Introduction
In today’s electric utility industry, optimizing important distribution Volt/VAr assets requires integration, automation, and savvy planning. Investigating and selecting the best control for local intelligence, the best communications media, and the best overriding control program, then integrating each into Distribution Management System (DMS) or Energy Management System (EMS) requires coordinated diligence, utility-proven technologies and the cooperation of vendors with the systems knowledge to help bring it all together. This article examines the elements required to meet these tough criteria.
Distributed Intelligent Control
Today’s distribution system is not one in which loads are static and unchanging. In fact, with more Distribution Automation (DA) switching, and the inclusion of Distributed Generation (DG), managing Volt/VAr assets becomes more of a concern. Coupled with Power Quality (PQ) and power delivery concerns, the Operations group has their hands full. How can the Engineering group help?
If the objective is seeking true automation, it makes good sense to consider distributed intelligence. Intelligence at the site of the control creates the basis of an automation platform for control of voltage and VAr assets at the local level where the most dynamic of the loads reside. Selection of control elements such as capacitor controls, load tap changer controls, and line regulator controls should be evaluated with regard to enhancing our automation model for the distribution system while achieving the benefits of good volt/VAr management practice.
Given the dynamic nature of the distribution system, the control elements chosen should have the capability to detect these continuous changes and automatically adjust their operating characteristics and adapt to the newly-created operating scenarios. Control elements that do not have automatically-adapting capabilities are fixed-set controls that would have to be manually re-set or reconfigured every time the system changed in order to optimize the field assets. No utility has the manpower to keep up with the dynamic system changes that occur in distribution systems where the current operating practices include DA, DG, and similarly advanced control algorithms.
Communications
When remote bypass or override of the local control is being implemented, or when centralized control of volt/VAr assets is a consideration, the first task on the planning agenda is to thoroughly investigate the capabilities of the communication media to be employed. The chosen communications media should be based on a very robust common public carrier network for infrastructure, or based on the utility-owned private network. In many cases, utilities have gone to the expense of installing their own basic network, which may interconnect all substations and the control center with a fiber optic loop. This ensures dedicated, uninterrupted data communications between all assets out to, at least, the substation level. The shortfall is that there are many more controls beyond the substation that should be communicated with, in order to manage the entire distribution system more successfully.
The outlying assets in the distribution system often can provide the best information to influence better system-wide control. Bringing this information back into the control algorithm often increases the level of control refinement meaning the difference in bottom-line profitability. Depending on the size of the utility, millions of dollars annually can be lost due to losses in the distribution system. Better control of outlying assets can offset these losses, recapture unbillable energy, delay capital expenditure, lower maintenance costs and lower operating costs.
The chosen communications media should be supported by a dedicated data telemetry network with sufficient bandwidth to return that important data collected by the intelligent local controls. Collection of historical data can often provide important trend information to the asset planner, allowing him to achieve and maintain efficiencies he normally wouldn’t be able to experience without intelligent field devices. The dedicated telemetry network should not allow borrowing of bandwidth from the utility by the service provider when channel traffic begins to rise. The network should have good territorial coverage or, at the very least, ways to expand coverage areas including build-out options that may be negotiated or employed with the participating utility.
The chosen data telemetry network should also have reliability and security built into its infrastructure. Redundancy in network operations centers, capability to re-route traffic, and redundancy in low orbit satellites (if so equipped), and message delivery guarantees, should all be factors when judging the reliability of the network. Message encryption, multiple message paths, and pass-coding should be employed in a worthy network selection.
Does a private network or a public network best serve the utility’s interests and financial stance? Private networks are expensive (capital intensive) to establish and the owner must maintain them 100%. The advantage of public networks is that the network has been around a while, proven itself, and most of all is fully maintained at the expense of someone else besides the utility.
Of course, if the network to be employed is a public network, there are other factors to consider. Is the price of the messaging broken into a recurring monthly fee and a data transmitted fee? Are there special rates for utility data? Is there support for special utility needs? Are there costs for billing services? Can the utility be a service provider themselves and do their own internal billing? Are there other uses of the telemetry that gain economies of scale as far as breaks in usage go? All these factors must be addressed when analyzing the choice of a network.
Centralized or Overriding Control of Volt/VAr Assets
While localized intelligence for controls is adequate most of the time, there are some situations where having the capability to override that local intelligence for the sake of better overall system performance would be beneficial. These situations include emergencies (such as voltage collapse), changes to system field assets after circuit switching when local intelligence needs to move faster, and transmission side support (where contracts require the same). It is for these, and many other, reasons that remote control of field assets has been employed. Since operating philosophies differ drastically on remote control and its methodology, this article will not attempt to explain, indemnify, or disparage any of the available technologies. Philosophical strategies for operation and integration of the chosen remote control scheme is, and will be, solely at the discretion of the utility.
Nonetheless, selecting a good centralized VAr dispatch program can be a perplexing task, since the underlying foundation of such a program must be based on accurate measurement of system-wide parameters at all strategic locations throughout the distribution system. Methods of measurement also vary greatly between vendors of such system programs, but the fundamental measurements (to be effective) should include, at a minimum:
These measurements of the system parameters are fed into the centralized asset management system algorithm, which then makes decisions as to the exact control asset to effect and what action is to be taken. Some of these asset management systems rely on fiercely complex algorithms and heavy calculations, which require input frequently (nearly every second) in order to make decisions on the assets to effect. In this type of system, the control of the asset is usually by a non-intelligent switch. Other programs require less input (i.e. longer polling intervals) from field elements and in some cases, use only deviation reporting of the system elements to drive their algorithms. Still others prefer to allow intelligent controls to make their own locally-intelligent decisions for system control, monitor the system values continually, and bypass the local control only when actually needed. The latter control system can only be implemented where the system is populated with sufficient intelligent field assets to provide the data required. Each of these centralized volt/VAr asset management systems require flexibility in the communications media used and the system demographics.
Sometimes, the utility may already have a legacy system in place with its own network infrastructure as well as some older communications media (400 MHz UHF, 900 MHz FHSS, one-way paging, etc.) but would also like to take advantage of some of the newer intelligent IEDs that employ newer telemetry. In many cases, when these situations begin to arise as concerns for the utility, a good centralized VAr dispatch program that can integrate old and new controls as well as old and new communications media into one seamless and transparent application program may be the solution that can carry them into the next generation of control refinement.
Summary
With the objectives remaining the same: reduce system losses, lower operating costs, improve power quality and improve bottom-line profitability, this may be the opportune time to consider a new approach to volt/VAr management. Combining the elements of the newest technology; intelligent local controls, an inexpensive robust public network backbone, and an overriding comprehensive control program that can integrate the old with the new, provides all the elements of a system that can advance the refinement of automated control efficiencies to outstanding operating levels. So then, what is the best method of comprehensive control? The choice is up to you.
About the Author
Mark Dixon is Manager-Market & Project Development for Control Products & Systems for Beckwith Electric Company. He has over 25 years of experience with various manufacturers providing products, systems and services to the electrical power generation and distribution industry. He began his career in the U.S. Air Force as Power Production Specialist, in charge of 59 generator sites and 11 Titan II Nuclear Missile Silos for power generation and distribution, both prime power and emergency stand-by units/applications. He has in-depth knowledge of protective relays, excitation systems, synchronizing systems and equipment, and rotating machinery controls. Most recently he held positions in substation and distribution automation, and is knowledgeable about communications methods and products.
Mark has an A.S. degree in electronics, an A.A. degree in business and has completed additional coursework in protective relaying engineering, business management and economics. He is a member of IEEE.
In today’s electric utility industry, optimizing important distribution Volt/VAr assets requires integration, automation, and savvy planning. Investigating and selecting the best control for local intelligence, the best communications media, and the best overriding control program, then integrating each into Distribution Management System (DMS) or Energy Management System (EMS) requires coordinated diligence, utility-proven technologies and the cooperation of vendors with the systems knowledge to help bring it all together. This article examines the elements required to meet these tough criteria.
Distributed Intelligent Control
Today’s distribution system is not one in which loads are static and unchanging. In fact, with more Distribution Automation (DA) switching, and the inclusion of Distributed Generation (DG), managing Volt/VAr assets becomes more of a concern. Coupled with Power Quality (PQ) and power delivery concerns, the Operations group has their hands full. How can the Engineering group help?
If the objective is seeking true automation, it makes good sense to consider distributed intelligence. Intelligence at the site of the control creates the basis of an automation platform for control of voltage and VAr assets at the local level where the most dynamic of the loads reside. Selection of control elements such as capacitor controls, load tap changer controls, and line regulator controls should be evaluated with regard to enhancing our automation model for the distribution system while achieving the benefits of good volt/VAr management practice.
Given the dynamic nature of the distribution system, the control elements chosen should have the capability to detect these continuous changes and automatically adjust their operating characteristics and adapt to the newly-created operating scenarios. Control elements that do not have automatically-adapting capabilities are fixed-set controls that would have to be manually re-set or reconfigured every time the system changed in order to optimize the field assets. No utility has the manpower to keep up with the dynamic system changes that occur in distribution systems where the current operating practices include DA, DG, and similarly advanced control algorithms.
Communications
When remote bypass or override of the local control is being implemented, or when centralized control of volt/VAr assets is a consideration, the first task on the planning agenda is to thoroughly investigate the capabilities of the communication media to be employed. The chosen communications media should be based on a very robust common public carrier network for infrastructure, or based on the utility-owned private network. In many cases, utilities have gone to the expense of installing their own basic network, which may interconnect all substations and the control center with a fiber optic loop. This ensures dedicated, uninterrupted data communications between all assets out to, at least, the substation level. The shortfall is that there are many more controls beyond the substation that should be communicated with, in order to manage the entire distribution system more successfully.
The outlying assets in the distribution system often can provide the best information to influence better system-wide control. Bringing this information back into the control algorithm often increases the level of control refinement meaning the difference in bottom-line profitability. Depending on the size of the utility, millions of dollars annually can be lost due to losses in the distribution system. Better control of outlying assets can offset these losses, recapture unbillable energy, delay capital expenditure, lower maintenance costs and lower operating costs.
The chosen communications media should be supported by a dedicated data telemetry network with sufficient bandwidth to return that important data collected by the intelligent local controls. Collection of historical data can often provide important trend information to the asset planner, allowing him to achieve and maintain efficiencies he normally wouldn’t be able to experience without intelligent field devices. The dedicated telemetry network should not allow borrowing of bandwidth from the utility by the service provider when channel traffic begins to rise. The network should have good territorial coverage or, at the very least, ways to expand coverage areas including build-out options that may be negotiated or employed with the participating utility.
The chosen data telemetry network should also have reliability and security built into its infrastructure. Redundancy in network operations centers, capability to re-route traffic, and redundancy in low orbit satellites (if so equipped), and message delivery guarantees, should all be factors when judging the reliability of the network. Message encryption, multiple message paths, and pass-coding should be employed in a worthy network selection.
Does a private network or a public network best serve the utility’s interests and financial stance? Private networks are expensive (capital intensive) to establish and the owner must maintain them 100%. The advantage of public networks is that the network has been around a while, proven itself, and most of all is fully maintained at the expense of someone else besides the utility.
Of course, if the network to be employed is a public network, there are other factors to consider. Is the price of the messaging broken into a recurring monthly fee and a data transmitted fee? Are there special rates for utility data? Is there support for special utility needs? Are there costs for billing services? Can the utility be a service provider themselves and do their own internal billing? Are there other uses of the telemetry that gain economies of scale as far as breaks in usage go? All these factors must be addressed when analyzing the choice of a network.
Centralized or Overriding Control of Volt/VAr Assets
While localized intelligence for controls is adequate most of the time, there are some situations where having the capability to override that local intelligence for the sake of better overall system performance would be beneficial. These situations include emergencies (such as voltage collapse), changes to system field assets after circuit switching when local intelligence needs to move faster, and transmission side support (where contracts require the same). It is for these, and many other, reasons that remote control of field assets has been employed. Since operating philosophies differ drastically on remote control and its methodology, this article will not attempt to explain, indemnify, or disparage any of the available technologies. Philosophical strategies for operation and integration of the chosen remote control scheme is, and will be, solely at the discretion of the utility.
Nonetheless, selecting a good centralized VAr dispatch program can be a perplexing task, since the underlying foundation of such a program must be based on accurate measurement of system-wide parameters at all strategic locations throughout the distribution system. Methods of measurement also vary greatly between vendors of such system programs, but the fundamental measurements (to be effective) should include, at a minimum:
- Substation bus voltages and currents
- Feeder head voltages and currents
- Substation breaker status
- Transformer loading
- Voltages from as far along radial feeders as can be read
- End of line voltages
- Direction of power flow
These measurements of the system parameters are fed into the centralized asset management system algorithm, which then makes decisions as to the exact control asset to effect and what action is to be taken. Some of these asset management systems rely on fiercely complex algorithms and heavy calculations, which require input frequently (nearly every second) in order to make decisions on the assets to effect. In this type of system, the control of the asset is usually by a non-intelligent switch. Other programs require less input (i.e. longer polling intervals) from field elements and in some cases, use only deviation reporting of the system elements to drive their algorithms. Still others prefer to allow intelligent controls to make their own locally-intelligent decisions for system control, monitor the system values continually, and bypass the local control only when actually needed. The latter control system can only be implemented where the system is populated with sufficient intelligent field assets to provide the data required. Each of these centralized volt/VAr asset management systems require flexibility in the communications media used and the system demographics.
Sometimes, the utility may already have a legacy system in place with its own network infrastructure as well as some older communications media (400 MHz UHF, 900 MHz FHSS, one-way paging, etc.) but would also like to take advantage of some of the newer intelligent IEDs that employ newer telemetry. In many cases, when these situations begin to arise as concerns for the utility, a good centralized VAr dispatch program that can integrate old and new controls as well as old and new communications media into one seamless and transparent application program may be the solution that can carry them into the next generation of control refinement.
Summary
With the objectives remaining the same: reduce system losses, lower operating costs, improve power quality and improve bottom-line profitability, this may be the opportune time to consider a new approach to volt/VAr management. Combining the elements of the newest technology; intelligent local controls, an inexpensive robust public network backbone, and an overriding comprehensive control program that can integrate the old with the new, provides all the elements of a system that can advance the refinement of automated control efficiencies to outstanding operating levels. So then, what is the best method of comprehensive control? The choice is up to you.
About the Author
Mark Dixon is Manager-Market & Project Development for Control Products & Systems for Beckwith Electric Company. He has over 25 years of experience with various manufacturers providing products, systems and services to the electrical power generation and distribution industry. He began his career in the U.S. Air Force as Power Production Specialist, in charge of 59 generator sites and 11 Titan II Nuclear Missile Silos for power generation and distribution, both prime power and emergency stand-by units/applications. He has in-depth knowledge of protective relays, excitation systems, synchronizing systems and equipment, and rotating machinery controls. Most recently he held positions in substation and distribution automation, and is knowledgeable about communications methods and products.
Mark has an A.S. degree in electronics, an A.A. degree in business and has completed additional coursework in protective relaying engineering, business management and economics. He is a member of IEEE.
