Cost and performance of fossil fuel power plants with CO2 capture and storage

CO₂ capture and storage (CCS) is receiving considerable attention as a potential greenhouse gas (GHG) mitigation option for fossil fuel power plants. Cost and performance estimates for CCS are critical factors in energy and policy analysis. CCS cost studies necessarily employ a host of technical and economic assumptions that can dramatically affect results. Thus, particular studies often are of limited value to analysts, researchers, and industry personnel seeking results for alternative cases. In this paper, we use a generalized modeling tool to estimate and compare the emissions, efficiency, resource requirements and current costs of fossil fuel power plants with CCS on a systematic basis. This plant-level analysis explores a broader range of key assumptions than found in recent studies we reviewed for three major plant types: pulverized coal (PC) plants, natural gas combined cycle (NGCC) plants, and integrated gasification combined cycle (IGCC) systems using coal. In particular, we examine the effects of recent increases in capital costs and natural gas prices, as well as effects of differential plant utilization rates, IGCC financing and operating assumptions, variations in plant size, and differences in fuel quality, including bituminous, sub-bituminous and lignite coals. Our results show higher power plant and CCS costs than prior studies as a consequence of recent escalations in capital and operating costs. The broader range of cases also reveals differences not previously reported in the relative costs of PC, NGCC and IGCC plants with and without CCS. While CCS can significantly reduce power plant emissions of CO₂ (typically by 85–90%), the impacts of CCS energy requirements on plant-level resource requirements and multi-media environmental emissions also are found to be significant, with increases of approximately 15–30% for current CCS systems. To characterize such impacts, an alternative definition of the “energy penalty” is proposed in lieu of the prevailing use of this term.     

The long-term life cycle private and external costs of high coal usage in the US

Using four times as much coal in 2050 for electricity production need not degrade air quality or increase greenhouse gas emissions. Current SO_x and NO_x emissions from the power sector could be reduced from 12 to less than 1 and from 5 to 2 million tons annually, respectively, using advanced technology. While direct CO₂ emissions from new power plants could be reduced by over 87%, life cycle emissions could increase by over 25% due to the additional coal that is required to be mined and transported to compensate for the energy penalty of the carbon capture and storage technology. Strict environmental controls push capital costs of pulverized coal (PC) and integrated coal gasification combined cycle (IGCC) plants to $1500–1700/kW and $1600–2000/kW, respectively. Adding carbon capture and storage (CCS) increases costs to $2400–2700/kW and $2100–3000/kW (2005 dollars), respectively. Adding CCS reduces the 40–43% efficiency of the ultra-supercritical PC plant to 31–34%; adding CCS reduces the 32–38% efficiency of the GE IGCC plant to 27–33%. For IGCC, PC, and natural gas combined cycle (NGCC) plants, the carbon dioxide tax would have to be $53, $74, and $61, respectively, to make electricity from a plant with CCS cheaper. Capturing and storing 90% of the CO₂ emissions increases life cycle costs from 5.4 to 11.6 cents/kWh. This analysis shows that 90% CCS removal efficiency, although being a large improvement over current electricity generation emissions, results in life cycle emissions that are large enough that additional effort is required to achieve significant economy-wide reductions in the US for this large increase in electricity generation using either coal or natural gas.     

Effects of technological learning on future cost and performance of power plants with CO2 capture

This paper demonstrates the concept of applying learning curves in a consistent manner to performance as well as cost variables in order to assess the future development of power plants with CO₂ capture. An existing model developed at Carnegie Mellon University, which had provided insight into the potential learning of cost variables in power plants with CO₂ capture, is extended with learning curves for several key performance variables, including the overall energy loss in power plants, the energy required for CO₂ capture, the CO₂ capture ratio (removal efficiency), and the power plant availability. Next, learning rates for both performance and cost parameters were combined with global capacity projections for fossil-fired power plants to estimate future cost and performance of these power plants with and without CO₂ capture. The results of global learning are explicitly reported, so that they can be used for other purposes such as in regional bottom-up models. Results of this study show that IGCC with CO₂ capture has the largest learning potential, with significant improvements in efficiency and reductions in cost between 2001 and 2050 under the condition that around 3100 GW of combined cycle capacity is installed worldwide. Furthermore, in a scenario with a strict climate policy, mitigation costs in 2030 are 26, 11, 19 €/t (excluding CO₂ transport and storage costs) for NGCC, IGCC, and PC power plants with CO₂ capture, respectively, compared to 42, 13, and 32 €/t in a scenario with a limited climate policy. Additional results are presented for IGCC, PC, and NGCC plants with and without CO₂ capture, and a sensitivity analysis is employed to show the impacts of alternative assumptions on projected learning rates of different systems.     

CO2 control technology effects on IGCC plant performance and cost

As part of the USDOE's Carbon Sequestration Program, an integrated modeling framework has been developed to evaluate the performance and cost of alternative carbon capture and storage (CCS) technologies for fossil-fueled power plants in the context of multi-pollutant control requirements. This paper uses the newly developed model of an integrated gasification combined cycle (IGCC) plant to analyze the effects of adding CCS to an IGCC system employing a GE quench gasifier with water gas shift reactors and a Selexol system for CO₂ capture. Parameters of interest include the effects on plant performance and cost of varying the CO₂ removal efficiency, the quality and cost of coal, and selected other factors affecting overall plant performance and cost. The stochastic simulation capability of the model is also used to illustrate the effect of uncertainties or variability in key process and cost parameters. The potential for advanced oxygen production and gas turbine technologies to reduce the cost and environmental impacts of IGCC with CCS is also analyzed.     

Pre-combustion, post-combustion and oxy-combustion in thermal power plant for CO2 capture

This paper presents a summary of technical-economic studies. It allows evaluating, in the French context, the production cost of electricity derived from coal and gas power plants with the capture of CO₂, and the cost per tonne of CO₂ avoided. Three systems were studied: an Integrated Gasification Combined Cycle (IGCC), a conventional combustion of Pulverized Coal (PC) and a Natural Gas Combined Cycle (NGCC). Three main methods were envisaged for the capture of CO₂: pre-combustion, post-combustion and oxy-combustion.For the IGCC, two gasification types have been studied: a current technology based on gasification of dry coal at 27 bars (Shell or GE/Texaco radiant type) integrated into a classical combined cycle providing 320 MWe, and a future technology (planned for about 2015–2020) based on gasification of a coal–water mixture (slurry) that can be compressed to 64 bars (GE/Texaco slurry type) integrated into an advanced combined cycle (type H with steam cooling of the combustion turbine blades) producing a gross power output of 1200 MWe.     

Effects of supplementary biomass firing on the performance of combined cycle power generation: A comparison between NGCC and IGCC plants

In the present work, effects of biomass supplementary firing on the performance of fossil fuel fired combined cycles have been analyzed. Both natural gas fired combined cycle (NGCC) and integrated coal gasification combined cycle (IGCC) have been considered in the study. The efficiency of the NGCC plant monotonically reduces with the increase in supplementary firing, while for the IGCC plant the maximum plant efficiency occurs at an optimum degree of supplementary firing. This difference in the nature of variation of the efficiency of two plants under the influence of supplementary firing has been critically analyzed in the paper. The ratings of different plant equipments, fuel flow rates and the emission indices of CO₂ from the plants at varying degree of supplementary firing have been evaluated for a net power output of 200 MW. The fraction of total power generated by the bottoming cycle increases with the increase in supplementary firing. However, the decrease in the ratings of gas turbines is much more than the increase in that of the steam turbines due to the low work ratio of the topping cycle. The NGCC plants require less biomass compared to the IGCC under identical condition. A critical degree of supplementary firing has been identified for the slag free operation of the biomass combustor. The performance parameters, equipment ratings and fuel flow rates for no supplementary firing and for the critical degree of supplementary biomass firing have been compared for the NGCC and IGCC plants.     

Combined power and hydrogen production from coal. Part B: Comparison between the IGHP and CPH systems

Currently, plants for hydrogen production from coal are based on IGCC (Integrated Gasification Combined Cycle) technologies with CO₂ capture and electrical power is also produced by using the purge gas coming from the hydrogen separation unit as fuel in a gas turbine combined cycle.     

Optimal greenhouse gas emissions in NGCC plants integrating life cycle assessment

The optimal design of an energy-intensive process involves a compromise between costs and greenhouse gas emissions, complicated by the interaction between optimal process emissions and supply chain emissions. We propose a method that combines generic abatement cost estimates and the results of existing (LCA) life cycle assessment studies, so that supply chain emissions are properly handled during optimization. This method is illustrated for a (NGCC) natural gas combined cycle power plant model with the following design and procurement options: procurement of natural gas from low-emissions producers, fuel substitution with (SNG) synthetic natural gas from wood, and variable-rate CO₂ capture and sequestration from both the NGCC and SNG plants. Using multi-objective optimization, we show two Pareto-optimal sets with and without the proposed LCA method. The latter can then be shown to misestimate CO₂ abatement costs by a few percent, penalizing alternate fuels and energy-efficient process configurations and leading to sub-optimal design decisions with potential net losses of the order of $1/MWh. Thus, the proposed LCA method can enhance the economic analysis of emissions abatement technologies and emissions legislation in general.     

Comparative assessment of future power generation technologies based on carbon price development

The long-term assessment of new electricity generation was performed for various long-run policy scenarios taking into account two main criteria: private costs and external GHG emission costs. Such policy oriented power generation technologies assessment based on carbon price and private costs of technologies can provide information on the most attractive future electricity generation technologies taking into account climate change mitigation targets and GHG emission reduction commitments for world regions.Analysis of life cycle GHG emissions and private costs of the main future electricity generation technologies performed in this paper indicated that biomass technologies except large scale straw combustion technologies followed by nuclear have the lowest life cycle GHG emission. Biomass IGCC with CO₂ capture has even negative life cycle GHG emissions. The cheapest future electricity generation technologies in terms of private costs in long-term perspective are: nuclear and hard coal technologies followed by large scale biomass combustion and biomass CHPs. The most expensive technologies in terms of private costs are: oil and natural gas technologies. As the electricity generation technologies having the lowest life cycle GHG emissions are not the cheapest one in terms of private costs the ranking of technologies in terms of competitiveness highly depend on the carbon price implied by various policy scenarios integrating specific GHG emission reduction commitments taken by countries and climate change mitigation targets.     

Clean coal technology development in China

Coal is found in huge amounts throughout the world and is expected to play a crucial role as an abundant energy source. However, one critical issue in promoting coal utilization is controlling environmental pollution. Clean coal technologies are needed to utilize coal in an environmentally acceptable way and to improve coal utilization efficiency. This paper describes coal's role in China's energy system and the environmental issues related to coal use. Coal is responsible for 90% of the SO₂ emissions, 70% of the dust emissions, 67% of the NO_x emissions, and 70% of the CO₂ emissions. But as the most abundant energy resource, it will continue to be the dominant energy supply for a long time. Therefore, the development and deployment of clean coal technologies are crucial to promote sustainable development in China. Clean coal technologies currently being developed in China are described including high efficiency combustion and advanced power generation technologies, coal transformation technologies, IGCC (integrated gasification combined cycle) and carbon capture and storage (CCS). Although China only recently began developing clean coal technologies, there have been many successes. Most recent orders of coal-fired power plants are units larger than 600 MW and new orders for supercritical and ultra supercritical systems are increasing rapidly. Many national research programs, industrial research programs and international collaboration projects have been launched to develop on IGCC and CCS systems in China. Finally, suggestions are given on how to further promote clean coal technologies in China.     

Effect of supplementary firing options on cycle performance and CO2 emissions of an IGCC power generation system

Supplementary firing is adopted in combined‐cycle power plants to reheat low‐temperature gas turbine exhaust before entering into the heat recovery steam generator. In an effort to identify suitable supplementary firing options in an integrated gasification combined‐cycle (IGCC) power plant configuration, so as to use coal effectively, the performance is compared for three different supplementary firing options. The comparison identifies the better of the supplementary firing options based on higher efficiency and work output per unit mass of coal and lower CO₂ emissions. The three supplementary firing options with the corresponding fuel used for the supplementary firing are: (i) partial gasification with char, (ii) full gasification with coal and (iii) full gasification with syngas. The performance of the IGCC system with these three options is compared with an option of the IGCC system without supplementary firing. Each supplementary firing option also involves pre‐heating of the air entering the gas turbine combustion chamber in the gas cycle and reheating of the low‐pressure steam in the steam cycle. The effects on coal consumption and CO₂ emissions are analysed by varying the operating conditions such as pressure ratio, gas turbine inlet temperature, air pre‐heat and supplementary firing temperature. The results indicate that more work output is produced per unit mass of coal when there is no supplementary firing. Among the supplementary firing options, the full gasification with syngas option produces the highest work output per unit mass of coal, and the partial gasification with char option emits the lowest amount of CO₂ per unit mass of coal. Based on the analysis, the most advantageous option for low specific coal consumption and CO₂ emissions is the supplementary firing case having full gasification with syngas as the fuel. Copyright © 2008 John Wiley & Sons, Ltd.     

Trade-off in emissions of acid gas pollutants and of carbon dioxide in fossil fuel power plants with carbon capture

This paper investigates the impact of capture of carbon dioxide (CO₂) from fossil fuel power plants on the emissions of nitrogen oxides (NO_X) and sulphur oxides (SO_X), which are acid gas pollutants. This was done by estimating the emissions of these chemical compounds from natural gas combined cycle and pulverized coal plants, equipped with post-combustion carbon capture technology for the removal of CO₂ from their flue gases, and comparing them with the emissions of similar plants without CO₂ capture. The capture of CO₂ is not likely to increase the emissions of acid gas pollutants from individual power plants; on the contrary, some NO_X and SO_X will also be removed during the capture of CO₂. The large-scale implementation of carbon capture is however likely to increase the emission levels of NO_X from the power sector due to the reduced efficiency of power plants equipped with capture technologies. Furthermore, SO_X emissions from coal plants should be decreased to avoid significant losses of the chemicals that are used to capture CO₂. The increase in the quantity of NO_X emissions will be however low, estimated at 5% for the natural gas power plant park and 24% for the coal plants, while the emissions of SO_X from coal fired plants will be reduced by as much as 99% when at least 80% of the CO₂ generated will be captured.     

Process simulation and integration of IGCC systems for H2/syngas/electricity generation with control on CO2 emissions

IGCC is a pre-combustion technology that can be effectively used to produce both hydrogen and electricity while reducing the greenhouse gas (GHG) emissions. Two process models are developed in Aspen Plus^® software and are compared techno-economically. The conventional design of IGCC process is taken as case 1, whereas, case 2 represents the conceptual design of sequential integration of reforming model with the gasification unit to enhance the syngas yield. The case 2 utilizes the steam generated in the gasification process to sustain the methane reforming process which consequently enhances both the H₂ production capacity and cold gas efficiency. It has been analyzed from results that case 2 can enhance the process performance by 4.77% and economics in terms of cost of electricity by 5.9% compared to the conventional process. However, the utilization of natural gas in the case 2 is considered as a standalone fuel so the process performance of NGCC power plants has been also incorporated to ensure the realistic analysis. The results also showed that case 2 design offers 3.9% higher process performance than the cumulative (IGCC + NGCC) processes, respectively. Moreover, the CO₂ specific emissions and LCOE for the case 2 is also lower than the case.     

Performance and cost of wet and dry cooling systems for pulverized coal power plants with and without carbon capture and storage

Thermoelectric power plants require significant quantities of water, primarily for the purpose of cooling. Water also is becoming critically important for low-carbon power generation. To reduce greenhouse gas emissions from pulverized coal (PC) power plants, post-combustion carbon capture and storage (CCS) systems are receiving considerable attention. However, current CO₂ capture systems require a significant amount of cooling. This paper evaluates and quantifies the plant-level performance and cost of different cooling technologies for PC power plants with and without CO₂ capture. Included are recirculating systems with wet cooling towers and air-cooled condensers (ACCs) for dry cooling. We examine a range of key factors affecting cooling system performance, cost and plant water use, including the plant steam cycle design, coal type, carbon capture system design, and local ambient conditions. Options for reducing power plant water consumption also are presented.     

Techno-economic appraisal of fossil-fuelled power generation systems with carbon dioxide capture and storage

Carbon capture and storage (CCS) facilities coupled to power plants provide a climate change mitigation strategy that potentially permits the continued use of fossil fuels whilst reducing the carbon dioxide (CO₂) emissions. This process involves three basic stages: capture and compression of CO₂ from power stations, transport of CO₂, and storage away from the atmosphere for hundreds to thousands of years. Potential routes for the capture, transport and storage of CO₂ from United Kingdom (UK) power plants are examined. Six indicative options are evaluated, based on ‘Pulverised Coal’, ‘Natural Gas Combined Cycle’, and ‘Integrated (coal) Gasification Combined Cycle’ power stations. Chemical and physical CO₂ absorption capture techniques are employed with realistic transport possibilities to ‘Enhanced Oil Recovery’ sites or depleted gas fields in the North Sea. The selected options are quantitatively assessed against well-established economic and energy-related criteria. Results show that CO₂ capture can reduce emissions by over 90%. However, this will reduce the efficiency of the power plants concerned, incurring energy penalties between 14 and 30% compared to reference plants without capture. Costs of capture, transport and storage are concatenated to show that the whole CCS chain ‘cost of electricity’ (COE) rises by 27-142% depending on the option adopted. This is a significant cost increase, although calculations show that the average ‘cost of CO₂ captured’ is £15/tCO₂ in 2005 prices [the current base year for official UK producer price indices]. If potential governmental carbon penalties were introduced at this level, then the COE would equate to the same as the reference plant, and make CCS a viable option to help mitigate large-scale climate change.     

Towards net-zero compatible hydrogen from steam reformation – Techno-economic analysis of process design options

Increased consumption of low-carbon hydrogen is prominent in the decarbonisation strategies of many jurisdictions. Yet prior studies assessing the current most prevalent production method, steam reformation of natural gas (SRNG), have not sufficiently evaluated how process design decisions affect life cycle greenhouse gas (GHG) emissions. This techno-economic case study assesses cradle-to-gate emissions of hydrogen produced from SRNG with CO₂ capture and storage (CCS) in British Columbia, Canada. Four process configurations with amine-based CCS using existing technology and novel process designs are evaluated. We find that cradle-to-gate GHG emission intensity ranges from 0.7 to 2.7 kgCO₂e/kgH₂ – significantly lower than previous studies of SRNG with CCS and similar to the range of published estimates for hydrogen produced from renewable-powered electrolysis. The levelized cost of hydrogen (LCOH) in this study (US$1.1–1.3/kgH₂) is significantly lower than published estimates for renewable-powered electrolysis.     

Reducing life cycle greenhouse gas emissions of corn ethanol by integrating biomass to produce heat and power at ethanol plants

A life-cycle assessment (LCA) of corn ethanol was conducted to determine the reduction in the life-cycle greenhouse gas (GHG) emissions for corn ethanol compared to gasoline by integrating biomass fuels to replace fossil fuels (natural gas and grid electricity) in a U.S. Midwest dry-grind corn ethanol plant producing 0.19 hm³ y⁻¹ of denatured ethanol. The biomass fuels studied are corn stover and ethanol co-products [dried distillers grains with solubles (DDGS), and syrup (solubles portion of DDGS)]. The biomass conversion technologies/systems considered are process heat (PH) only systems, combined heat and power (CHP) systems, and biomass integrated gasification combined cycle (BIGCC) systems. The life-cycle GHG emission reduction for corn ethanol compared to gasoline is 38.9% for PH with natural gas, 57.7% for PH with corn stover, 79.1% for CHP with corn stover, 78.2% for IGCC with natural gas, 119.0% for BIGCC with corn stover, and 111.4% for BIGCC with syrup and stover. These GHG emission estimates do not include indirect land use change effects. GHG emission reductions for CHP, IGCC, and BIGCC include power sent to the grid which replaces electricity from coal. BIGCC results in greater reductions in GHG emissions than IGCC with natural gas because biomass is substituted for fossil fuels. In addition, underground sequestration of CO₂ gas from the ethanol plant’s fermentation tank could further reduce the life-cycle GHG emission for corn ethanol by 32% compared to gasoline.     

A comparison of electricity and hydrogen production systems with CO2 capture and storage. Part A: Review and selection of promising conversion and capture technologies

We performed a consistent comparison of state-of-the-art and advanced electricity and hydrogen production technologies with CO₂ capture using coal and natural gas, inspired by the large number of studies, of which the results can in fact not be compared due to specific assumptions made. After literature review, a standardisation and selection exercise has been performed to get figures on conversion efficiency, energy production costs and CO₂ avoidance costs of different technologies, the main parameters for comparison. On the short term, electricity can be produced with 85–90% CO₂ capture by means of NGCC and PC with chemical absorption and IGCC with physical absorption at 4.7–6.9 €ct/kWh, assuming a coal and natural gas price of 1.7 and 4.7 €/GJ. CO₂ avoidance costs are between 15 and 50 €/t CO₂ for IGCC and NGCC, respectively. On the longer term, both improvements in existing conversion and capture technologies are foreseen as well as new power cycles integrating advanced turbines, fuel cells and novel (high-temperature) separation technologies. Electricity production costs might be reduced to 4.5–5.3 €ct/kWh with advanced technologies. However, no clear ranking can be made due to large uncertainties pertaining to investment and O&M costs. Hydrogen production is more attractive for low-cost CO₂ capture than electricity production. Costs of large-scale hydrogen production by means of steam methane reforming and coal gasification with CO₂ capture from the shifted syngas are estimated at 9.5 and 7 €/GJ, respectively. Advanced autothermal reforming and coal gasification deploying ion transport membranes might further reduce production costs to 8.1 and 6.4 €/GJ. Membrane reformers enable small-scale hydrogen production at nearly 17 €/GJ with relatively low-cost CO₂ capture.     

Natural gas combined cycle with exhaust gas recirculation and CO2 capture at part-load operation

This paper aims to evaluate part-load operation of a natural gas combined cycle (NGCC) power plant with exhaust gas recirculation (EGR) and a CO₂ capture plant. Several studies have demonstrated the feasibility and the advantages of EGR at full load, but operation at part load is also important because it is a common condition when NGCC power plants are being used as backup for renewables. The results of this study show that the number of absorber trains is reduced from 4 to 3 with EGR. The efficiency of the NGCC plant with EGR was 0.5% points higher than a conventional NGCC at full load as a result of a higher CO₂ concentration in the flue gas. However, this efficiency advantage decreased as the load was reduced from 100% to 50%, with both cases presenting the same efficiency at 50% load. This means that there was no benefit from the effect of EGR at lower loads. The efficiency of a NGCC plant with EGR and CO₂ capture configuration decreased from 52.6% to 45.9% when the load was reduced from 100% to 50% compared with a conventional NGCC where the efficiency changed from 52.1% to 45.9%. It was concluded that a NGCC plant with EGR and CO₂ capture is viable, results in lower capital costs due to the smaller number of absorber trains and yields slightly higher efficiencies, for operation at part-load down to 50%.     

Carbon capture and storage: Fundamental thermodynamics and current technology

Carbon capture and storage (CCS) is considered a leading technology for reducing CO₂ emissions from fossil-fuelled electricity generation plants and could permit the continued use of coal and gas whilst meeting greenhouse gas targets. However considerable energy is required for the capture, compression, transport and storage steps involved. In this paper, energy penalty information in the literature is reviewed, and thermodynamically ideal and “real world” energy penalty values are calculated. For a sub-critical pulverized coal (PC) plant, the energy penalty values for 100% capture are 48.6% and 43.5% for liquefied CO₂, and for CO₂ compressed to 11 MPa, respectively. When assumptions for supercritical plants were incorporated, results were in broad agreement with published values arising from process modelling. However, we show that energy use in existing capture operations is considerably greater than indicated by most projections. Full CCS demonstration plants are now required to verify modelled energy penalty values. However, it appears unlikely that CCS will deliver significant CO₂ reductions in a timely fashion. In addition, many uncertainties remain over the permanence of CO₂ storage, either in geological formations, or beneath the ocean. We conclude that further investment in CCS should be seriously questioned by policy makers.