AC Substation Equipment Failure Report - nerc.com Substation Equipment Task Force ACSETF...been...

NERC | AC Substation Equipment Failure Report | November 2014 I

AC Substation Equipment Failure Report NERC ACSETF

December 2014

Table of Contents

Preface ....................................................................................................................................................................... iii

Executive Summary ................................................................................................................................................... iv

Introduction ................................................................................................................................................................1

Chapter 1 – Equipment Failure Analysis and Observation .........................................................................................4

Chapter 3 – Discussion of Observations and Recommendations ............................................................................ 23

Chapter 4 – ACSETF Roster ...................................................................................................................................... 26

Appendix – Analysis of TADS Data ........................................................................................................................... 29

NERC | AC Substation Equipment Failure Report | November 2014 ii

Preface The North American Electric Reliability Corporation (NERC) is a not-for-profit international regulatory authority whose mission is to ensure the reliability of the bulk power system (BPS) in North America. NERC develops and enforces Reliability Standards; annually assesses seasonal and long-term reliability; monitors the BPS through system awareness; and educates, trains, and certifies industry personnel. NERC’s area of responsibility spans the continental United States, Canada, and the northern portion of Baja California, Mexico. NERC is the electric reliability organization (ERO) for North America, subject to oversight by the Federal Energy Regulatory Commission (FERC) and governmental authorities in Canada. NERC’s jurisdiction includes users, owners, and operators of the BPS, which serves more than 334 million people. The North American BPS is divided into several assessment areas within the eight Regional Entity (RE) boundaries, as shown in the map and corresponding table below.

FRCC Florida Reliability Coordinating Council

MRO Midwest Reliability Organization NPCC Northeast Power Coordinating

Council RF ReliabilityFirst SERC SERC Reliability Corporation SPP-RE Southwest Power Pool Regional

Entity TRE Texas Reliability Entity WECC Western Electricity Coordinating

Council

NERC | AC Substation Equipment Failure Report | November 2014 iii

Executive Summary Background NERC’s AC Substation Equipment Task Force (ACSETF) was formed to analyze one of NERC’s top-priority reliability issues: ac substation equipment failures. This report presents the analysis of substation alternating current (ac) equipment failures and contributing causes based on the data gathered by the ACSETF.1 It summarizes contributing causes, observations, and recommendations to reduce the impact of substation equipment failures. As reported in NERC’s 2013 State of Reliability report2 and reconfirmed in the 2014 State of Reliability report,3 ac substation equipment failures are a significant contributor to disturbance events and have a positive correlation to increased transmission outage severity.4 AC substation equipment failure data was assembled from NERC’s Event Analysis Process,5 the Transmission Availability Data System (TADS)6 (including a voluntary survey7), and equipment failure data collected by the WECC Substation Work Group (SSWG).8 The ACSETF analyzed ac substation equipment failures, identified possible root causes and contributing causes, and developed observations, conclusions, and recommendations to reduce the risk to BPS reliability by reducing the impact of ac substation equipment failures. The ac substation equipment failure data varied from data source to data source. For example, the data was collected at various voltage thresholds, some data sources include equipment nameplate information, and each data source had varying degrees of root cause investigation and coding. AC Substation Equipment Failures Impact Transmission Severity Metric Inherent in ac substation equipment failure is an increased probability that additional BPS elements will also be forced out of service, potentially increasing the calculated value of the transmission severity metric. The current method of calculating transmission outage severity does not include the impact of transformer outages and treats the impact of any line within a voltage class as identical, without regard to actual capacity or value to reliability of the integrated transmission system. It also does not consider the impact of outage duration in the calculation. The definition of transmission severity, and the function and configuration of ac substation equipment, naturally lead to a positive correlation of ac substation equipment failures with increased transmission severity. Transmission severity metrics and suggested improvements to its calculation are discussed further in this report. The recommended improvements include adding an outage duration component and including transformer outages to the transmission severity metric calculation. Automatic Outages from AC Substation Equipment Failures Decline In addition to the transmission severity metric, NERC metric ALR6-13,9 the ACSETF reviewed the metric Automatic Outages Initiated by Failed AC Substation Equipment/AC Circuit Equipment. An analysis of ALR6-13, provided later in the report, revealed that ac substation equipment failures are on a downward trend and have been consistently

1ACSETF Scope, http://www.nerc.com/comm/PC/AC%20Substation%20Equipment%20Task%20Force%20ACSETF/ACSETF_Scope_June_2013_updated%2009-18-2013.pdf 2 2013 State of Reliability report, http://www.nerc.com/pa/RAPA/PA/Performance%20Analysis%20DL/2013_SOR_May%2015.pdf 3 2014 State of Reliability report, http://www.nerc.com/pa/RAPA/PA/Performance%20Analysis%20DL/2014_SOR_Final.pdf 4 Transmission Severity, 2013 State of Reliability report, http://www.nerc.com/pa/RAPA/PA/Performance%20Analysis%20DL/2013_SOR_May%2015.pdf 5 NERC Event Analysis Process, http://www.nerc.com/files/ERO_Event_Analysis_Process_Document_Version_1_Feb_2012.pdf 6 TADS, http://www.nerc.com/pa/RAPA/tads/Pages/default.aspx 7 TADS Voluntary Survey, http://www.nerc.com/comm/PC/AC%20Substation%20Equipment%20Task%20Force%20ACSETF/ACSETF_Substation_Equipment_Failure_Survey_112213_final.xlsx 8WECC SSWG, http://www.wecc.biz/committees/StandingCommittees/OC/TOS/SSWG/Shared%20Documents/Forms/AllItems.aspx 9 ALR6-13, http://www.nerc.com/pa/RAPA/ri/Pages/Automatic-OutagesInitiatedbyFailedACSubstationACCirc.aspx

NERC | AC Substation Equipment Failure Report | November 2014 iv

http://www.nerc.com/comm/PC/AC%20Substation%20Equipment%20Task%20Force%20ACSETF/ACSETF_Scope_June_2013_updated%2009-18-2013.pdf

http://www.nerc.com/comm/PC/AC%20Substation%20Equipment%20Task%20Force%20ACSETF/ACSETF_Scope_June_2013_updated%2009-18-2013.pdf

http://www.nerc.com/pa/RAPA/PA/Performance%20Analysis%20DL/2013_SOR_May%2015.pdf

http://www.nerc.com/pa/RAPA/PA/Performance%20Analysis%20DL/2014_SOR_Final.pdf

http://www.nerc.com/pa/RAPA/PA/Performance%20Analysis%20DL/2013_SOR_May%2015.pdf

http://www.nerc.com/files/ERO_Event_Analysis_Process_Document_Version_1_Feb_2012.pdf

http://www.nerc.com/pa/RAPA/tads/Pages/default.aspx

http://www.nerc.com/comm/PC/AC%20Substation%20Equipment%20Task%20Force%20ACSETF/ACSETF_Substation_Equipment_Failure_Survey_112213_final.xlsx

http://www.nerc.com/comm/PC/AC%20Substation%20Equipment%20Task%20Force%20ACSETF/ACSETF_Substation_Equipment_Failure_Survey_112213_final.xlsx

http://www.wecc.biz/committees/StandingCommittees/OC/TOS/SSWG/Shared%20Documents/Forms/AllItems.aspx

http://www.nerc.com/pa/RAPA/ri/Pages/Automatic-OutagesInitiatedbyFailedACSubstationACCirc.aspx

Executive Summary

at a low level of failures. The ACSETF recommends the initiation of enhanced data collection on ac substation equipment failures. Additional information is needed on each failure to identify substation equipment failure trends. There may be opportunities for NERC to collaborate with other organizations for data sharing and collection. Observations and Recommendations The ACSETF does not believe that ac substation equipment failures are at a level that warrants immediate intervention to reduce the failure rate. The 2014 State of Reliability report states: “The metric (ALR6-13) shows that outages per element demonstrate year-over-year improvement from 2011 to 2013.” In fact, that metric has been consistently below 0.05 outages per ac circuit due to ac substation equipment failures for six years now. Nevertheless, the ACSETF recommends continued monitoring of ac substation equipment failures. This monitoring could identify emerging trends that need to be communicated to the industry. Rather than duplicate data that is being collected by other organizations, the ACSETF recommends that NERC research a cooperative method of acquiring and analyzing substation equipment failure data with other organizations that are currently collecting failure data and performing analysis. In addition to the suggestions above, the ACSETF also proposes following observation and recommendations:

Table 1: Observations and Recommendations

Observation Recommendation Referencing Section of Chapter 3 for Further Detail

Reliance on TADS6 data and transmission severity calculation does not provide industry a complete picture of failed ac substation equipment’s impact on reliability.

NERC should incorporate data from other sources and analyze the impact on BES reliability. NERC should consider improvements in transmission severity calculation as mentioned in report.

Transmission Severity and TADS Data

The failure of a circuit breaker to operate properly increases the probability that additional BPS elements will also be forced out of service, increasing the transmission outage severity of the incident.

NERC should evaluate the failure rate of circuit breakers and consider the impact of bus configuration on ac transmission circuit outages.

Equipment Application, Bus configuration and Design

Bus configuration is the primary determinant of the impact of breaker failure on transmission outage severity.

Entities should evaluate the impact of breaker failures on system performance when choosing bus configurations for new installations or modifying existing substations.

Equipment Application, Bus configuration and Design

The duration of a BPS element outage is not captured in the transmission outage severity calculation.

NERC should add a duration component to transmission outage severity calculation.


Transformer outages are not included in the transmission outage severity calculation.

NERC should add a component to account for transformer outages to transmission outage severity calculation.


NERC | AC Substation Equipment Failure Report | November 2014 v

Executive Summary

Table 1: Observations and Recommendations

Observation Recommendation Referencing Section of Chapter 3 for Further Detail

Existing data collection processes are not sufficient for cause analysis of failed ac substation equipment.

NERC and entities should investigate a consistent method for collection of ac substation equipment failure data using industry guidelines and share the results with applicable organizations.

Improving Data Collection

The historical reporting practice of treating bushings as a part of a large piece of substation equipment could lead to insufficient research or industry-wide notification, causing system reliability vulnerabilities to persist.

High-voltage equipment bushings should be categorized and treated as a completely separate piece of substation equipment.

Improving Data Collection

The analysis of ALR6-13 indicates that the outage trend of Failed ac substation equipment is declining and immediate intervention is not warranted at this time.

NERC should continue to monitor and trend this metric.

ALR6-13: Automatic Outages Initiated by Failed AC Substation Equipment

The ACSETF recommends that substation equipment failure analysis be continued. This analysis may be performed as a regional activity, similar to WECC SSWG, or in partnership with various industry groups. The analysis should be gathered by NERC for trending and reporting. Analysis of existing data sets cannot validate whether the current level of performance is acceptable. Finally, the ACSETF concludes that, though it is not possible to eliminate all substation equipment failures, it is important that entities design, build, and maintain substation configurations and equipment to minimize adverse effects (i.e., severity) associated with potential ac substation equipment failures. Determination of the BPS reliability implications and transmission outage severity can provide a basis for system enhancement. Report Organization Chapter 1 introduces the ACSETF and provides the background information related to the formation of ACSETF, and Chapter 2 details the equipment failure analysis performed by the ACSETF. Chapter 3 presents observations and recommended actions from the ACSETF. Chapter 4 provides the ACSETF roster.

NERC | AC Substation Equipment Failure Report | November 2014 vi

Introduction Purpose The ACSETF was formed to analyze one of NERC’s top-priority reliability issues: ac substation equipment failures. As reported in NERC’s 2013 State of Reliability report and reconfirmed in the 2014 State of Reliability report, ac substation equipment failures have been found to be a significant contributor to disturbance events, and have a positive correlation to increased transmission outage severity. The ACSETF analyzed ac substation equipment failure data from NERC’s Event Analysis Process (EAP),5 the Transmission Availability Data System (TADS),6 and equipment failure data collected by the WECC Substation Work Group (SSWG).8 The purpose of the analysis was to identify key factors associated with ac substation equipment failures that increased transmission outage severity and to recommend corrective actions to mitigate the impact of these failures on the BS. Membership The scope of the ACSETF was approved by the NERC Planning Committee (PC) on June 12, 2013, and was endorsed by the NERC Operating Committee (OC) on September 18, 2013. The ACSETF is comprised of the following:

1. Subject matter experts from each of the eight NERC Regions

2. At least one representative each with experience in transmission planning/operating, system protection, human performance, ac substation design, and ac substation maintenance, including but not limited to circuit breakers, transformers, arresters, and switches

3. A NERC staff coordinator

Additional members that have subject matter expertise that may be added at the request of the PC and OC. Industry experts may be requested to participate as guests to support the task force’s activities. Please refer to Chapter 4 for a roster of the task force members. Activities The ACSETF began work in October 2013 by conducting periodic conference calls and holding several face-to-face meetings. NERC provided event analysis data that was collected from 2010 through 2013. Regional Entity ACSETF members performed the event analysis for their Regions to ensure that the confidentiality of the event data was maintained. NERC staff performed an analysis of the TADS data from 2008 through 2013, and additional data from a voluntary TADS survey was conducted specifically for the ACSETF. The WECC ACSETF members performed an initial analysis of the WECC Region data collected on substation equipment failures from 1983 through 2013. The data analysis was presented to the ACSETF, which performed the following activities:

• Analysis of ac substation equipment failure data and contributing outage cause identification

• Identification of specific actionable items

• Development of conclusions and recommendations from the analysis of ac substation equipment failures

NERC | AC Substation Equipment Failure Report | November 2014 1

Introduction

AC Substation Equipment Failure and Transmission Severity Inherent in the analysis of ac substation equipment failure is an increased probability that additional BPS elements will also be forced out of service, potentially increasing transmission outage severity. The concept of transmission severity was introduced in NERC’s 2013 State of Reliability report. It is based on the analysis of outages of ac transmission circuits in TADS. TADS data was historically collected for circuits operating at 200 kV and above. For any given event, transmission severity is calculated using the following equation:4

𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇 𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑇𝑇𝑇𝑇𝑆𝑆𝑆𝑆𝑇𝑇𝑟𝑟𝑟𝑟𝑟𝑟𝑟𝑟 =∑ (𝑀𝑀𝑀𝑀𝑀𝑀𝑟𝑟𝑎𝑎𝑎𝑎 × 𝑀𝑀𝐴𝐴 𝐴𝐴𝑇𝑇𝑇𝑇𝐶𝐶𝐶𝐶𝑇𝑇𝑆𝑆𝑇𝑇 𝑂𝑂𝐶𝐶𝑆𝑆𝑇𝑇𝑂𝑂𝑆𝑆𝑇𝑇)𝑉𝑉𝑉𝑉𝑉𝑉𝑉𝑉𝑟𝑟𝑎𝑎𝑉𝑉 𝐶𝐶𝑉𝑉𝑟𝑟𝑟𝑟𝑟𝑟

∑ (𝑀𝑀𝑀𝑀𝑀𝑀𝑟𝑟𝑎𝑎𝑎𝑎 × 𝑇𝑇𝑇𝑇𝑆𝑆𝑇𝑇𝑇𝑇 𝑀𝑀𝐴𝐴 𝐴𝐴𝑇𝑇𝑇𝑇𝐶𝐶𝐶𝐶𝑇𝑇𝑆𝑆𝑇𝑇)𝑉𝑉𝑉𝑉𝑉𝑉𝑉𝑉𝑟𝑟𝑎𝑎𝑉𝑉 𝐶𝐶𝑉𝑉𝑟𝑟𝑟𝑟𝑟𝑟

Table 2 lists the MVA assigned to ac transmission circuits for each TADS voltage class.

Table 2: Transmission Severity Equivalent MVA Values10 Voltage Class Equivalent MVA Value 200–299 kV 700 300–399 kV 1,300 400–599 kV 2,000 600–799 kV 3,000

This measure of transmission severity does not include the impact of transformer outages and treats the impact of any line within a voltage class as equal. It also ignores the actual loading of the line at the time of the outage, assumes the relative value of each line to reliability is equivalent, and does not consider the duration of the outage. Transmission severity associated with an event can only increase in one of two ways:

• An increase in the voltage class of the transmission line associated with the event; or

• An increase in the number of transmission lines interrupted in the event

The function and arrangement of substation equipment often increases the number of transmission lines forced out of service when substation equipment fails. By design, substation equipment is always located in close proximity to transmission line terminals. In some cases, substation equipment failures can be explosive and combustive, resulting in additional ac transmission circuits forced out of service. In addition, faults caused by substation equipment failure can result in large fault currents in the ground grid, occasionally impacting relay communications which leads to protection system misoperations. Multiple protection system misoperations can also be caused by failed instrument transformers. AC circuit breakers have been identified in the 2013 State of Reliability report as the most common type of failed ac substation equipment. A circuit breaker is used as an interrupting device for one or more circuit elements, interrupting both load and fault currents. Circuit breakers are the most prone to failure due to:

• Frequency of operation

• Number of circuit breakers in service In addition, circuit breakers contribute to increased transmission severity because they can impact multiple transmission elements upon failure.

10 http://www.nerc.com/docs/pc/rmwg/SRI_Equation_Refinement_May6_2011.pdf


http://www.nerc.com/docs/pc/rmwg/SRI_Equation_Refinement_May6_2011.pdf

Introduction

Depending on bus configuration, a circuit breaker failure will cause the transmission severity to increase more than any other substation equipment failure because of its potential to involve multiple ac circuits. When other substation equipment fails, only one circuit is typically removed from service. A protection system misoperation can cause the transmission outage severity to increase because it has the possibility of removing multiple ac circuits similar to failed circuit breakers. However, the duration of the outage is minimal compared to to the time it takes to replace a failed circuit breaker. A misoperation of the protection system can occur at the same time as the failed circuit breaker, which can cause more transmission circuits to be out of service.


Chapter 1 – Equipment Failure Analysis and Observation Description of Data Sources Several data sets were used in the research and development of this report. The data has not been collected in a consistent manner and, therefore, it was difficult to detect trends or root causes of failure. Manufacturer information in the data sets does not have the specificity required to develop trends on potential design and quality issues. In addition, since the failure mode data lacks detail, it was not possible to determine any common trend of failure mode for a particular manufacture or design. NERC Event Analysis Process5 The event analysis data used by the ACSETF consists of data that was received through the NERC Event Analysis Process (EAP). The EAP is a voluntary process that entities elect to participate in by submitting brief reports for qualifying events. A description of the types of events that are considered to be qualifying events can be found in the EAP document.Error! Bookmark not defined. The EAP received 393 qualifying event brief reports from November 2010 through September 2013. These 393 brief reports were reviewed for substation equipment failures by NERC and Regional Entity event analysis staff. There were 83 reports identified as having substation equipment failures as a part of the qualifying event. Those 83 reports were reviewed for information regarding the cause of the station equipment failures. Information from the reports was redacted to maintain anonymity and was aggregated into a single data set for analysis. WECC SSWG8 Trouble Reports WECC has a process in place to collect data on substation equipment failures. This data set includes the equipment manufacturer’s name, equipment model type, and date of manufacture. A utility can submit a trouble report any time a piece of equipment fails to perform as designed. Seventy-seven percent of WECC trouble reports did not involve system outages or disturbances. The concept is to share information with WECC member utilities about equipment failure trends before they cause a problem for another utility. WECC SSWG is made up of substation maintenance engineers and supervisors from the WECC member utilities. The work group annually collects trouble reports from participants on substation equipment problems. Participation in the work group is voluntary, and most years it receives participation from 40 to 50 percent of the members. The WECC SSWG started collecting reports in 1984 and now has 30 years of data on substation equipment problems. Each trouble report contains the following data:

• Equipment type • Manufacturer name • Model number • Equipment ratings • Severity of system disturbance (if any occurred) • Date of manufacture • Date of reported trouble • Problem type • Problem description

Six of the major substation equipment types are further broken down by problem type for additional trend analysis, as listed below:

Circuit Breaker Circuit Switcher Disconnect Switch


Chapter 1 – Equipment Failure Analysis and Observation

• Interrupter • Interrupter • Live Parts

• Operating Mechanism • Operating Mechanism • Operating Mechanism

• Relay or Trip/Close Coil • Live Parts • Insulator

• Dielectric • Insulator • Other/Unknown

• Mechanical • Other/Unknown

• Electrical Accessory

• Other/Unknown

Transformer Instrument Transformer Bushing

• Winding • Winding • Transformer

• Dielectric • Dielectric • Circuit Breaker

• Tap Changer • Mechanical • Instrument Transformer

• Mechanical • Other/Unknown • Other/Unknown

• Electrical Accessory

• Other/Unknown

WECC performs trend analyses within each major equipment type to look at failures based on age of equipment or model type. While the data from WECC is small compared to the industry overall, it is believed to be statistically representative of the rest of the industry. NERC and entities should investigate a consistent method for collection of ac substation equipment failure data using industry guidelines, and share the results with applicable organizations. For the purpose of this report, ACSETF reviewed the categories mentioned above, but not all of them have been included in the analysis, due to lack of data availability. NERC Transmission Availability Data System (TADS) TADS data used by ACSETF consist of following two datasets: TADS Mandatory Survey Transmission outage data is collected in a common format in TADS for:

1. ac circuits ≥ 200 kV (overhead and underground)

2. transformers with ≥ 200 kV low side

3. ac/dc back-to-back converters with ≥ 200 kV ac on both sides

4. dc circuits with ≥ ±200 kV dc voltage Analysis of the TADS data is used to quantify certain performance aspects of the transmission system. In addition to collecting simple transmission equipment availability, TADS collects detailed information about individual outage events. When analyzed at the regional and NERC level, this data provides information that may be used to improve reliability.



TADS Voluntary Survey The ACSETF conducted a voluntary survey to provide additional insight into automatic outages due to ac substation equipment failure. The survey was based on TADS Common Dependent Mode Automatic Outages with an initiating or sustained cause code of Failed AC Substation Equipment or Failed AC Circuit Equipment for calendar years 2008, 2009, 2010, 2011 & 2012. The important data fields that were requested in the survey included: type of failed equipment, cause of failure, manufacturer, bus configuration, age, and model number. Entities provided survey responses for 251 TADS events. The detailed analysis of survey data can be found in various sections of this report as supplemental information to other data sources. CIGRE11 ACSETF also reviewed two CIGRE reports related to ac substation equipment failure modes. The first of these was the Final Report of the 2004 – 2007 International Enquiry on Reliability of High Voltage Equipment, Part 2, and Reliability of High Voltage SF6 Circuit Breakers, published in October 2012 by the CIGRE Working Group A3.06. This report contained the results of survey data from 2004 to 2007 for circuit breakers greater than 60 kV and encompassed approximately 281,090 circuit breaker years of service. The second report was the Final Report of the 2004 – 2007 International Enquiry on Reliability of High Voltage Equipment, Part 4, and Instrument Transformers, published in October 2012 by CIGRE Working Group A3.06. This report contained the results of survey data from 2004 to 2007 for instrument transformers 60 kV and higher. It included 690 major failures, encompassing approximately 1,290,335 instrument transformer years of service. 2013 SOR Survey In 2013, an additional voluntary survey was conducted by the TADS Working Group to obtain more detailed data on substation equipment failures to support the findings in the 2013 State of Reliability report. The survey was developed and conducted in early 2013. It requested respondents to identify the type of equipment involved in 2012 TADS outages caused by substation equipment failures. Respondents cited circuit breakers as the failed equipment in 29 percent of the 2012 outages considered. Thirty-four percent of the outages were due to “Other,” or unknown, equipment. Analysis and Observations by Equipment Type The following highlights the analysis and observations gained from the data sources. These are arranged by types of substation equipment and their associated components. The major equipment types included are circuit breakers, transformers, instrument transformers, arresters, and bushings. Figure 1 shows the substation failures by equipment types and Table 3 shows the distribution of failures by equipment type from various data sources.

11 CIGRE, http://a3.cigre.org/Publications/Technical-Brochures


http://a3.cigre.org/Publications/Technical-Brochures


Figure 1: AC Substation Equipment Failures by Equipment Type

Table 3: Data Source, Number of Failures and Equipment Type

Equipment Type Number of Failures

Data Source NERC EA TADS Survey WECC Total

Circuit Breaker 43 62 745 850 Transformer 8 25 569 602 Bushing 5 15 195 215 Instrument Transformer 12 10 83 105

Switch 2 6 63 71 Capacitor 49 49 Circuit Switcher 1 49 50 Arrester 13 15 33 61 All Other 94 78 172

39%

28%

10%

5% 3% 2% 2%3%

8%Circuit Breaker

Transformer

Bushing

Instrument Transformer

Switch

Capacitor

Circuit Switcher

Arrester

All Other



Circuit Breakers Based on the voluntary SOR survey conducted on 2012 TADS outages, the 2013 SOR stated that 29 percent of TADS outages initiated by failed ac substation equipment are due to circuit breaker failures. AC circuit breakers were identified in the 2013 State of Reliability report as the most common type of failed ac substation equipment. Circuit breaker failures fall into two general categories. The first category includes failures that initiate faults, such as bushing failures or loss of interrupting medium. The second and more common failure occurs when a breaker is called upon to clear a fault on another circuit element and fails to do so within a predetermined time interval. This type of failure will result in breaker failure relay operation or backup protection removing additional circuit elements. All types of breaker failures will result in more than one BES element being removed, which causes an increase in the transmission outage severity calculation. Not all breaker failure relay operations are due to breaker failures. In some cases, the relay operation is a misoperation of the breaker failure relay, and in others it is a failure of the protection system to energize the breaker trip coils for reasons not related to the breaker itself. The failure to energize the trip coils is usually due to a failed auxiliary relay or another dc control component in the protection system. It is likely that a significant number of breaker failure reports in TADS and other data sources are, in fact, protection system failures. The NERC definition of protection system includes the trip coils of any circuit breaker required to trip. In general, trip coil failures are usually not failures of the protection system, but are caused by sluggish or stuck breaker mechanisms. Most Protection System failures due to failed breaker trip coils are more properly considered breaker failures. The ACSETF further categorized circuit breaker failures into four distinct failure modes. These failure modes are interrupter, mechanism, relay/trip coil and bushing.12 Figure 2 shows circuit breaker failure by failure mode and Table 4 shows the distribution of failures by failure mode from various data sources.

Figure 2: Circuit Breaker Failure by Failure Mode

12 WECC data categorizes bushing as a separate failure, the analysis if bushing is mentioned in separate section in this chapter.

38%

37%

11%14%

Interrupter

Mechanism

Relay/Trip Coil

All Other



Table 4: Data Source, Number of Failures, and Failure Mode

Failure Mode

Number of Failures

Data Sources

NERC EA TADS

Survey WECC Total Interrupter

22 18 177 217 Mechanism

8 15 116 139 Relay/Trip Coil 1 7 19 27 All Other 2 16 139 157 Total 33 56 451 540

Circuit breaker analysis by failure mode Interrupter Interrupter problems are caused by a problem with any portion of the energized, internal, or current carrying parts of the circuit breaker. A breaker failure was classified as an interrupter failure when:

1. The breaker was called upon to open and subsequently failed internally;

2. The breaker failed to extinguish the arc after opening and the breaker failure relay operated; or

3. The breaker failed internally due to the interrupter contacts not closing properly. The data analysis indicated that 38 percent of circuit breaker failures are due to interrupter failures.13 The ACSETF was not able to identify any trends with a particular manufacturer or model of circuit breaker due the lack of data that supports the analysis. More data would enhance the ability to analyze circuit breaker failures and determine detailed trends, and should include at minimum:

1. Manufacturer name

2. Model/type

3. Date of manufacture

4. Failure mode A more formal approach would be to use the IEEE Guide for Investigation, Analysis, and Reporting of Power Circuit Breaker Failures (C37.10-2011). This guide provides a well-defined framework for future data collection and standardized failure modes.

13 Event Analysis data was 46.5% (20/43), TADS survey data was 32.3% (21/65) and WECC data was 39.2% (177/451)



The ACSETF also looked at the CIGRE circuit breaker data for the analysis. However, the CIGRE data was parsed differently than the other data that the task force used. CIGRE divided failures into minor and major categories. For the CIGRE circuit breaker data, it only represents SF6 Gas Circuit Breakers. It did not include oil circuit breakers or air blast circuit breakers. The CIGRE circuit breaker data parsed failed components into four categories, as opposed to the other data sources that used seven circuit breaker component categories. Breaker Mechanism Failures Operating mechanism problems are problems associated with the mechanism responsible for opening or closing the circuit breaker contacts or storing the energy required to move the contacts. When these failures retard or prevent tripping, on occasions where the breaker is operated to clear a fault, they will usually result in breaker failure relay operation, but typically will not result in a faulted breaker. They are closely related to trip coil failures, as they probably cause the large majority of trip coil failures. The data analysis indicated that approximately 37 percent of circuit breaker failures are due to mechanism failures. Many mechanism failures may be caused by improper or improperly maintained lubrication of the mechanism. Guides have been developed for lubrication materials, application and maintenance for a variety of mechanisms and environments.

Relay/Trip Coil Relay and trip/close coil problems were those reported as problems with electromechanical relays installed in the circuit breaker or trip/close coils that burned open or failed to operate. By IEEE standards, breaker trip coils must operate successfully even at one-half of nominal dc control voltage. In practice, most dc control power schemes operate at slightly higher than nominal voltage, and trip coils are designed to operate successfully at somewhat less than half nominal voltage to ensure they meet the standard. The electrical power delivered to the trip coil is normally far in excess of that necessary for operation. Because of this, trip coils are intended to be de-energized very quickly at the beginning of the breaker trip motion. When tripping is retarded due to a stuck or sluggish mechanism, the trip coil can be destroyed in a very short time. Though frequently cited as the cause of a breaker failure, burned up trip coils usually indicate a problem in the breaker mechanism. The data analysis indicated that approximately 11 percent of circuit breaker failures are due to relay/trip coil failures. Other relays associated with breakers, as opposed to protection systems, include relays in anti-pump schemes, pole disagreement schemes, and gas pressure monitors. While failures of some of these devices may result in breaker tripping, they are more properly considered as control failures, and typically are not associated with increased transmission outage severity. Bushing Since bushing is common to circuit breakers and transformers, this analysis is in a separate section of this chapter. Lubrication Data analysis indicates that approximately 37 percent of circuit breaker failures are due to mechanism failures. Circuit breaker mechanisms have rolling element bearings, plain or sleeve bearings, gears, chains, sprockets, threaded connections, cams, slides, pivot pins, guides, pistons, belts, and couplings that must operate together for the breaker to perform properly. If one component does not operate correctly, the circuit breaker operation could fail, and with expensive consequences. Some circuit breaker mechanism failures have been traced to faulty lubricants or questionable lubrication practices. Good lubrication practices are essential because circuit breakers typically remain inactive for long periods and are exposed to extreme temperatures, wind, rain, dust, humidity, chemical fumes, and other harsh conditions. Even after long periods of inactivity in harsh environments, the breaker must function when suddenly called upon.



Transmission circuit breakers have become a maintenance challenge because of their extended time in the field without relubrication. Some circuit breakers in use today can be up to 60 years old. The lubrication requirements across a fleet of circuit breakers can be a challenge because of circuit breakers that were lubricated with what the manufacturer specified 30 or 60 or more years ago, that have had no lubrication or minimal lubrication since manufacture. Many of these old lubricants will break down over time. Some greases will separate, leaving only a dry thickener, which can slow the breaker action. Some greases and penetrating oils can change in physical form, leaving what appears to be a varnish-like residue in bearings and other critical friction areas. Many synthetic lubricants available today will out-perform and outlast conventional lubricants. Thus, effective cleaning and lubrication—using lubricants that stand up to prolonged exposure to harsh conditions—are essential in ensuring that breakers will operate properly when needed. Improper lubrication or using the wrong lubricants will lead to premature equipment failure. In order for moving parts to perform satisfactorily, they must be kept clean and well lubricated. Part of the function of the lubricant is to protect against contaminants and to flush away wear products. While performing these duties, the lubricant itself will become contaminated and must be renewed periodically to prevent damage to the parts. A lubricant can also deteriorate over a period of time, due to the constant exposure to the environment (e.g., temperature changes, changes in humidity, and pollutants). So even if it does not become contaminated, the lubricant must still be removed and replaced occasionally. In addition, special attention needs to be paid to the following:

1. Avoid mixing products—Compatibility of lubricants is always a concern if they should become mixed. Due to the complex petroleum additives that are now used to create lubricants, it is impossible to predict what effect different products will have on each other, or in combination.

2. New parts—New bearings are often shipped with a protective substance, such as cosmoline, to protect them from corrosion. It is imperative that this substance be removed to allow for the applied lubrication to adhere properly to the metal surface.

Note the following:

• Penetrating aerosols are solvents, not lubricants.

• Solvents will wash out grease and other lubricants.

• Solvents should be used only in emergencies as a short-term measure and only if the unit will be lubricated within a few days.

• Solvents will quickly dry up and fail to provide lubrication or prevent friction. Transmission owners are recommended to have a maintenance policy on the types of approved lubricants to be used and a policy on when to replace circuit breaker mechanism lubrication. Breaker Service Advisory Example Manufacturers send out advisories when performance or material issues in a given product are identified. A process that ensures manufacturer advisories are communicated to the appropriate maintenance personnel within a utility is critical. Participation in industry groups such as Edison Electric Institute (EEI), Centre for Energy Advancement through Technological Innovation (CEATI), and the North American Transmission Forum (NATF) can help entities share experiences and be aware of common issues with equipment. Transformers Based on a survey conducted in 2012, the 2013 SOR report revealed that 15 percent of TADS outages initiated by failed ac substation equipment outages are due to transformer failures. The ACSETF data analysis indicated transformer failures represent about 28 percent of failed ac substation equipment occurrences. Transformer outages are currently not included in the calculation of transmission outage severity.



Transformer Analysis by Failure Modes The transformer failures analyzed were categorized into the five distinct failure modes. These failure modes are winding, tap changer, mechanical, dielectric, and accessory. For the purpose of this report, ACSETF focused on winding and tap changer failures. Since bushings are common to circuit breakers and transformers, the analysis of bushing failures has been provided in a separate section later in this chapter. Figure 3 shows transformer failure by failure mode and table 5 shows the distribution of failures by failure mode and various data sources

Figure 3: Transformer Failures by Failure Mode

33%32%

13%

10%

7%

3%2%

Winding

Tap Changer

Dielectric

Mechanical

Other

Unknown

Accessory



Table 5: Data Source, Number of Failures and Failure Mode

Failure Mode

Number of Failures

Data Sources

NERC EA TADS Survey WECC Total

Winding 5 3 192 200

Tap Changer 6 189 195

Dielectric 1 9 66 76

Mechanical 59 59

Other 7 35 42 Unknown 2 18 20

Accessory 9 9

Winding Failures Transformer winding failures include turn-to-turn short circuits, open windings, turn-to-turn insulation failures within the windings, and winding insulation failures to ground due to electrical, mechanical, or thermal stress. The data analysis indicated that approximately 34 percent of transformer failures are due to winding failures. The ACSETF did not attempt to identify any trends with a particular manufacturer. Typical utility practices for detection of winding failures include periodic insulation power factor testing, turns-ratio testing, dissolved gas-in-oil analysis, excitation current measurement, and percent impedance measurement. On-line continuous monitoring devices are also available. These practices may detect incipient failure modes prior to a major failure. This allows utilities to plan outages for repairs or replacement prior to a major failure. Tap Changer Failures Tap changer failure modes can be mechanical or electrical failures, or related to the quality of oil and contacts. The data analysis indicated that approximately 33 percent of transformer failures are due to tap changer failures, either a Load Tap Changer (LTC) or De-Energized Tap Changer (DETC). Typical utility practices for tap changers include dissolved gas-in-oil analysis, infra-red inspections, turns-ratio testing, or excitation current measurement. Depending on the type of tap changer, utilities may also use periodic off-line inspections of load-tap changer contacts and oil quality. On-line continuous monitoring devices are also available. These practices may detect incipient failure modes prior to a major failure and allow for planned outages for maintenance and repair. Summary of Observations Below are a few observations from actual field cases.



Winding and tap changer Figure 4 shows the catastrophic failure of a power transformer.

Figure 4: Catastrophic Failure of Power Transformer Utilities typically do not re-close when a large transformer trips by relay action. This has the effect of prolonging the outage duration to allow for diagnostic testing and inspection. Therefore, full restoration is not implemented until after testing and inspection of the transformer is conducted. This very appropriate practice has the effect of increasing the duration of the severity imposed on the transmission system. Transmission severity as defined in the 2013 State of Reliability report does not consider transformer outages or any outage duration in the evaluation. Analysis of TADS data on Failed AC Substation Equipment outages indicates an average outage duration of over 840 hours for sustained outages on transmission transformers, versus an average sustained outage duration of 93 hours for all other failed ac substation equipment outages. The ability to restore the transmission system to its normal state becomes less certain, and operating conditions potentially more constraining, with the unavailability of a key transmission element like transformers, which potentially have long lead times for replacement. Outage duration is a key factor that needs to be addressed for long-lead-time equipment.

The latest revision of the NERC transmission planning standard (TPL-001-4) approved by FERC in 2013 addresses the condition under which a long-lead-time item such as a transformer becomes unavailable for an extended period of time with the following requirement:

In the case of the TRE region, ERCOT believes that the outage and subsequent long-term unavailability of autotransformers can impact system reliability and should be accounted for in planning studies. To ensure that planning assessments for the BES consider the long-term impacts of a large autotransformer becoming unavailable, the ERCOT region recently implemented a revision to its reliability criteria associated with the loss of long-lead-time equipment (e.g., transformers). In ERCOT’s case, the reliability criteria revision consists of requiring

2.1.5. When an entity’s spare equipment strategy could result in the unavailability of major Transmission equipment that has a lead time of one year or more (such as a transformer), the impact of this possible unavailability on System performance shall be studied. The studies shall be performed for the P0, P1, and P2 categories identified in Table 1 with the conditions that the System is expected to experience during the possible unavailability of the long lead time equipment.



performance testing under a condition in which a transformer is unavailable due to failure (i.e., long term). Under this more severe condition, the system is required to continue meeting performance requirements equal to those under a single-contingency condition. Instrument Transformers The ACSETF data analysis indicated that 4.9 percent of failed ac substation equipment occurrences are due to instrument transformer failures. Failures of instrument transformers can increase transmission outage severity. These failures are often both combustive and explosive. Ionized gases and debris from instrument transformer failures can damage other nearby substation equipment and result in multiple outages. The CIGRE report on instrument transformer reliability determined that for all voltage classes, approximately one-sixth of major failures resulted in fire or explosion. Major failures are considered to be those that result in the loss of one or more of the instrument transformer’s fundamental functions. Figures 5 and 6 show the catastrophic failure of an oil-filled voltage transformer, and the resulting debris field after explosive failure of a capacitor-coupled voltage transformer, respectively.

Figure 5: Catastrophic Failure of


Figure 6: Debris Field after Explosive

Failure of Instrument Transformer Debris and ionized gases from catastrophic instrument transformer failures will often result in removal of circuit elements adjacent to the failed device. Failures of instrument transformers on straight buses will generally result in the outage of all circuit elements connected to the bus. The failure of a bus potential transformer on a breaker and a half-scheme may result in the misoperation of several impedance relays in multiple circuits in the substation. A secondary effect of instrument transformers is the impact they have on the performance of protection system operations. All of these characteristics of instrument transformer failures create a tendency to remove more than one circuit element per failure.

Three examples from event analysis of Category 1a events illustrate how instrument transformer failure may cause multiple element outages. In the first case, a catastrophic failure of a 230 kV line voltage transformer resulted in a permanent line fault. Smoke from the burning transformer drifted into an adjacent 230 kV bus. That bus cleared, but there was a misoperation of a breaker failure relay. The net result was the loss of two 230 kV lines, a 230 kV bus, a BES transformer, a 115 kV bus, and two radial 115 kV lines to load centers.

In a second case, an explosive failure of a CT resulted in a sustained 230 kV line outage. Twenty-three cycles later, smoke and debris from the destroyed current transformer caused a phase-to-phase fault on a 230 kV bus. A



combination of correct and incorrect relay operations tripped three 230 kV buses and two BES autotransformers, and de-energized nonessential station auxiliary power at a generating station (no generation tripped).

In a third case, a bus PT catastrophically failed, sending porcelain, copper, oil, and steel into adjacent breaker bays and associated protection zones. Relays correctly tripped a 161 kV bus, two generators, and an autotransformer. A distance relay also misoperated due to loss of potential and tripped a transmission line.

Figure 7: Catastrophic Failure of Instrument Transformer

Instrument Transformer Analysis by Failure Modes The instrument transformer failures were categorized into five distinct failure modes. These failure modes are winding, mechanical, dielectric, unknown, and other. For the purpose of this report, ACSETF focused on winding, dielectric, and mechanical. Since bushing is common to circuit breakers and transformers, the analysis of bushing failures has been provided in a separate section in this chapter. Figure 8 shows Instrument transformer failure by failure mode and table 6 shows the distribution of failures by failure mode and various data sources

Figure 8: Instrument Transformer Failures by Failure Mode

18%

63%

7%

12%

Winding

Dielectric

Mechanical

All Other



Table 6: Data Source, Number of Failures and Failure Mode

Failure Mode

Number of Failures

Data Sources

NERC EA TADS Survey WECC Total

Winding 1 5 8 14 Dielectric 7 41 48 Mechanical 5 5 All Other 4 5 9

Winding Failure Winding failures typically involved open or shorted turns within the transformer portion of the device. Dielectric Failure Dielectric failures were categorized by a breakdown of the high-voltage insulation portion of the device or a failure of the voltage divider portion of a capacitive- or inductive-coupled voltage transformer. Sixty-three percent of the failures of instrument transformers were caused by a dielectric failure. Mechanical Failure Mechanical failures were typically related to oil seal leaks or problems with the outer housing of the device. Instrument Transformers – Analysis and Observations CIGRE data indicates that the failure rate of instrument transformers energized at 60 kV or higher is less than one per 1,000 service years. Compared to transformers and circuit breakers, instrument transformers are low-cost, low-lead-time items. Construction costs and time for failed instrument transformers is also relatively low. Low failure rates and replacement costs provide economic support for a practice of run to failure. The following practices may be used to improve the reliability of substation instrument transformers:

• Adopting a program to power factor test the dielectrics or capacitor voltage dividers—in the case of CVTs, at the time of initial installation—and then performing regular power factor tests and comparing the results to the initial test can indicate incipient failure before a more costly failure occurs.

• Many new electronic relays now have the ability to compare voltages between phases and alarm when one phase trends upward or downward compared to the other phases. This method can also be used to detect incipient failures of an instrument transformer’s dielectrics, thereby allowing the operator to take a planned outage to conduct further testing, or replace the instrument transformer before it can cause a system disturbance.

Substation Equipment Bushings (Circuit Breakers and Transformers) – Analysis and Observations Figure 1 shows 10 percent of ac substation equipment failed due to bushing failure. Historically, bushings have been viewed as part of a large piece of substation equipment. This view of bushings has often resulted in the reporting of the catastrophic failure of high-voltage equipment bushings as either a circuit breaker or transformer failure, when in fact the circuit breaker or transformer was damaged collaterally as a result of the failed bushing.



The NERC EAP does not break out bushings as a separate equipment category. However, in 2012 the WECC SSWG began the process of reporting bushing failures separately from the equipment on which they were installed. The increase of industry awareness in the failure of bushings over recent years provided the observation that bushings fail at a different rate than the equipment they are attached to. Therefore, the ACSETF recommends that high-voltage equipment bushings should be categorized and treated as a completely separate piece of substation equipment. For example:

• A 2012 root cause evaluation report associated with the trip of a U.S. Nuclear Plant cited low-impedance ground fault on the 345 kV B Phase bushing as the initiating event.

• A 2013 World Academy of Science, Engineering and Technology (WASET) publication14 presented the results of a comprehensive investigation of five blackouts that occurred from August 28 to September 8, 2011, due to transformer bushing failures.

The ACSETF makes the following recommendation for improvement of the NERC EAP data collection: In the capturing of equipment failures in the cause coding process, the EAP should further refine the “Characteristics and Attributes” for failed equipment, to further differentiate down to subcomponent (such as breaker bushing, or transformer bushing) when possible. To accomplish this granularity in data, reporting in the EAP would need to be more precise. Substation Configurations Circuit breakers are used to isolate failed circuits. The bus configuration within a substation determines the number of circuit elements that will be removed from service in the event of a circuit breaker failure. Of the many bus configurations available, the following three will be considered to demonstrate the configuration effect:

• Straight or radial bus

• Ring bus

• Breaker and a half bus The impact of these bus configurations on transmission severity resulting from circuit breaker failure is described below. Straight or Radial Bus Configuration Figure 9 shows a straight or radial bus configuration with six lines connected to the bus, each through a dedicated circuit breaker. An ac circuit breaker failure for this bus configuration results in clearing the entire bus. Furthermore, if there are no methods to automatically or remotely isolate the circuit breakers, the outage of these lines will be prolonged. This configuration results in the highest transmission outage severity among the three configurations due to a failed circuit breaker.

14 International Science Index Vol: 7, No:6, 2013 waset.org/Publication/4707



Figure 9: Straight Bus Configuration

Ring Bus Figure 10 shows a six-position intact ring bus, with six transmission lines. With this configuration, an ac circuit breaker failure will result in the loss of only two transmission lines. This configuration dramatically reduces the impact on transmission severity resulting from a failed circuit breaker compared to the straight bus, while requiring the same number of breakers.

Figure 10: Ring Bus Configuration

Breaker and a Half Figure 11 shows a breaker and a half bus configuration with six transmission lines. With this configuration, the failure of the middle circuit breaker a will result at most in only two transmission lines being removed from service. A failure in any circuit breaker connected to a bus will result in a bus outage and only one transmission line. All other lines remain in service with full functional connectivity. This configuration further reduces the impact on transmission severity resulting from a failed circuit breaker.



Figure 11: Breaker and a Half Configuration

The correlation between circuit breaker failures and transmission outage severity is primarily due to a combination of the function of circuit breakers to isolate faulted circuit elements from the power system, and the specific configuration of circuit breakers in the substation. Circuit breakers are the only viable substation device for clearing faults, but the configuration in which they are arrayed varies with substation design choices. Results from ACSETF Voluntary Survey In conducting review on the number of circuit breaker failures and its associated severity to the transmission system, the ACSETF made an observation associated with substation bus configurations. Figure 12 summarizes the ACSETF survey data for outages that were initiated by failed ac substation equipment, indicates that 29 percent of outages were due to the failure of a circuit breaker. Figure 13 shows 67 percent of the circuit breaker-initiated outages were located at substations with a single bus-single breaker bus configuration.15 By its nature, a single bus-single breaker bus configuration results in an increased severity caused by the failure of a single circuit breaker. In a single bus-single breaker bus configuration, the failure of a circuit breaker will result in the operation of all other circuit breakers connected to the bus. This results in increased severity to the transmission system due to the number of transmission circuits that are removed from service as a result of the single circuit breaker failure. In one case, the failure of a single circuit breaker resulted in the operation of seven additional circuit breakers. This specific condition might not be evaluated as a valid contingency condition in a planning study prior to the adoption of Reliability Standard TPL-001-4.

15 Single bus-single breaker bus configuration are also known as Straight bus, Radial, Main and transfer bus.



Figure 12: Failed AC Substation Equipment by Equipment Type (ACSETF Survey Results)

Figure 13: Circuit Breaker Failure by Bus Configurations (ACSETF Survey Results)

Based on the survey data results and experience within the ACSETF, the severity level associated with the failure of a circuit breaker increases when the substation is a constructed with a single-bus, single-breaker substation configuration. Measures of severity associated with the assessment in the 2013 State of Reliability report do not attempt to isolate the number of circuit breaker outages associated with a single-bus, single-breaker design for measuring severity risk associated with substation equipment failures. Understanding the role of bus configuration will assist in evaluating mitigation opportunities to reduce the impact on reliability. The number of additional circuit elements lost due to a circuit breaker failure is a key factor that needs to be addressed when planning a new BES substation.

29%

3%5%

44%

12%

7% 0%

Circuit Breaker

Disconnect Switch


ALL other

Power Transformer

Surge Arrester

(blank)

13%

3%

12%

5%

67%

Breaker and a Half

Other

Ring Bus

Sectionalized Bus

Single Bus



The latest revision of TPL-001-4 approved in 2013 addresses this to some extent. The condition under which the loss of a bus section becomes unavailable, as is the case for a single-bus, single-breaker bus under a breaker failure scenario, is not one that requires assessment as a single contingency condition under the presently effective NERC Reliability Standards. Presently, a single-bus breaker failure scenario is evaluated as a multiple contingency event (Category C) under the current NERC transmission planning standard (TPL-001-4). The revised standard requires testing for both the loss of a bus section and the condition of a circuit breaker failure and for the system to meet the performance requirements as a single-contingency event. ACSETF believes this change in the NERC Reliability Standard will assist in reducing the consequences associated with severity levels associated with the failure of a circuit breaker. Other Substation Equipment Review Substations contain a wide range of equipment, all of which is valuable for grid reliability. However, in reviewing the various data sets and types of equipment, several types of equipment are seen as important to reliability but to a lesser degree than equipment covered previously. While this equipment cannot be ignored, it represents a secondary level of risk and corresponding focus. This equipment, which includes arresters, switches, circuit switchers, insulators, connectors, and capacitors, is shown in Figure 1 as “all other” and was determined to be causes of transmission outages in less than 5 percent of the data studied.


Chapter 3 – Discussion of Observations and Recommendations Transmission Severity and TADS Data The ACSETF agrees with the conclusion in the 2013 State of Reliability report that substation equipment failures, particularly circuit breaker failures, tend to increase “transmission outage severity.” The ACSETF also observes that the measure “transmission outage severity” may overstate the negative impact on the BES in some cases, and understate it in others. For example, the duration of the outage is not considered. A breaker failure scheme that includes automatic isolation of the failed breaker and automatic restoration of affected BES elements is considered to have the identical impact as a scheme leaving multiple elements out for prolonged periods. Large autotransformers with normal clearing will have no impact on transmission severity. The loss of the transformer may have significant impact on BES operations and reliability. The impact of transmission line outages with the same voltage level is treated equally regardless of operational value to the integrated BES. Because of these and other concerns, focusing on reducing ac substation failures to reduce the measure transmission outage severity may not be the most effective use of resources in improving the reliability of the BES. The ACSETF recommends that NERC address these issues in the calculation of transmission outage severity. Equipment Application, Bus Configuration and Design Many options are available in substation design that can have an impact on the correlation between circuit breaker failure and transmission severity. The choice of a particular bus configuration is usually a balance between economic issues and performance issues. Straight bus configurations are comparably low in cost, but are a configuration in which breaker failures have a high impact on BES performance. Breaker failure protection can incorporate automatic isolation of the failed breaker; automatic and manual reclosing techniques to reduce the duration of circuit outages associated with the non-failed breakers on a straight bus to few minutes. Using these techniques reduces the impact of a breaker failure on the BES, although it is not an improvement reflected in the current measure of transmission severity. Straight buses can also be constructed in a manner that facilitates economic conversion to other configurations, such as breaker and a half, at a future date. The additional real estate and electrical facilities needed to enable this are usually small cost increases to the overall cost of building the initial straight bus configuration. The impact of breaker failures on system performance over time should always be evaluated when choosing bus configurations and substation designs for new installations. As stated in the implementation plan for TPL-001-4, “TPL-001-4 raises the bar in several areas where performance requirements have been changed in the new Standard versus those in existing TPL-001-3, TPL-002-2b, TPL-003-2a and TPL-004-2 because loss of Non-Consequential Load or interruption of firm transfers is no longer allowed for certain events, whereas the existing Reliability Standards were interpreted by many to allow such actions.”

Improving Data Collection The data sources that were used by the ACSETF included TADS data, Event Analysis data, and WECC SSWG workgroup data.

TADS is the largest source of data. The original purpose of TADS was to track transmission availability. It was not originally intended to be an equipment failure analysis resource. As such, analysis of TADS data is currently limited by the information provided for equipment failure analysis. It does not provide any information about the type of equipment that failed. In order to gain more information for this analysis, the ACSETF had to do an additional survey and analyze additional data sets to gather more information on the equipment failures.

Event Analysis data can provide good data for equipment failure analysis. However, its limitation is its small dataset.If the analysis of ac substation equipment failures in the future is to have value, NERC should determine the most efficient method to collect that data in the future.


Chapter 3 – Discussion of Observations and Recommendations

The ACSETF was not able to identify any trends with a particular manufacturer or model of circuit breaker due the lack of data that support analysis. More data would enhance the ability to analyze circuit breaker failures and determine detailed trends, and include at minimum:

1. Manufacturer name 2. Model/type 3. Date of manufacture 4. Failure mode

A possible solution would be to standardize information that is collected and then aggregate all NERC data into one dataset. There are also numerous organizations that currently collect substation equipment failure data. From an efficiency perspective, it would be beneficial to work with those organizations to minimize the amount of reporting that entities must perform. It may be possible to work collaboratively with those organizations and aggregate that data. The IEEE Guide for Investigation, Analysis, and Reporting of Power Circuit Breaker Failures (C37.10-2011) could aid in developing a framework for future data collection and standardized failure modes. The historical reporting practice of treating bushings as a part of a large piece of substation equipment could lead to insufficient research or industry-wide notification, causing system reliability vulnerabilities to persist. The increase of industry awareness in the failure of bushings over the recent years provided the observation that bushings fail at a different rate than the equipment they are attached to. Therefore, the ACSETF recommends that high-voltage equipment bushings should be categorized and treated as a completely separate piece of substation equipment. ALR6-13: Automatic Outages Initiated by Failed AC Substation Equipment The NERC metric for monitoring AC Substation Equipment Failures is ALR6-13. The 2014 State of Reliability report states “The metric (ALR6-13) shows that outages per element demonstrate year-over-year improvement from 2011 to 2013.” In fact, that metric has been consistently below .05 outages per ac circuit due to ac substation equipment failures for six years, as shown in Figure 14. The ACSETF believes that continued monitoring of ac substation equipment failures is prudent. This monitoring could identify emerging trends that need to be communicated to the industry.

Figure 14: ALR6-13 Metric Trend for 2008–2013

.049.046 .044

0.05

.041

.029

0

0.01

0.02

0.03

0.04

0.05

0.06

2008 2009 2010 2011 2012 2013


Chapter 3 – Discussion of Observations and Recommendations

Participation, Data Sharing and Best Practices • Use optimal lubrication practices for each circuit breaker.

• Define a process for the distribution, tracking, and analysis of manufacturer-issued service advisories.

• Investigate, analyze, and report all BES substation equipment failures per the applicable IEEE Guidelines.

• Participate in industry groups such as NATF and EEI, etc., to share investigation results.

• Include results in NERC Event Analysis investigations.

• Proactively replace equipment where industry experience identifies a generic problem in a specific device.


Chapter 4 – ACSETF Roster

Table 7: ACSETF Roster

Membership Name Address Contact Information

Chair

NPCC

Michael Lombardi

Manager, System Studies

Northeast Power Coordinating Council, Inc.

1040 Avenue of the Americas, 10th floor

New York, NY 10018

212-840-1070

[email protected]

NERC Staff Coordinator

Naved Khan

Engineer, Reliability Performance Analysis

North American Reliability Corporation

1325 G Street NW, Suite 600

Washington, DC 20005

202-644-8086

[email protected]

MRO Richard Quest

Principal System Protection Engineer

Midwest Reliability Organization

380 St. Peter Street, Suite 800

St. Paul, MN 55102

651-855-1704

[email protected]

Texas RE David Penney, P.E.

Senior Reliability Engineer

Texas Reliability Entity

805 Las Cimas, Suite 200

Austin, TX 78746

512-583-4958

[email protected]

WECC

Salt River Project

Andy Keels

Senior Electrical Engineer

Apparatus Engineering Dept.

Apparatus Engineering Dept. Salt River Project (Phoenix, AZ) W: 602-236-8618 C: 602-809-3561

602-236-8618

[email protected]

SERC David Greene, P.E.

Senior Reliability Engineer

SERC Reliability Corporation

3701 Arco Corporate Drive, Suite 300 Charlotte, NC 28273

704-414-5238

[email protected]

NERC Staff Howard Gugel

Director, Performance Analysis, RAPA


3353 Peachtree Road NE, Suite 600 – North Tower

404-446-9693

[email protected]


mailto:[email protected]










NERC Staff Ben McMillan

Senior Risk Analysis Engineer, Reliability Risk Management



Atlanta, GA 30326

404-446-9729

[email protected]

NERC Staff Rich Bauer

Reliability Risk Manager



Atlanta, GA 30326

404-446-9738

[email protected]

SPP Thomas Teafatiller

Senior Compliance Engineer

Southwest Power Pool Regional Entity

201 Worthen Dr.

Little Rock, AR 72223

501-688-2514

[email protected]

Transmission Planner Entity

LCRA Transmission Services Corporation

Sergio Garza, P.E.

Manager, System Planning and Protection

3505 Montopolis Drive

Mailstop D-140

Austin, Texas 78744

512-578-4149

[email protected]

RFC

Baltimore Gas & Electric

Daniel Blaydon, P.E.

Senior Engineer, Substation Engineering Design & Standards

Baltimore Gas & Electric 410-470-8827

[email protected]

FRCC

Duke Energy

G. Brantley Tillis, P.E.

Manager, Transmission Performance

Duke Energy

3300 Exchange Place

Lake Mary, FL 32746

407-942-9569

[email protected]

Doble Engineering

Don Angell Doble Engineering

85 Walnut St.

Watertown, MA 02472

617-393-2996

[email protected]

WECC Kraig Patterson

Utility Operations Specialist

Western Electricity Coordinating Council

155 North 400 West, Suite 200

Salt Lake City, UT 84103

801-819-7672

[email protected]

RFC Bill Crossland Reliability First 216-503-0613













Sr. Engineer, Protection

3 Summit Park Dr., Suite 600

Cleveland, OH 44131

[email protected]



Appendix – Analysis of TADS Data Outage Mode Summary From 2008 through 2013, there were a total of 26,805 automatic outages of all types entered in the TADS system. Figure 15 depicts the TADS Outages from 2008 to 2013 by Outage Mode. Of the 26,805 outages, 6918 (25.8 percent) involved multiple elements, defined as either Common Mode (one of two or more Automatic Outages with the same Initiating Cause Code (ICC) where the outages are not consequences of each other and occur nearly simultaneously) or Dependent Mode (an Automatic Outage of an Element which occurred as a result of an initiating outage, whether the initiating outage was an Element outage or a non-Element outage).

Figure 15: TADS Outages by Outage Mode 2008–2013

Sustained outage duration from Common Mode and Dependent Mode outages from 2008 through 2013 was 274,185 hours, or 47.9 percent of the total outage duration of 572,998 hours. Table 8 provides the number of events and outage duration from 2008 to 2013 by outage mode. Figure A.2 illustrates the TADS Outage Duration from 2008 to 2013 by Outage Mode.

Single Mode74%

Dependent Mode

Initiating6%

Dependent Mode11%

Common Mode

8%

Common Mode

Initiating1%


Appendix – Analysis of TADS Data

Table 8: TADS Outage Duration and Number of Events by Outage Mode 2008–2013

Outage Mode

Momentary Outage Events

Sustained Outage Events

Total Number of Events

Total Outage

Duration (Hrs.)

Average Duration of Sustained Outages

(Hrs.) / Event

Single Mode 8982 10905 19887 298813 27.4 Dependent Mode Initiating 731 859 1590 68804 80.1

Dependent Mode 829 2178 3007 105273 48.3

Common Mode 563 1549 2112 92722 59.9

Common Mode Initiating 51 158 209 7386 46.7 Total 11156 15649 26805 572998 36.6

Figure 16: TADS Outage Duration by Outage Mode 2008–2013 Outages Caused by Failed AC Substation Equipment As shown in Figure 17 and Figure 18, Failed AC Substation Equipment represented 5.1 percent of Single Mode outages and was the second largest initiating cause of Common Mode and Dependent Mode outages, representing 13.6 percent of the total outages.

Single Mode52%

Dependent Mode

Initiating12%

Dependent Mode19%

Common Mode16%

Common Mode

Initiating1%



Figure 17: Single Mode Outages by Initiating Cause 2008–2013

Weather, excluding lightning

15%

Lightning21%

Environmental0%Contamination

4% Foreign Interference

5%

Fire3%

Vandalism, Terrorism, or

Malicious Acts0%

Failed AC Substation Equipment

5%

Failed AC/DC Terminal Equipment

0%

Failed Protection System Equipment

5%

Failed AC Circuit Equipment

7%

Failed DC Circuit Equipment

0%

Vegetation1%

Power System Condition

1%

Human Error7%

Unknown22%

Other2%

Unavailable0%



Figure 18: Common Mode/Dependent Mode Outages by Initiating Cause 2008–2013 Failed AC Substation Equipment was the second-largest cause of outage duration for Single Mode outages, representing 76,140 hours (25.5 percent of the total). Failed AC Substation Equipment dominates the outage duration for Common Mode and Dependent Mode outages, representing 141,583 hours (51.6 percent of the total), or an average of over 177 hours per event. Tables 9 and 10 provide the number of events and outage duration from 2008 to 2013 by outage initiating cause. Figures 19 and 20 depict the TADS Outage Duration from 2008–2013 by Initiating Cause for single mode and common mode outages respectively.


9%

Lightning16%

Environmental0%

Contamination2%

Foreign Interference

2%

Fire3%


Malicious Acts0%


14%

Failed AC/DC Terminal

Equipment0%

Failed Protection

System Equipment

12%


5%


0%

Vegetation0%


11%

Human Error11%

Unknown8%

Other4%

Unavailable0%



Table 9: TADS Single Mode Outage Duration and Number of Events by Initiating Cause 2008–2013

Single Mode Outage Initiating Cause



Total Number of

Events

Total Outage

Duration (Hrs.)


(Hrs.)

Weather, excluding lightning 1034 1948 2982 66152.03 33.9 Lightning 2909 1312 4221 1996.77 1.5 Environmental 2 22 24 2928.23 133.1 Contamination 444 276 720 5098.87 18.5 Foreign Interference 503 461 964 2193.22 4.8 Fire 132 370 502 8807.37 23.8

Vandalism, Terrorism, or Malicious Acts 9 32 41 418.27 13.1

Failed AC Substation Equipment 164 848 1012 76140.33 89.8

Failed AC/DC Terminal Equipment 1 77 78 1486.98 19.3

Failed Protection System Equipment 309 767 1076 5455.5 7.1

Failed AC Circuit Equipment 338 1114 1452 86351.63 77.5

Failed DC Circuit Equipment 1 13 14 290.05 22.3 Vegetation 46 173 219 3102.27 17.9 Power System Condition 38 182 220 2597.4 14.3 Human Error 253 1192 1445 9135.75 7.7 Unknown 2665 1786 4451 11080.75 6.2 Other 134 325 459 5023.55 15.5 Unavailable 0 7 7 10553.9 1507.7 Total 8982 10905 19887 298812.9 27.4



Table 10: TADS Common/Dependent Outage Duration and Number of Events by Initiating Cause 2008–2013

Common/Dependent Mode Outage Initiating Cause



Total Number

of Events

Total Outage

Duration (Hrs.)

Average Duration of Sustained

Outages (Hrs.) per Event

Weather, excluding lightning 193 454 647 33147.38 73 Lightning 643 476 1119 1033.38 2.2 Environmental 2 29 31 6999.05 241.3 Contamination 50 66 116 354.02 5.4 Foreign Interference 45 124 169 2479.4 20 Fire 17 208 225 6821.3 32.8 Vandalism, Terrorism, or Malicious Acts 0 9 9 496.87 55.2

Failed AC Substation Equipment 148 796 944 141582.5 177.9

Failed AC/DC Terminal Equipment 1 23 24 60.32 2.56

Failed Protection System Equipment 333 497 830 3477.67 7

Failed AC Circuit Equipment 46 302 348 41412.72 137.1 Failed DC Circuit Equipment 0 3 3 243.5 81.2 Vegetation 4 24 28 237.45 9.9 Power System Condition 264 529 793 8590.48 16.2 Human Error 130 643 773 3740.83 5.8 Unknown 257 325 582 4041.07 12.4 Other 41 236 277 14050.47 59.5 Unavailable 0 0 0 5416.35 0 Total 2174 4744 6918 274184.8 57.8



Figure 19: Single Mode Outage Duration by Initiating Cause 2008–2013


22%

Lightning1%

Environmental1%

Contamination2%


1%Fire3%


Malicious Acts0%


25%


Equipment0%

Failed Protection System Equipment

2%


29%

Failed DC Circuit

Equipment0%

Vegetation1%


1%

Human Error3%

Unknown4%

Other2%

Unavailable4%



Figure 20: Common Mode/Dependent Mode Outage Duration by

Initiating Cause 2008–2013 NERC Metric for Failed AC Substation Equipment NERC analyzes various metrics to trend the performance of the transmission system based on TADS data. ALR6-13 is the metric that uses data and calculations directly from the NERC TADS effort and provides the overall percentage of outages per circuit initiated by failed substation equipment “inside the substation fence,” including transformers and circuit breakers, but excluding protection system equipment. ALR6-13 is based on the number of outages initiated by failed ac substation equipment divided by the total number of outages. The data for ALR6-13 can be used in aggregate to yield an “all ac circuit” trend or can be subdivided into categories to yield a trend for a specific grouping (e.g., voltage class or equipment type). As illustrated in Figure 21, the yearly trend in the ALR6-13 metric for all ac circuits clearly shows an improving downward trend in the percentage of outages caused by Failed AC Substation Equipment. The task force’s concern with this metric is that it does not trend outage duration. To accurately reflect the severity of an event, it is necessary not only to consider the number of elements removed from service, but also the duration that the elements will be out of service.


12%

Lightning0%

Environmental3%

Contamination0%


1%Fire2%


Malicious Acts0%


52%


Equipment0%

Failed Protection

System Equipment

1%


15%


0%

Vegetation0%


3%

Human Error1%

Unknown1%

Other5%

Unavailable2%



Figure 21: ALR-6-13 Metric Trend for All AC Circuits 2008–2013

ALR6-13 by Voltage Level Figure 22 illustrates the ALR6-13 metric according to voltage level. Historically, the 600–799 kV voltage class has a higher percentage of outage events caused by Failed AC Substation Equipment due in part to the fewer overall number of events that occur at that voltage level. The percentage of events caused by Failed AC Substation Equipment trended downward on average during the last three years.

0.05010.0462 0.0447

0.0504

0.0423

0.0302

0

0.01

0.02

0.03

0.04

0.05

0.06

2008 2009 2010 2011 2012 2013



Figure 22: ALR-6-13 Metric Trend by Voltage Level 2008–2013 Table 11 provides the data associated with Figure 22.

Table 11: ALR-6-13 Metric Data by Voltage Level 2008–2013 ALR6-13 Metric 200-299 kV 300-399 kV 400-599 kV 600-799 kV Total 2008 0.044 0.0495 0.0837 0.1182 0.0501 2009 0.0408 0.0521 0.0643 0.0818 0.0462 2010 0.0408 0.0567 0.0314 0.0991 0.0447 2011 0.0377 0.079 0.0564 0.1081 0.0504 2012 0.0311 0.0647 0.0592 0.0811 0.0423 2013 0.0215 0.0449 0.0467 0.0763 0.0302 Average 0.036 0.0578 0.057 0.0941 0.044

ALR6-13 by Equipment Type Figure 23 illustrates the ALR6-13 metric according to equipment type. There appears to be a downward trend in the percentage of events caused by Failed AC Substation Equipment for overhead ac circuits, while the percentage of Failed AC Substation Equipment events for underground ac circuits and transformers varies.

0

0.02

0.04

0.06

0.08

0.1

0.12

0.14

2008 2009 2010 2011 2012 2013

200-299 kV 300-399 kV 400-599 kV 600-799 kV



Figure 23: ALR-6-13 Metric Trend by Equipment Type 2008-2013

Table 12 provides the data associated with Figure 23.

Table 12: ALR-6-13 Metric Data by Equipment Type 2008–2013

ALR 6-13 Metric

Overhead AC Circuits

Underground AC Circuits Transformers Total

2008 0.0498 0.0581 0.047 0.0501 2009 0.0459 0.0565 0.0477 0.0462 2010 0.0438 0.0791 0.0463 0.0447 2011 0.0505 0.0441 0.0723 0.0504 2012 0.0412 0.08 0.0589 0.0423 2013 0.0296 0.0537 0.0459 0.0302 Average 0.0435 0.0619 0.053 0.044

Failed AC Substation Equipment Events by Outage Duration As previously stated, the average duration of a Failed AC Substation Equipment outage was over 89 hours for a Single Mode outage and over 177 hours for a Common Mode or Dependent Mode outage during the period of 2008–2013. Figure 24 depicts the Failed AC Substation Equipment Outage Duration for 2008–2013 for all Single Mode, Common Mode, and Dependent Mode outages. Over 61 percent of Failed AC Substation Equipment outages lasted at least two hours or more. The average duration of outages on ac circuits greater than 200 kV due

0

0.01

0.02

0.03

0.04

0.05

0.06

0.07

0.08

0.09

2008 2009 2010 2011 2012 2013

Overhead AC Circuits Underground AC Circuits Transformers Total



to Failed AC Substation Equipment was 77 hours per outage. The average duration of outages on TADS transformers due to Failed AC Substation Equipment was 831 hours per outage.

Figure 24: Failed AC Substation Equipment Outage Duration 2008–2013

As shown in Figure 25, ac circuits lead the outage count over power transformers, accounting for 95 percent of the failed ac substation equipment outages for 2008–2013. However, as shown in Figure 26, outage durations associated with power transformers account for 34 percent of the Failed AC Substation Equipment outage durations for the period of 2008–2013.

Figure 25: Failed AC Substation Equipment

Outage Count by Equipment Type, 2008–2013

Figure 26: Failed AC Substation Equipment

Outage Duration by Equipment Type, 2008–2013

1-5 Minutes

11%

6-10 Minutes4%

11-30 Minutes

7%

31-120 Minutes

17%121 Minutes to 24 Hours

43%

> 24 Hours to 48 Hours

5% > 48 Hours13%

AC Circuit

95%

Transformer5%

AC Circuit

66%

Transformer34%



Table 13 provides the data associated with Figures 25 and 26.

Table 13: Failed AC Substation Equipment Outages by Equipment Type 2008–2013

Failed AC Substation Equipment Outages by Equipment Type



Total Number

of Events

Total Outage

Duration (Hrs.)

Average Duration of Sustained

Outages (Hrs.) AC Circuit (Single Mode) 164 813 977 64237 79

AC Circuit (Common/Dependent Mode) 147 744 891 80350.7 108 AC Circuit (All Outages) 311 1557 1868 144587.7 92.9 Transformer (Single Mode) 0 35 35 11903.3 340.1

Transformer (Common/Dependent Mode) 1 52 53 61231.9 1177.5 Transformer (All Outages) 1 87 88 73135.2 840.6 Total 312 1644 1956 217722.9 132.4

The aggregate data used to create Figures 25 and 26 was subdivided into the annual data for 2008–2013. Figure 27 was created using the 2008–2013 annual data.

Figure 27: Failed AC Substation Equipment Outage Count and Duration, 2009–2013

0

100

200

300

400

500

600

0

10000

20000

30000

40000

50000

60000

2008 2009 2010 2011 2012 2013

Failed AC Equipment Outage Duration



Figure 27 shows that the outage duration in a given year for failed ac substation equipment outages is highly variable, ranging from 20,000 hours in both 2009 and 2012 to over 53,000 hours in 2011. Additionally, from Figure 27, it is observed that outage count and outage duration are not proportional. Failed AC Substation Equipment Events by Event Type TADS outages are assigned an Event Type. The Event Types are grouped by Normal Clearing and Abnormal Clearing. Table 14 provides a brief description of each Event Type. Note that Event Type 50, which was used prior to January 2012, has now been separated into multiple categories as noted.

Table 14: TADS Event Types Normal Clearing

Event Type Description

5 Single bus section fault or failure (200 kV or above) resulting in one or more Automatic Outage(s). 6 Single internal circuit breaker fault (200 kV or above) resulting in one or more Automatic Outage(s).

11 Automatic Outage of a single Element. 13 Automatic Outage of two or more Elements within one Normal Clearing Circuit Breaker Set.

31

Automatic Outages of two or more TADS adjacent AC Circuits or DC Circuits on common structures. To qualify as Event Type 31 the Automatic Outages must be the direct result of the circuits occupying common structures.

49 Automatic Outage(s) with Normal Clearing not covered by Event Types 05 through 31 above.

50 (Starting 1/1/2012) Separated into two categories: Normal Clearing – 05, 06, 13, 31,49; Abnormal Clearing - 60, 61, 62 and 90

Abnormal Clearing

60 Breaker Failure: One or more Automatic Outage(s) with Delayed Fault Clearing due to a circuit breaker (200 kV and above) being stuck, slow to open or failure to interrupt current.

61

Dependability (failure to operate): One or more Automatic Outage(s) with Delayed Fault Clearing due to failure of a single Protection System (primary or secondary backup) under either of these conditions: a. failure to initiate the isolation of a faulted power system Element as designed, or within its designed operating time, or

b. In the absence of a fault, failure to operate as intended within its designed operating time. (Item b is a very rare type of event.)

62

Security (unintended operation): One or more Automatic Outage(s) caused by improper operation (e.g. overtrip) of a Protection System resulting in isolating one or more TADS Elements it is not intended to isolate, either during a fault or in the absence of a fault.

90 Automatic Outage(s) with Abnormal Clearing not covered by Event Types 60 through 62 above. The following charts show historical data by Event Type for Common Mode and Dependent Mode Failed AC Substation Equipment outages by initiating cause and duration. For the period 2008–2013, Figures 28 and 29 depict the Failed AC Substation Equipment Outages by Event Type and Outage Durations by Event Type, respectively. For 2012–2013, using the expanded Event Types, Figure 30 and 31 depict the Failed AC Substation Equipment Outages by Event Type and Outage Durations by Event Type, respectively. For 2012–2013, when more granular Event Type recording was in place, 84 percent of the outages (98 percent of all outage duration) were from “Normal Clearing” events (Event Types 05, 06, 11, 13, 31, and 49) for Common Mode and Dependent Mode Failed AC Substation Equipment outages.



For the 2012–2013 Normal Clearing events, bus faults with normal clearing (Event Type 05) represented 10 percent of the outages and 12 percent of outage duration. Breaker faults with normal clearing (Event Type 06) represented 10 percent of the outages and 7 percent of outage duration. Automatic Outage of a single element with normal clearing (Event Type 11) represented 38 percent of the outages and 7 percent of outage duration. Automatic outages of two or more elements within one normal clearing circuit breaker set (Event Type 13) represented 11 percent of the outages and 59 percent of outage duration. Automatic outages with normal clearing not covered by Event Types 05 through 31 (Event Type 49) represented 15 percent of the outages and 13 percent of outage duration. For the 2012–2013 “Abnormal Clearing” events, breaker failures with abnormal clearing (Event Type 60) represented 4 percent of the outages and 1 percent of outage duration. Protection system failures with abnormal clearing (Event Types 61 and 62) represented 12 percent of the outages and 1 percent of outage duration. Automatic outages with abnormal clearing not covered by Event Types 60 through 62 (Event Type 90) represented 9 percent of the outages and 1 percent of outage duration. Table 15 provides the data associated with Figures 28–31.

Table 15: Failed AC Substation Equipment Outages by Outage Type 2008–2013 Failed AC Substation Equipment Outages by Outage Type

Momentary Outage Events Sustained Outage Events

Total Number

of Events

Total Outage

Duration (Hrs.)


(Hrs.) 5 8 44 52 6997.03 159 6 6 44 50 4721.62 107.3 11 44 805 973 99416.55 123.5 13 6 45 51 32098.83 713.3 31 0 60 69 1905.18 31.8 49 8 60 68 7277.87 121.3 50 94 507 601 60115.78 118.6 60 0 26 26 282.1 10.9 61 2 6 8 138.58 23.1 62 10 34 44 663.57 19.5 90 1 13 14 300.6 23.1 For 2012–2013 Only 5 13 72 85 13484.9 187.3 6 9 72 81 8028.8 111.5 11 53 270 323 7087.4 26.2 13 10 81 91 63931.8 789.3 49 13 111 124 13671.4 123.1 60 0 37 37 501.8 13.6 61 0 8 8 223.3 27.9 62 16 55 71 1087.3 19.8



90 2 21 23 465.4 22.2

Figure 28: Failed AC Substation Equipment Outages by Event Type 2008–2013

53%

63%

1147%

133%

313%

494%

5033%

601%

610%

622%

901%

53%

62%

1147%

1315%

311%

494%

5028%

600%

610%

620%

900%



Figure 29: Failed AC Substation Equipment Outage Duration by Event Type 2008–2013

Figure 30: Failed AC Substation Equipment Outages by Event Type 2012–2013

Figure 31: Failed AC Substation Equipment Outage Duration by Event Type 2012–2013

510%

610%

1138%

1311%

4915%

604%

611% 62

8%

903%

512%

67%

117%

1359%

4913%

601%

610%

621%

900%


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