creating smart distribution through automation

PAC World magazine : Creating Smart DISTRIBUTION through AUTOMATION

http://www.pacw.org/no-cache/issue/march_2012_issue/cover_story/protection_and_control_in_the_smart_grid/complete_article/1/print.html[2/23/2015 10:06:02 PM]

Home . March 2012 Issue . Cover Story . Creating Smart DISTRIBUTION through AUTOMATION

Creating Smart DISTRIBUTION through AUTOMATIONAuthor:Robert Uluski, EPRI, USA

Enhanced Distribution Operating Goals

The distribution system operating goals have always included maintaining a safe environment, providing reliable service (including restoring service quickly when the lights go out), maintaining acceptable voltage, being reasonably efficient, and protecting the assets. While these fundamental operating objectives still apply, the Electric Power Research Institute's (EPRI) R&D activities in advanced distribution applications show clearly that today's utilities are seeking to accomplish much more:

Maximize efficiency and reliabilityImprove system performanceControl the growth of demand and promote energy conservationAccommodate as many distributed energy resources (DERs) as possible, andHandle major new loads such as electric vehicle chargers

A fundamental strategy being implemented by an increasing number of utilities to accomplish many of these objectives is Distribution Automation (DA).

What is DA? Today's electric distribution systems depend on intelligent field devices and control systems to maintain maximum efficiency, reliability and performance while improving safety and protection of distribution assets. These facilities must perform properly in dynamic operating environments due to higher penetrations of distributed generating resources (including renewable energy resources with highly variable output) and new types of loads such as electric vehicle chargers. This dynamic operating environment is especially challenging for existing protection, automation, and control (PAC) facilities, which must adapt to continuously changing operating environment. Distribution system operators must also be able to deal with a rapidly expanding amount of new distribution system information that threatens to overwhelm the operators. To address this situation, distribution control centers are transitioning from mostly manually operated devices and paper-driven processes, to remotely operated devices and computer-assisted, electronic decision support systems which (in some cases) perform fully-automatic control actions without manual intervention.

Distribution SCADA - The Foundation for the Smart Distribution System A key enabler for the smart distribution system is the ability to continuously monitor and automatically control distribution field devices located in distribution substations and out on the feeders themselves. This enabler is commonly referred to as Distribution Supervisory Control and Data Acquisition (DSCADA.) Until recently, very few DSCADA facilities were available on the distribution system, especially for portions of the distribution system that are outside the substation fence (Figure 1.) To enable the smart distribution system, robust and reliable communication facilities are needed to acquire measurement data and to initiate remote control actions. One of the most significant barriers that prevent widespread DSCADA deployment is lack of available two-way communication facilities at the field devices. Distribution system communications are especially challenging due to the wide coverage area, large number of communicating devices, and presence of obstructions. Many utilities are seeking to leverage AMI communication networks and public and private infrastructure (e.g., cellular networks). However, numerous challenges must be overcome, such as overall system security, performance during power outages, and overall data throughput.

Establishing this DSCADA foundational element will enable electric distribution utilities to implement advanced distribution applications, such as Fault Location Isolation and Service Restoration (FLISR) and Volt-VAR Optimization (VVO), which are described below.

http://www.pacw.org/home.html

http://www.pacw.org/issue/march_2012_issue.html

http://www.pacw.org/issue/march_2012_issue/cover_story.html



Fault Location Isolation and Service Restoration (FLISR)

Fault Location Isolation and Service Restoration (FLISR): One of the important characteristics of the smart grid is its ability to “self heal”. This does not mean that the smart grid will be able to repair damaged equipment and automatically return the damaged equipment to service. Rather, the self-healing function will automatically restore service to as many customers as possible as quickly as possible while field crews make the necessary repairs. The key DA application for implementing a self-healing network is the FLISR application.

FLISR creates a switching plan for re-energizing portions of a distribution circuit that have been de-energized as a result of a permanent feeder fault. Once the switching plan is created, FLISR can automatically execute the plan to restore service where possible, usually in less than one minute following the initial fault occurrence. Without FLISR, at least part of the distribution feeder will be out of service until field crews arrive on the scene. Figure 2 contains a time line showing the typical sequence of activities from the occurrence of the fault to the return to normal service.

As seen on the time line, following receipt of customer telephone calls (or “last gasp” messages from advanced meters), field crews must travel to the approximate fault location identified by protective relay IEDs and faulted circuit indicators or predicted by an outage management system (OMS,) and investigate the fault by patrolling the suspected faulted portion of the feeder.

Once the field crews locate the damage, they either make the necessary repairs or isolate the problem area and perform manual switching to restore power to as

many customers as possible. Based on the typical time line, customers connected to “healthy” portions of the feeder can experience an outage lasting several hours (see Figure 2).

The FLISR application can reduce the outage duration for these same customers to less than one minute. When a fault occurs, fault detectors mounted on remote controlled line switches immediately report the fault to FLISR. Prior to performing any actual control actions, the FLISR application will allow conventional protection and control schemes (e.g., automatic reclosers) a time period to operate. If automatic reclosing is not successful, FLISR control actions are triggered. The FLISR application function

automatically detects that a fault has occurred, locates the fault (between two medium voltage switches), issues control commands to open the switches that bound the damaged area to isolate the damaged section of the feeder, and then closes other switches (where possible) to restore service to healthy sections of the feeder. The current state-of-the-art allows all of these actions to be completed without manual intervention (fully-automatic control). These steps are detailed below:

Fault Detection: FLISR should only operate following a short circuit (fault) on the feeder itself or in the facilities that normally supply the feeder. FLISR should not operate when a feeder becomes de-energized due to manual switching activities or due to a system wide emergency that triggers underfrequency or undervoltage load shedding. To meet this requirement, one or more fault detectors are needed to trigger FLISR operation when fault-level currents are detected (see Figure 3.) Common practice is to use a protective relay intelligent electronic device (IED) in the substation or a line recloser with self contained protection facilities to determine that a fault occurred in the distribution feeder protection zone and then provide a signal to trigger FLISR operation

Fault Location: The next step is to determine the "section" of the feeder that contains the fault. FLISR "sections" are portions of the feeder that are bounded by remotely controlled switches. Each switch includes a Faulted Circuit Indicator (FCI) that determines if fault current has recently passed through the switch. This would indicate that there is a fault located "downstream" (further from the substation) of the switch. FLISR uses the FCI status indications and knowledge of the as-operated feeder topology to determine what section is faulted. The faulted section is bounded by one FCI that has a fault indication and one or more FCIs that did not "see" the fault (see Figure 4)Fault Isolation: FLISR then issues control commands to open the switches needed to completely isolate the damaged section of the feeder based on the Fault Location analysis



described above (see Figure 5.) It is common practice for FLISR to defer these control actions until the standard automatic reclosing sequence has been completed. This ensures that feeder reconfiguration by FLISR is only performed following a permanent fault (should not reconfigure the feeder if fault is a self-clearing "temporary" fault)Service Restoration: Once the damaged section of the feeder is isolated, FLISR attempts to restore service to as many "healthy" sections of the feeder as possible via the available sources. Available sources include the normal source of supply to the feeder as well as any available backup sources that are connected to the faulted feeder via normally-open, remotely controlled tie switches that have spare capacity to carry additional load

Any feeder section that is “upstream” of the faulted feeder section (closer to the substation) can be restored from the original source with no verification of available capacity. However, to restore feeder sections that are “downstream” of the faulted feeder section (further away from the substation), the feeder must have at least one backup source with sufficient capacity to carry the additional load being transferred. If suitable backup sources do not exist, FLISR

provides no additional benefit beyond what can be gained through regular line reclosers without supervisory control and FLISR software. FLISR determines the “pre-fault” load on each “healthy” feeder section, and then compares that load with the spare capacity on backup sources. If sufficient capacity exists, then the tie switch is closed to restore service. If sufficient capacity does not exist, then the section in question will remain de-energized until field crews arrive on the scene. With modern application software and sufficient communication bandwidth, all of the above actions can be completed in less than one minute with no manual intervention.

As can be seen in Figure 6, the upstream portion of the feeder has been restored, and one of the two downstream sections is restored. One downstream section remains de-energized due to lack of available capacity on the backup source.

Future FLISR deployments will attempt to restore this portion of the feeder by executing demand response to release some existing capacity or perform secondary load transfers. Future FLISR applications may also use microgrid technology to restore this section of the feeder using distributed energy resources.

FLISR Impact on Existing Protection and Control Facilities

FLISR Impact on Existing Protection and Control Facilities: DA FLISR systems such as that described above must be well coordinated with existing protection and control facilities. Key issues pertaining to existing protection are described below:

The protection system must provide information to indicate that a fault has occurred on the distribution system. As noted earlier, FLISR should not operate when a distribution feeder or portion of a feeder has become de-energized due to manual switching or when underfrequency (or undervoltage) load shedding relays operate. The protection system must be able to supply fault detection information to FLISR. In most cases this requires a protective relay IED rather than an electromechanical relayFLISR should not trigger any control actions until existing protective relays systems have completed their necessary control actions, such as automatic reclosing. FLISR control actions should only be triggered when automatic reclosing is unsuccessful. Some modifications to existing protection and control functions may be needed to support this requirement. For example, if automatic reclosing is unsuccessful and the automatic reclosing relay goes to lockout, then some means must be provided to allow the affected switches to be closed via remote control following fault isolation by FLISRFLISR switch-closing actions are often disabled when field crews are performing live-line work. This is similar to the well-established practice of disabling automatic reclosing during such work activities. FLISR disabling should be included in the utility’s “hot-line” tagging procedureTransferring a significant portion of a faulted feeder to a backup feeder may lengthen the backup feeder by a considerable amount. Protective relays on the backup feeder must be able to “see” faults on the entire feeder following re-configuration. This may require extending the reach of the distribution protective relays to handle worst case conditions. Alternatively, if protective relay IEDs exist, FLISR may be able to initiate a transfer to an alternative setting group following feeder re-configuration



Volt-VAR Control and Optimization: The smart grid concept has also dramatically changed the design and operation of modern Volt-VAR control systems. The objectives for Volt-VAR Control have expanded considerably beyond simply maintaining acceptable voltage and power factor. “Volt-VAR Control” has become “Volt-VAR Optimization”, which has the expanded objectives to increase overall efficiency, reduce electrical demand, promote energy conservation, and improve power quality.

Volt-VAR Optimization (VVO) systems must accommodate distributed energy resources (DERs), and must respond automatically when the status or output level of DERs changes. In addition, VVO systems must operate effectively following feeder reconfiguration, which will happen more frequently in a smart distribution grid due to optimal network reconfiguration, automatic service restoration, and other applications involving “smart” switching. As the name implies, VVO is generally comprised of two main parts: VAR control

and Voltage control. Early volt-VAR control schemes handled these two main functions separately via independent controllers with little or no coordination of control actions. The current industry trend is integrated volt-VAR control in which control of switched capacitor banks, voltage regulators, substation transformer load tap changers (LTCs), and other volt-VAR control devices is fully coordinated to produce optimal results.

VAR Control

VAR Control is the management of reactive power flow in the electric distribution system. In the past, VAR control focused on maintaining power factor (PF) on the distribution system as close to unity as possible to reduce electrical losses and to minimize the flow of reactive power from the central generators over the transmission network to the distribution system. VAR control was usually accomplished by installing fixed and switched capacitor banks in the distribution substations and out on the distribution feeders themselves. The control objective is to switch the capacitor bank on when needed most based on “local” measurements (measurements taken at the capacitor bank location itself) that directly or indirectly indicate the need for more reactive power compensation.

Table 1 lists the typical control parameters for switched capacitor banks with standalone controllers. To achieve overall efficiency improvements, it is necessary to deploy a VVO strategy that bases its control actions on system level, rather than local, measurements.

Accomplishing this design objective requires communication facilities that are typically part of a DSCADA system. The communication facilities enable the system to base its control actions on overall system conditions rather than just on local conditions at the site of the capacitor bank or voltage regulator. The communication facilities also enable distribution system operators to monitor the status of the field voltage control and VAR control equipment so that appropriate actions can be taken immediately when a component failure occurs. Figure 8 depicts this approach. The DSCADA approach to VVO is a considerable improvement versus the standalone controller approach due to its ability to base control actions on a holistic view of the distribution system rather than local measurements. This approach works well for the operating environment that exists on many electric utility distribution feeders today (minimal DG, infrequent changes in feeder configuration0. However, in the future as the penetration of large DG units grows and advanced distribution applications (such as optimal network reconfiguration) become prevalent, the rules-based approach may lack the flexibility to address all future operating possibilities. In such cases, a more sophisticated “model-driven” solution may be needed.

Voltage Control is the management of voltage at all points along the distribution feeder. The primary objective for voltage control has been to maintain acceptable voltage for all customers under all loading conditions. Figure 7 shows the range of acceptable voltage conditions. It is common practice for utilities to operate in the upper portion of the acceptable voltage range. This ensures that the voltage will not temporarily dip below the voltage range for “out of normal operation” shown in Figure 7. Recently, as electric utilities seek to address energy efficiency and conservation portfolios, many electric distribution utilities are turning to voltage reduction (VR) as a way to satisfy energy efficiency, demand reduction, and energy conservation objectives. VR involves operating the distribution feeder at a voltage that is in the lower portion of the acceptable voltage range. Electric utility experience, backed by extensive laboratory testing, has shown that many electrical loads, especially electric motors, consume less real and reactive power and perform just as well (or better) when voltage is



lowered slightly. Numerous utilities are planning to operate with reduced voltage on a continuous basis (for energy conservation) or during peak load periods (for demand reduction). The specific benefits that can be achieved with VR depend on customer type (residential, commercial, industrial, etc), time of day, day of week and season, and other such factors. The amount of benefit is also affected by the amount the voltage can be reduced without violating the voltage constraints. VR benefits will be affected by new “up and coming” appliances that comprise a growing percentage of the load. Many new appliances will be equipped with electronic controls that exhibit “constant power” behavior which is not favorable for achieving VR benefits. With constant power loads, the electricity consumed by the device stays constant as voltage is reduced. However, as the voltage is reduced, current increases which can produce higher electrical (I2R) losses on the feeder. To assist electric utilities in evaluating the potential benefits of CVR, EPRI has embarked on a new research effort: “Load Modeling for Voltage Optimization”. This project includes laboratory testing to identify characteristics of new appliances under reduced voltage conditions, development of a library of customer load models for standard customer classes, and extensive field demonstrations to verify the accuracy of the new customer load models. This research effort is being coordinated with the Volt-VAR Task Force of the IEEE PES Smart Distribution Working Group.

Impact on Existing Protection and Control Systems: DSCADA based VVO systems are not expected to have a significant impact on existing protection systems. However, the protective relays and other IEDs will be expected to supply many of the real-time measurements needed by the VVO logic, such as current and voltage measurements, real power, and reactive power. One area of concern is the level of accuracy of such measurements. Since VVO systems are often seeking to achieve benefits of a few percentage points of normal operation, measurement accuracy of 1% or better is needed. Existing control systems, such as voltage regulators, will need to accept control signals the VVO system. Typically, control signals are provided in the form of setpoint changes. However, direct raise and lower commands may be issued to voltage regulators and substation load tap changers.

Distribution Management Systems' Evolution

Distribution Management Systems' Evolution Today, the concept of DA is evolving into a Distribution Management System (DMS), which is a decision support system to help electric utility personnel monitor and control the entire distribution system in an “optimal” manner while improving safety and asset protection. The DMS will assist, not replace, the operating personnel who will continue playing an essential role in managing the operation of the distribution system. While some DMS control applications are fully-automatic, this does not eliminate the need for operator oversight of all applications. A primary DMS objective is to optimize distribution system performance by “squeezing” as much capability as possible out of existing assets. This is a major new responsibility for control room operators, who have focused on maintaining workforce safety and “keeping the lights on.” Adding this new operating responsibility is one of the most significant DMS implementation challenges, often requiring new control room procedures, extensive training and certification, and additional technical support. The DMS is comprised of three major components: Distribution Supervisory Control and Data Acquisition (DSCADA), advanced distribution applications, and external interfaces. Figure 9 illustrates how these three pieces fit together. New DMS applications are continuously being developed to meet the growing need for decision support and advanced control in the increasingly complex distribution grid. Operation of the smart distribution grid is complicated by the presence of high penetrations of DERs and potential large new loads such as electric vehicles. Additional decision support capabilities are needed to manage these resources effectively. Several examples are listed below:

Predictive Fault Location (PFL) uses the distribution system model and fault current magnitude supplied by protective relay Intelligent Electronic Devices (IEDs) to accurately identify the location of a fault. The application uses a short circuit analysis program to identify possible fault locations that could



have produced the fault current magnitude recorded by the IEDs. In most cases, this approach is considerably more accurate than alternative fault location strategies such as OMS “outage grouping and tracing” techniques and “distance to fault” calculations contained within the protective relay IEDs.

Enhanced Fault Location and Automatic Restoration: Many utilities are implementing FLISR systems that automatically detect faults, isolate the damaged portion of the feeder, and restore as much service as possible within seconds as part of their strategy to achieve a “self healing” grid. One problem with these systems is that service restoration is often blocked due to heavy loading on backup feeders. The next generation of automatic restoration systems will take advantage of other advanced control facilities that are being deployed as part of the smart grid. For example, when encountering a load transfer limit, the automatic restoration system may initiate actions to free up capacity on the affected feeders thus enabling the load transfer to proceed. As illustrated in Figure 10, capacity release strategies may include initiation of demand response actions, activation of CVR, and temporary reduction of fast charging activities for electric vehicles.

Fault Anticipation and Contingency Analysis - While much of today’s operating activities are focused on “healing” the grid following a fault, the future DMS is expected to play a much larger role in “anticipating” problems before they occur. Current research efforts to identify incipient problems through current and voltage waveform analysis activities are achieving positive results and may soon become a part of DMS application suite. Distribution “contingency analysis” applications, which continuously examine potential outage scenarios, are also available from several

DMS vendors. When the contingency analysis program identifies a potential problem (such as a substation transformer that is approaching its loading limits) the distribution system operator is alerted so that corrective action, can be initiated.

Sidebars: As the smart distribution grid continues to unfold, there will be a growing number of new challenges for DA system operators.

Protection and control personnel and technicians must work closely with smart grid specialists to ensure the effective integration of all intelligent devices.

The new generation of “smart” distribution control centers should manage the distribution system with improved performance standards, and without compromising age-old mandates to be safe and keep the lights on and bright.

It is essential that the basic operating principles, including maintaining safety and protecting the high voltage assets, are not compromised along the way to a smarter, more efficient grid.

DA is becoming an essential element of the smart distribution system, helping utilities meet the needs of the 21st century.

The DMS is comprised of three major components: Distribution Supervisory Control and Data Acquisition (DSCADA), advanced distribution applications, and external interfaces.

Biography

Biography: Robert (Bob) Uluski has BSEE from Northeastern University and MSEE from University of Wisconsin-Madison. He is a Technical Executive at the Electric Power Research Institute. He is currently leading EPRI's effort in the areas of Distribution Management Systems and smart distribution. Prior to joining EPRI, Bob assisted many electric utilities with the planning, procurement and implementation of T&D automation systems. Bob is an officer of the IEEE PES Smart Distribution Working Group and was awarded IEEE's Douglas M. Staszesky award in 2010 for contributions in the field of DA.

Home | Current Issue | Tutorials | White papers | Books | Tools | Events | Advertising | Classified | Forum

Terms and Conditions of Use and Privacy Policy

© PAC World - Last updated: 08 May 2012

http://www.pacw.org/home.html

http://www.pacw.org/issue/december_2014_issue.html

http://www.pacw.org/tutorials.html

http://www.pacw.org/white_papers.html

http://www.pacw.org/books.html

http://www.pacw.org/tools.html

http://www.pacw.org/index.php?id=7&no_cache=1

http://www.pacw.org/advertising.html

http://www.pacw.org/classified.html

http://www.pacw.org/forum.html

http://www.pacw.org/top_menu_elements/legal.html

creating smart distribution through automation

Documents