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ELECTRICAL POWER MONITORING AND CONTROL
GE Consumer and Industrial
SECTION 16215
Electrical Power Monitoring and Control
SPECIFIER NOTE This is Parts 1, 2 & 3 of Extended Section 16215 Electrical Power Monitoring and
Control System. Specification is based on a GE PMCS system. The description contained herein is
relatively complete and includes a GE EPM 9650 Power Quality meter. Other meters may be provided by
GE and it is suggested the writer become familiar with the multiple products available as different
metering capabilities may be desirable at different points in the Electrical System.
PART 1 GENERAL
A. The requirements of the Contract, Division 1, and Division 16 apply to work
related to Protection Metering & Control System in this Section.
1.01 PRODUCT OVERVIEW / SUMMARY
A. The Power Management and Control System offering shall provide reliable, upto-date information on the status of important processes and systems to the
system operators. The system shall also provide a valuable backup for
monitoring and control of the system status for diagnostic and forensic
purposes. The Power Management and Control System (PMCS) offering must
have open system architecture. The PMCS shall be a Windows XP or Windows
2003 Server based master control system software. This includes functions
useful to the operation and maintenance of major electrical systems in the
facilities, including, UPS systems, batteries, generators, ATS, paralleling
switchgear, distribution boards, PDU systems, video cameras, fire systems,
security systems, and off site or remote monitoring.
B. The PMCS system includes UPS and apparatus predictive maintenance,
motor/turbine predictive maintenance, energy analysis and cost allocation
software modules.
C. The system Human Machine Interface (HMI) shall be designed for the following
functions:
1. Provide immediate analysis when a power quality event occurs. Used to
correct equipment failures in-house or correlate an internal failure with a
utility event.
2. Provide monitoring data to benchmark power quality levels at each facility
and/or for the total organization.
3. Provide a single database for storing all disturbance monitoring and recording
data that is needed for power quality, reliability, and fault analysis.
4. Provide power quality data to evaluate performance of power conditioning
equipment. Show compliance with specification to include transfer times,
voltage regulation, and harmonic output.
5. Requesting and receiving information from distributed facility Intelligent
Electronic Devices (IEDs) using Modbus RTU IED protocols.
6. Gathering and locally storing historical operation/fault, events with original
IED time stamping preserved. Options can be configured to logically
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combine events, to eliminate duplicate events, or to display the events
grouped by either time/day/month/year or by device.
7. Gathering and locally storing facility fault records and waveforms generated
during the abnormal operation of facility devices.
8. Interfacing with enterprise level Wide Area Network (WAN).
9. Providing access to individual IEDs from either the facility or dial-in remote
locations, using specific IED protocols. Dial-in should be telephone or via
Internet.
10. Provide an information service that can be offered to customers for
evaluation of the system performance and the impact of power quality
variations on their equipment.
11. Provide continuous performance information to Account Managers for
evaluation of customer power quality concerns.
12. Identify internal power quality problems before catastrophic failure. An
example is predicting the failure of a UPS based upon its output harmonics
and unbalance.
13. Provide a platform to support the automated monitoring and maintenance of
the facility
14. Provide reports of power quality performance that can be used to prioritize
system maintenance and capital expenditure plans.
15. Perform automated power quality audits and produce reports using Artificial
Intelligence to pinpointing fault causes and possible preventive measures.
16. Produce summary graphs of CBEMA charts and time plots from the
collected data.
17. The HMI shall have at least 30 standard building protocols available.
1.02 SECTION INCLUDES
A. The Section includes Power Management Control Systems (PMCS) and the
communication network of electrical power circuits as per Contract Documents
B. Power Management Control System (PMCS)
C. Communications network
D. Metering and Protection Devices also called Intelligent Electronic Devices
(IEDs)
1.03 REFERENCES
A. The product description and protection devices in this specification are designed
and manufactured according to latest revision of the following standards (unless
otherwise noted).
1. NEC Article 725 Class II for Power Limited Circuits
2. EIA-485 for RS485 Modbus RTU (Remote Terminal Unit)
3. IEEE 802.3 for Ethernet
1.04 DEFINITIONS
A. Modbus RTU: An industry standard, high-performance network communications
protocol developed by Modicon.
B. Open Protocol: An industry standard protocol that is published and used by
many other manufacturers and is, therefore, non-proprietary.
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C. RS 485 / EIA 485: A physical wiring standard for high speed, noise tolerant
network communication often used with the Modbus RTU protocol.
D. Ethernet: A high performance local area network standard providing the two
lower levels of the ISO/OSI seven-layer reference model, the physical layer and
the data link layer. Use Cat5e cabling for 100MB and Cat6 for 1 GB
communications
E. Ethernet Gateway: A physical device that translates communications protocol to
Ethernet communications protocol.
F. Communications Protocol: A formal set of conventions governing the control of
Inputs and Outputs within the communicating process.
G. Client/Server architecture: A network architecture in which each computer on
the network is either a Client or a Server. Servers are computers dedicated to
acquiring, archiving, and serving data. Clients, also called Viewers, are
computers that present data from one or more Servers to the end user.
H. OPC – OLE for Process Control. OPC is an open connectivity in industrial
automation and the enterprise systems that support industry. Interoperability is
assured through the creation and maintenance of open standards specifications.
I. SCADA: System Control and Data Acquisition
J. LAN: Local Area Network
K. Modbus Concentrator: A physical device that converts data from CommNet
devices to Modbus RTU protocol
L. System Redundancy: Capability of a system to log and serve data to primary and
secondary computer simultaneously and automatically switching over from the
primary to the secondary computer in case of a failure, without losing any data.
1.05 SYSTEM DESCRIPTION
A. Provide all components, software, and systems integration for a complete
operational PMCS as specified.
1. The following devices shall communicate power system values and data via
Modbus RTU connectivity, dry contacts, analog 4-20 ma signals, or a
combination of each to the PMCS system. (Note: See product sections for
specifications of these devices. See drawings for quantities and locations):
a. Automatic Transfer Switches (ATS)
b. Automatic Static Transfer Switches (ASTS)
c. Batteries
d. Generators
e. Generator Paralleling Switchgear
f. Distribution Boards
g. Load Bank
h. Main Switchboards
i. Panel Boards
j. Power Distribution Units
k. Primary Service Switchboards
l. Uninterruptible Power Supplies (UPS)
m. Trip Units
n. Meters/Relays
o. Chillers
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p. ODP Panels
q. Computer Room Air Conditioning (CRAC) Systems
r. Video Channels
s. Fire Alarm
t. Building Management Systems
B. Provide options for a development software package (such that the owner is
licensed to modify the software in the event of future expansion or equipment
modifications) and a runtime only package.
C. The system shall be equipped with a standard Human Machine Interface (HMI) /
Supervisory Control and Data Acquisition (SCADA) software for displaying
data from the power monitoring devices. The following customized graphic
screens shall be provided:
1. Site plan
2. Animated one-line diagrams for each switchgear lineup including breaker
status
3. Tabular data for monitored devices
4. Waveform Capture for supported devices
5. Alarms
6. Trends with four points per monitored device
7. Event log
8. Generator Control Panel (GCP) overview screen - One per GCP.
9. PLC tabular screen
10. UPS tabular data screen
11. PDU tabular data screen
12. Battery Monitor status screen
13. Device communication overview screen
14. Total harmonic distortion (THD) analysis screen
D. The system shall also support the following functions:
1. Cost allocation of monitored devices over the web
2. Customer defined reports
3. Remote dial in capability for remote diagnostics and troubleshooting using a
modem or Internet, and appropriate communications software.
4. Automatic power analysis and report generation for power quality events.
E. WEB access and viewing
F. Built in System Health Monitor to continuously monitor the functionality of the
server and the software associated with the PMCS.
G. The communications network shall consist of a combination of RS-485 Modbus
RTU and Ethernet TCP/IP technology as indicated on the contract drawings. If
another protocol is required, the vendor shall indicate the proprietary protocol
and provide the equipment with gateway devices and/or drivers necessary to
convert to Modbus RTU. Under no circumstances shall a proprietary
protocol be accepted.
H. Where LAN based communications are not available, the equipment vendor will
make the appropriate data available via dry contact discrete signals and 4-20 ma
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analog signals. The PMCS supplier will provide the necessary Input/Output
devices to integrate those signals into the PMCS.
I. The system configuration shall be capable of offering redundant computer
operation.
J. The system shall be IRIG-B time synchronization capable.
K. The PMCS shall be a true Client/Server architecture. The system shall be
capable of viewing (monitoring) critical system parameters from a workstation
other than the server PC. The system shall support two types of remote viewing.
The first type shall be with an individual viewer software license located on a
client PC. The second type shall be with a server based web viewer software
license and a commercially available web browser on the client PC.
1.06 SUBMITTALS
A. Manufacturer shall provide copies of the following documents to the owner for
review and evaluation in accordance with general requirements of Division 1
and Division 16:
B. Functional description of the PMCS including proposed network configuration.
C. Site test plan for the PMCS.
D. Product Data sheets showing compliance with specified PMCS and Application
Modules.
E. The following sample screens (Note: For purpose of submittal documentation,
screens are not required to be job specific. They should be examples similar to
the actual screens to be provided.):
1. Site plan
2. Animated one-line diagrams for a switchgear lineup including breaker status
3. Tabular data for monitored devices
4. Typical Waveform Capture
5. Automated Power Quality Reports
6. Typical Waveform Record Harmonic Analysis
7. Alarms Screen
8. Typical Historical and Real Trend
9. Event log screen
10. System Health Monitor Alarm Screens
11. Generator Control Panel (GCP) overview screen
12. PLC tabular screen
13. UPS tabular data screen
14. PDU tabular data screen
15. Battery Monitor status screen
1.07 OPERATION AND MAINTENANCE MANUAL
A. Manufacturer shall provide copies of installation, operation and maintenance
procedures to the owner for the PMCS and Application Modules.
B. Deliver one copy of the software to the customer simultaneous with the system
hardware and software delivery.
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C. Deliver copies of the system instruction manuals in conjunction with the training
requirements of this section.
1.08 QUALITY ASSURANCE (QUALIFICATIONS)
A. Manufacturer shall be able to demonstrate experience and expertise in the
manufacture and assembly of electrical distribution systems and PMCS
software.
B. The PMCS vendor shall provide a full time telephone technical help center for
customers.
1.09 FACTORY ACCEPTANCE (TESTING)
A. System shall be 100% tested through simulation of Modbus RTU and Modbus
over IP before installation at the owner’s site.
1.10 DELIVERY, STORAGE, AND HANDLING
A. Deliver, store, protect, and handle products in accordance with recommended
practices listed in manufacturer’s Installation and Maintenance Manuals.
B. Deliver one copy of the software and copies of system instruction manuals on
CD ROM
C. Inspect and report concealed damage to carrier within specified time.
1.11 WARRANTY
A. Manufacturer warranty for the PMCS shall be 1 year from date of installation or
18 months from date of purchase, whichever occurs first.
PART 2 PRODUCTS
2.01 MANUFACTURER
A. General Electric Company products have been used as the basis for design.
Other manufacturers’ products of equivalent quality and operating features may
be acceptable, at the Engineer’s discretion; if they comply with all requirements
specified or indicated in the Contract documents. All component parts should be
based on open communication protocols and standards so those components
from different manufacturers can be combined to build an integrated Power
Management Control System (PMCS).
2.01 POWER QUALITY METER CHARACTERISTICS (EPM 9650)
A. Power Quality meters shall continuously monitor the three-phase, WYE or Delta
power system.
B. Power meter shall be UL listed, MV 90 compatible, multi-function 3-phase
solid-state unit with ability to continuously monitor the three-phase, WYE or
Delta power system. Meter shall have a four-year warranty.
C. The meter shall have four (4) independent voltage inputs and four (4)
independent current inputs of the stated capacity. Voltage input shall exceed
IEEE 37.90.1. Current input shall be rated for 5 amps with a continuous input
capability of 10 amps. Current inputs shall be solid U-Bolt stud inputs with a 10
second over-current rating of 100 amps and a 1-second over-current rating of
300 amps.
D. Power meter shall measure and report the following quantities at a minimum:
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1. Voltage, both phase to neutral and phase to phase, for all three phases;
Auxiliary voltage; Phase angles for each voltage relative to each other.
2. Current, phase A, B, C, N-measured, and N-calculated; Phase angles for each
current relative to voltages.
3. Watts (total and per phase), VARs (total and per phase), VA (total and per
phase), Power Factor (total and per phase) and Frequency
4. Accumulated Watt-hr, VA-hr, and VAR-hr.
5. Power demand shall be calculated using four (4) different averaging methods:
Thermal Average, Fixed Window Average, Sliding Window Average, and
Predicted Average. Values for all averaging intervals must be available
simultaneously.
6. Power meter shall provide updates of all voltage and current readings at
intervals of 1 cycle, 50 milliseconds, and 1 second. Readings shall be
available for both metering and control. All specified readings shall be made
available via the RS-485 ports over the Modbus as well as Ethernet.
7. Power meter shall provide time-stamped maximum and minimum readings
for every measured parameter.
8. Power meter shall provide coincident VAR readings for all maximum Watt
readings.
E. Power meter shall provide the following accuracies:
1. Power meter shall meet ANSI C12.20 and IEC 687 accuracy requirements.
2. Voltage accuracy shall be 0.01% or better for the 1-second readings
3. Current accuracy shall be 0.025% or better for the 1-second readings.
4. Power and energy accuracy shall be 0.04% or better at unity PF
5. Frequency accuracy shall be 0.001 Hz or better.
F. Power meter shall provide multiple configurable digital communication ports and
support multiple open protocols.
G. Power meter shall be fully web based and should be able to transmit its
measured data over the web using customer’s Local Area Network. Data shall
be accessible at any location with Web connection through the use of standard
Web Browser. No additional software shall be required to read data.
H. Power meters shall also be capable of acting as web host for the meters/trip units
etc connected to the meter. Power meter shall make the measured data from the
connected devices (up to eight) available over the web.
I. Meter shall have an Ethernet port and a 56K internal modem as an available
option.
J. Meter shall offer communications using both Modbus and DNP 3.0 open
protocols simultaneously as standard configurations. All instantaneous data,
logged data, event data, power quality analysis and waveform information shall
be available using these open protocols.
K. Meter shall include four (4) independent, digital communication ports. Each port
shall be RS-485 architecture. Port 1 shall be user selectable as either RS232 or
RS-485.
L. Power meter shall provide sequence of events capture and recording.
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M. Meter shall have at least eight high-speed status inputs for capturing external
events with one millisecond resolution, monitored at a user set rate of 1- 8
samples per millisecond. All changes in status shall be time stamped and stored.
N. High-speed status inputs shall be able to trigger waveform recording to the
waveform log.
O. Power meter shall provide a separate IRIG-B input for time synchronizing to
GPS time signal.
P. Power meter shall provide external display(s), up to 4, to accommodate access to
readings locally and/or up to 4000 feet remotely. Display(s) shall be LCD
Touch-Screen and/or LED Display.
Q. The LCD Display shall display:
1. Time of Use Readings
2. Real-Time Readings
3. Phasor Diagrams
4. Harmonic Spectrum (to the 127th order)
5. Real-Time Waveforms (all channels)
6. Up to 8 different meters simultaneously
7. Capable of interfacing with up to 168 EPM 9650 meters by addressing
functions
R. Power meter shall be equipped with 4MB non-volatile RAM for recording logs
and programming information. In the event of loss of control power, data stored
in memory shall be retained for at least 10 years. Meter shall store historical
trending data, power quality data and waveform recordings in memory
S. The power meter shall sample waveform at user configurable rates of 16 to 512
samples per 60 Hz cycle. All voltage and current readings shall be recorded
using a 16-bit A/D converter. Power meter shall measure harmonics up to the
th
255 order for each voltage and current. Real-time harmonics are resolved to the
th
128 for all voltages and currents.
T. Power meter shall capture, record and date/time stamp up to 1024 CBEMA
quality events.
U. Meter shall hold at least 96 seconds of waveform recording in non-volatile
memory. Each record shall be a minimum of 8 cycles in duration at the highest
sample rate or 64 cycles in duration at the lowest sample rate.
V. Waveforms shall be recorded with time resolution to within one millisecond.
W. A waveform record shall be taken whenever the RMS value of voltage or
current exceeds user-set limits.
X. Power meter shall have expandable external auxiliary I/O capability. This
capability shall allow the power meter to operate as an RTU for control and data
acquisition.
Y. Power meter shall be appropriately constructed to provide long life in abusive
physical and electrical environments. The meter shall operate successfully
between -40C to +70C.
Z. Power meter shall be General Electric / model: EPM9650 with 4 Meg memory.
2.02 ELECTRONIC TRIP UNITS CHARACTERISTICS
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A. Each specified circuit breaker shall have an electronic trip unit that will display
and optionally communicate the following information to an operator or to the
PMCS.
B. Provide the following breaker/trip unit information to the PMCS network:
1. Breaker frame size and trip unit options.
2. Breaker sensor rating.
3. Rating plug.
4. Breaker status information.
5. Type of last trip (overload, short circuit, ground fault)
6. Breaker trip counters (Inst., short time, long time, ground fault)
7. Trip unit setup
C. Provide the following metering information:
1. RMS current per phase
2. RMS voltage (line to line and line to neutral)
3. Real, reactive and apparent power.
4. Power factor
5. Frequency
2.03 GENERATOR PROTECTIVE RELAY CHARACTERISTICS
A. Each generator will be protected by a generator protection relay similar to the
GE Multilin SR 489 relay. This relay will be able to communicate status and
electrical power information to the PMCS system using Modbus RTU protocol
communications port. All measured quantities can be viewed on the front panel
display, through the communication ports or through one of the 4 optional
analog outputs. As a minimum the following information can be monitored or
viewed:
1. Generator current per phase
2. Generator voltage
3. Generator Power: kW, Kvar, kVA
4. Energy use MWh Mvarh
5. Power factor,
6. Demand and peak demand for current and power (kW, kvar, kVA)
7. Frequency
8. 4 each optional analog input
9. Generator temperature, (12 each RTD inputs)
10. Event Recorder. Capture and store the 40 events, recording time, date, and
cause.
11. Waveform Capture
2.04 UPS CHARACTERISTICS
A. Each UPS will provide information to the PMCS either through a Modbus RTU
communications port or dry contact discrete signals and 4-20 ma analog signals.
As a minimum the following information can be monitored or viewed:
1. UPS bypass volts (line-line, all phases)
2. UPS critical bus voltage (Line-line & line-neutral, all phases)
3. UPS critical bus current (all phases)
4. UPS critical bus frequency
5. UPS critical bus KVA
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6. UPS critical bus KW
7. Thirty-two (32) UPS status points
2.05 PDU CHARACTERISTICS
A. Each PDU will provide information to the PMCS either through a Modbus RTU
communications port or dry contact discrete signals and 4-20 ma analog signals.
As a minimum the following information can be monitored or viewed:
1. PDU input volts (line-line, all phases)
2. PDU output volts (Line-line & line-neutral, all phases)
3. PDU output current (all phases)
4. PDU output frequency
5. PDU output KVA
6. PDU output KW
7. Sixteen (16) PDU status points
2.06 PMCS NETWORK
A. The communications layer shall be designed to collect data over many
topographies including modem, Ethernet, Internet, etc. The communications
software shall support both solicited and unsolicited data input from Intelligent
Electronic Devices. Software for identifying and adding new monitors to the
system shall be included.
B. PMCS Ethernet network should allow the owner the capability to program and
troubleshoot PLC’s and other IED devices over the network.
C. Ethernet switches shall be managed, industrial hardened switches using the
appropriate cable to handle bandwidth and speed in the case of copper and for
fiber optics.
2.07 PMCS INTERFACE TO BUILDING MANAGEMENT SYSTEMS (BMS)
A. PMCS shall be built on a platform that can support the capabilities to be a full
Building Management System, with capabilities of climate/temperature control,
video surveillance, fire and security alarm system, and lighting control.
B. The high-speed network utilized by the PMCS system shall permit easy interface
with other the Building Management Systems (BMS). Data located in the power
monitoring devices and PLC registers, and associated inputs/outputs shall be
made available to the BMS vendor via the PMCS host computer. Data from the
PMCS may be accessed using OPC or ODBC technology, as well as DDE
legacy technology.
C. Hardware and software required by a BMS to retrieve data from the PMCS data
highway shall be the responsibility of the BMS vendor. PMCS supplier shall
provide all required system output configuration required for the BMS vendor to
read information.
2.08 PMCS SOFTWARE DESCRIPTION
A. The PMCS shall be supplied with user-friendly application software suitable for
operation on personal computer workstations. The workstations shall serve as
central control stations by monitoring the devices in the system, recording
events, indicating alarm conditions, and displaying and logging device data.
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2.09 DATA COLLECTION SOFTWARE
A. The data collection software will be a multi-threaded application to allow for the
simultaneous collection of data from multiple monitors.
2.10 DATA COLLECTION
A. The software will collect all data recorded by the IED’s. This will involve
retrieving data from the various stored logs to include historical or trend logs,
power quality logs and waveform logs. Each meter location shall have its own
data collection frequency. The power quality meter and data collection
configuration information shall be stored in a relational database. Error
checking will be used to verify data integrity. All data will be stored in a comma
separated file format.
2.11 DATABASE
A. The database shall be an open architecture ODBC compliant database for the
storage of all measurement data. The software and database schema shall be
compatible with ODBC compliant database engines to include SQL Server,
Oracle, and Access.
B. Self-documenting, tagged structures shall not be acceptable.
C. The software will include an API for the database.
2.12 TIME SYNCHRONIZATION
A. The system data collection layer shall use a GMT standard to account for time
zones and time changes. The collected data will use the time stamp of the
monitor itself and will not be adjusted by the System. The ability to incorporate
devices that can be time synchronized by the PC clock or an IRIG-B signal shall
be available. The System shall be capable of synchronizing the monitor clocks
with a degree of accuracy dependent upon the communications topography
using Internet based time synchronization services.
2.13 ALARM - EVENT NOTIFICATION
A. The system shall provide a high level of flexibility to alarm and notify personnel
when a user-defined event has occurred. For each monitor site, the ability shall
be provided to select an “event parameter” a high and low limit, and an
“action”. The Bidder shall provide details of the proposed system’s capabilities
or make recommendations of the options available to provide this capability.
B. The system shall accommodate a unique text message defined by the user to
describe the alarm condition and the monitor. Upon alarm, one or more
designated people will be paged and/or emailed with the text message. The
system should accommodate numeric and alphanumeric pagers. All alarms will
be recorded in an alarm log. All software required to do paging must be
included.
C. The system shall also provide for automatic report generation triggered by an
alarm condition. All report generated by the system shall be available to be
triggered by an alarm condition.
D. The system shall provide a separate Event log and viewer, allowing the user to
sort the events by time stamps, event type, etc. The event log file shall be
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capable of holding at least 1,000 events, the date/time of the event, and a
descriptive text.
2.14 GRAPHICAL USER INTERFACE
A. Software shall be provided with graphical interface to view the archived data,
both tabular and waveforms. Multiple waveform events representing a
continuous waveform should be appended and displayed as a single multi-cycle
waveform event.
B. The ability to produce summary graphs of CBEMA charts and time plots shall be
provided with the ability to jump to specific events of interest. The specific
charts required include CBEMA, ITIC, Sag Frequency Distribution, Harmonic
Distribution, and time plots for each parameter measurement by the monitor to
include energy, demand, PF, VARS, VA, THD, W, and unbalance.
C. The charting and graphing software shall not be device dependent. It shall be
able to provide charting and graphing of all available power monitors available
today as well as those that will be introduced in the future. It shall also be
capable of plotting and charting non-power monitor kinds of data to include
analog type data (temperature, flow, etc., as well as binary information (breaker
open closed data).
D. For each cycle of waveform data displayed, the software will compute and
display simultaneously power parameters to include W, VA, VARS, THD, any
single harmonic, V or A unbalance, Vrms, Arms, and PF.
2.15 COMPUTER HEALTH MONITORING SOFTWARE
A. Computer Health monitoring software shall continuously monitor the
functioning of the computer as well as the related system software. In case of a
problem, the software shall automatically generate alarm for predictive as well
as diagnostic maintenance.
2.16 INTELLIGENT ASSISTANCE Power Quality ANALYSIS SOFTWARE
A. Software shall perform automated power quality audits and produce reports
using Artificial Intelligence to pin point fault causes and possible preventive
measures The software shall rank each recorded event in terms of its severity
i.e. its potential destructive impact on sensitive electronic loads. It shall also
determine the direction of the source of the disturbance as upstream or
downstream from the monitoring location. The software shall attempt to
determine the specific source of the disturbance, the equipment it may affect,
and offer a generally accepted solution for the problem.
B. Software shall be able automatically conduct energy audits and send reports in
simple format through the email or fax. The output of the analysis shall be
automatically generated report that clearly explains the results of the analysis in
text and graphics.
C. WEB CAPABILITIES
1.The PMCS system shall be web enabled to allow clients and Customer
engineers to view reports generated by the system and to allow Customer
engineers to have full access to the monitor data. The web software will be
provided by the supplier and have the following features:
a. Graphics including Flash components as agreed by Customer.
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b. Database driven security levels allowing access to web reports and data.
c. Ability to determine available reports and to offer the user only those
available reports.
d. Links as determined by Customer
2.17 PMCS SOFTWARE
A. PMCS Software package shall include:
B. Operate in multitasking, multi-user environment. Windows 2K compliant
C. Log PMCS data to a hard disk at user-specified intervals and provide exporting
functions to allow usage of the logged data by other software products. Be able
to export data to other Microsoft ® Windows applications via the OPC server or
Dynamic Data Exchange (DDE) technology, comma separated variable (CSV)
format or COMTRADE format.
D. Manage Alarm Function. Annunciates and logs alarm messages from discrete
input and controls outputs, according to programmable security access. Provides
visual, audible and/or required acknowledgment.
E. Report the status inputs and outputs, transformer temperature monitor relays
(fan, alarm, and emergency shutdown relays), electronic trip unit status, status
I/O associated with programmable logic controllers, etc.
F. Include harmonic information in the graphic waveform displays for power
quality meters including total harmonic distortion (THD), RMS magnitudes,
peak values, crest factors (CF), magnitudes of the individual harmonics,
telephone interference factor (TIF), etc. Plot and apply fast Fourier analysis to
ac voltage and current waveforms, captured by network devices, for accurate
viewing of harmonic content up to the 128th order;
G. Standard reports to simplify routine printouts of various data formats. Reports
shall contain information as described within this specification.
H. Password-protected.
I. In conjunction with a programmable logic controller, provide supervisory
control as indicated above under “System Description”;
J. Be able to interface to Building Management System or other devices to expand
the role of the PMCS system
K. Systems shall be capable of providing context sensitive on-line help.
L. Define and initiates load-shedding schemes based on time schedules and/or in
response to set points.
M. Software shall contain interactive color-graphics as follows:
1. One-Line electrical distribution drawing as shown on contract documents.
2. Accurate graphical representation of each monitored device.
3. Define and view trends for any of the parameters available via the metering
devices on the network.
4. Alarms sorted by date, time, device type or type of alarm.
5. View captured and recorded waveforms.
6. Provide capabilities for Annunciator panel creation.
7. Custom screens and reports.
8. Diagnostic system analysis reports.
2.18 COST ALLOCATION MODULE
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A. Cost allocation module to provide the following:
1. WEB based solutions capable of standalone operation.
2. Pinpoint when and by whom peak demands are set.
3. Find out how much energy individual tenants or departments are using.
4. Allocate utility costs per building, floor, shift, production line, process step or
department.
5. Benchmark departments on energy savings and motivate them to attain
energy savings goals.
6.Create virtual meters and define cost centers.
7.Provide data in SQL database.
8. Store data in CSV format.
9. Allow for aggregation of numerous sites at common location.
10. Import or generate real-time pricing structures.
11. Manage up to 50 different rate structures at the same time.
2.19 COMPUTER HARDWARE REQUIREMETNS FOR RUNNING SOFTWARE
A. The PMCS system shall have a minimum of one Host Computer (PC). All
computers supplied shall be complete with Application Software and license as
specified. The computers shall be pre-configured with all software and
configuration files by the vendor and ready to connect and operate when
delivered to the job site.
B. Host Computer / Server Computer / Mission Critical Computer shall serve as
central control station by monitoring the devices in the system, recording
events, indicating alarm conditions, and displaying and logging device data.
This Server/Mission Critical Computer shall have the following minimum
requirements:
1. Processor: Dual Core Intel Xeon Processor, 2.33GHz or faster,
2. Additional Processor (when required): dual core Intel Xeon processor,
2.33GHz or faster.
3. Memory: 2GB RAM (additional memory if required by the HMI vendor)
4. Operating System: Windows Server 2003R2 or Windows XP Professional –
SP25.
6. Primary Hard Drive: 80GB (optional 146GB hard drive)
9. CD/DVD Drive: 24X IDE CD-RW/DVD ROM drive
10. Mouse: optical two-button mouse, USB
11. Network Adapter: Intel PRO 1000PT dual port server adapter
12. Power Supply: Energy Smart redundant power supply with straight cord
C. Viewer Computer (when required) shall meet the following requirements:
1. Processor: Intel Pentium Processor 1GHz or more
2. Memory: 512GB RAM (additional memory if required by the HMI vendor)
3. Operating System: Genuine Windows XP Professional, SP25.
or Windows Server 2003R2
4. Primary Hard Drive: 80GB (require minimum available space 700Mb on
system drive and 40GB available space on installation drive.
5. CD/DVD Drive: 24X CDRW/DVD Combo
6. Mouse: optical two-button mouse, USB
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7. Network Adapter: Intel PRO 1000PT dual port server adapter
8. Video capable of displaying 16-bit 1024 x 768 resolution minimum
(1280x1024 resolution recommended)
D. Printer:
1. Network capable laser printer
2. Parallel port line printer for alarms
PART 3 EXECUTION
3.01 INSTALLATION
A. Coordinate with the manufacturer and electrical contractors to insure all junction
boxes, repeaters and other appurtenances necessary for a complete, operational
PMCS system and network are provided.
B. All power quality meters, electronic trip units, transformer temperature monitors,
motor protection devices, shall be installed by the manufacturer within the
supplied electrical equipment for all circuits as indicated by the project
drawings.
C. All control power, CT, PT, and data communications wire shall be factory-wired
and harnessed within the equipment enclosure.
D. Where external circuit connections are required, terminal blocks shall be
provided and the manufacturer's drawings must clearly identify the
interconnection requirements, including wire type to be used. Splices within
cabinets shall not be accepted.
3.02 ON-SITE PMCS START-UP
A. Install all HMI software, graphic screens, system configuration information and
point databases on the host computer in accordance with PMCS Users Guide.
The manufacturer shall provide [] days (including travel and living) of on site
startup assistance for system setup and operation of PMCS system.
B. Start-up shall include a complete working demonstration of the PMCS with
control and monitoring of each device in the system and simulation of all
possible operating conditions, which may be encountered.
C. After completion of the startup, a customer signoff document will be generated
and a closeout meeting will occur.
3.03 ON-SITE PMCS TRAINING
A. The project bid shall include [] days of training including travel and living.
B. Training shall include any documentation and hands-on exercises necessary to
enable electrical operations personnel to assume full operating responsibility for
the PMCS after completion of the training period.
3.04 PMCS SERVICE AGREEMENT OPTIONS:
A. The PMCS supplier shall provide the following Service Agreement Options.
The customer shall have the flexibility to select from the below listed service
offerings.
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1. One (1) or Three (3) year service support to include software upgrades,
Technical Specialist phone support, System Operational status reviews
through remote system access.
2. One (1) year System Audits and consulting services
3. Technical Phone Support from PMCS system specialists (40 hours or more
per year)
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