Conference Papers

Implementation of an Innovative AdvancedLoop Scheme to Provide Distribution

Reliability Improvement

Richard WernsingJames Hubertus

Mike DuffyGreg HatawayDerek ConnerElijah Nelson

Paper No.10 B2

B2

978-1-4244-5473-0/10/$26.00 ©2010 IEEE

Implementation of an Innovative Advanced Loop Scheme to Provide Distribution

Reliability Improvement Richard Wernsing, James Hubertus, and Mike Duffy, Public Service Electric and Gas Company

Greg Hataway, formerly of Schweitzer Engineering Laboratories, Inc. Derek Conner and Elijah Nelson, Schweitzer Engineering Laboratories, Inc.

Abstract—With the ever-increasing importance of electricity, excellent service reliability is no longer a luxury in the eyes of consumers but an expectation. In response to this expectation, Public Service Electric and Gas Company (PSE&G) is making a significant investment in a new technology to help improve reliability. This new technology has resulted in an automated feeder reconfiguration scheme that not only minimizes the duration of an outage due to a fault and the number of customers impacted by it but also reduces the number of customers experiencing a blink and subsequent switching. PSE&G has implemented an innovative solution designed to improve their reliability indices. The advanced loop scheme (ALS) builds on the PSE&G standard distribution scheme that used a normally open tie to separate two feeders.

The original scheme offered automatic reconfiguration but was inherently slow and subjected customers to unnecessary blinks during reconfiguration. The new scheme uses a close-before-open methodology in which the tie is closed before sectionalizing is done. Because of this manner of operation, customers on unfaulted line sections are not exposed to an outage for the fault or the switching performed to isolate the faulted line section. Additionally, with communication comes the ability to simplify coordination and apply transmission protection principles to improve protection and increase the density of protective devices along the feeders, thus reducing the number of customers per section.

This paper examines the design and implementation of the ALS. It gives specific settings and operational details of the scheme. Additionally, a review of the operational history highlights the impact that the scheme has had on the reliability of the utility distribution network.

I. INTRODUCTION Public Service Electric and Gas Company (PSE&G), based

in Newark, New Jersey, serves 2.1 million electric customers covering a 2,600-square-mile corridor across the state from Bergen to Gloucester Counties. The service territory covers more than 300 urban, suburban, and rural communities, including the six largest cities in New Jersey. PSE&G is a recognized leader in service reliability and is committed to improving customer service and reliability. Efforts have historically been focused on improving reliability through traditional fault prevention measures, such as right-of-way maintenance. In January 2008, the PSE&G Electric Delivery Group was challenged by senior executive management to review their present operation methodology and find ways to improve reliability through better operational methods.

The Electric Delivery Group began to review all possible operating practices to find a way to improve service by reducing outages. Working with Distribution Vision DV2010, a consortium of six utilities (including PSE&G) that are dedicated to enhancing reliability, they considered high-speed network reconfiguration and new system configurations to operate the system as a looped network as opposed to the traditional radial operation. The end result was a hybrid of the two systems. They decided that the preferred manner of operation was a system normally operated radially but with a network reconfiguration scheme that tied feeders together at a normally open tie point.

To design and implement this type of scheme, PSE&G looked at available technology and sought to partner with a services group. During the design phase, much emphasis was placed on maintaining traditional safety and operational practices while looking for opportunities to improve operation, along with high-speed network reconfiguration functionality.

II. THE STARTING POINT The standard feeder layout used at PSE&G to this point

was either a three- or five-recloser loop, as shown in Fig. 1. Two feeders were separated by a normally open tie recloser, with either one or two midpoint reclosers on each feeder. Following a fault on one of the feeders, automatic reconfiguration was done by time-delayed closing of the tie on loss of voltage. Prior to the tie closing, automatic settings changes were required on the midpoint reclosers on the faulted feeder to maintain coordination for the existing fault that was fed from the alternate direction.

Fig. 1. Five-Recloser Loop

B2-1

While the automated reconfiguration of the five-recloser loop offers speed and simplicity improvements over manual local or remote switching via SCADA (supervisory control and data acquisition), it does not address momentary customer outages. Opportunities for fewer momentary outages and reduced numbers of customers experiencing these outages were identified and addressed in the new scheme development.

III. INCREASE PROTECTIVE DEVICE DENSITY The feeders chosen for the initial installation of the new

advanced loop scheme (ALS) were deemed the “worst performers” by the utility. These feeders were selected so that the anticipated dramatic improvement in reliability would be evident in a short time frame. These first feeders were in densely populated areas with a high ratio of customers per section.

In the traditional five-recloser loop, each line section averaged approximately 1,500 customers. It was recognized early in the development of the new strategy that reducing the number of customers per line section by installing additional protective devices would offer a significant benefit to improved reliability. Devices were added to reduce the number of customers per line section to approximately 500, as shown in Fig. 2. This effectively tripled the number of line sections and protective devices on each feeder.

Fig. 2. Increased Density of Protective Devices

The increased number of protective devices allows for more precision in clearing and isolating a fault so that fewer customers are affected by these events. To achieve these gains, proper coordination must be maintained between devices so that secure, selective tripping can be done. Because the traditional method of coordinating adjacent devices by delaying upstream time-overcurrent curves means prohibitively long tripping times for some faults, the scheme must address these concerns.

IV. INSTALL COMMUNICATION At the onset, the designers determined the recloser controls

would need to communicate with each other reliably and securely to realize speed improvement while maintaining safety and operational standards. To provide a medium for this communication, PSE&G decided to invest in fiber-optic cable along the feeders involved.

The recloser controls chosen for installation include a communications protocol that allows bits of information to pass between adjacent controls. Each recloser control offers two channels of this high-speed communications protocol, allowing communication between the respective adjacent upstream and downstream recloser controls. Fig. 3 illustrates this communication. Because each recloser control communicates only between the two recloser controls adjacent to it, only a single pair of fibers is needed for operation. An additional pair of fibers is used at each recloser control to allow Ethernet network communication to pass SCADA data and allow for engineering access at each control. Fig. 4 shows the details of the installed communications infrastructure.

Fig. 3. Communications Between Controls

Fig. 4. Installed Communications Infrastructure

B2-2

The ALS was developed using this high-speed communication. The foremost requirement was for the scheme to close the tie point prior to opening the isolating devices for fault clearing. This methodology ensures that only the customers on the faulted line section experience an outage, either momentary or sustained, during the fault clearing and network reconfiguration. Fig. 5 offers a simplified explanation of the close-before-open methodology.

Fig. 5. Close-Before-Open Methodology

Prior to ALS implementation, traditional time-overcurrent protection was used for feeder protection. Proper coordination was obtained by setting different pickup levels and time dial values along the feeders. With the farthest downline recloser coordinating with only one additional midpoint recloser and substation relay, maximum tripping times were held at a reasonable value for faults along the feeders. However, with the increased density of protective devices, coordination between devices using traditional methods was not realistic because tripping times would have been prohibitively high.

The capacity of the high-speed communications protocol offered a solution for the coordination issues. A blocking scheme for the overcurrent protection was developed as part of the ALS. With the normally open tie, the two feeders of the loop operate radially prior to and following reconfiguration. Because the feeders are radial, a blocking scheme relying only on simple overcurrent elements is implemented. More complicated directional blocking is not required, and consequently, the complexity of the scheme is minimized.

With the radial system, only the reclosers between the source and fault experience the overcurrent condition and can block operation of the respective upstream device. The recloser upstream and nearest the fault point does not receive a block from the next downline recloser that is on the open tie

side of the fault. In the absence of a blocking signal, the overcurrent element in the proper recloser is allowed to operate and time out. An example of the blocking scheme operation is shown in Fig. 6.

R6

Sub1

Relay

Normally Open

Recloser

R1

Recloser

R2

Recloser

R3

Recloser

R5

R4

Recloser

Recloser

BlockBlockBlock

Fig. 6. Blocking Scheme Implementation

With the blocking scheme in place, the scheme is made selective so that proper coordination between protective devices is achieved and only the proper line section for the fault is isolated.

Reliability and speed for fault clearing were addressed next. This blocking scheme allows simple overcurrent elements to be used for protection. While the blocking scheme requires only a short coordination delay for the blocking signal to be received, there are still traditional protective devices on the taps along the feeders that require proper coordination, so the time-overcurrent element used previously is retained. This element allows a proper coordinating delay for any blocking signal to be received and can be set to coordinate with any tap fuses or reclosers installed along the line. Traditional time-overcurrent elements are also retained as a backup in the event communication is lost between reclosers.

Because the ALS requires the normally open tie to be closed prior to tripping, intermediate steps were added to the traditional protection logic. The overcurrent elements were removed from directly tripping the recloser and moved to scheme initiation. In the ALS logic, once the time-overcurrent element(s) have asserted, a latching bit inside the control is set to initiate scheme operation. This latching bit triggers communication between devices along the feeder to identify the isolating recloser and close the normally open tie. Once closed, the tie returns a bit to the isolating and initiating controls to allow them to open, clearing the faulted line section. Because reconfiguration has already occurred on closing the tie, no additional customers experience any outage beyond those on the faulted line section. Operation of this scheme is further shown in Fig. 7, Fig. 8, and Fig. 9.

B2-3

Fig. 7. Initiating Sequence of Events

Blocked

R6

Sub1

Relay

Normally Open

Recloser

R1

Recloser

R2

Recloser

R3

Recloser

R5

R4

Recloser

Recloser

19: Trip Asserted 18: Bit Received

17: Bit Transmitted16: Trip Asserted15: Bit Received

14: Bit Transmitted (Echo)13: Bit Received

12: Bit Transmitted 11: Tie Closed

Blocked

Fig. 8. Sectionalizing Sequence of Events

R6

Sub1

Relay

Normally Open Recloser

R1

Recloser

R2

Recloser

R3

Recloser

R5

R4

Recloser

Recloser

Initiating Recloser Open

Isolating Recloser Open

Tie Closed

Fig. 9. Post-Event Topology

B2-4

Note that although the asserting time-overcurrent element does not trip the recloser directly, a commitment to trip is made once it asserts. The closing of the tie and subsequent tripping of the isolating and initiating reclosers are done as quickly as communication allows once the time-overcurrent element asserts. This results in only minimal time added to the fault clearing time because of reconfiguration. The time that the two feeders are tied together through the normally open tie with the fault present is minimized.

Because this reconfiguration takes place for the first trip, one shot of automatic reclosing is allowed so that customers on the faulted line section experience only a momentary outage for temporary faults. For reclosing, only the initiating recloser closes, leaving the system radial. If reclosing is unsuccessful, the open devices are locked out until repairs are made. For successful reclosing, the system goes through a restoration process after a qualifying time delay. This puts the system back at the pre-initiation topology without manual intervention.

V. SINGLE-POLE TRIPPING ENHANCEMENT The initial pilot installation used existing reclosers that

were capable of three-pole operation only. During the scheme design, it was recognized that taking advantage of reclosers and controls capable of independent pole operation could provide additional benefits. Following the pilot installation, the scheme was enhanced for single-pole operation and utilized on subsequent projects.

Operationally, the scheme performs as described previously for faults involving multiple phases. However, for single-phase faults (the most common fault experienced), the scheme only opens the recloser pole corresponding to the affected phase on the initial trip by the initiating recloser. The normally open tie and the isolating recloser continue to operate in a three-pole manner to avoid undesired system configurations. Fig. 10 illustrates operation for a single-phase fault. For permanent faults, the initiating recloser opens all three phases to lock out for unsuccessful reclosing.

Fig. 10. Single-Pole Tripping Enhancement

VI. ANTICIPATED RELIABILITY IMPROVEMENT Although there were significant challenges to overcome in

the design and implementation of the ALS, PSE&G recognized that an operational change was also required to make a meaningful impact to the service reliability provided to customers. Historically, reliability improvement resources were focused on preventative efforts, such as vegetation management, system design (e.g., lightning arrestor installation), and maintenance activities (e.g., pole replacement). While these efforts remain important, their direct impact on reliability is not easily determined. Implementation of the ALS offers a path to improving reliability in an easily quantifiable manner.

With the close-before-open methodology, both momentary and sustained outages beyond the absolute minimum are avoided. Additionally, increasing the density of protective devices to lower the number of customers per line section, as well as utilizing independent pole tripping, offers inherent improvement by increasing precision of fault isolation.

Fig. 11 and Fig. 12 are diagrams of the distribution system selected for the first implementation of the ALS. Fig. 11 shows the customer distribution along the feeders utilizing the three-recloser loop. Fig. 12 shows the placement of the increased number of protective devices and lower customer distribution per line section after implementing the ALS.

Fig. 11. Original Layout and Customer Count

B2-5

Fig. 12. Customer Count After Implementing ALS

Table I summarizes the calculated reliability index contributions from these two feeders for possible fault locations using the traditional protection scheme. For these calculations, we assume an even distribution of the 1,682 Laurel Avenue Substation customers and the 2,382 West Caldwell Substation customers served between the two line sections of each feeder.

TABLE I TRADITIONAL SCHEME RELIABILITY CONTRIBUTION

Fault Location

Customer Momentary

Outages (Temporary Faults)

Unnecessary Momentary

Outages (All Faults)

Sustained Outages

(Permanent Faults)

1 1,682 841 841

2 841 0 841

3 1,191 0 1,191

4 2,382 1,191 1,191

This system has experienced faults between the substation breaker and the midpoint recloser. In these cases, 100 percent of the customers experience a momentary outage. The duration of this momentary outage is equal to the reclose open interval (10 seconds) for temporary faults. Permanent faults on this section result in an additional momentary outage to the

customers served between the midpoint recloser and the normally open tie recloser. The duration of this momentary outage is equivalent to the transfer time for the voltage-based transfer scheme without communication (approximately 90 seconds).

With the ALS installed, the unnecessary momentary outages are eliminated, and the number of customers experiencing either momentary or sustained outages is reduced, as shown in Table II.

TABLE II ALS (THREE-POLE TRIP) RELIABILITY CONTRIBUTION

Fault Location

Customer Momentary

Outages (Temporary Faults)

Unnecessary Momentary

Outages (All Faults)

Sustained Outages

(Permanent Faults)

L1 0 0 0

L2 0 0 0

L3 146 0 146

L4 691 0 691

L5 845 0 845

W6 236 0 236

W5 561 0 561

W4 519 0 519

W3 523 0 523

W2 543 0 543

W1 0 0 0

If we consider that the first populated line segment of the ALS-configured system was previously served from the first line section of the traditional three-recloser loop, a value can be placed on improvement obtained for that particular physical fault location, as shown in Table III and Table IV.

TABLE III LAUREL AVENUE TRADITIONAL VERSUS ALS (THREE-POLE TRIP)

Customer Momentary

Outages (Temporary Faults)

Unnecessary Momentary

Outages (All Faults)

Sustained Outages

(Permanent Faults)

Traditional 1,682 841 841

ALS 146 0 146

Gain 93.5% 100% 82.60%

TABLE IV WEST CALDWELL TRADITIONAL VERSUS ALS (THREE-POLE TRIP)

Customer Momentary

Outages (Temporary Faults)

Unnecessary Momentary

Outages (All Faults)

Sustained Outages

(Permanent Faults)

Traditional 2,382 1,191 1,191

ALS 543 0 543

Gain 77.20% 100% 54.40%

B2-6

Additionally, improvements resulting from implementation of independent pole operation for temporary single-line-to-ground faults can be calculated as shown in Table V and Table VI. Presently, the scheme locks out three phases for permanent faults, so no improvements to sustained outages are seen.

TABLE V LAUREL AVENUE TRADITIONAL VERSUS ALS (SINGLE-POLE TRIP)

Customer Momentary

Outages (Temporary Faults)

Unnecessary Momentary

Outages (All Faults)

Sustained Outages

(Permanent Faults)

Traditional 1,682 841 841

ALS-SPT 49 0 146

Gain 97.08% 100% 82.60%

TABLE VI WEST CALDWELL TRADITIONAL VERSUS ALS (SINGLE-POLE TRIP)

Customer Momentary

Outages (Temporary Faults)

Unnecessary Momentary

Outages (All Faults)

Sustained Outages

(Permanent Faults)

Traditional 2,382 1,191 1,191

ALS-SPT 181 0 543

Gain 92.40% 100% 54.40%

VII. OPERATIONAL EXPERIENCE The June 2008 initial installation of the ALS was a pilot

project involving two feeders. Subsequently, loops have been installed, and operational experience has been gained. Because this was a radically different approach to distribution system operation, there was much interest in the clearing time difference between the traditional protection philosophy and the ALS philosophy of reconfiguration before clearing.

The following diagrams and figures show the oscillography captured from the three reclosers involved in an actual fault. The fault was located one line section away from the normally open tie between two of the feeder reclosers, as shown in Fig. 13. Fig. 14 shows the event report captured at the initiating recloser, R4, for this event.

Fig. 13. Recloser Positions for Oscillography

Fig. 14. Event Report Captured at Initiating Recloser

The increased phase currents and depressed voltages identify this as a three-phase fault. The dashed vertical line indicates when the trip was asserted following closing of the normally open tie.

Fig. 15 shows the waveforms seen by the isolating recloser, R5. The dashed vertical line indicates when the tie closed. R5 opened 3 cycles after the digital trace TRIP3P was asserted, and the fault was isolated. Evidence of the closing of the normally open tie recloser is apparent from the increase in currents seen by the isolating recloser. To this point, the isolating recloser had not experienced fault current values. The duration between the tie closing and the trip assertion at the isolating recloser can also be calculated from the event by subtracting the time that fault currents were seen at the recloser from the time the trip was asserted.

Fig. 15. Waveforms as Seen by the Isolating Recloser R5

B2-7

B2-8

Finally, Fig. 16 shows the values captured at the tie recloser. In this waveform capture, voltage from either side of the normally open tie is shown with the currents. The currents at the top of the graph are an indication of how long the two feeders were tied together with the fault present. The middle traces show the prefault voltage seen on the nonfaulted feeder, followed by the depressed voltage when the systems were tied together, and finally the return to normal when the isolating recloser opened to separate the systems. The bottom traces show the voltage on the faulted feeder during the radial fault, followed by the increased voltage during the time the systems were tied together, and finally a return to normal voltage when the systems were separated again. Note that the systems were tied together for only about 3 cycles. This time is not related to the severity of the fault but to the communications time between the tie and the isolating recloser.

Fig. 16. Values Captured at the Tie Recloser

VIII. CONCLUSIONS The implementation of this ALS is an aggressive approach

aimed at improving the experience seen by the end user of the utility product. While often perceived as harmless in relation to sustained outages, momentary outages or blinks are significantly disruptive to customers. This innovative change in the method of operation makes measurable improvements to reliability indices by eliminating all unnecessary momentary outages. While improvement to these measured and calculated scores is important, the ALS also offers improvement to the utility customers’ perception of service because they experience far fewer blinks that disrupt many commercial and residential processes.

The following summarizes some important discoveries: A close-before-open reconfiguration methodology

offers a solution to unnecessary outages of any kind. Technology is available now to implement innovative

schemes previously thought to be unattainable. Adding precision to fault isolation through

independent phase operation and higher density of protective devices offers an inherent improvement to reliability by minimizing the number of affected customers.

IX. BIOGRAPHIES Richard Wernsing works at Public Service Electric and Gas Company (PSE&G) as a maintenance expert. He has extensive knowledge and technical expertise, with over 40 years of experience at PSE&G in the delivery, transmission, and production of electricity and support of computer and telecommunications. Most recently, he has developed a computerized maintenance management system that provides condition and critical assessment for inside plant equipment, including transformers, breakers, and relays.

James Hubertus, P.E., received his B.S. in Electrical Engineering from Lafayette College in 1990 and his M.S. in Electrical Engineering from the New Jersey Institute of Technology in 1995. He joined Jersey Central Power and Light (JCP&L) as a relay and controls engineer in 1990. In 1996, he left JCP&L and joined ABB as an application engineer. In 1997, he joined Public Service Electric and Gas Company (PSE&G) as a relay engineer. Currently, he works for PSE&G as the manager of system protection. He is pursuing his Ph.D. in Electrical Engineering at the New Jersey Institute of Technology. Mr. Hubertus has more than 15 years of experience in the design and analysis of power system protection schemes and in the study of power systems. He is a registered professional engineer in the State of New Jersey.

Mike Duffy graduated from the New Jersey Institute of Technology and has over 20 years of experience working for Public Service Electric and Gas Company. He has held various positions, including relay technician, construction specialist responsible for the construction and commissioning of electric delivery and transmission projects, and, most recently, senior distribution supervisor.

Greg Hataway received his B.S. in Electrical Engineering from the University of Alabama in 1991. He has broad experience in the field of power system operations and protection. Upon graduating, he served nearly 12 years at Alabama Electric Cooperative, where he worked in distribution, transmission, and substation protection before assuming the role of superintendent of technical services. In this position, he coordinated the utility’s efforts in protection and power quality. He worked at Schweitzer Engineering Laboratories, Inc. for seven years as a field application engineer in the southeast region of the United States.

Derek Conner received his B.S. in Electrical Engineering from Pennsylvania State University in 2005. He has broad experience in the field of power system protection, including industrial, generation, distribution, and transmission. Upon graduating, he worked as a field engineer for Electric Power Inc. testing power plant and substation relays and gaining experience with generator and motor protective relays. Derek joined Schweitzer Engineering Laboratories, Inc. in 2007 and is a protection engineer in the engineering services division.

Elijah Nelson received his B.S. in Electrical Engineering from Washington State University in 2006. He joined Schweitzer Engineering Laboratories, Inc. in 2006 and currently holds the position of marketing engineer responsible for distribution relays and distribution controls worldwide. Eli has been a member of the IEEE since 2002.

20100204 • TP6420