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In platelets, elevated cytosolic Ca 2+ is a crucial second messenger, involved in most functional responses, including shape change, secretion, aggregation and procoagulant activity. The platelet Ca 2+ response consists of Ca 2+ mobilization from endoplasmic reticulum stores, complemented with store-operated or receptor-operated Ca 2+ entry pathways. Several channels can contribute to the Ca 2+ entry, but their relative contribution is unclear upon stimulation of ITAM-linked receptors such as glycoprotein VI (GPVI) and G-protein coupled receptors such as the protease-activated receptors (PAR) for thrombin. We employed a 96-well plate high-throughput assay with Fura-2-loaded human platelets to perform parallel [Ca 2+] i measurements in the presence of EGTA or CaCl 2. Per agonist condition, this resulted in sets of EGTA, CaCl 2 and Ca 2+ entry ratio curves, defined by six parameters, reflecting different Ca 2+ ion fluxes. We report that threshold stimulation of GPVI or PAR, with a variable contribution of secondary mediators, induces a maximal Ca 2+ entry ratio of 3-7. Strikingly, in combination with Ca 2+-ATPase inhibition by thapsigargin, the maximal Ca 2+ entry ratio increased to 400 (GPVI) or 40 (PAR), pointing to a strong receptor-dependent enhancement of store-operated Ca 2+ entry. By pharmacological blockage of specific Ca 2+ channels in platelets, we found that, regardless of GPVI or PAR stimulation, the Ca 2+ entry ratio was strongest affected by inhibition of ORAI1 (2-APB, Synta66) > Na +/Ca 2+ exchange (NCE) > P2× 1 (only initial). In contrast, inhibition of TRPC6, Piezo1/2 or STIM1 was without effect. Together, these data reveal ORAI1 and NCE as dominating Ca 2+ carriers regulating GPVI- and PAR-induced Ca 2+ entry in human platelets.

In a net zero economy compliant with the emission targets implicit in the Paris Climate Change Agreement any residual greenhouse gas emissions from hydrogen produced via steam methane reforming (SMR) of natural gas will require reduction to zero. The initial step to achieving this is the capture and storage of 100% of the fossil carbon from both the natural gas feedstock and the natural gas used for combustion, hereafter referred to as zero residual CO2 emission production. For an SMR this means achieving an overall CO2 capture fraction of 99.8% from the flue gases. The remaining 0.2% of stack CO2 emissions are then equal to the atmospheric CO2 from the combustion air used in the steam methane reformer furnace. Via the process modelling of a steam methane reformer integrated with post-combustion CO2 capture (using the CCSI MEA steady state model [1]), we predict that, for an open-art solvent of 35%wt aqueous MEA, a capture fraction of 99.8% and a peak desorber temperature of 125oC, the CO2 absorber column requires 20m of structured packing and the intercooling of the solvent, compared to an estimated 14m of structured packing and no intercooling for 5% residual emission hydrogen (95.2% capture fraction). For a 1 GW hydrogen production facility, we use public domain cost studies to estimate that this translates to an increase in total capital requirements of 6.5%, from £987M to £1051M, and a marginal increase in specific CO2 capture energy requirements of 1.6%, from 3.62 GJ/tCO2 to 3.67 GJ/tCO2 of low grade thermal energy, provided by low pressure steam extracted from the process. The resulting net operating costs, including CO2 transport and storage, natural gas fuel and steam for solvent regeneration but excluding any CO2 emission costs associated with the cases with residual emissions, increase by 3.7% from £468M to £485M p/a. The additional CO2 captured reduces hydrogen production efficiency by 1.9 percentage points on an HHV basis (from 68.7% HHV to 66.8% HHV). For 2020 UK capital costs, an assumed natural gas price of 28 £/MWhth HHV (82 p/therm) and average electricity selling price of 90 £/MWhe, hydrogen can be produced with zero residual emissions at a Levelised Cost of Hydrogen (LCOH) of the order of 62 £/MWhth HHV (2.4 £/kg H2) with an associated levelised cost of capture (LCOC), excluding transport and storage, of 54.1 £/tCO2. This translates to a marginal increase of 0.34 £/tCO2 per percentage point increase in net capture fraction when compared to operating with 5% residual emissions (52.4 £/tCO2). Hydrogen production with residual CO2 emissions of 5% results in the same LCOH of 62 £/MWhth HHV with a carbon price of 172 £/tCO2.

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.

For most of its history carbon capture and storage (CCS) has generally been regarded as a way of overcoming a shortage of oil and gas, essentially a response to an oil crisis, like renewable energy. With countries moving towards targets of net-zero CO2 emissions (e.g., the UK and France) and potentially towards negative greenhouse gas emissions, CCS will become increasingly essential if our climate objectives are to be achieved. In order to achieve a solution on global warming, then all countries have to participate. Money spent on CCS is much more likely to get a return in terms of influencing other countries than if spent on low-carbon technologies that are already well-known and widely deployed.

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.

Increasing amounts of variable renewable energy sources will cause fundamental and structural changes to thermal power plant operating regimes. Maintaining key reserve requirements will lead to an increase in power plant start-ups and cycling operations for some units. An enhanced unit commitment model with energy storage and flexible ${\text C}{{\text O}_2}$ capture is formulated. High-resolution on-/offshore wind data for the U.K., and probabilistic wind power forecast, model wind imbalances at operational timescales. The strategic use of flexible ${\text C}{{\text O}_2}$ capture and energy storage helps maintain reserve levels, decreasing power plant cycling operations and wind curtailment. A temporally explicit variability assessment of net demand illustrates the generation flexibility requirements and the nonlinear impacts of increasing wind capacity on power plant operating regimes.

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.

In their Perspective “The trouble with negative emissions” (14 October, p. [182][1] ), K. Anderson and G. Peters assert that negative-emissions technologies are an “unjust and high-stakes gamble.” This characterization would sideline negative-emissions technologies and remove potentially important options from the portfolio for mitigating and ameliorating climate change. As Anderson and Peters acknowledge, the remaining carbon budget is pitifully small; at the current rate, the world will blow through 600 Gt of CO2 in 15 years. Dumping this much CO2 in the atmosphere will almost certainly result in more than 1.5°C warming. Indeed, as advocates of a 350-ppm target point out, the remaining CO2 budget could be negative. Anderson and Peters provide no evidence that faith in negative-emissions technologies is to blame for a delay in implementing other mitigation plans or for the failure of countries to cut emissions. This failure is easily explained by the free-riding behavior of some countries ([ 1 ][2]), and taking negative-emissions technologies off the table would not make collective action any easier. Indeed, given that negative-emission technologies require financial contributions, not changes in behavior, their development and deployment may well be less vulnerable to free riding. Furthermore, we need a lot of arrows in the quiver to stand a chance of meeting the Paris targets. This was a key finding from the integrated assessment modelers ([ 2 ][3]). Rather than dividing mitigation into competing strategies, an inclusive approach would focus on stopping climate change as fast as possible while minimizing risk to vulnerable populations and to societal stability. Negative-emission technologies are not unique in facing challenges, risks, and uncertainties. It is true that negative emissions may fall short of closing the gap, but to characterize them as a high-stakes gamble is not consistent with the facts and the plausibility of meeting the Paris goals without them. Throwing a life-preserver to a drowning victim may not assure a successful rescue, but it is not a high-stakes gamble. Offering the life-preserver is preferable to withholding it, even though it might reduce the victim's incentive for learning how to swim. ![][4] At the current rate of carbon emissions, it will be difficult to meet climate goals. PHOTO: YOCAMON [www.sciencemag.org/cgi/content/full/354/6313/714-a/DC1][5] Full author list 1. [↵][6]1. S. Barrett, 2. R. Stavins , Int. Environ. Agreements 3, 349 (2003). [OpenUrl][7] 2. [↵][8]1. O. Edenhofer 2. et al IPCC, Climate Change 2014: Mitigation of Climate Change. Contribution of Working Group III to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change, O. Edenhofer et al., Eds. (Cambridge Univ. Press, 2014). [1]: http://www.sciencemag.org/content/354/6309/182.full [2]: #ref-1 [3]: #ref-2 [4]: /embed/graphic-1.gif [5]: http://www.sciencemag.org/cgi/content/full/354/6313/714-a/DC1 [6]: #xref-ref-1-1 "View reference 1 in text" [7]: {openurl}?query=rft.jtitle%253DInt.%2BEnviron.%2BAgreements%26rft.volume%253D3%26rft.spage%253D349%26rft.genre%253Darticle%26rft_val_fmt%253Dinfo%253Aofi%252Ffmt%253Akev%253Amtx%253Ajournal%26ctx_ver%253DZ39.88-2004%26url_ver%253DZ39.88-2004%26url_ctx_fmt%253Dinfo%253Aofi%252Ffmt%253Akev%253Amtx%253Actx [8]: #xref-ref-2-1 "View reference 2 in text"

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.

Decarbonisation of UK electricity generation is unlikely to be achieved without carbon dioxide capture and geological storage for natural gas fired power plants. In a period when fast learning curves for carbon dioxide capture technologies can be expected, it is important that gas plants built as capture ready are able to incorporate technology developments that occur during the period of time when the plant operates without capture. This paper focuses on carbon dioxide capture from combined cycle gas turbine plants and extends concepts previously proposed by the authors for capture-ready designs to include novel options capable of covering a wide range of solvent properties. These options avoid locking in power plants to a specific solvent technology at the time of commissioning and effectively act as a hedge against risk associated with technology obsolescence at the time of retrofitting. They follow the general principles of capture-ready design of low additional capital cost, no upfront performance penalty, good performance with capture and the ability to operate with the capture unit bypassed. Particularly in countries not yet committed to carbon dioxide capture and geological storage, power plant developers may want to keep their retrofit options open by building plants capable of fitting radically different solvents from current state-of-the-art amines.

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 capture option is an option contract where the option holder can exercise a contract to retrofit an existing fossil fuel plant to capture carbon dioxide (CO2) on or before a fixed date. We suggest that new thermal power plants, particularly those in developing countries, consider issuing capture options at the design stage, because the sellers—the owners of newly built thermal power plants—may then invest in making these plants CO2 capture ready (CCR) to optimise returns from selling capture options. In a detailed case study on a 600 MW ultrasupercritical pulverised coal-fired power unit a potential storage site in Guangdong, China, the value of a capture option and CCR investment is evaluated using the backward deduction option pricing method through a stochastic cash flow model with Monte-Carlo simulations. If the power plant is retrofittable without CCR investment, then for an 8% discount rate the value of a capture option is US $11 million before CCR investment. Investing US $3.8 million in CCR increases the value of the capture option by an estimated US $12 million. Perhaps more important from a policy point of view, CCR investment can reduce the odds of early closure by 20% and also increase the chance of retrofitting to capture by 43%. If the power plant is not retrofittable in the absence of CCR design modifications, CCR investment to avoid ‘carbon lock-in’ is not only important for climate policy but is also economic from an investment point of view. We also conduct sensitivity analyses on a range of key assumptions to test the robustness of the findings.

Carbon capture and storage (CCS) could play a significant role in reducing global CO2 emissions. It has the unique characteristic of keeping fossil carbon in the ground by allowing fossil fuels to be used, but with the CO2 produced being safely stored in a geological formation. Initial versions of the key component technologies are at a sufficient level of maturity to build integrated commercial-scale demonstration plants. If CCS is to reach its full potential to contribute to global efforts to mitigate the risk of dangerous climate change, it is urgent that a number of actions begin now in order to be ready for CCS deployment from around 2020 using proven designs that can be built in large numbers. This article discusses some key challenges for CCS, with a focus on development in the next decade, highlighting the potential benefits of a two tranche programme for integrated commercial-scale demonstration to develop proven reference plant designs and reviewing the importance of distinguishing between different classes of CCS according to their ability to significantly reduce CO2 emissions associated with fossil fuel use. It also identifies some ongoing CCS projects and initiatives and examines some possible implications of current policy discussions for technology development.

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.

Current efforts to reduce carbon dioxide emissions associated with energy services in buildings have focused on efficiency and a ‘distributed energy’ approach, using renewables and small-scale combined heat and power plants fuelled by natural gas or biomass. The same fuels can, however, give similar results if used in centralised plants to generate electricity that can then power heat pumps. A greater emphasis on the use of heat pumps would also facilitate the use of non-fossil electricity and the future application of carbon capture and storage to reduce emissions from any centralised fossil fuel use. Carbon capture and storage and electricity can give cuts in carbon dioxide emissions of 75% or more compared with local direct use of gas and overall negative emissions with biomass. Centralised hydrogen production with carbon capture and storage can also be combined with distributed combined heat and power. Given the potential effectiveness of these combined centralised/distributed approaches for emissions reductions, it is important that further work is undertaken so that they can be accurately evaluated as additional policy options. Infrastructure developments should also take into account the likely importance of decarbonised electricity and/or hydrogen in the future and not be locked into direct use of natural gas with its minimum emission limit of approximately 0·2 kgCO2/kWh.

Rapid global deployment of carbon capture and storage (CCS) requires a two-track approach. CCS needs to be deployed at scale as quickly as possible and other plants, if built without CCS, need to be built CO2 capture ready (CCR) before they are retrofitted. In particular, coal plants are likely to continue to be built in large numbers in developing countries. CCS is not an immediate option for all or most of these plants, but it would be feasible to make large numbers of them CCR for subsequent retrofit of flue gas scrubbing systems for post-combustion capture. This article will examine options for CCR steam turbines for such plants, showing that effective thermodynamic integration with the capture equipment can be achieved for minimal additional cost. The performance will be compared with the retrofit of non-CCR steam turbine configurations. Finally, the uncertainty of CCS development will be discussed and the performance of the CCR steam turbine options proposed will be assessed for a range of future possible CO2 scrubbing solvents that are less energy intensive than the original design case using current solvents.