Life cycle GHG assessment of fossil fuel power plants with carbon capture and storage

The evaluation of life cycle greenhouse gas emissions from power generation with carbon capture and storage (CCS) is a critical factor in energy and policy analysis. The current paper examines life cycle emissions from three types of fossil-fuel-based power plants, namely supercritical pulverized coal (super-PC), natural gas combined cycle (NGCC) and integrated gasification combined cycle (IGCC), with and without CCS. Results show that, for a 90% CO₂ capture efficiency, life cycle GHG emissions are reduced by 75–84% depending on what technology is used. With GHG emissions less than 170 g/kWh, IGCC technology is found to be favorable to NGCC with CCS. Sensitivity analysis reveals that, for coal power plants, varying the CO₂ capture efficiency and the coal transport distance has a more pronounced effect on life cycle GHG emissions than changing the length of CO₂ transport pipeline. Finally, it is concluded from the current study that while the global warming potential is reduced when MEA-based CO₂ capture is employed, the increase in other air pollutants such as NO_x and NH₃ leads to higher eutrophication and acidification potentials.     

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.     

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.     

Strategies for carbon dioxide emissions reductions: Residential natural gas efficiency,economic, and ancillary health impacts in Maryland

As part of its commitments to the Regional Greenhouse Gas Initiative (RGGI), the State of Maryland, USA, auctions emission permits to electric utilities, creating revenue that can be used to benefit consumers and the environment. This paper explores the CO₂ emissions reductions that may be possible by allocating some of that revenue to foster efficiency improvements in the residential sector’s use of natural gas. Since these improvements will require changes to the capital stock of houses and end use equipment, efficiency improvements may be accompanied by economic and ancillary health impacts, both of which are quantified in this paper.     

In-situ mineralization of carbon dioxide in a coal-fired power plant

Mitigation of anthropogenic carbon dioxide is needed in order to allow societies to maintain the existing carbon-based infrastructure, while minimizing the effects of carbon dioxide (CO₂) on the earth eco-system. A system that consists of pressure swing adsorption and in-situ mineralization unit was introduced to capture carbon dioxide (CO₂) from a 700 MW pulverized coal-fired power plant. Results from the work demonstrate that pressure swing adsorption for post-combustion carbon capture consumed the least energy, followed by biomass co-firing, pre-combustion cryogenic-membrane hybrid, and post-combustion monoethanolamine absorption. For carbon capture and sequestration, the pressure swing adsorption-fixation system was found to yield the lowest environmental burden factor, followed by off-site sequestration in deep sea and depleted underground oil/gas fields.     

Using steam reforming to produce hydrogen with carbon dioxide capture by chemical-looping combustion

In this paper, a novel process for hydrogen production by steam reforming of natural gas with inherent capture of carbon dioxide by chemical-looping combustion is proposed. The process resembles a conventional circulating fluidized bed combustor with reforming taking place in reactor tubes located inside a bubbling fluidized bed. Energy for the endothermic reforming reactions is provided by indirect combustion that takes place in two separate reactors: one for air and one for fuel. Oxygen is transferred between the reactors by a metal oxide. There is no mixing of fuel and air so carbon dioxide for sequestration is easily obtained. Process layout and expected performance are evaluated and a preliminary reactor design is proposed. It is found that the process should be feasible. It is also found that it has potential to achieve better selectivity towards hydrogen than conventional steam reforming plants due to low reactor temperatures and favorable heat-transfer conditions.     

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.     

Is there cross-country convergence in carbon dioxide emissions?

This paper examines the spatial distribution of per capita carbon dioxide emissions in 87 countries during the period 1960–1999. In order to overcome the methodological limitations of conventional convergence analysis, I have used a non-parametric approach which allows us to study the dynamics of the entire cross-section distribution. The results show that cross-country disparities in per capita carbon dioxide emissions decreased throughout the study period. In fact, the probability mass concentrated around the average increased over time, which helps to explain the observed reduction in the polarisation of the distribution under consideration. In any event, the intradistribution mobility level is relatively low. I have also investigated how far spatial differences in per capita carbon dioxide emission levels can be explained by factors such as per capita income, the degree of trade openness or climatic conditions.     

Energy consumption-economic growth relationship and carbon dioxide emissions in China

This paper applies the panel unit root, heterogeneous panel cointegration and panel-based dynamic OLS to re-investigate the co-movement and relationship between energy consumption and economic growth for 30 provinces in mainland China from 1985 to 2007. The empirical results show that there is a positive long-run cointegrated relationship between real GDP per capita and energy consumption variables. Furthermore, we investigate two cross-regional groups, namely the east China and west China groups, and get more important results and implications. In the long-term, a 1% increase in real GDP per capita increases the consumption of energy by approximately 0.48–0.50% and accordingly increases the carbon dioxide emissions by about 0.41–0.43% in China. The economic growth in east China is energy-dependent to a great extent, and the income elasticity of energy consumption in east China is over 2 times that of the west China. At present, China is subject to tremendous pressures for mitigating climate change issues. It is possible that the GDP per capita elasticity of carbon dioxide emissions would be controlled in a range from 0.2 to 0.3 by the great effort.     

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.     

Performance modelling of a carbon dioxide removal system for power plants

In this paper, a carbon dioxide removal and liquefaction system, which separates carbon dioxide from the flue gases of conventional power plants, was modelled. The system is based on an amine chemical absorption stripping system, followed by a liquefaction unit to treat the removed CO₂ for transportation and storage. The effect of the main parameters on the absorption and stripping columns is presented. The main constraints set for the model are a capture efficiency of 90% and the use of an aqueous solution with a maximum 30% amine content by weight. The goal of this study is to remove the CO₂ with minimum energy requirements for the process when it is integrated in a fossil fuel fired power plant. Results of the simulation are compared to experimental and literature data from feasibility studies and existing plants.

The power plant to which the removal system is connected is a 320 MW steam power plant with steam reheat and 8 feedwater heaters. Two different fossil fuels were considered: coal and natural gas. The effect of the modifications necessary to integrate the CO₂ removal system in the power plant is also studied.

The capital cost of the removal and liquefaction system is estimated, and its influence on the cost of generated electricity is calculated.     

Techno-economic and environmental performances of glycerol reforming for hydrogen and power production with low carbon dioxide emissions

This paper is evaluating from the conceptual design, thermal integration, techno-economic and environmental performances points of view the hydrogen and power generation using glycerol (as a biodiesel by-product) reforming processes at industrial scale with and without carbon capture. The evaluated hydrogen plant concepts produced 100,000 Nm³/h hydrogen (equivalent to 300 MW_th) with negligible net power output for export. The power plant concepts generated about 500 MW net power output. Hydrogen and power co-generation was also assessed. The CO₂ capture concepts used alkanolamine-based gas–liquid absorption. The CO₂ capture rate of the carbon capture unit is at least 90%, the carbon capture rate of the overall reforming process being at least 70%. Similar designs without carbon capture have been developed to quantify the energy and cost penalties for carbon capture. The various glycerol reforming cases were modelled and simulated to produce the mass & energy balances for quantification of key plant performance indicators (e.g. fuel consumption, energy efficiency, ancillary energy consumption, specific CO₂ emissions, capital and operational costs, production costs, cash flow analysis etc.). The evaluations show that glycerol reforming is promising concept for high energy efficiency processes with low CO₂ emissions.     

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.     

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.     

Baselines for carbon emissions in the Indian and Chinese power sectors: Implications for international carbon trading

The study examines the dynamics of carbon emissions baselines of electricity generation in Indian states and Chinese provinces in the backdrop of ongoing electricity sector reforms in these countries. Two Indian states—Gujarat and Andhra Pradesh, and three Chinese provinces–Guangdong, Liaoning and Hubei have been chosen for detailed analysis to bring out regional variations that are not captured in aggregate country studies. The study finds that fuel mix is the main driver behind the trends exhibited by the carbon baselines in these five cases. The cases confirm that opportunities exist in the Indian and Chinese electricity sectors to lower carbon intensity mainly in the substitution of other fuels for coal and, to a lesser extent, adoption of more efficient and advanced coal-fired generation technology. Overall, the findings suggest that the electricity sectors in India and China are becoming friendlier to the global environment. Disaggregated analysis, detailed and careful industry analysis is essential to establishing a power sector carbon emissions baseline as a reference for CDM crediting. However, considering all the difficulties associated with the baseline issue, our case studies demonstrate that there is merit in examining alternate approaches that rely on more aggregated baselines.     

Simulation scenarios for rapid reduction in carbon dioxide emissions in the western electricity system

This paper describes a computer simulation analysis of carbon dioxide emissions in the electric power system in the western United States. Legislation at both the state and federal level would impose a price on emissions via cap-and-trade in allowances for carbon dioxide emissions. The simulation scenarios for the western system indicate that dramatic reductions in emissions are possible with generating technologies that exist today. Wind and biomass generators play a key role even with conservative assumptions about their future costs. In contrast, generation from advanced technologies provide only a minor contribution by the year 2025. These scenarios provide support to those who argue that the US should move expeditiously to put a price on carbon dixoide emissions.     

Understanding the challenges of industrial carbon capture and storage: an example in a U.S. petrochemical corridor

Industrial carbon capture and storage (CCS) is carbon capture from non-power, stationary emissions sources, typically involving high-purity emissions from a non-combustion exhaust stream. Industrial CCS activities represent a significant opportunity for reducing carbon emissions in concentrated geographic locations and a potential ‘bridge’ to more widespread CCS. This paper provides a summary of the opportunities for industrial CCS and market-based revenue streams, like those associated with enhanced crude oil recovery (EOR). The use of EOR changes the nature of carbon from being a pollutant to a valuable commercial input, which requires a judicious understanding of the technical industrial sequestration process, historic oil and gas operations, and the specific location and types of industrial carbon sources that can facilitate this type of carbon emissions mitigation strategy. We review literature on costs and summarise geospatial data to provide an overview of the potential for an integrated industrial CCS-EOR system in a petrochemical corridor.     

Interactions between electricity-saving measures and carbon emissions from power generation in England and Wales

The relationship between electricity demand reduction and the consequent change in carbon emissions is central to greenhouse gas emissions policy. This paper examines this relationship for the power system of England and Wales. Previous analysis showed that the commonly used conversion factor based on the system average emission factor significantly underestimates these savings (Hitchin and Pout, 2002. The carbon intensity of electricity: how many kgC per kWhe?. Building Serv. Eng. Res. Technol. 23(4)). Thus any policy analysis based on the system-average emission factor will under-estimate the potential for carbon savings from reductions in electricity demand. The present paper extends the previous analysis by using more detailed modelling to explore differences between demand reductions of differing load shape and magnitude; and the sensitivity of these figures to changes of the fuel mix of the generation system.     

Natural gas based hydrogen production with zero carbon dioxide emissions

A novel process flowsheet is presented that co-produces hydrogen and formic acid from natural gas, without emitting any carbon dioxide. The principal technologies employed in the process network include combustion, steam methane reforming (SMR), pressure swing adsorption, and formic acid production from CO₂ and H₂. Thermodynamic analysis provides operating limits for the proposed process, and the use of reaction clusters leads to the synthesis of a feasible process flowsheet. Heat and power integration studies show this flowsheet to be energetically self-sufficient through the use of heat engine and heat pump subnetworks. Operating cost/revenue studies, using current market prices for natural gas, hydrogen and formic acid, identify the proposed design’s operating revenue to cost ratio to be 9.29.     

Expert assessments of retrofitting coal-fired power plants with carbon dioxide capture technologies

A set of 13 US based experts in post-combustion and oxy-fuel combustion CO₂ capture systems responded to an extensive questionnaire asking their views on the present status and future expected performance and costs for amine-based, chilled ammonia, and oxy-combustion retrofits of coal-fired power plants. This paper presents the experts' responses for technology maturity, ideal plant characteristics for early adopters, and the extent to which R&D and deployment incentives will impact costs. It also presents the best estimates and 95% confidence limits of the energy penalties associated with amine-based systems. The results show a general consensus that amine-based systems are closer to commercial application, but potential for improving performance and lowering costs is limited; chilled ammonia and oxy-combustion offer greater potential for cost reductions, but not without greater uncertainty regarding scale and technical feasibility.