A guide to specifying, justifying, and installing
substation monitoring and control systems
BY STEPHEN PAULI, BALDUR O. KRAHL, & BLANE LEUSCHNER
four 13.8 kV substations,
1996
and
and two 34.5-kV substa-
1999, a large
tions. The legacy system is
chemical firm
only marginally supported
made US$1 billion in capital
and not expandable. This
investments, adding produc-
infrastructure
tion capacity and doubling
installed a Web-enabled sub-
the site load to 220 MW.
station monitoring and con-
This growth strained the
trol system (SMCS) for the
capacity of critical substa-
two new substations. The
tions to carry loads had its
purchased SMCS has been in
companion transformer failed
service since February of
B
(in a typical main-tie-main
© EYEWIRE
project
2002. A third substation’s
SMCS was updated in 2004,
arrangement). In parallel to a
year 2000 cogeneration agreement, this firm funded a
and the remaining four legacy installations are scheduled
US$13 million project to improve the electrical distribu-
for updates in the year 2005.
tion system infrastructure. This project installed a third
The principal role of the legacy monitoring system is to
138-kV yard, a 138 kV/34.5 kV 2 × 64 MVA substation,
alarm the utilities operators of failures in the existing sub-
and a satellite 2 × 34 MVA 13.8 kV substation. A legacy
stations. Prior to purchasing the new SMCS, the authors
monitoring system, operating in a Windows 95 environ-
recognized that to operate, maintain, and improve the
ment, monitored the two existing 138-kV switchyards,
electrical distribution system, the operators needed essential
1077-2618/05/$20.00©2005 IEEE
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ETWEEN
21
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22
information that had not previously been available. To
really manage the cost of electrification—energy costs,
electrical asset utilization, and, most importantly, system reliability and downtime avoidance—the authors
concluded that there was a need to log accurate power
flow and critical event information to understand and
resolve the root cause of system problems or equipment
failures. This information would only be available
through a new-generation SMCS. This essential tool
would be used by operations, maintenance, engineering, and accounting to manage the cost, quality, and
reliability of one of the plant’s most expensive production resources—electrical power.
An extensive investigation of available monitoring
systems resulted in a detailed bid specification for the
new SMCS. The authors discovered that in recent years
there have been substantial advances in the technical
capabilities of electrical meters, the networking capabilities of those meters, and the software available to monitor and/or control an electrical power distribution
system. An SMCS, as described in this article, is defined
as the collection of hardware and software that monitor
and record the power quality, the electrical power values,
and the actions of critical components of the industrial
substation. Additionally, an SMCS may be designed to
control selected substation elements.
The purpose of this article is twofold:
1) provide the electrical engineer with a guide to the
writing of specifications for the installation of an
SMCS
2) provide a case study of the installation of an SMCS
with some discussion of justification concepts.
This article first explores power quality terminology
as well as types of meters and communication interface
components and their capabilities. Next, it examines
how the system functions as a whole and compares the
different philosophies of monitoring versus monitoring
and controlling. This article also provides guidance for
assembling requirements, identifying hardware alarms,
system user types and database management. Then it
explores the system architecture options, the system
design, assembly, maintainability, multivendor support
and Web capabilities. Finally, system benefits and payback are summarized.
Power Quality Terms
IEEE 1159–1995 [1] classifies power quality disturbances into seven categories. The substation monitoring
system to be specified uses meters with various capabilities to monitor, capture, and report these disturbances.
The authors encourage the electrical engineer to refer to
IEEE 1159–1995 to understand these terms prior to the
specification process.
The IEEE classifications of these disturbances are summarized in Table 1.
Meters: The Basic Tool/Building Block
Based on a survey of meters available in the United
States, meters can be separated into families of meters
with common features and measured values found in
each group.
Basic Meters
The lowest cost, basic meter will record all simple values
of voltage, current, power (watts), real energy (watt
hours), apparent energy (volt amperes), and power factor.
The basic meter accuracy is in the 0.5% range when connected to current transformers (CTs) and potential transformers (PTs) of equal or greater accuracy. This meter
would be used for basic in-plant metering or billing of
electrical service where only the most elementary measurements are required. This class of meter will usually
have minimal communication options and no inputs or
outputs (I/O).
Midrange Meters
The midrange meter will add to the capabilities of the
basic meter by measuring real and apparent energy
demand. The midrange meter will have more advanced
communication capabilities and digital I/O.
TABLE 1. IEEE 1159 TABLE 2 POWER QUALITY TERMS.
Category
Types
Transients
Impulsive
Oscillatory
Short Duration
Variations
Sags
Swells
Interruptions
0.1–0.9 pu
1.1–1.8 pu
Long Duration
Variations
Undervoltages
Overvoltages
Interruptions
0.8–0.9 pu
1.1–1.2 pu
0.0 pu
>1 min
Poor Regulation,
Overloads, Utility
0.5 –2%
Steady State
Unbalanced Loads
Varies 0–20%
Steady State
Electronic Loads
0.1–7%
Intermittent
Arcing Loads,
Loose Connections
<10 s
Poor Generator Control
Voltage Imbalance
Waveform Distortion
Voltage Fluctuations
Frequency Variations
DC Offset, Harmonics,
Notching Noise
Voltage Levels
Duration
Common Causes
<1 cycle
Lightning, Switching
Loads
Faults, Motor Starting,
<1 min
This meter serves well for the monitoring of substation
feeder breakers when no form of electrical disturbance data
is required. The case study used meters of this class for all
feeder breakers.
Advanced Meters
Meter Memory
Advanced meters have the capability of capturing large
amounts of interval and event-based data logging and
wave-form information. Differences exist between manufacturers’ design in how this data is stored. One
design may use the meter and network to transport all
data to the server or computer as soon as it becomes
available. Other manufacturers provide meters with
larger memory. That larger memory allows for storage
of more measured values (some as much as a month’s
worth of data) along with captured waveforms. The
Phase A-N Voltage
512 Points/Cycle
750
500
250
0
−250
−500
−750
65
70
75
80
85
90
95
ms
(a)
Phase A-N Voltage
83,333 Points/Cycle
Voltage
These high-end meters offer transient detection in the megahertz
range. These meters compete well
in the market for dedicated transient or disturbance monitors.
They feature waveform capture
and harmonic analysis as high as
the 255th harmonic. The sensitivity of this waveform capture is
measured in numbers of samples
taken per cycle. Sample rates in
the range of 512 samples per
cycle are common. High speed
meters can capture transients at 5
MHz (83,333 samples per cycle).
By contrast, dedicated substation
transient recorders (also known as
disturbance monitors) capture
similar waveforms at rates as high
as 23 kHz or 384 samples per
cycle. Figure 1 shows the same
transient captured at 30.7 kHz
and 5 MHz. Note the difference
in the magnitude of the peak
voltage measurements for the
identical transient. The 5-MHz
Voltage
Transient Detection Meters
2,500
2,000
1,500
1,000
500
0
−500
0.00
0.05
0.10
0.15
0.20
0.25 0.30
ms
0.35
(b)
Identical transients captured by a meter at two sample rates.
0.40
0.45
0.50
1
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In addition to measuring the values in basic and
midrange meters, the advanced meter has the electronics
and firmware algorithms to measure power quality variations as defined in IEEE 1159-1995. Accurate readings
of harmonics, total harmonic distortion (THD), sag, and
swell are possible. Meters in this family often have waveform capture, data logging, alarming, and date and time
stamping. Some advanced meters may determine the
direction of a disturbance; that is, they can indicate if a
disturbance occurred upstream or downstream of the
meter. Some meters may also have an alarm setpoint
learning feature that aids the engineer in meter configuration. Analog I/O as well as digital I/O are available in
this family of meters. Advanced revenue metering features such as KYZ outputs, sliding window demand, and
predictive demand powers are available. On-board memory often exists in this meter family, as well as multiple
communications options. Many meters have built-in
Web-based communications and can host HTML pages.
Only an Ethernet connection, a fixed IP address and an
Internet browser are required to view the measured values. The advanced meter serves very well as a main circuit breaker monitor and can serve as a quality, although
expensive, feeder breaker monitor. The chemical firm in
this case study used these meters at three 138-kV service
points and at each of four main
circuit breakers.
meter will allow the troubleshooter to conclusively
determine the magnitude, duration, and polarity of an
extremely fast voltage event and allow a better diagnosis
of the event’s source. In addition to triggering waveform
captures based on impulse events, these meters can trigger waveform captures based on the wave shape distortion such as is caused by “ringing.” Capacitor switching
is one source of this ringing phenomenon.
They also include high-speed event recording that is
useful for sequence of event recording (SER). They offer the
most communication options as well as quantity of I/O.
They serve well as monitors for the utility service entrance
points or as monitors for the main circuit breakers of
switchgear. The owner did not install any of these meters as
the advanced meter has proven to be adequate to date.
Table 2 shows features for these four families of meters.
Other features found in meters on the market today in
include meter memory, meter communication networks,
and meter programming/Web capabilities.
23
TABLE 2. METERING DEVICE SELECTION GUIDE.
Meter Type
Basic
Meter
Midrange
Meter
Advanced
Meter
Transient
Detection Meter
Applications
Simple
Feeders
Substation
Feeders
Substation
Service Entrance
Mains & Feeders & Main C.B.s
Cost
1 p.u.
> 1, < 3 p.u.
> 3 p.u.
≥ 4 p.u.
Measured Value/Features
Revenue Accuracy ANSI:
C12.16
C12.16
C12.20
C12.20
Current, Voltage, Power, Apparent Power
X
X
X
X
Power Factor
X
X
X
X
Frequency
X
X
X
X
Energy Real, Reactive & Apparent
X
X
X
X
Harmonics: Voltage & Current
X
X
X
Apparent/Displacement Power Factor
X
X
X
Demand Current & Powers
X
X
X
Predicted Power Demands
X
X
X
THD Voltage & Current
X
X
Sag & Swell Detection
X
X
Waveform Capture On board
X
X
Waveform Capture to Host PC
X
X
Wave shape Alarm
X
X
X
X
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Power Quality
24
Disturbance Direction Detection
X
Transient Detection
X
I/O
None
X
KYZ Outputs
X
Less than 3
X
10 or more
X
X
X
X
Network Communications
None
X
Proprietary
X
Modbus RTU RS 232 RS485
X
X
X
Ethernet Twisted Pair
X
X
X
Ethernet Fiber Optics
X
X
Integral Web Pages/Email Alarming
X
X
GPS Clock Synchronization
X
X
Programmable Functions/Logic
X
X
Advanced Capabilities
On Board Memory
X
X
High Speed Sequence of Event Recording
X
X
Alarm Setpoint Learning
X
X
X
X
Data Logging
X
X
combination of meter memory and
software that takes advantage of the
meter’s intelligence can provide a
substation monitoring system that
survives day-long network or server
outages. Data loss can be minimized
during network downtime if the
meters provide more of the intelligence and the buffering. There is no
right or wrong in these conflicting
meter philosophies it is a matter of
choice for the electrical engineer.
Meter Communication Networks
SUBSTATION
MONITORING
SYSTEMS CAN
PROVIDE THE
OWNER WITH
REAL BENEFITS IN
MONITORING OF
POWER QUALITY
EVENTS,
SUBSTATION
OPERATIONS,
LOADFLOWS,
AND ENERGY
CONSERVATION.
Substation Monitoring
Philosophy
The electrical engineer must establish
and convey the monitoring philosophy for the desired SMCS. Substation
monitoring philosophy may fall into
any of the following categories:
Monitor Meters Only
The lowest cost, least risk alternative
for substation monitoring networks
meters to a monitoring PC. This philosophy provides power quality monitoring, energy monitoring and
reporting at the minimal cost.
Monitor Meters and Breaker Status
By adding breaker status contacts (52a)
to the system design the engineer adds
alarming capabilities that can notify
operators of breaker operations. This is an extremely valuable tool for remote substations. If the meters specified in
this design have digital input capability, the wiring,
alarming and programming can be simplified.
Monitoring Meters, Breakers, and Alarm Points
An SMCS that requires many alarm points will usually
include a programmable logic controller (PLC). The PLC
is the most flexible tool for the gathering of signals from
different sources at multiple voltage levels.
Monitoring of Above Plus Protective Relays
The monitoring of protective relays via a serial link
affords the client the ability to remotely read protective
device trips, trip levels, and conditions prior to trip.
Relay programming may also be possible. The inclusion
of the protective devices in the SMCS is an extremely
powerful option, albeit potentially risky. The primary
function of these relays is the protection of equipment.
Programming errors may cause an inadvertent relay trip
unacceptable to the substation owner. Consider the needs
and the risks.
The control philosophy of the system described herein
disallowed serial links to any device capable of tripping a
circuit breaker. The authors used a PLC digital input connection to the protective relay’s trouble contact to provide a
safe and effective alarming alternative to a serial connection.
Monitor and Control of All Substation Components
Meter Programming/Web Capabilities
Meters exist with integral Web-based communications.
The engineer can communicate with or program a
The most powerful SMCS integrates the use of digital or
analog outputs to control breakers, generators, power factor devices, or load shedding equipment. The substation
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The selection of a robust, open, digital
communication protocol is very important for the ease of implementation and
future maintenance or upgrade of the
SMCS. Modbus RTU RS-485 communications over single or dual twisted
wire pairs will allow the economical
connection of up to 32 meters and was
the choice for this application. Modbus
RTU is a very efficient and simple protocol and typically utilized for wired
system configurations. Being a time
delimited protocol, Modbus is generally not recommended for modem applications. Modbus ASCII is typically
recommended for modem applications but is a less efficient protocol option with each message being roughly
twice the size of a comparable RTU message. Modbus protocol is the most widely used communications choice for
North American industrial facilities.
Serial RS232 communications are not practical for
substation installations due to wire length limitations
(50 ft) and the lower signal levels. It is used typically
between the host computer port and a nearby RS232/RS485 media converter.
Some vendors use proprietary buses for their communications. The meter that uses a proprietary wiring and
communication bus must interface with “foreign” computers or networks via dedicated interface converters and
software. The gear purchased in this case study contained
meters of another manufacturer. This installation of an
SMCS using these buses may lead to higher future costs if
the software becomes obsolete or needs to be upgraded. If
all else is equal in the engineer’s options, the Modbus RS485 protocol is preferable. High-end meters will have
Ethernet communications capability. Ethernet meter
communications are designed in such a way that the
meter with the Ethernet port acts as a hub, which communicates with downstream meters via an internal RS485 serial port. The most commonly used protocol is
Modbus RTU over Ethernet TCP/IP. Ethernet connections using twisted pair copper wiring is referred to as 10
base T or 100 base T (10 or 100 Mb/s speeds).
Web-enabled meter by simply connecting to the meter’s network port
with a PC and Web browser. The
electrical engineer requiring the simplest of metering and monitoring
could communicate with meters connected to the plant Ethernet and
using a Web browser.
25
computers, or database configuration,
depending upon the capabilities of
PRIOR TO
the software to be supplied.
Most industrial firms do not have
ISSUING A BID
full-time electrical operating personnel. This substation monitoring sysSPECIFICATION,
tem was specified to include the use
of separate common alarm contacts,
THE ELECTRICAL
wired to the legacy monitoring sysENGINEER MUST
tem, that would notify the utilities
operator of a substation alarm. That
ASSEMBLE THE
common alarm to a utilities operator
Assembling Requirements
provides a means for contacting onAfter choosing the meters and
SYSTEM
call electricians or engineers in the
devices to monitor, but prior to issuevent of a substation alarm. The qualing a bid specification, the electrical
REQUIREMENTS.
ity specification will include various
engineer must assemble the system
alarm levels, and expected user alert
requirements.
or action for each level.
There are several products on the market that will proIdentification of Needs
The substation monitoring system specification must vide paging capabilities tied to alarms. Text and/or voice
contain a complete list of devices to be monitored and pages and telephone calls can be automatically generated
to notify operators of problems. Some software packages
controlled. The specification should include:
can be programmed to call lists, specific calling times, and
■ complete one-line diagrams
many other combinations.
■ a list of all existing meters and model numbers
■ new meter requirements
■ a list of alarm points and breakers to be monitored
Identification of System Users
■ analog input requirements
The System Manager is the metering expert for the site.
This individual shall be responsible for the generation of
■ pulse input or outputs for utility interfaces
reports, configuration of the meters, and alarms. This
■ switchgear connection points
individual acts as the system owner and is responsible for
■ serial interfaces to third party equipment: RTUs,
setting security levels, access rights and making deciutility meters, etc.
sions on Web access versus client installations. A good
■ operator stations and locations
understanding of graphics packages, power monitoring
■ the location of the central computer or server
and power quality are necessary for the system manager.
■ the physical layout of substation connections
The system manager should attend any classes available
■ the physical layout of proposed/current LAN locations.
This information is most easily compiled via a detailed from the monitoring system vendor.
System Computer Support: This individual is usually an
I/O list in spreadsheet format. In a similar manner, if the
SMCS is to communicate with a third-party serial device, information services (IS) person, experienced in networking, server installation and startup and database manageinclude the details of that serial interface.
The electrical engineer should communicate the long- ment. This person shall also perform database backups and
range growth potential of the SMCS. The authors’ specifi- restoration. This individual does not necessarily possess
cation dictated the growth plan of the SMCS by including the skill sets of the system manager. Identify in the project
detailed one-line diagrams and I/O lists of the legacy sys- scope who will provide the system support.
Technicians operating the substations would acknowledge
tem. With this information the SMCS vendor could size
the system to monitor the entire site distribution system alarms and perhaps generate reports. Identify in the specification what permissions should be granted to technicians.
and its 220-MW load.
Guest Engineers/Users typically are occasional users that
For these new substation installations the authors
reduced installation costs by prewiring the switchgear search for historical data on loads or disturbances. Identito suit the SMCS installation. The switchgear 52a and fy these users in the specification. The substation monirelay alarm contacts were prewired to a central cubicle toring system connected to the plant-wide LAN may be
for the later installation of the SMCS. Likewise, the queried for load flow data or energy reports, directly or
RS-485 serial link was prewired to a central point to via a Web interface.
reduce installation time.
Database Sizing and
Maintenance, Reporting Needs
Identification of Alarms
The detailed I/O list provides a good starting point for The monitoring system will use a database to track and
the identification of the alarming needs of the system. record the historical data. The database used should be a
The detailed specification will also identify any need to commonly available package that supports open queries.
group alarms by some geographical location, produc- It should be a fully compatible structured query language
tion unit, or substation. The grouping and isolation (SQL) database. The most powerful development in dataneeds of the alarm points may require separate PLCs, base tools uses object linking and embedding (OLE) for
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monitoring system described in this
article has not yet utilized the control
capabilities of the software.
In summary, a clearly defined
statement of the substation monitoring philosophy is a critical component of a quality specification. The
philosophy must clearly state which
devices will be monitored or monitored and/or controlled.
26
M
M
M
M
M
52a
52a
52a
52a
M
M
M
PC
Gateway
M
Gateway
M
52a
M
52a
M
52a
52a
52a
52a
63x
86T
PLC
2
3
Multiple location/single PC design with copper or fiberoptic modems.
Meters with PLC Connections.
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process controls (OPC). The use of
apparent power, and reactive
OPC tools “opens up” the exchange of
energy
THE ELECTRICAL
data across multiple historians,
■ voltage history: volts line-to-line
operator interfaces, PLCs and distribor average
ENGINEER MUST
uted control systems. The electrical
■ current loading: phase currents.
engineer should work with the IS supESTABLISH AND
port department in understanding the
System Design and Assembly
databases available.
The system block diagram can be
CONVEY THE
The electrical engineer must decide
started once the electrical engineer has
MONITORING
how the system will be used and
assembled the information described
determine the values to be logged by
in this article. Substation monitoring
SYSTEM
the database and the logging interval.
systems can be as simple as single
This allows the vendor to estimate the
PC/single site solution on up to a
PHILOSOPHY FOR
size of the database and the corremultiple site, client/server system.
sponding hardware and software
THE DESIRED
required to best fit the users’ needs.
Single PC Solution
The electrical engineer must seriously
A single PC solution connects several
SMCS.
answer the question, “What type of
meters to the PC via a serial data link.
reports do I want to view, and what
A minimal of digital I/O is involved,
information do I log now?” and
perhaps only breaker status monitor“What information would I want to retrieve one year ing. This design can act as a building block for multiple
from now?” In this case study, the following data is substation installations. The PC may also act as a storage
logged to the server every 15 min:
buffer for the monitored values.
■ voltage: line- to-line or average
■ phase currents or average current
Single PC, Multiple Substations
■ real power
The single PC, multiple substation design would typically use fiber optics or modems to convey the serial data
■ apparent power
over greater distances. The use of a site-wide LAN would
■ real and reactive energy
also provide the capability to extend the reach of a single
■ peak demand powers.
This data is logged for one year and then archived. Keep PC. This concept will monitor only the minimal amount
the data logging simple and the system will run better of I/O. Figure 2 shows a block design for both a single or
multiple substation design.
and be simpler to maintain.
The specification should identify long-term storage
requirements, methods to purge or archive the data, and Use of a PLC for High I/O Counts
automatic back-up features. Writing data to CD-ROM or For designs that require high I/O counts the PLC protape is an economical solution, but the engineer should vides the most flexible, high density, and cost effecunderstand the vendor’s methods to retrieve the archived tive means to monitor alarm contacts and provide
data. Unless this is clearly specified at the beginning of digital outputs for external alarming and control. The
the job, the engineer may have an inoperative system due PLC will easily accept inputs of different voltage levto a full hard drive within the first year.
els. Plug-in PLC cards are available with integral EthIdentify the reporting needs of the SMCS. Quantify:
ernet switches and fiber optic ports to make the
networking needs of a larger system much simpler.
■ number of reports required
Figure 3 shows a simple PLC installation. The connec■ cost-allocation reports for real energy and peak
tion between the PC and the PLC could be Ethernet,
demand
RS232, or proprietary bus.
■ usage trends: incremental energy, power factor,
27
stations with fiber optic cables provides an excellent
means to maintain high quality communications
between components. If there is a need to connect the
dedicated substation LAN to the plant WAN, install a
router/firewall between the two networks. By the use of
a firewall the system support personnel can block the
entrance of viruses or unauthorized users to the substation LAN. This is especially important if the system
philosophy has protective relays or breaker controls connected to the substation LAN.
The system in this case study utilized a server in
the IS department and a PLC and industrial hardened
client PC in each of the two substations. The PLC’s
used integral Ethernet switches and fiber optics to
connect between the three locations. A router is
installed between the power distribution LAN and the
plant WAN for security. Figure 4 shows such a large
system and represents a simplified diagram of the system installed by the authors.
Large System: Client/Server Architecture
Larger systems are typically installed in a client/server
configuration. The larger systems will require the purchase of a database server. The server stores all the data,
graphics and performs the majority of the work in data
exchange and retrieval. The server should be provided
with redundant hard drives, dual processors, and a large
memory. Enlist the support of the IS department prior
to specifying the server machine. With the use of a
plant wide-area network (WAN) and fiber optics, the
server can be mounted a great distance away from the
industrial substation.
Depending on the architecture chosen, the client PC
may act as only an operator interface, or for more
demanding applications it may act as a buffer to store
and “push” meter data up to the server. One may choose
industrial hardened PCs for installation in the field or
may opt for an office-grade PC at a desk. Each vendor has
their own design philosophy in the use of the field client
PCs. The choice of the client PC is based heavily on data
buffering and environmental considerations.
The large system will utilize an Ethernet network of
copper and fiber optic hardware to connect meters,
PLCs, switches, and operator stations. The most robust
design will include a dedicated Ethernet LAN for power
distribution networking needs. Interconnecting the sub-
28
Router/
Firewall
Engineering
PC
Data
Server
Modem
SMS
LAN
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Plant
WAN
Fiber
Optics
EN
Switch
Client
PC
Fiber
Optic
M
PLC with
Ethernet
Switch
Multiple Vendor Systems
The simplest design uses the meters and software of
the same manufacturer. Most sites however have legacy
meters or systems that the engineer wishes to upgrade
or replace at the minimal of costs. The authors’ firm
had purchased switchgear and meters from one vendor
prior to selecting a suitable substation monitoring system vendor. It was determined later in
the project that the most desirable software package was made
by a different vendor. By using
serial to proprietary bus converters, metered values were easily
conveyed to the software. The
Plant PCs
advanced metering needs however (disturbance monitoring,
Client
waveform capture, etc.) could
PC
not be conveyed through the
proprietary custom interface
converter. The project team
found that the best solution
M
M
M
installed an additional meter at
each main breaker to capture
disturbances for that entire bus.
In this case, the use of a redunLaser
dant meter was more economical
Printer
than attempting to develop custom software to capture disturbance data from a proprietary
bus and meter.
M
M
52a
M
Meter
Interface
52a
M
63x
86
M
Legacy Meters
4
Client/server system with multiple locations.
Monitoring via the Web
A particularly powerful capability
of substation monitoring software
is to display information in Web
page format. This cost-saving
design uses a Web browser to provide the information needs of
occasional users, without the purchase of a client license. Web
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Billing Package: Basic billing and
pages on the company intranet may be
energy usage reports are available in
viewed by any authorized PC in the
WHAT TYPE OF
all packages. However, if special allocorporation. Accounting may monitor
cated bills, tied to fluctuating fossil
and bill customers’ energy consumpREPORTS DO I
fuel costs, are required the owner
tion. Corporate engineering could colmay opt to purchase a more powerful
lect load data on feeders and
WANT TO VIEW,
billing software package add-on.
determine the need for additional
This was not required for the case
loadcenters. Operating units can
AND WHAT
study installation.
determine if there is capacity for addiINFORMATION
Meter Licensing: Some vendors may
tional loads. Utilities operators could
charge a per meter license fee similar
observe alarms and save unneeded
DO I LOG NOW?
to the manner that a DCS vendor
call-ins for off-shift power distribution
charges a per control loop fee. This
technicians.
exposes the owner to additional costs
Security reasons may dictate that
for metering additions.
Web pages only monitor the substaWeb Page Licenses: The Web page options are not includtion instead of controlling it, to avoid risks. License or
“seat” costs for clients on the software specified may be ed in the base system. Identify the Web page costs. The
substantial. Investigate and understand the Web page authors purchased customized Web pages for his system
generation process of the prospective software supplier. A avoiding the purchase of client licenses for utilities operacustom-built Web page that becomes obsolete with the tors and support engineers.
Yearly Maintenance Fees: Plan on major software
first meter addition is a poor economic choice.
It is also possible for advanced meters with integral upgrades in your package over the years ahead. A yearly
Web capabilities to generate Web pages for down- maintenance contract may cover support and product
stream connected devices. Some meters may also be pro- upgrades for a fixed annual fee.
Customer Support Fees: Identify if there is a customer
grammed through a Web interface. Although many of
the Web pages contain very useful information, and are support line, charges for use of customer support and
readily accessible with the SMCS software, the informa- the skill level of that customer support. Some vendors
tion is not retained for a long period of time. The Web- can monitor and host your data and provide power conenabled meter pages do not provide a system wide sultation services and reports that identify areas where
perspective for troubleshooting and analysis of medium savings can be realized.
Training Costs: Factory training is essential to the
to large systems. Therefore, it is the authors’ opinion
that a meter’s integral Web capabilities are best suited understanding of these packages. Choose a vendor who
for monitoring relatively small number of connected has a complete list of courses available for purchase. A
qualified user of the system who has information and
devices not requiring storage of long term data.
reports ready for use achieves the best return on the
investment.
Software: Tieing It All Together
The graphical software package should use computeraided design (CAD) for screen backgrounds with real System Benefits/Payback
time data superimposed. The software should be easy to Electrical costs can be broken down into three main
use, maintainable, reliable, and accessible over the plant areas: 1) energy cost, 2) equipment cost/asset utilizanetwork. The software must be flexible and adaptive as tion, and 3) downtime and lost production. The type of
new applications are discovered and have the ability to electrical cost savings sought will drive the design phiexpand as new substations are installed. Determine if the losophy of the SMCS. A system designed around areas
1) and 2) will often result in a basic monitoring system
software has full OPC capability.
The SMCS software cost will vary depending on the requiring minimal customization and integration. The
rate of return for such a system may be harder to justify
following:
Server License: A single cost for the server license is most to management since utility bill savings will likely be
common. Determine if there is a yearly maintenance fee the sole basis. When systems are designed around all
three areas, the component selection becomes more
associated with the license or upgrade of same.
Client License: This is usually priced in a per concur- important. In addition to power flow information, an
rent user basis. This cost is thousands of dollars per SMCS provides information critical to understanding
seat. The cost is often negotiable during the initial bid system or equipment failures. These advanced systems
process but expensive afterwards. Understand what the provide the necessary information to understand and
vendor defines as a user. The authors purchased three resolve the root cause of problems instead of looking at
just the symptoms or effects.
client licenses.
In the past, plant engineers tried to justify an SMCS
Graphics Package: The most basic of monitoring systems
may display metered values only. Custom graphics, one only on the premises for reconciling and verifying enerline diagrams, or animated screens may require the pur- gy costs and providing operators with real-time data. It
chase of an add-on graphics package. Identify if this is a was hard to identify the rate of return and hence the
system cost or a per seat cost. The authors purchased projects were postponed. However, the keeping of
detailed power outage records, and lost profit opportunities,
graphics packages for each client.
29
IEEE INDUSTRY APPLICATIONS MAGAZINE • MAR|APR 2005 • WWW.IEEE.ORG/IAS
30
the SMCS can be justified on the basis of aiding in incident investigations, eliminating or minimizing electrical disturbances and improving power quality.
Excellent papers [2] and [3] address these justification
issues in deeper detail.
The primary function of the authors’ SMCS is the
monitoring, and alarming of the two new substations,
the 138 kV yard and underground cables. The automatic alarming of all critical points reduces the substation walk-through requirements from daily to a
maximum of once per week. This represents a
US$15,000 yearly cost avoidance. Power quality events
are now captured, logged, and alarmed by the SMCS,
eliminating the need for a dedicated transient recorder
costing US$40,000. Utility check meters have been
installed for monthly energy usage and demand recording. The check energy and demand values correlate
with the utility readings within 0.5%. Historical data
is now captured and held for one year. The legacy system logged for a maximum of 30 days. The installed
serial interface to the legacy meters has provided an
inexpensive upgrade path for meters installed in the
older substations.
An added benefit and payback of this installed SMCS
is the ability of the chemical firm’s power distribution
engineer to connect to the system from his office or
home to analyze problems or alarms. The ability to connect to the system by modem may save technician call
outs and has saved several trips by the SMCS design
engineer to the plant. The SMCS vendor can, with the
owners’ permission, connect to the server for maintenance and troubleshooting.
In many plants paybacks are realized by preventing
disturbances and making the system more robust to
future disturbances. Plant electrical engineers also use
historical data logging, load profiles, and other standard
reports to analyze existing capacity on electrical substations and to avoid unnecessary capital outlays for new
equipment on large projects.
Accurate data and waveform captures from the SMCS
may allow engineers to work together with the local utility to resolve power quality issues, relay problems, and
nuisance electrical faults. Improved communications
with the local utility company tend to exist after the
realization that the customer has high quality disturbance data capable of determining whether the disturbance is outside or inside the facility, the severity and
actual time of the event.
Meters equipped with GPS time synchronization
provide accurate time stamp information within 1 ms
plant wide. With waveforms, high-speed time stamps
and real time values the actual sequence of events and
effects of a fault can be captured and analyzed. The
authors will be installing GPS synchronization to the
site’s advanced meters and integrating the GPS signals
with high speed PLC I/O. Substation and system alarms
will soon be captured and time traceable within 1 ms
across the entire site.
Large paybacks are realized by continuously monitoring and controlling the established peak demand relative
to the present demand. The SMCS can warn operators if
the present load is close to the peak setpoint providing
ample time for switching to an alternate energy source or
shedding load before a higher peak penalty is reached.
The SMCS can provide control components to shed load
based on real time system data. By comparing actual
plant load versus generation capacity, it can shed the
minimum amount of load to maintain the system stability. To date, demand control has not been implemented
on the authors’ site. However, a 1% reduction in the
energy bill on the authors’ site will result in a payback
period of three months.
The SMCS can provide corporate management the ability to obtain real-time aggregate electrical usage, generation and demand costs from other U.S. production
facilities for leveraging utility contracts in the free market.
Conclusion
Substation monitoring systems can provide the owner
with real benefits in monitoring of power quality events,
substation operations, loadflows, and energy conservation. The careful analysis of what is presently available in
the market and the exact needs of the customer is necessary in order to write a quality specification for a substation monitoring system. The assembly of data described
in this article will provide the electrical engineer with a
document to present to the suppliers of meters and substation monitoring hardware and software. The system
installed in the case study is performing well and provides the authors an upgrade path for his legacy metering system.
Acknowledgments
The authors thank Lisa Rush (Square D/Schneider Electric)
for her contributions to this article.
References
[1] IEEE Recommended Practice for Monitoring Electrical Power Quality,
ANSI/IEEE 1159–1995 (R2001).
[2] A.P. Stublen, C.M. Wellman, S.A. Kell, and T.W. Langston, “Justifying and planning an energy monitoring system in an existing plant,” in
IEEE PCIC 1995 Conf. Rec., pp. 13–19 and as “Justifying and planning
an energy monitoring system,” IEEE Ind. Appl. Mag., vol. 3, pp. 54–61,
Mar./Apr. 1997.
[3] K.E. Nicholson P.E., R.L. Doughty, L. Mane, G. Miranda, and
F.D. Pulaski, “Cost effective strategies for industrial electric power
management systems,” in IEEE PCIC 1998 Conf. Rec., pp. 223–233,
and as “Cost effective power management systems,” IEEE Ind. Appl.
Mag., vol. 6, pp. 23–33, Mar./Apr. 2000.
Stephen Pauli (Stephen.Pauli@BayerMaterialScience.com) is
with Bayer MaterialScience in Baytown, Texas. Baldur O.
Krahl and Blane Leuschner are with Square D/Schneider Electric in Houston, Texas. Pauli, Krahl, and Leuschner are Members of the IEEE. This article first appeared in its original form
at the 2003 IEEE/IAS Petroleum and Chemical Industry Technical Committee Conference.