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An option for solar thermal repowering of fossil fuel fired power plants
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Solar Energy 85 (2011) 344–349 www.elsevier.com/locate/solener
An option for solar thermal repowering of fossil fuel fired power plants Dimityr Popov ⇑ Technical University of Sofia, Thermal and Nuclear Power Engineering Department, Kliment Ohridski, 8, bl. 2, EMF, 1000 Sofia, Bulgaria Received 18 February 2010; received in revised form 30 September 2010; accepted 18 November 2010 Available online 21 December 2010 Communicated by: Associate Editor Robert Pitz-Paal
Abstract Global climate change urges immediate measures to be taken to limit greenhouse gas emission coming from the fossil fuel fired power plants. Solar thermal energy can be involved in different ways in existing power generation plants in order to replace heat produced by fossil fuels. Solar field feed water preheating is mainly discussed in this paper as an option for fast and feasible RES penetration. Rankine regenerative steam cycled power plant has been modelled with Thermoflow software. The plant model incorporates also a field with solar Fresnel collectors that directly heats boiler’s feed water. The proposed plant modification yields substantial fossil fuel input reduction. The best results can be obtained when the group of high pressure heaters is replaced and feed water temperature exceeds its original design value. The solar power generation share can reach up to 23% of the power plant capacity in this case, having efficiency higher than 39% for the best solar hour of the year. Ó 2010 Elsevier Ltd. All rights reserved. Keywords: Solar thermal power; Fossil fuels; Rankine regenerative cycle; Repowering; High pressure heaters; Fresnel collectors
1. Introduction Global climate change urges immediate measures to be taken in order to limit greenhouse gas emission coming from the fossil fuel fired power plants. Combining many of the available solar energy conversion technologies with conventional fossil-fueled power plants could reduce fuel costs while simultaneously helping utilities that are struggling to meet their CO2 emissions reduction targets. Combining solar thermal and fossil-fuel energy in one system is not a new concept. It is well know that most of the first solar energy generating system (SEGS) power plants in California use natural gas as a backup energy source. The most recent concepts integrate concentrated solar thermal energy into modern gas turbine based combined cycles. The integrated solar-combined cycle system (ISCC) calls for part of the heat recovery steam generator to be ⇑ Tel./fax: +35929652303.
E-mail address: dpopov@tu-sofia.bg 0038-092X/$ - see front matter Ó 2010 Elsevier Ltd. All rights reserved. doi:10.1016/j.solener.2010.11.017
either replaced or paralleled by equipment serviced by solar thermal energy to supplement turbine exhaust gases. This approach increases thermal energy input which produces more electrical output. Four ISCC projects were under construction at the end of 2008 in USA, Egypt, Algeria and Morocco summing up to a capacity of 140 MW. But the modern gas turbine based combined cycles plants uniformly have very high thermal efficiency and the smallest carbon footprint of any fossil-fueled generation technology nowadays. At the same time there is large fleet of conventional Rankine regenerative steam cycled power plant worldwide. These plants are usually coal fired – although in some regions they are heavy oil fired – and contribute to global warming in a greatest extent. All of the electrical power produced in a conventional steam plant is produced by burning fossil fuels. This fact can be very advantageous for a hybrid cycle in which solar energy displaces fossil-fuel energy. In addition, boiler efficiency typically increases slightly as boiler load is reduced, so using solar energy to
D. Popov / Solar Energy 85 (2011) 344–349
reduce boiler load to save fuel is an added advantage. Solar repowering could be very beneficial in this case both in terms of fuel costs reduction and faster RES penetration. 2. Solar repowering options Steam power plant repowering is not a new proposition. It is usually associated with gas turbine addition to the existing plant in order to increase its efficiency and lifetime. In this way, every coal fired plant can be converted into combined cycle plant, where the hot gas turbine exhaust gas delivers heat input to the steam cycle. The same approach can be applied with heat input coming from solar thermal generation field located in the vicinity of plant. Determining how to technically integrate solar heat into the existed conventional steam plant is the first step in the design process. A very simple introductory option could be the replacement of the plant auxiliary steam system with Direct Solar Steam Generation process. The function of the auxiliary steam system usually is to provide a dependable source of steam to the following plant systems: steam heavy fuel oil heaters, steam air heaters, turbine gland steam, air ejectors, deaerator, burners, soot blowers and thermal seawater desalination system for process water and boiler makeup if applicable. The auxiliary steam system itself can be supplied from several sources depending on the unit status and boiler pressure. The system can receive steam from the unit’s main steam line, the unit’s cold reheat steam line or from the next unit auxiliary steam header. High pressure steams from the main steam line or from the cold reheat line flows in through a pressure control valve. The auxiliary steam header distributes steam with typical parameters: pressure of 10 to 15 bar and temperature up to 230 °C. The auxiliary steam consumption can reach up to 2% to 3% of the actual steam output of the boiler. The exemplary heavy fuel oil fired 130 MW unit located in Cyprus is served by a boiler producing up to 390 tons of superheated steam per hour. It means that the auxiliary steam flow is almost 12 t/h. This amount can be easily produced with on the market available direct solar steam generation equipment (Mills and Morrison, 1999; Ha¨berle et al., 2002). A solar field with a capacity of only 8 MWt, based on Fresnel collector technology can feed the plant’s unit auxiliary steam header and saves a ton of heavy fuel oil per hour. The anticipated fuel saving is based on moderate heavy fuel oil preheating up to 100 °C. Further fuel temperature raise up to 180 °C will need more auxiliary steam or respectively more solar heat input and will result in bigger saving. This solar repowering option although with very limited scope can be feasible approach when there is not enough flat land around the plant for large solar field location. It is also very interesting for the utilities that would like to test a given CSP technology before deployment of large scale solar power project. The most radical approach in integrating solar heat into the Rankine cycle plant is boiler replacement partially or
345
fully with appropriate solar based steam generation facility (Ugolini et al., 2009). A typical subcritical Rankine cycle power plant has turbine throttle steam conditions of 16 MPa and 540 °C. A steam with such of parameters could be generated by high-temperature solar technology like solar tower or advanced parabolic trough collectors. The admission of solar-generated superheated steam directly into the high pressure steam line to the steam turbine is a beneficial option in this case. But the state of the art solar steam conditions are far below the aforementioned level. For example, the most recent AndaSol project in Spain, demonstrates turbine inlet conditions of 10 MPa and 370 °C (Aringhoff et al., 2002). Obviously real solar based fossil fuel fired boiler replacement is a long term task. Some solar energy options assume the thermal energy produced by a CSP system will heat feedwater to displace turbine extraction steam to the feed water heaters. Reducing or eliminating extraction steam to feed water heaters appears to be the most practical application for mediumtemperature solar integration, as it avoids complex issues of direct steam generation and integration with the boiler and its controls. Furthermore, such of hybridization will save fuel when the solar system is available, and has inherent backup via fossil fuel when the solar system is unavailable. This approach has been discussed regularly in the recent 10 years (Ying and Hu, 1999; Morrison et al., 1999; Hu et al., 2003, 2009; Bockamp et al., 2003; Morin et al., 2004; Yinghong et al., 2007). A project in very advanced stage is located at the coal fired power plant Liddell in New South Wales in Australia. Fresnel collectors are used to generate saturated steam. This steam is intended to supply feed water heater. Testing operation of 1 MWt solar field started in 2004. As the second phase of this project, a 9-MWt solar thermal steam system has been constructed. But this effort is still aimed at solar steam generation although this steam will be used for feed water preheating. The present study is going to analyze comprehensively different direct solar feed water preheating options. 3. Solar heated feed water preheating options Conventional power plants consist of a boiler, using usually either coal or heavy oil that supplies steam to a multi-stage turbine-generator exhausting to a condenser at high vacuum. From there, the condensate is pumped through a number of feed water heaters that utilize steam extracted from progressively higher pressure stages of the turbine, until the final feed water temperature is increased as high as possible consistent with design of the steam boiler, or economic considerations of the cycle. The foregoing, commonly referred to as regenerative feed water heating, results in a high cycle efficiency being primarily dependent upon the number of extraction points and feed water heaters that it is economically feasible to utilize. The customary feed water cycle consists of two series of heaters: LP Heaters and HP Heaters (see Fig. 1.).
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D. Popov / Solar Energy 85 (2011) 344–349
Fig. 1. Schematic diagram of ordinary steam turbine plant.
The low pressures heaters group consists of up to four heat exchangers. After passing these heaters the condensate is degasified in direct contact heater/deaerator. The high pressures heaters group consists of up to three heat exchangers usually fed with high temperature superheated steam coming from high and intermediate pressure turbines. The feed water is further heated up in the boiler’s economizer. From the practical point of view the direct solar feed water preheating process in existing power plant can be accomplished in three different arrangements: LP heaters replaced by solar field consisting of water based solar collectors. HP heaters replaced by similar solar field. HP heaters and economizer replaced by solar field heating. As a result of this replacement, reduction or elimination of the extraction steam will occur. This non-extracted steam will expand in the respective turbine stages and finally will be exhausted to the condenser. In this way some turbine stages can be overloaded due to surplus steam flow. This is especially true for the LP turbine last stages. Such mode of operation is not new for the turbine practice. It occurs occasionally when some feed water heaters are out of operation due to different reasons. In order, any damage to be avoided in the last stages of the turbine, the original equipment manufacturers usually impose capacity limitations in this case. It means that when some feed water heaters are out of operation the steam flow at the turbine inlet has to be reduced in order steam volumetric flow in the last turbine stages to be kept at its design point. It is clear that the same approach has to be applied in our case when a group of feed heaters is planed to be switched off and replaced by solar field. In other words, steam turbine capacity must be unavoidable reduced. Nevertheless, eliminating extraction steam to feed water heaters may result in large fuel savings as the boiler steam output will be
reduced. In order to estimate the anticipated effects hybrid power plant model has to be developed. One of the key questions in this modeling work is the selection of appropriate CSP technology. Parabolic trough solar collectors are proven enough and commercially available as thermal oil heaters. It is clear that using such of collectors for water heating will need a little but some developments efforts. Since the beginning of their introduction Fresnel solar collectors have been developed as water based system (Mills, 2004). The fixed absorption tubes of the linear Fresnel collectors do not need heat or pressure resistant joints. Therefore, the pressure limitations that are inherent to parabolic trough technology can be avoided. This factor is very important as the feed water pressure is usually very high. As a result the linear Fresnel solar concentrating technology has been selected in this study as more suitable for feed water preheating. 4. Computation of fossil fuel fired plant repowered with solar feed water preheating One of the best computational tools suitable for detailed power plant engineering is created by Thermoflow, Inc. Its software THERMOFLEX is a modular program with a graphical interface that allows one to assemble a model from icons representing over one hundred and seventy-five different components. The program covers both design and off-design simulation, and models all types of power plants, including combined cycles, conventional steam cycles, and repowering. The latest THERMOFLEX version 20 has been used in this study as it includes a number of features to model solar thermal power and heating cycles. It provides design point heat balance, physical equipment size, off-design performance, and cost estimates for parabolic trough collector fields, linear Fresnel collector fields and related components (Griffin et al., 2009). A theoretical sun-atmosphere model with latitude, time of day, day of year, and haze index that is also provided with the aforementioned program was used for solar characteristics calculation. Vasilikos Power Station located in Cyprus on a site with latitude 34° north has been selected as a base case in this study. It has 130 MW gross capacity, a boiler with superheated steam output of 390 t/h and steam turbine throttle steam conditions of 14 MPa and 540 °C. The estimated site peaking Direct Normal Irradiance is 860.2 W/ m2. Overall computational work has been split in four cases: A. Base case calculations in design and off-design mode. B. Off-design calculations of case A plant with LP heaters replaced by solar field. This case assumes solar feed water preheating from about 34 °C up to 159 °C; C. Off-design calculations of case A plant with HP heaters replaced by solar field. This case assumes feed water preheating from about 168 °C up to 249 °C (see in Fig. 2);
D. Popov / Solar Energy 85 (2011) 344–349
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Fig. 2. Computational diagram of 130 MW power plant repowered with solar field for feed water preheating.
D. Off-design calculations of case A plant with HP heaters replaced by solar field. The boiler’s economizer is also but partially replaced by large solar field. This case assumes feed water preheating from about 168 °C up to 319 °C During case A design calculations, all power plant main parameters were computed. In this way, last turbine stages steam flow was determined. Several off-design calculations with heavy fuel oil inputs lower than its design value were also done. During case B calculations LP heaters was replaced by solar field performing direct feed water preheating. Boiler’s steam output has been progressively cut in order to avoid last turbine stages overloading. Corresponding heavy fuel oil input was fixed at a lower level. As a result plant’s gross and net capacity was reduced. The anticipated solar field model was run in thermodynamic and engineering design mode for the best solar hour of the year. Solar field capacity and basic configuration were determined. During case C calculations HP heaters was replaced by solar field performing direct feed water preheating. Boiler’s steam output has been progressively cut in order to avoid last turbine stages overloading. Corresponding heavy fuel oil input was fixed at a level lower than its design value. As a result plant’s gross and net capacity was again reduced. The anticipated solar field model was run in thermodynamic and engineering design mode for the best solar hour of the year. Solar field capacity and basic configuration were determined. During case D calculations HP heaters fully and economizer partially were replaced by solar field performing direct feed water preheating. The feed water outlet temperature was fixed at level of 319 °C in order economizer’s steaming to be avoided. Boiler’s steam output has been
progressively cut in order to avoid last turbine stages overloading. Corresponding heavy fuel oil input was fixed at a lower level. The anticipated solar field model was run in thermodynamic and engineering design mode for the best solar hour of the year. Solar field capacity and basic configuration were determined. Solar power generation share has been calculated in the following manner. As stated above, fuel inputs for cases B, C and D were determined. Case A in off-design mode was run after that with the fuels inputs coming from cases B, C and D. In this way, power generation based on fossil fuel heat input only was calculated. The differences between the capacities coming from the calculations of the cases B, C and D and the capacities generated by the same heavy fuel oil inputs without solar input (case A computational scheme) represent the actual solar heat based power generation. The results for the best solar hour of the year along with the total solar field installed costs are summarized in Table 1. The results indicate that case B is the worst option especially with regard to the imposed large reduction in electric capacity. This case was excluded from further evaluation. Cases C and D look very promising and their off-design models were used to simulate 24-h base load operation for 1 year by simulating 8760 cases. The purpose of this simulation was to obtain data in terms of energy on yearly basis. This information was used to make a comparison between different hybrid plant options and the same plant, fired with fossil fuel only. Table 2 shows a summary of the results. In order to have the same net power generation output the base case A annual operating hours has been slightly reduced. As expected over the course of the year, all cases have almost the same power generation but the solar fields added cases C and D consume less fuel. Based on pricing
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D. Popov / Solar Energy 85 (2011) 344–349
Table 1 Basic engineering summary of the repowered fossil fuel power plant at solar field design point. Key repowering parameters
Solar repowering options
Solar heat input (kW) Net fuel input (kW) Net unit capacity (kW) Solar power generation (kW) Net electric efficiency (%) Solar heat to power efficiency (%) Collector field required land area (ha) Total active aperture area (m2) Installed solar field total cost (MM US$) Specific solar adder capital cost (US$/kW)
A
B
C
D
0 341,925 122,156 0 35.67 0 0 0 0 0
39,522 276,248 104,352 6818 33.05 17.25 17.71 81,807 21,778 3194
33,721 295,252 116,418 11,476 35.39 34.03 15.03 64,280 17,112 1491
67,906 259,675 116,912 26,642 35.69 39.23 28.06 129,656 34,516 1295
Table 2 Summary comparison of year long simulations of cases C and D versus base case. Simulation parameters on annual basis
Solar repowering options A
C
D
Operating hours (h) Net Power (MW h) Heavy fuel oil input (tons) Fuel savings (tons) CO2 emission avoided (tons)
8674 10,59,594 259,960 0 0
8760 10,59,490 254,465 5495 17,419
8760 10,59,700 247,815 12,145 38,728
for the proposed plant location (Middle East) the heavy fuel oil price in the recent month can be fixed at about 435 US$ per ton (source: http://www.bunkerworld.com/ markets/prices/ae/fjr/). Using this fuel price, the C option generates an incremental revenue of 2.39 MM US$ per year due to fuel saving while the D option generates up to 5.28 MM US$ per year. This translates to about 7.2 years to repay the incremental capital cost of the case C and 6.5 of the case D. This analysis is conservative. A more refined analysis would include a price premium for solar power, other renewable incentives, and perhaps CO2 reduction credits if applicable. Nonetheless, until fuel prices rise to reflect fuel’s intrinsic value, and the price of power naturally follows, the economics of solar power produced or fuel savings alone, can foster the proposed solarhybridization development. 5. Conclusions The obtained results clearly indicate case B as the worst scenario for the proposed solar repowering. LP heaters replaced with solar field feed water prehearing need large power generation capacity reduction and very limited solar input. The most attractive option is case D especially for the future power plants. The group of high pressure heaters is replaced and feed water temperature exceeds its original design value within this option. The solar power generation share can reach up to 25% of the power plant capacity, having instant efficiency higher than 39% at design point. The weak side is the need of very large plot of flat land
in the vicinity of the plant for solar field location. Some special boiler designs rely on steaming economizers. This design feature may put obstacle in the proposed extended solar feed water preheating in existing plants as the economizer tubes could be overheated in this case. But this problem could be surmounted if the case D mode of operation is envisaged at new plant design phase. Case D is also attractive with its smallest carbon footprint. The best option for existing plants solar repowering is case C. It needs almost “zero” power plant modification and proposes large solar power generation share, large fossil fuel savings and high power plant efficiency. This efficiency would be far higher if the plant is operated at partial load during the night, and would be lower in locations with poorer solar characteristics. From a fuel consumption viewpoint, this plant modification has good solar leverage. References Aringhoff, R., Geyer, M., Herrmann, U., Kistner, R., Nava P., Osuna, R., 2002. AndaSol – 50MW solar plants with 9 hour storage for southern Spain. In: Proceedings of 11th SolarPACES International Symposium, Zurich, Switzerland, 4–6 September 2002, pp. 37–42. Bockamp, S., Griestop, T., Fruth, M., Ewert, M., Lerchenmu¨ller, H., Mertins, M., Morin, G., Ha¨berle A., Dersch, J., 2003. Solar thermal power generation. Presented at Power-Gen Europe 2003, Du¨sseldorf, Germany.. Griffin, P., Huschka, K., Morin, G., 2009. Software for design, simulation and cost estimation of solar thermal power and heat cycles. In: Proceedings of the SolarPACES 2009 Conference in Berlin, Germany. . Ha¨berle, A., Zahler, C., Lerchenmu¨ller, H., Mertins, M., Wittwer, C., Trieb, F., Dersch, Ju¨rgen, 2002. The Solarmundo line focussing Fresnel collector. Optical and thermal performance and cost calculations. In: Proceedings of 11th SolarPACES International Symposium, 4–6 September 2002, Zurich, Switzerland. . Hu, E., Yang, Y., Nishimura, A., Yilmaz, F., Kouzani, A., in press. Solar thermal aided power generation. Applied Energy.
D. Popov / Solar Energy 85 (2011) 344–349 fmt=high&_orig=search&_sort=d&_docanchor=&view=c&_search StrId=1208663696&_rerunOrigin=google&_acct=C000061252&_vers ion=1&_urlVersion=0&_userid=3738940&md5=d4db3830563cadee6 58565bcf22e2dee#secx6>. Hu, E.J., Mills, D., Morrison, G., Lievre, P., 2003. Solar power boosting of fossil fuelled power plant. In: Proceedings ISES 2003, Go¨teborg, June 14–19, 2003.. Mills, D., Morrison, G.L., 1999. Compact linear Fresnel reflector solar thermal power plants. Solar Energy 68, 263–283. Mills, D., 2004. Advances in solar thermal electricity technology. Solar Energy 76 (1–3), 19–31, . Morin, G., Lerchenmu¨ller, H., Mertins, M., Ewert, M., Fruth, M., Bockamp, S., Griestop T., Ha¨berle, A., 2004. Plug-in strategy for market introduction of Fresnel-collectors. In: 12th International Symposium SolarPaces, 2004. .
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Morrison, G., Mills, D., Corporatio, Stanwell, 1999. Solar thermal power systems – stanwell power station project. In: Proceedings of the ANZSES Annual Conference, Geelong 1999.. Ugolini, D., Zachary, J., Park, H.J., 2009. Fossil Fuels + Solar Energy = The Future of Electricity Generation. Power Business and Technology for the Global Generation Industry. Official Publication of Electric Power Conferences & Exhibitions, April 1, 2009. . Yinghong, C., Yongping, Y., Juan, C., 2007. Utilization of solar energy in a coal-fired plant. Challenges of power engineering and environment. In: Proceedings of the International Conference on Power Engineering 2007. . Ying, Y., Hu, E., 1999. Thermodynamic advantages of using solar energy in the regenerative Rankine power plant. Applied Thermal Engineering 19 (11), 1173–1180, .
Solar Energy 85 (2011) 344–349 www.elsevier.com/locate/solener
An option for solar thermal repowering of fossil fuel fired power plants Dimityr Popov ⇑ Technical University of Sofia, Thermal and Nuclear Power Engineering Department, Kliment Ohridski, 8, bl. 2, EMF, 1000 Sofia, Bulgaria Received 18 February 2010; received in revised form 30 September 2010; accepted 18 November 2010 Available online 21 December 2010 Communicated by: Associate Editor Robert Pitz-Paal
Abstract Global climate change urges immediate measures to be taken to limit greenhouse gas emission coming from the fossil fuel fired power plants. Solar thermal energy can be involved in different ways in existing power generation plants in order to replace heat produced by fossil fuels. Solar field feed water preheating is mainly discussed in this paper as an option for fast and feasible RES penetration. Rankine regenerative steam cycled power plant has been modelled with Thermoflow software. The plant model incorporates also a field with solar Fresnel collectors that directly heats boiler’s feed water. The proposed plant modification yields substantial fossil fuel input reduction. The best results can be obtained when the group of high pressure heaters is replaced and feed water temperature exceeds its original design value. The solar power generation share can reach up to 23% of the power plant capacity in this case, having efficiency higher than 39% for the best solar hour of the year. Ó 2010 Elsevier Ltd. All rights reserved. Keywords: Solar thermal power; Fossil fuels; Rankine regenerative cycle; Repowering; High pressure heaters; Fresnel collectors
1. Introduction Global climate change urges immediate measures to be taken in order to limit greenhouse gas emission coming from the fossil fuel fired power plants. Combining many of the available solar energy conversion technologies with conventional fossil-fueled power plants could reduce fuel costs while simultaneously helping utilities that are struggling to meet their CO2 emissions reduction targets. Combining solar thermal and fossil-fuel energy in one system is not a new concept. It is well know that most of the first solar energy generating system (SEGS) power plants in California use natural gas as a backup energy source. The most recent concepts integrate concentrated solar thermal energy into modern gas turbine based combined cycles. The integrated solar-combined cycle system (ISCC) calls for part of the heat recovery steam generator to be ⇑ Tel./fax: +35929652303.
E-mail address: dpopov@tu-sofia.bg 0038-092X/$ - see front matter Ó 2010 Elsevier Ltd. All rights reserved. doi:10.1016/j.solener.2010.11.017
either replaced or paralleled by equipment serviced by solar thermal energy to supplement turbine exhaust gases. This approach increases thermal energy input which produces more electrical output. Four ISCC projects were under construction at the end of 2008 in USA, Egypt, Algeria and Morocco summing up to a capacity of 140 MW. But the modern gas turbine based combined cycles plants uniformly have very high thermal efficiency and the smallest carbon footprint of any fossil-fueled generation technology nowadays. At the same time there is large fleet of conventional Rankine regenerative steam cycled power plant worldwide. These plants are usually coal fired – although in some regions they are heavy oil fired – and contribute to global warming in a greatest extent. All of the electrical power produced in a conventional steam plant is produced by burning fossil fuels. This fact can be very advantageous for a hybrid cycle in which solar energy displaces fossil-fuel energy. In addition, boiler efficiency typically increases slightly as boiler load is reduced, so using solar energy to
D. Popov / Solar Energy 85 (2011) 344–349
reduce boiler load to save fuel is an added advantage. Solar repowering could be very beneficial in this case both in terms of fuel costs reduction and faster RES penetration. 2. Solar repowering options Steam power plant repowering is not a new proposition. It is usually associated with gas turbine addition to the existing plant in order to increase its efficiency and lifetime. In this way, every coal fired plant can be converted into combined cycle plant, where the hot gas turbine exhaust gas delivers heat input to the steam cycle. The same approach can be applied with heat input coming from solar thermal generation field located in the vicinity of plant. Determining how to technically integrate solar heat into the existed conventional steam plant is the first step in the design process. A very simple introductory option could be the replacement of the plant auxiliary steam system with Direct Solar Steam Generation process. The function of the auxiliary steam system usually is to provide a dependable source of steam to the following plant systems: steam heavy fuel oil heaters, steam air heaters, turbine gland steam, air ejectors, deaerator, burners, soot blowers and thermal seawater desalination system for process water and boiler makeup if applicable. The auxiliary steam system itself can be supplied from several sources depending on the unit status and boiler pressure. The system can receive steam from the unit’s main steam line, the unit’s cold reheat steam line or from the next unit auxiliary steam header. High pressure steams from the main steam line or from the cold reheat line flows in through a pressure control valve. The auxiliary steam header distributes steam with typical parameters: pressure of 10 to 15 bar and temperature up to 230 °C. The auxiliary steam consumption can reach up to 2% to 3% of the actual steam output of the boiler. The exemplary heavy fuel oil fired 130 MW unit located in Cyprus is served by a boiler producing up to 390 tons of superheated steam per hour. It means that the auxiliary steam flow is almost 12 t/h. This amount can be easily produced with on the market available direct solar steam generation equipment (Mills and Morrison, 1999; Ha¨berle et al., 2002). A solar field with a capacity of only 8 MWt, based on Fresnel collector technology can feed the plant’s unit auxiliary steam header and saves a ton of heavy fuel oil per hour. The anticipated fuel saving is based on moderate heavy fuel oil preheating up to 100 °C. Further fuel temperature raise up to 180 °C will need more auxiliary steam or respectively more solar heat input and will result in bigger saving. This solar repowering option although with very limited scope can be feasible approach when there is not enough flat land around the plant for large solar field location. It is also very interesting for the utilities that would like to test a given CSP technology before deployment of large scale solar power project. The most radical approach in integrating solar heat into the Rankine cycle plant is boiler replacement partially or
345
fully with appropriate solar based steam generation facility (Ugolini et al., 2009). A typical subcritical Rankine cycle power plant has turbine throttle steam conditions of 16 MPa and 540 °C. A steam with such of parameters could be generated by high-temperature solar technology like solar tower or advanced parabolic trough collectors. The admission of solar-generated superheated steam directly into the high pressure steam line to the steam turbine is a beneficial option in this case. But the state of the art solar steam conditions are far below the aforementioned level. For example, the most recent AndaSol project in Spain, demonstrates turbine inlet conditions of 10 MPa and 370 °C (Aringhoff et al., 2002). Obviously real solar based fossil fuel fired boiler replacement is a long term task. Some solar energy options assume the thermal energy produced by a CSP system will heat feedwater to displace turbine extraction steam to the feed water heaters. Reducing or eliminating extraction steam to feed water heaters appears to be the most practical application for mediumtemperature solar integration, as it avoids complex issues of direct steam generation and integration with the boiler and its controls. Furthermore, such of hybridization will save fuel when the solar system is available, and has inherent backup via fossil fuel when the solar system is unavailable. This approach has been discussed regularly in the recent 10 years (Ying and Hu, 1999; Morrison et al., 1999; Hu et al., 2003, 2009; Bockamp et al., 2003; Morin et al., 2004; Yinghong et al., 2007). A project in very advanced stage is located at the coal fired power plant Liddell in New South Wales in Australia. Fresnel collectors are used to generate saturated steam. This steam is intended to supply feed water heater. Testing operation of 1 MWt solar field started in 2004. As the second phase of this project, a 9-MWt solar thermal steam system has been constructed. But this effort is still aimed at solar steam generation although this steam will be used for feed water preheating. The present study is going to analyze comprehensively different direct solar feed water preheating options. 3. Solar heated feed water preheating options Conventional power plants consist of a boiler, using usually either coal or heavy oil that supplies steam to a multi-stage turbine-generator exhausting to a condenser at high vacuum. From there, the condensate is pumped through a number of feed water heaters that utilize steam extracted from progressively higher pressure stages of the turbine, until the final feed water temperature is increased as high as possible consistent with design of the steam boiler, or economic considerations of the cycle. The foregoing, commonly referred to as regenerative feed water heating, results in a high cycle efficiency being primarily dependent upon the number of extraction points and feed water heaters that it is economically feasible to utilize. The customary feed water cycle consists of two series of heaters: LP Heaters and HP Heaters (see Fig. 1.).
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D. Popov / Solar Energy 85 (2011) 344–349
Fig. 1. Schematic diagram of ordinary steam turbine plant.
The low pressures heaters group consists of up to four heat exchangers. After passing these heaters the condensate is degasified in direct contact heater/deaerator. The high pressures heaters group consists of up to three heat exchangers usually fed with high temperature superheated steam coming from high and intermediate pressure turbines. The feed water is further heated up in the boiler’s economizer. From the practical point of view the direct solar feed water preheating process in existing power plant can be accomplished in three different arrangements: LP heaters replaced by solar field consisting of water based solar collectors. HP heaters replaced by similar solar field. HP heaters and economizer replaced by solar field heating. As a result of this replacement, reduction or elimination of the extraction steam will occur. This non-extracted steam will expand in the respective turbine stages and finally will be exhausted to the condenser. In this way some turbine stages can be overloaded due to surplus steam flow. This is especially true for the LP turbine last stages. Such mode of operation is not new for the turbine practice. It occurs occasionally when some feed water heaters are out of operation due to different reasons. In order, any damage to be avoided in the last stages of the turbine, the original equipment manufacturers usually impose capacity limitations in this case. It means that when some feed water heaters are out of operation the steam flow at the turbine inlet has to be reduced in order steam volumetric flow in the last turbine stages to be kept at its design point. It is clear that the same approach has to be applied in our case when a group of feed heaters is planed to be switched off and replaced by solar field. In other words, steam turbine capacity must be unavoidable reduced. Nevertheless, eliminating extraction steam to feed water heaters may result in large fuel savings as the boiler steam output will be
reduced. In order to estimate the anticipated effects hybrid power plant model has to be developed. One of the key questions in this modeling work is the selection of appropriate CSP technology. Parabolic trough solar collectors are proven enough and commercially available as thermal oil heaters. It is clear that using such of collectors for water heating will need a little but some developments efforts. Since the beginning of their introduction Fresnel solar collectors have been developed as water based system (Mills, 2004). The fixed absorption tubes of the linear Fresnel collectors do not need heat or pressure resistant joints. Therefore, the pressure limitations that are inherent to parabolic trough technology can be avoided. This factor is very important as the feed water pressure is usually very high. As a result the linear Fresnel solar concentrating technology has been selected in this study as more suitable for feed water preheating. 4. Computation of fossil fuel fired plant repowered with solar feed water preheating One of the best computational tools suitable for detailed power plant engineering is created by Thermoflow, Inc. Its software THERMOFLEX is a modular program with a graphical interface that allows one to assemble a model from icons representing over one hundred and seventy-five different components. The program covers both design and off-design simulation, and models all types of power plants, including combined cycles, conventional steam cycles, and repowering. The latest THERMOFLEX version 20 has been used in this study as it includes a number of features to model solar thermal power and heating cycles. It provides design point heat balance, physical equipment size, off-design performance, and cost estimates for parabolic trough collector fields, linear Fresnel collector fields and related components (Griffin et al., 2009). A theoretical sun-atmosphere model with latitude, time of day, day of year, and haze index that is also provided with the aforementioned program was used for solar characteristics calculation. Vasilikos Power Station located in Cyprus on a site with latitude 34° north has been selected as a base case in this study. It has 130 MW gross capacity, a boiler with superheated steam output of 390 t/h and steam turbine throttle steam conditions of 14 MPa and 540 °C. The estimated site peaking Direct Normal Irradiance is 860.2 W/ m2. Overall computational work has been split in four cases: A. Base case calculations in design and off-design mode. B. Off-design calculations of case A plant with LP heaters replaced by solar field. This case assumes solar feed water preheating from about 34 °C up to 159 °C; C. Off-design calculations of case A plant with HP heaters replaced by solar field. This case assumes feed water preheating from about 168 °C up to 249 °C (see in Fig. 2);
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Fig. 2. Computational diagram of 130 MW power plant repowered with solar field for feed water preheating.
D. Off-design calculations of case A plant with HP heaters replaced by solar field. The boiler’s economizer is also but partially replaced by large solar field. This case assumes feed water preheating from about 168 °C up to 319 °C During case A design calculations, all power plant main parameters were computed. In this way, last turbine stages steam flow was determined. Several off-design calculations with heavy fuel oil inputs lower than its design value were also done. During case B calculations LP heaters was replaced by solar field performing direct feed water preheating. Boiler’s steam output has been progressively cut in order to avoid last turbine stages overloading. Corresponding heavy fuel oil input was fixed at a lower level. As a result plant’s gross and net capacity was reduced. The anticipated solar field model was run in thermodynamic and engineering design mode for the best solar hour of the year. Solar field capacity and basic configuration were determined. During case C calculations HP heaters was replaced by solar field performing direct feed water preheating. Boiler’s steam output has been progressively cut in order to avoid last turbine stages overloading. Corresponding heavy fuel oil input was fixed at a level lower than its design value. As a result plant’s gross and net capacity was again reduced. The anticipated solar field model was run in thermodynamic and engineering design mode for the best solar hour of the year. Solar field capacity and basic configuration were determined. During case D calculations HP heaters fully and economizer partially were replaced by solar field performing direct feed water preheating. The feed water outlet temperature was fixed at level of 319 °C in order economizer’s steaming to be avoided. Boiler’s steam output has been
progressively cut in order to avoid last turbine stages overloading. Corresponding heavy fuel oil input was fixed at a lower level. The anticipated solar field model was run in thermodynamic and engineering design mode for the best solar hour of the year. Solar field capacity and basic configuration were determined. Solar power generation share has been calculated in the following manner. As stated above, fuel inputs for cases B, C and D were determined. Case A in off-design mode was run after that with the fuels inputs coming from cases B, C and D. In this way, power generation based on fossil fuel heat input only was calculated. The differences between the capacities coming from the calculations of the cases B, C and D and the capacities generated by the same heavy fuel oil inputs without solar input (case A computational scheme) represent the actual solar heat based power generation. The results for the best solar hour of the year along with the total solar field installed costs are summarized in Table 1. The results indicate that case B is the worst option especially with regard to the imposed large reduction in electric capacity. This case was excluded from further evaluation. Cases C and D look very promising and their off-design models were used to simulate 24-h base load operation for 1 year by simulating 8760 cases. The purpose of this simulation was to obtain data in terms of energy on yearly basis. This information was used to make a comparison between different hybrid plant options and the same plant, fired with fossil fuel only. Table 2 shows a summary of the results. In order to have the same net power generation output the base case A annual operating hours has been slightly reduced. As expected over the course of the year, all cases have almost the same power generation but the solar fields added cases C and D consume less fuel. Based on pricing
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Table 1 Basic engineering summary of the repowered fossil fuel power plant at solar field design point. Key repowering parameters
Solar repowering options
Solar heat input (kW) Net fuel input (kW) Net unit capacity (kW) Solar power generation (kW) Net electric efficiency (%) Solar heat to power efficiency (%) Collector field required land area (ha) Total active aperture area (m2) Installed solar field total cost (MM US$) Specific solar adder capital cost (US$/kW)
A
B
C
D
0 341,925 122,156 0 35.67 0 0 0 0 0
39,522 276,248 104,352 6818 33.05 17.25 17.71 81,807 21,778 3194
33,721 295,252 116,418 11,476 35.39 34.03 15.03 64,280 17,112 1491
67,906 259,675 116,912 26,642 35.69 39.23 28.06 129,656 34,516 1295
Table 2 Summary comparison of year long simulations of cases C and D versus base case. Simulation parameters on annual basis
Solar repowering options A
C
D
Operating hours (h) Net Power (MW h) Heavy fuel oil input (tons) Fuel savings (tons) CO2 emission avoided (tons)
8674 10,59,594 259,960 0 0
8760 10,59,490 254,465 5495 17,419
8760 10,59,700 247,815 12,145 38,728
for the proposed plant location (Middle East) the heavy fuel oil price in the recent month can be fixed at about 435 US$ per ton (source: http://www.bunkerworld.com/ markets/prices/ae/fjr/). Using this fuel price, the C option generates an incremental revenue of 2.39 MM US$ per year due to fuel saving while the D option generates up to 5.28 MM US$ per year. This translates to about 7.2 years to repay the incremental capital cost of the case C and 6.5 of the case D. This analysis is conservative. A more refined analysis would include a price premium for solar power, other renewable incentives, and perhaps CO2 reduction credits if applicable. Nonetheless, until fuel prices rise to reflect fuel’s intrinsic value, and the price of power naturally follows, the economics of solar power produced or fuel savings alone, can foster the proposed solarhybridization development. 5. Conclusions The obtained results clearly indicate case B as the worst scenario for the proposed solar repowering. LP heaters replaced with solar field feed water prehearing need large power generation capacity reduction and very limited solar input. The most attractive option is case D especially for the future power plants. The group of high pressure heaters is replaced and feed water temperature exceeds its original design value within this option. The solar power generation share can reach up to 25% of the power plant capacity, having instant efficiency higher than 39% at design point. The weak side is the need of very large plot of flat land
in the vicinity of the plant for solar field location. Some special boiler designs rely on steaming economizers. This design feature may put obstacle in the proposed extended solar feed water preheating in existing plants as the economizer tubes could be overheated in this case. But this problem could be surmounted if the case D mode of operation is envisaged at new plant design phase. Case D is also attractive with its smallest carbon footprint. The best option for existing plants solar repowering is case C. It needs almost “zero” power plant modification and proposes large solar power generation share, large fossil fuel savings and high power plant efficiency. This efficiency would be far higher if the plant is operated at partial load during the night, and would be lower in locations with poorer solar characteristics. From a fuel consumption viewpoint, this plant modification has good solar leverage. References Aringhoff, R., Geyer, M., Herrmann, U., Kistner, R., Nava P., Osuna, R., 2002. AndaSol – 50MW solar plants with 9 hour storage for southern Spain. In: Proceedings of 11th SolarPACES International Symposium, Zurich, Switzerland, 4–6 September 2002, pp. 37–42. Bockamp, S., Griestop, T., Fruth, M., Ewert, M., Lerchenmu¨ller, H., Mertins, M., Morin, G., Ha¨berle A., Dersch, J., 2003. Solar thermal power generation. Presented at Power-Gen Europe 2003, Du¨sseldorf, Germany.
D. Popov / Solar Energy 85 (2011) 344–349 fmt=high&_orig=search&_sort=d&_docanchor=&view=c&_search StrId=1208663696&_rerunOrigin=google&_acct=C000061252&_vers ion=1&_urlVersion=0&_userid=3738940&md5=d4db3830563cadee6 58565bcf22e2dee#secx6>. Hu, E.J., Mills, D., Morrison, G., Lievre, P., 2003. Solar power boosting of fossil fuelled power plant. In: Proceedings ISES 2003, Go¨teborg, June 14–19, 2003.
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Morrison, G., Mills, D., Corporatio, Stanwell, 1999. Solar thermal power systems – stanwell power station project. In: Proceedings of the ANZSES Annual Conference, Geelong 1999.