as total kWh of lost output per tonne of CO2 captured including ancillary power and compression, for likely combinations of these three key post-combustion process parameters. This correlation provides a more representative method for comparing post-combustion capture technology options than the use of single parameters such as solvent heat of regeneration.

Existing coal-fired power plants were not designed to be retrofitted with carbon dioxide post-combustion capture (PCC) and have tended to be disregarded as suitable candidates for carbon capture and storage on the grounds that such a retrofit would be uneconomical. Low plant efficiency and poor performance with capture compared to new-build projects are often cited as critical barriers to capture retrofit. Steam turbine retrofit solutions are presented that can achieve effective thermodynamic integration between a post-combustion CO 2 capture plant and associated CO 2 compressors and the steam cycle of an existing retrofitted unit for a wide range of initial steam turbine designs. The relative merits of these capture retrofit integration options with respect to flexibility of the capture system and solvent upgradability will be discussed. Provided that effective capture system integration can be achieved, it can be shown that the abatement costs (or cost per tonne of CO 2 to justify capture) for retrofitting existing units is independent of the initial plant efficiency. This then means that a greater number of existing power plants are potentially suitable for successful retrofits of post-combustion capture to reduce power sector emissions. Such a wider choice of retrofit sites would also give greater scope to exploit favourable site-specific conditions for CCS, such as ready access to geological storage.

Policies to develop and deploy CCS as a tool for climate change mitigation should consider the key differences between three classes of CCS projects: carbon-positive, near carbon-neutral and potentially carbon-negative. In class 1 are projects that are ‘carbon positive’ since they capture CO2 from the production of fossil hydrocarbon fuels and there is no guarantee that the CO2 generated when these are used will be captured and stored. Class 1 CCS might be treated as a condition of the ‘licence to operate’ for hydrocarbon production projects that emit large amounts of CO2, and be distinguished from other classes of CCS projects in any incentive framework. In the event of serious global action on climate change, it seems likely that class 1 CCS would be employed to minimise fossil fuel supply chain CO2 emissions, but in addition all fossil fuels would need to be used with class 2, near carbon neutral, CCS, so that the vast majority of fossil carbon is captured and stored and the main products are decarbonised energy vectors such as electricity, hydrogen and heat. Class 2 CCS projects are generally more expensive than class 1 projects and require more novel technologies, so they are unlikely to be widely deployed at present without specific incentives, an analogous situation to that for many renewable generation technologies. Carbon negative class 3 projects, where biomass use and CCS are combined, or where CO2 is captured directly from the air, could also be important since they have the potential to achieve a net reduction in atmospheric CO2 concentrations, as well as to offset residual emissions from other classes of CCS.

A set of 13 coals of different rank has been tested for ignition propensity in a 20-L explosion chamber simulating oxyfuel combustion gas conditions. Their char residues were also analysed thermogravimetrically. The effects of coal type, coal concentration (from 100 to 600 g/m 3 ), O 2 in CO 2 atmospheres (up to 40% v/v) and particle size were investigated. The higher rank coals were significantly more difficult to ignite and mostly required higher energy chemical igniters (1000 or 2500 J) whereas the lower rank coals could be ignited with a 500 J igniter even at low coal dust concentrations. The minimum explosibility limit/ignition concentration in air varied slightly around a value of 200 g/m 3 , a little higher for low volatile coals and a little lower for high volatile coals. The ignition limit changed significantly, however, with O 2 concentration in CO 2 , where coals required more oxygen to ignite. Most coals failed to ignite at all in 21% v/v O 2 in CO 2 , but an increase to 30 or 35% v/v O 2 gave ignition patterns similar to those in air. In addition, the minimum ignition concentration decreased with increase in O 2 . However, a further increase to 40% v/v O 2 did not generally affect the minimum ignition concentration. Particle size had a non-linear effect on coal ignition. The fine particles ( 53 μm) was generally more difficult to ignite and exhibited a much lower weight loss.

In a period where fast learning-curves for capture technologies can be expected it is important that plants built as carbon capture-ready avoid becoming potential stranded assets during the period of time when the plant operates without capture. At the same time recent evidence shows that decarbonisation of electricity generation cannot be achieved without a CCS option for gas plants. This article first proposes steam turbine design options to build combined cycle gas turbine plants as carbon capture-ready. Then steam cycle options for the existing fleet of coal-fired units are then presented. Although these plants have not been initially designed to operate with CCS it is possible to achieve effective thermodynamic integration–and an overall electricity output penalty in kWh per tonne of CO2 close to a plant built with capture from the outset–with appropriate steam turbine retrofits. Finally, novel insights into the design of capture-ready steam cycles are discussed for futureproofing pulverised coal plants that may have capture fitted after the first learning cycles of postcombustion capture technologies occur or that may be upgraded over their lifetimes.

A consensus for the development of a low carbon economy in China is growing rapidly among Chinese energy stakeholders. But there is considerable uncertainty as to the role that carbon capture and storage (CCS) retrofit could play in this development. The State Council in China has set a target of cutting carbon dioxide emissions per unit of GDP by 40% by 2020 compared with the level for 2005. Although this provides some policy impetus for reducing carbon dioxide emissions in China, it is also important to note that over 350 GW of coal-fired power plant capacity has been built within the past five years and that these power plants are expected to operate for at least another 25 years. Because coal is an affordable and accessible fuel in China, both the China Electricity Council (CEC) and the International Energy Agency (IEA) estimates that another 300 GW of supercritical and ultra-supercritical new coalfired power plants will be constructed in the next decade to satisfy the growing energy demand of the country . But unless other options to reduce emissions can be implemented, a simple consideration of the emissions they produce suggests that some of these recently built power plants may be required to shut down within the next two decades to address Chinese and/or international climate policies. During the past five years, the national policy of ‘closing smaller and/or inefficient units to build large and more efficient units’ has been implemented not only to save energy, but also to reduce specific carbon dioxide emissions (i.e. reduced gCO 2 /kWh of electricity produced). Forcing early plant closure has, however, proved to be a difficult task under the institutional framework of the Chinese electricity sector, because these plants usually had not reached the end of their design lifetimes. Also it was only partially successful in the context of CO 2 reduction in the sense that companies wanted to build large plants to increase electrical output and strict rules meant they could only do this by closing a specified amount of older plant. But the end result was still that more coal was burnt and hence total CO 2 emissions to atmosphere increased. Retrofitting some of the existing power plants to capture CO 2 , which by contrast can achieve an absolute decrease in CO 2 emissions to atmosphere for an analogous loss in plant output (to the closures previously enforced) is therefore, an important option to address the threat of climate change while maintaining in the meantime the country’s electricity supply from coal. A preliminary investigation of over 100 large power plants in China was conducted to determine their potential for a retrofit with CO 2 capture, transport and storage. Factors assessed included geographic location, space on site, plant layout, water restriction, coal supply, efficiency, FGD status and potential access to storage sites. Based on these criteria, retrofitting prospects were evaluated and rated. It appears that about 45% of existing power plants may suffer from ‘carbon lock-in’ status, i.e. their emissions could not be abated using CCS technology, at least at ‘reasonable’ cost. Critical factors that would preclude capture retrofit are, not surprisingly, access to storage sites and unsuitable plant layout and/or space on site. Variations in other factors would affect the level of retrofitting cost, but this effect could be positive as well as negative. In principle, plants would be retrofitted in an order that reflects the extent to which these site specific factors would give higher or lower retrofit costs. The results aim to provide an overview of the potential issues that need to be considered by stakeholders, policy makers and manufacturing companies when deciding the market potential for CCS retrofit technology in China.

While CCS is demonstrated globally utilities will face a period with fast learning curves for capture technologies. Technology and cost uncertainty is a topic of particular concern for first-movers. For post-combustion capture plants, costs are expected to decrease in the future and improved solvents are likely to become commercially available after the first CCS plants have started operating. Given that power generation assets are usually paid back over extensive periods of time it is important that, in this context, the first generation of plants and any capture-ready plants can be future-proofed to incorporate future technological improvements. This paper presents selected results from a forthcoming report commissioned by the IEAGHG. A methodology based on a sensitivity analysis of solvent properties is used to identify pieces of equipment, which contribute to locking-in performance with capture. Finally, some principles for analysing power plant economics with improved solvents and assessing the potential financial benefits in competitive electricity market of mitigating these technology risks are examined.

Making best use of existing assets is a high priority for industry, particularly when significant capital expenditure would be required to construct replacement capacity to meet continued demand if they were taken out of service. In this context, the potential to retrofit carbon dioxide (CO 2 ) capture to existing power plants so that they can continue to operate in plausible future scenarios where significant cuts in CO 2 emissions are required from the electricity sector has become an increasingly ‘hot topic’. One potentially important characteristic of retrofitted plants that is typically over-looked in assessments of CO 2 capture retrofit is that they are likely to have ‘built-in flexibility’. For example, for plants that retrofit post-combustion capture without any significant changes to the power cycle (i.e. that do not undertake a boiler/turbine retrofit at the time as adding capture), it should be technically feasible for the plant to avoid the majority of the efficiency penalty associated with operating CO 2 capture by temporarily bypassing the capture unit. The low pressure steam turbine, condenser and generator will be sized so that they are able to use the steam that is diverted away from the CO 2 capture unit for power generation without any additional expenditure, since this steam was included in the design flow before capture was fitted. This paper and a related PhD thesis contributes to developing understanding of the potential value of built-in flexibility of coal-fired power plants retrofitted with post-combustion capture and potential enhancements associated with temporary storage of rich solvent. This analysis is important to inform investment and policy decisions and brings together engineering and economic assessment. Thus, it is able to draw robust conclusions that are relevant in determining both priorities for future technical design work and decisions about which modes of operating flexibility may be sufficiently valuable to warrant further analysis within investment appraisal or policy-making related to retrofitting post-combustion capture to pulverised coal plants.

Making new coal-fired power plants carbon capture ready (Carbon Capture Ready) in China has been recognised as a crucial by a number of stakeholders academics, energy companies and regional government, based on a study in EU-UK-China NZEC project. A number of publications have investigated the definition, engineering requirements, economic and finance of CCR for China. However there remain a number of questions regarding the extent to which a plant’s physical location might constrain the feasibility of CCS retrofit. To address this issue, a Geographical Information System (GIS) has been used as a tool for mapping current and planned large carbon dioxide sources in Guangdong, also illustrating potential storage sites and calculating possible carbon dioxide transportation route. This paper investigates the location factors that should be considered when locating new build CCR power plants and demonstrates the methodology of using GIS software with spatial analysis in planning new build power plant in Guangdong. A preliminary study has identified over 30 large power plants within the region, with plant locations and historical emission data collected and presented in ArcGIS. Factors such as distance to potential storage site, route of CO 2 pipeline, extra space on site and potential development plan etc. were investigated in the modelling and calculated the potential source and sink solution. The study then moves on to suggest possible new build plant locations which can be easily fitted in to the current network, based on economic optimisation. The scope for future coal plant development combined with a possible nuclear plant siting plan is discussed towards the end of the paper. Guangdong province, which owns the third largest coal-fired power installed capacity out of 31 provinces, generated over 8% of China’s total electricity every year for the past 15 years. CO 2 storage opportunities could be found in the surrounding South China Sea, where Guangdong has a total of 4,300 km of coastline and some small scale oil fields on shore within the region. It is also among the first places to start the national open and reform policy in China. The province is one of the richest in China, with the highest GDP among all other provinces since 1989, and the foreign trade accounts for more than a quarter of China’s total amount. It also contributes around 12 of the total national economic output. Currently, the provincial government is proposing a low carbon roadmap, which is the first of its kind in China. The work has created a totally new thinking on capture ready power plant planning. This differs from existing studies (e.g., which aim to investigate the existing carbon dioxide emission sources at specified location and provide source and sink matching analysis. Instead the study focuses on policy implementation for new build capture ready power plants. Three clusters within Guangdong province are identified as potential temporary CO 2 storage hubs before transporting the gas to a long term storage site. When officials are planning new power plant locations from a capture ready perspective, the plants should not necessarily be close to storage sites in straight line, but rather should be within a reasonable distance of a cluster. Transport of the captured CO 2 will not be limited to pipelines, but could be extended to road and rail tankers. Power plant parameters and storage site data were collected for this research. Public transportation, utilities, landscapes, river, land used and population data were referenced from various sources; therefore, some of the data could be out of date. Nevertheless, it should still provide enough information when deciding the location of the transport cluster. Any future work could build on the existing model with updated data. Moreover, it could fit in with the national natural gas transportation network and utility planning network to provide long term integrated energy system analysis. The paper could provide policy makers, investors and urban planning officials with a view on how conventional thermal power plant investment and planning could be optimised, using Carbon Capture Ready designs, to keep the CCS retrofitting option open.

A computer controlled wire mesh apparatus has been developed that uses radiant heating elements at 900 °C to combust individual biomass particles. Optical access allows particle combustion characterisation by video image analysis. Combustion test results are presented for roughly cubic particles of European ash at a range of sizes with different moisture contents. As the moisture content of the particles increased the overall times required for drying, devolatilisation and burnout increased. The effect of moisture content, however, had a lesser effect upon total burning time than the effect of particle mass, which was shown to dominate the total combustion time for this single biomass type.

Making new plants CO 2 capture ready (CCR) would enable them to retrofit to capture CO 2 at a later date at lower cost when the appropriate policy and/or economic drivers are in place. In order to understand the economic value and investment characteristics of making new plants CCR in China, a typical 600 MW pulverised coal-fired ultra-supercritical power plant, locating in Guangdong province, was examined. Combined with an engineering assessment, costs were estimated for different CCR scenarios. To analyze CCR investment opportunities, the paper applies a cash flow model for valuing capture options and CCR investment. Results were obtained by Monte-Carlo simulation, based on engineering surveys and an IEA GHG CCR study, as well as plant performance information and expert projections on carbon prices, coal prices and electricity prices. CCR investments are justified by factors such as higher retrofitting probabilities, lower early closure probabilities and fair economic return. However, the economic case for CCR largely depends on two factors: (a) whether the original plant is retrofittable without CCR; and (b) the type of investments made, for example, investments essential to CCR tend to be more economic than additional non-essential CCR features such as clutched low pressure turbines. The carbon price and discount rate were found to have significant impacts on the economics of CCR. Overall, it appears that the value of the ‘capture options’ that CCR generates for retrofitting CCS is significant, and so could justify a modest CCR investment, even assuming the original plant is retrofittable without CCR. It was also found the value of CCR might be significantly understated if the range of potential retrofitting dates is artificially constrained.

The UK-China Near Zero Emissions Coal project was officially launched on 20th November 2007 in Beijing and will run until June 2009. The objectives of the project are to: • Enable knowledge transfer between Chinese and UK parties (academic, industrial and other) • Model the future energy requirements of China, taking CCS technology into account. • Produce case studies of potential carbon dioxide capture technologies. • Build capacity in China for evaluation of storage potential for CO 2 and perform first stage characterisations for selection of sites suitable for CO 2 storage. • Develop a technical and policy level roadmap for CCS. The capture and transport theme in the NZEC project has fourteen Chinese and overseas partners undertaking ten different capture plant case studies and an overview of CO 2 transport in China. The range of coal applications in China means that a number of different approaches may be required, depending on the circumstances. All major types of CCS capture options are being examined: oxyfuel as a new build and a retrofit installation, post-combustion capture using conventional and advanced technologies and gasification with pre-combustion capture for dedicated IGCC and for polygeneration plants. Details of the case studies to be undertaken are presented, with a discussion of key issues in the unique conditions of the Chinese electricity supply market. A comprehensive set of underlying ‘ground rules’ for the studies in the Chinese context will also be described. These will be related to standard conditions used for other studies, e.g. IEA GHG capture technology assessments, and their effects on equivalent plant performance will be estimated to provide ‘correction factors’ for the results of published studies when similar technologies are transferred into the Chinese context.

Delivering a rapid reduction in global CO2 emissions through CCS requires a two-track approach: CCS needs to be developed at s cale as quickly as possible and other plants, if built without CCS, need to be built CO2 capture ready (CCR). CCR plants can be upgraded as CCS technology develops so that their cost of electricity production can be minimised. Retrofitted CCR plants could also be very suitable for providing flexible electricity output. The options availabl e for making steam turbines at pulverised coal plants suitable for adding post-combustion CO2 capture unit s are discussed, together with their potential for upgrad ing and enhanced flexibility.

The UK carbon capture and storage consortium (UKCCSC) is a £2M multidisciplinary project involving academics from 15 universities and research institutes in the UK. The project has sought to improve understanding of CCS with a UK perspective in a global context. This paper outlines the broad range of activities undertaken by the consortium, including science and engineering achievements, contributions to the ongoing policy debate and capacity building.

The business case for investment in power plants with CO 2 capture is greatly improved if they are able to accommodate uncertainty in future market conditions and variations in local operating requirements.. This paper will outline a range of operating modes that could be important in determining the value of power plants with CO 2 capture from various stakeholder perspectives. Different quantitative techniques that could provide useful insights into plant value with flexible operation are discussed and some preliminary baseline results from a deterministic simulation are reported.

China has built at least 70 GW of new coal- fired power installed capacity annually since 2005 and the growth is expected to continue (CEC, 2008). Chinese government, industry and academic stakeholders perceive that China will not mandate new plants to be built with carbon dioxide capture and storage systems in the short term and there is little incentive even to contemplate the first steps needed to fit plants with capture equipment [Reiner, D., Liang, X., Sun, X., Zhu, Y., Li, D., 2007. Stakeholder attitudes towards carbon dioxide capture and storage technologies in China, International Climate Change Conference, Hong Kong, May 29–31 2007]. We investigate the value of making new plants CO 2 Capture Ready (CCR), which would enable them to retrofit to capture CO 2 without unnecessary additional costs when the appropriate policy and /or economic drivers are in place (IEA, 2007). In order to understand the value and investment characteristics of CCR in China, a typical 600 MW pulverized-coal -fired ultra-supercritical power plant, locating at Guangdong province, was examined. Combined with a detailed engineering assessment, we obtained the costs for different CCR scenarios. To analyze CCR investment opportunities, we apply a cash flow model for valuing Capture Options, as developed in [Liang, X., Reiner, D., Gibbins J., Li J., 2007. Fianncing CCR coal-fired power plants in China by issuing capture options, EPRG Working Paper Series, EPRG0728, Cambridge, December. Available at: www.electricitypolicy.org.uk/pubs/wp/eprg0728.pdf ]. Results are obtained by Monte-Carlo simulation, based on engineering surveys and the IEA (2007) CCR study, as well as plant performance information and expert projections on carbon prices, coal prices and electricity prices. CCR investments are justified by factors such as higher retrofitting probabilities, lower early-closure probabilities and fair economic return. However, the economic case for CCR largely depends on the type of investments made, for example, CCR-essential investments tend to be more economic than additional non-essential CCR features such as CCR Essential with clutched low-pressure turbines. Carbon price, coal price and discount rate also were found to have significant impacts on the economics of CCR. Overall, it appears that the value of capture options are significant, and therefore clear retrofitting strategies would be valuable for any CCR investment.

Carbon capture and storage (CCS) covers a broad range of technologies that are being developed to allow carbon dioxide (CO2) emissions from fossil fuel use at large point sources to be transported to safe geological storage, rather than being emitted to the atmosphere. Some key enabling contributions from technology development that could help to facilitate the widespread commercial deployment of CCS are expected to include cost reductions for CO2 capture technology and improved techniques for monitoring stored CO2. It is important, however, to realise that CCS will always require additional energy compared to projects without CCS, so will not be used unless project operators see an appropriate value for reducing CO2 emissions from their operations or legislation is introduced that requires CCS to be used. Possible key advances for CO2 capture technology over the next 50 years, which are expected to arise from an eventual adoption of CCS as standard practice for all large stationary fossil fuel installations, are also identified. These include continued incremental improvements (e.g. many potential solvent developments) as well as possible step-changes, such as ion transfer membranes for oxygen production for integrated gasifier combined cycle and oxyfuel plants.

Carbon dioxide (CO 2 ) and other greenhouse gases from fossil fuel use in many developed and developing countries are expected to be the major source of anthropogenic emissions for the foreseeable future. As a result, the potential to use CO 2 capture and storage (CCS) for significant reductions in CO 2 emissions from the use of coal (and other fossil fuels) at large point sources could become very important in determining the feasibility of climate change mitigation. Large-scale deployment of CCS in the EU from 2020 has been suggested, but this paper illustrates how time is very short if two complete learning cycles are to be achieved before a possible rollout in the early/mid 2020s. It also highlights some key differences between CO 2 capture technologies that suggest that learning can be achieved more quickly with post-combustion capture than with other options. This might allow rollout to be accelerated by perhaps 5 years for post-combustion capture.

Pulverised coal-fired plants often play an important role in electricity grids as mid-merit plants that can operate flexibly in response to changes in supply and demand. As a consequence, these plants are required to operate over a wide output range. This paper presents an initial evaluation of some potential impacts of adding post-combustion CO2 capture on the part load performance of pulverised coal-fired plants. Preliminary results for ideal cases analysed using a simple high-level model indicate that post-combustion CO2 capture could increase the options available to power plant operators. In particular, solvent storage could allow higher effective plant load factors to be achieved to assist with capital recovery while still permitting flexible operation for grid support. A number of areas for more detailed analysis are identified.

Although bireflectance measurements are routine, to date they have been limited to selected single point measurements. This study uses a 360° rotating polarizer in the incident light path combined with digital imaging to map the optical bireflectance of a polished specimen over the complete field of view, a system herein referred to as ‘Bireflectance Imaging of Coal and Carbon Specimens’ (BRICCS). True maximum reflectance maps and maps of polarizer angle for maximum reflectance (to identify co-ordered regions) are obtainable from the same data. A variety of coal, coke, char, graphite, and carbon/carbon specimens have been examined with the BRICCS system and the results demonstrate that the system can produce accurate maximum and apparent minimum reflectance, bireflectance, and extinction angle images. For example, flakes of natural graphite show no bireflectance along their long axis except in areas that have been strained. The images are maps showing the value of every pixel that has been calibrated by mineral reflectance standards. The maps are unique in that they show fields of view that cannot be seen by normal viewing through the microscope. For example, the bireflectance maps show the maximum difference between the maximum and apparent minimum reflectances for each of the million pixels at twenty orientations of the polarizer.

This study has been undertaken to determine the extent of structural ordering and thermal deactivation which can occur when coal chars are heated to high temperatures. The chars have been prepared using the captive-sample wire-mesh reactor at temperatures up to 2200°C at very short hold times (500 ms), and the microstructures have been examined using high-resolution transmission electron microscopy (HRTEM). The char structures have been compared to those of natural graphites. Regions within the chars have been observed to show a similar degree of ordering to that present in the graphites. The reactivities for oxidation of the high temperature chars and graphites have been determined by TGA methods and compared to the reactivity of chars prepared at lower temperatures. The structural ordering and reactivity data indicates that thermal deactivation may account for the low reactivity of a proportion of the char present in utility boiler fly ash.

Measurements of the intrinsic reactivity to oxygen of chars are increasingly being sought as an indicator of the combustion potential of fuels, particularly with respect to residual char burn-out. A TG-based method is described which is suitable for both routine industrial use and for research studies. Ramp heating, typically at 15 K/min, offers the significant advantages of allowing the entire sample to be assessed, requiring only a short time (approximately 1 h) to complete and being able to use the same conditions to test almost any sample. Reduced oxygen concentrations (6.3% O2 v/v) minimise uncontrolled exothermic heating of the sample; this is also comparable to oxygen levels encountered in the later stages of pulverised fuel (PF) combustion. Data processing methods, made possible by developments in computer hardware and software, have been developed to give fundamental, quantitative measurements of char reactivity, allowing direct comparison of the overall reactivities of different chars. Information on the heterogeneity of chars can also be derived. Typical results for a range of coal chars and comparison with other TG-based char characterisation methods are presented. Reactivity values measured on two TG instruments with different geometries, both of which operated using the methods developed, have been compared and found to be in agreement.

The effect of particle size on rapid-heating volatile yields from a range of particle size cuts prepared from three different coals have been measured using a wire-mesh apparatus. Samples were pyrolysed in helium at heating rates of 1000 K s −1 to 950°C with 10 s hold time. Particle size cuts over the range 38–150 μ m were prepared by two methods: sieving from a ground coal and regrinding the largest-sieved size cut. The latter approach was employed in a (partially successful) effort to minimise differences in size-cut compositions. In general, total daf volatile yields were observed to increase slightly with decreasing particle size, but for two of the coals, this effect was not monotonic over the range 38–150 μ m and was also dependent on the sample preparation method. Maceral analysis showed significant differences in all cases; however, with smaller particle-size cuts generally enriched in liptinite. To examine the effect of particle size without interference from maceral enrichment, a vitrain was used to prepare size cuts over the range 38–300 μ m. Volatile yields from these samples were virtually identical. The overall conclusion from this study is that mass transfer effects due to different particle sizes are probably less significant than unavoidable maceral enrichment effects during sample preparation. For rapid-heating volatile release tests (e.g., drop tube furnace, wire-mesh apparatus) requiring a sized coal sample, a comparison of TGA (thermogravimetric analysis) volatile yield measurements have been shown to be a reasonable indicator of whether or not the size cut has a similar composition to the whole coal.

Low oxidation reactivities and well-developed turbostratic crystallinity have recently been observed in residual carbon samples extracted from commercial and pilot-scale coal combustion fly ash. Thermal deactivation in high-temperature regions of the furnaces has been suggested as a likely mechanism to explain the low reactivities, but this hypothesis has never been tested directly. This paper describes the application of a new experimental technique for the direct measurement of rapid char deactivation under combustionrelevant conditions. The technique operates in inert environments to isolate the thermal deactivation mechanisms from possible oxidative mechanisms occurring in true combustion experiments. The technique, based on an inert-gas-purged, refractory-metal, high-temperature wire mesh, is demonstrated here on monomaceral-rich fractions from four parent coals of diverse origin. The results show that char reactivity is quite sensitive to preparation conditions in the range of interest to combustion, decreasing by a factor of 30–50 between 1000°C and 1800°C in only 2 s of treatment for seven of eight samples examined. The 1800°C chars have similar reactivities to boiler fly-ash chars measured previously, lending support for the thermal deactivation hypothesis. The results also show that thermal deactivation propensity is a function of precursor, with vitrinite-rich fractions deactivating more readily than inertinite-rich fractions. The propensity for deactivation is shown to correlate with the extent of crystalline order development as observed by high-resolution TEM fringe imaging. The paper discusses the relationship between fuel chemistry and deactivation propensity as well as the implications of the reactivity results for combustion processes.

The amount of residual, or unburned, carbon in fly ash is an important concern in the design and operation of pulverized coal fired boilers. Char oxidation is the slowest step in the coal combustion process, and the rate at which this heterogeneous reaction proceeds has an important effect on the degree of carbon burnout. There is an extensive literature on char combustion kinetics based on data in the early and intermediate stages of carbon conversion. A critical fundamental question is whether the small fraction of the fuel carbon that passes unreacted through a boiler is representative of the char during the main portion of the combustion process. This article addresses that question through a detailed characterization of eight carbon-containing fly ash samples acquired from commercial scale combustion systems. The fly ash characterization included measurement of joint carbon-size distribution and determination of the combustion reactivity of the residual carbon. To minimize mineral matter interactions in the reactivity tests, the technique of incipient fluidization was developed for separation of carbon-rich extracts (∼75 wt% carbon) from the inorganic portion of the fly ash. Reactivity measurements were made at 1400–1800 K to represent conditions in pulverized coal fired boilers. Measurements were also made at 700–1100 K to minimize transport effects and to isolate the influence of char chemistry and microstructure. In both temperature regimes, the residual carbon extracts were significantly less reactive than chars extracted from a laboratory scale laminar flow reactor in the early to intermediate stages of combustion. It is concluded that the boiler environment deactivates chars, making high carbon burnout more difficult to achieve than is predicted by existing char combustion kinetic models that were developed from data on laboratory chars. Finally, the results are used to discuss potential char deactivation mechanisms, both thermal and oxidative, in coal fired boilers.

The development of a new version of the wire-mesh apparatus, capable of achieving both high heating rates and peak temperatures in excess of 1500°C, has allowed captive sample measurements of N release during devolatilisation under PF combustion conditions to be made for the first time. Both volatile and N release yields differ significantly from previous wire-mesh data obtained for peak temperatures in the region of 1000°C. Significant differences are also found in N release patterns between different coal types. Comparison of the high-temperature wire-mesh apparatus N release data with NOx formation data from combustion plant, including full size boilers, shows that differences in NOx formation between coals with similar N contents can be related to their different patterns of volatile nitrogen release.

A flowing-solvent liquefaction reactor has been used to examine the primary solubilization potential of a range of coals. The reactor configuration allows the suppression of secondary reactions by sweeping the heated zone with a continuous flow of solvent. The design of the system combines low thermal inertia and direct electrical resistance heating to provide closely controlled time-temperature ramping, and a variable preset holding time at the target temperature. Heating rates of 0.1–15K s −1 up to temperatures of 450 °C and hold times of 0–1600 s can be achieved. Data are reported for a range of European and US coals with elemental carbon contents ranging from 74 to 91%. The effect on conversion of reactor pressure, heating rate, temperature, holding time at temperature and solvent flow rate have been determined. In contrast with pyrolysis, results suggest that liquefaction reactivities are relatively insensitive to changes in the heating rate. Comparison with results from micro-bomb reactors has shown that the continuous solvent sweep allows the relatively intact removal of primary solubilization products from the reaction zone. Molecular mass distributions of solubilized products thus obtained have been found to increase with increasing carbon content of the substrate coal (up to ~85%), and to decline with further increases up to 91% carbon content. In general, this reactor configuration appears to offer a promising avenue for analytically probing the more reactive structures of coals without interference from effects of secondary reactions.

Pyrolysis total volatile yields obtained (in helium and hydrogen) using a wire-mesh reactor at pressures up to 160 bar and heating rates between 1 K s −1 and 1000 K s −1 are compared with hydropyrolysis total volatile (and tar) yields at pressures up to 100 bar and a heating rate of 5 K s −1 to 590 °C obtained in a hot-rod (fixed-bed) reactor. Comparisons of product distributions from the two reactors are used to highlight some of the difficulties encountered in collecting and interpreting hydropyrolysis data as a function of reactor geometry, hold time, heating rate and hydrogen pressure. A common sample of Linby (low rank British bituminous) coal was used in all experiments.

A flowing-solvent (F-S) liquefaction reactor with a continuous solvent sweep through a fixed bed of coal has been developed. In contrast to liquefaction experiments using closed (batch) reactors, where products remain within the reactor for the duration of the experiment, solubilized liquefaction products are continuously swept out of the reaction zone. In this way the possibility of retrogressive reactions is minimized. Results are presented and compared with data obtained in a mini-bomb (M-B) reactor under comparable conditions and using the same sample of Point of Ayr coal. Conversion data indicate that, unlike M-B experiments performed under similar conditions, no increase in solid residue is observed during long residence time-high temperature runs in the F-S reactor. Size-exclusion chromatography shows that products from the F-S reactor increase in molecular weight with increasing reaction time and temperature whereas, due to secondary reactions, products from the M-B reactor are generally observed to decrease in molecular weight as the severity of the reaction conditions is increased.