Optimal operation scheduling of wind power integrated with compressed air energy storage (CAES)

This study optimises and compares the operation of a conventional gas-fired power generation company with its operation in combination with wind power and compressed air energy storage (CAES). A mixed integer non-linear programming (MINLP) formulation is developed for the optimisation problem. Limits in ramp rate, capacity, and minimum on/off time, as well as start-up cost constraints, are considered for the modelling of conventional units. Injected and produced power constraints, storage, air balance and CAES-operation limits are considered in the CAES modelling. Two objective functions (profit maximisation and cost minimisation) are modelled. Without considering capital costs, it is found that the use of CAES results in 43% higher operational profits and 6.7% lower costs in a market environment.     

Economic evaluation of latent heat thermal energy storage using embedded thermosyphons for concentrating solar power applications

An economic evaluation of a latent heat thermal energy storage (LHTES) system for large scale concentrating solar power (CSP) applications is conducted. The concept of embedding gravity-assisted wickless heat pipes (thermosyphons) within a commercial-scale LHTES system is explored through use of a thermal network model. A new design is proposed for charging and discharging a large-scale LHTES system. The size and cost of the LHTES system is estimated and compared with a two-tank sensible heat energy storage (SHTES) system. The results suggest that LHTES with embedded thermosyphons is economically competitive with current SHTES technology, with the potential to reduce capital costs by at least 15%. Further investigation of different phase change materials (PCMs), thermosyphon working fluids, and system configurations has the potential to lead to designs that can further reduce capital costs beyond those reported in this study.     

The role of energy storage in accessing remote wind resources in the Midwest

Replacing current generation with wind energy would help reduce the emissions associated with fossil fuel electricity generation. However, integrating wind into the electricity grid is not without cost. Wind power output is highly variable and average capacity factors from wind farms are often much lower than conventional generators. Further, the best wind resources with highest capacity factors are often located far away from load centers and accessing them therefore requires transmission investments. Energy storage capacity could be an alternative to some of the required transmission investment, thereby reducing capital costs for accessing remote wind farms. This work focuses on the trade-offs between energy storage and transmission. In a case study of a 200 MW wind farm in North Dakota to deliver power to Illinois, we estimate the size of transmission and energy storage capacity that yields the lowest average cost of generating and delivering electricity ($/MW h) from this farm. We find that transmission costs must be at least $600/MW-km and energy storage must cost at most $100/kW h in order for this application of energy storage to be economical.     

Hydrogen refueling station compression and storage optimization with tube-trailer deliveries

Hydrogen refueling stations require high capital investment, with compression and storage comprising more than half of the installed cost of refueling equipment. Refueling station configurations and operation strategies can reduce capital investment while improving equipment utilization. Argonne National Laboratory developed a refueling model to evaluate the impact of various refueling compression and storage configurations and tube trailer operating strategies on the cost of hydrogen refueling. The modeling results revealed that a number of strategies can be employed to reduce fueling costs. Proper sizing of the high-pressure buffer storage reduces the compression requirement considerably, thus reducing refueling costs. Employing a tube trailer to initially fill the vehicle's tank also reduces the compression and storage requirements, further reducing refueling costs. Reducing the cut-off pressure of the tube trailer for initial vehicle fills can also significantly reduce the refueling costs. Finally, increasing the trailer's return pressure can cut refueling costs, especially for delivery distances less than 100 km, and in early markets, when refueling stations will be grossly underutilized.     

Thermoeconomic optimization of an ice thermal storage system for gas turbine inlet cooling

The gas turbine power output and efficiency decrease with increasing ambient temperature. With compressor inlet air cooling, the air density and mass flow rate as well as the gas turbine net power output increase. The inlet cooling techniques include vapor or absorption refrigeration systems, evaporative cooling systems and thermal energy storage (TES) systems. In this paper the thermoeconomic analysis of ice (latent) thermal energy storage system for gas turbine inlet cooling application was performed. The optimum values of system design parameters were obtained using genetic algorithm optimization technique. The objective function included the capital and operational costs of the gas turbine, vapor compression refrigeration system, without (objective function I) and with (objective function II) corresponding cost due to the system exergy destruction. For gas turbines with net power output in the range of 25-100 MW, the inlet air cooling using a TES system increased the power output in the range of 3.9-25.7%, increased the efficiency in the range 2.1-5.2%, while increased the payback period from about 4 to 7.7 years.     

Bulk storage of hydrogen

The technical aspects and economics of bulk hydrogen storage in underground pipes, lined rock caverns (LRC) and salt caverns are analyzed. Hydrogen storage in underground pipes is more economical than in geological caverns for useable amounts <20-t-H₂. However, because the pipe material is a major cost factor, the capital and operating costs for this storage method do not decrease appreciably with an increase in the amount of stored H₂. Unlike underground pipes, the installed capital cost of salt caverns decreases appreciably from ~$95/kg-H₂ at 100 t-H₂ stored to <$19/kg-H₂ at 3000 t-H₂ stored. Over the same scale, the annual storage cost decreases from ~$17/kg-H₂ to ~$3/kg-H₂. Like salt caverns, the installed capital cost of lined rock caverns decreases from ~$160/kg-H₂ at 100 t-H₂ stored to <$44/kg-H₂ at 3000 t-H₂ stored. Storing >750-t useable H₂ requires multiple caverns. The cost of salt caverns scales more favorably with size because the salt caverns are larger than lined rock caverns and need to be added at a slower rate as the storage capacity is increased.     

Dynamic modeling of hybrid energy storage systems coupled to photovoltaic generation in residential applications

A model of a photovoltaic (PV) powered residence in stand-alone configuration was developed and evaluated. The model assesses the sizing, capital costs, control strategies, and efficiencies of reversible fuel cells (RFC), batteries, and ultra-capacitors (UC) both individually, and in combination, as hybrid energy storage devices. The choice of control strategy for a hybrid energy storage system is found to have a significant impact on system efficiency, hydrogen production and component utilization. A hybrid energy storage system comprised of batteries and RFC has the advantage of reduced cost (compared to using a RFC as the sole energy storage device), high system efficiency and hydrogen energy production capacity. A control strategy that preferentially used the RFC before the battery in meeting load demand allows both grid independent operation and better RFC utilization compared to a system that preferentially used the battery before the RFC. Ultra-capacitors coupled with a RFC in a hybrid energy storage system contain insufficient energy density to meet dynamic power demands typical of residential applications.     

Baseload electricity from wind via compressed air energy storage (CAES)

This study investigates two methods of transforming intermittent wind electricity into firm baseload capacity: (1) using electricity from natural gas combined-cycle (NGCC) power plants and (2) using electricity from compressed air energy storage (CAES) power plants. The two wind models are compared in terms of capital and electricity costs, CO₂ emissions, and fuel consumption rates. The findings indicate that the combination of wind and NGCC power plants is the lowest-cost method of transforming wind electricity into firm baseload capacity power supply at current natural gas prices (∼$6/GJ). However, the electricity supplied by wind and CAES power plants becomes economically competitive when the cost of natural gas for electric producers is $10.55/GJ or greater. In addition, the Wind-CAES system has the lowest CO₂ emissions (93% and 71% lower than pulverized coal power plants and Wind-NGCC, respectively) and the lowest fuel consumption rates (9 and 4 times lower than pulverized coal power plants and Wind-NGCC, respectively). As such, the large-scale introduction of Wind-CAES systems in the U.S. appears to be the prudent long-term choice once natural gas price volatility, costs, and climate impacts are all considered.     

Hydrogen storage and demand to increase wind power onto electricity distribution networks

An optimal power flow (OPF) methodology is developed to investigate the provision of a demand hydrogen as a means to maximise wind power generation in relation to a constrained electricity network. The use of excess wind energy to generate hydrogen for use as a transport fuel is investigated. Hydrogen demand is included in the objective function of the OPF, and a techno-economic analysis is presented. We conclude that using this method to generate hydrogen increases the utilisation of wind energy and allows for a hydrogen demand to be met at or near to the point of use. The OPF algorithm that has been developed optimises the amount of wind energy utilised, as well as minimising the amount of hydrogen demand not met. The cost at which the hydrogen is produced was found to be dependent on the operating methodology, component capital investment costs, level of hydrogen demand, and storage constraint.     

Performance evaluation of district cooling plant with ice storage

District cooling system (DCS) is a massive cooling energy production scheme that serves a group of buildings. The system performance can often be improved by the incorporation of a cool-storage system, in that part of the cooling demand is shifted from peak hours to non-peak hours. This brings mutual benefits to the power supplier and the consumers. In order to evaluate the energy performance and cost effectiveness of such an integrated technology, a feasible district cooling plus ice-storage system was developed for a hypothetical site in Hong Kong. A parametric study making use of the DOE-2 and TRNSYS simulation software was conducted to evaluate the system performance at different partial storage capacities, control strategies, and tariff structures. Other than the basic design factors, the results from 27 cases showed the importance of the tariff structure, the capital and electricity costs in this issue.     

Pumped storage in systems with very high wind penetration

This paper examines the operation of the Irish power system with very high levels of wind energy, with and without pumped storage. A unit commitment model which accounts for the uncertainty in wind power is used. It is shown that as wind penetration increases, the optimal operation of storage depends on wind output as well as load. The main benefit from storage is shown to be a decrease in wind curtailment. The economics of the system are examined to find the level at which storage justifies its capital costs and inefficiencies. It is shown that the uncertainty of wind makes the option of storage more attractive. The size of the energy store has an impact on results. At lower levels of installed wind (up to approximately 50% of energy from wind in Ireland), the reduction in curtailment is insufficient to justify building storage. At greater levels of wind, storage reduces curtailment sufficiently to justify the additional capital costs. It can be seen that if storage replaces OCGTs in the plant mix instead of CCGTs, then the level at which it justifies itself is lower. Storage increases the level of carbon emissions at wind penetration below 60%.     

Cost and performance of fossil fuel power plants with CO2 capture and storage

CO₂ capture and storage (CCS) is receiving considerable attention as a potential greenhouse gas (GHG) mitigation option for fossil fuel power plants. Cost and performance estimates for CCS are critical factors in energy and policy analysis. CCS cost studies necessarily employ a host of technical and economic assumptions that can dramatically affect results. Thus, particular studies often are of limited value to analysts, researchers, and industry personnel seeking results for alternative cases. In this paper, we use a generalized modeling tool to estimate and compare the emissions, efficiency, resource requirements and current costs of fossil fuel power plants with CCS on a systematic basis. This plant-level analysis explores a broader range of key assumptions than found in recent studies we reviewed for three major plant types: pulverized coal (PC) plants, natural gas combined cycle (NGCC) plants, and integrated gasification combined cycle (IGCC) systems using coal. In particular, we examine the effects of recent increases in capital costs and natural gas prices, as well as effects of differential plant utilization rates, IGCC financing and operating assumptions, variations in plant size, and differences in fuel quality, including bituminous, sub-bituminous and lignite coals. Our results show higher power plant and CCS costs than prior studies as a consequence of recent escalations in capital and operating costs. The broader range of cases also reveals differences not previously reported in the relative costs of PC, NGCC and IGCC plants with and without CCS. While CCS can significantly reduce power plant emissions of CO₂ (typically by 85–90%), the impacts of CCS energy requirements on plant-level resource requirements and multi-media environmental emissions also are found to be significant, with increases of approximately 15–30% for current CCS systems. To characterize such impacts, an alternative definition of the “energy penalty” is proposed in lieu of the prevailing use of this term.     

Redox flow batteries—Concepts and chemistries for cost-effective energy storage

Electrochemical energy storage is one of the few options to store the energy from intermittent renewable energy sources like wind and solar. Redox flow batteries (RFBs) are such an energy storage system, which has favorable features over other battery technologies, e.g. solid state batteries, due to their inherent safety and the independent scaling of energy and power content. However, because of their low energy-density, low power-density, and the cost of components such as redox species and membranes, commercialised RFB systems like the all-vanadium chemistry cannot make full use of the inherent advantages over other systems. In principle, there are three pathways to improve RFBs and to make them viable for large scale application: First, to employ electrolytes with higher energy density. This goal can be achieved by increasing the concentration of redox species, employing redox species that store more than one electron or by increasing the cell voltage. Second, to enhance the power output of the battery cells by using high kinetic redox species, increasing the cell voltage, implementing novel cell designs or membranes with lower resistance. The first two means reduce the electrode surface area needed to supply a certain power output, thereby bringing down costs for expensive components such as membranes. Third, to reduce the costs of single or multiple components such as redox species or membranes. To achieve these objectives it is necessary to develop new battery chemistries and cell configurations. In this review, a comparison of promising cell chemistries is focused on, be they all-liquid, slurries or hybrids combining liquid, gas and solid phases. The aim is to elucidate which redox-system is most favorable in terms of energy-density, power-density and capital cost. Besides, the choice of solvent and the selection of an inorganic or organic redox couples with the entailing consequences are discussed.     

Optimization of hybrid solar energy sources/wind turbine systems integrated to utility grids as microgrid (MG) under pool/bilateral/hybrid electricity market using PSO

This study presents an optimized design of microgrid (MG) in distribution systems with multiple distributed generation (DG) units under different market policies such as pool/hybrid electricity market.Proposed microgrid includes various energy sources such as photovoltaic array and wind turbine with energy storage devices such as battery bank.In this study, microgrid is considered as independent power producer company (IPP) in power system. Price of selling/buying power in on-peak or off-peak for MG, DG and upstream power system (DISCO) under pool/bilateral/hybrid electricity market are different. In this study, particle swarm optimization (PSO) algorithm has been implemented for the optimization of the microgrid cost. The costs include capital cost, replacement cost, operation and maintenance costs and production cost for microgrid and DGs. Then, an objective function to maximize total net present worth (NPW) is presented. PSO approach is employed to obtain the minimum cost of microgrid, during interconnected operation by optimizing the production of local DGs and power exchanges with the main distribution grid. The optimization algorithm is applied to a typical LV network operating under different market policies.     

Long-term prospects for compressed air storage

The compressed air storage (CAS) concept has been reviewed in the light of the long-term requirement for energy storage to effect load following in a predominantly nuclear generating system. This requirement would eventually lead to the operation of storage plant on a daily cycle of storing energy for 6–8 h and generating for 12–16 h. Conventional CAS schemes, typified by the Nordwestdeutchen Kraftwerke (NWK) installation in West Germany, are shown to be incapable of fulfilling this duty on merit.The basic concept is then re-examined and a novel development is proposed which, by using uncooled compressors and conserving the compression energy, constitutes a true energy storage scheme requiring no fuel other than the off-peak energy taken from the electrical grid. The efficiency and other performance characteristics of this proposal are discussed.The capital cost of an 8 GWh storage scheme is tentatively put at £125–175/kW (at 1974 price levels), depending on the air store construction, well within the £200/kW cost target which storage plant would need to meet to be of interest for storing off-peak nuclear power by the end of the present century. It is concluded that, once developed, CAS schemes which incorporate heat storage could provide an attractive method for storing off-peak electricity.     

Biomass-fired cogeneration systems with CO2 capture and storage

In this study, we estimate and analyze the CO₂ mitigation costs of large-scale biomass-fired cogeneration technologies with CO₂ capture and storage. The CO₂ mitigation cost indicates the minimum economic incentive required (e.g. in the form of a carbon tax) to make the cost of a less carbon intensive system equal to the cost of a reference system. If carbon (as CO₂) is captured from biomass-fired energy systems, the systems could in principle be negative CO₂ emitting energy systems. CO₂ capture and storage from energy systems however, leads to reduced energy efficiency, higher investment costs, and increased costs of end products compared with energy systems in which CO₂ is vented. Here, we have analyzed biomass-fired cogeneration plants based on steam turbine technology (CHP-BST) and integrated gasification combined cycle technology (CHP-BIGCC). Three different scales were considered to analyze the scale effects. Logging residues was assumed as biomass feedstock. Two methods were used to estimate and compare the CO₂ mitigation cost. In the first method, the cogenerated power was credited based on avoided power production in stand-alone plants and in the second method the same reference output was produced from all systems. Biomass-fired CHP-BIGCC with CO₂ capture and storage was found very energy and emission efficient and cost competitive compared with other conversion systems.     

Battery storage in residential applications of energy from photovoltaic sources

Electric energy storage in batteries is discussed for future applications in homeowner-controlled grid-tied photovoltaic power generation systems for residences. Energy storage would enable more effective matching of the intermittent solar-generated energy to high-use periods, as well as storage of energy for sale to the utilities, taking advantage of future variable (time-of-day) utility rate and buy-back structures. State-of-the-art lead-acid batteries are economically viable for utility rate scenarios that are expected to be in effect in many areas of the United States in the mid-1980s.¹ ‘Advanced batteries’ (e.g. sodium-sulfur, zinc-bromine, lithium-metal sulfide) with decreased capital investment costs, minimal maintenance and improved performance characteristics could have enhanced consumer acceptance in the late 1980s.     

Representation of variable renewable energy sources in TIMER,an aggregated energy system simulation model

The power system is expected to play an important role in climate change mitigation. Variable renewable energy (VRE) sources, such as wind and solar power, are currently showing rapid growth rates in power systems worldwide, and could also be important in future mitigation strategies. It is therefore important that the electricity sector and the integration of VRE are correctly represented in energy models. This paper presents an improved methodology for representing the electricity sector in the long-term energy simulation model TIMER using a heuristic approach to find cost optimal paths given system requirements and scenario assumptions. Regional residual load duration curves have been included to simulate curtailments, storage use, backup requirements and system load factor decline as the VRE share increases. The results show that for the USA and Western Europe at lower VRE penetration levels, backup costs form the major VRE cost markup. When solar power supplies more than 30% of the electricity demand, the costs of storage and energy curtailments become increasingly important. Storage and curtailments have less influence on wind power cost markups in these regions, as wind power supply is better correlated with electricity demand. Mitigation scenarios show an increasing VRE share in the electricity mix implying also increasing contribution of VRE for peak and mid load capacity. In the current scenarios, this can be achieved by at the same time installing less capital intensive gas fired power plants. Sensitivity analysis showed that greenhouse gas emissions from the electricity sector in the updated model are particularly sensitive to the availability of carbon capture and storage (CCS) and nuclear power and the costs of VRE.     

Harvest schedule to fill storage for year-round delivery of grasses to biorefinery

Number of annual harvest days is a critical variable in the scheduling of year-round delivery of grasses to a biorefinery. It defines the number of harvest machines required and the size of satellite storage capacity. An increase in both these parameters increases capital cost and thus the average delivered cost of biomass for year-round operation. The objective of this study was to determine the impact (number of harvest machines required and storage capacity required) of several harvest scenarios for switchgrass (Panicum virgatum). Calculations were done for a database of potential production fields within a 48-km radius of Gretna, Virginia. Four harvest scenarios were chosen ranging from short, October–December to extended, July–March. The extended harvest required only 33 round balers while the short (October–December) harvest required 64; consequently, capital cost for extended-harvest balers was only 51% of the baler capital cost for the short season. Maximum required storage capacity was 75% of the total annual harvest for the short season and 44% for the extended season. Capital cost to build storage was reduced by 41% by selecting the extended harvest season.     

Effect of storage options on price-based scheduling for a hybrid trigeneration system

Trigeneration is efficient to supply cooling, heat, and power demands. Also, hydro (pumped) storage with zero fuel costs can increase profit when price-based scheduling problem is solved. The goal of this study is to investigate the effects of electric boiler, hydro storage, and heat storage tank on price-based scheduling problem for hybrid trigeneration (trigeneration-conventional-gas boiler) system. A heuristic algorithm is applied to a power system where in validation case, total cost reduction of 0.63% to 0.91% is reached as compared with reported in literature. The results show that the utilization of electric boiler, hydro storage, and heat storage tank leads to profit improvement by 4.58%. Also, a critical sensitivity analysis is conducted and the results show the significant effects of several factors on scheduling results.