Realizing the smart grid of the future through AMI technology

Realizing the smart grid of the future through AMI technology

Carl LaPlace

Robert W. Uluski

01 June 2009

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Document number: WP42-1003A

Realizing the smart grid of the future through AMI technology 1

Contents

Executive summary.......................................................................................... 2 Current situation.............................................................................................. 2

Smart metering .................................................................................... 2 Distribution system remote monitoring and control .................................... 3

AMI technology and realizing the smart grid......................................................... 4 Supports system monitoring through low cost sensors ................................ 5

Future distribution grid using EnergyAxis System for AMI....................................... 5 EnergyAxis System data access methods.................................................. 6

Periodic polling .......................................................................... 6 Triggered data access ................................................................. 6

EnergyAxis System for AGI in realizing the smart grid ........................................... 7 AGI and the smart grid .......................................................................... 8 AGI and distribution automation.............................................................. 8 AGI and outage management ................................................................. 8 AGI and power quality ........................................................................... 8 AGI and loss detection ........................................................................... 9 AGI and state estimation........................................................................ 9 AGI and integrated volt-VAR control ........................................................ 9

Conclusion .....................................................................................................10 About the authors ...........................................................................................10

Carl LaPlace ........................................................................................10 Robert W. Uluski, PE.............................................................................10


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Executive summary Advanced metering infrastructure (AMI) technology is a vital component within the smart grid of the future. AMI technology provides utilities with a wealth of new information that was not readily available with automated meter reading (AMR) technology or cost effective with today’s distribution automation (DA) systems. AMI technology provides information that can be used to optimize business operations, such as system engineering, maintenance or customer service. AMI systems also provide a ubiquitous communication infrastructure that supports continual monitoring and remote control of power system components and greatly improved visibility and optimal control of the power system.

This paper identifies how utilities can utilize the information provided by an AMI communication infrastructure to build and support the smart grid of the future.

Current situation Many electric utilities have deployed one or more systems for automatically monitoring and, in some cases, controlling portions of the transmission and distribution system from a central location. The extent to which these automated systems have been deployed varies widely from utility to utility based on individual business cases. Typically, these systems operate completely independent of one another with little or no sharing of facilities and information between systems. Consequently, these systems form islands of automation that must be bridged to realize the smart grid of the future.

A growing number of utilities are implementing AMI systems because it provides two-way communications that allow utilities to collect more than monthly consumption data used for billing. AMI systems can now provide load profile data, demand, time-of-use (TOU), voltage profile data, and power quality data. AMI systems also allow widespread deployment of TOU rates, which historically have been offered only to the utility company’s largest customers (large commercial and industrial customers). Despite these significant advancements in the metering process, most information and infrastructure provided by the metering system has primarily been used to support billing, on-demand reads, and demand response.

Smart metering Smart metering systems eliminate many labor-intensive business processes, such as manual meter reading, field trips for service connects and disconnects, on-demand reads, power outage and restoration management, and other metering support functions.

Smart metering systems that continually communicate with smart meters are able to report loss of voltage to an outage management system (OMS). A well-designed OMS system can group and analyze customer calls using feeder models that provide information about likely fault locations. This information,


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in turn, is passed along to crews that are working in the field to resolve fault conditions.

AMI systems with two-way communications enable the utility to send pricing signals to alert customers of critical peak pricing (CPP) periods. Direct communication to the customer encourages conservation during such periods and enables utilities to implement direct control of demand side management (DSM) features. Figure 1 shows a conceptual diagram of a typical AMI deployment.

An AMI system with smart meters has many other benefits beyond delivering advanced metering data. Electric utilities have only begun to tap the valuable resources available through AMI technology, however. Greatly improved transformer load management, proactive feedback when abnormal voltage conditions exist on the feeders, and generation of accurate load models for improved engineering analysis and decision making are just a few of the added benefits utilities can realize using AMI technology.

Figure 1. AMI system

Distribution system remote monitoring and control Distribution system supervisory control and data acquisition (SCADA) facilities enable system operators to continuously monitor the health and performance of the distribution system and in some cases to control distribution equipment from a central location. Distribution SCADA also furnishes information needed by planning and design engineers, and provides information to support equipment maintenance scheduling. See Figure 2.

In almost all cases, distribution SCADA is limited to substation equipment. Operators, engineers, and maintenance personnel typically have little visibility of the electrical conditions on the distribution feeders because there are no continual monitoring facilities for feeder equipment. Some electric utilities can obtain data from the substation end of each feeder, but that data provides minimal insight about the electrical conditions on the feeders themselves. Engineering analysis tools model the feeders using statistical estimates of the customer load distributed along


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the feeder. This is a traditional analytical technique that yields an approximation to the actual conditions on the feeder that is only as good as the accuracy of the load estimates.

Very few utility companies have monitoring and control facilities on the feeders themselves (outside the substation fence). So operators must rely on periodic routine inspections, reports from customers and local authorities, and other such sources to determine the status, performance and loading of equipment. The primary reason only a few utilities have deployed widespread distribution monitoring and control facilities is that the benefits do not warrant the deployment costs, a large part of which are communication costs.

Remote monitoring and control of distribution feeder equipment offers benefits that go well beyond the benefits of distribution substation SCADA. The incremental benefits of deploying distribution feeder automation include reliability improvement, reduced electrical losses, and early detection of abnormal conditions out on the feeders. Electric utilities can reduce the total cost to achieve these benefits by leveraging AMI technology to provide the communications network for remote monitoring and control of distribution feeder equipment.

Figure 2. Distribution SCADA

AMI technology and realizing the smart grid AMI technology will play a significant role in realizing the distribution system of the future: the smart grid. Historically, information acquired from customer meters was used only for


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billing purposes. This information can now be used to create and fine tune the feeder and load models used by advanced DMS applications such as integrated volt-VAR control and automatic service restoration, thereby allowing these software tools to play a key role in optimizing the performance and reliability of the distribution network.

AMI systems can supply key measurements (voltage, current, equipment status, etc.) in near real time (within minutes) from strategic locations across the distribution network. This greatly improves the visibility of the distribution system, and empowers distribution system operators with the information needed to make informed decisions during crisis conditions and control the system in the most optimal manner during normal conditions.

The AMI communication infrastructure can be leveraged to provide connectivity to the high voltage equipment located on the distribution feeders. Thus, the AMI communication infrastructure becomes an enabler for the advanced monitoring and control applications that are the foundation of the future smart grid.

While SCADA communication infrastructure is typically limited due to cost, AMI deployments involve all customer sites across the distribution grid and are extremely cost sensitive. This introduces an opportunity in today’s systems by having a pervasive, low cost communications network deployed across the power grid. This provides a unique opportunity to gather more information on voltage, current, power, and outages across the distribution grid to enable new and exciting applications. This is the premise for the advanced grid infrastructure - AGI – leveraging the AMI infrastructure to realize the smart grid.

Supports system monitoring through low cost sensors The smart grid of the future will include numerous low cost sensors that are installed all along the distribution feeders. These sensors support asset management and condition-based maintenance of distribution facilities.

One barrier to the successful deployment of such sensors is the lack of suitable cost-effective communication facilities for reporting the state of these sensors to operators and other responsible parties. Utility companies that have recently deployed AMI systems have been able to leverage the AMI communication system to provide near real time access to low cost sensors such as circuit fault indicators.

AMI technology is a foundational element of the smart grid. The communications backbone of the AMI system should provide connectivity for distributed sensors and control devices to a distribution control center and create an intelligent self-healing network.

Future distribution grid using EnergyAxis System for AMI AMI has the ability to provide information from across the distribution network: end points, feeders, and substations. The


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EnergyAxis System provides an effective platform to acquire new information that can greatly improve future distribution system automation and associated applications. Technical applications include functions that support the needs of distribution operations, engineering, maintenance of distribution assets, and other functions outside the baseline billing revenue collection and protection use of the data.

Figure 3 shows the future use of AMI data and communication infrastructure across the distribution network.

EnergyAxis System data access methods The EnergyAxis System has two methods of data access: periodic polling and triggered access. EnergyAxis System uses both methods for obtaining data as described below.

Periodic polling This is the normal method of acquiring meter information. Periodically, each meter is requested to provide a predetermined set of data. Typical polling intervals are once every four to six hours. This is significantly less frequent than electric utility SCADA systems used for operational purposes. SCADA polling intervals range from every few seconds for the most critical data items (equipment alarms) to once every several minutes for less critical items (for example, equipment loading). As previously indicated, SCADA polling intervals cannot be economically achieved by advanced metering systems for all meters due to the sheer volume of metered points. However, it is possible to poll a strategic number of meters to retrieve critical meter data on a near real time basis.

Triggered data access Upon occurrence of an abnormal system condition, or upon demand from an operator or system, additional data items beyond that needed for billing purpose may be collected from selected meters or monitoring nodes. For example, an AMI meter can detect that an electrical parameter (such as voltage, current, or load) has varied from a specified threshold for a certain period of time and send a message to the head-end AMI system. The AMI meter is configured to provide exception reports whenever an electrical parameter varies from the specified operational band limits.

When an AMI meter or node detects that an electrical parameter has exceeded a specified threshold for a certain period of time, the DMS is notified. Upon receiving notification of such conditions, the DMS runs the system optimization program and initiates appropriate actions (for example, operates a capacitor bank controller, voltage regulator, or load tap changer) to restore optimal conditions.


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Figure 3. Future distribution grid using EnergyAxis System for AMI

EnergyAxis System for AGI in realizing the smart grid Elster’s AGI Initiative provides the utility industry with a powerful set of hardware, software, and communications solutions needed to more effectively manage power distribution networks. AGI builds on Elster’s EnergyAxis System’s communications and metering infrastructure by adding advanced measurement and monitoring nodes and software applications to extend the reach of the AMI system to the distribution system itself.

An AMI system may be the largest single automation investment that a utility will make in its power monitoring system. AGI leverages the capabilities of the AMI system to cover key measurements from strategic locations across the distribution network. By improving the measurements received from the distribution system, utilities obtain vital information to help them make strategic decisions during crisis conditions and to control the system in an optimal manner during normal conditions. With the EnergyAxis System’s two-way communications, the utility can cost effectively extend its smart grid reach into the distribution network.

The AGI Initiative is a collaborative effort between utilities, Elster, and key technology partners to embed innovative sensing and


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monitoring technology in combination with Elster’s proven AMI technology for the smart grid of the future.

AGI and the smart grid The smart grid of the future starts with the foundation of an advanced metering infrastructure re-enforced by Elster’s AGI measurement and distribution automation nodes. AGInodes™ provide a wealth of previously unavailable information that improves the electric utilities’ knowledge about the reliability and quality of the distribution system. The AGI Initiative allows Elster and its partners to offer smart grid, standards-based solutions that enable utilities to improve the operation of their distribution network by leveraging their AMI investment.

AGI and distribution automation DA applications implemented by the utility require two-way communications with voltage regulators, capacitor banks, automated switches, and reclosers located on the feeders. One of the most significant barriers to widespread deployment of remote monitoring and control of distribution feeder equipment is the lack of reliable and cost effective facilities for communicating with this equipment. The lack of suitable communication facilities is often the reason why electric utilities do not implement continual monitoring and control on the feeder.

To address this problem, utilities can leverage their EnergyAxis System LAN and WAN communication systems linked to AGInodes to provide alternative communication channels to the DA feeder devices. AGInodes distributed throughout the feeder network re-enforce the AMI communication network.

AGI and outage management When the power fails, utilities need to find the fault location quickly so trouble crews can restore power. AGInodes can be equipped with last gasp capabilities that allow the OMS software to narrow down fault locations within the protection zone of the device. AGInodes can also confirm power restoration to verify that service has been restored.

Additionally, utilities can more quickly determine the fault location by adding AGInodes throughout the distribution network. The AGInode information enables the utility to narrow down possible fault locations, reducing the overall investigation time.

AGI and power quality Power quality (PQ) events such as voltage sags, surges, and momentary outages can result in consequences that are as minor as a light flicker to as serious as equipment damage. The ability to monitor such PQ characteristics can be a powerful tool to reduce peak system delivery losses. Additionally, the ability to track PQ profiles allows for more effective management of energy peaks during high demand, thereby allowing utilities to realize significant savings both in rate penalties and generation avoidance.


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With AGI, utilities can install smart meters or AGInodes to monitor and report PQ quantities for both current and voltage at selected customer locations. Power quality data from customer meters that are distributed throughout the feeder can help determine the location and cause of a power quality problem. Smart meters and AGInodes can also be programmed to report detection of potential PQ problems automatically so that utilities can take preventative actions.

AGI and loss detection Protecting revenue is an important attribute of an AMI system. By installing smart meters and AGInodes at distribution transformers and along the feeder, utilities have an affordable ability to narrow down the cause of potential energy loss due to theft or technical losses. To quickly pinpoint the source of potential energy loss, a utility can compare time synchronized energy measurements at targeted feeder boundary points to aggregated downstream smart meter and AGInode distribution transformer readings.

AGI and state estimation Estimating the power flow for distribution feeders helps the utility respond to the state of their distribution network. By installing AGInodes at strategic locations in the distribution system, utilities can improve their on-line power flow measurement of their distribution feeders. By continuous monitoring of power flow measurements from a strategic number of AGInodes utilities will be able to more effectively optimize energy delivery across the feeder network. Benefits include the following:

• Feeder load balancing: operators can routinely transfer feeder sections to balance loads between adjacent feeders that have substantial load diversity.

• Improved service restoration activities: operators can make informed decisions when restoring service after a fault because the system will know the pre-fault load on each feeder.

• Feeder automation override: having more accurate load flow calculations, operators can determine whether blocking actions by feeder automation can be safely overridden.

AGI and integrated volt-VAR control Demand management is designed to reduce electrical demand while minimizing electrical losses. Utilities use an integrated volt-VAR control (IVVC) system to determine the optimal settings for all distribution voltage regulating and control devices. Typical IVVC systems use on-line power flow estimates with stale data, however. Since utilities are required to maintain a set voltage to their customers, most integrated volt-VAR systems use overly conservative values to prevent unacceptable low voltage conditions.

By collecting feeder voltage measurements from selected AGInodes at strategic feeder locations (for example, at feeder extremities), the AGInodes can report these measurements on a


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periodic basis. The integrated volt-VAR system can use this information to maintain the required level of service to customers.

Conclusion Advanced metering can be much more than automated billing. The information provided by AMI systems can be used to support improved decision making by system operators, engineers, maintenance managers, and other persons throughout the enterprise. The AMI communication infrastructure should be leveraged to link feeder devices to distribution management systems. This will greatly improve the visibility of the distribution network, and will enable the electric utility to optimize the performance of field equipment. AMI should be a foundational element and a vital part of the communication backbone of electric utility’s Smart Grid vision.

About the authors

Carl LaPlace Carl LaPlace has been involved in the development and product management of power distribution automation products with several companies over the past 25 plus years. More recently he holds the position of strategic senior product manager for Elster’s Advanced Grid Infrastructure (AGI) Initiative in Raleigh, North Carolina. Previously Carl was R&D Manager for ABB MV Distribution Automation group in Raleigh, North Carolina where his main responsibility was for feeder control and feeder automation product development. Carl was also engineering manager for the Advanced Electronic Development group within Siemens Energy & Automation where he was responsible for the development and product management of specialized controls and systems for application in both industrial and utility power markets. He is a long time member of IEEE.

Robert W. Uluski, PE Robert W. Uluski has served as a lead technical consultant in the areas of distribution automation, feeder automation, and power system reliability improvement for numerous North American and International electric utilities. With over 30 years experience in the electric utility industry, Mr. Uluski's work experience includes twelve years as an engineer and engineering manager at New England Electric System (NEES). Mr. Uluski specializes in developing the business case for implementing substation and feeder automation, and has developed computer programs to assist in performing the detailed benefit cost analysis for such projects.


01 June 2009

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Realizing the smart grid of the future through AMI technology

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