层次分析法在多联产系统综合性能评价中的应用

按照系统工程方法进行多联产系统的优化设计，应用层次分析法建立了多联产系统综合评价模型，对多种甲醇．电多联产系统方案进行了单项效益和综合效益的计算、分析和评价，进一步证明了多联产方案比单产方案在节能、经济、环境保护方面有较大优势，并指出：在年产甲醇20万t，发电容量300MW的规模下，富CO气体一次通过并联多联产系统（E1）和富CO气体一次通过串联多联产系统（F1）综合效益较高，可以根据实际情况来选取，为系统进一步优化指明了方向。图1表8参10     

Design of an integrated process for simultaneous chemical looping hydrogen production and electricity generation with CO2 capture

This study was aimed at proposing a novel integrated process for co-production of hydrogen and electricity through integrating biomass gasification, chemical looping combustion, and electrical power generation cycle with CO₂ capture. Syngas obtained from biomass gasification was used as fuel for chemical looping combustion process. Calcium oxide metal oxide was used as oxygen carrier in the chemical looping system. The effluent stream of the chemical looping system was then transferred through a bottoming power generation cycle with carbon capture capability. The products achieved through the proposed process were highly-pure hydrogen and electricity generated by chemical looping and power generation cycle, respectively. Moreover, LNG cold energy was used as heat sink to improve the electrical power generation efficiency of the process. Sensitivity analysis was also carried out to scrutinize the effects of influential parameters, i.e., carbonator temperature, steam/biomass ratio, gasification temperature, gas turbine inlet stream temperature, and liquefied natural gas (LNG) flow rate on the plant performance. Overall, the optimum heat integration was achieved among the sub-systems of the plant while a high energy efficiency and zero CO₂ emission were also accomplished. The findings of the present study could assist future investigations in analyzing the performance of integrated processes and in investigating optimal operating conditions of such systems.     

A strategy of mid-temperature natural gas based chemical looping reforming for hydrogen production

Steam methane reforming (SMR) needs the reaction heat at a temperature above 800 °C provided by the combustion of natural gas and suffers from adverse environmental impact and the hydrogen separated from other chemicals needs extra energy penalty. In order to avoid the expensive cost and high power consumption caused by capturing CO₂ after combustion in SMR, natural gas Chemical Looping Reforming (CLR) is proposed, where the chemical looping combustion of metal oxides replaced the direct combustion of NG to convert natural gas to hydrogen and carbon dioxide. Although CO₂ can be separated with less energy penalty when combustion, CLR still require higher temperature heat for the hydrogen production and cause the poor sintering of oxygen carriers (OC). Here, we report a high-rate hydrogen production and low-energy penalty of strategy by natural gas chemical-looping process with both metallic oxide reduction and metal oxidation coupled with steam. Fe₃O₄ is employed as an oxygen carrier. Different from the common chemical looping reforming, the double side reactions of both the reduction and oxidization enable to provide the hydrogen in the range of 500–600 °C under the atmospheric pressure. Furthermore, the CO₂ is absorbed and captured with reduction reaction simultaneously.Through the thermodynamic analysis and irreversibility analysis of hydrogen production by natural gas via chemical looping reforming at atmospheric pressure, we provide a possibility of hydrogen production from methane at moderate temperature. The reported results in this paper should be viewed as optimistic due to several idealized assumptions: Considering that the chemical looping reaction is carried out at the equilibrium temperature of 500 °C, and complete CO₂ capture can be achieved. It is assumed that the unreacted methane and hydrogen are completely separated by physical adsorption. This paper may have the potential of saving the natural gas consumption required to produce 1 m³ H₂ and reducing the cost of hydrogen production.     

Prospect options of CO2 capture technology suitable for China

Reviewing the progress of CO₂ capture and storage (CCS) technology, the main obstacles and the potentials of greenhouse gas control in China are identified. An important point can be drawn is that the innovative energy systems, besides simple implementation of existing technology, are needed for CO₂ control in China. On the basis of integration principle of energy utilization and CO₂ separation, several innovative energy systems, including chemical-looping combustion with CO₂ capture, a partial gasification with O₂/CO₂ cycle, and a polygeneration system with CO₂ capture, are introduced. With synergetic integrating CO₂ into chemical energy conversion and utilization processes, these systems may make breakthrough in CO₂ capture with less or even zero energy penalty. Finally, according to the specific issue of China, a new scenario of Energy Network, which composed of energy source, transportation chain, and terminal user, is recommended for sustainable development in China.     

A chemical intercooling gas turbine cycle with chemical-looping combustion

A novel methanol-based power system with Chemical-Looping Combustion (CLC) is proposed in this paper. CLC system is a promising approach to greatly decrease the energy penalty for CO₂ removal, where iron oxides circulate between two reactors and an inherent CO₂ separation occurs. The combustion process of CLC systems mainly include two steps: a reduction reaction of iron oxides, where the fuel is not mixed with air and the thermal energy for the endothermic reaction is supplied by the intercooling heat of the compressor of the gas turbine, and an oxidation reaction of iron oxides, where the compressed air is heated by the iron oxides. On the basis of the system's integration of cascade utilization of chemical energy of methanol and thermal energy, the thermal efficiency of this novel cycle is expected to be 56.8% with 90% of CO₂ recovery, 10.2 percentage points higher than a combined cycle (CC) with the same CO₂ capture. The promising results obtained here indicate that this novel thermal cycle is a promising approach to accomplish the efficient utilization of chemical energy of methanol without a decrease in thermal efficiency for CO₂ removal.     

How to make the production of methanol/DME "GREENER"-Integration of wind power with modern coal chemical industry

The urgency and necessity of alternative fuels give an impetus to the development of modern coal chemical industry. Coal-based methanol/DME is the key element of this industry. Wind power, whose installed capacity increased at a rate of more than 100% in recent years, has the most developed technologies in renewable energy. However, there still exist many unsolved problems in wind power for on-grid utilization. A new integrated system which combines coal-based methanol/DME production with wind power is proposed in this paper. In this system, wind power is used to electrolyze water to produce H₂ and O₂. TheO₂ is fed to the gasifier as gasification agent. The H₂ is mixed with the CO-rich gas to adjust the H₂/CO to an appropriate ratio for methanol synthesis. In comparison with conventional coal-based methanol/DME system, the proposed system omits the expensive and energy-consuming ASU and greatly reduces the water gas shift process, which brings both advantages in the utilization of all raw materials and significant mitigation of CO₂ emission. This system will be attractive in the regions of China which have abundant wind and coal resources.     

Optimization of the design of polygeneration systems for the residential sector under different self-consumption regulations

Polygeneration systems enable natural resources to be exploited efficiently, decreasing CO₂ emissions and achieving economic savings relative to the conventional separate production. However, their economic feasibility depends on the legal framework. Preliminary design of polygeneration systems for the residential sector based on the last Spanish self-consumption regulations RD 900/2015 and RD 244/2019 was carried out in Zaragoza, Spain. Both regulations were applied to individual and collective installations. Several technologies, appropriate for the energy supply to residential buildings, for example, photovoltaics, wind turbines, solar thermal collectors, microcogeneration engines, heat pump, gas boiler, absorption chiller, and thermal and electric energy storage were considered candidate technologies for the polygeneration system. A mixed integer linear programming model was developed to minimize the total annual cost of polygeneration systems. Scenarios with and without electricity sale were considered. CO₂ emissions were also calculated to estimate the environmental impact. Results show that RD 900/2015 discourages the investment in self-consumption systems whereas the RD 244/2019 encourages them, especially in renewable energy technologies. Moreover, in economic terms, it is more profitable to invest in collective self-consumption installations over individual installations. However, this does not necessarily represent a significant reduction of CO₂ emissions with respect to individual installations since the natural gas consumption tends to increase as its unit price decreases because of the increase of its consumption level. Thus, more appropriate pricing of natural gas in residential sector, in which its cost would not be reduced when increasing its consumption, would be required to achieve significant CO₂ emissions reduction. In all cases, the photovoltaic panels (PV) are competitive and profitable without subsidies in self-consumption schemes and the reversible heat pump (HP) played an important role for the CO₂ emissions reduction. In a horizon to achieve zero CO₂ emissions, the net metering scheme could be an interesting and profitable alternative to be considered.     

Proposal of a natural gas-based polygeneration system for power and methanol production

A new kind of natural gas-based polygeneration system for methanol and power production is proposed in this paper. With the sequential connection between chemical production and power generation, the new system adopts innovative integration of partial-reforming and partial-recycle scheme in methanol synthesis subsystem. To reveal the characteristics of the new system, exegetic comparisons between the new system and a reference polygeneration system with full-reforming and once through methanol synthesis scheme have been carried out. Results indicate that the new system can save energy about 6 percentages versus single product systems. By the aid of graphical exergy analysis methodology, the specific information on internal phenomena of key processes was illustrated. The analysis shows that it is the synergetic combination of partial-reforming and partial-recycle schemes that makes the significant contribution to the performance improvement, and plays the most important role in system integration.     

Technoeconomic analysis of a methanol plant based on gasification of biomass and electrolysis of water

Methanol production process configurations based on renewable energy sources have been designed. The processes were analyzed in the thermodynamic process simulation tool DNA. The syngas used for the catalytic methanol production was produced by gasification of biomass, electrolysis of water, CO₂ from post-combustion capture and autothermal reforming of natural gas or biogas. Underground gas storage of hydrogen and oxygen was used in connection with the electrolysis to enable the electrolyser to follow the variations in the power produced by renewables. Six plant configurations, each with a different syngas production method, were compared. The plants achieve methanol exergy efficiencies of 59–72%, the best from a configuration incorporating autothermal reforming of biogas and electrolysis of water for syngas production. The different processes in the plants are highly heat integrated, and the low-temperature waste heat is used for district heat production. This results in high total energy efficiencies (∼90%) for the plants. The specific methanol costs for the six plants are in the range 11.8–25.3 €/GJ_exergy. The lowest cost is obtained by a plant using electrolysis of water, gasification of biomass and autothermal reforming of natural gas for syngas production.     

Hydrogen production from autothermal CO2 gasification of cellulose in a fixed-bed reactor: Influence of thermal compensation from CaO carbonation

Biomass gasification is a promising technology to produce renewable syngas used for energy and chemical applications. However, biomass gasification has challenges of low process energy efficiency, low syngas production with low H₂/CO ratio and the sintering of biomass ash which limit the deployment of the technology. This work investigated the influence of in-situ generated heat from CaO–CO₂ on cellulose CO₂ gasification using a fixed bed reactor, thermogravimetric analysis-Fourier transform infrared spectroscopy (TGA-FTIR) and differential scanning calorimetry (DSC). Experimental results indicate an approximate 20 °C temperature difference in the fix-bed reactor between cellulose CO₂ gasification with the energy compensation of CaO carbonation (denoted auto-thermal biomass gasification) and conventional CO₂ gasification of cellulose after the power of external furnaces were turned off. Around 5 times H₂/CO molar ratio is obtained after switching off the power in the auto-thermal biomass gasification compared with conventional gasification. The gas yield enhances significantly from 0.29 g g^?1 cellulose to 0.56 g g^?1 cellulose when CaO/cellulose mass ratio increases from 0 to 5. Furthermore, the TGA-FTIR results demonstrate the feasibility of adopting energy compensation of CaO carbonation to reduce the gasification temperature. DSC analysis also proves that the released heat from the CaO–CO₂ reaction reduces the required energy for cellulose degradation.     

System study on natural gas-based polygeneration system of DME and electricity

An innovative system for the polygeneration of dimethyl ether (DME) and electricity was proposed in this paper. The system uses natural gas as the raw material. Polygeneration is sequential, with one-step and once-through DME synthesis. Syngas is made to react to synthesize DME first, and then the residual syngas is sent to the power generation unit as fuel. The exergy analysis from the view of cascade utilization was executed for individual generation and for polygeneration. The analysis results showed that both chemical energy and thermal energy in polygeneration were effectively utilized, and both chemical exergy destruction and thermal exergy destruction in polygeneration were decreased. The cause of the decrease in exergy destruction was revealed. The analysis showed that hydrogen-rich (natural gas-based) polygeneration was as desirable as carbon-rich (coal-based) polygeneration. The energy saving ratio of polygeneration was about 10.2%, which demonstrated that high efficiency natural gas-based polygeneration is attainable, and the cascade utilizations of both chemical energy and thermal energy are key contributors to the improvement of performance. Copyright © 2007 John Wiley & Sons, Ltd.     

Cost-effective CO2 emission reduction through heat,power and biofuel production from woody biomass: A spatially explicit comparison of conversion technologies

Bioenergy is regarded as cost-effective option to reduce CO₂ emissions from fossil fuel combustion. Among newly developed biomass conversion technologies are biomass integrated gas combined cycle plants (BIGCC) as well as ethanol and methanol production based on woody biomass feedstock. Furthermore, bioenergy systems with carbon capture and storage (BECS) may allow negative CO₂ emissions in the future. It is still not clear which woody biomass conversion technology reduces fossil CO₂ emissions at least costs. This article presents a spatial explicit optimization model that assesses new biomass conversion technologies for fuel, heat and power production and compares them with woody pellets for heat production in Austria. The spatial distributions of biomass supply and energy demand have significant impact on the total supply costs of alternative bioenergy systems and are therefore included in the modeling process. Many model parameters that describe new bioenergy technologies are uncertain, because some of the technologies are not commercially developed yet. Monte-Carlo simulations are used to analyze model parameter uncertainty. Model results show that heat production with pellets is to be preferred over BIGCC at low carbon prices while BECS is cost-effective to reduce CO₂ emissions at higher carbon prices. Fuel production – methanol as well as ethanol – reduces less CO₂ emissions and is therefore less cost-effective in reducing CO₂ emissions.     

Evaluation of power generation schemes based on hydrogen-fuelled combined cycle with carbon capture and storage (CCS)

IGCC is a power generation technology in which the solid feedstock is partially oxidized to produce syngas. In a modified IGCC design for carbon capture, there are several technological options which are evaluated in this paper. The first two options involve pre-combustion arrangements in which syngas is processed, either by shift conversion or chemical looping, to maximise the hydrogen level and to concentrate the carbon species as CO₂. After CO₂ capture by gas-liquid absorption or chemical looping, the hydrogen-rich gas is used for power generation. The third capture option is based on post-combustion arrangement using chemical absorption.Investigated coal-based IGCC case studies produce 400-500 MW net power with more than 90% carbon capture rate. Principal focus of the paper is concentrated on evaluation of key performance indicators for investigated carbon capture options, the influence of various gasifiers on carbon capture process, optimisation of energy efficiency by heat and power integration, quality specification of captured CO₂. The capture option with minimal energy penalty is based on chemical looping, followed by pre-combustion and post-combustion.     

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.     

Improving the technical, environmental and social performance of wind energy systems using biomass-based energy storage

A completely renewable baseload electricity generation system is proposed by combining wind energy, compressed air energy storage, and biomass gasification. This system can eliminate problems associated with wind intermittency and provide a source of electrical energy functionally equivalent to a large fossil or nuclear power plant. Compressed air energy storage (CAES) can be economically deployed in the Midwestern US, an area with significant low-cost wind resources. CAES systems require a combustible fuel, typically natural gas, which results in fuel price risk and greenhouse gas emissions. Replacing natural gas with synfuel derived from biomass gasification eliminates the use of fossil fuels, virtually eliminating net CO₂ emissions from the system. In addition, by deriving energy completely from farm sources, this type of system may reduce some opposition to long distance transmission lines in rural areas, which may be an obstacle to large-scale wind deployment.     

Development of new green-fuel production technology by combination of fossil fuel and renewable energy

A new system combining fossil fuel and renewable energy to produce methanol (environmentally benign) with a zero CO₂ emission process was studied. The objectives of this paper are to propose a practical process for the new system, to prove the zero CO₂ emission process for this new system using a system evaluation simulator, and to provide an economical evaluation. The system combining the electrolysis of water (producing both O₂ and H₂) using solar energy with the partial oxidation of coal and natural gas (Case 1) gives the best evaluation for CO₂ reduction and for energy conversion efficiency to upgrade the fossil fuel energy using solar energy. An economical evaluation shows that the product (methanol) cost is nearly the same as that for the conventional (commercial) methanol production process (29.5 yen/kg methanol) when the CO₂ recovery and disposal process is taken into account.     

Reduction of CO2 emission and oil dependency with biomass-based polygeneration

We compare different options for the use of lignocellulosic biomass to reduce CO₂ emission and oil use, focusing on polygeneration of biomass-based motor fuels and electricity, and discuss methodological issues related to such comparisons. The use of biomass can significantly reduce CO₂ emission and oil use, but there is a trade-off between the reductions in CO₂ emission and oil use. Bioelectricity from stand-alone plants replacing coal-based electricity reduced CO₂ emission by 99 kg per GJ biomass input but gave no oil use reduction. Stand-alone produced methanol replacing diesel reduced the CO₂ emission with 38 kg and the oil use with 0.67 GJ per GJ biomass, indicating that a potential CO₂ emission reduction of 90 kg is lost per GJ oil reduced. CO₂ emission and oil use reduction for alternatives co-producing fuel and electricity fall between the stand-alone alternatives. Plug-in hybrid-electric vehicles using bioelectricity reduced CO₂ emission by 75–88 kg and oil use by 0.99–1.2 GJ, per GJ biomass input. Biomass can also reduce CO₂ emission and/or oil use more efficiently if fossil-fuel-fired boilers or electric heating is replaced by district heating from biomass-based combined heat and power generation. This is also true if electricity or motor fuel is produced from black liquor gasification in pulp mills or if wood is used instead of concrete in building construction. Biomass gasification is an important technology to achieve large reductions, irrespective of whether CO₂ emission or oil use reduction is prioritised.     

Clean combustion of solid fuels

A chemical-looping process is proposed for the clean combustion of solid fuels for electric power or heat generation. The process is based on coal gasification with CO₂ to produce CO. The CO then reduces CaSO₄, which is used as an oxygen carrier, in a separate reactor to give CaS and CO₂. A portion of the CO₂ is recycled for the gasification stage and the rest can be sent for sequestration. The CaS is sent to another reactor for oxidation with air and to generate heat or power. The overall thermal effect is the same as direct combustion, but separation of CO₂ and other pollutants, such as sulphur, is achieved. In comparison with conventional chemical-looping combustion of natural gas, much less water is present in the CO₂ product, and hence the loss of heat energy and corrosion of the fuel–reactor system can be reduced.     

Decarbonization synergies from joint planning of electricity and hydrogen production: A Texas case study

Hydrogen (H₂) shows promise as an energy carrier in contributing to emissions reductions from sectors which have been difficult to decarbonize, like industry and transportation. At the same time, flexible H₂ production via electrolysis can also support cost-effective integration of high shares of variable renewable energy (VRE) in the power system. In this work, we develop a least-cost investment planning model to co-optimize investments in electricity and H₂ infrastructure to serve electricity and H₂ demands under various low-carbon scenarios. Applying the model to a case study of Texas in 2050, we find that H₂ is produced in approximately equal amounts from electricity and natural gas under the least-cost expansion plan with a CO₂ price of $30–60/tonne. An increasing CO₂ price favors electrolysis, while increasing H₂ demand favors H₂ production from Steam Methane Reforming (SMR) of natural gas. H₂ production is found to be a cost effective solution to reduce emissions in the electric power system as it provides flexibility otherwise provided by natural gas power plants and enables high shares of VRE with less battery storage. Additionally, the availability of flexible electricity demand via electrolysis makes carbon capture and storage (CCS) deployment for SMR cost-effective at lower CO₂ prices ($90/tonne CO₂) than for power generation ($180/tonne CO₂). The total emissions attributable to H₂ production is found to be dependent on the H₂ demand. The marginal emissions from H₂ production increase with the H₂ demand for CO₂ prices less than $90/tonne CO₂, due to shift in supply from electrolysis to SMR. For a CO₂ price of $60/tonne we estimate the production weighted-average H₂ price to be between $1.30–1.66/kg across three H₂ demand scenarios. These findings indicate the importance of joint planning of electricity and H₂ infrastructure for cost-effective energy system decarbonization.     

Biomass gasification in district heating systems – The effect of economic energy policies

Biomass gasification is considered a key technology in reaching targets for renewable energy and CO₂ emissions reduction. This study evaluates policy instruments affecting the profitability of biomass gasification applications integrated in a Swedish district heating (DH) system for the medium-term future (around year 2025). Two polygeneration applications based on gasification technology are considered in this paper: (1) a biorefinery plant co-producing synthetic natural gas (SNG) and district heat; (2) a combined heat and power (CHP) plant using integrated gasification combined cycle technology. Using an optimisation model we identify the levels of policy support, here assumed to be in the form of tradable certificates, required to make biofuel production competitive to biomass based electricity generation under various energy market conditions. Similarly, the tradable green electricity certificate levels necessary to make gasification based electricity generation competitive to conventional steam cycle technology, are identified. The results show that in order for investment in the SNG biorefinery to be competitive to investment in electricity production in the DH system, biofuel certificates in the range of 24–42 EUR/MWh are needed. Electricity certificates are not a prerequisite for investment in gasification based CHP to be competitive to investment in conventional steam cycle CHP, given sufficiently high electricity prices. While the required biofuel policy support is relatively insensitive to variations in capital cost, the required electricity certificates show high sensitivity to variations in investment costs. It is concluded that the large capital commitment and strong dependency on policy instruments makes it necessary that DH suppliers believe in the long-sightedness of future support policies, in order for investments in large-scale biomass gasification in DH systems to be realised.