热力发电厂专业英语结课论文(中英文互译)
汇报热电厂基本情况范文
汇报热电厂基本情况范文（中英文版）Report on the Basic Situation of the Thermal Power Plant热电厂基本情况汇报范文The basic information of the thermal power plant is as follows.首先，我厂是一座大型热电厂，位于我国北方一个重要的工业城市。
Our thermal power plant is a large-scale one located in an important industrial city in northern China.Our plant has a total installed capacity of 6 million kilowatts, with two units of 3 million kilowatts each.我厂主要燃烧煤炭，同时也在积极探索清洁能源的使用。
We mainly burn coal, but we are also actively exploring the use of clean energy.Our plant produces not only electricity but also steam, which is supplied to nearby factories for heating and power purposes.我厂在安全生产方面一直保持着良好的记录，同时也在不断提高环保水平。
We have maintained a good record in safety production and are continuously improving our environmental protection level.In summary, our thermal power plant is a key contributor to the local economy, providing both electricity and steam to support industrial production, while also ensuring the safety and environmental protection of the surrounding area.总结来说，我厂在保障当地电力和热力供应方面发挥着重要作用，同时也在安全生产和环保方面不断努力，为可持续发展做出贡献。
专业英语中热电厂的总结
专业英语中热电厂的总结热电厂（Combined Heat and Power Plant，缩写为CHP）是一种利用燃料（如煤炭、天然气、生物质等）同时产生电力和热能的设施。
下面是对热电厂的专业英语总结：1. Definition: A combined heat and power plant, also known as a cogeneration plant, is a facility that simultaneously generates electricity and heat from fuel sources such as coal, natural gas, and biomass.2. System Configuration: A CHP plant consists of several components, including a prime mover (such as a gas turbine or steam turbine), a generator, a heat recovery system, and a heat distribution network.3. Electricity Generation: The prime mover drives the generator to produce electricity. The electricity generated can be used on-site or fed into the power grid.4. Heat Recovery: Waste heat from the electricity generation process is captured and utilized for various heating purposes, such as space heating, water heating, and industrial processes.5. Energy Efficiency: Compared to separate electricity and heat production, CHP systems offer significantly higher energy efficiency, as they effectively utilize waste heat that would otherwise be wasted in conventional power plants.6. Environmental Benefits: CHP plants help reduce greenhouse gas emissions and promote sustainability by maximizing fuel utilization and minimizing thermal losses.7. Types of CHP Systems: There are various types of CHP systems, including topping cycle, bottoming cycle, and combined cycle configurations, each suited for specific applications and fuel sources.8. Applications: CHP plants are commonly used in industrial facilities, hospitals, universities, and district heating systems, where there is a continuous demand for both electricity and heat.9. Economic Considerations: CHP systems can provide cost savings through reduced energy consumption, lower operating costs, and potential revenue from selling excess electricity to the grid.10. Maintenance and Operation: Proper maintenance and regular inspections are crucial to ensure the efficient and safe operation of the equipment in a CHP plant.It is important to note that this summary is devoid of any sensitive or classified information, and complies with Chinese laws and regulations.。
热能与动力工程专业外文翻译、中英对照、英汉互译
毕业设计外文翻译原文标题：Proposal for a high efficiency LNGpower-generation System utilizing wasteheat from the combined cycle中文标题:一个高效的利用液化天然气联合循环余热的发电系统学院名称：能源与动力工程学院专业名称：热能与动力工程Proposal for a high efficiency LNG power-generation system utilizing waste heat from the combined cycleY. Hisazumi*, Y. Yamasaki, S. SugiyamaEngineering Department, Osaka Gas Co., 1-2 Hiranomachi 4-chome Chuo-ku, Osaka 541, Japan Accepted 9 September 1998AbstractHigh-efficiency power-generation with an LNG vaporizing system isproposed: it utilizesthe LNG's cold energy to the best potential limit. This system can be applied to LNG vaporizers in gas companies or electric power companies and recovers the LNG's cold energy as electric power. The system consists of a Rankine cycle using a Freon mixture, natural-gas. Rankine cycle and a combined cycle with gas and steam turbines. The heat sources for this system are the latent heat from the steam-turbine's condenser and the sensible heat of exhaust gas from the waste-heat recovery boiler. In order to find out the optimal condition of the system, several factors, such as gas turbine combustion pressure, steam pressure, condensing temperature in combined cycle, composition of mixture Freon, and natural gas vaporizing pressure are evaluated by simulation. The results of these studies show that in the total system, about 400 kWh can be generated by vaporizing 1 ton of LNG, including about 60 kWh/LNG ton recovered from the LNG cold energy when supplying NG in 3.6 MPa.. About 8.2MWh can be produced by using 1 ton of LNG as fuel, compared with about 7 MWh by the conventional combined system. A net efficiency of over 53%HHV could be achieved by the proposed system. In the case of the LNG terminal receiving 5 million tons of LNG per year, this system can generate 240 MW and reduce the power of the sea water pump by more than 2MW. 1998 Elsevier Science Ltd. All rights reserved.1. IntroductionIn the fiscal year 1994, the amount of LNG imported to Japan reached about 43 million tons; of this 31 million tons were used as fuel for power generation. As shown in Fig. 1, about 20% of the LNG imported was used for power generation [2]. Fig. 2 shows the major LNG power generation systems now in operation and their outputs. Several commercial LNG power generation plants have been constructed since 1979, and their total output has reached approximately 73 MW. Among the new power-generation plants without CO2 emission, this value of 73 MW is second to the 450 MW input of geo-thermal power generation plants in Japan, with the exception of power generation by refuse incinerators, and is much larger compared with the 35 MW output of solar-power plants and the 14 MW output of wind-power stations.Table 1 shows the LNG power generation plants constructed in Japan. The economics of LNG power generation became worse as the appreciation of the yen madethe cost of energy kept constant but while raising the construction cost; the adoption of the combined cycle utilizing gas-turbine and steam turbine (hereafter called combined cycle) increased the gas send-out pressure and lowered the power output per ton of LNG. Therefore, no LNG powergeneration plants were constructed in the 1990s due to lower cost effectiveness of the systems.As for the thermal power plant using natural gas as fuel, the steam turbine produced only about 6 MWh of power output per ton of LNG. But recently, improvement in blade-cooling technology and materials of the gas turbine enabled a 1400℃class turbine to be designed and increased the combustion pressure up to 3 MPa. Therefore, as shown in Fig. 3, the heat efficiency of the combined cycle has been improved and the electrical output from 1 ton of LNG has reached about 7MWh.In this paper, a proposal is made for the high-efficiency LNG power generation system based on a new concept which fully utilizes the cold energy without discarding it into the sea. The system is composed of the combined cycle and the LNG power-generation plant.2. High-efficiency LNG power-generation system2.1. Basic componentsFig.4 shows the process flow diagram of the high-efficiency LNG power-generation system. This complex system consists of the combined cycle and the LNG power generation cycle. The combined cycle is composed of a gas turbine (GAS-T) and a steam turbine (ST-T) using natural gas (NG) as fuel, while the LNG power generation cycle is composed of a Freon (uorocarbon) mixture turbine (FR-T) and a natural-gas turbine (NG-HT, NG-LT) using the latent heat of condensation from the exhaust steam and the sensible heat of the exhaust gas as heat sources. The plate fin type heat exchanger can be used for the LNG/natural gas (LNG-CON) and LNG/ Freon mixture (FR-CON). The shell-and-tube type can be selected as exchangers for exhaust steam/natural gas (LNG-VAP),exhaust steam/Freon mixture(FR-VAP), and exhaust gas/natural gas (NG-SH) applications according to the operating conditions.Ice thickness on the surface of the heat-exchanger tubes becomes a problem as heat is exchanged between exhaust gas and cold natural gas or Freon mixture. The ice thickness can be estimated by the technology of heat transfer between LNG and sea water, thus enabling one to avoid blockages due to ice inside the tubes.In addition, stable and continuous send-out of gas is made possible by using a bypass system, even if turbines and pumps for the Freon mixture and natural gas circulating systems (FR-RP, LNG-RP) stop.2.2. Features of the systemThe practical use of the following existing technologies in combination shows the high feasibility of the proposed system:. Power generation using Freon or hydrocarbon type Rankine cycle,. Power generation by natural-gas direct expansion],. TRI-EX type vaporizer which vaporizes LNG by using an intermediate medium or vacuum type LNG vaporizer.The Freon mixture is made up of the HFC type, which is a fluorocarbon consisting of H, F, and C and has no adverse influence on the ozone layer; it enables reduction in exergy loss at the heat exchanger and increases itscirculating flow rate to be achieved.The effective recovery of cold exergy and pressure exergy is made possible by the combined system using natural gas and Freon mixture Rankine cycle.Fig. 5 shows the temperature-heat duty relation when vaporizing 1 kg of LNG in the system shown in Fig. 4. Separation of the condensed natural-gas in two sections enables an increase in the heat duty between Freon (FR) and LNG, and a reduction of difference in temperature of LNG and natural gas between the inlet and outlet of the heat exchanger.3. Evaluation of the characteristics of the proposed system3.1. Process simulationThe characteristics of this system were evaluated by using process simulator. The followings are the conditions used for the calculation:Effciencies of rotating machines LNG compositionGas turbine (GAS-T) 88% CH4 89.39%Steam turbine (ST-T) 85% C2H6 8.65%Natural-gas turbine (NG-HT, LT) 88% C3H8 1.55%Freon turbine (FR-T) 88% iC4H10 0.20%Air compressor (AIR-C) 85% nC4H10 0.15%LNG pump (LNG-MP, RP) 70% iC5H12 0.01%Freon pump (FR-RP) 70% N2 0.05%Natural gas gross heat-value: 10,510 kcal/Nm3AIR/NG flow ratio of gas turbine: 323.2. Effects of send-out pressure of the natural gasWhen natural-gas is sent out at 3.5 or 1.8 MPa, evaluations were made of the effects of send-out pressure of the LNG and change in superheating temperature of the natural gas on the total output of the high pressure (NG-HT) and the low pressure (NG-LT) natural-gas expansion-turbines. Fig. 6 shows the results of this calculation, where self consumption of power is calculated from the power, raising the pressure of the LNG up to the inlet pressure of the turbine minus the power required for the original send-out pressure. In both cases, the inlet pressure rise for the turbine causes an increase of self consumption power, but brings about a greater out-put. About 7 MPa of the inlet pressure of the turbine is appropriate considering the pressure tolerance of the heat exchangers.When the superheating temperature of the natural gas at the inlet to the turbine becomes high, the recovery of power increases, but the temperature of the exhaust gas from the outlet of the natural-gas super heater (NG-SH) declines, thus indicating that there is a limitation to superheating gas.3.3. Effects of combustion pressure of the gas turbineThe outputs of the gas turbine and the steam turbine, and the efficiency per gross heating value were evaluated by changing the combustion pressure of the gas turbine operating at 1300℃turbine-inlet temperature - see Fig. 7.If the combustion pressure of the gas turbine becomes high, the output of the gas turbine increases, but the output of the steam turbine decreases because the rise in combustion pressure causes a lowering of the exhaust-gas temperature at the outlet of the gas turbine and consequently a decline in the steam temperature at the inlet of the steam turbine. However, the overall efficiency of the turbines increases upon increasing the combustion pressure because the increment of gas-turbine output exceeds the decrement of steam turbine output. As a result, taking the pressure loss into account, it is appropriate to set the send-out pressure of the natural gas at the LNG terminal at 3.5 MPa.（FR-vap），3.4. Effects of Inlet pressure of the steam turbineFig. 8 shows the relations between the steam-turbines output and exhaust gas temperatures by changing the steam pressure in the range of 3-7 MPa. As the steam pressure increases, the output of the steam turbine rises and the temperature of the exhaust gases also increase. Besides, the power required for the water-supply pump increases with a rise in the steam pressure. Therefore, the current combined cycles operate at steam pressure of 7 MPa or more because the increment of the output of steam turbine exceeds the additional power required for the water-supply pump.3.5. Rankine cycle using a Freon-mixture refrigerant.The Freon refrigerant was selected from the HFC refrigerants on the basis of marketability, boiling point and freezing-point. Table 2 shows the physical properties of HFC Freon.When only HFC-23 is used as the medium, because of its low freezing-point it never freezes even if heat is exchanged between the LNG and HFC-23. But if HFC-23 is heated by the exhaust steam of the steam turbine, the pressure rises approximately up to the critical pressure. Therefore, the use of HFC-23 is not cost effective, because it is then necessary to set a high design pressure. To cope with this problem, we evaluated the compound refrigerant composed of HFC-134a (with high boiling point) and HFC-23.Fig. 9 shows saturated vapor pressure at various temperatures, the boiling point and the dew point at atmospheric pressure for mixtures of HFC-23 andHFC-134a of various compositions. The saturated pressure at each temperature rises with the increasing mole ratio of HFC-23: Hence, 40-45% of the mole ratio of HFC-23 is the optimal value considering the design pressure of the equipment.Fig. 10 shows the plots of the output of the Freon turbine versus the condensing temperature of the steam turbine when changing the composition of the HFC-23. In this figure, the turbine outlet pressure is determined in such a way that thedifference in temperature between the LNG and Freon mixture is not less than 5℃in the Freon condenser (FR-CON). The Freon turbine's inlet-pressure is set to the saturatedtemperature of the Freon mixture, i.e. less than 2℃from the steam-condensing temperature.This figure indicates that the output of the turbine scarcely correlates with the mole ratio of HFC-23. The higher the steam-condensing temperature becomes, the greater the output per ton of LNG the turbine produces, but in such a case, it is necessary to evaluate the system as a whole because more fuel is required, as described below. The result indicates that the optimal mole composition of HFC-23 and HFC-134a is 40%/60% considering both design pressure and the output of the turbine.3.6. Comprehensive evaluation from the viewpoint of the steam-condensing Temperature.As the dew point of the exhaust gas is 42℃, it is wise to set the exit temperature of the exhaust gas from the natural-gas super heater (NG-SH) to 80℃or more in order to prevent white smoke from the smoke stack. Table 3 shows the effect of the steam-condensing temperature on the generated output of the total system. The lower steam-condensing temperature brings about a higher efficiency of the total system, but also causes a lowering in the inlet temperature of natural-gas turbine. Therefore, it is appropriate to set the steam-condensing temperature at approximately 30℃.When the condensing temperature is 30C, the generated outputs per ton of LNG of the combined cycle and LNG power generation plant are 342.83 and67.55 kWh, respectively, resulting in 402.64 kWh of total generated output aftersubtracting the self-use power. As 48.94 kg of fuel is used for operating the system, the generated outputs of the combined cycle and the total system reach about 7 and 8.2 MWh, per ton of fuel respectively.3.7. Evaluation of exergyNatural-gas is liquefied at an LNG liquefaction terminal, with the consumption of about 380 kWh/LNG-ton: 1 ton of LNG having about 250 kWh of physical exergy as cold exergy and 13.5 MWh of chemical exergy. Fig. 11 shows the result of evaluating the exergy of the system shown in Fig. 4 under the optimal condition. The total output of Freon and natural gas turbines is 67.5 kWh, and the effective recovery percentage of cold exergy is 56%. As 90 kWh out of the pressure exergy can be recovered as output, about 157 kWh of net recovery can be obtained, which indicates the recovery percentage reaches about 63% for 250 kWh of LNG cold exergy. This conversion efficiency is higher than that achieved from chemical exergy to electric power.Most of the exergy loss occurs in the heat exchanger and the turbine, and in mixing with re-condensed LNG. As for the turbines, the loss of energy may be improved by using high-efficiency turbines. On the other hand, modification of the heat exchanger to reduce the energy loss may cause increased complexity of the system and is difficult to be done from the economic viewpoint. Though the recovery.percentage of cold energy in this system is low compared with the 80% in air-separation equipment, this system has the advantage of recovering a large amount of the available cold energy.4. ConclusionThe paper has proposed a high-efficiency LNG power generation system in combination with a combined-cycle power generation system fueled by natural-gas. The system utilizes LNG cold energy and it requires no sea water as a heat source.This system can be applied to LNG vaporization and send-out processes of gas companies or electric-power companies. The system recovers LNG coldenergy as an electric-power output without wasting it into sea water. The system consists of Rankine cycle with Freon mixture and a natural-gas Rankine cycle using the latent heat of exhaust steam from the steam turbine and the sensible heat of exhaust gas from the waste-heat recovery boiler. To improve the total efficiency of the system, a simulation was conducted to evaluate several factors, such as the composition of the Freon mixture, natural gas send-out pressure, as well as the combustion pressure steam inlet pressure, and steam-condensing temperature of the combined cycle. As a result, not less than 60 kWh/LNG-ton of output was generated even at a high natural-gas send-out pressure of 3.5 MPa. This value is considerably higher than the output generated at a LNG send-out pressure of 3 or 4 MPa, as given in Table 2.The system can produce about 400 kWh of net output when vaporizing 1 ton of LNG. While the conventional combined-cycle system in operation generates about 7 MWh when 1 ton of LNG is used as fuel, the system using the same amount of fuel generates about 8.2 MWh with a high degree of efficiency: a not-less-than 53% conversion efficiency was achieved per gross heat value.In the case of an LNG terminal receiving 5 million tons of LNG per year, this system can generate a power of about 240 MW when 600 t of LNG is used in an hour. With the elimination of about 24,000 tons per hour of sea water, which has been used for vaporizing 600 t/h of LNG in the conventional system, no less than 2 MW of electric power for operating sea water pumps can be saved.The proposed system emits no CO2, and can generate a large amount of electricity with high cost efficiency when incorporated into a combined cycle, with no use of sea water. Therefore, we consider that installation of this system is the one of the most favorable means of investment to put a new energy source or energy-saving equipment to practical use.To realize the full potential of this system, it is necessary to understand the heat characteristics of the Freon mixture, the icing and heat transfer characteristics of exhaust steam, the controllability of total system and the characteristics against partial load.References[1] The Center for Promotion of Natural gas Foundation. Research and development report of cold energy utilizing system, 1994[2] Japan's Energy and Economy Research Center. Energy and economy statistical data in 1995[3] Abe. Operating results and future prospect of a recent combined-cycle power generation plant. Thermal and Nuclear Power 1995;46(6):33-41[4] Maertens J. Design of Rankine cycles for power generation. Int. Refrig. 1986;9:137-43[5] Terada, Nakamoto. Power generation utilizing LNG cold. Thermal and Nuclear Power Generation 1986;37(10):66-71[6] Ooka, Ueda, Akasaka. Advanced LNG vaporizer and power generation utilizing LNG cold. Chemical Engineering 1981;45(3):187-90[7] Miura. The development of LNG vaporizer using vacuum steam heat (VSV). Journal of Japan Gas Society 1992;45:34-6[8] Nagai. Software-package and the usage. Chemical Equipment1994;August:31-7[9] Daikin Co. Ltd. Freon Data Sheet of HFC23一个高效的利用液化天然气联合循环余热的发电系统日本大阪541燃气有限公司工程部1-2平野町4肖梅中央谷，1998年9月概述本文提出了一个高效液化天然气气化发电系统，它是利用液化天然气冷能的最佳潜能极限。
火电厂自动化 电气自动化毕业设计外文翻译
在相同大气压下，当它的温度超过了它的饱和温度时，水蒸气就成为过热蒸气。当它沸腾之后收集起来，通过一个管道将它远离流体，然后加入更多的热量给它，这一过程中进一步给过热蒸汽补充能量，从而提高热量转换为电能的效率。
如前所述,热量补充给已开始沸腾的水不会引起温度的进一步变化。相反，它却改变流体的状态。一旦形成了蒸汽，焓降有助于蒸汽的总热量的增加。这些显热再加上潜热用于增加每公斤流体过热程度。
如图1.2所示，显示了压力/容积关系的流体在汽缸内的整个循环周期。由于这一进程是一个反复循环的过程，所以研究可以从任何方便的起点开始，我们将在A点开始，在气缸盖（在这个时候假定为是一个理想导体），使热量从热源进入气缸。结果是，中期开始扩大，如果它被允许自由扩大，玻意耳定律（其中指出，在任何温度之间关系的压力和容量是常数）中规定的温度不会上升，但将留在其初始温度（T1） 。这就是所谓的等温膨胀。
当介质的压力和容积已达到B点时，气缸盖由理想导体转换成一个绝缘体，而介质允许继续扩大，而没有热的增减，这就是所谓的绝热膨胀。当介质的压力和容积已达到C点时，气缸盖转变成理想导体，但外部热源被散热器取而代之。活塞开始驱动，然后压缩介质。热流经头部的散热片，当温度达到中等，在散热片（点D），缸盖再次切换到理想绝缘体，戒指被压缩直至到达初始条件的压力和温度，这个周期便完成了，在绝热情况下对外做功。
热电联产中英文对照外文翻译文献
中英文对照外文翻译文献(文档含英文原文和中文翻译)外文文献:The Optimal Operation Criteria for a Gas Turbine Cogeneration System Abstract: The study demonstrated the optimal operation criteria of a gas turbine cogeneration system based on the analytical solution of a linear programming model. The optimal operation criteria gave the combination of equipment to supply electricity and steam with the minimum energy cost using the energy prices and the performance of equipment. By the comparison with a detailed optimization result of an existing cogeneration plant, it was shown that the optimal operation criteria successfully provided a direction for the system operation under the condition where the electric power output of the gas turbine was less than the capacity.Keywords: Gas turbine; Cogeneration; Optimization; Inlet air cooling.1. IntroductionCogeneration, or combined heat and power production, is suitable for industrial users who require large electricity as well as heat, to reduce energy and environmental impact. To maximize cogeneration, the system has to be operated with consideration electricity and heat demands andthe performance of equipment. The optimal operation of cogeneration systems is intricate in many cases, however, due to the following reasons. Firstly, a cogeneration system is a complex of multiple devices which are connected each other by multiple energy paths such as electricity, steam, hot water and chilled water. Secondly, the performance characteristics of equipment will be changed by external factors such as weather conditions.For example, the output and the efficiency of gas turbines depend on the inlet air temperature. Lastly,the optimal solution of operation of cogeneration systems will vary with the ratio of heat demand to electricity demand and prices of gas, oil and electricity.Because of these complexities of cogeneration systems, a number of researchers have optimal solutions of cogeneration systems using mathematical programming or other optimization techniques. Optimization work focusing on gas turbine cogeneration systems are as follows. Yokoyama et al. [1] presented optimal sizing and operational planning of a gas turbine cogeneration system using a combination of non-linear programming and mixed-integer linear programming methods. They showed the minimum annual total cost based on the optimization strategies. A similar technique was used by Beihong andWeiding [2] for optimizing the size of cogeneration plant. A numerical example of a gas turbine cogeneration system in a hospital was given and the minimization of annual total cost was illustrated. Kong et al. [3] analyzed a combined cooling, heating and power plant that consisted of a gas turbine, an absorption chiller and a heat recovery boiler. The energy cost of the system was minimized by a linear programming model and it was revealed that the optimal operational strategies depended on the load conditions as well as on the cost ratio of electricity to gas. Manolas et al. [4] applied a genetic algorithm (GA) for the optimization of an industrial cogeneration system, and examined the parameter setting of the GA on the optimization results. They concluded that the GA was successful and robust in finding the optimal operation of a cogeneration system.As well as the system optimization, the performance improvement of equipment brings energy cost reduction benefits. It is known that the electric power output and the efficiency of gas turbines decrease at high ambient temperatures. Some technical reports [5, 6] show that the electric power output of a gas turbine linearly decreases with the rise of the ambient temperature, and it varies about 5 % to 10 % with a temperature change of 10 ◦C. Therefore, cooling of the turbine inlet air enhances electric output and efficiency. Some studies have examined theperformance of the gas turbine with inlet air cooling as well as the effect of various cooling methods [7, 8, 9].The cooling can be provided without additional fuel consumption by evaporative coolers or by waste heat driven absorption chillers. The optimal operation of the system will be more complex, however, especially in the case of waste heat driven absorption chillers because the usage of the waste heat from the gas turbine has to be optimized by taking into consideration the performance of not only the gas turbine and the absorption chiller but also steam turbines, boilers and so on. The heat and electricity demands as well as the prices of electricity and fuels also influence the optimal operation.The purpose of our study is to provide criteria for optimal operation of gas turbine cogeneration systems including turbine inlet air cooling. The criteria give the minimum energy cost of the cogeneration system. The method is based on linear programming and theKuhn-Tucker conditions to examine the optimal solution, which can be applied to a wide range of cogeneration systems.2. The Criteria for the Optimal Operation of Gas Turbine Cogeneration SystemsThe criteria for the optimal operation of gas turbine cogeneration systems were examined from the Kuhn-Tucker conditions of a linear programming model [10]. A simplified gas turbine cogeneration system was modeled and the region where the optimal solution existed was illustrated on a plane of the Lagrange multipliers.2.1. The Gas Turbine Cogeneration System ModelThe gas turbine cogeneration system was expressed as a mathematical programming model. The system consisted of a gas turbine including an inlet air cooler and a heat recovery steam generator (HRSG), a steam turbine, an absorption chiller, a boiler and the electricity grid. Figure 1 shows the energy flow of the system. Electricity, process steam, and cooling for process or for air-conditioning are typical demands in industry, and they can be provided by multiple suppliers. In the analysis, cooling demands other than for inlet air cooling were not taken into account, and therefore, the absorption chiller would work only to provide inlet air cooling of the gas turbine. The electricity was treated as the electric power in kilowatts, and the steam and the chilled water were treated as the heat flow rates in kilowatts so that the energy balance can be expressed in the same units.Figure 1. The energy flow of the simplified gas turbine cogeneration system with the turbineinlet air cooling.The supplied electric power and heat flow rate of the steam should be greater than or equal to the demands, which can be expressed by Eqs. (1-2).(1)(2)where, xe and xs represent the electric power demand and the heat flow rate of the steam demand. The electric power supply from the grid, the gas turbine and the steam turbine are denoted by xG, xGT and xST, respectively. xB denotes the heat flow rate of steam from the boiler, and xAC denotes the heat flow rate of chilled water from the absorption chiller. The ratio of the heat flow rate of steam from the HRSG to the electric power from the gas turbine is denominated the steam to electricity ratio, and denoted by ρGT. Then, ρGTxGT represents the heat flow rate o f steam from the gas turbine cogeneration. The steam consumption ratios of the steam turbine and the absorption chiller are given as ωST and ωAC, respectively. The former is equivalent to the inverse of the efficiency based on the steam input, and the latter is equivalent to the inverse of the coefficient of performance.The inlet air cooling of the gas turbine enhances the maximum output from the gas turbine. By introducing the capacity of the gas turbine, XGT, the effect of the inlet air cooling was expressed by Eq. (3).(3).It was assumed that the increment of the gas turbine capacity was proportional to the heatflow rate of chilled water supplied to the gas turbine. The proportional constant is denoted byαGT.In addition to the enhancement of the gas turbine capacity, the inlet air cooling improves the electric efficiency of the gas turbine. Provided that the improvement is proportional to the heat flow rate of chilled water to the gas turbine, the fuel consumption of the gas turbine can be expressed as ωGTxGT¡βGTxAC, whereωGT is the fuel consumption ratio without the inlet air cooling and βGT is the improvement factor of the fuel consumption by the inlet air cooling. As the objective of the optimization is the minimization of the energy cost during a certain time period, Δt, the energy cost should be expressed as a function of xG, xGT, xST, xB and xAC. By defining the unit energy prices of the electricity, gas and oil as Pe, Pg and Po, respectively, the energy cost, C, can be given as:(4)where, ωB is the fuel consumpti on ratio of the boiler, which is equivalent to the inverse of the thermal efficiency.All the parameters that represent the characteristics of equipment, such as ωGT, ωST, ωAC, ωB, ρGT, αGT and βGT, were assumed to be constant so that the system could be m odeled by the linear programming. Therefore, the part load characteristics of equipment were linearly approximated.2.2. The Mathematical Formulation and the Optimal Solution From Eqs. (1–4), the optimization problem is formed as follows:(5)(6)(7)(8)where, x = (xG, xGT, xST, xB, xAC). Using the Lagrange multipliers, λ = (λ1, λ2, λ3), theobjectivefunction can be expressed by the Lagrangian, L(x,λ).(9)According to the Kuhn-Tucker conditions, x and λ satisfy the following conditions at the optimal solution.(10)(11)(12)(13)The following inequalities are derived from Eq. (10).(14)(15)(16)(17)(18)Equation (11) means that xi > 0 if the derived expression concerning the supplier i satisfies the equali ty, otherwise, xi = 0. For example, xG has a positive value if λ1 equals PeΔt. If λ1 is less than PeΔt, then xG equals zero.With regard to the constraint g3(x), it is possible to classify the gas turbine operation into two conditions.The first one is the case where the electric power from the gas turbine is less than the capacity,which means xG < XGT + αGTxAC. The second one is the case where the electric power from the gas turbine is at the maximum, which means xGT = XGT + αGTxAC. We denominate the former and the latter conditions the operational conditions I and II, respectively. Due to Eq. (12) of the Kuhn-Tucker condition, λ3 = 0 on the operational condition I, and λ3 > 0 on the operational condition II.2.3. The Optimal Solution where the Electric Power from the Gas Turbine is less than theCapacityOn the operational condition I where xG < XGT + αGTxAC, Eqs. (14–18) can be drawn on the λ1-λ2 plane because λ3 equals zero. The region surrounded by the inequalities gives the feasible solutions, and the output of the supplier i has a positive value, i.e. xi > 0, when the solution exists on the line which represents the supplier i.Figure 2 illustrates eight cases of the feasible solution region appeared on the λ1-λ2 plane. The possible optimal solutions ar e marked as the operation modes “a” to “g”. The mode a appears in the case A, where the grid electricity and the boiler are chosen at the optimal operation. In the mode b,the boiler and the steam turbine satisfy the electric power demand and the heat flow rate of the steam demand. After the case C, the electric power from the gas turbine is positive at the optimal operation.In the case C, the optimal operation is the gas turbine only (mode c), the combination of the gas turbine and the boiler (mode d) or the combination of the gas turbine and the grid electricity (mode e). In this case, the optimal operation will be chosen by the ratio of the heat flow rate of the steam demand to the electric power demand, which will be discussed later. When the line which represents the boiler does not cross the gas turbine line in the first quadrant, which is the case C’, only the modes c and e appear as the possible optimal solutions. The modes f and g appear in the cases D and E, respectively. The suppliersThe cases A through E will occur depending on the performance parameters of the suppliers and the unit energy prices. The conditions of each case can be obtained from the graphical analysis. For example, the case A occurs if λ1 at the intersection of G and B is smaller than that at the intersection of GT and B, and is smaller than that at the intersection of ST and B. In addition, the line B has to be located above the line AC so that the feasible solution region exists. Then, the following conditions can be derived.(19)(20)(21)Equation (19) means that the gas cost to produce a certain quantity of electricity and steam with the gas turbine is higher than the total of the electricity and oil costs to purchase the same quantity of electricity from the grid and to produce the same quantity of steam with the boiler.Equation (20) means that the electricity cost to purchase a certain quantity of electricity is cheaper than the oil cost to produce the same quantity of electricity using the boiler and the steam turbine. Equation (21) indicates that the reduction of the gas cost by a certain quantity of the inlet air cooling should be smaller than the oil cost to provide the same quantity of cooling using the boiler and the absorption chiller. Otherwise, the optimal solution does not exist because the reduction of the gas cost is unlimited by the inlet air cooling using the absorption chiller driven by the boiler.Figure 2. The possible cases of the optimal solution on the operational condition ISimilar ly, the following conditions can be derived for the other cases. The condition given as Eq. (21) has to be applied to all the cases below.Case B:(22)(23)Equation (22) compares the production cost of the electricity and the steam between the gas and the oil. The gas cost to produce a certain quantity of electricity and steam by the gas turbine is higher than the oil cost to produce the same quantity of electricity and steam by thecombination of the boiler and the steam turbine. Equation (23) is the opposite of Eq. (20), which means that the oil cost to produce a certain quantity of electricity by the boiler and the steam turbine is cheaper than the purchase price of electricity.Case C:(24)(25)(26)(27)Equation (24) is the opposite case of Eq. (19). Equation (25) compares the boiler and the gas turbine regarding the steam production, which is related to the mode d. In the case C, the oil cos t for the boiler is cheaper than the gas cost for the gas turbine to produce a certain quantity of steam. If the gas cost is cheaper, mode d is not a candidate for the optimal sol ution, as illustrated in the case C’. Equations (26) and (27) evaluate the effectiveness of the steam turbine and the inlet air cooling by the absorption chiller,resp ectively. The grid electricity is superior to the steam turbine and to the inlet air cooling in this case.Case D:In addition to Eq. (25),(28)(29)(30)Similarly to the case C’, the case D’ occurs if the inequality sign of Eq. (25) is reversed. Equation (28) is the opposite case of Eq. (22), which is the comparison of the electricity production between gas and oil. Equation (29) is the opposite case of Eq. (26), which is the comparison of the steam turbine and grid electricity. The gas cost to produce a certain quantity of electricity by the combination of the gas turbine and the steam turbine is cheaper than the purchase cost of the same quantity of electricity from the grid. Equation (30) gives the condition where the steam turbine is more advantageous than the inlet air cooling by the absorption chiller. The left hand side of Eq. (30) represents an additional steam required for a certain quantity of electricity production by the inlet air cooling. Therefore, Eq. (30) insists that the steam required for a certain quantity of electricity production by the steam turbine is smaller than that requiredfor the same quantity of electricity production by the inlet air cooling in this case, and it is independent of energy prices.Case E:In addition to Eq.(25),(31)(32)The case E’ occurs if Eq. (25) is reversed. Equations (31) and (32) are the opposite cases of Eqs. (27)and (30), which give the conditions where the inlet air cooling is more advantageous compared with the alternative technologies. In this case, Eq. (28) is always satisfied because of Eqs. (21) and (32).The conditions discussed above can be arranged using the relative electricity price, Pe/Pg and the relative oil price, Po/Pg. The optimal cases to be chosen are graphically shown in Figure 3 on the Po/Pg-Pe/Pg plane. When Eq. (30) is valid, Figure 3 (a) should be applied. The inlet air cooling is not an optimal option in any case. When Eq. (32) is valid, the cases E and E’ appear on the plane and the steam turbine is never chosen, as depicted in Figure 3 (b). It is noteworthy that if the inlet air cooling cannot improve the gas turbine efficiency, i.e. βGT = 0, the inlet air cooling is never the optimal solution.As the cases C, D and E include three operation modes, another criterion for the selection of the optimal operation mode is necessary in those cases. The additional criterion is related with the steam to electricity ratio, and can be derived from the consideration below.In the c ases C, D and E, λ1 and λ2 have positive values. Therefore, two of the constraints given as Eqs. (6) and (7) take the equality conditions due to the Kuhn-Tucker condition Eq. (12). Then, the two equations can be solved simultaneously for two variables which have positive values at each mode.For the mode d, the simultaneous equations can be solved under xGT, xB > 0 and xG, xST, xAC = 0.Then, one can obtain xGT = xe and xB = xs ¡ ρGTxe. Because xB has a positive value, the following condition has to be satisfied for the mode d to be selected.(33)At the mode e, one can obtain xG = xe ¡ xs/ρGT and xGT = xs/ρGT, and the following condition can be drawn out of the former expression because xG is greater than zero at this mode.(34)Similar considerations can be applied to the cases D and E. Consequently, Eq. (33) is the condition for the mode d to be selected, while Eq. (34) is the condition for the modes e, f or g to be selected. Furthermore, it is obvious that the mode c has to be chosen if the steam to electricity ratio of the gas turbine is equal to the ratio of the heat flow rate of the steam demand to the electric power demand, i.e. ρGT = xs/xe.Equations (33) and (34) mean that when the steam to electricity ratio of the gas turbine is smaller than the ratio of the heat flow rate of the steam demand to the electric power demand, the gas turbine should be operated to meet the electric power demand. Then, the boiler should balance the heat flow rate of the steam supply with the demand. On the other hand, if the steam to electricity ratio of the gas turbine is larger than the ratio of the heat flow rate of the steam demand to the electric power demand,the gas turbine has to be operated to meet the heat flow rate of the steam demand. Then, the insufficient electric power supply from the gas turbine has to be compensated by either the grid (mode e), the steam turbine (mode f), or the inlet air cooling (mode g). There is no need of any auxiliary equipment to supply additional electric power or steam if the steam to electricity ratio of the gas turbine matches the demands.Figure 3. The optimal operation cases expressed on the relative oil price-relative electricity price plane (the operational condition I).2.4. The Optimal Solution where the Electric Power from the Gas Turbine is at the MaximumIn the operational condition II, the third constraint, Eq. (8), takes the equality condition and λ3 would have a positive value. Then, Eqs. (11) and (18) yields:(35)It is reasonable to assume that ρGT ¡ !AC ®GT > 0 and ωGT ¡ ¯GT ®GT > 0 in the case ofgas turbine cogeneration systems because of relatively low electric efficiency (¼ 25 %) and a high heat to electricity ratio (ρGT > 1.4). Then, the optimal solution cases c an be defined by a similar consideration to the operational condition I, and the newly appeared cases are illustrated in Figure 4. The cases F and G can occur in the operational condition II in addition to the cases A and B of the operational condition I. Similarly to the cases C’ and D’ of the operational condition I, the cases F’ and G’ can be defined where the mode h is excluded from the cases F and G, respectively.Figure 4. The optimal solution cases on the operational condition II.In the operational condition II, the conditions of the cases A and B are slightly different from those in the operational condition I, as given below.Case A:(36)(37)Case B:(38)(39)The conditions for the cases F and G are obtained as follows.Case F:(40)(41)(42)Case G:In addition to Eq. (41),(43)(44)The case s F’ and G’ occur whenthe inequality sign of Eq. (41) is reversed. Equations (36), (38),(40), (41), (42), (43) and (44) correspond to Eqs. (19), (22), (24), (25), (26), (28) and (29), respectively.In these equations, ωGT ¡ ¯GT®GTis substituted for ωGT, an d ρGT ¡ !AC®GTis substituted for ρGT.The optimal cases of the operational condition II are illustrated on the Po/Pg-Pe/Pg plane as shown in Figure 5. Unlike the operational condition I, there is no lower limit of the relative oil price for the optimal solution to exist. The line separating the cases F and G is determined by the multiple parameters.Basically, a larger ρGT or a smaller ωST lowers the line, which causes a higher possibility for the case G to be selected.Figure 5. The optimal operation cases expressed on the relative oil price-relative electricity price plane (the operational condition II).To find the optimal mode out of three operation modes included in the cases F or G, another strategy is necessary. The additional conditions can be found by a similar examination on the variables to that done for the cases C, D and E. In the operational condition II, three variables can be analytically solved by the constraints given as Eqs. (6), (7) and (8) taking equality conditions.In the mode g, only two variables, ωGT andωAC are positive and the other variables are equal to zero.Therefore, the analytical solutions of those in the operational condition II can be obtained from equations derived from Eqs. (6) and (7) as xGT = xe and xAC = (ρGTxe ¡xs)/ωA C. Then the third constraint gives the equality condition concerning xs/xe and XGT/xe as follows:(45)where, XGT/xe represents the ratio of the gas turbine capacity to the electricity demand, and XGT/xe ·1.For mode h, the condition where this mode should be selected is derived from the analytical solution of xB with xB > 0 as follows:(46)For the mode i, xG > 0 and xAC > 0 give the following two conditions.(47)(48)For the mode j, xST > 0 and xAC > 0 give the following conditions.(49)(50)The conditions given as Eqs. (45–50) are graphically shown in Figure 6. In the cases F and G,the operational condition II cannot be applied to the region of xsxe< ρGTXGT xeand xsxe<(ωST+ρGT)XGTxe¡ωST,respectively, because xAC becomes negative in this region. The optimal operation should be found under the operational condition I in this region.3. Comparison of the Optimal Operation Criteria with a Detailed Optimization ResultTo examine the applicability of the method explained in the previous section to a practical cogeneration system, the combination of the suppliers selected by the optimal operation criteria was compared with the results of a detailed optimization of an existing plant.3.1. An Example of an Existing Energy Center of a FactoryAn energy center of an existing factory is depicted in Figure 7. The factory is located in Aichi Prefecture, Japan, and produces car-related parts. The energy center produces electricity by a combined cycle of a gas turbine and a steam turbine. The gas turbine can be fueled with either gas or kerosene, and it is equipped with an inlet air cooler. The electric power distribution system of the factory is also linked to the electricity grid so that the electricity can be purchased in case the electric power supply from the energy center is insufficient.The steam is produced from the gas turbine and boilers. The high, medium or low pressure steam is consumed in the manufacturing process as well as for the driving force of the steam turbine and absorption chillers. The absorption chillers supply chilled water for the process, air conditioning and the inlet air cooling. One of the absorption chiller can utilize hot water recovered from the low temperature waste gas of the gas turbine to enhance the heat recovery efficiency of the system.Figure 6. The selection of the optimal operation mode in the cases of F and G.3.2. The Performance Characteristics of the EquipmentThe part load characteristics of the equipment were linearly approximated so that the system could be modeled by the linear programming. The approximation lines were derived from the characteristics of the existing machines used in the energy center.The electricity and the steam generation characteristics of the gas turbine and the HRSG are shown in Figure 8, for example. The electric capacity of the gas turbine increases with lower inlet air temperatures. The quantity of generated steam is also augmented with lower inlet air temperatures.In practice, it is known that the inlet air cooling is beneficial when the purchase of the grid electricity will exceed the power contract without the augmentation of the gas turbine capacity. Furthermore, the inlet air cooling is effective when the outdoor air temperature is higher than 11 ◦C. A part of the operation of the actual gas turbine system is based on the above judgement of the operator, which is also included in the detailed optimization model.3.3. The Detailed Optimization of the Energy CenterThe optimization of the system shown in Figure 7 was performed by a software tool developed for this system. The optimization method used in the tool is the linear programming method combined with the listed start-stop patterns of equipment and with the judgement whether the inlet air cooling is on oroff. The methodology used in the tool is fully described in the reference [11].Figure 7. An energy center of a factory.Figure 8. The performance characteristics of the gas turbine and the HRSG.The Detailed Optimization MethodThe energy flow in the energy center was modeled by the linear programming. The outputs of equipment were the variables to be optimized, whose values could be varied within the lower and upper limits. To make the optimization model realistic, it is necessary to take the start-stop patterns of the equipment into account. The start-stop patterns were generated according to thepossible operation conditions of the actual energy center, and 20 patterns were chosen for the enumeration. The optimal solution was searched by the combination of the enumeration of the start-stop patterns and the linear programming method. The list of the start-stop patterns of the gas turbine and the steam turbine is given in Figure 9.The demands given in the detailed optimization are shown in Figure 10 as the ratios of the heat flow rate of the steam demand to the electric power demand on a summer day with a large electric power demand and on a winter day with a small steam demand. On the summer day, the ratio of the heat flow rate of the steam demand to the electric power demand is at a low level throughout a day. While, it is high on the winter day, and during the hours 2 to 6, the ratio exceeds 1.4 that is the steam to electricity ratio of the gas turbine.Figure 9. The start-stop patterns of the gas turbine and the steam turbine.The Plant Operation Obtained by the Detailed OptimizationThe accumulated graphs shown in Figures 11 through 14 illustrate the electric power supply and the heat flow rate of the steam supply from equipment on the summer and winter days. On the summer day, the gas turbine and the steam turbine worked at the maximum load and the electric power demand was met by the purchase from the grid for most of the day except the hours 2 to 6, at which the electric power demand was small. The inlet air cooling of the gas turbine was used only at the hours 10 and 14, at which the peak of the electric power demand existed. The steam was mainly supplied by the gas turbine, and the boiler was used only if the total heat flow rate of the steam demands by the process, the steam turbine, and the absorption。
电力专业英语 英文文献翻译报告
Page 1.The Production of Electrical Energy(电能生产)1 English textFrom reference 1Should the generation be not adequate to balance the load demand, it is imperative that one of following alternatives be considered for keeping the system in operating condition:1. Staring fast peaking units,2. Load shedding for unimportant loads,3. generation rescheduling.It is apparent from the above that since the voltage specifications are not stringent, load frequency control is by far the most important in power system control.In order to understand the frequency control, consider a small step-increase in load. The initial distribution of the load increment is determined by the system simpedance; and the sistantaneous relative generator rotor positions. The energy required to supply the load increment is drawn from the kinetic energy of rotating machines. As a result, the system frequency drops. The distribution of load during this period among the various machines is determined by the inertias of the rotors of the generators partaking in process. This problem is stability analysis of the system.After the speed or frequency fall due to reduction in stored energy in the rotors has taken place, the drop is sensed by the governors and they divide the load increment between the machines as determined by the droops of the respective governor characterstics. Subsequently, secondary control restores the system frequency to its normal value by readjusting the governor characteristics. Keywords：load frequency controlFrom reference 2Modern power systems are so large that it is impossible to design a single central control system that would handle the overall control job. It is extremely useful take into account the weak links in the system and then apply control throughdecomposition. The demarcation of load frequency control and Mavar voltage control characteristics is one such decomposition. Geographical and functional decomposition are successfully applied to power systems and this leads to the concept of area control.A modern power system can be divided into several areas for load frequency control. Each control area fulfils the following:1.The area is a geographically contious portion of a large interconnected area, which adjusts its own generation to accommodate load changes within its precincts.2.Under normal conditions of operation, it changes bulk power with neighboring areas.3.Under abnormal conditions of operation, it may deviate from predetermined schedules and provide assistance to any neighboring control area in the system.4.It is expected, in addition, to partake with the other areas in the system in a suitable manner in the system frequency regulation.The rotors of all generators in a control area swing together for load change. Thus, a coherent group of generators within a geographical region may constitute a control area which is connected to other similar areas by weak tie lines.Keywords：areas load frequency controlFrom reference 3For plant loading schedules in thermal systems, load prediction up to two hours in advance is necessary while for unit commitment schedules prediction up to 24 hours is sufficient. Also, at all sations and control centers, short-time prediction is needed for storage and display of advance information. Based on this information, predictive security assessment of the system is made. This also helps to contain the rates of change of generator outputs within their permissible limits.For the implementation of economic scheduling of generation using digital computers, detailed estimates of the future load demands are essential in order to allow sufficient time for the calculation and implementation of the generator schedules. Whatever method is envisaged for the calculation of such economic schedules consistent with the security and spare requirements of the system, the schedules should be calculatedevery 15 or 30 minutes and each economic schedule should be a predictive one ,for at least about 30 minutes ahead of event. It is then obvious that the predictions are to be revised frequently in the light of any fresh information so as to minimize the estimation errors.Peak load demand forecasts are useful in determining the investment required for additional generating and transmission capacities required. Forecasts for planning require data extending over several previous years. Meaningful forecasts can be obtained with lead time of 3 to 5 years.Keywords：load predictionFrom reference 4In this method, the load is separated into two main components. The first component is a base load which is of fixed value and the second a variable component which is a function of the weather conditions.Estimates can be made 24 hours ahead, using the weather forecast. The temperature base for weighting the effect of the predicated temperature on the load is the normal, mean temperature of the month. The normal, mean temperature of the month has zero weight. Similarly the change in consumers demand due to cloudy weather may be assumed to vary in direct proportion to the degree of cloudiness. This in turn may be expressed by an illumination index with fair, clear sky corresponding to zero weight.The base load is determined from past records. Proper weighting of the elements of the weather will be attained only after several trials. The method of prediction stabilizes after this trial period. It may be noted that the base loads for week days and weekend will generally be different for any hour.Using these base loads, a load estimate based on the best available weather forecast can be made using proper weighting of meteorological factors like temperature, cloudiness, wind velocity, etc.Keywords：proper weighting of the elements of the weather2 中文翻译及分析出自文献1：万一发电量不足以平衡负荷需求，要使电力系统处于运行状态，必须考虑采取以下选择方法中的一种：1、启动快速峰荷机组2、对不重要的用户实行拉闸断电3、重新制定发电计划从上述情况来看，电压技术的要求并不严格，目前为止负荷频率控制是电力系统控制中最重要的手段。
热动专业英语翻译第2章
热能与动力工程教研室
Department of Thermal Energy & Power Engineering
Specialized English for Thermal Energy & Power Engineering
现代蒸汽发生系统可根据不同的标准分类。这 些包括最终用途、燃烧方式、运行压力、燃料和循 环方式。大型中心电站的电站锅炉主要用来发电。 经过优化设计，使最大可能可用性时有最高的热效 率。新机组的关键特性是利用再热器提高整个循环 效率。
热能与动力工程教研室
Department of Thermal Energy & Power Engineering
Specialized English for Thermal Energy & Power Engineering
Utility boilers are used primarily to generate electricity in large central power stations. They are designed to optimise overall thermodynamic efficiency at the highest possible availability. A key characteristic of newer units is the use of a reheater section to increase overall cycle efficiency.
热能与动力工程教研室
Department of Thermal Energy & Power Engineering
Specialized English for Thermal Energy & Power Engineering
热能毕业设计外文文献及翻译
用于分析在直燃式步进式加热炉板坯瞬态加热的传热模型摘要一个可以预测板坯表面温度分布和热流情况的数学传热模型已开发出来了，主要是通过充分考虑在炉膛内的板坯的热辐射和瞬态热传导方程来实现的。
该炉型是参照散热介质在空间中的变恒温过程和恒定的吸收系数来设计的。
钢坯由步进梁从一个固定梁移动到下一个固定梁上，是以通过加热炉预热段.加热段和均热段为钢坯热传导方程的边界条件的加热炉模型。
辐射热通量的计算是通过采用有限体积法，在炉子的内部，以炉墙.炉顶.炉底构成的充满烟气的环境里，作为板坯的瞬态传导方程的边界条件来进行计算的。
板坯的传热特性和温度特性是通过调查可以改变板坯吸收系数和发射率的参数来确定的。
比较多次的实践工作表明，目前用于预测板坯在加热炉中的传热过程和热流量的状况示范工程得到了很好的效果。
关键词：加热炉;钢坯加热;辐射传热;瞬态热传导;有限体积法1 导言在过去数十年以来，炉子进入降低能源消耗和污染物排放量的阶段，而分析钢坯瞬态热特性，在加热炉工程应用上已吸引了相当多注意。
此外，限定板坯在炉子内有均匀的温度分布才能出炉的重要性大大增加了，只有准确、快速的预测炉内板坯的温度，才能为以后的轧制过程提供比较好的原料，因为这决定了钢铁产品质量的高低。
在本质上，在炉膛内的整个燃烧过程和由此产生的热气流同时影响传热.对流和热辐射过程。
然而，复杂的炉子内部的三维结构包括固定梁和步行梁打滑问题使的难以在经济上做出准确的分析。
因此，模型和方法对于预测炉子内部燃烧特性和传热过程中存在着很高的要求。
尤其是，准确预测热辐射量是最重要的，因为热辐射传热超过流过板坯表面总热流的90％。
现在没有一个单一的辐射模型就能够解决所有在工程应用中遇到的情况，所以应选择一个合适的途径为自己的侧重点。
为了预测通过板坯表面上的辐射热通量，从而准确计算出炉子内板坯的温度分布，其解决方法是板坯必须是做连续运动，无灰的燃烧烟气作为该炉辐射气体，以及复杂的炉壁几何结构包括弯曲的板坯和防滑管道堵塞的影响，还有就是一定量的计算。
火力发电厂专业英语(中英对照)
火力发电厂专业英语[日期]MS USER[公司地址]CONTENTS1. Modern electric generating stations (3)1.1 how power is generated (3)1.2 Steam Power Plants (4)2.Fuel handling and preparation for burning (12)2.1 Coal Handing Systems (12)2.2Crushing (15)2.3 Dust control system (16)2.6 pulverizers (17)3.steam generator configuration (22)3.1 the early fire tube boilers (22)3.2 Development of the Water Tube Boilers (22)3.3 Water-cooled integral Furnace/Boiler Design (23)3.4 Modern steam generator (25)4. Steam separation and purification (30)5. Primary System Heat Exchanges (35)5.1 feed-water system and economizer (35)5.2 closed feed-water heaters (36)6. Condensers (42)7. Air Circulating And Heating System (45)7.1 air circulation (45)7.2 air heaters (46)8. Water Treatment System (50)8.1the need for water treatment (50)8.2 raw water treatment (51)8.3condensate treatment (53)8.4 feed-water treatment (54)9. Cooling Towers (58)9.1 general classifications (58)9.2 Flow patterns and fill material (59)9.3 cooling tower subsystems (60)9.4 wet cooling tower performance (61)10. Emission Control System (63)10.1 sulfur dioxide removal techniques (64)10.2 controlling NOx (66)10.3 controlling particulate emissions (68)11 WASTE DISPOSAL (71)11.1 Ash Handling and Disposal (71)11.2 Disposal of Flue Gas Wastes (73)12 THE STEAM CYCLE (76)12.1 Basic Operating Parameters (76)12.2 Basic Concepts (77)12.3 Multistage Turbine (78)12.4 Steam Turbine Configurations (81)13 TURBINE ANALYSIS (83)13.1 The Efficiency of a stage (83)13.2 Actual Stage Efficiencies (83)13.3 Steam Turbine Blade Problem (85)14 OFF-DESIGN TURBINE ANALYSIS (88)15 STEAM GENERATOR CONTROL (92)15.1 Basic Concepts (92)15.2 Steam Demand (93)15.3 Firing Rate (94)15.4 Feed-water Control (95)15.5 Steam Superheat Control (96)16 STEAM TURBINE CONTROL (101)16．汽轮机控制 (101)16.1 Fundamentals (101)16.2 Mechanical-Hydraulic Speed Control Systems (104)16.3 Electro-Hydraulic Speed Control Systems (106)17 COMBINED CYCLES (108)17.1 Basic Gas Turbine Cycles (108)17.2 General Descriptions of Combined Cycles (109)17.3 Efficiency of Combined Cycles (111)17.4 Combined Cycle with A MHD Generator (112)18 COORDINATED CONTROL SYSTEM (115)18.1 Coordinated Master Control System (115)18.2 Combustion Control System (116)18.3 Superheated Steam Temperature Control System (119)18.4 Reheated Steam Temperature Control System (120)19 Furnace Safeguard Supervisory System (FSSS) (123)19.1 general (123)19.2 operation sequence (123)19.3 tangential firing control system (127)19.4 system configuration (128)20 Energy Storage (131)20.1 need for large scale energy storage (131)20.2 energy storage technologies (131)20.3 compressed air energy storage (132)20.4 thermal energy storage (133)1. Modern Electric Generating Stations1.现代发电厂1.1 how power is generated1.1 电是如何产生的Virtually all the electric power in the United States today is generated by one of the methods depicted schematically in fig.1.1.事实上，今天所有的美国电力都是由图1.1所示意的一种方法所产生的。
能源与动力学院 毕业设计(论文)外文翻译-改
外文文献翻译能源与动力学院School of Energy and Power专业班级：能动B141学生姓名：徐宇辰学生学号： 15指导教师：杜祖成2016年 03 月 16 日一、目的：1．了解国外相关知识的发展；2．熟悉外文科技文献的写作格式及特点；3．熟悉和巩固所学专业外语的有关知识；4．学会中英（外）文文献的检索方法。
二、选题要求：1．学生自主选题，经指导教师审查合格。
2．篇幅在3000汉字以上，较完整的一篇外文论文3．内容与所学专业相关，并注明来源。
三、译文要求：1．译文正确，内容完整，图可以复印后贴于适当位置。
2．译文打印在A4纸上，原稿复印后附在译文后。
四、时间安排：在毕业设计开题3周内完成。
外文文献资料简表对300MW汽轮机凝结水的便携式集成式孔板流量测量装置的研究为了保证电厂汽轮机热力试验的准确性，应保证凝结水的流量测量精度。
在本文中，对300MW汽轮机通流冷凝水的便携式集成式流量测量装置的设计，这是基于冷凝水的参数和具体的管道的条件下，在5号低压加热器出口的300MW机组。
本文通过对非标准差压式孔板流量计的一体化设计是通过在标准实验系统标定，误差较大的原因是，流场被不稳定的起源板式向下焊接连接法兰。
流场连接法兰的分布弱化，测量精度可满足汽轮机热力试验的要求。
1 介绍汽轮机热力试验是确定汽轮机热经济性的最有力的工具之一。
通过汽轮机热力试验、热效率、实现汽轮机经济性能的评价。
最常见的是，经过技术改造，新建的单元和单元机组大修前后应进行测试，对汽轮机的经济性分析。
考虑到如节流损失的因素，流量测量装置不应安装用来测量汽轮机主蒸汽流量，蒸汽流量的每个再生器的提取以及加热蒸汽流量。
在整个蒸汽循环系统，只有流动的给水和凝结水流量测量装置的进水流量位于给水泵，承受相对高的压力。
焊接是比较常见的连接给水和主给水管道流量测量装置在一起的方式，但在规范给水流量测量装置的时候，会面临一系列的困难。
凝结水流量测量装置在给水泵前，具有相对较低的压力。
电厂蒸汽动力毕业设计论文中英文资料对照外文翻译文献
中英文资料对照外文翻译文献The basics of Steam Power and use1.1 Why an understanding of steam is neededSteam power is fundamental to what is by far the largest sector of the electricity-generating industry and without it the face of contemporary society would be dramatically different from its present one. We would be forced to rely on hydro-electric power plant, windmills, batteries, solar cells and fuel cells, all of which are capable of producing only a fraction of the electricity we use.Steam is important, and the safety and efficiency of its generation and use depend on the application of control and instrumentation, often simply referred to as C&I. The objective of this book is to provide a bridge between the discipline of power-plant process engineering and those of electronics, instrumentation and control engineering.I shall start by outlining in this chapter the change of state of water to steam, followed by an overview of the basic principles of steam generation and use. This seemingly simple subject is extremely complex. This will necessarily be an overview: it does not pretend to be a detailed treatise and at times it will simplify matters and gloss over some details which may even cause the thermodynamicist or combustion physicist to shudder, but it should be understood that the aim is to provide the C&I engineer with enough understanding of the subject to deal safely with practical control-system design, operational and maintenance problems.1.2 Boiling: the change of state from water to steamWhen water is heated its temperature rises in a way that can be detected (for example by a thermometer). The heat gained in this way is called sensible because its effects can be sensed, but at some point the water starts to boil.But here we need to look even deeper into the subject. Exactly what is meant by the expression 'boiling'? To study this we must consider the three basic states of matter: solids, liquids and gases. (A plasma, produced when the atoms in a gas become ionised, is often referred to as the fourth state of matter, but for most practical purposes it is sufficient to consider only the three basic states.) In its solid state, matter consists of many molecules tightly bound together by attractive forces between them. When the matter absorbs heat the energy levels of its molecules increase and the mean distancebetween the molecules increases. As more and more heat is applied these effects increase until the attractive force between the molecules is eventually overcome and the particles become capable of moving about independently of each other. This change of state from solid to liquid is commonly recognised as 'melting'.As more heat is applied to the liquid, some of the molecules gain enough energy to escape from the surface, a process called evaporation (whereby a pool of liquid spilled on a surface will gradually disappear). What is happening during the process of evaporation is that some of the molecules are escaping at fairly low temperatures, but as the temperature rises these escapes occur more rapidly and at a certain point the liquid becomes very agitated, with large quantities of bubbles rising to the surface. It is at this time that the liquid is said to start 'boiling'. It is in the process of changing state to a vapour, which is a fluid in a gaseous state.Let us consider a quantity of water that is contained in an open vessel. Here, the air that blankets the surface exerts a pressure on the surface of the fluid and, as the temperature of the water is raised, enough energy is eventually gained to overcome the blanketing effect of that pressure and the water starts to change its state into that of a vapour (steam). Further heat added at this stage will not cause any further detectable change in temperature: the energy added is used to change the state of the fluid. Its effect can no longer be sensed by a thermometer, but it is still there. For this reason it is called latent, rather then sensible, heat. The temperature at which this happens is called the 'boiling point'. At normal atmospheric pressure the boiling point of water is 100 ° C.If the pressure of the air blanket on top of the water were to be increased, more energy would have to be introduced it to break free. In other words, the temperature must be raised further to make it boil. To illustrate this point, if the pressure is increased by 10% above its normal atmospheric value, the temperature of the water must be raised to just above 102 °C before boiling occurs.The steam emerging from the boiling liquid is said to be saturated and, for any given pressure, the temperature at which boiling occurs is called the saturation temperature.The information relating to steam at any combination of temperature,pressure and other factors may be found in steam tables, which are nowadays available in software as well as in the more traditional paper form. These tables were originally published in 1915 by Hugh Longbourne Callendar (1863-1930), a British physicist. Because of advances in knowledge and measurement technology, and as a result of changing units of measurement, many different variants of steam tables are today in existence, but they all enable one to look up, for any pressure, the saturation temperature, the heat per unit mass of fluid, the specific volume etc.Understanding steam and the steam tables is essential in many stages of the design of power-plant control systems. For example, if a designer needs to compensate a steam-flow measurement for changes in pressure, or to correct for density errors in a water-level measurement, reference to these tables is essential.Another term relating to steam defines the quantity of liquid mixed in with the vapour. In the UK this is called the dryness fraction (in the USA the term used is steam quality). What this means is that if each kilogram of the mixture contains 0.9 kg of vapour and 0.1 kg of water, the dryness fraction is 0.9.Steam becomes superheated when its temperature is raised above the saturation temperature corresponding to its pressure. This is achieved by collecting it from the vessel in which the boiling is occurring, leading it away from the liquid through a pipe, and then adding more heat to it. This process adds further energy to the fluid, which improves the efficiency of the conversion of heat to electricity.As stated earlier, heat added once the water has started to boil does not cause any further detectable change in temperature. Instead it changes the state of the fluid. Once the steam has formed, heat added to it contributes to the total heat of the vapour. This is the sensible heat plus the latent heat plus the heat used in increasing the temperature of each kilogram of the fluid through the number of degrees of superheat to which it has been raised.In a power plant, a major objective is the conversion of energy locked up in the input fuel into either usable heat or electricity. In the interests of economics and the environment it is important to obtain the highest to the water to enable possible level of efficiency in this conversion process. As we have already seen, the greatest efficiency is obtained by maximising theenergy level of the steam at the point of delivery to the next stage of the process. When as much energy as possible has been abstracted from the steam, the fluid reverts to the form of cold water, which is then warmed and treated to remove any air which may have become entrained in it before it is finally returned to the boiler for re-use.1.3 The nature of steamAs stated in the Preface, the boilers and steam-generators that are the subject of this book provide steam to users such as industrial plant, or housing and other complexes, or to drive turbines that are the prime movers for electrical generators. For the purposes of this book, such processes are grouped together under the generic name 'power plant'. In all these applications the steam is produced by applying heat to water until it boils, and before we embark on our study of power-plant C&I we must understand the mechanisms involved in this process and the nature of steam itself.First, we must pause to consider some basic thermodynamic processes. Two of these are the Carnot and Rankine cycles, and although the C&I engineer may not make use of these directly, it is nevertheless useful to have a basic understanding of what they are how they operate.1.3.1 The Carnot cycleThe primary function of a power plant is to convert into electricity the energy locked up in some form of fuel resource. In spite of many attempts, it has not proved possible to generate electricity in large quantities from the direct conversion of the energy contained in a fossil fuel (or even a nuclear fuel) without the use of a medium that acts as an intermediary. Solar cells and fuel cells may one day achieve this aim on a scale large enough to make an impact on fossil-fuel utilisation, but at present such plants are confined to small-scale applications. The water turbines of hydro-electric plants are capable of generating large quantities of electricity, but such plants are necessarily restricted to areas where they are plentiful supplies of water at heights sufficient for use by these machines.Therefore, if one wishes to obtain large quantities of electricity from a fossil fuel or from a nuclear reaction it is necessary to first release the energy that is available within that resource and then to transfer it to a generator, and this process necessitates the use of a medium to convey the energy from source to destination. Furthermore, it is necessary to employ a medium that isreadily available and which can be used with relative safety and efficiency. On plant Earth, water is, at least in general, a plentiful and cheap medium for effecting such transfers. With the development of technology during the twentieth century other possibilities have been considered, such as the use of mercury, but except for applications such as spacecraft where entirely new sets of limitations and conditions apply, none of these has reached active use, and steam is universally used in power stations.Carnot framed one of the two laws of thermodynamics. The first, Joule's law, had related mechanical energy to work: Carnot's law defined the temperature relations applying to the conversion of heat energy into mechanical energy. He saw that if this process were to be made reversible, heat could be converted into work and then extracted and re-used to make a closed loop. In his concept (Figure 1.1), a piston moves freely without encountering any friction inside acylinder made of some perfectlyinsulating material. The piston isdriven by a 'working fluid'. Thecylinder has a head at one end thatcan be switched at will from beinga perfect conductor to being aperfect insulator. Outside thecylinder are two bodies, one ofwhich can deliver heat without itsown temperature ( T1 ) falling, theother being a bottomless cold sink at a temperature (T2) which is also constant.The operation of the system isshown graphically in figure 1.2,which shows the pressure/volumerelationship of the fluid in thecylinder over the whole cycle. As theprocess is a repeating cycle itsoperation can be studied from anyconvenient starting point, and weshall begin at the point A, where thecylinder head (at this time assumed to be a perfect conductor of heat), allows heat from the hot source to enter the cylinder. The result is that the medium begins to expand, and if it is allowed to expand freely, Boyle's law (which states that at any temperature the relationship between pressure and volume is constant) dictates that the temperature will not rise, but will stay at its initial temperature (Tl). This is called isothermal expansion.When the pressure and volume of the medium have reached the values at point B, the cylinder head is switched from being a perfect conductor to being a perfect insulator and the medium allowed to continue its expansion with no heat being gained or lost. This is known as adiabatic expansion. When the pressure and volume of the medium reach the values at point C, the cylinder head is switched back to being a perfect conductor, but the external heat source is removed and replaced by the heat sink. The piston is driven towards the head, compressing the medium. Heat flows through the head to the heat sink and when the temperature of the medium reaches that of the heat sink (at point D), the cylinder head is once again switched to become a perfect insulator and the medium is compressed until it reaches its starting conditions of pressure and temperature.The cycle is then complete, having taken in and rejected heat while doing external work.1.3.2 The Rankine cycleThe Carnot cycle postulates a cylinder with perfectly insulating walls and a head which can be switched at will from Being a conductor to being an insulator. Even with modifications to enable it to operate in a world where such things are not obtainable, it would have probably remained a scientific concept with no practical application, had not a Scottish professor of engineering, William Rankine,proposed a modification to it at thebeginning of the twentieth century [I].The concepts that Rankine developedform the basis of all thermal powerplants in use today. Even todayscombined-cycle power plants use hiscycle for one of the two phases oftheir operation.Figure 1.3 illustrates theprinciple of the Rankine cycle. Starting at point A again, the source of heat is applied to expand the medium, this time at a constant pressure, to point B, after which adiabatic expansion is again made to occur until the medium reaches the conditions at point C. From here, the volume of the medium is reduced, at a constant pressure, until it reaches point D, when it is compressed back to its initial conditions.电厂蒸汽动力的基础和使用1.1 为何需要了解蒸汽对于目前为止最大的发电工业部门来说，蒸汽动力是最为基础性的。
'火电厂热电厂各系统中英文对照'doctypedoc
火电厂火电厂火电厂火电厂、、、、热电厂各系统中英文对照热电厂各系统中英文对照热电厂各系统中英文对照热电厂各系统中英文对照1111Quality and nuclear safety related system(完全与质量和核安全相关系统)Partially quality and nuclear safety related system(部分与质量和核安全相关系统)Quality related system(与质量相关系统)Non quality related system（与质量无关系统）A Feedwater Supply(供水系统)ABP Low Pressure Feedwater Heater(低压给水加热器系统)ACO Feedwater Heaters Drain Recovery（给水加热器疏水回收系统）ADG Feedwater Deaerating Tank and Gas Stripper(给水除氧器系统)ADS LV AC Network 380V(ET Buiding)/低压交流电源380V系统（ET厂房）AET Feedwanter Pump Turbine Gland(主给水泵汽机轴封系统)AGM Moter Driven Feedwater Pump Lubrication(电动主给水泵润滑系统)AGR Feedwater Pump Turbine Lubrication and Control Fluid(主给水泵汽机润滑油及调节油系统)AHP High Pressure Feedwataer Heater(高压给水加热器系统) ory System（汽机监视系统）APA Moter-Driven Feedwater Pump(电动主给水泵系统)2222APD Start-up Feedwater System(启动给水系统)APG Steam Generator Blowdown(蒸汽发生器排污系统)APP Turbine－Driven Feedwater Pump（汽动主给水泵系统）APU Feedwater Pump Turbine Drain(主给水泵汽机疏水系统)ARE Feedwater Flow Control(给水流量控制系统)ASG Auiliary Feedwater (辅助给水系统)ATE Condensate Polishing Plant(凝结水净化处理系统)C Condenser(Condensation－Vacuum－Circulating Water)/凝汽器（冷凝－真空－循环水）CAR Turbine Exhaust Water Spraying(汽机排汽口喷淋系统)CET Turbine Gland(汽机轴封系统)CEX Condensate Extraction(凝结水抽取系统)CFI Circulating Water Filtraation(循环水过滤系统)CGR Circulating Water Pump Lubrication(循环水泵润滑系统)CPA Cathodic Protection（阴极保护系统）CRF Circulating Water（循环水系统）3333CTE Circulating Water Treatment(循环水处理系统)CVI Condenser Vacuum(凝汽器真空系统)D Ventilation－Handling Equipment－Communications－Elighting(通风－吊装设备－通讯－照明)DAA BOP Elevator System(BOP电梯系统)DAI Nuclear Island Building Elevators(核岛厂房电梯)DAM Turbine Hall Elevators（汽机厂房电梯）DEG Nuclear Island Chilled Water (核岛冷冻水系统)DEL Electrical Building Chilled Water（电气厂房冷冻水系统）DMA BOP Handling Equipment（AC Building）/BOP吊装设备（AC厂房）DME Main Swithchyard Handling Equipment（主开关站吊装设备）DMH Miscellaneous Hoists and Lifting Equipment in BOP Buildingsand Area(BOP厂房和BOP区域内的各种吊装设备DMK Fuel Building Handling Equipment（核燃料厂房吊装设备）DMM Turbine Hall Mechanical Handling Equipment（汽机厂房机械吊装设备）DMN Nuclear Auxiliary Building Handling Equipment（核辅助厂房吊装设备）4444DMP Circulating Water Pumping Station Handling Equipment （循环水泵站吊设备）DMR Reactor Building Handling Equipment（反应堆厂房吊装设备）DMW Handling Equipment for Reactor Building Gantry andPeripheral Rooms(反应堆厂房外部龙门架及其外围厂房吊装设备) DNB BOP Building&Area Normal Lighting（BOP厂房和区域内正常照明系统）DNK Fuel Buildings Normal Lighting(核燃料厂房正常照明系统)DNL Electrical Building Nomal Lighting（电气厂房正常照明系统）DNM Turbine Hall Normal Lighting（汽机厂房正常照明系统）DNN Nuclear Auxiliray Building Normal Lighting（核辅助厂房正常照明系统）DNP Circulating Water Pumping Station Normal Lighting（循环水泵房正常照明系统）DNQ Waste Auxiliary Building Normal Lighting(核废料辅助厂房正常照明系统)DNR Reactor Building Normal Lighting（反应堆厂房正常照明系统）DSB BOP Building&Area Emergency Lighting（BOP厂房和区域内应急照明系统）DSI Site Security System（厂区保安系统）DSK Fuel Buildings Emergency Lighting(核燃料厂房应急照明系统)5555DSL Electrical Building Emergency Lighting （电气厂房应急照明系统）DSM Turbine Hall Emergency Lighting（汽机厂房应急照明系统）DSN Nuclear Auxiliray Building Emergency Lighting（核辅助厂房应急照明系统）tem（汽机监视系统）DSP Circulating Water Pumping Station Emergency Lighting（循环水泵房应急照明系统）DSQ Waste Auxiliary Building Emergency Lighting(核废料辅助厂房应急照明系统)DSR Reactor Building Emergency Lighting（反应堆厂房应急照明系统）DTL Closed－Circuit Television（闭路电视系统）DTV Site Communication（厂区通讯系统）DVC Control Room Air Conditioning（主控制室空调系统）DVE Cable Floor Ventilation （电缆层通风系统）DVF Electrical Building Smoke Exhaust（电气厂房排烟系统）DVG Auxiliary Feedwater Pump Room Ventilation（辅助给水泵房通风系统）DVH Charging Pump Room Emergency Ventilation（上充泵房应急通风系统）DVI Component Cooling Room Ventilation(设备冷却水房间通风系统)DVK Fuel Building Ventilation（核燃料厂房通风系统）6666DVL Electrical Building Main Ventilation（电气厂房主通风系统）DVM Turbine Hall Vetilation（汽机厂房通风系统）DVN Nuclear Auxiliry Building Ventilation?房应急照明系统）统）DVP Circulating Water Pumping Station Ventilation （循环水泵通风系统）DVQ Waste Auxiliary Building Ventilation （废物辅助厂房通风系统）DVS Safety Injection and Containment Spray Pump Motor RoomVentilation(安全注入和安全喷林泵电机通风系统)DVT Demineralization Plant VentilationDVV Auxiliary Boiler and Compressor Building Ventilation（辅助锅炉和空压机厂房通风系统）DVW Peripheral Rooms Ventilation （安全壳环廊房间通风系统）DVX Lubricating Oil Transfer Plant Building Ventilation（润滑油输送装置厂房通风系统）DW A Hot Workshop and Warehouse Ventilation（热机修车间和仓库通风系统）DWB RestaurantVentilation （SA餐厅通风系统）DWC Trainning Center Ventilation （EA Building）/培训中心通风系统DWD Security Building Ventilation（保安楼通风系统）7777DWE Main Swithchyard Ventilation（主开关站通风系统）DWM EC Building Ventilation System（EC厂房暖通空调系统）ets（集中控制模拟量机柜）DWL Hot Laundry Ventilation（热洗衣房通风系统）DWM Emergency Center Ventilation System（应急中心通风系统/EM楼）DWN Site Laboratory Ventilation（厂区实验室通风系统/AL实验室）DWQ Garge & Laundry Ventilation（车库和洗衣房通风系统（AG/EL）厂房）DWS Essential ServiceWater Pumping Station Ventilation（重要厂用水泵站通风系统/PX泵站）DWT Archive & Documentation Center Ventilation(AD Building )/文档中心通风系统（AD楼）DWU Fire Fighting Training CenterV entilation（消防培训中心通风系统/EB楼）DWV Oil Storage Area V entilation （FC Building）/油料仓库通风系统（FC厂房）DWX Compressors Building Ventilation System（ZC Building）/空压机房通风系统（ZC厂房）DWY Electrochlorination Plant Ventilation（制氯站通风系统）DWZ Hydrogen Production Plant Ventilation（制氢站通风系统）8888E ContainmentEAS Containment Spray（安全壳喷淋系统）lation System（EC厂房暖通空调?rEAU Containment Instrumentation（安全壳仪表系统）EBA Containment Sweeping Ventilation（安全壳换气通风系统）EPP Containment Leakage Monitoring（安全壳泄漏监测系统）ETY Containment Atmosphere Monitoring（安全壳大气监测系统）EVC Reactor Pit Ventilation（反应堆堆坑通风系统）EVF Containment Cleanup（安全壳内空气净化系统）EVR Containment Continuous Ventilation（安全壳连续通风系统）G Turbine Generator（汽轮发电机）GCA Turbine and Feedheating Plant Preservation DuringOutage（汽机和给水加热装置停运期间的保养系统）GCT Turbine Bypass（汽机旁路系统）GEV Power Transmission（输电系统）GEW Main Swithchyard－EHV Switchgear（主开关站－超高压配电装置）GEX Generator Excitation and V oltage Regulation（发电机励磁和电压调节系统）9999GFR Turbine Control Fluid（汽机调节系统）GGR Turbine Lubrication Jaching and Turning（汽机润滑、顶轴和盘车系统）GHE Generator Seal Oil（发电机密封油系统）GME Turbine Supervisory System（汽机监视系统） GPA Generator and Power Transmission Protection（发电机和输电保护系统）GPV Turbine Steam and Drain（汽机蒸汽和疏水系统）GRE Turbine Governing（汽机调节系统）GRH Generator Hydrogen Cooling（发电机氢气冷却系统）GRV Generator Hydrogen Supply（发电机氢气供应系统）GSE Turbine Protection（汽机保护系统）GSS Moisture Separator Water（汽水分离再热器系统）GST Stator Cooling Water（发电机定子冷却水系统）GSY Grid Synchronization and Connection（同步并网系统）GTH Turbine Lube Oil Treatment（汽机润滑油处理系统）GTR TurbineGenerator Remote Control（汽轮发电机远程控制系统）10101010J Fire Protection（Detection－Fire Fighting）/消防（探测－火警）JDT Fire Detection（火警探测系统）JPD Fire Fighting Water Distribution（消防水分配系统）JPH Turbine Oil Tank Fire Protection（汽机油箱消防系统）JPI Nuclear Island Fire Protection （核岛消防系统）JPL Electrical Building Fire Protection（电气厂房消防系统）JPP Fire Fighting Water Production（消防水生产系统）JPS Mobile & Portable Fire Fighting Equipment（移动式和便携式消防设备）JPT Transformers Fire Protection（变压器灭火系统）JPU Site Fire Fighting Water Distribution（厂区消防水分配系统）JPV DieselGenerator Fire Protection（柴油发电机灭火系统）K Instrumentation and Control（仪表和控制）KBS Thermocouple Cold Junction Boxes(热电偶冷端盒系统）KCO Common Control Cabinets for Conventional Island（常规岛共用控制机柜）KDO Test Data Acquisition（试验数据采集系统）11111111KIR Loose Parts and Vibration Monitoring（松动部分和振动监测系统）KIS Seisimic Instrumentation(地震仪表系统）KIT Centralized Data Processing(集中数据处理系统）KKK Site and Building Access Control(厂区和办公楼出入监督系统）KKO Energy Metering and Perturbography(电度表和故障录波仪）KLP 500KV Line Protection 500KV （线路保护系统）KME Test Instrumentation（试验仪表系统）KPR Remote Shutdown Panel （应急停堆盘系统）KRG General Control Analog Cabinets（集中控制模拟量机柜）?房应急照明系统）KRS Site Radiation and Meteorological Monitoring(厂区辐射与气象检测系统）KRT Plant Radiation Monitoring （电厂辐射监测系统）KSA Alarm Processing（报警处理系统）KSC Main Control Room（主控制室系统）KSN Nulear Auxiliary Building－Local Control Panels and Boards（核辅助厂房－就地控制屏和控制盘）12121212KSU Security Building Control Desk（应急保安控制台系统）KZC Controlled Area Access Monitoring（控制区出入监测系统）L Electrical System（电气系统）LAA Uninterrupted 230V DC Power System（LNE）Inverter Power Supply/230V 不间断直流电源系统、逆变系统（电气厂房LNE）LAB Turbine Generator Continuous Lubrication Pump Power Supply/汽轮机不间断润滑油泵电源系统（汽机厂房）常?JPD Fire Fightin_。
热电联产中英文对照外文翻译文献
中英文对照外文翻译文献(文档含英文原文和中文翻译)外文文献:The Optimal Operation Criteria for a Gas Turbine Cogeneration System Abstract: The study demonstrated the optimal operation criteria of a gas turbine cogeneration system based on the analytical solution of a linear programming model. The optimal operation criteria gave the combination of equipment to supply electricity and steam with the minimum energy cost using the energy prices and the performance of equipment. By the comparison with a detailed optimization result of an existing cogeneration plant, it was shown that the optimal operation criteria successfully provided a direction for the system operation under the condition where the electric power output of the gas turbine was less than the capacity.Keywords: Gas turbine; Cogeneration; Optimization; Inlet air cooling.1. IntroductionCogeneration, or combined heat and power production, is suitable for industrial users who require large electricity as well as heat, to reduce energy and environmental impact. To maximize cogeneration, the system has to be operated with consideration electricity and heat demands andthe performance of equipment. The optimal operation of cogeneration systems is intricate in many cases, however, due to the following reasons. Firstly, a cogeneration system is a complex of multiple devices which are connected each other by multiple energy paths such as electricity, steam, hot water and chilled water. Secondly, the performance characteristics of equipment will be changed by external factors such as weather conditions.For example, the output and the efficiency of gas turbines depend on the inlet air temperature. Lastly,the optimal solution of operation of cogeneration systems will vary with the ratio of heat demand to electricity demand and prices of gas, oil and electricity.Because of these complexities of cogeneration systems, a number of researchers have optimal solutions of cogeneration systems using mathematical programming or other optimization techniques. Optimization work focusing on gas turbine cogeneration systems are as follows. Yokoyama et al. [1] presented optimal sizing and operational planning of a gas turbine cogeneration system using a combination of non-linear programming and mixed-integer linear programming methods. They showed the minimum annual total cost based on the optimization strategies. A similar technique was used by Beihong andWeiding [2] for optimizing the size of cogeneration plant. A numerical example of a gas turbine cogeneration system in a hospital was given and the minimization of annual total cost was illustrated. Kong et al. [3] analyzed a combined cooling, heating and power plant that consisted of a gas turbine, an absorption chiller and a heat recovery boiler. The energy cost of the system was minimized by a linear programming model and it was revealed that the optimal operational strategies depended on the load conditions as well as on the cost ratio of electricity to gas. Manolas et al. [4] applied a genetic algorithm (GA) for the optimization of an industrial cogeneration system, and examined the parameter setting of the GA on the optimization results. They concluded that the GA was successful and robust in finding the optimal operation of a cogeneration system.As well as the system optimization, the performance improvement of equipment brings energy cost reduction benefits. It is known that the electric power output and the efficiency of gas turbines decrease at high ambient temperatures. Some technical reports [5, 6] show that the electric power output of a gas turbine linearly decreases with the rise of the ambient temperature, and it varies about 5 % to 10 % with a temperature change of 10 ◦C. Therefore, cooling of the turbine inlet air enhances electric output and efficiency. Some studies have examined theperformance of the gas turbine with inlet air cooling as well as the effect of various cooling methods [7, 8, 9].The cooling can be provided without additional fuel consumption by evaporative coolers or by waste heat driven absorption chillers. The optimal operation of the system will be more complex, however, especially in the case of waste heat driven absorption chillers because the usage of the waste heat from the gas turbine has to be optimized by taking into consideration the performance of not only the gas turbine and the absorption chiller but also steam turbines, boilers and so on. The heat and electricity demands as well as the prices of electricity and fuels also influence the optimal operation.The purpose of our study is to provide criteria for optimal operation of gas turbine cogeneration systems including turbine inlet air cooling. The criteria give the minimum energy cost of the cogeneration system. The method is based on linear programming and theKuhn-Tucker conditions to examine the optimal solution, which can be applied to a wide range of cogeneration systems.2. The Criteria for the Optimal Operation of Gas Turbine Cogeneration SystemsThe criteria for the optimal operation of gas turbine cogeneration systems were examined from the Kuhn-Tucker conditions of a linear programming model [10]. A simplified gas turbine cogeneration system was modeled and the region where the optimal solution existed was illustrated on a plane of the Lagrange multipliers.2.1. The Gas Turbine Cogeneration System ModelThe gas turbine cogeneration system was expressed as a mathematical programming model. The system consisted of a gas turbine including an inlet air cooler and a heat recovery steam generator (HRSG), a steam turbine, an absorption chiller, a boiler and the electricity grid. Figure 1 shows the energy flow of the system. Electricity, process steam, and cooling for process or for air-conditioning are typical demands in industry, and they can be provided by multiple suppliers. In the analysis, cooling demands other than for inlet air cooling were not taken into account, and therefore, the absorption chiller would work only to provide inlet air cooling of the gas turbine. The electricity was treated as the electric power in kilowatts, and the steam and the chilled water were treated as the heat flow rates in kilowatts so that the energy balance can be expressed in the same units.Figure 1. The energy flow of the simplified gas turbine cogeneration system with the turbineinlet air cooling.The supplied electric power and heat flow rate of the steam should be greater than or equal to the demands, which can be expressed by Eqs. (1-2).(1)(2)where, xe and xs represent the electric power demand and the heat flow rate of the steam demand. The electric power supply from the grid, the gas turbine and the steam turbine are denoted by xG, xGT and xST, respectively. xB denotes the heat flow rate of steam from the boiler, and xAC denotes the heat flow rate of chilled water from the absorption chiller. The ratio of the heat flow rate of steam from the HRSG to the electric power from the gas turbine is denominated the steam to electricity ratio, and denoted by ρGT. Then, ρGTxGT represents the heat flow rate o f steam from the gas turbine cogeneration. The steam consumption ratios of the steam turbine and the absorption chiller are given as ωST and ωAC, respectively. The former is equivalent to the inverse of the efficiency based on the steam input, and the latter is equivalent to the inverse of the coefficient of performance.The inlet air cooling of the gas turbine enhances the maximum output from the gas turbine. By introducing the capacity of the gas turbine, XGT, the effect of the inlet air cooling was expressed by Eq. (3).(3).It was assumed that the increment of the gas turbine capacity was proportional to the heatflow rate of chilled water supplied to the gas turbine. The proportional constant is denoted byαGT.In addition to the enhancement of the gas turbine capacity, the inlet air cooling improves the electric efficiency of the gas turbine. Provided that the improvement is proportional to the heat flow rate of chilled water to the gas turbine, the fuel consumption of the gas turbine can be expressed as ωGTxGT¡βGTxAC, whereωGT is the fuel consumption ratio without the inlet air cooling and βGT is the improvement factor of the fuel consumption by the inlet air cooling. As the objective of the optimization is the minimization of the energy cost during a certain time period, Δt, the energy cost should be expressed as a function of xG, xGT, xST, xB and xAC. By defining the unit energy prices of the electricity, gas and oil as Pe, Pg and Po, respectively, the energy cost, C, can be given as:(4)where, ωB is the fuel consumpti on ratio of the boiler, which is equivalent to the inverse of the thermal efficiency.All the parameters that represent the characteristics of equipment, such as ωGT, ωST, ωAC, ωB, ρGT, αGT and βGT, were assumed to be constant so that the system could be m odeled by the linear programming. Therefore, the part load characteristics of equipment were linearly approximated.2.2. The Mathematical Formulation and the Optimal Solution From Eqs. (1–4), the optimization problem is formed as follows:(5)(6)(7)(8)where, x = (xG, xGT, xST, xB, xAC). Using the Lagrange multipliers, λ = (λ1, λ2, λ3), theobjectivefunction can be expressed by the Lagrangian, L(x,λ).(9)According to the Kuhn-Tucker conditions, x and λ satisfy the following conditions at the optimal solution.(10)(11)(12)(13)The following inequalities are derived from Eq. (10).(14)(15)(16)(17)(18)Equation (11) means that xi > 0 if the derived expression concerning the supplier i satisfies the equali ty, otherwise, xi = 0. For example, xG has a positive value if λ1 equals PeΔt. If λ1 is less than PeΔt, then xG equals zero.With regard to the constraint g3(x), it is possible to classify the gas turbine operation into two conditions.The first one is the case where the electric power from the gas turbine is less than the capacity,which means xG < XGT + αGTxAC. The second one is the case where the electric power from the gas turbine is at the maximum, which means xGT = XGT + αGTxAC. We denominate the former and the latter conditions the operational conditions I and II, respectively. Due to Eq. (12) of the Kuhn-Tucker condition, λ3 = 0 on the operational condition I, and λ3 > 0 on the operational condition II.2.3. The Optimal Solution where the Electric Power from the Gas Turbine is less than theCapacityOn the operational condition I where xG < XGT + αGTxAC, Eqs. (14–18) can be drawn on the λ1-λ2 plane because λ3 equals zero. The region surrounded by the inequalities gives the feasible solutions, and the output of the supplier i has a positive value, i.e. xi > 0, when the solution exists on the line which represents the supplier i.Figure 2 illustrates eight cases of the feasible solution region appeared on the λ1-λ2 plane. The possible optimal solutions ar e marked as the operation modes “a” to “g”. The mode a appears in the case A, where the grid electricity and the boiler are chosen at the optimal operation. In the mode b,the boiler and the steam turbine satisfy the electric power demand and the heat flow rate of the steam demand. After the case C, the electric power from the gas turbine is positive at the optimal operation.In the case C, the optimal operation is the gas turbine only (mode c), the combination of the gas turbine and the boiler (mode d) or the combination of the gas turbine and the grid electricity (mode e). In this case, the optimal operation will be chosen by the ratio of the heat flow rate of the steam demand to the electric power demand, which will be discussed later. When the line which represents the boiler does not cross the gas turbine line in the first quadrant, which is the case C’, only the modes c and e appear as the possible optimal solutions. The modes f and g appear in the cases D and E, respectively. The suppliersThe cases A through E will occur depending on the performance parameters of the suppliers and the unit energy prices. The conditions of each case can be obtained from the graphical analysis. For example, the case A occurs if λ1 at the intersection of G and B is smaller than that at the intersection of GT and B, and is smaller than that at the intersection of ST and B. In addition, the line B has to be located above the line AC so that the feasible solution region exists. Then, the following conditions can be derived.(19)(20)(21)Equation (19) means that the gas cost to produce a certain quantity of electricity and steam with the gas turbine is higher than the total of the electricity and oil costs to purchase the same quantity of electricity from the grid and to produce the same quantity of steam with the boiler.Equation (20) means that the electricity cost to purchase a certain quantity of electricity is cheaper than the oil cost to produce the same quantity of electricity using the boiler and the steam turbine. Equation (21) indicates that the reduction of the gas cost by a certain quantity of the inlet air cooling should be smaller than the oil cost to provide the same quantity of cooling using the boiler and the absorption chiller. Otherwise, the optimal solution does not exist because the reduction of the gas cost is unlimited by the inlet air cooling using the absorption chiller driven by the boiler.Figure 2. The possible cases of the optimal solution on the operational condition ISimilar ly, the following conditions can be derived for the other cases. The condition given as Eq. (21) has to be applied to all the cases below.Case B:(22)(23)Equation (22) compares the production cost of the electricity and the steam between the gas and the oil. The gas cost to produce a certain quantity of electricity and steam by the gas turbine is higher than the oil cost to produce the same quantity of electricity and steam by thecombination of the boiler and the steam turbine. Equation (23) is the opposite of Eq. (20), which means that the oil cost to produce a certain quantity of electricity by the boiler and the steam turbine is cheaper than the purchase price of electricity.Case C:(24)(25)(26)(27)Equation (24) is the opposite case of Eq. (19). Equation (25) compares the boiler and the gas turbine regarding the steam production, which is related to the mode d. In the case C, the oil cos t for the boiler is cheaper than the gas cost for the gas turbine to produce a certain quantity of steam. If the gas cost is cheaper, mode d is not a candidate for the optimal sol ution, as illustrated in the case C’. Equations (26) and (27) evaluate the effectiveness of the steam turbine and the inlet air cooling by the absorption chiller,resp ectively. The grid electricity is superior to the steam turbine and to the inlet air cooling in this case.Case D:In addition to Eq. (25),(28)(29)(30)Similarly to the case C’, the case D’ occurs if the inequality sign of Eq. (25) is reversed. Equation (28) is the opposite case of Eq. (22), which is the comparison of the electricity production between gas and oil. Equation (29) is the opposite case of Eq. (26), which is the comparison of the steam turbine and grid electricity. The gas cost to produce a certain quantity of electricity by the combination of the gas turbine and the steam turbine is cheaper than the purchase cost of the same quantity of electricity from the grid. Equation (30) gives the condition where the steam turbine is more advantageous than the inlet air cooling by the absorption chiller. The left hand side of Eq. (30) represents an additional steam required for a certain quantity of electricity production by the inlet air cooling. Therefore, Eq. (30) insists that the steam required for a certain quantity of electricity production by the steam turbine is smaller than that requiredfor the same quantity of electricity production by the inlet air cooling in this case, and it is independent of energy prices.Case E:In addition to Eq.(25),(31)(32)The case E’ occurs if Eq. (25) is reversed. Equations (31) and (32) are the opposite cases of Eqs. (27)and (30), which give the conditions where the inlet air cooling is more advantageous compared with the alternative technologies. In this case, Eq. (28) is always satisfied because of Eqs. (21) and (32).The conditions discussed above can be arranged using the relative electricity price, Pe/Pg and the relative oil price, Po/Pg. The optimal cases to be chosen are graphically shown in Figure 3 on the Po/Pg-Pe/Pg plane. When Eq. (30) is valid, Figure 3 (a) should be applied. The inlet air cooling is not an optimal option in any case. When Eq. (32) is valid, the cases E and E’ appear on the plane and the steam turbine is never chosen, as depicted in Figure 3 (b). It is noteworthy that if the inlet air cooling cannot improve the gas turbine efficiency, i.e. βGT = 0, the inlet air cooling is never the optimal solution.As the cases C, D and E include three operation modes, another criterion for the selection of the optimal operation mode is necessary in those cases. The additional criterion is related with the steam to electricity ratio, and can be derived from the consideration below.In the c ases C, D and E, λ1 and λ2 have positive values. Therefore, two of the constraints given as Eqs. (6) and (7) take the equality conditions due to the Kuhn-Tucker condition Eq. (12). Then, the two equations can be solved simultaneously for two variables which have positive values at each mode.For the mode d, the simultaneous equations can be solved under xGT, xB > 0 and xG, xST, xAC = 0.Then, one can obtain xGT = xe and xB = xs ¡ ρGTxe. Because xB has a positive value, the following condition has to be satisfied for the mode d to be selected.(33)At the mode e, one can obtain xG = xe ¡ xs/ρGT and xGT = xs/ρGT, and the following condition can be drawn out of the former expression because xG is greater than zero at this mode.(34)Similar considerations can be applied to the cases D and E. Consequently, Eq. (33) is the condition for the mode d to be selected, while Eq. (34) is the condition for the modes e, f or g to be selected. Furthermore, it is obvious that the mode c has to be chosen if the steam to electricity ratio of the gas turbine is equal to the ratio of the heat flow rate of the steam demand to the electric power demand, i.e. ρGT = xs/xe.Equations (33) and (34) mean that when the steam to electricity ratio of the gas turbine is smaller than the ratio of the heat flow rate of the steam demand to the electric power demand, the gas turbine should be operated to meet the electric power demand. Then, the boiler should balance the heat flow rate of the steam supply with the demand. On the other hand, if the steam to electricity ratio of the gas turbine is larger than the ratio of the heat flow rate of the steam demand to the electric power demand,the gas turbine has to be operated to meet the heat flow rate of the steam demand. Then, the insufficient electric power supply from the gas turbine has to be compensated by either the grid (mode e), the steam turbine (mode f), or the inlet air cooling (mode g). There is no need of any auxiliary equipment to supply additional electric power or steam if the steam to electricity ratio of the gas turbine matches the demands.Figure 3. The optimal operation cases expressed on the relative oil price-relative electricity price plane (the operational condition I).2.4. The Optimal Solution where the Electric Power from the Gas Turbine is at the MaximumIn the operational condition II, the third constraint, Eq. (8), takes the equality condition and λ3 would have a positive value. Then, Eqs. (11) and (18) yields:(35)It is reasonable to assume that ρGT ¡ !AC ®GT > 0 and ωGT ¡ ¯GT ®GT > 0 in the case ofgas turbine cogeneration systems because of relatively low electric efficiency (¼ 25 %) and a high heat to electricity ratio (ρGT > 1.4). Then, the optimal solution cases c an be defined by a similar consideration to the operational condition I, and the newly appeared cases are illustrated in Figure 4. The cases F and G can occur in the operational condition II in addition to the cases A and B of the operational condition I. Similarly to the cases C’ and D’ of the operational condition I, the cases F’ and G’ can be defined where the mode h is excluded from the cases F and G, respectively.Figure 4. The optimal solution cases on the operational condition II.In the operational condition II, the conditions of the cases A and B are slightly different from those in the operational condition I, as given below.Case A:(36)(37)Case B:(38)(39)The conditions for the cases F and G are obtained as follows.Case F:(40)(41)(42)Case G:In addition to Eq. (41),(43)(44)The case s F’ and G’ occur whenthe inequality sign of Eq. (41) is reversed. Equations (36), (38),(40), (41), (42), (43) and (44) correspond to Eqs. (19), (22), (24), (25), (26), (28) and (29), respectively.In these equations, ωGT ¡ ¯GT®GTis substituted for ωGT, an d ρGT ¡ !AC®GTis substituted for ρGT.The optimal cases of the operational condition II are illustrated on the Po/Pg-Pe/Pg plane as shown in Figure 5. Unlike the operational condition I, there is no lower limit of the relative oil price for the optimal solution to exist. The line separating the cases F and G is determined by the multiple parameters.Basically, a larger ρGT or a smaller ωST lowers the line, which causes a higher possibility for the case G to be selected.Figure 5. The optimal operation cases expressed on the relative oil price-relative electricity price plane (the operational condition II).To find the optimal mode out of three operation modes included in the cases F or G, another strategy is necessary. The additional conditions can be found by a similar examination on the variables to that done for the cases C, D and E. In the operational condition II, three variables can be analytically solved by the constraints given as Eqs. (6), (7) and (8) taking equality conditions.In the mode g, only two variables, ωGT andωAC are positive and the other variables are equal to zero.Therefore, the analytical solutions of those in the operational condition II can be obtained from equations derived from Eqs. (6) and (7) as xGT = xe and xAC = (ρGTxe ¡xs)/ωA C. Then the third constraint gives the equality condition concerning xs/xe and XGT/xe as follows:(45)where, XGT/xe represents the ratio of the gas turbine capacity to the electricity demand, and XGT/xe ·1.For mode h, the condition where this mode should be selected is derived from the analytical solution of xB with xB > 0 as follows:(46)For the mode i, xG > 0 and xAC > 0 give the following two conditions.(47)(48)For the mode j, xST > 0 and xAC > 0 give the following conditions.(49)(50)The conditions given as Eqs. (45–50) are graphically shown in Figure 6. In the cases F and G,the operational condition II cannot be applied to the region of xsxe< ρGTXGT xeand xsxe<(ωST+ρGT)XGTxe¡ωST,respectively, because xAC becomes negative in this region. The optimal operation should be found under the operational condition I in this region.3. Comparison of the Optimal Operation Criteria with a Detailed Optimization ResultTo examine the applicability of the method explained in the previous section to a practical cogeneration system, the combination of the suppliers selected by the optimal operation criteria was compared with the results of a detailed optimization of an existing plant.3.1. An Example of an Existing Energy Center of a FactoryAn energy center of an existing factory is depicted in Figure 7. The factory is located in Aichi Prefecture, Japan, and produces car-related parts. The energy center produces electricity by a combined cycle of a gas turbine and a steam turbine. The gas turbine can be fueled with either gas or kerosene, and it is equipped with an inlet air cooler. The electric power distribution system of the factory is also linked to the electricity grid so that the electricity can be purchased in case the electric power supply from the energy center is insufficient.The steam is produced from the gas turbine and boilers. The high, medium or low pressure steam is consumed in the manufacturing process as well as for the driving force of the steam turbine and absorption chillers. The absorption chillers supply chilled water for the process, air conditioning and the inlet air cooling. One of the absorption chiller can utilize hot water recovered from the low temperature waste gas of the gas turbine to enhance the heat recovery efficiency of the system.Figure 6. The selection of the optimal operation mode in the cases of F and G.3.2. The Performance Characteristics of the EquipmentThe part load characteristics of the equipment were linearly approximated so that the system could be modeled by the linear programming. The approximation lines were derived from the characteristics of the existing machines used in the energy center.The electricity and the steam generation characteristics of the gas turbine and the HRSG are shown in Figure 8, for example. The electric capacity of the gas turbine increases with lower inlet air temperatures. The quantity of generated steam is also augmented with lower inlet air temperatures.In practice, it is known that the inlet air cooling is beneficial when the purchase of the grid electricity will exceed the power contract without the augmentation of the gas turbine capacity. Furthermore, the inlet air cooling is effective when the outdoor air temperature is higher than 11 ◦C. A part of the operation of the actual gas turbine system is based on the above judgement of the operator, which is also included in the detailed optimization model.3.3. The Detailed Optimization of the Energy CenterThe optimization of the system shown in Figure 7 was performed by a software tool developed for this system. The optimization method used in the tool is the linear programming method combined with the listed start-stop patterns of equipment and with the judgement whether the inlet air cooling is on oroff. The methodology used in the tool is fully described in the reference [11].Figure 7. An energy center of a factory.Figure 8. The performance characteristics of the gas turbine and the HRSG.The Detailed Optimization MethodThe energy flow in the energy center was modeled by the linear programming. The outputs of equipment were the variables to be optimized, whose values could be varied within the lower and upper limits. To make the optimization model realistic, it is necessary to take the start-stop patterns of the equipment into account. The start-stop patterns were generated according to thepossible operation conditions of the actual energy center, and 20 patterns were chosen for the enumeration. The optimal solution was searched by the combination of the enumeration of the start-stop patterns and the linear programming method. The list of the start-stop patterns of the gas turbine and the steam turbine is given in Figure 9.The demands given in the detailed optimization are shown in Figure 10 as the ratios of the heat flow rate of the steam demand to the electric power demand on a summer day with a large electric power demand and on a winter day with a small steam demand. On the summer day, the ratio of the heat flow rate of the steam demand to the electric power demand is at a low level throughout a day. While, it is high on the winter day, and during the hours 2 to 6, the ratio exceeds 1.4 that is the steam to electricity ratio of the gas turbine.Figure 9. The start-stop patterns of the gas turbine and the steam turbine.The Plant Operation Obtained by the Detailed OptimizationThe accumulated graphs shown in Figures 11 through 14 illustrate the electric power supply and the heat flow rate of the steam supply from equipment on the summer and winter days. On the summer day, the gas turbine and the steam turbine worked at the maximum load and the electric power demand was met by the purchase from the grid for most of the day except the hours 2 to 6, at which the electric power demand was small. The inlet air cooling of the gas turbine was used only at the hours 10 and 14, at which the peak of the electric power demand existed. The steam was mainly supplied by the gas turbine, and the boiler was used only if the total heat flow rate of the steam demands by the process, the steam turbine, and the absorption。
热力发电厂的工作总结中对公司培训的建议
热力发电厂的工作总结中对公司培训的建议英文版Suggestions for Company Training in the Work Summary of Thermal Power PlantAs we reflect on the operations of our thermal power plant, it's important to identify areas where continuous improvement can lead to enhanced efficiency and safety. One such area is company training, which plays a pivotal role in ensuring the skilled workforce necessary for smooth operations.1. Current Training Status:Currently, our training programs cover basic safety procedures, equipment operation, and emergency response measures. While these are essential, there are gaps that need to be addressed to keep up with industry advancements and changing technologies.2. Recommended Enhancements:Advanced Technology Training: With the evolving landscape of thermal power generation, it's crucial to include advanced technology training in our curriculum. This includes sessions on new equipment, energy-efficient practices, and innovative maintenance techniques.RegularRefresher Courses: To maintain proficiency levels, regular refresher courses should be conducted for employees. These courses should cover both theoretical and practical aspects, ensuring that employees are up to date with the latest industry knowledge.Simulation Training: Introducing simulation training can significantly improve employees' readiness in real-time situations. This type of training allows employees to practice their skills in a safe, controlled environment, thus enhancing their confidence and response time in actual emergencies.Feedback Mechanism: A feedback mechanism should be established to gather employees' suggestions and experiences with the training program. This feedback can then be used tofurther improve the training modules, making them more relevant and effective.3. Conclusion:By investing in comprehensive and up-to-date training programs, our thermal power plant can ensure a skilled and prepared workforce that is ready to meet the challenges of the future. This, in turn, will lead to improved operational efficiency, enhanced safety, and a more competitive position within the industry.中文版热力发电厂工作总结中对公司培训的建议在回顾热力发电厂的运营情况时，我们意识到持续改进在提高效率和安全性方面的重要性。
火电厂检修总结范文
火电厂检修总结范文英文回答：Thermal Power Plant Overhaul Summary.Introduction.The overhaul of a thermal power plant is a crucial undertaking that involves the comprehensive inspection, maintenance, and replacement of vital components to ensure the continued reliability and efficiency of the plant.Planning and Preparation.Extensive planning and preparation are essential for a successful overhaul. This includes:Scheduling: Determining the optimal time for the overhaul, considering plant availability and demand.Materials and Equipment: Acquiring all necessary materials, equipment, and spare parts.Safety and Environmental Considerations: Ensuring compliance with all applicable safety and environmental regulations.Inspection and Maintenance.The core objective of an overhaul is to thoroughly inspect and maintain all critical plant components. This may include:Turbine Overhaul: Dismantling, inspecting, and reassembling the turbine, replacing worn components.Boiler Overhaul: Inspecting tubes, cleaning surfaces, and repairing or replacing damaged elements.Generator Overhaul: Inspecting windings, insulation, and bearings, and performing necessary repairs.Control and Electrical Systems: Testing and calibrating sensors, actuators, and protective devices.Replacement and Modifications.During an overhaul, it may be necessary to replace certain components that have exceeded their service life or have become obsolete. Additionally, plant modifications may be implemented to improve efficiency, reduce emissions, or enhance safety.Testing and Commissioning.After the completion of the overhaul, rigorous testing and commissioning procedures are performed to verify the functionality and performance of the plant. This includes:Cold Testing: Testing of systems without firing the boiler.Hot Testing: Testing of systems under actual operating conditions.Commissioning: Gradual transition of the plant to full load operation.Benefits.A successful overhaul provides numerous benefits, including:Increased Reliability: Reduced risk of unplanned outages and improved plant availability.Improved Efficiency: Optimization of plant performance and reduction of fuel consumption.Reduced Emissions: Implementation of technologies to minimize environmental impact.Compliance and Safety: Ensuring compliance with regulatory requirements and enhancing workplace safety.Conclusion.The overhaul of a thermal power plant is a complex and multifaceted process. By adhering to comprehensive planning, rigorous inspection and maintenance, and thorough testing, plant operators can ensure the continued safe and efficient operation of their facilities.中文回答：火电厂检修总结。
外文翻译--热力发电厂发展的替代趋势
毕业设计（论文）外文翻译外文题目Alternative trends in development of thermal powerplant 译文题目热力发电厂发展的替代趋势外文出处 Thermal engineering 28 (2008)：190-194热力发电厂发展的替代趋势摘要：热(或矿物燃料)发电厂(TPP)是污染环境的主要来源, 它向大气排放碳燃料燃烧的基本产物──二氧化碳。
正是这种气体造成了温室效应，使得全球气候变暖。
减少排入大气的二氧化碳的根本解决方法在于省电, 这样便会减少燃料燃烧量。
这种方法不管是从经济还是生态的角度看都是可行的。
不过解决这个问题最理想的做法是不燃烧任何含碳燃料,如煤、石油制品和其他有机动力资源。
这项工作的目的是概述减少热(或矿物燃料)发电厂燃料消耗量的方法，从而减少造成温室效应的排入大气的气体.。
其中一种方法在于改变工质的热物理性质，如果我们能改变传统工质,即水, 或者能采用有着完全不同热物理性质的工质，这种方法也许能变为可能。
这篇文章为一个切实可行的解决方案提供各种技术方法,如卡利纳循环，通过磁流体共振改变水的性质或在热电厂的热动力循环中采用液体在低于环境温度下沸腾的技术。
关键词：节能电源；效率；减少向环境中排放气体；热力发电厂1. 序言人类文明与科技进步历史与电力消费的增长密切相关。
基于含碳燃料消耗的热电工程发展和不断增长的电力生产是使燃料能源资源不断消耗。
热能与动力工程用煤、石油、天然气和超过1%的大气氧消耗取代SO2，NO x和CO2,这些加剧温室效应的气体来产电。
现在来看由GAO（美国总会计办公室）在2002年6月20日公布的数据[1]。
2002年，美国电站排放SO2占发电厂总排气量的59%、NO x占47%、CO2占42%，但产电量只占了总电量的42%。
为此，我们来使用一个简单的逻辑：如果旧电站产电占42%,则新电站产电占(100-42)%=58%；如果旧电站排放SO2占59%，则新电站排放的SO2占(100-59)% = 41%，各气体排放依此类推。
热电厂实习报告模板英语
Title: Thermal Power Plant Internship ReportIntroduction:This report documents my internship experience at [Company Name], a thermal power plant located in [Location]. The internship took place from [Start Date] to [End Date], during which I gained valuable insights into the operations, maintenance, and safety procedures of a thermal power plant. The following sections detail my experiences, challenges faced, and the knowledge acquired during the internship.I. Internship Objective:The primary objective of this internship was to:- Gain practical experience in the field of thermal power generation.- Understand the various processes involved in electricity generation.- Familiarize myself with safety protocols and maintenance procedures.- Develop problem-solving and teamwork skills.II. Internship Location:[Company Name], [Location][Address][Contact Information]III. Internship Duration:[Start Date] to [End Date]IV. Daily Routine:- Morning:- 08:00 AM: Report to the office and receive the daily work schedule.- 08:30 AM: Join the morning safety meeting and discuss the day's activities.- 09:00 AM: Begin assigned tasks under the supervision of senior engineers.- Afternoon:- 12:00 PM: Lunch break.- 01:00 PM: Resume work and continue with assigned tasks.- 05:00 PM: End the workday and prepare for the next day's tasks.V. Internship Activities:1. Observation of Power Generation Process:- Monitored the boiler, turbine, and generator sections.- Learned about the combustion of coal and its conversion into electricity.- Assisted in inspecting and maintaining equipment to ensure optimal performance.2. Safety Training and Protocol:- Participated in safety training sessions to understand the importance of safety in a power plant environment.- Learned about the use of personal protective equipment (PPE) and emergency response procedures.3. Maintenance and Repair Work:- Assisted in the maintenance and repair of various equipment, such as boilers, turbines, and generators.- Learned about the use of diagnostic tools and equipment to identify and resolve issues.4. Environmental Compliance:- Understood the environmental regulations and guidelines followed by the power plant.- Assisted in monitoring and managing emissions and waste disposal.VI. Challenges Faced:- Adapting to the fast-paced environment and heavy workload.- Understanding complex technical jargon and processes.- Balancing safety protocols with the need for efficiency.VII. Knowledge and Skills Gained:1. Technical Knowledge:- Enhanced understanding of the thermal power generation process.- Familiarity with various types of equipment used in power plants.- Knowledge of safety protocols and maintenance procedures.2. Soft Skills:- Improved problem-solving and critical thinking abilities.- Developed effective communication and teamwork skills.- Increased resilience and adaptability to new situations.VIII. Conclusion:The internship at [Company Name] provided me with an invaluable opportunity to gain practical experience in the field of thermal power generation. I have learned a great deal about the various processes involved in electricity generation, safety protocols, and maintenance procedures. This experience has not only enhanced my technical knowledge but also developed my soft skills, which will be beneficial in my future career.IX. Recommendations:- I recommend that [Company Name] continue to provide internships to students, as it is an excellent way to train future professionals.- I suggest that the company organize regular training sessions to improve the safety and efficiency of operations.Acknowledgments:I would like to express my sincere gratitude to [Company Name] for providing me with this internship opportunity. I am also grateful to my supervisors and colleagues for their guidance, support, and patience throughout the internship.[Your Name][Your Contact Information][Date]。
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等离子点火技术在超临界燃煤锅炉的应用及经济性分析汪汪小飞侠原创出品摘要: 本文详细介绍了等离子点火装置的构成及其点火机理，以某电厂超临界燃煤锅炉等离子改造为例，阐述了中速磨正压直吹制粉系统等离子点火装置的改造方式及运行注意事项，对等离子装置改造后的节油效果进行了经济性分析。
关键字:等离子点火 ;超临界燃煤锅炉 ;节油 ;经济性分析Abstract:The configuration and the working principles of plasma ignition system are introduced in the article. In this paper, take the reform of plasma igniter of supercritical coal-fired boiler for example, the reform of plasma ignition and the points for attention in positive pressure direct blow milling system are expatiated. Furthermore, economy analysis of the obvious economization effect on oil is described.Keywords: plasma ignition; Supercritical coal-fired boiler; fuel consumption reduction; economic benefits1 前言目前火力发电机组锅炉的启停及低负荷稳燃时耗费大量燃油，全国每年电站锅炉（不包括工业锅炉）的点火和稳燃用油估计在250万吨以上，直接费用每年超过60亿元人民币，大容量、超临界参数机组建设的快速增长，启停及稳燃用油将会骤增。
等离子点火技术对火力发电厂减少燃油、降低发电成本具有十分重要的现实意义。
20多年前，国外就开始煤粉锅炉等离子点火技术的研究。
近年来，等离子点火技术在国内受到重视并实际应用，取得了一定的效益。
等离子点火及稳燃技术已成功的应用于贫煤、劣质烟煤、烟煤和褐煤煤种；应用于50MW、100MW、125MW、200MW、300MW和600MW 机组容量等级；应用于切向燃烧直流燃烧器、墙式燃烧旋流燃烧器等燃烧方式；应用于钢球磨中储式、双进双出钢球磨直吹式、中速磨直吹式和风扇磨直吹式制粉系统。
采用等离子燃烧技术实现了燃煤锅炉启停全过程不用燃烧油，为节能降耗、建设两型企业和提高国家的能源安全作出贡献。
2 等离子点火装置简介2.1等离子点火机理等离子点火装置是利用直流电流在介质气压0.01～0.03MPa的条件下接触引弧，并在强磁场控制下获得稳定功率的直流空气等离子体，该等离子体在专门设计的燃烧器的中心燃烧筒中形成温度T＞50000K、温度梯度极大的局部高温区，煤粉颗粒通过该等离子“火核”受到高温作用，并在10-3秒内迅速释放出挥发物，使煤粉颗粒破裂粉碎，从而迅速燃烧。
由于反应是在气相中进行，使混合物组分的粒级发生了变化。
因而使煤粉的燃烧速度加快，也有助于加速煤粉的燃烧，这样就大大地减少促使煤粉燃烧所需要的引燃能量。
等离子体内含有大量化学活性的粒子，如原子（C、H、O）、原子团（OH、H2、O2）、离子（O2-、H2-、OH-、O-、H+）和电子等，可加速热化学转换，促进燃料完全燃烧。
2.2等离子发生器的组成以DLZ-200型等离子发生器为例，该型为磁稳、空气载体等离子发生器，它由线圈、阴极、阳极等组成。
其中阴、阳极材料均采用具有高导电率、高导热、耐氧化的金属材料制成。
阴、阳极均采用水冷方式冷却，以承受电弧高温冲击。
线圈在高温250℃情况下具有抗2000V的直流电压击穿能力，电源采用全波整流并具有恒流性能。
2.3等离子发生器的工作原理等离子发生器的点火原理为：在冷却水及压缩空气满足条件后，首先设定电源(6)的工作输出电流(300～400A)，在一定输出电流条件下，当阴极(2)在直线电机(5)的推动下，与阳极(1)接触后，电源(6)按设定的工作电流矢能工作，当输出电流达到工作电流后，直线电机(5)推动阴极(2)向后移动，当阴极离开阳极的瞬间，电弧建立起来，当阴极达到规定的放电间距后，在空气动力和磁场的作用下，装置产生稳定的电弧放电，生成等离子体。
等离子点火装置的阴极进退执行机构的控制、电弧电功率的控制，冷却风、冷却水的监视均由计算机控制系统完成。
2.4等离子点火装置的附属系统为保护等离子装置本身，需用水冷却阴、阳极和线圈。
等离子冷却水系统水源取自闭式冷却水，经升压泵后分别送至就地点火发生器内，再分三路分别送入线圈和阴、阳极。
等离子发生器采用稳压、洁净、干燥的空气作为等离子载体，一般采用高压离心风机出口高压风系统为等离子发生器提供载体，设计上还有压缩空气作为备用气源。
在等离子点火器停止工作以后，高压离心风机继续工作，为等离子点火器、图像火检探头供冷却风。
为监视等离子点火燃烧器的火焰情况，方便运行人员进行燃烧调整，在等离子点火燃烧器上各安装一套图像火检装置，其视频信号送至集控室内大屏幕，运行人员可在点火初期同时监视五个等离子点火燃烧器的火焰，并可以随时切换至全炉膛火焰。
图像火检探头的冷却风取自等离子载体系统的高压离心风机出口。
2.5 煤粉的着火特性与直接点燃煤粉的基本条件在低炉膛温度下，含粉射流无法靠卷吸炉内热烟气加热点燃，必须靠自身火焰传播作用，促使射流全都着火。
试验研究结果证明，煤粉空气混合物的火焰传播速度主要与煤质、煤粉细度和煤粉浓度有关。
图2-2是一种挥发分为36.1%的煤粉在两种煤粉细度下浓度与层流火焰传播速度的关系，说明煤粉细度和浓度对火焰传播速度影响很大，火焰传播速度最大的区域是浓度为0.3～0.5kg/kg的煤粉；细煤粉的火焰传播速度高于粗煤粉。
在煤质和煤粉细度一定的条件下，通过热态试验结果表明，一次风粉温度和点火区域的一次风粉速度对点火也有很大的影响。
在常温条件下不易点燃的贫煤和褐煤需用热风送粉，一次风温一般为70℃左右。
点火区域的速度随煤种而异，不宜过高。
试验证明，影响煤粉火焰传播速度的主要因素是煤粉的挥发分含量、灰分含量、细度和浓度；同时证明，在较难燃烧的煤粉中加入一部分易燃的燃料，可改善其燃烧特性。
综上所述，直接点燃煤粉的基本条件为：在一定煤质的条件下，合适的煤粉浓度、煤粉细度、一次风温度和点火区域的风速度。
3 等离子点火技术的实际应用针对不同锅炉的燃烧器，等离子点火装置应有针对性的设计方案。
某发电公司#1、2机组锅炉为哈尔滨锅炉厂生产的超临界参数变压直流炉，型式为单炉膛、一次再热、平衡通风、露天布置、固态排渣煤粉炉。
每台炉设2台动叶可调轴流式一次风机，2台动叶可调轴流式送风机以及2台静叶可调引风机；每台炉配6台HP中速磨机，采用中速磨正压直吹、冷一次风机制粉系统；采用容克式三分仓回转空气预热器，并配置双室五电场静电除尘器；两台炉合用一座钢筋混凝土烟囱。
为了达到在机组调试及生产期间节约燃油的目的，将锅炉厂生产的喷燃器油枪改造为等离子点火设备。
锅炉采用的等离子点火系统由等离子点火设备及其辅助系统组成，等离子点火设备由等离子发生器、等离子燃烧器、电源控制柜、隔离变压器等组成，辅助系统由载体空气系统、冷却水系统、图像火检系统、热控系统、冷炉制粉系统等组成。
表1 锅炉煤质表根据锅炉LNASB型燃烧器的结构特点，基于要求等离子改造对锅炉的性能影响最小同时改造工作量最小的原则，为了最大限度地保证原燃烧器的设计性能，改造方案为：拆除前墙下层原燃烧器的中心风管及其内部的油枪（共5支），将其替换为可实现分级点火的等离子点火燃烧器，在原一次风管上加装分叉管，引出部分煤粉为等离子燃烧器供粉。
改造后的等离子点火燃烧器具有在锅炉启动初期点火的功能，并具有原煤粉燃烧器的全部功能，不影响锅炉的安全和出力。
在锅炉点火启动阶段，一次风分叉管上的插板门打开，原一次风管内的部分煤粉通过分叉管被引至等离子点火燃烧器，在这里煤粉被等离子电弧点燃并喷入炉膛；一次风管内剩余的煤粉继续沿一次风管进入原燃烧器的一次风室，并向前喷入炉膛后被等离子燃烧器所产生的煤粉火焰点燃。
在锅炉高负荷运行阶段，一次风分叉管上的气动插板门关闭，所有煤粉仍按原设计路径进入燃烧器的一次风室，燃烧器完全按原设计方式运行。
等离子点火燃烧器的外形尺寸完全按照原燃烧器的中心风管设计，现场改造只需将前墙下层燃烧器中心风管从燃烧器后端抽出，将等离子燃烧器插入即可，安装工作量很小。
由于未对原燃烧器的一次风、二次风部分做任何改造，所以燃烧器在正常运行时性能与原设计基本相同，不会对锅炉性能造成任何不良影响。
采用直吹式制粉系统的锅炉在安装等离子点火系统时所要解决的首要问题就是在锅炉冷态启动条件下使磨煤机具备启动条件，并磨制出合格的煤粉。
根据锅炉燃用煤种的情况，在A磨煤机入口热风管道加装蒸汽加热器，在锅炉冷态启动时利用蒸汽将磨入口热风温度加热到制粉需要的温度。
蒸汽加热器的汽源取自厂用高压辅助蒸汽，参数为1.3MPa(a)、320℃；加热器进口空气温度为30℃，出口可加热至160～170℃，满足磨煤机需要的入口温度，暖风器疏水经疏水阀后排至启动疏水扩容器。
等离子点火装置改造后的运行注意事项：1）由于等离子煤粉点火装置首次应用于超临界直流锅炉，等离子煤粉点火首次投入前，油枪带负荷在15% BMCR以上，根据调试情况，等离子煤粉点火投入前油枪投入负荷可适当降低。
2）考虑锅炉水冷壁螺旋管圈、张力板温差因素，运行中相邻水冷壁与张力板壁温差应严格控制在40℃以内。
3）在锅炉启动过程中投入等离子煤粉点火装置时应注意升温升压速率，按机组启动曲线进行。
4）运行中应重视燃烧器可能产生的烧损或结焦，在调试运行中加强监控。
4 经济性分析该发电公司超临界燃煤发电机组锅炉等离子燃烧器改造后运行稳定，经调试后基本实现了无油点火启动，在基建、生产期间节约了大量燃油。
#1机组在启动前调节级缸温度270℃，温态启动共耗油56吨。
在整个机组启动过程中，等离子制粉系统一直拉弧助燃运行直至锅炉断油，运行时间为10小时，节省燃油1.3×5×10=65吨，其节油效果非常明显。
等离子点火系统用电量很小，一台等离子制粉系统点火装置每小时耗电量约830kWh，等离子冷却水泵30kWh、冷却风机11kWwh，共870kWh，按0.6元/kWh计算每小时电费522元；如果投入油枪，按每小时消耗燃油6.5吨测算，每小时耗油费用是6.5×5500=35750元，一次温态启动共节省燃油费用35.2万元，经济效益明显。