Team Power
Buchanan Engineering
Room 213
P.O. Box 441023
Moscow, ID 83844
December 4, 2009
John J. Kumm, P.E.
Department Manager
Power Engineers
1300 16th Ave. Suite 200
Clarkston, WA 99403
Dear John:
Our report addressing the communications system for the wind farm collector substation is
attached. It contains information on our design decisions along with a description of the final
design.
If you have any questions about the report or the final design, feel free to contact Matthew
Warren or Mark Nelson at matthewwarren@vandals.uidaho.edu or
mark.nelson@vandals.uidaho.edu. Thank you for the opportunity that you have given us to work
on this project and for all your help.
Sincerely,
Team Power
Enclosure: Design Report
Power Engineers
Windmill Collector
Substation Project
ECE 480
Senior Design
December 4, 2009
Submitted by:
Mark Nelson
mark.nelson@vandals.uidaho.edu
Matthew Warren
matthewwarren@vandals.uidaho.ed
Table of Contents
I. Executive Summary…………………………………………………………………………...1
II. Background…………………………………………………………………………………...1
III. Problem Definition…………………………………………………………………………..2
3.1 Goal 1…………………………………………………………………………………2
3.2 Goal 2…………………………………………………………………………………2
3.3 Goal 3…………………………………………………………………………………3
3.4 Goal 4…………………………………………………………………………………3
IV. Project Plan…………………………………………………………………………………..3
4.1 Task 1…………………………………………………………………………………4
4.2 Task 2…………………………………………………………………………………4
4.3 Task 3…………………………………………………………………………………4
4.4 Task 4…………………………………………………………………………………4
4.5 Task 5…………………………………………………………………………………4
V. Concept Development………………………………………………………………………...4
5.1 Communications Processors Considered…………………………………………...4
5.2 Protocols Considered………………………………………………………………...5
5.3 HMI Screen Configurations Considered…………………………………………...6
5.4 Communications Cables Considered……………………………………………….6
VI. Product Description…………………………………………………………………………7
6.1 Relay Selection……………………………………………………………………….7
6.2 Communications Processor Selection………………………………………………8
6.3 Protocol Selection……………………………………………………………………8
6.4 HMI Screen Configuration Selection.........................................................................9
6.5 Communication Cable Selection…………………………………………………….9
VII. System Architecture……………………………………………………………………….10
IX. Design Evaluation..................................................................................................................12
8.1 SEL 2414…………………………………………………………………………….12
8.2 SEL 351S…………………………………………………………………………….12
8.3 SEL 387A……………………………………………………………………………13
X. Recommendations and Future Work………………………………………………………14
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I. Executive Summary
The goal of the Power Engineers Windmill Collector Substation project is to design and
implement a wind farm substation. Specifically, this project deals with the selection of
Schweitzer Engineering Laboratories (SEL) relays to accomplish protection scheme tasks
specified by Team Power. In conjunction with the protection scheme, a secondary Human
Machine Interface (HMI) will be designed and setup. The end result will be a functional wind
farm collector substation controlled with an HMI running SEL relays and operating though the
SEL 3530 communication processor (SEL 3530). The greatest benefits and features of this
solution come primarily from the new SEL 3530. By supplying a software set called RTAC, this
product provides Team Power the flexibility and scalability to design a small scale system that
can be applied to more diverse projects. Specifically, this software allows you to establish
template files for your specific needs. These templates allow you to take existing smaller projects
like ours and apply it to much larger systems.
II. Background
The need for this project comes from the shortage of engineers graduating from accredited
universities in electrical engineering. In a recent IEEE Transactions on Power Systems journal,
researchers stated “a manpower shortage is forecasted for qualified electric power engineers as
the number of retirees exceeds new hires” (Nigim et al., 2007). Furthermore, a large portion of
engineers are working in the utility fields. Power Engineers, the sponsor for this project, realized
this need and has provided Team Power the opportunity to gain valuable experience in the utility
field while providing them first hand information on the new 3530. They have done this by
creating a project based on new technology (e.g., power generated by wind farms), centered
around the foundation of substation design and utility applications.
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III. Problem Definition
The goals for this project were as follows:
1. Determine the big picture (i.e., what does a substation entail)
2. Determine our project needs
3. Develop SCADA design and configuration
4. Learn how to use the RTDS for bench testing
The main deliverables for this project are as follows:
1. Functional list
2. SCADA architecture diagram
3. Functional SCADA / RTDS rack mounted SEL configuration (located in Model Power
Lab)
3.1 Goal 1
Initially, Team Power started this project by determining what entailed a substation and what a
typical substation layout might be. Our team found these steps necessary in order to get an idea
of the big picture with respect to the control aspect. We knew that we would first need to
understand what a typical substation layout looked like and what was available to control. After
researching this topic, two different articles helped us to understand this big picture (Myrda and
Donahoe, 2007; Scheer and Dolezilek, 2007). Specifically, both articles discussed the layout and
helped describe potential areas of concern for redundant protection.
3.2 Goal 2
In order to determine the direction for this project, we met with our main project contact, John
Kumm with Power Engineers, Inc., and discussed the specific needs, or points list, for this
project. To create a points list, a functional list needs to be first constructed. This functional list
is a listing of all of the relays and all of the associated functions those relays should perform. For
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this project, the functional list will be our specifications and will drive this project. Our goal was
to complete this functional list, which was our first main deliverable by March 20th, 2009. The
list was submitted on time and according to schedule.
3.3 Goal 3
Team Power’s third main goal was to produce an architecture diagram. Along with determining
what elements were required to create this diagram, we used our functional list to produce our
design. The architecture diagram can be found in Appendix A. This diagram was our second
main deliverable, which we completed on schedule on March 20th, 2009.
3.4 Goal 4
Team Power’s fourth goal was to learn how to utilize the Real Time Digital Power Systems
Simulator (RTDS) in order to provide bench testing. This was an optional goal but one in which
our team found important because this is the new and upcoming system to verify protection
schemes. It was very beneficial for us to get some experience using this system and worked well
to populate our values on the 387A. Please refer to the following web address for the final
presentation that shows the RTDS populating both the analog and digital values:
(http://seniordesign.engr.uidaho.edu/2008_2009/power/index.htm).
IV. Project Plan
The project plan was based on specific tasks established by John Kumm. These tasks were very
specific and organized in a manner to allow our team to complete each piece in a methodical and
efficient manner. The specific tasks were:
1. Communications design
2. SCADA design
3. SCADA device configuration
4. RTDS
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5. SCADA bench test
4.1 Task 1
In this task our primary goal was to produce the architecture diagram and the bill of materials
(BOM).
4.2 Task 2
In this task our primary goal was to produce the SCADA design, which consisted of the points
list, a derivative of the functional list that we are using, and a theory of operation.
4.3 Task 3
In this task we had two primary goals, which were to develop the HMI screens and setup the
relay and communications settings to make them communicate effectively.
4.4 Task 4
In this optional task we were to learn how to setup and implement a working model to populate
analog and digital information to the SCADA configuration.
4.5 Task 5
In this task our primary goal was to develop and implement a test procedure for visual
confirmation that our communication system was operating effectively.
V. Concepts Development
5.1 Communications Processors Considered
The communications processor gathers information from the relays. One of our key decisions
was to decide what communications processor we were going to use to perform this task. The
two communications processors considered were the SEL 3530 and the SEL 2030. The
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advantage to the SEL 3530 communications processor was that it combines the function of the
SEL 2030 communications processor and several other SEL relays such as the SEL 2411 and
SEL 2100. The SEL 3530 relay also uses a new software program that makes it easier to
configure than the SEL 2030. The drawback to the SEL 3530 was that it was still being
developed and the software for configuring it was not available until Spring 2009. Using this
relay would have slowed down the progress of creating a points list for the information gathered
from the relays. The advantage to using the SEL 2030 is that it was already in production and, as
a result, software for configuring it was already available.
5.2 Protocols Considered
The SEL relays and communications processor support several different protocols. Of these
protocols, there were three different protocols that suited our application. These three protocols
were DNP3, SEL fast messaging and modbus. The advantage to the DNP3 protocol is that it is
widely used in the power system protection industry and, as a result, most protection equipment
will support it regardless of the manufacturer. However DNP3 does not allow ASCII commands
to be sent over the same serial communications cable. This is a drawback to the DNP3 protocol
because in some applications it is desirable to be able to send ASCII commands to the relays as
well as commands from the HMI. If the DNP3 protocol is being used and this functionality is
required, a second communications cable for the ASCII commands has to be added in parallel
with the cable carrying commands from the HMI. The advantage to SEL fast messaging is that it
was specifically designed for sending ASCII commands and commands from the HMI over the
same cable. As a result, the second cable is no longer required. The third protocol, modbus, is a
very basic protocol that must be used with certain devices that do not support other protocols
such as DNP3.
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5.3 HMI Screen Configurations Considered
Along with selecting the protocols used to collect information from the relays we also had to
determine how to display this information on the HMI screen. Our original idea for the HMI
screen was for the user to be able to enter any standard ASCII relay command into the HMI and
have the information associated with that command printed onto the HMI screen. The idea
behind this was that it would allow the user to display any information that was available on the
relay. It turned out that pulling this much information from the relay was not practical and, as a
result, the list of information that was going to be presented to the user had to be narrowed down.
Along with narrowing down the amount of information that was going to be made available to
the user, Power Engineers Inc. wanted a more graphical way of displaying the information on the
HMI than just listing the information.
5.4 Communications Cables Considered
Another design choice was the type of communications cables that would be used to connect the
relays. The three types of communications cables that we considered were serial
communications cables, ethernet, and fiber optic cables. There were two main factors that
influenced the choice of what communication cables would be used to connect the relays. The
first factor was the distance that the cable could communicate over and the second was the cost
of the cable. Serial communications cables have a relatively short operating distance and can
usually only be used for distances up to 20 meters. Ethernet has the second longest operating
distance and can be used for applications where the distance is less than 100 meters. For
distances over this 100-meter limit fiber optic communication cables are used. Cost of the
communications cables also increase as the performance of the cable increases. A serial
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communications cable is approximately $32 and requires no transceiver. Although ethernet and
fiber optic communications cables are not very expensive they require a transceiver which can
cost $100-$1500. Where the cost of this transceiver falls in this range of prices depends on the
length of the communications cable connected to the transceiver.
VI. Product Description
6.1 Relay Selection
The first decision that we had to make was which relays we were going to use to create our
protection scheme. Our choices were limited by the protection functions that each relay was
required to perform. The one line diagram that was provided to our team by Power Engineers
Inc., specified the required protection functions. The one line diagram is included in the
Appendix as Figure A1. Figure 1A also specifies by ANSI relay device numbers the protection
functions that the relays are required to perform. The protection function associated with each of
these ANSI device numbers can be looked up using the table included in the Appendix as List
B1. In the end there was only one logical choice for the selection of the relays that were going
to perform the desired protection functions. Protection functions that were in the same physical
location within the wind farm needed to be performed by the same relay to prevent wires from
being run long distances to reach their destination. In each case after the protection functions
were grouped according to their physical location there was only one relay that could function as
desired. The relays selected and the protection functions they perform are listed in Table 1
below. Links to relay data sheets and instruction manuals are included in the Appendix as list
D1.
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Table 1: Relay Selection Summary
Relay Selected
Name On Figure A1
SEL 351S
151, 251, 351
SEL 387A
51T1
SEL 587Z
87B1
SEL 2414
NONE
Required Protection Functions
27
50
59
59
51
50
87
49
71
63
21
6.2 Communications Processor Selection
The 3530 was selected as the communications processor that would gather all of the information
from the relays. Although the software for the 3530 will not be available until the end of the
spring 2009, after further looking into the 3530 we decided that the ease with which the 3530
allows the user to configure the communications processor would more than make up for the
setbacks it will cause.
6.3 Protocol Selection
The protocol selected for communication between the communications processor and the relays
was the DNP3 protocol. The DNP3 protocol was selected over the SEL fast messaging protocol
because SEL fast messaging is only supported by SEL relays. By using the DNP3 protocol
equipment from manufactures other that SEL could be integrated into the system in the future
while maintaining one protocol throughout the communications system as much as possible.
The modbus protocol was used for communications between the communications processor and
the HMI screen. Although DNP3 would have been the preferred choice, modbus was chosen
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because it was the only protocol supported by both the communications processor and the HMI
screen.
6.4 HMI Screen Configuration Selection
We decided that the most user friendly way to set up the HMI screen would be to have the main
screen of the HMI look exactly like the one line diagram. This way the location of the relays on
the HMI screen would be representative of their physical location within the wind farm. From
the main screen the user will be able to click on each individual relay and have a screen pop up
which displays front panel targets, I/O information, and analog quantities. Analog quantities will
be organized in a table. Front panel targets will be displayed to the user in exactly the same way
they would be if the user were standing in front of the actual relay. Whenever the relay performs
a protection function a front panel led is lit on the face of the relay as an indication. Our HMI
screen that displays front panel targets will look exactly like the face of the relay and have all the
same front panel led lit. I/O information will be displayed on a screen that looks exactly like the
back of the relay where all the I/O ports are located. All of the I/O ports will be labeled based on
what that I/O port is connected to or controls and will change color to indicate whether the port is
logic level 1 or 0. Some conceptual screen designs are included in the Appendix; Figure C1 is
the main HMI screen and Figure C2 is for displaying the front panel targets.
6.5 Communication Cable Selection
Serial communication cables were chosen to connect the communications processor, relays and
the HMI screen. The scope of our project involved getting the communications processor, relays
and HMI screen to interact in order to transfer the desired information from the relays to the
HMI. During configuration the relays were within fairly close proximity of each other and did
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not have to communicate over long distances. As a result serial communications cables were a
cost effective choice for our project.
VII. System Architecture
The first key point deals with the understanding of Power Engineers Inc. current measurements
sheet (Appendix A). Current measurements cannot be directly taken at full line current because
the magnitude is too high. So in order to correctly make these measurements, you need to use a
current transformer (CT). These can be found in Appendix A as a three half circles all tied
together located on the 230KV bus line as well as on the 34.5KV feeder circuits. The end of the
last half circle has two configurations. The first is shown at the very top of the drawing next to
the 230KV line, which is the CT in use with a positive value being sent on the line connected to
the top half circle. The other configuration is the CT shown just below the transformer with a
line connecting it to itself. This means the CT is shorted and not being used for measurements
but in place for future use. The positive value on the top of the CT (as shown by a square on the
diagram) is then fed into the associated relay. For example, the CT located just below the 230KV
bus heading shows a positive square feeding into the power call out 87T1 (Team Power specified
387A). That line feeds a circle called 51 P1 which, as stated previously, is an ANSI call out used
to specify an AC time over current relay (Appendix B).
The second key point deals again with the understanding of the voltage measurements on Power
Engineers, Inc. sheet E1 (Appendix A). Voltage measurements cannot be taken directly from the
full bus voltage. Therefore, in order to attain a reading of magnitude recognizable by the relay
you need a voltage transformer (VT). The first and only voltage transformer is shown in the
center of the drawing labeled VT-4 and it drops the bus voltage from 34.5KV to 115V. After the
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voltage drop, it feeds a control voltage or comparing bus line into the power callouts 151, 251
and 351 (Team Power specified 351’S). Those feeders run into the ANSI callouts 59,
overvoltage relay, 27, under voltage relay (Appendix B). The voltage measurements are needed
because they provide the ability for each relay to detect whether the associated windmill is
allowing a sag in the line (27 under voltage error) or a swell in the line (59 overvoltage error).
This is important because it provides the user the ability to maintain a stable system by dropping
out the bad leg. After becoming familiar with all of these measurements, we were able to
associate the correct ANSI device callouts with the second page of the data sheets (Appendix D).
The second step of the system architecture was to consolidate all of these selections into one
document that was easily understandable and diagrammatic in nature so as to make it workable
for a contractor to install. This diagram was introduced in the problem definitions section as the
architecture diagram (Appendix E).
The architecture diagram is centered on the 3530 shown in the center of the sheet with both the
front panel and the back panel. All of the relays feed into the 3530 sequentially from left to right
listed as follows:
1.
587Z (connected to comm. Port 1)
2.
351S (connected to comm. Port 2), feeder 1
3.
351S (connected to comm. Port 3), feeder 2
4.
351S (connected to comm. Port 4), feeder 3
5.
387A (connected to comm. Port 5)
6.
2414 (connected to comm. Port 6)
7.
Automation Direct HMI (connected to comm. Port 7)
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IX. Design Evaluation
As discussed above, the project specifications for this project were based on the functional list or
points list (Appendix F). Each SEL relay that performs different functions is listed and discussed
below.
8.1 SEL 2414
This relay required digital information only in the form of transformer monitoring quantities. We
utilized the RTDS to simulate these quantities by switching in and out a 24 VDC power supply
connected to the back of the SEL 2414. From the back of the relay, we mapped those inputs to
the correct front panel target to simulate the correct transformer trip. This populated the values in
the data mapping table, which provided us a status point that we could call from the
communications processor. From here the HMI populated the test values by calling the values
just populated to the communications processor and displaying them in the HMI screen labeled
2414 (Appendix C). With regards to verification of meeting the project specification, we
accomplished this for the SEL 2414 in two ways:
1. You are able to see the values populating in real time on the HMI screen with full
functionality from the RTDS.
2. You are able to see the validity of the values in the 3530 RTAC software, again
verifying the functionality.
8.2 SEL 351S
This relay required both analog and digital information in the form of voltage currents and digital
front panel targets. We utilized a standard electrical cord to provide the voltage and populated
the front panel targets based on the front panel targets available. In regards to the points required
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for both current and voltage (or just current), we were unable to populate those quantities
because our SEL351S did not come equipped with the required hardware to do so. With respect
to verification of meeting the project specification, we accomplished this for the SEL 351S in
two ways:
1. You are able to see the voltages and front panel targets populating real time on the HMI
screen from the power cord and partially populated data map.
2. You are able to see the validity of the values in the 3530 RTAC software, again verifying
the functionality.
8.3 SEL 387A
This relay required both analog and digital information in the form of currents and front panel
targets. We utilized the RTDS to populate all data mapping required by the specification. This
was done by running the RTDS model with a hard-wired connection into the front face of the
relay. This provided information to the relay that it was in fact receiving real time current
information. This information was then called by the 3530 communications processor, which
was also called by the HMI. With respect to verification of meeting the project specification, we
accomplished this for the SEL 387A in two ways:
1. You are able to see the currents and front panel targets populating real time on the HMI
screen from the RTDS.
2. You are able to see the validity of the values in the 3530 RTAC software, again verifying
the functionality.
Product testing is paramount in this project because in order to verify any of our assumptions
about the operation, product testing is the only way to verify our design. Because of this, we
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decided to take on the additional task of researching how to design and run an RTDS model.
With the help of John Leman and Brian Johnson with Power Engineers, Inc. and the University
of Idaho, respectively, we were able to produce a working model that populated all of the
information on the SEL 2414 and SEL 387A. Please refer to Appendix G for a screenshot of the
RTDS model. In regards to the population of values for the SEL 351S, we had to populate those
values using a power cord though the standard voltage inputs on the back of the relay. We had
to populate in this manner because the relay that we received did not have a connection for the
RTDS.
The results for this project are easy to verify because are all verifications can be made visually.
The data points require a lot of work to get to that visual verification but in the end we were able
to make all of the results visual. This being the case, please refer to the following website for a
video link to our final presentation, which walks you through the final visual verification:
(http://seniordesign.engr.uidaho.edu/2008_2009/power/index.htm)
Additionally, because our project included the implementation of existing products and only the
design of software was mostly based off of industry standards, we chose not to display our
DFMEA analysis. Our analysis, along with estimating the costs, did not really apply because
everything was donated to the project. In order to repeat this project, the University of Idaho
would only need Dr. Johnson to make a phone call to SEL and any supplies and costs would be
negligible.
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X. Recommendations and Future Work
This project was an excellent learning experience for anyone looking to work in the protection
consulting industry. It provided our team the opportunity to learn valuable skills that can only be
learned on the job. Additionally, we feel there could be much more done with this project. At this
point the projects software is working and the relays are communicating effectively and
populating the HMI as specified. However, the next team could focus more specifically on the
RTDS and create a much more realistic model. This future team could also learn how to setup a
protection scheme and how to make the current model function based on signals initiated from
the RTDS. This would provide an excellent foundation for those students to learn about and
potentially move into a career in protection systems studies after graduation.
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Citations
Myrda, P. and K. Donahoe. 2007. The True Vision. IEEE Power & Energy Magazine: 32-44.
Nigim, K., G.T. Heydt, and J. Palais. 2007. E-Learning Opportunities for Electric Power
Engineers. IEE Transactions on Power Systems 22: 1382-1383.
Scheer, G.W. and D.J. Dolezilek. 2007. Selecting, Designing, and Installing Modern Data
Networks in Electrical Substations; Pullman WA. SEL 1-9.
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Appendix A
Power Engineers Sheet E1 One Line Diagram
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Figure A1:
Section of One Line Diagram that Specifies Relay Protection Functions
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Appendix B
ANSI Device Numbers
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Listing B1:
List of ANSI Device Numbers and Acronyms
1 - Master Element
2 - Time Delay Starting or Closing Relay
3 - Checking or Interlocking Relay
4 - Master Contactor
5 - Stopping Device
6 - Starting Circuit Breaker
7 - Rate of Change Relay
8 - Control Power Disconnecting Device
9 - Reversing Device
10 - Unit Sequence Switch
11 - Multi-function Device
12 - Overspeed Device
13 - Synchronous-speed Device
14 - Underspeed Device
15 - Speed - or Frequency, Matching Device
16 - Data Communications Device (see note 5)
17 - Shunting or Discharge Switch
18 - Accelerating or Decelerating Device
19 - Starting to Running Transition Contactor
20 - Electrically Operated Valve
21 - Distance Relay
22 - Equalizer Circuit Breaker
23 - Temperature Control Device
24 - Volts Per Hertz Relay
25 - Synchronizing or Synchronism-Check Device
26 - Apparatus Thermal Device
27 – Under voltage Relay
28 - Flame Detector
29 - Isolating Contactor
30 - Annunciator Relay
31 - Separate Excitation Device
32 - Directional Power Relay
33 - Position Switch
34 - Master Sequence Device
35 - Brush-Operating or Slip-Ring Short-Circuiting, Device
36 - Polarity or Polarizing Voltage Devices
37 - Undercurrent or Under power Relay
38 - Bearing Protective Device
39 - Mechanical Conduction Monitor
40 - Field (over/under excitation) Relay
41 - Field Circuit Breaker
42 - Running Circuit Breaker
43 - Manual Transfer or Selector Device
44 - Unit Sequence Starting Relay
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45 - Abnormal Atmospheric Condition Monitor
46 - Reverse-phase or Phase-Balance Current Relay
47 - Phase-Sequence Voltage Relay
48 - Incomplete Sequence Relay
49 - Machine or Transformer, Thermal Relay
50 - Instantaneous Over current or Rate of Rise, Relay
51 - AC Inverse Time Over current Relay
52 - AC Circuit Breaker
53 - Exciter or DC Generator Relay
54 - Turning Gear Engaging Device
55 - Power Factor Relay
56 - Field Application Relay
57 - Short-Circuiting or Grounding (Earthing) Device
58 - Rectification Failure Relay
59 - Overvoltage Relay
60 - Voltage or Current Balance Relay
61 - Density Switch or Sensor
62 - Time-Delay Stopping or Opening Relay
63 - Pressure Switch
64 - Ground (Earth) Detector Relay
65 - Governor
66 - Notching or Jogging Device
67 - AC Directional Over current Relay
68 - Blocking of "Out-of-Step" Relay
69 - Permissive Control Device
70 - Rheostat
71 - Liquid Level Switch
72 - DC Circuit Breaker
73 - Load-Resistor Contactor
74 - Alarm Relay
75 - Position Changing Mechanism
76 - DC Over current Relay
77 - Telemetering Device
78 - Phase-Angle Measuring Relay
79 - AC Reclosing Relay
80 - Flow Switch
81 - Frequency Relay
82 - DC Reclosing Relay
83 - Automatic Selective Control or Transfer Relay
84 - Operating Mechanism
85 - Carrier or Pilot-Wire Receiver Relay
86 - Lockout Relay
87 - Differential Protective Relay
88 - Auxiliary Motor or Motor Generator
89 - Line Switch
90 - Regulating Device
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91 - Voltage Directional Relay
92 - Voltage and Power Directional Relay
93 - Field Changing Contactor
94 - Tripping or Trip-Free Relay
95 - For specific applications where other numbers are not suitable
96 - For specific applications where other numbers are not suitable
97 - For specific applications where other numbers are not suitable
98 - For specific applications where other numbers are not suitable
99 - For specific applications where other numbers are not suitable
AFD - Arc Flash Detector
CLK - Clock or Timing Device
DFR - Digital Fault Recorder
ENV - Environmental Data
HIZ - High Impedance Fault Detector
HMI - Human Machine Interface
HST - Historian
LGC - Scheme Logic
MET - Substation Metering
PDC - Phasor Data Concentrator
PMU - Phasor Measurement Unit
PQM - Power Quality Monitor
RIO - Remote Input / Output Device
RTU - Remote Terminal Unit
SER - Sequential Events Recorder
TCM - Trip Circuit Monitor
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Appendix C
Conceptual HMI Screens
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HMI Screen for One Line
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SEL-351S HMI Screen
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SEL-387A HMI Screen
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SEL-2414 HMI Screen
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HMI Screen for the Help File
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Appendix D
Relay Data Sheets
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Listing D1:
Links to Relay Data Sheets and Instruction Manuals
351S Documentation
-Data Sheet
-https://www.selinc.com/WorkArea/DownloadAsset.aspx?id=2856
-Instruction Manual
-https://www.selinc.com/WorkArea/DownloadAsset.aspx?id=3635
387A Documentation
-Data Sheet
-https://www.selinc.com/WorkArea/DownloadAsset.aspx?id=2857
-Instruction Manual
-https://www.selinc.com/WorkArea/DownloadAsset.aspx?id=3637
587Z Documentation
-Data Sheet
-https://www.selinc.com/WorkArea/DownloadAsset.aspx?id=2841
-Instruction Manual
-https://www.selinc.com/WorkArea/DownloadAsset.aspx?id=3647
2414 Documentation
-Data Sheet
-https://www.selinc.com/WorkArea/DownloadAsset.aspx?id=1185
-Instruction Manual
-https://www.selinc.com/WorkArea/DownloadAsset.aspx?id=3604
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Appendix E
Architecture Diagram
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Figure E1:
Architecture Diagram
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Appendix F
Points List
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Sel Relay
2414
351 S
Function
Oil Level (Tank)
Pressure Relief (Tank)
Fault Pressure (Tank)
Sudden Pressure (#)
Heat Detector
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Assoc.
Sym.
71
63
63
63
49
Front Panel Targets
LED 1
LED 2
LED 3
LED 4
LED 5
Ac Time Overcurrent Relay
51
51 LED Front Panel
Instant Overcurrent or Rate of
rise relay
Overvoltage Relay
Undervoltage Relay
Breaker Wear Monitor
50
59
27
50 LED Front Panel
59 LED Front Panel
27 LED Front Panel
LED Front LED
Station Battery Monitor
LED Front LED
Scada Trip BRKR
Front Panel Buttons
Scada Close BRKR
Front Panel Buttons
Scada Trip Indication
Trip LED
FX BRKR 52A (Open or Closed)
Front Panel Buttons
Trip LED and One
Line
Front Panel Buttons
HMI Tables
HMI Tables
HMI Tables
HMI Tables
HMI Tables
HMI Tables
HMI Tables
HMI Tables
Relay Alarm
Targets Reset
Current,Magnitudes & Angles
Voltage,Magnitudes & Angles
Power, Real & Imaginary
Frequency
Energy MVaRh 3p
Energy MWh 3p
Power MW 3p
Power MVARS 3p
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387A
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Ac Time Overcurrent Relay
(phase)
Instant Overcurrent or Rate
of rise relay (phase)
Breaker Wear Monitor
Station Battery Monitor
230KV BRKR 52A (Open or
Closed)
230KV BRKR Trip
Scada Trip BRKR
Scada Close BRKR
Scada Trip Indication
Relay Alarm
Current,Magnitudes &
Angles
Frequency
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51 LED Front Panel
50
50 LED Front Panel
LED Front LED
LED Front LED
Front Panel Buttons
Trip LED
Front Panel Buttons
Front Panel Buttons
Trip LED
Trip LED and One
Line
HMI Tables
HMI Tables
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Appendix G
RTDS Model
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RTDS Model
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