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The paper describes formation and spreading of dense shelf waters in the Adriatic Sea (North Adriatic Dense Water, NAdDW) during the winter of 2012 as a consequence of an intense and long cold air outbreak of northeasterly Bora winds. As a result, during February 2012 northern Adriatic Sea water temperature dropped to about 6 degrees C and density exceeded 1030 kg/m(3), most likely the maximum value since 1929. NAdDW dynamics has been investigated by means of a 3-D ocean-wave coupled model running on a high resolution and eddy-permitting grid. The numerical experiments have relied on the Coupled-Ocean-Atmosphere-Wave-Sediment-Transport (COAWST) system forced one-way with atmospheric forcings provided by the model COSMO-17. A suite of observational data has been used to characterize the Bora event and evaluate numerical model performance. At sub-basin scales, the newly formed waters flowing southerly have produced a water renewal of the northern Adriatic, as more than 50% of water volumes have left the basin. Dense waters volume transports, evaluated through different Adriatic cross-sections, have been modulated by tides (damped for the densest water masses) and reached about 1 Sv. The contribution of wave-induced forcings has been quantified and examined, indicating that these represent a major driving mechanism during NAdDW production and spreading phases. This work provides evidence that NAdDW is spread accordingly with two different mechanisms: at early stages of its formation, the wind-driven ocean circulation pushes newly formed waters to leave the northern basin with relatively high speeds (about 0.30 m/s). Later on, remaining NAdDW leaks slowly out (0.09 m/s as average) from the production site. Residence times of dense waters in the north, middle, and south Adriatic Sea are also documented. (C) 2014 Elsevier Ltd. All rights reserved.

Bioenergy crops are well known for their ability to reduce greenhouse gas emissions and increase the soil carbon stock. Although such crops are often held to be in competition with food crops and thus raise the question of current and future food security, at the same time mitigation measures are required to tackle climate change and sustain local farming communities and crop production. However, in some cases the actions envisaged for specific pedo-climatic conditions are not always economically sustainable by farmers. In this frame, energy crops with high environmental adaptability and yields, such as giant reed (Arundo donax L.), may represent an opportunity to improve farm incomes, making marginal areas not suitable for food production once again productive. In so doing, three of the 17 Sustainable Development Goals (SDGs) of the United Nations would be met, namely SDG 2 on food security and sustainable agriculture, SDG 7 on reliable, sustainable and modern energy, and SDG 13 on action to combat climate change and its impacts. In this work, the response of giant reed in the marginal areas of an agricultural district of southern Italy (Destra Sele) and expected farm incomes under climate change (2021-2050) are evaluated. The normalized water productivity index of giant reed was determined (WP; 30.1gm-2) by means of a SWAP agro-hydrological model, calibrated and validated on two years of a long-term field experiment. The model was used to estimate giant reed response (biomass yield) in marginal areas under climate change, and economic evaluation was performed to determine expected farm incomes (woodchips and chopped forage). The results show that woodchip production represents the most profitable option for farmers, yielding a gross margin 50% lower than ordinary high-input maize cultivation across the study area.

Abstract The hydro energy of the gravity water flow from the coal-fired thermal power plant units to the river in an open cooling system of turbine condensers is determined. On the basis of statistical data for a long time period, the water net head duration curve due to the river annual level change, as well as the reduction of the hydro energy potential due to the thermal power plant overhauls periods, are evaluated in the case study of the Thermal Power Plant “Nikola Tesla B” in Serbia. A small hydro power plant is designed for the utilization of this hydro energy, and the economic benefits of the project are calculated. The internal rate of returns and pay back periods are calculated in dependence of the electricity price and total investment costs. The increase of profitability is assessed, bearing in mind that the plant might be realized as the Clean Development Mechanism project according to the Kyoto protocol. The obtained results show that the project is economically attractive, and it can be carried out with standard matured solutions of hydro turbines available at the market. Even for the relatively low electricity price from small hydro power plants in Serbia of 0.08 €/kW h the internal rate of return and the pay back period are 17.5% and 5.5 years.

Artículos en revistas Previous studies of market power within a regional system have considered multiple competing generation operators and the role of transmission constraints. However, these studies typically assume simplified structures in which each operator is restricted to a unique node in a transmission constrained network. Real systems typically have operators making decisions for units in several zones at once. Past studies also implicitly treated market power as a static concept for a given set of market rules and network configuration. We demonstrate that market power is dynamic, and can vary significantly with fuel prices and even with large-scale weather patterns. We also demonstrate the impact on region-wide market power of operators that manage units in multiple zones. We use the Electric Reliability Council of Texas (ERCOT) as an illustrative case study, and apply a Conjectured Supply Function Equilibrium (CSFE) approach that accounts for transmission constraints. We show that the companies with greater influence on the market price will depend on the relative prices of coal and natural gas. We also show that a weather event, such as a period without any wind, can have a substantial impact on market power. info:eu-repo/semantics/publishedVersion

Abstract The storage of heat in aquifers, also referred to as Aquifer Thermal Energy Storage (ATES), bears a high potential to bridge the seasonal gap between periods of highest thermal energy demand and supply. With storage temperatures higher than 50 °C, High-Temperature (HT) ATES is capable to facilitate the integration of (non-)renewable heat sources into complex energy systems. While the complexity of ATES technology is positively correlated to the required storage temperature, HT-ATES faces multidisciplinary challenges and risks impeding a rapid market uptake worldwide. Therefore, the aim of this study is to provide an overview and analysis of these risks of HT-ATES to facilitate global technology adoption. Risk are identified considering experiences of past HT-ATES projects and analyzed by ATES and geothermal energy experts. An online survey among 38 international experts revealed that technical risks are expected to be less critical than legal, social and organizational risks. This is confirmed by the lessons learned from past HT-ATES projects, where high heat recovery values were achieved, and technical feasibility was demonstrated. Although HT-ATES is less flexible than competing technologies such as pits or buffer tanks, the main problems encountered are attributed to a loss of the heat source and fluctuating or decreasing heating demands. Considering that a HT-ATES system has a lifetime of more than 30 years, it is crucial to develop energy concepts which take into account the conditions both for heat sources and heat sinks. Finally, a site-specific risk analysis for HT-ATES in the city of Hamburg revealed that some risks strongly depend on local boundary conditions. A project-specific risk management is therefore indispensable and should be addressed in future research and project developments.

Coal use—and thus investment—is expected to grow considerably in the Russian Federation over the next few decades. Projections suggest that at least $200 billion of investment will be needed to modernize existing coal-fired power plants by 2030, but the bulk of this financing is to come from the private sector or foreign enterprises. This study asks: what are the possible investment risks and rewards of pursuing this expansion of coal in the Russian power sector? To provide an answer, the study uses a mixed methods approach consisting of elite semi-structured interviews and a review of English and Russian peer-reviewed literature. The study provides a brief overview of the Russian electricity sector before discussing five distinct rewards to investing in coal such as low production costs, competitive returns on investment, rural modernization, expansion of exports, and the acceleration of innovation. These benefits however are offset by five risks: inferior performance to investments in oil and gas, development challenges, air pollution and climate change, social degradation from mining, and a tradeoff with existing policies incentivizing renewable energy and energy efficiency. The study concludes by analyzing what these disparate risks and rewards mean for policymakers and energy analysts.

This work presents a multi-level method for the design and selection of heat exchange working fluids tailored for Organic Rankine Cycle (ORC) systems used in power and/or heat cogeneration from renewable, low enthalpy sources. A systematic methodology is employed supporting the design of optimum working fluid candidates using Computer Aided Molecular Design (CAMD). The performance of the designed fluids is evaluated using ORC models that enable simulation and economic design optimization. In addition to chemical/physical properties the performed evaluation considers working fluid characteristics such as safety (toxicity and flammability) and environmental properties (ozone depletion potential and global warming potential) that are equally important to economic efficiency. The proposed approach is illustrated through a case study involving varying geothermal field conditions employed as energy sources for greenhouse power and heat co-generation.

Biomass-derived liquid fuels with low greenhouse gas emissions are an integral part of decarbonization plans. Three pathways for enhancing production of methanol from biomass and municipal solid waste (MSW), natural gas, and renewable electricity are explored using hydrogen produced from water electrolysis, natural gas pyrolysis, or combinations of these inputs. A combined electrolysis and natural gas pyrolysis process is designed to be flexible, changing operation modes depending on the cost of feedstocks (i.e. electricity and natural gas). A techno-economic analysis is performed to assess and compare the economic attractiveness of these processes. Hydrogen produced from natural gas pyrolysis could potentially be more economically attractive than electrolytic hydrogen using renewable electricity. Moreover, natural gas pyrolysis CO2 emissions could be substantially lower than emissions from conventional steam methane reforming (e.g., CO2 emissions which are 25 % or lower compared to CO2 emission from steam methane reforming). Hydrogen enhancement of the methanol production process results in increase of around a factor of two in carbon conversion efficiency (e.g. from 44% to 94 %). Methane pyrolysis shows high economic potential assuming the technical challenges to its commercialization are successfully addressed. Given an installed cost of electrolyzer of 1000 $/kW, electricity price of 50 $/MWh, natural gas price of 5 $/GJ and 100 $/ton selling price of carbon black, the natural gas pyrolysis design results in the lowest methanol production cost. Our analysis indicates that methanol could be produced in a price range of 300–1000 $/ton depending on feedstock price (particularly electricity) and the chosen process.