A probabilistic estimate of the frequency of mowing and baling days available in Oklahoma USA for the harvest of switchgrass for use in biorefineries

Determining the time available for required harvest operations is an essential prerequisite to optimizing lignocellulosic biomass (LCB) harvest costs. Estimating the number of days expected to be available for mowing and baling is difficult because agricultural field work is heavily weather dependent. Harvest costs are expected to constitute a large component of the cost to deliver LCB to a biorefinery. Harvest costs depend in part on the investment required in harvest machines, and this investment depends on the number of field workdays during the harvest window. Therefore, a reasonably precise estimate of the number of harvest days is necessary to determine the investment in harvest machines required to support a LCB biorefinery. The objective of this study was to determine the number of suitable field workdays in which switchgrass (Panicum virgatum) can be mowed and the number of days that mowed material can be baled. Empirical distributions of the days available for mowing and for baling switchgrass were determined for nine counties in the USA state of Oklahoma. Distributions were determined for each month and for two potential harvest seasons (short, October–December and extended, July–February). Beginning harvest in July and extending harvest through February would require only 37% as many baling machines as would be required for a short (October–December) harvest season. This potential reduction in harvest machine investment is consistent across location. An extended harvest season could reduce the investment required in harvest machines and the costs to deliver feedstock.     

Impact of battery storage on economics of hybrid wind‐diesel power systems in commercial applications in hot regions

Integration of wind machines and battery storage with the diesel plants is pursued widely to reduce dependence on fossil fuels. The aim of this study is to assess the impact of battery storage on the economics of hybrid wind‐diesel power systems in commercial applications by analyzing wind‐speed data of Dhahran, East‐Coast, Kingdom of Saudi Arabia (K.S.A.). The annual load of a typical commercial building is 620,000 kWh. The monthly average wind speeds range from 3.3 to 5.6 m/s. The hybrid systems simulated consist of different combinations of 100‐kW commercial wind machines (CWMs) supplemented with battery storage and diesel generators. National Renewable Energy Laboratory's (NREL's) (HOMER Energy's) Hybrid Optimization Model for Electric Renewables (HOMER) software has been employed to perform the economic analysis. The simulation results indicate that for a hybrid system comprising of 100‐kW wind capacity together with 175‐kW diesel system and a battery storage of 4 h of autonomy (i.e. 4 h of average load), the wind penetration (at 37‐m hub height, with 0% annual capacity shortage) is 25%. The cost of generating energy (COE, $/kWh) from this hybrid wind–battery–diesel system has been found to be 0.139 $/kWh (assuming diesel fuel price of 0.1$/L). The investigation examines the effect of wind/battery penetration on: COE, operational hours of diesel gensets. Emphasis has also been placed on un‐met load, excess electricity, fuel savings and reduction in carbon emissions (for wind–diesel without battery storage, wind–diesel with storage, as compared to diesel‐only situation), cost of wind–battery–diesel systems, COE of different hybrid systems, etc. The study addresses benefits of incorporation of short‐term battery storage (in wind–diesel systems) in terms of fuel savings, diesel operation time, carbon emissions, and excess energy. The percentage fuel savings by using above hybrid system is 27% as compared to diesel‐only situation Copyright © 2012 John Wiley & Sons, Ltd.     

Transforming the electricity generation of the Berlin–Brandenburg region,Germany

We present possible steps for Germany's capital region for a pathway towards high-level renewable energy contributions. To this end, we give an overview of the current energy policy and status of electricity generation and demand of two federal states: the capital city Berlin and the surrounding state of Brandenburg. In a second step we present alternative, feasible scenarios with focus on the years 2020 and 2030. All scenarios were numerically evaluated in hourly time steps using a cost optimisation approach. The required installed capacities in an 80% renewables scenario in the year 2020 consist of 8.8 GW wind energy, 4.8 GW photovoltaics, 0.4 GW_el bioenergy, 0.6 GW_el methanation and a gas storage capacity of 180 GWh_th. In order to meet a renewable electricity share of 100% in 2030, approximately 9.5 GW wind energy, 10.2 GW photovoltaics and 0.4 GW_el bioenergy will be needed, complemented by a methanation capacity of about 1.5 GW_el and gas storage of about 530 GWh_th. In 2030, an additional 11 GWh_el of battery storage capacity will be required. Approximately 3 GW of thermal gas power plants will be necessary to cover the residual load in both scenarios. Furthermore, we studied the transmission capacities of extra-high voltage transmission lines in a second simulation and found them to be sufficient for the energy distribution within the investigated region.     

An optimization algorithm-based pinch analysis and GA for an off-grid batteryless photovoltaic-powered reverse osmosis desalination system

Freshwater pinch analysis (FWaPA) as an extended pinch analysis technique has been proposed for retrofitting the off-grid batteryless photovoltaic-powered reverse osmosis system (PVS-RO) with a water storage tank to minimize the required outsourced freshwater. The freshwater composite curve (FWaCC) as the graphical tool, and freshwater storage cascade table (FWaSCT) as the numerical tool of the FWaPA are introduced to determine the optimal delivered electricity to the RO system, water storage tank capacity, and wasted electricity in each time-interval with minimized outsourced freshwater. A multi-objective optimization algorithm by combining FWaPA numerical tool and genetic algorithm (FWaPA-GA) minimizes three objective functions including required outsourced freshwater during first operation year, outsourced freshwater during normal operation year, and total annual cost of the system to obtain the optimal number of PV panels, membranes, and capacity of water storage tank. The FWaPA-GA was implemented to find optimal design of an off-grid PVS-RO-WT system for a case study in Kish island, Iran. The results clearly represented that the FWaPA-GA can be used to grassroots design of the desalination systems with renewable energy sources, where the designed PVS-RO-WT system for the case study needs 178.5 m³ freshwater to provide 10 m³/d freshwater-on-demand with the total annual cost of 13,652 $/year.     

Power generation scenarios for Nigeria: An environmental and cost assessment

Exploratory scenarios for the power sector in Nigeria are analysed in this paper using possible pathways within the Nigerian context and then compared against the Government's power expansion plan in the short to medium term. They include two fossil-fuel (FF and CCGT) and two sustainable-development-driven scenarios (SD1 and SD2). The results from the FF scenarios indicate this is the preferred outcome if the aim is to expand electricity access at the lowest capital costs. However, the annual costs and environmental impacts increase significantly as a consequence. The SD1 scenario, characterised by increased penetration of renewables, leads to a reduction of a wide range of environmental impacts while increasing the annual costs slightly. The SD2 scenario, also with an increased share of renewables, is preferred if the aim is to reduce GHG emissions; however, this comes at an increased annual cost. Both the SD1 and SD2 scenarios also show significant increases in the capital investment compared to the Government's plans. These results can be used to help inform future policy in the Nigerian electricity sector by showing explicitly the range of possible trade-offs between environmental impacts and economic costs both in the short and long terms.     

The utility of energy storage to improve the economics of wind–diesel power plants in Canada

Wind energy systems have been considered for Canada's remote communities in order to reduce their costs and dependence on diesel fuel to generate electricity. Given the high capital costs, low-penetration wind–diesel systems have been typically found not to be economic. High-penetration wind–diesel systems have the benefit of increased economies of scale, and displacing significant amounts of diesel fuel, but have the disadvantage of not being able to capture all of the electricity that is generated when the wind turbines operate at rated capacity.Two representative models of typical remote Canadian communities were created using HOMER, an NREL micro-power simulator to model how a generic energy storage system could help improve the economics of a high-penetration wind–diesel system. Key variables that affect the optimum system are average annual wind speed, cost of diesel fuel, installed cost of storage and a storage systems overall efficiency. At an avoided cost of diesel fuel of 0.30 $Cdn/kWh and current installed costs, wind generators are suitable in remote Canadian communities only when an average annual wind speed of at least 6.0 m/s is present. Wind energy storage systems become viable to consider when average annual wind speeds approach 7.0 m/s, if the installed cost of the storage system is less than 1000 $Cdn/kW and it is capable of achieving at least a 75% overall energy conversion efficiency. In such cases, energy storage system can enable an additional 50% of electricity from wind turbines to be delivered.     

冰源热泵系统在设施水产养殖中的技术经济性研究

针对目前刺参养殖的水温调控系统能耗大及适用性差等问题,提出基于冰源热泵的高效清洁供热及结合跨季节蓄冷实现全年冷热管理的技术思路,采用冰源热泵系统和跨季节蓄冷型冰源热泵系统对养殖水体温度进行调控,建立模型定量对比分析系统的运行能效及技术经济性.结果表明:(1)冰源热泵系统供热和供冷时的性能系数分别为3.33和3.39,全...     

Production costs of potential corn stover harvest and storage systems

Corn stover has potential as a bioenergy feedstock in North America. We simulated production costs for stover harvest (three-pass and two-pass with baling or chopping, and single-pass with baling or chopping) and on-farm storage (outdoor and indoor bales, outdoor wrapped bales, and chopped stover in bags, bunks, or piles). For three- and two-pass harvest, chopping was 33–45% more expensive than baling. For baling and chopping, two-pass harvest was 25% cheaper than three-pass. Single-pass chopping harvests were on average 42% cheaper than three-pass or two-pass chopping. Single-pass baling was cheaper (4–31%) than multi-pass baling at low rates of stover collection, but more expensive (1–39%) at high rates of collection. For bales, outdoor storage of wrapped bales was cheapest. Outdoor, unwrapped bale storage, even with 12% dry matter loss, was cheaper than indoor storage. For chopped stover, storage in bags was always cheapest, followed by piles, and then bunkers. With harvest and storage together, there were four least cost systems: single-pass, ear-snap baling with wrapped bale storage; single-pass chopping with silage bag storage; and two-pass baling with wrapped-bale storage. A second group of harvest/storage systems was 25% more expensive, including single-pass, whole-plant baling with wrapped-bale storage; two-pass chopping with silage-bag storage; and three-pass baling with wrapped-bale storage. The three-pass chop harvest with silage bag storage was most expensive. Our analysis suggests all harvest and farm storage systems have tradeoffs and several systems can be economically and logistically viable.     

Projected costs of a grid-connected domestic PV system under different scenarios in Ireland,using measured data from a trial installation

This paper presents results of a study of projected costs for a grid-connected PV system for domestic application in Ireland. The study is based on results from a 1.72 kWp PV system installed on a flat rooftop in Dublin, Ireland. During its first year of operation a total of 885.1 kWh/kWp of electricity was generated with a performance ratio of 81.5%. The scenarios employed in this study consider: a range of capital costs; cost dynamics based on a PV module learning rate of 20±5%; projections for global annual installed PV capacity under an advanced and moderate market growth conditions; domestic electricity cost growth of 4.5% based on historic data; and a reduction of 25% or 50% in the CO₂ intensity of national electricity production by 2055. These scenarios are used to predict when system life cycle production costs fall to grid prices (grid parity).     

Marginal cost of delivering switchgrass feedstock and producing cellulosic ethanol at multiple biorefineries

Limited information is available regarding the change in cost to deliver dedicated energy crop feedstock as the quantity of required feedstock increases. The objective is to determine the marginal cost to produce and deliver switchgrass feedstock to biorefineries. A mathematical programming model that includes 77 production regions (Oklahoma counties), monthly feedstock requirements, integer activities for harvest machines and integer activities for each of 16 potential biorefinery locations was constructed. The model was initially solved for a single biorefinery. The number of plants was incremented by one and the model resolved until nearly 10% of the cropland and improved pasture land was converted to switchgrass. The estimated cost to deliver 1.0 Mg of feedstock to a single 189 dam³ y⁻¹ capacity biorefinery is 55 $. The cost to deliver feedstock increases as additional biorefineries are constructed and the cost for the ninth biorefinery of 87 $ Mg⁻¹ is 58% greater than the cost to deliver to the first biorefinery. The cost difference is primarily due to differences in transportation cost. Initial cellulosic biorefineries will have an opportunity for establishing a feedstock cost advantage by carefully selecting land for conversion to switchgrass and by negotiating long term leases.     

Optimization of an atmospheric air volumetric central receiver system: Impact of solar multiple,storage capacity and control strategy

Portugal has a high potential for concentrated solar power and namely for atmospheric air volumetric central receiver systems (CRS). The solar multiple and storage capacity have a significant impact on the power plant levelized electricity cost (LEC) and their optimization and adequate control strategy can save significant capital for the investors. The optimized proposed volumetric central receiver system showed good performance and economical indicators.For Faro conditions, the best 4 MW_e power plant configuration was obtained for a 1.25 solar multiple and a 2 h storage. Applying control strategy #1 (CS#1) the power plant LEC is 0.234 €/kWh with a capital investment (CAPEX) of € 22.3 million. The capital invested has an internal rate of return (IRR) of 9.8%, with a payback time of 14 years and a net present value (NPV) of € 7.9 million (considering an average annual inflation of 4%). In the case of better economical indicators, the power plant investment can have positive contours, with an NPV close to € 13 million (annual average inflation of 2%) and the payback shortened to 13 years.     

Analysis of systems for the generation of electricity from solar radiation

The analysis developed here relates the annual electrical output of any type of solar-electric facility directly to the effective annual insolation received on its solar collectors per unit collector area. A general expression for the capacity factor of such a facility is derived through which the ratio of the actual annual electrical output to the maximum mean annual output without demand, generating and downtime reductions, and storage losses can be determined. A general expression for a solar availability factor is also obtained which measures the ratio of the maximum mean annual output of the solar facility to that of a conventional fuel-fired plant of the same installed capacity generating at full capacity continuously for a year. An expression for the fraction of the total electrical output supplied by the solar facility is also derived. The analysis takes full account of the daily and seasonal cycles of solar radiation and its intermittent stochastic character. All results are given for a unit area of solar collector and are thus independent of the size of the facility.The capital cost of solar-electric facilities is expressed in dollars for each kWh per yr of electrical output rather than dollars per kW of installed capacity as is customary for conventional electric generating plants. This cost in turn is divided among three components: for solar-electric generation, for nonsolar auxiliary power, and for storage. A general expression is derived in terms of actual or estimated component costs, and the results for solar generation and storage are shown in Figs. 4 and 5. The choice of solar collector area and of the relative dependence on storage and auxiliary nonsolar power is also discussed.     

Economic implications of thermal energy storage for concentrated solar thermal power

Solar energy is an attractive renewable energy source because the sun's energy is plentiful and carbon-free. However, solar energy is intermittent and not suitable for base load electricity generation without an energy backup system. Concentrated solar power (CSP) is unique among other renewable energy options because it can approach base load generation with molten salt thermal energy storage (TES). This paper describes the development of an engineering economic model that directly compares the performance, cost, and profit of a 110-MW parabolic trough CSP plant operating with a TES system, natural gas-fired backup system, and no backup system. Model results are presented for 0–12 h backup capacities with and without current U.S. subsidies. TES increased the annual capacity factor from around 30% with no backup to up to 55% with 12 h of storage when the solar field area was selected to provide the lowest levelized cost of energy (LCOE). Using TES instead of a natural gas-fired heat transfer fluid heater (NG) increased total plant capital costs but decreased annual operation and maintenance costs. These three effects led to an increase in the LCOE for PT plants with TES and NG backup compared with no backup. LCOE increased with increasing backup capacity for plants with TES and NG backup. For small backup capacities (1–4 h), plants with TES had slightly lower LCOE values than plants with NG backup. For larger backup capacities (5–12 h), plants with TES had slightly higher LCOE values than plants with NG backup. At these costs, current U.S. federal tax incentives were not sufficient to make PT profitable in a market with variable electricity pricing. Current U.S. incentives combined with a fixed electricity price of $200/MWh made PT plants with larger backup capacities more profitable than PT plants with no backup or with smaller backup capacities. In the absence of incentives, a carbon price of $100–$160/tonne CO_2eq would be required for these PT plants to compete with new coal-fired power plants in the U.S. If the long-term goal is to increase renewable base load electricity generation, additional incentives are needed to encourage new CSP plants to use thermal energy storage in the U.S.     

The representation of variable hydro potential in long-range electricity planning models

The long-range planning of electricity supply in countries for which hydro power constitutes a sizeable proportion of total capacity should take into account the effects of variable hydro inflow. Fluctuations occur in the water intake to storage lakes from year to year; reserve generating capacity is required to ensure that demand can still be met in years of low water intake. The least cost choice for reserve capacity must take into account not only the capital costs of generating capacity but also the extra fuel and operating costs, the latter costs being incurred only when water intake is low.This paper describes an LP model of the long-range planning problem in which the effects of both low water inflows and high water inflows are included. The formulation used to represent these variable elements in the model was designed to minimise the number of additional constraints required.     

System-level power-to-gas energy storage for high penetrations of variable renewables

According to outlooks by the IEA and the U.S. EIA, renewables will become the largest source of electricity by 2050 if global temperature rise is to be limited to 2 °C. However, at penetrations greater than 30%, curtailment of wind and solar can be significant in even the most flexible systems. Energy storage can reduce curtailment and increase utilisation of variable renewables. Power-to-gas is a form of long-term storage based on electrolytic production of hydrogen. This research models the co-sizing of wind and solar PV capacity and electrolyser capacity in a jurisdiction targeting 80% penetration of variable renewable electricity. Results indicate that power-to-gas can reduce required wind and solar capacity by as much as 23% and curtailment by as much as 87%. While the majority of charging events last less than 12 h, the majority of the total annual stored energy comes from longer-term events. Additional scenarios reveal that geographic diversity of wind farms reduces capacity requirements, but the same benefit is not found for distributing solar PV.     

A computer study for estimation of seasonal energy consumption and selection of air-conditioner in six Saudi Arabian cities

A computer model was developed to simulate the building cooling load and the seasonal energy consumption of standard residential sized central air-conditioning systems. The model was first validated by comparing the predicted cooling energy consumption against the metered energy of a 100 m² residence. The model predicts within 10% of the metered value. The validated model was next used to compute the cooling load and seasonal energy consumption for similar 100 m² residences in six cities located in different climatic zones of Saudi Arabia. Simulations showed that the cities of Dhahran and Riyadh required a 17.6 kW system to satisfy the cooling load through the year, whereas the defined residences in the cities of Taif, Hail, Jeddah and Gizan required a 14.1 kW system. Our analysis showed that the selected residence in Gizan would consume 23,100 kWh annually, while a comparable residence located in Dhahran, having a more severe summer, required only 21,500 kWh. This difference may be explained by analysis of the weather data which revealed that Gizan required year-round cooling, whereas Dhahran needed cooling for only 283 days during the year. Investigation showed that, by selecting the next smaller capacity air-conditioning unit for each location than required to satisfy the load for 100% of the time, the annual power consumption may be reduced, on an average, by 10%, with about 7% of the hours during the cooling season when the air-conditioning load may not be satisfied.     

Technical assessment of cryo-compressed hydrogen storage tank systems for automotive applications

On-board and off-board performance and cost of cryo-compressed hydrogen storage are assessed and compared to the targets for automotive applications. The on-board performance of the system and high-volume manufacturing cost were determined for liquid hydrogen refueling with a single-flow nozzle and a pump that delivers liquid H₂ to the insulated cryogenic tank capable of being pressurized to 272 atm. The off-board performance and cost of delivering liquid hydrogen were determined for two scenarios in which hydrogen is produced by central steam methane reforming (SMR) or by central electrolysis. The main conclusions are that the cryo-compressed storage system has the potential of meeting the ultimate target for system gravimetric capacity, mid-term target for system volumetric capacity, and the target for hydrogen loss during dormancy under certain conditions of minimum daily driving. However, the high-volume manufacturing cost and the fuel cost for the SMR hydrogen production scenario are, respectively, 2–4 and 1.6–2.4 times the current targets, and the well-to-tank efficiency is well short of the 60% target specified for off-board regenerable materials.     

Assessing green energy growth in Nepal with a hydropower-hydrogen integrated power grid model

The involvement of green hydrogen in energy transformation is getting global attention. This assessment examines the hydrogen production and its utilization potential in one of the hydropower-rich regions, Nepal under various demand growth and technology intervention scenarios by developing a power grid model of 52 nodes and 68 transmission lines operating at an hourly time-step. The model incorporates a grid-connected hydrogen storage system as well as charging stations for electric and hydrogen vehicles. The least-costly pathways for power grid expansion at the nodal and provincial levels are identified through optimization. The results show that 32 GW of installed capacity is required to meet domestic electricity demand and 14 GW more hydropower should be exploited to completely decarbonize the transport sector by 2050. For maintaining 50% shares of hydrogen vehicle in the transport sector and meet government electricity export targets, Nepal requires 5.7 GW, 12 GW and 23 GW of the additional electrolyzer, hydrogen storage tanks and storage-based hydropower capacities respectively. For a given electricity demand, introducing hydrogen systems can reduce the capacity requirements of hydro storage by storing surplus power generated from pondage run-of-the-river and run-of-the-river hydropower during the rainy season and using it in the dry season.     

Reduced storage and balancing needs in a fully renewable European power system with excess wind and solar power generation

The storage and balancing needs of a simplified European power system, which is based on wind and solar power generation only, are derived from an extensive weather-driven modeling of hourly power mismatches between generation and load. The storage energy capacity, the annual balancing energy and the balancing power are found to depend significantly on the mixing ratio between wind and solar power generation. They decrease strongly with the overall excess generation. At 50% excess generation the required long-term storage energy capacity and annual balancing energy amount to 1% of the annual consumption. The required balancing power turns out to be 25% of the average hourly load. These numbers are in agreement with current hydro storage lakes in Scandinavia and the Alps, as well as with potential hydrogen storage in mostly North-German salt caverns.     

蓄冰空调系统在办公类建筑中的经济性分析

针对蓄冰空调系统的工程应用,阐述系统工作原理及其适用性分析,选取河北省某办公建筑作为研究对象,按照此建筑用能特点以及当地电价结构,选择了100%、80%、60%、40%、20%五档部分负荷率对蓄冰空调系统与传统空调系统进行全年运行能耗及电费对比,分析结果表明:虽然蓄冰空调系统初投资偏高,但其年运行费用比传统空调系统节省电费32.4%,寿命期内年费用节省20.43%。