A reduced-form approach for representing the impacts of wind and solar PV deployment on the structure and operation of the electricity system

In many climate change mitigation scenarios, integrated assessment models of the energy and climate systems rely heavily on renewable energy technologies with variable and uncertain generation, such as wind and solar PV, to achieve substantial decarbonization of the electricity sector. However, these models often include very little temporal resolution and thus have difficulty in representing the integration costs that arise from mismatches between electricity supply and demand. The global integrated assessment model, MESSAGE, has been updated to explicitly model the trade-offs between variable renewable energy (VRE) deployment and its impacts on the electricity system, including the implications for electricity curtailment, backup capacity, and system flexibility. These impacts have been parameterized using a reduced-form approach, which allows VRE integration impacts to be quantified on a regional basis. In addition, thermoelectric technologies were updated to include two modes of operation, baseload and flexible, to better account for the cost, efficiency, and availability penalties associated with flexible operation. In this paper, the modeling approach used in MESSAGE is explained and the implications for VRE deployment in mitigation scenarios are assessed. Three important stylized facts associated with integrating high VRE shares are successfully reproduced by our modeling approach: (1) the significant reduction in the utilization of non-VRE power plants; (2) the diminishing role for traditional baseload generators, such as nuclear and coal, and the transition to more flexible technologies; and (3) the importance of electricity storage and hydrogen electrolysis in facilitating the deployment of VRE.     

Application of a high-detail energy system model to derive power sector characteristics at high wind and solar shares

Solar irradiation and wind speed vary with climatic, as well as seasonal and daily weather conditions. In order to represent these variable renewable energy (VRE) resources in specialized energy system models, high temporal and spatial resolution information on their availability is used. In contrast, integrated assessment models (IAM), typically characterized by long-term time scales and low temporal and spatial resolution, require aggregated information on VRE availability and balancing requirements at various levels of VRE penetration and mix. Parametric studies that provide such information typically regard solar energy synonymously with photovoltaic power generation. However, solar energy can also be harvested with concentrating solar power (CSP) plants, which can be dispatchable if equipped with thermal storage. Accounting for this dispatchable use of the variable solar resource can change the balancing requirements at any solar energy penetration level. In this paper, we present an application of the high-resolution energy system model REMix to a set of European supply scenarios with theoretical VRE shares ranging from 0% to 140%, three solar-to-wind ratios, with CSP included in the solar share. We evaluate balancing measures, curtailments and costs and compare the findings to previous results in which CSP is regarded a backup option among other dispatchable power plants. The results show that CSP potentials in Europe are widely exploited in most scenarios. System costs are found to be lowest for wind-dominated systems or balanced mixes of wind and solar and for an overall VRE share between 40% for a low and 80% for a high scenario of the future CO₂ emission certificate price. The comparison with previous results shows that storage capacity is the only system variable that is significantly affected by allocating CSP to the VRE resources category. It is reduced by 24% on average across all VRE shares and proportions and by around 80% at most.     

The impacts on climate mitigation costs of considering curtailment and storage of variable renewable energy in a general equilibrium model

The curtailment and storage associated with the fluctuation of electricity supplied by variable renewable energy (VRE) may limit its penetration into electricity systems. Therefore, these factors need to be explicitly treated in the integrated assessment models (IAMs). This study improves the representation of curtailment and storage of VRE in a computable general equilibrium (CGE) model. With the data generated from an hourly power sector model, curtailment and storage of VRE electricity are treated as a function of the shares of solar and wind in the electricity mix. This relationship is incorporated into a CGE model and we also updated the VRE costs and resource potential. The results show that with such improvement, by 2100, in a 450 ppm atmospheric CO₂ equivalent concentration (henceforth ppm) scenario, some electricity generated from VRE is either curtailed (2.1%) or needs to be stored (2.9%). In contrast, if VRE fluctuation is not considered, the long-term global economic cost of carbon mitigation is significantly underestimated (by 52%) in the same scenario. Conversely, updating the VRE costs and resource potential leads to a decrease in mitigation costs. Our simulation implies that the fluctuation of VRE cannot be ignored and needs to be incorporated into CGE models. Moreover, in addition to storage with batteries, many other options are available to reduce curtailment of VRE. The top-down type CGE model has limitations to fully incorporate all aspects due to its limited spatial, temporal, and technological resolution.     

System integration of wind and solar power in integrated assessment models: A cross-model evaluation of new approaches

Mitigation-Process Integrated Assessment Models (MP-IAMs) are used to analyze long-term transformation pathways of the energy system required to achieve stringent climate change mitigation targets. Due to their substantial temporal and spatial aggregation, IAMs cannot explicitly represent all detailed challenges of integrating the variable renewable energies (VRE) wind and solar in power systems, but rather rely on parameterized modeling approaches. In the ADVANCE project, six international modeling teams have developed new approaches to improve the representation of power sector dynamics and VRE integration in IAMs.In this study, we qualitatively and quantitatively evaluate the last years' modeling progress and study the impact of VRE integration modeling on VRE deployment in IAM scenarios. For a comprehensive and transparent qualitative evaluation, we first develop a framework of 18 features of power sector dynamics and VRE integration. We then apply this framework to the newly-developed modeling approaches to derive a detailed map of strengths and limitations of the different approaches. For the quantitative evaluation, we compare the IAMs to the detailed hourly-resolution power sector model REMIX. We find that the new modeling approaches manage to represent a large number of features of the power sector, and the numerical results are in reasonable agreement with those derived from the detailed power sector model. Updating the power sector representation and the cost and resources of wind and solar substantially increased wind and solar shares across models: Under a carbon price of 30$/tCO₂ in 2020 (increasing by 5% per year), the model-average cost-minimizing VRE share over the period 2050–2100 is 62% of electricity generation, 24%-points higher than with the old model version.     

Economic evaluation of the dual mode CAES solution for increased wind energy contribution in autonomous island networks

Wind parks operating in autonomous island grids, such as those encountered in the Aegean Archipelago, face considerable wind energy curtailments, owed to the inability of local electricity networks to absorb the entire wind energy production. On the other hand, plans promoting the natural gas-based electricity generation in big islands (such as Crete) question the future of wind energy. To recover wind energy curtailments and benefit from the introduction of natural gas, the adoption of compressed air energy storage (CAES) systems suggests an appreciable energy solution. Furthermore, to improve the economic performance of the proposed system, it is decided that guaranteed energy amounts should be delivered to the local grid during peak demand periods. In an effort to obtain favourable negotiation conditions – for the selling price of energy delivered – and also improve the economic performance of the system, a dual mode CAES operation is currently examined. Proceeding to the economic evaluation of dual mode CAES configurations that ensure maximum wind energy recovery, the feasibility of the proposed system may be validated. Lower electricity production costs and considerable reduction of fuel consumption achieved – in comparison with the requirements of conventional peak demand power units – illustrate the system's advantages.     

Fluctuating renewables in a long-term climate change mitigation strategy

Integrated Assessment models, widely applied in climate change mitigation research, show that renewable energy sources (RES) play an important role in the decarbonization of the electricity sector. However, the representation of relevant technologies in those models is highly stylized, thereby omitting important information about the variability of electricity demand and renewables supply. We present a power system model combining long time scales of climate change mitigation and power system investments with short-term fluctuations of RES. Investigating the influence of increasingly high temporal resolution on the optimal technology mix yields two major findings: the amount of flexible natural gas technologies for electricity generation rises while the share of wind energy only depends on climate policy constraints. Furthermore, overall power system costs increase as temporal resolution is refined in the model, while mitigation costs remain unaffected.     

Decarbonizing global power supply under region-specific consideration of challenges and options of integrating variable renewables in the REMIND model

We present two advances in representing variable renewables (VRE) in global energy-economy-climate models: accounting for region-specific integration challenges for eight world regions and considering short-term storage. Both advances refine the approach of implementing residual load duration curves (RLDCs) to capture integration challenges. In this paper we derive RLDCs for eight world regions (based on region-specific time series for load, wind and solar) and implement them into the REMIND model. Therein we parameterize the impact of short-term storage using the highly-resolved model DIMES. All RLDCs and the underlying region-specific VRE time series are made available to the research community. We find that the more accurate accounting of integration challenges in REMIND does not reduce the prominent role of wind and solar in scenarios that cost-efficiently achieve the 2 °C target. Until 2030, VRE shares increase to about 15–40% in most regions with limited deployment of short-term storage capacities (below 2% of peak load). The REMIND model's default assumption of large-scale transmission grid expansion allows smoothening variability such that VRE capacity credits are moderate and curtailment is low. In the long run, VRE become the backbone of electricity supply and provide more than 70% of global electricity demand from 2070 on. Integration options ease this transformation: storage on diurnal and seasonal scales (via flow batteries and hydrogen electrolysis) and a shift in the non-VRE capacity mix from baseload towards more peaking power plants. The refined RLDC approach allows for a more accurate consideration of system-level impacts of VRE, and hence more robust insights on the nature of power sector decarbonization and related economic impacts.     

The value of energy storage in optimal non-firm wind capacity connection to power systems

Wind is a variable and uncontrollable source of power with a low capacity factor. Using energy storage facilities with a non-firm connection strategy is the key to maximum integration of distant wind farms into a transmission-constrained power system. In this paper, we explore the application of energy storage in optimal allocation of wind capacity to a power system from distant wind sites. Energy storage decreases transmission connection requirements, smoothes the wind farm output and decreases the wind energy curtailments in a non-firm wind capacity allocation strategy. Specifically, we examine the use of compressed air energy storage (CAES) technology to supplement wind farms and downsize the transmission connection requirements. Benders decomposition approach is applied to decompose this computationally challenging and large-scale mixed-integer linear programming (MILP) into smaller problems. The simulation results show that using energy storage systems can decrease the variation of wind farms output as well as the total cost, including investment and operation costs, and increase the wind energy penetration into the power system.     

Assessment of hydrogen as a potential energy storage for urban areas’ PV-assisted energy systems - Case study

The world is experiencing unprecedented development in the clean energy sector in residential and industrial applications. This paper provides a case study assessing different scenarios of greenizing the electrical energy demand in El-Mostakbal city in Egypt. Three scenarios are studied with consideration of a photovoltaic (PV) system integrated with the grid-connected city with different integrated system configurations. The scenarios for the grid-connected city are scenario-I: only PV, scenario-II: PV with batteries for electricity storage along with grid electricity, and scenario-III: PV with hydrogen production, storage, and utilization for covering the electric demand along with grid electricity, these scenarios are assessed technoeconomically, and the results show an optimized case where the electricity demand of the city can be met with 64.3% produced from solar energy, at $71.7 M of the net present cost.     

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.     

Integration of large-scale hydrogen storages in a low-carbon electricity generation system

This study investigates the overall feasibility of large energy storages with hydrogen as energy carrier onsite with a pre-combustion carbon capture and storage coal gasification plant and assesses the general impacts of such a backup installation on an electricity generation system with high wind power portion. The developed system plant configuration consists of four main units namely the gasification unit, main power unit, backup power unit including hydrogen storage and ancillary power unit. Findings show that integrating a backup storage in solid or gaseous hydrogen storage configuration allows to store excessive energy under high renewable power output or low demand and to make use of the stored energy to compensate low renewable output or high power demand. The study concludes that the developed system configuration reaches much higher load factors and efficiency levels than a plant configuration without backup storage, which simply increases its power unit capacity to meet the electricity demand. Also from an economical point of view, the suggested system configurations are capable to achieve lower electricity generation costs.     

Comparative transient simulation of a renewable energy system with hydrogen and battery energy storage for residential applications

Energy systems for the building sector nowadays are moving towards using renewable energy sources such as solar and wind power. However, it is nearly impossible to fully develop a multi-generation energy system for a building only relying on these sources without convenient energy storage, backup systems, or connection to the grid. In this work, using TRNSYS software, a model was developed to study the transient behavior of an energy system applicable for residential buildings to supply the heating, cooling, domestic hot water, and electricity in demand. This study contains the comparison of two methods of energy storage, a hydrogen fuel cell/electrolyzer package and a conventional battery system. This study also provides information on environmental impacts and economical aspects of the proposed system. The results show that for an HVAC system when using hydrogen storage system the capital cost is twice the cost of using a battery system. However, the hydrogen system shows better performance when used at higher loads. Hydrogen storage systems show higher performance when used at higher size units.     

Large-scale hydrogen energy storage in salt caverns

Large-scale energy storage methods can be used to meet energy demand fluctuations and to integrate electricity generation from intermittent renewable wind and solar energy farms into power grids. Pumped hydropower energy storage method is significantly used for grid electricity storage requirements. Alternatives are underground storage of compressed air and hydrogen gas in suitable geological formations. Underground storage of natural gas is widely used to meet both base and peak load demands of gas grids. Salt caverns for natural gas storage can also be suitable for underground compressed hydrogen gas energy storage. In this paper, large quantities underground gas storage methods and design aspects of salt caverns are investigated. A pre-evaluation is made for a salt cavern gas storage field in Turkey. It is concluded that a system of solar-hydrogen and natural gas can be utilised to meet future large-scale energy storage requirements.     

Achieving California's 80% greenhouse gas reduction target in 2050: Technology,policy and scenario analysis using CA-TIMES energy economic systems model

The CA-TIMES optimization model of the California Energy System (v1.5) is used to understand how California can meet the 2050 targets for greenhouse gas (GHG) emissions (80% below 1990 levels). This model represents energy supply and demand sectors in California and simulates the technology and resource requirements needed to meet projected energy service demands. The model includes assumptions on policy constraints, as well as technology and resource costs and availability. Multiple scenarios are developed to analyze the changes and investments in low-carbon electricity generation, alternative fuels and advanced vehicles in transportation, resource utilization, and efficiency improvements across many sectors. Results show that major energy transformations are needed but that achieving the 80% reduction goal for California is possible at reasonable average carbon reduction cost ($9 to $124/tonne CO₂e at 4% discount rate) relative to a baseline scenario. Availability of low-carbon resources such as nuclear power, carbon capture and sequestration (CCS), biofuels, wind and solar generation, and demand reduction all serve to lower the mitigation costs, but CCS is a key technology for achieving the lowest mitigation costs.     

Design of hybrid power-to-power systems for continuous clean PV-based energy supply

The increasing penetration of intermittent renewable sources, fostering power sector decarbonization, calls for the adoption of energy storage systems as an essential mean to improve local electricity exploitation, reducing the impact of distributed power generation on the electric grid. This work compares the use of hydrogen-based Power-to-Power systems, battery systems and hybrid hydrogen-battery systems to supply a constant 1 MW_el load with electricity locally generated by a photovoltaic plant. A techno-economic optimization model is set up that optimizes the size and annual operation of the system components (photovoltaic field, electrolyzer, hydrogen storage tanks, fuel cell and batteries) with the objective of minimizing the annual average cost of electricity, while guaranteeing an imposed share of local renewable self-generation. Results show that, with the present values of investment costs and grid electricity prices, the installation of an energy storage system is not economically attractive by itself, whereas the installation of PV panels is beneficial in terms of costs, so that the baseline optimal solution consists of a 4.2 MW_p solar field capable to self-generate 33% of the load annually. For imposed shares of self-generation above 40%, decoupling generation and consumption becomes necessary. The use of batteries is slightly less expensive than the use of hydrogen storage systems up to a 92% self-generation rate. Above this threshold, seasonal storage becomes predominant and hybrid storage becomes cheaper than batteries. The sale of excess electricity is always important to support the plant economics, and a sale price reduction sensibly impacts the results. Hydrogen storage becomes more competitive when the need for medium and long terms energy shift increases, e.g. in case of having a cap on the available PV capacity.     

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     

Overview of energy storage systems for storing electricity from renewable energy sources in Saudi Arabia

Renewable power (photovoltaic, solar thermal or wind) is inherently intermittent and fluctuating. If renewable power has to become a major source of base-load dispatchable power, electricity storage systems of multi-MW capacity and multi-hours duration are indispensable. An overview of the advanced energy storage systems to store electrical energy generated by renewable energy sources is presented along with climatic conditions and supply demand situation of power in Saudi Arabia. Based on the review, battery features needed for the storage of electricity generated from renewable energy sources are: low cost, high efficiency, long cycle life, mature technology, withstand high ambient temperatures, large power and energy capacities and environmentally benign. Although there are various commercially available electrical energy storage systems (EESS), no single storage system meets all the requirements for an ideal EESS. Each EESS has a suitable application range.     

Techno-economic optimization of wind energy based hydrogen refueling station case study Salalah city Oman

Clean energy resources will be used more for sustainability improvement and durable development. Efficient technologies of energy production, storage, and usage results in reduction of gas emissions and improvement of the world economy. Despite 30% of electricity being produced from wind energy, the connection of wind farms to medium and large-scale grid power systems is still leading to instability and intermittency problems. Therefore, the conversion of electrical energy generated from wind parks into green hydrogen consists of an exciting solution for advancing the development of green hydrogen production, and the clean transportation sector. This paper presents a techno-economic optimization of hydrogen production for refueling fuel cell vehicles, using wind energy resources. The paper analyses three configurations, standalone Wind-Park Hydrogen Refueling Station (WP-HRS) with backup batteries, WP-HRS with backup fuel cells, and grid-connected WP-HRS. The analysis of different configurations is based on the wind potential at the site, costs of different equipment, and hydrogen load. Therefore, the study aims to find the optimized capacity of wind turbines, electrolyzers, power converters, and storage tanks. The optimization results show that the WP-HRS connected to the grid has the lowest Present Worth Cost (PWC) of 6,500,000 €. Moreover, the Levelized Hydrogen Cost (LHC) of this solution was found to be 6.24 €/kg. This renewable energy system produces 80,000 kg of green hydrogen yearly.     

Role of hydrogen in future North European power system in 2060

The Balmorel model has been used to calculate the economic optimal energy system configuration for the Scandinavian countries and Germany in 2060 assuming a nearly 100% coverage of the energy demands in the power, heat and transport sector with renewable energy sources. Different assumptions about the future success of fuel cell technologies have been investigated as well as different electricity and heat demand assumptions. The variability of wind power production was handled by varying the hydropower production and the production on CHP plants using biomass, by power transmission, by varying the heat production in heat pumps and electric heat boilers, and by varying the production of hydrogen in electrolysis plants in combination with hydrogen storage. Investment in hydrogen storage capacity corresponded to 1.2% of annual wind power production in the scenarios without a hydrogen demand from the transport sector, and approximately 4% in the scenarios with a hydrogen demand from the transport sector. Even the scenarios without a demand for hydrogen from the transport sector saw investments in hydrogen storage due to the need for flexibility provided by the ability to store hydrogen. The storage capacities of the electricity storages provided by plug-in hybrid electric vehicles were too small to make hydrogen storage superfluous.     

Optimization and control of autonomous renewable energy systems

Recently, there has been a growing interest in harnessing renewable energy resources particularly for electricity generation. One of the main concerns in the design of an electric power system that utilizes renewable energy sources, is the accurate selection of system components that can economically satisfy the load demand. This depends on the load that ought to be met, the capacity of renewable resources, the available space for wind machines and solar panels, and the capital and running costs of system components. Once size optimization is achieved, the autonomous system must be controlled in order to correcly match load requirements with instantaneous variation of input energy. In this paper, a new formulation for optimizing the design of an autonomous wind-solar-diesel-battery energy system is developed. This formultation employs linear programming techniques to minimize the average production cost of electricity while meeting the load requirements in a reliable manner. The computer program developed reads the necessary input data, formulates the optimization problem by computing the coefficients of the objective function and the constraints and provides the optimum wind, solar, diesel, and battery ratings. In order to study the effect of parameters predefined by the designer on the optimum design, several sensitivity analysis studies are performed, and the effects of the expected energy not served, the load level, the maximum available wind area, the maximum available solar area, and the diesel engines' lifetime are investigated. A controller the monitors the operation of the autonomous system is designed. The operation of this controller is based on three major policies; in the first, batteries operate before diesel engines and hence the storage system acts as a fuel saver, while in the second diesel engines are operated first so that the unmet energy is lower but the fuel cost is high. According to the third policy, the supply is made through diesel engines only. This is done for the purpose of making a performance comparison between the isolated diesel system and the hybrid renewable energy system. The proposed optimization and control techniques are tested on Lebanese data. Although three different control policies have been adopted in this work, the software is able to accommodate other policies.