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 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.     

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.     

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.     

Conversion of fossil and biomass fuels to electric power and transportation fuels by high efficiency integrated plasma fuel cell (IPFC) energy cycle

The IPFC is a high efficiency energy cycle, which converts fossil and biomass fuel to electricity and co-product hydrogen and liquid transportation fuels (gasoline and diesel). The cycle consists of two basic units, a hydrogen plasma black reactor (HPBR) which converts the carbonaceous fuel feedstock to elemental carbon and hydrogen and CO gas. The carbon is used as fuel in a direct carbon fuel cell (DCFC), which generates electricity, a small part of which is used to power the plasma reactor. The gases are cleaned and water gas shifted for either hydrogen or syngas formation. The hydrogen is separated for production or the syngas is catalytically converted in a Fischer–Tropsch (F–T) reactor to gasoline and/or diesel fuel. Based on the demonstrated efficiencies of each of the component reactors, the overall IPFC thermal efficiency for electricity and hydrogen or transportation fuel is estimated to vary from 70 to 90% depending on the feedstock and the co-product gas or liquid fuel produced. The CO₂ emissions are proportionately reduced and are in concentrated streams directly ready for sequestration. Preliminary cost estimates indicate that IPFC is highly competitive with respect to conventional integrated combined cycle plants (NGCC and IGCC) for production of electricity and hydrogen and transportation fuels.     

The energy and environmental implications of UK more electric transition pathways: A whole systems perspective

Electricity generation contributes a large proportion of the total greenhouse gas emissions in the United Kingdom (UK), due to the predominant use of fossil fuel (coal and natural gas) inputs. Indeed, the various power sector technologies [fossil fuel plants with and without carbon capture and storage (CCS), nuclear power stations, and renewable energy technologies (available on a large and small {or domestic} scale)] all involve differing environmental impacts and other risks. Three transition pathways for a more electric future out to 2050 have therefore been evaluated in terms of their life-cycle energy and environmental performance within a broader sustainability framework. An integrated approach is used here to assess the impact of such pathways, employing both energy analysis and environmental life-cycle assessment (LCA), applied on a ‘whole systems’ basis: from ‘cradle-to-gate’. The present study highlights the significance of ‘upstream emissions’, in contrast to power plant operational or ‘stack’ emissions, and their (technological and policy) implications. Upstream environmental burdens arise from the need to expend energy resources in order to deliver, for example, fuel to a power station. They include the energy requirements for extraction, processing/refining, transport, and fabrication, as well as methane leakage that occurs in coal mining activities – a major cotribution – and from natural gas pipelines. The impact of upstream emissions on the carbon performance of various low carbon electricity generators [such as large-scale combined heat and power (CHP) plant and CCS] and the pathways distinguish the present findings from those of other UK analysts. It suggests that CCS is likely to deliver only a 70% reduction in carbon emissions on a whole system basis, in contrast to the normal presumption of a 90% reduction. Similar results applied to other power generators.     

Carbon capture and storage potential in coal-fired plant in Malaysia—A review

Secure, reliable and affordable energy supplies are necessary for sustainable economic growth, but increases in associated carbon dioxide (CO₂) emissions, and the associated risk of climate change are a cause of major concern. Experts have projected that the CO₂ emissions related to the energy sector will increase 130% by 2050 in the absence of new policies or supply constraints as a result of increased fossil fuel usage. To address this issue will require an energy technology revolution involving greater energy efficiency, increased renewable energies and nuclear power, and the near-decarbonisation of fossil fuel-based power generation. Nonetheless, fossil fuel usage is expected to continue to dominate global energy supply. The only technology available to mitigate greenhouse gas (GHG) emissions from large-scale fossil fuel usage is carbon capture and storage (CCS), an essential part of the portfolio of technologies that is needed to achieve deep global emission reductions. However, CCS technology faces numerous issues and challenges before it can be successfully deployed. With Malaysia has recently pledged a 40% carbon reduction by 2020 in the Copenhagen 2009 Climate Summit, CCS technology is seen as a viable option in order to achieve its target. Thus, this paper studies the potential and feasibility of coal-fired power plant with CCS technology in Malaysia which includes the choices of coal plants and types of capture technologies possible for implementation.     

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.     

Baseload electricity from wind via compressed air energy storage (CAES)

This study investigates two methods of transforming intermittent wind electricity into firm baseload capacity: (1) using electricity from natural gas combined-cycle (NGCC) power plants and (2) using electricity from compressed air energy storage (CAES) power plants. The two wind models are compared in terms of capital and electricity costs, CO₂ emissions, and fuel consumption rates. The findings indicate that the combination of wind and NGCC power plants is the lowest-cost method of transforming wind electricity into firm baseload capacity power supply at current natural gas prices (∼$6/GJ). However, the electricity supplied by wind and CAES power plants becomes economically competitive when the cost of natural gas for electric producers is $10.55/GJ or greater. In addition, the Wind-CAES system has the lowest CO₂ emissions (93% and 71% lower than pulverized coal power plants and Wind-NGCC, respectively) and the lowest fuel consumption rates (9 and 4 times lower than pulverized coal power plants and Wind-NGCC, respectively). As such, the large-scale introduction of Wind-CAES systems in the U.S. appears to be the prudent long-term choice once natural gas price volatility, costs, and climate impacts are all considered.     

Valuing flexibility: The case of an Integrated Gasification Combined Cycle power plant

In this paper we analyze the choice between two technologies for producing electricity. In particular, the firm has to decide whether and when to invest either in a Natural Gas Combined Cycle (NGCC) power plant or in an Integrated Gasification Combined Cycle (IGCC) power plant, which may burn either coal or natural gas. Instead of assuming that fuel prices follow standard geometric Brownian motions, here they are assumed to show mean reversion, specifically to follow an inhomogeneous geometric Brownian motion.First we consider the opportunity to invest in a NGCC power plant. We derive the optimal investment rule as a function of natural gas price and the remaining life of the right to invest. In addition, the analytical solution for a perpetual option to invest is obtained.Then we turn to the IGCC power plant. We analyse the valuation of an operating plant when there are switching costs between modes of operation, and the choice of the best operation mode. This serves as an input to evaluate the option to invest in this plant.Finally we derive the value of an opportunity to invest either in a NGCC or IGCC power plant, i.e. to choose between an inflexible and a flexible technology, respectively. Depending on the opportunity's time to maturity, we derive the pairs of coal and gas prices for which it is optimal to invest in NGCC, in IGCC, or simply not to invest.Numerical computations involve the use of one- and two-dimensional binomial lattices that support a mean-reverting process for coal and gas prices. Basic parameter values are taken from an actual IGCC power plant currently in operation. Sensitivity of some results with respect to the underlying stochastic process for fuel price is also checked.     

Long-term CO2 emissions reduction target and scenarios of power sector in Taiwan

This study analyses a series of carbon dioxide (CO₂) emissions abatement scenarios of the power sector in Taiwan according to the Sustainable Energy Policy Guidelines, which was released by Executive Yuan in June 2008. The MARKAL-MACRO energy model was adopted to evaluate economic impacts and optimal energy deployment for CO₂ emissions reduction scenarios. This study includes analyses of life extension of nuclear power plant, the construction of new nuclear power units, commercialized timing of fossil fuel power plants with CO₂ capture and storage (CCS) technology and two alternative flexible trajectories of CO₂ emissions constraints. The CO₂ emissions reduction target in reference reduction scenario is back to 70% of 2000 levels in 2050. The two alternative flexible scenarios, Rt4 and Rt5, are back to 70% of 2005 and 80% of 2005 levels in 2050. The results show that nuclear power plants and CCS technology will further lower the marginal cost of CO₂ emissions reduction. Gross domestic product (GDP) loss rate in reference reduction scenario is 16.9% in 2050, but 8.9% and 6.4% in Rt4 and Rt5, respectively. This study shows the economic impacts in achieving Taiwan's CO₂ emissions mitigation targets and reveals feasible CO₂ emissions reduction strategies for the power sector.     

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.     

High efficiency electric power generation: The environmental role

Electric power generation system development is reviewed with special attention to plant efficiency. It is generally understood that efficiency improvement that is consistent with high plant reliability and low cost of electricity is economically beneficial, but its effect upon reduction of all plant emissions without installation of additional environmental equipment, is less well appreciated. As CO₂ emission control is gaining increasing acceptance, efficiency improvement, as the only practical tool capable of reducing CO₂ emission from fossil fuel plant in the short term, has become a key concept for the choice of technology for new plant and upgrades of existing plant. Efficiency is also important for longer-term solutions of reducing CO₂ emission by carbon capture and sequestration (CCS); it is essential for the underlying plants to be highly efficient so as to mitigate the energy penalty of CCS technology application. Power generating options, including coal-fired Rankine cycle steam plants with advanced steam parameters, natural gas-fired gas turbine-steam, and coal gasification combined cycle plants are discussed and compared for their efficiency, cost and operational availability. Special attention is paid to the timeline of the various technologies for their development, demonstration and commercial availability for deployment.     

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.     

Critical factors in the design,operation and economics of coal gasification plants: The case of the flexible co-production of hydrogen and electricity

Power generation from wind and solar sources is growing in importance, but requires back up from fossil fuel plants, greatly compromising fossil fuel plant economics. This includes the economics of most proposed IGCC–Hypogen type plant schemes which are intended to produce hydrogen and electricity, as well as capturing CO₂. IGCC–Hypogen plants, however, that are able to change the ratio of hydrogen to electricity will be able to operate at maximum capacity all of the time, switching from power generation to hydrogen production as the demand for these two forms of energy changes. Because of the need to provide power to the IGCC–Hypogen ancillaries, some hydrogen from the plant will have to be utilised to supply some of this power. A preliminary economic study examines how the plant could produce electricity and hydrogen at competitive prices.     

The European power plant infrastructure—Presentation of the Chalmers energy infrastructure database with applications

This paper presents a newly established database of the European power plant infrastructure (power plants, fuel infrastructure, fuel resources and CO₂ storage options) for the EU25 member states (MS) and applies the database in a general discussion of the European power plant and natural gas infrastructure as well as in a simple simulation analysis of British and German power generation up to the year 2050 with respect to phase-out of existing generation capacity, fuel mix and fuel dependency. The results are discussed with respect to age structure of the current production plants, CO₂ emissions, natural gas dependency and CO₂ capture and storage (CCS) under stringent CO₂ emission constraints.     

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.     

Innovative energy technologies and climate policy in Germany

Due to the size and structure of its economy, Germany is one of the largest carbon emitters in the European Union. However, Germany is facing a major renewal and restructuring process in electricity generation. Within the next two decades, up to 50% of current electricity generation capacity may retire because of end-of-plant lifetime and the nuclear phase-out pact of 1998. Substantial opportunities, therefore, exist for deployment of advanced electricity generating technologies in both a projected baseline and in alternative carbon policy scenarios. We simulate the potential role of coal integrated gasification combined cycle (IGCC), natural gas combined cycle (NGCC), carbon dioxide capture and storage (CCS), and wind power within a computable general equilibrium model of Germany from the present through 2050. These advanced technologies and their role within a future German electricity system are the focus of this paper. We model the response of greenhouse gas emissions in Germany to various technology and carbon policy assumptions over the next few decades. In our baseline scenario, all of the advanced technologies except CCS provide substantial contributions to electricity generation. We also calculate the carbon price where each fossil technology, combined with CCS, becomes competitive. Constant carbon price experiments are used to characterize the model response to a carbon policy. This provides an estimate of the cost of meeting an emissions target, and the share of emissions reductions available from the electricity generation sector.     

A framework for environmental assessment of CO2 capture and storage systems

Carbon dioxide capture and storage (CCS) is increasingly seen as a way for society to enjoy the benefits of fossil fuel energy sources while avoiding the climate disruption associated with fossil CO₂ emissions. A decision to deploy CCS technology at scale should be based on robust information on its overall costs and benefits. Life-cycle assessment (LCA) is a framework for holistic assessment of the energy and environmental footprint of a system, and can provide crucial information to policy-makers, scientists, and engineers as they develop and deploy CCS systems. We identify seven key issues that should be considered to ensure that conclusions and recommendations from CCS LCA are robust: energy penalty, functional units, scale-up challenges, non-climate environmental impacts, uncertainty management, policy-making needs, and market effects. Several recent life-cycle studies have focused on detailed assessments of individual CCS technologies and applications. While such studies provide important data and information on technology performance, such case-specific data are inadequate to fully inform the decision making process. LCA should aim to describe the system-wide environmental implications of CCS deployment at scale, rather than a narrow analysis of technological performance of individual power plants.     

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.