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.     

Sizing and operating power-to-gas systems to absorb excess renewable electricity

Various configurations of power-to-gas system are investigated as a means for capturing excess wind power in the Emden region of Germany and transferring it to the natural gas grid or local biogas-CHP plant. Consideration is given to producing and injecting low concentration hydrogen admixtures, synthetic methane, or hydrogen/synthetic methane mixtures. Predictions based on time series data for wind generation and electricity demand indicate that excess renewable electricity levels will reach about 40 MW and 45 GW h per annum by 2020, and that it is desirable to achieve a progression in power-to-gas capacity in the preceding period. The findings are indicative for regions transitioning from medium to high renewable power penetrations. To capture an increasing proportion of the growing amount of excess renewable electricity, the following recommendations are made: implement a 4 MW hydrogen admixture plant and hydrogen buffer of 600 kg in 2018; then in 2020, implement a 17 MW hybrid system for injecting hydrogen and synthetic methane (with a hydrogen storage capacity of at least 400 kg) in conjunction with a bio-methane injection plant. The 17 MW plant will capture 68% of the available excess renewable electricity in 2020, by offering an availability to the electricity grid operator of >97% and contributing 19.1 GW h of ‘green’ gas to the gas grid.     

Projects for industrial development of advanced alkaline electrolysers in France

Economic competition between processes for hydrogen production has changed during the last ten years, due to the increasing cost of naphtha, LPG, and natural gas compared to hydraulic or nuclear electricity. France, which has very low fossil fuel resources, has developed a large nuclear programme which results in both a low cost nuclear base electricity and availability of off-peak nuclear electricity within 6–8 years. The structure of the electricity demand is described, with reference to the different types of power production (nuclear, hydraulic, coal or fuel) and this situation appears quite favorable for use of off-peak nuclear electricity for water electrolysis and hydrogen production. Evaluation of electrolysis processes started in 1975 and detailed studies performed in 1977–1978 have focused interest on advanced alkaline electrolysis, with the objective of some improvement in process efficiency and a large decrease in the cost of electrolysers. In 1979, two industrial groups have been contracted to make a two-year R & D programme in order to define an improved alkaline electrolysis process, to operate this process on a 20–30 kW bench, and to elaborate a design of a 2–3 MW pilot electrolyser. The technical performances of the two selected processes are described and some indications are given on the future development of this programme.     

Performance enhancement in coal fired thermal power plants. Part II: steam turbines

This paper presents the results of the performance enhancement study on 22 coal fired thermal power stations of capacities 30–500 MW. The oldest units (30 MW) have served for 33yr and the newer units (500 MW) have been in operation since 7yr. The turbine efficiencies are in the range 31·00–41·90% as compared to the design range of 34·80–43·97%. The isentropic efficiencies are in the range 74·13–86·40% as compared to design values of 83·20–89·10%. Considerable scope for efficiency improvement through low cost solutions: operational optimization, capital overhaul, simple modifications, etc., exists for all classes of units. The efficiencies can be restored to their design values. The developments in turbines over the last quarter of this century which have led to improved isentropic and thermal efficiencies must be adopted for existing units through retrofits, upgrades and revamps. The turbine efficiencies can be improved to 38·0% for 30 MW units and to 47% for 500 MW units. The maximum potential is for improvement in 210 and 500 MW units followed by 110 and 120 MW units. The potential for 30 and 62·5 MW units is rather limited because of their low capacity share, lack of interest in manufacturers to sell spares (because of the low volume of requirement) and large pay back periods for modernisation schemes. Copyright © 1999 John Wiley & Sons, Ltd.     

Thermodynamic development and design of a concentrating solar thermochemical water-splitting process for co-production of hydrogen and electricity

A concentrating solar plant is proposed for a thermochemical water-splitting process with excess heat used for electricity generation in an organic Rankine cycle. The quasi-steady state thermodynamic model consisting of 23 components and 45 states uses adjustable design parameters to optimize hydrogen production and system efficiency. The plant design and associated thermodynamic model demonstrate that cerium oxide is suitable for thermochemical water-splitting cycles involving the co-production of hydrogen and electricity. Design point analyses at 900 W/m² DNI indicate that a single tower with solar radiation input of 27.74 MW and an aperture area of 9.424 m² yields 10.96 MW total output comprised of 5.55 MW hydrogen (Gibbs free energy) and 5.41 MW net electricity after subtracting off 22.0% of total power generation for auxiliary loads. Pure hydrogen output amounts to 522 tonne/year at 20.73 GWh/year (HHV) or 17.20 GWh/year (Gibbs free energy) with net electricity generation at 14.52 GWh/year using TMY3 data from Daggett, California, USA. Annual average system efficiency is 38.2% with the constituent hydrogen fraction and electrical fraction being 54.2% and 45.8%, respectively. Sensitivity analyses illustrate that increases in particle loop recuperator effectiveness create an increase in hydrogen production and a decrease in electricity generation. Further, recuperator effectiveness has a measurable effect on hydrogen production, but has limited impact on total system efficiency given that 81.1% of excess heat is recuperated within the system for electricity generation.     

Recent estimates of energy efficiency potential in the USA

Understanding the potential for reducing energy demand through increased end-use energy efficiency can inform energy and climate policy decisions. However, if potential estimates are vastly different, they engender controversial debates, clouding the usefulness of energy efficiency in shaping a clean energy future. A substantive question thus arises: is there a general consensus on the potential estimates? To answer this question, this paper reviews recent studies of US national and regional energy efficiency potential in buildings and industry. Although these studies are based on differing assumptions, methods, and data, they suggest technically possible reductions of ~25–40 % in electricity demand and ~30 % in natural gas demand in 2020 and economic reductions of ~10–25 % in electricity demand and ~20 % in natural gas demand in 2020. These estimates imply that electricity growth from 2009 to 2020 ranges from turning US electricity demand growth negative, to reducing it to a growth rate of ~0.3 %/year (compared to ~1 % baseline growth).     

A data‐driven approach to study the role of interconnectors in a future low‐carbon electricity supply system

This paper investigates the potential role of the electricity interconnectors in improving the security of supply in Great Britain (GB) in 2030. Real electricity demand and price data for GB and France in 2016 were used to understand the relationship between power exchange between the two countries and their wholesale electricity prices. A linear programming optimisation model was developed to find the economic power dispatch. Two interconnection links were considered; two‐way trade interconnector with a capacity of 5.4 GW and a 12.3 GW import‐only interconnector between GB and other states. The GB–France link transmits electricity from cheaper system to the more expensive one. The total electricity demand in 2030 will be 406 TWh. Gas‐fired power plants w/wo CCS will provide 83 TWh of the total electricity demand, whereas nuclear power plants will produce 74 TWh. In addition, wind farms and solar PVs are expected to deliver ~120 TWh electricity. CHP units will provide 88 TWh electricity in 2030. The electricity traded between GB and France in 2030 was found to be 33 TWh, which is 160% larger compared with 2016. The power import from France is about 27 TWh and occurs in 59% of the time. For 64% of the time, the interconnector with France is fully loaded. The electricity imported via the 12.3 GW interconnector in 2030 is 1 TWh and mainly occurs during winter‐time when the demand in GB is high. De‐rated capacity margin was calculated based on instantaneous electricity demand and varies between ?2% and 139%. The impact of the price of the imported electricity via the 12.3 GW link was investigated. Increasing the price of the imported electricity via the 12.3 GW link results in a higher capacity factor for all the generation options except the 12.3 GW interconnector link.     

On the efficient market diffusion of intermittent renewable energies

Capacity costs of renewable energies have been decreasing dramatically and are expected to fall further, making them more competitive with fossils. Building on an analytically tractable peak-load pricing model, we analyze how intermittency of renewable energies affects the market diffusion that results from these lower costs. In particular, once renewables have become competitive by attaining the same levelized cost of electricity (LCOE) as fossils, the marginal increase in efficient capacities due to a further cost reduction varies substantially. Initially it is small, then it rises, but it falls again once renewable capacities are large enough to satisfy the whole electricity demand at times of high availability. If external costs of fossils are internalized by a Pigouvian tax, then perfect competition leads to efficient investments in renewable and fossil capacities; even though we assume that only a subgroup of consumers can adapt their demand to price fluctuations that are caused by the intermittency of renewables. Moreover, fossils receive a capacity payment through the market for their reliability in serving demand of non-reactive consumers. Maximum electricity prices rise with the share of renewables. If regulators impose a price cap, this initially raises investments in renewables, but the effect may reverse if the share of renewables is large.     

Ultrasupercritical power plant development and high temperature materials applications in China

Abstract

The rapid development of Chinese economy demands sustainable growth of power generation to meet industrial and domestic demand. The total installed capacity of electricity and annual overall electricity generation are now both the second highest in the world, close to those of the USA. Forecasts of China's electricity demand over the period 2010–20 are presented. Chinese power plants, like those worldwide, are facing demands to increase thermal efficiency and to decrease the emission of CO₂, SO_X and NO_X. In light of the national resource of coal and electricity market requirements in the next 15 years, power generation – especially ultrasupercritical (USC) power plants with the steam temperature over 600°C – will undergo rapid development. The first 1000 MW USC power unit, with steam parameters 600°C, 26·25 MPa, entered service in November 2006. It is estimated that more than 350 USC power units will be installed in China by 2020. USC power plant designs will adopt a variety of qualified high temperature materials for boiler and turbine manufacturing applications. Among these materials, the modified 9–12%Cr ferritic steels, Ni–Cr austenitic steels and certain nickel base superalloys have received special attention in the Chinese materials market.     

Indications for a changing electricity demand pattern: The temperature dependence of electricity demand in the Netherlands

This study assesses the electricity demand pattern in the relatively temperate climate of the Netherlands (latitude 52°30′N). Daily electricity demand and average temperature during the period from 1970 until 2007 are investigated for possible trends in the temperature dependence of electricity demand. We hypothesize that the increased use of cooling applications has shifted the temperature dependence of electricity demand upwards in summer months. Our results show significant increases in temperature dependence of electricity demand in May, June, September, October and during the summer holidays. During the period studied, temperature dependence in these months has shifted from negative to positive, meaning that a higher temperature now leads to an increased electricity demand in these months, rather than a decreased demand as observed historically. Although electricity demand in countries with moderate summer temperatures such as the Netherlands generally peaks in winter months and shows a minimum in summer months, this trend may signal the development of an additional peak in summer, especially given the expected climatic change. As power generating capacity may be negatively influenced by higher temperatures due to decreasing process cooling possibilities, an increasing electricity demand at higher temperatures may have important consequences for power generation capacity planning and maintenance scheduling.     

Integration of a cogeneration unit into a kraft pulping process

The integration of cogeneration with other measures that impact the power production capacity in a Canadian Kraft pulping mill is studied. Those measures are removal of pressure reduction valves, adjustment of the steam pressure level, biomass boiler capacity, and reduction in process energy demand. CADSIM Plus software is used to simulate the cogeneration plant. The dynamic behavior of the process during start-up and its effect on electricity generation are also considered. It is shown that by replacing the PRVs with turbines, 14.4 MW of power can be generated. Moreover, by implementing cogeneration units and process measures to recover 23% of internal energy, 44.5 MW of electricity can be generated in addition to shutting down the existing bunker oil boiler. Therefore, implementation of cogeneration in the pulp and paper industry is technically possible and it offers significant economic advantages. A cost analysis of the complete project gives a simple payback time of less than a year.     

Optimizing biogas plants with excess power unit and storage capacity in electricity and control reserve markets

Increasing shares of intermittent power sources such as solar and wind will require biomass fueled generation more variable to respond to the increasing volatility of supply and demand. Furthermore, renewable energy sources will need to provide ancillary services. Biogas plants with excess generator capacity and gas storages can adapt the unit commitment to the demand and the market prices, respectively. This work presents a method of day-ahead unit commitment of biogas plants with excess generator capacity and gas storage participating in short-term electricity and control reserve markets. A biogas plant with 0.6 MW annual average electric output is examined in a case study under German market conditions. For this biogas plant different sizes of the power units and the gas storage are compared in consideration of costs and benefits of installing excess capacity. For optimal decisions depending on prices, a mixed-integer linear programming (MILP) approach is presented.The results show that earnings of biogas plants in electricity markets are increased by additional supplying control reserve. Furthermore, increasing the installed capacity from 0.6 MW to 1 MW (factor 1.7) leads to the best cost–benefit-ratio in consideration of additional costs of excess capacity and additional market revenues. However, the result of the cost–benefit-analysis of installing excess capacity is still negative. Considering the EEG flexibility premium, introduced in 2012 in the German renewable energy sources act, the result of the cost–benefit-analysis is positive. The highest profit is achieved with an increase of the installed capacity from 0.6 MW to 2 MW (factor 3.3).     

Levels of consumers’ agency and capacity as predictors for electricity demand reduction in the residential sector

A field study of 50 households in a collective community in Israel provides initial support for the hypotheses about the relations between actors’ agency, capacity and electricity demand reduction. ‘Agency’ refers to actors’ willingness and ability to make their own free choices and ‘capacity’ refers to actors’ ability to perform the choices they made. According to the hypotheses, change is more likely to happen when actors’ levels of agency and capacity are high; unlikely to happen when the levels are low and uncertain when there is a mismatch between levels of agency and capacity (one is high and the other low). In the research, levels of agency and capacity regarding 11 energy saving actions were self-reported and electricity consumption was metered before and during energy saving campaign. Findings show that levels of agency were lower than those of capacity for no-cost actions which require high engagement, while levels of capacity were lower than those of agency for high-cost action which require low engagement. In addition, households with high agency and high capacity reduced their electricity consumption by 9.39 % (on average); those with low agency and low capacity increased their consumption by 6.67 %; and those with a mismatch between agency and capacity reduced their consumption by 1.91 %.     

Economics of electricity and heat production by gasification or flash pyrolysis of short rotation coppice in Flanders (Belgium)

Short rotation coppice (SRC) seems attractive as an energy crop on degraded land. Gasification and flash pyrolysis are promising technologies for the conversion of SRC into energy or chemicals. A model has been developed to calculate the net present value (NPV) of the cash flows generated by an investment in gasification or flash pyrolysis of SRC for the production of electricity or for combined heat and power production. The NPV has been calculated and compared for (combined heat and) power stations with an electrical capacity (P_e) between 5 MW and 20 MW. Furthermore the minimal amount of heat that has to be sold to make combined heat and power production more profitable than pure electricity production has been determined. By performing Monte Carlo simulations, key variables that influence the NPV have been identified.In the case of small scale SRC conversion, i.e. at an electrical capacity of 5 MW-10 MW, flash pyrolysis is more profitable than gasification. At the smallest scale of 5 MW it is necessary to invest in combined heat and power production, as the sole production of electricity is not profitable at this low scale. At an electrical capacity of 10 MW flash pyrolysis for the sole production of electricity becomes profitable, but gasification for electricity production is still not viable. At this capacity however, the extra investments required in the case of combined heat and power production are already paid back if only 25% of the produced heat can be sold. At a higher capacity of 20 MW, the technology choice becomes unclear taking into account the most uncertain variables, i.e. investment cost parameters and energetic efficiencies.     

Demand response in China

The escalating demand for electricity in China has caused an electricity shortage in the past several years. This paper discusses the role of demand response (DR) as an integral component in alleviating the problem and coping with this shortfall. It reviews current experience with DR programs, analyzes China's situation and makes suggestions for DR implementation. Although China's DR programs offer high potential to succeed, they require substantial efforts in resolving such key issues as the programs' funding mechanisms, pricing, and relationship with electricity industry reform.     

Cost‐optimized allocation of wind power investments: a Nordic–German perspective

Using a linear cost minimization model with a 1 h time resolution, we investigated the influence of geographic allocation of wind power on large‐scale wind power investments, taking into account wind conditions, distance to load, and the nature of the power system in place (i.e. power generation and transmission capacities). We employed a hypothetical case in which a 20% wind power share of total electricity demand is applied to the Nordic–German power system. Free, i.e. geographically unrestricted, allocation of new wind power capacity is compared with a case in which national planning frameworks impose national limitations on wind power penetration levels. Given the cost assumptions made in the present work, the prospect of increasing the wind power capacity factor from 20 to 30% could motivate investments in transmission capacity from northern Scandinavia to continental Europe. The results obtained using the model show that the distribution of wind farms between regions with favorable wind conditions is dependent upon two factors: (i) the extent to which existing lines can be used to transmit the electricity that results from the new wind power and (ii) the correlation for wind power generation between the exporting region and the wind power generation already in place. In addition, the results indicate that there is little difference, i.e. just over 1%, in total yearly cost between the free allocation of new wind power and an allocation that complies with national planning frameworks. However, on a national level, there are significant differences with respect to investments in transmission and wind power capacities and the replacement of conventional power generation. Copyright © 2012 John Wiley & Sons, Ltd.     

Weighing regional scrap availability in global pathways for steel production processes

This study analyses the impact of the rising availability of steel scrap on the future steel production up to the year 2100 and implications for steel production capacity planning. Steel production processes are energy, resource, and emission intensive, but there are significant variations due to different production routes, product mixes, and processes. This analysis is based on the development of steel demand, using the Steel Optimization Model, which provides a region-detailed representation of technologies, energy and material flows, and trade activities. It is linked to the Scrap Availability Assessment Model which estimates the theoretical steel scrap availability. Aggregated crude steel production is estimated to evolve into an almost balanced split by 2050 between the primary production route using iron ore in the blast oven furnace and the secondary route using mostly steel scrap in the electric arc furnace. By 2060, the share of secondary steel production will exceed the share of primary steel production globally. The results also estimate a global increase in scrap use from 611 Mtonnes in 2015 to 1500 Mtonnes in 2050, with the highest growth being for post-consumer scrap. In 2050, almost 50% of post-consumer scrap is expected to be traded, with the main exporter being China and major importing regions being Africa, India, and other developing Asian countries. The results provide valuable insights on scrap availability and capacity development at the regional level for producers contemplating new investments. Regional availability, quality, and trade patterns of scrap will influence production route choices, possibly in favor of secondary routes. Also, policy instruments such as carbon taxation may affect investment choices and favor more energy-efficient and less carbon-intensive emerging technologies.     

Review of barriers to the introduction of residential demand response: a case study in the Netherlands

Demand response, defined as the shifting of electricity demand, is generally believed to have value both for the grid and for the market: by matching demand more closely to supply, consumers could profit from lower prices, while in a smart grid environment, more renewable electricity can be used and less grid capacity may be needed. However, the introduction of residential demand response programmes to support the development of smart grids that includes renewable generation is hampered by a number of barriers. This paper reviews these barriers and categorises them for different demand programmes and market players. The case study for the Netherlands shows that barriers can be country specific. Two types of demand response programmes have been identified as being the most promising options for households in smart grids: price‐based demand response and direct load control, while they may not be beneficial for market players or distribution system operators. © 2016 The Authors. International Journal of Energy Research Published by John Wiley & Sons Ltd.     

Strategic optimization of forest residues to bioenergy and biofuel supply chain

Forest residues are renewable materials for bioenergy conversion that have the potential to replace fossil fuels beyond electricity and heat generation. A challenge hindering the intensified use of forest residues for energy production is the high cost of their supply chain. Previous studies on optimal design of forest residue supply chains focused on biofuel or bioenergy production separately, mostly with a single time period approach. We present a multi‐period mixed integer linear programming model that optimizes the supply chain of forest residues for the production of bioenergy and biofuels simultaneously. The model determines (i) the location, type and size of the technologies to install and the period to install them, (ii) the mix of biofuel and bioenergy products to generate, (iii) the type and amount of forest residues to acquire and the sourcing points, (iv) the amount of forest residues to transport from sources to facilities and (v) the amount of product to transport from facilities to markets. The objective of the model is to maximize the net present value of the supply chain over a 20‐year planning horizon with yearly time steps. We applied the model to a case study in British Columbia, Canada, to investigate the production of heat, electricity, pellets and pyrolysis bio‐oil from available forest harvesting residues and sawmill wastes. Based on current energy generation costs in the region and the predicted operating costs of new conversion plants, the results of our model recommended the installation of small biomass boilers coupled with steam turbines for electricity production (0.5 and 5 MW) and pyrolysis plants with a capacity of 200 and 400 odmt day^?1. We performed a sensitivity analysis to evaluate the sensitivity of the optimal result to changes in the demand and price of products, as well as the availability and cost of forest residues. Copyright © 2014 John Wiley & Sons, Ltd.     

Revision of reserve requirements following wind power integration in island power systems

This contribution studies the impact of wind power on the operation of island power systems. The analysis focuses on the available flexibility of thermal generation to balance wind power variations and prediction errors. This issue is highly relevant for small and medium sized islands where interconnections are absent and the smoothing of variations is limited due to a small geographical surface. The main objective is to determine if additional reserve requirements are necessary for ensuring reliable wind power integration in an isolated transmission system. In this context, a case study is performed for Cyprus, a medium-sized island, where wind developments towards 2020 schedule an installed capacity of 300 MW, reaching 7% of the annual electricity consumption. Simulations with installed wind power capacities up to 400 MW show that the current available flexibility in the generation system is inadequate to balance real-time wind power fluctuations and prediction errors. Consequently, large amounts of wind curtailment and demand shedding may be expected. Therefore, current reserve requirements should be revised, in order to reliably facilitate wind power into the system. Furthermore, the impact of introducing natural gas for electricity generation in Cyprus on the reserve requirements, following wind power integration, is examined.