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.     

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.     

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.     

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.     

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.     

Water usage and energy penalty of different hybrid cooling system configurations for a natural gas combined cycle power plant—Effect of carbon capture unit integration

Electric power generation from thermoelectric power plants is associated with a negative impact on water availability, referenced as the water‐energy nexus, which is aggravated by climate change. In the present study, the effect of four different hybrid cooling system configurations on water usage and power penalty of a natural gas combined cycle has been investigated. The hybrid cooling system with a parallel connected indirect dry cooling system and wet cooling system is the most conventional studied hybrid cooling system in the literature, while the other studied hybrid configurations in the present study are novel regarding their effect on water requirement and power penalty. Simulations were conducted using the COCO 3.3 software and have been validated using data sets from a reference natural gas combined cycle plant, both with and without carbon capture unit, which is available in the literature. Four hybrid cooling system configurations were explored to evaluate their water requirements and power penalty. Other conventional cooling systems such as closed cooling, once‐through, and direct and indirect dry cooling methods were simulated with and without postcombustion carbon capture (PCCC) integration for comparison. It was found that the hybrid configuration, including indirect air‐cooled condenser and natural draft wet cooling tower, has the best performance as compared to the other conventional and hybrid cooling systems, amounting to 2.038 (gal/min)/MW_net, 1.573 (gal/min)/MW_net, and 12.29 MW for water withdrawal, consumption, and energy penalty, respectively, for the case of a unit without PCCC unit and 3.9 (gal/min)/MW_net, 2.928 (gal/min)/MW_net, and 15.177 MW for water withdrawal, consumption, and energy penalty, respectively, for a unit with carbon capture unit. It was confirmed that the PCCC integration approximately doubles the water withdrawal and consumption for all cooling systems. In addition, the indirect air‐cooled condenser and wet cooling tower is still the best performing cooling system with PCCC integration.     

The outlook for improved carbon capture technology

Carbon capture and storage (CCS) is widely seen as a critical technology for reducing atmospheric emissions of carbon dioxide (CO₂) from power plants and other large industrial facilities, which are major sources of greenhouse gas emissions linked to global climate change. However, the high cost and energy requirements of current CO₂ capture processes are major barriers to their use. This paper assesses the outlook for improved, lower-cost technologies for each of the three major approaches to CO₂ capture, namely, post-combustion, pre-combustion and oxy-combustion capture. The advantages and limitations of each of method are discussed, along with the current status of projects and processes at various stages in the development cycle. We then review a variety of “roadmaps” developed by governmental and private-sector organizations to project the commercial roll-out and deployment of advanced capture technologies. For perspective, we also review recent experience with R&D programs to develop lower-cost technologies for SO₂ and NO_x capture at coal-fired power plants. For perspective on projected cost reductions for CO₂ capture we further review past experience in cost trends for SO₂ and NO_x capture systems. The key insight for improved carbon capture technology is that achieving significant cost reductions will require not only a vigorous and sustained level of research and development (R&D), but also a substantial level of commercial deployment, which, in turn, requires a significant market for CO₂ capture technologies. At present such a market does not yet exist. While various incentive programs can accelerate the development and deployment of improved CO₂ capture systems, government actions that significantly limit CO₂ emissions to the atmosphere ultimately are needed to realize substantial and sustained reductions in the future cost of CO₂ capture.     

Techno-economic assessment of fossil fuel power plants with CO2 capture – Results of EU H2-IGCC project

In order to address the ever-increasing demand for electricity, need for security of energy supply, and to stabilize global warming, the European Union co-funded the H₂-IGCC project, which aimed to develop and demonstrate technological solutions for future generation integrated gasification combined cycle (IGCC¹) plants with carbon capture. As a part of the main goal, this study evaluates the performance of the selected IGCC plant with CO₂ capture from a techno-economic perspective. In addition, a comparison of techno-economic performance between the IGCC plant and other dominant fossil-based power generation technologies, i.e. an advanced supercritical pulverized coal (SCPC²) and a natural gas combined cycle (NGCC³), have been performed and the results are presented and discussed here. Different plants are economically compared with each other using the cost of electricity and the cost of CO₂ avoided. Moreover, an economic sensitivity analysis of every plant considering the realistic variation of the most uncertain parameters is given.     

Determinants of the costs of carbon capture and sequestration for expanding electricity generation capacity

This study models the costs of electricity generation with carbon capture and sequestration (CCS), from generation at the power plant to carbon injection at the reservoir, examining the economic factors that affect technology choice and CCS costs at the individual plant level. The results suggest that natural gas and coal prices have profound impacts on the carbon price needed to induce CCS. To extend previous analyses we develop a "cost region" graph that models technology choice as a function of carbon and fuel prices. Generally, the least-cost technology at low carbon prices is pulverized coal, while intermediate carbon prices favor natural gas technologies and high carbon prices favor coal gasification with capture. However, the specific carbon prices at which these transitions occur is largely determined by the price of natural gas. For instance, the CCS-justifying carbon price ranges from $27/t CO₂ at high natural gas prices to $54/t CO₂ at low natural gas prices. This result has important implications for potential climate change legislation. The capital costs of the generation and CO₂ capture plant are also highly important, while pipeline distance and criteria pollutant control are less significant.     

Potential for flexible operation of pulverised coal power plants with CO2 capture

Abstract

Fossil-fired plants play an important role in electricity networks as mid-merit plants that can respond relatively quickly to changes in supply and demand. As a consequence, they are required to operate over a wide output range and play an important role in maintaining the quality and security of electricity supply by providing response and reserve capacity. Carbon dioxide capture and storage (CCS) has been identified as a critical technology for future electricity generation from coal in the UK. Although the performance of CCS schemes where CO₂ capture plants are operated at full load has been considered in detail, part load performance is less well understood. Developing a better understanding of part load performance of plants operating with CO₂ capture is crucial in determining their suitability to operate as mid-merit plants. This paper presents an assessment of the potential impact of adding post-combustion CO₂ capture at pulverised-coal power plants. Estimated performance of steam cycles working with post-combustion CO₂ capture plant are presented at full and part load, leading to performance predictions for pulverised-coal power plants operated over a range of loads and with varying levels of CO₂ capture. By adjusting the operation of the capture plant, as well as the boiler/steam cycle, an extended range of operation can be achieved including lower minimum stable generation levels and additional 'pumped storage like' capacity for times of high demand. For example, plant operators can alter the energy penalty for the CO₂ capture plant with an associated change in plant output by reducing the level of CO₂ capture. This can allow extra electricity to be generated and sold when electricity prices are high. With solvent storage it should also be possible to increase power plant output for a number of hours, but without associated increases in CO₂ emissions.     

Biomass-fired cogeneration systems with CO2 capture and storage

In this study, we estimate and analyze the CO₂ mitigation costs of large-scale biomass-fired cogeneration technologies with CO₂ capture and storage. The CO₂ mitigation cost indicates the minimum economic incentive required (e.g. in the form of a carbon tax) to make the cost of a less carbon intensive system equal to the cost of a reference system. If carbon (as CO₂) is captured from biomass-fired energy systems, the systems could in principle be negative CO₂ emitting energy systems. CO₂ capture and storage from energy systems however, leads to reduced energy efficiency, higher investment costs, and increased costs of end products compared with energy systems in which CO₂ is vented. Here, we have analyzed biomass-fired cogeneration plants based on steam turbine technology (CHP-BST) and integrated gasification combined cycle technology (CHP-BIGCC). Three different scales were considered to analyze the scale effects. Logging residues was assumed as biomass feedstock. Two methods were used to estimate and compare the CO₂ mitigation cost. In the first method, the cogenerated power was credited based on avoided power production in stand-alone plants and in the second method the same reference output was produced from all systems. Biomass-fired CHP-BIGCC with CO₂ capture and storage was found very energy and emission efficient and cost competitive compared with other conversion systems.     

Production of power using underground coal gasification

Underground coal gasification (UCG) is a process that converts deep, un-mineable coal resources into syngas, which can then be converted into valuable end products such as electric power. This paper provides a summary of the options to combine UCG with electric power production and focuses on commercial-scale applications using a combined-cycle power plant including integration options and syngas cleanup steps. Simulation results for a UCG power plant with carbon capture are compared against the results for an equivalent Integrated Gasification Combined Cycle (IGCC) plant using the same feedstock. Relative capital cost savings for a UCG power plant are estimated based on published IGCC process unit costs. The UCG power plant with carbon capture is shown to provide a higher thermal efficiency, lower CO₂ intensity, and lower capital cost than an equivalent IGCC plant. Finally, the potential of UCG as a method for producing cost-effective, low-emissions electrical power from deep coal is discussed and some of the challenges and opportunities are summarized.     

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.     

Comparison of carbon capture IGCC with pre-combustion decarbonisation and with chemical-looping combustion

Carbon capture from conventional power cycles is accompanied by a significant loss of efficiency. One process concept with a potential for better performance is chemical-looping combustion (CLC). CLC uses a metal oxide to oxidize the fuel, and the reduced metal is then re-oxidized in a second reactor with air. The combustion products CO₂ and water remain unmixed with nitrogen, thereby avoiding the need for energy intensive air separation. In this paper, the performance of various configurations of CLC used in integrated gasification combined cycle power plants (CLC-IGCC) are analyzed and compared to a conventional IGCC design with pre-combustion carbon capture by physical absorption. The analysis is based on process simulation using Aspen Plus and GateCycle. Key design parameters are varied, and the results are interpreted using exergy analysis. The CLC-IGCC offers the advantages of higher plant efficiency and more complete carbon capture. The efficiency is very sensitive to changes in the gas turbine inlet temperature for both the CLC and the conventional IGCC designs. The development of oxygen carrier particles with a high thermal stability is therefore crucial for capitalizing on the potential efficiency advantage of CLC.     

Techno – Economic assessment of flexible decarbonized hydrogen and power co-production based on natural gas dry reforming

The need for flexible power plants could increase in the future as variable renewable energy (VRE) share will increase in the power grid. These power plants could balance the increasing strain on electricity grids by renewables. The proposed plant in this paper can adapt to these ramps in electricity demand of the power grid by maintaining a constant feed and producing also high purity hydrogen. Dry methane reforming (DMR) is incorporated into a flexible power plant model and the key performance indicators are calculated from a techno-economic perspective. The net output of the plant is 450 MW with the possibility to lower power production and produce hydrogen, maintaining a high CO₂ capture rate (72%). Two cases are compared to the base case to quantify: (i) energy and cost penalties for CO₂ capture and (ii) advantages of flexible power plant operation. The levelized cost of electricity (LCOE) for the base case is 67 Euro/MWh, the addition of a carbon capture unit increases it to 82 Euro/MWh. In the case of flexible operation, both the LCOE and levelized cost of hydrogen (LCOH) are calculated and the two depend on the cost allocation factor. The LCOE ranges from 65 to 85 Euro/MWh while the LCOH from 0.15 to 0.073 Euro/Nm³. The DMR power plant presented in Cases 1 and 2 present little advantages in today's market conditions however, the flexible plant (Case 3) can be viable option in balancing VRE.     

Effects of coal characteristics to performance of a highly efficient thermal power generation system based on pressurized oxy‐fuel combustion

Because of its fuel flexibility and high efficiency, pressurized oxy‐fuel combustion has recently emerged as a promising approach for efficient carbon capture and storage. One of the important options to design the pressurized oxy‐combustion is to determine method of coal (or other solid fuels) feeding: dry feeding or wet (coal slurry) feeding as well as grade of coals. The main aim of this research is to investigate effects of coal characteristics including wet or dry feeding on the performance of thermal power plant based on the pressurized oxy‐combustion with CO₂ capture versus atmospheric oxy‐combustion. A commercial process simulation tool (gCCS: the general carbon capture and storage) was used to simulate and analyze an advanced ultra‐supercritical(A‐USC) coal power plant under pressurized and atmospheric oxy‐fuel conditions. The design concept is based on using pure oxygen as an oxidant in a pressurized system to maximize the heat recovery through process integration and to reduce the efficiency penalty because of compression and purification units. The results indicate that the pressurized case efficiency at 30 bars was greater than the atmospheric oxy‐fuel combustion (base line case) by 6.02% when using lignite coal firing. Similarly, efficiency improvements in the case of subbituminous and bituminous coals were around 3% and 2.61%, respectively. The purity of CO₂ increased from 53.4% to 94% after compression and purification. In addition, the study observed the effects of coal‐water slurry using bituminous coal under atmospheric conditions, determining that the net plant efficiency decreased by 3.7% when the water content in the slurry increased from 11.12% to 54%. Copyright © 2016 John Wiley & Sons, Ltd.     

Performance and costs of power plants with capture and storage of CO2

This paper assesses the three leading technologies for capture of CO₂ in power generation plants, i.e., post-combustion capture, pre-combustion capture and oxy-fuel combustion. Performance, cost and emissions data for coal and natural gas-fired power plants are presented, based on information from studies carried out recently for the IEA Greenhouse Gas R&D Programme by major engineering contractors and process licensors. Sensitivities to various potentially significant parameters are assessed.     

CO2 capture study in advanced integrated gasification combined cycle

This paper presents the results of technical and economic studies in order to evaluate, in the French context, the future production cost of electricity from IGCC coal power plants with CO₂ capture and the resulting cost per tonne of CO₂ avoided. The economic evaluation shows that the total cost of base load electricity produced in France by coal IGCC power plants with CO₂ capture could be increased by 39% for ‘classical’ IGCC and 28% for ‘advanced’ IGCC. The cost per tonne of avoided CO₂ is lower by 18% in ‘advanced’ IGCC relatively to ‘classical’ IGCC. The approach aimed to be as realistic as possible for the evaluation of the energy penalty due to the integration of CO₂ capture in IGCC power plants. Concerning the CO₂ capture, six physical and chemical absorption processes were modeled with the Aspen Plus™ software. After a selection based on energy performance three processes were selected and studied in detail: two physical processes based on methanol and Selexol™ solvents, and a chemical process using activated MDEA. For ‘advanced’ IGCC operating at high-pressure, only one physical process is assessed: methanol.     

MCFC-based CO2 capture system for small scale CHP plants

Carbon dioxide emissions into the atmosphere are considered among the main reasons of the greenhouse effect. The largest share of CO₂ is emitted by power plants using fossil fuels. Nowadays there are several technologies to capture CO₂ from power plants' exhaust gas but each of them consumes a significant part of the electric power generated by the plant. The Molten Carbonate Fuel Cell (MCFC) can be used as concentrator of CO₂, due to the chemical reactions that occurs in the cell stack: carbon dioxide entering into the cathode side is transported to the anode side via CO₃⁼ ions and is finally concentrated in the anodic exhaust. MCFC systems can be integrated in existing power plants (retro fitting) to separate CO₂ in the exhaust gas and, at the same time, produce additional energy. The aim of this study is to find a feasible system design for medium scale cogeneration plants which are not considered economically and technically interesting for existing technologies for carbon capture, but are increasing in numbers with respect to large size power plants. This trend, if confirmed, will increase number of medium cogeneration plants with consequent benefit for both MCFC market for this application and effect on global CO₂ emissions. System concept has been developed in a numerical model, using AspenTech engineering software. The model simulates a plant, which separates CO₂ from a cogeneration plant exhaust gases and produces electric power. Data showing the effect of CO₂ on cell voltage and cogenerator exhaust gas composition were taken from experimental activities in the fuel cell laboratory of the University of Perugia, FCLab, and from existing CHP plants. The innovative aspect of this model is the introduction of recirculation to optimize the performance of the MCFC. Cathode recirculation allows to decrease the carbon dioxide utilization factor of the cell keeping at the same time system CO₂ removal efficiency at high level. At anode side, recirculation is used to reduce the fuel consumption (due to the unreacted hydrogen) and to increase the CO₂ purity in the stored gas. The system design was completely introduced in the model and several analyses were performed. CO₂ removal efficiency of 63% was reached with correspondent total efficiency of about 35%. System outlet is also thermal power, due to the high temperature of cathode exhaust off gases, and it is possible to consider integration of this outlet with the cogeneration system. This system, compared to other post-combustion CO₂ removal technologies, does not consume energy, but produces additional electrical and thermal power with a global efficiency of about 70%.