Optimum design of substation protection, control and monitoring systems

Material Information

Optimum design of substation protection, control and monitoring systems
Bader, Julie Lorraine
Publication Date:
Physical Description:
xiv, 212 leaves : illustrations ; 29 cm


Subjects / Keywords:
Electric power systems -- Protection ( lcsh )
Protective relays ( lcsh )
Electric power systems -- Protection ( fast )
Protective relays ( fast )
bibliography ( marcgt )
theses ( marcgt )
non-fiction ( marcgt )


Includes bibliographical references (leaves 172-174).
General Note:
Diagrams on 3 folded sheets in pocket.
General Note:
Submitted in partial fulfillment of the requirements for the degree, Master of Science, Electrical Engineering.
General Note:
Department of Electrical Engineering
Statement of Responsibility:
by Julie Lorraine Bader.

Record Information

Source Institution:
University of Colorado Denver
Holding Location:
Auraria Library
Rights Management:
All applicable rights reserved by the source institution and holding location.
Resource Identifier:
30839162 ( OCLC )
LD1190.E54 1993m .B33 ( lcc )

Full Text
Julie Lorraine Bader
B.S.E.E., Colorado School of Mines, 1987
B.S.GP.E., Colorado School of Mines, 1987
A thesis submitted to the
Faculty of the Graduate School of the
University of Colorado at Denver
in partial fulfillment
of the requirements for the degree of
Master of Science
Electrical Engineering

This thesis for the Master of Science
degree by
Julie Lorraine Bader
has been approved for the
Department of
Electrical Engineering
Dr. William R. Roemish
Dr. Robert Erickson


Bader, Julie Lorraine (M.S., Electrical Engineering)
Optimum Design of Substation Protection, Control and
Monitoring Systems
Thesis directed by Professor Pankaj K. Sen
Microprocessor-based systems used in substation
relaying, controls and monitoring design use a
station computer (SC), data highway, protection
clusters (PC), and data acquisition units (DAU).
The SC collects and stores information. The data
highway sends and receives information, control
messages and data. The PC executes relaying tasks
and is the center control point between the SC and
DAU. The DAU accepts voltages, currents and status
of contact inputs and digitizes (formats)
information before sending it to the PC.
Profit and economics focus on producing DAUs,
PCs, SCs, microprocessor-based systems, software and
hardware. But not enough attention has been focused
on the inputs to the DAU's and the overall
optimization of the design based on input data.
The main purpose of this thesis is to discuss,
in detail, the data input points required for the

design. The three substations (categorized as
small, medium and large) which will be discussed in
this thesis are: (i) Bridgeport Substation 115 kV
(small), (ii) Spence Substation 230 kV (medium)
and (iii) Bears Ears Substation 345 kV (large).
Three separate lists of equipment and devices
were generated from each substation's single line
diagram including breakers, different switches and
disconnecting devices, shunt reactor, instrument
transformers, relaying and metering schemes and
communication requirements. From the equipment and
devices list, based on various functions and
capabilities/requirements, a numerical value for the
number of points was generated to fulfill the
required function.
The data points were summarized into each
function and analyzed. The substations were defined
using their similarities and differences. This
thesis discusses the microprocessor-based control
system by providing a complete understanding of the
data points required to protect, control, monitor
and communicate with different sizes of substations.

Costs were generated based on the number of data
This abstract accurately represents the content of
the candidate's thesis
I recommend its publication.
Dr. Pankaj K. Sen

Dedicated to
My Husband, Donnie
For His Patience, Love and Support

This thesis is submitted to the University of
Colorado at Denver (UCD) as the final requirement
for the Master of Science degree in Electrical
Engineering. The work could not have been completed
without the cooperation and assistance of several
Thanks to my academic and thesis advisor,
Dr. Pankaj K. Sen, Professor of Electrical
Engineering at UCD, whose knowledge, support, and
encouragement kept me enthusiastic and determined to
complete the MS degree in the Electric Power
Engineering option at CU-Denver.
It is my pleasure to acknowledge Dr. Bill
Roemish for his expertise in protective relaying. I
am very thankful for having the opportunity to work
under his guidance.
Many thanks to Dr. Bob Erickson for his time
and expertise in the electrical engineering field.
Special thanks and appreciation to Western Area
Power Administration (Western), Golden, Colorado,
for their continuous support and interest. Western
is a key resource for this thesis and the power

Thanks to Frank Phillips of Bonneville Power
Administration in Portland, Oregon; and John Dean of
the Public Service Electric and Gas Company of New
Jersey for their technical information on Deans
Thanks to the Bureau of Reclamation, especially
Chris Cook for providing publishing support and
Roberta "Birdie" Hensley for creating the
illustrations and providing the necessary graphic

1. INTRODUCTION ............................ 1
Concerns ............................... 7
Substation Characteristics ............ 14
Substation Similarities ............... 22
Substation Differences ................ 24
Relay Descriptions......................24
3. FUNCTIONS................................72
Brief History...........................72
Five Functions..........................73
Communication ...................... 81
Microprocessor-Based Systems .......... 88
Data Acquisition Unit................89
Protection Cluster ................. 91
Ethernet/Data Highway .............. 94
Station Computer ................... 95

Microprocessor Advantages ............. 99
Microprocessor Disadvantages .... 102
Similarities/Differences ............. 104
Data Point Results.................... 110
Substation Summary ................ Ill
Function/Data Point Summary . . . 114
Spence Functions .................. 117
Spence Equipment .................. 147
5. COST EVALUATION/ESTIMATE............. 14 9
Breakdown of Cost Estimate Spence
Substation............................ 150
Data Acquisition Unit (DAU) . . . 150
Data Highway....................... 157
Ethernet........................... 158
Fiber Optic........................ 158
Protection Cluster (PC) ........... 159
Station Computer (SC).............. 160
Summary of Cost....................... 161
6. CONCLUSION............................. 165
Assumptions........................... 168
Contributions ........................ 169
Future Work........................... 170

7. REFERENCES.............................. 172
APPENDIX........................................ 175
A. Glossary................................ 176
B. Bridgeport Substation Details -
115 kV................................. 181
C. Spence Substation Details -
230 kV................................. 193
D. Bears Ears Substation Details -
345 kV................................. 204

Figure 1.1 Integrated Relaying and Control
System ............................... 3
Figure 1.2 Bridgeport Substation 115 kV . . 10
Figure 1.3 Bridgeport Single Line
Diagram ......................... Pocket
Figure 1.4 Spence Substation 230 kV . . . . 11
Figure 1.5 Spence Single Line Diagram . Pocket
Figure 1.6 Bears Ears Substation 345 kV . . 13
Figure 1.7 Bears Ears Single Line
Diagram ......................... Pocket
Figure 1.8 SCADA Communications..................16
Figure 1.9 Communication Channel ............... 17
Figure 1.10 Power Line Carrier.................18
Figure 1.11 Radio Freguency ..................... 18
Figure 1.12 Microwave..........................19
Figure 1.13 Fiber Optic ......................... 19
Figure 1.14 Leased Telephone Lines .............. 20
Figure 1.15 Satellite..........................21
Figure 1.16 Typical Electromechanical Relay . 27
Figure 1.17 Typical Solid-State Relay .... 28
Figure 1.18 Blind Zone Protection ............... 31
Figure 1.19 Ground Differential Scheme for
Protection of Line-Connected
Reactors...........................3 3
Figure 1.20 Dry-Type Shunt Reactor ............... 34

Figure 1.21 Three-phase, Oil-immersed Shunt
Reactor...........................3 5
Figure 2.1 Existing Relay Network Interface
Figure 2.2 SCS 100 System.......................41
Figure 2.3 SCS 200 System.......................43
Figure 2.4 Distribution Automation Remote
Terminal Unit (DART)................45
Figure 2.5 Integrated Control and Protection
System Block Diagram .............. 47
Figure 2.6 New Control and Protection System
for Switchgear......................53
Figure 2.7 WESPAC System Architecture .... 58
Figure 2.8 Integrated Substation Design ... 62
Figure 2.9 Basic Components of Computer
Figure 2.10 System Architecture ................ 68
Figure 2.11 Typical Communication Network
for an Electrical Utility .... 70
Figure 3.1 Data Acquisition Unit [7] .... 90
Figure 3.2 Protection Cluster [7] 92
Figure 3.3 Data Highway Load
(Verbal Information [23]) .... 96
Figure 3.4 Station Computer [7] 98
Figure 3.5 One-Line Diagram of Deans

Figure 5.1
Figure 5.2
Figure 5.3
Bridgeport Microprocessor-Based
System .......................
Spence Microprocessor-Based
System .......................
Bears Ears Microprocessor-Based
System .......................

Table 1.1 Substation Apparatus Ratings and
Switching Configuration ............... 23
Table 1.2 Relay Descriptions.....................2 6
Table 4.1 Substation Summary.................... 112
Table 4.2 Function/Data Point Summary .......... 116
Table 4.3 Bridgeport Functions.................. 118
Table 4.4 Bridgeport Equipment.................. 121
Table 4.5 Spence Functions...................... 123
Table 4.6 Spence Equipment...................... 126
Table 4.7 Bears Ears Functions.................. 127
Table 4.8 Bears Ears Equipment.................. 131
Table 5.1 Breakdown of Cost Estimate
Bridgeport Substation 115 kV -
246 Points............................ 151
Table 5.2 Breakdown of Cost Estimate
Spence Substation 230 kV -
336 Points............................ 153
Table 5.3 Breakdown of Cost Estimate
Bears Ears Substation 345 kV -
427 Points............................ 155
Table 5.4 Summary of Cost....................... 163
Table 6.1 Summary............................... 166

Various magazines, utilities, manufacturers and
universities have provided information on
microprocessor-based protection and control systems,
computer relaying, and research and development in
the application of "high technology" in the power
industry. The information explains the future
relaying and control of substations using multiple
microprocessors, multiplexed digital communications,
and optical-fiber data transmission media. The
articles on computer relaying explain the minimal
execution time, available memory, analog data
acquisition system, and digital input/output system.
Various manufacturers have developed microprocessor
distance relays which have programmable ability to
perform fault detection, self checking, logic
operations, calculations, etc. By incorporating
each of these areas, new improved power systems are
Microprocessor-based systems are capable of
incorporating relaying and controls. Deans

Substation of Public Service Electric & Gas
Corporation, New Jersey [1], [2], demonstrates an
integrated microprocessor-based digital system.
This specific system provides high-speed protective
relaying, pre- and post-fault information, occupies
a small amount of space compared to conventional
equipment, self-checks, increases equipment
availability, reduces operating and maintenance
costs, uses advanced technology to lower costs and
provides more information for rapid restoration, to
name a few. Figure 1.1 represents a microprocessor-
based system similar to what is found at Deans
Figure 1.1 gives an overall picture of how the
outdoor substation equipment interfaces with the
microprocessor-based system. The data points
originate from the major equipment. The CT, CCVT,
and circuit breaker provide current, voltage, status
and alarm samples to the Data Acquisition Unit
(DAU), inclusive. The DAU accepts the data,
digitizes and formats the samples in order to
transmit it to the Protection Cluster (PC) via fiber

Figure l.i Integrated Relaying and
Control System [2]

optic cable. The PC accepts the data, provides
relaying protection and is a center point between
the DAU and the Station Computer (SC). The PCs are
connected to one another via an ethernet which
allows communication and sharing of data. The SC
performs relaying tasks, stores substation
information, and communicates to remote locations.
The SC is connected to all PCs via a data highway.
Thus, this system is an example of how the
substation data points interface with
The thesis focuses on three conventional
substations. These substations utilize
electromechanical and solid-state relaying. These
substations do not follow Udren's [3] integrated
microprocessor-based system. The thesis will
provide the requirements for such a system at each
of the three substations. Refer to the thesis
pocket which contains an overall view of a
microprocessor-based design for each substation.
Computer relaying is state-of-the-art
technology because the precise characteristics of

relays to system conditions are imposed on software.
The microprocessors are being replaced with computer
relays which depend basically on communication
digital operations and high speed computations. The
philosophy of computer relaying is to adapt to power
system situations whereby the command and feedback
process results in a normal power system situation.
Applications of microprocessors entered the
power industry in 1981. Since that time, many types
of microprocessor-based systems have been produced
along with many articles on research and existing
installations of microprocessing control systems.
Low cost 8-bit, single-board microcomputers were
made for basic relaying functions. High-performance
16-bit multi-microprocessor systems were made for
complex distance relaying designs. All are part of
the process of utilizing state-of-the-art
There are several benefits of integrated
systems. Cost savings has improved due to the
elimination of copper cabling. Conventional
substations require cable from all outdoor

substation equipment to the control building. The
new microprocessor system requires copper cable from
the outdoor substation equipment to the DAU which is
located in the yard near the breakers. Fiber optic
cable is used from the DAU to the control building.
The cost of fiber optic cable is approximately
$0.17/foot, which is significantly less than the
$2.50/foot of copper cable. Another benefit is
improved instrument transformer performance and
greater accuracy of data supplied to
Udren [3] discusses how an integrated system
must consider the following functions: protection,
automatic control, monitoring, system interface,
data acquisition, and display. Modern day
substations are utilizing this integrated system of
multiple microprocessors, along with multiplexed
digital communications and optical-fiber data
transmission. Thus, this new technology can replace
discrete relays, instruments, controls and wiring,
and/or interface with existing conventional control

This thesis will contribute to the input data
points required for optimum design of substations by
answering the following concerns:
1. Research has been devoted to relays, computers,
microprocessors, but not enough research has
been devoted to the data points which are input
into these devices.
2. How to improve the design of substation
protection, control, monitoring, and
Supervisory Control and Data Acquisition
(SCADA) and design philosophy.
3. A substation guideline does not exist for
beginning electrical engineers.
Concern #1:
The majority of the references and sources
contributing to this thesis focus on the various
relays, computers and microprocessors. No reference
discusses the data points which are defined as
samples of voltages, current, status and alarms from
the major equipment in the substation.
Concern #2:
There are many ways to design substation

protection, control and monitoring systems. But
behind every design, there is a philosophy, theory
and basic design approach which is the basis for
substation design. The design of substations begins
with the data points. The data points are the
current, voltage, status and alarms from the outdoor
substation equipment; transformer, circuit breaker,
CT, CCVT, etc., These data points are utilized by
relays/devices for protection, control, monitor and
communication. Thus, the philosophy of substation
design evolves and contributes to the entire power
Concern #3:
This thesis lists many references and sources
which are utilized in substation design; books,
magazines, existing substations and engineers. The
key is to know how to locate this information. Once
you have found the information, one must understand
the information, learn how it can be used, combine
the sources and extract applicable information.
This thesis is an attempt to combine many of these

sources into one document in order to visualize the
entire substation power system. Thus, the data
points are defined, listed and related to the
substation equipment, corresponding relays,
microprocessors and overall power system.
What is a substation? A substation has many
descriptions and characteristics. The substation
characteristics help define the data points. This
thesis will use the substation characteristics to
clarify the data points and ultimate design. For
example, Figure 1.2 is a switching diagram of
Bridgeport substation. This substation is
considered small because it is rated at 115 kV.
Bridgeport substation is made up of a main-n-
transfer scheme, five breakers (three line breakers
one transfer breaker and one transformer breaker).
The main bus section is protected by differential
relaying (see Figure 1.3 Bridgeport Single Line
Diagram Pocket).
Figure 1.4 is a switching diagram of a medium
rated substation; 230 kV, called Spence substation.
Spence is a ring bus, consisting of three line

Figure 1.2 Bridgeport Substation 115 kV

Figure 1.4 Spence Substation 230 kV

breakers, three lines and a shunt reactor. A
ringbus utilizes one breaker per line. Instead of
bus differential relaying, the bus is protected by
the line relays; distance relays (see Figure 1.5 -
Spence Single Line Diagram Pocket). One advantage
of a ring bus is that a faulted line can be isolated
by tripping two breakers without disrupting the
other lines at the substation. A disadvantage of a
ring bus is the fact that a line must be de-
energized prior to testing its line relays. Also,
each remote station requires a transfer tripping
channel because of complications in applying local
backup breaker failure relaying [5].
Figure 1.6 is a switching diagram of a large
substation; 345 kV, called Bears Ears substation.
Bears Ears consists of a ring bus arrangement, three
line breakers, and three lines. This substation is
similar in bus arrangement to Spence. A ring bus
has the advantages that it can be expanded into a
breaker-and-a-half arrangement when additional lines
are added. This is one of the reasons Figure 1.6
illustrates two switches in series with one another.

Figure 1.6 Bears Ears Substation 345 kV

In the future, a line can be added between these two
switches, along with a power circuit breaker and a
switch (see Figure 1.7 Bears Ears Single Line
Diagram Pocket). The following is a list of
substation characteristics.
Substation Characteristics
1. Physical Aspects:
a. Voltage Level
b. Switches: control and monitoring (open,
close, reclose, automatic sequences)
c. Breakers: control and monitoring (open,
close, reclose, failure)
d. Instrument Transformers: control and
monitoring (current, voltage)
e. Lines, cable, etc.
f. Bus Arrangements: Ring Bus, Main-n-
Transfer, etc.
g. Major Equipment: shunt reactor, power
transformers, series and shunt capacitors,
2. Protection:
a. Relaying Schemes: Primary, Backup, etc.
b. Tripping Schemes: Poles (single or three
Pilot (Direct Comparison
Unblocking, Permissive
Overreach Transfer Trip)
3. Control: open (trip), close, reclose, etc.
a. Switches: Motor-Operated Disconnects
(MOD), Motor-Operated Interrupters (MOI),
disconnects, etc.

b. Breakers: Oil, SF6 gas, air, etc.
4. Monitor:
a. Annunciator
b. Recorder
c. SCADA Points
d. Remote Terminal Unit (RTU): interface
between the traditional high-energy
discrete wiring of the substation and the
new, multiplexed, low-energy communication
5. Communications r41: Transfer-tripping schemes
utilize tones over telephone, microwave,
dedicated carrier, or a 3-state carrier shared
with pilot relays or stepping of blocking
carrier provided for pilot relaying. For
example, two different types of communication
systems are utilized for protection functions
in order to increase reliability. For example,
Power Line Carrier (PLC) and microwave may be
used in parallel to provide protection for a
transmission line. The two communication
systems communicate relaying and tripping
schemes to each end of the transmission line.
The Supervisory Control and Data Acquisition
(SCADA) is made up of several of the above
technologies. The SCADA system allows the
operation of equipment, monitors and accepts
the required information needed by the
protection function. Once the operation is
performed and/or the information is retrieved
by the SCADA system, the result is sent over
one or more communication systems (Figure 1.8).
The following pages describes each
communication system.


nsen optics
Figure 1.8 SCADA Communications [4]

1. Communication Channel: Information is
transmitted from one location to another via a
signal. This signal can be a change of signal
frequency (frequency shift keying or FSK) or a
change of signal phase (phase shift keying or
PSK). Information can be transmitted in one or
both directions; simplex, half-duplex or full-
duplex channel.
Figure 1.9 Communication Channel
2. Power Line Carrier (PLC): PLC has been used
for voice communication and protective relaying
since the 1920s. The PLC is characterized by
voltage. Voltages above 115 kV utilizes
frequencies of 50-500 kHz and below 115 kV
utilizes frequencies in the range of 3-55 kHz.
The optimum range for the distribution line
carrier (DLC) is 5-10 kHz.

Figure 1.10 Power Line Carrier
3. Radio Frequency (RF): This communication has
been used for the past 40 years in the control
and operation of power utility systems. The
various bands include High Frequency (HF); 3-30
MHz, radio frequencies via Very High Frequency
(VHF); 30-300 MHz, Ultra High Frequency (UHF);
300-1000 MHz and the Extremely High Frequency
(EHF); 1 GHz-30 GHz. Most frequencies travel
in a line-of-sight mode, are refracted by
changes in atmospheric conditions and their
penetration is less at lower frequencies.
RAO to
Figure 1.11 Radio Frequency

4. Microwave: These frequencies are licensed by
the FCC under Part 94 of the Rules and
Regulations. Power utilities operate in UHF,
Super High Frequency (SHF) and EHF bands.
5. Fiber Optic: Fiber Optics has existed since
the 1970s for voice and data communication.
This information is transferred via light waves
over flexible hair thin threads of glass or
Figure 1.12 Microwave
Figure 1.13 Fiber Optic

Leased Telephone Lines: SCADA utilizes
telephone lines either 2-wire half duplex or 4-
wire full duplex system with data transmission
speeds of 1200 bps to 64 Kbps. Type 3002
channel is the basic AT&T system available for
Figure 1.14 Leased Telephone Lines
Satellite: Satellites are located 22,300 miles
over the equator in orbit. They provide
superior performance compared to a telephone
company. Figure 1.5 illustrates a satellite,
transponder, master earth station, user network
control center, and user's satellite earth
station. Even though satellite radio signals
travel at the speed of light, there is an
inherent propagation delay in the system of
approximately .5 seconds. Satellite signals

travel in a "Double Hop" configuration. The
signal leaves the point of origin; VSAT (very
small aperture terminal), travels up to the
orbiting satellite, then down to the master
earth station (HUB). Thus, the delay is due to
the "Double Hop" which is approximately 90,000
Progressing from one bus arrangement to another
is an example of a changing technology. In fact,
the trend for the past 30 40 years has been to
upgrade and retrofit a substation to meet today's
requirements. Bridgeport substation was designed
and built with the intentions of converting it from
a 115 kV to a 230 kV substation. Another example is
the voltage trend in the 1940-50S, when only 115 kV

Figure 1.15 Satellite

substations were built. In the 1960-70S, 230 kV
substations were built. The 1980-90S have seen 345
kV and 500 kV substations. Thus, there is a
constant pattern of improving technology.
Table 1.1 lists the main characteristics of
each of the three substations. From this list, the
substation's similarities and differences can be
obtained. By finding the data points similar to all
three substations, a basic design can be produced.
This basic design can than be used to produce a base
microprocessor system which can be utilized by all
three substations. The following is a list of items
which are common to all three substations:
Substation Similarities
1. Breakers: Oil, SF6 gas
2. Transducers: Watt, Var
3. Meters: Current, Volt, Watt, Var
4. Current and Voltage Transformers (CT and CCVT):
5. Relays: Distance, Differential
Every Substation is unique, it has its own
function and contribution to the entire power

115/12.47 kV 230 kV 345 kV
1. 115 kV 1. Ring 1. Ring
Main-n-Transfer Bus Three Bus Three
Scheme Breakers Breakers
2. One 2. One 2. Three
Transfer Breaker 230 kV Shunt 3450 kV Lines:
3. One 115- Reactor -Bonanza
12.47/7.2 kV 3. Three -Craig
Transformer 230 kV Lines: -Rifle
-Delta/Wye -Thermopolis
-15/20/25 MVA -Dave
4. One 115 Johnston
kV Transformer -Mustang
5. Three
115 kV Lines:
-Wheatbelt PPD
Table 1.1 Substation Apparatus Ratings and
Switching Configuration

system. By defining the data points based on the
differences between the three substations, a unique
design results. These data points can than be used
to produce the optimum design and microprocessor-
based system.
The following is a list of items which are
unique to each of the three substations:
Substation Differences
1. Control Schemes: Bridgeport has a main-n-
transfer scheme, while Spence and Bears Ears
each have a ring bus scheme.
2. Protection Schemes: Spence utilizes distance
relays while Bridgeport and Bears Ears utilize
a combination of distance and differential
3. Major Equipment; Transformers, Shunt Reactor,
etc.: Spence utilizes a shunt reactor, while
Bridgeport utilizes a power transformer.
4. Communication: Spence and Bears Ears utilize
PLC and microwave, while Bears Ears utilizes
PLC, microwave and fiber optics.
Relay Descriptions
Up to this point, the thesis has covered the
overall microprocessor integration trend, concerns,
substation characteristics, substation similarities

and differences. Next, the thesis will focus on one
of the three substations; Spence. The following
explanation defines the data points for the optimum
design of Spence. Every Spence data point will be
discussed and clarified using diagrams,
illustrations and tables. Table 1.2 specifies the
relays utilized at Spence substation and Figure 1.15
(Pocket) illustrates Spence's single line diagram.
The following information is a clarification of
Table 1.2:
Column 1: Specifies the standard IEEE numbers
which represent the different types
of relays.
Column 2: Lists the various manufacturers of
the relays; GEC Measurements (GECM),
Westinghouse/ASEA Brown Boveri
(W/ABB), General Electric (GE) and
Schweitzer (SEL).
Column 3; Lists the manufacturer's name for
each relay.
Column 4: Lists specific ratings or
characteristics of each relay.
The first five rows are distance (21) relays.
A distance (21) relay utilizes the currents and
voltages of the line it is protecting to calculate

21A-3.21B-3 GECU QUAD .04-48 OHU Z1.Z2.Z3
21-5 KD-10 Z1.Z2
KD-11 Z3
214-6 GE TYS3
218-6 SEL PG10
25/27-382 GECU UAVS01 5-82.5 DEGREES
25/27-582.586 CVE-1
50-5 KC-2
508F-382 GECU UCTI39 .5-16 AMPS
508F-582.586 GE 12SBC
67N0 IRD-9
67NP KRO-4
68-5 KS-3
79-582.586 SGR-52
64-382,582,556 AB8 50H 0HNO ZONE RELAY
50/51-A,8,C 50/51C /ABB CO-9 .2-2AOC TOC RANGE: .5-6A VI TIME UNIT: 1-12 IIT:6-144A SINGLE TRIP
87R GE PVD 21A1A OV UNIT: 75-400V INSTAN OC: 3-48A
Table 1.2 Relay Descriptions [6]

the apparent impedance to a fault.
Rows 2 and 3 are electromechanical distance
(21) relays produced by Westinghouse and are called
KD-10, KD-11, etc. These relays have been utilized
since the middle of the 20th century and are
distinguished by the following units:
a. Magnetic Attraction
b. Magnetic Induction KD distance relays
c. D'Arsonval
d. Thermal
Figure 1.16 illustrates a typical electromechanical
Figure 1.16 Typical Electromechanical Relay

Rows 1, 4 and 5 are static (solid-state)
distance (21) relays which are relatively new; late
1980s. The solid-state relay is usually found
backed up by an electromechanical relay and/or
another solid-state distance relay. Figure 1.17
illustrates a typical solid-state relay.
Figure 1.17 Typical Solid-State Relay
The solid-state relay is different from an
electromechanical relay in many ways. The solid-
state relay has greater speed, requires less space,
has greater variation of characteristics with
temperature and is more sensitive. Still, the
solid-state relay is vulnerable to voltage spikes.

Still, electromechanical relays require the entire
switchboard for the protection of one transmission
line. Whereas, the solid-state relays are compact
and only require 17" X 19" space for one line. In
summary, there is an overall trend toward
integrating from the electromechanical to solid-
state and onto microprocessor-based systems.
Rows 6 and 7 are verification relays utilized
when closing and reclosing line breakers.
Synchronism-check (25) relays prevent out-of-step
reclosure. For example, refer to Spence's single
line diagram (Figure 1.5 Pocket). Breakers 382
and 582 utilize a high-speed reclosing (79) relay.
If there is a fault on the Thermopolis line, both
breakers 382 and 582 would trip to isolate the line
(the breakers at the other end of the line would
also trip). Breakers 382 and 582 have their
reclosing checked by the 25 relays to prevent
machine damage caused by out-of-synchronism
reclosure. The undervoltage check (27) relays
monitor the voltage on each side of the breaker.
The breaker will close when voltages are within the
voltage differential and phase setting tolerances.
Than, the time delay initiates closing of the
breaker. The 27 relay can be time-delay or
instantaneous on pickup. For example, to avoid
premature reclosure of a breaker onto a fault,
reclosing is delayed approximately one second. This
time delay is a setting in the 27 relay.
Row 8 is an electromechanical overcurrent (50)
relay used to protect the Dave Johnston line at
Spence. This relay is required in the Direct
Comparison Unblocking (DCU) scheme. It is set to
detect all minimum internal line faults.
Row 9 and 10 are breaker failure (50BF) relays
which protect the breaker by monitoring current.
This 50BF relay can be set to be picked up
continuously on load current. During a fault and if
a PCB is inoperable, the 50BF relays do not drop
out. This condition indicates a failed PCB.
Various schemes initiate tripping of local backup

PCBs and transfer trip to clear fault. For example,
the Thermopolis and Mustang line are designed using
the Permissive Overreach Transfer Trip (POTT) scheme
as a means to trip the necessary remote breakers.
The following items are common breaker failures:
a. Loss of direct current (DC) supply to
circuit breaker.
b. Failure in trip coil of circuit breaker.
c. Mechanical failure of tripping mechanism
d. Failure in circuit breaker interrupter.
Rows 11 and 12 are electromechanical relays
called directional overcurrent ground (67NB) relays.
This relay is a zero-sequence, dual polarized relay
which contains both an instantaneous unit and a
time-delayed unit having very inverse time current
characteristics. This relay is utilized for primary
protection of non-pilot schemes and underreaching
transfer trip schemes. The 67NB relay is utilized
in the Dave Johnston Directional Comparison
Unblocking (DCU) scheme.
Row 13 is an electromechanical, out-of-step
detection (68) relay. The KS-3 relay is an
induction relay.
Row 14 and 15 are reclosing (79) relays used on
line breakers. These relays are single-shot type
Row 16 is a Blind Zone (50) relay required when
free standing current transformers (CTs) are
utilized in place of bushing CTs. Free standing CTs
are utilized with air blast and SF6 gas breakers.
These CTs are generally installed on only one side
of the breaker interrupting mechanism, leaving a
blind zone of protection as indicated in Figure

Figure 1.18 Blind Zone Protection

Row 17 includes overcurrent (50/51) relays
which provide the primary protection against multi-
phase faults. The ground overcurrent (51G) relay
provides protection against ground faults on lines
connected to solidly grounded systems. The
following are characteristics of the 50/51 and the
51G relays; instantaneous, time overcurrent, phase,
and ground capabilities. These relays are
attraction-type, inexpensive and easily applied.
For example, the Spence shunt reactor is protected
by very inverse, time phase and ground overcurrent
relays. Note, the shunt reactor is located between
breakers 382 and 582 which in turn protects the
Thermopolis line.
Row 18 is a voltage differential (87R) relay
utilized as part of the protection for the shunt
reactors (Figure 1.19). This relay detects phase-
to-ground faults only. The Spence shunt reactor
scheme involves three bus-side CTs and one ground-
side CT. This scheme can be verified using Spence's
single line diagram. Furthermore, this relay is
incapable of detecting internal turn faults, which
is why "Row 19" exists.
Row 19 is a sudden pressure (63) relay which
protects against arcing faults within the reactor
tank. This relay initiates tripping of the
necessary breakers; 382 and 582, upon operation.
Shunt reactors are utilized in several types of
designs. Spence substation utilized a properly
sized shunt reactor on a long (HV /EHV) line to help
ensure that lightly loaded line voltages would not
exceed rated levels. Figures 1.20 and 1.21
illustrate two types of shunt reactors [5].

Figure 1.19 Ground Differential Scheme for
Protection of Line-Connected Reactors

Figure 1.20 Dry-Type Shunt Reactor

Figure 1.21 Three-phase, Oil-immersed
Shunt Reactor

This chapter explains the various references
which the thesis is based upon. The following
explanations illustrate a pattern of the information
lacking in the design of microprocessor-based
systems. This information (data points) is a
quantified listing of the input into a
microprocessor-based system. The data points will
be emphasized in the thesis.
The document "Digital Techniques for Control
and Protection of Transmission Class Substations"
[7] focuses on the latest technologies in power
systems. Microprocessor, fiber optic techniques and
design are currently used for digital control and
protection systems. These systems are applied to
transmission substations. Each system complements
one another by providing a communication media which
is exceptional against Electro-Magnetic Interference
(EMI) and transients. An example of the latest
communication technology are Large Scale Integrated
circuits (LSI). Along these same lines, computers

are already being used for data acquisition or
supervisory control functions.
This particular paper was prepared for a
workshop. The workshop covered general system
overview, microprocessor technology, communications
technology and other miscellaneous problems.
Various manufacturers and utilities explained their
view of system responsibility, system demonstration
and digital-line protection relay capabilities.
Concerns were discussed such as temperature, EMI,
effect of MOS chips, security, reliability and
requirements. The workshop concluded that the
latest technologies are advanced enough for
substation control, protection systems and costs are
WRELCOM's "First Complete Substation Network
For Relay Monitoring, Data Acquisition and Event
Recording" [8] is a software package introduced by
Asea Brown Boveri (ABB). This network is capable of
exchanging data through a standard phone circuit for
monitoring, inspection of all relay inputs, targets
and settings. Settings can be checked or changed,

targets monitored and reset, and events recorded.
The status of contacts are monitored with a time lag
if applicable, and time is always synchronized.
Figure 2.1 illustrates an existing relay network
interface (ERNI) which is used to monitor the status
of contacts. This network is applicable for relays
(solid state and electromechanical), switches,
station annunciator alarms, and circuit breakers.
Other types of ABB-WRELCOM products are the Master
Incom Network Translator (MINT), MDAR, a
microprocessor-based transmission line protective
relay system and the Distribution Protective relay
(DPU). The DPU combines overcurrent protection with
reclosing and metering. This article explained the
result of using the software package, but does not
specify how this is done or what inputs are used
and/or considered. This is verified throughout most
of the following references.
ABB's "Microprocessor-Based Substation Control
System for Distribution Networks" [9] involves the
"SCS 100" system. This system is a self-supervised
control system for operation, supervision,

Figure 2.1 Existing Relay Network Interface (ERNI)

calculation, registration and reports. It is made
up of a fiber optic data bus, communication,
supervision and relay protection modules. The
system is based on a number of control panels with
instruments, control switches, alarm annunciators
and other equipment. This man-machine technique
utilizes a "mouse", information displayed in
windows, on-line programming and user-defined
pushbuttons. The user controls, supervises the
substation (manual or automatic), and creates its
own reporting system. This system is similar to a
dispatch center. For example, the "SCS 100" (Figure
2.2) has the ability to read and change relay
settings, read voltage and current values, collect
events, provide status indication, alarms, trips,
and operations.
ABB's "Microprocessor-Based Substation Control
System For Subtransmission and Transmission
Networks" [10] involves the "SCS 200" system.
This systems main functions are manual control,
automatic control (auto-reclosing), monitoring,
communication (fault conditions), and remote control

. i-*
Figure 2.2 SCS 100 System

interfacing. The protection of this network is
designed to interface between electromechanical
relays and microprocessor-based electronics. The
network is flexible because it takes into account
substation expansion and new lines. The "SCS 200"
(Figure 2.3) control equipment is broken down into
bay levels. Each bay level has several functions;
control, alarm, sequential events reports (energy,
statistics, daily), event logs, communication and
protection. Each bay level is independent of the
others so that a fault would only influence a small
part of the control equipment. Other programs can
be added to this system for various applications,
documentation, and fault tracing.
DART Westronic, Inc., specializes in
"Distribution Automation Remote Terminal Unit" [11]
for electric utilities, also known as "DART". The
various RTU's are capable of data tracking,
communication, station automation, high speed analog
processing, protection systems and man-machine
interface. RTU software involves "C" language,
multiple software system sources, down load

Figure 2.3
SCS 200 System

capabilities and open-ended applications. The
DART's main features are expanded temperature range,
CT and PT interface, KW, KWH, KVAR, KVARH
measurement, phase angle measurement, and fault
detection to name a few. The "DART" (Figure 2.4)
excepts CT and PT values, status input/output,
control information and connects direction to the
The article, "Digital System Controls
Switchyard Equipment" [12] explains how the Digital
Control System (DCS) was installed for the Arizona
Public Service Co. (APS). APS used the DCS to
monitor and control generators and switchyard
equipment. The DCS permits a reduction in spare
parts, allows better communication, faster
distribution of information, contains internal
sequence of events, and increases efficiency. The
system hardware provides reliability through
redundancy, as well as uninterruptable transfer of
functions to back up equipment. The processing time
from the operator console to a switchyard control
output was approximately 1.05 seconds. The system

t t
Figure 2.4 Distribution Automation Remote
Terminal Unit (DART)

communication is a redundant, unidirectional serial
data highway. The system graphics capability
provides a physical arrangement of the system being
monitored and controlled. The graphics shows
breaker position, transformer current readouts, oil
temperature, power values, synchroscope selection
and incoming voltages. The DCS is currently in
service and exceeding designers' expectations.
The article, "Microprocessor Applications to
Substation Control and Protection" [13] covers the
characteristics of microprocessor applications,
fault recording, computer relaying, SCADA and system
integration (Figure 2.5). System integration is
cost effective because of the combination of
automation and data acquisition functions.
The cost of digital microprocessors decreases
as its capability of more functions increase. For
example, transmission lines are protected by
distance relays which are digital microprocessors.
These microprocessors sample input signals, perform
self-checking and have multi-zone protection. They
have different communication options for transfer

Figure 2.5 Integrated Control and Protection
System Block Diagram

tripping/blocking functions, local breaker failure
protection, high-speed reclosing, automatic
synchronism-check, out-of-step protection, transient
recording, fault location and sequence of events
recording. Furthermore, the microprocessor is an
integrated system which accomplishes real-time
diagnosis of the system, monitors short- and
long-term load trend, detects abnormal conditions
and improves protection reliability.
A microprocessor can be illustrated by three
levels; the substation level, the processing level,
and the data acquisition unit (DAU) level. The
substation level includes the communication system.
The processing level contains relaying, recording
and local control. The DAU level is the switchyard
equipment. The system combines all these functions
into one computer along with a network of several
microcomputers. The processing power is distributed
to a number of different microprocessors which are
then interconnected. Thus, a number of different
functions are performed by one microprocessor which
in turn integrates with other microprocessors.

The article, "Power Plants Upgrade
Instrumentation and Control Systems" [14] explains
how microprocessor-based distributed digital control
systems are being retrofitted to older plants and
installed in new substations and plants. Three
projects utilize the microprocessor-based system
which contains decision-making components and memory
storage. The first project involved Programmable
Logic Controllers (PLC) completed by Sargent and
Lundy. This PLC replaced an existing dust
collecting system which is owned by Commonwealth
Edison. The PLC has control capabilities which have
replaced old and pertinent eguipment. This system
is operating successfully and provides operation at
a reduced load without support fuel.
The second project was completed at the Irish
Electricity Supply Board's (ESB) newest electric
generating plant. The control system is a
microprocessor-based decentralized process control
system for control and information gathering. This
system is made up of seventeen automatic stations
(AS) for storing all modulating, binary and data

acquisition functions. The AS's are connected to a
long distance bus (UI) which allows integration and
coordination. This system monitors operation of gas
turbine generator, rotor speed, temperature,
pressure, vibration and flows. The system
calculates different levels of different gases and,
most importantly, is easily reconfigured. The
cogeneration plant and its new micro-system have
been operating successfully for the past seven
The third project is the Nevada Power Upgrade.
The upgrade replaced the twenty-year-old boiler,
scrubber, analog and scrubber logic controls with a
Distributed Control System (DCS). The DCS is a
digital instrumentation system which is distributed
throughout the plant and is linked to a sequence of
events recorder and annunciator via a data highway.
The DCS includes control stations for controller
redundancy. Presently, the DCS controls the plant
without operator assistance.
"How Idaho Power Controls Substations
Electronically" [15] is Programmable Logic

Controllers (PLC). In this case, PLC's are used to
assemble electric utility substation controls
because they cut costs by speeding design
fabrication, are easily installed and reduce space
and maintenance. A PLC can be used for a control
scheme simply by selecting approximately eighty
standard modules found in a computer-aided design
and drafting (CADD) system. The PLC replaces
auxiliary and electromechanical relays and performs
functional checking on a scheme's control and
protection. The PLC's are programmed to service as
transmission line reclose devices and annunciators.
The PLC reviews data, makes the decision whether
reclosing is required, operates the breaker
mechanism and continuously checks the reclosing
status/procedures. Small PLC's cost approximately
$400.00/unit. A company may chose many PLC's over a
single, large controller.
The article, "Microprocessor-Based Control and
Protection System for Switchgear, Designed with an
Eye to the Future" [16] explains how the control and
protection systems can cover all the secondary

equipment, functions, control and monitoring of the
power distribution process. The main functions are
station control, discrimination protection and
switchgear interlocking (Figure 2.6). The system is
divided into two levels; station control and local
control. The station control includes the control
panel, relays, alarm signals, synchronizing, fuses,
voltage application and station protection. All
these items are connected to a rack which in turn
connects to the local control. The local control
includes the switchgear and information about each
bay. The information includes alarm-signals,
measurement and protection. Also, each bay
processes its own task. This particular system
requires minimum wiring, space and provides
self-monitoring. Subsystems are located in the
switchgear bays and incorporate many functions;
distance protection, auto-reclosure, fault detection
and signal comparison.
The new control and protection system has
several advantages; high flexibility due to hardware
and software design. The system adapts easily

Field I/Os
Field I/Os
Figure 2.6 New Control and Protection
System for Switchgear

because of simple installation, additional hardware
and software, and contains self-monitoring and fault
diagnostics. The economic advantage is the
combination of all secondary equipment. This
microprocessor is capable of combining functions
such as distance protection with auto-reclosing.
Also, measurement values are obtained to eliminate
separate sets of instrument transformers.
The paper, "Applications of Microcomputer-Based
Systems in Power Substations" [17] describes three
applications of microprocessors in power
substations; metering, high speed data recording,
and distribution feeder automation. The first
application; substation alarm reporting, is
accomplished by a Revenue Metering System (RMS),
Transmission Control and Dispatch Systems (TCDS),
and Real-Time Operation and Dispatch Systems (RODS).
The RMS is similar to a dial-up alarm system which
can be supplemented with Supervisory Control and
Data Acquisition (SCADA) systems by monitoring small
(remote) substations. An automatic Data Acquisition
Unit (DAU) and dedicated communications can be

replaced with an RMS. Its main function is to
monitor transformer banks and low tap voltages. The
TCDS is a computer which supports dispatch in
addition to SCADA. Eventually, SCADA systems may be
replaced by the TCDS. The RODS performs automatic
generation control, power scheduling and dispatch
reports. All contribute to monitoring small
substations, limit customer outages, reduce damage
to transformer banks, reduce battery problems and
save valuable manpower.
The second application is data recording using
Digital Fault Recorders (DFR). The DFR monitors the
system, reduces costs, permits data communication,
is flexible, improves data collection and provides
memory. DFR's provide many features not found on
conventional equipment.
The third application discusses remote feeder
monitoring and control. Microprocessors have the
power to protect, control and perform as a DAU. Its
capabilities include integrating system protection
with other functions and detecting various types of
faults. As an integrated system it is cost

effective, allows several functions to be "mutually
informed" about the power system/control, diagnoses
the area of failure, reduces repair time and
improves reliability. This system provides better
data and understanding of the operation, reduces
hardware complexity, improves programmability and
improves availability of data.
The article, "A New Approach To Digital
Protection" [18] focuses on the protection required
for generation, transformers and feeders. The
protection functions are combined into a parallel
bus-oriented system which utilizes multi-processors;
different levels of redundancy which provides remote
monitoring and establishes parameters. The type of
protection includes line, transformer, substation
control, digital, generator, parallel-bus and
multi-processor. The protection is based on the
same set of current and voltage signals and binary
inputs. This is called shared signal conditioning.
All these characteristics allow the system to be
economical, flexible, secure and dependable.
The article focuses on a system which is

divided into several levels. One level is a
hardware scheme; a battery and control system which
is connected to the central processing unit (CPU).
The CPU executes the protection schemes and controls
logic functions. The CPU connects to a parallel-bus
which in turn connects to the protection system.
The protection system includes the analog-to-digital
converter, binary input/output and trip output. The
protection system connects to the interface unit
which includes signals from the current transformers
(CT), potential transformers (PT) and trip outputs.
This system is built to protect against electro-
magnetic interference (EMI), maintain high accuracy,
long-term stability, wide setting ranges, is
redundant, self-monitoring and self-testing.
Currently, this system provides all expectations and
The article, "An Integrated, Microprocessor-
Based System For Relaying and Control of Substations
- Design Features and Testing Program" [3] by E. A.
Udren is an article most closely related to this
thesis. It defines the microprocessor functions

Figure 2.7 WESPAC System Architecture

(Figure 2.7). Udren discusses how an integrated
system must consider the following functions:
protection, automatic control, monitoring, system
interface, data acquisition and display. Each
function is broken down by line, device, piece of
equipment, type of communication and type of scheme,
to name a few. Udren goes on to discuss how the
Branchburg and Deans Substations are utilizing this
integrated system of multiple microprocessors, along
with multiplexed digital communications and optical-
fiber data transmission. This new technology can
replace discrete relays, instruments, controls and
wiring, and/or interface with existing conventional
control circuits. The integrated system excepts the
control circuit information through a number of data
acquisition units (DAU). The DAU's interface with a
protection cluster (PC), which in turn connects to a
data highway. The data highway integrates and
coordinates with all other PCs. Also, connected to
the data highway is the station computer (SC) which
is the main control point, communication center and
has the most storage.

The article, "Integrate Substation Control,
Protection" [19] focuses on the need to emphasize
the gains in both economy and efficiency of an
integrated control and protection system. The
economic advantage is cost, which can be decreased
by sharing input signals from the Data Acquisition
Units (DAU), data links and highways. Costs can
decrease when a system uses serial communication
links between the integrated system and the
substation equipment. These links replace numerous
expensive cables. Sharing input/output signals
among multiple processing clusters such as Sequence
of Events (SOE) records, remote oscillography, fault
location and transformer load monitoring will reduce
the cost. Integrated systems decrease installation
time, allow operation in an adaptive mode, allow
transformers to adjust themselves to changes in tap
settings, adjust for fault clearing times and adapt
to new settings. To do this, the system has three
levels; the first level is the communication for the
entire system, the second level comprises all
critical processing functions (protective relaying)

and the third level is the interface with the power
The article, "New Concepts Are Used For
Substation Automation" [20] focuses on how digital
systems have integrated relaying and controls
(Figure 2.8). The conventional design has separate
meters, communication, seguence-of-events (SOE)
recorder, relays, control panels, and annunciator
with wires connecting to/from the switchyard
devices. The WESPAC system is an integrated design
which combines relays, oscillography, SOE, controls,
alarm, displays, communication, and SCADA into one
control house. DAU's interface between the control
house and switchyard devices. The integrated design
reduces costs, provides self-checking, improves
functions and their capabilities, is easily
modified, and decreases maintenance. The WESPAC
system is constantly monitored to improve future
The article, "Computer Relaying: Beginning To
Show Its Muscle" [21] compares the conventional
relays to the computer relays. Unlike the

The WESPAC Concept
Integration of Substation Functions
Switchyard Davlcas
Figure 2.8 Integrated Substation Design

conventional relay, the computer relay monitors
itself, detects and reports malfunctions, changes
relay characteristics and protection schemes,
calculates and stores parameters and locates faults
(Figure 2.9). Although the computer relay is not as
reliable and has a shorter life-span than the
conventional relay, the benefits are broader and
more rewarding, especially as communication
The computer relay is future technology, backed
by four generations of relaying; electromechanical,
discrete solid state, rack-mounted, multi-function
microprocessor and computer relaying. Computer
relays are digital, operate at high speeds, have
data processing storage, are designed using
algorithms and will eventually eliminate high
voltage instrument transformers, transducers, etc.
Computer relays are in the trial period where they
must prove themselves, be improved and be integrated
in with the older/slower systems.
'Computer Relaying: Its Impact on Improved
Control and Operation of Power Systems" [22] focuses

Low-pass filter^, Sample/hold amplifier
Programmable- Analog/
gain amplilier digital
6 Direct trip,
permissive trip,
block trip,
direct close,
external trigger
- 7 Trip. dose.
A1. A2. A3.
A4, alarm
Enable 01 G1
02 G2 03 G3
51N target reset
Figure 2.9 Basic Components of Computer Relaying

on substation monitoring, protection and control
functions. These functions will act as a "feedback
control system" to the main computer system. The
computer system is capable of execution, stores
data, contains an analog data acquisition system
and provides digital input/output. A computer relay
ranges from $5000.00 to $8000.00, plus the software
development costs. Computer relays make up for
these costs by monitoring themselves, supplying
internal auxiliary CTs and PTs, providing redundancy
protection and acting as measurement devices. The
computer relay replaces many measurement devices by
measuring symmetrical components, voltages,
currents, harmonics, frequency, real and reactive
power. These measurements are accomplished by using
state vectors, Fourier Transforms and estimation of
phasers. Also, it has an internal clock
synchronization for timing capability. Thus,
computer relays are capable of controlling circuit
breakers, transformer taps, switches, static VAR
systems and various transformers.
Cost reference [23] involves a list of

publications/companies/manufacturers which were
utilized for cost estimation through out the thesis.
Costs found in the thesis are from the time period
1990 through 1992. It is very difficult to provide
accurate cost values because technology is always
changing. The thesis provides hardware cost
estimates relating to a specific time period, three
specific substations and specific hardware.
"Proceedings: Transmission and Distribution
Automation Systems" [1] is a book of 25 individual
papers presented at an EPRI seminar. The papers
focused on substations similar to Deans Substation;
a fully integrated protection and control system.
Deans integrated system utilizes DAUs, PCs and SC.
The articles provided information on the conception,
development, design and implementation of digital
technology and fiber optics for integrated systems.
This information related to protection, control,
monitor and communication functions required for a
"Substation Control and Protection Project" [2]
is a manual describing the results of the

microprocessor-based system at Deans Substation.
The system is called WESPAC (Westinghouse Substation
Protection and Control). EPRI researchers
developed, designed, built and installed this
microprocessor-based digital system for protection,
control, monitor and communication (Figure 2.10).
Deans Substation is owned by Public Service Electric
and Gas Corporation of New Jersey. This thesis
utilizes Deans Substation as a sample of the systems
designed for Bridgeport, Spence and Bears Ears.
Presently, these substations utilize conventional
relays and devices.
"Western Area Power Administration (Western)"
[6] is a government agency under the Department of
Energy (DOE). There main function involves the
transmission and distribution of power in the
Western United States. The three substations
utilized in the thesis were designed and installed
by Western.
"Bureau of Reclamation Protective Relaying
Practice" [5] is a thesis submitted to the
University of Colorado by Dr. William Roemish. This

Figure 2.10 System Architecture

thesis outlines protective relaying philosophy and
practice. It provides various relay applications,
settings and is an excellent reference for the power
industry. Dr. Roemish's thesis expands on
electromechanical relays as well as solid-state
relays. This thesis relates the trend from
electromechanical to solid-state relays.
The last reference, "Comparative Study and
Application Guidelines of the Available
Communication Systems for Use with Supervisory
Systems in Electric Utilities" [4], is a thesis
submitted to the University of Colorado by Mohamed
H. Lyzzaik which discusses in detail various
communication systems: PLC, radio, telephone lines
(leased), microwave, fiber optics and leased
satellite (Figure 2.11). Several of these types of
communications are found in the three substations
presented in this thesis.
Throughout these articles, minimal information
is supplied about the main power system which is
being protected and/or controlled. Each substation
and plant has similarities and differences; for

Figure 2.11 Typical Communication Network for an
Electrical Utility

example, the type of existing equipment or relays,
the scheme, number of breakers, number of lines,
etc. So many questions and very little data.
Therefore, the thesis will define three substations
in a quantified manner. Like the other articles,
the thesis is an attempt to improve and add to the
microprocessor-based control systems.

Brief History
The paper began with the question how to
determine the optimum design criteria for
protection, monitoring and control scheme design for
a typical 115 kV, 230 kV, and 345 kV substation or
switching station. The following three substations
are from Western Area Power Administration (Western)
and are utilized in this thesis.
1. Bridgeport 115 kV small
2. Spence 230 kV medium
3. Bears Ears 345 kV large
Up to this point the thesis defines the three
substations, each substation's data points and how
they interface with the different types of relays
and microprocessor-based systems. It is clear how
the data points correlate with the electromechanical
and solid-state relays, but more needs to be said

about how the data points correlate to the
microprocessor-based system. This is accomplished
by focusing on five main functions in substation
protection and control scheme design:
Five Functions
1. Protection
2. Control
3. Communication
4. Monitoring
5. Supervisory Control and Data Acguisition
One important item to note about the various
functions is that over the past forty years each
function had its own designer. There was a
protection engineer, control engineer and a
communication engineer to name a few. Today, a
substation designer must be all of these. He must
be familiar with many functions in order to design a
complete substation protection and control scheme.
This broad knowledge is necessary for the

integration from electromechanical, to solid-state
and on to microprocessor devices.
The next several pages will define each
function in detail. A description of the various
items in each function will provide an understanding
of how the current and voltages (samples and data
points) from the outdoor substation eguipment are
used to accomplish a particular function. The
functions will correlate the data points to the
microprocessor logic.
Protection is a broad area of relaying
functions such as various faults, tripping schemes,
equipment, relay curves, curve settings, setting of
coordination parameters and analysis of signal
waveforms. Relays range from electromechanical,
recloser, directional ground overcurrent and phase
comparison relays, to modern all purpose
microprocessor-based designs. The following list of
protection functions will help define the data

1. Line Fault Protection
2. Transformer Fault Protection
3. Bus Fault Protection
4. Breaker Failure and Fault Protection
5. Shunt Reactor Protection
6. Transfer Tripping
The following is a description of each
protection function:
1. LINE FAULT PROTECTION: Provided for high
speed tripping on circuit breakers at each
terminal. This is accomplished using
either pilot or non-pilot protection
options. Backup fault protection can be
time-delayed to trip the breakers in case
of relay or breaker failure at either
All three substations utilize the distance (21)
relay for line protection.
Bears Ears Substation utilizes differential
(87) relays for the Craig line because this is
a short line.
high speed tripping of circuit breakers
when a fault is detected within the
protected zone. Internal faults, through
faults and inrush currents are
differentiated by tripping logic based on
over-excitation, differential overcurrent,
time overcurrent, over-temperature, sudden
pressure and gas analysis.

Bridgeport Substation utilizes differential
(87) overcurrent (50/51), ground overcurrent
(50/51G), over-temperature devices and sudden
pressure (63) devices.
3. BUS FAULT PROTECTION: Requires high speed
tripping in order to isolate any bus fault
detected within the protected zone.
Backup protection is a phase differential
with ground overcurrent protection.
Automatic reclosing is an option because
most faults can be cleared momentarily.
Bridgeport Substation utilizes differential
(87) relays to protect its main-n-transfer bus
Looks for current flow through a breaker
to collapse to zero within a reasonable
time when the trip circuit of a breaker is
energized. If the current does not go to
zero, the adjacent backup breakers are
initiated to isolate the fault and/or
defective breaker.
All three substations utilize breaker failure
(50BF) protection.
faults with overcurrent differential
relays or impedance measurements. When a
fault is detected, a local or remote trip
signal is generated to disconnect the
faulted shunt reactor. Furthermore,
turn-to-turn faults are detected through
current imbalance checks.
Spence Substation utilizes differential (87),
overcurrent (50/51), ground overcurrent
(50/51G) and sudden pressure (63) devices.

6. TRANSFER TRIPPING: Schemes which use
frequency shift key (FSK) tones via
telephone, microwave, dedicated FSK
carrier, or shared pilot relaying. Dual
channels allow comparison of
inconsistencies. Transfer trip backup
utilizes a closing high speed grounding
Spence Substation; Thermopolis and Mustang
lines utilize POTT scheme via microwave.
Automatic control functions operate substation
equipment both locally and remotely via signal
generation. These signals incorporate the trip
parameters for time curves, time dial settings,
pickup and instantaneous currents.
The following is a list of control functions:
1. Local Control of Voltage and VAR Flow
2. Tie-Line Tripping
3. Load Shedding
4. Automatic Reclosing
5. Synchronism Checking and Synchronizer
6. Automatic Switching Sequences
7. Interlocking

8. Tap Changer Control for Voltage Regulation
9. Load Transfer for Transformers
10. Sequential Control
11. Power Restoration
12. Control of Capacitor Bank
13. Energy Measurement
The following is a description of each control
accomplished by operating the transformer
bank load tap changer (LTC) or by
switching in/out capacitor banks, reactor
banks, or SVARS. Dead-band, delay and
inhibiting logic provide proper dynamic
response. Control is initiated
automatically or manually.
Spence Substation; shunt reactor (KV1A) is
required to maintain voltage.
2. TIE-LINE TRIPPING: Is a transmission tie
to a neighboring utility of heavy power
outflow in conjunction with system
underfrequency. This conditions initiates
a trip signal or alarm. This
characteristic can be traced on a load
flow versus time curve.
Spence Substation; Dave Johnston line has a
steam power plant at the other end of the line.
LOAD SHEDDING; Occurs when loads increase
and the frequency level decreases. Blocks

of load are dropped automatically to
restore system frequency to normal.
Spence Substation; Dave Johnston line has a
steam power plant at the other end of the line.
AUTOMATIC RECLOSING: Is utilized on line
breakers because the majority of overhead
line faults are momentary faults. There
are two reclosing schemes. First scheme
is high speed (unchecked) reclosing which
utilizes single-shot reclosing relays.
The second scheme is checked reclosing
which utilizes bus and line undervoltage
and synchronism check monitoring relays.
Single-shot or multiple-shot reclosing
relays may be used.
Spence Substation utilizes single-shot
reclosing (79) relays.
CLOSING; Synchronism checking is
performed by a supervisory relay.
Synchronizer closing initiates closing.
An auto-synchronizer determines when it is
safe to close the breaker, based on the
magnitude, phase angle, and frequency
difference between voltages on opposite
sides of any open circuit breaker.
All three substations utilize synchronism-check
(25/27) devices.
bus transfers, sectionalizing, isolation
of faulted transformer or faulted breaker.
All three substations utilize supervisory
control (RE) to operate breakers, MODs, MOIs,

The following automatic control functions are
not found in the three substations. These functions
are microprocessor capabilities.
7. INTERLOCKING; Commands from the keyboard or
via the remote control are checked against
programmed interlocking conditions. The
verification of conditions for each bay is
performed in the bay level computers whereas
combined conditions from several bays are
verified in the station computer.
The transformer tap changer can be operated
manually by means of the keyboard or
automatically according to specified levels.
Manual control is selected on the station
diagram, a selection is then made, and a
command issued for an increase or decrease.
The automatic system is prepared for parallel
control of two or more transformers.
evaluates the load of the transformers, and if
a protection for one of the transformers trips,
the load is transferred to the other
transformer, provided the load is below a given
10. SEQUENTIAL CONTROL; This performs a sequence
of control operations when required conditions
are fulfilled, for example, connecting a line
to a specific bus bar. Operation is initiated
from function keyboard control, using a select-
execute sequence.

11. POWER RESTORATION; The power restoration
function automatically reconnects bus bars and
lines in the event of a major breakdown. The
circuit breakers are given a closing priority
depending upon existing conditions.
12. CONTROL OF CAPACITOR BANK; The capacitor bank
is automatically regulated via settings which
are based upon demand, i.e., workdays,
Saturdays, Sundays, and holidays.
13. ENERGY MEASUREMENT; Reads the pulses from an
energy measuring unit, sums these pulses for
the past hour, and creates a statistical report
sorted by the hour for the previous 24 hours.
There are several forms of communication;
voice, data transfer, metering and system
information. The communication functions involve
bi-directional communications, local operator
interface, download capability and transfer of fault
recordings. Communication travels via telephone,
radio, microwave, fiber optics, PLC, dedicated FSK
carrier, shared pilot relaying or satellite.
Communication allows capability of various
protection schemes. The substation design will
dictate whether the communication requires single,

dual or more channels, weak-in-feed, echo, etc.
In the past, telephone and radio communication
were most common. Today, most substations utilize
PLC, microwave and fiber optics. In the future,
satellite may be a common form of communication.
In substations, it is common to use two
different mediums of communication. For example,
microwave and fiber optics are both found at Bears
Ears for one line. The primary and backup forms of
communication are desired because if communication
is lost, the entire power system can be effected.
If there is a problem in California's power system,
it can effect the entire Western United States. One
solution is to integrate communication into the
entire power system. Presently, state-of-the-art
technology is researching the option of utilizing
conventional hardware to establish reliable
communication interface.
Monitoring functions include protection,
control, communication, various checks, and

transformer characteristics. The following is a
list of monitoring functions:
1. Pilot and Transfer-Trip Channel Monitoring
2. Load Monitoring and Out-of-Step Protection
3. Monitoring and Control of Breakers and Switches
4. Inferential Measurement Check
5. Transformer Overload and Tap Position
6. Self-checking
The following is a description of each
monitoring function:
MONITORING: Tests the pilot protection,
transfer trip channels, on-off (blocking)
carrier channels, FSK tone channels, and
FSK carrier channels.
Spence Substation: POTT scheme via microwave
DCU scheme via PLC
PROTECTION: Monitors line current, and
the apparent impedance looking into the
line. The apparent impedance locus
indicates if the machines of the power
system are slipping out of synchronism.
If this occurs and the system allows, two
balanced islands are implemented.

Spence Substation: Distance (21) relays
utilize current and voltage to calculate the
apparent impedance. This information is used
to provide fault protection. Spence does not
utilize fault location devices.
SWITCHES: Checks the position of breakers
and switches via auxiliary contacts,
current flow, voltage data, timing
problems, lagging poles, and sustained
pole disagreement. Control operations
include single pole tripping, closing
supervision through voltage of synchronism
checks, and lockout initiation.
Spence Substation: Three breakers and three
motor-operated disconnects (MOD).
currents and voltages. Currents are
checked by making use of the fact that
instantaneous and RMS currents passing
through a portion of a bus section sum to
zero. Voltages are checked by confirming
that the potential at two points on the
same phase which have a connected path
between them are essentially the same.
This check is a microprocessor function. It is
not found in any of the three substations.
MONITORING: Involves transformer
temperature, pressure, gas analysis, and
current. Calculated values and estimates
include hourly peak MW and MVAR values,
loading capability, and transformer life

6. SELF-CHECKING; Falls into two categories:
those which check the system hardware
through equipment diagnostics and those
which check the validity of the incoming
data through application of related known
characteristics. In short, self checking
programs identify malfunctioning equipment
and block its operation.
This is a microprocessor function. The solid-
state relays found in each of the three
substations have an internal self checking
Supervisory Control and Data Acquisition
(SCADA) is a supervisory system which monitors,
provides remote control and provides instantaneous
real-time data gathering, as well as system
interface, data acquisition and display. This
system interfaces between the protection, control
system and the external world by pre/post fault data
recording, operator selectable event recording,
event time lagging, feeder load monitoring and
feeder harmonics/noise recording. Different areas
of interfaces are:
Local Man Machine Subsystem