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IEEE GUIDE FOR Transmission Substation Smart Grid Interoperability
IEEE Preliminary Draft 0.1
Revision 0.5
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 Avenue
New York, New York 10016-5997, USA
All 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
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Contents
1
Overview ..................................................................................................................... 1
1.1
Scope ................................................................................................................... 1
1.2
Purpose................................................................................................................ 1
2 References ................................................................................................................... 1
3 Definitions................................................................................................................... 2
3.1
HMI (Human Machine Interface) ....................................................................... 2
3.2
PMU (Phasor Measurement Units) ..................................................................... 2
3.3
Transformer......................................................................................................... 2
3.4
Circuit Breaker .................................................................................................... 2
3.5
Circuit Interrupter/ (Interrupter Switch) ............................................................. 3
3.6
Digital Fault Recorder......................................................................................... 3
3.7
Relay ................................................................................................................... 3
3.8
Sequence of Event Recorder ............................................................................... 3
3.9
RTU (Remote Terminal Unit) ............................................................................. 3
3.10 Meter ................................................................................................................... 3
3.11 PLC (Programmable Logic Controller) .............................................................. 3
3.12 Static VAR Compensator .................................................................................... 4
3.13 Series Capacitors ................................................................................................. 4
3.14 Weather Station/ (Weather Monitoring) ............................................................. 4
3.15 Security Camera and Devices ............................................................................. 4
3.16 Battery Charger ................................................................................................... 4
3.17 Generator backup/ (Diesel-generator backup) .................................................... 4
3.18 Mobile Substation ............................................................................................... 4
3.19 AC-DC Systems/ (Converter) ............................................................................. 4
3.20 Communication gear/ (Communication-Electronic (C-E) equipment)............... 5
3.21 Protective Equipment/ (relay system) ................................................................. 5
3.22 Lighting/ (Lighting Branch Circuit).................................................................... 5
3.23 Ground Grid ........................................................................................................ 5
3.24 CCVT (Coupling Capacitor Voltage Transformer) ............................................ 5
3.25 Reactor ................................................................................................................ 6
3.26 Disconnect........................................................................................................... 6
3.27 Surge Arrestor ..................................................................................................... 6
3.28 Grounding Switch ............................................................................................... 6
3.29 Motor operated device/ (Mechanical operation of a switch) .............................. 6
3.30 Shunt Capacitor ................................................................................................... 6
3.31 LTC (Load Tap Changer) ................................................................................... 6
3.32 Regulator/ (Device number 90—regulating device) ........................................... 7
3.33 Battery/ (Standby Power System) ....................................................................... 7
3.34 Mechanical structures/ (Support components).................................................... 7
3.35 Wave Trap/ (Line trap) ....................................................................................... 7
3.36 GIS substation devices/ (Gas-Insulated Substation (GIS)) ................................. 7
3.37 Firewalls/ (Fire-Resistive Barrier) ...................................................................... 7
3.38 Lock Out Switches (Lockout Relay)................................................................... 7
3.39 Intelligent Electronic Devices (IED) ...................................................................... 8
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IEEE GUIDE FOR Transmission Substation Smart Grid Interoperability
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5
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Substation Automation Overview ............................................................................... 8
Smart Grid Monitoring Devices.................................................................................. 9
5.1
Circuit breakers ................................................................................................... 9
5.2
Transformers ..................................................................................................... 10
5.3
Relays ................................................................................................................ 12
5.4
Phasor Measurement Units ............................................................................... 12
5.5
Control - SCADA ............................................................................................. 14
5.6
Digital Fault Recorders ..................................................................................... 15
5.7
HMI ................................................................................................................... 15
5.8
Remedial Action Schemes (RAS) and (C-RAS) .............................................. 16
5.8.1
REMEDIAL ACTION SCHEMES .......................................................... 16
5.8.2
CENTRALIZED REMEDIAL ACTIONS SCHEMES ........................... 17
6 Smart Grid Methodology .......................................................................................... 18
6.1
Decision-making sequence ............................................................................... 18
6.2
Failure modes and effects analysis ................................................................... 18
6.3
Circuit breaker failure modes, failure characteristics/patterns, and monitoring
parameters ..................................................................................................................... 18
6.4
Risk assessment ................................................................................................ 18
7 Cost-benefit (economic) analysis .............................................................................. 19
8 Annex A (informative) Examples of circuit breaker monitoring analysis ................ 19
9 Annex B (informative) Examples of maintenance programs with and without
monitoring ......................................................................................................................... 19
10
Annex C (informative) Bibliography .................................................................... 19
Copyright © 2009 IEEE. All rights reserved
IEEE GUIDE FOR Transmission Substation Smart Grid Interoperability
IEEE
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IEEE Guide for Smart Grid
Interoperability
1 Overview
1.1 Scope
This 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 Purpose
This 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 References
This 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
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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 Definitions
For 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]).
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]).
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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 Recorder
Device 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 Sequence of Event Recorder
Device 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]).
3.9 RTU (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]).
3.10 Meter
(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]).
3.11 PLC (Programmable Logic Controller)
Digital control system with programming capability that performs functions similar to a
relay logic system (See IEEE Std. 1010-2006 [B18]).
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3.12 Static VAR Compensator
A 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]).
3.13 Series Capacitors
A 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]).
3.14 Weather 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]).
3.15 Security Camera and Devices
The 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]).
3.16 Battery Charger
Equipment 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]).
3.17 Generator 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]).
3.18 Mobile Substation
Substation equipment mounted and readily movable as a system of transportable devices
(See IEEE Std. 1268-2005 [B21]).
3.19 AC-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 dcdc converter, frequency converter, inverter, and rectifier (See IEEE Std. 388-1992 [B12]).
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3.20 Communication 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]).
3.21 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. C37.90.12002 [B5]).
3.22 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]).
3.23 Ground 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]).
3.24 CCVT (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]).
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3.25 Reactor
(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]).
3.26 Disconnect
(Watt-hour meter). A conductor, bar, or nut used to open an electrical circuit for
isolation purposes (See IEEE Std. Dictionary 1984 [B1]).
3.27 Surge 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]).
3.28 Grounding Switch
A 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]).
3.29 Motor 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]).
3.30 Shunt Capacitor
An 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. 182002 [B9]).
3.31 LTC (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]).
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3.32 Regulator/ (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. C37.21996 [B4]).
3.33 Battery/ (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]).
3.34 Mechanical 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]).
3.35 Wave 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]).
3.36 GIS 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]).
3.37 Firewalls/ (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]).
3.38 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]).
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3.39 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).
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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.
2.
3.
4.
5.
6.
Trip Coil Continuity
Aux Switch Timing
Mechanism Charge Time
Pump Starts (for Hydraulic and Pneumatic Mechanisms)
Quantitative Gas Density OK (for gas breakers)
Tank heater continuity and currents (for heated low-temperature gas breakers)
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.
2.
3.
4.
5.
Accumulated I^2 X T on Interrupters
Trip Coil Current
Quantitative Gas Density Trending
Contact Travel/Speed, which also allow reaction time measurement
Mechanism motor currents
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.
2.
3.
Trip Coil Current Wave Shape
Opening and Closing Acoustic Signatures (mechanical, not PD)
On-line partial discharge by either electrical or acoustical sensors
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The selected set of monitored parameters depends 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)
No. of CB
Monitors
Sample rate
in seconds
Elements
monitored 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
Total Data
Size (Bytes)
per Monitor
5.2 Transformers
The selected set of monitored parameters depends 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:


Status
o
o
o
o
o
o
o
o
Gas Detector
Loss of Cooling Power
Loss of Oil Flow
Loss of Aux / Emergency Power
Conservator Low Oil
Fault Pressure Relief
Control Power
Main Tank Low Oil
Analog
o Megawatts
o Megavars
o Low Side Voltage
o High Side Voltage (Autotransformer and GSU)
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o
o
o
o
Load Tap Changes
Load Tap Changes
Load Tap Changes
Load Tap Changes
IEEE
Std XXX
LTC position indication
LTC position control
LTC loss of Vacuum
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.

Analog
o Temperature Top Oil
o Temperature Ambient
o Temperature Load Tap Changer Diff
o Load Tap Changes LTC oil level
Third Tier - More difficult to measure and/or interpret.

Status
o Run Time on Banks / Banks Exercising
o Fan Current Monitor (Analog and Status)

Analog
o Temperature Winding
o Temperature Ageing Rate
o Moisture
o Fan Current Monitor ( Analog and Indication)
o Dissolved Gas Analysis Probe
H2
o Dissolved Gas Analysis Probe
O2 and N2
o Dissolved Gas Analysis Probe
CO and CO2
o Dissolved Gas Analysis Probe
CH4
o Dissolved Gas Analysis Probe
C2H6
o Dissolved Gas Analysis Probe
C2H4
o Dissolved Gas Analysis Probe
C2H2
o Temperature Load Tap Changer Diff
o Power Factor
o Partial Discharge
o Accumulated I2tt
Typical data and sample rate for transformer monitor:
Substation
Size
Large
No. of
Trans.
Monitors
Sample rate
in seconds
Elements
monitored per
Monitor
10 - 30
8 to 15
10 to 40
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Total Data
Size (Bytes)
per Monitor
10 to 60
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Medium &
Small
1 - 10
8 to 15
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Std XXX
10 to 40
10 to 60
Typical data and sample rate for transformer Bushing monitor:
No. of
Trans.
Monitors
Sample rate
in seconds
Elements
monitored per
Monitor
Large
1 - 10
8 to 15
10 - 40
30 - 60
Medium &
Small
1-6
8 to 15
10 - 40
30 - 60
Substation
Size
Total Data
Size (Bytes)
per Monitor
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
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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/20 = 234kb/3 min. = 234 kb/180 second = ~1.3kb/sec baud rate

Typical data and sample rate for PMUs:
No. of
PMUs
Individual
Event
Data Size
(Mbytes)
per 3
min. scan
Baud Rate
needed
Kbytes/sec
No. of
Events/Year
from
Substation
Large
2
4.7
2.6
Continuous
stream
Medium &
Small
1
4.7
1.3
Continuous
stream
Substation
Size
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
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 Mbytes
135.4
Gbytes
Medium &
Small
1
30
20
4.7 Mbytes
67.7
Gbytes
Substation
Size
Event data (assuming 20 events per day)
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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
Large
Medium &
Small
No. of
PMUs
3 minute
events
per day
2
20
1
20
File
Storage
size for 3
min of
data
4.7
Mbytes
4.7
Mbytes
File
Storage
size per
month
2.8 Gbytes
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 Type
Advanced Automation (HMI)
Legacy (RTU)
Substation
Size1
# Analog
Points2
# Digital
Points
Total
Data
Size
(Kbytes)
Large
400
1000
925
Medium
250
400
550
Small
100
200
225
Large
220
360
485
Medium
120
280
275
50
100
113
Small
Data Poll
Frequency
1 second
1 second3
Notes:
1HMI Stations: Large > 40 IEDs, Medium >20 IEDs, Small > 1 IED, RTU
Stations:
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Defined by # of analog and digital
points.
2Analog
3Data
points (16 or 32 bit)
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 100BASEFX 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):
No. of Sensors1
(Avg)
Event Data Size
(Mbytes)
Min - Max
Large
300
0.1 - 30
163 - 4100
Medium
180
0.1 - 15
30 - 5800
Small
100
0.1 - 5
16 - 3700
Substation
Size
1Refers
No. of Events/Year
Min - Max
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
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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
Small
Medium
Large
No. of Devices
(relays, meters,
etc)
1 - 20
20 - 30
30 - 50
Total number
of points
monitored per
Device (IED)
500 - 8,000*
500 - 8,000
500 - 8,000
Sample
rate in
seconds
8 - 15
8 - 15
8 - 15
Total File Storage
size for all
Devices (Mbytes)
5 - 15
15 - 40
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
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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
Large
Medium & Small
Number of
RAS schemes
2 to 3
1
Data Size (bits)
~ 12 bits
~ 12 bits
Communication
Latency
requirements
(mili seconds)
133 ms - 200 ms
133 ms - 200 ms
Frequency of
events
multiple per day
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.
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IEEE GUIDE FOR Transmission Substation Smart Grid Interoperability
Substation
Size
Large
Medium
Small
Number of
RAS schemes
100
25
10
61850 Data
Size (bits)
128???
128???
128???
Communication
Latency
requirements
(mili seconds)
50 ms
50 ms
50 ms
IEEE
Std XXX
Frequency of
events (arming
and control)
multiple per day
multiple per day
multiple per day
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
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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 CDROM 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.
Copyright © 2009 IEEE. All rights reserved
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Std XXX
[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.
Copyright © 2009 IEEE. All rights reserved
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