The present study presents a techno-economic analysis of a novel power plant layout developed to increase the dispatch flexibility of a Combined Cycle Gas Turbine (CCGT) coupled to a District Heating Network (DHN). The layout includes the incorporation of high temperature heat pumps (HP) and thermal energy storage (TES). A model for optimizing the short-term dispatch strategy of such system has been developed to maximize its operational profit. The constraints and boundary conditions considered in the study include hourly demand and price of electricity and heat, ambient conditions and CO 2 emission allowances. To assess the techno-economic benefit of the new layout, a year of operation was simulated for a power plant in Turin, Italy. Furthermore, different layout configurations and critical size-related parameters were considered. Finally, a sensitivity analysis was made to assess the performance under different market scenarios. The results show that it is indeed beneficial, under the assumed market conditions, to integrate a HP in a CCGT plant coupled to a DHN, and that it remains profitable to do so under a variety of market scenarios. The best results for the assumed market conditions were found when integrating a 15 MW th capacity HP in the 400 MW el CCGT-CHP. For this case study, the investment in the HP would yield a net present value (NPV) of 1.22 M€ and an internal rate of return (IRR) of 3.04% for a lifetime of 20 years. An increase was shown also in operational flexibility with 0.14% of the electricity production shifted while meeting the same heating demand. Additionally, it was found that the TES makes the system even more flexible, but does not make up for the extra investment.

In the pursuit of increasing their profitability, the design and operation of combined cycle power plants needs to be optimized for new liberalized markets with large penetration of renewables. A clear consequence of such renewable integration is the need for these plants for being more flexible in terms of ramping-up periods and higher part-load efficiencies. Flexibility becomes an even clearer need for combined heat and power plants to be more competitive, particularly when simultaneously following the market hourly price dynamics and varying demands for both the heat and the electricity markets. In this paper, three new plant layouts have been investigated by integrating different storage concepts and heat-pump units in key sections of a traditional plant layout. The study analyses the influence that market has on determining the optimum layouts for maximizing profits in energy-only markets (in terms of plant configuration, sizing and operation strategies). The study is performed for a given location nearby Turin, Italy, for which hourly electricity and heat prices, as well as meteorological data, have been gathered. A multi-parameter modeling approach was followed using KTH’s in house techno-economic modeling tool, which uses time-dependent market data, e.g. price and weather, to determine the trade-off curves between minimizing investment and maximizing profits when varying critical size-related power plant parameters e.g. installed power capacities and storage size, for pre-defined layouts and operating strategies. A comparative analysis between the best configurations found for each of the proposed layouts and the reference plant is presented in the discussion section of the results. For the specific case study set in northern Italy, it is shown that the integration of a pre-cooling loop into baseload-like power-oriented combined cycle plants is not justified, calling for investigating new markets and different operating strategies. Only the integration of a heat pump alone was shown to improve the profitability, but within the margin of error of the study. Alternatively, a layout where district heating supply water is preheated with a combination of a heat pump with hot thermal tank was able to increase the internal rate of return of the plant by up to 0.5%, absolute, yet within the error margin and thus not justifying the added complexity in operation and in investment costs. All in all, the analysis shows that even when considering energy-only market revenue streams (i.e. heat and electricity sells) the integration of heat pump and storage units could increase the profitability of plants by making them more flexible in terms of power output levels and load variations. The latter is shown true even when excluding other flexibility-related revenue streams. It is therefore conclusively suggested to further investigate the proposed layouts in markets with larger heat and power price variations, as well as to investigate the impact of additional control logics and dispatch strategies.

This paper presents the development of a simulation tool for modeling the transient behavior of micro-CHP systems, equipped with both thermal and electric storage units and connected with both electric and district heating grid. The prime mover considered in this paper is an internal combustion reciprocating engine, which is currently the only well-established micro-CHP technology. Different users, characterized by different demands of electric and thermal energy, both in terms of absolute value and electric-to-thermal energy ratio, are analyzed in this paper. Both summer and winter hourly trends of electric and thermal energy demand are simulated by using literature data. The results present a comprehensive energy analysis of all scenarios on a daily basis, in terms of both user demand met and energy share among system components. The transient response of the prime mover and the thermal energy storage is also analyzed for the two scenarios with the lowest and highest daily energy demand, together with the trend over time of the state of charge of both thermal and electric energy storage.

In the next years energy grids are expected to become increasingly complex, due to the integration between traditional generators (operating with fossil fuels, especially natural gas), renewable energy production systems and storage devices. Furthermore, the increase of installed distributed generation systems is posing new issues for the existing grids. The integration involves both electric grids and thermal networks, such as district heating networks. In this scenario, it is fundamental to optimize the production mix and the operation of each system, in order to maximize the renewable energies exploitation, minimize the economic costs (in particular the fossil fuel consumption) and the environmental impact. The aim of this paper is the analysis of different solutions in terms of energy generation mix, in order to define the optimal configuration for a given network. With this purpose, in this study a real district heating network served by a combined heat and power unit and four boilers has been considered. The current mode of operation of the selected network has been simulated, in order to individuate eventual criticism and/or improvement possibility. On the basis of the obtained results, several scenarios have been developed by considering the addition of thermal or electric energy production systems from renewable energy sources and/or heat pumps. For a given scenario, a whole year of operation has been simulated with an in-house developed software, called EGO (Energy Grid Optimizer), based on genetic algorithms and able to define the load distribution of a number of energy systems operating into an energy grid, with the aim to minimize the total cost of the energy production. Further considered constraints have been the avoiding of thermal dissipations and the minimization of the electric energy sale to the national grid (in order to increase the grid stability). The carried out analysis has allowed to evaluate the yearly fuel consumption, the yearly electric energy sold to the network and the yearly electric energy purchased from the network, for each of the developed configurations. In this study the obtained results have been discussed in order to compare the proposed scenarios and to define an optimal solution, which enables to reduce the yearly operation costs of the production plant.

Ansaldo Energia AE64.3A gas turbine is especially effective in small to medium size applications such as grid support, co-generation and district heating applications due its F-class efficiency coupled with proven affordability, optimal size and low life cycle costs. This paper describes the latest AE64.3A gas turbine configuration that is now available. Technical features are presented in detail: the compressor and the hot-section turbine fourth stage have been directly derived from the AE94.3A F-class 310 MW size gas turbine design; the exhaust gas duct improved with profiled struts; the journal and axial-thrust bearing enhanced in performance; a two-steps secondary air optimization strategy for engine performance increase has led the upgrades of the air-cooled turbine stages, of the combustion chamber equipped with ceramic-tiles and of the high-temperature low-NOx burners. The specific burners which are capable of burning low-BTU gas with LHV down to 19 MJ/kg are also described. Finally the technical features of the turbine blades and vanes with maintenance intervals extended to 33’000 Equivalent Operating Hours are presented.

This paper describes the first completely gas-turbine powered stations used for supplying primary power for military installations. The stations, with one exception, are equipped with waste-heat boilers which supply steam for use in all heating including barracks. Gas turbines were specified as the most economical means of satisfying the electric power and central heating requirements. The stations are completely self-contained with no connection to any commercial power. The gas turbines, with one exception, use natural gas as the primary fuel and No. 2 diesel fuel as standby fuel. Changeover to liquid fuel is automatic. Change back to gas is manual.

The closed-cycle gas turbine (CCGT) may well emerge in the foreseeable future as a major contributor to the U. S. electric utility industry because of: (a) its adaptability to coal-fired and to nuclear heat sources, (b) very high fuel utilization efficiency when the high grade waste heat is used, (c) potential for high degree of reliability and availability and low maintenance, (d) efficient, cost-effective dry cooling where no cooling water is available, and (e) an established technology base for commercial introduction into the power generation industry. In addition, the gas turbine HTGR provides a vehicle for demonstrating and developing the technology for economical nuclear process heat. In Europe, the closed-cycle gas turbine has demonstrated a high degree of reliability and availability, with both air and helium as working fluids. Power plants up to 50 MWe have operated successfully on a variety of liquid, gaseous, and solid fossil fuels. The waste heat thermal energy from these plants, in the form of hot water, has been used for urban and industrial district heating with the result that the fuel utilization efficiency has approached 80 percent, an impressive value indeed for an approaching era of energy conservation, where high power plant efficiency, and particularly high energy utilization effectiveness will be of the essence. In this paper, the established technology bases for closed-cycle gas turbines and high temperature gas cooled reactors (HTGR) are summarized.

The utilization of coal-fired closed cycle gas turbine/atmospheric fluidized bed (CCGT/AFB) electrical power generating plants for cogeneration was investigated in a Department of Energy-sponsored study program conducted by The Garrett Corporation. Both industrial process and district heating and cooling applications in the 10- to 50-MW e range were considered. An evaluation procedure was developed in which cogeneration plant capital, operating, maintenance, and financing costs are calculated and compared with the cost of providing equivalent services by traditional methods. Computer optimized conceptual designs of the CCGT/AFB plants were prepared, and performance and capital costs were estimated. A broad spectrum of applications including towns, military bases, universities, and industrial processes was surveyed. This paper presents the general evaluation procedure, typical plant designs, and the evaluation of two applications.

Technical and economic aspects of utilization of steam and gas turbine plans for district heating are presented and discussed. Combined use of these plants for heat and electrical generation is considered. Advantages of flexible and combined operation, wide load variation and increase of the district heating supply temperature are presented and discussed.

Technical aspects of utilization of gas turbines for district heating applications are discussed. Economic advantages of gas turbine plants for district heating loads below 700 MWt are presented. Use of gas turbines with steam turbines in different combinations are also discussed.

The evaluation of the performance of a cogeneration cycle is a complex balance of heat assignments for various portions of the cycle. Selection of the optimum gas turbine, steam turbine, and boiler combination to match the process or district heating requirements requires numerous heat balances. A method is presented to determine the most fuel-efficient cycle as well as the most efficient combination of equipment to meet the load profile. This system of plotting performance facilitates the selection of a combination that is the most economical for a given electrical and heat load requirement. Parameters of boiler supplemental firing temperature and equivalent electrical heat rate with steam flow and total fuel consumption for all load conditions are displayed.

It is widely accepted that coal gasification combined-cycle plants represent an environmentally superior alternative to conventional coal fired power plants with flue gas desulfurization. Purpose of this paper is to show that technology is available for all steps required to convert coal to electricity, including treatment of waste streams. Based on examples for power plants in the 200–800 MW range using current and as well as advanced gas turbines, it is shown that under both European and US-conditions cost of electricity from this (new) route of coal based power generation is certainly no higher — and probably even lower — than from conventional PC (pulverized coal) power plants equipped with equivalent environmental control technology. Thus, this technology is likely to be a prime contributor when it comes to enhance environmental acceptability of power plants in general, and to help solve the acid rain problem in particular. In addition the versatility of the proposed technology for repowering, decentralized application and district heat system is explained.

District heating projects in the Netherlands are cogeneration projects with special emphasis on high-efficiency power generation. Together with their customer N.V. IJsselcentrale, Thomassen International B.V., designed a cogeneration system based on gas and steam turbines. The system has following main features: - the gross electrical efficiency of the system is over 50%, which is a highly remarkable achievement in power generation - the main components, 2 gas turbines, a steam turbine and one generator are mounted in line on a single shaft. Successful start up of the plant happened in November 1985, performance tests have shown the target of power generation with an efficiency of 50% is met.

This paper considers the utilization of the high temperature Brayton closed cycle with air cooled atmospheric fluidized bed combustor in district heating plants. The main features of a closed cycle plant are compared with those of a conventional steam cycle plant with flue gas desulphurization and with a steam plant fired by a circulating atmospheric fluidized bed boiler. The characteristics of the main items are analyzed.

In the past 15 years the combined-cycle (gas/steam turbine) power plant has come into its own in the power generation market. Today, approximately 30 000 MW of power are already installed or being built as combined-cycle units. Combined-cycle plants are therefore a proven technology, showing not only impressive thermal efficiency ratings of up to 50 percent in theory, but also proving them in practice and everyday operation (1) (2). Combined-cycle installations can be used for many purposes. They range from power plants for power generation only, to cogeneration plants for district heating or combined cycles with maximum additional firing (3). The main obstacle to further expansion of the combined cycle principle is its lack of fuel flexibility. To this day, gas turbines are still limited to gaseous or liquid fuels. This paper shows a viable way to add a cheap solid fuel, coal, to the list. The plant system in question is a 2 × 150 MW combined-cycle plant of BBC Brown Boveri with integrated coal gasification plant of British Gas/Lurgi. The main point of interest is that all the individual components of the power plant described in this paper have proven their worth commercially. It is therefore not a pilot plant but a viable commercial proposition.

A number of studies have shown that the Kalina cycle, using an ammonia-water mixture, can reach higher efficiencies than the normal steam Rankine cycle. In this paper, the Kalina cycle, with a gas turbine topping cycle is applied to cogeneration for district heating. Since the district heating temperatures vary with the heat demand over the year, this application may prove to be especially suitable for the Kalina cycle with its many degrees of freedom in the condensation system. A theoretical comparison between different bottoming cycles producing heat for a typical Scandinavian district heating network has been carried out. The Kalina cycle, the Rankine cycle with a mixture of ammonia and water as the working fluid and the normal single pressure steam Rankine cycle are compared. It is shown that a simple Rankine cycle with an ammonia-water mixture as the working fluid produces more heat and power than the steam Rankine cycle. The best results, however, are obtained for the Kalina cycle, which generates considerably higher heat and power output than the steam Rankine cycle.

With current gas turbine practice up to two-thirds of the energy available in the fuel is lost in the form of unused heat, By making practical use of this waste heat in a recovery boiler to produce steam for district heating or process applications it is possible to reduce the energy wastage to as little as 10 percent. In this paper different performance criteria for assessment of a gas turbine cogeneration plant (GTCP) have been defined and compared with each other, Also, the practical range of performance criteria have been determined.

This paper has been written exactly 50 years after the first disclosure of a closed-cycle gas turbine concept with a simplistic uranium heater. Clearly, this plant was ahead of its time in terms of technology readiness, and the closed-cycle gas turbine was initially deployed in a cogeneration mode burning dirty fuels (e.g., coal, furnace gases). In the 1950s through the mid 1980s about 20 of these plants operated providing electrical power and district heating for European cities. The basic concept of a nuclear gas turbine plant was demonstrated in the USA on a small scale in 1961 with a mobile closed-cycle nitrogen gas turbine [330 KW(e)] coupled with a nuclear reactor. In the last three decades, closed-cycle gas turbine research and development, particularly in the U.S. has focused on space power systems, but today the utility size gas turbine-modular helium reactor (GT-MHR) is on the verge of being realized. The theme of this paper traces the half century of closed-cycle gas turbine evolution, and discusses the recent enabling technologies (e.g., magnetic bearings, compact recuperator) that now make the GT-MHR close to realization. The author would like to dedicate this paper to the late Professor Curt Keller who in 1935 filed the first closed-cycle gas turbine patent in Switzerland, and who exactly 50 years ago, first described a power plant involving the coupling of a helium gas turbine with a uranium heater.

Among cogeneration facilities block heating stations and large combined cycle plants are two extreme examples of district heating technologies. In this paper, these two alternatives will be applied to one and the same representative district heating task. The thermodynamic differences will be made clear and the advantages of heating by extracting steam from a combined cycle plant will become evident. An important conclusion from an engineering point of view is that extracting heat from a combined cycle plant should be considered even if this plant is located at greater distances from the heat consumers.

The paper deals with optimal sizing of a gas turbine for repowering of cogeneration power plant Ljubljana considering possible plant operational strategy with respect to variations of electric and heat loads and energy costs. CHP plant is a main source for the Ljubljana town district heating system. Existing plant consists of two condensing steam turbines with steam extraction, back pressure turbine with steam extraction, auxiliary steam and hot water boilers for peak heat load production. This system delivers up to 111 MW into the power grid and up to 348 MW of heat. Repowering with gas turbine generator set with additionally fired heat recovery boiler is considered. For uncoupling heat and power generation a heat storage tank is assumed. For sizing of new equipment and plant operational strategy a model based on mixed-integer linear programming was developed. Zero - one integer variables are adopted to indicate the on/off status of operation, continuous variables to indicate the operational level of each constituent equipment and an optimal solution is derived by branch and bound method. Two prospective sizes of TG sets were tested for range of assumptions regarding power purchase tariff schedules. Different optimal operation policies resulted. The study provides background for contract negotiation and for investment decisions.