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A diagram of the TVA pumped storage facility at Raccoon Mountain Pumped-Storage Plant in Tennessee, United States
Ludington Pumped Storage Power Plant in Michigan on Lake Michigan

Pumped-storage hydroelectricity (PSH), or pumped hydroelectric energy storage (PHES), is a type of hydroelectric energy storage used by electric power systems for load balancing. A PSH system stores energy in the form of gravitational potential energy of water, pumped from a lower elevation reservoir to a higher elevation. Low-cost surplus off-peak electric power is typically used to run the pumps. During periods of high electrical demand, the stored water is released through turbines to produce electric power.

Pumped-storage hydroelectricity allows energy from intermittent sources (such as solar, wind, and other renewables) or excess electricity from continuous base-load sources (such as coal or nuclear) to be saved for periods of higher demand.[1][2] The reservoirs used with pumped storage can be quite small, when contrasted with the lakes of conventional hydroelectric plants of similar power capacity, and generating periods are often less than half a day.

The round-trip efficiency of PSH varies between 70% and 80%. Although the losses of the pumping process make the plant a net consumer of energy overall, the system increases revenue by selling more electricity during periods of peak demand, when electricity prices are highest. If the upper lake collects significant rainfall, or is fed by a river, then the plant may be a net energy producer in the manner of a traditional hydroelectric plant.

Pumped storage is by far the largest-capacity form of grid energy storage available, and, as of 2020, accounted for around 95% of all active storage installations worldwide, with a total installed throughput capacity of over 181 GW and as of 2020 a total installed storage capacity of over 1.6 TWh.[3]

As of 2025, according to International Hydropower Association[4], worldwide PSH provides 200 GW power and 9000 GWh energy storage, while the Battery energy storage system market is catching up very fast in terms of power generation capacity. As of May 2025, China’s cumulative BESS installations are reported[5] at 106.9 GW and 240.3 GWh.

Basic principle

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Power distribution, over a day, of a pumped-storage hydroelectricity facility. Green represents power consumed in pumping. Red is power generated.
Energy from a source such as sunlight is used to lift water upward against the force of gravity, giving it potential energy. The stored potential energy is later converted to electricity that is added to the power grid, even when the original energy source is not available.

A pumped-storage hydroelectricity generally consists of two water reservoirs at different heights, connected with each other. At times of low electrical demand, excess generation capacity is used to pump water into the upper reservoir. When there is higher demand, water is released back into the lower reservoir through a turbine, generating electricity. Pumped storage plants usually use reversible turbine/generator assemblies, which can act both as a pump and as a turbine generator (usually Francis turbine designs).[6] Variable speed operation further optimizes the round trip efficiency in pumped hydro storage plants.[7][8] In micro-PSH applications, a group of pumps and Pump As Turbine (PAT) could be implemented respectively for pumping and generating phases.[9] The same pump could be used in both modes by changing rotational direction and speed:[9] the operation point in pumping usually differs from the operation point in PAT mode.

Types

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In closed-loop systems, pure pumped-storage plants store water in an upper reservoir with no natural inflows, while pump-back plants utilize a combination of pumped storage and conventional hydroelectric plants with an upper reservoir that is replenished in part by natural inflows from a stream or river. Plants that do not use pumped storage are referred to as conventional hydroelectric plants; conventional hydroelectric plants that have significant storage capacity may be able to play a similar role in the electrical grid as pumped storage if appropriately equipped.

Economic efficiency

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Taking into account conversion losses and evaporation losses from the exposed water surface, energy recovery of 70–80% or more can be achieved.[10][11][12][13][14] This technique is currently the most cost-effective means of storing large amounts of electrical energy, but capital costs and the necessity of appropriate geography are critical decision factors in selecting pumped-storage plant sites.

The relatively low energy density of pumped storage systems requires either large flows and/or large differences in height between reservoirs. The only way to store a significant amount of energy is by having a large body of water located relatively near, but as high as possible above, a second body of water. In some places this occurs naturally, in others one or both bodies of water were man-made. Projects in which both reservoirs are artificial and in which no natural inflows are involved with either reservoir are referred to as "closed loop" systems.[15]

These systems may be economical because they flatten out load variations on the power grid, permitting thermal power stations such as coal-fired plants and nuclear power plants that provide base-load electricity to continue operating at peak efficiency, while reducing the need for "peaking" power plants that use the same fuels as many base-load thermal plants, gas and oil, but have been designed for flexibility rather than maximal efficiency. Hence pumped storage systems are crucial when coordinating large groups of heterogeneous generators. Capital costs for pumped-storage plants are relatively high, although this is somewhat mitigated by their proven long service life of decades - and in some cases over a century,[16][17] which is three to five times longer than utility-scale batteries. When electricity prices become negative, pumped hydro operators may earn twice - when "buying" the electricity to pump the water to the upper reservoir at negative spot prices and again when selling the electricity at a later time when prices are high.

The upper reservoir, Llyn Stwlan, and dam of the Ffestiniog Pumped Storage Scheme in North Wales. The lower power station has four water turbines which generate 360 MW of electricity within 60 seconds of the need arising.

Along with energy management, pumped storage systems help stabilize electrical network frequency and provide reserve generation. Thermal plants are much less able to respond to sudden changes in electrical demand that potentially cause frequency and voltage instability. Pumped storage plants, like other hydroelectric plants, can respond to load changes within seconds.

The most important use for pumped storage has traditionally been to balance baseload powerplants, but they may also be used to abate the fluctuating output of intermittent energy sources. Pumped storage provides a load at times of high electricity output and low electricity demand, enabling additional system peak capacity. In certain jurisdictions, electricity prices may be close to zero or occasionally negative on occasions that there is more electrical generation available than there is load available to absorb it. Although at present this is rarely due to wind or solar power alone, increased use of such generation will increase the likelihood of those occurrences.[citation needed]

It is particularly likely that pumped storage will become especially important as a balance for very large-scale photovoltaic and wind generation.[18] Increased long-distance transmission capacity combined with significant amounts of energy storage will be a crucial part of regulating any large-scale deployment of intermittent renewable power sources.[19] The high non-firm renewable electricity penetration in some regions supplies 40% of annual output, but 60% may be reached before additional storage is necessary.[20][21][22]

Small-scale facilities

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Smaller pumped storage plants cannot achieve the same economies of scale as larger ones, but some do exist, including a recent 13 MW project in Germany. Shell Energy has proposed a 5 MW project in Washington State. Some have proposed small pumped storage plants in buildings, although these are not yet economical.[23] Also, it is difficult to fit large reservoirs into the urban landscape (and the fluctuating water level may make them unsuitable for recreational use).[23] Nevertheless, some authors defend the technological simplicity and security of water supply as important externalities.[23]

Location requirements

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The main requirement for PSH is hilly country. The global greenfield pumped hydro atlas[24] lists more than 800,000 potential sites around the world with combined storage of 86 million GWh (equivalent to the effective storage in about 2 trillion electric vehicle batteries), which is about 100 times more than needed to support 100% renewable electricity. Most are closed-loop systems away from rivers. Areas of natural beauty and new dams on rivers can be avoided because of the very large number of potential sites. Some projects utilise existing reservoirs (dubbed "bluefield") such as the 350 Gigawatt-hour Snowy 2.0 scheme[25] under construction in Australia. Some recently proposed projects propose to take advantage of "brownfield" locations such as disused mines such as the Kidston project[26] under construction in Australia.[27]

Environmental impact

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Taum Sauk Hydroelectric Power Station under construction

Water requirements for PSH are small:[28] about 1 gigalitre of initial fill water per gigawatt-hour of storage. This water is recycled uphill and back downhill between the two reservoirs for many decades, but evaporation losses (beyond what rainfall and any inflow from local waterways provide) must be replaced. Land requirements are also small: about 10 hectares per gigawatt-hour of storage,[28] which is much smaller than the land occupied by the solar and windfarms that the storage might support. Closed loop (off-river) pumped hydro storage has the smallest carbon emissions[29] per unit of storage of all candidates for large-scale energy storage.

Potential technologies

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Seawater

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Pumped storage plants can operate with seawater, although there are additional challenges compared to using fresh water, such as saltwater corrosion and barnacle growth.[30] Inaugurated in 1966, the 240 MW Rance tidal power station in France can partially work as a pumped-storage station. When high tides occur at off-peak hours, the turbines can be used to pump more seawater into the reservoir than the high tide would have naturally brought in. It is the only large-scale power plant of its kind.

In 1999, the 30 MW Yanbaru project in Okinawa was the first demonstration of seawater pumped storage. It has since been decommissioned. A 300 MW seawater-based Lanai Pumped Storage Project was considered for Lanai, Hawaii, and seawater-based projects have been proposed in Ireland.[31] A pair of proposed projects in the Atacama Desert in northern Chile would use 600 MW of photovoltaic solar (Skies of Tarapacá) together with 300 MW of pumped storage (Mirror of Tarapacá) lifting seawater 600 metres (2,000 ft) up a coastal cliff.[32][33]

Freshwater coastal reservoirs

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Freshwater from the river floods is stored in the sea area replacing seawater by constructing coastal reservoirs. The stored river water is pumped to uplands by constructing a series of embankment canals and pumped storage hydroelectric stations for the purpose of energy storage, irrigation, industrial, municipal, rejuvenation of overexploited rivers, etc. These multipurpose coastal reservoir projects offer massive pumped-storage hydroelectric potential to utilize variable and intermittent solar and wind power that are carbon-neutral, clean, and renewable energy sources.[34]

Underground reservoirs

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The use of underground reservoirs has been investigated.[35] Recent examples include the proposed Summit project in Norton, Ohio, the proposed Maysville project in Kentucky (underground limestone mine), and the Mount Hope project in New Jersey, which was to have used a former iron mine as the lower reservoir. The proposed energy storage at the Callio site in Pyhäjärvi (Finland) would utilize the deepest base metal mine in Europe, with 1,450 metres (4,760 ft) elevation difference.[36] Several new underground pumped storage projects have been proposed. Cost-per-kilowatt estimates for these projects can be lower than for surface projects if they use existing underground mine space. There are limited opportunities involving suitable underground space, but the number of underground pumped storage opportunities may increase if abandoned coal mines prove suitable.[37]

In Bendigo, Victoria, Australia, the Bendigo Sustainability Group has proposed the use of the old gold mines under Bendigo for Pumped Hydro Energy Storage.[38] Bendigo has the greatest concentration of deep shaft hard rock mines anywhere in the world with over 5,000 shafts sunk under Bendigo in the second half of the 19th Century. The deepest shaft extends 1,406 metres vertically underground. A recent pre-feasibility study has shown the concept to be viable with a generation capacity of 30 MW and a run time of 6 hours using a water head of over 750 metres.

US-based start-up Quidnet Energy is exploring using abandoned oil and gas wells for pumped storage. If successful they hope to scale up, utilizing some of the 3 million abandoned wells in the US.[39][40]

Using hydraulic fracturing pressure can be stored underground in impermeable strata such as shale.[41] The shale used contains no hydrocarbons.[42]

Decentralised systems

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Small (or micro) applications for pumped storage could be built on streams and within infrastructures, such as drinking water networks[43] and artificial snow-making infrastructures. In this regard, a storm-water basin has been concretely implemented as a cost-effective solution for a water reservoir in a micro-pumped hydro energy storage.[9] Such plants provide distributed energy storage and distributed flexible electricity production and can contribute to the decentralized integration of intermittent renewable energy technologies, such as wind power and solar power. Reservoirs that can be used for small pumped-storage hydropower plants could include[44] natural or artificial lakes, reservoirs within other structures such as irrigation, or unused portions of mines or underground military installations. In Switzerland one study suggested that the total installed capacity of small pumped-storage hydropower plants in 2011 could be increased by 3 to 9 times by providing adequate policy instruments.[44]

Using a pumped-storage system of cisterns and small generators, pico hydro may also be effective for "closed loop" home energy generation systems.[45][46]

Underwater reservoirs

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Further information: Stored Energy at Sea

In March 2017, the research project StEnSea (Storing Energy at Sea) announced their successful completion of a four-week test of a pumped storage underwater reservoir. In this configuration, a hollow sphere submerged and anchored at great depth acts as the lower reservoir, while the upper reservoir is the enclosing body of water. Electricity is created when water is let in via a reversible turbine integrated into the sphere. During off-peak hours, the turbine changes direction and pumps the water out again, using "surplus" electricity from the grid.

The quantity of power created when water is let in, grows proportionally to the height of the column of water above the sphere. In other words: the deeper the sphere is located, the more densely it can store energy. As such, the energy storage capacity of the submerged reservoir is not governed by the gravitational energy in the traditional sense, but by the vertical pressure variation.

High-density pumped hydro

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RheEnergise[47] aim to improve the efficiency of pumped storage by using fluid 2.5x denser than water ("a fine-milled suspended solid in water"[48]), such that "projects can be 2.5x smaller for the same power."[49]

History

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Principle of the pumped storage power plant as an energy storage system

The first use of pumped storage was in 1907 in Switzerland, at the Engeweiher pumped storage facility near Schaffhausen, Switzerland.[50][51] In the 1930s reversible hydroelectric turbines became available. This apparatus could operate both as turbine generators and in reverse as electric motor-driven pumps. The latest in large-scale engineering technology is variable speed machines for greater efficiency. These machines operate in synchronization with the network frequency when generating, but operate asynchronously (independent of the network frequency) when pumping.

The first use of pumped-storage in the United States was in 1930 by the Connecticut Electric and Power Company, using a large reservoir located near New Milford, Connecticut, pumping water from the Housatonic River to the storage reservoir 70 metres (230 ft) above.[52]

Worldwide use

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See also: List of pumped-storage hydroelectric power stations

In 2009, world pumped storage generating capacity was 104 GW,[53] while other sources claim 127 GW, which comprises the vast majority of all types of utility grade electric storage.[54] The European Union had 38.3 GW net capacity (36.8% of world capacity) out of a total of 140 GW of hydropower and representing 5% of total net electrical capacity in the EU. Japan had 25.5 GW net capacity (24.5% of world capacity).[53]

The six largest operational pumped-storage plants are listed below (for a detailed list see List of pumped-storage hydroelectric power stations):

Station Country Location Installed generation
capacity (MW)		 Storage capacity (GWh) Refs
Fengning Pumped Storage Power Station China 41°39′58″N 116°31′44″E / 41.66611°N 116.52889°E / 41.66611; 116.52889 (Fengning Pumped Storage Power Station) 3,600 40 [55][56]
Bath County Pumped Storage Station United States 38°12′32″N 79°48′00″W / 38.20889°N 79.80000°W / 38.20889; -79.80000 (Bath County Pumped-storage Station) 3,003 24 [57]
Guangdong Pumped Storage Power Station China 23°45′52″N 113°57′12″E / 23.76444°N 113.95333°E / 23.76444; 113.95333 (Guangzhou Pumped Storage Power Station) 2,400 [58][59]
Huizhou Pumped Storage Power Station China 23°16′07″N 114°18′50″E / 23.26861°N 114.31389°E / 23.26861; 114.31389 (Huizhou Pumped Storage Power Station) 2,400 [60][61][62][63]
Okutataragi Pumped Storage Power Station Japan 35°14′13″N 134°49′55″E / 35.23694°N 134.83194°E / 35.23694; 134.83194 (Okutataragi Hydroelectric Power Station) 1,932 [64]
Ludington Pumped Storage Power Plant United States 43°53′37″N 86°26′43″W / 43.89361°N 86.44528°W / 43.89361; -86.44528 (Ludington Pumped Storage Power Plant) 1,872 20 [65][66]
Note: The power-generating capacity in megawatts is the usual measure for power station size and reflects the maximum instantaneous output power. The energy storage in gigawatt-hours (GWh) is the capacity to store energy, determined by the size of the upper reservoir, the elevation difference, and the generation efficiency.
Countries with the largest power pumped-storage hydro capacity in 2017[67]
Country Pumped storage
generating capacity
(GW)		 Total installed
generating capacity
(GW)[68]		 Pumped storage/
total generating
capacity
China 32.0 1646.0 1.9%
Japan 28.3 322.2 8.8%
United States 22.6 1074.0 2.1%
Italy 7.1 117.0 6.1%
India 6.8 308.8 2.2%
Germany 6.5 204.1 3.2%
Switzerland 6.4 19.6 32.6%
France 5.8 129.3 4.5%
Austria 4.7 25.2 18.7%
South Korea 4.7 103.0 4.6%
Portugal 3.5 19.6 17.8%
Spain (2024)[69] 3.3 129.0 2.6%
Ukraine 3.1 56.9 5.4%
South Africa 2.9 56.6 5.1%
United Kingdom 2.8 94.6 3.0%
Australia 2.6 67.0 3.9%
Russia 2.2 263.5 0.8%
Poland 1.7 37.3 4.6%
Thailand 1.4 41.0 3.4%
Bulgaria 1.4 12.5 9.6%
Belgium 1.2 21.2 5.7%
Kruonis Pumped Storage Plant, Lithuania

Australia

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The Wivenhoe Power Station in Queensland was built in 1984. It operates by pumping water from the Wivenhoe Dam up to the Splityard Creek Dam (capacity 28,700 megalitres), from where it can be used to generate 570MW of hydro electricity over 10 hours.[70] It is operated by CleanCo Queensland, a corporation owned by the Queensland Government.[71]

Australia has 15GW of pumped storage under construction or in development.

Examples include:

  • In June 2018, the Australian federal government announced that 14 sites had been identified in Tasmania for pumped storage hydro, with the potential of adding 4.8GW to the national grid if a second interconnector beneath Bass Strait was constructed.
  • The Snowy 2.0 project will link two existing dams in the New South Wales' Snowy Mountains to provide 2 GW of capacity and 350 GWh of storage.[72] The project is facing large challenges.[73]
  • In September 2022, a pumped hydroelectric storage (PHES) scheme was announced at Pioneer-Burdekin in central Queensland with the potential to be one of the largest PHES in the world at 2.5 — 5 GW / 120 GWh. When the project was cancelled in 2024,[74] power price forecasts increased by 60% for 2035.[75]

China

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China has the largest capacity of pumped-storage hydroelectricity in the world, and is expanding.

In January 2019, the State Grid Corporation of China announced plans to invest US$5.7 billion in five pumped hydro storage plants with a total 6 GW capacity, to be located in Hebei, Jilin, Zhejiang, Shandong provinces, and in Xinjiang Autonomous Region. China is seeking to build 40 GW of pumped hydro capacity installed by 2020.[76]

China added 7.75GW of PSH in 2024, bringing total installed PSH generation capacity to 58.69GW. With more than 200GW of PSH under construction or approved, China is on track to exceed its 2030 target of 120GW.[77]

Norway

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There are 9 power stations capable of pumping with a total installed capacity of 1344 MW and an average annual production of 2247 GWh. The pumped storage hydropower in Norway is built a bit differently from the rest of the world. They are designed for seasonal pumping. Most of them can also not cycle the water endlessly, but only pump and reuse once. The reason for this is the design of the tunnels and the elevation of lower and upper reservoirs. Some, like Nygard power station, pump water from several river intakes up to a reservoir.

The largest one, Saurdal, which is part of the Ulla-Førre complex, has four 160 MW Francis turbines, but only two are reversible. The lower reservoir is at a higher elevation than the station itself, and thus the water pumped up can only be used once before it has to flow to the next station, Kvilldal, further down the tunnel system. And in addition to the lower reservoir, it will receive water that can be pumped up from 23 river/stream and small reservoir intakes. Some of which will have already gone through a smaller power station on its way.

United States

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See also: Pumped storage in the United States
A shaded-relief topo map of the Taum Sauk pumped storage plant in Missouri, United States. The lake on the mountain is built upon a flat surface, requiring a dam around the entire perimeter.

In 2010, the United States had 21.5 GW of pumped storage generating capacity (20.6% of world capacity).[78] PSH contributed 21,073 GWh of energy in 2020 in the United States, but −5,321 GWh (net) because more energy is consumed in pumping than is generated.[79] Nameplate pumped storage capacity had grown to 21.6 GW by 2014, with pumped storage comprising 97% of grid-scale energy storage in the United States. As of late 2014, there were 51 active project proposals with a total of 39 GW of new nameplate capacity across all stages of the FERC licensing process for new pumped storage hydroelectric plants in the United States, but no new plants were currently under construction in the United States at the time.[80][81]

Italy

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Italy reached peak usage of pumped storage (pompaggi) in 2003, with about 8 TWh.[82] For decades, Italy had excess capacity because its own nuclear program was interrupted in the 1980s, so pumping stations are mostly operated by night when France exports surplus nuclear electricity at near-zero prices.[82] In 2019, the grid operator wanted 6 GW of extra capacity to be built in central and Southern Italy.[82] In 2024, Edison planned 500 MW new capacity.[83]

United Kingdom

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The United Kingdom has four operational pumped-hydro power stations with a generating capacity of 2.8 GW and a total energy capacity of 23.9 GWh.[84] These are Dinorwig (1728 MW), Cruachan (440 MW), Ffestiniog (360 MW), and Foyers (300 MW).[84]

As of 2025, a 1300 MW facility in the Scottish Highlands named Coire Glas is being developed by SSE Renewables.[85][86]

Indonesia

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In Indonesia, the Development of Pumped Storage Hydropower in the Java–Bali System is under construction to enhance grid stability and support renewable energy integration in the region. The main component, the Upper Cisokan Pumped Storage (UCPS) plant in West Java, will have an installed capacity of about 1,040 MW (four 260 MW units). The facility will operate in both generation and pumping modes to balance peak and off-peak electricity demand and is designed to provide approximately 6.5 hours of generation per day. The project is co-financed by the World Bank and the Asian Infrastructure Investment Bank (AIIB), with total funding of around US$610 million, and is expected to begin operation around 2025. It represents Indonesia’s first large-scale pumped-storage development and a key milestone in the Java–Bali grid modernization program.[87][88][89]

Hybrid systems

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Conventional hydroelectric dams may also make use of pumped storage in a hybrid system that both generates power from water naturally flowing into the reservoir as well as storing water pumped back to the reservoir from below the dam. The Grand Coulee Dam in the United States was expanded with a pump-back system in 1973.[90] Existing dams may be repowered with reversing turbines thereby extending the length of time the plant can operate at capacity. Optionally a pump back powerhouse such as the Russell Dam (1992) may be added to a dam for increased generating capacity. Making use of an existing dam's upper reservoir and transmission system can expedite projects and reduce costs.

See also

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References

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[edit]
Revisions and contributorsEdit on WikipediaRead on Wikipedia

Pumped-storage hydroelectricity

View on Grokipedia
from Grokipedia
Pumped-storage hydroelectricity, commonly referred to as pumped storage hydropower (PSH), is a mature and widely used form of that employs two s at different elevations to store and generate on . In this system, excess from the grid—often generated during off-peak periods or from intermittent renewable sources—is used to pump from a lower to an upper one, converting into . When rises, is released from the upper , flowing through reversible turbines that generate power as it returns to the lower , effectively acting as a large-scale " battery." This closed-loop process, which reuses the same body of indefinitely, achieves round-trip efficiencies typically ranging from 70% to 85%, making it one of the most efficient large-scale storage technologies available. The origins of PSH trace back to the late 19th century, with the first experimental installations appearing in Italy and Switzerland during the 1890s to address early challenges in balancing electrical loads. In the United States, the technology debuted in 1930 with a small plant on the Housatonic River in Connecticut, but widespread adoption occurred between 1960 and 1990, when nearly half of the current U.S. PSH capacity was constructed to support growing grid demands. Globally, PSH has evolved into the dominant form of utility-scale energy storage, representing over 94% of worldwide energy storage capacity—especially for long-duration storage with typical discharge times exceeding 6 hours, compared to 1-4 hours for lithium-ion batteries—and over 20 times the energy storage capacity of all batteries combined as of 2025. With approximately 43 operational plants in the U.S. providing 22 gigawatts (GW) of capacity and 550 gigawatt-hours (GWh) of storage—accounting for 96% of the nation's utility-scale energy storage—PSH plays a pivotal role in modern power systems. Internationally, China leads with over 50 GW installed as of 2023, comprising about 30% of the global total, while annual additions are projected to double to 16.5 GW by 2030 to accommodate rising renewable integration. PSH offers significant benefits for grid reliability and the transition to low-carbon , including rapid response times for peaking power, ancillary services like frequency regulation, and long-duration storage capabilities that help balance variable and solar generation. By storing surplus and dispatching it during high demand, PSH reduces reliance on peaker plants, enhances system for stability, and supports decarbonization goals without emitting greenhouse gases during operation. However, challenges include high upfront costs for , environmental impacts from reservoir creation—particularly in open-loop systems affecting aquatic ecosystems—and the need for suitable , which limits new site development in some regions. Despite these hurdles, innovations in closed-loop designs using off-river and upgrades to existing facilities are expanding PSH's potential, with the U.S. alone capable of adding capacity to more than double current levels. As electricity systems worldwide incorporate more renewables, PSH remains essential for ensuring a resilient and flexible grid infrastructure.

Fundamentals

Principle of operation

Pumped-storage hydroelectricity operates using a two-reservoir system, consisting of an upper at a higher and a lower at a lower , connected by a conduit equipped with reversible turbines that function as pumps. This configuration leverages the difference in levels, known as the , to store and release gravitational potential energy. During periods of low electricity demand, excess power from the grid is used to pump water from the lower to the upper , converting into stored . When demand peaks, water is released from the upper through the turbines to the lower , driving the turbines to generate and converting the back into electrical power. This reversible process allows the system to act as a large-scale mechanism, balancing on the . The core components enabling this operation are reversible pump-turbines, typically Francis-type machines, which serve dual roles: as pumps to move uphill by imparting to the , and as turbines to extract from falling to drive generators. These units are synchronized with motor-generators that convert between mechanical and , ensuring efficient energy transfer in both modes. The fundamental principle relies on the conversion of gravitational , given by the equation Ep=mghE_p = m g h where EpE_p is the , mm is the of the , gg is the acceleration due to gravity (approximately 9.81 m/s²), and hh is the (elevation difference between reservoirs). During generation, this drives the turbines, while pumping reverses the process by requiring electrical input to overcome gravitational forces. The overall performance is quantified by the round-trip efficiency, defined as η=(EoutEin)×100%\eta = \left( \frac{E_\text{out}}{E_\text{in}} \right) \times 100\% where EoutE_\text{out} is the generated during discharge and EinE_\text{in} is the consumed during pumping, with typical values ranging from 70% to 85%. This accounts for losses in both pumping and stages, primarily due to hydraulic, mechanical, and .

Historical development

The concept of pumped-storage hydroelectricity emerged in the late , with early experiments in and utilizing surplus electricity to pump water to higher reservoirs for later generation, marking the initial practical applications of the technology. These developments built on broader advancements in , where reversible turbines were not yet common, and systems relied on separate pumps and turbines for and release. The first operational pumped-storage facility came online in 1907 near , , at the small-scale Engeweiher plant, which demonstrated the feasibility of using off-peak power for pumping and generating during . This installation, with a capacity of 1.5 MW, represented a modest but pivotal step, influencing subsequent designs in . Following , pumped-storage technology expanded rapidly in the 1950s and across Europe and the , driven by growing electricity grid demands and the need for peak-load balancing amid industrialization and . In the US, projects like the in entered planning phases during the to address surging peak power needs, with construction beginning in the late 1970s and operations starting in 1985 as one of the world's largest facilities at over 3 GW. This era saw a surge in installations, as utilities recognized pumped storage's role in stabilizing grids with increasing intermittent and base-load generation. Key 20th-century milestones included the scaling up of plants to gigawatt capacities, culminating in modern benchmarks like China's Fengning Pumped Storage Power Plant, which achieved full operation in 2024 with a 3.6 GW capacity using 12 reversible units, establishing it as the world's largest facility and highlighting ongoing advancements in high-head, large-scale systems. As of 2025, global pumped-storage capacity continues to grow, with leading additions to support renewable integration. Technological shifts in the and introduced variable-speed pumps, first implemented in at the Yasugawa plant in the early , enabling more efficient operation across a wider range of heads and flows by allowing turbines to adjust speeds up to 10% above and below nominal ratings. This innovation improved round-trip efficiency and flexibility, paving the way for integration with variable renewable sources.

System Design and Types

Conventional systems

Conventional pumped-storage hydroelectricity relies on a straightforward design that utilizes gravitational potential energy between two s at different elevations to store and release . The system consists of an upper , typically created by damming a hillside or valley, and a lower , which may be a natural like a or lake. Water is transferred between these reservoirs through reversible turbines housed in underground or surface powerhouses, connected by penstocks—large pipes that convey under . These turbines are commonly Francis-type for medium-head applications or Pelton-type for higher heads, engineered to operate bidirectionally: as turbines during generation and as pumps when storing energy. In operation, conventional systems cycle through three primary modes to integrate with electrical grids. During off-peak hours, excess powers electric motors coupled to the turbines, which function as pumps to lift from the lower to the upper , effectively storing energy as . When demand peaks, valves open to release through the penstocks, spinning the turbines to generate at rates up to several gigawatts. Additionally, many facilities can operate in mode, where the turbine-generator spins without flow, using grid power to provide reactive power support and stabilize voltage, enhancing grid reliability without active energy conversion. Design parameters for these systems are optimized for large-scale , with effective head heights ranging from 100 to 1,000 meters to maximize per unit of volume. Storage capacities typically span several gigawatt-hours (GWh), enabling daily or weekly load balancing, while cycle times allow for 4 to 12 hours of continuous from a full upper , depending on installed capacity and head. These parameters ensure the systems can respond to grid fluctuations within minutes, providing essential ancillary services like frequency regulation. Construction of conventional facilities often employs open-loop configurations, where the lower reservoir draws from or discharges to a natural body, contrasting with closed-loop designs that use artificial to minimize environmental interaction and enable construction in diverse terrains. Earthen dams, reinforced with clay cores and rockfill, are commonly used for both to contain economically, as seen in projects like the Bath County facility in , which features a closed-loop upper reservoir and an existing lake below. These methods prioritize site-specific to ensure long-term structural integrity over decades of operation. Maintenance in conventional systems focuses on addressing wear from the dual-role turbines and sediment accumulation in reservoirs and penstocks, which can reduce and capacity if unmanaged. Turbine blades experience from abrasive particles during pumping and generation cycles, necessitating periodic inspections and refurbishments every 10-20 years. Sediment management involves or flushing protocols to prevent buildup, particularly in open-loop systems connected to rivers, ensuring sustained hydraulic performance and minimizing downtime.

Advanced and variable-speed systems

Advanced and variable-speed systems represent an evolution of traditional pumped-storage hydroelectricity designs, incorporating adjustable-speed pump-turbines to enhance operational flexibility in response to integration. These systems employ adjustable drives, often using doubly-fed induction machines or full converter technologies, to vary the rotational speed of the turbine-generator units independently of the grid . This allows operation across a broader speed range, typically from about 90% to 110% of nominal speed in pumping and generating modes, enabling partial load adjustments without fixed constraints. The primary benefits of variable-speed pump-turbines include a wider operating range that supports power regulation in both pumping and generating modes, reducing the need for frequent start-stop cycles and minimizing mechanical wear. In pumping mode, these units can adjust power output by up to 30%, accommodating fluctuating grid demands more effectively than fixed-speed systems. Part-load is notably improved, with off-design gains reaching up to 10% in some configurations, allowing the plant to maintain higher overall round-trip during variable renewable energy curtailment or surplus periods. Additionally, the technology facilitates faster ramping rates and ancillary services like frequency regulation, enhancing grid stability. Implementation examples illustrate the practical adoption of these advancements. In , where adjustable-speed units were pioneered in the early 1990s, upgrades in the , such as the renovation of the Okutataragi Power Station, converted fixed-speed units to variable-speed operation to improve flexibility for integrating solar and , the Goldisthal Pumped Storage Plant in , commissioned in 2004, features two variable-speed units with 330 MVA capacity each, marking one of the first such applications outside Japan and demonstrating enhanced pumping regulation capabilities. These reversible pump-turbines, often Francis-type in large-scale setups, operate with asynchronous motor-generators to achieve the variable speed functionality. Control systems in variable-speed pumped-storage facilities integrate with supervisory control and data acquisition () platforms to enable real-time monitoring and automated responses to grid signals, optimizing speed adjustments based on deviations or load forecasts. This integration allows for precise active and reactive , supporting black-start capabilities and voltage stability in modern power systems. However, limitations persist, including higher initial —often 10-20% more than conventional systems—due to the complex and converter requirements, which can extend payback periods in regions with stable grid conditions. Despite these challenges, the technology's ability to boost penetration justifies investments in high-variability grids.

Economic and Efficiency Analysis

Energy conversion efficiency

Pumped-storage hydroelectricity systems achieve round-trip energy conversion efficiencies typically ranging from 70% to 85%, representing the fraction of input electrical energy recovered during the generation phase after accounting for various losses in the pumping and turbining processes. This efficiency is determined by the product of individual component efficiencies: ηtotal=ηpump×ηturbine×ηmotor×ηgenerator\eta_\text{total} = \eta_\text{pump} \times \eta_\text{turbine} \times \eta_\text{motor} \times \eta_\text{generator}, where each term denotes the hydraulic or electromechanical efficiency of the respective subsystem during operation. Losses in these systems arise from multiple sources, categorized as hydraulic, mechanical, and electrical. Hydraulic losses, mainly from in pipes, conduits, and in water flow, generally constitute 2–5% of the total input, with turbine hydraulic around 95% and pumping hydraulic reaching 98.5% in well-designed systems. Mechanical losses, primarily due to in bearings and seals, account for approximately 2% of the . Electrical losses in the motor and generator, stemming from resistance and magnetic inefficiencies, contribute 1–2% to the overall . Several factors influence these efficiencies. Higher head heights between reservoirs reduce the relative impact of fixed losses, such as and leakage, thereby improving overall performance. Variations in water temperature can subtly affect and thresholds, potentially altering flow dynamics and hydraulic efficiency. Air entrainment in the water flow, often occurring during reservoir drawdown or in surge tanks, introduces additional drag and reduces turbine efficiency by up to several percent in severe cases. Compared to other energy storage technologies, pumped-storage hydroelectricity provides efficiencies of 70–85%, which is competitive with lithium-ion batteries (often exceeding 90%) for short-duration applications but excels in long-duration storage (hours to days) where batteries suffer from higher and degradation. Optimization techniques, such as avoiding through precise runner design and management, can enhance hydraulic performance by minimizing vapor bubble formation and erosion. Advanced flow control via variable-speed motors allows operation closer to peak efficiency across varying heads and loads, potentially boosting round-trip efficiency by 2–3%.

Capital and operational costs

Capital costs for pumped-storage hydroelectricity projects typically range from $1,700 to $4,500 per kW of installed capacity (2024 USD), with variations depending on site-specific factors such as and requirements. These costs are predominantly driven by works, which account for 60-70% of the total investment, including the construction of , tunnels, and penstocks. Electromechanical and balance-of-plant components constitute the remaining share, often around 30-40%. Operational costs are notably low, primarily encompassing , , and minor repairs. These expenses represent about 1.5-2.5% of the initial capital investment annually, benefiting from the technology's and a typical operational lifespan of 50 to 100 years. Higher energy conversion efficiencies, as discussed in related analyses, further contribute to cost-effectiveness by reducing losses during repeated pumping and generation cycles. The levelized cost of storage (LCOS) for pumped-storage systems generally falls between $100 and $200 per MWh, making it competitive with emerging battery technologies for long-duration applications exceeding several hours. This metric accounts for capital recovery, operational expenses, and the system's extended service life over discount periods. Funding for these projects often involves public-private partnerships (PPPs), where governments provide regulatory support and subsidies to facilitate integration, while private investors handle construction and operations to mitigate risks. Such models are essential given the high upfront investments and long development timelines. Sensitivity analyses highlight the vulnerability of (ROI) to key variables, including interest rates—which can increase financing costs by 20-30% with a 1-2% rise—and construction delays, which may elevate total expenses by 10-15% due to extended overhead and . These factors underscore the need for robust project planning to maintain economic viability.

Small-scale and micro facilities

Small-scale pumped-storage hydroelectricity facilities are defined as those with capacities ranging from 1 MW to 100 MW, while micro facilities operate below 1 MW, contrasting with gigawatt-scale installations that dominate global capacity. These systems adapt conventional pumped-storage principles, such as reversible turbines for pumping and generating water between reservoirs, but incorporate scaled-down components to fit limited sites. A key advantage of small-scale and facilities is their reduced environmental footprint, particularly when using closed-loop configurations that avoid river diversions and minimize disruption through off-river reservoirs or existing quarries. They enable faster deployment compared to large projects, often completing construction in 2 to 5 years, making them ideal for integrating with renewables in remote areas, islands, or rural grids where grid stability is challenged by intermittent sources. For instance, these systems support by pairing with solar photovoltaics to provide reliable power to off-grid communities. Design adaptations for these facilities emphasize modularity and efficiency at lower capacities, including submersible pump-turbines that eliminate the need for large underground powerhouses and variable-speed units for better part-load performance. Off-river closed-loop setups further reduce land use by relying on artificial reservoirs rather than natural water bodies, allowing installation in diverse terrains like abandoned mines or urban peripheries. Representative examples include the proposed 5 MW and 10 MW facilities in Val de Bagnes, , which utilize local topography for voltage control and grid support in mountainous regions. In , the Jacksons Creek project integrates a small pumped-storage with , and battery storage to supply a neighborhood, generating approximately 60 MWh annually for local resilience. A study proposes a micro pumped hydro in , coupled with , for sustainable rural power, highlighting adaptability to developing contexts. Despite these benefits, challenges persist, including higher specific of $3,000 to $5,000 per kW due to economies-of-scale inefficiencies in and civil works. Site requirements for sufficient head and water volume remain stringent even at small scales, potentially limiting widespread adoption without innovative sourcing.

and Requirements

Geographical and topographical needs

Pumped-storage hydroelectricity requires substantial elevation differences, or , between upper and lower reservoirs to harness energy effectively, with site assessments typically specifying a minimum head of 200 meters and often favoring higher values up to 750 meters for optimal performance. Such is predominantly available in mountainous or hilly regions, where natural contours facilitate the placement of reservoirs at varying altitudes, minimizing excavation needs and enhancing project feasibility. Hydrological conditions demand access to adequate supplies for initial filling and operational cycling, with large facilities requiring volumes on the order of billions of cubic meters in aggregate to enable multi-hour without excessive or seepage losses. To avoid over-dependence on river systems, closed-loop configurations recycle internally, relying on minimal external inflows beyond makeup for losses. Geological stability is crucial, necessitating bedrock suitable for tunneling and construction, along with low-permeability soils or engineered liners for reservoirs to contain effectively. Sites must also steer clear of high-seismic-risk areas to safeguard integrity over decades of operation. Proximity to existing power grids and demand centers is a key siting criterion, as it curtails transmission infrastructure costs and energy losses, ideally positioning facilities within tens of kilometers of high-voltage lines. Suitable sites remain geographically scarce, with global evaluations estimating a technical storage potential of around 23,000 terawatt-hours for closed-loop systems, concentrated in select topographies worldwide.

Reservoir and infrastructure demands

Pumped-storage hydroelectricity systems require substantial reservoirs to store water for energy generation and pumping operations, with the upper reservoir volume typically calculated using the formula for potential energy storage. The volume VV of the upper reservoir is determined by V=P×tρ×g×h×ηV = \frac{P \times t}{\rho \times g \times h \times \eta}, where PP is the power output in watts, tt is the storage duration in seconds, ρ\rho is the density of water (approximately 1000 kg/m³), gg is the acceleration due to gravity (9.81 m/s²), hh is the effective head height in meters, and η\eta is the round-trip efficiency (often 70-85%). This sizing ensures sufficient water to meet peak demand periods, with typical upper reservoir volumes ranging from 10 to 100 million cubic meters for large-scale facilities to support multi-hour discharge cycles. The supporting infrastructure includes , which are large-diameter pipes or tunnels conveying water between reservoirs and the powerhouse. These are commonly constructed from or , with diameters typically between 5 and 10 meters to handle high flow rates during pumping and . Surge shafts, vertical openings connected to the penstock system, are essential for pressure regulation, absorbing sudden water hammer effects and preventing pipeline bursts during rapid load changes. Spillways serve as overflow channels to manage excess water during heavy inflows, directing it safely away from the facility to avoid structural damage. Construction of reservoirs and waterways emphasizes durability and watertightness, with linings applied to prevent seepage losses that could reduce efficiency. Common materials include geomembranes, such as reinforced or , alongside or compacted clay for high-permeability sites. Intake structures at the reservoirs feature screens to block debris, fish, and sediments, typically made of mesh with automated mechanisms to maintain flow without clogging the penstocks or turbines. These systems undergo frequent pump-back cycles to balance daily and seasonal energy demands. To adapt to modern requirements, upgrades often incorporate passages, such as vertical slot or trap-and-transport systems, to facilitate upstream and downstream migration without impeding flow. Sediment flushing systems, including gated outlets at the bottom, are also integrated to periodically remove accumulated deposits, preserving storage capacity and hydraulic efficiency over the facility's lifespan.

Environmental Considerations

Biodiversity and ecosystem impacts

Pumped-storage hydroelectricity facilities often lead to through the construction of reservoirs, which inundate terrestrial landscapes and divide into isolated patches. This process displaces native and , reducing connectivity for species movement and , particularly in mountainous or regions where upper and lower reservoirs are sited. Vegetation clearing and land inundation associated with these projects can result in the loss or disturbance of diverse habitats, exacerbating fragmentation in sensitive alpine or riparian environments. Aquatic ecosystems face significant disruptions from fluctuating water levels in pumped-storage operations, which alter flow regimes and impede patterns. Daily pumping and generation cycles create hydropeaking effects, stranding in dewatered channels or exposing them to rapid flow changes that disrupt spawning and foraging habitats. Turbine entrainment, where are drawn into structures and passed through , causes direct mortality through mechanical or pressure changes, with estimates indicating 5-10% mortality for passing a single facility, and higher cumulative rates in multi-dam systems. These impacts particularly affect migratory species like and eels, leading to population declines and reduced in connected riverine habitats. Terrestrial effects include disturbance to riparian zones during construction, where excavation and access road development increase and into adjacent waterways. This erosion degrades stream banks, reduces vegetation cover, and alters nutrient cycling, indirectly harming terrestrial reliant on stable riparian corridors for and food sources. Cumulative impacts from repeated daily drawdowns in reservoirs mimic unnatural flooding regimes, which can degrade wetland margins by promoting establishment and eroding organic soils, further diminishing overall resilience. A notable case is the Helms Pumped Storage Project in . The project's biological resources management plan addresses these by monitoring sensitive and minimizing entrainment through operational adjustments, though ongoing challenges persist for downstream fisheries. To mitigate losses, facilities incorporate measures such as ladders, which provide stepped channels allowing upstream migration around barriers, and screening devices to prevent entrainment of juveniles. These interventions, in use since the , have proven effective in restoring passage for anadromous in some systems, though their success depends on site-specific design and maintenance to accommodate diverse and flow conditions.

Water usage and climate effects

Pumped-storage hydroelectricity systems generally exhibit low consumption compared to other configurations, as they recirculate between upper and lower reservoirs during operation. In closed-loop designs, which do not rely on continuous inflows, the primary loss occurs through from reservoir surfaces and minor seepage, requiring periodic make-up to maintain storage volumes. These losses are minimal overall, often amounting to less than the natural in surrounding landscapes, and can be offset by local in many sites. Open-loop systems, which connect to natural bodies, may experience higher consumption due to additional from larger exposed surfaces and integration with stream flows, though still lower than evaporative demands of thermal power plants. The climate interactions of pumped-storage reservoirs are dual-natured, serving as potential carbon sinks through submerged that sequesters CO2 while also emitting from decomposition during initial flooding. from reservoirs contribute to about 5.2% of global anthropogenic in recent estimates, though pumped-storage facilities typically produce lower levels than large run-of-river due to smaller inundated areas. These systems are vulnerable to climate-driven droughts, which can diminish reservoir levels and reduce operational capacity in affected regions, exacerbating energy supply risks. Conversely, pumped storage enhances grid stability against variable renewable inputs intensified by , providing reliable dispatchable power during events. Adaptation strategies for water usage and include the adoption of closed-loop configurations, which minimize exposure to river variability and reduce by limiting size and openness. In arid regions, integration with plants allows excess to power water production, using pumped-storage output for high-demand periods while storing desalinated water, thereby addressing dual challenges of energy and . Globally, potential conflicts arise in water-stressed basins, where approximately 26% of existing and projected sites, including pumped-storage opportunities, overlap with high-stress areas, necessitating careful to avoid exacerbating local shortages. These measures position pumped storage as a sustainable option for , with lower lifecycle emissions than alternatives.

Emerging Technologies

Seawater and coastal variants

Seawater pumped-storage hydroelectricity adapts the conventional pumped-storage principle by utilizing the as the lower and constructing an artificial upper on coastal cliffs or elevated , enabling hydraulic heads typically ranging from 300 to 600 meters. This configuration leverages natural coastal topography to store , pumping uphill during periods of excess and releasing it through turbines to produce when demand peaks. Unlike traditional systems reliant on inland freshwater , this variant targets locations where elevation differences meet the , broadening deployment possibilities in marine environments. The integration of seawater introduces significant technical challenges, primarily and . Seawater's high accelerates material degradation, necessitating the use of corrosion-resistant alloys such as for critical components like turbines, pumps, and penstocks; titanium's passive oxide layer provides exceptional resistance to pitting and in saline conditions. , where marine organisms accumulate on submerged surfaces, can impede flow and reduce operational efficiency, addressed through strategies like electrolytic chlorination systems or antifouling coatings to maintain clear waterways and equipment integrity. These adaptations increase construction complexity but enable reliable operation in harsh marine settings. Efficiency in seawater systems is marginally lower than in freshwater counterparts, typically achieving round-trip values of 65% to 80%, influenced by seawater's greater (about 1.025 g/cm³ compared to 1 g/cm³ for freshwater), which alters hydrodynamic forces on pumps and turbines. Additional losses may arise from biofouling-related drag or the need for in hybrid applications, though modern designs mitigate these through optimized reversible pump-turbines and materials that minimize . Despite these adjustments, the technology remains competitive for large-scale storage due to its longevity and capacity. Notable implementations include the Okinawa Yanbaru Pumped Storage in , the world's first such facility at 30 MW, which operated experimentally from 1999 until its decommissioning in 2016 to validate seawater use in . Planned developments highlight growing interest, such as the 320 MW project in , , announced in 2024 by Renewable Energy Developers Choice (REDC), aimed at integrating with renewable sources. These examples underscore the shift toward hybrid setups combining seawater storage with wind or solar to enhance renewable integration. A primary advantage of seawater variants is their independence from freshwater supplies, ideal for water-scarce coastal zones and reducing competition with agricultural or domestic needs. This opens up extensive site opportunities worldwide, with assessments indicating vast potential along global coastlines capable of supporting terawatt-scale capacity to bolster energy transitions. By exploiting abundant marine resources, these systems contribute to scalable, dispatchable storage essential for variable renewables.

Underground and closed-loop designs

Underground and closed-loop pumped-storage hydroelectricity designs utilize artificial reservoirs or excavated caverns disconnected from natural rivers, enabling off-river pumping operations that cycle water between isolated upper and lower storage sites. These systems, often referred to as closed-loop configurations, minimize reliance on river flows and allow deployment in areas lacking suitable natural by creating engineered differences. By situating reservoirs or powerhouses underground, such as in mined caverns or shafts, these designs further reduce surface disruption while maintaining the core principle of storing energy through reversible . Key advantages of underground closed-loop systems include significantly reduced surface compared to traditional surface-based pumped storage, often requiring only a fraction of the footprint due to subterranean placement of reservoirs and infrastructure. This approach also lowers evaporation losses, as water is contained in sealed underground environments rather than open-air reservoirs, and decreases flood risk by avoiding exposure to surface weather events. Additionally, these designs can adapt geographical constraints by leveraging existing underground voids, such as those in geologically stable regions with prior activity, thereby expanding viable siting options beyond steep valleys. Design features typically involve pressurized tunnels to convey water between reservoirs, reinforced with waterproof linings to prevent leakage and ensure structural integrity under high pressures. Head heights in deep underground setups can reach up to 500 meters or more, achieved by exploiting vertical mine shafts or cavern depths for greater storage. Powerhouses may be located underground to further compact the facility, with reversible turbines handling both pumping and generation phases in a self-contained loop. A prominent example is the Snowy 2.0 in , a 2 gigawatt underground expansion of the existing , featuring 27 kilometers of tunnels connecting two artificial reservoirs in a closed-loop system without river integration. As of 2025, construction is 67% complete, though facing cost overruns beyond the initial A$12 billion budget and potential delays, with operations now anticipated around 2028, utilizing one of the deepest cavern excavations for its powerhouse. Potential also exists in repurposing abandoned coal mines as lower reservoirs, where existing shafts provide ready infrastructure for utility-scale storage, as explored in U.S. initiatives targeting regions with legacy mining. Despite these benefits, challenges include high upfront excavation costs for creating or adapting underground spaces, which can exceed those of surface projects due to specialized and reinforcement needs. intrusion poses another risk, requiring robust sealing and systems to maintain and prevent structural damage or operational inefficiencies. These issues necessitate thorough geological assessments to ensure long-term viability.

Decentralized, underwater, and high-density innovations

Decentralized pumped-storage systems emphasize modular, small-scale units designed for localized energy storage, typically in the range of 1-10 MW, suitable for integration near renewable sources like solar farms or community grids. These systems utilize prefabricated components, such as elevated water tanks with simple foundations, to minimize site-specific engineering and enable rapid deployment in non-traditional locations without large reservoirs. For instance, Absaroka Energy's modular pumped-storage hydropower (PSH) employs stackable tanks that can be scaled to match storage durations from hours to days, offering a flexible alternative to centralized facilities for off-grid or microgrid applications. Similarly, the Grid-Level Integrated Diverse Energy Storage (GLIDES) system, developed by Oak Ridge National Laboratory, is a hybrid combining pumped-storage hydropower with compressed air energy storage; it demonstrates a 20 kW prototype that pairs with photovoltaic installations to trade energy locally, achieving high round-trip efficiency over 30 years of operation. These innovations, often at technology readiness levels (TRL) 3-5, address geographical constraints of conventional PSH by prioritizing portability and lower capital costs, though they remain in early commercialization phases. Underwater pumped-storage concepts leverage ocean depths to create natural head differences, using subsea reservoirs like flexible bladders or rigid spheres anchored to the to store and release under hydrostatic . In these systems, excess pumps into the reservoirs during low , and reversal generates power as flows out, harnessing depths of 600-800 meters for storage capacities up to gigawatt-hours without surface infrastructure. The Stored Energy in the Sea (StEnSea) project, led by Fraunhofer Institute for Energy Economics and Energy Technology, proposes offshore PSH with hollow spheres that exploit seawater for densities comparable to land-based systems, potentially scalable for coastal renewable integration; as of November 2024, it received $7.7 million in funding from the and German governments for a subsea pilot demonstration off . Another example is Ocean Grazer's Ocean Battery, a Dutch innovation employing large flexible bladders on the to store from offshore farms, with a targeting 0.5 MW and efficiencies exceeding 80%; in 2025, it launched the AquaVault product in April and Project NEMO in March, following testing completion in 2024. Recent advancements include a US-German funded pilot using 3D-printed structures for subsea bladders, aiming to demonstrate long-duration storage at depths around 600 meters. These early-stage technologies (TRL 4-6) promise decentralized marine deployment but face challenges in material durability against and . High-density pumped-storage innovations replace water with denser fluids, such as suspensions of fine particles in water, to boost by up to 2.5 times, allowing effective operation with reduced head heights of 30-150 meters and smaller volumes. This approach circumvents the need for mountainous terrain, enabling installations in flat or urban areas while maintaining round-trip efficiencies of 75-80%. RheEnergise's High-Density Hydro system exemplifies this, using a fluid that achieves 2.5 times water's , as validated in UK-based prototypes that store 100 kWh in facilities 60% smaller than traditional PSH equivalents; in 2025, it completed mechanical works at a 500 kW demonstrator site in Plymouth in September, secured €2.5 million funding in July, and initiated a conceptual study with in July for a potential project. Lab-scale tests have confirmed the fluid's stability and pump-turbine compatibility, positioning it for community-scale applications near renewables. Although brine-based variants have been explored for similar density gains, they pose compatibility issues with , limiting adoption compared to particle suspensions. These concepts, primarily at TRL 5-7, offer scalable potential for off-grid resilience but require further validation on fluid longevity and environmental impacts.

Global Deployment

Capacity and major projects overview

Pumped-storage hydroelectricity represents the dominant form of utility-scale globally, with an installed capacity of approximately 190 GW as of mid-2025. This accounts for over 94% of worldwide utility-scale storage capacity. Annual additions have accelerated in recent years, reaching 8.4 GW in 2024 alone, reflecting growing demand for grid flexibility amid expansion. Among the largest facilities, China's stands out with a capacity of 3.6 GW, making it the world's biggest upon full commissioning in 2024. The in the United States follows closely at 3 GW, operational since 1985 and providing critical peaking support. Other notable projects include China's Huizhou Pumped Storage Power Station at 2.4 GW and Belgium's Coo-Trois-Ponts at 1.1 GW, both exemplifying efficient large-scale implementations. Roughly 80% of global capacity is concentrated in and , with holding about 98 GW and around 55 GW as of 2024. The theoretical global potential exceeds 800 GW, far outpacing current deployment and highlighting underutilized opportunities for expansion. Typical plant sizes range from 500 to 1,000 MW, and in mature electricity grids, pumped storage often supplies 10-20% of to enhance reliability. According to International Association reports, achieving net-zero emissions will require substantial pumped-storage growth, with a development pipeline surpassing 600 GW to support renewable integration.

Implementations in Asia

Asia has emerged as a global leader in pumped-storage hydroelectricity deployment, driven by the need to support rapid economic growth and integrate variable renewable energy sources. China dominates the region with over 62 GW of installed capacity as of August 2025, accounting for approximately 30% of the world's total, while Japan maintains around 27 GW with an emphasis on earthquake-resistant designs. India, with about 6 GW operational as of 2025, is accelerating developments to bolster its energy security amid rising demand. In , pumped-storage capacity has expanded rapidly to balance the surge in and , particularly in regions like the where solar integration is prioritized. The in Province, the world's largest facility, achieved full operation in late 2024 with a 3.6 GW installed capacity, featuring 12 reversible pump-turbines and reservoirs holding over 116 million cubic meters combined. This project exemplifies 's scale, supporting peak load shifting for the Beijing-Tianjin area. Nationally, more than 91 GW of pumped-storage projects are under construction, positioning the country to surpass its 120 GW target by 2030 and reach up to 130 GW. Japan's 27 GW of pumped-storage capacity, representing about 15% of global installations, focuses on resilience against seismic activity, with facilities designed to withstand earthquakes up to magnitude 8. The Okawachi Pumped Storage Power Station in , operational since 1992, provides 1.28 GW through four 320 MW units and a 9.31 million cubic meter upper , aiding grid stability in a densely populated nation with limited land for new energy . These systems store excess nuclear and , ensuring reliable supply during high-demand periods. India's current 6 GW of pumped-storage capacity supports its hydropower ambitions, with expansions underway to integrate renewables and meet urban energy needs. The in , part of a 1.96 GW complex with pumped-storage components, exemplifies early adoption since the , enabling efficient water management for and power. The government has identified over 200 GW of potential sites, with 8 GW under construction as of 2025, aiming for significant growth through a dedicated policy outlined in the 2024-25 Union Budget to promote storage for grid reliability. Regional drivers include accelerating and the push for renewables integration, as seen in China's pairing of pumped storage with desert solar farms to manage . However, challenges persist, such as monsoon-induced water variability affecting reservoir levels in and , and land acquisition hurdles due to environmental regulations and community negotiations, which delay projects across the continent.

Implementations in Europe

Europe's pumped-storage hydroelectricity infrastructure is characterized by a network of established facilities, many leveraging alpine topography for significant head differences, contributing to grid flexibility in a region with high renewable penetration. was an early pioneer, with one of the first commercial pumped-storage plants opening in 1909 near , following experimental installations in and during the 1890s. In , pumped-storage capacity stands at approximately 1.37 GW, supporting the country's hydro-dominant electricity system where accounts for over 90% of generation. The Aurland complex exemplifies this, with its combined facilities offering around 1.1 GW and incorporating pumped-storage operations to optimize reservoir levels in a fjord-rich . This setup enables seasonal energy , enhancing export capabilities to neighboring grids. The features notable installations like the in , operational since 1984 with a 1.728 GW capacity, capable of rapid response to within seconds. As one of Europe's largest, it stores excess nighttime generation and discharges during high-load periods, bolstering grid stability. Current plans outline over 10 GW of new pumped-storage projects in development, aimed at meeting net-zero targets by 2050 through enhanced long-duration storage. Italy maintains about 7 GW of pumped-storage capacity, concentrated in the to harness steep elevations for efficient energy cycling. The Roncovalgrande plant on , with 1.04 GW output, ranks as the country's second-largest facility and generates around 408 GWh annually by pumping water between reservoirs during off-peak hours. This alpine-centric approach integrates with Italy's broader 18 GW hydropower portfolio, providing ancillary services amid growing solar and integration. Switzerland, an early leader, operates roughly 2 GW of pumped-storage capacity, emphasizing high-head alpine sites for maximal efficiency. Facilities like Nant de Drance, with 900 MW and 20 GWh storage, operate underground to minimize surface impact while enabling variable-speed pumping to match fluctuating renewables. These systems support Switzerland's 7 GW total hydropower base, exporting flexibility to the European grid. Across the European Union, trends focus on revitalizing existing infrastructure to align with the Green Deal's decarbonization goals, including variable-speed upgrades that improve part-load efficiency by up to 5-10%. Projects such as the conversion at Le Cheylas in France demonstrate this, retrofitting fixed-speed units for broader operational ranges and better renewable integration. Such revamps, supported by initiatives from Eurelectric and the International Hydropower Association, aim to extend plant lifespans beyond 80 years while unlocking additional storage potential.

Implementations in North America and Oceania

Pumped-storage hydroelectricity in the United States boasts the largest installed capacity in , totaling approximately 22.2 gigawatts (GW) as of 2025, accounting for the majority of the region's grid-scale . This capacity is distributed across 43 facilities, primarily in the eastern and western states, where suitable supports upper and lower reservoirs. The in stands out as the largest single facility, with a capacity of 3 GW, representing about 13% of the national total and demonstrating the technology's role in balancing for utilities like . However, new developments face significant hurdles due to the (FERC) licensing process, which can span 5–10 years and involves rigorous environmental impact assessments under the , often resulting in delays or denials for projects on sensitive lands. In Canada, installed pumped-storage capacity remains modest at 177 megawatts (MW) as of 2024, concentrated in a few facilities that integrate with the country's extensive conventional hydroelectric infrastructure. The primary operational plant is the Sir Adam Beck Pump Generating Station in Ontario, a 174 MW facility that pumps water from the Niagara River to an upper reservoir for storage and generation, enhancing grid reliability in the densely populated region. Quebec's Hydro-Québec system, while dominated by over 40 GW of run-of-river and reservoir-based hydro, leverages pumped storage sparingly but benefits from its overall hydro dominance—producing about 342 terawatt-hours annually—to support interprovincial exports and renewable integration. Regulatory challenges, including environmental reviews by provincial authorities and federal impact assessments, combined with indigenous consultation requirements under treaties, have limited expansions, though recent studies highlight untapped potential exceeding 8,000 GW at nearly 1,200 sites. Australia leads implementations in Oceania with an installed pumped-storage capacity of around 800 MW as of mid-2024, augmented by major projects under construction to bolster the National Electricity Market's transition to renewables. Hydroelectric Scheme includes pumped-storage components within its 4.1 GW total capacity, but the flagship Snowy 2.0 expansion—adding 2 GW of and 350 gigawatt-hours of storage—is slated for completion by 2028, utilizing existing reservoirs to provide firming services for variable wind and solar. The Kidston Pumped Storage Hydro Project in , a 250 MW closed-loop facility repurposing abandoned gold mine pits, achieved key construction milestones in 2025 and represents the first private-sector pumped hydro in over 40 years, with energization expected in the second half of 2025. Across , trends emphasize closed-loop designs at former sites, with 37 viable locations in offering 540 gigawatt-hours of storage potential, tapping into the region's abundant disused pits for low-impact development. Overall untapped potential in the area exceeds 10 GW, driven by mining legacies, though projects contend with protracted environmental approvals and negotiations under native title laws.

Integration and Future Role

Hybrid systems with renewables

Hybrid systems integrate pumped-storage hydroelectricity (PSH) with variable renewable energy sources such as solar photovoltaic (PV) and , typically through co-location at the same site to optimize and infrastructure sharing. In solar-PSH configurations, excess daytime solar generation pumps water to the upper , storing for discharge during evening peaks or low solar periods. Wind-PSH setups similarly use surplus nighttime or off-peak wind output for pumping, enabling the system to convert intermittent renewable production into dispatchable power. These arrangements enhance the reliability of renewables by addressing their variability, with PSH acting as a long-duration buffer. The primary benefits include smoothing output intermittency from solar and , which reduces curtailment and improves grid integration. Standalone solar and plants often operate at capacity factors of 10-20%, but hybridizing with PSH can elevate the overall system to over 50% by utilizing stored energy during non-production periods. This synergy also boosts renewable penetration levels, supports energy shifting, and minimizes reliance on peaker plants for balancing. Notable examples illustrate these configurations in practice. The Kidston Renewable Energy Hub in , , features a 250 MW PSH facility co-located with a 270 MW solar PV plant in a former mine, allowing excess to charge the storage for on-demand release; construction began in 2021, with operations commencing in late 2025. In , the proposed 1,300 MW Eagle Mountain Pumped Storage Project aims to pair PSH with regional and solar resources, converting intermittent generation into firm, dispatchable output to support the state's clean energy goals. Technical integration in these hybrids can occur via direct DC coupling between renewable inverters and PSH pumps for efficient energy transfer without grid intermediation, or through grid-mediated connections for broader flexibility. PSH in hybrid setups typically provides 8-24 hours of storage duration, enabling daily or multi-day cycling to match renewable generation patterns. This allows for seamless operation, where renewables prioritize pumping during surplus and PSH generation supplements during deficits. Economically, hybrid systems reduce the levelized cost of storage (LCOS) by 20-30% compared to standalone PSH through shared transmission lines, site preparation, and permitting costs. Infrastructure synergies, such as common reservoirs or access roads, further lower capital expenditures, making hybrids more viable for scaling renewable integration.

Contributions to grid stability and energy transition

Pumped-storage hydroelectricity (PSH) delivers critical grid services that bolster the reliability and stability of electricity systems, particularly as renewable energy integration increases. Through its synchronous generators, PSH provides rotational inertia that resists rapid frequency deviations, mimicking the stabilizing effect of traditional fossil fuel or nuclear plants and helping to maintain grid balance during disturbances. Fixed-speed PSH units offer reactive power support similar to conventional synchronous machines, while adjustable-speed units enable precise frequency regulation by modulating active and reactive power via power electronics. Additionally, PSH supports black-start capabilities, allowing isolated facilities to self-start and restore power to the grid following outages without reliance on external sources, as demonstrated in operational scenarios like the Ludington facility in the US. These services are essential in low-inertia grids dominated by inverter-based renewables, where PSH can contribute inertia provision comparable to several gigawatts of synchronous generation across deployed systems. In the broader toward decarbonization, PSH facilitates deeper penetration of variable renewables like and solar, enabling system-wide shares of 50-70% by absorbing surplus generation during peak production and releasing stored energy to offset shortfalls. This time-shifting capability is particularly valuable for aligning supply with rising demands, such as charging electric vehicles and powering heat pumps, where PSH can store excess daytime renewable output for evening or seasonal use. By providing long-duration storage—often exceeding 10 hours—PSH reduces curtailment of renewables and supports the shift away from fossil fuels, enhancing overall system flexibility without the challenges of batteries. Projections indicate a need for total installed PSH capacity to reach 420 GW globally by 2050 (implying over 250 GW additional), according to analyses aligned with scenarios, underscoring its role in scaling clean energy infrastructure. PSH also enhances grid resilience against climate impacts and disruptions, with closed-loop designs offering drought-proofing by operating independently of natural river flows through self-contained reservoirs. These configurations minimize vulnerability to , ensuring consistent storage performance even in arid regions or during prolonged dry spells. In applications, PSH provides dispatchable, long-term energy backup that integrates with distributed renewables, enabling isolated or community-scale systems to maintain autonomy and recover from events like storms. measures further promote PSH deployment; for instance, the US extends investment tax credits (up to 50% in qualifying cases) and production tax credits to PSH projects, incentivizing development to support resilience and transition goals.

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