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1.
In this article, we present a life cycle assessment (LCA) of CO2 capture and storage (CCS) for several lignite power plant technologies. The LCA includes post-combustion, pre-combustion and oxyfuel capture processes as well as subsequent pipeline transport and storage of the separated CO2 in a depleted gas field.The results show an increase in cumulative energy demand and a substantial decrease in greenhouse gas (GHG) emissions for all CO2 capture approaches in comparison with power plants without CCS, assuming negligible leakage within the time horizon under consideration. Leakage will, however, not be zero. Due to the energy penalty, CCS leads to additional production of CO2. However, the CO2 emissions occur at a much lower rate and are significantly delayed, thus leading to different, and most likely smaller, impacts compared to the no-sequestration case. In addition, a certain share of the CO2 will be captured permanently due to chemical reactions and physical trapping.For other environmental impact categories, the results depend strongly on the chosen technology and the details of the process. The post-combustion approach, which is closest to commercial application, leads to sharp increases in many categories of impacts, with the impacts in only one category, acidification, reduced. In comparison with a conventional power plant, the pre-combustion approach results in decreased impact in all categories. This is mainly due to the different power generation process (IGCC) which is coupled with the pre-combustion technology.In the case of the oxyfuel approach, the outcome of the LCA depends highly on two uncertain parameters: the energy demand for air separation and the feasibility of co-capture of pollutants other than CO2. If co-capture were possible, oxyfuel could lead to a near-zero emission power plant.  相似文献   

2.
Given the dominance of power plant emissions of greenhouse gases, and the growing worldwide interest in CO2 capture and storage (CCS) as a potential climate change mitigation option, the expected future cost of power plants with CO2 capture is of significant interest. Reductions in the cost of technologies as a result of learning-by-doing, R&D investments and other factors have been observed over many decades. This study uses historical experience curves as the basis for estimating future cost trends for four types of electric power plants equipped with CO2 capture systems: pulverized coal (PC) and natural gas combined cycle (NGCC) plants with post-combustion CO2 capture; coal-based integrated gasification combined cycle (IGCC) plants with pre-combustion capture; and coal-fired oxyfuel combustion for new PC plants. We first assess the rates of cost reductions achieved by other energy and environmental process technologies in the past. Then, by analogy with leading capture plant designs, we estimate future cost reductions that might be achieved by power plants employing CO2 capture. Effects of uncertainties in key parameters on projected cost reductions also are evaluated via sensitivity analysis.  相似文献   

3.
Oxyfuel combustion in a pulverised fuel coal-fired power station produces a raw CO2 product containing contaminants such as water vapour plus oxygen, nitrogen and argon derived from the excess oxygen for combustion, impurities in the oxygen used, and any air leakage into the system. There are also acid gases present, such as SO3, SO2, HCl and NOx produced as byproducts of combustion. At GHGT8 (White and Allam, 2006) we presented reactions that gave a path-way for SO2 to be removed as H2SO4 and NO and NO2 to be removed as HNO3. In this paper we present initial results from the OxyCoal-UK project in which these reactions are being studied experimentally to provide the important reaction kinetic information that is so far missing from the literature. This experimental work is being carried out at Imperial College London with synthetic flue gas and then using actual flue gas via a sidestream at Doosan Babcock's 160 kW coal-fired oxyfuel rig. The results produced support the theory that SOx and NOx components can be removed during compression of raw oxyfuel-derived CO2 and therefore, for emissions control and CO2 product purity, traditional FGD and deNOx systems should not be required in an oxyfuel-fired coal power plant.  相似文献   

4.
The oxyfuel process is one of the most promising options to capture CO2 from coal fired power plants. The combustion takes place in an atmosphere of almost pure oxygen, delivered from an air separation unit (ASU), and recirculated flue gas. This provides a flue gas containing 80–90 vol% CO2 on a dry basis. Impurities are caused by the purity of the oxygen from the ASU, the combustion process and air ingress. Via liquefaction a CO2 stream with purity in the range from 85 to 99.5 vol% can be separated and stored geologically. Impurities like O2, NOX, SOX, and CO may negatively influence the transport infrastructure or the geological storage site by causing geochemical reactions. Therefore the maximum acceptable concentrations of the impurities in the separated CO2 stream must be defined regarding the requirements from transportation and storage. The main objective of the research project COORAL therefore is to define the required CO2 purity for capture and storage.  相似文献   

5.
Flue gas purification is a necessary method to avoid emission of sour gases like SOx and NOx into the environment. Another important aspect is the zero CO2 emission from coal-fired power plants. Oxyfuel technology is one of the processes to reach this goal. LINDE KCA Dresden in cooperation with Vattenfall Europe is operating a pilot plant producing liquefied CO2. Product specification and material requirements make flue gas purification for the removal of SOx and NOx unavoidable. The new oxyfuel technologies offer new process conditions for flue gas purification which are not available at atmospheric conditions.At Linde laboratories, catalytic and non-catalytic DeNOx and DeSOx processes have been screened for oxyfuel application. After first feasibility studies, laboratory experiments and economic evaluations, it was decided to develop a process based on wet scrubber systems to remove NOx from flue gas, simultaneously producing ammonia nitrites which can be thermally decomposed into nitrogen in a second step. After demonstration of the single process steps on laboratory scale, a pilot scrubber was erected and commissioned in 2010 at Schwarze Pumpe Oxyfuel Pilot Plant. In September 2010, the successful completion of the pilot tests demonstrated the NOx removal efficiency of this technology. The data from the pilot plant tests have been used to finalise a kinetic model describing the NOx absorption behaviour regarding NOx removal rate and nitrite selectivity for demonstration of plant scale up. This DeNOx-process is now marketed under the name “LICONOX”.  相似文献   

6.
This work provides the essential information and approaches for integration of carbon dioxide (CO2) capture units into power plants, particularly the supercritical type, so that energy utilization and CO2 emissions can be well managed in the subject power plants. An in-house model, developed at the University of Regina, Canada, was successfully used for simulating a 500 MW supercritical coal-fired power plant with a post-combustion CO2 capture unit. The simulations enabled sensitivity and parametric study of the net efficiency of the power plant, the coal consumption rate, and the amounts of CO2 captured and avoided. The parameters of interest include CO2 capture efficiency, type of coal, flue gas delivery scheme, type of amine used in the capture unit, and steam pressure supplied to the capture unit for solvent regeneration. The results show that the advancement of MEA-based CO2 capture units through uses of blended monoethanolamine–methyldiethanolamine (MEA–MDEA) and split flow configuration can potentially make the integration of power plant and CO2 capture unit less energy intensive. Despite the increase in energy penalty, it may be worth capturing CO2 at a higher efficiency to achieve greater CO2 emissions avoided. The flue gas delivery scheme and the steam pressure drawn from the power plant to the CO2 capture unit should be considered for process integration.  相似文献   

7.
The application of post-combustion capture (PCC) processes in coal fired power stations can result in large reductions of the CO2-emissions, but the consequential decrease in generation efficiency is an important draw-back. The leading PCC technology is based on chemical absorption processes as this technology is the one whose scale-up status is closest to full-scale capture in power plants. The energy performance of this process is analysed in this contribution. The analysis shows that the potential for improvement of the energy performance is quite large. It is demonstrated that further development of the capture technology and the power plant technology can lead to generation efficiencies for power plants with 90% CO2 capture which are equivalent to the current generation efficiencies without CO2 capture, i.e. 0.4 (HHV), leading to an additional resource consumption of 16%. These improvements are possible throughout a combined improvement for the capture process and power generation processes.  相似文献   

8.
In this work the feasibility of a CO2 capture system based on sodium carbonate–bicarbonate slurry and its integration with a power plant is studied. The results are compared to monoethanolamine (MEA)-based capture systems. Condensing power plant and combined heat and power plant with CO2 capture is modelled to study the feasibility of combined heat and power plant for CO2 capture.Environmental friendly sodium carbonate would be an interesting chemical for CO2 capture. Sodium carbonate absorbs CO2 forming sodium bicarbonate. The low solubility of sodium bicarbonate is a weak point for the sodium carbonate based liquid systems since it limits the total concentration of carbonate. In this study the formation of solid bicarbonate is allowed, thus forming slurry, which can increase the capacity of the solvent. With this the energy requirement of stripping of the solvent could potentially be around 3.22 MJ/kg of captured CO2 which is significantly lower than with MEA based systems which typically have energy consumption around 3.8 MJ/kg of captured CO2.Combined heat and power plants seem to be attractive for CO2 capture because of the high total energy efficiency of the plants. In a condensing power plant the CO2 capture decreases directly the electricity production whereas in a combined heat and power plant the loss can be divided between district heat and electricity according to demand.  相似文献   

9.
10.
This paper presents the results of a study to develop Air Products’ air separation unit (ASU) offerings for oxyfuel coal CO2 capture projects. A scalable “reference plant” concept is described to match particular sizes of power generation equipment, taking into account factors such as safety, reliability, operating flexibility, efficiency, and low capital cost. We describe the selection of a process cycle to exploit the low purity requirements, as well as the options for compression machinery and drivers as the scale of the plant increases and the sizes of referenced equipment limit the possibilities. We also explore integration with other elements of the system, such as preheating condensate or heating and expanding pressurised nitrogen. In addition, we consider how the ASU affects the flexibility of the oxyfuel system and discuss how its power consumption can be reduced during periods of high power demand. Finally, the advantages and disadvantages of different execution strategies for air separation unit projects are discussed, as well as alternative commercial models for the supply of oxygen.  相似文献   

11.
Existing coal-fired power plants were not designed to be retrofitted with carbon dioxide post-combustion capture (PCC) and have tended to be disregarded as suitable candidates for carbon capture and storage on the grounds that such a retrofit would be uneconomical. Low plant efficiency and poor performance with capture compared to new-build projects are often cited as critical barriers to capture retrofit. Steam turbine retrofit solutions are presented that can achieve effective thermodynamic integration between a post-combustion CO2 capture plant and associated CO2 compressors and the steam cycle of an existing retrofitted unit for a wide range of initial steam turbine designs. The relative merits of these capture retrofit integration options with respect to flexibility of the capture system and solvent upgradability will be discussed. Provided that effective capture system integration can be achieved, it can be shown that the abatement costs (or cost per tonne of CO2 to justify capture) for retrofitting existing units is independent of the initial plant efficiency. This then means that a greater number of existing power plants are potentially suitable for successful retrofits of post-combustion capture to reduce power sector emissions. Such a wider choice of retrofit sites would also give greater scope to exploit favourable site-specific conditions for CCS, such as ready access to geological storage.  相似文献   

12.
Post-combustion CO2 capture and storage (CCS) presents a promising strategy to capture, compress, transport and store CO2 from a high volume–low pressure flue gas stream emitted from a fossil fuel-fired power plant. This work undertakes the simulation of CO2 capture and compression integration into an 800 MWe supercritical coal-fired power plant using chemical process simulators. The focus is not only on the simulation of full load of flue gas stream into the CO2 capture and compression, but also, on the impact of a partial load. The result reveals that the energy penalty of a low capture efficiency, for example, at 50% capture efficiency with 10% flue gas load is higher than for 90% flue gas load at the equivalent capture efficiency by about 440 kWhe/tonne CO2. The study also addresses the effect of CO2 capture performance by different coal ranks. It is found that lignite pulverized coal (PC)-fired power plant has a higher energy requirement than subbituminous and bituminous PC-fired power plants by 40.1 and 98.6 MWe, respectively. In addition to the investigation of energy requirement, other significant parameters including energy penalty, plant efficiency, amine flow rate and extracted steam flow rate, are also presented. The study reveals that operating at partial load, for example at half load with 90% CO2 capture efficiency, as compared with full load, reduces the energy penalty, plant efficiency drop, amine flow rate and extracted steam flow rate by 9.9%, 24.4%, 50.0% and 49.9%, respectively. In addition, the effect of steam extracted from different locations from a series of steam turbine with the objective to achieve the lowest possible energy penalty is evaluated. The simulation shows that a low extracted steam pressure from a series of steam turbines, for example at 300 kPa, minimizes the energy penalty by up to 25.3%.  相似文献   

13.
Oxycombustion is being considered as a promising solution to carbon capture and sequestration. Standard sampling and measurement methods may or may not be valid under oxycombustion conditions because the flue gas differs significantly from that of conventional air-blown coal combustion.Bench-scale tests were conducted to evaluate the measurement validity of continuous mercury monitors (CMMs), with and without a flue gas preconditioning unit, in a simulated oxycombustion flue gas with varied CO2 concentrations. Tests also included mercury capture with activated carbon in typical oxyfuel combustion flue gas. Research data indicated that highly concentrated CO2 streams affect the accuracy of the mass flow rate and the subsequent gaseous mercury measurement, although this is specific to the type of CMM. Concentrated CO2 streams also induced solid precipitation in the wet-chemistry conversion unit and resulted in a biased measurement of the gas-phase mercury. Flue gas dilution appeared to provide accurate measurement of total gas-phase mercury and be applicable to mercury measurement in highly concentrated CO2 streams, although mercury speciation appeared to be problematic and will require additional modification and validation. Mercury capture with activated carbon under CO2-enriched conditions showed similar performance to typical high-acid coal combustion flue gas.  相似文献   

14.
The widespread use of fossil fuels within the current energy infrastructure is considered as the largest source of anthropogenic emissions of carbon dioxide, which is largely blamed for global warming and climate change. At the current state of development, the risks and costs of non-fossil energy alternatives, such as nuclear, biomass, solar, and wind energy, are so high that they cannot replace the entire share of fossil fuels in the near future timeframe. Additionally, any rapid change towards non-fossil energy sources, even if possible, would result in large disruptions to the existing energy supply infrastructure. As an alternative, the existing and new fossil fuel-based plants can be modified or designed to be either “capture” or “capture-ready” plants in order to reduce their emission intensity through the capture and permanent storage of carbon dioxide in geological formations. This would give the coal-fired power generation units the option to sustain their operations for longer time, while meeting the stringent environmental regulations on air pollutants and carbon emissions in years to come.Currently, there are three main approaches to capturing CO2 from the combustion of fossil fuels, namely, pre-combustion capture, post-combustion capture, and oxy-fuel combustion. Among these technology options, oxy-fuel combustion provides an elegant approach to CO2 capture. In this approach, by replacing air with oxygen in the combustion process, a CO2-rich flue gas stream is produced that can be readily compressed for pipeline transport and storage. In this paper, we propose a new approach that allows air to be partially used in the oxy-fired coal power plants. In this novel approach, the air can be used to carry the coal from the mills to the boiler (similar to the conventional air-fired coal power plants), while O2 is added to the secondary recycle flow as well as directly to the combustion zone (if needed). From a practical point of view, this approach eliminates problems with the primary recycle and also lessens concerns about the air leakage into the system. At the same time, it allows the boiler and its back-end piping to operate under slight suction; this avoids the potential danger to the plant operators and equipment due to possible exposure to hot combustion gases, CO2 and particulates. As well, by integrating oxy-fuel system components and optimizing the overall process over a wide range of operating conditions, an optimum or near-optimum design can be achieved that is both cost-effective and practical for large-scale implementation of oxy-fired coal power plants.  相似文献   

15.
Due to its compatibility with the current energy infrastructures and the potential to reduce CO2 emissions significantly, CO2 capture and geological storage is recognised as one of the main options in the portfolio of greenhouse gas mitigation technologies being developed worldwide. The CO2 capture technologies offer a number of alternatives, which involve different energy consumption rates and subsequent environmental impacts. While the main objective of this technology is to minimise the atmospheric greenhouse gas emissions, it is also important to ensure that CO2 capture and storage does not aggravate other environmental concerns. This requires a holistic and system-wide environmental assessment rather than focusing on the greenhouse gases only. Life Cycle Assessment meets this criteria as it not only tracks energy and non-energy-related greenhouse gas releases but also tracks various other environmental releases, such as solid wastes, toxic substances and common air pollutants, as well as the consumption of other resources, such as water, minerals and land use. This paper presents the principles of the CO2 capture and storage LCA model developed at Imperial College and uses the pulverised coal post-combustion capture example to demonstrate the methodology in detail. At first, the LCA models developed for the coal combustion system and the chemical absorption CO2 capture system are presented together with examples of relevant model applications. Next, the two models are applied to a plant with post-combustion CO2 capture, in order to compare the life cycle environmental performance of systems with and without CO2 capture. The LCA results for the alternative post-combustion CO2 capture methods (including MEA, K+/PZ, and KS-1) have shown that, compared to plants without capture, the alternative CO2 capture methods can achieve approximately 80% reduction in global warming potential without a significant increase in other life cycle impact categories. The results have also shown that, of all the solvent options modelled, KS-1 performed the best in most impact categories.  相似文献   

16.
Among the various configurations of fossil fuel power plants with carbon capture, this paper focuses on pre-combustion techniques applied to natural gas combined cycles. With more detail, the plant configuration here addressed includes: (i) the steam reforming of natural gas, based on an air-blown autothermal process, following a recuperative pre-reforming treatment, (ii) the water gas shift producing CO2 and H2, (iii) the separation of CO2 by means of a mixed physical–chemical absorption system using a MDEA solution, and (iv) a hydrogen fuelled combined cycle.Similar configurations have been studied quite extensively, being among the most attractive for full-scale realizations in a near-mid term future. This paper proposes a detailed thermodynamic study and optimization of the plant configuration, bringing to a reliable performance estimation based on today's best available technology as far as the various plant sections are concerned (gas and steam turbine, natural gas reforming process, CO2 separation). The predicted LHV efficiency for the base configuration is about 50%. Being this value at the top of the range quoted in the open literature studies (35–50%), the paper includes a quite extensive sensitivity analysis, showing that more conservative assumptions may bring to significantly poorer performance, especially considering the pretty large number of operating parameters involved in the process.  相似文献   

17.
Most of the current CO2 capture technologies are associated with large energy penalties that reduce their economic viability. Efficiency has therefore become the most important issue when designing and selecting power plants with CO2 capture. Other aspects, like reliability and operability, have been given less importance, if any at all, in the literature.This article deals with qualitative reliability and operability analyses of an integrated reforming combined cycle concept. The plant reforms natural gas into a syngas, the carbon is separated out as CO2 after a water-gas shift section, and the hydrogen-rich fuel is used for a gas turbine. The qualitative reliability analysis in the article consists of a functional analysis followed by a failure mode, effects, and criticality analysis (FMECA). The operability analysis introduces the comparative complexity indicator (CCI) concept.Functional analysis and FMECA are important steps in a system reliability analysis, as they can serve as a platform and basis for further analysis. Also, the results from the FMECA can be interesting for determining how the failures propagate through the system and their effects on the operation of the process. The CCI is a helpful tool in choosing the level of integration and to investigate whether or not to include a certain process feature. Incorporating the analytical approach presented in the article during the design stage of a plant can be advantageous for the overall plant performance.  相似文献   

18.
The goal of this paper is to find methodologies for removing a selection of impurities (H2O, O2, Ar, N2, SOx and NOx) from CO2 present in the flue gas of two oxy-combustion power plants fired with either natural gas (467 MW) or pulverized fuel (596 MW). The resulting purified stream, containing mainly CO2, is assumed to be stored in an aquifer or utilized for enhanced oil recovery (EOR) purposes. Focus has been given to power cycle efficiency i.e.: work and heat requirements for the purification process, CO2 purity and recovery factor (kg of CO2 that is sent to storage per kg of CO2 in the flue gas). Two different methodologies (here called Case I and Case II) for flue gas purification have been developed, both based on phase separation using simple flash units (Case I) or a distillation column (Case II). In both cases purified flue gas is liquefied and its pressure brought to 110 atm prior to storage.Case I: A simple flue gas separation takes place by means of two flash units integrated in the CO2 compression process. Heat in the process is removed by evaporating the purified liquid CO2 streams coming out from both flashes. Case I shows a good performance when dealing with flue gases with low concentration of impurities. CO2 fraction after purification is over 96% with a CO2 recovery factor of 96.2% for the NG-fired flue gas and 88.1% for the PF-fired flue gas. Impurities removal together with flue gas compression and liquefaction reduces power plant output of 4.8% for the NG-fired flue gas and 11.6% for the PF-fired flue gas. The total amount of work requirement per kg stored CO2 is 453 kJ for the NG-fired flue gas and 586 kJ for the PF-fired flue gas.Case II: Impurities are removed from the flue gas in a distillation column. Two refrigeration loops (ethane and propane) have been used in order to partially liquefy the flue gas and for heat removal from a partial condenser. Case II can remove higher amounts of impurities than Case I. CO2 purity prior to storage is over 99%; CO2 recovery factor is somewhat lower than in Case I: 95.4% for the NG-fired flue gas and 86.9% for the PF-fired flue gas, reduction in the power plant output is similar to Case I.Due to the lower CO2 recovery factor the total amount of work per kg stored CO2 is somewhat higher for Case II: 457 kJ for the NG-fired flue gas and 603 kJ for the PF-fired flue gas.  相似文献   

19.
This paper summarizes the spectrum of options that can be employed during the initial design and construction of pulverized coal (PC), and integrated gasification and combined cycle (IGCC) plants to reduce the capital costs and energy losses associated with retrofitting for CO2 capture at some later time in the future. It also estimates lifetime (40 year) net present value (NPV) costs of plants with differing levels of pre-investment for CO2 capture under a wide range of CO2 price scenarios. Three scenarios are evaluated—a baseline supercritical PC plant, a baseline IGCC plant and an IGCC plant with pre-investment for capture. This analysis evaluates each technology option under a range of CO2 price scenarios and determines the optimum year of retrofit, if any. The results of the analysis show that a baseline PC plant is the most economical choice under low CO2 prices, and IGCC plants are preferable at higher CO2 prices (e.g., an initial price of about $22/t CO2 starting in 2015 and growing at 2%/year). Little difference is seen in the lifetime NPV costs between the IGCC plants with and without pre-investment for CO2 capture. This paper also examines the impact of technology choice on lifetime CO2 emissions. The difference in lifetime emissions become significant only under mid-estimate CO2 price scenarios (roughly between $20 and 40/t CO2) where IGCC plants will retrofit sooner than a PC plant.  相似文献   

20.
Capture and storage of CO2 from fossil fuel fired power plants is drawing increasing interest as a potential method for the control of greenhouse gas emissions. An optimization and technical parameter study for a CO2 capture process from flue gas of a 600 MWe bituminous coal fired power plant, based on absorption/desorption process with MEA solutions, using ASPEN Plus with the RADFRAC subroutine, was performed. This optimization aimed to reduce the energy requirement for solvent regeneration, by investigating the effects of CO2 removal percentage, MEA concentration, lean solvent loading, stripper operating pressure and lean solvent temperature.Major energy savings can be realized by optimizing the lean solvent loading, the amine solvent concentration as well as the stripper operating pressure. A minimum thermal energy requirement was found at a lean MEA loading of 0.3, using a 40 wt.% MEA solution and a stripper operating pressure of 210 kPa, resulting in a thermal energy requirement of 3.0 GJ/ton CO2, which is 23% lower than the base case of 3.9 GJ/ton CO2. Although the solvent process conditions might not be realisable for MEA due to constraints imposed by corrosion and solvent degradation, the results show that a parametric study will point towards possibilities for process optimisation.  相似文献   

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