Modelling of hydrogen production from hydrogen sulfide in geothermal power plants

Geothermal power plants emit high amount of hydrogen sulfide (H₂S). The presence of H₂S in the air, water, soils and vegetation is one of the main environmental concerns for geothermal fields. There is an increasing interest in developing suitable methods and technologies to produce hydrogen from H₂S as promising alternative solution for energy requirements. In the present study, the AMIS technology is the invention of a proprietary technology (AMIS^® - acronym for “Abatement of Mercury and Hydrogen Sulfide” in Italian language) for the abatement of hydrogen sulphide and mercury emission, is primarily employed to produce hydrogen from H₂S. A proton exchange membrane (PEM) electrolyzer operates at 150 °C with gaseous H₂S sulfur dimer in the anode compartment and hydrogen gas in the cathode compartment. Thermodynamic calculations of electrolysis process are made and parametric studies are undertaken by changing several parameters of the process. Also, energy and exergy efficiencies of the process are calculated as % 27.8 and % 57.1 at 150 °C inlet temperature of H₂S, respectively.     

Problems of hydrogen application in space power plants and power propulsion plants

Application of hydrogen is a necessary condition to achieve acceptable power and overall-dimensional characteristics of space power and propulsion plants. Some functional elements as part of the plants require protection from hydrogen, which is provided by construction and technological preparation of materials. For subsequent improvement of the plants, it is necessary to look for materials with low hydrogen penetrability in the temperature range of 800–2500 K and also for protective coatings on graphite for conditions of thermocycling in the range of 300–2100 K.     

Modified exergoeconomic modeling of geothermal power plants

In this study, a modified exergoeconomic model is proposed for geothermal power plants using exergy and cost accounting analyses, and a case study is in this regard presented for the Tuzla geothermal power plant system (Tuzla GPPS) in Turkey to illustrate an application of the currently modified exergoeconomic model. Tuzla GPPS has a total installed capacity of 7.5 MW and was recently put into operation. Electricity is generated using a binary cycle. In the analysis, the actual system data are used to assess the power plant system performance through both energy and exergy efficiencies, exergy losses and loss cost rates. Exergy efficiency values vary between 35% and 49% with an average exergy efficiency of 45.2%. The relations between the capital costs and the exergetic loss/destruction for the system components are studied. Six new exergetic cost parameters, e.g., the component annualized cost rate, exergy balance cost, overall unavoidable system exergy destruction/loss cost rate, overall unavoidable system exergy destruction/loss cost rate, overall unavoidable system exergy production cost rate and the overall unavoidable system exergy production cost rate are studied to provide a more comprehensive evaluation of the system.     

Predictive economic efficiency of combining nuclear power plants with autonomous hydrogen power complex

Currently, the United Energy System (UEC) of Russia is trending in the deficit of peak and half-peak capacity with a simultaneous increase in the number of nuclear power plants (NPPs), which will require the participation of the NPPs in the variable part of the schedule of electrical loads.In addition to the economic need to maintain the high-level utilization rate, there are technological limitations of maneuverability for NPPs.The authors developed an approach to solving this problem by combining with an environmentally friendly energy source – an autonomous hydrogen power complex, which includes thermal batteries and an additional multifunctional low-power steam turbine installation.The developed energy complex can also provide reliable reservation of electricity supply to consumers of their own needs of the nuclear power plant in case of complete blackout of the plant.The feasibility study of the main equipment of the autonomous hydrogen power complex, which is necessary for combining with a two-unit nuclear power plant with WWER-1000, has been evaluated.On the basis of the assessment of the inflation indicators of the Russian economy over the past 11 years, three variants of fuel cost dynamics and tariff rates for electricity (capacity) as well as the size of operating costs, including depreciation deductions to the main equipment, are defined, taking into account the current principles of price formation.The result is a value for accumulated net present value, depending on the ratio of the cost of the half-peak and off-peak electricity at different inflation rates.The positive economic effect of reducing the risk of the core damage accident, replacing the construction of the gas turbine unit as a maneuverable source of electricity in the power grid and increasing the income of the Russian federal budget from the savings of natural gas has been taken into account.The greatest economic efficiency is achieved with maximum projected inflation, which is associated with the maximum rate of discounting and the high rate of growth of electricity tariffs.Reducing the risk of the core damage accident ensures that the proposed approach is competitive in all the inflation options under consideration and the ratio of electricity tariffs.     

Woody biomass supply potential for thermal power plants in Japan

Biomass energy is one of mitigation method of CO₂ reduction. In Japan, it aimed to reduce fossil fuels supply 670,000 kL of crude oil equivalent in thermal power plants and 340,000 kL of crude oil equivalent in the utilization of heat by biomass. It was decided to use 25% or more of the forestry products such as logging residues. Japanese government aim to supply 634 PJ of woody biomass for power generation in 2010. This amount of energy accounts for 2.8% of total primary energy. More than 68% of Japan is covered by forests, and more than 40% of these forests are plantations. But the use of woody biomass is limited because it is still not seen as economically viable. In this article, we developed a large scale forestry economic model which can estimate the wood chips supply for coal thermal power plants across all around Japan. By using this model, wood chips supply potential is currently 32,000 m³/year and supply will increase drastically when wood chips price increase or carbon credit is installed and we found that biomass production of 15 PJ that is the numeric target of Japanese government is possible. Especially, the lengthening of rotation period of forestry and the decrease of wood chips transportation cost is important for wood chips use in coal thermal plant.     

Exergetic analysis of various types of geothermal power plants

Based on available surveys, it has been shown that Iran has substantial geothermal potential in the north and north-western provinces, where in some places the temperature reaches 240 °C. In order to better exploit these renewable resources, it is necessary to study this area. Thus, the aim of this paper is a comparative study of the different geothermal power plant concepts, based on the exergy analysis for high-temperature geothermal resources. The considered cycles for this study are a binary geothermal power plant using a simple organic Rankine cycle (ORC), a binary geothermal power plant using an ORC with an internal heat exchanger (IHE), a binary cycle with a regenerative ORC, a binary cycle with a regenerative ORC with an IHE, a single-flash geothermal power plant, a double-flash geothermal power plant and a combined flash-binary power plant. With respect to each cycle, a thermodynamic model had to be developed. Model validation was undertaken using available data from the literature. Based on the exergy analysis, a comparative study was done to clarify the best cycle configuration. The performance of each cycle has been discussed in terms of the second-law efficiency, exergy destruction rate, and first-law efficiency. Comparisons between the different geothermal power plant concepts as well as many approaches to define efficiencies have been presented. The maximum first-law efficiency was found to be related to the ORC with an IHE with R123 as the working fluid and was calculated to be 7.65%. In contrast, the first-law efficiency based on the energy input into the ORC revealed that the binary cycle with the regenerative ORC with an IHE and R123 as the working fluid has the highest efficiency (15.35%). Also, the maximum first-law efficiency was shown to be given by the flash-binary with R123 as the working fluid and was calculated to be 11.81%.     

A simple method to evaluate the technical and economic feasibility of micro hydro power plants in existing irrigation systems

A simple method is proposed to site turbines and choose their power output, evaluate costs and incomes and provide useful indications for Micro Hydro Power (MHP) plant design in existing irrigation systems. This method, based on simple models available in literature and requiring a reduced number of input parameters easy to survey in preliminary design stages, has been applied and verified in an existing irrigation system located in Calabria (Italy).The results have highlighted that in the case study the smallest profitable turbine would produce 5 kW. A lower number of plants (with higher output) would produce no particular monetary savings compared to a greater number of smaller turbines. Furthermore, neither was the option of increasing pipeline diameter found to provide savings.In general, an appreciable potential from MHP operation has been shown in existing irrigation systems, providing a return on investment higher than that provided by the Italian financial market.Finally, MHP profitability noticeably increases with total annual operation time, being on average 55% higher in a wet year (eight months of electrical production/four month of irrigation) compared to a dry year (six months of electrical production/six months of irrigation).     

Quantifying CO2 abatement costs in the power sector

CO₂ cap-and-trade mechanisms and CO₂ emission taxes are becoming increasingly widespread. To assess the impact of a CO₂ price, marginal abatement cost curves (MACCs) are a commonly used tool by policy makers, providing a direct graphical link between a CO₂ price and the expected abatement. However, such MACCs can suffer from issues related to robustness and granularity. This paper focuses on the relation between a CO₂ emission cost and CO₂ emission reductions in the power sector. The authors present a new methodology that improves the understanding of the relation between a CO₂ cost and CO₂ abatement. The methodology is based on the insight that CO₂ emissions in the power sector are driven by the composition of the conventional power portfolio, the residual load and the generation costs of the conventional units. The methodology addresses both the robustness issue and the granularity issue related to MACCs. The methodology is based on a bottom-up approach, starting from engineering knowledge of the power sector. It offers policy makers a new tool to assess CO₂ abatement options. The methodology is applied to the Central Western European power system and illustrates possible interaction effects between, e.g., fuel switching and renewables deployment.     

Impact of heat,power and hydrogen generation on optimal placement and operation of fuel cell power plants

In this paper, a stochastic model is proposed for planning the location and operation of Fuel Cell Power Plants (FCPPs) as Combined Heat, power, and Hydrogen (CHPH) units. Total cost, emissions of FCPPs and substation, and voltage deviation are the objective functions to be minimized. Location and operation of FCPPs as CHPH are considered in this paper while their investment cost is not taken into account. In the proposed model, indeterminacy refers to electrical and thermal loads forecasting, pressure of oxygen and hydrogen, and the nominal temperature of FCPPs. In this method, scenarios are produced using roulette wheel mechanism and probability distribution function of input random variables. Using this method, the probabilistic problem is considered to be distributed as some scenarios and consequently probabilistic problem is considered as combination of some deterministic problems. Considering the nature of objective functions, the problem of locating and operating FCPPs as CHPH is considered as a mixed integer nonlinear problem. A Self Adaptive Charged System Search (SACSS) algorithm is employed for determining the best Pareto optimal set. Furthermore, a set of non-dominated solutions is saved in repository during simulation procedure. A 69-bus distributed system is used for verifying the beneficiary proposed method.     

Investment cost for geothermal power plants

Stepwise development strategy is considered a suitable method for securing a cost-effective way for the development of geothermal power plants. This strategy has been in use in Iceland for the last decade. Geothermal high-temperature fields are developed in steps of 20–30 MW. About 6 years are required for each step in the development. Parallel development of several fields in a country might be preferable, especially when a rapid increase of the generation capacity is required in that country. The capacity factor of geothermal power plants depends on the mix of power plants serving the electricity grid. Where geothermal power plants can be operated as base load, the capacity factor is usually in excess of 0.9. The investment cost of geothermal power plants is divided into the cost of surface equipment and activities and the cost of subsurface investment. The surface costs include the cost of surface exploration, and the plant and steam-gathering system, while the cost of subsurface investment is that of drilling. Surface equipment costs can be estimated with the same accuracy as other construction works at the surface (buildings, roads, bridges), whereas higher uncertainty might be associated with the cost of drilling. Analyses of the surface costs of five power plants in Iceland show that the investment cost of the surface equipment is linear with size, in the range 20–60 MW. Surface costs were found to be about 1000 USD/kW with a relative error of 10%. Stefánsson (Stefánsson, V., 1992. Success in geothermal development. Geothermics 21, 823–834) published a statistical study of the drilling results in 31 high-temperature fields in the world. Using these results, it is possible to estimate the expectation value and its limits of error for the subsurface investment in an arbtitrary geothermal field. The results obtained for the range 20–60 MW are summarized as follows:

Full-size image

Ideal thermal efficiency for geothermal binary plants

The Carnot cycle is reviewed as to its appropriateness to serve as the ideal model for geothermal binary power plants. It is shown that the Carnot cycle sets an unrealistically high upper limit on the thermal efficiency of these plants. A more useful model is the triangular (or trilateral) cycle because binary plants operating on geothermal hot water use a non-isothermal heat source. The triangular cycle imposes a lower upper bound on the thermal efficiency and serves as a more meaningful ideal cycle against which to measure the performance of real binary cycles. Carnot and triangular cycle efficiencies are contrasted and the thermal efficiencies of several actual binary cycles are weighed against those of the ideal triangular cycle to determine their relative efficiencies. It is found that actual binary plants can achieve relative efficiencies as high as 85%. The paper briefly discusses cycles using two-phase expanders that in principle come close to the ideal triangular cycle.     

Efficiency improvement for geothermal power generation to meet summer peak demand

Geothermal power is an important part of New Zealand's renewable electricity supply due to its attractive cost and reliability. Modular type binary cycle plants have been imported and installed in various geothermal fields in New Zealand, with plans for further expansion. Power output of these plants deteriorates in the summer because plant efficiency depends directly on the geothermal resource and the ambient temperature. As these plants normally use air-cooled condensers, incorporating a water-augmented air-cooled system could improve the power output in summer thereby matching the peak air-conditioning demand. In this work, power generation for the Rotokawa plant was characterized using a similar plant performance and local weather. The improved performance was modelled for retrofit with a wet-cooling system. Maximum generation increase on the hottest day could be 6.8%. The average gain in power over the summer, November–February, was 1.5%, and the average gain for the whole year was 1%. With current binary unit generation capacity at the Rotokawa plant of 35 MW, investment in a water-augmented air-cooled system could provide 2 MW of peak generation on the hottest days. This investment in efficiency is found to compare favourably to other supply options such as solar PV, wind or gas.     

Valuation of marginal CO2 abatement options for electric power plants in Korea

The electricity generation sector in Korea is under pressure to mitigate greenhouse gases as directed by the Kyoto Protocol. The principal compliance options for power companies under the cap-and-trade include the application of direct CO₂ emission abatement and the procurement of emission allowances. The objective of this paper is to provide an analytical framework for assessing the cost-effectiveness of these options. We attempt to derive the marginal abatement cost for CO₂ using the output distance function and analyze the relative advantages of emission allowance procurement option as compared to direct abatement option. Real-option approach is adopted to incorporate emission allowance price uncertainty. Empirical result shows the marginal abatement cost with an average of €14.04/ton CO₂ for fossil-fueled power plants and confirms the existence of substantial cost heterogeneity among plants which is sufficient to achieve trading gains in allowance market. The comparison of two options enables us to identify the optimal position of the compliance for each plant. Sensitivity analyses are also presented with regard to several key parameters including the initial allowance prices and interest rate. The result of this paper may help Korean power plants to prepare for upcoming regulations targeted toward the reduction of domestic greenhouse gases.     

Reducing cycling costs in coal fired power plants through power to hydrogen

The increase of renewable share in the energy generation mix makes necessary to increase the flexibility of the electricity market. Thus, fossil fuel thermal power plants have to adapt their electricity production to compensate these fluctuations. Operation at partial load means a significant loss of efficiency and important reduction of incomes from electricity sales in the fossil power plant. Among the energy storage technologies proposed to overcome these problems, Power to Gas (PtG) allows for the massive storage of surplus electricity in form of hydrogen or synthetic natural gas. In this work, the integration of a Power to Gas system (50 MWe) with fossil fuel thermal power plants (500 MWe) is proposed to reduce the minimum complaint load and avoid shutdowns. This concept allows a continuous operation of power plants during periods with low demand, avoiding the penalty cost of shutdown. The operation of the hybrid system has been modelled to calculate efficiencies, hydrogen and electricity production as a function of the load of the fossil fuel power plant. Results show that the utilisation of PtG diminishes the specific cost of producing electricity between a 20% and 50%, depending on the framework considered (hot, warm and cold start-up). The main contribution is the reduction of the shutdown penalties rather than the incomes from the sale of the hydrogen. At the light of the obtained results, the hybrid system may be implemented to increase the cost-effectiveness of existing fossil fuel power plants while adapting the energy mix to high shares of variable renewable electricity sources.     

几种类型发电公司环境成本核算的分析研究

在自由的电力市场条件下，发电厂的环境成本将会被纳入发电成本，成为影响市场竞争力的重要因素。为了比较不同电源的环境成本对电价的影响程度，应用环境经济学理论分别对燃煤发电、天然气发电以及核能发电的环境成本进行了核算和比较。     

Primary frequency regulation in the power system by nuclear power plants based on hydrogen-thermal storage

According to the Technical Requirements for Generating Equipment of Participants in the Wholesale Market of the Unified Energy System (UES) of Russia, from 2016 to participate in the general primary frequency regulation (PFR), the maneuverable characteristics of generating equipment of nuclear power plants with VVER reactors put into operation before 2009 should ensure frequency deviations guaranteed realization of the required primary power for loading up to 2% of the nominal electric power. For this, the current capacity of the reactor installation should be maintained at a level of not more than 98% of the nominal thermal power. The fulfillment of this requirement significantly reduces the installed capacity utilization factor (ICUF) of reactor plant.In addition, at present in the UES of the Russian Federation there is a tendency towards an increase in the deficit of peak and half-peak capacities. The majority of fossil fuel-fired thermal stations are switched to the half-peak mode, which negatively affects their efficiency and reliability. In addition, the rise in price of natural gas makes it more profitable to sell it abroad instead of burning at power plants. On the other hand, an increase in the share of nuclear power plants is observed in the UES, which exacerbates the problems associated with the passage of minima and maxima of the daily load in the power system, due to the economically and technically justified need to load NPPs with maximum CUF.The authors developed an approach to solving this problem by combining NPPs with an environmentally friendly energy source – an autonomous hydrogen power complex (AHPC), which includes heat accumulators and an additional multifunctional steam turbine unit. The developed energy complex will allow energy to be accumulated during hours of minima load in the power system due to the electrolysis of water to produce hydrogen and oxygen, as well as the accumulation of hot water in the storage tanks. The accumulated energy can be used to generate super-nominal electricity to cover the half-peak load zone in the power system. In addition, the presence of a low-power steam turbine installation will ensure uninterrupted power supply to consumers of their own needs at the NPP by using the energy of the residual heat from the reactor when the station is completely de-energized.Based on the proposed power complex, a method has been developed to ensure the participation of NPPs in the PFR in an energy system with a constant CUF. To assess the effectiveness of the proposed solution, a methodology for thermodynamic analysis of the power complex based on the combination of NPPs with AHPC was developed. The dependence of the required hydrogen fuel consumption and the efficiency of using off-peak electricity on the temperature of the feed water supplied to the hydrogen-oxygen steam generator from the hot water tanks is constructed.Based on the results obtained, the technical and economic efficiency of the developed power complex is considered. The accumulated net present value was determined depending on off-peak electricity tariffs with three variants of the forecast dynamics of the half-peak electricity tariff, taking into account natural gas savings, reduced investment in NPP safety systems and the economic effect of ensuring the participation of NPPs in the PFR with the plant load at 100%.     

Cost evaluation of two potential nuclear power plants for hydrogen production

Hydrogen is recognized as one of the most promising alternative fuels to meet the energy demand for the future by providing a carbon-free solution. In regards to hydrogen production, there has been increasing interest to develop, innovate and commercialize more efficient, effective and economic methods, systems and applications. Nuclear based hydrogen production options through electrolysis and thermochemical cycles appear to be potentially attractive and sustainable for the expanding hydrogen sector. In the current study, two potential nuclear power plants, which are planned to be built in Akkuyu and Sinop in Turkey, are evaluated for hydrogen production scenarios and cost aspects. These two plants will employ the pressurized water reactors with the electricity production capacities of 4800 MW (consisting of 4 units of 1200 MW) for Akkuyu nuclear power plant and 4480 MW (consisting of 4 units of 1120 MW) for Sinop nuclear power plant. Each of these plants are expected to cost about 20 billion US dollars. In the present study, these two plants are considered for hydrogen production and their cost evaluations by employing the special software entitled “Hydrogen Economic Evaluation Program (HEEP)” developed by International Atomic Energy Agency (IAEA) which includes numerous options for hydrogen generation, storage and transportation. The costs of capital, fuel, electricity, decommissioning and consumables are calculated and evaluated in detail for hydrogen generation, storage and transportation in Turkey. The results show that the amount of hydrogen cost varies from 3.18 $/kg H₂ to 6.17 $/kg H₂.     

Dual-fluid-hybrid power plant co-powered by low-temperature geothermal water

Three variants of power plants fuelled or co-fuelled by geothermal water have been assessed, with the aim of making the best use of the energy contained in a stream of 80–120 °C geothermal water. Heat-flow calculations for three power plant types, namely an Organic Rankine Cycle (ORC) power plant, a dual-fluid-hybrid power plant and a single-fluid hybrid-fuelled power plant, are presented. The analysis shows the thermodynamic benefits, in terms of the extent of using the thermal energy of low-temperature geothermal water, that arise from utilizing hybrid and dual-fluid-hybrid power plants rather than ORC power plants. The dual-fluid plant optimizes the use of the geothermal water, but the hybrid plant makes the best overall utilization of the energy compared to separate ORC and fuel-fired plants.