Pumped Hydro Energy Storage Research Articles

Revisiting the potential of pumped-hydro energy storage: A method to detect economically attractive sites

This study innovatively combines a set of methods to assess the economic potential of pumped hydro energy storage. It first provides a method based on geographic information systems to study the potential of pumped-hydro for different topologies. Second, using cost estimates for each identified site, cost-potential curves are derived. Finally, these curves are used for planning a fully renewable system to assess their impact on investment recommendations. Applications to Chile, Peru, and Bolivia show the usability of the methods. Over 450 pumped-hydro locations are identified, totaling around 20 TWh (or 1600 GW of installed capacity with 12 h of storage). These numbers exceed by 20-fold the projected daily energy demand of the corresponding countries. When taking into account investment costs, most locations are cheaper than current Li-ion batteries, but only some are expected to remain competitive in the future. When using the resulting cost-potential curves to design a future energy system, the planning tool recommends about 1.6 and 5.0 times more pumped-hydro storage compared to using average values and literature values, respectively. These differences underline the significance of the found cost curves.

Indonesia’s Vast Solar Energy Potential

In this paper, we conclude that Indonesia has vast potential for generating and balancing solar photovoltaic (PV) energy to meet future energy needs at a competitive cost. We systematically analyse renewable energy potential in Indonesia. Solar PV is identified to be an energy source whose technical, environmental and economic potential far exceeds Indonesia’s present and future energy requirements and is far larger than all other renewable energy resources combined. We estimate that electricity consumption in Indonesia could reach 9000 terawatt-hours per year by 2050, which is 30 times larger than at present. Indonesia has abundant space to deploy enough solar to meet this requirement, including on rooftops, inland reservoirs, mining wasteland, and in combination with agriculture. Importantly, Indonesia has a vast maritime area that almost never experiences strong winds or large waves that could host floating solar capable of generating >200,000 terawatt-hours per year. Indonesia also has far more off-river pumped hydro energy storage potential than required for balancing solar generation.

Conceptual modeling of energy storage systems

AbstractConceptual models are explicit representations of complex systems that help people understand and communicate the system and its behavior in its actual context. The stable energy systems that we rely on in our daily life require a balance between energy production and consumption. Energy systems, particularly those that include renewable energy sources, have inherent dynamic behavior due to the intermittence of energy sources such as solar and wind. We use conceptual models to understand this behavior.The transition towards a carbon neutral energy system requires energy storage to ensure a supply of renewable energy when needed. The sizing strategy for energy storage systems is challenging because both the supply side and the demand side varies with time. In this paper, we investigate how energy storage technologies can provide seasonal storage for an existing energy system with excess electric power production during the summer months. We use conceptual models to review pumped hydro energy storage, hydrogen storage, and brine technology.The conceptual models simplify the selection process and help in choosing the most suitable energy storage solution from technical and economic criteria. The conceptual models are effective in communicating the constraints and opportunities of the system. However, we find it difficult to balance between comprehension that requires simplification, and accuracy that requires details.

Life-cycle assessment of gravity energy storage systems for large-scale application

Interest in energy storage systems has been increased with the growing penetration of variable renewable energy sources. This paper discusses a detailed economic analysis of an attractive gravitational potential energy storage option, known as gravity energy storage (GES). The economic performance of this energy storage system is compared to other alternative energy storage technologies such as pumped hydro energy storage (PHES) and compressed air energy storage (CAES). Moreover, a life cycle costs and levelized cost of electricity delivered by this energy storage are analyzed to provide expert, power producers, and grid operators insight about the economic implications of this grid-scale gravitational energy storage technology. Depending on the considered scenarios and assumptions, the levelized cost of storage of GES varies between 7.5 €ct/kWh and 15 €ct/kWh, while it is between 3.8 €ct/kWh and 7.3 €ct/kWh for gravity energy storage with wire hoisting system (GESH). The LCOS of GES and GESH were then compared to other energy storage systems. The obtained results show that GESH is very cost-competitive with pumped hydro and Compressed Air Energy Storage technologies; while GES is competitive with PHES and may be cost-competitive with CAES depending on the operation cycles. The performed analysis has also shown that both GES and GESH offer interesting economic advantages for the provision of energy arbitrage service.

Path selection for wind power in China: Hydrogen production or underground pumped hydro energy storage?

Hydrogen production from wind power and energy storage from wind power are considered as effective measures to overcome the problem associated with wind curtailment. However, their further development is clearly constrained by the incurred costs. Hydrogen production from offshore wind power (HPFW), hydrogen production from onshore wind power (HPNW), and underground pumped hydro energy storage from wind power (UPHESW) are considered in this paper. This paper employs a life cycle cost analysis to calculate and compare the levelized costs of hydrogen production and energy storage in China. A sensitivity analysis is conducted to evaluate the influences of different factors on levelized costs. The results show that the levelized cost of HPFW is 1.44 times that of HPNW. The levelized cost of UPHESW is lower than that of traditional pumped hydro energy storage with the same installed capacity and also lower than that of UPHESW with the smaller installed capacity. The economic competitiveness between UPHESW and HPNW depends on the installed capacity of UPHESW. If it exceeds 453 MW, UPHESW is more economical. If it remains below 453 MW, HPNW is more economical.

Spatial Analysis of Pumped Hydro Energy Storage Integration with Wind Farms in Nova Scotia

Renewable energy systems have been implemented globally to help lower carbon emissions; for example, pumped hydro energy storage (PHES) is a system that helps mitigate peak loads on electrical grids to reduce dependency on fossil fuel energy generation. As a form of energy storage, PHES involves using two water reservoirs at different elevations to generate electricity at times of peak demand. Integrating PHES near wind farms allows the required water-pumping electricity to be supplied by wind power, rather than fossil fuels. A spatial analysis was done using ArcGIS Pro to determine the most ideal sites for PHES within close proximity to wind farms in Nova Scotia. Five potential sites were identified, and map layouts were produced showing conceptual models of PHES at these locations throughout the province. Due to the topography of Nova Scotia, development of PHES is not feasible at many potential sites. Five suitable sites were ranked based on environmental and technoeconomic costs; the Barrachois Wind PHES hybrid project was ranked the highest, followed by the Digby, Ellershouse, Maryvale, and South Canoe wind energy sites. The study concluded that integrating PHES into wind farms in Nova Scotia would be a useful method for boosting electrical grid stability, and attaining emissions reductions targets throughout the province.

Techno-economic benefits deriving from optimal scheduling of a Virtual Power Plant: Pumped hydro combined with wind farms

Wind and solar are renewable sources characterized by a great potential but a variable and unpredictable nature. Characteristics that provoke mismatch between power supply and demand which in turns are the source of network control issues. Problems manageable with the installation of large-scale energy storage like Pumped Hydro Energy Storage (PHES). To this purpose, the paper presents a techno-economic analysis for assessing the benefits deriving from the hybridization of a seawater PHES (sPHES) plant with an in-operation wind farm. Plants work as a Virtual Power Plant (VPP) instead of two separate unit. The hybridization aims to avoid the unbalances of the wind farm, having negative impact on both the grid and the wind farm owner itself. The unbalances cause unpredictable deviations from the predicted production and, hence, power production fluctuations faced by the grid with curtailments and/or calls in operation of fossil-fuelled power plants. A VPP techno-economic optimization on a daily bases is performed using the ASD-PSO algorithm while the optimization aim is the revenue maximization. Results show that a VPP composed by a sPHES and a wind farm and with a single owner, is able to manage the wind farm production, improving the revenue of 6.8% compared to plants acting separately on the market. The VPP approach is also convenient in the case of a joint venture between the plants owners. But, in this case, the revenue is increased only of 0.4% compared to plants working separately. Finally, results also highlight that, in the Italian electricity market, a sPHES plant alone is not able to generate sufficient revenue to guarantee a reasonable payback time while coupling it with a wind farm increases incomes and working days and avoid cost and grid issues in managing the unpredictable wind farm production.

Comparison of underwater with conventional pumped hydro-energy storage systems

The laws of fluid mechanics imply that modular offshore pumped hydro-energy storage systems like StEnSEA have no advantage over similar but much cheaper modular onshore systems.

Sizing and Cost Minimization of Standalone Hybrid WT/PV/Biomass/Pump-Hydro Storage-Based Energy Systems

In this study, a standalone hybrid wind turbine (WT)/photovoltaic (PV)/biomass/pump-hydro-storage energy system was designed and optimized based on technical, economic, and environmental parameters to provide the load demand with an objective function of minimum cost of energy (COE). The constraints of the proposed approach are the loss of power supply probability, and the excess energy fraction. The proposed approach allows the combination of different sources of energy to provide the best configuration of the hybrid system. Therefore, the proposed system was optimized and compared with a WT/PV/biomass/battery storage-based hybrid energy system. This study proposes three different optimization algorithms for sizing and minimizing the COE, including the whale optimization algorithm (WOA), firefly algorithm (FF) and particle swarm optimization (PSO) and the optimization procedure was executed using MATLAB software. The outcomes of these algorithms are contrasted to select the most effective, and the one providing the minimum COE is chosen based on statistical analysis. The results indicate that the proposed hybrid WT/PV/biomass/pump-hydro storage energy system is environmentally and economically practical. Meanwhile, the outcomes demonstrated the technical feasibility of a pump-hydro energy storage system in expanding the penetration of renewable energy sources compared to other existing systems. The COE of the pumped-hydro storage hybrid system was found to be lower (0.215 $/kWh) than that with batteries storage hybrid system (0.254 $/kWh) which was determined using WOA at the same load demand.

Low carbon policy and market mechanisms to enable carbon capture and storage and decarbonisation in Australia

The scale of decarbonisation required to meet global emission reduction targets necessitates every abatement technology available be adequately explored. Carbon capture and storage (CCS) allows decarbonisation for sectors that are otherwise technically difficult and expensive to transition. This analysis used a levelised cost of electricity (LCOE) approach to identify optimal market-based mechanisms that would provide necessary funding support for CCS deployment. The results of that analysis were presented to energy policy stakeholders to determine their amenability. Four mechanisms were investigated; capital subsidies, regulated requirements for increased grid services from all generators, a partial capacity and inertia market with emission constraints and a clean energy certificate scheme. As a means for encouraging CCS, subsidies were favoured by stakeholders. The financial analysis suggested this policy could assist CCS, although was not the optimal choice due to its potential market distortion. A carbon-constrained capacity and inertia market was the preferred pathway for the deployment of CCS technologies from an investment viewpoint. This market model encourages a range of other low-emission technologies, including large-scale batteries and pumped-hydro energy storage. Further modelling is required to determine the overall system and abatement costs involved in the implementation of a partial carbon-constrained capacity market.

Performance analysis of a Brayton Pumped Thermal Electricity Storage (PTES) with a liquid sensible heat storage

A pervasive Renewable Energy Source (RES) exploitation poses a wide range of issues to electric grids, which the enhancement of the electric grid flexibility may mitigate. There are several approaches to improve grid flexibility, and a significant help will come from efficient, reliable, durable and cheap electric storage technologies. Inevitably, different storage technologies will be needed since different power and energy spectra characterise RES issues. In the category of high capacity-to-power ratio technologies, Pumped Thermal Electricity Storage (PTES) is becoming more and more popular. Such technology aims at replacing Pumped Hydro Energy Storage (PHES), and it is suited for daily cyclic operation (load shifting). In this paper, a Brayton PTES with liquid sensible heat storages is studied. Compared to the standard system equipped with packed beds, the liquid heat storage allows for a more straightforward state of charge estimation, control and, potentially, for a better usage of storage volume. Through a parametric analysis involving the main design specifications, the system performance is assessed under realistic assumptions. The resulting figures provide an exhaustive characterisation of the performance achievable by the system, which may be useful for a fair comparison between PTES and other competing storage technologies.

Policy roadmap to net zero: the role of gas in decarbonising the National Energy Market

As the National Energy Market (NEM) changes to a more diverse grid with emissions reduction targets, the way we value technologies must also change (Boston et al. 2017). This change in value is fundamental as the future low emissions grid will require careful planning and implementation to guarantee the lowest total system cost is maintained, particularly as a net zero grid will be drastically larger than the current system. This planning must include system strength. The Australian Energy Market Operator Integrated System Plan states that the current market mechanisms cannot facilitate achieving a low emissions grid (Australian Energy Market Operator (AEMO) 2020a). Policy and market mechanisms will need to be designed for this changing system. If net zero is to be met, Modelling of Energy and Grid Services by Red Vector and Gamma Energy technology has shown that this future grid needs to contain: approximately 100GW of variable renewable energy; almost 20GW of firm, low emissions generation, such as gas or coal with carbon capture and storage (CCS), bioenergy with CCS and hydroelectric power. If CCS is not available, nuclear power will be required; more than 10GW of storage, including pumped hydro energy storage and other energy storage technologies and over 30GW of firm, dispatchable peaking plant, including coal- and gas-fired power generation. This study sets out the role for gas in a policy road map to net zero for the NEM, harnessing and reforming existing policies, as well as introducing new mechanisms to achieve net zero emissions while retaining a reliable grid at the lowest total system cost.

Stability and Efficiency Performance of Pumped Hydro Energy Storage System for Higher Flexibility

Stability and Efficiency Performance of Pumped Hydro Energy Storage System for Higher Flexibility

Global Atlas of Closed-Loop Pumped Hydro Energy Storage

<h2>Summary</h2> The difficulty of finding suitable sites for dams on rivers, including the associated environmental challenges, has caused many analysts to assume that pumped hydro energy storage has limited further opportunities to support variable renewable generation. Closed-loop, off-river pumped hydro energy storage overcomes many of the barriers. Small (square km) upper reservoirs are typically located in hilly country away from rivers, and water is circulated indefinitely between an upper and lower reservoir. GIS analysis of high resolution global digital elevation models was used to determine economically feasible closed-loop scheme locations outside protected and urban areas. This search identified 616,000 potential storage sites with an enormous combined storage potential of 23,000 TWh. This is two orders of magnitude more than required to support large fractions of renewable electricity, allowing flexible site selection. Importantly, the resource is widely distributed to effectively support large-scale solar and wind deployment for electrical grid decarbonization.

Analysis of Cost-Optimal Renewable Energy Expansion for the Near-Term Jordanian Electricity System

Jordan is affected by an ever changing environment in the midst of climate change, political challenges, a fast growing economy and socio-economic pressures. Among other countries in the Middle East and Northern Africa, Jordan is facing a number of electricity related challenges, such as a rising energy demand, high dependency on fossil fuel imports and management of local, fossil and renewable resources. The paper presents an analysis based on an open source optimisation modelling approach identifying a cost-optimal extension of the Jordanian electricity system with growing demand projections until 2030 utilising pumped hydro energy storage and determining the costs of different CO2 mitigation pathways. The results highlight the large potential of renewable energy for the cost effective, environmentally friendly and energy independent development of the Jordanian electricity sector. A share of up to 50% renewable energy can be achieved with only a minor increase in levelised cost of electricity from 54.42 to 57.04 $/MWh. In particular, a combination of photovoltaic and pumped hydro storage proved to be a superior solution compared to the expansion of existing shale oil deployments due to high costs and CO2 emissions. Aiming for a more than 50% renewable energy share within the electricity mix calls for substantial wind energy deployments. In a system with a renewable energy share of 90%, wind energy covers 45% of the demand.

Development and assessment of geothermal‐based underground pumped hydroenergy storage system integrated with organic Rankine cycle and district heating

This study develops a geothermal-based underground pumped hydroenergy storage system (UPHES) integrated with an organic Rankine cycle (ORC) and district heating. The ORC has been integrated into the system for contributing the power demand of the pump used during the charging period to pump the water from the underground to the upper reservoir. District heating has been performed by geothermal. Heat recovered from the ORC has been used for the preheating of water used in district heating before entering the upper reservoir. With this proposed integrated system, both the peak energy demand has been shifted to off-peak hours and district heating has been performed. An ORC has also been included in the system to contribute to the energy demand of the UPHES pump. In order to evaluate the system's performance, thermodynamic analysis has been performed base on energetic and exergetic efficiencies. In the base case study, 60 MWh of electricity has stored by the UPHES. Also, a 2.8 MW of heating demand of 100 houses has been met and a 1.7 MW of power has been generated by the ORC. The power of the UPHES pump has been calculated as 6.81 MW. The efficiency of the UPHES system is 73.34%. Overall energy and exergy efficiencies of the proposed integrated system have been calculated as 93.09% and 78.37%, respectively.

Mitigating Curtailment and Carbon Emissions through Load Migration between Data Centers

Summary As the share of variable renewable energy (VRE) grows in the electric grid, so does the risk of curtailment. While energy storage and hydrogen production have been proposed as solutions to the curtailment problem, they often pose technological and economic challenges. Here, we analyze the potential of data center load migration for mitigating curtailment and greenhouse gas (GHG) emissions. Using historical hourly electricity generation, curtailment, and typical data center server utilization data, we simulate the effect of migrating data center workloads from the fossil-fuel-heavy PJM to the renewable-heavy CAISO. The results show that load migration within the existing data center capacity during the curtailment hours in CAISO has the potential to reduce 113–239 KtCO2e per year of GHG emissions and absorb up to 62% of the total curtailment with negative abatement costs in 2019. Our study demonstrates the overlooked role that data centers can play for VRE integration and GHG emissions mitigation.

A review on energy storage and demand side management solutions in smart energy islands

European Union has definitely identified the priorities towards sustainable and low-carbon energy systems recognizing a key role to islands that have been described as ideal sites to develop and test innovative strategies and solutions that will then boost the transition on the mainland. Nevertheless, the integration of Variable Renewable Energy Sources (vRES) into the electricity grid are already causing technical problems to island grids thus making grid flexibility a key topic. In the past, since power plants were completely manageable while the load was unpredictable, the grid flexibility was supplied by traditional power plants; but now, due to vRES, the variability and unpredictability has moved to the generation side and the opposite shift has happened to flexibility agents. This paper deals with solutions that improve the ability of the grid to cope with vRES unpredictability such as energy storage technologies and all the solutions offered by sector coupling strategies. Particularly, this research focus on solutions that deals with such solutions in the insular contexts. Several solutions have been presented concluding that battery energy systems and pumped hydro energy storage are the most used technologies in islands. As regard sector coupling and Demand Side Management solutions, all the analysed solutions showed relevant results in terms of i) reduction of excess electricity production and ii) increased grid ability of hosting vRES. Nevertheless, some of the current gaps in literature have been pinpointed and future research challenge and opportunities have been suggested.

Parameter analysis and performance optimization for the vertical pipe intake-outlet of a pumped hydro energy storage station

Abstract The vertical pipe intake-outlet plays an important role in the pumped hydro energy storage (PHES), and its main parameters included the orifice height ratio (H∗), the diffuser short semi-axis ratio (a∗), the diffuser long semi-axis ratio (b∗) and the cover plate radius ratio (Rc∗). The aim of this study was to analyse effects of the parameters and obtain the optimal design. An integration method combining computational fluid dynamics (CFD), response surface methodology (RSM) and genetic algorithm was proposed. To evaluate grid independency, the grid converge index was introduced. Based on the validation for the baseline design (H∗ = 0.577, a∗ = 1.087, b∗ = 4.231 and Rc∗ = 1.635), a reliable CFD model was developed to obtain results of sample points. Then RSM models were constructed and assessed, and contribution and interactions of the parameters were analyzed. Finally, the optimal design (H∗ = 0.422, a∗ = 1.177, b∗ = 5.363 and Rc∗ = 2.115) was obtained. The CFD results show that the overall head loss coefficient, the inflow and the outflow velocity distribution coefficient are reduced by 4.687%, 11.765% and 38.596%, respectively. Especially, the negative velocity at the trashrack section in the pump mode is eliminated. The improvement demonstrates that the proposed method achieves significant superiority over the trial-and-error method traditionally adopted in the intake-outlet design.

Underground Pumped Storage Hydropower Case Studies in Belgium: Perspectives and Challenges

To avoid the geographical and topographical prerequisites of the conventional pumped hydro energy storage, the use of underground cavities as water reservoirs allows countries without steep topography, such as Belgium, to increase the potential of the energy storage capacity. Belgium abounds in disused mines and quarries convertible into water basins. In this article, two Belgian case studies are presented and discussed for their singularity. A slate quarry in Martelange is discussed in technical aspects proposing three operating scenarios. Moreover, a preliminary economic analysis of the underground pumped storage system and a greenhouse gas emission evaluation for the storage system’s lifetime are presented. The analysis for a 100 MW power plant estimates a total initial investment of over 12 million euros and two million of CO2 avoided over its lifetime. This article also proposes the use of the coal mine 500 m deep of Pérronnes-lez-Binche. The mine representation discussed here offers a high energy capacity, but the substantial head drop (from about 500 to 200 m) challenges the selection of the hydraulic turbomachinery. A 1D simulation computed in SIMSEN draws out the behaviour of the unusual hydraulic configuration of turbines in series.