Condition and development of the cogeneration facilities based on autoproduction investment model in Turkey

Turkey, with its young population and growing energy demand per person, its fast growing urbanization, and its economic development, has been one of the fast growing power markets of the world for the last 20 years. It is expected that the demand for electric energy in Turkey will be 294 billion kWh by the year 2010 and 556 billion kWh by the year 2020. Turkey’s electric energy demand is growing 7% yearly. Because a substantial amount of Turkey’s energy need has been met by cogeneration facilities in recent years. Cogeneration facilities have an important role in Turkey’s energy strategy. While there were only four cogeneration facilities and the total capacity of them was 30 MW_e in 1994, in 1999, 10.6% of total electric production was produced by these facilities. In accordance with the governmental decree numbered 85/9799, cogeneration is the technology which produces electricity and heat synchronously and autoproduction is the name of the firm which was founded for the purpose of producing electricity and heat. In this study, the development of autoproduction facilities in Turkey, which are the most convenient legal investment model for cogeneration investors, has been investigated.     

Evaluating the role of cogeneration for carbon management in Alberta

Developing long-term carbon control strategies is important in energy intensive industries such as the oil sands operations in Alberta. We examine the use of cogeneration to satisfy the energy demands of oil sands operations in Alberta in the context of carbon management. This paper evaluates the role of cogeneration in meeting Provincial carbon management goals and discusses the arbitrary characteristics of facility- and product-based carbon emissions control regulations. We model an oil sands operation that operates with and without incorporated cogeneration. We compare CO₂ emissions and associated costs under different carbon emissions control regulations, including the present carbon emissions control regulation of Alberta. The results suggest that incorporating cogeneration into the growing oil sands industry could contribute in the near-term to reducing CO₂ emissions in Alberta. This analysis also shows that the different accounting methods and calculations of electricity offsets could lead to very different levels of incentives for cogeneration. Regulations that attempt to manage emissions on a product and facility basis may become arbitrary and complex as regulators attempt to approximate the effect of an economy-wide carbon price.     

Dynamic optimization of a cogeneration plant for an industrial application with two different hydrogen embedding solutions

Seasonal storage of hydrogen is a valuable option today increasingly considered in order to optimize cogeneration plants under continuous operation in an incentive framework where electricity sale to the national grids is becoming less economically profitable than in the past. The paper concerns the numerical study and optimization of a cogeneration plant installed in an industrial site having an availability of hydrogen over a continuous time scale, to meet the energy needs and mitigating the environmental impact of the plant operation by reducing the energy withdrawal from traditional sources. Two alternatives are analyzed into detail: the former regards energy production through an internal combustion engine, this last properly controlled to be fueled with blends of natural gas and increasing percentages of hydrogen, the latter concerning the addition of fuel cells to the proposed layout to further reduce the electricity integration by the grid. The dynamic response of the cogeneration system under examination is dynamically evaluated to efficiently fulfill the industrial loads to be fulfilled. First, optimization is performed by implementing a PID controller to better track the industrial demand of electric energy. The main results of this solution reveal a ?81% reduction of excess electricity, a ?7% reduction of natural gas consumed but a 47% raise of CO₂ emissions due to the increase in thermal integration. Then, an additional energy generation from fuel cells is assumed. An economic analysis is carried out for each of the implemented configurations. The adoption of fuel cells, despite requiring a greater initial investment, allows obtaining a SPB of 1,4 years (? 16%), 1,17 Mln € of avoided costs (? 18,5%) and 1320 t/year of CO₂ emissions avoided (? 95%) with respect to the initial layout.     

Government policy and the development of electric vehicles in Japan

The aim of this paper is to analyse the role that the Japanese Government has played in the development of alternatives to conventional vehicles, the effect of government programmes, and the importance of technical flexibility in government support schemes. The focus is on battery-powered electric vehicles (BPEVs), hybrid electric vehicles (HEVs), and fuel cell electric vehicles.     

Sustainability assessment of cogeneration sector development in Croatia

The effective and rational energy generation and supply is one of the main presumptions of sustainable development. Combined heat and power production, or co-generation, has clear environmental advantages by increasing energy efficiency and decreasing carbon emissions. However, higher investment cost and more complicated design and maintenance sometimes-present disadvantages from the economical viability point of view. As in the case of most of economies in transition in Central and Eastern Europe, Croatia has a strong but not very efficient co-generation sector, delivering 12% of the final energy consumption. District heating systems in the country's capital Zagreb and in city of Osijek represent the large share of the overall co-generation capacity. Besides district heating, co-generation in industry sector is also relatively well developed. The paper presents an attempt to assess the sustainability of Croatian co-generation sector future development. The sustainability assessment requires multi-criteria assessment of specific scenarios to be taken into consideration. In this respect three scenarios of Croatian co-generation sector future development are taken into consideration and for each of them environmental, social and economic sustainability indicators are defined and calculated. The assessment of complex relationships between environmental, social and economic aspects of the system is based on the multi-criteria decision-making procedure. The sustainability assessment is based on the General Sustainability Index rating for different cases reflecting different criteria and their priority. The method of sustainability assessment is applied to the Croatian co-generation sector contributing to the evaluation of different strategies and definition of a foundation for policy related to the sustainable future cogeneration sector development.     

Evaluating the power investment options with uncertainty in climate policy

This paper uses a real options approach (ROA) for analysing the effects of government climate policy uncertainty on private investors’ decision-making in the power sector. It presents an analysis undertaken by the International Energy Agency (IEA) that implements ROA within a dynamic programming approach for technology investment choice. Case studies for gas, coal and nuclear power investment are undertaken with the model. Illustrative results from the model indicate four broad conclusions: i) climate change policy risks can become large if there is only a short time between a future climate policy event such as post-2012 and the time when the investment decision is being made; ii) the way in which CO₂ and fuel price variations feed through to electricity price variations is an important determinant of the overall investment risk that companies will face; iii) investment risks vary according to the technology being considered, with nuclear power appearing to be particularly exposed to fuel and CO₂ price risks under various assumptions; and iv) the government will be able to reduce investors' risks by implementing long-term (say 10 years) rather than short-term (say 5 years) climate change policy frameworks. Contributions of this study include: (1) having created a step function with stochastic volume of jump at a particular time to simulate carbon price shock under a particular climate policy event; (2) quantifying the implicit risk premium of carbon price uncertainty to investors in new capacity; (3) evaluating carbon price risk alongside energy price risk in investment decision-making; and (4) demonstrating ROA to be a useful tool to quantify the impacts of climate change policy uncertainty on power investment.     

Feasibility of small-scale gas engine-based residential cogeneration in Spain

Nowadays all countries are developing their own policies to promote cogeneration in the small-scale residential sector. In this paper the feasibility of small-scale gas engine-based residential cogeneration plants under the current Spanish regulation is studied. A unitary thermal load profile is obtained to characterised the thermal demand of residential applications in Spain. This unitary profile is used to analyse the potential of cogeneration in the small-scale range of powers (100–1000 kW). A complete characterisation of the gas fuelled engines in the market is performed and subsequently used to evaluate the economic feasibility within the selected range by means of a self-tailored simulation model. It is underlined how the thermal storage is a crucial element that should be suitably included in a residential cogeneration plant and the distortions that the actual pricing system adds to the profitability of residential plants of different sizes. Finally a sensibility study is carried out in order to evaluate how the Spanish regulation is able to deal with future variations in the energy prices. It is shown that a rise in the price of the natural gas increases the current feasibility of a plant while a decrease descends the profitability.     

The German Renewable Energy Sources Act—an investment into the future pays off already today

While the success of the German Renewable Energy Sources Act in supporting the use of renewable energy sources for electricity generation is widely acknowledged, it is partly criticised for imposing unjustified extra costs on society. Based on the well established ExternE methodology for the quantification of environmental externalities the paper makes an attempt to estimate the external costs avoided in the German energy system due to the use of renewable energies for electricity generation, and to compare them against the compensation to be paid by grid operators for electricity from renewable energies according to the Renewable Energy Sources Act. In spite of existing uncertainties associated with the assessment of external costs, results clearly indicate that the reduced environmental impacts and related economic benefits do outweigh the additional costs for the compensation of electricity from renewable energies.     

An analysis of the legal and market framework for the cogeneration sector in Croatia

Following a strategic orientation towards sustainable development, the Government of the Republic of Croatia has changed its energy legislation and has put forward a framework for the systematic development and increased use of renewable energy sources and cogeneration. This paper focuses on changes in the regulatory context relevant to the cogeneration sector and also analyses the impact of energy market transition on cogeneration viability in municipal district heating, industry, services and the residential sector. Particular attention has been paid to the expected changes of heat, electricity and gas prices. We present a simple model for quantitative prediction of the cogeneration system profitability at different power levels under given national circumstances. Our findings support a need for a strong institutional support for initial penetration of the micro-cogeneration technologies into the Croatian energy system.     

CPH systems for cogeneration of power and hydrogen from coal

Three layouts with an integrated coal gasifier hydrogen production and a small powerplant section have been modelled using a computer code (ASPEN PLUS^TM${\mathrm{PLUS}}^{\mathrm{TM}}$). The integration allows to eliminate or to reduce the losses at the condenser of the powerplant: the steam is reheated and fed to the gasifier. The resulting counterpressure operation of the powerplant is justified like in a co-generator of heat and power (CHP). In this case we have a co-generation of power and hydrogen (CPH). Therefore the efficiency of the power plant is not high, but it shows an “apparent” efficiency very high. Even if the concept has been demonstrated, further work is required because power generation is very small with respect to the hydrogen production.     

An estimation of cogeneration potential by using refinery residuals in Mexico

Electric power generation in Mexico is mainly based on fossil fuels, specifically heavy fuel oil, although the use of natural gas combined cycles (NGCC) is becoming increasingly important. This is the main destination that has promoted growing imports of natural gas, currently accounting for about 20% of the total national annual consumption. Available crude oil is becoming heavier; thus refineries should be able to process it, and to handle greater quantities of refinery residuals. If all refinery residuals are used in cogeneration plants serving petroleum refineries, the high heat/power ratio of refinery needs, leads to the availability of appreciable quantities of electricity that can be exported to the public utility. Thus, in a global perspective, Mexican imports of natural gas may be reduced by cogeneration using refinery residuals. This is not the authors’ idea; in fact, PEMEX, the national oil company, has been entitled by the Mexican congress to sell its power leftovers to The Federal Electricity Commission (CFE) in order to use cogeneration in the way described for the years to come. A systematic way of determining the cogeneration potential by using refinery residuals from Mexican refineries is presented here, taking into account residual quantities and composition, from a national perspective, considering expected scenarios for Maya crude content going to local refineries in the years to come. Among different available technologies for cogeneration using refinery residuals, it is believed that the integrated gasification combined cycle (IGCC) would be the best option. Thus, considering IGCC plants supplying heat and power to refineries where it is projected to have refinery residuals for cogeneration, the expected electric power that can be sent to the public utility is quantified, along with the natural gas imports mitigation that may be attained. This in turn would contribute to a necessary fuel diversification policy balancing energy, economy and ecology.     

Decentralised optimisation of cogeneration in virtual power plants

Within several projects we investigated grid structures and management strategies for active grids with high penetration of renewable energy resources and distributed generation (RES & DG). Those ”smart grids” should be designed and managed by model based methods, which are elaborated within these projects. Cogeneration plants (CHP) can reduce the greenhouse gas emissions by locally producing heat and electricity. The integration of thermal storage devices is suitable to get more flexibility for the cogeneration operation. If several power plants are bound to centrally managed clusters, it is called “virtual power plant”. To operate smart grids optimally, new optimisation and model reduction techniques are necessary to get rid with the complexity.There is a great potential for the optimised management of CHPs, which is not yet used. Due to the fact that electrical and thermal demands do not occur simultaneously, a thermally driven CHP cannot supply electrical peak loads when needed. With the usage of thermal storage systems it is possible to decouple electric and thermal production. We developed an optimisation method based on mixed integer linear programming (MILP) for the management of local heat supply systems with CHPs, heating boilers and thermal storages. The algorithm allows the production of thermal and electric energy with a maximal benefit. In addition to fuel and maintenance costs it is assumed that the produced electricity of the CHP is sold at dynamic prices. This developed optimisation algorithm was used for an existing local heat system with 5 CHP units of the same type. An analysis of the potential showed that about 10% increase in benefit is possible compared to a typical thermally driven CHP system under current German boundary conditions. The quality of the optimisation result depends on an accurate prognosis of the thermal load which is realised with an empiric formula fitted with measured data by a multiple regression method.The key functionality of a virtual power plant is to increase the value of the produced power by clustering different plants. The first step of the optimisation concerns the local operation of the individual power generator, the second step is to calculate the contribution to the virtual power plant. With small extensions the suggested MILP algorithm can be used for an overall EEX (European Energy Exchange) optimised management of clustered CHP systems in form of the virtual power plant. This algorithm has been used to control cogeneration plants within a distribution grid.     

Role of a district-heating network as a user of waste-heat supply from various sources – the case of Göteborg

District-heating (DH) networks can utilise heat that would otherwise be of limited use. This study analyses a municipal DH system, which uses waste heat from industries and waste incineration as base suppliers of heat and is currently investing in a natural-gas fired combined heat-and-power (CHP) plant. An important assumption in this study is of the establishment of an integrated European electricity-market, which means higher electricity prices than are traditional in Sweden. The study shows that there is space in the DH system for all three energy carriers; heat from industries, waste incineration and CHP plants. The new CHP plant replaces mainly other heat sources, i.e., hot water boilers and heat pumps. The new CHP plant’s operating time is strongly dependent on the electricity price.     

Enhancing the performance of a high-pressure cogeneration boiler with waste hydrogen-rich fuel

The cogeneration boiler has been applied extensively for simultaneously supplying electrical power and high-pressure steam. In this study, the performance of a high-pressure cogeneration boiler (max 280 tons/h boiler capacity) that burnt fuel oil (FO) and natural gas (NG) in a full-scale petrochemical plant was enhanced by partially replacing the NG with a waste hydrogen-rich refinery gas (RG), a byproduct from catalytic reforming and catalytic cracking operations. The addition of RG does not influence the boiler efficiency; it results in saving the energy consumption and significantly decreasing the greenhouse gas emission. If the inlet FO/NG/RG volumetric flow rate ratio is maintained at 50:33:17, adding RG will save 14,500,000 m³/year of NG and reduce 12,900 tons/year of CO₂ emission. Therefore, the use of RG to partially replace NG has practical benefits for reducing energy consumption and greenhouse gas emission.     

Impact of tax reform on renewable energy and cogeneration projects

This study examines the sensitivity of renewable energy and cogeneration project returns to proposed changes in the federal tax code, specifically to reforms proposed in 1985 by President Reagan. We examine six different technologies by defining typical configurations. Project cash flows are projected over a twelve year horizon, and the investor's internal rate of return (IRR) is calculated. We calculate changes in IRR as various proposed tax changes are assumed to take effect. We find that capital intensive projects, such as geothermal and small hydro, suffer most from proposed tax code changes. Conversely, the least capital intensive projects, cogeneration, fare best.     

Optimal planning and economic evaluation of cogeneration system

Cogeneration plants, which simultaneously produce electricity and heat energy, have been introduced increasingly for commercial and domestic applications in Korea because of their energy efficiency. The optimal plant configuration of a specific commercial building can be determined by selecting the sizes and the number of cogeneration systems and the auxiliary equipment based on the annual demands of electricity, heating and cooling. In this study, a mixed-integer, linear programming, utilizing the branch and bound algorithm was used to obtain the optimal solution. Both the optimal configuration system equipment and the optimal operational mode were determined based on the annual cost method for the installation of a cogeneration system to a hospital and a group of apartments in Seoul, Korea. In addition, the economic evaluation for the optimal cogeneration system depending on the fuel tariff system was calculated. A short payback period and higher internal rate of return on the initial investment were found to be essential for the adoption of cogeneration plants to hospitals and apartments.     

Assessment of current Dutch energy transition policy instruments for the existing housing stock

This research assesses to what extent current Dutch energy transition policy instruments for the existing housing stock can fulfil local executive actors’ needs and instigate adoption of energy efficiency measures by them. This is done by studying energy policy instruments for the existing housing stock in the Netherlands and in other European countries, and by an empirical research, which analyses barriers and needs of local executive actors. We found that, despite current Dutch energy transition policy instruments for the existing housing stock seem to fulfil local executive actors’ needs to a large extent, complementary policy instruments are needed to stimulate and pressure the incumbent renovation regime. A long-term oriented financial rewarding system is needed to build up a structural market for the deployment of renewables, to increase the number of specialist jobs in the building sector, and to stimulate the development of integrated, standardized, building components. Furthermore, a long-term oriented financial rewarding system for energy efficiency investments in housing renovation projects, and a low VAT rate applied to energy efficient renovation measures, are needed. Finally, enforcement possibilities and sanctions (fines) should become an integrative part of Dutch energy certification regulation to make the certificate become part of a value chain.     

Targeting cogeneration and waste utilization through process integration

In this paper we focus on energy flows and specifically on the complex interactions between heat and power generation and use in steam systems along with combustible wastes of the process. Our objective is to present a systematic methodology for the quick targeting of power cogeneration potential in steam systems ahead of designing the power generation network. The devised approach makes effective utilization of combustible wastes and reconciles the use and dispatch of process fuel sources, heating and non-heating uses of steam, and power generation. The new concept of extractable energy is introduced to facilitate a simple calculation of cogeneration potential in the process. Balances around steam headers are used to identify surpluses and deficits. Next, surplus and deficit composite curves are constructed to identify feasible transfers of extractable energy. The result is the identification of the cogeneration target and excess steam that can be used in condensing turbines. This methodology takes a holistic view of the process and can easily be combined with other mass and energy integration techniques. It specifically accommodates both (a) production objectives (mass integration) and (b) heat recovery network targeting and utility selection (energy integration). An example problem is presented to illustrate the methodology.     

Returns on investment in electricity producing photovoltaic systems under de-escalating feed-in tariffs: The case of Greece

Under the threat of ballooning energy bills, the Greek legal framework supporting the electricity producing photovoltaic systems (PVS) changed in January 2009 from a fixed to a de-escalating feed-in tariff schedule. In this paper we investigate the internal rate of return (IRR) on investing in PVS under the new regulatory environment. We find that the new scheme favours strongly the early entry in the market. Unless there is a significant decrease in the equipment cost over the next decade, entering the market from 2015 onwards will be prohibitive. The bias of the current policy design towards early entry in a rapidly developing set of technologies entails the risk of a lock-up with sub-optimal technological option. This outlines the importance for policy design of linking the rate of feed-in-tariff de-escalation to more realistic expectations regarding the technology learning curve.