 |
 |
|
| ADDING VALUE TO THE MODERN GRID | ||
|
|
|
| ADDING VALUE TO THE MODERN GRID | ||
| Welcome | About ESA | Contact Us | Search | ||
| ESA Sponsors: |
 |
 |
 |
 |
See the menu at left for discussions of individual storage applications.
Energy storage can provide “ride-through” for momentary outages, and extended protection from longer outages. Coupled with advanced power electronics, storage systems can reduce harmonic distortions, and eliminate voltage sags and surges.
In combination with renewable resources, energy storage can increase the value of photovoltaic (PV) and wind-generated electricity, making supply coincident with periods of peak consumer demand.
Energy storage systems can be used to follow load, stabilize voltage & frequency, manage peak loads, improve power quality, defer upgrade investments, and support renewables. The side chart shows the power and discharge time requirements for a variety of storage applications in the utility industry.
The world market for batteries is estimated at about US $15 billion each year. The ESA estimates that industrial batteries, as might be used in uninterruptable power supplies, power quality applications, standby and reserve batteries amount to US $5 billion each year.
Manufacturing facilities for advanced batteries specifically designed for energy storage applications on power systems are being installed in North America, Europe and Asia. New manufacturing capability of at least 300 MW per year has been brought on stream in the past twelve to eighteen months.
There is a revival of interest world-wide in energy storage and its applications. It is not just about batteries. Other techniques such as advanced flywheels and superconductivity are also attracting great interest.
Electricity storage provides several benefits for electric power utilities, transmission companies, electricity generators, and electric power end users. These benefits include: reduced financial losses due to poor power quality and power outages, energy price arbitrage involving charging with low priced “off-peak” energy for use later when energy cost and price is high, and a variety of services that can be described, but which may or may not provide revenue at present. An economist might say that though the benefits exist, they are not internalized, meaning that today no mechanism whereby the supplier can accrue revenue from the benefit. Simply put, the electricity market is not economically efficient because of the way the services are priced. Over the past decade or so, which has seen several attempts at reregulation, the value of the benefits that electricity storage can provide have been expanded and quantified. Some have been evaluated, isolated, and even demonstrated. The latter include, for example, the class of benefits called “distributed” benefits (those which accrue because of the location of the storage capacity), and benefits associated with superior performance of the transmission system. Here we follow a summary of benefits initially explored by Joe Iannucci and Jim Eyer of Distributed Utility Associates. They developed this approach for the California Energy Commission (CEC) and the U.S. Department of Energy (DOE). As a result, though the examples in this section have wide validity, the descriptions and quantities, particularly the market estimates given later are California-centric mainly relevant to the situation in California. Generally, more than one benefit is required for the total value of a storage installation to exceed its costs. However, one cannot just look at the sum of all possible benefits because there may be some interference between the functionality and value of different aspects. A thorough (qualitative and quantitative) consideration of the technology and the market are required before benefits may be combined appropriately. Because the purpose of this section is to provide the analyst with a set of tools rather than supply answers, we simply list and describe the possible benefits. At some later time, it may be possible to add quantitative information on the magnitude of the potential market.
Arbitrage involves purchasing inexpensive electricity when its demand and cost are low; and then selling the electricity when demand and price are high. Storage systems that operate in this market generally have the capacity to storage large amounts of energy, interact with the power grid at the transmission level, and operate on a diurnal cycle of charge and discharge. Examples are pumped hydro plants, compressed air electricity storage facilities, and large battery installations.
A variety of reliability demands apply to the electric utilities. Amongst others, and perhaps the most significant is that a utility or a group of utilities must be able to accommodate the loss of the largest generator in the system with limited power flow and frequency variation. This generally means that all generators on the system must have a few percent of immediate reserve capacity associated with their rotational inertia and their primary energy sources such as steam or hydro. Besides the fact that each generator must run below its rated value, additional fuel is used or water is wasted. Thus, excess CO2 is emitted and the overall efficiency of the power grid is reduced. Papers as early as 1973 suggested that a large SMES system designed for diurnal use could accommodate some of a utilities’ spinning reserve requirements by installing additional power capacity into its four-quadrant ac-dc power converter. That is, the rated value of the converter would be some 20 % greater than the normal power rating of the system. The additional capacity would always be held in reserve (i.e., not used for arbitrage) and used only for in the case of loss of generation on the grid. Though the larger converter requires greater capital expenditure, because the operating temperature is somewhat reduced, it would not only provide this security, it bout be more efficient during normal operation than a device with a lower rating. At the time, no other electricity storage concept used a controllable converter and further, there was no way for the owner to accrue monetary benefits from the service. Today, many electricity storage systems including batteries, capacitors, and flywheels interact with the grid via an electronic power controller and thus have this capability. In addition, some power markets assign high value to this functionality, allowing the owner of a facility with this characteristic to accrue monetary benefits.
The utilities generally have several reserves Spinning Reserve – Generation capacity that is on-line but unloaded and that can respond within 10 minutes to compensate for generation or transmission outages. “Frequency-responsive” spinning reserve responds within 10 seconds to maintain system frequency. Spinning reserves are the first type used when shortfalls occur. Supplemental Reserve – Generation capacity that may be off-line or that is comprised of a block of “curtailable” and/or “interruptible” load and that can be available within 10 minutes. Unlike spinning reserve capacity, supplemental reserve capacity is not “synchronized” with the grid (frequency). Supplemental reserves are used after all spinning reserves are on-line. Backup Supply – Generation that can pick up load within an hour. Its role is, essentially, a backup for reserves. Backup supply may also be used as back up for commercial energy sales.
This application is sometimes referred to as “Deferred T&D Upgrade Investment”. It involves the temporary use of an electricity storage device. The storage unit is installed on the power grid, usually near the end use, where the need for a T&D upgrade is forecast. The electricity storage system allows the existing transmission line to be used for a longer time, either because it is not replaced or is not upgraded. The benefit is equal to the annual carrying charges for the capital investment that are avoided if the upgrade is deferred. Example: Consider a 3 MW upgrade to a 9 MW distribution system, which will eventually be needed to supply a 12 MW load. The total expenditure for the change might be $1,500,000 to $2,000,000 and the annual carrying charge for the investment would be about $150,000, i.e., $50 per kW per year. Since, in practical cases, the total increase in capacity is not needed immediately. If the load growth is typical of the US, it will be less than 2.5 % each year. Thus, a 225 kW electricity storage system would ensure capacity during the first year. Similarly, an additional 225 kW could be added the next year, etc. So long as the annual cost of the storage system is less than the annual carrying charges, it is a good solution. In fact, with the leverage, it is possible that the storage system would pay for itself in less than two years. At some point, however, the grid upgrade must occur. At that time, the electricity storage system will be disconnected from the grid. Depending on the life expectation of the storage system, it could then be used for exactly the same purpose at a different site.
Electricity storage improves the performance of the transmission system to the extent that it increases the load carrying capacity of the transmission system, a benefit accrues if additional load carrying capacity defers the need to add more transmission capacity and/or additional T&D equipment. This provides a benefit to the owner of the transmission system.
Utilities that do not own transmission facilities pay those who do for transmission “service”. Thus, when non-owners use the transmission system to move energy from one place to another the owners impose an “access” charge to cover carrying charges and operations and maintenance costs. Today, transmission capacity for a transaction can include an access charge, which is scaled with overall power flow in the corridor, not just a linear relationship based on needed power flow. The end user may avoid these charges by installing electricity storage.
NOTE: avoided congestion charges is an established financial opportunity. It is related to too many kWh for the Transmission system to transmit based on rated capacity. The price is set by ISOs.
The Transmission Support application is really used to modify the “electrical performance” of the system, per the EPRI/DOE Handbook. Discharge, the storage duration is probably just a few seconds.
|
Type |
Description |
|
Transmission Stability Damping |
Increase load carrying capacity by improving dynamic stability. |
|
Sub-Synchronous Resonance Damping |
Increase line capacity by allowing higher levels of series compensation by providing active real and/or reactive power modulation at sub-synchronous resonance modal frequencies. |
|
Voltage Control and Stability |
1. Transient Voltage Dip Improvement: Increase load carrying capacity by reducing the voltage dip which follows a system disturbance. |
|
Under-frequency Load Shedding Reduction |
Reduce load shedding needed to manage under-frequency conditions which occur during large system disturbances. |
If the electricity storage capability is sufficiently large compared to the users’ requirements or utility generation capacity, it can be used in lieu of central generation capacity. If so, the several costs associated with ownership of a power plant are avoided. Equivalently, the cost to “rent” capacity in the wholesale electricity marketplace is avoided. In some sense this couples directly with arbitrage and the assignment of value to the two aspects depends on the method of charges set up by the utility.
Similar to the above items, a utility can defer the upgrade of certain substation components or perhaps even an entire substation by having an electricity storage system at the proper location. For example, a storage facility within the substation allows stored electricity to be distributed at specific times when the power limits of one or more transformer or circuit breaker would be exceeded. One might wish to consider this item as part of a broader T&D deferral, but structurally the substation is different from the lines and may be owned by different entities.
In some cases, there are severe changes in total load associated with a region or a specific user, for example power demand increases abruptly in several steps in the early morning. An arc furnace, where metal is fused and melted for reuse, has several periods of demand during a day. An electricity storage system can act as a buffer that isolates the rest of the power grid from these frequent and rapid power changes. VAR support and spike control are also important capabilities of a storage system for the arc furnace amelioration. The latter is a bonus value for device that it has because of the power conversion system. This capability is independent of the energy part of the storage system.
For small power systems, for example where there are only one or a few generators, significant load increases will cause the frequency to slow and the voltage to droop. Similarly, the frequency will increase when there is loss of load. If the frequency varies by too large an amount, there are system wide impacts as motors speed up or slow down, etc. Of particular significance is the case where the frequency and voltage decrease. Under these conditions, electric motors tend to demand greater current to maintain power output and thus worsen the effect.
Large power systems have frequency control requirements that set limits at which the utility or the generator must carry out some action. An electricity storage device can supplement the power system while total generation is increased either by the addition of generators or while the power output of online generation is increased.
Electricity storage can enhance the value of energy from renewable generation in at least two fundamental ways. Storage can “firm-up” renewables’ output so that electric power (kW) can be used when needed. Similarly electric energy (kWh) generated during times when the value is low can be “time-shifted” so that the energy can be sold when its value is high. One option would be to charge existing storage with electricity from wind generation as well as from the grid. Another would be to install additional storage at the renewable site.
This is much like arbitrage, but it is on the user side of the meter. Customers that pay “time-of-use” energy prices may find that storage can reduce their overall cost for electric energy. Customers increase the amount of stored electricity during off-peak time periods when their electric energy price is low, then discharge the energy during times when on-peak (time-of-use) energy prices apply.
Similar to other cases, electricity storage can be used by the end-user who must pay an incremental amount (typically each month) for the peak power delivered for any 15-minute period during that month. This is a negotiated cost and is based on the amount above some base value. It is a single value, say 5 $/kW/month and changes from month to month as the demand changes. The user typically controls certain parts of the load, such as air conditioning, large pumps, etc to keep the demand charge under control. Onsite electricity storage provides the user with additional control of process costs and allows control of the demand charge so it is less of a factor in determining facility operation.
One way to improve the reliability of electric service is to use electricity storage systems for important or critical loads. In the event of a power outage lasting more than a few seconds, the storage system provides enough energy to a) ride through outages of extended duration, and/or b) complete an orderly shutdown of processes, and/or c) transfer load to on-site generation resources.
Improving electric service power quality (PQ) involves use of electricity storage to protect important or sensitive loads against short duration power system anomalies that affect the quality of power delivered.
Some manifestations of poor power quality which may damage or affect operation of electric loads and that could be reduced or eliminated by energy storage include:
• Variations in voltage magnitude
• Variations in the primary 60 cycles/sec frequency at which power is delivered
• Low power factor
• Harmonics
When storage near a load is charged off peak, the total resistive (I2R) losses over the period of a day are reduced. Losses associated with the lower current are smaller than the losses along the same transmission corridor during heavy load periods. A benefit accrues if there is a significant differential between T&D resistive losses on peak versus losses off-peak. For example, if T&D I2R losses are 8% on peak and 5% off-peak the avoided losses are 3%. As a result, fuel use and related air emissions are reduced. The benefit is the total cost of the extra energy generated and the cost of extra generation and transmission capacity. This can amount to some 20 to 50 $/kW/year.
Similar to T&D deferral, storage may be used to reduce maximum loading on T&D equipment such that the useful life of the T&D equipment may be extended. If so, the financial benefit could be similar in magnitude to that for T&D deferral. For example, many underground cables are approaching their rated life. Extending that life by reducing the effects of overheating caused by over loading circuits for long periods or current spikes associated with ground faults can add multiple years to a cable’s life.
If storage is charged at night and then discharged during the day, one effect may be that the T&D system is used, on average, more that if storage was not deployed. This could result in improved returns on the capital investment of the various components that see greater use.
The use of electricity storage can reduce overall air emissions for fossil fuel plants, the amount depending on the generation plants and fuels used. For example, by arbitrage because cleaner fuels and more efficient generation plants are typically available off-peak, by load following because changing power output in any way requires excess fuel (efficiency is less during these periods). The increase in the use of renewables can provide an environmental credit that can be used either directly by the owner of the storage device or can be traded/exchanged for other benefits with users who need, e.g., carbon credits.