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.     

Comparative assessment of CO2 capture technologies for carbon-intensive industrial processes

This article presents a consistent techno-economic assessment and comparison of CO₂ capture technologies for key industrial sectors (iron and steel, cement, petroleum refineries and petrochemicals). The assessment is based on an extensive literature review, covering studies from both industries and academia. Key parameters, e.g., capacity factor (91-97%), energy prices (natural gas: 8 €₂₀₀₇/GJ, coal: 2.5 €₂₀₀₇/GJ, grid electricity: 55 €/MWh), interest rate (10%), economic plant lifetime (20 years), CO₂ compression pressure (110 bar), and grid electricity CO₂ intensity (400 g/kWh), were standardized to enable a fair comparison of technologies. The analysis focuses on the changes in energy, CO₂ emissions and material flows, due to the deployment of CO₂ capture technologies. CO₂ capture technologies are categorized into short-mid term (ST/MT) and long term (LT) technologies. The findings of this study identified a large number of technologies under development, but it is too soon to identify which technologies would become dominant in the future. Moreover, a good integration of industrial plants and power plants is essential for cost-effective CO₂ capture because CO₂ capture may increase the industrial onsite electricity production significantly.For the iron and steel sector, 40-65 €/tCO₂ avoided may be achieved in the ST/MT, depending on the ironmaking process and the CO₂ capture technique. Advanced LT CO₂ capture technologies for the blast furnace based process may not offer significant advantages over conventional ones (30-55 €/tCO₂ avoided). Rather than the performance of CO₂ capture technique itself, low-cost CO₂ emissions reduction comes from good integration of CO₂ capture to the ironmaking process. Advanced smelting reduction with integrated CO₂ capture may enable lower steel production cost and lower CO₂ emissions than the blast furnace based process, i.e., negative CO₂ mitigation cost. For the cement sector, post-combustion capture appears to be the only commercial technology in the ST/MT and the costs are above 65 €/tCO₂ avoided. In the LT, a number of technologies may enable 25-55 €/tCO₂ avoided. The findings also indicate that, in some cases, partial CO₂ capture may have comparative advantages. For the refining and petrochemical sectors, oxyfuel capture was found to be more economical than others at 50-60 €/tCO₂ avoided in ST/MT and about 30 €/tCO₂ avoided in the LT. However, oxyfuel retrofit of furnaces and heaters may be more complicated than that of boilers.Crude estimates of technical potentials for global CO₂ emissions reduction for 2030 were made for the industrial processes investigated with the ST/MT technologies. They amount up to about 4 Gt/yr: 1 Gt/yr for the iron and steel sector, about 2 Gt/yr for the cement sector, and 1 Gt/yr for petroleum refineries. The actual deployment level would be much lower due to various constraints, about 0.8 Gt/yr, in a stringent emissions reduction scenario.     

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.     

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.     

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.     

Hydrogen production from coal gasification for effective downstream CO2 capture

The coal gasification process is used in commercial production of synthetic gas as a means toward clean use of coal. The conversion of solid coal into a gaseous phase creates opportunities to produce more energy forms than electricity (which is the case in coal combustion systems) and to separate CO₂ in an effective manner for sequestration. The current work compares the energy and exergy efficiencies of an integrated coal-gasification combined-cycle power generation system with that of coal gasification-based hydrogen production system which uses water-gas shift and membrane reactors. Results suggest that the syngas-to-hydrogen (H₂) system offers 35% higher energy and 17% higher exergy efficiencies than the syngas-to-electricity (IGCC) system. The specific CO₂ emission from the hydrogen system was 5% lower than IGCC system. The Brayton cycle in the IGCC system draws much nitrogen after combustion along with CO₂. Thus CO₂ capture and compression become difficult due to the large volume of gases involved, unlike the hydrogen system which has 80% less nitrogen in its exhaust stream. The extra electrical power consumption for compressing the exhaust gases to store CO₂ is above 70% for the IGCC system but is only 4.5% for the H₂ system. Overall the syngas-to-hydrogen system appears advantageous to the IGCC system based on the current analysis.     

A comparison of electricity and hydrogen production systems with CO2 capture and storage—Part B: Chain analysis of promising CCS options

Promising electricity and hydrogen production chains with CO₂ capture, transport and storage (CCS) and energy carrier transmission, distribution and end-use are analysed to assess (avoided) CO₂ emissions, energy production costs and CO₂ mitigation costs. For electricity chains, the performance is dominated by the impact of CO₂ capture, increasing electricity production costs with 10–40% up to 4.5–6.5 €ct/kWh. CO₂ transport and storage in depleted gas fields or aquifers typically add another 0.1–1 €ct/kWh for transport distances between 0 and 200 km. The impact of CCS on hydrogen costs is small. Production and supply costs range from circa 8 €/GJ for the minimal infrastructure variant in which hydrogen is delivered to CHP units, up to 20 €/GJ for supply to households. Hydrogen costs for the transport sector are between 14 and 16 €/GJ for advanced large-scale coal gasification units and reformers, and over 20 €/GJ for decentralised membrane reformers. Although the CO₂ price required to induce CCS in hydrogen production is low in comparison to most electricity production options, electricity production with CCS generally deserves preference as CO₂ mitigation option. Replacing natural gas or gasoline for hydrogen produced with CCS results in mitigation costs over 100 €/t CO₂, whereas CO₂ in the power sector could be reduced for costs below 60 €/t CO₂ avoided.     

Combined production of hydrogen and power from heavy oil gasification: Pinch analysis,thermodynamic and economic evaluations

Integrated Gasification Combined Cycle (IGCC) represents a commercially proven technology available for the combined production of hydrogen and electricity power from coal and heavy residue oils. When associated with CO₂ capture and sequestration facilities, the IGCC plant gives an answer to the search for a clean and environmentally compatible use of high sulphur and heavy metal contents fuels, the possibility of installing large size plants for competitive electric power and hydrogen production, and a low cost of CO₂ avoidance.     

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.     

Industrial test and techno-economic analysis of CO2 capture in Huaneng Beijing coal-fired power station

The first industrial-scale CO₂ capture plant in China has been demonstrated at Huaneng Beijing power plant has shown that this technology is a good option for the capture of CO₂ produced by commercial coal-fired power plants. The commissioning and industrial tests are introduced in this paper. The tests show that in the early stages of the passivation phase, the concentration variations of amine, anti-oxidant and Fe³⁺ are in the normal range, and the main parameters achieve the design value. The efficiency of the CO₂ capture was about 80–85%, and by the end of January 2009 about 900 tons of CO₂ (99.7%) have been captured. The equipment investment and consumptive costs, including steam, power, solution and others, have been analyzed. The results show: the cost of the absorber and the stripper account for about 50% of main equipment; the consumptive cost is about 25.3 US$ per metric tons of CO₂, of which the steam requirement accounts for about 55%; the COE increased by 0.02 US$/kW h and the electricity purchase price increased by 29%.     

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

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

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.     

Internalizing externalities of electricity generation: An analysis with MESSAGE-MACRO

This paper examines the global impacts of a policy that internalizes the external costs (related to air pollution damage, excluding climate costs) of electricity generation using a combined energy systems and macroeconomic model. Starting point are estimates of the monetary damage costs for SO₂, NO_X, and PM per kWh electricity generated, taking into account the fuel type, sulfur content, removal technology, generation efficiency, and population density. Internalizing these externalities implies that clean and advanced technologies increase their share in global electricity production. Particularly, advanced coal power plants, natural gas combined cycles, natural gas fuel cells, wind and biomass technologies gain significant market shares at the expense of traditional coal- and gas-fired plants. Global carbon dioxide emissions are lowered by 3% to 5%. Sulfur dioxide emissions drop significantly below the already low level. The policy increases the costs of electricity production by 0.2 (in 2050) to 1.2 € cent/kWh (in 2010). Gross domestic product losses are between 0.6% and 1.1%. They are comparatively high during the initial phase of the policy, pointing to the need for a gradual phasing of the policy.     

Techno-economic evaluation of the evaporative gas turbine cycle with different CO2 capture options

The techno-economic evaluation of the evaporative gas turbine (EvGT) cycle with two different CO₂ capture options has been carried out. Three studied systems include a reference system: the EvGT system without CO₂ capture (System I), the EvGT system with chemical absorption capture (System II), and the EvGT system with oxyfuel combustion capture (System III). The cycle simulation results show that the system with chemical absorption has a higher electrical efficiency (41.6% of NG LHV) and a lower efficiency penalty caused by CO₂ capture (10.5% of NG LHV) compared with the system with oxyfuel combustion capture. Based on a gas turbine of 13.78 MW, the estimated costs of electricity are 46.1 $/MW h for System I, while 70.1 $/MW h and 74.1 $/MW h for Systems II and III, respectively. It shows that the cost of electricity increment of chemical absorption is 8.7% points lower than that of the option of oxyfuel combustion. In addition, the cost of CO₂ avoidance of System II which is 71.8 $/tonne CO₂ is also lower than that of System III, which is 73.2 $/tonne CO₂. The impacts of plant size have been analyzed as well. Results show that cost of CO₂ avoidance of System III may be less than that of System II when a plant size is larger than 60 MW.     

Thermodynamic performance assessment and comparison of IGCC with solid cycling process for CO2 capture at high and medium temperatures

Solid sorbents can be used to capture CO₂ from pre-combustion sources at various temperatures. MgO and CaO are typical medium- and high-temperature CO₂ sorbents. However, pure MgO is not active toward CO₂. The addition of Na₂CO₃ increases the operating temperature and significantly increases the reactivity of sorbents to capture CO₂. Na₂CO₃-promoted MgO is a promising medium-temperature CO₂ sorbent. In this study, the thermodynamic performance of integrated gasification combined cycle (IGCC) systems with Na₂CO₃–MgO-based warm gas decarbonation (WGDC) and CaO-based hot gas decarbonation (HGDC) is evaluated and compared with that of an IGCC system with methyldiethanolamine (MDEA)-based cold gas decarbonation (CGDC). Assuming that the average CO₂ capture capacities of solid sorbents are one-third of their theoretical maxima, we reveal that the IGCC system undergoes approximately 2.8% and 3.6% improvement on net efficiency when switching from CGDC to WGDC and to HGDC, respectively. The net efficiency of the system is increased by improving the CO₂ capture capacity of the sorbent. The IGCC with Na₂CO₃–MgO experiences more significant increase in efficiency than that with CaO along with the improvement of sorbent average CO₂ capture capacity. The efficiency of the IGCC systems reaches the same value when the average CO₂ capture capacities of both sorbents are 53% of their theoretical levels. The effects of gas turbine combustor fuel gas inlet temperature on IGCC system performance are analyzed. Results show that the efficiency of the IGCC systems with HGDC and WGDC increases by 0.74% and 0.53% respectively as the fuel gas inlet temperature increases from 250 °C to 650 °C.     

Exergoeconomic assessment of a geothermal assisted high temperature steam electrolysis system

Exergoeconomic formulations and procedure including exergy flows and cost formation and allocation within a high temperature steam electrolysis (HTSE) system are developed, and applied at three environmental temperatures. The cost accounting procedure is based on the specific exergy costing (SPECO) methodology. Exergy based cost-balance equations are obtained by fuel and product approach. Cost allocations in the system are obtained and effect of the second-law efficiency on exergetic cost parameters is investigated. The capital investment cost, the operating and maintenance costs and the total cost of the system are determined to be 422.2, 2.04, and 424.3 €/kWh, respectively. The specific unit exergetic costs of the power input to the system are 0.0895, 0.0702, and 0.0645 €/kWh at the environmental temperatures of 25 °C, 11 °C, and −1 °C, respectively. The exergetic costs of steam are 0.000509, 0.000544, and 0.000574 €/kWh at the same environmental temperatures, respectively. The amount of energy consumption for the production of one kg hydrogen is obtained as 133 kWh (112.5 kWh power + 20.5 kWh steam), and this corresponds to a hydrogen cost of 1.6 €/kg H₂.     

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.     

Greenhouse-gas emissions from solar electric- and nuclear power: A life-cycle study

Solar- and nuclear-electricity-generation technologies often are deemed “carbon-free” because their operation does not generate any carbon dioxide. However, this is not so when considering their entire lifecycle of energy production; carbon dioxide and other gases are emitted during the extraction, processing, and disposal of associated materials. We determined the greenhouse gas (GHG) emissions, namely, CO₂, CH₄, N₂O, and chlorofluorocarbons due to materials and energy flows throughout all stages of the life of commercial technologies for solar-electric- and nuclear-power generation, based on data from 12 photovoltaic (PV) companies, and reviews of nuclear-fuel life cycles in the United States, Europe, and Japan. Previous GHG estimates vary widely, from 40 to 180 CO₂-eq./kWh for PV, and 3.5–100 CO₂-eq./kWh for nuclear power. Country-specific parameters account for many of these differences, which are exacerbated by outdated information. We conclude, instead, that lifetime GHG emissions from solar- and nuclear-fuel cycles in the United States are comparable under actual production conditions and average solar irradiation, viz., 22–49 g CO₂-eq./kWh (average US), 17–39 g CO₂-eq./kWh (south west) for solar electric, and 16–55 g CO₂-eq./kWh for nuclear energy. However, several factors may significantly change this picture within the next 5 years, and there are unanswered questions about the nuclear fuel cycle that warrant further analyses.     

Cost of energy and environmental policy in Portuguese CO2 abatement—scenario analysis to 2020

This paper quantifies the contribution of Portuguese energy policies for total and marginal abatement costs (MAC) for CO₂ emissions for 2020. The TIMES_PT optimisation model was used to derive MAC curves from a set of policy scenarios including one or more of the following policies: ban on nuclear power; ban on new coal power plants without carbon sequestration and storage; incentives to natural gas power plants; and a cap on biomass use. The different MAC shows the policies’ effects in the potential for CO₂ abatement. In 2020, in the most encompassing policy scenario, with all current and planned policies, is possible to abate only up to +35% of 1990 emissions at a cost below 23 € t/CO₂. In the more flexible policy scenarios, it is possible to abate up to −10% of 1990 emissions below the same cost. The total energy system costs are 10–13% higher if all policies are implemented—76 to 101 B€—roughly the equivalent to 2.01–2.65% of the 2005 GDP. Thus, from a CO₂ emission mitigation perspective, the existing policies introduce significant inefficiencies, possibly related to other policy goals. The ban on nuclear power is the instrument that has the most significant effect in MAC.     

Internalizing externalities into capacity expansion planning: The case of electricity in Vietnam

This paper examines the impacts of including external costs such as environmental and health damages from power production on power generation expansion planning in Vietnam. Using the MARKAL model and covering a 20-year period to 2025, the study shows that there are substantial changes in the generation structure in favor of renewable energy technologies and other low emitting technologies. These changes lead to a reduction in fossil fuel requirements, and consequently, a reduction of CO₂, NO_x, SO₂, and PM emissions which could be expected to also reduce the associated environmental and human health impacts. The avoided external costs would be equivalent to 4.4 US cent/kWh. However, these gains are not free as the additional electricity production cost would be around 2.6 US cent/kWh higher if the switch to more expensive, but lower emitting technologies were made. The net benefit of internalizing these externalities is thus around 1.8 US cent/kWh.