4.5.5.1.1 Process Description

Conventional PHS uses two water reservoirs, separated vertically. During off-peak hours, water is pumped from the lower reservoir to the upper reservoir. When required, the water flow is reversed to generate electricity. Some high-dam hydro plants have a storage capability and can be dispatched as a pumped hydro. Underground pumped storage, using flooded mine shafts or other cavities, is also technically possible. Open sea can also be used as the lower reservoir.

A schematic view of a pumped hydroelectric storage system is shown in Figure 4.11 (Kaldellis et al., 2009). It consists of (i) two reservoirs located at different elevations, (ii) a unit to pump water to the reservoir at high elevation (to store electricity in the form of hydraulic potential energy during availability of renewable power and/or during off-peak hours), and (iii) a turbine to generate electricity with the water flowing from the higher reservoir to the reservoir at low elevation (converting the potential energy to electricity). Clearly, the amount of stored energy is proportional to the difference in height between the two reservoirs and the volume of water stored. Some high-dam hydroelectric power plants have a storage capability and can be dispatched as a PHS. Underground pumped storage, using flooded mine shafts or other cavities, is also technically possible. If the PHS is located near seaside, open sea can be treated as the lower reservoir (Ahearne, 2004).

4.5.5.1.2 Performance Characteristics

• The self-discharge (energy dissipation) per day for PHS has a very small self-discharge ratio, so it is suitable for a long storage period.

• PHS has a cycle efficiency of 60-90%.

• The energy density of PHS is among the lowest, below ~ 30 Wh/kg.

• PHS has a long cycle life. This technology is based on conventional mechanical engineering, and the lifetime is mainly determined by the lifetime of the mechanical components.

4.5.5.1.3 Pumped Hydro Storage Applications

The typical rating of PHS is about 1000 MW (100-3000 MW), and facilities continue to be installed worldwide at a rate of up to 5 GW per year. The rating of PHS is the highest all over the available ESS, hence it is generally applied for energy management, frequency control, and provision of reserve. Since the first use in Italy and Switzerland in the 1890s and the first large-scale commercial application in the United States in 1929 (Rocky River PHS plant, Hartford), there are now over 200 units and 100 GW of PHS in operation worldwide (Ahearne, 2004; Linden, 2003) (32 GW installed in Europe, 21 GW in Japan, 19.5 GW in the United States, and others in Asia and Latin America), which is about 3% of global generation capacity (ESA, 2009). Pumped storage is the most widespread energy storage system in use on power networks. Its main applications are for energy management, frequency control, and provision of reserve.

4.5.5.1.4 Advantages/Disadvantages

PHS is a mature technology with large volume, long storage period, high efficiency, and relatively low capital cost per unit of energy. Owing to the small evaporation and penetration, the storage period of PHS can be varied, from typically hours to days and even years. Taking into account the evaporation and conversion losses, 71-85% of the electrical energy used to pump the water into the elevated reservoir can be regained.

The major drawback of PHS lies in the scarcity of available sites for two large reservoirs and one or two dams. Long lead time (typically 10 years) and high cost (typically hundreds to thousands of million US dollars) for construction and environmental issues (e.g., removing trees and vegetation from the large amounts of land prior to the reservoir being flooded) (Denholm et al., 2004; Denholm and Holloway, 2005) are the other three major constraints in the deployment of PHS. Many pumped hydroelectric systems can have negative impacts on land and wildlife. Disruption of fish spawning routes or creation of large reservoirs that fill canyons or gorges are common concerns. In general, in geographically flat places, PHS may be difficult to use or may not be used at all.

The construction of PHS systems inevitably involves destruction of trees and green land for building reservoirs. The construction of reservoirs could also change the local ecological system, which may have environmental consequences.

4.5.5.1.5 Commercial Maturity

PHS is a matured technology and has been in use for more than 100 years. Pump hydroelectricity installations that are 1000 MW and larger are shown in Table 4.5.

4.5.5.1.6 Cost

Capital cost is one of the most important factors for the industrial take-up of the ESS. It is expressed in terms of cost per kW, per kWh, and per kWh per cycle. All the costs per unit energy shown here have been divided by the storage efficiency to obtain the cost per unit of output energy. The per-cycle cost is defined as the cost per unit energy divided by the cycle life, which is one of the best ways to evaluate the cost of energy storage in a frequent charge/discharge application such as load leveling. The costs of operation and maintenance, disposal, replacement, and other ownership expenses are not considered, because they are not available for some emerging technologies (Haisheng et al., 2009).

4.5.5.1.7 Developers/Suppliers

MWH

Corporate Headquarters

380 Interlocken Crescent

Suite 200, Broomfield, Colorado USA 80021

4.5.5.2.1 Process Description

Off-peak electricity is used to power a motor/generator that drives compressors to force air into an underground storage reservoir. Figure 4.12 shows a schematic diagram of a CAES system (Jewitt, 2005; McDowall, 2004). It consists of five major components: (1) a motor/generator that employs clutches to provide alternate engagement to the compressor or turbine trains; (2) an air compressor of two or more stages with intercoolers and aftercoolers, to achieve economy of compression and reduce the moisture content of the compressed air; (3) a turbine train, containing both high- and low-pressure turbines; (4) a cavity/container for storing compressed air, which can be underground rock caverns created by excavating comparatively hard and impervious rock formations, salt caverns created by solution- or dry-mining of salt formations, and porous media reservoirs made by water-bearing aquifers or depleted gas or oil fields (e.g., sandstone and fissured lime); and (5) equipment controls and auxiliaries such as fuel storage and heat exchanger units.

CAES works on the basis of conventional gas turbine generation. It decouples the compression and expansion cycles of a conventional gas turbine into two separated processes and stores the energy in the form of elastic potential energy of compressed air (Haisheng et al., 2009). During low demand, electrical energy is stored by compressing air into an airtight space, typically 4.0-8.0 MPa. To extract the stored electrical energy, compressed air is withdrawn from the storage vessel, heated, and then expanded through a high-pressure turbine. Thus, it captures some of the energy in the compressed air. The air is then mixed with fuel and combusted with the exhaust-expanded air through a low-pressure turbine. Both the high- and low-pressure turbines are connected to a generator to produce electricity.

4.5.5.2.2 Performance Characteristics

• The self-discharge (energy dissipation) per day for CAES has a very small self-discharge ratio, so it is suitable for a long storage period.

• CAES has a cycle efficiency of 60-90%.

• CAES has medium energy density.

• CAES has a long cycle life. This technology is based on conventional mechanical engineering, and the lifetime is mainly determined by the lifetime of the mechanical components.

4.5.5.2.3 Applications

The concept of CAES to help generate electricity is more than 30 years old. Two plants currently exist: an 11-year-old plant (110 MW) in McIntosh, Alabama, and a 23-year-old plant (290 MW) in Germany, both in caverns created by salt deposits. The construction took 30 months and cost $65 M (about $591/kW). It takes about 1.5-2 years to create such a cavern by dissolving salt. This unit comes on line within 14 min. The third commercial CAES, the largest ever, is a 2700 MW plant that is planned for construction in Norton, Ohio. This 9-unit plant will compress air to 1500 psi in an existing limestone mine some 2200 ft underground.

4.5.5.2.4 Advantages/Disadvantages

In a conventional power plant, nearly two-thirds of the natural gas is consumed by a typical natural gas turbine because the gas is used to drive the machine's compressor. In contrast, a compressed air storage plant uses low-cost heated compressed air to power the turbines and create off-peak electricity, conserving some natural gas.

However, compressed air has safety concerns, mainly the catastrophic rupture of the tank. Highly conservative safety codes make this a rare occurrence at the trade-off of higher weight. Codes may limit the legal working pressure to less than 40% of the rupture pressure for steel bottles (safety factor of 2.5), and less than 20% for fiber-wound bottles (safety factor of 5).

CAES is based on conventional gas turbine technology and involves combustion of fossil fuel, hence emissions can be an environmental concern.

4.5.5.2.5 Commercial Maturity

CAES is a developed technology and is commercially available. However, the actual applications, especially for large-scale utility, are still not widespread. Their competitiveness and reliability still need more trials by the electricity industry and the market.

4.5.5.2.6 Cost

Capital cost is one of the most important factors for the industrial take-up of the ESS. It is expressed in terms of cost per kW, per kWh, and per kWh per cycle. The costs of operation and maintenance, disposal, replacement, and other ownership expenses are not considered, because they are not available for some emerging technologies (Haisheng et al., 2009).

4.5.5.2.7 Developers/Suppliers

CAES Development Company

Dresser-Rand Company

Energy Storage and Power LLC

Ridge Energy Storage

4.5.5.3.1 Main Features of Vanadium Flow Batteries

The main features of the VRB are shown in Figure 4.13. The cell consists of two compartments separated by a proton exchange membrane that allows protons (H⁺ ions) to pass but prevents vanadium ions from passing through the membrane. The electrolyte on each side consists of vanadium dissolved in a sulfuric acid solution of concentration 2-3 M. At one electrode, V^4 + ion is converted into V^5 + ion during discharge of the cell, releasing an electron that is transferred to the electrode in the second compartment, where V^3 + ion is converted into V^2 + ion with the absorption of an electron. The membrane prevents cross mixing of the electrolytes. Each side of the cell contains an inert electrode made of highly porous carbon felt. The electrolytes, both anolyte and catholyte, are stored in two large external reservoirs. The rechargeable electrolyte is pumped through the inert electrode, where the electrochemical reactions occur.

During charging, electrochemical reactions within the battery stack change the valence of the vanadium, the negative reaction change V(III) to V(II), and the positive reaction change V(IV) to V(V). This process is reversed during the discharge cycle.

In the vanadium redox cell, the following half-cell reactions are involved:

At the negative electrode:

${\mathrm{V}}^{3+}+{\mathrm{e}}^{-}\Rightarrow {\mathrm{V}}^{2+}E°=-0.26\mathrm{V}$

At the positive electrode:

${\mathrm{V}\mathrm{O}}^{2+}+2{\mathrm{H}}^{+}+{\mathrm{e}}^{-}\Rightarrow {{\mathrm{V}\mathrm{O}}_2}^{+}+{\mathrm{H}}_2\mathrm{O}E°=1.00\mathrm{V}$

This gives a standard cell potential E° (cell) = 1.26 V at concentrations of 1 mol per liter and at 25 °C. Under actual cell conditions, an open-circuit cell voltage of 1.4 V is observed at 50% state of charge (SOC), while a fully charged cell produces more than 1.6 V at open circuit. The electrolyte for the vanadium battery is 2 M vanadium sulfate in 2.5 M H₂SO₄, the vanadium sulfate (initially 1 M V (III) + 1 M V (IV)) being prepared by chemical reduction or electrolytic dissolution of V₂O₅ powder.

The stability of the electrolyte is affected by the operating temperature, SOC, vanadium concentrations, sulfuric acid concentrations, and so on.

A stack of these energy-producing cells can be connected in series in a bipolar manner. The physical size of the battery stack determines the power kW available from the battery, and the volume of the electrolyte in the reservoirs determines the kWh energy storage of the battery (Rahman and Skyllas-Kazacos, 2000).

4.5.5.3.2 Performance Characteristics

Cell lifetimes are expected to be up to 10 years, though cells have run for up to 14,000 cycles. A VRB can be refurbished by replacing the cell stack alone. The reagents and storage tanks should be reusable. During operation, round-trip efficiency is about 75%. Units can run up from zero to full power in several milliseconds. However, other equipment associated with the cell may limit its response time to around 20 mS. A unit can provide instant pulses of energy without the reservoir pumps running, provided it is charged. Charged units can supply up to five times the rated output for limited periods.

4.5.5.3.3 Advantages

The VRB system offers many advantages over conventional LA batteries.

• It has very high efficiency.

• It has reasonable energy density.

• It has high charge/discharge rates.

• It has a long lifespan, independent of state-of-charge and load profiles.

• Instant recharge is possible by replacing the discharged electrolyte with fresh-charged solution, or the solution can be electrically recharged at high rates about 8-10 times faster than for LA batteries.

• The capacity of the battery can be simply increased by adding extra electrolyte to the reservoirs.

• The system can be fully discharged with no adverse effects to the battery.

• The solution life is indefinite and can be recycled continuously, so replacement costs are low and there are no waste disposal problems.

• The vanadium battery system is considered environmentally friendly.

• It requires low maintenance.

• The shelf life is theoretically unlimited.

The battery is insensitive to atmospheric oxygen, has a high 1.4 V cell voltage, and the electrolytes are not mutually destructive. The battery stack electrochemical reactions are all highly efficient with the energy, with efficiencies ranging from 75 to 80%. An accurate state-of-charge determination is possible by measuring the potential of a small open-circuit cell attached to the battery, with some portion of the electrolytes being pumped through it. No complex solid phase changes are involved during charging and discharging, which lead to shedding or shorting in conventional batteries.

Redox flow batteries, and to a lesser extent hybrid flow batteries, have the advantages of flexible layout (due to separation of the power and energy components), long cycle life (because there are no solid-solid phase changes), quick response times (similar to nearly all batteries), no need for “equalization” charging, and no harmful emissions (similar to nearly all batteries). Some types also offer easy state-of-charge determination (through voltage dependence on charge), low maintenance, and tolerance to overcharge/overdischarge.

Additionally, this battery has a feature that allows for some new options not available with LA technology. It is possible to simultaneously charge the battery at one voltage while discharging it at another voltage. This feature can be utilized to make a minimum cost, high efficiency, and maximum power point tracker, or allow the battery to operate as a DC transformer, electrochemically transforming a current and a voltage into a different current and voltage.

Significant interest has been observed recently in VRB system research and applications in different countries. In 2002, a research and development laboratory for VRB was established in Central South University in China with the financial support of Panzhihua Steel Corporation (Huang et al., 2008). Vetter et al. (2010) reported research activities on various redox flow batteries, including VRB, at Fraunhofer Institute for Solar Energy Systems (ISE), Heidenhofstraße, Freiburg, Germany.

Vanadium redox flow battery energy storage research and development work has made new progress. Dalian Institute of Chemical Physics, Chinese Academy of Sciences recently initiated vanadium redox flow battery energy storage research and development to achieve new progress in the successful development of a 1 kW-class vanadium redox flow battery from the storage battery module composed of a 10 kW-class battery system, based on the successfully developed 5 kW all-vanadium flow storage battery module. The module is running stable, with energy efficiency of 78% (Miller, 2009).

4.5.5.3.4 Disadvantages

On the negative side, flow batteries are rather complicated in comparison with standard batteries, as they may require pumps, sensors, control units, and secondary containment vessels. The energy densities vary considerably but are, in general, rather low compared to portable batteries, such as the Li-ion.

4.5.5.3.5 Use of Local Raw Materials

One of the main components of VRB is vanadium electrolyte prepared in 2-3 M sulfuric acid solution. This will utilize sulfur or in turn sulfuric acid as a local raw material. Another component is the conducting polymer that is used in the electrode material.

4.5.5.3.6 Commercialization Status of VRB

Several demonstration VRBs of various sizes have been evaluated in Australia, Japan, and Thailand, where atmospheric temperature does not exceed 40 °C. Vanadium electrolyte optimization studies are being performed to improve the stability of the electrolyte at higher temperatures (Rahman et al., 1996, 2004; Rahman, 1998; Rahman and Skyllas, 1998; Rahman and Skyllas-Kazacos, 2009).

A 5 kW/13kWh vanadium battery system has been installed in a solar demonstration house in collaboration with the Centre for Photovoltaic Devices and Systems, UNSW, and Thai Gypsum Products Co. Ltd., Thailand, and its suitability for application in energy self-sufficient remote housing has been evaluated. Another vanadium battery of 4.1 kW peak power and 3.9 kWh capacity has recently been evaluated as a submarine backup battery for the Department of Defense in Australia, while a golf cart with the 5 kW battery stack mounted on the back and electrolyte tanks under the seat has been undergoing testing at UNSW since 1994. Extensive off-road trials of this battery showed excellent performance over a range of terrains. With 40 l of 1.85 M vanadium electrolyte per half-cell tank, a driving range of 17 km was obtained. The total driving range expected for 3 M vanadium solutions and full tanks containing 60 l each side, therefore, is around 40 km (Menictas et al., 1994).

In 1997, a 200 kW/800 kWh grid-connected vanadium battery was commissioned at the Kashima-Kita Electric Power station in Japan, where it is currently undergoing long-term testing as a load-leveling system. By the beginning of 1998, it had already undergone 150 charge-discharge cycles and was continuing to show high energy efficiencies of close to 80% at current densities of 80-100 mA/cm².

Skyllas-Kazacos and Kazacos (2009) reported that VRB technology has been technically proven in systems up to 6 MWh; its more widespread commercialization in large grid-connected applications necessitated further cost reductions in membrane materials, cell stack design, and control systems. Brief information about several VRB units currently under evaluation by Sumitomo is given below.

Substation Demonstration System (Load leveling DC 450 kW × 2 h)
This demonstration system installed in Tatsumi Substation of the Kansai Electric Power Co., Inc. is linked to the commercial systems. The large amount of demonstration data obtained through this system has become the basis of the present systems. (Operation start: Dec. 1996)

System for Office Building (Load Leveling AC 100 kW × 8 h)
The system is installed in the head office building of Sumitomo Densetsu Co., Ltd. The electrolyte tank is installed in an underground cistern (dead space). (Operation start: Feb. 2000)

Wind Power Generation Output Stabilization: (Output Stabilization AC 170 kW × 6 h)
The facilities were delivered to NEDO and IAE for the demonstration testing of wind power generation output stabilization. The facilities were constructed next to the wind power generator of Hokkaido Electric Power Co., Ltd. (Operation start: Mar. 2001)

Voltage Sag Protection (Voltage Sag Protection AC 3000kW × 1.5 s; Load Leveling AC 1500 kW × 1 h)
This ESS is constructed for the liquid crystal plant of Tottori SANYO Electric Co., Ltd. When instantaneous voltage sag is caused by lightning or other causes, the system protects low voltage and prevents the manufacturing line from stopping. Under normal conditions, load-leveling operation is conducted. (Operation start: Apr. 2001)

PowerPedia: Vanadium Redox Batteries (2009)
The extremely large capacities possible from vanadium redox batteries make them well suited to use in large power storage applications, helping to average out the production of highly variable generation sources such as wind or solar power, or to help generators cope with large surges in demand. Their extremely rapid response times also make them superbly well suited to UPS-type applications, where they can be used to replace LA batteries and even diesel generators.

Currently installed vanadium batteries include

• A 1.5 MW UPS system in a semiconductor fabrication plant in Japan

• A 275 kW output balancer in use on a wind power project in the Tomari Wind Hills of Hokkaido

• A 200 kW, 800kWh output leveler in use at the Huxley Hill Wind Farm on King Island, Tasmania

• A 250 kW, 2 MWh load leveler in use at Castle Valley, Utah

4.5.5.3.7 Cost

Cost estimates of VRBs by the UNSW group and independent consulting groups place mass production costs between $300 and $500 per kW for the cell stack and $30-50 per kWh for the electrolyte (Skyllas-Kazacos, 2006; Hennessy, 2008). It should be noted that apart from cost, the VRB has some additional advantages that were previously discussed. Variation in capital cost of VRBs with storage time is illustrated in Figure 4.14, and a comparison of cost of energy ($/MWh) for VRBs and LA batteries is shown in Figure 4.15. The important feature of this graph is that the cost of each kWh generated by the VRB over its life is considerably lower than that provided by LA batteries for storage times in excess of 1.5 h. This confirms the significant cost benefit of the VRB in applications that require long storage times.

(Total battery costs per kWh versus storage time for stack cost of $AUD 500/kW and V₂O₅ price of $US5/lb)

An NaS battery consists of liquid (molten) sulfur at the positive electrode and liquid (molten) sodium at the negative electrode as active materials. They are separated by a solid beta alumina ceramic electrolyte (see Figure 4.16). The electrolyte allows only the positive sodium ions to go through it and combines with sulfur to form sodium polysulfides according to the following reaction (ESA, 2009):

$2\mathrm{N}\mathrm{a}+4\mathrm{S}\to {\mathrm{N}\mathrm{a}}_2{\mathrm{S}}_4$

The NGK design for the NaS battery is cylindrical. In the center is a pool of molten sodium, which is maintained in a molten state by keeping the cell temperature around 300-350 °C. This pool is contained and surrounded by a cylindrical tube of solid electrolyte, a material called beta alumina, which is surrounded by molten sulfur and the cell container. During discharge, sodium atoms give up electrons to the sodium electrode, becoming sodium ions, which then migrate through the solid beta alumina to the sulfur, where they react to form NaS compounds with the take-up of electrons. Cell reactions are reversed during charging, regenerating the liquid sodium and the liquid sulfur. Open circuit voltage for this cell remains constant for up to 75% of the discharge. The cell is capable of providing short-term currents of up to five times its rated output.

The typical energy and power density of NaS batteries are in the range of 150-240 W/kg. They have a typical cycle life of 2500 cycles. NaS battery cells are efficient (75-90%) and have a pulse power capability over six times their continuous rating (for 30 s). This attribute enables NaS batteries to be economically used in combined power quality and peak shaving applications (Chen et al., 2009).

4.5.5.4.2 Advantages/Disadvantages

The NaS battery is unique among secondary cells in using a solid electrolyte. The cell operates at a high temperature, which enhances transport of ions through the solid. It has up to three times the energy density of a LA battery, its lifetime is longer, and it requires little maintenance. It can utilize sulfur, which is a disposal problem in Saudi Arabia.

The major drawback is that a heat source is required, which uses the battery's own stored energy. This partially reducing battery performance, because the NaS battery needs to operate at a high temperature (300-350 °C), as previously mentioned. High-temperature operation is more costly than operating at ambient temperature, but this cell has several advantages that may outweigh the additional operating costs.

4.5.5.4.3 Cost

Initial capital cost is another issue ($2000/kW and $350/kWh), but it is expected to fall as the manufacturing capacity is expanding.

4.5.5.4.4 Developers/Suppliers and Deployment Status

NaS battery is an advanced secondary battery that was developed by Tokyo Electric Power Company (TEPCO) and NGK Insulators, Ltd. in 1983 (Kamibayashi and Tanaka, 2001). Feasibility studies of various demonstration projects show that the NAS battery technology is attractive for use in relatively large-scale battery energy storage system applications due to its outstanding energy density, efficiency, and zero maintenance.

Typical NaS battery modules developed by NGK have a rated power of 50 kW and rated capacity of 360-430 kWh. A 50 kW unit can supply 100 kW for 2 h and 250 kW for 30 s. The typical rated lifetime is 15 years or 4500 cycles to 90% capacity. DC-DC efficiency is 85%. A NaS module can reach full power output in 1mS. When in standby, a 50 kW unit uses 2-3 kW to maintain its temperature. Table 4.6 shows NaS batteries deployed at various locations in Japan.

NaS battery technology has been demonstrated at more than 190 sites in Japan, totaling more than 270 MW with stored energy suitable for 6 h daily peak shaving. The largest NaS installation is a 34 MW, 245 MWh unit for wind stabilization in Northern Japan. US utilities have deployed 9MW battery for peak shaving, backup power, firming wind capacity, and other applications, and project development is in progress for an amount equal to Japan's.

The demand for NaS batteries as an effective means of stabilizing renewable energy output and providing ancillary services is expanding. Several projects are under development in Europe, as well as in Japan and the United States. The annual production capacity is 90 MW, 150 MW, planned in 2010 (ESA, 2009).

Efforts are being made to reduce the operating temperature of the NaS battery. Inside Ceramatec's wonder battery is a chunk of solid sodium metal mated to a sulfur compound by an extraordinary, paper-thin ceramic membrane. The membrane conducts ions—electrically charged particles—back and forth to generate a current. The company calculates that the battery will cram 20-40 kWh of energy into a package about the size of a refrigerator, and operate below 90 °C.

NiCd batteries consists of a positive electrode plate made up of nickel hydroxide, a cadmium hydroxide negative electrode plate, a separator, and an alkaline electrolyte. NiCd batteries generally have a metal case with a sealing plate equipped with a self-sealing safety valve. The positive and negative electrode plates, isolated from each other by the separator, are rolled in a spiral shape inside the case. Ni-Cd batteries rank alongside LA batteries in terms of their commercial maturity (~ 100 years) and popularity.

The chemical reaction is

$2\mathrm{N}\mathrm{i}\mathrm{O}\left(\mathrm{O}\mathrm{H}\right)+\mathrm{C}\mathrm{d}+2{\mathrm{H}}_2\mathrm{O}\leftrightarrow 2\mathrm{N}\mathrm{i}{\left(\mathrm{O}\mathrm{H}\right)}_2+\mathrm{C}\mathrm{d}{\left(\mathrm{O}\mathrm{H}\right)}_2$

4.5.5.5.2 Performance Characteristics

The efficiency of a Ni-Cd battery is around 70% for DC-to-DC, although others in the family can provide efficiencies as high as 85%. The cells will self-discharge more rapidly than LA batteries will, and can lose up to 5% of their charge per month. Their lifetime varies, depending on the type of duty for which they are used. With low levels of discharge, Ni-Cd cells can operate for up to 50,000 cycles. Typical cells are rated for lifetimes of 10-15 years but can operate for longer. This drops, however, if the operating temperature becomes elevated. However, they are good for operations at low temperatures.

4.5.5.5.3 Cost

Ni-Cd battery system costs are expected to be higher than the cost of LA batteries because the cells themselves are more expensive. The Fairbanks battery energy storage plant costs around $30 m for a plant with a rated power of 27 MW, providing a unit cost of $1110/kW. EPRI-DOE estimates suggest that in 2003, the cost per kWh for batteries was around $1200/kWh for a 5 MW plant, while total plant cost was $1780/kW. This is significantly higher than the estimated cost of LA cells previously quoted.

4.5.5.5.4 Advantages/Disadvantages

NiCd batteries are robust and reliable, and they have reasonable energy density (50-75 Wh/kg) and very low maintenance requirements, but relatively low cycle life (2000-2500). These advantages over LA batteries make them favored for power tools, portable devices, emergency lighting, UPS, telecoms, and generator starting. However, over the past decade, portable devices such as mobile telephones, tablets, and laptops have been effectively displaced from these markets by other electrochemistries.

The main drawback of NiCd batteries is their relatively high cost (~$1000/kWh), due to the expensive manufacturing process. Besides, cadmium is a toxic heavy metal and has issues associated with the disposal of Cd from waste NiCd batteries. NiCd batteries also suffer from the “memory effect,” where the batteries will only take full charge after a series of full discharges. Proper battery management procedures can help mitigate this effect.

4.5.5.5.5 Developers/Suppliers and Deployment Status

The NiCd system is the “world's largest (most powerful) battery,” installed at Golden Valley, Fairbanks, Alaska, United States (Breeze, 2009). The system is rated at 27 MW for 15 min, 40 MW for 7 min, and with an ultimate 46 MVA limitation imposed by the power converter. The batteries are expected to perform 100 complete and 500 partial discharges in the system's 20-year design life. The system provides critical spinning reserve functionality in what is effectively an “electrical island.”

LA batteries, invented in 1859, are the oldest and most widely used rechargeable electrochemical devices. A LA battery consists of (in the charged state) electrodes of lead metal and lead oxide in an electrolyte of about 37% (5.99 M) sulfuric acid.

The chemical reactions are (charged to discharged)

Anode (oxidation):

$\mathrm{P}\mathrm{b}\left(\mathrm{s}\right)+{{\mathrm{H}\mathrm{S}\mathrm{O}}_4}^{-}\left(\mathrm{a}\mathrm{q}\right)+{\mathrm{H}}_2\mathrm{O}\left(\mathrm{l}\right)\leftrightarrow {\mathrm{PbSO}}_4\left(\mathrm{s}\right)+{\mathrm{H}}_3{\mathrm{O}}^{+}\left(\mathrm{a}\mathrm{q}\right)+2{\mathrm{e}}^{-}E°=-0.356\mathrm{V}$

Cathode (reduction):

${\mathrm{P}\mathrm{b}\mathrm{O}}_2\left(\mathrm{s}\right)+3{\mathrm{H}}_3{\mathrm{O}}^{+}\left(\mathrm{a}\mathrm{q}\right)+{{\mathrm{H}\mathrm{S}\mathrm{O}}_4}^{-}\left(\mathrm{a}\mathrm{q}\right)+2{\mathrm{e}}^{-}\leftrightarrow {\mathrm{PbSO}}_4\left(\mathrm{s}\right)+5{\mathrm{H}}_2\mathrm{O}\left(\mathrm{l}\right)E°=1.685\mathrm{V}$

Because of the open cells with liquid electrolyte in most LA batteries, overcharging with excessive charging voltages will generate oxygen and hydrogen gas by electrolysis of water, forming an explosive mix. The acid electrolyte is also corrosive.

The cell reaction in a LA battery involves lead (Pb), lead oxide (PbO₂), and sulfuric acid (H₂SO₄). One electrode of the cell is composed of lead oxide and the other of lead (usually in an alloy form to make it more tractable). During discharge of the cell, lead dissolves into the electrolyte at one electrode, releasing electrons that are transferred to the second electrode via an external circuit, where they are taken up by lead oxide, which also thereby dissolves into the sulfuric acid electrolyte. This depletes the active material on both the electrodes and the concentration of the sulfuric acid, and eventually the cell can produce no more electricity. Charging the cell reverses both these processes, depositing lead on one electrode and lead oxide on the other, while regenerating the sulfuric acid.

4.5.5.6.2 Performance Characteristics

Efficiency of LA batteries depends on a number of factors, including temperature variation and depth of charge. Typical efficiencies range between 75% and 85% for DC-DC cycling. Cells will lose charge over time due to a small but significant electrical conductivity of the electrolyte. This will increase with temperature, increasing the self-discharge rate. At low temperatures, performance will drop off too, with capacity falling as the temperature falls. At very low temperatures the electrolyte can freeze, so the optimum temperature of operation is 25 °C. The typical lifetime for a LA battery is around 5 years or up to 1000 charge-discharge cycles, though this depends on the way the cells are used. Batteries designed for utility applications can have lifetimes of 15-30 years.

There are several types of LA batteries, including the flooded battery requiring regular topping up with distilled water, the sealed maintenance-free battery having a gelled/absorbed electrolyte, and the valve-regulated battery. It is a popular storage choice for power quality, UPS, and some spinning reserve applications. Its application for energy management, however, has been very limited due to its short cycle life (500-1000 cycles) and low energy density (30-50 Wh/kg) due to the inherently high density of lead.

4.5.5.6.3 Cost

The current cost of utility-scale LA battery facilities is a matter for conjecture. Recent estimates suggest that such plants can be built for $200-580/kW. However, the costs for the plants in Table 4.7 were between $1100 and $1800/kW, significantly higher. All the plants in the table were first-of-kind designs, and costs might be expected to be high. More significant for a storage plant is the cost per kWh. For the plants listed in Table 4.7, this was between $456 and $1574/kWh, an extremely wide range that probably again reflects their first-of-kind status. More recent cost estimates obtained by EPRI-DOE, based on 2003 prices, suggest that costs were between $320 and $1260/kW for the batteries and basic interconnections and racks. The power converter system added a further $150-220/kW and balance of plant another $100/kW, putting the total cost between $570 and $1580/kW. The estimated cost/kWh for systems with capacities of 10 MW, 10 MWh and 10 MW, 40 MWh in 2003 was $590/kWh and $393/kWh.

4.5.5.6.4 Advantages/Disadvantages

LA batteries have high reliability. One of the major problems with LA batteries is that they produce hydrogen and oxygen during charging (by electrolysis of water), once the charging voltage exceeds a certain value. Because a rise in voltage is inevitable as the cell charges, the generation of gas cannot be avoided. Some cell designs simply allow the gas to escape. Such cells are normally called flooded cells because the electrodes are “flooded” with sulfuric acid electrolyte, and the water level is topped up regularly to take account of the loss through electrolysis. The alternative is the valve-regulated LA cell, sometimes also called the sealed LA cell. These use special design features to encourage the hydrogen and oxygen generated by the cell to recombine into water, while releasing any excess gas that does not recombine through a control valve. LA batteries also have a poor low-temperature performance, and therefore require a thermal management system.

4.5.5.6.5 Developers/Suppliers and Deployment Status

GNB Industrial Power/Exide

Delco

East Penn

Teledyne

Optima Batteries

Winston Salem

JCI Battery Group

Trojan

Crown Battery

A number of large-scale LA battery-based utility storage plants have been built, though none recently. Details of these are collected in Table 4.7. The earliest modern LA storage plant was built by the Berlin utility BEWAG to provide peak power and grid support on what was then an island grid in West Berlin. This unit has a rated power of 8.5 MW, which it could supply for up to 1 h. Output could be doubled to 15 MW, but this could only be maintained for 20 min. The plant operated successfully, with few problems. The largest one is a 40 MWh system in Chino, California (USA), which works with a rated power of 10 MW for 4 h (Moore and Douglas, 2006).