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.     

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.     

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.     

Evaluation of power generation schemes based on hydrogen-fuelled combined cycle with carbon capture and storage (CCS)

IGCC is a power generation technology in which the solid feedstock is partially oxidized to produce syngas. In a modified IGCC design for carbon capture, there are several technological options which are evaluated in this paper. The first two options involve pre-combustion arrangements in which syngas is processed, either by shift conversion or chemical looping, to maximise the hydrogen level and to concentrate the carbon species as CO₂. After CO₂ capture by gas-liquid absorption or chemical looping, the hydrogen-rich gas is used for power generation. The third capture option is based on post-combustion arrangement using chemical absorption.Investigated coal-based IGCC case studies produce 400-500 MW net power with more than 90% carbon capture rate. Principal focus of the paper is concentrated on evaluation of key performance indicators for investigated carbon capture options, the influence of various gasifiers on carbon capture process, optimisation of energy efficiency by heat and power integration, quality specification of captured CO₂. The capture option with minimal energy penalty is based on chemical looping, followed by pre-combustion and post-combustion.     

Hydrogen production from fossil fuels with carbon capture and storage based on chemical looping systems

This paper analyzes innovative processes for producing hydrogen from fossil fuels conversion (natural gas, coal, lignite) based on chemical looping techniques, allowing intrinsic CO₂ capture. This paper evaluates in details the iron-based chemical looping system used for hydrogen production in conjunction with natural gas and syngas produced from coal and lignite gasification. The paper assesses the potential applications of natural gas and syngas chemical looping combustion systems to generate hydrogen. Investigated plant concepts with natural gas and syngas-based chemical looping method produce 500 MW hydrogen (based on lower heating value) covering ancillary power consumption with an almost total decarbonisation rate of the fossil fuels used.The paper presents in details the plant concepts and the methodology used to evaluate the performances using critical design factors like: gasifier feeding system (various fuel transport gases), heat and power integration analysis, potential ways to increase the overall energy efficiency (e.g. steam integration of chemical looping unit into the combined cycle), hydrogen and carbon dioxide quality specifications considering the use of hydrogen in transport (fuel cells) and carbon dioxide storage in geological formation or used for EOR.     

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.     

Engineering economic analysis of biomass IGCC with carbon capture and storage

Integration of biomass energy technologies with carbon capture and sequestration could yield useful energy products and negative net atmospheric carbon emissions. We survey the methods of integrating biomass technologies with carbon dioxide capture, and model an IGCC electric power system in detail. Our engineering process model, based on analysis and operational results of the Battelle/Future Energy Resources Corporation gasifier technology, integrates gasification, syngas conditioning, and carbon capture with a combined cycle gas turbine to generate electricity with negative net carbon emissions. Our baseline system has a net generation of 123 MW_e, 28% thermal efficiency, 44% carbon capture efficiency, and specific capital cost of 1,730 $ kW_e⁻¹. Economic analysis suggests this technology could be roughly cost competitive with more conventional methods of achieving deep reductions in CO₂ emissions from electric power. The potential to generate negative emissions could provide cost-effective emissions offsets for sources where direct mitigation is expected to be difficult, and will be increasingly important as mitigation targets become more stringent.     

Techno-economic evaluation of coal-to-liquids (CTL) plants with carbon capture and sequestration

Coal-to-liquids (CTL) processes that generate synthetic liquid fuels from coal are of increasing interest in light of the substantial rise in world oil prices in recent years. A major concern, however, is the large emissions of CO₂ from the process, which would add to the burden of atmospheric greenhouse gases. To assess the options, impacts and costs of controlling CO₂ emissions from a CTL plant, a comprehensive techno-economic assessment model of CTL plants has been developed, capable of incorporating technology options for carbon capture and storage (CCS). The model was used to study the performance and cost of a liquids-only plant as well as a co-production plant, which produces both liquids and electricity. The effect of uncertainty and variability of key parameters on the cost of liquids production was quantified, as were the effects of alternative carbon constraints such as choice of CCS technology and the effective price (or tax) on CO₂ emissions imposed by a climate regulatory policy. The efficiency and CO₂ emissions from a co-production plant also were compared to the separate production of liquid fuels and electricity. The results for a 50,000 barrels/day case study plant are presented.     

Life cycle assessment of geothermal binary power plants using enhanced low-temperature reservoirs

Geothermal binary power plants that use low-temperature heat sources have gained increasing interest in the recent years due to political efforts to reduce greenhouse gas emissions and the consumption of finite energy resources. The construction of such plants requires large amounts of energy and material. Hence, the question arises if geothermal binary power plants are also environmentally promising from a cradle-to-grave point of view. In this context, a comprehensive Life Cycle Analysis (LCA) on geothermal power production from EGS (enhanced geothermal systems) low-temperature reservoirs is performed. The results of the analysis show that the environmental impacts are very much influenced by the geological conditions that can be obtained at a specific site. At sites with (above-) average geological conditions, geothermal binary power generation can significantly contribute to more sustainable power supply. At sites with less favorable conditions, only certain plant designs can make up for the energy and material input to lock up the geothermal reservoir by the provided energy. The main aspects of environmentally sound plants are enhancement of the reservoir productivity, reliable design of the deep wells and an efficient utilization of the geothermal fluid for net power and district heat production.     

Carbon capture and storage

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

Environmental analysis of a German strategy for carbon capture and storage of coal power plants

This paper combines an existing projection of the development of electricity production with a technology-specific environmental assessment. The combination of these two approaches, which so far have only been performed separately, allows a discussion about environmental effects of carbon capture and storage (CCS) implementation strategies on a national level. The results identify the future role of lignite and hard coal in German power production. The implementation of CCS technology leads to a considerable loss of efficiency. Due to CCS, about 50 million t of lignite will be additionally required in 2030 in comparison to the reference case without CCS in 2010. Increasing demand, the replacement of old plants and the compensation of efficiency losses lead to highly ambitious expansion rates. In the case of CCS implementation, the global warming potential (GWP) can be reduced by up to 70%. However, other environmental impacts increase in part considerably. Compliance with national ceilings for NO_x emissions can only be reached by compensation measures in other sectors. The results of the environmental assessment demonstrate the significant role of the coal composition, coal origin and the required transport. CO₂ pipeline transport and CO₂ storage make a fairly minor contribution to the overall environmental impact.     

Greenhouse gas mitigation in a carbon constrained world: The role of carbon capture and storage

Carbon capture and storage (CCS) promises to allow for low-emissions fossil-fuel-based power generation. The technology is under development; a number of technological, economic, environmental and safety issues remain to be solved. CCS may prolong the prevailing coal-to-electricity regime and countervail efforts in other mitigation categories. Given the need to continue using fossil-fuels for some time, however, it may also serve as a bridging technology towards a renewable energy future. In this paper, we analyze the structural characteristics of the CCS innovation system and perform an energy-environment-economic analysis of the potential contribution of CCS, using a general equilibrium model for Germany. We show that a given climate target can be achieved at lower marginal costs when the option of CCS is included into the mix of mitigation options. We conclude that, given an appropriate legal and policy framework, CCS, energy efficiency and some other mitigation efforts are complementary measures and should form part of a broad mix of measures required for a successful CO₂ mitigation strategy.     

Multi-objective design optimization of a natural gas-combined cycle with carbon dioxide capture in a life cycle perspective

The use of multi-objective optimization techniques is attractive to incorporate environmental objectives into the design of energy conversion systems. A method to locally optimize a given process while considering its global environmental impact by using life cycle assessment (LCA) to account for avoidable and unavoidable off-site emissions for each independent material input is presented. It is applied to study the integration of a CO₂-capture process using monoethanolamine in a natural gas-combined cycle power plant, simultaneously optimizing column dimensions, heat exchange, and absorbent flow configuration with respect to two objectives: the levelized cost of electricity and its life cycle global-warming potential. The model combines a process flow-sheeting model and a separate process-integration model. After optimization using an evolutionary algorithm, the results showed that widening the absorber and generating near-atmospheric pressure steam are cost-effective options but that increasing stripper complexity is less so. With $7.80/GJ natural gas and $20/ton CO₂ handling, the minimum on-site CO₂ abatement cost reaches $62.43/ton on a life cycle basis, achieved with a capture rate of over 90%. Of this, $2.13/ton is related to off-site emissions – a specific advantage of LCA that could help industries and governments anticipate the actual future costs of CO₂ capture.     

Hydrogen and power co-generation based on coal and biomass/solid wastes co-gasification with carbon capture and storage

This paper investigates the potential use of renewable energy sources (various sorts of biomass) and solid wastes (municipal wastes, sewage sludge, meat and bone meal etc.) in a co-gasification process with coal to co-generate hydrogen and electricity with carbon capture and storage (CCS). The paper underlines one of the main advantages of gasification technology, namely the possibility to process lower grade fuels (lower grade coals, renewable energy sources, solid wastes etc.), which are more widely available than the high grade coals normally used in normal power plants, this fact contributing to the improvement of energy security supply. Based on a proposed plant concept that generates 400–500 MW net electricity with a flexible output of 0–200 MW_th hydrogen and a carbon capture rate of at least 90%, the paper develops fuel selection criteria for coal blending with various alternative fuels for optimizing plant performance e.g. oxygen consumption, cold gas efficiency, hydrogen production and overall energy efficiency. The key plant performance indicators were calculated for a number of case studies through process flow simulations (ChemCAD).     

Integrated gasification combined cycle and carbon capture: A risky option to mitigate CO2 emissions of coal-fired power plants

The power sectors of many big economies still rely on coal-fired plants and emit huge amounts of carbon dioxide. Emerging countries like Brazil, China and South Africa plan to expand the use of coal-fired thermal plants in the next decade. Integrated gasification combined cycle (IGCC) is an innovative technology that facilitates the implementation of carbon capture (CC). The present work analyzes the maturity and costs of the IGCC technology, with and without CC, and assesses the effect of the technology risk on its economic viability. Findings show that the inclusion of the risk in the economic analysis of IGCC plants raises the cost of CO₂ avoided from 36 US$/t_CO2 to 106 US$/t_CO2 in the case of Shell Gasifiers and from 39 US$/t_CO2 to 112 US$/t_CO2 in the case of GE Gasifiers. Thus, the introduction of IGCC with CC on a wider scale faces huge uncertainties. The feasibility of these plants will rely heavily on the overcoming of the technology risk. Besides, its implementation in the short run will depend on government incentives to bear with the additional cost incurred in the first-generation plants.     

Production of hydrogen-rich fuels for pre-combustion carbon capture in power plants: A thermodynamic assessment

Hydrogen-fueled plants can play an important role in the field of carbon capture and storage, because they facilitate the mitigation of harmful emissions. In this paper, two combined-cycle power plants with pre-combustion CO₂ capture are examined, in which natural gas is converted into a hydrogen-rich fuel through reforming. The first plant considered operates with a hydrogen-separating membrane and the second with an autothermal reformer. The two plants are compared to a reference plant without CO₂ capture and briefly to alternative oxy-fuel and post-combustion capture technologies. It is found that both plants suffer high penalties caused by the high energy requirements of the reforming components and the CO₂ compression units. Additionally, both plants appear inferior to alternative capture technologies. When comparing the two reforming plants, the plant with the hydrogen-separating membrane operates somewhat more efficiently. However, in order to make these technologies more attractive, their thermodynamic efficiency must be enhanced. The potential for improving the efficiencies of these plants is revealed by an exergetic analysis.     

A scalable infrastructure model for carbon capture and storage: SimCCS

In the carbon capture and storage (CCS) process, CO₂ sources and geologic reservoirs may be widely spatially dispersed and need to be connected through a dedicated CO₂ pipeline network. We introduce a scalable infrastructure model for CCS (simCCS) that generates a fully integrated, cost-minimizing CCS system. SimCCS determines where and how much CO₂ to capture and store, and where to build and connect pipelines of different sizes, in order to minimize the combined annualized costs of sequestering a given amount of CO₂. SimCCS is able to aggregate CO₂ flows between sources and reservoirs into trunk pipelines that take advantage of economies of scale. Pipeline construction costs take into account factors including topography and social impacts. SimCCS can be used to calculate the scale of CCS deployment (local, regional, national). SimCCS’ deployment of a realistic, capacitated pipeline network is a major advancement for planning CCS infrastructure. We demonstrate simCCS using a set of 37 CO₂ sources and 14 reservoirs for California. The results highlight the importance of systematic planning for CCS infrastructure by examining the sensitivity of CCS infrastructure, as optimized by simCCS, to varying CO₂ targets. We finish by identifying critical future research areas for CCS infrastructure.     

Fuel cells for carbon capture and power generation: Simulation studies

The decarbonization of hydrocarbons is explored in this work as a method to produce hydrogen and mitigate carbon dioxide (CO₂) emissions. An integrated process for power generation and carbon capture based on a hydrocarbon fueled-decarbonization unit was proposed and simulated. Ethane and propane were used as fuels and subjected to the thermal decomposition (decarbonization) process. The system is also composed of a carbon fuel cell (CFC) and hydrogen fuel cell (HFC) for the production of power and a pure CO₂ stream that is ready for sequestration. The HFC is a high-temperature proton exchange membrane fuel cell operating at 200 °C. Simulations were performed using ASPEN HYSYS V.10 for the entire process including the CFC and HFC being operated at various operating temperatures (200–800 °C). The power output from the CFC and the HFC as well as the overall process efficiency were calculated. The model incorporates an energy recovery system by adopting a counter-current shell and tube heat exchangers and a turbine. The water produced from the fuel cell system can be utilized in the plant to recover the heat from the furnace. The results showed a 100% carbon capture with a nominal plant capacity of 108 MWe produced when propane fuel was fed to the decarbonizer. The CFC theoretical efficiency is 100% and the practical efficiency was taken as 70% when all internal polarizations were considered. The results showed that, in the case of propane, the CFC power output was 89 MWe when the CFC operated at 650 °C, and the HFC power output was around 45 MWe at 200 °C with an overall actual plant efficiency of 35% and 100% carbon capture. Sensitivity analysis recommends a hydrocarbon fuel cost of 0.011 $/kW as the most feasible option. The results reported here on the decarbonization of hydrocarbon fuels are promising toward the direct production of hydrogen with full carbon dioxide sequestration at a potentially lower cost especially in rural areas. The overall actual efficiencies are very competitive to those of conventional power plants operated without carbon capture.     

A comprehensive review of direct carbon fuel cell technology

Fuel cells are under development for a range of applications for transport, stationary and portable power appliances. Fuel cell technology has advanced to the stage where commercial field trials for both transport and stationary applications are in progress. The electric efficiency typically varies between 40 and 60% for gaseous or liquid fuels. About 30–40% of the energy of the fuel is available as heat, the quality of which varies based on the operating temperature of the fuel cell. The utilisation of this heat component to further boost system efficiency is dictated by the application and end-use requirements. Fuel cells utilise either a gaseous or liquid fuel with most using hydrogen or synthetic gas produced by a variety of different means (reforming of natural gas or liquefied petroleum gas, reforming of liquid fuels such as diesel and kerosene, coal or biomass gasification, or hydrogen produced via water splitting/electrolysis). Direct Carbon Fuel Cells (DCFC) utilise solid carbon as the fuel and have historically attracted less investment than other types of gas or liquid fed fuel cells. However, volatility in gas and oil commodity prices and the increasing concern about the environmental impact of burning heavy fossil fuels for power generation has led to DCFCs gaining more attention within the global research community. A DCFC converts the chemical energy in solid carbon directly into electricity through its direct electrochemical oxidation. The fuel utilisation can be almost 100% as the fuel feed and product gases are distinct phases and thus can be easily separated. This is not the case with other fuel cell types for which the fuel utilisation within the cell is typically limited to below 85%. The theoretical efficiency is also high, around 100%. The combination of these two factors, lead to the projected electric efficiency of DCFC approaching 80% - approximately twice the efficiency of current generation coal fired power plants, thus leading to a 50% reduction in greenhouse gas emissions. The amount of CO₂ for storage/sequestration is also halved. Moreover, the exit gas is an almost pure CO₂ stream, requiring little or no gas separation before compression for sequestration. Therefore, the energy and cost penalties to capture the CO₂ will also be significantly less than for other technologies. Furthermore, a variety of abundant fuels such as coal, coke, tar, biomass and organic waste can be used. Despite these advantages, the technology is at an early stage of development requiring solutions to many complex challenges related to materials degradation, fuel delivery, reaction kinetics, stack fabrication and system design, before it can be considered for commercialisation. This paper, following a brief introduction to other fuel cells, reviews in detail the current status of the direct carbon fuel cell technology, recent progress, technical challenges and discusses the future of the technology.     

A preliminary infrastructure design to use fossil fuels with carbon capture and storage and renewable energy systems

This paper proposes a design methodology for energy infrastructure to address the recent economic and environmental challenges. The proposed energy infrastructure was based on the recognition that fossil fuels will be used for some time with renewable energy sources because renewables are currently unable to replace fossil fuels entirely. A two-fold strategy for the energy infrastructure design is proposed. One is to minimize the negative impact of fossil fuel systems by installing carbon capture and storage (CCS) facilities to reduce greenhouse gas emissions. The other is to accelerate the introduction of renewable energy systems in their place. The design of integrated energy infrastructure is transformed as a Mixed Integer Linear Programming (MILP) problem. Cases of installing CCS and H₂ as a renewable energy source in Korea are illustrated with a discussion of the systematic design of energy infrastructure.