PRC-005-2 Workshop July 29-30 2014 Salt Lake City Utah · 7/29/2014 · PRC-005-2 Workshop July...

PRC-005-2 Workshop July 29-30 2014

Salt Lake City Utah Updated for final posting August 12, 2014

Phil O’Donnell, WECC Manager Operations & Planning Audits

Roger Cummins, WECC Senior Compliance Auditor Joe Veltri, WECC Compliance Auditor

Fred Johnson, WECC Consultant Jim Terpening, WECC Consultant

John (Rob) Robertson, Manager of Electric Regulatory Compliance First Wind Rick Ashton, Tri-State G&T Substation Maintenance Supervisor

WECC PRC-005-2 Workshop Agenda

Day 1 Subject 1:00 -1:15 PM Welcome and Introductions 1:15-1:35 PM Overview and Definitions of Standard PRC-005 1:35 – 1:45 PM Upcoming Changes 1:45 - 2:00 PM Break 2:00 – 4:00 PM Applicability and BES Examples 4:00 – 4:30 PM Questions

Day 2 Subject 8:00 – 10:00 AM PRC-005-2 Requirements and WECC audit

Approach 10:00 – 10:30 AM Break 10:30 – 11:00 AM PRC-005-2 Implementation Plan 11:00 – 11:30 AM Questions and Wrap-Up

3

• The Standard – Background • Applicability • Definitions and Terms • Tables and Attachments • Data and Evidence Retention • Future Changes to PRC-005

Introduction and Definitions

4

Top 10 Violated Standards in WECC

0

50

100

150

200

250

300

350

CIP

-007

PR

C-0

05C

IP-0

01C

IP-0

04C

IP-0

06C

IP-0

05V

AR

-002

CIP

-003

CIP

-002

TOP

-002

Standard Totals

LargestRequirement

5

• FERC Order 693 • Direction to modify PRC-005-1 o Include maximum allowable intervals o Combine PRC-005, PRC-008, PRC-011 and

PRC-017

Background

6

Order Date Modification Implementing Version 3/16/2007 Order 693 Original PRC-005-1 PRC-005-1 9/26/2011 Order Approving Interpretation for

Radially Connected Transformers (1a)

PRC-005-1a

2/3/2012 Order 758 Interpretation of Protection System Definition (1b)

PRC-005-1b

2/3/2012 Order Approving Modification to Definition of Protection System. (to include battery chargers)

NERC Glossary

9/19/2013 Order 785 Generation Req. at Transmission Interface

PRC-005-1.1b

12/19/2013 Order 793 – Combine Standards and Performance Based Programs

PRC-005-2

7

Name and Change in Purpose

PRC-005-1 Transmission and Generation Protection System Maintenance and Testing Purpose: To ensure all transmission and generation Protection Systems affecting the reliability of the Bulk Electric System (BES) are maintained and tested.

PRC-005-2 Protection System Maintenance Purpose: To document and implement programs for the maintenance of all Protection Systems affecting the reliability of the Bulk Electric System (BES) so that these Protection Systems are kept in working order.

8

• PRC-005-1 Transmission and Generation Protection System Maintenance and Testing

• PRC-008-0 Implementation and Documentation of Underfrequency Load Shedding Equipment Maintenance Program

• PRC-011-0 Undervoltage Load Shedding System Maintenance and Testing

• PRC-017-0 Special Protection System Maintenance and Testing

Combines Existing Standards

PRC-005-1 PRC-008-0 PRC-011-0 PRC-017-0

PRC-005-2

9

• Transmission Owner • Generator Owner • Distribution Provider

• BES Applicability Addressed Later

Applicable To…

10

• Protection Systems that are installed for the purpose of detecting Faults on BES Elements (lines, buses, transformers, etc.)

• Protection Systems used for underfrequency load-shedding systems installed per ERO underfrequency load-shedding requirements.

• Protection Systems used for undervoltage load-shedding systems installed to prevent system voltage collapse or voltage instability for BES reliability.

• Protection Systems installed as a Special Protection System (SPS) for BES reliability.

Facilities (TO, DP)

11

• Protection Systems that act to trip the generator either directly or via lockout or auxiliary tripping relays.

• Protection Systems for generator step-up transformers for generators that are part of the BES.

• Protection Systems for transformers connecting aggregated generation, where the aggregated generation is part of the BES (e.g., transformers connecting facilities such as wind-farms to the BES).

• Protection Systems for station service or excitation transformers connected to the generator bus of generators which are part of the BES, that act to trip the generator either directly or via lockout or tripping auxiliary relays.

Protection Systems for generator Facilities that are part of the BES

12

• Protective relays which respond to electrical quantities, • Communications systems necessary for correct operation of protective

functions • Voltage and current sensing devices providing inputs to protective

relays, • Station dc supply associated with protective functions (including

batteries, battery chargers, and non-battery based dc supply), and • Control circuitry associated with protective functions through the trip

coil(s) of the circuit breakers or other interrupting devices.

Definitions:

Protection System –

13

Any one of the five specific elements of the Protection System Definition.

o Relays o Sensing Devices o Communications o DC Control Circuitry o Batteries & Supply

Definitions:

Component Type

14

A component is any individual discrete piece of equipment included in a Protection System, including but not limited to a protective relay or current sensing device. The designation of what constitutes a control circuit component is very dependent upon how an entity performs and tracks the testing of the control circuitry. Some entities test their control circuits on a breaker basis whereas others test their circuitry on a local zone of protection basis.

Definitions: Component

15

Thus, entities are allowed the latitude to designate their own definitions of control circuit components. Another example of where the entity has some discretion on determining what constitutes a single component is the voltage and current sensing devices, where the entity may choose either to designate a full three-phase set of such devices or a single device as a single component.

Definitions: Component (cont.)

16

• An ongoing program by which Protection System components are kept in working order and proper operation of malfunctioning components is restored. A maintenance program for a specific component includes one or more of the following activities:

• Verify — Determine that the component is functioning correctly. • Monitor — Observe the routine in-service operation of the component. • Test — Apply signals to a component to observe functional performance or

output behavior, or to diagnose problems. • Inspect — Examine for signs of component failure, reduced performance or

degradation. • Calibrate — Adjust the operating threshold or measurement accuracy of a

measuring element to meet the intended performance requirement.

Definitions: Protection System Maintenance Program (PSMP)

17

A deficiency identified during a maintenance activity that causes the component to not meet the intended performance, cannot be corrected during the maintenance interval, and requires follow-up corrective action.

Definitions: Unresolved Maintenance Issue

18

• Protection Systems or components of a consistent design standard, or a particular model or type from a single manufacturer that typically share other common elements. Consistent performance is expected across the entire population of a Segment.

• A Segment must contain at least sixty (60) individual components

Definitions: Segment

19

PRC-005-2 Workshop Protection Systems

o A Misoperation ‐ a false operation of a Protection System or a failure of the Protection System to operate, as designed, when needed ‐ can result in equipment damage, personnel hazards, and wide‐area Disturbances or unnecessary customer outages.

o Maintenance or testing programs are used to determine the performance and availability of Protection Systems.

20

A failure of a component requiring repair or replacement, any condition discovered during the maintenance activities in Tables 1-1 through 1-5 and Table 3 which requires corrective action, or a Misoperation attributed to hardware failure or calibration failure.

o Misoperations due to product design errors, o software errors, o relay settings different from specified settings, o Protection System component configuration errors, o or Protection System application errors are

Are not included in Countable Events.

Definitions: Countable Event

21

Tables & Attachments

Table or Att. Description Table 1-1 Protective Relay’s Table 1-2 Communications Systems Table 1-3 Sensing Devices Table 1-4a DC Supply (VLA Batteries) Table 1-4b DC Supply (VRLA Batteries) Table 1-4c DC Supply (NiCad Batteries) Table 1-4d DC Supply (non- Battery Table 1-4e Exclusions for monitoring Table 1-5 Control Circuitry Table 2 Alarming Paths Table 3 Distributed UFLS and UVLS Systems Attachment A Criteria for a Performance Based Protection

System Maintenance Program.

22

• The following evidence retention periods identify the period of time an entity is required to retain specific evidence to demonstrate compliance.

• For instances where the evidence retention period

specified is shorter than the time since the last audit, the Compliance Enforcement Authority may ask an entity to provide other evidence to show that it was compliant for the full time period since the last audit.

Data and Evidence Retention

23

• Current dated Protection System Maintenance Program, as well as any superseded versions since the preceding compliance audit, including the documentation that specifies the type of maintenance program applied for each Protection System Component Type.

• Documentation of legacy programs also required.

Data and Evidence Retention Requirement 1

24

• Documentation of the two most recent performances of each distinct maintenance activity for the Protection System Component, or

• All performances of each distinct maintenance activity for the Protection System Component since the previous scheduled audit date, whichever is longer.

Data and Evidence Retention Requirements 2-5

Project 2007-17.3 (PRC-005-X)

Protection System Maintenance and Testing – Phase 3 (Sudden Pressure

Relays)

High Level PRC-005-X Draft 2 Changes • Removed Requirement R6 (BA Requirement) • Modified Table 5 to provide clarity • Revised Section 4.2.6.1 to address situations where

Balancing Authorities participate in a Reserve Sharing Group

• Modified Facilities Section 4.2.5.3 by adding Sudden Pressure Relaying

• Modified the Supplementary Reference and FAQ Document to reflect the changes in the Standard

PRC-005-X Key Dates

• July 25, 2014: Standard posted for 45-day comment and ballot

• September 2014: Final Ballot • November 2014: NERC Board of Trustees adoption • December 2014: File with FERC

PRC-005-X NERC Contact

• Jordan Mallory, NERC Standards Developer Specialist

Phone: 404.446.9733 Email: [email protected] Project Page Link • Please call or email with any questions or concerns

regarding Project 2007-17.3 (PRC-005-X)

mailto:[email protected]

http://www.nerc.com/pa/Stand/Pages/Project-2007-17_3-Protection-System-Maintenance-and-Testing-Phase-3.aspx

Project 2014-01 Dispersed Generation Resources

Standard Drafting Team (DGR SDT)

Overview of PRC-005-X(X) DGR SDT Recommended Changes • DGR SDT scope limited to recommendations on

Standards applicability to DGRs • Changes made in tandem with Project 2007-17.3

(Sudden Pressure Relays) • Changes clarify the applicability of PRC-005-X to DGRs

• The DGR SDT made no substantive changes to the Standard • Section 4.2.5 separated into two sections (4.2.5 and

4.2.6) • Differentiates between typical Bulk Electric System generator

Facilities and BES generators • The applicability to DGR Facilities has been modified and

relocated from 4.2.5 to 4.2.6.

Applicability PRC-005-2/3/X

• 4.2.6 Protection Systems for the following BES generator Facilities for dispersed power producing resources identified through Inclusion I4 of the BES definition:

• 4.2.6.1 Protection Systems for Facilities used in aggregating dispersed BES generation from the point where those resources aggregate to greater than 75 MVA to a common point of connection at 100 kV or above.

• Rationale for 4.2.6: The Facilities listed that are applicable to dispersed power

producing facilities are covered within 4.2.6. The intent is to NOT include the individual generating resources in the Protection System Maintenance Program, and as such the Protection Systems within the individual generating resources would not be within the scope of PRC-005. Only Protection Systems on equipment used in aggregating the dispersed BES generation from the point where those resources aggregate to greater than 75MVA to a common point of connection at 100kV would be included in the Protection System Maintenance Program, including the Protection Systems for those transformers used in aggregating generation.

PRC-005-X(X) Key Dates

• June 12, 2014: Standard posted for 45-day comment and ballot

• July 18-28, 2014: Initial ballot period • September 2014: Second ballot (if necessary) • November 2014: Target date for NERC Board

adoption

PRC-005-X(X) NERC Contact

• Sean Cavote, NERC Standards Developer Phone: 404.446.9697 Email: [email protected] Project Page: http://www.nerc.com/pa/Stand/Pages/Project-2014-01-Standards-Applicability-for-Dispersed-Generation-Resources.aspx

• Please call or email with any questions or concerns

regarding Project 2014-01 (PRC-005-X(X))


http://www.nerc.com/pa/Stand/Pages/Project-2014-01-Standards-Applicability-for-Dispersed-Generation-Resources.aspx

















Fred Johnson & Jim Terpening WECC Compliance Auditor Consultants

Applicability of PRC-005-2 & Examples of New BES Definition

35

• During the past 20 years, major functional advances are primarily due to the introduction of microprocessor technology for power system devices, such as primary measuring relays, monitoring devices, control Systems, and telecommunications equipment.


Protection and control systems have seen dramatic technological changes spanning several generations.

36

Self monitoring capability Ability to capture Fault records Ability to meter currents and voltages Data communications via ports Ability to trip or close circuit breakers and switches Construction from electronic components


Modern microprocessor‐based relays have six significant traits that impact a Maintenance strategy:

37

Acting as a Digital Fault Recorder (DFR) Allowing Protection Engineers to study the fault(s)

and the clearing time of the fault.


Modern microprocessor‐based relays

o Fault record(s) showing how the Protection System responded to a Fault in its zone of protection, or to a nearby Fault

38

• Meter currents and voltages, as well as status

of connected circuit breakers, continuously during non‐Fault times.

• Can compute values, such as MW and MVAR line flows, that are sometimes used for operational purposes, such as SCADA.



39

Modern microprocessor‐based relays • Provide remote access to all of the results of

Protection System monitoring, recording and measurement.


40

Modern microprocessor‐based relays • Trip or close circuit breakers and switches

through the Protection System outputs o On command from remote data communications

messages • From relay front panel button requests.


41


• Significant advances in the technology behind the other components of the Protection Systems, Microprocessors are now a part of: Battery chargers Associated communications equipment Voltage and current‐measuring devices Control circuitry (in the form of software‐latches

replacing lock‐out relays, etc.)


42

NERC Definition of a Protection System: o Protective relays which respond to electrical

quantities

o Communications Systems necessary for correct operation of protective functions

o Voltage and current sensing devices providing inputs to protective relays


43

NERC Definition of a Protection System: o Station dc supply associated with protective

functions (including station batteries, battery chargers, and non‐battery‐based dc supply)

o Control circuitry associated with protective functions through the trip coil(s) of the circuit breakers or other interrupting devices.


44


Applicable Relays The NERC Glossary definition of a Protection System includes relays, dc supply, current and voltage sensing devices, dc control circuitry and associated communications circuits. The relays to which this standard applies are those protective relays that respond to electrical quantities and provide a trip output to trip coils, dc control circuitry or associated communications equipment. This definition extends to IEEE Device No. 86 (lockout relay) and IEEE Device No. 94 (tripping or trip‐free relay), as these devices are tripping relays that respond to the trip signal of the protective relay that processed the signals from the current and voltage‐sensing devices. Relays that respond to non‐electrical inputs or impulses (such as, but not limited to, vibration, pressure, seismic, thermal or gas accumulation) are not included.

45


• This standard does not cover circuit breaker maintenance or transformer maintenance.

• The standard also does not presently cover testing of

devices, such as sudden pressure relays (63), temperature relays (49), and other relays which respond to mechanical parameters, rather than electrical parameters.

Mechanical Devices that do not operate electrically with no calibration settings

46

• An auxiliary relay, IEEE Device No.# 94, is described in IEEE Standard C37.2‐2008 as: “A device that functions to trip a circuit breaker, contactor, or equipment; to permit immediate tripping by other devices; or to prevent immediate reclosing of a circuit interrupter if it should open automatically, even though its closing circuit is maintained closed.”


Auxiliary Relays

47

• A lock‐out relay, IEEE Device No.# 86, is described in IEEE Standard C37.2 as: “A device that trips and maintains the associated equipment or devices inoperative until it is reset by an operator, either locally or remotely.”

• Software‐latch 86 that replaces an electromechanical 86 does not require routine trip testing

• Any trip circuitry associated with the “soft 86” would still need applicable verification activities performed, but the actual “86” does not have to be “electrically operated” or even toggled

P 13 – Supplementary Reference and FAQ dated October 2012


Lock-out Relay

48

New Bulk Electric System Definition Application to PRC-005-2


49

Unless modified by the lists of Inclusions or exclusions, all Transmission Elements operated at 100 kV or higher and Real Power and Reactive Power resources connected at 100 kV or higher. This does not include facilities used in the local distribution of electric energy.

Bulk Electric System (BES) Definition

50

Compliance obligations for newly identified Elements (Phase 2): o Twenty‐four months after the applicable

effective date of the definition: July 1, 2014 + 24 mo. = July 1, 2016

or o If a longer timeframe is needed…the

appropriate timeframe may be determined on a case‐by‐case basis by agreement between the RRO and Element owner/operator.

BES Definition – Newly Defined Elements- Compliance Obligation

51

Compliance obligations for newly identified Elements: o New Elements to be commissioned after July 1,

2014 must be compliant prior to being placed into service.

BES Definition – Newly Defined Elements

52

Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit breaker, bus section, or transmission line. An element may be comprised of one or more components.

Transmission Element

53

• Step 1- Apply core definition o Is the device operated at 100kV or higher? o Is the power or reactive resource connected at

100kV or greater? • Step 2- Apply specific inclusions o Do any of the inclusions result in additional

devices to be considered a “BES element”?

Process to determine if a element is BES

54

• Step 3- Apply specific exclusions o Are there specific situations for potential

exclusion from the BES?

RESULT: The protection systems associated with the resultant BES elements are subject to PRC-005-2

Process to determine if a element is BES (continued)

55

I1. Transformers with the primary terminal and at least one secondary terminal operated at 100 kV or higher unless excluded under Exclusion E1 [radial] or E3 [local network].

BES Inclusion I1- Transformers

56

A B Typical Two winding Transformer Question: Which Transformer is a BES element?


> 100 kV > 100 kV > 100 kV < 100kV

57

A B

Typical Three winding Transformer

Question: Which Transformer is a BES element?


Load Load

58

I2. Generating resource(s) including the generator terminals through the high‐side of the step‐up transformer(s) connected at a voltage of 100 kV or above with: • Gross individual nameplate rating greater than 20

MVA. Or, • Gross plant/facility aggregate nameplate rating

greater than 75 MVA.

BES Inclusions I2- Generating Resources

59

A B > 20 MVA 19 MVA

Question: Which Power Resource is a BES element?


60

A Multiple Generators Examples B


61

Multiple Generators with an Aggregate Resources of 79 MVA


62

Multiple Generators with an Aggregate Resources of 79 MVA with one Generator serving load


63

I3. Blackstart Resources identified in the Transmission Operator’s restoration plan. Resources are included in the BES regardless of configuration or location.

BES Inclusions I3- Blackstart Resources

64

I4. Dispersed power producing resources that aggregate to a total capacity greater than 75 MVA (gross nameplate rating), and that are connected through a system designed primarily for delivering such capacity to a common point of connection at a voltage of 100 kV or above. Thus, the facilities designated as BES are: • The individual resources, and • The system designed primarily for delivering capacity from the point

where those resources aggregate to greater than 75 MVA to a common point of connection at a voltage of 100 kV or above.

BES Inclusions I4- Dispersed Power Resources

65

BES Inclusions I4- Dispersed Power Resources – Wind Farm 80 MVA

<100 kV/≥100 kV

≥100 kV

Wind Farm – 80 MVA individual units 2 MVA

The Common Point of connection is where the individual transmission Element(s) of the collector system is connected to the 100kV or higher

Transmission system. (Note: This point is typically specified in the respective Transmission Owner and Generator Operator Interconnection Agreements.)

The point of aggregation is where

the individual generator name plate

ratings of the dispersed generation total > 75 MVA (actual 80 MVA) and a failure would result in loss of 75 of MVA capacity or

greater to the BES.

66

<100 kV/≥100 kV

≥100 kV

Photovoltaic System – 80 MVA individual units 20 MVA

Photovoltaic Cells & Inverters (Banks)

The Common Point of connection is where the individual transmission

Element(s) of the collector system is connected to the 100kV or higher Transmission system. (Note: This

point is typically specified in the respective Transmission Owner and Generator Operator Interconnection

Agreements.)

BES Inclusions I4- Dispersed Power Resources- 80MVA Photovoltaic System

The point of aggregation is where the individual generator name plate ratings of the

dispersed generation total > 75 MVA (actual 80 MVA) and a failure would result in loss of 75 of

MVA capacity or greater to the BES.

67

Photovoltaic System – 80 MVA individual units 20 MVA aggregated below 100kV.

BES Inclusions I4- Dispersed Power Resources- 80 MVA Photovoltaic System

The point of aggregation is where the individual generator name plate ratings of the dispersed

generation total > 75 MVA (actual 80 MVA) and a failure would result in loss of 75 of MVA

capacity or greater to the BES.

The Common Point of connection is where the individual transmission Element(s) of the

collector system is connected to the 100kV or higher Transmission system. (Note: This point is typically specified in the respective Transmission Owner and Generator Operator Interconnection

Agreements.)

≥100 kV

≥100 kV

<100 kV <100 kV

<100 kV

Photovoltaic Cells & Inverters (Banks)

68

I5. Static or dynamic devices (excluding generators) dedicated to supplying or absorbing Reactive Power that are connected at 100 kV or higher, or through a dedicated transformer with a high‐side voltage of 100 kV or higher, or through a transformer that is designated in Inclusion I1.

BES Inclusions I5- Static or Dynamic Devices

69

BES Inclusions I5- Reactive Resources Reactive Resource “2” is connected directly to the station bus (≥100 kV) and is therefore considered to be a BES Element

Reactive Resource “1” is connected through the tertiary winding of a transformer that meets the inclusion criteria established by Inclusion I5 (i.e., through a transformer that is designated in Inclusion I1) and is therefore considered to be a BES Element

Reactive Resource “3” is connected through a dedicated transformer with a high-side voltage of ≥ 100 kV and is therefore considered to be a BES Element. The dedicated transformer does not meet the inclusion criteria established by Inclusion I1 and is therefore not considered to be a BES Element

Reactive Resource “4” is connected directly to the station bus (≥100 kV) and is not connected through a dedicated transformer with a high-side voltage of 100 kV or higher or through a transformer that is designated in Inclusion I1, and is therefore not considered to be a BES Element

1 2

3

4 Load

> 100 kV

<100 kV <100 kV

>100 kV /<100 kV >100 kV

>100 kV >100 kV

70

E1. Radial systems: A group of contiguous transmission Elements that emanates from a single point of connection of 100 kV or higher and: a.) Only serves Load. Or, b.) Only includes generation resources, not identified in Inclusions I2, I3, or I4, with an aggregate capacity less than or equal to 75 MVA (gross nameplate rating). Or, c.) Where the radial system serves Load and includes generation resources, not identified in Inclusions I2, I3, or I4, with an aggregate capacity of non‐retail generation less than or equal to 75 MVA (gross nameplate rating).

BES Exclusion E1- Radial Systems

71

“Single Point of Connection of 100 kV or higher” is where the radial system will begin if it meets the criteria of Exclusion E1, including parts a, b, or c. For example, the start of the radial system may be a hard tap of the Transmission line, or could be the tap point within a ring or breaker and a half bus configuration. The connection to the radial system must be from only one point at 100 kV or higher. Any group of contiguous transmission elements that have multiple connections at 100 kV or higher do not qualify for Exclusion E1. Normally open switching devices between radial systems, will not disqualify a radial system from this exclusion.

E1- Definition “Single Point of Connection”

72

BES Exclusion E1- Radial System: Serving only load

Radial System: Serving only load

≥100 kV

Load

Substation Boundary

≥100 kV

Load

Substation Boundary

≥100 kV <100 kV

≥100 kV <100 kV

Green identifies non-BES (excluded radial system

The single Point of connection is where the radial system (group of

contiguous transmission Elements) emanates at a

voltage of 100 kV or higher from the Transmission

system.

73

BES Exclusion E1a- Multiple radial systems with underlying loop at ≤ 50 kV

Multiple Radial Systems (Underlying Loop Facilities ≤ 50 kV)

The single Point of connection is where the radial system (group of contiguous transmission Elements) emanates at a voltage of

100 kV or higher from the Transmission system.

A B C

D E F

Green identifies non-BES (excluded radial system

≥100 kV

Load

Substation Boundary

≥100 kV < 50 kV

Load

≥100 kV < 50 kV

< 50 kV Sub-100 kV Loop

74

BES Exclusion E1b- Radial System: Single Generation Resource

Radial System: Single Generation Resource ≥100 kV

The single Point of connection is where

the radial system (group of contiguous

transmission Elements) emanates at a voltage

of 100 kV or higher from the Transmission

system.

≥100 kV

≥100 kV <100 kV

≥100 kV <100 kV

≥100 kV ≥100 kV

15 MVA 25 MVA

75

BES Exclusion E1b- Radial System: Multiple Generation Resources less than 75 MVA

Radial System: Multiple Generators

≥100 kV

18 MVA

<100 kV / ≥100 kV

15 MVA

≥100 kV / <100 kV

The single Point of connection is where the radial system (group of

contiguous transmission Elements) emanates at a

voltage of 100 kV or higher from the

Transmission system.

The non-retail generators have gross individual nameplate

ratings ≤ 20 MVA (actual 18 MVA, 15 MVA, 14 MVA, 12 MVA, & 10 MVA. By application of Inclusion I2 these units are not considered

a BES Element

12 MVA

14 MVA

<100 kV / ≥100 kV

<100 kV / ≥100 kV

≥100 kV <100 kV

10 MVA

Generator Site Boundary

76

BES Exclusion E1c- Radial System: Generation Resources & Serving Load

Radial System: Generation Resources & Serving load ≥100 kV The single Point of connection is where the

radial system (group of contiguous transmission Elements) emanates at a voltage of 100 kV or higher from the


The generator has a gross individual nameplate rating >

20 MVVA (actual 25 MVA) and is connected through the high-side of the step-up transformer

at a voltage of 100 kV or above. By application of

Inclusion I2 this unit is a BES Element

The substation transformers are not part

of the BES since both (primary and secondary

terminals are not operated at ≥ 100 kV as

per Inclusion I1

≥100 kV <100 kV

25 MVA

≥100 kV <100 kV

≥100 kV <100 kV

Load

Load

77

BES Exclusion E1c- Radial System: Generation Resources & Serving Load

Radial System: Generation Resources & Serving load

≥100 kV The single Point of connection is where the radial system (group of contiguous

transmission Elements) emanates at a voltage of 100 kV or higher from the


Green identifies non-BES (excluded) radial system. The excluded radial system serves Load and has <20 MVA gross aggregate nameplate rating of

connected non-retail generation (actual 15 MVA)

and therefore meets the criteria of Exclusion E1c.

The substation transformers are not part

of the BES since both (primary and secondary

terminals are not operated at ≥ 100 kV as

per Inclusion I1

≥100 kV <100 kV

15 MVA

≥100 kV <100 kV

≥100 kV <100 kV

Load

Load

78

BES Exclusion E1- Radial System: Normally Open Switching Device

Two Radial Systems separated by an open switch

≥100 kV ≥100 kV

The single Point of connection is where the radial system (group of contiguous transmission Elements) emanates at a voltage of 100 kV or

higher from the Transmission system.

To Load

Substation Boundary

To Load

Substation Boundary

≥100 kV <100 kV

≥100 kV <100 kV

The normally open (N.O.) device between the radial systems does

not affect this exclusion

N.O.

<100 kV

The normally open (N.O.) device between the radial systems does not

affect this exclusion

N.O.

<100 kV

79

E2. A generating unit or multiple generating units on the customer’s side of the retail meter that serve all or part of the retail customer Load with electric energy on the customer’s side of the retail meter if:

BES Exclusion E2- Generation Resources on the customer side of a retail meter

80

(i) the net capacity provided to the BES does not exceed 75 MVA, and

(ii) standby, back‐up, and maintenance power services are provided to the generating unit or multiple generating units or to the retail Load by a Balancing Authority, or provided pursuant to a binding obligation with a Generator Owner or Generator Operator, or under terms approved by the applicable regulatory authority.


81

Net capacity: The net capacity determination for Exclusion E2 is the net flow to the BES as measured by integrated hourly revenue metering for the most recent 12 month period. Periods of net capacity to the BES that exceed the threshold value when directed by the applicable Balancing Authority do not preclude the ability to utilize this exclusion.


82


Behind‐the‐Meter Generation: Net Capacity to the BES less than 75 MVA

≥100 kV The single Point of connection is where the customer owned equipment is connected to the 100 kV or higher Transmission System. (Note:

This point is specified in the respective Interconnection Agreements.)

50 MVA to BES

100 MVA to Industrial Process

Customer owned generation behind the customer's meter is excluded from the BES by application of Exclusion E2: • Net capacity to the BES is less than 75 MVA

(Actual 50 MVA, and • Standby power has been secured in

accordance with the language of Exclusion E2.

≥100 kV/<100 kV

≥100 kV <100 kV

150 MVA

83


Behind‐the‐Meter Generation: Net Capacity to the BES greater than 75 MVA

≥100 kV The single Point of connection is where the

customer owned equipment is connected to the 100 kV or higher Transmission System. (Note:

This point is specified in the respective Interconnection Agreements.)

100 MVA to BES

50 MVA to Industrial Process

Customer owned generation resource behind the customer's meter is included in the BES: • By application of Inclusion I2, because the

generator’s gross individual nameplate rating is > 20 MVA (actual 150 MVA, and

• The net capacity to the BES is > 75 MVA (Actual 100 MVA, therefore Exclusion E2 does not apply.

≥100 kV/<100 kV

≥100 kV <100 kV

150 MVA

84

E3. Local networks (LN): A group of contiguous transmission Elements operated at less than 300 kV that distribute power to Load rather than transfer bulk power across the interconnected system. LN’s emanate from multiple points of connection at 100 kV or higher to improve the level of service to retail customers, and not to accommodate bulk power transfer across the interconnected system. The LN is characterized by all of the following:

BES Exclusion E3 - Local Networks

85

Limits on connected generation: The LN and its underlying Elements do not include generation resources identified in Inclusions I2, I3, or I4, and do not have an aggregate capacity of non‐retail generation greater than 75 MVA (gross nameplate rating);

Real Power flows only into the LN and the LN does not transfer energy originating outside the LN for delivery through the LN; and

Not part of a Flowgate or transfer path: The LN does not contain any part of a permanent Flowgate in the Eastern Interconnection, a major transfer path within the Western Interconnection, or a comparable monitored Facility in the ERCOT or Quebec Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).

BES Exclusion E3 - Local Networks

86

BES Exclusion E3- Local Network with aggregate generation less than 75 MVA LN operated at 138 kV with aggregate generation < 75 MVA with power

flow into network.

<300kV

230kV

The multiple points of connection are where the local network (group of contiguous transmission Elements) emanates at a voltage of 100 kV or higher from the Transmission system.

Power Flow

<100 kV 138 kV

The substation transformers are not part of the BES since both (primary and secondary) terminals are not operated at ≥100 kV as per Inclusion I1.

Load Load

<100 kV 138 kV

15 MVA

Power Flow

138 kV 230 kV

<300 kV 138 kV

15 MVA 10 MVA

Generation Site

Boundary

<300 kV 230 kV

<300 kV 230 kV

Power Flow

Load <100 kV/138 kV

25 MVA

1

2

3

4

87

BES Exclusion E3- Local Network with aggregate generation less than 75 MVA

LN operated at 138 kV with a BES generator.

<300 kV

230 kV

The multiple points of connection are where the local network (group of contiguous transmission Elements) emanates at a voltage of 100 kV or higher from the Transmission system.

Power Flow

<100 kV 138 kV

The substation transformers are not part of the BES since both (primary and secondary) terminals are not operated at ≥100 kV as per Inclusion I1. Except for the transformer on generation > 20 MVA.

Load Load

<100 kV 138 kV

30 MVA

Power Flow

138 kV 230 kV

<300 kV 138 kV

15 MVA 10 MVA

Generation Site

Boundary

<300 kV 230 kV

<300 kV 230 kV

Power Flow

Load <100 kV/138 kV

25 MVA

1

2

3

4

88

BES Exclusion E3- Sub 100kV loop power flowing out of network

Sub 100kV loop with Power flowing out of network

The presence of the sub-100 kV loop establishes multiple points of connection at a voltage level

of 100 kV or higher to the Transmission System

Load

Substation Boundary

<300 kV <100 kV/>50 kV

Load

Sub-100 kV Loop

A B C

D E F

<300 kV

Power Flow

The network does not meet the exclusion criteria established in Exclusion E3 due to power flowing out of the networked system (E3b)

<300 kV <100 kV/>50 kV

<100 kV/>50 kV

The substation transformers are not part of the BES since both (primary and secondary) terminals are not operated at ≥100 kV as per Inclusion I1.

Power Flow

89

E4. Reactive Power devices installed for the sole benefit of a retail customer(s). Reactive Power devices installed for the sole benefit of a retail customer(s) supersedes the more general Inclusion I5 (Static or Dynamic Reactive Power Devices). Reactive Power devices installed for the sole benefit of a retail customer are, by definition, not required for operation of the interconnected transmission system.

BES Exclusion E4- Reactive Power Devices

90

• Step 1- Apply core definition o Is the device operated at 100 kV or higher? o Is the power or reactive resource connected at

100kV or greater? • Step 2- Apply specific inclusions o Do any of the inclusions result in additional

devices to be considered a “BES element”?

Hierarchical Application of the Definition

91

• Step 3 - Exclusions should be applied in the following sequence: o Exclusion E2 - Behind‐the‐Meter Generation o Exclusion E4 - Reactive Power Devices o Exclusion E3 - Local Networks o Exclusion E1 - Radial Systems

RESULT: The protection systems associated with the resultant BES elements are subject to PRC-005-2

Hierarchical Application of the Definition

Joe Veltri Compliance Auditor, WECC

PRC-005-2 Workshop

Requirement R1

July 29th – 30th, 2014 Salt Lake City, UT

93

Establish a Protection System Maintenance Program for

Protection Systems

Requirement R1

94

Requirement R1.1

Identify which maintenance method (time-based, performance-based per PRC-005 Attachment A, or a combination) is used to address each Protection System Component Type. All batteries associated with the station dc supply Component Type of a Protection System shall be included in a time-based program as described in Table 1-4 and Table 3.

95

Include the applicable monitored Component attributes applied to each Protection System Component Type consistent with the maintenance intervals specified in Tables 1-1 through 1-5, Table 2, and Table 3 where monitoring is used to extend the maintenance intervals beyond those specified for unmonitored Protection System Components.

Requirement R1.2

96

Determine Maintenance Method • Time Based Condition Based (extending the interval)

• Performance Based

Requirement R1

97

TBM – time‐based maintenance – externally prescribed maximum maintenance or testing intervals are applied for components or groups of components.

Time Based Maintenance

98

• Select Appropriate Component Type Table • Determine Degree of Monitoring • Find Minimum Maintenance Activity • Determine Maximum Interval

Tables and Monitoring

99

• The Maintenance Activity(ies) is the minimum maintenance that must be performed and documented

• Under TBM, entities are responsible only for performing Minimum Maintenance Activities within the defined (or extended) interval.

Maintenance Activity

100

• Four Calendar Months Add four months from the last time the activity was performed.

• A battery bank is inspected in month no.1

then it is due again before the end of the month number 5.

Interval Definitions

101

Calendar Year ‐ January 1 through December 31 of any year. As an example, if an event occurred on June 17, 2009 and is on a “One Calendar Year Interval,” the next event would have to occur on or before December 31, 2010.

Interval Definitions

102

The Component Types

Sensing Devices Table 1-3

DC Supply Table 1-4a through 4f

Protective Relay Table 1-1

Communication Systems Table 1-2

Control Circuitry Table 1-5

103

• Table 1-1 Protective Relays • Table 1-2 Associated Communications • Table 1-3 Instrument Transformers • Table 1-4 Station DC Supply • Table 1-5 Control Circuits

Tables Associated with your Component

104

• Table 2 Alarming & Paths • Table 3 Distributed UFLS & UVLS • A DISTRIBUTED UFLS or UVLS scheme

contains individual relays which make independent load shed decisions based on applied settings and localized voltage and/or current inputs

Tables Associated with your Component

105

Protective Relay

Table 1-1 Component Type - Protective Relay

Excluding distributed UFLS and distributed UVLS (see Table 3) Component Attributes Maximum Maintenance Maintenance Activities Interval1

Any unmonitored protective relay not having all the monitoring attributes of a category below

6 calendar years

For all unmonitored relays: • Verify that settings are as specified

For non-Microprocessor relays: • Test and, if necessary calibrate

For Microprocessor relays: • Verify operation of the relay inputs

and outputs that are essential to proper functioning of the Protection System

• Verify acceptable measurement of

power system input values

Protective Relay (con’t)


Excluding distributed UFLS and distributed UVLS (see Table 3) Component Attributes Maximum Maintenance Maintenance Activities Interval1 Monitored microprocessor protective relay with the following: • Internal self-diagnosis and alarming

(see Table 2)

• Voltage and/or current waveform sampling three or more times per power cycle, and conversion of samples to numeric values for measurement calculations by microprocessor electronics.

• Alarming for power supply failure (see

Table 2)

12 calendar years

Verify:

• Settings are as specified.

• Operation of the relay inputs and outputs that are essential to proper functioning of the Protection System.

• Acceptable measurement of power

system input values

Protective Relay (con’t)


Excluding distributed UFLS and distributed UVLS (see Table 3) Component Attributes Maximum Maintenance Maintenance Activities Interval1 Monitored microprocessor protective relay with preceding row attributes and the following: • AC measurements are continuously verified

by comparison to an independent ac measurement source, with alarming for excessive error (see Table 2)

• Some or all binary or status inputs and control outputs are monitored by a process that continuously demonstrates ability to perform as designed, with alarming for failure (See Table 2)

• Alarming for change of settings (see Table 2).

12 calendar years

Verify only the unmonitored relay inputs and outputs that are essential to proper functioning of the Protection System.

DC Supply VLA

Table 1-4(a) Component Type – Protection System dc Supply Using Vented Lead Acid

(VLA) Batteries Excluding distributed UFLS and distributed UVLS (see Table 3)

Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS Systems

or non-distributed UVLS systems excluded (See Table 1-4(e))

Component Attributes Maximum Maintenance Maintenance Activities Interval

• Protection System Station dc supply using

Vented Lead-Acid (VLA) batteries not having monitored attributes of Table 1-4(f).

4 Calendar Months

Verify: • Station dc supply voltage Inspect: • Electrolyte level

• For unintentional grounds

DC Supply VLA






• Protection System Station dc supply using

Vented Lead-Acid (VLA) batteries not having monitored attributes of Table 1-4(f).

18 Calendar Months

Verify:

• Float voltage of battery charger • Battery continuity • Battery terminal connection resistance • Battery intercell or unit-to-unit connection

resistance

Inspect:

• Cell condition of all individual battery cells where cells are visible or measure battery cell/unit internal ohmic values where the cells are not visible.

• Physical condition of battery rack.

DC Supply VLA






• Protection System Station dc supply using Vented

Lead-Acid (VLA) batteries not having monitored attributes of Table 1-4(f).

18 Calendar Months

-or-

6 Calendar

Years

Verify that the station battery can perform as manufactured by evaluating cell/unit measurements indicative of battery performance ( e.g. internal ohmic values or float current) against the station battery baseline.

-or-

Verify that the station battery can perform as manufactured by conducting a performance of modified performance capacity test of the entire battery bank.

112

• Table 1-4(b) Valve regulated Lead Acid • Table 1-4(c) Nickel Cadmium (NICAD) • Table 1-4(d) Non Battery Based Energy

Storage Each Table defines Maximum Maintenance Interval and Maintenance Activities

DC Supply Tables

113

• Any unmonitored communication system necessary for correct operation of protective functions

• Continuous monitoring or periodic automated testing and alarm for loss of function

• Continuous monitoring or automated testing (signal level. Reflected power, data error rates)

• Binary inputs and control outputs monitored by process continuously demonstrating ability to perform as designed with alarming for failure.

Communication Systems Table 1-2

114

• Trip Coils • Electromechanical lockout devices • Unmonitored control circuitry associated with

SPS • Unmonitored control circuitry inclusive of all

auxiliary relays • Monitored & alarmed control circuitry

associated with protective functions and /or SPS

Control Circuitry Associated with Protective Functions

Instrument Transformers

Table 1-3 Component Type – Voltage and Current Sensing Devices providing inputs

to Protective Relays Excluding distributed UFLS and distributed UVLS Table 3) Component Attributes Maximum Maintenance

Maintenance Activities Interval1

12 calendar years

Any voltage and current sensing devices not having monitoring attributes of the category below

Verify that current & voltage signal values are provided to the protective relays

Instrument Transformers

Table 1-3 Component Type – Voltage and Current Sensing Devices providing inputs

to Protective Relays Excluding distributed UFLS and distributed UVLS Table 3) Component Attributes Maximum Maintenance

Maintenance Activities Interval1

No Periodic Maintenance

specified

Voltage and current sensing devices connected to microprocessor relays with AC measurements are continuously verified by comparison of sensing input value as measured by the MP relay to independent measuring source with alarming for unacceptable error failure (See table 2)

None

Extension for DC Supply Monitoring Table 1-4 (f)

Alarming Paths & Monitoring

119

• Unmonitored Protective Relays • Monitored Microprocessor Relays • Instrument Transformers • Protection System DC Supply • Control Circuits o Relay to Lockout o Lockout to tripping device Excludes Trip Coils of Non- BES interrupting devices

UFLS / UVLS Table 3

Roger Cummins Sr. Compliance Auditor, WECC

PRC-005-2 Workshop Requirement R2

July 29th – 30th, 2014

Salt Lake City, UT

121

Establishing a Performance-based Plan

Requirement R2

122

Establishing a Performance-based Plan

Requirement R2

123

R2. Each Transmission Owner, Generator Owner, and Distribution Provider that uses performance-based maintenance intervals in its PSMP shall follow the procedure established in PRC-005 Attachment A to establish and maintain its performance-based intervals.

Requirement R2

124

• There is a requirement to develop a PSMP

• There is no requirement to develop a Performance-based PSMP

• A PBM PSMP must be followed, even if more stringent (activities, intervals)

R2 Applicability

125

Maintain components per the

Maintenance Program (R4)

R2 – The Process

Establish a Maintenance

Program (R1)

Choose TBM or PBM

for each Component

Type (R1)

Follow Attachment A criteria to establish and maintain PBM

(R2)

Maintain components per the

Tables (R3)

Maintain components per the Maintenance

Program (R4) Take action to

correct Unresolved Maintenance Issues

(R5)

Start

End

PBM TBM

PRC-005-2 Requirements

Flowchart

Follow Attachment A criteria to

establish and maintain PBM (R2)

126

Segment o At least 60 components. oComponents of a consistent design standard,

particular model or type, single manufacturer, share other common elements.

oConsistent performance is expected across the population of a Segment.

R2 – Definitions

127

Segment Considerations oManufacturer oModel oDesign Standard o Failure Mode o Environment o Vintage o…

R2 – Definitions

128

Countable Events o a failure of a component requiring repair or

replacement o any condition discovered during the

maintenance activities which requires corrective action

o a Misoperation attributed to hardware or calibration failure.

R2 – Definitions

129

The solution with the fewest assumptions should be selected

o in the absence of certainty, embrace simplicity o trade simplicity only for greater explanatory power o explanatory power shifts the burden of proof

Occam’s Razor

130

R2 – Follow Attachment A to establish and maintain performance-based intervals

R2 – Attachment A Criteria

131

Establish per Attachment A 1. Develop Segments 2. Maintain Components 3. Document Maintenance Activities 4. Analyze Maintenance Activities 5. Determine Maximum Intervals

R2 – Attachment A Criteria

132

1. Develop a list of Segments with a description of Components included in each designated Segment.

2. Maintain the Components in each Segment according to the time-based intervals in the Tables until results are available for a minimum of 30 individual Components.

Establish Technical Justification

133

3. Document the program activities and results for each Segment, including dates and Countable Events for each Component.

4. Analyze the activities and results for each

Segment to determine the overall performance of the Segment.


134

5. Determine the maximum allowable maintenance interval for each Segment

• such that the Segment experiences Countable Events on no more than 4% of the Components within the Segment,

• for the greater of either the last 30 Components maintained or all Components maintained in the previous year.


135

…such that the Segment experiences Countable Events on no more than 4% of the Components within the Segment…

• Population of greater last 30 components maintained, or, all components maintained within the last year.

• Must do 30 or the greater of the 2 • Count # of events in the segment (and maintenance) population • Calculate Countable Events %:

Countable Events

# CEs in Segment + Maintenance Population Countable Events % = ──────────────────────── X 100 Segment Population

136

If you have 4% or more...? o Develop, document, and implement an action plan to

reduce the Countable Events to less than 4% of the Segment population within 3 years. • Increase maintenance activities • Reduce Segment interval • Accelerate maintenance to maintain all

components in the Segment within the reduced interval.

Countable Events

200 Devices

Phil O’Donnell WECC Manager Operations & Planning Audits

Requirement 3- Implementation of Time based programs

139

R3. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes timebased maintenance program(s) shall maintain its Protection System Components that are included within the time-based maintenance program in accordance with the minimum maintenance activities and maximum maintenance intervals prescribed within Tables 1-1 through 1-5, Table 2, and Table 3.

WECC Auditor’s Approach to Auditing the PRC Standards PRC-005-2 – Requirement 3

140

Very similar to the current PRC Standards except… ● Required Maintenance Activities are

specified ● Maximum Interval is Specified

WECC Auditor’s Approach to Auditing the PRC Standards

PRC-005-2 – Requirement 3

141

142

A comprehensive list of all of the entity’s Protection System Components (and Alarm Paths) being maintained under PRC-005-2 time-based maintenance programs providing:

● Will be requested prior to audit (when RSAW and initial documentation is due)

● This will provide the basis for a sample records for additional review

● This will be communicated by completing the Attachment G Supplemental spreadsheet.

Evidence for Assessment Per Draft RSAW

143

Tracking and Providing Additional Data

Attachment G Supplement

144

● Type of Program: TBM (or PBM or Combination for R4) ● Applicable Standard: PRC-005-2 (or Legacy Program) ● The Component Identification

o (Device Name and Device Description, Protection Type)

● Physical location o (Bus or Generator)

● Component Type o (Relay, Sensing Device, Com, DC Control Circuity, Battery/DC Supply)

● The dates of the last two performances of all maintenance activities, or all performances of maintenances activities since the last audit, whichever is greater.

● The maintenance interval(s) pertaining to the Component or Path in each year since the last audit. (There may be more than one).

● The applicable PRC-005-2 Table being used for required maintenance.

Evidence for Assessment Attachment G Supplement Info

145

• Expand the Attachment G Supplement to include the required data.

• Provide options for organization of data.


146

Option 1: Legacy tabs will be provided. o Input data as before, additional data required.


147

• Use the Legacy tabs – (PRC-005-1, 008, 011, 017) • Input as before;

Option 1 - Legacy

Gen/Substation Name

Device Name

Device Description

Date Last Tested

Prior Test Date

Interval

148

Additional data is required.

Option 1 – Legacy

Interval Maintenance Method

Maintenance Program Version (Last)

Maintenance Program Version (Prior)

Monitoring (Y/N)

Segment Identifier

12 yrs TBM v2 v1 Yes 8 yrs TBM v1 v1 Yes 20 yrs PBM v2 v1 Yes B

Use other Legacy tabs as applicable to list UFLS, SPS

149

Option 2: PRC-005 All Components o List all devices in this single tab


150

Additional data required

Option 2 – One Big Pile

Protection Type (UFLS,

SPS) Table

UFLS Table 3

SPS

UVLS

151

Option 3: Segment tabs o List Segments o List all PBM Components by Segment. o TBM components use either Option 1 or 2.


152

Option 3 – By Segment

Segment Identifier

Segment Description

Segment Interval Countable

Events (%)

Date of Most

Recent Analysis

General Notes

1 2 3 4 1 2 3 4

A Line Package 12 12 18 16 0 0 1

B SEL MP Relay 20 20 20 20 1 0 0 0

C GE BDD EM Relay 10 8 8 6 2 2 3 2

… … … …

Segments tab o List each defined Segment

153

Segment Components tab o List the Components within each Segment.

Option 3

Segment Identifier

Component Location

Component Name/ Description

Last Test Date

Program Version (Last)

Prior Test Date

Program Version (Prior)

A Elroy Sub LL Package V2 V1 A Astro Sub LL Package V2 v1 B Jane #1 JJ-KK Line SEL-321 V1 v1 B George #2 JJ-KK Line SEL-321 V1 v1

154

NERC Sampling Guidelines

155

NERC Sampling Guidelines

156

● Samples will be requested which satisfy NERC sampling guidelines.

● Detailed Documentation for each Component required if selected for sample.

● Documentation that the maintenance specified by the Tables was performed on the dates required. o The evidence may include but is not limited to dated maintenance records, dated maintenance

summaries, dated check-off lists, dated inspection records, or dated work orders.

Evidence for Assessment

New Documentation that that each component or Path being maintained under PRC-005-2 has the attributes specified by the PRC-005-2 Tables which justifying the use of the maintenance interval and/or minimum maintenance activities being performed.

157

Legacy Programs

158

● More info in discussion on Implementation of PRC-005-2

● Single Attachment G Supplement ● Samples will include some from old

programs ● Will be held to requirements of previous

standards ● Will be looking for Progress on Transition.

Legacy Programs

Fred Johnson- WECC Consultant

Requirement 4 -Implementation of Performance

Based Maintenance Programs

160

PRC-005-2, R4 Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes performance-based maintenance program(s) in accordance with Requirement R2 shall implement and follow its PSMP for its Protection System Components that are included within the performance-based program(s).

PRC-005-2 Workshop R4- Implementation of Performance Based Maintenance Program

161

Requirement 2 states: Each Transmission Owner, Generator Owner, and Distribution Provider that uses performance-based maintenance intervals in its PSMP shall follow the procedure established in PRC-005-2, Attachment A to establish and maintain its performance-based intervals.


162

This requirement is to verify that the entity has implemented its program in accordance with Attachment A and that the components within the segments has been maintained within their established intervals and the minimum maintenance activities have been performed in accordance with Tables 1-1 through 1-5, Table 2, and Table 3


163

RSAW Evidence o In order to verify maintenance intervals have

been properly established and maintained by following is required: A list of all segments established or maintained

since last audit. List is to include: • Segment identification • Segment Description ( SEL 421, Control circuitry, ASEA

PT’s, Protection System Package) • Maximum Maintenance interval • Countable events • Countable Events %


164

RSAW Evidence o Complete list of all segments since last audit List is to include

• Individual segment identification • Identification of each component and its location within

each segment. • Segment population. • Maximum Maintenance Interval. • Last and previous maintenance dates. • Program version used for prior maintenance


Jim Terpening WECC Consultant

PRC-005-2 Workshop R5 Unresolved Maintenance Issues

July 29 – 30, 2014 Salt Lake City, UT

166

PRC-005-2, R5 o Each Transmission Owner, Generator Owner,

and Distribution Provider shall demonstrate efforts to correct identified Unresolved Maintenance Issues. Compliance Date is April 1, 2015


167

Definition – Unresolved Maintenance Issue o A deficiency identified during a maintenance

activity that causes the component to not meet the intended performance, cannot be corrected during the maintenance interval, and requires follow-up action.


168

Application o Transmission and Generation Protection

Systems (PRC-005) o Under-frequency Load Shedding Equipment (PRC-008)

o Undervoltage Load Shedding Equipment (PRC-011)

o Special Protection Systems (PRC-017)

o These standards have now been incorporated into our PRC-005-2


169

• The Maintenance Activities specified in the Tables do not present any requirements related to Restoration; R5 of the standard does require that the entity “shall demonstrate efforts to correct any identified Unresolved Maintenance Issues.”

• The type of corrective activity is not stated; however it could include repairs or replacements.


170

Example Correction of Unresolved Maintenance issues o Include but not limited to: Replacement of capacitors in distance relays Replacement of relay(s) Other Protection System Components Upgrade of electromechanical relay(s) Upgrade of Solid State Protective relay(s) to

Microprocessor based devices


171

RSAW Evidence o Complete list of all Unresolved Maintenance

Issues Since last audit April 1, 2015

• Any UMI on this date will be reviewed back to 2014 • Tracking from April 1, 2014 for UMI will be needed

List is to include • Resolved Maintenance Issues • Remaining Unresolved Maintenance Issues


172

RSAW Evidence o Complete list of all Unresolved Maintenance

Issues List is to include (con’t)

• Date encountered • Local Zone of Protection • Protected Element • Substation • Other Location(s) • Specific Components • Function • Manufacture


173

RSAW Evidence o Unresolved Maintenance Issues Evidence demonstrating efforts to correct the

Identified Unresolved Maintenance Issue. • Evidence – Documentation should be but not limited to:

• Copies of component orders • Invoices • Project schedules with completed milestones • Return Material authorizations • Purchase orders


Roger Cummins Sr. Compliance Auditor, WECC

PRC-005-2 Workshop Implementation and Transition

July 29th – 30th, 2014

Salt Lake City, UT

175

Implementation And

Transition

PRC-005-2

176

Implementation What To Do

And When To Do It

PRC-005-2

177

For purposes of calculating the time periods in the implementation plan, the regulatory approval date in the U.S. is February 24, 2014.

Implementation

178

PRC-005-2 was effective April 1, 2014. o The first compliance date is April 1, 2015. o Must have a PSMP (TBM, PBM or both). o Current plan may be used to become compliant

with PRC-005-2.

Implementation

179

Current intervals and activities may be used to maintain compliance, but o the implementation plan compliance dates must

be met o only maintenance performed according to the

PRC-005-2 Standard is compliant with v2 o The legacy standards retire 2027

Implementation

180

• Entities shall be 100% compliant on the first day of the first calendar quarter twelve (12) months following applicable regulatory approvals.

• April 1, 2015.

Implementation

181

• R1 – Establish a plan • R2 – Follow Att. A to establish PBM • R5 – Unresolved Maintenance Issues o Entities should be tracking UMI as of April 1,

2014. o Evidence of efforts to correct the UMI may be

requested for those outstanding on April 1, 2015.

Implementation

182

• Phased implementation, based on Maximum Allowable Interval.

• R3 and R4 refer to components in both TBM and in PBM.

Implementation

183

Implementation

Maximum Interval <1 calendar year Compliance Months Compliance Date

100% 18 October 1, 2015

Maximum Interval ≥1 / <2 calendar years Compliance Months Compliance Date

100% 36 April 1, 2017

184

Implementation

Maximum Interval 3 calendar years Compliance Months* Compliance Date

30% 24 April 1, 2016 60% 36 April 1, 2017

100% 48 April , 2018

*For generating plants with scheduled outage intervals exceeding two years, at the conclusion of the first succeeding maintenance outage.

185

Implementation

Maximum Interval 6 calendar years Compliance Months* Compliance Date

30% 36 April 1, 2017 60% 60 April 1, 2019

100% 84 April 1, 2021

*For generating plants with scheduled outage intervals exceeding three years, at the conclusion of the first succeeding maintenance outage.

186

Implementation

Maximum Interval 12 calendar years Compliance Months Compliance Date

30% 60 April 1, 2019 60% 108 April 1, 2023

100% 156 April 1, 2027

187

Transition Things We Need To Know

and Stating The Obvious

PRC-005-2

188

• While in transition, be prepared to identify: o All applicable Protection System components. o The plan under which they were last

maintained; PRC-005-2 or the applicable Legacy plan.

Transition

189

Added maintenance activities: o For activities being added to an entity’s

program, evidence may be available to show only a single performance.

Transition

190

The Legacy Standards: o Remain active throughout the phased

implementation; o Applicable to an entity’s Protection System

component maintenance not yet transitioned to PRC-005-2.

Transition

191

The Legacy Standards o “retired” by the entity as Component Types

become compliant with PRC-005-2… All of a type described in the Component Attributes

or defined in a Segment; A Maximum Allowable Interval must be determined.

Transition

192

Maintain Protection System components: o According to the maintenance program already

in place for the legacy standards or the maintenance program for PRC-005-2.

But not both.

Transition

193

Choose the version of your plan that will be used to come into compliance with PRC-005-2. o May apply individually to specific Components o May apply to all Components o If using Legacy plan, the intervals and activities

in the legacy plan may be used. To maintain compliance with Legacy standards

Transition

194

Once an entity has designated PRC-005-2 as its maintenance program for specific Protection System components, it cannot revert to the original program for those components. • You get to make the call but you can’t take it

back.

Transition

195

Maintain Components according to the Tables: o Staying with TBM? Test according to the

Tables. o Moving to PBM? Test 30 according to Tables. Or, verify maintenance activities for 30 are available Perform analysis and implement that Segment.

Transition

196

Maintain documentation to demonstrate compliance with the Legacy Standards o until the entity meets the requirements of

PRC-005-2 in accordance with this implementation plan.

Transition

197

“…meets the requirements of PRC-005-2…” o Once an individual component has been

maintained according to the Tables Last test demonstrates performance of the Minimum

Maintenance Activities.

Transition

198

“…meets the requirements of PRC-005-2…” Or, o The Component is in an established Segment. Consistent performance expectation Sampled annually (≥ 5%) Reasonable assurance of consistent performance

across the population.

Transition

199

Formally transitioning Component Type(s) to PRC-005-2. o Once a Last and Prior test demonstrate

performance according to the tables, that specific Component is compliant with PRC-005-2. (an EM relay)

o Once a group of components, or Component Type is compliant, that Component Type may be transitioned to PRC-005-2. (All EM relays)

Transition

200

TBM to TBM Transition

Last Tested Due Date

2013 2021

Legacy Plan Defined 8 year Interval

201


Last Tested 100%

2013 2021

30%

2017 2019

60%

2015

Compliance Date

PRC-005-2 TBM Maximum 6 year Interval

Includes past maintenance, if compliant

202

TBM to PBM Transition

Last Tested

2013

Test 30

Components

2015

Compliance Date

PRC-005-2 PBM Segment A

Max Interval for this

Segment

Each Year

Test ≥5%

Test ≥5%

Test ≥5%

Time-Based Performance-Based (R2) (R4)

100%

203


Last Tested Due Date

2013 2019

Legacy Plan Defined 3 year Interval

Due Date

2016

Due Date

2022

204


Last Tested 100%

2013 2021

PRC-005-2 TBM Maximum 6 year Interval

2019 2016

30% 60%

2017

Thank you

206

• PRC-005-2 Standard http://www.nerc.com/pa/Stand/Reliability%20Standards/PRC-005-2.pdf

• PRC-005 Implementation Plan http://www.nerc.com/pa/Stand/PRC0052RD/Project_2007-17_Implementation_Plan_Clean_errata.pdf

• Supplementary Reference and FAC http://www.nerc.com/pa/Stand/PRC0052RD/Project_200717_Protection_System_Maintenance_and%20T_Supplementary_Reference_clean_10-2012_2.pdf

• PRC-005-X Project Page http://www.nerc.com/pa/Stand/Pages/Project-2007-17_3-Protection-System-Maintenance-and-Testing-Phase-3.aspx

• BES Definition, Notification and Exception Process http://www.nerc.com/pa/RAPA/Pages/BES.aspx

Workshop References Links to NERC’s website as of August 2014

http://www.nerc.com/pa/Stand/Reliability Standards/PRC-005-2.pdf

http://www.nerc.com/pa/Stand/PRC0052RD/Project_2007-17_Implementation_Plan_Clean_errata.pdf

http://www.nerc.com/pa/Stand/PRC0052RD/Project_200717_Protection_System_Maintenance_and T_Supplementary_Reference_clean_10-2012_2.pdf

http://www.nerc.com/pa/Stand/PRC0052RD/Project_200717_Protection_System_Maintenance_and T_Supplementary_Reference_clean_10-2012_2.pdf



http://www.nerc.com/pa/RAPA/Pages/BES.aspx

207

• Phil O’Donnell, WECC Manager Operations & Planning Audits [email protected]

• Roger Cummins, WECC Senior Compliance Auditor [email protected]

• Joe Veltri, WECC Compliance Auditor [email protected]

For questions on Project 2007-17.3 • Jordan Mallory, NERC Standards Developer Specialist

[email protected]

For questions on Project 2014-01 • Sean Cavote, NERC Standards Developer

[email protected]

Workshop Contact Information






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PRC-005-2 Workshop July 29-30 2014 Salt Lake City Utah · 7/29/2014 · PRC-005-2 Workshop July...

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