Parametric techno‐economic studies of coal/biomass co‐gasification for IGCC plants with carbon capture using various coal ranks,fuel‐feeding schemes,and syngas cooling methods

Because of biomass's limited supply (as well as other issues involving its feeding and transportation), pure biomass plants tend to be small, which results in high production and capital costs (per unit power output) compared with much larger coal plants. Thus, it is more economically attractive to co‐gasify biomass with coal. Biomass can also make an existing plant carbon‐neutral or even carbon‐negative if enough carbon dioxide is captured and sequestered (CCS). As a part of a series of studies examining the thermal and economic impact of different design implementations for an integrated gasification combined cycle (IGCC) plant fed with blended coal and biomass, this paper focuses on investigating various parameters, including radiant cooling versus syngas quenching, dry‐fed versus slurry‐fed gasification (particularly in relation to sour‐shift and sweet‐shift carbon capture systems), oxygen‐blown versus air‐blown gasifiers, low‐rank coals versus high‐rank coals, and options for using syngas or alternative fuels in the duct burner for the heat recovery steam generator (HRSG) to achieve the desired steam turbine inlet temperature. Using the commercial software, Thermoflow^®, the case studies were performed on a simulated 250‐MW coal IGCC plant located near New Orleans, Louisiana, and the coal was co‐fed with biomass using ratios ranging from 10% to 30% by weight. Using 2011 dollars as a basis for economic analysis, the results show that syngas coolers are more efficient than quench systems (by 5.5 percentage points), but are also more expensive (by $500/kW and 0.6 cents/kW h). For the feeding system, dry‐fed is more efficient than slurry‐fed (by 2.2–2.5 points) and less expensive (by $200/kW and 0.5 cents/kW h). Sour‐shift CCS is both more efficient (by 3 percentage points) and cheaper (by $600/kW or 1.5 cents/kW h) than sweet‐shift CCS. Higher‐ranked coals are more efficient than lower‐ranked coals (2.8 points without biomass, or 1.5 points with biomass) and have lower capital cost (by $600/kW without using biomass, or $400/kW with biomass). Finally, plants with biomass and low‐rank coal feedstock are both more efficient and have lower costs than those with pure coal: just 10% biomass seems to increase the efficiency by 0.7 points and reduce costs by $400/kW and 0.3 cents/kW h. However, for high‐rank coals, this trend is different: the efficiency decreases by 0.7 points, and the cost of electricity increases by 0.1 cents/kW h, but capital costs still decrease by about $160/kW. Copyright © 2016 John Wiley & Sons, Ltd.     

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.     

Techno‐economic analysis of biomass/coal Co‐gasification IGCC systems with supercritical steam bottom cycle and carbon capture

In recent years, integrated gasification combined cycle technology has been gaining steady popularity for use in clean coal power operations with carbon capture and sequestration (CCS). This study focuses on investigating two approaches to improve efficiency and further reduce the greenhouse gas (GHG) emissions. First, replace the traditional subcritical Rankine steam cycle portion of the overall plant with a supercritical steam cycle. Second, add different amounts of biomass as feedstock to reduce emissions. Employing biomass as a feedstock has the advantage of being carbon neutral or even carbon negative if CCS is implemented. However, due to limited feedstock supply, such plants are usually small (2–50 MW), which results in lower efficiency and higher capital and production costs. Considering these challenges, it is more economically attractive and less technically challenging to co‐combust or co‐gasify biomass wastes with low‐rank coals. Using the commercial software, Thermoflow®, this study analyzes the baseline plants around 235 MW and 267 MW for the subcritical and supercritical designs, respectively. Both post‐combustion and pre‐combustion CCS conditions are considered. The results clearly show that utilizing a certain type of biomass with low‐rank coals up to 50% (wt.) can, in most cases, not only improve the efficiency and reduce overall emissions but may be economically advantageous, as well. Beyond a 10% Biomass Ratio, however, the efficiency begins to drop due to the rising pretreatment costs, but the system itself still remains more efficient than from using coal alone (between 0.2 and 0.3 points on average). The CO₂ emissions decrease by about 7000 tons/MW‐year compared to the baseline (no biomass), making the plant carbon negative with only 10% biomass in the feedstock. In addition, implementing a supercritical steam cycle raises the efficiency (1.6 percentage points) and lowers the capital costs ($300/kW), regardless of plant layout. Implementing post‐combustion CCS consistently causes a drop in efficiency (at least 7–8 points) from the baseline and increases the costs by $3000–$4000/kW and In recent years, integrated gasification combined cycle technology has been gaining steady popularity for use in clean coal power operations with carbon capture and sequestration (CCS). This study focuses on investigating two approaches to improve efficiency and further reduce the greenhouse gas (GHG) emissions. First, replace the traditional subcritical Rankine steam cycle portion of the overall plant with a supercritical steam cycle. Second, add different amounts of biomass as feedstock to reduce emissions. Employing biomass as a feedstock has the advantage of being carbon neutral or even carbon negative if CCS is implemented. However, due to limited feedstock supply, such plants are usually small (2–50 MW), which results in lower efficiency and higher capital and production costs. Considering these challenges, it is more economically attractive and less technically challenging to co‐combust or co‐gasify biomass wastes with low‐rank coals. Using the commercial software, Thermoflow®, this study analyzes the baseline plants around 235 MW and 267 MW for the subcritical and supercritical designs, respectively. Both post‐combustion and pre‐combustion CCS conditions are considered. The results clearly show that utilizing a certain type of biomass with low‐rank coals up to 50% (wt.) can, in most cases, not only improve the efficiency and reduce overall emissions but may be economically advantageous, as well. Beyond a 10% Biomass Ratio, however, the efficiency begins to drop due to the rising pretreatment costs, but the system itself still remains more efficient than from using coal alone (between 0.2 and 0.3 points on average). The CO₂ emissions decrease by about 7000 tons/MW‐year compared to the baseline (no biomass), making the plant carbon negative with only 10% biomass in the feedstock. In addition, implementing a supercritical steam cycle raises the efficiency (1.6 percentage points) and lowers the capital costs ($300/kW), regardless of plant layout. Implementing post‐combustion CCS consistently causes a drop in efficiency (at least 7–8 points) from the baseline and increases the costs by $3000–$4000/kW and $0.06–$0.07/kW‐h. The SO_x emissions also decrease by about 190 tons/year (7.6 × 10^?6 tons/MW‐year). Finally, the CCS cost is around $65–$72 per ton of CO₂. For pre‐combustion CCS, sour shift appears to be superior both economically and thermally to sweet shift in the current study. Sour shift is always cheaper, (by a difference of about $600/kW and $0.02‐$0.03/kW‐h), easier to implement, and also 2–3 percentage points more efficient. The economic difference is fairly marginal, but the trend is inversely proportional to the efficiency, with cost of electricity decreasing by 0.5 cents/kW‐h from 0% to 10% biomass ratio (BMR) and rising 2.5 cents/kW‐h from 10% to 50% BMR. Pre‐combustion CCS plants are smaller than post‐combustion ones and usually require 25% less energy for CCS due to their compact size for processing fuel flow only under higher pressure (450 psi), versus processing the combusted gases at near‐atmospheric pressure. Finally, the CO₂ removal cost for sour shift is around $20/ton, whereas sweet shift's cost is around $30/ton, which is much cheaper than that of post‐combustion CCS: about $60–$70/ton. Copyright © 2014 John Wiley & Sons, Ltd.     

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.     

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.     

The cost of integration of zero emission power plants—A case study for the island of Cyprus

In this work, a technical, economic and environmental analysis is carried out for the estimation of the optimal option scenario for the Cyprus's future power generation system. A range of power generation technologies integrated with carbon capture and storage (CCS) were examined as candidate options and compared with the business as usual scenario. Based on the input data and the assumptions made, the simulations indicated that the integrated gasification combined cycle (IGCC) technology with pre-combustion CCS integration is the least cost option for the future expansion of the power generation system. In particular, the results showed that for a natural gas price of 7.9US$/GJ the IGCC technology with pre-combustion CCS integration is the most economical choice, closely followed by the pulverized coal technology with post-combustion CCS integration. The combined cycle technology can, also, be considered as alternative competitive technology. The combined cycle technologies with pre- or post-combustion CCS integration yield more expensive electricity unit cost. In addition, a sensitivity analysis has been also carried out in order to examine the effect of the natural gas price on the optimum planning. For natural gas prices greater than 6.4US$/GJ the least cost option is the use of IGCC technology with CCS integration. It can be concluded that the Cyprus's power generation system can be shifted slowly towards the utilization of CCS technologies in favor of the existing steam power plants in order not only to lower the environmental emissions and fulfilling the recent European Union Energy Package requirements but also to reduce the associated electricity unit cost.     

中国中长期碳减排战略目标初探(Ⅱ)——中国煤炭消费过程的碳排放及减排措施

中国能源领域排放的二氧化碳主要来自煤炭,因此煤炭消费过程中的碳减排措施尤为重要。煤炭的主要用户是发电部门,基于应对气候变化的需要,煤电行业的低碳途径不得不考虑采用CCS技术。不论是新建燃煤电厂,还是今后在传统电厂改建过程中增设CCS设施已是大势所趋,预计多数仍将采用MEA法脱除烟气中二氧化碳这一成熟技术。由于MEA法技术经济指标不够先进,估计10~20年内必将出现更先进的脱二氧化碳工艺技术。传统的燃煤锅炉增加CCS的经济效益已经逊于IGCC-CCS,预计2020年后IGCC电厂将成为新建煤电厂的首选方案。20年后采用临氢气化炉与燃料电池FC发电相结合、把高温的热能和甲烷的化学能直接转化为电力的IGFC高效燃煤电厂或将成功应用,IGFC综合能量转化效率比IGCC相对高出1/2~3/4,发展前景不可低估。钢铁、水泥和化工等高耗煤工业部门可通过节能和采用CCS技术降低碳排放,其余用煤的工业部门和分散用户则应考虑节能或用天然气等低碳燃料替代,间接起到减排效果。预计2050年燃煤发电和高耗煤工业总计将排放二氧化碳4.6Gt,如果二氧化碳捕集量是2.9Gt,则净排放量为1.7Gt。加上其他难以捕集二氧化碳的工业、部门及民用煤排放二氧化碳1.0Gt,合计二氧化碳净排放量为2.7Gt(情景A)。如果采用更先进的技术和严格的节能减排措施,可减少煤炭消耗0.31Gt标煤,减少二氧化碳排放0.5Gt,使煤源二氧化碳净排放量减少到2.2Gt(情景B)。无论哪种情景,实施CCS的任务都十分艰巨。     

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.     

Future carbon regulations and current investments in alternative coal-fired power plant technologies

We analyze how uncertain future US carbon regulations shape the current choice of the type of power plant to build. Our focus is on two coal-fired technologies, pulverized coal (PC) and integrated coal gasification combined cycle technology (IGCC). The PC technology is cheapest—assuming there is no need to control carbon emissions. The IGCC technology may be cheaper if carbon must be captured. Since power plants last many years and future regulations are uncertain, a US electric utility faces a standard decision under uncertainty. A company will confront the range of possible outcomes, assigning its best estimate of the probability of each scenario, averaging the results and determining the power plant technology with the lowest possible cost inclusive of expected future carbon related costs, whether those costs be in the form of emissions charges paid or capital expenditures for retrofitting to capture carbon. If the company assigns high probability to no regulation or to less stringent regulation of carbon, then it makes sense for it to build the PC plant. But if it assigns sufficient probability to scenarios with more stringent regulation, then the IGCC technology is warranted. We provide some useful benchmarks for possible future regulation and show how these relate back to the relative costs of the two technologies and the optimal technology choice. Few of the policy proposals widely referenced in the public discussion warrant the choice of the IGCC technology. Instead, the PC technology remains the least costly. However, recent carbon prices in the European Emissions Trading System are higher than these benchmarks. If it is any guide to possible future penalties for emissions in the US, then current investment in the IGCC technology is warranted. Of course, other factors need to be factored into the decision as well.     

Integrated biomass energy systems and emissions of carbon dioxide

Electric Power Research Institute (EPRI) and the US Department of Energy (DOE) have been funding a number of case studies under the initiative entitled “Economic Development through Biomass Systems Integration”, with the objective of investigate the feasibility of integrated biomass energy systems, utilizing a dedicated feedstock supply system (DFSS) for energy production. This paper deals with the full fuel cycle for four of these case studies, which have been examined with regard to the emissions of carbon dioxide, CO₂. Although the conversion of biomass to electricity in itself does not emit more CO₂ than is captured by the biomass through photosynthesis, there will be some CO₂ emissions from the DFSS. External energy is required for the production and transportation of the biomass feedstock, and this energy is mainly based on fossil fuels. By using this input energy, CO₂ and other greenhouse gases are emitted. However, by utilizing biomass with fossil fuels as external input fuels, we would get about 10–15 times more electric energy per unit fossil fuel, compared with a 100% coal power system. By introducing a DFSS on former farmland the amount of energy spent for production of crops can be reduced, the amount of fertilizers can be decreased, the soil can be improved and a significant amount of energy will be produced compared with an ordinary farm crop. Compared with traditional coal-based electricity production, the CO₂ emissions are in most cases reduced significantly by as much as 95%. The important conclusion is the great potential for reducing greenhouse gas emissions through the offset of coal by biomass.     

Comparative assessment of future power generation technologies based on carbon price development

The long-term assessment of new electricity generation was performed for various long-run policy scenarios taking into account two main criteria: private costs and external GHG emission costs. Such policy oriented power generation technologies assessment based on carbon price and private costs of technologies can provide information on the most attractive future electricity generation technologies taking into account climate change mitigation targets and GHG emission reduction commitments for world regions.Analysis of life cycle GHG emissions and private costs of the main future electricity generation technologies performed in this paper indicated that biomass technologies except large scale straw combustion technologies followed by nuclear have the lowest life cycle GHG emission. Biomass IGCC with CO₂ capture has even negative life cycle GHG emissions. The cheapest future electricity generation technologies in terms of private costs in long-term perspective are: nuclear and hard coal technologies followed by large scale biomass combustion and biomass CHPs. The most expensive technologies in terms of private costs are: oil and natural gas technologies. As the electricity generation technologies having the lowest life cycle GHG emissions are not the cheapest one in terms of private costs the ranking of technologies in terms of competitiveness highly depend on the carbon price implied by various policy scenarios integrating specific GHG emission reduction commitments taken by countries and climate change mitigation targets.     

Clean coal technology development in China

Coal is found in huge amounts throughout the world and is expected to play a crucial role as an abundant energy source. However, one critical issue in promoting coal utilization is controlling environmental pollution. Clean coal technologies are needed to utilize coal in an environmentally acceptable way and to improve coal utilization efficiency. This paper describes coal's role in China's energy system and the environmental issues related to coal use. Coal is responsible for 90% of the SO₂ emissions, 70% of the dust emissions, 67% of the NO_x emissions, and 70% of the CO₂ emissions. But as the most abundant energy resource, it will continue to be the dominant energy supply for a long time. Therefore, the development and deployment of clean coal technologies are crucial to promote sustainable development in China. Clean coal technologies currently being developed in China are described including high efficiency combustion and advanced power generation technologies, coal transformation technologies, IGCC (integrated gasification combined cycle) and carbon capture and storage (CCS). Although China only recently began developing clean coal technologies, there have been many successes. Most recent orders of coal-fired power plants are units larger than 600 MW and new orders for supercritical and ultra supercritical systems are increasing rapidly. Many national research programs, industrial research programs and international collaboration projects have been launched to develop on IGCC and CCS systems in China. Finally, suggestions are given on how to further promote clean coal technologies in China.     

Optimising trans-national power generation and transmission investments: a Southern African example

Increased integration and co-operation within the Southern African power sector has opened up significant opportunities for reducing the economic and environmental costs of meeting increasing electricity demand in Southern Africa. This paper applies a linear programming model to investigate the economic and environmental benefits of regional integrated planning for electricity, and the impact of including environmental costs in the decision-making process. We find that, from a financial perspective, optimising generation and transmission investments in the region would result in savings of $2–4 billion over 20 years, or 5% of total system costs. Introducing a tax based on the external damage costs of carbon dioxide as part of the decision-making process would result in moderate increases in financial costs (15–20%), but would reduce regional carbon emissions by up to 55% at a mitigation cost of $11 per tonne of carbon dioxide. This raises the possibility of financing regional power projects with Clean Development Mechanism funding, which we explore with an example.     

Comparing least cost scenarios for 100% renewable electricity with low emission fossil fuel scenarios in the Australian National Electricity Market

Policy makers face difficult choices in planning to decarbonise their electricity industries in the face of significant technology and economic uncertainties. To this end we compare the projected costs in 2030 of one medium-carbon and two low-carbon fossil fuel scenarios for the Australian National Electricity Market (NEM) against the costs of a previously published scenario for 100% renewable electricity in 2030. The three new fossil fuel scenarios, based on the least cost mix of baseload and peak load power stations in 2010, are: (i) a medium-carbon scenario utilising only gas-fired combined cycle gas turbines (CCGTs) and open cycle gas turbines (OCGTs); (ii) coal with carbon capture and storage (CCS) plus peak load OCGT; and (iii) gas-fired CCGT with CCS plus peak load OCGT. We perform sensitivity analyses of the results to future carbon prices, gas prices, and CO₂ transportation and storage costs which appear likely to be high in most of Australia. We find that only under a few, and seemingly unlikely, combinations of costs can any of the fossil fuel scenarios compete economically with 100% renewable electricity in a carbon constrained world. Our findings suggest that policies pursuing very high penetrations of renewable electricity based on commercially available technology offer a cost effective and low risk way to dramatically cut emissions in the electricity sector.     

How carbon pricing changes the relative competitiveness of low-carbon baseload generating technologies

There is wide public debate about which electricity generating technologies will best be suited to reduce greenhouse gas emissions (GHG). Sometimes this debate ignores real-world practicalities and leads to over-optimistic conclusions. Here we define and apply a set of fit-for-service criteria to identify technologies capable of supplying baseload electricity and reducing GHGs by amounts and within the timescale set by the Intergovernmental Panel on Climate Change (IPCC). Only five current technologies meet these criteria: coal (both pulverised fuel and integrated gasification combined cycle) with carbon capture and storage (CCS); combined cycle gas turbine with CCS; Generation III nuclear fission; and solar thermal backed by heat storage and gas turbines. To compare costs and performance, we undertook a meta-review of authoritative peer-reviewed studies of levelised cost of electricity (LCOE) and life-cycle GHG emissions for these technologies. Future baseload electricity technology selection will be influenced by the total cost of technology substitution, including carbon pricing, which is synergistically related to both LCOE and emissions. Nuclear energy is the cheapest option and best able to meet the IPCC timetable for GHG abatement. Solar thermal is the most expensive, while CCS will require rapid major advances in technology to meet that timetable.     

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.     

Cost effective integration of hydrogen in energy systems with CO2 constraints

The integration of hydrogen in national energy systems is illustrated in four extreme scenarios, reflecting four technological mainstreams (energy conservation, renewables, nuclear and CO₂ removal) to reduce C emissions. Hydrogen is cost-effective in all scenarios with higher CO₂ reduction targets. Hydrogen would be produced from fossil fuels, or from water and electricity or heat, depending upon the scenario. Hydrogen would be used in the residential and commercial sectors and for transport vehicles, industry, and electricity generation in fuel cells. At severe (50–70%) CO₂ reduction targets, hydrogen would cost-effectively supply more than half of the total useful energy demands in three out of four scenarios. The marginal emission reduction costs in the CO₂ removal scenario at severe CO₂ reduction targets are DFL 200/tCO₂ (ca $ 100/t). In the nuclear, renewable and energy conservation scenarios these costs are much higher. Whilst the fossil fuel scenario would be less expensive than the other scenarios, the possibility of CO₂ storage in depleted gas reservoirs is a conditio sine qua non.     

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.     

Engineering economic analysis of biomass IGCC with carbon capture and storage

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

A system performance and economics analysis of IGCC with supercritical steam bottom cycle supplied with varying blends of coal and biomass feedstock

In recent years, Integrated Gasification Combined Cycle Technology (IGCC) has been gaining popularity for use in clean coal power operations with carbon capture and sequestration. Great efforts have been continuously spent on investigating ways to improve the efficiency and further reduce the greenhouse gas emissions of such plants. This study focuses on investigating two approaches to achieve these goals. First, replace the traditional subcritical Rankine cycle portion of the overall plant with a supercritical steam cycle. Second, add biomass as co‐feedstock to reduce carbon footprint as well as SO_x and NO_x emissions. In fact, plants that use biomass alone can be carbon neutral and even become carbon negative if CO₂ is captured. Due to a limited supply of feedstock, biomass plants are usually small, which results in higher capital and production costs. In addition, biomass can only be obtained at specific times in the year, resulting in fairly low capacity factors. Considering these challenges, it is more economically attractive and less technically challenging to co‐gasify biomass wastes with coal. The results show that for supercritical IGCC, the net efficiency increases with increased biomass in all cases. For both subcritical and supercritical cases, the efficiency increases from 0% to 10% (wt.) biomass and decreases thereafter. However, the efficiency of the blended cases always remains higher than that of the pure‐coal baseline cases. The emissions (NO_x, SO_x, and effective CO₂) and the capital costs decrease as biomass ratio (BMR) increases, but the cost of electricity (CoE) increases with BMR due to the high cost of the biomass used. Finally, implementing a supercritical steam cycle is shown to increase the net plant output power by 13% and the thermal efficiency by about 1.6 percentage points (or 4.56%) with a 6.7% reduction in capital cost, and a 3.5% decrease in CoE. Copyright © 2013 John Wiley & Sons, Ltd.