Volume 6, Number 2, Spring 2006
Originally, the role of the distribution systems is to provide the interconnection between the generation and transmission system and industrial, commercial, and residential load centers. The distribution systems generally can be considered to be passive networks–that is, they do little to dynamically regulate voltage. In contrast, the transmission system operator must deal with voltage problems that arise from a number of power-system events such as lost load, line or cable outages, dropped generation, capacitor bank outages, heavy power transfers, parallel flows, or unusually high or low load demands.
Originally, the role of the distribution systems is to provide the interconnection between the generation and transmission system and industrial, commercial, and residential load centers. The distribution systems generally can be considered to be passive networks–that is, they do little to dynamically regulate voltage. In contrast, the transmission system operator must deal with voltage problems that arise from a number of power-system events such as lost load, line or cable outages, dropped generation, capacitor bank outages, heavy power transfers, parallel flows, or unusually high or low load demands. The primary voltage control methods available to the operator include increasing or decreasing generation and adding or adjusting sinks or sources of reactive in the system. In future, real-time regulation of voltage at the customer’s own buses may be best performed using local sources of active and reactive power, or distributed energy resources (DER). Local regulation is much more efficient with local sources, and the DER can supply precisely the level of regulation needed. In some areas it may be most economical for the distribution utility to supply only a nominal level of reliability, and the reliability will be elevated to the customer’s requirements with DER. Within the customer’s distribution systems, some buses may be designated for critical or sensitive loads, and some may be for loads that could be reduced or shed if needed to maintain correct voltage at the critical loads. This concept already is occurring in some parts of the country 4,8. What about the reliability of power from local sources? Lambda is an index used to assess reliability by measuring the frequency of sustained outages. In a recent discussion of the attributes of distributed resources, the best frequency of interruption data, or lambda, for a primary distribution system is 0.515 based on Best in Class utility data 2. Surprisingly, the sub transmission and transmission systems’ contributions are quite low, 0.115, but the distribution primary contribution is 0.4, or 78 percent of the total frequency of interruption of 0.515. Detail break down of the primary distribution that will results in 88 percent of the outages are due to the overhead-line component. The other two components, underground line and substations, have comparatively few failures. Typically, local power parks do not contain overhead lines. They are composed of cable sin conduits and direct burial. Using the values for these components, and an availability of 0.95 for an internal combustion engine, outages at local power parks should be about four times better that the average transmission and distribution (T&D) performance.
U.S.-Canada Power System Outage Task Force _ August 14th Blackout: Causes and Recommendations
Figure 1. Basic Structure of the Electric System
Dynamic reactive power reserves from generation increase in effectiveness as voltage decays, and they also are the most reliable means for voltage stability enhancement.
Reserves provided from local generation reduce reactive losses resulting from increased active power transfer. Simulations found cases where a 15 percent increase in pure megawatts at a single bus can trigger a voltage collapse. This type of flow-triggered voltage collapse played a role in the superconductor August 14 blackout. This is because the increased active power flow aggravates reactive losses in the occupied transmission paths. Dynamic reactive reserves available from generators, synchronous condensers, static var compensators, and other inverter-based devices are the most effective and reliable means to prevent voltage collapse due to unanticipated system contingencies (line loss, generator loss, etc).
Today, most spinning reserve is provided from a few high-operating cost machines. Spin is not evenly distributed across a control area. Reactive reserves are available from these same machines because they are operating in a “backed off” mode and have high reactive power level available. Thus the reactive reserves are not distributed evenly. With an unequal pick up of reserves and area, there is an impact on power flow. When planning reactive reserves for contingency cases, these “lump” reactive reserves can cause problems. Flow paths have no paths, it actually have to be de-rated. This, in turn, has caused the curtailment of operating units. One solution is to build more transmission. This will take 5 to 10 years in most cases. A better solution is to provide reactive power from distributed energy resource (DER) units that are evenly spread across the control area.
Utility-owned DER would be possible in areas where there is no market for local generation1. Ancillary service or regulated resource contracts could reimburse small generators for reactive power produced during heavy load periods or absorbed during light conditions. In fact, some utility contracts already provide financial inducement for power factor correction.
Instead of switching capacities in and out of the grid, there is a way to generate controllable reactive power directly by switching power converters. These converters are operated as voltage or current sources and produce reactive power without energy storage components by switching alternating current (AC) among phases of the AC system. Their operation is similar to that of an ideal synchronous machine whose reactive power output is varied by excitation control. If they are supplied with an energy source, they can also supply active power to the AC system. These converters are often called static synchronous generators (SSGs) when supplied with an energy source and static synchronous compensators (SSCs) when operated without an energy source.
These compensators are capable of providing both direct voltage and transient and dynamic stability improvements to increase stability margin and provide power oscillation damping. Regulation of the voltage at intermediate points and selected loads can limit voltage variation significantly, increase the capability to transport active power, prevent voltage collapse, increase transient stability limits, and even provide power systems oscillation damping as well as reducing energy losses. The cost of the power electronics switches in converters decreases with technology improvements, and the mass production of the devices. It is likely that their use in distribution systems and to interface small power generators will become ubiquitous.
Figure 2: Types of distributed energy resources and Technologies
There is a possibility that the voltage regulators on generators could be controlled much more quickly to deliver the services provided by the rapid control of static var compensators (SVC). The SVC behaves like a shunt-connected variable reactance and generally is used for transmission voltage regulation. It can either produce or absorb reactive power to regulate voltage. It is basically a capacitor bank in parallel with a thyristor-controlled reactor. The strength of the SVC is that it is very fast acting and can dampen power system oscillations.
Thus, the transmission voltage is directly regulated at high speed. The droop (slope) setting of SVC is usually small compared to generators regulating terminal voltage. This means SVC will respond much more quickly, including responding to transients while the generator respond more slowly, usually based on a voltage schedule.
We suggest that the DER’s voltage
regulator (or switching converter) be controlled to provide services such as
control of costumer’s voltage, assistance in regulation of distribution
voltage, and providing unity power factor both in the distribution system and
transmission system. The most important service may be the increase in margin
of reactive power. To meet the rising demand for reactive power, American
Superconductor has developed a superconducting synchronous condenser with an
8MVAR continuous rating and a 64 MVAR short-term rating. It is designed to
provide steady state volt-amp-reactive (VAR) support while maintaining this
large reserve for transient problems. One is being installed near a steel mill
DER generally will increase voltage along a feeder, but the impact depends on its active and reactive power and the feeder loading. The DER easily can be controlled to help regulate voltage. If voltage increases when active power increases, decreasing reactive power will typically cause voltages to drop. In some cases, reactive power control alone may not be adequate to control voltage. In these cases, the voltage would need to be controlled by a voltage regulator. Present-day voltage regulators sometimes make decisions as to the optimum tap setting based on the sensed voltage, the secondary current, the secondary voltage and the line resistance and inductance.
When there is a mix of voltage control devices such as capacitor banks, voltage regulators and DER control, the local control decision making will become more complicated, but not excessive. A local intelligent agent would be ideal for local conditions and making decisions regarding tap settings, DER reactive power output, and capacitor bank connections. Central dispatch would still control the voltage and power factor of the central generators, and would provide the local intelligent agent with instructions such as the voltage schedule to be maintained.
Devices using power electronics interfaces will simplify coordination greatly among the conventional distribution equipment and DER. Response to some types of transients, such as voltage sags, will have to be quite fast. Power electronics devices are fast enough to distinguish between a large non-linear load and actual sag caused by short-circuit current flowing into a fault.
From the point of view of voltage stability, existing feeders could be retrofitted to provide local voltage regulation with DER by using a microprocessor that is provided with the needed information 1,7. The local microprocessor needs only a small, selected set of data. A relatively simple local microprocessor could be used if a hierarchical control system were used with a group of distributed system managers geographically spread over a wide area. A study by Hydro Quebec of a decentralized approach found that a completely peer-to-peer distributed architecture could be applied without changing the system dynamic operation. Improved damping to contingencies can be achieved with distributed control.
Figure 3: Load Supply of Reactive Power
For one contingency, global control using a hierarchical/decentralized architecture was the only scheme capable of keeping the system stable. One of the significant differences was the voltage enhancement at remote weak buses. All these are accomplished using conventional processor and supervisory control and data acquisition (SCADA) technology. New feeders can be designed to provide DER voltage control with and without a hierarchical/decentralized architecture as described above. Obviously, with a hierarchical/decentralized architecture, there are significant advantages in the system operation. However, local voltage regulation still could be provided to some degree without distributed control. The challenges, again, will be protection, coordination and voltage stability. Local control will not require a replacement of infrastructure. A few sensor locations with communications (such as radio) distributed along feeder would be needed to advise the central control authority of voltage conditions, but no more locations than are presently used.
In the Pennsylvania New Jersey Maryland Interconnection (PJM), Regional Transmission Organization (RTO), voltage control services are paid for in a two-part tariff. In the first part, for reactive power within rated capacity, the customers pays a charge proportional to the generation owner’s total revenue requirement and the amount of monthly use of network. For second part, generators are paid for when they are required to reduce active power production in order to produce reactive power. PJM interconnection ensures the reliability of the high-voltage electric power system serving 51 million people in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia. PJM coordinates and directs the operation of the region’s transmission grid, which includes 6,038 substations and 56,070 miles of transmission lines; administers the world’s largest competitive wholesale electricity market; and plans regional transmission expansion improvements to maintain grid reliability and relieve congestion3. Monitor flows over transmission lines and other facilities to ensure that thermal (heating) limits are not exceeded. The dynamic interactions between generators and loads, combined with the fact that electricity flows freely across all interconnected circuits, mean that power flow is ever-changing on transmission and distribution lines. All lines, transformers, and other equipment carrying electricity are heated by the flow of electricity through them 9.
Figure 4: PJM Load Curve, August 2003
Figure 5: Normal and Abnormal Frequency
There may be several advantages to providing regulation from DER technologies as a regulated T&D resource. The benefits relate to reducing the risks (reliability and financial) associated with new technologies. Regulating the asset allows system operators and state regulators to control the resting and deployment of new technology. Consequently, they can proactively seek technology driven improvements. The technology would be developed only as rapidly as it proved itself and the system operator gained confidence in it. Ratepayers benefit as well because new cost-reducing reliability-improving technologies get introduced much more quickly 4,5. Technology also is tested in a way that does not jeopardize system reliability. Regulators perform their historic benefits likely will exceed costs and approving world worthwhile demonstrations. Rate payers assume the reasonable risk of funding promising test programs.
Technology investors benefit, too. They can move more incrementally toward full-scale deployment. They need not overcome all technical and market rule obstacles. Instead, they can focus on technical viability. Similarly, T&D companies benefit. They too can focus on technical implementation and getting the technology right 6. Both are guaranteed cost recovery (assuming the technology performs competently). The technology may migrate to the competitive market once the system operator is satisfied that it is technically proven and that there are sufficient potential resources to warrant going to the effort to change any market or reliability rules. Alternatively, it may be more appropriate for the technology to remain a regulated T&D asset.
The supply of dynamic reactive power has been dwindling over the last few years for a number of reasons; (1) generators are being purchased with lower reactive support capability; (2) system planners are relying more on capacitor banks instead of the more expensive dynamic reactive sources; and (3) increased energy transfer level absorb higher levels of reactive power. The reactive power supplied by capacitors decreases with the square of voltage, however, the dynamic response of capacitors is problematic under a disturbance. Excessive use of capacitors can aggravate the imbalance of reactive power and can actually become one of the causes of voltage collapse1, 2, 3. Dynamic reactive power reserves from generation increases as voltage decays, and are the most reliable means for voltage stability enhancement.
Reactive power does not flow long distances from a source, especially during times of system stress. Reactive power absorption on transmission lines with the square of the flow. Additionally, existing reactive power reserves tend to be lumped together. If reactive power is supplied from resources that are evenly spread across the control area, congestion from contingency planning could be greatly relieved. Reactive reserve provided from local generation reduces reactive losses resulting from increased active power transfer. In addition, distribution losses are the largest percentage of total system losses, comprising about 27 percent of total losses1. When reactive power is supplied from DER, losses on the distribution feeder can be reduced, and local power quality can also be significantly improved.
Reactive power markets are
developing both in the
9. “Final report on the August
14, 2003 blackout in the
Causes and recommendations,” US–Canada Power System Outage Task Force,
Distributed Energy Resources = DER.
Transmission and Distribution = T&D
Alternating Current = AC
Static Synchronous Generators - SSG
Static VAR Compensators = SVC
Mega-Volt-ampere Reactive = MVAR
Supervisory Control and Data Acquisition = SCADA
Volt-ampere reactive = VAR
Reliability Must-Run = RMR
Regional Transmission Organization = RTO