Turlock AB 2514 California Energy Storage

Notes from 29 page: Turlock Irrigation district Energy Storage Study. 2014. Willie G. Manuel 9/17/2014

Recommendation. The analysis performed shows that the benefits of deploying various types of storage systems fall short of the capital cost of such systems. Furthermore, except for pumped storage systems, there is limited operational history on utility scale storage systems. Hence there is limited data on performance degradation, operation and maintenance expense, and the life of storage systems in utility applications. Given that the analysis show that storage systems are currently not cost effective and that there is limited operating history, staff recommends that the Board make a determination that it is not appropriate to adopt energy storage procurement targets at this time.

Li-on batteries typically have a life of 15-20 years and round trip efficiencies of about 83%.

This battery technology is currently the fastest growing segment for stationary storage

applications. They have been deployed in a wide range of utility energy-storage applications, ranging from a few kilowatt-hours in residential systems with rooftop photovoltaic arrays to multi-megawatt containerized batteries for the provision of grid ancillary services. Currently there are roughly 83 MW of Li-on based storage systems in operation in the United States.

Sodium sulfur batteries (“NAS”) use electrochemical reactions between sodium and molten sulfur to charge and discharge. They operate at fairly high temperature of about 300-350oC, are highly corrosive, have low power-to-energy ratios, life of 15 years, and round trip efficiencies of about 75%. There are currently 12 MW of NAS batteries that have been installed by U.S.utilities with about another 9 MW in-progress. Globally, there is 316 MW of NAS installed to date.

Flow batteries use a liquid electrolyte and an electrochemical cell to store/generate electricity. The liquid electrolyte is stored externally and pumped through the cell. This allows the energy capacity of the battery to be increased at a moderate cost making them suitable for long duration applications. These types of batteries are expected to last about 15 years and have round trip efficiencies of 70-80%. Relative to integrated battery technologies such as the Li-on and NAS, flow batteries tend to have a larger footprint due to the need for flow system components. Historically, flow batteries can experience irreversible capacity loss over time and thus have not been widely used.

The vanadium redox system is the more mature type of flow battery. In the United States, there is a total of 1 MW of flow battery based storage systems operational.

Some of the key advantages of flywheel energy storage are low maintenance, long life (some flywheels are capable of well over 100,000 full depth of discharge cycles and the newest configurations are capable of greater than 175,000 full depth of discharge cycles), and negligible environmental impact. They have high energy density and substantial durability whichallows them to be cycled frequently with no impact to performance. They also have very fast response and ramp rates. They generally can respond to regulation signals in milliseconds and can go from full discharge to full charge within a few seconds or less. Round trip efficiencies are between 70-80%. Flywheel energy storage systems (FESS) are well suited for high power, relatively low energy applications such as power quality maintenance and frequency response.

There are two flywheel installations operating in the United States for a combined total of 32 MW.

Compressed air energy storage (“CAES”) has been used since the 1870’s. However, the first utility scale deployment came online in the 1970’s. CAES stores energy by compressing and storing ambient air under pressure (typically at 1,015 psia) in an underground cavern or above ground pressure vessels or pipes. To generate electricity, the pressurized air is heated and expanded in a turbine that drives a generator.

There are currently only two operating utility sized CAES plants, the 321 MW plant in Huntorf, Germany (operating since December 1978) and the 110 MW plant in McIntosh, Alabama (with 18 years of operating history). These systems typically have round trip efficiencies of 42-55%.

Salt caverns in deep salt formations have traditionally been used. The use of natural aquifers and depleted natural gas fields are currently being studied. 3.4.

Thermal 3.4.1. Ice Thermal Ice storage supplements existing HVAC systems by creating ice during the off-peak periods which is then used during the on-peak periods to reduce the cooling load of the HVAC system.

There are currently 36 MW of ice storage systems online in the United States. These systems are designed to last 20-25 years.

Solar Thermal Solar thermal power plants store energy by heating a medium (typically oil or molten salt) to store thermal energy and later using such medium to generate steam that drives a turbine to produce electricity. In 2013 the 280 MW Solana Generation Station in Arizona came online. The project consists of a concentrated solar plant using parabolic trough coupled with six hours of storage capacity using molten salt. The 150 MW Rice Solar Energy Project to be located in Riverside County, CA also will consist of a concentrated solar plant coupled with molten salt thermal storage. The project is expected to be online in 2016.

Pumped Hydro Pumped hydro is one of the most established energy storage technologies and has been used since the 1920s. Energy storage is achieved by pumping water uphill (typically during the off-peak low energy cost periods) to an upper reservoir. When energy is needed the water pumped uphill is released and allowed to flow downhill through a hydro turbine. Pumped storage power plants are unlike traditional hydroelectric power plants in that they are a net consumer of electricity, due to hydraulic and electrical losses incurred in the cycle of pumping from lower to upper reservoirs. These plants typically have round-trip efficiencies of 76-85%.

Time-of-Day Arbitrage In this application, the storage device is charged during periods when electricity prices are lower (generally during the off-peak periods) and discharged during periods when electricity prices are higher (generally during the on-peak periods). This application also allows for efficient operations of baseload generation resources. Often baseload generation has to be operated at less efficient output levels during the off-peak periods. Installing a storage system may allow a baseload generation to generate at a higher output (more efficient) level during the off-peak periods resulting in fuel cost savings.

Peak Capacity. A storage system can be used to serve peak load and thus reducing the need for capacity from traditional generating resources. In this application, the storage system is charged in low load periods and discharged during the high load periods. This is somewhat similar to the previous application since generally low electricity prices occur during the low load (off-peak) periods and high electricity prices occur during the high load (on-peak) periods. This application also allows for efficient operations of baseload generation.

Ancillary Service. Western Electricity Coordinating Council (“WECC”) regulations require us to maintain minimum operating reserves that consist of regulating, spinning, and non-spinning reserves. Storage systems could be used to provide regulation, spinning, and non-spinning reserves and therefore freeing up capacity on existing generating resources for other uses such as power sales or reducing the need for additional generating capacity.

Load Following and Renewable Integration. In order to balance supply and demand, generator output is constantly varied to match demand. At TID, generally the output of Don Pedro or Walnut Energy Center (“WEC”) is varied up or down in order to balance the system. The constant movement of output puts additional wear and tear on the power plants particularly thermal units such as WEC.

Storage systems can be used to assist in balancing system supply and demand. The presence of intermittent resources (such as wind or solar) in a system presents additional challenges to balance supply and demand in an electric system. Storage systems can be located at or near intermittent resources to smooth the output from the intermittent resource prior to it entering the electric system thereby reducing system imbalance.

Voltage Support Storage systems could be used to assist in maintaining the electric grid’s voltage in lieu of traditional tools such as generators, capacitors, and voltage regulators.

Black Start. During catastrophic grid failures, a storage system can be used to energize the grid and provide station power so power plants can be brought back on-line. In this application, the storage system is charged and remains charged until a grid failure occurs.

Transmission and Distribution Upgrade Deferral. Transmission and distribution (“T&D”) facilities generally do not operate close to their capacity. In most cases the load on a T&D facility only approach capacity limits a few hours a year. Rather than increasing the capacity of the T&D facility that is reaching its limits, a storage device could be used to serve a portion of the load during the few peak hours in a year thereby delaying and possibly avoiding T&D upgrades. Hence, installing a storage system allows the T&D capacity to be optimized and could extend the life of the T&D facilities since the facility is not subjected to higher loading. Storage systems could also be designed to be mobile and therefore could be move around an electric utility system where it is needed. For example, a storage system could be installed to defer upgrades to a substation. Once that substation is eventually upgraded the storage system could then be moved to another substation.

Lithium-Ion Battery (without Regulation Reserve Sales) In this scenario we model a 30 MW Lithium Ion battery (“30 MW Li-on”) with 2 hour duration that can provide capacity, energy, regulation, spinning reserve, and non-spinning reserve. Sales of energy, spinning reserves, andnon-spinning reserves from TID’s generation resources and the storage system are permitted in this scenario. However, sales of regulation reserves are not permitted which reflects current operations. Below are the assumptions used for the 30 MW Lion: Technology Lithium Ion Capacity 30 MW Duration 2 Hours Capital Cost $1,800/kW ($900/kWh) Fixed O&M Cost $10/kW-yr Variable O&M Cost $0.3/MWh Project Life 20 years Battery Replacement Cost $244/kWh Battery Replacement Yr of Occurrence 11th year Roundtrip Efficiency 83% Debt Interest Rate (20 Yr Term) 4% Debt Interest Rate (10 Yr Term) 3% O&M Escalation Rate 2%/yr

As shown in Chart 1 below, adding a 30 MW Li-on into TID’s resource portfolio increases TID’s Net Purchase Power Cost (“NPP”) by $0.9-3.0 million per year. The 30 MW Li-on provided energy, capacity, regulation reserve, spinning reserve, and non-spinning reserve. However, the reduction in variable costs due to the addition of the 30 MW Li-on was less than the annual fixed cost of the 30 MW Lion (see Chart2 below).

Technology Lithium Ion Capacity 50 MW Duration 2 Hours Capital Cost $1,800/kW ($900/kWh) Fixed

O&M Cost $10/kW-yr Variable O&M Cost $0.3/MWh Project Life 20 years Battery Replacement Cost

$244/kWh Battery Replacement Yr of Occurrence 11th year Roundtrip Efficiency 83% Debt Interest

Rate (20 Yr Term) 4% Debt Interest Rate (10 Yr Term) 3% O&M Escalation Rate 2%/yr Adding the 50

MW Li-on into TID’s resource portfolio increased TID’s NPP by $2.0-5.2 million per year (see

Chart 1 above) again due to the fact that the savings in TID’S NPP is less than the annual fixed cost of the storage system (see Chart 3 below).

As can be seen from Chart 4, Chart 5, and Chart 6 below, permitting regulation reserve sales increase the value of the Li-on storage system because of higher value regulation reserve sales. However, despite allowing the higher value regulation reserve sales, adding the 30 MW Li-on and 50 MW Li-on into TID’s resource portfolio increases NPP by $0.6-2.6 million per year and by $1.2-4.4 million per year respectively. Chart 4

Flywheel As mentioned earlier, flywheel energy storage systems are well suited for high capacity low power quick response applications such as regulation. In this study we modeled a 30 MW flywheel with a 0.25 hour (“Flywheel”) that can provide capacity, energy, regulation, spinning reserve, and non-spinning reserve. Similar to the analysis done for the Li-on, the Flywheel was analyzed with and without regulation reserve sales. Below are the assumptions used for the Flywheel: Technology Flywheel Capacity 30 MW Duration 0.25 Hours Capital Cost $2,000/kW

($8,000/kWh) Fixed O&M Cost $5.8/kW-yr Variable O&M Cost $0.3/MWh Project Life 20 years

Roundtrip Efficiency 81% Debt Interest Rate (20 Yr Term) 4% Debt Interest Rate (10 Yr Term) 3%

O&M Escalation Rate 2%/yr Adding the Flywheel to TID’s resource portfolio increased TID’s NPP by $3.5 to 4.0 million per year without regulation sales modeled (see Chart 7 below), and by $3.3-4.0 million per year with regulation sales (see Chart 8 below). The

Flywheel provided energy, capacity, regulation reserve, spinning reserve, and non-spinning reserve. But, similar to the Li-on, the benefit (reduction in variable cost) provided by the Flywheel did not exceed the additional annual fixed cost of the Flywheel (see Chart 9).

Furthermore, the Flywheel provides minimal capacity value since it only had 0.25 hour duration.

Chart 7 Net Purchase Power Cost ($ Mil) $150.0

Thermal Storage. For this analysis, we assumed that 1,000 Ice Bear systems are deployed in the TID service area. The Ice Bear systems reduce afternoon cooling load by 6 MW combined for six hours. Below are the assumptions used for the Ice Bear systems: Technology Capacity Duration Capital Cost Fixed O&M Cost Variable O&M Cost Project Life Roundtrip Efficiency Debt

Interest Rate (20 Yr Term) Debt Interest Rate (10 Yr Term) Ice Thermal Storage 6 MW (combined)

  1. 00 Hours $1,700/kW ($284/kWh) $54/kW-yr NA 20 years 120% 4% 3% O&M Escalation Rate 2%/yr

As shown in Chart 10 and 11 below, deploying the Ice Bear systems resulted in an average increase in the NPP by $0.2 million per year. Similar to other energy storage technologies studied, the reduction in variable costs achieved due to the Ice Bear systems were less than the fixed costs of the Ice Bear systems deployed (see Chart 12 below).

5Transmission and Distribution Upgrade Deferral. When a substation approaches its limits generally a new transformer or new substation are added. Storage systems can be used to defersuch distribution system upgrades. For this analysis, we used the following assumptions:

Substation Size 25 Mva

New Substation Cost $6,000,000

New Transformer Cost $1,000,000

Substation Annual Load Growth 1.0% Technology Lithium Ion Capital Cost $1,800/kW ($900/kWh)

Fixed O&M Cost $10/kW-yr Variable O&M Cost $0.3/MWh Project Life 20 years Battery Replacement

Cost $244/kWh Battery Replacement Yr of Occurrence 11th year Roundtrip Efficiency 83% Debt

Interest Rate (20 Yr Term) 4% Debt Interest Rate (10 Yr Term) 3% O&M Escalation Rate 2%/yr

A review of historical substation loading shows that in order to effectively reduce the peak loading on a substation by 0.5 MW the storage system has to be able to discharge a minimum of 3 hours and to effectively reduce peak loading by 1.0 MW the storage system has to be able to discharge a minimum of 5 hours. Assuming an annual load growth of 1.0%, a 25 Mva substation’s load will grow 0.25 MW per year. Therefore, a 0.5 MW-3 hour duration storage system could defer a substation upgrade for 2 years and a 1.0 MW-5 hour duration storage system could defer a substation upgrade by 4 years. Deferring the installation of a 25 Mva substation results in an annual savings of $240,000/yr ($6,000,000 x 4%). The capital cost of a 0.5 MW-3 hour duration storage system is $1,350,000. Since the storage system can only defer the substation upgrade by

2 years the savings realized by deferring the substation upgrade is not sufficient to pay for the storage device. A 1 MW-5 hour duration storage system will have a capital cost of

$4,500,000. Since the storage system can only defer the distribution system upgrade by 4 years the savings realized by deferring the substation upgrade is not sufficient to pay for the storage device. Also, the savings calculated above assumed a new substation was installed. If a new transformer is added instead, the annual savings would be reduced from $240,000/yr to $40,000/yr ($1,000,000 x 4%) making the storage system an even less economic solution for the purpose of deferring the distribution upgrade. Some storage systems are designed such that theycan be moved to different locations to defer upgrades on several substations. But at current storage system cost, one would have to defer upgrades at more than a few substations to become cost effective. Even if a mobile storage system prove to be a cost-effective way to defer transmission and distribution upgrades there are currently no anticipated upgrades needed in TID’s transmission and distribution system that can be deferred by installing a storage system.

For example, TID has 22 distribution substations and only 2 experience peak loads that reach 80% of capacity.

 

Please follow and like us:
This entry was posted in Battery - Utility Scale. Bookmark the permalink.

Comments are closed.