Modern design concepts for thermal power generation towards highest efficiency, increased utilization and reduced carbon footprint

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1 PROCEEDINGS OF ECOS THE 29 TH INTERNATIONAL CONFERENCE ON EFFICIENCY, COST, OPTIMIZATION, SIMULATION AND ENVIRONMENTAL IMPACT OF ENERGY SYSTEMS JUNE 19-23, 2016, PORTOROŽ, SLOVENIA Modern design concepts for thermal power generation towards highest efficiency, increased utilization and reduced carbon footprint Christian Bergins a, Michalis Agraniotis a, Malgorzata Stein Brzozowska a, Torsten Buddenberg a, Emmanouil Kakaras a a Mitsubishi Hitachi Power Systems Europe, Duisburg, Germany, m_agraniotis@eu.mhps.com Abstract: In the present work an overview from the viewpoint of a large scale power plant manufacturer is provided, on how modern thermal power plant technology can comply with the new requirements for flexibility and provision of balancing services and back-up power towards support grid stability in systems with high shares of RES penetration. In this framework future trends in power plant design are presented towards: - further increase of efficiency through thermal cycle optimization and fuel pre- drying - retrofit options for faster load change and extension of load range - integration of electricity storage concepts in power plants - product diversification and cross-sectorial energy storage and utilization (Power to Heat, Power to Chemicals) as well as for maximizing the plant utilization. It is shown that these technologies can significantly improve the economics of power plant operation and also have much lower carbon footprints, when renewable energy is integrated in the operation. Depending on the needs of future markets high efficient base load power plants as well as plants, which are fully flexible in fuel use, products output and operational range, can be designed and supplied. Keywords: Thermal power generation, flexibility, electric ignition, indirect firing, coal pre-drying, energy storage, Power to Methanol, Liquid Air Energy Storage, product diversification 1. Introduction Overview The increasing global energy demand together with the increased need on sustainability, security of supply and competitiveness in power generation has led to considerable changes in energy policies all around the world. Especially in Germany but also in entire Europe over the past decade the penetration of renewable energy sources (RES) has remarkably increased, which in some cases has significant impact on the electric grid. The intermittent character of the RES and their high cost now require new measures for balancing the grid and reducing the consequential cost burden. The present paper presents existing and novel approaches for the increase of power plant flexibility and for integrating energy storage and conversion technologies in conventional power plants to make new and existing power plants more flexible towards grid balancing and value creation by new products. At first possible modification concepts of firing systems including indirect firing with biomass and dry lignite as well as improved ignition systems using electric ignition are presented. With these technologies today s power plants can be improved, in order to serve the increasing demands on higher operational flexibility. 1

2 Furthermore, the Power to Methanol (PTM) or generally Power to Fuel concept is presented and discussed. It is an energy storage technology, which easily can be applied today to overcome many of the challenges, which arise from the increasing share of renewable energies. An oversupply and consequential curtailment of electricity can be avoided, when the trans-sectorial concept of energy transformation of excess electricity and of CO 2 towards transport fuels - like methanol, synthetic natural gas or hydrogen and their follow up products - is implemented in a cost competitive and sustainable way. The technology is especially suited to offer an option to absorb high amounts of excess electricity, while keeping power plants always grid connected to provide primary and secondary control as well as back-up power. Liquid air energy storage (LAES) is a technology developed to cover future demands for large scale storage. The LAES system developed jointly by MHPSE and Linde has similarities to compressed air energy storage (CAES). In both concepts electricity is used to compress air during charging phase and air turbine expanders are installed to produce electricity at discharging phase. The difference lays in the fact that in the LAES concept compressed air is further liquefied and stored in liquid air tanks on-site, thus avoiding CAES dependency on air-tight caverns. Therefore depending on grid configuration, a LAES facility can be installed near transmission substations, wind / solar generation facilities, or beneficially integrated in existing power plants for daily electricity storage but does not rely on certain geological boundary conditions. At last an overall evaluation of the above mentioned technologies is presented and general results are drawn regarding possible implementation of these technologies in today s and tomorrow s electricity systems Energy system predictions The penetration of the RES in European countries like Germany makes it necessary to re-think all aspects of the power generation system. In the future the generation system will consist of RES, conventional power plants and storage devices, while those storage devices can be electrical, hybrid and cross sectorial storage technologies. Fig. 1 shows the example for the probable development of the German energy system in 2050 [1]. 2

3 Energy-System 2050 Control-Energy > 5% Storage >80% Energy from renewable sources with needed surplus production 315% (259 GW) Secured energy from conventional power plants CHP, multi-fuel & bio-mass; <<20% CO 2 Fossil fuels Cross-Sector-Market Power to Heat Vehicle to Grid Power to Gas CO 2 Overspill state 2050 (target) 100 GW max. load demand 397 GW available capacity 59 GW conventional 259 GW renewables 14 GW storage 53 GW cross sector 12 GW biomass Load demand is expected to slightly rise until 2050 (13GW) Demand Side Management to be planned and operated by big consumers Conventional power plant fleet to decrease to 50% electricity = a cheap commodity Maximum load 87 GW + 13 GW in Demand Side Management (DSM) Fig. 1. Energy System in Germany 2050 Prediction based on scenarios for the energy turn towards dominant renewable energy use The study of AGORA from 2015 [2] comes to a similar conclusion for most cost effective way to implement the RES in the energy system. There is a preliminary cost optimum which was calculated as a requirement of 14 GW short term storage and the installation of at least 16 GW cross-sectorial storage. The difference between those two developments can be explained by a simple reason. The assumption of AGORA is the full development of the grid extensions according to the German grid plan [3], while Kakaras et.al. [1] assume based on current literature [4] that due to public acceptance problems the full extension of the grid plan will not be reached. This is changing the basic techno-economic boundary conditions and changes the optimum of the necessary installation of long term storage. It can be assumed that an optimized development will end up between those two values. The political decision to use high amounts of RES in the future leads to higher electricity cost for the electricity supply, but there is no option for stepping back from this roadmap, if the carbon footprint of Europe shall be lowered. But it also can be shown that a pure conventional development in the power generation, would have led to significant higher electricity pricing [5] and so a cost optimization of a system with high RES penetration, in order to avoid curtailment is the overall most cost effective way towards a low carbon future. This leads to the conclusion, as a basic assumption for this paper, that the energy system of the future will be an integrated system combining power generation with other carbon dioxide intensive industry sectors. So it is only consequent to combine the necessary conventional power plants with novel energy storage technologies to make the conventional generation a high flexible partner for the RES. 3

4 2. Increase of flexibility in existing and new thermal power plants 2.1. Flexibility definitions What is the meaning of flexibility for conventional power plants? This is the question we have to answer front-up to discuss the use for novel technologies. Conventional power plant like gas-, coal-, lignite- or nuclear power plants in the past have been designed for their maximum efficiency to minimize their variable cost. Flexibility at this time has been the capability of power plants to follow the load requirements of the grid, determined only by consumption. Nevertheless, due to the fact that in earlier times the penetration of the RES has been low, the minimum load of the power plants was not important. Even if many thermal power plants have been out of operation, due to a low demand period, the generation system used to have enough rotating mass in operation, so that transmission & distribution grid could operate without problems. Nowadays, in countries with increased share of installed RES, like Germany, there is an increased need of rotating mass for stabilizing the transmission and distribution grid at all times of the day. On the other hand high penetrations of RES lead to a decrease of total electricity demand from conventional power plants and to reduced electricity prices forcing conventional power plants to get out of operation. At a certain point this is contradicting and may endanger system stability [3]. So system relevant power plants are kept in operation, while at the same time renewable generation is curtailed. This shows the importance of the ancillary services like primary & secondary control for the transmission & distribution system. To avoid now the necessity of curtailment the optimal conventional generation system, would be able to be operated on a variable mode, between full load and zero output, or even in negative load with storing the energy of the system. Power generation systems like this do not exist today. Standard minimum loads of new built power plants are approx % for gas fired, lignite or nuclear power plants and 25% for hard coal fired power plants. It becomes clear that plants with these characteristics cannot serve the upcoming increased needs on flexibility and back up. So the main approaches must be the significant lowering of the minimum load of the power plants and also provide measures to older plants which have even higher minimum loads. It is far more important than higher load change rates, which are today already at 3-5% per minute for the most power plants. There are serval measures to decrease the minimum load of thermal units which will be discussed in the following. Also measures, which reduce the cost overburden from flexible operation like cost for auxiliary fuels will be handled. [6], [7]. None of these measures alone gives the possibility of running down to zero load with a conventional power plant. So it is necessary to take additional steps to reach at least this goal. All this new ideas are about the energy efficient integration of storage technologies in the power plants as integral parts of the unit. Increasing flexibility in future thermal power plants is not a straightforward approach, since there are several operating parameters which need to be optimised under a high number of constraints. In general terms, the key targets towards increasing flexible plant operation are: Reduction of minimum load Increase of ramp up/ down rates Reduction of start-up cost and start up time Increase of maximum load period And, of course, all these targets will have to be fulfilled at lowest investment and operating costs; at highest plant efficiency rate and lowest CO 2 emissions; by always keeping below the flue gas emission limits. 4

5 A graphic representation of these parameters is given in Fig. 2. The two main design goals for the increase of flexibility - often regarded as competing - are: the decrease of minimum load towards avoiding a plant dispatch and keeping the plant in operation at times of excess electricity from renewables; and the increase of ramp up/down rates and the decrease of start-up time and costs towards the prompter start-up and load of the plant after a dispatch. It should be underlined that, from a grid stability point of view, the option of keeping a plant in operation at minimum load provides additional benefits, since this is the only way thermal plants can actively support the electric grid by providing primary and secondary reserve. max. min. (old) min. (new) Load Reduction of minimum load Reduction of startup cost and startup time Time Increase of load change speed Maximum load extension Minimum load reduction (+) Continuous sales of grid services (+) Auxiliary fuel saving (+) Reduction of thermal fatigue (-) Lower efficiency = higher specific cost Non regret strategy for flexibility! Improvement of startup only (+) auxiliary fuel savings (+) faster startup (-) Loss of operational hours and income (all services!) Fig. 2. Overview and comparison of flexibility measures and impact on the operating mode An overview of the current state of the art of technical parameters related with flexible operation of coal plants is provided in Table 1 for a) older plants commissioned in the 90s b) newer plants commissioned after 2000 representing state of the art and c) future plants following highly flexible design characteristics. Table 1: State of the art and future targets in operating parameters related with plant flexibility Parameters / characteristics Minimum load for continuous operation [%] Currently operating PP fleet (PPs erected in 80s-90s) 1) Current BAT (PPs erected after 2000) 1) 5 Targets for hard coal for hard coal 2) ~15 (considering alternative >50 for lignite 4) for lignite 3) 4) & low carbon solid support fuels and their blends) Ramping rate [%/min ~10 Frequent start-up and shut down ability (cold/warm/hot) Emissions and plant efficiency must be kept during part load Specific nr. of start-ups /shut downs foreseen per year (limited to few cold start-ups) Optimum design for high efficiency and lowest emissions at full load Possible daily start-up for hard coal PP (usually hot/warm daily, cold over the weekend) Optimum design for high efficiency and lowest emissions at full load and some low loads Possible daily variations between % to avoid daily start ups Optimum design for high efficiency and lowest emissions (IED) for load following operation 1) Best possible known, and documented 2) Usual min load operation for recent new built plants still is only around 30-40% due to lowest marginal cost of all hard coal units, minimum load reduction is more difficult for the modern supercritical units compared to subcritical units from the past 3) Oil/gas may be required as supporting fuel for lignite 4) Plants are existing in Germany or are being retrofitted with dry lignite firing to operate in the range of 20%-30% load

6 2.2. State of the art measures towards flexibility increase utilising the inherent potential of existing plants In a first step the inherent potential on flexibility increase of the existing equipment shall be investigated. A comprehensive study towards the determination of the current state of operation of each plant and of the possible improvements through small scale measures is usually required in the initial stage. In this frame operation with reduced number of mills and with decreased load per burner is one of the measures to be investigated. In order to lower the boiler load in terms of firing system different operation modes can be investigated, such as a 2-mill operation in partial mill load vs. 1-mill operation at full mill load in case of a hard coal fired plant. In case of lignite firing systems a 4 or a 3 mill operation can be considered as a measure to decrease minimum load depending from the number of installed mills in each boiler. It shall be noted that the minimum load reduction may have considerable impact in the boiler operation as well from the steam side as also from the flue gas side. The calculation of the expected boiler behaviour based on a validated boiler model is required, in order to be able to predict the boiler performance under low load operation. SH and RH steam outlet temperatures and the difference of the outlet temperatures between each line at the outlet headers shall be controlled by calculation tools, experience and experimental observations on site. The performance of the economiser in low load conditions shall be also checked, in order to avoid a) either too low flue gas temperatures, which may endanger the SCR operation or b) too high feedwater outlet temperatures, leading to evaporation already in the economiser section and raising flow instability issues. Furthermore, overall control and safety concepts for boiler and overall plant have to be checked under the prism of a reduced min load operation. Possible 1-mill firing concepts in the case of hard coal fired boilers and 3-mill firing concepts in the case of lignite fired boilers have to be evaluated, tested and certified in terms of redundancy and safety on case by case basis. Additional or updated flame monitoring systems may be needed, in order to secure that the necessary information on flame stability and control and flame intensity can be utilised by the boiler control and safety system. Summarising, it can be stated that current boilers may possess inherent flexibility characteristics, which shall be evaluated on case by case basis. By following this approach customised measures for small scale retrofits can be studied, in order to achieve certain flexibility improvements without the need for extensive and costly modifications Further measures indirect firing systems The increased number of required start-ups in today s hard coal and lignite boilers leads to increased consumption of expensive support fuels such as natural gas or fuel oil. For this reason their replacement by other fuels like pulverized hard coal dust, pre-dried lignite and low carbon fuels such as various solid biomass fuels (e.g. saw dust) as start-up fuels is winning on interest. In order to realize it in the most effective way Indirect Firing is suggested (IF). Indirect firing (IF) considers an additional pulverized fuel storage system (Fig. 3). During the lower load demand the mill can be operated normally and pulverized fuel produced partly can be stored in the additional dust bunker. As during the milling process the solid fuel is dried, the dried fuel dust can be used a) as supporting fuel for combustion stabilization in low load operation, b) as supporting fuel in case of very low quality fuels and c) as alternative start-up fuel during start-ups and shut downs. In the IF system the fuel powder is directly injected into the boiler via a special burner. For these applications MHPSE has developed the DS-T burner (Fig. 4), suitable for indirect firing of different pre-dried fuels. Due to the high turn down ratio, the DS-T burner may be used in a broad load range during start-up and shut down, leading to savings in conventional start-up fuels 6

7 of up to 95%. Furthermore, in lignite power plants the potential integration of an external predrying system may be used for the production of pre-dried lignite, which can be utilised as start-up and supporting fuel in existing and future lignite power plants (Fig. 5). By the use of dry lignite and the suitable design of boiler and firing system using dry lignite the minimum load in lignite power plants can be reduced to less than 20%, similar to the hard coal boilers described above. Detailed information about possible lignite drying technologies, which can be integrated in thermal cycles have been presented by the same authors in previous papers [6], [7]. Fig. 3. Indirect firing system Fig. 4. DST-Brenner burner for dried fuel dust (1 - core air, 2 - fuel, 3 - secondary air, 4 - tertiary air, 5 - fuel nozzle, 6 - swirler) Fig. 5. Lignite pre-drying system towards flexibility increase of current and new power plants 2.4. Further measures electric ignition systems As mentioned above dried pulverized fuels, especially biomass and dried lignite, which are characterized by very high volatiles content, but as well hard coal powder can be used as alternative fuels for start-up and quick load increase. In order to reduce the consumption of costly auxiliary fuels such as oil and gas the possibility for ignition of dried solid fuels by electric based start-up technologies is currently developed by MHPSE. More specifically, two technologies are currently in the development process a) the electrically heated burner nozzle and b) the plasma ignition 7

8 system. Whereas the electrically heated burner nozzle is foreseen for start-up of further burner levels when increasing the boiler load, the plasma ignition system is designed for cold, warm and hot start-up. Electrically heated burner nozzle is described in detail in [9]. The idea here is to cause the ignition of a pulverized fuel through the heat radiation from and contact with the hot burner nozzle (Fig. 6). Ignition using a plasma flame (Fig. 7) is possible as plasma is a highly reactive blend of electrons, radicals, atoms and molecules. The development aims at the optimized positioning of the plasma flame in low NO x swirled burners for save ignition for a wide range of fuels while minimizing the necessary plasma power. The implementation of such electric ignition systems not only is aiming at reduced use of supporting fuels but also at the reduction of maintenance cost of the complex infrastructure and/or storage of heavy fuel oil or light fuel oil and gas start-up systems, which have to undergo regular safety inspections. Fig. 6. Electrically heated nozzle proof of concept. Burner nozzle is heated (1:30), see slightly visible glowing of the metal surface. When the nozzle surface temperature is high enough, coal is dosed and ignition is witnessed directly at the nozzle (1:59). Fig kw plasma flame incorporated in the 30 MW DS burner during the cold commissioning tests. Depending on plasma and burner operation parameters the shape of plasma flame changes significantly from round and short to longitudinal reaching up to almost 1 m in length Further measures Multi-line design and optimization of thickwalled components Further concepts include a) the replacement of existing thick walled components (header, steam outlet pipes) by thinner walled components by using higher grade materials and b) the application of multi-line designs in the boiler s convective part (Fig. 8). Use of multi-line design allows for smaller diameters of steam tubes and headers, due to the distribution of total steam mass flow to several lines. This offers a significant wall thickness reduction potential. As an example, the replacement of an existing header with 52mm wall thickness by a new one made from high grade steel with a reduced wall thickness of 40mm may facilitate an increase in the allowable ramp-up rate from 7% to 10%/min (Fig. 9). The particular results are based on standardised stress calculations, which take into account standardised number of cycles and hours of operations. Additional information can be found in relevant literature [10]. 8

9 Fig. 8. Multi-line design vs. classical layout (new build solution). Fig. 9. Impact of reduced wall thickness on ramping rate (retrofit or new build solution). 3. Integration of large scale storage concepts in existing and new thermal power plants towards flexibility increase Energy storage technologies are expected to play an important role in the future European electricity system by supporting the further deployment of the renewable energy sources and the increase of RES feed in in the electricity grids. During times of excess electricity production from RES energy storage systems can be charged supporting grid stabilization. The stored energy can be then fed in into the grid at times of low RES feed in. Going one step further, excess electricity together with CO 2 from thermal power plants may be used for the production of valuable fuels and chemicals, following the Power to Fuel concept. In this frame two storage concepts currently under development by MHPSE will be presented in the chapters below, the Power to Methanol concept and the Liquid Air Energy Storage (LAES). Through Power to Methanol technology it is possible to utilize CO 2 from thermal plants and excess electricity for the production of chemicals with high energy content like H 2, CH 4, MeOH which can be used in the power plant or externally as fuel. In this way a diversification of the product portfolio of the power plant is possible. Liquid Air Energy Storage (LAES), to be presented below, is a developed storage technology, whose possible integration in existing power plants can provide multiple advantages and economies of scale. The components of the concept are already existing and commercially available, while the overall concept fits best to existing design of conventional thermal power plants. Examples will be provided which show that integration of such technologies provides full synergies and widens the operational range of conventional power plants with highly efficient integrated energy storage. In contrast to batteries storage or pumped hydro storage the proposed concepts can be characterised by: Low cost for installation when retrofitted to existing infrastructure No geological restriction as the storage can be on site with existing thermal units The possibility for GWh scale storage near to power plants and consumers 9

10 4. Integration of Power to Methanol in thermal power plants towards flexibility increase 4.1. Introduction - Power to Methanol technology MHPSE together with Carbon Recycling International (CRI, Reykjavik, Iceland) has developed the Power to Methanol (PTM) technology in the last years, in order to provide technical options for utilising excess electricity and CO 2 and transform it to valuable fuels. In this sense although Power to Methanol may be considered as an energy transformation and energy storage technology, a proper sizing and integration of the concept in large scale thermal power plants, may contribute to the flexibility increase of the existing thermal power plant fleet. Conventionally, methanol is produced by steam methane reforming (SMR) or coal gasification. The feedstock is natural gas (NG) or coal. The production model is a mega scale plant at the size of 1 million tons per year, centrally located near the sources of primary energy. Methanol is shipped to the ports of import by large tankers. In contrast, Power to Methanol production may be also designed according to a decentralised model ([11]), where the plant is built nearby the feedstock source. An envisioned power to methanol plant size is in the range of thousand tons per year and is located near the sources of use. The feedstock consists of basic utility available at a power or chemical plant, which includes power, hydrogen surplus, and carbon dioxide. Each plant is designed to take advantages of the available infrastructure, by-products, and waste heat. Carbon dioxide is captured and purified on site for use as the main feedstock. Furthermore, as shown in Fig. 10 methanol is considered as one basic intermediate products of the petrochemical industry and is required for the production of further chemicals (e.g. formaldehyde, acetic acid), fuels such as gasoline or fuel additives such as DME and MTBE. This indicates that methanol will in the long term continue to be a valuable chemical and that no overcapacity, due to increased methanol production, can be expected in the very large global market of liquid fuels and chemicals. Hence, the Power to Methanol concept facilitates the trans-sectorial energy storage, increasing flexibility of conventional power plants and supports their operation under Demand Side Management (DSM) concept providing them new potential revenues and business models. It is clearly shown in that Fig. 10: Potential Products from Power to Methanol technology [15] 10

11 For PTM 1.4 ton of CO 2 are captured per ton of produced methanol (Fig. 11). For natural gas and coal methanol plants, large amounts of carbon dioxide are emitted. It is 1 ton of CO 2 emitted per ton of methanol produced by natural gas methanol plants; and 3 tons of CO 2 per ton produced by coal methanol plants. In general the power to fuel technology is using hydrogen and carbon dioxide to produce methanol in a low temperature reactor, avoiding the high temperatures of the traditional methanol production with synthesis gas, which has high investment cost. The process now has risen interest in Europe and elsewhere since a) it enables a profitable solution of utilization of excess electricity from renewable electricity, b) offers the possibility of diversification, OPEX reduction and flexibility increase of thermal power plants and c) it contributes to overall CO 2 emissions reduction from industry via producing fuels avoiding in this way the import of conventional fuels with higher CO 2 foot-print [11]-[13]. As shown in Fig. 11 the process has a maximum theoretic thermal efficiency of approx. 85% based on the LHV, starting from compressed hydrogen and CO 2 and is utilizing 1.4 metric tonnes of carbon dioxide per produced metric ton of methanol. Fig. 11: General process of power to methanol - PTM It is assumed first that the hydrogen is produced via electrolysis of water, without being the best choice. If the PTM technology is integrated in other process industries, where hydrogen is present as by-product such as the chlor-alkali process, the ethylene production process or a hydrogen separation from coke oven gas, very high total thermal efficiencies and low specific production costs are feasible. The core technologies involved are in every case a) the supply of clean, compressed hydrogen, b) the CO 2 capture and compression, c) the methanol production and purification and d) the process integration in other facilities. As the examination focus on short term technical and economic feasibility of the overall process, the post-combustion-capture (PCC) technology is considered for CO 2 capture and the alkaline electrolyzer technology is considered for H 2 production Integration options of PTM in existing power plants As already published by the authors a viable process for Power to methanol is the reaction of CO 2 and electricity from a power plant hydrogen is generated by electrolysis [11]-[17]. The reactor for the conversion of syngas to methanol is designed for low heat loss, high conversion of hydrogen to methanol at above 98%, and high catalytic selectivity at above 99% [18] and under low pressure and temperature. On carbon capture and storage, the process has been developed and demonstrated at large scale in the last ten years. Today, Power to Methanol is a proven solution which can be implemented with available equipment, catalysts, control system, and operating experience. A ready application is to produce methanol using carbon dioxide captured with a post combustion carbon capture plant (PCC) at carbon dioxide source point of a coal power plant. Fig. 12 depicts the process flow of a Power to Methanol plant with a PCC configuration. 11

12 50-150MW el electrolyser 4.5% - 18% Carbon Capture H 2 commercial scale 410 t/d h el/th ~61%, MeOH output: max 95MW th water electricity electrolysis Post combustion CO 2 capture Methanol synthesis Methanol distillation pure methanol coal air O 2 power plant gas cleaning electricity flue gas Base case Max load with PtM min load 1543MW th coal 658MW el to grid MW el net (h=46%) 52MW el 137 t MeOH/d 32MW th Min load with PtM max load Import 14MW el 142MW el 410 t MeOH/d 95MW th Fig. 12: Power to Methanol Plant Design with Post Combustion Capture, Electrolyzer, and CO 2 Methanol Production The size of the Power to Methanol operation can be tailored to the capacity management requirements for the applicable coal power plant. The size of the electrolyzer is bounded by the limits established to operate the power plant efficiently and to take in the majority of feed in renewable electricity. Nominally, the hydrogen generation capacity is targeted to be in the range of 20% of the capacity of a coal power plant, or 150 MW el electrolyzer for a 710 MW el (net) plant. The arbitrage is producing methanol during low electrical load and high feed in renewable energy and generating electricity during high electrical load and low feed in renewable energy. The operation of such a plant fulfils in addition the requirement from the grid to ramp down the power plant to zero load, while still enabling it to serve all ancillary services to the electrical transmission & distribution grid. Highest efficiency of Power to Methanol for a PCC application is gained by efficient process and energy integration and application of state of the art technologies for Power to methanol. Capture of carbon dioxide in the range of 4.5 to 18 percent of the overall emissions is efficient by using reaction heat from the catalytic reaction of CO 2 and hydrogen to methanol (~50%) and by bleed steam from the inlet of the low pressure turbine. By combining waste heat recovery, advanced solvents, and an innovative process design, energy required for carbon capture is less than 2600kJ per kg of CO 2 for the desorption [19] and in total it is less than 20kWs el per MWs th methanol (LHV). An optimized electrolyzer can generate 4 kwh per Nm³ of hydrogen and is fed by direct current from a rectifier with an efficiency of 97%. The compression units, comprising of the main and recycling syngas compressors of the methanol loop consume 42 kws el per MWs th methanol. The main heat loss primarily comes from the operation of the electrolyzer. Heat recovery from CO 2 and hydrogen reaction is used for the distillation of crude methanol and for carbon capture. Material loss is minimized by a hydrogen recovery unit at the outlet of the purge system. The resulting thermal efficiency of a power to methanol operation is in the range of 61% (electric energy to LHV of methanol). Fig. 12 shows the possible operation range of the power plant of 710 MW el and associated MW el / MW th MeOH with and without the power to methanol operation of 410 tons per day of methanol. A potential way of operation can be shown in Fig. 13 in the example of the real operation data of a 150 MW coal fired power plant. It is shown that the combined methanol production can keep a power plant in operation and raise its utilization by maximum methanol production during nights and at the weekend, also offering the possibility of power import. In the same manner the feed in to the grid could be further reduced in future during the nights, while at least keeping the overall utilization of the power plant the same. In this way application of power to methanol shall be considered as measure to increase economic competitiveness of existing thermal power plants and enhance environmental performance and sustainability through supporting the further increase of RES share. 12

13 150 MW Power Plant (load balancing mode, today) 12.9GWh today 150 MW Power-to-Methanol 6.6GWh Electricity to the grid 12.1GWh future to grid 0 to grid to fuel Time -50 Time Fig. 13: Power plant operation without/with MeOH production (2012/2013 data) 5. Integration options of Liquid Air Energy Storage (LAES) towards flexibility increase 5.1. Introduction Liquid Air Energy Storage (LAES) technology A number of storage technologies are currently available in the market, including Pumped Hydro Storage, Compressed Air Energy Storage (CAES), flywheels and various types of batteries. However there is no one size fits all energy storage solution. Battery technologies, most notably Li-Ion batteries, have seen increasing application in recent years and are currently being demonstrated for critical grid services such as frequency regulation. However, battery storage is still mostly limited to small scale (from kilowatt-hours to a few megawatt-hours) and often more suitable for short duration discharging (15-30 minutes) due to their cost, cycle life and service life. Only a few technology options are available to cover large grid scale storage (hundreds to thousands of megawatt-hours) demands. The most mature and proven technology of them, which accounts for 95% of the present energy storage capacity in the US (approximately 25 GW total) is pumped hydro storage. However environmental concerns, specific geographic limitation and a long construction lead time for water reservoirs are preventing new pumped hydro projects being permitted and constructed. Compressed Air Energy Storage systems have been available to the market for decades, but their application potential is limited by the dependency on underground caverns for storage of pressurized air. Recognizing this need for a flexible, scalable, and durable new storage option to support future growth of renewable energy, Mitsubishi Hitachi Power Systems (MHPS) and the Linde group have developed the LAES technology for large grid scale applications. The MHPS-Linde Liquid Air Energy Storage (LAES) technology has similarities to compressed air energy storage in that both use electricity to compress air during charging phase and use air turbine expanders to produce electricity, but in LAES compressed air is further liquefied and stored in liquid air tanks, thus avoiding CAES dependency on air-tight caverns. Therefore depending on grid configuration, a LAES facility can be installed near transmission substations, wind / solar generation facilities, or existing power plants. Unlike batteries, a LAES system like other thermal power equipment can be designed for 30 year service life, much like traditional power plants. Further information can be found in the literature sources [20]-[24]. 13

14 5.2. Integration options of LAES in existing power plants open cycle GTs In Fig. 14 the GT-LAES variant is presented. In this configuration, the simple cycle gas turbine is essentially a stand-alone unit, with the only exception being that the exhaust gas from the GT is routed to preheat the air from the LAES in a heat recovery air heater (HRAH) before entering the expander. No modifications are necessary to the gas turbine itself, which can be either existing or new. Typically, the waste heat of a gas turbine is used in a heat recovery system for preheating the pressurized air to a temperature close to 500 C or higher before the air is expanded in the air expander. In order to be able to evaluate the LAES efficiency of different systems following efficiency rate definitions are proposed and used (Table 2), whereas LAES output is denoted as the total power output from all rotating parts of the LAES system (air expander and turbine) Table 2: Efficiency definitions for Liquid Air Energy Storage Efficiency definitions System efficiency Storage efficiency Round-trip Efficiency Fuel Efficiency Mathematical expression η system = η s,50% = η RT = η F = Air Expander Output Compressor Input LAES Output ηng Gas Input, with η NG =50% Compressor Input LAES Output Compressor Input + Gas Input LAES Output Gas Input Fig. 14: GT LAES variant flow scheme The GT-LAES variant is based on commercially available components, thus avoiding the need for lengthy product development. A GT-LAES power plant with storage can be built today. The LAES part of the process can be also built as a retrofit to an existing open cycle gas turbine power plant. If necessary the gas turbine can still be operated as a separate open cycle unit without the charging / discharging operation. In this case the plant functions as a pure peaking unit. 14

15 Although Fig. 14 depicts LAES integrated with an open cycle gas turbine, other waste heat sources can be utilized in the similar way. Due to the efficient use of waste heat, the electric efficiency of GT-LAES is much higher than the adiabatic system. Higher grade waste heat from GT exhaust also makes it possible to use single stage air expander, resulting in a simple system arrangement. With typical GT gas exhaust temperatures in the range of 500 C to over 600 C, electric storage efficiencies in the range of 70% to 85% can be expected, compared to around 50-60% for adiabatic LAES. The efficiency of GT-LAES can be further increased to 90% or higher, if two-stage expanders are used with an inter-stage air heater Integration options of LAES in existing power plants coal fired power plants Due to the reason that LAES systems are free in the heat source it is possible to integrate them into existing or new build pulverized coal fired power plants (PCPP). The integration concept during charging and discharging is presented in Fig. 15 and Fig. 16. The integration of a Liquid Air Energy Storage System in a coal power plant steam cycle may bring two additional benefits in the power plant operation through a) the additional provision of energy storage services by the power plant and b) the increase of flexible operation of the power plant through a combined operation mode. More specific, a decrease of the net power production to a lower minimum load will be possible in times of excess electricity from RES. Respectively, an increase of total production to values higher than the existing maximum capacity will be feasible in times of low RES feed in and high electricity demands. A detailed presentation of the two operating modes is presented below. During the charging process the required power for the operation of the air compressors is obtained from the gross electric power produced in the plant, reducing in this way the net produced power and hence the plant s minimum load (Fig. 15). In addition to this the additional heat at a temperature level of 130 C produced by the intermediate cooling of air during the charging phase can be utilized in the low pressure feed water pre-heaters (or in CHP applications), decreasing the requirements on steam extractions. In this way the plant efficiency keeps constant in the low load operation and an additional efficiency drop is avoided. Based on initial thermal cycle calculations a reduction of PPs minimum load is possible during the charging operation of LAES system in the case of a 700 MWe class hard coal power plant. Accordingly, an increase of total net plant capacity is possible during the LAES discharge process. The evaporated air can be also stepwise preheated from low, medium and high temperature steam extractions so that it can be effectively expanded in the air expanders (Fig. 16). In this way the extracted heat of the steam bleeds is used to preheat the stored high pressure air, so that it can produce additional power in the integrated system. 15

16 HP preheating LP preheating HP preheating LP preheating Cold storage Cold storage G LAES energy release (liquid air evaporation and heating by bleed steam, air expansion) Liquid air storage LAES storage (liquid air production & waste heat recovery in LP PH) M G LAES energy release (liquid air evaporation and heating by bleed steam, air expansion) Liquid air storage LAES storage (liquid air production & waste heat recovery in LP PH) M Fig. 15: Integration of Liquid Air Energy Storage (LAES) in existing coal power plant cycle charging process Fig. 16: Integration of Liquid Air Energy Storage (LAES) in existing coal power plant cycle - discharging process The detailed results are presented in the following tables. Table 3 shows the net plant efficiency over the plant load range in the reference case of stand-alone 711 MWe state-of-the-art-coal power plant. Table 4 shows the combined operation of an LAES system with the same coal power plant. A significant increase of the plant flexibility and efficiency is possible. The operating range of the plant is extended from the range 25% - 100% to the range of 12% - 100%, which corresponds to % compared to the initial stand-alone case. At the same time the maximum load increases by 14% from 711 MW el to 811 MW el. In this operation the round trip efficiency (h rt ) of LAES part is 67% combined with a fuel efficiency of 65% (h fuel ) and it is operated with a time factor of 2,25 what means that the charging time 2.25 longer than the discharging time comparing full load charging with full load discharging. Table 3: Efficiency of a state of the art coal fired power plant Steam-Cycle [MW] h [%] (net) 711 (100%) (50%) (25%) 38.9 Table 4: Combined operation of power plant and LAES system Steam-LAES-Cycle [MW] h [%] (net) Comment 811 (new 100%) 48.8 Powering 100% PCPP Powering 100% LAES 411 (new 50%) 47.2 Powering 50% PCPP Powering 50% LAES 96 (new 12%) 25.3 Powering 25% PCPP Charging 100% LAES Fig. 17 shows the full extended operation scheme of the PCPP with LAES. It can be stated that the LAES system for the PCPP is a significant capacity extension, at the same time a flexibility accelerator and an efficient storage device. While in the past in Europe several coal plants were retrofitted with GT topping cycles for peak load extension utilizing the GT flue gas heat in the coal plants steam cycle (preheating or direct steam injection), the new system offers the additional minimum load reduction and does not require the more expensive NG as fuel. The implementation in an existing plant will also be much more cost effective than the stand alone new build of a GT-LAES system, at least in the EU market with high NG prices. Of course this system can be also operated in cogeneration (coal, lignite or biomass) fired power plants. In that case the compression waste heat at the charging phase can be used alternatively in the district 16

17 heating system and lead to an increase of independence between heat demand and power production. 0,5 Combined Powering PCPP + LAES 0,4 0,3 0,2 Steam Cycle Time Shifted Power Generation Reduced minimum Load of PCPP Additional power in combined operation of PCPP and LAES system 0, P Netto [MW] Fig. 17: Combined operation of coal power plant with LAES system CONCLUSIONS In the present paper state of the art MHPSE technologies which contribute to the flexibility increase of today s thermal power plants are presented and discussed. Small scale retrofit measures, which utilise the inherent flexibility characteristics of modern thermal power plants, are initially presented. Furthermore, state of the art technologies, such as indirect firing and electric ignition, which can facilitate to the reduction of minimum load and to decrease of start-up costs are presented. At last, the Power to Methanol and Liquid Air Energy Storage technologies are discussed. A qualitative overview of the main characteristics of all described technologies is provided in Table 5 below. All concepts mentioned in this paper are able to serve the increasing requirements on highly flexible power generation in the future electricity generation system, while Power to Methanol (PTM) is also considered as a trans-sectorial energy storage & conversion, converting conventional power plants to flexible industrial devices operated in DSM and producing an all-purpose commodity like methanol. The financial feasibility of storage systems (PTM and LAES) proposed strongly depends from the future electricity market design. In the case of a high daily spread in the hourly electricity prices caused by high and low demand in the morning and evening, the application of the PCPP- LAES concept may have a positive business case operating as an improved and extended peaking plant, such as an open cycle gas turbine, and also as a storage facility providing ancillary services to the grid and utilising the arbitrage on daily basis. If electricity prices continue to decrease due to the increasing share of renewables increasingly fed to the grid, the PTM technology integrated in PCPPs can offer a new business case to power plants, which otherwise would suffer from high cost for frequent start-ups, high maintenance costs from increased wear and low income from decreased electricity production and decreased number of operating hours. Without additional sources of revenues like PTM the operation of those plants will not be economically feasible. Thus the particular plants will have to be mothballed or would require capacity payments or other incentives, in order to be available for back-up power and grid 17

18 control. However, the extensive application of these types of measures increases further the overall electricity cost to be paid by the consumers and hinders the development of a competitive EU Internal Energy Market. Hence, trans-sectorial energy storage, like Power to Methanol shall pay a significant role in the future energy system with very high shares of renewable electricity. Table 5: Qualitative evaluation of presented concepts for flexibility increase Decrease of minimum load Increase of ramp rate Reduction of auxiliary fuel costs Increase of part load efficiency Improvement of emissions performance at low load Comprehensive study and measurement campaign towards determination of the current state plant operation Upgrading I&C, boiler and plant I&C, safety safety systems system and flame Flame Monitoring System monitoring system Retrofit measures in firing system (incl. mills) Overall plant cycle retrofit measures Integration of energy storage technology Retrofits in mills Installation of additional indirect firing system Installation of a dedicated burner for indirect firing 1) 1) Replacement of thick walled components by other thinner walled ones using optimised materials Change of 2 - line to 4 - line arrangement Improving short term load flexibility by condensate stop concept (increasing feed water tank capacity, modernising turbine valves and I&C) Reduction of auxiliary power consumption through installation of variable speed controlled components (ID, FD fans) Retrofit at flue gas path, at SCR and FGD units Integration of Power to Methanol 2) 4) Integration of LAES 3) 4) 1) through improved control of stoichiometry and thus increased boiler efficiency / lower NOx in part load 2) through the integrated operation of the electrolyser following load demand 3) through the integrated operation of the compressor and expander following load demand 4) through the reduction of minimum load fewer start-ups per year will be required 5) through utilisation of excess electricity and the production of valuable fuels (methanol) Possible additional revenues 6) through the provision of an enlarged portfolio of ancillary services to the el. grid (e.g. higher primary energy reserve) 5) 6) 18