grouper.ieee.orggrouper.ieee.org/groups/scc21/2030/email/docLXDv5k52sd.doc · Web view3.29 CCVT (Coupling Capacitor Voltage Transformer) 6 3.30 Reactor 6 3.31 Disconnect 6 3.32 Surge

IEEE GUIDE FOR Transmission Substation Smart Grid InteroperabilityIEEE Preliminary Draft 0.21

Revision 0.15

IEEE Std P2030 Draft Guide for Smart Grid Interoperability of the Electric

Power System (EPS) for Application in Transmission Substations

Prepared by the Transmission Substation Subcommittee Work Group of

Taskforce 1, Power Engineering Technology of IEEE SCC21 P2030

Copyright © 2009 by the Institute of Electrical and Electronics Engineers, Inc.Three Park AvenueNew York, New York 10016-5997, USAAll rights reserved.

This document is an unapproved draft of a proposed IEEE guide to the XXXX series of XXX guides on Smart Grid Interoperability of the EPS for application in transmission substations. As such, this document is subject to change. USE AT YOUR OWN RISK! Because this is an unapproved draft, this document must not be utilized for any conformance/compliance purposes. Permission is hereby granted for IEEE Standards Committee participants to reproduce this document for purposes of IEEE standardization activities only. Prior to submitting this document to another standards development organization for standardization activities, permission must first be obtained from the Manager, Standards Licensing and Contracts, IEEE Standards Activities Department. Other entities seeking permission to reproduce this document, in whole or in part, must obtain permission from the Manager, Standards Licensing and Contracts, IEEE Standards Activities Department.

IEEE Standards Activities DepartmentStandards Licensing and Contracts445 Hoes Lane, P.O. Box 1331Piscataway, NJ 08855-1331, USA

Copyright © 2009 IEEE. All rights reserved 1

IEEE GUIDE FOR Transmission Substation Smart Grid Interoperability IEEEStd XXX

Contents

1 Overview ......................................................................................................................11.1 Scope ....................................................................................................................11.2 Purpose ................................................................................................................1

2 References ....................................................................................................................13 Definitions ...................................................................................................................2

3.1 HMI (Human Machine Interface) ........................................................................23.2 PMU (Phasor Measurement Units) ......................................................................23.3 Transformer .........................................................................................................23.4 Circuit Breaker .....................................................................................................23.5 Circuit Interrupter/ (Interrupter Switch) ..............................................................33.6 Digital Fault Recorder .........................................................................................33.7 Relay ....................................................................................................................33.8 Arc Flash ..............................................................................................................33.9 Dead Station Tripping ..........................................................................................33.10 Frequency Deviation ............................................................................................33.11 Communication system reliability .......................................................................43.12 Frequency estimation ...........................................................................................43.13 Sequence of Event Recorder ................................................................................43.14 RTU (Remote Terminal Unit) .............................................................................43.15 Meter ....................................................................................................................43.16 PLC (Programmable Logic Controller) ...............................................................43.17 Static VAR Compensator ....................................................................................43.18 Series Capacitors .................................................................................................53.19 Weather Station/ (Weather Monitoring) ..............................................................53.20 Security Camera and Devices ..............................................................................53.21 Battery Charger ....................................................................................................53.22 Generator backup/ (Diesel-generator backup) .....................................................53.23 Mobile Substation ................................................................................................53.24 AC-DC Systems/ (Converter) ..............................................................................53.25 Communication gear/ (Communication-Electronic (C-E) equipment) ...............53.26 Protective Equipment/ (relay system) ..................................................................63.27 Lighting/ (Lighting Branch Circuit) ....................................................................63.28 Ground Grid .........................................................................................................63.29 CCVT (Coupling Capacitor Voltage Transformer) .............................................63.30 Reactor .................................................................................................................63.31 Disconnect ...........................................................................................................63.32 Surge Arrestor ......................................................................................................73.33 Grounding Switch ................................................................................................73.34 Motor operated device/ (Mechanical operation of a switch) ...............................73.35 Shunt Capacitor ...................................................................................................73.36 LTC (Load Tap Changer) ....................................................................................73.37 Regulator/ (Device number 90—regulating device) ............................................73.38 Battery/ (Standby Power System) ........................................................................73.39 Mechanical structures/ (Support components) ....................................................8

Copyright © 2009 IEEE. All rights reserved


3.40 Wave Trap/ (Line trap) ........................................................................................83.41 GIS substation devices/ (Gas-Insulated Substation (GIS)) ..................................83.42 Firewalls/ (Fire-Resistive Barrier) .......................................................................83.43 Lock Out Switches (Lockout Relay) ...................................................................83.44 Intelligent Electronic Devices (IED) ...................................................................8

4 Substation Automation Overview ................................................................................85 Smart Grid Monitoring Devices ..................................................................................9

5.1 Circuit breakers ....................................................................................................95.2 Transformers ......................................................................................................115.3 Relays ................................................................................................................135.4 Phasor Measurement Units ................................................................................135.5 Control - SCADA ..............................................................................................155.6 Digital Fault Recorders ......................................................................................165.7 HMI ....................................................................................................................165.8 Remedial Action Schemes (RAS) and (C-RAS) ...............................................17

5.8.1 REMEDIAL ACTION SCHEMES ...........................................................175.8.2 CENTRALIZED REMEDIAL ACTIONS SCHEMES ............................18

5.9 Regulators (Tier 2 and 3) ...................................................................................195.10 Capacitor Banks (Tier 1 and 3) ..........................................................................20

6 Smart Grid Methodology ...........................................................................................206.1 Decision-making sequence ................................................................................206.2 Failure modes and effects analysis ....................................................................206.3 Circuit breaker failure modes, failure characteristics/patterns, and monitoring parameters ......................................................................................................................206.4 Risk assessment .................................................................................................20

7 Cost-benefit (economic) analysis ..............................................................................218 Annex A (informative) Examples of circuit breaker monitoring analysis ................219 Annex B (informative) Examples of maintenance programs with and without monitoring ..........................................................................................................................2110 Annex C (informative) Bibliography .....................................................................211 Overview ......................................................................................................................1

1.1 Scope ....................................................................................................................11.2 Purpose ................................................................................................................1

2 References ....................................................................................................................13 Definitions ...................................................................................................................2

3.1 HMI (Human Machine Interface) ........................................................................23.2 PMU (Phasor Measurement Units) ......................................................................23.3 Transformer .........................................................................................................23.4 Circuit Breaker .....................................................................................................23.5 Circuit Interrupter/ (Interrupter Switch) ..............................................................33.6 Digital Fault Recorder .........................................................................................33.7 Relay ....................................................................................................................33.8 Sequence of Event Recorder ................................................................................33.9 RTU (Remote Terminal Unit) .............................................................................33.10 Meter ....................................................................................................................33.11 PLC (Programmable Logic Controller) ...............................................................3



3.12 Static VAR Compensator ....................................................................................43.13 Series Capacitors .................................................................................................43.14 Weather Station/ (Weather Monitoring) ..............................................................43.15 Security Camera and Devices ..............................................................................43.16 Battery Charger ....................................................................................................43.17 Generator backup/ (Diesel-generator backup) .....................................................43.18 Mobile Substation ................................................................................................43.19 AC-DC Systems/ (Converter) ..............................................................................43.20 Communication gear/ (Communication-Electronic (C-E) equipment) ...............53.21 Protective Equipment/ (relay system) ..................................................................53.22 Lighting/ (Lighting Branch Circuit) ....................................................................53.23 Ground Grid .........................................................................................................53.24 CCVT (Coupling Capacitor Voltage Transformer) .............................................53.25 Reactor .................................................................................................................63.26 Disconnect ...........................................................................................................63.27 Surge Arrestor ......................................................................................................63.28 Grounding Switch ................................................................................................63.29 Motor operated device/ (Mechanical operation of a switch) ...............................63.30 Shunt Capacitor ...................................................................................................63.31 LTC (Load Tap Changer) ....................................................................................63.32 Regulator/ (Device number 90—regulating device) ............................................73.33 Battery/ (Standby Power System) ........................................................................73.34 Mechanical structures/ (Support components) ....................................................73.35 Wave Trap/ (Line trap) ........................................................................................73.36 GIS substation devices/ (Gas-Insulated Substation (GIS)) ..................................73.37 Firewalls/ (Fire-Resistive Barrier) .......................................................................73.38 Lock Out Switches (Lockout Relay) ...................................................................73.39 Intelligent Electronic Devices (IED) .......................................................................8

4 Substation Automation Overview ................................................................................85 Smart Grid Monitoring Devices ..................................................................................9

5.1 Circuit breakers ....................................................................................................95.2 Transformers ......................................................................................................105.3 Relays ................................................................................................................125.4 Phasor Measurement Units ................................................................................125.5 Control - SCADA ..............................................................................................145.6 Digital Fault Recorders ......................................................................................155.7 HMI ....................................................................................................................155.8 Remedial Action Schemes (RAS) and (C-RAS) ...............................................165.8.1 REMEDIAL ACTION SCHEMES ...................................................................165.8.2 CENTRALIZED REMEDIAL ACTIONS SCHEMES ....................................176 Smart Grid Methodology ...................................................................................186.1 Decision-making sequence ................................................................................186.2 Failure modes and effects analysis ....................................................................186.3 Circuit breaker failure modes, failure characteristics/patterns, and monitoring parameters ......................................................................................................................186.4 Risk assessment .................................................................................................18



7 Cost-benefit (economic) analysis ......................................................................198 Annex A (informative) Examples of circuit breaker monitoring analysis ........199 Annex B (informative) Examples of maintenance programs with and without monitoring ......................................................................................................................1910 Annex C (informative) Bibliography .................................................................19



IEEE Guide for Smart Grid Interoperability

1 Overview

1.1 ScopeThis document provides guidelines for smart grid interoperability. This guide provides a knowledge base addressing terminology, characteristics, functional performance and evaluation criteria, and the application of engineering principles for smart grid interoperability of the electric power system with end-use applications and loads. The guide discusses alternate approaches to good practices for the smart grid.

1.2 PurposeThis standard provides guidelines in understanding and defining smart grid interoperability of the electric power system with end-use applications and loads. Integration of energy technology and information and communications technology is necessary to achieve seamless operation for electric generation, delivery, and end-use benefits to permit two way power flow with communication and control. Interconnection and intra-facing frameworks and strategies with design definitions are addressed in this standard, providing guidance in expanding the current knowledge base. This expanded knowledge base is needed as a key element in grid architectural designs and operation to promote a more reliable and flexible electric power system.

2 ReferencesThis guide shall be used in conjunction with the following publications. When the following publications are superseded by an approved revision, the revision shall apply.

CAN/CSA-Q634-91, Risk analysis requirements and guidelines.2

CEA Project No. 485T1049 (1997), On-line condition monitoring of substation power equipment–Utility needs.3

IEC 60812:1985-07, Analysis techniques for system reliability–Procedure for failure mode and effects analysis (FMEA).4

IEEE Std C37.10-1995, IEEE Guide for Diagnostics and Failure Investigation of Power Circuit Breakers.5

IEEE Std 493-1997, IEEE Recommended Practice for the Design of Reliable Industrial and Commercial Power Systems (IEEE Gold Book™).

NOTES



1– Appendix J and Appendix N of IEEE Std 493-1997 contain summaries of the more comprehensive documents in Annex C–Beierer et al. [B6]6, CIGRE [B5]7, CIGRE [B8], and Diagnostic techniques [B9].

2–IEEE Std 493-1997, Appendix J, "Summary of CIGRE 13.06 Working Group World Wide Reliability Data and Maintenance Cost Data on High Voltage Circuit Breakers Above 63 kV” by C. R. Heising, A. L. J. Janssen, W. Lenz, E. Columbo, and E. N. Dialynaas (IEEE-IAS Industrial Application Conference, October 2–5, 1994, Denver, Colorado, 94CH34520, pp. 2226–2234).

3–EEE Std 493-1997, Appendix N, Transmission Line and Equipment Outage Data, Part 3, “Transmission Equipment Reliability Data from Canadian Electricity Association” by D. O. Koval (IEEE Transactions on Industry Applications, vol. 32, no. 6, Nov./Dec. 1996, pp. 1–9).

3 DefinitionsFor the purposes of this guide, the following terms and definitions apply. The Authoritative Dictionary of IEEE Standards Terms [B12] should be referenced for terms not defined in this clause.

3.1 HMI (Human Machine Interface)Includes keyboards, displays, keypads, touch screens, and similar devices to allow human interaction with a system (See IEEE Std. 610.12-1990 [B14]).

3.2 PMU (Phasor Measurement Units)Device that extracts power system frequency, phase angle, and magnitude data from sensor signals (See IEEE Std. 1646-2004 [B24]). (suggestion that this might be a military definition – need to check)

3.3 Transformer(1) (National Electrical Code). A device, which when used, will raise or lower the voltage of alternating current of the original source.(2) (Power and Distribution Transformer). A static electric device consisting of a winding, or two or more coupled windings, with or without a magnetic core, for introducing mutual coupling between electric circuits. Transformers are extensively used in electric power systems to transfer power to electromagnetic induction between circuits at the same frequency, usually with changed values of voltage and current (See IEEE Std. Dictionary 1984 [B1]).

3.4 Circuit Breaker(Transmission and Distribution). A switching device capable of making, carrying, and breaking currents under normal circuit conditions and also making, carrying for a specified time, and breaking currents under specified abnormal conditions such as those of short circuit (See IEEE Std. Dictionary 1984 [B1]).



3.5 Circuit Interrupter/ (Interrupter Switch)A switching device, designed for making specified currents and breaking specified steady state currents (See IEEE Std. 1247-2005 [B20]).

3.6 Digital Fault RecorderDevice that samples and stores analog and related binary data during power system transients (See IEEE Std. C37.115-2003 [B7]).

3.7 Relay(Power Switchgear). An electrical device designed to respond to input conditions in a prescribed manner and after specified conditions are met to cause contact operation or similar abrupt change in associated electric control circuits (See IEEE Std. Dictionary 1984 [B1]).

3.8 Arc FlashArc Flash Heat Energy is produced during faults in substations and feeders. Once the line breaker opens in the presence of faults the produced arc during opening status generates high energy which is dangerous for the people who are working close to the breakers. The Arc Flash Energy limit is 8 Cal/cm^2 for OH lines. This varies based on the clothing of the people who are working close to the breakers. 751 Arc Flash relays need to be installed in the substations that violate the limit. 751 relays are instantaneous relays that operate based on the high fault current and the light generated form the arc. Another option will be installing the temporary instantaneous relays on the feeders or the whole substations while the crew is working close to the breakers. For the coordination purposes, the protection scheme needs to be switched to the previous time over current status after the work is done.

3.9 Dead Station TrippingDST is the method to reconnect the dead stations after the fault is clear. The communication system has to send a reset signal to the DST scheme in every substation to deactivate the tripping process.

3.10 Frequency DeviationOnce the system is islanded to clear the fault from up/down stream devices, the frequency will change based on the amount of the load that is disconnected from the grid. The smart grid needs to have a proper communication method to be capable of talking to the existing governor and field controller on the synchronous generators to recover the frequency to its nominal value.



3.11 Communication system reliabilityIn order to have a reliable communication system, a back up system needs to be installed to ensure that the power flow is under control if the communication cables are out of order or broken due to physical faults.

3.12 Frequency estimationThe phase locked loops (PLLs) that are being used in the power systems are not capable of estimating the frequency and phase of the voltage fast enough for unbalanced systems. This delay might cause some communication issues with the load part of the smart grid which can be highly unbalanced.

3.13Sequence of Event RecorderDevice that samples and stores events like contact status changes, trips, limit violations, etc., for later play and analysis. The events are time tagged (See IEEE Std. 1646-2004 [B24]).

3.14RTU (Remote Terminal Unit)A piece of equipment located at a distance from a master station to monitor and control the state of outlying power equipment and to communicate the information back to the master station or host (See IEEE Std. 1379-2000 [B22]).

3.15Meter(1) Demand Meter (Metering). A metering device that indicates or records the demand, maximum demand, or both.

(2) Electricity Meter. A device that measures and registers the integral of an electrical quantity with respect to time.

(3) Watt-hour meter. An electricity meter that measures and registers the integral, with respect to time, of the active power of the circuit in which it is connected. This power integral is the energy delivered to the circuit during the interval over which the integration extends, and the unit in which it is measured is usually the kilowatt-hour (See IEEE Std. Dictionary 1984 [B1]).

3.16PLC (Programmable Logic Controller)Digital control system with programming capability that performs functions similar to a relay logic system (See IEEE Std. 1010-2006 [B18]).

3.17Static VAR CompensatorA shunt-connected static var generator or absorber whose output is adjusted to exchange capacitive or inductive current to maintain or control specific parameters of the electrical power system (typically bus voltage) (See IEEE Std. 1031-2000 [B19]).



3.18Series CapacitorsA three-phase assembly of capacitor units with the associated protective devices, discharge current limiting reactors, protection and control system, bypass switch, and insulated support structure that has the primary purpose of introducing capacitive reactance in series with an electric circuit (See IEEE Std. 824-2004 [B17]).

3.19Weather Station/ (Weather Monitoring)Procedures to monitor and report weather conditions that may affect the operation of the power network (See IEEE Std. 1646-2004 [B24]).

3.20Security Camera and DevicesThe protection of hardware and software from accidental or malicious access, use, modification, destruction, or disclosure. Security also pertains to personnel, data, communications, and the physical protection of computer installations (See IEEE Std. 1547.3-2007 [B23]).

3.21Battery ChargerEquipment that converts ac power to dc power and is used to recharge and maintain a station battery in a fully charged condition and to supply power to dc loads during normal operation (See IEEE Std. 650-2006 [B16]).

3.22Generator backup/ (Diesel-generator backup)An independent source of standby electrical power that consists of a diesel-fueled internal combustion engine (or engines) coupled directly to an electrical generator (or generators); the associated mechanical and electrical auxiliary systems; and the control, protection, and surveillance systems (See IEEE Std. 387-1995 [B11]).

3.23Mobile SubstationSubstation equipment mounted and readily movable as a system of transportable devices (See IEEE Std. 1268-2005 [B21]).

3.24AC-DC Systems/ (Converter)A machine or device for changing dc power to ac power, for changing ac power to dc power, or for changing from one frequency to another. This definition covers several different power conversion functions, each of which is known by a separate term, see dc-dc converter, frequency converter, inverter, and rectifier (See IEEE Std. 388-1992 [B12]).

3.25Communication gear/ (Communication-Electronic (C-E) equipment)

Any item intentionally generating, transmitting, conveying, acquiring, storing, processing, or utilizing electronic and electromagnetic information in the broadest sense. Such devices are used to meet a variety of operational requirements such as communications, surveillance, identification, navigation, guided missile control, SONAR, countermeasures, and space operations (See ANSI Std. C63.14-1998 [B2]).



3.26 Protective Equipment/ (relay system)An assembly usually consisting of current and voltage circuits, measuring units, logic, and power supplies to provide a specific relay scheme, such as line, transformer, bus, or generator protection. A relay system may include connections to other systems, such as data logging, alarm, communications, or other relay systems (See IEEE Std. C37.90.1-2002 [B5]).

3.27 Lighting/ (Lighting Branch Circuit)A circuit that supplies energy to lighting outlets. A lighting branch circuit may also supply portable desk or bracket fans, small heating appliances, motors of 190 W and less, and other portable apparatus of not over 600 W each (See IEEE Std. 45-2002 [B10]).

3.28Ground Grid(Conductor stringing equipment). A system of interconnected bare conductors arranged in a pattern over a specified area and on or buried below the surface of the earth. Normally, it is bonded to ground rods driven around and within its perimeter to increase its grounding capabilities and provide convenient connection points for grounding devices. The primary purpose of the grid is to provide safety for workmen by limiting potential differences within its perimeter to safe levels in case of high currents which could flow if the circuit being worked became energized for any reason or if an adjacent energized circuit faulted. Metallic surface mats and gratings are sometimes utilized for this same purpose. When used, these grids are employed at pull, tension and midspan splice sites (See IEEE Std. Dictionary 1984 [B1]).

3.29CCVT (Coupling Capacitor Voltage Transformer)(Metering). A voltage transformer comprised of a capacitor divider and an electromagnetic unit so designated and interconnected that the secondary voltage of the electromagnetic unit is substantially proportional to, and in phase with, the primary voltage applied to the capacitor divider for all values of secondary burdens within the rating of the coupling-capacitor voltage transformer (See IEEE Std. Dictionary 1984 [B1]).

3.30Reactor(Power and distribution transformer). An electromagnetic device, the primary purpose of which is to introduce inductive reactance into a circuit (See IEEE Std. Dictionary 1984 [B1]).

3.31Disconnect(Watt-hour meter). A conductor, bar, or nut used to open an electrical circuit for isolation purposes (See IEEE Std. Dictionary 1984 [B1]).



3.32Surge Arrestor(AC power circuits). A protective device for limiting surge voltages on equipment by discharging or bypassing surge current: it prevents continued flow of follow current to ground, and is capable of repeating these functions as specified (See IEEE Std. Dictionary 1984 [B1]).

3.33Grounding SwitchA mechanical switching device by means of which a circuit or piece of apparatus may be electrically connected to ground (See IEEE Std. C37.100-1992 [B6]).

3.34Motor operated device/ (Mechanical operation of a switch)Operation by means of an operating mechanism connected to the switch by mechanical linkage.Note: Mechanically operated switches may be actuated either by manual, electrical, or other suitable means (See IEEE Std. C37.100-1992 [B6]).

3.35Shunt CapacitorAn assembly of dielectric and electrodes in a container (case), with terminals brought out, that is intended to introduce capacitance into an electric power circuit (See IEEE Std. 18-2002 [B9]).

3.36LTC (Load Tap Changer)(Power and Distribution transformer). A selector switch device used to change transformer taps with the transformer de-energized (See IEEE Std. Dictionary 1984 [B1]).

3.37Regulator/ (Device number 90—regulating device)A device that functions to regulate a quantity or quantities, such as voltage, current, power, speed, frequency, temperature, and load, at a certain value or between certain (generally close) limits for machines, tie lines, or other apparatus (See IEEE Std. C37.2-1996 [B4]).

3.38Battery/ (Standby Power System)An independent reserve source of electric energy that, upon failure or outage of the normal source, provides electrical power of acceptable quality so that the user's facilities may continue in satisfactory operation (See IEEE Std. 446-1995 [B13]).



3.39Mechanical structures/ (Support components)The components that give additional strength and rigidity or both to the bus enclosure and are basic subassemblies of the enclosure (See IEEE Std. C37.100-1992 [B6]).

3.40Wave Trap/ (Line trap)A main coil with a protective device, with or without tuning device(s), series connected in a power circuit to provide a high impedance at carrier frequencies, and negligible impedance at the power frequency (See ANSI Std. C93.3-1995 [B3]).

3.41GIS substation devices/ (Gas-Insulated Substation (GIS))A compact, multicomponent assembly, enclosed in a grounded metallic housing in which the primary insulating medium is a compressed gas, and which normally consists of buses, switchgear, and associated equipment (See IEEE Std. C37.122-1993 [B8]).

3.42Firewalls/ (Fire-Resistive Barrier)A wall, floor, or floor-ceiling assembly that is erected to prevent the spread of fire. To be effective, fire-resistive barriers must have sufficient fire resistance to withstand the effects of the most severe fire that may be expected to occur in the adjacent area and must provide a complete barrier to resist the spread of fire (See IEEE Std. 634-2004 [B15]).

3.43 Lock Out Switches (Lockout Relay)(Power switchgear). An electronically reset or hand-reset auxiliary relay whose function is to hold associated devices inoperative until it is reset (See IEEE Std. Dictionary 1984 [B1]).

3.44 Intelligent Electronic Devices (IED) IEDs receive data from sensors and power equipment, and can issue control commands, such as tripping circuit breakers if they sense voltage, current, or frequency anomalies, or raise/lower voltage levels in order to maintain the desired level. Common types of IEDs include protective relaying devices, load tap changer controllers, circuit breaker controllers, capacitor bank switches, recloser controllers, voltage regulators, etc. (From Wikipedia)

4 Substation Automation Overview Trends in the electric utility automation, specifically substation automation, have evolved over the years from data collected into Remote Terminal Units (RTU) then to the utilization of Programmable Logic Controllers (PLC) to now in many instances a LAN based network with a reliance on Intelligent Electronic Devices (IEDs). With this change



has come a migration from hardware based systems, such as the electro-mechanical relays to a more software orientation, utilizing microprocessor based devices and systems. Along with this comes the communication network, to the current day Ethernet based networks utilizing IEC61850 protocol, as well as those legacy systems using DNP3 protocol, which is the most prevalent in the electric industry today. These communication networks are broken into two, with one comprising a secure local area network (LAN) and the other a wide area network (WAN).

The following is a typical substation, where in lies many devices being monitored and controlled, besides the typical relays, PLCs, and digital fault recorders (DFR).

5 Smart Grid Monitoring Devices

5.1 Circuit breakers

Circuit Breaker Monitoring Functions There are many candidate parameters for monitoring, as evidenced in the attached documents. But the most mentioned and most likely parameters are listed below. Three tiers of parameters are listed, with a short definition of each. Assumed is that a computer or IED is utilized to collect data for the monitored parameters.



Communications with the IED/PC is another variable, with anything from free-standing (alarm contacts or display only) to substation network or SCADA being possible. (Surprisingly, many breaker monitors installed today have no communications, using only alarm outputs). First Tier – relatively easy to carry out with few additional sensors, and addressing most probable failure modes, with easiest interpretation of measured parameters

1. Trip Coil Continuity 2. Aux Switch Timing 3. Mechanism Charge Time 4. Pump Starts (for Hydraulic and Pneumatic Mechanisms) 5. Quantitative Gas Density OK (for gas breakers) 6. Tank heater continuity and currents (for heated low-temperature gas breakers) 7. Number of breaker operations

Second Tier – moderately easy to carry out, but some additional sensors might be necessary, and measured parameters may be more difficult to evaluate. Benefit to preventing failures not as high.

1. Accumulated I^2 X T on Interrupters 2. Trip Coil Current 3. Quantitative Gas Density Trending 4. Contact Travel/Speed, which also allow reaction time measurement 5. Mechanism motor currents 6. Contact simultaneity

Third Tier – more difficult to measure and/or interpret. These elements have less benefits for preventing failures, partially because of difficulty in interpreting measured parameters, and partially because of relative probability of failure modes.

1. Trip Coil Current Wave Shape 2. Opening and Closing Acoustic Signatures (mechanical, not PD) 3. On-line partial discharge by either electrical or acoustical sensors 4. Main Contact Re-strike

The selected set of monitored parameters can depend ondepends at least the following: 1. Purpose of the monitoring 2. Budget allocated 3. Criticality of the breaker location 4. Experience with the specific breaker type to be monitored

Typical data and sample rate for circuit breaker monitor: (waiting info)



Substation Size

No. of CB Monitors

Sample rate in seconds

Elements monitored per

Monitor

Total Data Size (Bytes) per Monitor

Large x 8 to 15 5 to 20? 10 to 60???Medium & Small x 8 to 15 5 to 20? 10 to 60???

Substation Size

No. of CB Monitors

Sample rate in seconds


Monitor

Total Data Size (Bytes) per

Monitor

Large x 8 to 15 5 to 20 5 to 60 Medium & Small x 8 to 15 5 to 20 5 to 60

5.2 Transformers

The selected set of monitored parameters can depend ondepends at least the following: 1. Purpose of the monitoring 2. Budget allocated 3. Criticality of the transformer location 4. Experience with the specific transformer type and parameters to be monitored

First Tier - Relatively easy to carry out with few additional sensors, and addressing most probable failure modes, with easiest interpretation of the following measured parameters:

Statuso Gas Detectoro Loss of Cooling Powero Loss of Oil Flowo Loss of Aux / Emergency Powero Conservator Low Oilo Fault Pressure Reliefo Control Power o Main Tank Low Oil

Analog

o Megawattso Megavarso Low Side Voltageo High Side Voltage (Autotransformer and GSU)o Load Tap Changes LTC position indicationo Load Tap Changes LTC position control



o Load Tap Changes LTC loss of Vacuumo Load Tap Changes LTC pressure failure

Second Tier - Moderately easy to carry out, but some additional sensors might be necessary, and measured parameters may be more difficult to evaluate.

Analogo Temperature Top Oilo Temperature Ambiento Temperature Load Tap Changer Diffo Load Tap Changes LTC oil level

Third Tier - More difficult to measure and/or interpret.

Statuso Run Time on Banks / Banks Exercisingo Fan Current Monitor (Analog and Status)

Analog

o Temperature Windingo Temperature Ageing Rateo Moistureo Fan Current Monitor ( Analog and Indication)o Dissolved Gas Analysis Probe H2o Dissolved Gas Analysis Probe O2 and N2o Dissolved Gas Analysis Probe CO and CO2o Dissolved Gas Analysis Probe CH4o Dissolved Gas Analysis Probe C2H6o Dissolved Gas Analysis Probe C2H4o Dissolved Gas Analysis Probe C2H2o Temperature Load Tap Changer Diffo Power Factoro Partial Dischargeo Accumulated I2tt

Typical data and sample rate for transformer monitor:

Substation Size

No. of Trans.

MonitorsSample rate in seconds


Monitor


Large 10 - 30 8 to 15 10 to 40 10 to 60



Medium & Small 1 - 10 8 to 15 10 to 40 10 to 60

Typical data and sample rate for transformer Bushing monitor:

Substation Size

No. of Trans.

MonitorsSample rate in seconds


Monitor


Large 1 - 10 8 to 15 10 - 40 30 - 60Medium & Small 1 - 6 8 to 15 10 - 40 30 - 60

5.3 Relays

5.4 Phasor Measurement Units

Synchronized Phase Measurement Unit (PMU) is a monitoring device, which was first introduced in mid-1980s. Phasor measurement units (PMU) are devices, use synchronization signals from the global positioning system (GPS) satellites and provide the phasors of voltage and currents measured at a given substation.

The phasor measurement units (PMUs) that are installed at various locations in the system collect power system data such as voltages and currents phasors and send through dedicated communication channels to a central location called phasor data concentrator (PDC). This PDC collects continuous data along with the time stamp.

In a typical application if the PDC detects any disturbance (trigger flag) in the data collected it stores a 3-minute file with 1 minute pre-disturbance. The PDC continuously send out data via Ethernet as a UDP stream. This UDP stream is collected by the application running on the workstation and is stored on the server every 3-minutes as 3 minute archives of real time data called stream files. This continuous data is stored for 60 to 90 days and then discarded. Another application goes via network to fetch the stored disturbance/event files from the PDC and stores them as event files, which is kept for a longer period.

A typical PMU units input into the PDC might be: 16-bit long word 30 samples per second, continuous stream 30 elements per PMU



Data is read and stored continuously from each PMU. A typical PMU monitors 10 phasors with two components 16 bit words. The following summarizes the continuous baud rate needed to move the data from the substation to the head end storage.

Example: PMU with 10 phasors (or 20 elements) produces a 4.68Mb file every 3 minutes: 4.68Mb * 8 bits/byte / 180 sec. = 209 kb/sec baud rate /20 = 234kb/3 min. = 234 kb/180 second = ~1.3kb/sec baud rate

Typical data and sample rate for PMUs:

Substation Size

No. of PMUs

Event Data Size (Mbytes) per 3

min. scan

Baud Rate

kb/secNo. of Events/Year

from Substation

Large 2 4.7 418 Continuous streamMedium & Small 1 4.7 209 Continuous stream

The PMU data is stored in a historian as per each utilities specification. The data is stored as steam data (every point) continuously, and event data. The event data is defined by those events that have exceeded a preset trigger. This data is generally stored indefinitely. Examples of the requirements for storing PMU data is as follows:

Some typical through-put numbers for a 15 PMU system are stream files with real-time data irrespective of any disturbance or event in the system. They are stored in continuous 3-minute files each 4.7MB. There will be 20 files per hour, 480 files per day and 14,400 files per month. The 14,400 files of 4.7 MB occupy 67.7GB.

Stream Data

Substation Size

No. of PMUs

Sample per

second

Elements monitored per PMU

File Storage

size for 3 min of data

File Storage size per month

Large 2 30 20 4.7 Mbytes135.4 Gbytes

Medium & Small 1 30 20 4.7 Mbytes

67.7 Gbytes

Event data (assuming 20 events per day)



Event files are the files that are recorded only if there is an event or disturbance in the system. On an average there could be 20 event files per day and 600 per month. A 2.8GB of space is required for 600 4.7MB files per month.

Event Data

Substation Size

No. of PMUs

3 minute events per day

File Storage

size for 3 min of data

File Storage size per month

Large 2 204.7

Mbytes 2.8 GbytesMedium & Small 1 20

4.7 Mbytes 2.8 Gbytes

Note the data is stored in continuous 3 minute intervals for this system.

Another issue facing PMU data is the issue concerning the transport of large files. This is a continuous stream of 16 Bit integer format using IEEE PC37.118 data format. The data is transmitted to the local PDC using the connectionless UDP protocol to minimize overhead, at this time. Average latency (end to end) with Authentication is in the range of 60 to 75 ms depending on distance.

5.5 Control - SCADA

The following identifies the SCADA data, or the data used monitor and control the electric grid:

Substation TypeSubstation Size1

# Analog Points2

# Digital Points

Total Data Size

(Kbytes)Data Poll

Frequency

Advanced Automation (HMI)Large 400 1000 925

1 secondMedium 250 400 550Small 100 200 225

Legacy (RTU)Large 220 360 485

1 second3Medium 120 280 275Small 50 100 113

Notes:1HMI Stations: Large > 40 IEDs, Medium >20 IEDs, Small > 1 IED, RTU Stations:

Defined by # of analog and digital points.



2Analog points (16 or 32 bit)3Data from most RTU-based stations is polled every 1 second.

5.6 Digital Fault Recorders

Need words – rough shot at it

Digital Fault Recorder (DFR) are monitoring devices usually placed in substation or plant environments with the capability to capture and analyze short transient and longer term disturbances on the electrical transmission network. It is a device that can sample rates up to 0.10 milli seconds creating very high speed resolution, and typically record contact openings and closing of field devices such as electromechanical and microprocessor controlled relays. DFRs have flexible triggering modes that make them ideal for monitoring the protection operations, as well as power quality as well as phasor measurements. The events that are recorded, typically include date, time, event number, normal state, recorded state and some kind of descriptor.

DFRs come equipped with a sweet of software packages that assist with trending and other analysis applications. Typical features available on these units include:

Typical communication to the device is the choice of RS232, or Ethernet with 100BASE-FX available. The data is typically downloaded to a central location after an event has taken place, per preset trigger points. DFR’s can be poled for this information or set to automatically upload to their head end computer upon a certain level event. Interfaces to these devices come in many proprietary protocols or IEC 61000, IEC 60255 and COMTRADE IEEE Std C37.xx as example.

The following identifies DFR data characteristics for transmission substations (500kv to 66kv):

Substation Size

No. of Sensors1 (Avg)

Event Data Size (Mbytes)Min - Max

No. of Events/YearMin - Max

Large 300 0.1 - 30 163 - 4100Medium 180 0.1 - 15 30 - 5800Small 100 0.1 - 5 16 - 3700

1Refers to the number of DFR inputs, i.e. CTs and PTs.

5.7 HMI

(Human Machine Interface) The user interface, data aggregator, and control system in a electrical substation environment. It provides a graphics-based visualization of a Substation control and monitoring system. HMI’s are typically reside on a substation



harden Windows (some times strip down version) based computer that collects data from each of the IED (Intelligent Electrical Devices) in substation. This data is polled or delivered to the HMI by exception and stored in the HMI until it is uploaded to the SCADA or other head-end computer usually located in the grid operations center.

An optional, stand-alone substation graphical interface will display data and allow substation control via communication via this panel to the field devices.

Typical HMI related data:

Substation Size

No. of Devices (relays, meters,

etc)

Total number of points

monitored per Device (IED)

Sample rate in

seconds

Total File Storage size for all

Devices (Mbytes)Small 1 - 20 500 - 8,000* 8 - 15 5 - 15Medium 20 - 30 500 - 8,000 8 - 15 15 - 40Large 30 - 50 500 - 8,000 8 - 15 40 - 400

* Point count is dependent on age of IED (when it was built & how used) * Word size can vary from 8 bits to 64 bit words

5.8 Remedial Action Schemes (RAS) and (C-RAS)

5.8.1 REMEDIAL ACTION SCHEMES

Remedial Action Schemes (RAS) are designed to monitor and protect electrical systems by automatically performing switching operations in response to an event(s) or conditions on the grid that requires mitigation. Direct-tripping generation is a classic method to protect the remaining operating transmission lines from overloads that could result from the congestion.

RAS schemes are used in place of building new transmission lines when the cost and delay due to siteing have made it impractical to add new generation. RASs are comprised of three parts: monitoring, event detection and mitigation. The equipment used in a typical RAS scheme are digital protection devices such as relays, that will be deployed within one or two neighboring substations with a local controller that initiates any mitigation signal actions within the substation or neighboring substations.

Latency of the communication network becomes a critical factor in the design of the RAS schemes. The monitor to trip action must occur in 8 to 12 cycles. The digital data transmitted is very small, limited to line status, tip commands, with limited overhead. Each substation will have two redundant and diversely routed telecommunication circuits



with at least T-1 capability to each protection device and the Energy Management System.

The data protocol is vendor specific and usually proprietary. They send the data in MIRRORED BITS communications that provides high-speed, secure, point-to-point communication. MIRRORED BITS communications is a relay-to-relay communications technology that exchanges the status of internal logic points called MIRRORED BITS, encoded in a digital message, from one device to another.

Substation Size

Number of RAS schemes Data Size (bits)

Communication Latency requirements (mili seconds)

Frequency of events

Large 2 to 3 ~ 12 bits 133 ms - 200 ms multiple per dayMedium & Small 1 ~ 12 bits 133 ms - 200 ms multiple per day

5.8.2 CENTRALIZED REMEDIAL ACTIONS SCHEMES

The technology opportunities that exist today to improve RASs — and make them centralized — include combining the capabilities of new intelligent electronic devices (IEDs) with high-speed telecommunications assets.

In the proposed centralized RAS (C-RAS), IEDs will be used to monitor current grid conditions and detect events that potentially require mitigation. IEDs will “package” key data and, using IEC 61850 communication protocols, send the data to a central control processor that will decide what, if any, mitigation (generator dropping or load dropping) is needed or allowed under the specified criteria. The central controller will then package mitigation instructions for delivery to key locations. Breakers or other switching devices will be performed, accomplishing the needed mitigation action.

The speed requirement of the three cycles or 50 mili-sec, was established based on the existing RASs. The system performs event and fault detection, processing and mitigation, with a total elapsed time of approximately 16 cycles, or 267 mili-sec, including circuit-breaker operating delays. Existing schemes allow for approximately 2 cycles for processing, or 33.4 mili-sec. Adding a cycle to the processing time requirement for margin puts C-RAS on a 50-msec time-delay limitation. This becomes an issue for centralized solution, where distances of 700 miles could exist between field equipment and the head end equipment.

The C-RAS system would be designed with triple redundancy (at least T-1 capability) for high availability and dependability. The controller would be located in redundant facilities with the EMS (Energy management system). We expect that this network of RAS schemes would be deployed at approximately 100 substations for a large utility.



Substation Size

Number of RAS schemes

61850 Data Size (bits)

Communication Latency requirements (mili seconds)

Frequency of events (arming and control)

Large 100 128??? 50 ms multiple per dayMedium 25 128??? 50 ms multiple per daySmall 10 128??? 50 ms multiple per day

5.9 Regulators (Tier 2 and 3)

Tier 2STATUSPer Phase Communications StatusPer Phase Reduction Status and LevelPer Phase Automatic/Manual Status

CONTROLSPer Phase Voltage Reduction (multiple step availability)Per Phase Automatic/Manual Control

ANALOGPer Phase MWPer Phase MVARPer Phase Voltage THDPer Phase Current THDPer Phase VoltagePer Phase CurrentPer Phase PFPer Phase Tap PositionPer Phase Max Tap PositionPer Phase Min Tap Position

Tier 3STATUSPer Phase CBEMA Curve Selection (Multiple Curves)

CONTROLSPer Phase RaisePer Phase LowerPer Phase Drag Hand Reset

ANALOGPer Phase Number of Taps through NeutralPer Phase Number of Tap ChangesPer Phase CBEMA Start & Stop Times



Per Phase R & X Values

5.10 Capacitor Banks (Tier 1 and 3)

Tier 1Number of operationsNumber of lockoutsPercent Availability

Tier 3Neutral Current

6 Smart Grid Methodology

6.1 Decision-making sequence

6.2 Failure modes and effects analysis

6.3 Circuit breaker failure modes, failure characteristics/patterns, and monitoring parameters

6.4 Risk assessment

After the effect of a failure is determined, the criticality or risk associated with that effect should be assessed. The risk assessment quantifies the importance of each failure effect (CAN/CSA-Q634-91).

Risk is formed from two factors: the probability of any event occurring and its consequence. Risk is high when an event is likely to occur, and it has serious results. Risk can be moderate if the probability is low and the consequences are high, when both are medium, or when the probability is high and consequences are low. Risk is low if both probability and consequences are low.

By evaluating the probability of an event happening and developing an idea of how serious the situation might be if it occurs, risk can be evaluated. High-risk items generally require action be taken to reduce the risk, whereas low-risk items may not need to have any action taken. In this assessment, action to be taken is implementation of condition monitoring, whereas in the area of maintenance, selection of appropriate maintenance



tasks is undertaken. Obviously, manufacturers make these assessments based on the knowledge they have regarding the circuit breaker design and manufacture. The end user has application information not available to manufacturers and, therefore, is in a position to conduct an assessment appropriate to each situation.

Table 20 can be used to help quantify risk. Determine the level of probability that an event can occur and the consequences if that event does happen (regardless of how often it happens) to develop the level of risk that should be recognized. Consequences and probabilities can be quantified in the areas of financial impact as well as in the areas of safety, environmental, public, employee, or regulatory impact [CEA Project No. 485T1049 (1997) and CAN/CSA-Q634-91]. A complete analysis would consider the consequences and probabilities associated with risk in each of the areas of financial, safety, environmental, public, employee, or regulatory impact; and other areas of risk appropriate to the specific installation.

7 Cost-benefit (economic) analysis

The following section describes some of the elements that might be included when developing a business case tailored to a specific situation. It is important to recognize that the examples are for illustrative purposes only. Numeric financial values are strictly for the purpose of showing that values can be assigned, if so chosen. Actual circumstances can dictate values, costs, and expenses to be used in the quantifying of risk, economic evaluation and justification, and the ultimate selection of monitoring. The specific circuit breaker technology employed can also either restrict or broaden opportunities for monitoring.

8 Annex A (informative) Examples of circuit breaker monitoring analysis

9 Annex B (informative) Examples of maintenance programs with and without monitoring

10 Annex C (informative) Bibliography[B1] IEEE Standard Dictionary of Electrical and Electronics Terms 1984.

[B2] ANSI C63.14-1998 American National Standard Dictionary for Technologies of Electromagnetic Compatibility (EMC), Electromagnetic Pulse (EMP), and Electrostatic Discharge (ESD). IEEE Standards Dictionary CD-ROM 2008.

[B3] ANSI C93.3-1995 Requirements for Power-Line Carrier Carrier Traps. IEEE Standards Dictionary CD-ROM 2008.

[B4] IEEE Std C37.2-1996 (R2001) IEEE Standard Electrical Power System Device Function Numbers and Contact Designations. IEEE Standards Dictionary CD-ROM 2008.



[B5] IEEE Std C37.90.1-2002™ IEEE Standard for Surge Withstand Capability (SWC) Tests for Relays and Relay Systems Associated with Electric Power Apparatus. IEEE Standards Dictionary CD-ROM 2008.

[B6] IEEE Std C37.100-1992 IEEE Standard Definitions for Power Switchgear. IEEE Standards Dictionary CD-ROM 2008.

[B7] IEEE Std C37.115™-2003 IEEE Standard Test Method for Use in the Evaluation of Message Communications between Intelligent Electronic Devices in an Integrated Substation Protection, Control, and Data Acquisition System. IEEE Standards Dictionary CD-ROM 2008.

[B8] IEEE Std C37.122-1993 IEEE Standard for Gas-Insulated Substations. IEEE Standards Dictionary CD-ROM 2008.

[B9] IEEE Std. 18™-2002 IEEE Standard for Shunt Power Capacitors. IEEE Standards Dictionary CD-ROM 2008.


Documents

grouper.ieee.orggrouper.ieee.org/groups/scc21/2030/email/docLXDv5k52sd.doc · Web view3.29 CCVT (Coupling Capacitor Voltage Transformer) 6 3.30 Reactor 6 3.31 Disconnect 6 3.32 Surge