Economics of compressed air energy storage to integrate wind power: A case study in ERCOT

Compressed air energy storage (CAES) could be paired with a wind farm to provide firm, dispatchable baseload power, or serve as a peaking plant and capture upswings in electricity prices. We present a firm-level engineering-economic analysis of a wind/CAES system with a wind farm in central Texas, load in either Dallas or Houston, and a CAES plant whose location is profit-optimized. With 2008 hourly prices and load in Houston, the economically optimal CAES expander capacity is unrealistically large – 24 GW – and dispatches for only a few hours per week when prices are highest; a price cap and capacity payment likewise results in a large (17 GW) profit-maximizing CAES expander. Under all other scenarios considered the CAES plant is unprofitable. Using 2008 data, a baseload wind/CAES system is less profitable than a natural gas combined cycle (NGCC) plant at carbon prices less than $56/tCO₂ ($15/MMBTU gas) to $230/tCO₂ ($5/MMBTU gas). Entering regulation markets raises profit only slightly. Social benefits of CAES paired with wind include avoided construction of new generation capacity, improved air quality during peak times, and increased economic surplus, but may not outweigh the private cost of the CAES system nor justify a subsidy.     

The value of compressed air energy storage with wind in transmission-constrained electric power systems

In this work, we examine the potential advantages of co-locating wind and energy storage to increase transmission utilization and decrease transmission costs. Co-location of wind and storage decreases transmission requirements, but also decreases the economic value of energy storage compared to locating energy storage at the load. This represents a tradeoff which we examine to estimate the transmission costs required to justify moving storage from load-sited to wind-sited in three different locations in the United States. We examined compressed air energy storage (CAES) in three “wind by wire” scenarios with a variety of transmission and CAES sizes relative to a given amount of wind. In the sites and years evaluated, the optimal amount of transmission ranges from 60% to 100% of the wind farm rating, with the optimal amount of CAES equal to 0–35% of the wind farm rating, depending heavily on wind resource, value of electricity in the local market, and the cost of natural gas.     

Techno‐economic study of compressed air energy storage systems for the grid integration of wind power

Integrating variable renewable energy from wind farms into power grids presents challenges for system operation, control, and stability due to the intermittent nature of wind power. One of the most promising solutions is the use of compressed air energy storage (CAES). The main purpose of this paper is to examine the technical and economic potential for use of CAES systems in the grid integration. To carry out this study, 2 CAES plant configurations: adiabatic CAES (A‐CAES) and diabatic CAES (D‐CAES) were modelled and simulated by using the process simulation software ECLIPSE. The nominal compression and power generation of both systems were given at 100 and 140 MWe, respectively. Technical results showed that the overall energy efficiency of the A‐CAES was 65.6%, considerably better than that of the D‐CAES at 54.2%. However, it could be seen in the economic analysis that the breakeven electricity selling price (BESP) of the A‐CAES system was much higher than that of the D‐CAES system at €144/MWh and €91/MWh, respectively. In order to compete with large‐scale fossil fuel power plants, we found that a CO₂ taxation scheme (with an assumed CO₂‐tax of €20/tonne) improved the economic performance of both CAES systems significantly. This advantage is maximised if the CAES systems use low carbon electricity during its compression cycle, either through access to special tariffs at times of low carbon intensity on the grid, or by direct coupling to a clean energy source, for example a 100‐MW class wind farm.     

Compressed Air Energy Storage in an Electricity System With Significant Wind Power Generation

In this paper, a stochastic electricity market model is applied to estimate the effects of significant wind power generation on system operation and on economic value of investments in compressed air energy storage (CAES). The model's principle is cost minimization by determining the system costs mainly as a function of available generation and transmission capacities, primary energy prices, plant characteristics, and electricity demand. To obtain appropriate estimates, notably reduced efficiencies at part load, start-up costs, and reserve power requirements are taken into account. The latter are endogenously modeled by applying a probabilistic method. The intermittency of wind is covered by a stochastic recombining tree and the system is considered to adapt on increasing wind integration over time by endogenous modeling of investments in selected thermal power plants and CAES. Results for a German case study indicate that CAES can be economic in the case of large-scale wind power deployment     

System behaviour of compressed-air energy-storage in Denmark with a high penetration of renewable energy sources

In 2005, wind power supplied 19% of the 36 TWh annual electricity demand in Denmark, while 50% was produced at combined heat-and-power plants (CHP). The installed wind-turbine capacity in Western Denmark exceeds the local demand at certain points in time. So far, excess production has been exported to neighbouring countries. However, plans to expand wind power both in Denmark and in its neighbouring countries could restrain the export option and create transmission congestion challenges. This results in a need to increase the flexibility of the local electricity-system. Compressed-Air Energy-Storage (CAES) has been proposed as a potential solution for levelling fluctuating wind-power production and maintaining a system balance. This paper analyses the energy-balance effects of adding CAES to the Western Danish energy-system. Results show that even with an unlimited CAES plant capacity, excess power production is not eliminated because of the high percentage of CHP production. The optimal wind-power penetration for maximum CAES operation is found to be around 55%. The minimum storage size for CAES to fully eliminate condensing power plants operation in the optimized system is over 500 GWh, which corresponds to a cavern volume of around 234 Mm³ at an average pressure of 60 bar. Such a storage size would be technically and economically unfeasible. The analysis, however, did not include the potential role of a CAES plant in regulating the power services.     

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.     

A 100% renewable electricity generation system for New Zealand utilising hydro,wind, geothermal and biomass resources

The New Zealand electricity generation system is dominated by hydro generation at approximately 60% of installed capacity between 2005 and 2007, augmented with approximately 32% fossil-fuelled generation, plus minor contributions from geothermal, wind and biomass resources. In order to explore the potential for a 100% renewable electricity generation system with substantially increased levels of wind penetration, fossil-fuelled electricity production was removed from an historic 3-year data set, and replaced by modelled electricity production from wind, geothermal and additional peaking options. Generation mixes comprising 53–60% hydro, 22–25% wind, 12–14% geothermal, 1% biomass and 0–12% additional peaking generation were found to be feasible on an energy and power basis, whilst maintaining net hydro storage. Wind capacity credits ranged from 47% to 105% depending upon the incorporation of demand management, and the manner of operation of the hydro system. Wind spillage was minimised, however, a degree of residual spillage was considered to be an inevitable part of incorporating non-dispatchable generation into a stand-alone grid system. Load shifting was shown to have considerable advantages over installation of new peaking plant. Application of the approach applied in this research to countries with different energy resource mixes is discussed, and options for further research are outlined.     

Design and thermodynamic analysis of compressed air energy storage system

压缩空气储能技术具有提升风能与太阳能等可再生资源电能质量的潜力,通过此项技术实现间歇性与不稳定性可再生电力的有效储存,进而在电网负荷高峰期以优质电力的形式稳定输出.结合热力学分析方法设计了储能功率56.58 MW,释能输出功率154.76 MW的压缩空气储能系统.在释能阶段透平机组配置上,参照GE 9171E燃机布置第二级透平入口参数,并以其812.41 K高温烟气余热提供第一级透平工质所需全部热量,无需为第一级透平配备专门燃烧器.在此思路下设计的压缩空气储能系统,热耗可降低至3783.96 kJ/(kW·h),储能系统的能量转换效率也高达56.11%.     

The technical,geographical, and economic feasibility for solar energy to supply the energy needs of the US

So far, solar energy has been viewed as only a minor contributor in the energy mixture of the US due to cost and intermittency constraints. However, recent drastic cost reductions in the production of photovoltaics (PV) pave the way for enabling this technology to become cost competitive with fossil fuel energy generation. We show that with the right incentives, cost competitiveness with grid prices in the US (e.g., 6–10 US¢/kWh) can be attained by 2020. The intermittency problem is solved by integrating PV with compressed air energy storage (CAES) and by extending the thermal storage capability in concentrated solar power (CSP). We used hourly load data for the entire US and 45-year solar irradiation data from the southwest region of the US, to simulate the CAES storage requirements, under worst weather conditions. Based on expected improvements of established, commercially available PV, CSP, and CAES technologies, we show that solar energy has the technical, geographical, and economic potential to supply 69% of the total electricity needs and 35% of the total (electricity and fuel) energy needs of the US by 2050. When we extend our scenario to 2100, solar energy supplies over 90%, and together with other renewables, 100% of the total US energy demand with a corresponding 92% reduction in energy-related carbon dioxide emissions compared to the 2005 levels.     

A model for the development of a power production system in Greece,Part II: Where RES meet EU targets

This paper studies the electricity production system of the Greek Interconnected Electric System using a development model created with the software package WASP-IV. The period of study is from 2009 till 2030. It consists of three scenarios using three different criteria: energy, environmental, and economic. The three scenarios are the Renewable Energy Source (RES), the lignite–RES, and the natural gas–RES. Subsequently, a sensitivity analysis is carried out for annual growth rate of electricity consumption and load demand. It is considered that there are no other energy sources beyond those already in use (lignite, oil, natural gas, biomass, solar, wind, and hydropower), no CO₂ capture policies are implemented, and electricity production from RES meets targets of the European Union in 2020. The present paper completes the study started with the paper “A model for the development of a power production system in Greece, Part I: RES do not meet EU targets”. It is shown that with regard to fossil fuels, the use of natural gas is the best choice. The use of RES, though environmentally friendly, is an expensive solution.     

Energy balance analysis of wind-based pumped hydro storage systems in remote island electrical networks

The introduction of pumped hydro storage (PHS) systems in isolated electrical grids, such as those found in island regions, appears to be a promising solution that is able to face both the high electricity production cost and the continuously increasing power demand encountered in these areas. In this context, the current work presents a methodology for the sizing of PHS systems that exploit the excess wind energy amounts produced by local wind farms, otherwise rejected due to imposed electrical grid limitations. The methodology is accordingly applied to the Greek island of Lesbos. Initially, a calculation of the wind power penetration ability to the local grid is carried out and the corresponding curtailments of existing and future wind farms are determined. An integrated computational algorithm is then presented which simulates the operation of the system during an entire year and gives in detail the hourly operational status as well as the various energy losses of the system main components. Based on the application results obtained, the ability of the wind energy to remarkably contribute to the electrification of the remote islands becomes evident.     

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.     

Improving the technical, environmental and social performance of wind energy systems using biomass-based energy storage

A completely renewable baseload electricity generation system is proposed by combining wind energy, compressed air energy storage, and biomass gasification. This system can eliminate problems associated with wind intermittency and provide a source of electrical energy functionally equivalent to a large fossil or nuclear power plant. Compressed air energy storage (CAES) can be economically deployed in the Midwestern US, an area with significant low-cost wind resources. CAES systems require a combustible fuel, typically natural gas, which results in fuel price risk and greenhouse gas emissions. Replacing natural gas with synfuel derived from biomass gasification eliminates the use of fossil fuels, virtually eliminating net CO₂ emissions from the system. In addition, by deriving energy completely from farm sources, this type of system may reduce some opposition to long distance transmission lines in rural areas, which may be an obstacle to large-scale wind deployment.     

The Lebanese electricity system in the context of sustainable development

The Lebanese electricity system has been evaluated in terms of its sustainability. An integrated approach was adopted to assess the life-cycle technical, environmental, energy and economic attributes of the system. The findings show that the Lebanese electricity system is characterized by a weak performance in all analysed aspects related to the sustainability of energy systems. Specifically, the system lacks adequacy and security leading to a supply–demand deficit and poor diversity. It gives rise to significant environmental emissions (including green-house gases), and produces large economic inefficiencies. The costs and benefits of optimising the performance of the centralised electricity system are presented, indicating substantial net benefits (together with considerable benefits in reduced environmental impacts across the life-cycle assessment categories, including carbon emissions) from improving the transmission and distribution networks, upgrading existing conventional plants to their design standards, and shifting towards the use of natural gas. The expected levelised cost of various energy sources in Lebanon also indicates that renewable energy sources are competitive alternatives at the present time.     

Bulk energy storage potential in the USA, current developments and future prospects

Stored energy can provide electricity during periods of high demand, as currently demonstrated with bulk storage systems such as pumped hydro storage (PHS), which accounts for only 2.5% of the current installed base load in the USA. Sites for future developments have become less available, and environmental siting issues, as well as high costs have stopped further prospects. This paper looks at the potential beyond PHS, with bulk storage systems such as compressed air energy storage (CAES) flow-batteries and 1 MW flywheel systems that can provide system stability/support at the grid, substations and distributed level. Current developments in bulk energy storage will be reviewed as well as some storage project developments incorporating wind energy and the impact on base-loaded coal and natural gas fired GT combined cycle plants. The large potential and the economic benefits for energy storage in the US will be examined.     

Exploring the impact on cost and electricity production of high penetration levels of intermittent electricity in OECD Europe and the USA,results for wind energy

In this study we explore for the USA and OECD Europe (OECD Europe includes the countries that participate in the Organisation of Economic Cooperation and Development, among which Western Europe, USA and Japan) dynamic changes in electricity production, cost and CO₂ emissions when intermittent electricity sources are used with increasing penetration levels. The methodology developed can be applied for both solar photovoltaic (PV) and wind energy. Here the focus of the results is on penetration of wind electricity in the electricity system as simulated in a long-term model experiment in which the electricity demand is kept constant over time. All important parameter are included in a sensitivity analysis. With increasing penetration levels the cost reduction of wind electricity caused by upscaling and technological learning is counteracted by the cost increase due to (1) the need for additional back-up capacity, (2) the need to generate wind electricity at less favourable sites, and (3) discarded wind electricity because of supply–demand mismatch. This occurs after about 20% wind electricity production as percentage of current electricity production. At this level about 500 (OECD Europe) and 750 (USA) TWh yr⁻¹ wind electricity is absorbed in the system with the electricity demand of the year 2000. Wind electricity is found to be discarded when the production is about 55 (USA) to 10 times (OECD Europe) the present electricity produced from wind power. Beyond 30% of present electricity production, cost increases most significantly because of discarded wind electricity, excluding storage. In both regions the use of wind electricity would mainly avoid use of natural gas. The CO₂ emissions abatement costs range from 14 (OECD Europe) to 33 (USA) $ per ton CO₂ differ in both regions due to a faster wind electricity cost increase in OECD Europe.     

Combining hydro and variable wind power generation by means of pumped-storage under economically viable terms

Pumped hydro storage (PHS) systems which are located at isolated regions and are able to exploit the rejected wind energy amounts produced by local wind farms, seem to gain interest worldwide and to become essential in regard to higher shares of renewable-generated electricity. Despite the high wind potential encountered in many Greek island regions, the wind energy contribution to the electrification of these areas is significantly restricted due to imposed electrical grid limitations. In this context, the current work examines the economic viability of a wind-based PHS system (wind-hydro solution) which provides the local electrical grid of an Aegean Sea island, Lesbos, with guaranteed energy amounts during the peak load demand periods. Based on the maximization of the project’s net present value, the optimum system configuration is proposed while many other feasible solutions are revealed. According to the results obtained the implementation of this project demonstrates excellent technical and economic performance, while at the same time renewable energy sources (RES) contribution is doubled reaching almost 20% of the Lesbos island electrical energy consumption.     

Thermo-economic analysis and sizing of a PV plant equipped with a compressed air energy storage system

Photovoltaic (PV) farms are widely used around the world to provide required electricity. Compressed air energy storage (CAES) system has been already proposed for energy storage applications in large scales. In this work, employing a CAES unit equipped with an ancillary solar heating system for a large scale PV farm in Brazil is proposed. A PV farm with 100 MWp (megawatt peak) capacity is proposed to be built in the most suitable point within Brazil. The sizing of the CAES unit and the solar heating system, which has not been investigated, along with selecting the best power sales strategy for the power plant, which has been always a challenge for renewable energy source power plants, are carried out emphasizing energy-economic considerations. In order to prove the proficiency of the proposal, the performance of the power plant and energy storage unit is assessed over a sample year. In order to have a comprehensive economic analysis, Net Present Value (NPV) method is employed and all the possible uncertainties in the system have been taken into account.     

Baseload wind energy: modeling the competition between gas turbines and compressed air energy storage for supplemental generation

The economic viability of producing baseload wind energy was explored using a cost-optimization model to simulate two competing systems: wind energy supplemented by simple- and combined cycle natural gas turbines (“wind+gas”), and wind energy supplemented by compressed air energy storage (“wind+CAES”). Pure combined cycle natural gas turbines (“gas”) were used as a proxy for conventional baseload generation. Long-distance electric transmission was integral to the analysis. Given the future uncertainty in both natural gas price and greenhouse gas (GHG) emissions price, we introduced an effective fuel price, p_NGeff, being the sum of the real natural gas price and the GHG price. Under the assumption of p_NGeff=$5/GJ (lower heating value), 650 W/m² wind resource, 750 km transmission line, and a fixed 90% capacity factor, wind+CAES was the most expensive system at ¢6.0/kWh, and did not break even with the next most expensive wind+gas system until p_NGeff=$9.0/GJ. However, under real market conditions, the system with the least dispatch cost (short-run marginal cost) is dispatched first, attaining the highest capacity factor and diminishing the capacity factors of competitors, raising their total cost. We estimate that the wind+CAES system, with a greenhouse gas (GHG) emission rate that is one-fourth of that for natural gas combined cycle plants and about one-tenth of that for pulverized coal plants, has the lowest dispatch cost of the alternatives considered (lower even than for coal power plants) above a GHG emissions price of $35/tC_equiv., with good prospects for realizing a higher capacity factor and a lower total cost of energy than all the competing technologies over a wide range of effective fuel costs. This ability to compete in economic dispatch greatly boosts the market penetration potential of wind energy and suggests a substantial growth opportunity for natural gas in providing baseload power via wind+CAES, even at high natural gas prices.     

Economic feasibility and optimisation of an energy storage system for Portland Wind Farm (Victoria,Australia)

This paper presents the details of a theoretical study of the economic advantages of using large-scale energy storage to complement a wind farm in a base-load dominated electricity grid. A computer model is developed which simulates the operation of several energy storage systems when used with the 190-MW Portland Wind Farm (PWF) located in Portland, Victoria, Australia. A variety of operating strategies are compared with the results of a dynamic programming model which finds the maximum possible revenue which a given system can generate for a set of input conditions. Three energy storage systems are modelled and costed: Pumped Seawater Hydro Storage (PSHS), Compressed Air Energy Storage (CAES), and Thermal Energy Storage (TES). It is found that CAES is the most profitable storage medium, requiring a capital expenditure of A$140 M and generating a rate of return (ROR) of 15.4%. The ROR for PSHS was 9.6%, and for TES was 8.0%. Therefore, a significant investment opportunity exists for the installation of an energy storage system in this wind farm. It is therefore highly recommended that CAES is investigated further with the aim of introducing large-scale energy storage to PWF and other similar wind turbine installations.