Supercritical Coal-fired Power Plant Research Articles

Advanced Thermodynamic Analysis and Evaluation of a Supercritical Power Plant

A conventional exergy analysis can highlight the main components having high thermodynamic inefficiencies, but cannot consider the interactions among components or the true potential for the improvement of each component. By splitting the exergy destruction into endogenous/exogenous and avoidable/unavoidable parts, the advanced exergy analysis is capable of providing additional information to conventional exergy analysis for improving the design and operation of energy conversion systems. This paper presents the application of both a conventional and an advanced exergy analysis to a supercritical coal-fired power plant. The results show that the ratio of exogenous exergy destruction differs quite a lot from component to component. In general, almost 90% of the total exergy destruction within turbines comes from their endogenous parts, while that of feedwater preheaters contributes more or less 70% to their total exergy destruction. Moreover, the boiler subsystem is proven to have a large amount of exergy destruction caused by the irreversibilities within the remaining components of the overall system. It is also found that the boiler subsystem still has the largest avoidable exergy destruction; however, the enhancement efforts should focus not only on its inherent irreversibilities but also on the inefficiencies within the remaining components. A large part of the avoidable exergy destruction within feedwater preheaters is exogenous; while that of the remaining components is mostly endogenous indicating that the improvements mainly depend on advances in design and operation of the component itself.

Performance analysis of a 500 MWe coal-fired power plant with a post-combustion CO2 capture process

In this study, a performance analysis of a 500 MWe coal-fired power plant with a post-combustion CO2 capture system was performed. The amine-based chemical absorption process was considered as a base CO2 capture system. Based on the design conditions of the flue gas from the supercritical coal-fired power plant operating in the Republic of Korea, the energy consumption of the CO2 capture system was simulated using a process simulator. The simulation of the CO2 capture system was undertaken using Aspen Plus software with ELECNRTL property packages; based on these results, the energy requirement of the CO2 capture system and the overall efficiency of a power plant with the CO2 capture system was estimated. It was observed that the thermal energy required to regenerate the solvent reduces the efficiency of the power plant by 8.36%, the energy required to compress the CO2 from 0.1 to 11 MPa is the next largest factor, reducing the efficiency by 3.59%, and the other energy requirement amounts to 0.45%.

Optimization and Application of Oxygen Control in Supercritical Coal-Fired Power Plant

The general information and features of supercritical unit are illustrated. By controlling the input air according to fuel, combustion efficiency can be ensured. By coordinating the input oxygen in proportion to the load, heat efficiencies and emissions can be accomplished. The detailed design of the control schemes is described. The effectiveness of the proposed schemes is illustrated through industrial application. It’s hoped that the analysis and optimization can provide useful experience and lessons for the design of the supercritical coal-fired unit’s controls.

국내 초임계 석탄화력발전소에 연소 후 CO2포집공정 설치 시 성능 및 경제성 평가

국내 초임계 석탄화력발전소에 연소 후 <TEX>$CO_2$</TEX> 포집공정을 설치하였을 경우에 예상되는 발전단가와 <TEX>$CO_2$</TEX> 저감비용(Cost of <TEX>$CO_2$</TEX> avoided)을 산출하였다. 본 연구에서 고려된 연소 후 <TEX>$CO_2$</TEX> 포집기술은 이미 상업적으로 적용이 가능하고, 기존의 화력발전에 적용이 용이한 아민 화합물을 이용한 화학 흡수법을 기초로 하였으며, 경제성 평가를 위해 연간 발생하는 비용 및 발전량을 연간 균등화(Levelized)하여 발전단가를 산정하는 수명기간 중 발전단가 분석(LCCA: Life Cycle Cost Analysis) 방식을 활용하여 분석하였다. 경제성 평가에서 가장 중요한 항목 중 하나인 설비 투자비(건설비 등) 및 운영비 산출을 위해, 기존의 <TEX>$CO_2$</TEX> 포집 설비가 없는 기준 석탄화력발전소의 건설비는 IEA(국제에너지기구)에서 제시하는 국내 초임계석탄화력 발전소(순출력 767 MW급)의 데이터를 활용하였으며, 석탄화력발전소에 <TEX>$CO_2$</TEX> 포집설비가 추가된 경우에도 IEA에서 제시하는 기준 석탄화력발전소와 <TEX>$CO_2$</TEX> 포집설비 설치 후의 OECD 평균 순공사비(Overnight cost) 증감분을 참조하여 계산하였다. 상기 데이터를 이용하여 기존 석탄화력발전소 및 <TEX>$CO_2$</TEX> 포집 설비 설치 후의 발전단가 및 <TEX>$CO_2$</TEX> 포집비용을 분석한 결과 <TEX>$CO_2$</TEX> 포집설비 설치 후 발전 효율은 기존 초임계 석탄화력발전소의 발전효율 41%에서 31.6%로 약 9.4%가 저하되었으며, 발전단가는 기존의 45.5 USD/MWh에서 73.9 USD/MWh로 약 62%가 증가되었고 <TEX>$CO_2$</TEX> 포집비용은 41.3 USD/<TEX>$tCO_2$</TEX>로 산출되었다. In this study, Economic analysis of supercritical coal-fired power plant with <TEX>$CO_2$</TEX> capture process was performed. For this purpose, chemical absorption method using amine solvent, which is commercially available and most suitable for existing thermal power plant, was studied. For the evaluation of the economic analysis of coal-fired power plant with post-combustion <TEX>$CO_2$</TEX> capture process in Korea, energy penalty after <TEX>$CO_2$</TEX> capture was calculated using the power equivalent factor suggested by Bolland et al. And the overnight cost of power plant (or cost of plant construction) and the operation cost reported by the IEA (International Energy Agency) were used. Based on chemical absorption method using a amine solvent and 3.31 GJ/<TEX>$tonCO_2$</TEX> as a regeneration energy in the stripper, the net power efficiency was reduced from 41.0% (without <TEX>$CO_2$</TEX> capture) to 31.6% (with <TEX>$CO_2$</TEX> capture) and the levelized cost of electricity was increased from 45.5 USD/MWh (Reference case, without <TEX>$CO_2$</TEX> capture) to 73.9 USD/MWh (With <TEX>$CO_2$</TEX> capture) and the cost of <TEX>$CO_2$</TEX> avoided was estimated as 41.3 USD/<TEX>$tonCO_2$</TEX>.

Processing of Advanced Cast Alloys for A-USC Steam Turbine Applications

The high-temperature components within conventional supercritical coal-fired power plants are manufactured from ferritic/martensitic steels. To reduce greenhouse-gas emissions, the efficiency of pulverized coal steam power plants must be increased to as high a temperature and pressure as feasible. The proposed steam temperature in the DOE/NETL Advanced Ultra Supercritical power plant is high enough (760°C) that ferritic/martensitic steels will not work for the majority of high-temperature components in the turbine or for pipes and tubes in the boiler due to temperature limitations of this class of materials. Thus, Ni-based superalloys are being considered for many of these components. Off-the-shelf forged nickel alloys have shown good promise at these temperatures, but further improvements can be made through experimentation within the nominal chemistry range as well as through thermomechanical processing and subsequent heat treatment. However, cast nickel-based superalloys, which possess high strength, creep resistance, and weldability, are typically not available, particularly those with good ductility and toughness that are weldable in thick sections. To address those issues related to thick casting for turbine casings, for example, cast analogs of selected wrought nickel-based superalloys such as alloy 263, Haynes 282, and Nimonic 105 have been produced. Alloy design criteria, melt processing experiences, and heat treatment are discussed with respect to the as-processed and heat-treated microstructures and selected mechanical properties. The discussion concludes with the prospects for full-scale development of a thick section casting for a steam turbine valve chest or rotor casing.

Optimisation of the connection of membrane CCS installation with a supercritical coal-fired power plant

In this paper, the methods of the integration of a supercritical coal-fired power plant with membrane CCS installation are shown. In addition to membrane modules, the CCS installation also consists of two vacuum pumps and two CO2 compressors. In this paper, the relationship between the auxiliary power required to drive these machines and the recoverable amount of heat is shown. This relationship is the reason for the integration of the supercritical coal unit with the CCS installation, which is used for cooling compressed CO2 in the CCS installation by use of condensate (or feed water) from the supercritical coal unit cycle. This cooling process causes both a reduction of the auxiliary power required to drive the compressors and vacuum pumps and increase of power ratio of a steam turbine. In this paper, the optimisation method for minimising the decrease of overall efficiency of the power plant connected with its integration with CCS installation is shown. This results in choosing the optimal pressure ratios in the applied compressors and vacuum pumps under the condition of sufficient heat transmission to the steam turbine cycle. For investigated units, the cost of CO2 emission avoidance and the break-even price of electricity were also calculated.

A technical and economic assessment of ammonia-based post-combustion CO 2 capture at coal-fired power plants

An ammonia-based post-combustion CO 2 capture system processing flue gas from a supercritical coal-fired power plant was modeled, and its estimated performance and cost were compared to an amine-based capture system. For the ammonia system the absorber CO 2 capture efficiency, NH 3 slip, and solids precipitation were evaluated for changes in lean solution NH 3 concentration, NH 3/CO 2 ratio, and absorber temperature. Reductions in NH 3 slip were also assessed for changes in absorber temperature and water wash flow rate. For 90% CO 2 capture the levelized cost of electricity generation (annual revenue requirement) for the plant with ammonia-based capture was estimated at $US 105/MWh, which is comparable to the levelized cost of electricity generation for the plant with an amine-based capture system. The cost of the ammonia-based system was found to depend strongly on the fraction of CO 2 captured as well as on key process design parameters such as lean solution NH 3 concentration. Uncertainties in system performance and cost also were estimated probabistically. Assumptions about plant financing and utilization, as well as uncertainties in cooling costs and reaction rates that affect absorber cost were found in particular to produce a wide range of cost estimates for ammonia-based CO 2 capture systems, and as a result the importance of reducing these uncertainties is emphasized.

ANN-GA based optimization of a high ash coal-fired supercritical power plant

The efficiency of coal-fired power plant depends on various operating parameters such as main steam/reheat steam pressures and temperatures, turbine extraction pressures, and excess air ratio for a given fuel. However, simultaneous optimization of all these operating parameters to achieve the maximum plant efficiency is a challenging task. This study deals with the coupled ANN and GA based (neuro-genetic) optimization of a high ash coal-fired supercritical power plant in Indian climatic condition to determine the maximum possible plant efficiency. The power plant simulation data obtained from a flow-sheet program, “Cycle-Tempo” is used to train the artificial neural network (ANN) to predict the energy input through fuel (coal). The optimum set of various operating parameters that result in the minimum energy input to the power plant is then determined by coupling the trained ANN model as a fitness function with the genetic algorithm (GA). A unit size of 800 MWe currently under development in India is considered to carry out the thermodynamic analysis based on energy and exergy. Apart from optimizing the design parameters, the developed model can also be used for on-line optimization when quick response is required . Furthermore, the effect of various coals on the thermodynamic performance of the optimized power plant is also determined.

Economic and environmental evaluation of selected advanced power generation technologies

In this article, the economic and ecological benefits of selected advanced technologies for electricity production based on coal and natural gas are evaluated. Among the analysed technologies are integrated gasification combined cycle (IGCC) systems, supercritical coal-fired power plants, multi-fuel hybrid cycles, and natural gas combined cycles. In addition, as a complement to coal technologies, CO2 capture and storage installations are adopted. The main indicators evaluated are the unit carbon dioxide emission and the break-even price of electricity. The analysis took into account, among other factors, the existing support mechanisms for ecological technologies, primarily in the form of the European Union (EU) Emissions Trading Scheme. The analysis shows that the systems integrated with CO2 capture can be competitive compared to systems without capture. Especially interesting in this context are IGCC systems integrated with carbon capture installations. The results are, however, affected by many factors, such as the fuel price, operational reliability, and auxiliary power need. The influence of these factors is evaluated in this article both qualitatively and quantitatively.

Economic analysis of amine based carbon dioxide capture system with bi-pressure stripper in supercritical coal-fired power plant

Post-combustion CO2 capture and storage is among the most mature technologies to capture, compress, transport and store CO2 from flue gas in coal-fired power plant. This paper presents the simulation of monoethanolamine (MEA) based CO2 capture and compression process integrated within a 600MWe supercritical coal-fired power plant using chemical process simulators. Comparison between bi-pressure stripper and single-pressure stripper reveals that improved CO2 capture system with bi-pressure stripper minimizes energy penalty of CO2 capture and compression by up to 6.3% at full unit load. The study also explores optimization of some important process parameters affecting the performance of coal-fired power plant by taking into account both CO2 capture process and CO2 compression at full unit load. These parameters include operating stripper pressure, CO2 capture efficiency and steam extraction location. Results show that the optimal stripper pressure is within the range of 1.9–2.1bar and feasible CO2 capture efficiency is between 60% and 90%. Results also show that low-pressure steam extraction reduces energy penalty. Evaluation of improved CO2 capture system is also performed at part flue gas load ranging from 40% to 90%. The study reveals that operating at part flue gas load, as compared with full load, increases energy penalty of carbon capture. Not only energy penalty but also lean solution flow rate and plant efficiency are studied at different flue load levels in this paper. In addition, results show that bi-pressure stripper configuration is also effective in reducing energy penalty at part unit load.

Optimized post combustion carbon capturing on coal fired power plants

Abstract Worldwide coal contributes to over 40% of the electricity generation today and its share is expected to increase steadily over the coming decades. The continued dominance of coal in global energy structure and the growing concern of climate change necessitate accelerated development and deployment of new technologies for clean and efficient coal utilization. Coal fired power plants with CO 2 capture and sequestration (CCS) are widely expected to be an important part of a sensible future technology portfolio to achieve overall global CO 2 reductions required for stabilizing atmospheric CO 2 concentration and stopping global warming. Within the last decades the efficiency of coal fired power plants was significantly raised by different technical steps as running the steam generator on higher temperatures and pressures. So an efficiency (based on LHV) of higher than 45% for hard coal and 43% for lignite coal are more or less the technical standard for modern supercritical coal fired power plants. The amine scrubbing carbon capturing technology, which is planed to be added for fossil fuel fired power stations, will raise the self consumption of the plant and so lower the efficiency drastically. To minimize this effect it is necessary not only to find solvents with a small heat duty for the carbon dioxide scrubbing process, but also to optimize the heat re-integration to the water steam cycle and reduce the electrical self consumption of the scrubbing plant. This can be successfully designed with a detailed review of all key components as the turbine, LP–and HP–preheaters, the steam generator, the flue gas cleaning systems including CO 2 scrubbing equipment and the cooling system of the plant. By improving the internal heat recovery in the power station the efficiency penalty of carbon capture (including the compression) can be reduced to values of 8 percentage points instead of 12 or more percentage points for systems without heat recovery and turbine modifications. This optimization is shown for different stages of heat reintegration from the CO 2 -compression unit, CO 2 capture unit to the water-steam and flue gas side of the power station. Hardware modifications of components like the steam turbine are as well discussed as the additional components to be inserted in the boiler and water-steam cycle. As a global technology and equipment provider for complete thermal power plants, Hitachi has the knowledge and capability to address the above challenges of CCS.

Technical and economic assessment of ammonia-based post-combustion CO2 capture

The performance and cost of two ammonia-based post-combustion CO2 capture systems operating at a new supercritical coal-fired power plant were modeled and compared to an amine-based CO2 capture system operating at a similar plant. This assessment showed that for a fixed coal input, the plant derating of a CO2 capture system operating with high ammonia concentrations (HighNH3) was found to be 2 percentage points lower than a plant with the amine-based system. The plant derating of a CO2 capture system operating with low ammonia concentrations (LowNH3) was substantially higher. Preliminary estimates of the revenue requirement of the plants with HighNH3 and LowNH3 systems are $US 117/MWh and $US 148/MWh respectively, compared to $US 119/MWh for a plant with an amine-based system. The results from this performance assessment and preliminary cost analysis suggest that the LowNH3 system will not be competitive and that the HighNH3 system may have a slight energy and cost advantage over the amine system. Furthermore, a preliminary uncertainty analysis explores the critical factors that may affect the performance and cost estimates of these systems, including the potential for slow reaction kinetics to increase absorber costs, and these results are presented.

Optimization of MEA based post combustion CO2 capture process: Flowsheeting and energetic integration

Abstract The main limitation of post-combustion CO 2 capture technology is the high energy consumption leading to a power output loss of approximately 25% when coupled with CO 2 compression. Studies to break this limitation follow two main paths: formulation of new solvents and optimization of the process flowsheet. The purpose of this works is to assess the impact of the different flowsheet modifications and power plant integration on the plant performance. CO 2 capture amine plant has been integrated in a gross electrical 1200 MWe supercritical coal-fired power plant; a process optimization study coupled with economical and availability analysis has been performed for each studied case and compared to a reference case: standard amine capture process with 30%wt MEA. The capture plant increases the cost of a new power plant by approximately 70% and the electricity price by 45%. Process flowsheet optimization on the amine capture plant do no significantly increase the specific power plant cost (from 0 to 2%) with CO 2 capture, the additional expenditure are compensated with the plant efficiency gains. The cost of electricity is, also, almost not affected by the flowsheet optimization (from −2.5 to +1.5%). The best tested configuration allows a reduction of 10% of the cost of avoided CO 2 . The addition of a capture plant increases by approximately 1.4%pt the risk of forced outage factor and therefore decreases the whole power plant availability by the same value. The effects of the availability decreases due to the capture plant on CO 2 and electricity prices are negligible. This work shows that these modifications alone are not sufficient to enable an economically feasible carbon capture on coal fired power plant despites a loss of efficiency of approximately 10%pt. The goal of less than 5%pt efficiency losses induced by post combustion carbon capture need a combination of new solvent and optimized process or a totally new breakthrough process.

Improvements of Feedwater Controller for the Super Fast Reactor

The main steam temperature of SCWRs sensitively changes with the power-to-flow ratio. In this article, the feedwater controller of the Super FR (fast-spectrum SCWR) is modified from that of the Super LWR (thermal-spectrum SCWR) for suppressing the variation of the main steam temperature. A plant system analysis code SPRAT-F is used. One of three feedback terms is added to the original feedwater controller that took only the deviation of the main steam temperature into consideration. In the feedwater controller (A), the deviation of the power-to-flow ratio is considered. In the feedwater controller (B), the deviation of the power is considered. In the feedwater controller (C), the time derivative of the power is considered. All the modified feedwater controllers keep the variation of the main steam temperature within 2°C, which has been achieved in recent supercritical coal-fired power plants, against typical load change. In order to further confirm the performance of the modified feedwater controllers, five typical perturbations are analyzed. All the feedwater controllers including the original one stably control the Super FR against all the perturbations without a significant oscillation or offset. Among them, the feedwater controller (B) gives a smaller or at least not larger variation of the main steam temperature compared with the original one at all the perturbations, while the feedwater controllers (A) and (C) give a larger variation in particular cases. From these results, it is concluded that the original feedwater controller is successfully improved as the feedwater controller (B).

How clean is clean? Incremental versus radical technological change in coal-fired power plants

In the discussion on innovations for sustainable development, radical innovations are frequently called for in order to transform society into a system perceived as sustainable successfully. The reason for this is the greater environmental efficiency of these innovations. This hypothesis is, however, not supported by empirical evidence. Given the background of a global increase in coal-fired power plants and the consequent environmental impacts to be expected, the hypothesis that radical innovations are superior to incremental innovations and will thus be introduced to the market is reviewed on the basis of fossil fuel power plants. In this paper we examine the diffusion of incremental and radical innovations in the field of power plants and the basic obstacles confronting these innovations. For example, we compare Pressurized Pulverized Coal Combustion (PPCC) as a radical innovation and supercritical coal-fired power plants as an incremental innovation. PPCC failed due to technological uncertainty. We show in an ex-post analysis of the German R&D portfolio for power plants in the past three decades from an environmental viewpoint that, for radically innovative technologies, it was difficult to be accepted by possible investors. The future potential of radical innovations in the field of power plant technology is to be regarded as relatively low, especially due to technological uncertainty, market uncertainty and sunk costs. The conclusion for future R&D work in the sector of large-scale power plants is that an innovation is more likely to succeed if it follows established technological trajectories. In the context of energy market liberalization, hardly any radical innovations are expected in the technology of power plants. The findings of this paper may also be helpful to evaluate risks or probabilities of success of technologies being developed currently. We discuss for example the technological trajectories currently favored in CO2 capture.

Evolution of Carbide Precipitates in 2.25Cr-1Mo Steel during Long-Term Service in a Power Plant

Carbide precipitation from the steel matrix during long-term high-temperature exposure can adversely affect the fracture toughness and high-temperature creep resistance of materials with implications on the performance of power plant components. In the present work, carbide evolution in 2.25Cr-1Mo steel after long-term aging during service was investigated. Boiler pipe samples of this steel were removed from a supercritical water-cooled coal-fired power plant after service times of 17 and 28 years and a mean operational temperature of 810 K (537 °C). The carbide precipitation and coarsening effects were studied using the carbon extraction replica technique followed by analysis using transmission electron microscopy and energy dispersive X-ray spectroscopy. The carbides extracted using an electrolytic technique were also analyzed using X-ray diffraction to evaluate phase transformations of the carbides during long-term service. Small ball punch and Vickers hardness were used to evaluate the changes in mechanical performance after long-term aging during service.

Integration of post-combustion capture and storage into a pulverized coal-fired power plant

Post-combustion CO 2 capture and storage (CCS) presents a promising strategy to capture, compress, transport and store CO 2 from a high volume–low pressure flue gas stream emitted from a fossil fuel-fired power plant. This work undertakes the simulation of CO 2 capture and compression integration into an 800 MW e supercritical coal-fired power plant using chemical process simulators. The focus is not only on the simulation of full load of flue gas stream into the CO 2 capture and compression, but also, on the impact of a partial load. The result reveals that the energy penalty of a low capture efficiency, for example, at 50% capture efficiency with 10% flue gas load is higher than for 90% flue gas load at the equivalent capture efficiency by about 440 kWh e/tonne CO 2. The study also addresses the effect of CO 2 capture performance by different coal ranks. It is found that lignite pulverized coal (PC)-fired power plant has a higher energy requirement than subbituminous and bituminous PC-fired power plants by 40.1 and 98.6 MW e, respectively. In addition to the investigation of energy requirement, other significant parameters including energy penalty, plant efficiency, amine flow rate and extracted steam flow rate, are also presented. The study reveals that operating at partial load, for example at half load with 90% CO 2 capture efficiency, as compared with full load, reduces the energy penalty, plant efficiency drop, amine flow rate and extracted steam flow rate by 9.9%, 24.4%, 50.0% and 49.9%, respectively. In addition, the effect of steam extracted from different locations from a series of steam turbine with the objective to achieve the lowest possible energy penalty is evaluated. The simulation shows that a low extracted steam pressure from a series of steam turbines, for example at 300 kPa, minimizes the energy penalty by up to 25.3%.

Improvements of Feedwater Controller for the Super Fast Reactor

The main steam temperature of SCWRs sensitively changes with the power-to-flow ratio. In this article, the feedwater controller of the Super FR (fast-spectrum SCWR) is modified from that of the Super LWR (thermal-spectrum SCWR) for suppressing the variation of the main steam temperature. A plant system analysis code SPRAT-F is used. One of three feedback terms is added to the original feedwater controller that took only the deviation of the main steam temperature into consideration. In the feedwater controller (A), the deviation of the power-to-flow ratio is considered. In the feedwater controller (B), the deviation of the power is considered. In the feedwater controller (C), the time derivative of the power is considered. All the modified feedwater controllers keep the variation of the main steam temperature within 2°C, which has been achieved in recent supercritical coal-fired power plants, against typical load change. In order to further confirm the performance of the modified feedwater controllers, five typical perturbations are analyzed. All the feedwater controllers including the original one stably control the Super FR against all the perturbations without a significant oscillation or offset. Among them, the feedwater controller (B) gives a smaller or at least not larger variation of the main steam temperature compared with the original one at all the perturbations, while the feedwater controllers (A) and (C) give a larger variation in particular cases. From these results, it is concluded that the original feedwater controller is successfully improved as the feedwater controller (B).

Integration of CO2 capture unit using blended MEA–AMP solution into coal-fired power plants

This study evaluated feasibility of using blended MEA and 2-amino-2-methyl-1-propanol (AMP) in the CO2 capture unit that is integrated into a supercritical coal-fired power plant. The evaluation was carried out by using the integrated power plant and gas absorption model developed at the University of Regina, Canada. Simulation results were presented in terms of energy requirement for solvent regeneration, sizes of absorber and regenerator, cost of CO2 capture and energy penalty. Conventional MEA process was also simulated and used as a benchmark for a comparison purpose.

Capture-ready supercritical coal-fired power plants and flexible post-combustion CO2 capture

Abstract 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.