GEK-113631C - GE Digital Energy

GEK-113631C - GE Digital Energy
GE
Digital Energy
Multilin™ EPM 9900
Electronic Meter
Instruction Manual
Software Revision: 1.0x
Manual P/N: 1601- 0036-A4
Manual Order Code: GEK-113631C
LISTED
*1601-0036-A4*
Copyright © 2014 GE Multilin Inc. All rights reserved.
Multilin™ EPM 9900 Electronic Meter Instruction Manual for product revision 1.0x.
The contents of this manual are the property of GE Multilin Inc. This documentation is
furnished on license and may not be reproduced in whole or in part without the permission
of GE Multilin. The manual is for informational use only and is subject to change without
notice.
Part number: 1601-0036-A4 (December 2014)
Note
GENERAL SAFETY PRECAUTIONS - EPM 9900
• Failure to observe and follow the instructions provided in the equipment manual(s)
could cause irreversible damage to the equipment and could lead to property
damage, personal injury and/or death.
• Before attempting to use the equipment, it is important that all danger and
caution indicators are reviewed.
• If the equipment is used in a manner not specified by the manufacturer or
functions abnormally, proceed with caution. Otherwise, the protection provided by
the equipment may be impaired and can result in Impaired operation and injury.
• Caution: Hazardous voltages can cause shock, burns or death.
• Installation/service personnel must be familiar with general device test practices,
electrical awareness and safety precautions must be followed.
• Before performing visual inspections, tests, or periodic maintenance on this device
or associated circuits, isolate or disconnect all hazardous live circuits and sources
of electric power.
• Failure to shut equipment off prior to removing the power connections could
expose you to dangerous voltages causing injury or death.
• All recommended equipment that should be grounded and must have a reliable
and un-compromised grounding path for safety purposes, protection against
electromagnetic interference and proper device operation.
• Equipment grounds should be bonded together and connected to the facility’s
main ground system for primary power.
• Keep all ground leads as short as possible.
• At all times, equipment ground terminal must be grounded during device
operation and service.
• In addition to the safety precautions mentioned all electrical connections made
must respect the applicable local jurisdiction electrical code.
• Before working on CTs, they must be short-circuited.
• To be certified for revenue metering, power providers and utility companies must
verify that the billing energy meter performs to the stated accuracy. To confirm the
meter’s performance and calibration, power providers use field test standards to
ensure that the unit’s energy measurements are correct.
This product cannot be disposed of as unsorted municipal waste in the European
Union. For proper recycling return this product to your supplier or a designated
collection point. For more information go to www.recyclethis.info.
Safety words and definitions
The following symbols used in this document indicate the following conditions
Indicates a hazardous situation which, if not avoided, will result in death or serious
injury.
Note
Indicates a hazardous situation which, if not avoided, could result in death or serious
injury.
Note
Indicates a hazardous situation which, if not avoided, could result in minor or
moderate injury.
Note
Indicates practices not related to personal injury.
Note
Indicates general information and practices, including operational information, that
are not related to personal injury.
Note
NOTE
For further assistance
For product support, contact the information and call center as follows:
GE Digital Energy
650 Markland Street
Markham, Ontario
Canada L6C 0M1
Worldwide telephone: +1 905 927 7070
Europe/Middle East/Africa telephone: +34 94 485 88 54
North America toll-free: 1 800 547 8629
Fax: +1 905 927 5098
Worldwide e-mail: [email protected]
Europe e-mail: [email protected]
Website: http://www.gedigitalenergy.com/multilin
Warranty
For products shipped as of 1 October 2013, GE Digital Energy warrants most of its GE
manufactured products for 10 years. For warranty details including any limitations and
disclaimers, see the GE Digital Energy Terms and Conditions at
https://www.gedigitalenergy.com/multilin/warranty.htm
For products shipped before 1 October 2013, the standard 24-month warranty applies.
GLOSSARY
0.2 Second Values:
These values are the RMS values of the indicated quantity as calculated after
approximately 200 milliseconds (3 cycles) of sampling.
1- Second Values:
These values are the RMS values of the indicated quantity as calculated after one
second (60 cycles) of sampling.
Alarm:
An event or condition in a meter that can cause a trigger or call-back to occur.
Annunciator:
A short label that identifies particular quantities or values displayed, for example kWh.
Average (Current):
When applied to current values (Amps) the average is a calculated value that
corresponds to the thermal average over a specified time interval.
The interval is specified by the user in the meter profile. The interval is typically 15
minutes. So, Average Amps is the thermal average of Amps over the previous 15minute interval. The thermal average rises to 90% of the actual value in each time
interval. For example, if a constant 100 Amp load is applied, the thermal average will
indicate 90 amps after one time interval, 99 amps after two time intervals and 99.9
amps after three time intervals.
Average (Input Pulse Accumulations):
When applied to Input Pulse Accumulations, the “Average” refers to the block (fixed)
window average value of the input pulses.
Average (Power):
When applied to power values (Watts, VARs, VA), the average is a calculated value that
corresponds to the thermal average over a specified time interval.
The interval is specified by the user in the meter profile. The interval is typically 15
minutes. So, the Average Watts is the thermal average of Watts over the previous 15minute interval. The thermal average rises to 90% of the actual value in each time
interval. For example, if a constant 100 kW load is applied, the thermal average will
indicate 90 kW after one time interval, 99 kW after two time intervals and 99.9 kW
after three time intervals.
Bit:
A unit of computer information equivalent to the result of a choice between two
alternatives (Yes/No, On/Off, for example).
Or, the physical representation of a bit by an electrical pulse whose presence or
absence indicates data.
Binary:
Relating to a system of numbers having 2 as its base (digits 0 and 1).
Block Window Avg. (Power):
The Block (Fixed) Window Average is the average power calculated over a user-set
time interval, typically 15 minutes. This calculated average corresponds to the
demand calculations performed by most electric utilities in monitoring user power
demand. (See Rolling Window Average.)
Byte:
A group of 8 binary digits processed as a unit by a computer (or device) and used
especially to represent an alphanumeric character.
CBEMA Curve:
A voltage quality curve established originally by the Computer Business Equipment
Manufacturers Association. The CBEMA Curve defines voltage disturbances that could
cause malfunction or damage in microprocessor devices. The curve is characterized
by voltage magnitude and the duration which the voltage is outside of tolerance. (See
ITIC Curve.)
Channel:
The storage of a single value in each interval in a load profile.
Cold Load Pickup:
This value is the delay from the time control power is restored to the time when the
user wants to resume demand accumulation.
CRC Field:
Cyclic Redundancy Check Field (Modbus communication) is an error checksum
calculation that enables a Slave device to determine if a request packet from a Master
device has been corrupted during transmission. If the calculated value does not
match the value in the request packet, the Slave ignores the request.
CT (Current) Ratio:
A Current Transformer Ratio is used to scale the value of the current from a secondary
value up to the primary side of an instrument transformer.
Cumulative Demand:
The sum of the previous billing period maximum demand readings at the time of
billing period reset. The maximum demand for the most recent billing period is added
to the previously accumulated total of the maximum demands.
Demand:
The average value of power or a similar quantity over a specified period of time.
Demand Interval:
A specified time over which demand is calculated.
Display:
User-configurable visual indication of data in a meter.
DNP 3.0:
A robust, non-proprietary protocol based on existing open standards. DNP 3.0 is used
to operate between various systems in electric and other utility industries and SCADA
networks.
EEPROM:
Nonvolatile memory; Electrically Erasable Programmable Read Only Memory that
retains its data during a power outage without need for a battery. Also refers to
meter’s FLASH memory.
Energy Register:
Programmable record that monitors any energy quantity. Example: Watt-hours, VARhours, VA-hours.
Ethernet:
A type of LAN network connection that connects two or more devices on a common
communi-cations backbone. An Ethernet LAN consists of at least one hub device (the
network backbone) with multiple devices connected to it in a star configuration. The
most common versions of Ethernet in use are 10BaseT and 100BaseT as defined in
IEEE 802.3 standards. However, several other versions of Ethernet are also available.
Flicker:
Flicker is the sensation that is experienced by the human visual system when it is
subjected to changes occurring in the illumination intensity of light sources. IEC
61000-4-15 and former IEC 868 describe the methods used to determine Flicker
severity.
Harmonics:
Measuring values of the fundamental current and voltage and percent of the
fundamental.
I2T Threshold:
Data will not accumulate until current reaches programmed level.
Integer:
Any of the natural numbers, the negatives of those numbers, or zero.
Invalid Register:
In the EPM 9900 meter’s Modbus Map there are gaps between Registers. For example,
the next Register after 08320 is 34817. Any unmapped Register stores no information
and is said to be invalid.
ITIC Curve:
An updated version of the CBEMA Curve that reflects further study into the
performance of microprocessor devices. The curve consists of a series of steps but still
defines combinations of voltage magnitude and duration that will cause malfunction
or damage.
Ke:
kWh per pulse; i.e. the energy.
kWh:
Kilowatt hours; kW x demand interval in hours.
KYZ Output:
Output where the rate of changes between 1 and 0 reflects the magnitude of a
metered quantity.
LCD:
Liquid Crystal Display.
LED:
Light Emitting Diode.
Maximum Demand:
The largest demand calculated during any interval over a billing period.
Modbus ASCII:
Alternate version of the Modbus protocol that utilizes a different data transfer format.
This version is not dependent upon strict timing, as is the RTU version. This is the best
choice for telecommunications applications (via modems).
Modbus RTU:
The most common form of Modbus protocol. Modbus RTU is an open protocol spoken
by many field devices to enable devices from multiple vendors to communicate in a
common language. Data is transmitted in a timed binary format, providing increased
throughput and therefore, increased performance.
Network:
A communications connection between two or more devices to enable those devices
to send to and receive data from one another. In most applications, the network is
either a serial type or a LAN type.
NVRAM:
Nonvolatile Random Access Memory: able to keep the stored values in memory even
during the loss of circuit or control power. High speed NVRAM is used in the EPM 9900
meter to gather measured information and to insure that no information is lost.
Optical Port:
A port that facilitates infrared communication with a meter. Using an ANSI C12.13
Type II magnetic optical communications coupler and an RS232 cable from the
coupler to a PC, the meter can be programmed with GE Communicator software.
Packet:
A short fixed-length section of data that is transmitted as a unit. Example: a serial
string of 8-bit bytes.
Percent (%) THD:
Percent Total Harmonic Distortion. (See THD.)
Protocol:
A language that is spoken between two or more devices connected on a network.
PT Ratio:
Potential Transformer Ratio used to scale the value of the voltage to the primary side
of an instrument transformer. Also referred to as VT Ratio.
Pulse:
The closing and opening of the circuit of a two-wire pulse system or the alternate
closing and opening of one side and then the other of a three-wire system (which is
equal to two pulses).
Q Readings:
Q is the quantity obtained by lagging the applied voltage to a wattmeter by 60
degrees. Values are displayed on the Uncompensated Power and Q Readings screen.
Quadrant (Programmable Values and Factors on the EPM 9900 meter):
Watt and VAR flow is typically represented using an X-Y coordinate system. The four
corners of the X-Y plane are referred to as quadrants. Most power applications label
the right hand corner as the first quadrant and number the remaining quadrants in a
counter-clockwise rotation. Following are the positions of the quadrants: 1st - upper
right, 2nd - upper left, 3rd - lower left and 4th - lower right.
Power flow is generally positive in quadrants 1 and 4.
VAR flow is positive in quadrants 1 and 2. The most common load conditions are:
Quadrant 1 - power flow positive, VAR flow positive, inductive load, lagging or positive
power factor; Quadrant 2 - power flow negative, VAR flow positive, capacitive load,
leading or negative power factor.
Register:
An entry or record that stores a small amount of data.
Register Rollover:
A point at which a Register reaches its maximum value and rolls over to zero.
Reset:
Logs are cleared or new (or default) values are sent to counters or timers.
Rolling Window Average (Power):
The Rolling (Sliding) Window Average is the average power calculated over a user-set
time interval that is derived from a specified number of sub-intervals, each of a
specified time. For example, the average is calculated over a 15-minute interval by
calculating the sum of the average of three consecutive 5-minute intervals. This
demand calculation methodology has been adopted by several utilities to prevent
customer manipulation of kW demand by simply spreading peak demand across two
intervals.
RS232:
A type of serial network connection that connects two devices to enable
communication between the devices. An RS232 connection connects only two points.
Distance between devices is typically limited to fairly short runs.
Current standards recommend a maximum of 50 feet but some users have had
success with runs up to 100 feet. Communications speed is typically in the range of
1200 bits per second to 57,600 bits per second. RS232 connection can be
accomplished using Port 1 of the EPM 9900 9450/9650 meter.
RS485:
A type of serial network connection that connects two or more devices to enable
communication between the devices. An RS485 connection allows multi-drop
communication from one to many points.
Distance between devices is typically limited to around 2,000 to 3,000 wire feet.
Communications speed is typically in the range of 120 bits per second to 115,000 bits
per second.
Sag:
A voltage quality event during which the RMS voltage is lower than normal for a period
of time, typically from 1/2 cycle to 1 minute.
Secondary Rated:
Any Register or pulse output that does not use any CT or PT(VT) Ratio.
Serial Port:
The type of port used to directly interface with a device using the RS232 standard.
Swell:
A voltage quality event during which the RMS voltage is higher than normal for a
period of time, typically from 1/2 cycle to 1 minute.
TDD:
The Total Demand Distortion of the current waveform. The ratio of the root-sumsquare value of the harmonic current to the maximum demand load current. (See
equation below.)
NOTE: The TDD displayed in the Harmonics screen is calculated by GE Communicator
software, using the Max Average Demand.
THD:
Total Harmonic Distortion is the combined effect of all harmonics measured in a
voltage or current. The THD number is expressed as a percent of the fundamental. For
example, a 3% THD indicates that the magnitude of all harmonic distortion measured
equals 3% of the magnitude of the fundamental 60Hz quantity. The %THD displayed is
calculated by your EPM 9900 meter.
Time Stamp:
A stored representation of the time of an event. Time Stamp can include year, month,
day, hour, minute, second and Daylight Savings Time indication.
TOU:
Time of Use.
Uncompensated Power:
VA, Watt and VAR readings not adjusted by Transformer Loss Compensation.
V2T Threshold:
Data stops accumulating when voltage falls below programmed level.
Voltage Imbalance:
The ratio of the voltage on a phase to the average voltage on all phases.
Voltage Quality Event:
An instance of abnormal voltage on a phase. The events the meter tracks include
sags, swells, interruptions and imbalances.
VT Ratio:
The Voltage Transformer Ratio is used to scale the value of the voltage to the primary
side of an instrument transformer. Also referred to as PT Ratio.
Voltage, Vab:
Vab, Vbc, Vca are all Phase-to-Phase voltage measurements. These voltages are
measured between the three phase voltage inputs to the meter.
Voltage, Van:
Van, Vbn, Vcn are all Phase-to-Neutral voltages applied to the monitor. These voltages
are measured between the phase voltage inputs and Vn input to the meter.
Technologically, these voltages can be “measured” even when the meter is in a Delta
configuration and there is no connection to the Vn input. However, in this
configuration, these voltages have limited meaning and are typically not reported.
Voltage, Vaux:
This is the fourth voltage input measured frombetween the Vaux and Vref inputs. This
input can be scaled to any value. However, the actual input voltage to the meter
should be of the same magnitude as the voltages applied to the Va, Vb and Vc
terminals.
Table of contents
1: THREE-PHASE POWER
MEASUREMENT
THREE-PHASE SYSTEM CONFIGURATIONS ........................................................................... 1-2
WYE CONNECTION .............................................................................................................. 1-2
DELTA CONNECTION ........................................................................................................... 1-4
BLONDEL’S THEOREM AND THREE PHASE MEASUREMENT ........................................... 1-6
POWER, ENERGY AND DEMAND ............................................................................................... 1-8
REACTIVE ENERGY AND POWER FACTOR ............................................................................. 1-11
HARMONIC DISTORTION .............................................................................................................. 1-13
POWER QUALITY .............................................................................................................................. 1-16
2: OVERVIEW AND
SPECIFICATIONS
EPM 9900 METER OVERVIEW ..................................................................................................... 2-1
METER FEATURES ................................................................................................................ 2-1
DNP V3.00 LEVEL 2 ......................................................................................................................... 2-3
SOFTWARE OPTION TECHNOLOGY .......................................................................................... 2-4
UPGRADING THE METER’S SOFTWARE OPTION KEY ...................................................... 2-4
MEASUREMENTS AND CALCULATIONS .................................................................................. 2-5
DEMAND INTEGRATORS ...................................................................................................... 2-7
MEASURED VALUES ............................................................................................................ 2-9
UTILITY PEAK DEMAND ....................................................................................................... 2-10
ORDERING ........................................................................................................................................... 2-10
ORDER CODES ..................................................................................................................... 2-10
EPM ACCESSORIES ............................................................................................................. 2-11
SPECIFICATIONS ............................................................................................................................... 2-12
ACCURACY (FOR FULL RATING SPECIFICATIONS, SEE 2.6 Specifications) .............. 2-15
3: MECHANICAL
INSTALLATION
OVERVIEW ........................................................................................................................................... 3-1
MOUNTING THE EPM 9900 METER ................................................................................ 3-1
METER AND PANEL CUT-OUT DIMENSIONS .................................................................... 3-2
MOUNTING INSTRUCTIONS ................................................................................................. 3-2
MOUNTING THE OPTIONAL EXTERNAL I/O MODULES .................................................... 3-4
4: ELECTRICAL
INSTALLATION
SAFETY CONSIDERATIONS WHEN INSTALLING METERS ................................................ 4-1
CT LEADS TERMINATED TO METER ........................................................................................... 4-3
CT LEADS PASS THROUGH (NO METER TERMINATION) ................................................... 4-4
QUICK CONNECT CRIMP-ON TERMINATIONS ..................................................................... 4-5
WIRING THE MONITORED INPUTS AND VOLTAGES .......................................................... 4-6
GROUND CONNECTIONS .............................................................................................................. 4-7
FUSING THE VOLTAGE CONNECTIONS .................................................................................. 4-7
WIRING THE MONITORED INPUTS - VAUX ............................................................................ 4-7
WIRING THE MONITORED INPUTS - CURRENTS ................................................................. 4-7
ISOLATING A CT CONNECTION REVERSAL ............................................................................ 4-8
INSTRUMENT POWER SUPPLY CONNECTIONS ................................................................... 4-8
115AC POWER SUPPLY
............................................................................................................................................... 4-9
HI HIGH-VOLTAGE POWER SUPPLY ................................................................................. 4-10
LD LOW-VOLTAGE POWER SUPPLY ................................................................................. 4-10
WIRING DIAGRAMS ......................................................................................................................... 4-11
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
TOC–1
5: COMMUNICATION
INSTALLATION
COMMUNICATION OVERVIEW .................................................................................................... 5-1
RJ45 AND FIBER ETHERNET CONNECTIONS ........................................................................ 5-1
ANSI OPTICAL PORT ........................................................................................................................ 5-1
USB CONNECTION ........................................................................................................................... 5-2
RS485 CONNECTIONS ................................................................................................................... 5-2
USING THE MULTINET ......................................................................................................... 5-4
REMOTE COMMUNICATION WITH RS485 .............................................................................. 5-5
PROGRAMMING MODEMS FOR REMOTE COMMUNICATION ........................................ 5-5
SELECTED MODEM STRINGS ....................................................................................................... 5-6
HIGH SPEED INPUTS CONNECTION ......................................................................................... 5-7
IRIG-B CONNECTIONS .................................................................................................................... 5-8
TIME SYNCHRONIZATION ALTERNATIVES ............................................................................. 5-10
6: USING THE EPM 9900
METER’S TOUCH SCREEN
DISPLAY
INTRODUCTION ................................................................................................................................ 6-1
FIXED SYSTEM SCREENS ............................................................................................................... 6-1
DYNAMIC SCREENS ......................................................................................................................... 6-9
7: TRANSFORMER LOSS
COMPENSATION
INTRODUCTION ................................................................................................................................ 7-1
EPM 9900 METER'S TRANSFORMER LOSS COMPENSATION ......................................... 7-4
LOSS COMPENSATION IN THREE ELEMENT INSTALLATIONS .......................................... 7-4
8: TIME-OF-USE
FUNCTION
INTRODUCTION ................................................................................................................................ 8-1
THE EPM 9900 METER'S TOU CALENDAR .............................................................................. 8-1
TOU PRIOR SEASON AND MONTH ............................................................................................ 8-2
UPDATING, RETRIEVING AND REPLACING TOU CALENDARS ....................................... 8-2
DAYLIGHT SAVINGS AND DEMAND ......................................................................................... 8-3
9: EPM 9900 NETWORK
COMMUNICATIONS
HARDWARE OVERVIEW ................................................................................................................. 9-1
SPECIFICATIONS ............................................................................................................................... 9-3
NETWORK CONNECTION .............................................................................................................. 9-3
TOTAL WEB SOLUTIONS ............................................................................................................... 9-5
VIEWING WEBPAGES .......................................................................................................... 9-5
10: FLICKER ANALYSIS
OVERVIEW ........................................................................................................................................... 10-1
THEORY OF OPERATION ................................................................................................................ 10-1
SUMMARY ............................................................................................................................. 10-3
EN50160/IEC61000-4-30 FLICKER LOGGING ..................................................................... 10-4
IEC61000-4-30 HARMONIC AND INTERHARMONIC LIMITS SCREEN ........................ 10-7
EN50160/IEC61000-4-30 FLICKER POLLING SCREEN ..................................................... 10-8
POLLING THROUGH COMMUNICATIONS .............................................................................. 10-11
LOG VIEWER ....................................................................................................................................... 10-11
PERFORMANCE NOTES .................................................................................................................. 10-11
11: USING THE I/O
OPTIONS
OVERVIEW ........................................................................................................................................... 11-1
INSTALLING OPTION CARDS ....................................................................................................... 11-2
CONFIGURING OPTION CARDS .................................................................................................. 11-2
PULSE OUTPUT/RS485 OPTION CARD (S OPTION) ............................................................ 11-3
PULSE OUTPUT/RS485 OPTION CARD (S OPTION) WIRING ....................................... 11-4
TOC–2
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
ETHERNET OPTION CARD: RJ45 (E1) OR FIBER OPTIC (E2) ............................................. 11-5
RELAY OUTPUT OPTION CARD (R1) .......................................................................................... 11-6
RELAY OUTPUT OPTION CARD (R1) WIRING .................................................................. 11-7
DIGITAL INPUT OPTION CARD (D1) ........................................................................................... 11-8
DIGITAL INPUT OPTION CARD (D1) WIRING ................................................................... 11-9
OPTIONAL EXTERNAL I/O MODULES ....................................................................................... 11-10
PORT OVERVIEW ................................................................................................................. 11-11
INSTALLING OPTIONAL EXTERNAL I/O MODULES .......................................................... 11-11
POWER SOURCE FOR EXTERNAL I/O MODULES ............................................................ 11-12
USING PSIO WITH MULTIPLE I/O MODULES ................................................................ 11-13
FACTORY SETTINGS AND RESET BUTTON ....................................................................... 11-14
ANALOG TRANSDUCER SIGNAL OUTPUT MODULES ..................................................... 11-15
DIGITAL DRY CONTACT RELAY OUTPUT (FORM C) MODULE ........................................ 11-16
DIGITAL SOLID STATE PULSE OUTPUT (KYZ) MODULE ................................................ 11-17
ANALOG INPUT MODULES ................................................................................................. 11-18
ADDITIONAL EXTERNAL I/O MODULE SPECIFICATIONS .................................................. 11-20
A: INSTALLING THE USB
VIRTUAL COMM PORT
INTRODUCTION ................................................................................................................................ A-1
INSTALLING THE VIRTUAL PORT'S DRIVER ............................................................................ A-1
CONNECTING TO THE VIRTUAL PORT ..................................................................................... A-3
B: POWER SUPPLY
OPTIONS
C: USING THE IEC 61850
PROTOCOL ETHERNET
NETWORK SERVER
OVERVIEW OF IEC 61850 ............................................................................................................. C-1
RELATIONSHIP OF CLIENTS AND SERVERS IN IEC 61850 ............................................ C-2
STRUCTURE OF IEC 61850 NETWORK ........................................................................... C-3
STEPS TO CONFIGURING AN IEC 61850 NETWORK ..................................................... C-5
GE DIGITAL ENERGY’S IMPLEMENTATION OF THE IEC 61850 SERVER ..................... C-7
REFERENCE MATERIALS ...................................................................................................... C-9
FREE TOOLS FOR IEC 61850 START-UP ........................................................................ C-9
COMMERCIAL TOOLS FOR IEC 61850 IMPLEMENTATION ............................................ C-9
USING THE EPM 9900 METER’S IEC 61850 PROTOCOL ETHERNET NETWORK SERVER
................................................................................................................................................................. C-10
OVERVIEW ............................................................................................................................ C-10
CONFIGURING THE IEC 61850 PROTOCOL ETHERNET NETWORK SERVER ............... C-11
TESTING ................................................................................................................................................ C-22
D: MANUAL REVISION
HISTORY
RELEASE NOTES ................................................................................................................................ D-1
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
TOC–3
TOC–4
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
GE Energy
EPM 9900 Electronic Meter
Chapter 1: Three-Phase Power
Measurement
Three-Phase Power Measurement
This introduction to three-phase power and power measurement is intended to provide
only a brief overview of the subject. The professional meter engineer or meter technician
should refer to more advanced documents such as the EEI Handbook for Electricity
Metering and the application standards for more in-depth and technical coverage of the
subject.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
1–1
CHAPTER 1: THREE-PHASE POWER MEASUREMENT
1.1
Three-Phase System Configurations
Three-phase power is most commonly used in situations where large amounts of power
will be used because it is a more effective way to transmit the power and because it
provides a smoother delivery of power to the end load. There are two commonly used
connections for three-phase power, a wye connection or a delta connection. Each
connection has several different manifestations in actual use.
When attempting to determine the type of connection in use, it is a good practice to follow
the circuit back to the transformer that is serving the circuit. It is often not possible to
conclusively determine the correct circuit connection simply by counting the wires in the
service or checking voltages. Checking the transformer connection will provide conclusive
evidence of the circuit connection and the relationships between the phase voltages and
ground.
1.1.1
Wye Connection
The wye connection is so called because when you look at the phase relationships and the
winding relationships between the phases it looks like a wye (Y). Fig. 1.1 depicts the winding
relationships for a wye-connected service. In a wye service the neutral (or center point of
the wye) is typically grounded. This leads to common voltages of 208/120 and 480/277
(where the first number represents the phase-to-phase voltage and the second number
represents the phase-to-ground voltage).
Figure 1-1: Three-Phase Wye Winding
A
Ia
Van
B
Vbn
Vcn
N
C
The three voltages are separated by 120° electrically. Under balanced load conditions with
unity power factor the currents are also separated by 120°. However, unbalanced loads
and other conditions can cause the currents to depart from the ideal 120° separation.
1–2
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 1: THREE-PHASE POWER MEASUREMENT
Three-phase voltages and currents are usually represented with a phasor diagram. A
phasor diagram for the typical connected voltages and currents is shown in Figure 1.2.
Figure 1-2: Phasor diagram showing Three-phase Voltages and Currents
Vcn
Ic
Van
Ia
Ib
Vbn
The phasor diagram shows the 120° angular separation between the phase voltages. The
phase-to-phase voltage in a balanced three-phase wye system is 1.732 times the phaseto-neutral voltage. The center point of the wye is tied together and is typically grounded.
Table 1.1 shows the common voltages used in the United States for wye-connected
systems.
Table 1–1: Common Phase Voltages on Wye Services
Phase-to-Ground Voltage
120 volts
Phase-to-Phase Voltage
208 volts
277 volts
480 volts
2,400 volts
4,160 volts
7,200 volts
12,470 volts
7,620 volts
13,200 volts
Usually a wye-connected service will have four wires; three wires for the phases and one
for the neutral. The three-phase wires connect to the three phases (as shown in Fig. 1.1).
The neutral wire is typically tied to the ground or center point of the wye (refer to Figure
1.1).
In many industrial applications the facility will be fed with a four-wire wye service but only
three wires will be run to individual loads. The load is then often referred to as a deltaconnected load but the service to the facility is still a wye service; it contains four wires if
you trace the circuit back to its source (usually a transformer). In this type of connection
the phase to ground voltage will be the phase-to-ground voltage indicated in Table 1.1,
even though a neutral or ground wire is not physically present at the load. The transformer
is the best place to determine the circuit connection type because this is a location where
the voltage reference to ground can be conclusively identified.
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CHAPTER 1: THREE-PHASE POWER MEASUREMENT
1.1.2
Delta Connection
Delta connected services may be fed with either three wires or four wires. In a three-phase
delta service the load windings are connected from phase-to-phase rather than from
phase-to-ground.
Figure 1.3 shows the physical load connections for a delta service.
Figure 1-3: Three-Phase Delta Winding Relationship
A
Ia
Iab
Vab
Vca
B
Ib
Vbc
C
Ica
Ibc
Ic
In this example of a delta service, three wires will transmit the power to the load. In a true
delta service, the phase-to-ground voltage will usually not be balanced because the
ground is not at the center of the delta.
Fig. 1.4 shows the phasor relationships between voltage and current on a three-phase
delta circuit.
1–4
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In many delta services, one corner of the delta is grounded. This means the phase to
ground voltage will be zero for one phase and will be full phase-to-phase voltage for the
other two phases. This is done for protective purposes.
Figure 1-4: Phasor diagram showing three-phase voltages, currents delta connected.
Vca
Ic
Vbc
Ia
Ib
Vab
Another common delta connection is the four-wire, grounded delta used for lighting loads.
In this connection the center point of one winding is grounded. On a 120/240 volt, fourwire, grounded delta service the phase-to-ground voltage would be 120 volts on two
phases and 208 volts on the third phase. Figure 1.5 shows the phasor diagram for the
voltages in a three-phase, four-wire delta system.
Figure 1-5: Phasor diagram showing Three-phase, Four-wire Delta Connected System
Vnc
120 V
Vca
Vbc
120 V
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
Vbn
Vab
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CHAPTER 1: THREE-PHASE POWER MEASUREMENT
1.1.3
Blondel’s Theorem and Three Phase Measurement
In 1893 an engineer and mathematician named Andre E. Blondel set forth the first
scientific basis for poly phase metering. His theorem states:
•
If energy is supplied to any system of conductors through N wires, the total power in
the system is given by the algebraic sum of the readings of N wattmeters so arranged
that each of the N wires contains one current coil, the corresponding potential coil
being connected between that wire and some common point. If this common point is
on one of the N wires, the measurement may be made by the use of N-1 wattmeters.
The theorem may be stated more simply, in modern language:
•
In a system of N conductors, N-1 meter elements will measure the power or energy
taken provided that all the potential coils have a common tie to the conductor in
which there is no current coil.
•
Three-phase power measurement is accomplished by measuring the three individual
phases and adding them together to obtain the total three phase value. In older
analog meters, this measurement was accomplished using up to three separate
elements. Each element combined the single-phase voltage and current to produce a
torque on the meter disk. All three elements were arranged around the disk so that the
disk was subjected to the combined torque of the three elements.
As a result the disk would turn at a higher speed and register power supplied by each
of the three wires.
•
According to Blondel's Theorem, it was possible to reduce the number of elements
under certain conditions. For example, a three-phase, three-wire delta system could
be correctly measured with two elements (two potential coils and two current coils) if
the potential coils were connected between the three phases with one phase in
common.
In a three-phase, four-wire wye system it is necessary to use three elements. Three
voltage coils are connected between the three phases and the common neutral
conductor. A current coil is required in each of the three phases.
•
In modern digital meters, Blondel's Theorem is still applied to obtain proper metering.
The difference in modern meters is that the digital meter measures each phase
voltage and current and calculates the single-phase power for each phase. The meter
then sums the three phase powers to a single three-phase reading.
Some digital meters calculate the individual phase power values one phase at a time. This
means the meter samples the voltage and current on one phase and calculates a power
value. Then it samples the second phase and calculates the power for the second phase.
Finally, it samples the third phase and calculates that phase power. After sampling all three
phases, the meter combines the three readings to create the equivalent three-phase
power value. Using mathematical averaging techniques, this method can derive a quite
accurate measurement of three-phase power.
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More advanced meters actually sample all three phases of voltage and current
simultaneously and calculate the individual phase and three-phase power values. The
advantage of simultaneous sampling is the reduction of error introduced due to the
difference in time when the samples were taken.
Figure 1-6: Three-Phase Wye Load illustrating Kirchhoff’s Law and Blondel’s Theorem
C
B
Phase B
Phase C
Node "n"
Phase A
A
N
Blondel's Theorem is a derivation that results from Kirchhoff's Law. Kirchhoff's Law states
that the sum of the currents into a node is zero. Another way of stating the same thing is
that the current into a node (connection point) must equal the current out of the node. The
law can be applied to measuring three-phase loads. Figure 1.6 shows a typical connection
of a three-phase load applied to a three-phase, four-wire service. Krichhoff's Laws hold
that the sum of currents A, B, C and N must equal zero or that the sum of currents into
Node "n" must equal zero.
If we measure the currents in wires A, B and C, we then know the current in wire N by
Kirchhoff's Law and it is not necessary to measure it. This fact leads us to the conclusion of
Blondel's Theorem that we only need to measure the power in three of the four wires if they
are connected by a common node. In the circuit of Figure 1.6 we must measure the power
flow in three wires. This will require three voltage coils and three current coils (a three
element meter). Similar figures and conclusions could be reached for other circuit
configurations involving delta-connected loads.
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CHAPTER 1: THREE-PHASE POWER MEASUREMENT
1.2
1–8
Power, Energy and Demand
•
It is quite common to exchange power, energy and demand without differentiating
between the three. Because this practice can lead to confusion, the differences
between these three measurements will be discussed.
•
Power is an instantaneous reading. The power reading provided by a meter is the
present flow of watts. Power is measured immediately just like current. In many digital
meters, the power value is actually measured and calculated over a one second
interval because it takes some amount of time to calculate the RMS values of voltage
and current. But this time interval is kept small to preserve the instantaneous nature
of power.
•
Energy is always based on some time increment; it is the integration of power over a
defined time increment. Energy is an important value because almost all electric bills
are based, in part, on the amount of energy used.
•
Typically, electrical energy is measured in units of kilowatt-hours (kWh). A kilowatthour represents a constant load of one thousand watts (one kilowatt) for one hour.
Stated another way, if the power delivered (instantaneous watts) is measured as 1,000
watts and the load was served for a one hour time interval then the load would have
absorbed one kilowatt-hour of energy. A different load may have a constant power
requirement of 4,000 watts. If the load were served for one hour it would absorb four
kWh. If the load were served for 15 minutes it would absorb ¼ of that total or one
kWh.
•
Figure 1.7 shows a graph of power and the resulting energy that would be transmitted
as a result of the illustrated power values. For this illustration, it is assumed that the
power level is held constant for each minute when a measurement is taken. Each bar
in the graph will represent the power load for the one-minute increment of time. In
real life the power value moves almost constantly.
•
The data from Figure 1.7 is reproduced in Table 2 to illustrate the calculation of energy.
Since the time increment of the measurement is one minute and since we specified
that the load is constant over that minute, we can convert the power reading to an
equivalent consumed energy reading by multiplying the power reading times 1/60
(converting the time base from minutes to hours).
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Figure 1-7: Power use over time
80
70
kilowatts
60
50
40
30
20
10
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
Time (minutes)
Table 1–2: Power and energy relationship over time.
Time Interval
(Minute)
Power (kW)
Energy (kWh)
Accumulated
Energy (kWh)
1
30
0.50
0.50
2
50
0.83
1.33
3
40
0.67
2.00
4
55
0.92
2.92
5
60
1.00
3.92
6
60
1.00
4.92
7
70
1.17
6.09
8
70
1.17
7.26
9
60
1.00
8.26
10
70
1.17
9.43
11
80
1.33
10.76
12
50
0.83
12.42
13
50
0.83
12.42
14
70
1.17
13.59
15
80
1.33
14.92
As in Table 1.2, the accumulated energy for the power load profile of Figure 1.7 is 14.92
kWh.
Demand is also a time-based value. The demand is the average rate of energy use over
time. The actual label for demand is kilowatt-hours/hour but this is normally reduced to
kilowatts. This makes it easy to confuse demand with power. But demand is not an
instantaneous value. To calculate demand it is necessary to accumulate the energy
readings (as illustrated in Figure 1.7) and adjust the energy reading to an hourly value that
constitutes the demand.
In the example, the accumulated energy is 14.92 kWh. But this measurement was made
over a 15-minute interval. To convert the reading to a demand value, it must be
normalized to a 60-minute interval. If the pattern were repeated for an additional three 15minute intervals the total energy would be four times the measured value or 59.68 kWh.
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CHAPTER 1: THREE-PHASE POWER MEASUREMENT
The same process is applied to calculate the 15-minute demand value. The demand value
associated with the example load is 59.68 kWh/hr or 59.68 kWd. Note that the peak
instantaneous value of power is 80 kW, significantly more than the demand value.
Figure 1.8 shows another example of energy and demand. In this case, each bar
represents the energy consumed in a 15-minute interval. The energy use in each interval
typically falls between 50 and 70 kWh. However, during two intervals the energy rises
sharply and peaks at 100 kWh in interval number 7. This peak of usage will result in setting
a high demand reading. For each interval shown the demand value would be four times
the indicated energy reading. So interval 1 would have an associated demand of 240 kWh/
hr. Interval 7 will have a demand value of 400 kWh/hr. In the data shown, this is the peak
demand value and would be the number that would set the demand charge on the utility
bill.
Figure 1-8: Energy Use and Demand
100
kilowatt-hours
80
60
40
20
0
1
2
3
4
5
6
Intervals (15 mins.)
7
8
As can be seen from this example, it is important to recognize the relationships between
power, energy and demand in order to control loads effectively or to monitor use correctly.
1–10
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CHAPTER 1: THREE-PHASE POWER MEASUREMENT
1.3
Reactive Energy and Power Factor
•
The real power and energy measurements discussed in the previous section relate to
the quantities that are most used in electrical systems. But it is often not sufficient to
only measure real power and energy. Reactive power is a critical component of the
total power picture because almost all real-life applications have an impact on
reactive power. Reactive power and power factor concepts relate to both load and
generation applications. However, this discussion will be limited to analysis of reactive
power and power factor as they relate to loads. To simplify the discussion, generation
will not be considered.
•
Real power (and energy) is the component of power that is the combination of the
voltage and the value of corresponding current that is directly in phase with the
voltage. However, in actual practice the total current is almost never in phase with the
voltage. Since the current is not in phase with the voltage, it is necessary to consider
both the inphase component and the component that is at quadrature (angularly
rotated 90o or perpendicular) to the voltage. Figure 1.9 shows a single-phase voltage
and current and breaks the current into its in-phase and quadrature components.
Figure 1-9: Voltage and complex current
IR
V
θ
IX
I
•
The voltage (V) and the total current (I) can be combined to calculate the apparent
power or VA. The voltage and the in-phase current (IR) are combined to produce the
real power or watts. The voltage and the quadrature current (IX) are combined to
calculate the reactive power.
The quadrature current may be lagging the voltage (as shown in Figure 1.9) or it may
lead the voltage. When the quadrature current lags the voltage the load is requiring
both real power (watts) and reactive power (VARs). When the quadrature current leads
the voltage the load is requiring real power (watts) but is delivering reactive power
(VARs) back into the system; that is VARs are flowing in the opposite direction of the
real power flow.
•
Reactive power (VARs) is required in all power systems. Any equipment that uses
magnetization to operate requires VARs. Usually the magnitude of VARs is relatively
low compared to the real power quantities. Utilities have an interest in maintaining
VAR requirements at the customer to a low value in order to maximize the return on
plant invested to deliver energy. When lines are carrying VARs, they cannot carry as
many watts. So keeping the VAR content low allows a line to carry its full capacity of
watts. In order to encourage customers to keep VAR requirements low, most utilities
impose a penalty if the VAR content of the load rises above a specified value.
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CHAPTER 1: THREE-PHASE POWER MEASUREMENT
A common method of measuring reactive power requirements is power factor. Power
factor can be defined in two different ways. The more common method of calculating
power factor is the ratio of the real power to the apparent power. This relationship is
expressed in the following formula:
Total PF = real power / apparent power = watts/VA
This formula calculates a power factor quantity known as Total Power Factor. It is called
Total PF because it is based on the ratios of the power delivered. The delivered power
quantities will include the impacts of any existing harmonic content. If the voltage or
current includes high levels of harmonic distortion the power values will be affected. By
calculating power factor from the power values, the power factor will include the impact of
harmonic distortion. In many cases this is the preferred method of calculation because the
entire impact of the actual voltage and current are included.
A second type of power factor is Displacement Power Factor. Displacement PF is based on
the angular relationship between the voltage and current. Displacement power factor
does not consider the magnitudes of voltage, current or power. It is solely based on the
phase angle differences. As a result, it does not include the impact of harmonic distortion.
Displacement power factor is calculated using the following equation:
Displacement PF = cos θ,
where θ is the angle between the voltage and the current (see Fig. 1.9).
In applications where the voltage and current are not distorted, the Total Power Factor will
equal the Displacement Power Factor. But if harmonic distortion is present, the two power
factors will not be equal.
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1.4
Harmonic Distortion
Harmonic distortion is primarily the result of high concentrations of non-linear loads.
Devices such as computer power supplies, variable speed drives and fluorescent light
ballasts make current demands that do not match the sinusoidal waveform of AC
electricity. As a result, the current waveform feeding these loads is periodic but not
sinusoidal. Figure 1.10 shows a normal, sinusoidal current waveform. This example has no
distortion.
Figure 1-10: Non-distorted current waveform
Current (amps)
1000
500
0
a
t
2a
–500
–1000
Figure 1.11 shows a current waveform with a slight amount of harmonic distortion. The
waveform is still periodic and is fluctuating at the normal 60 Hz frequency. However, the
waveform is not a smooth sinusoidal form as seen in Figure 1.10.
Figure 1-11: Distorted current wave
1500
Current (amps)
1000
500
0
a
t
2a
–500
–1000
–1500
The distortion observed in Figure 1.11 can be modeled as the sum of several sinusoidal
waveforms of frequencies that are multiples of the fundamental 60 Hz frequency. This
modeling is performed by mathematically disassembling the distorted waveform into a
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
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CHAPTER 1: THREE-PHASE POWER MEASUREMENT
collection of higher frequency waveforms. These higher frequency waveforms are referred
to as harmonics. Figure 1.12 shows the content of the harmonic frequencies that make up
the distortion portion of the waveform in Figure 1.11.
Figure 1-12: Waveforms of the harmonics
250
200
Current (amps)
150
100
50
t
0
a
-50
-100
-150
-200
-250
The waveforms shown in Figure 1.12 are not smoothed but do provide an indication of the
impact of combining multiple harmonic frequencies together.
When harmonics are present it is important to remember that these quantities are
operating at higher frequencies. Therefore, they do not always respond in the same
manner as 60 Hz values.
Inductive and capacitive impedance are present in all power systems. We are accustomed
to thinking about these impedances as they perform at 60 Hz. However, these impedances
are subject to frequency variation.
XL = jωL and
XC = 1/jωC
At 60 Hz, ω = 377; but at 300 Hz (5th harmonic) ω = 1,885. As frequency changes
impedance changes and system impedance characteristics that are normal at 60 Hz may
behave entirely different in presence of higher order harmonic waveforms.
Traditionally, the most common harmonics have been the low order, odd frequencies, such
as the 3rd, 5th, 7th, and 9th. However newer, non-linear loads are introducing significant
quantities of higher order harmonics.
Since much voltage monitoring and almost all current monitoring is performed using
instrument transformers, the higher order harmonics are often not visible. Instrument
transformers are designed to pass 60 Hz quantities with high accuracy. These devices,
when designed for accuracy at low frequency, do not pass high frequencies with high
accuracy; at frequencies above about 1200 Hz they pass almost no information. So when
instrument transformers are used, they effectively filter out higher frequency harmonic
distortion making it impossible to see.
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However, when monitors can be connected directly to the measured circuit (such as direct
connection to 480 volt bus) the user may often see higher order harmonic distortion. An
important rule in any harmonics study is to evaluate the type of equipment and
connections before drawing a conclusion. Not being able to see harmonic distortion is not
the same as not having harmonic distortion.
It is common in advanced meters to perform a function commonly referred to as
waveform capture.
Waveform capture is the ability of a meter to capture a present picture of the voltage or
current waveform for viewing and harmonic analysis. Typically a waveform capture will be
one or two cycles in duration and can be viewed as the actual waveform, as a spectral
view of the harmonic content, or a tabular view showing the magnitude and phase shift of
each harmonic value. Data collected with waveform capture is typically not saved to
memory. Waveform capture is a real-time data collection event.
Waveform capture should not be confused with waveform recording that is used to record
multiple cycles of all voltage and current waveforms in response to a transient condition.
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CHAPTER 1: THREE-PHASE POWER MEASUREMENT
1.5
Power Quality
Power quality can mean several different things. The terms ‘power quality’ and ‘power
quality problem’ have been applied to all types of conditions. A simple definition of ‘power
quality problem’ is any voltage, current or frequency deviation that results in mis-operation
or failure of customer equipment or systems. The causes of power quality problems vary
widely and may originate in the customer equipment, in an adjacent customer facility or
with the utility.
In his book “Power Quality Primer”, Barry Kennedy provided information on different types
of power quality problems. Some of that information is summarized in Table 1.3 below.
Table 1–3: Typical power quality problems and sources.
Cause
Disturbance Type
Impulse Transient
Transient voltage
disturbance, sub-cycle
duration
Lightning
Electrostatic discharge
Load switching
Capacitor switching
Source
Oscillatory transient with
decay
Transient voltage, sub-cycle
duration
Line/cable switching
Capacitor switching
Load switching
Sag / swell
RMS voltage, multiple cycle
duration
Remote system faults
Interruptions
RMS voltage, multiple
second or longer duration
System protection
Circuit breakers
Fuses
Maintenance
Undervoltage / Overvoltage
RMS voltage, steady state,
multiple second or longer
duration
Motor starting
Load variations
Load dropping
Voltage flicker
RMS voltage, steady state,
repetitive condition
Intermittent loads
Motor starting
Arc furnaces
Harmonic distortion
Steady state current or
voltage, long term duration
Non-linear loads
System resonance
It is often assumed that power quality problems originate with the utility. While it is true
that many power quality problems can originate with the utility system, many problems
originate with customer equipment. Customer-caused problems may manifest themselves
inside the customer location or they may be transported by the utility system to another
adjacent customer. Often, equipment that is sensitive to power quality problems may in
fact also be the cause of the problem.
If a power quality problem is suspected, it is generally wise to consult a power quality
professional for assistance in defining the cause and possible solutions to the problem.
1–16
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
GE Energy
EPM 9900 Electronic Meter
Chapter 2: Overview and
Specifications
Overview and Specifications
2.1
EPM 9900 Meter Overview
The EPM 9900 meter is the latest in a generation of meters that combine high-end revenue
metering with sophisticated power quality analysis.
In European Union member state countries, this meter is NOT certified for revenue
metering. See the Safety Precautions section for meter certification details.
Note
2.1.1
Meter
Features
Revenue Metering
• Delivers laboratory-grade 0.06% Watt-hour accuracy (at full load Unity PF) in a
field-mounted device
• Auto-calibrates when there is a temperature change of more than 1.5 °C
• Meets ANSI C12.20 and IEC 62053-22 accuracy specifications for Class 20 meters
• Adjusts for transformer and line losses, using user-defined compensation factors
• Automatically logs time-of-use for up to eight programmable tariff registers
• Counts pulses and aggregates different loads
Power Quality
• Records up to 1024 samples per cycle on an event on all inputs
• Records sub-cycle transients on voltage or current readings
• Records high-speed voltage transients at a 50MHz sample rate, with accuracy to
10MHz
• Offers inputs for neutral-to-ground voltage measurements
• Synchronizes with IRIG-B clock signal
• Measures Flicker per IEC 61000-4-15 and IEC 61000-4-30 Class A standards;
Flicker analysis is available for Instantaneous, Short-Term, and Long-Term forms.
See Chapter 10 for more details.
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CHAPTER 2: OVERVIEW AND SPECIFICATIONS
RTU Features
• Advanced monitoring capabilities that provide detailed and precise pictures of any
metered point within a distribution network
• Extensive I/O capability that is available in conjunction with all metering
functions. I/O includes:
• Optional Relay Output card with 6 relay contact outputs (up to 2 Relay Output
cards can be installed in the meter)
• Optional Digital Input card with 16 status inputs (up to 2 Digital Input cards can be
installed in the meter)
• Optional External I/O modules consisting of up to 4 Analog Output modules, 1
Digital Dry Contact Relay Output module, up to 4 Digital Solid State Pulse Output
modules, and up to 4 Analog Input Modules
See Chapter 11 for detailed information on the I/O options.
Note
NOTE
• Logging of Modbus slave devices for RTU concentrator functions
Extensive Memory and Communication
• Onboard mass memory (over 1 GigaByte compact Flash) that enables the EPM
9900 meter to retrieve and store multiple logs
• Standard 10/100BaseT RJ45 Ethernet that allows you to connect to a PC via
Modbus TCP/IP, and, with Software Options B and C, offers IEC 61850 protocol; a
second, optional Ethernet connection can be either RJ45 or Fiber Optic
• A USB Virtual Com Port, compatible with USB1.1/USB2.0, that provides serial
communication
• Optional RS485/Pulse Output card that provides two RS485 ports and 4 pulse
outputs that are user programmable to reflect VAR-hours, Watt-hours, or VA-hours
• Advanced Power Quality analysis that includes measuring and recording
Harmonics to the 255th order (and Real Time Harmonics to the 128th order)
• Multiple Protocols that include DNP V3.00 (see Section 2.2 for more details)
• 100msec high speed updates that are available for Control applications
• Software Option technology that allows you to upgrade the meter in the field
without removing it from installation
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CHAPTER 2: OVERVIEW AND SPECIFICATIONS
2.2
DNP V3.00 Level 2
The EPM 9900 meter supports DNP V3.00 Level 2 over both serial and dual Ethernet ports.
DNP Level 2 Features
• Up to 136 measurements (64 Binary Inputs, 8 Binary Counters, 64 Analog Inputs)
can be mapped to DNP Static Points (over 3000) in the customizable DNP Point
Map.
• Report-by-Exception Processing (DNP Events) - Deadbands can be set on a perpoint basis.
• Freeze Commands - Available commands are Freeze, Freeze/No-Ack, Freeze with
Time, and Freeze with Time/No-Ack.
• Freeze with Time Commands enable the EPM 9900 meter to have internal timedriven Frozen and Frozen Event data. When the EPM 9900 meter receives the time
and interval, the data is created.
Visit the GE website http://www.gedigitalenergy.com, for more details.
Note
NOTE
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
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CHAPTER 2: OVERVIEW AND SPECIFICATIONS
2.3
Software Option Technology
The EPM 9900 meter is equipped with Software Option technology, a virtual firmwarebased switch that allows you to enable meter features through software communication.
Software Option technology allows the unit to be upgraded after installation without
removing it from service.
Available Software Option key upgrades
• Software Option (A) - Standard meter with 128 Megabytes memory with 512
samples/ cycle.
• Software Option (B) - 1 Gigabyte memory with 1024 samples/cycle, IEC 61850
Communications Protocol.
• Software Option (C) - 1 Gigabyte memory with 1024 samples/cycle, IEC 61850
Communications Protocol and 10MHz Transient Recording.
Software Options B and C enable IEC 61850 Protocol Server for the Main Ethernet card. See
Appendix C for details.
Note
NOTE
2.3.1
Upgrading the
Meter’s
Software
Option Key
To upgrade your meter to a higher Software Option key (e.g., B), follow these steps:
1.
To obtain a higher Software Option upgrade key, contact Digital Energy’s inside sales.
You will be asked for the following information:
• Serial number(s) of the meter you are upgrading.
• Desired Software Option upgrade.
• Credit card or Purchase Order number.
2.
Digital Energy will issue you the Software Option upgrade key. To enable the key,
follow these steps:
• Open GE Communicator software.
• Power up your EPM 9900 meter.
• Connect to the meter via GE Communicator. (See the GE Communicator User
Manual for detailed instructions: you can open the manual online by clicking
Help>Contents from the GE Communicator Main screen).
• Click Tools>Change Software Option from the Title Bar of the Main screen. A
screen opens, requesting the encrypted key.
• Enter the upgrade key provided by Digital Energy.
• Click OK. The Software Option key is enabled and the meter is reset.
2–4
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 2: OVERVIEW AND SPECIFICATIONS
2.4
Measurements and Calculations
The EPM 9900 meter measures many different power parameters. Following is a list of the
formulas used to perform calculations with samples for Wye and Delta services.
Samples for Wye: va, vb, vc, ia, ib, ic, in
Samples for Delta: vab, vbc, vca, ia, ib, ic
Root Mean Square (RMS) of Phase Voltages: N = number of samples
For Wye: x = a, b, c
N
2
 vx ( t )
V RMS =
x
t=1
--------------------N
(EQ 2.1)
Root Mean Square (RMS) of Line Currents: N = number of samples
For Wye: x= a, b, c, n
For Delta: x = a, b, c
N
2
 ix ( t )
I RMS =
x
t=1
------------------N
(EQ 2.2)
Root Mean Square (RMS) of Line Voltages: N = number of samples
For Wye: x, y= a,b or b,c or c,a
N
 ( vx ( t ) – vy ( t ) ) 2
V RMS
xy
=
t=1
--------------------------------------------N
(EQ 2.3)
For Delta: xy = ab, bc, ca
N
2
 vxy ( t )
V RMS
xy
=
t=1
----------------------N
(EQ 2.4)
Power (Watts) per phase: N = number of samples
For Wye: x = a, b, c
N
 vx ( t ) • ix ( t )
t=1
W X = -----------------------------------N
(EQ 2.5)
Apparent Power (VA) per phase:
For Wye: x = a, b, c
VA x = V RMS • I RMS
x
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
x
(EQ 2.6)
2–5
CHAPTER 2: OVERVIEW AND SPECIFICATIONS
Reactive Power (VAR) per phase:
For Wye: x = a, b, c
VAR x =
VA
2
x
– Watt
2
(EQ 2.7)
x
Active Power (Watts) Total: N = number of samples
For Wye:
WT = Wa + Wb + Wc
(EQ 2.8)
For Delta:
N
 ( vab ( t ) • ia ( t ) – vbc ( t ) • ic ( t ) )
t=1
W T = ------------------------------------------------------------------------------N
(EQ 2.9)
Reactive Power (VAR) Total: N = number of samples
For Wye:
VAR T = VAR a + VAR b + VAR c
(EQ 2.10)
For Delta:
(EQ 2.11)
N

AR T =
2
N
v ab ( t ) • i a ( t )
 vbc ( t ) • ic ( t )
( v RMS • I RMS ) 2 – --------------------------------------ab
a
N
+ ( v RMS • I RMS ) 2 – --------------------------------------bc
c
N
t=1
t=1
Apparent Power (VA) Total:
For Wye:
VA T = VA a + VA b + VA c
(EQ 2.12)
For Delta:
VA T =
2
W T + VAR T
2
(EQ 2.13)
Power Factor (PF):
For Wye: x = a,b,c,T
For Delta: x = T
Watt
PF x = --------------xVA x
2–6
(EQ 2.14)
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 2: OVERVIEW AND SPECIFICATIONS
Phase Angles:
∠= cos –1 ( PF )
(EQ 2.15)
% Total Harmonic Distortion (%THD):
For Wye: x = va, vb, vc, ia, ib, ic
For Delta: x = ia, ib, ic, vab, vbc, vca
127

( RMS xh ) 2
h=2
THD = ---------------------------------------RMS x1
(EQ 2.16)
K Factor:
x = ia, ib, ic
127

( h • RMS x ) 2
h
h=1
127
KFactor = --------------------------------------------

(EQ 2.17)
( RMS x ) 2
h
h=1
Watt hour (Wh): N = number of samples
N
Wh =

t=1
W(t )
--------------------3600 s ⁄ hr
(EQ 2.18)
VAR hour (VARh): N = number of samples
N
VARh =

t=1
2.4.1
Demand
Integrators
VAR ( t )
--------------------3600 s ⁄ hr
(EQ 2.19)
Power utilities take into account both energy consumption and peak demand when billing
customers. Peak demand, expressed in kilowatts (kW), is the highest level of demand
recorded during a set period of time, called the interval. The EPM 9900 meter supports the
following most popular conventions for averaging demand and peak demand: Block
Window Demand, Rolling Window Demand, Thermal Demand and Predictive Window
Demand. You can program and access all conventions concurrently with the GE
Communicator software (see the GE Communicator User Manual).
Block (Fixed) Window Demand:
This convention records the average (arithmetic mean) demand for consecutive time
intervals (usually 15 minutes).
Example: A typical setting of 15 minutes produces an average value every 15 minutes (at
12:00, 12:15. 12:30. etc.) for power reading over the previous fifteen minute interval (11:4512:00, 12:00-12:15, 12:15-12:30, etc.).
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
2–7
CHAPTER 2: OVERVIEW AND SPECIFICATIONS
Rolling (Sliding) Window Demand:
Rolling Window Demand functions like multiple overlapping Block Window Demands. The
programmable settings provided are the number and length of demand subintervals. At
every subinterval, an average (arithmetic mean) of power readings over the subinterval is
internally calculated. This new subinterval average is then averaged (arithmetic mean),
with as many previous subinterval averages as programmed, to produce the Rolling
Window Demand.
Example: With settings of 3 five-minute subintervals, subinterval averages are
computed every 5 minutes (12:00, 12:05, 12:15, etc.) for power readings over the previous
five-minute interval (11:55-12:00, 12:00-12:05, 12:05-12:10, 12:10-12:15, etc.). Further,
every 5 minutes, the subinterval averages are averaged in groups of 3 (12:00. 12:05, 12:10,
12:15. etc.) to produce a fifteen (5x3) minute average every 5 minutes (rolling (sliding) every
5 minutes) (11:55-12:10, 12:00-12:15, etc.).
Thermal Demand:
Traditional analog Watt-hour (Wh) meters use heat-sensitive elements to measure
temperature rises produced by an increase in current flowing through the meter. A pointer
moves in proportion to the temperature change, providing a record of demand. The
pointer remains at peak level until a subsequent increase in demand moves it again, or
until it is manually reset. The EPM 9900 meter mimics traditional meters to provide
Thermal Demand readings.
Each second, as a new power level is computed, a recurrence relation formula is applied.
This formula recomputes the thermal demand by averaging a small portion of the new
power value with a large portion of the previous thermal demand value. The proportioning
of new to previous is programmable, set by an averaging interval. The averaging interval
represents a 90% change in thermal demand to a step change in power.
Predictive Window Demand:
Predictive Window Demand enables the user to forecast average demand for future time
intervals. The EPM 9900 meter uses the delta rate of change of a Rolling Window Demand
interval to predict average demand for an approaching time period. The user can set a
relay or alarm to signal when the Predictive Window reaches a specific level, thereby
avoiding unacceptable demand levels. The EPM 9900 calculates Predictive Window
Demand using the following formula.
Example:
Using the previous settings of 3 five-minute intervals and a new setting of 120% prediction
factor, the working of the Predictive Window Demand could be described as follows:
At 12:10, we have the average of the subintervals from 11:55-12:00, 12:00-12:05 and
12:05-12:10. In five minutes (12:15), we will have an average of the subintervals 12:0012:05 and 12:05-12:10 (which we know) and 12:10-12:15 (which we do not yet know). As a
guess, we will use the last subinterval (12:05-12:10) as an approximation for the next
subinterval (12:10-12:15). As a further refinement, we will assume that the next subinterval
might have a higher average (120%) than the last subinterval. As we progress into the
subinterval, (for example, up to 12:11), the Predictive Window Demand will be the average
of the first two subintervals (12:00-12:05, 12:05-12:10), the actual values of the current
subinterval (12:10-12:11) and the prediction for the remainder of the subinterval, 4/5 of the
120% of the 12:05-12:10 subinterval.
2–8
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 2: OVERVIEW AND SPECIFICATIONS
# of Subintervals = n
Subinterval Length = Len
Partial Subinterval Length = Cnt
Prediction Factor = Pct
Subn
Sub1
Sub0
Partial
Predict
Len
Len
Len
Cnt
Len
Len – 1

Value i
i=0
Sub = -----------------------------------Len
Cnt – 1

n –2
Value i
i=0

i=0
(EQ 2.21)
n –2
Measured
Values
 Subi
Value i
Partial = ------------------------------- Partial + -------------------------- × 1 –
Cnt
n
2.4.2
(EQ 2.20)
Sub0 – Subn – 1
+ --------------------- + -------------------------------------- ×
2x ( n – 1 )
n–1
Len
– Cnt
-----------------------× Pct
Len
i=0
Len
– Cnt
-----------------------× Pct
Len
The EPM 9900 submeter provides the following Measured Values all in Real Time and some
additionally as Avg, Max and Min values.
Table 2–1: EPM 9900 Meter Measured Values.
Measured Values
Real Time
Avg
Max
Voltage L-N
X
X
Voltage L-L
X
X
Min
Current Per Phase
X
X
X
X
Current Neutral
X
X
X
X
Watts (A,B,C,Total)
X
X
X
X
VAR (A,B,C,Total)
X
X
X
X
VA (A,B,C,Total)
X
X
X
X
PF (A,B,C,Total)
X
X
X
X
+Watt-Hr (A,B,C,Tot)
X
- Watt-Hr (A,B,C,Tot)
X
X
X
Watt-Hr Net
X
+VAR-Hr (A,B,C,Tot)
X
-VAR-Hr (A,B,C,Tot)
X
VAR-Hr Net
X
VA-Hr (A,B,C,Total)
X
Frequency
X
Voltage Angles
X
Current Angles
X
% of Load Bar
X
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
2–9
CHAPTER 2: OVERVIEW AND SPECIFICATIONS
2.4.3
Utility Peak
Demand
The EPM 9900 meter provides user-configured Block (Fixed) Window or Rolling Window
Demand. This feature allows you to set up a Customized Demand Profile. Block Window
Demand is demand used over a user-configured demand period (usually 5, 15 or 30
minutes). Rolling Window Demand is a fixed window demand that moves for a userspecified subinterval period. For example, a 15-minute Demand using 3 subintervals and
providing a new demand reading every 5 minutes, based on the last 15 minutes.
Utility Demand Features can be used to calculate kW, kVAR, kVA and PF readings. All other
parameters offer Max and Min capability over the user-selectable averaging period.
Voltage provides an Instantaneous Max and Min reading which displays the highest surge
and lowest sag seen by the meter.
2.5
2.5.1
Ordering
Order Codes
Table 2–2: EPM 9900 Order Codes
PL9900
Base Unit
Control
Power
Frequency
Current
Inputs
Software
I/O Modules
(Slot 1)
(Slot 2)
(Slot 3)
(Slot 4)
2–10
PL9900
–
*
–
*
–
*
–
*
–
*
–
*
–
*
–
*
|
|
|
|
|
|
|
|
AC
HI
LD
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5
6
|
|
1A
5A
|
|
|
|
A
B
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
C
|
|
|
S
X
|
|
E1
|
|
|
E2
|
X
|
R1
D1
X
Description
EPM 9900 Multi-function metering
system
100 to 240 VAC Power Supply
90 to 265 VAC or 100 to 240 VDC
18 to 60 VDC (24 to 48 VDC Systems)
50 Hz AC frequency system
60 Hz AC frequency system
1 Amp
5 Amps
128 MB with 512 samples/cycle
1 GB memory with 1024 samples/cycle,
IEC 61850 Communications Protocol
| 1 GB memory with 1024 samples/ cycle,
IEC 61850 Communications Protocol and
10MHz Transient Recording
| 2-ports RS485 and 4 Pulse outputs
| Empty slot
| Second Ethernet Port, 10/100BaseTX,
RJ45
| Second Ethernet Port, 100FX, Multimode,
ST connector
| Empty slot
| 6 Relay outputs
| 16 Status inputs
| Empty slot
R1 6 Relay outputs
D1 16 Status inputs
X Empty slot
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 2: OVERVIEW AND SPECIFICATIONS
2.5.2
EPM Accessories
This section describes accessories for the EPM 9900 which are available separately for the
meter.
External Input/Output (I/O) Modules
The following external (I/O) modules are available:
External modules and accessories must be ordered separately from base meters.
Note
NOTE
Analog output modules:
PL9000 – * – * – * – * – * – * – * – 0 – 0
1
M
A
O
N
4
0
1
M
A
O
N
8
0
2
O
M
A
O
N
4
2
O
M
A
O
N
8
Four channel 0 to 1 mA analog outputs
Eight channel 0 to 1 mA analog outputs
Four channel 4 to 20 mA analog outputs
Eight channel 4 to 20 mA analog outputs
Analog input modules:
PL9000 – * – * – * – * – * – * – * – 0 – 0
8
A
I
1
0
0
0
0
0
8
A
I
2
0
0
0
0
0
8
A
I
3
0
0
0
0
0
8
A
I
4
0
0
0
0
0
Eight channel 0 to 1 mA analog inputs
Eight channel 0 to 20 mA analog inputs
Eight channel 0 to 5 V DC analog inputs
Eight channel 0 to 10 V DC analog inputs
Digital output modules:
PL9000 – * – * – * – * – 0 – 0 – 0 – 0 – 0
4
R
0
1
4
P
0
1
Four channel control relay outputs
Four channel KYZ solid-state pulse outputs
Auxiliary output power supply and mounting:
PL9000 – * – * – I – O – 0 – 0 – 0 – 0 – 0
M
B
I
O
0
0
0
0
0
P
S
I
O
0
0
0
0
0
Mounting bracket
(required for external modules)
Auxiliary power supply
(required for external modules)
Expandable Input/Output (I/O) Cards
The following table describes the expandable communications cards available for the EPM
9900 for specific slots.
Table 2–3: Expandable I/O Cards
Part Number
Description
I/O
Module
PL9900-ACC-SXX
2-ports RS485 and 4 Pulse Outputs
Slot 1
PL9900-ACC-E1X
Second Ethernet Port, 10/100BaseTX, RJ45
Slot 2
PL9900-ACC-E2X
Second Ethernet Port, 100FX, Multimode, ST
connector
Slot 2
PL9900-ACC-R1X
6 Relay Outputs
Slot 3
PL9900-ACC-D1X
16 Status Inputs
Slot 3
PL9900-ACC-R1X (same as Slot 3)
6 Relay Outputs
Slot 4
PL9900-ACC-D1X (same as Slot 3)
16 Status Inputs
Slot 4
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
2–11
CHAPTER 2: OVERVIEW AND SPECIFICATIONS
Upgrade Software Options
The following table describes the options available for upgrading software for the EPM
9900.
Table 2–4: Upgrade Software
Part Number
Description
PL9900-ACC-SAB
Upgrad Software option A to B: 1GB memory with 1024 samples/
cycle, IEC 61850 Communications Protocol
PL9900-ACC-SAC
Upgrad Software option A to C: 1GB memory with 1024 samples/
cycle, IEC 61850 Communications Protocol and 10MHz Transient
Recording
PL9900-ACC-SBC
Upgrad Software option B to C: 1GB memory with 1024 samples/
cycle, IEC 61850 Communications Protocol and 10MHz Transient
Recording
2.6
Specifications
POWER SUPPLY
Range:.................................................115 VAC Option:
UL Rated to (100-240)VAC ± 10% @50/60Hz
HI: Universal, (90-265)VAC @50/60Hz
or (100-240)VDC
LD: UL rated to (18-60) VDC
Power Consumption:....................(18 to 25)VA, (15 to 25)W depending on the meter's hardware
configuration
Connection: ......................................3 Pin 0.300" Pluggable Terminal
Block
Torque:3.5 Lb-In
AWG#12-24, Solid or Stranded
NoteNotes:
Branch circuit protection size should be 15 Amps.
VOLTAGE INPUTS
UL Measurement Category:......Category III
Range:.................................................Universal, Auto-ranging:
Phase to Neutral (Va, Vb, Vc, Vaux
to Neutral): (5 - 347) VAC
Phase to Phase (Va to Vb, Vb to Vc,
Vc to Va): (10 - 600) VAC
Supported hookups:.....................3 Element Wye, 2.5 Element Wye, 2
Element Delta, 4 Wire Delta
Input Impedance: ..........................5M Ohm/Phase
Burden: ..............................................0.072 VA/Phase Max at 600 Volts;
0.003VA/Phase Max at 120 Volts
Pickup Voltage: ...............................5 VAC
Connection: ......................................6 Pin 0.600" Pluggable Terminal
Block
Torque: 5 Lb-in
AWG#12 -24, Solid or Stranded
Fault Withstand:.............................Meets IEEE C37.90.1
Reading: .............................................Programmable Full Scale to any PT
Ratio
2–12
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 2: OVERVIEW AND SPECIFICATIONS
CURRENT INPUTS
Class 20: ........................................... 5 A Nominal, 20 A Maximum
Class 2: .............................................. 1 A Nominal, 2 A Maximum
Burden: .............................................. 0.008 VA Per Phase Max at 20 Amps
Pickup Current:............................... 0.1% of nominal
Connections: ................................... O Lug or U Lug electrical connection (Figure 4-1)
Tighten with #2 Philips screwdriver
Torque- 8 Lb-In
Pass through wire, 0.177" / 4.5mm
Maximum Diameter (Figure 4-2)
Quick connect, 0.25" Male Tab
(Figure 4-3)
Current Surge Withstand (at 23 ºC):
100 A/10 sec, 300 A/3 sec, 500 A/1 sec
Reading: ............................................ Programmable Full Scale to any CT Ratio
Continuous Current Withstand:
20 Amps; for sustained loads greater than 10 Amps use
Pass-through wiring method (see Chapter 4 for instructions).
FREQUENCY
Range: ................................................ (45 - 69.9) Hz
OPTIONAL RS485 PORT SPECIFICATIONS
RS485 Transceiver; meets or exceeds EIA/TIA-485 Standard:
Type:.................................................... Two-wire, half duplex
Min. Input Impedance:................ 96 kΩ
Max. Output Current:................... ±60 mA
ISOLATION
All Inputs to Outputs are isolated to 2500 VAC.
ENVIRONMENTAL RATING
Operating:......................................... (-20 to +70) °C
Storage: ............................................. (-30 to +80) °C
Humidity:........................................... up to 95% RH Non-condensing
Pollution Degree:........................... 2
Altitude:.............................................. Maximum Rated - 2000 M
MEASUREMENT METHODS
Voltage, Current:............................ True RMS
UPDATE RATE
High speed readings ................... 100 msec
Revenue-accurate readings.... 1 sec
COMMUNICATION
Standard ........................................... 10/100BaseT Ethernet
ANSI Optical Port
USB 1.1/2.0 Port, Full speed
Optional, through I/O card slot
Dual RS485 Serial Ports
Second 10/100 BaseT Ethernet or
100Base-FX Fiber Optic Ethernet
Protocols .......................................... Modbus RTU, Modbus ASCII, DNP 3.0, IEC 61850 (Software Option 2 and
above)
Com Port Baud Rate.................... 9600 to 115200 bps
Com Port Address ........................ 1-247 - Modbus protocol
1-65535 - DNP protocol
Data Format.................................... 8 Bit, No Parity
MECHANICAL PARAMETERS
Dimensions: see Chapter 3.
Weight:............................................... 3.9 lbs
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
2–13
CHAPTER 2: OVERVIEW AND SPECIFICATIONS
COMPLIANCE
Test
Reference Standard
Level/Class
Electrostatic Discharge
EN/IEC61000-4-2
Level 3
RF immunity
EN/IEC61000-4-3
10 V/m
Fast Transient Disturbance
EN/IEC61000-4-4
Level 3
Surge Immunity
EN/IEC61000-4-5
Level 3
Conducted RF Immunity
EN/IEC61000-4-6
Level 3
Radiated & Conducted Emissions
EN/IEC61000-6-4/
CISPR 11
Class A
Power magnetic frequency
EN/IEC61000-4-8
Level 4
Voltage Dip & interruption
EN/IEC61000-4-11
0, 40, 70, 80% dips, 250/300 cycle
interrupts
Power quality measurement
IEC61000-4-30
Class A
Harmonics
EN/IEC61000-4-2
Class A
Flicker/Limits
EN/IEC61000-3-3
APPROVALS
Applicable Council Directive
CE compliance
According to:
Low voltage directive
EN/IEC61010-1
EMC Directive
EN61000-6-2
EN61000-6-4
North America
cULus Listed
UL61010-1 (PICQ)
C22.2.No 61010-1 (PICQ7)
ISO
2–14
Manufactured under a registered
quality program
ISO9001
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 2: OVERVIEW AND SPECIFICATIONS
2.7
Accuracy (For full Rating specifications, see Table 2–4: Upgrade
Software)
Test conditions:
• 23 °C
• 3-phase balanced load
• 50 or 60 Hz (as per order)
• 5A (Class 10) Nominal unit
Parameter
Voltage L-N [V]
Accuracy
Accuracy Input Range1
0.1% of reading
(69 to 480)V
2
Voltage L-L [V]
0.2% of reading
(120 to 600)V
Current Phase [A]
0.1% of reading1,3
(0.15 to 5)A
1
(0.15 to 5)A @ (45-65)Hz
Current Neutral
(Calculated) [A]
2.0% F.S.
Active Power Total [W]
0.2% of reading1,2
(0.15 to 5)A @ (69 to 480)V @ +/-(0.5 to 1) lag/lead PF
Active Energy Total [Wh]
0.2% of reading1,2
(0.15 to 5)A @ (69 to 480)V @ +/-(0.5 to 1) lag/lead PF
Reactive Power Total
[VAR]
0.2% of reading
1,2
(0.15 to 5)A @ (69 to 480)V @ +/-(0.5 to 1) lag/lead PF
Reactive Energy Total
[VARh]
0.2% of reading1,2
(0.15 to 5)A @ (69 to 480)V @ +/-(0.5 to 1) lag/lead PF
Apparent Power Total [VA]
0.2% of reading1,2
(0.15 to 5)A @ (69 to 480)V @ +/-(0.5 to 1) lag/lead PF
Apparent Energy Total
[VAh]
0.2% of reading1,2
(0.15 to 5)A @ (69 to 480)V @ +/-(0.5 to 1) lag/lead PF
Power Factor
0.2% of reading1,2
(0.15 to 5)A @ (69 to 480)V @ +/-(0.5 to 1) lag/lead PF
Frequency [Hz]
0.03Hz
(45 to 65)Hz
Load Bar
+/- 1 segment
(0.005 to 6)A
1
• For 2.5 element programmed units, degrade accuracy by an additional 0.5% of
reading.
• For 1A (Class 2) Nominal, degrade accuracy by an additional 0.5% of reading.
• For 1A (Class 2) Nominal input current range for accuracy specification is 20% of
the values listed in the table.
2 For unbalanced voltage inputs where at least one crosses the 150V autoscale threshold
(for example, 120V/120V/208V system), degrade the accuracy to 0.4% of reading.
3
With reference voltage applied (VA, VB, or VC). Otherwise, degrade accuracy to 0.2%. See
hookup diagrams 8, 9, and 10 in Chapter 4.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
2–15
CHAPTER 2: OVERVIEW AND SPECIFICATIONS
2–16
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
GE Energy
EPM 9900 Electronic Meter
Chapter 3: Mechanical Installation
Mechanical Installation
3.1
Overview
The EPM 9900 meter is mounted in a panel. The various models use the same installation.
See Electrical Installation chapter for wiring diagrams.
Mount the meter in a dry location, which is free from dirt and corrosive substances.
Note
NOTE
3.1.1
The figures shown in this chapter depict horizontal installation, but you can also mount the
meter vertically. You can then rotate the display screens to support vertical installation
(see Chapter 6 for instructions).
Mounting the EPM 9900 Meter
The EPM 9900 meter is designed to mount in a panel. Refer to Section 3.2 for meter and
panel cut-out dimensions, and Section 3.3 for mounting instructions.
To clean the unit, wipe it with a clean, dry cloth.
Maintain the following conditions:
• Operating Temperature: -20°C to +70°C / -4.0°F to +158°F
• Storage Temperature: -30°C to +80°C / -22°F to +176°F
• Relative Humidity: 95% non-condensing
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
3–1
CHAPTER 3: MECHANICAL INSTALLATION
3.1.2
Meter and Panel Cut-out Dimensions
Figure 3-1: Meter Dimensions (Front)
Figure 3-2: Meter Back View
10.74”
[27.28cm]
7.49”/19.02cm
4.44”/11.28cm
6.96” [17.68cm]
6.74” [17.12cm]
Figure 3-3: Meter Top View
Figure 3-4: Meter Side View
1.87”
[4.75cm]
7.50”
[ 19.05cm]
6.91”
[17.55cm]
5.04”
[12.80cm]
5.73”
[14.55cm]
5.94” [15.09cm]
4.44” [11.28cm]
4.56”/11.58cm
Figure 3-5: Optional Octagonal Cutout Dimensions Figure 3-6: Optional Rectangular Cutout Dimensions
7.63”/19.38cm
3.1.3
3–2
Mounting Instructions
1.
Slide the meter into the panel.
2.
From the back of the panel, slide 4 mounting brackets into the grooves on the top and
bottom of the meter housing (2 fit on the top and 2 fit on the bottom).
3.
Snap the mounting brackets into place.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 3: MECHANICAL INSTALLATION
4.
Secure the meter to the panel with lock washer and a #8 screw in each of the 4
mounting brackets (see Figure 3.4).
5.
Tighten the screws with a #2 Phillips screwdriver. Do not over-tighten. Maximum
installation torque is 3.5 lb-in.
If necessary, replacement mounting brackets (Part number PL9000MBIO00000) may be
purchased from GE Digital Energy.
Note
NOTE
Figure 3-7: Mounting the Meter
Panel
Mounting Brackets
Grooves
#8 Screw
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
3–3
CHAPTER 3: MECHANICAL INSTALLATION
3.2
Mounting the Optional External I/O Modules
• Secure the mounting brackets to the I/O module using the screws supplied (#440
pan-head screws). Next, secure the brackets to a flat surface using a #8 screw
with a lock washer.
• If multiple I/O modules are connected together as shown in Figure 3.5, secure a
mounting bracket to both ends of the group. Connect multiple I/O modules using
the RS485 side ports. The EPM 9900 meter does not have internal power for I/O
modules: use an additional power supply, such as the GE Digital Energy PSIO. See
Using the I/O Options Chapter for additional information.
Figure 3-8: External I/O Modules Mounting Dimensions, Front View
Mounting Bracket
Mounting Bracket
6.879”/13.088cm
On
Power In
N(-)
!
L(+)
3.437”/8.729cm
DANGER
Power PSIO
Supply
2.200”/5.588cm
Max Power: 12 VA
Input Voltage: 12-60V DC
1.100”/2.54cm
90-240V AC/DC
Output Voltage: 12V DC
ElectroIndustries/GaugeTech
.618”/1.570cm
1.301”/3.305cm
Figure 3-9: External I/O Module Communication Ports and Mounting Brackets
Female RS485
Side Port
I/O Port
(Size and Pin
Configuration Vary)
3–4
Male RS485
Side Port
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 3: MECHANICAL INSTALLATION
Figure 3-10: External I/O Modules Mounting Diagram, Overhead View
5.629”/14.30cm
3X 1.301”/3.305cm
1.125”/2.858cm
Mounting Bracket
.090”/.229cm
Mounting Bracket
4.188”/10.638cm
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
3–5
CHAPTER 3: MECHANICAL INSTALLATION
3–6
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
GE Energy
EPM 9900 Electronic Meter
Chapter 4: Electrical Installation
Electrical Installation
4.1
Note
Note
NOTE
Safety Considerations When Installing Meters
•
Installation of the EPM 9900 meter must be performed only by qualified personnel
who follow standard safety precautions during all procedures. Those personnel should
have appropriate training and experience with high voltage devices. Appropriate
safety gloves, safety glasses and protective clothing are recommended.
•
During normal operation of the EPM 9900 meter, dangerous voltages flow through
many parts of the meter, including: Terminals and any connected CTs (Current
Transformers) and PTs (Potential Transformers), all I/O (Inputs and Outputs) and their
circuits. All Primary and Secondary circuits can, at times, produce lethal voltages and
currents. Avoid contact with any current-carrying surfaces.
•
Do not use the meter for primary protection or in an energy-limiting capacity. The
meter can only be used as secondary protection.
•
Do not use the meter for applications where failure of the meter may cause harm or
death.
•
Do not use the meter for any application where there may be a risk of fire.
•
All meter terminals should be inaccessible after installation.
•
Do not apply more than the maximum voltage the meter or any attached device can
withstand. Refer to meter and/or device labels and to the Specifications for all devices
before applying voltages.
•
Do not HIPOT/Dielectric test any Outputs, Inputs or Communications terminals.
•
To prevent hazardous voltage conditions, the use of fuse branch circuit protection for
voltage leads and the power supply are required.
To prevent CT damage and potential injuries, shorting blocks for CT circuits are
required if the meter needs to be removed from service.
The current inputs are only to be connected to external current transformers provided by
the installer. The CTs shall be Approved or Certified and rated for the current of the meter
used.
•
Branch circuit protection size should be 15 Amps.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
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CHAPTER 4: ELECTRICAL INSTALLATION
Note
Note
Note
4–2
•
For sustained loads greater than 10 Amps, the CT wires should be wired directly
through the CT opening (pass through wiring method - see CT Leads Pass Through (No
Meter Termination), using 10 AWG wire.
•
IF THE EQUIPMENT IS USED IN A MANNER NOT SPECIFIED BY THE MANUFACTURER,
THE PROTECTION PROVIDED BY THE EQUIPMENT MAY BE IMPAIRED.
•
THERE IS NO REQUIRED PREVENTIVE MAINTENANCE OR INSPECTION NECESSARY
FOR SAFETY. HOWEVER, ANY REPAIR OR MAINTENANCE SHOULD BE PERFORMED BY
THE FACTORY.
•
DISCONNECT DEVICE: The following part is considered the equipment disconnect
device. A SWITCH OR CIRCUIT-BREAKER SHALL BE INCLUDED IN THE END-USE
EQUIPMENT OR BUILDING INSTALLATION. THE SWITCH SHALL BE IN CLOSE
PROXIMITY TO THE EQUIPMENT AND WITHIN EASY REACH OF THE OPERATOR. THE
SWITCH SHALL BE MARKED AS THE DISCONNECTING DEVICE FOR THE EQUIPMENT.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 4: ELECTRICAL INSTALLATION
4.2
CT Leads Terminated to Meter
The EPM 9900 meter is designed to have current inputs wired in one of three ways. Figure
4-1 shows the most typical connection where CT Leads are terminated to the meter at the
current gills. This connection uses nickel-plated brass rods with screws at each end. This
connection allows the CT wires to be terminated using either an "O" or a "U" lug. Tighten
the screws with a #2 Phillips screwdriver (Torque- 8 Lb-In).
Figure 4-1: CT Leads terminated to Meter, #8 Screw for Lug Connection
Other current connections are shown in sections 4.2 and 4.3. Voltage and RS485/KYZ
connections can be seen in Figure 4-4.
Wiring diagrams are shown in the Wiring Diagrams section of this chapter;
Communications connections are detailed in the Communication Installation chapter.
Note
For sustained loads greater than 10 Amps, use pass through wiring method (Section
4.3), using 10 AWG wire.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
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CHAPTER 4: ELECTRICAL INSTALLATION
4.3
CT Leads Pass Through (No Meter Termination)
The second method allows the CT wires to pass through the CT inputs without terminating
at the meter. In this case, remove the current gills and place the CT wire directly through
the CT opening. The opening accommodates up to 0.177"/4.5mm maximum diameter CT
wire.
Figure 4-2: Pass Through Wire Electrical Connection
Note
4–4
For sustained loads greater than 10 Amps, use 10 AWG wire.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 4: ELECTRICAL INSTALLATION
4.4
Quick Connect Crimp-on Terminations
You can use 0.25" Quick Connect Crimp-on connectors for quick termination or for
portable applications.
Figure 4-3: Quick Connect Electrical Connection
Note
For sustained loads greater that 10 Amps, use pass through wiring method (Section
4.3), using 10 AWG wire.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
4–5
CHAPTER 4: ELECTRICAL INSTALLATION
4.5
Wiring the Monitored Inputs and Voltages
Select a wiring diagram from Section 4.12 that best suits your application and wire the
meter exactly as shown. For proper operation, the voltage connection must be maintained
and must correspond to the correct terminal. Program the CT and PT ratios in the Device
Profile section of the GE Communicator software; see the GE Communicator User Manual
for details.
Figure 4-4: Voltage and Power Supply Connections, RS485, Pulse Outputs, IRIG-B,
10/100BaseT Ethernet, High-Speed Inputs, Fiber Optic Connection, and Relay Outputs
10/100BaseT
Ethernet RS485 Connections
Fiber Optic Connection
Relay Outputs
IRIG-B
Voltage
Connection
Power Supply
Connection
(Shown for options
115AC or HI. See
section 4.11.3 for an
option LD connecton.)
8
4
High-Speed
Pulse
Inputs
Outputs
The cable required to terminate the voltage sense circuit should have an insulation rating
greater than 600VAC and a current rating greater than 0.1 A.
Voltage inputs
•
Wire type: Solid or stranded
•
Wire gauge: 12-24 AWG for either solid or stranded wire
•
Strip length: 7-8 mm
•
Torque: 5 Lb-In
Power supply connections
4–6
•
Wire gauge: 12-18 AWG for either solid or stranded wire
•
Torque: 3.5 Lb-In
•
Branch circuit protection size should be 15 A.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 4: ELECTRICAL INSTALLATION
4.6
Ground Connections
The meter's PE GND terminal should be connected directly to the installation's protective
earth ground. Use green or green with yellow jacketed AWG#12/2.5 mm2 wire for this
connection.
4.7
Fusing the Voltage Connections
For accuracy of the readings and for protection, GE Digital Energy requires using 0.1-Amp
rated fuses on all voltage inputs.
The EPM 9900 meter allows measurement up to a nominal 347VAC phase to neutral and
up to 600VAC phase to phase. Potential Transformers (PTs) are required for higher voltages
to insure proper safety.
Use a 3 Amp Slow-Blow fuse on the power supply for control power.
4.8
Wiring the Monitored Inputs - Vaux
The Voltage Auxiliary (Vaux) connection is an auxiliary voltage input that can be used for
any desired purpose, such as monitoring two different lines on a switch. The Vaux Voltage
rating is the same as the metering Voltage input connections.
4.9
Wiring the Monitored Inputs - Currents
Mount the current transformers (CTs) as close as possible to the meter. The following table
illustrates the maximum recommended distances for various CT sizes, assuming the
connection is via 14 AWG cable.
GE Digital Energy Recommendations
CT Size (VA)
Maximum distance from CT to EPM 9900 Meter
(Feet)
2.5
10
5
15
7.5
30
10
40
15
60
30
120
DO NOT leave the secondary of the CT open when primary current is flowing.
This may cause high voltage on open secondary CT which could be potentially lethal to
humans and destructive to equipment itself.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
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CHAPTER 4: ELECTRICAL INSTALLATION
If the CT is not connected, provide a shorting block on the secondary of the CT.
It is important to maintain the polarity of the CT circuit when connecting to the EPM 9900
meter. If the polarity is reversed, the meter will not provide accurate readings. CT polarities
are dependent upon correct connection of CT leads and the direction CTs are facing when
clamped around the conductors. Although shorting blocks are not required for proper
meter operation, GE Digital Energy recommends using shorting blocks to allow removal of
the EPM 9900 meter from an energized circuit, if necessary.
4.10 Isolating a CT Connection Reversal
For a Wye System, you may either:
•
Check the current phase angle reading on the EPM 9900 meter's display (see
Chapter 6). If it is negative, reverse the CTs.
•
Go to the Phasors screen of the GE Communicator software (see the GE
Communicator User Manual for instructions). Note the phase relationship between the
current and voltage: they should be in phase with each other.
For a Delta System:
Go to the Phasors screen of the GE Communicator software program (see the GE
Communicator User Manual for instructions). The current should be 30 degrees off the
phase-to-phase voltage.
4.11 Instrument Power Supply Connections
The EPM 9900 meter requires a separate power source. There are three optional power
supplies: 115AC, HI High-Voltage, and LD Low-Voltage.
Note
4–8
The power supply connections vary depending on the power supply option being used.
CAREFULLY follow the instructions and drawings in Sections 4.11.1-4.11.3 for proper
wiring.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 4: ELECTRICAL INSTALLATION
4.11.1 115AC Power Supply
1. Connect Line
Supply Wire
to L(+).
2. Connect
Neutral
Supply Wire
to N(-).
3. Connect earth
ground to
PE GND.
For the 115AC Option power supply:
1.
Connect the line supply wire to the L+ terminal.
2.
Connect the neutral supply wire to the N(-) terminal.
3.
Connect earth ground to the PE GND terminal.
Use a 3 Amp Slo-Blo fuse on the power supply.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
4–9
CHAPTER 4: ELECTRICAL INSTALLATION
4.11.2 HI High-Voltage Power Supply
1. Connect Line
Supply Wire
to L(+).
2. Connect
Neutral
Supply Wire
to N(-).
3. Connect earth
ground to
PE GND.
1.
For the HI Option power supply:
2.
Connect the line supply wire to the L+ terminal.
3.
Connect the neutral supply wire to the N- terminal.
4.
Connect earth ground to the PE GND terminal.
Use a 3 Amp Slo-Blo fuse on the power supply.
4.11.3 LD Low-Voltage Power Supply
Note
4–10
Note that the wiring for the LD Option power supply has the Positive and Negative
terminals REVERSED from the 115AC and HI models - BE CAREFUL to follow the
diagram and instructions shown.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 4: ELECTRICAL INSTALLATION
1. Connect the
Negative Voltage
to V(-).
2. Connect the
Positive Voltage
to V(+).
3. Connect earth
ground to
PE GND.
For the LD Option power supply:
1.
Connect the negative voltage to the V(-) terminal.
2.
Connect the positive voltage to the V(+) terminal.
3.
Connect earth ground to the PE GND terminal.
Use a 3 Amp Slo-Blo fuse on the power supply.
4.12 Wiring Diagrams
Choose the diagram that best suits your application. Diagrams appear on the following
pages. If the connection diagram you need is not shown, contact GE Digital Energy for a
custom connection diagram.
Service
PTs
CTs
Measurement
Method
Figure No.
4W Wye/Delta
0, Direct
Connect
3(4*)
3 Element
4.5
4W Wye/Delta
3
3(4*)
3 Element
4.6
4W Wye
2
3
2.5 Element
4.7
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
4–11
CHAPTER 4: ELECTRICAL INSTALLATION
Service
PTs
Measurement
Method
CTs
Figure No.
4W Wye
0, Direct
Connect
3
2.5 Element
4.8
3W Open Delta
2
2
2 Element
4.9
3W Open Delta
0, Direct
Connect
2
2 Element
4.10
*With optional CT for current measurement only.
4–12
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 4: ELECTRICAL INSTALLATION
Figure 4-5: 4-Wire Wye or Delta, 3-Element Direct Connect with 4 CTs
N/U
Va
HI
CTs
HI
HI
Vb
HI
ln
lc
lb
la
LO
LO
LO
LO
Vc
Vn
Vaux *
**
Vn
Vc
Vb
Va
C
C
A B C N
OR
B
A
A
B
* See Wiring the Monitored Inputs - Vaux section.
** Optional CT for current measurement only.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
4–13
CHAPTER 4: ELECTRICAL INSTALLATION
Figure 4-6: 4-Wire Wye or Delta, 3-Element with 3 PTs and 4 CTs
N/U
Va
Vb
CTs
Vc
Vn
Vaux *
**
Vn
PTs
Vc
Vb
Va
C
C
A B C N
OR
B
A
A
B
* See Wiring the Monitored Inputs - Vaux section.
** Optional CT for current measurement only.
4–14
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 4: ELECTRICAL INSTALLATION
Figure 4-7: 4-Wire Wye, 2.5-Element with 2 PTs and 3 CTs
Va
N/U
Vb
CTs
Vc
Vn
Vaux *
PTs
Vc
Vn
Va
C
A B C N
A
B
* See Wiring the Monitored Inputs - Vaux section.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
4–15
CHAPTER 4: ELECTRICAL INSTALLATION
Figure 4-8: 4-Wire Wye, 2.5-Element Direct Connect with 3 CTs
N/U
Va
Vb
CTs
Vc
Vn
Vaux *
Vn
Vc
Va
C
A B C N
A
B
* See Wiring the Monitored Inputs - Vaux section.
4–16
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 4: ELECTRICAL INSTALLATION
Figure 4-9: 3-Wire, 2-Element Open Delta with 2 PTs and 2 CTs
N/U
Va
Vb
Vc
Vn
CTs
Vaux *
PTs
Vc
Vb
Va
C
C
A B C
OR
B
A
B
A
* See Wiring the Monitored Inputs - Vaux section.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
4–17
CHAPTER 4: ELECTRICAL INSTALLATION
Figure 4-10: 3-Wire, 2-Element Open Delta Direct Voltage with 2 CTs
N/U
Va
Vb
Vc
Vn
CTs
Vaux *
Vc
Vb
Va
C
C
A B C
OR
B
A
B
A
* See Wiring the Monitored Inputs - Vaux section.
4–18
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
GE Energy
EPM 9900 Electronic Meter
Chapter 5: Communication
Installation
Communication Installation
5.1
Communication Overview
This chapter contains instructions for using the EPM 9900 meter's standard and optional
communication capabilities. The EPM 9900 meter offers the following communication
modes:
•
RJ45 100BaseT Ethernet connection (standard)
•
ANSI Optical port (standard)
•
USB 2.0 connection (standard)
•
Two RS485 communication ports (optional)
•
Second Ethernet connection - either RJ45 or Fiber Optic (optional)
5.2
RJ45 and Fiber Ethernet Connections
The standard RJ45 connection allows an EPM 9900 meter to communicate with multiple
PCs simultaneously. The RJ45 jack is located on the back of the meter. The EPM 9900
meter's Ethernet port conforms to the IEEE 802.3, 10BaseT and 100BaseT specifications
using unshielded twisted pair (UTP) wiring. GE Digital Energy recommends CAT5 for cabling.
For details on this connection, see the EPM 9900 Network Communications chapter.
The optional second Ethernet connection for the EPM 9900 meter consists of either an
RJ45 (E1) or a Fiber Optic (E2) Communication card. See Chapter 11 for details.
5.3
ANSI Optical Port
The Optical port lets the EPM 9900 meter communicate with one other device, e.g., a PC.
Located on the left side of the meter's face, it provides communication with the meter
through an ANSI C12.13 Type II Magnetic Optical Communications Coupler.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
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CHAPTER 5: COMMUNICATION INSTALLATION
5.4
USB Connection
The USB connection allows the EPM 9900 meter to communicate with a computer that has
a USB 1.1 or USB 2.0 Host port. The meter's USB port is configured to operate as a virtual
serial communication channel that the PC sees as a simple COM port with a baud rate of
up to 115200. The USB virtual serial communication channel:
•
Supports legacy applications that were designed to only work with a serial
communication channel
•
Is compatible with standard USB cables that terminate with a USB Type B plug (see
Figure 5.2)
•
The maximum length of the USB cable is 5 meters. Greater lengths require hubs or
active extension cables (active repeaters).
Figure 5-1: USB Type B Plug
If you are using a PC with Windows® 7 OS, connect the USB cable from your PC to the
meter’s USB port on the front panel. The system will install a driver for you. For earlier
operating systems, GE Communicator automatically installs the drivers for the EPM 9900
meter. The driver configures the computer's USB Host port as a virtual serial port
compatible with the EPM 9900 meter's USB device port. See Appendix A for instructions on
installing the driver.
5.5
RS485 Connections
The optional RS485 connections allow multiple EPM 9900 meters to communicate with
another device at a local or remote site. All RS485 links are viable for a distance of up to
4000 feet (1219 meters). RS485 ports 1 and 2 on the EPM 9900 meter are optional twowire, RS485 connections with a baud rate of up to 115200.
You need to use an RS485 to Ethernet converter, such as GE Digital Energy's Multinet. See
Section 5.5.1 for information on using the Multinet with the EPM 9900 meter.
You can order the Multinet from GE Digital Energy’s webstore:
www.gedigitalenergy.com.
Note
NOTE
Figure 5.3 shows the detail of a 2-wire RS485 connection.
Figure 5-2: 2-wire RS485 Connection
EPM 9900
Meter’s RS485
Port
5–2
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 5: COMMUNICATION INSTALLATION
NOTES on RS485 Communication:
• Use a shielded twisted pair cable 22 AWG (0.33 mm2) or thicker, and ground the
shield, preferably at one location only.
• Establish point-to-point configurations for each device on a RS485 bus: connect (+)
terminals to (+) terminals; connect (-) terminals to (-) terminals.
• Connect up to 31 meters on a single bus using RS485. Before assembling the bus,
each meter must have a unique address: refer to Chapter 5 of the GE
Communicator User Manual for instructions.
• Protect cables from sources of electrical noise.
• Avoid both "Star" and "Tee" connections (see Figure 5.5).
• Connect no more than two cables at any one point on an RS485 network, whether
the connections are for devices, converters, or terminal strips.
• Include all segments when calculating the total cable length of a network. If you
are not using an RS485 repeater, the maximum length for cable connecting all
devices is 4000 feet (1219 meters).
• Connect shield to RS485 Master and individual devices as shown in Figure 5.4. You
may also connect the shield to earth-ground at one point.
Termination Resistors (RT) may be needed on both ends for longer length transmission
lines. However, since the meter has some level of termination internally, Termination
Resistors may not be needed. When they are used, the value of the Termination
Resistors is determined by the electrical parameters of the cable.
Note
Figure 5.4 shows a representation of an RS485 Daisy Chain connection. Refer to Section
5.5.1 for details on RS485 connection for the Multinet.
Figure 5-3: RS485 Daisy Chain Connection
Master device
Last Slave device N
RT
SH
+
RT
-
Twisted pair, shielded (SH) cable
Slave device 1
Slave device 2
SH
SH
+
-
Twisted pair, shielded (SH) cable
+
-
SH
+
-
Twisted pair, shielded (SH) cable
Earth Connection, preferably at
single location
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
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CHAPTER 5: COMMUNICATION INSTALLATION
Figure 5-4: Incorrect "T" and "Star" Topologies
Slave device 1
SH
+
-
Long stub results “T” connection that can cause
interference problem!
Master device
Last Slave device N
RT
RT
Slave device 2
SH +
-
SH
Twisted pair, shielded (SH) cable
+
-
SH
Twisted pair, shielded (SH) cable
+
-
Twisted pair, shielded (SH) cable
Earth Connection, preferably at
single location
Twisted pair, shielded (SH) cable
Twisted pair, shielded (SH) cable
Slave device 1
Slave device 2
SH +
-
-
Master device
SH
+
SH
+
-
“STAR” connection can cause interference
problem!
-
SH
Slave device 3
5–4
Using the
Multinet
+
Slave device 4
Twisted pair, shielded (SH) cable
5.5.1
+ SH
Twisted pair, shielded (SH) cable
The Multinet provides RS485/Ethernet connection, allowing an EPM 9900 meter with the
optional RS485 port to communicate with a PC. See the Multinet Installation and Operation
Manual for additional information.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 5: COMMUNICATION INSTALLATION
5.6
Remote Communication with RS485
Use either optional RS485 port on the EPM 9900 meter. The link using RS485 is viable for up
to 4000 feet (1219 meters).
Use GE Communicator software to set the port's baud rate to 9600 and enable Modbus
ASCII protocol. See Chapter 5 of the GE Communicator User Manual for instructions.
Remember, Modbus RTU will not function properly with Modem communication. You must
change the protocol to Modbus ASCII.
You must use an RS485 to RS232 converter and a Null modem. GE Digital Energy
recommends using its F485 converter that enables devices with different baud rates to
communicate. It also eliminates the need for a Null modem and automatically programs
the modem to the proper configuration. Also, if the telephone lines are poor, Modem
Manager acts as a line buffer, making the communication more reliable.
Figure 5-5: Remote Communication
EPM 9900 Meter
805701A1.CDR
F485 converter
5.7
Programming Modems for Remote Communication
You must program a modem before it can communicate properly with most RS485 or
RS232-based devices. This task is often quite complicated because modems can be
unpredictable when communicating with remote devices.
If you are not using the GE Digital Energy Modem Manager device, you must set the
following strings to communicate with the remote EPM 9900 meter(s). Consult your
modem’s User manual for the proper string settings or see Section 5.8 for a list of selected
modem strings.
Modem Connected to a Computer (the Originate Modem)
• Restore modem to factory settings. This erases all previously programmed
settings.
• Set modem to display Result Codes. The computer will use the result codes.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
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CHAPTER 5: COMMUNICATION INSTALLATION
• Set modem to Verbal Result Codes. The computer will use the verbal result codes.
• Set modem to use DTR Signal. This is necessary for the computer to insure
connection with the originate modem.
• Set modem to enable Flow Control. This is necessary to communicate with remote
modem connected to the EPM 9900 meter.
• Instruct modem to write the new settings to activate profile. This places these
settings into nonvolatile memory; the setting will take effect after the modem
powers up.
Modem Connected to the EPM 9900 Meter (the Remote Modem)
• Restore modem to factory settings. This erases all previously programmed
settings.
• Set modem to auto answer on n rings. This sets the remote modem to answer the
call after n rings.
• Set modem to ignore DTR Signal. This is necessary for the EPM 9900 meter, to
insure connection with originate modem.
• Set modem to disable Flow Control. The EPM 9900 meter’s RS232 communication
does not support this feature.
• Instruct modem to write the new settings to activate profile. This places these
settings into nonvolatile memory; the setting will take effect after the modem
powers up.
• When programming the remote modem with a terminal program, make sure the
baud rate of the terminal program matches the EPM 9900 meter’s baud rate.
5.8
Selected Modem Strings
Modem
5–6
String/Setting
Cardinal modem
AT&FE0F8&K0N0S37=9
Zoom/Faxmodem VFX
V.32BIS(14.4K)
AT&F0&K0S0=1&W0&Y0
Zoom/Faxmodem 56Kx Dual
Mode
AT&F0&K0&C0S0=1&W0&Y0
USRobotics Sportster 33.6
Faxmodem:
DIP switch setting
AT&F0&N6&W0Y0 (for 9600 baud)
Up Up Down Down Up Up Up
Down
USRobotics Sportster 56K
Faxmodem:
DIP switch setting
AT&F0&W0Y0
Up Up Down Down Up Up Up
Down
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 5: COMMUNICATION INSTALLATION
5.9
High Speed Inputs Connection
The EPM 9900 meter’s built-in High Speed Inputs can be used in two ways:
• Attaching status contacts from relays, breakers or other devices for status or
waveform initiation
• Attaching the KYZ pulse outputs from other meters for pulse counting and
totalizing
Even though these inputs are capable of being used as high speed digital fault recording
inputs, they serve a dual purpose as KYZ counters and totalizers. The function in use is
programmable in the meter and is configured via GE Communicator. Refer to the GE
Communicator User Manual for instructions on programming these features.
The High Speed Inputs can be used with either dry or wet field contacts. For wet contacts,
the common rides on a unit-generated Nominal 15 VDC. No user programming is
necessary to use either wet or dry field contacts.
Figure 5-6: High-Speed Inputs Connection
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
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CHAPTER 5: COMMUNICATION INSTALLATION
5.10 IRIG-B Connections
IRIG-B is a standard time code format that synchronizes event time-stamping to within 1
millisecond. An IRIG-B signal-generating device connected to the GPS satellite system
synchronizes EPM 9900 meters located at different geographic locations. EPM 9900
meters use an un-modulated signal from a satellite-controlled clock (such as Arbiter
1093B). For details on installation, refer to the User manual for the satellite-controlled clock
in use. Below are installation steps and tips to help you.
Connection:
Connect the (+) terminal of the EPM 9900 meter to the (+) terminal of the signal generating
device; connect the (-) terminal of the EPM 9900 meter to the (-) terminal of the signal
generating device.
Installation:
Set Time Settings for the meter being installed.
1.
From the GE Communicator Device Profile menu:
i
Click General Settings>Time Settings>one of the Time Settings lines
to open the Time Settings screen.
ii
Set the Time Zone and Daylight Savings (Select AutoDST or Enable and
set dates).
iii
Click Update Device Profile to save the new settings.
(See Chapter 5 of the GE Communicator User Manual for details.)
5–8
2.
Before connection, check that the date on the meter clock is correct (or, within 2
Months of the actual date). This provides the right year for the clock (GPS does not
supply the year).
3.
Connect the (+) terminal of the EPM 9900 meter to the (+) terminal of the signal
generating device; connect the (-) terminal of the EPM 9900 meter to the (-) terminal of
the signal generating device.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 5: COMMUNICATION INSTALLATION
Troubleshooting Tip: The most common source of problems is a reversal of the two wires.
If you have a problem, try reversing the wires.
Figure 5-1: IRIG-B Communication.
GP
S
Sa
tel
lite
Co
nn
ec
tio
n
IRIG-B Port
Note
+
+
-
-
IRIG-B Time
Signal
Generating
Device
Please make sure that the selected clock can drive the amount of wired loads.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
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CHAPTER 5: COMMUNICATION INSTALLATION
5.11 Time Synchronization Alternatives
(See the GE Communicator User Manual for details.)
IRIG-B
• All EPM 9900 meters are equipped to use IRIG-B for time synchronization.
• If IRIG-B is connected, this form of time synchronization takes precedence over the
internal clock. If the GPS Signal is lost, the internal clock takes over time keeping at
the precise moment the signal is lost.
Line Frequency Clock Synchronization
• All EPM 9900 meters are equipped with Line Frequency Clock Synchronization,
which may be enabled or disabled for use instead of IRIG-B. If Line Frequency Clock
Synchronization is enabled and power is lost, the internal clock takes over at the
precise moment power is lost.
Internal Clock Crystal
• All EPM 9900 meters are equipped with internal clocks crystals which are accurate
to 20ppm, and which can be used if IRIG-B is not connected and/or Line Frequency
Clock Synchronization is not enabled.
DNP Time Synchronization
• Using GE Communicator, you can set the meter to request time synchronization
from the DNP Master. Requests can be made from once per minute to once per
day.
Other Time Setting Tools
• Tools>Set Device Time: for manual or PC Time Setting
• Script & Scheduler: time Stamps Retrieved Logs and Data
• MV90: can synchronize time on retrievals in the form of a time stamp; refer to the
GE Communicator User Manual (HHF Converter) for more MV-90 details.
5–10
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
GE Energy
EPM 9900 Electronic Meter
Chapter 6: Using the EPM 9900
Meter’s Touch Screen
Display
Using the EPM 9900 Meter’s Touch Screen Display
6.1
Introduction
The EPM 9900 meter's display is a QVGA (320 x 240 pixel) LCD color display with touch
screen capability. The display screens are divided into two groups:
• Fixed System screens
• Dynamic screens
6.2
Fixed System Screens
There are eleven Fixed System screen options: Device Information, Communication
Settings, Board Settings, Device Status, System Message, Touch Screen Calibration, CF
S.M.A.R.T. Tool, IEC-61850, Task Info, CPU Stats, and SNTP. In addition, there is a Back
option, which brings you to the first Dynamic screen. To view a screen, touch the screen
name on the display
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CHAPTER 6: USING THE EPM 9900 METER’S TOUCH SCREEN DISPLAY
NOTES:
NoteES: NOTES
NOTE
• You will only see the System Message option if there are messages for you to view.
See the page 6-4 for additional information on the System Message screen.
• If you want to calibrate the touch screen, perform the following actions:
1.
Press and hold the Backlight button on
the right front panel of the meter for about
2 seconds.
2.
Press the "i" button at the top of the
Dynamic screen within ten seconds of
pressing the Backlight button.
3.
You will see the Fixed System screens
menu shown above. Touch "Touch Screen
Calibration." See the instructions for using
the Touch Screen Calibration screen on
page 6-5.
Backlight
Button
Device Information:
This screen displays the following information about the EPM 9900 meter:
6–2
•
Device type
•
Device name
•
Serial number
•
COMM boot version
•
COMM runtime version
•
DSP1 boot version
•
DSP1 runtime version
•
DSP2 runtime version
•
FPGA version
•
Touch screen version
•
CF (Compact Flash) model
•
CF (Compact Flash) serial number
•
CF (Compact Flash) FAT type
•
CF (Compact Flash) size
•
Software Option level enabled currently
•
Sealing switch status
•
Security (Password) status
•
Current range (The current range class of the meter)
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 6: USING THE EPM 9900 METER’S TOUCH SCREEN DISPLAY
See the example screen below. The Back button returns you to the initial Fixed System
screen.
Communication Settings:
This screen displays the following Communication port information:
•
RS485 Port 1 settings
•
RS485 Port 2 settings
•
USB port settings
•
Optical port settings
•
Ethernet Port 1 settings
•
Ethernet Port 2 settings
See the example screen below. The Back button returns you to the initial Fixed System
screen.
Board Settings:
This screen displays the following information:
•
Analogue board settings
•
Ethernet 1 board settings
•
Digital board settings
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CHAPTER 6: USING THE EPM 9900 METER’S TOUCH SCREEN DISPLAY
•
Front panel settings
•
Option card Slot 1 settings
•
Option card Slot 2 settings
•
Option card Slot 3 settings
•
Option card Slot 4 settings
See the example screen below. The Back button returns you to the initial Fixed System
screen.
Device Status:
This screen displays the following information:
•
COMM runtime state
•
DSP1 state
•
DSP2 state
•
Meter "On Time"
•
Ethernet port link state
See the example screen below. The Back button returns you to the initial Fixed System
screen.
6–4
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System Message:
This screen displays any system messages. The bottom of the screen will show Prev Page
and Next Page buttons only if there is more than one page of messages. See the example
screen below.
The Back button returns you to the initial Fixed System screen. NOTE: This option only
appears in the Fixed System screens menu if there are messages to display.
Touch Screen Calibration:
This screen is used to calibrate the touch screen display. When you select this option, a
series of four messages directs you in performing screen calibration. Each message tells
you to touch a corner of the screen where a small crosshair is located. Touching the
crosshair calibrates the display. Use a pointed tool to touch the calibration crosshairs.
See the example screen below, showing the first of the four messages.
When all four calibrations have been performed, a Calibrating Test screen is shown.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
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CHAPTER 6: USING THE EPM 9900 METER’S TOUCH SCREEN DISPLAY
Three crosshairs indicate places to touch. After each touch a red crosshair is shown to
verify the calibration. If the calibration is correct, press the Accept button; otherwise press
the Reject button, which causes the calibration process to start again. See the example
screen below.
NOTE: See page 6-1 for instructions on accessing Touch Screen Calibration.
CF S.M.A.R.T. Tool
The EPM 9900 meter uses an Industrial grade, specialized compact flash disk drive. This
drive has many features not found in commercial flash. One of these features is the
S.M.A.R.T. tool. This tool provides user accessed diagnostics on the health of the drive.
This screen displays compact flash S.M.A.R.T. (Self-Monitoring, Analysis, and Reporting
Technology) information. The S.M.A.R.T. must be supported and enabled to contain valid
data. The screen displays the following information:
•
Compact flash model number
•
Compact flash serial number
•
Compact flash size in bytes
•
Type of compact flash (Regular/S.M.A.R.T.)
•
Status of S.M.A.R.T. feature (Supported/Not Supported, Enabled/Disabled)
•
Status of S.M.A.R.T. data (Valid/Invalid)
•
S.M.A.R.T. Revision code
•
S.M.A.R.T. Firmware version and date code
•
S.M.A.R.T. number of Initial Invalid blocks, number of bad Run Time blocks, number of
Spare blocks (decimal)
•
S.M.A.R.T. number of child pairs (decimal)
•
Compact flash type (SLC/MLC)
•
Compact flash specification’s maximum erase count (100000 if flash is SLC; 5000 if
flash is MLC)
•
Compact flash’s average erase count
•
Compact flash remaining % of life (100 - "Average erase count"*100/"Flash spec max
erase count")
This diagnostic information lets the user know when the drive may wear out and need to
be replaced or the meter be de-commissioned.
6–6
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 6: USING THE EPM 9900 METER’S TOUCH SCREEN DISPLAY
IEC–61850
The IEC-61850 screen
contains information about
the IEC-61850 Protocol
Ethernet Network server,
including any system or error
messages. It displays:
•
Server state
•
Server Initialization time
in seconds
•
Memory statistics
•
SCL parsing messages
•
Stack indications
•
Stack messages
Task Info
The Task Info screen contains
information about free stack
size based on the tasks in the
processing stack.
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CHAPTER 6: USING THE EPM 9900 METER’S TOUCH SCREEN DISPLAY
CPU Stats
The CPU Stats screen
contains information about
the processor’s state and how
close it is to executing the Idle
task.
SNTP
•
The SNTP screen
contains information
about the meter’s SNTP
(Simple Network Time
Protocol) settings:
•
State (enabled or
disabled)
•
Mode
•
UDP port number
•
Clock sync source
•
Sync process timeout in
seconds
•
Sync rate in minutes
•
SNTP server(s) IP address
See Chapter 5 of the GE Communicator Instruction Manual for details on setting SNTP
through the meter Device Profile.
6–8
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 6: USING THE EPM 9900 METER’S TOUCH SCREEN DISPLAY
6.3
Dynamic Screens
All of the Dynamic screens show the time and date at the bottom of the screen. With the
exception of the Logo screen, all of the Dynamic screens have buttons on the top that
allow you to navigate to the Fixed Main screen, the next screen in sequence, the previous
screen, and the Dynamic Main screen. There is also a Play/Pause button that stops and
starts the scrolling between Dynamic screens. You can adjust the screen rotation, which
lets you mount the meter vertically, and you can select English or Spanish for the display
language (see Display Settings, 6-23, for instructions).
Home Screen:
This is the first Dynamic screen shown after the system boots up. Touch the buttons to
access the following screens:
•
Trends: the Dynamic Trends screen
•
Alarms: the Dynamic Alarms screen
•
Real Time: the Real Time Readings screen
•
Power Quality: the Harmonics screen
•
Main: the Dynamic Main screen
(Dynamic) Main Screen:
This is a navigation screen for the Dynamic screens that are in scroll mode.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
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CHAPTER 6: USING THE EPM 9900 METER’S TOUCH SCREEN DISPLAY
Touch the button of the screen you want to access. Each of the screens is described in the
following sections.
Real Time:
Brings you to an overview of Real Time Readings consisting of the following:
•
Volts AN/BN/CN/AB/BC/CA
•
Amps A/B/C
•
Watts
•
VARS
•
VA
•
FREQ
Volts:
Brings you to Voltage readings details, consisting of the following:
•
Real time Volts AN/BN/CN/AB/BC/CA
•
Maximum Volts AN/BN/CN/AB/BC/CA
•
Minimum Volts AN/BN/CN/AB/BC/CA
Touch PH-N, PH-PH or PH-E to view details of Phase-to-Neutral, Phase-to-Phase or Phaseto-Earth readings.
6–10
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CHAPTER 6: USING THE EPM 9900 METER’S TOUCH SCREEN DISPLAY
Volts: Voltage Readings PH-N
Volts AN/BN/CN
 Touch the Back button to return to the Volts screen.
 Touch the Next/Previous arrows to go to Voltage Reading PH-PH
and Current Reading A-B-C.
 Touch the Home button to go to the Dynamic Home screen.
Volts: Voltage Readings PH-PH
Volts AB/BC/CA
 Touch Back to return to the Volts screen.
 Touch Next/Previous arrows to go to Voltage Reading PH-E and PHN Readings.
 Touch the Home button to go to the Dynamic Home screen.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
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CHAPTER 6: USING THE EPM 9900 METER’S TOUCH SCREEN DISPLAY
Volts: Voltage Readings PH-E
Volts AE/BE/CE/NE
 Touch Back to return to the Volts screen.
 Touch Next/Previous arrows to go to Current Reading A-B-C and
Voltage Reading PH-PH.
 Touch the Home button to go to the Dynamic Home screen.
Amps:
Brings you to current readings details, consisting of the following:
 Real time current A/B/C
 Maximum current A/B/C
 Minimum current A/B/C
 Current calculated Nc/measured Nm
 Maximum Current calculated Nc/measured Nm
 Minimum Current Calculated Nc/Measured Nm
Touch A-B-C to view Currents Detail.
6–12
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CHAPTER 6: USING THE EPM 9900 METER’S TOUCH SCREEN DISPLAY
Amps: Current Readings A-B-C
Real Time Current A/B/C
 Touch Back to return to the Amps screen.
 Touch Next/Previous arrows to go to Voltage Reading PH-N and
Voltage Reading PH-PH.
 Touch the Home button to go to the Dynamic Home screen.
Real Time Power:
Real Time Power Readings Details
•
Instant Watt/VAR/VA/PF
•
Thermal Watt/VAR/VA/PF
•
Predicted Watt/VAR/VA
Touch Demand to go to the Demand Power screen (shown below).
Demand Power:
Demand Power Readings Details
•
Thermal Window Average Maximum +Watt/+VAR/CoIn VAR
•
Block (Fixed) Window Average Maximum +Watt/+VAR/CoIn VAR
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
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CHAPTER 6: USING THE EPM 9900 METER’S TOUCH SCREEN DISPLAY
•
Predictive Rolling (Sliding) Window Maximum +Watt/+VAR/CoIn VAR
Touch R/T to view the Real Time Power screen.
Energy:
Brings you to Accumulated Energy Information, consisting of the following:
•
-Watthr Quadrant 2+Quadrant 3 (Primary)
•
+VAhr Quadrant 2 (Primary)
•
+VARhr Quadrant 2 (Primary)
•
+VAhr Quadrant 3 (Primary)
•
-VARhr Quadrant 3 (Primary)
•
+Watthr Quadrant 1+Quadrant 4 (Primary)
•
+VAhr for all quadrants (Primary)
Touch TOU to view the TOU Register Accumulations screen.
TOU:
Brings you to Accumulations Information, consisting of the following:
6–14
•
-Watthr Quadrant 2+Quadrant 3 (Primary)
•
+VAhr Quadrant 2 (Primary)
•
+VARhr Quadrant 2 (Primary)
•
+VAhr Quadrant 3 (Primary)
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 6: USING THE EPM 9900 METER’S TOUCH SCREEN DISPLAY
•
-VARhr Quadrant 3 (Primary)
•
+Watthr Quadrant 1+Quadrant 4 (Primary)
•
+VAhr Quadrants 1+Quadrant 4 (Primary)
•
-VARhr Quadrant 4 (Primary)
•
Status (Active or Stopped)
Touch Peak to view the Register Peak Demand screen.
Touch Next/Previous arrows to scroll Registers 1 - 8 and Totals.
Touch Next/Previous arrows to scroll Frozen, Prior Month, Active, and Current Month.
TOU:
Brings you to Register Demand information, consisting of the following:
•
Block (Fixed) Window +Watthr, +VARhr, -Watthr, -kVARh, Coin +kVARh, Coin -VARh
Touch Accu to view TOU Accumulations.
Touch Next/Previous arrows to scroll Registers 1 - 8 and Totals.
Touch Next/Previous arrows to scroll Frozen, Prior Month, Active, and Current Month.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
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CHAPTER 6: USING THE EPM 9900 METER’S TOUCH SCREEN DISPLAY
NOTE: If password protection is enabled for the meter a keyboard screen displays, allowing
you to enter the password. If a valid password is entered, the TOU data readings are
displayed; otherwise a message displays, indicating that the password is invalid.
Phasors:
Brings you to Phasor Analysis Information.
•
Phase/Phasor arrow buttons change the rotation of the diagram.
•
Phase/Mag button shows the phase/magnitude of:
•
Phase angle or magnitude Van/bn/cn
•
Phase angle or magnitude Ia/b/c
•
Phase angle or magnitude Vab/bc/ca
•
The PH-PH check box shows/hides the phase to phase voltage.
Harmonics-Spectrum:
Brings you to Harmonic Spectrum Analysis information, consisting of the following:
6–16
•
%THD
•
TDD (current only)
•
KFactor
•
Frequency
•
Phase A - N Voltage
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 6: USING THE EPM 9900 METER’S TOUCH SCREEN DISPLAY
Touch Waveform to see the channel's waveform.
Touch Volts B to view the Harmonics screen for Phase B - N voltage; Touch Volts C
(from the Volts B screen) to view the Harmonics screen for Phase C - N voltage.
Use the Scroll/Zoom radio buttons to select the mode of the directional arrows:
•
If Scroll is selected, the directional arrows move the axes horizontally/vertically.
•
If Zoom is selected, the directional arrows cause the display to zoom in/out.
Harmonics:
Brings you to the Waveform: Real Time Graph, showing the following information:
•
%THD
•
TDD (current only)
•
KFactor
•
Frequency
Touch Spectrum to see the Harmonic Spectrum Analysis screen for the channel.
Touch Volts B to view the Harmonics screen for Phase B - N voltage; Touch Volts C
(from the Volts B screen) to view the Harmonics screen for Phase C - N voltage.
Alarms:
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
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CHAPTER 6: USING THE EPM 9900 METER’S TOUCH SCREEN DISPLAY
Brings you to Alarm (Limits) Status information, consisting of the following:
•
Current Limits settings for the meters, ID 1 - 32.
•
For each ID number, the type of reading, value, status and setting is shown.
•
The green rectangle indicates a Within Limits condition and the red rectangle
indicates an Out of Limits condition.
•
The first screen displays the settings for Meters ID 1 to 4.
Touch Next/Previous arrows to view all of the Limits.
Flicker:
Brings you to Flicker Instantaneous information, consisting of the following:
•
Time: Start/Reset, Current, Next
•
PST, Next PLT
•
Frequency
•
Base Voltage
•
Voltage readings
Touch PST (Short Term) or PLT (Long Term) to view other flicker screens.
Flicker - Short Term:
Displays the following information:
•
6–18
Volts A/B/C
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 6: USING THE EPM 9900 METER’S TOUCH SCREEN DISPLAY
•
Max Volts A/B/C
•
Min Volts A/B/C
Touch PINST (Instantaneous) or PLT (Long Term) to view other flicker screens.
Flicker - Long Term:
Displays the following information:
•
Volts A/B/C
•
Max Volts A/B/C
•
Min Volts A/B/C
Touch PINST (Instantaneous) or PST (Short Term) to view other flicker screens.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
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CHAPTER 6: USING THE EPM 9900 METER’S TOUCH SCREEN DISPLAY
NOTE: If password protection is enabled for the meter a keyboard screen displays when
you press any action button (e.g., Reset). Use the keyboard to enter the password. If a valid
password is entered, the requested Flicker action takes place; otherwise a message
displays, indicating that the password is invalid.
Bargraph:
Brings you to a Bargraph display, consisting of the following:
•
Phase A - N Voltage
•
Phase B - N Voltage
•
Phase C - N Voltage
Touch the Up/Down arrows to move the vertical axis up/down.
Touch the +/- buttons to zoom in/out.
Touch Show All to display all of the bars in the screen.
Touch Volts PH-PH to view the Voltage Phase-to-Phase Bargraph screen.
Touch Current to view the Amps Bargraph screen. (The Current button is displayed on the
Voltage Phase-to-Phase Bargraph screen.)
6–20
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 6: USING THE EPM 9900 METER’S TOUCH SCREEN DISPLAY
Reset:
Brings you to the Meter Reset Command screen. From this screen, you can reset the
following values:
•
Max/Min and Demand
•
Hour, I2T and V2T counters
•
All logs
•
TOU for current month
•
TOU active
WARNING! RESETS CAUSE DATA TO BE LOST.
 Touch the box(es) to select the Reset you want to perform.
 Touch Reset. All boxes are unchecked after a reset is performed and
a check mark is displayed next to each item that was reset.
Note
NOTE
If password protection is enabled for the meter a keyboard screen displays, when you
press the Reset button. Use the keyboard to enter the password. If a valid password is
entered, the reset takes place; otherwise a message displays, indicating that the password
is invalid.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
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CHAPTER 6: USING THE EPM 9900 METER’S TOUCH SCREEN DISPLAY
Trends:
Brings you to the Trends Setting screen. From this screen, you can set the following for
viewing:
 Interval Log 1 or Log 2: touch the radio button of the log you want.
 Channel: select a channel by touching its button.
You will see the Trends - Graphic screen.
NOTES:
• The active channel appears at the lower right of the display.
• Data from the previously active channel is lost if the channel is changed.
Real Time Trending Graphic:
Trending for the channel selected from the Trends - Setting screen is shown on this screen.
6–22
•
Touch the Directional arrows to see additional points on the graph. You can view up
to 240 points at a time.
•
To see a table of logs for the Selected Channel, touch Table to view the Trends - Table
screen.
•
Touch Setting to select another log and/or channel.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 6: USING THE EPM 9900 METER’S TOUCH SCREEN DISPLAY
Real Time Trending Table:
A Table of logs for the selected channel (Volts AN is shown here).
Note
NOTE
•
Touch Graphic to return to the Trending - Graphic screen.
•
Touch Setting to select another log and/or channel.
If password protection is enabled for the meter a keyboard screen displays, when you
press any channel button. Use the keyboard to enter the password. If a valid password is
entered, the Trend graphic/Tables are displayed; otherwise a message displays, indicating
that the password is invalid.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
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CHAPTER 6: USING THE EPM 9900 METER’S TOUCH SCREEN DISPLAY
Log Status:
Brings you to Logging Status information, consisting of an overview of the meter's logs. For
each log, the following information is listed:
•
The number of records
•
Record size
•
% of memory used1
Touch the Next/Previous arrows to view additional logs.
Firmware Version:
This screen displays the current firmware version for the EPM 9900 meter, as well as the
meter designation and serial number. The following information is displayed:
6–24
•
Device name
•
Serial number
•
Comm Boot: 2.5075
•
Comm Runtime: 2.5145
•
DSP1 Boot: 1
•
DSP1 Runtime: DV
•
DSP2: S.0000
•
FPGA: 2.11
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 6: USING THE EPM 9900 METER’S TOUCH SCREEN DISPLAY
•
Touch Screen: 7.03
DISPLAY SETTINGS:
Brings you to a screen where you can configure settings for the LCD display. Set the
following:
•
Contrast: touch Left/Right arrows to increase/decrease the contrast for the display.
•
Backlight: the number of minutes after use that the display's backlight turns off.
 Touch Left/Right arrows to increase/decrease settings. To keep the
backlight on, make this setting “0.”
 To turn the Backlight on press and hold the switch on the front panel
beside the display for a few seconds.
Note
NOTE
•
Volume: touch Left/Right arrows to increase/decrease the speaker volume.
•
Rotation (degree): touch Left/Right arrows to set screen’s rotation to 0, 90, 180 or 360
degrees. This allows the meter to be mounted vertically.
•
Language: touch Left/Right arrows to choose English or Spanish as the screen
language.
You must press Apply for your Rotation and Language settings to be implemented.
Once you press Apply, the screen darkens momentarily and then the Home screen is
redisplayed with the selected rotation/language.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
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CHAPTER 6: USING THE EPM 9900 METER’S TOUCH SCREEN DISPLAY
Touch Next/Prev to go to the Serial Setting/Network Setting screens.
EPM 9900 Serial Communication Settings:
Select the serial communication mode you want to configure, by checking the Radio
Button to the left of it. The setting for each port is described below:
•
Optical port (Baud, Parity, Stop bit, Data size, Protocol, Tx delay, Address, Mode)
•
USB (Baud, Parity, Stop bit, Data size, Protocol, Tx delay, Address)
•
COMM 1 (Baud, Parity, Stop bit, Data size, Protocol, Tx delay, Address)
•
COMM 2 (Baud, Parity, Stop bit, Data size, Protocol, Tx delay, Address, Mode)
Touch Next/Prev to go to the Network Setting/Display Setting screens.
EPM 9900 Network Communication Settings:
Use the following fields to configure the meter's Network settings:
•
Network: click the Radio Button next to Network 1 or Network 2.
•
IP address
•
Subnet mask2
•
Default gateway
•
MAC address
Touch Next/Prev to go to the Display Setting/Serial Setting screens.
6–26
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
GE Energy
EPM 9900 Electronic Meter
Chapter 7: Transformer Loss
Compensation
Transformer Loss Compensation
7.1
Introduction
The Edison Electric Institute's Handbook for Electricity Metering, Ninth Edition defines Loss
Compensation as:
A means for correcting the reading of a meter when the metering point and point of
service are physically separated, resulting in measurable losses including I2R losses in
conductors and transformers and iron-core losses. These losses may be added to or
subtracted from the meter registration.
Loss compensation may be used in any instance where the physical location of the meter
does not match the electrical location where change of ownership occurs. Most often this
appears when meters are connected on the low voltage side of power transformers when
the actual ownership change occurs on the high side of the transformer. This condition is
shown pictorially in the figure below.
Figure 7-1: Low Voltage Metering Installation Requiring Loss Compensation
Ownership Change
M
It is generally less expensive to install metering equipment on the low voltage side of a
transformer and in some conditions other limitations may also impose the requirement of
low-side metering even though the actual ownership change occurs on the high-voltage
side.
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CHAPTER 7: TRANSFORMER LOSS COMPENSATION
The need for loss compensated metering may also exist when the ownership changes
several miles along a transmission line where it is simply impractical to install metering
equipment. Ownership may change at the midway point of a transmission line where
there are no substation facilities. In this case, power metering must again be
compensated. This condition is shown in see figure below.
Figure 7-2: Joint Ownership Line Meeting Requiring Loss Compensation
M
Point of Ownership
Change
A single meter cannot measure the losses in a transformer or transmission line directly. It
can, however, include computational corrections to calculate the losses and add or
subtract those losses to the power flow measured at the meter location. This is the method
used for loss compensation in the EPM 9900 meter. Refer to Appendix B of the GE
Communicator User Manual for detailed explanation and instructions for using the
Transformer Line Loss Compensation feature of the EPM 9900 meter.
The computational corrections used for transformer and transmission line loss
compensation are similar. In both cases, no-load losses and full-load losses are evaluated
and a correction factor for each loss level is calculated. However, the calculation of the
correction factors that must be programmed into the meter differ for the two different
applications. For this reason, the two methodologies will be treated separately in this
chapter.
In the EPM 9900 meter, Loss Compensation is a technique that computationally accounts
for active and reactive power losses. The meter calculations are based on the formulas
below. These equations describe the amount of active (Watts) and reactive (VARs) power
lost due to both iron and copper effects (reflected to the secondary of the instrument
transformers).
Total Secondary Watt Loss =
(((Measured Voltage/Cal point Voltage)2 x %LWFE) + ((Measured Current/Cal Point Current)2
x %LWCU)) x Full-scale Secondary VA
Total Secondary VAR Loss =
(((Measured Voltage/Cal point Voltage)4 x %LVFE) + ((Measured Current/Cal Point
Current)2 x %LVCU)) x Full-scale Secondary VA
The Values for %LWFE, %LWCU, %LVFE, and %LVCU are derived from the transformer and
meter information, as demonstrated in the following sections.
The calculated loss compensation values are added to or subtracted from the measured
Watts and VARs. The selection of adding or subtracting losses is made through the meter's
profile when programming the meter (see the following section for instructions). The meter
uses the combination of the add/subtract setting and the directional definition of power
flow (also in the profile) to determine how to handle the losses. Losses will be "added to" or
"subtracted from" (depending on whether add or subtract is selected) the Received Power
flow. For example, if losses are set to "Add to" and received power equals 2000 kW and
7–2
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CHAPTER 7: TRANSFORMER LOSS COMPENSATION
losses are equal to 20 kW then the total metered value with loss compensation would be
2020 kW; for these same settings if the meter measured 2000 kW of delivered power the
total metered value with loss compensation would be 1980 kW.
Since transformer loss compensation is the more common loss compensation method, the
meter has been designed for this application. Line loss compensation is calculated in the
meter using the same terms but the percent values are calculated by a different
methodology.
EPM 9900 Meter Transformer Loss Compensation:
•
Performs calculations on each phase of the meter for every measurement taken;
unbalanced loads are accurately handled.
•
Calculates numerically, eliminating the environmental effects that cause inaccuracies
in electromechanical compensators
•
Performs Bidirectional Loss Compensation
•
Requires no additional wiring; the compensation occurs internally.
•
Imposes no additional electrical burden when performing Loss Compensation
Loss Compensation is applied to 1 second per phase Watt/VAR readings and, because of
that, affects all subsequent readings based on 1 second per phase Watt/VAR readings.
This method results in loss compensation being applied to the following quantities:
•
Total Power
•
Demands, per phase and total (Thermal, Block (Fixed) Window, Rolling (Sliding) Window
and Predictive Window)
•
Maximum and minimum Demand
•
Energy accumulations
•
KYZ output of Energy accumulations
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CHAPTER 7: TRANSFORMER LOSS COMPENSATION
7.2
EPM 9900 Meter's Transformer Loss Compensation
The EPM 9900 meter provides compensation for active and reactive power quantities by
performing numerical calculations. The factors used in these calculations are derived
either:
•
By clicking the TLC Calculator button on the Transformer Loss screen of the Device
Profile, to open the GE Digital Energy Loss Compensation Calculator in Microsoft Excel
•
By figuring the values from the worksheet shown here and in Appendix B of the GE
Communicator User Manual
Either way, you enter the derived values into the GE Communicator software through the
Device Profile Transformer and Line Loss Compensation screen.
The GE Communicator software allows you to enable Transformer Loss Compensation for
Losses due to Copper and Iron, individually or simultaneously. Losses can either be added
to or subtracted from measured readings. Refer to Appendix B in the GE Communicator
User Manual for instructions.
Loss compensation values must be calculated based on the meter installation. As a result,
transformer loss values must be normalized to the meter by converting the base voltage
and current and taking into account the number of elements used in the metering
installation. For three-element meters, the installation must be normalized to the phaseto-neutral voltage and the phase current; in two-element meters the installation must be
normalized to the phase-to-phase voltage and the phase current. This process is
described in the following sections.
7.2.1
Loss
Compensation
in Three
Element
Installations
Loss compensation is based on the loss and impedance values provided on the
transformer manufacturer's test report. A typical test report will include at least the
following information:
•
Manufacturer
•
Unit serial number
•
Transformer MVA rating (Self-Cooled)
•
Test Voltage
•
No Load Loss Watts
•
Load Loss Watts (or Full Load Loss Watts)
•
% Exciting Current @ 100% voltage
•
% Impedance
The transformer MVA rating is generally the lowest MVA rating (the self-cooled or OA rating)
of the transformer winding. The test voltage is generally the nominal voltage of the
secondary or low voltage winding. For three-phase transformers these values will typically
be the three-phase rating and the phase-to-phase voltage. All of the test measurements
are based on these two numbers. Part of the process of calculating the loss compensation
percentages is converting the transformer loss values based on the transformer ratings to
the base used by the meter.
7–4
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 7: TRANSFORMER LOSS COMPENSATION
Correct calculation of loss compensation also requires knowledge of the meter installation.
In order to calculate the loss compensation settings you will need the following
information regarding the meter and the installation:
•
Number of meter elements
•
Potential transformer ratio (PTR)
•
Current transformer ratio (CTR)
•
Meter base Voltage
•
Meter base current
This section is limited to application of EPM 9900 meters to three-element metering
installations. As a result, we know that:
•
Number of metering elements = 3
•
Meter base Voltage = 120 Volts
•
Meter base current = 5 Amps
Three-Element Loss Compensation Worksheet
Company
Station Name
Date
Trf. Bank No.
Trf Manf
Trf Serial No.
Calculation by
Transformer Data (from Transformer Manufacturer's Test Sheet)
Winding
Voltage
MVA
HV - High
Connection
∆-Y
∆-Y
∆-Y
XV - Low
YV - Tertiary
Watts Loss
Value
3-Phase
1-Phase
1-Phase kW
No-Load Loss
Load Loss
Enter 3-Phase or 1-Phase values. If 3-Phase values are entered, calculate 1-Phase values
by dividing 3-Phase values by three. Convert 1-Phase Loss Watts to 1-Phase kW by
dividing 1-Phase Loss Watts by 1000.
Value
3-Phase MVA
1-Phase MVA
1-Phase kVA
Self-Cooled Rating
Enter 3-Phase or 1-Phase values. If 3-Phase values are entered, calculate 1-Phase values
by dividing 3-Phase values by three. Convert 1-Phase Self-Cooled MVA to 1-Phase kVA by
multiplying by 1000.
% Exciting Current
% Impedance
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CHAPTER 7: TRANSFORMER LOSS COMPENSATION
Value
Phase-to-Phase
Phase-to-Neutral
Test Voltage (Volts)
Full Load Current (Amps)
Test Voltage is generally Phase-to-Phase for three-phase transformers. Calculate Phaseto-Neutral Voltage by dividing Phase-to-Phase Voltage by the square root of 3. Calculate
Full Load Current by dividing the (1-Phase kW Self-Cooled Rating) by the (Phase-to-Neutral
Voltage) and multiplying by 1000.
Meter/Installation Data
Instrument Transformers
Numerator
Denominator
Multiplier
Potential Transformers
Current Transformers
Power Multiplier [(PT Multiplier) x (CT Multiplier)]
Enter the Numerator and Denominator for each instrument transformer. For example, a PT
with a ratio of 7200/120 has a numerator or 7200, a denominator or 120 and a multiplier
of 60 (7200/120 = 60/1).
Meter Secondary Voltage (Volts)
120
Meter Secondary Current (Amps)
Base Conversion Factors
Quantity
Transformer
Multiplier
Trf IT Sec
5
Meter Base
Voltage
120
Current
5
Meter/Trf
For Transformer Voltage, enter the Phase-to-Neutral value of Test Voltage previously
calculated. For Transformer Current, enter the Full-Load Current previously calculated. For
Multipliers, enter the PT and CT multipliers previously calculated.
TrfIT Secondary is the Base Value of Voltage and Current at the Instrument Transformer
Secondary of the Power Transformer. These numbers are obtained by dividing the
Transformer Voltage and Current by their respective Multipliers. The Meter/Trf values for
Voltage and Current are obtained by dividing the Meter Base values by the TrfIT Secondary
values.
Load Loss at Transformer
No-Load Loss Watts (kW) = 1-Phase kW No-Load Loss = ______________
No-Load Loss VA (kVA) = (%Exciting Current) * (1-Phase kVA Self-Cooled Rating) / 100 =
(______________) * (________________) / 100
= _______________ kVA
No-Load Loss VAR (kVAR) = SQRT((No-Load Loss kVA)2 - (No-Load Loss kW)2) =
SQRT((_________________)2 - (________________)2)
= SQRT((__________________) - (_________________))
= SQRT (_________________) = ____________________
Full-Load Loss Watts (kW) = 1-Phase Kw Load Loss = ______________
7–6
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CHAPTER 7: TRANSFORMER LOSS COMPENSATION
Full-Load Loss VA (kVA) = (%Impedance) * (1-Phase kVA Self-Cooled Rating) / 100 =
(______________) * (________________) / 100
= _______________ kVA
Full-Load Loss VAR (kVAR) = SQRT((Full-Load Loss kVA)2 - (Full-Load Loss kW)2) =
SQRT((_________________)2 - (________________)2)
= SQRT((__________________) - (_________________))
= SQRT (_________________) = _________________
Normalize Losses to Meter Base
Quantity
Value at
Trf Base
M/T Factor
No-Load Loss kW
V
No-Load Loss
kVAR
V
Load Loss kW
1
Load Loss kVAR
1
M/T Factor Value
Exp
M/T Factor w/
Exp
Value at
Meter Base
٨2
٨4
٨2
٨2
Enter Value at Transformer Base for each quantity from calculations above. Enter Meter/
Trf Factor value from Base Conversion Factor calculations above. Calculate M/T Factor
with Exponent by raising the M/T Factor to the power indicated in the "Exp" (or Exponent)
column.
Calculate the "Value at Meter Base" by multiplying the (M/T Factor w/ Exp) times the (Value
at Trf Base).
Loss Watts Percentage Values
Meter Base kVA = 600 * (PT Multiplier) * (CT Multiplier) / 1000
= 600 * (____________) * (___________) / 1000
= ________________
Calculate Load Loss Values
Quantity
Value at Meter
Base
Meter Base
kVA
% Loss at Meter
Base
Quantity
No-Load Loss kW
% Loss Watts FE
No-Load Loss
kVAR
% Loss VARs FE
Load Loss kW
% Loss Watts CU
Load Loss kVAR
% Loss VARs CU
Enter "Value at Meter Base" from Normalize Losses section. Enter "Meter Base kVA" from
previous calculation. Calculate "% Loss at Meter Base" by dividing (Value at Meter Base) by
(Meter Base kVA) and multiplying by 100.
Enter calculated % Loss Watts values into the EPM 9900 meter using GE Communicator
software. Refer to Appendix B of the GE Communicator User Manual for instructions.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
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CHAPTER 7: TRANSFORMER LOSS COMPENSATION
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EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
GE Energy
EPM 9900 Electronic Meter
Chapter 8: Time-of-Use Function
Time-of-Use Function
8.1
Introduction
A Time-of-Use (TOU) usage structure takes into account the quantity of energy used and
the time at which it was consumed. The EPM 9900 meter's TOU function, available with the
GE Communicator software, is designed to accommodate a variety of programmable rate
structures. The EPM 9900 meter's TOU function accumulates data based on the timescheme programmed into the meter.
See Chapter 10 of the GE Communicator User Manual for details on programming the EPM
9900 meter's 20-year TOU calendar and retrieving TOU data.
8.2
The EPM 9900 Meter's TOU Calendar
An EPM 9900 TOU calendar sets the parameters for TOU data accumulation. You may store
up to twenty calendars in the EPM 9900 meter and an unlimited amount of calendar files
on your computer.
The EPM 9900 TOU calendar profile allows you to assign a programmable usage schedule
- e.g., "Weekday," "Weekend," or "Holiday"- to each day of the calendar year. You may
create up to 16 different TOU schedules.
Each TOU schedule divides the 24-hour day into fifteen-minute intervals from 00:00:00 to
23:59:59. You may apply one of eight different programmable registers - e.g., "Peak," "Off
Peak," or "Shoulder Peak," to each fifteen-minute interval.
The EPM 9900 meter stores:
•
•
Accumulations on a seasonal basis (up to four seasons per year), weekly, daily or
hourly basis (active/frozen registers).
Accumulations on a monthly basis
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
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CHAPTER 8: TIME-OF-USE FUNCTION
Seasonal and monthly accumulations may span from one year into the next. Each season
and month is defined by a programmable start/billing date, which is also the end-date of
the prior season or month.
A season ends at midnight of the day before the start of the next season.
A month ends at midnight of the month's billing day.
If the year ends and there is no new calendar, TOU accumulations stop. The last
accumulation for the year ends on 12:31:23:59:59.
If a calendar is present for the following year, TOU accumulations continue until the next
monthly bill date or next start-of-season is reached. Accumulation can span into the
following year.
8.3
TOU Prior Season and Month
The EPM 9900 meter stores accumulations for the prior season and the prior month. When
the end of a billing period is reached, the current season or month is stored as the prior
data. The registers are then cleared and accumulations resume, using the next set of TOU
schedules and register assignments from the stored calendar. Prior and current
accumulations to date are always available.
8.4
Updating, Retrieving and Replacing TOU Calendars
GE Communicator software retrieves TOU calendars from the EPM 9900 meter or from the
computer's hard drive for review and edit.
Up to a maximum of twenty yearly calendars can be stored in the EPM 9900 meter at any
given time. You may retrieve them one at a time; a new calendar can be stored while a
current calendar is in use.
Accumulations do not stop during calendar updates. If a calendar is replaced while in use,
the accumulations for the current period will continue until the set end date. At that point,
the current time will become the new start time and the settings of the new calendar will
be used.
Reset the current accumulations, if you replace a calendar in use. A reset clears only the
current accumulation registers. This causes the current accumulations to use the present
date as the start and accumulate to the next new end date, which will be taken from the
new calendar. Once stored, prior accumulations are always available and cannot be reset.
See Chapter 5 of the GE Communicator User Manual for instructions on resetting TOU
accumulations.
At the end of a defined period, current accumulations are stored, the registers are cleared
and accumulations for the next period begin. When the year boundary is crossed, the
second calendar, if present, is used. To retain continuity, you have up to one year to replace
the old calendar with one for the following year.
8–2
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 8: TIME-OF-USE FUNCTION
8.5
Daylight Savings and Demand
To enable Daylight Savings Time for the meter: from the Device Profile menu click General
Settings>Time Settings. In the Time Settings screen, click Auto DST, which sets Daylight
Savings Time automatically (for the United States only). You can also select User Defined
and enter the desired dates for Daylight Savings Time. See Chapter 5 of the GE
Communicator User Manual for instructions.
To set Demand intervals: from the Device Profile menu click Revenue and Energy
Settings>Demand Integration Intervals and set the desired intervals. See Chapter 5 of
the GE Communicator User Manual for instructions.
To set Cumulative Demand Type, from the Device Profile menu click Revenue and Energy
Settings>Cumulative Demand Type and select Block or Rolling Window Average. See
Chapter 5 of the GE Communicator User Manual for instructions.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
8–3
CHAPTER 8: TIME-OF-USE FUNCTION
8–4
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
GE Energy
EPM 9900 Electronic Meter
Chapter 9: EPM 9900 Network
Communications
EPM 9900 Network Communications
9.1
Hardware Overview
The EPM 9900 meter can connect to multiple PCs via Modbus/TCP over the Ethernet or via
a DNP LAN/WAN connection.
Figure 9-1: EPM 9900 Meter Connected to Network
The EPM 9900 meter's Network is an extremely versatile communications tool. It:
• Adheres to IEEE 802.3 Ethernet standard using TCP/IP
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
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CHAPTER 9: EPM 9900 NETWORK COMMUNICATIONS
• Utilizes simple and inexpensive 10/100BaseT wiring and connections
• Plugs into your network using built-in RJ45 jack
• Is programmable to any IP address, subnet mask and gateway requirements
• Communicates using the industry-standard Modbus/TCP and DNP LAN/WAN
protocols
Multiple simultaneous connections (via LAN) can be made to the EPM 9900 meter. You can
access the EPM 9900 meter with SCADA, MV90 and RTU simultaneously.
Multiple users can run GE Communicator software to access the meter concurrently.
9–2
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 9: EPM 9900 NETWORK COMMUNICATIONS
9.2
Specifications
The EPM 9900 meter's main Network card (standard) has the following specifications at
25 °C:
Number of Ports: 1
Operating Mode: 10/100BaseT
Connection type: RJ45 modular (Auto- detecting ransmit and receive)
Diagnostic feature: Status LEDs for LINK and ACTIVE
Number of simultaneous Modbus connections: 8 (8 total connections over both the
main Network card and optional Network card 2.)
Number of simultaneous DNP LAN/WAN connections to the meter: 2 TCP and 1 UDP per
Network card
9.3
Network Connection
Use standard CAT5E network cables to connect with the EPM 9900 meter. The RJ45 line is
inserted into the RJ45 port on the back of the meter (see figure 9-1).
Set the IP Address using the following steps:
(Refer to the GE Communicator User Manual for more detailed instructions.)
1.
From the Device Profile screen, double-click General Settings>
Communications, then double-click on any of the ports. The Communications
Settings screen opens.
2.
In the Network Settings section enter the following data.
The settings shown below are the default settings of the main Network card. See Chapter
11 for the default settings of optional Network card 2.
Note
NOTE
•
IP Address:
10.0.0.1
•
Subnet Mask:
255.255.255.0
•
Default Gateway: 0.0.0.0
You can use different settings for the main Network card (check with your Network
Administrator for the correct settings).
Note
NOTE
We recommend the main Network card and Network card 2 be in different subnets,
though this is not a necessity.
3.
Once the above parameters have been set, GE Communicator connects via
the network using a Device Address of "1" and the assigned IP Address when
you follow these steps:
i
Open GE Communicator .
ii
Click the Connect icon in the icon tool bar. The Connect screen opens.
iii
Click the Network button at the top of the screen. Enter the following
information:
Device Address: 1
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
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CHAPTER 9: EPM 9900 NETWORK COMMUNICATIONS
Host:
Network Port:
Protocol:
iv
The Network card’s IP Address
502
Modbus TCP
Click the Connect button at the bottom of the screen. GE Communicator
connects to the meter via the network.
Network Information Through Display
You can see the Network settings through the meter's Touch Screen display:
9–4
1.
From the Main screen, select Setting.
2.
Press the Next button twice to go to the Network Settings screen (shown on
the next page).
3.
Click the button next to Network 1 to see the settings for the standard
Ethernet connection. Click the button next to Network 2 to see the settings for
the second, optional Network card, if installed.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 9: EPM 9900 NETWORK COMMUNICATIONS
9.4
Total Web Solutions
The EPM 9900 meter’s Network card supports GE’s Total Web Solutions, which is a Web
server that lets you view meter information over any standard Web browser. The EPM 9900
meter default webpages can be viewed by Internet Explorer, Firefox, Chrome, and Safari
web browsers. They can be viewed on PCs, tablet computers and smart phones.
The default webpages provide real-time readings of the meter's voltage, current, power,
energy, power quality, pulse accumulations and high speed digital inputs, as well as
additional meter information, alarm/email information and diagnostic information. You
can also upgrade the meter’s firmware through the webpages. You can customize the
default webpages - see Chapter 7 in the GE Communicator User Manual for instructions on
setting up Total Web Solutions and customizing webpages.
9.4.1
Viewing
Webpages
The following is information on accessing the default webpages.
1.
Open a Web browser on your PC, tablet computer or smart phone.
2.
Type the Ethernet Card’s IP address in the address bar, preceded by “http://”.
For example: http://10.0.0.1
3.
You will see the Volts/Amps webpage shown below. It shows voltage and current
readings.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
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CHAPTER 9: EPM 9900 NETWORK COMMUNICATIONS
9–6
4.
To view power and energy readings, click Power/Energy on the left side of the
webpage. You see the webpage shown below. Scroll to see all of the information.
5.
To view power quality information, click Power Quality on the left side of the
webpage. You see the webpage shown below.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 9: EPM 9900 NETWORK COMMUNICATIONS
6.
To view pulse accumulation data, click Pulse Accumulation on the left side of the
webpage. You see the webpage shown below.
7.
To view Inputs data, click Inputs on the left side of the webpage. You see the webpage
shown below.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
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CHAPTER 9: EPM 9900 NETWORK COMMUNICATIONS
9–8
8.
To view general meter information, click Meter Information on the left side of the
webpage. You see the webpage shown below.
9.
To view alarm/email information, click Emails on the left side of the webpage. You see
the webpage shown below. Scroll to see all of the information.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 9: EPM 9900 NETWORK COMMUNICATIONS
10. To view detailed information for the meter, click Diagnostic on the left side of the
webpage. You see the webpage shown below. The available diagnostic screens are
listed on the page - click on any of the listed items to view its detailed information.
The Tools link on the left side of the webpage opens the webpage shown below..
To upgrade the meter’s firmware, click Firmware Upgrade.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
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CHAPTER 9: EPM 9900 NETWORK COMMUNICATIONS
You can also upgrade the meter’s firmware using GE Communicator software.
NoteNOTE:
NOTE
Refer to the GE Communicator User Manual for instructions.
11. You will see a log on screen. See the example screen shown below.
Enter the correct Username and Password to access the meter and click OK.
If password protection is not enabled for the meter, the default username and password
are both “anonymous”.
NoteNOTE:
NOTE
12. The webpage “update1.htm” opens. See the example webpage shown below.
13. Click the Browse button to locate the Upgrade file.
You must be using the PC on which the upgrade file is stored.
NoteNOTE:
NOTE
9–10
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 9: EPM 9900 NETWORK COMMUNICATIONS
14. Click the Update Meter File button to begin the upgrade process. The upgrade starts
immediately (it may take several minutes to complete).
15. Once the upgrade is complete, you see a webpage with a confirmation message,
shown below. Click the Reset Meter button to reset the meter.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
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CHAPTER 9: EPM 9900 NETWORK COMMUNICATIONS
9–12
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
GE Energy
EPM 9900 Electronic Meter
Chapter 10: Flicker Analysis
Flicker Analysis
10.1 Overview
Flicker is the sensation that is experienced by the human visual system when it is
subjected to changes occurring in the illumination intensity of light sources. The primary
effects of flicker are headaches, irritability and, sometimes, epileptic seizures.
IEC 61000-4-15 and former IEC 868 describe the methods used to determine flicker
severity. This phenomenon is strictly related to the sensitivity and the reaction of
individuals. It can only be studied on a statistical basis by setting up suitable experiments
among people.
The EPM 9900 meter has compliance for flicker and other power quality measurements.
Refer to Chapters 16 and 17 of the GE Communicator User Manual for additional
information on flicker and compliance monitoring.
10.2 Theory of Operation
Flicker can be caused by Voltage variations that are in turn caused by variable loads, such
as arc furnaces, laser printers and microwave ovens. In order to model the eye brain
change, which is a complex physiological process, the signal from the power network has
to be processed while conforming with figure 10-1.
• Block 1 consists of scaling circuitry and an automatic gain control function that
normalizes input Voltages to Blocks 2, 3 and 4.
• Block 2 recovers the Voltage fluctuation by squaring the input voltage scaled to
the reference level. This simulates the behavior of a lamp.
• Block 3 is composed of a cascade of two filters and a measuring range selector. In
this implementation, a log classifier covers the full scale in use so the gain
selection is automatic and not shown here. The first filter eliminates the DC
component and the double mains frequency components of the demodulated
output. For 50 Hz operation, the configuration consists of a first-order high pass
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
10–1
CHAPTER 10: FLICKER ANALYSIS
filter with 3db cut-off frequency at about 0.05 Hz and a 6-order butterworth low
pass filter with 35 Hz 3 db cut-off frequency. The second filter is a weighting filter
that simulates the response of the human visual system to sinusoidal Voltage
fluctuations of a coiled filament, gas-filled lamp (60 W - 230 V). The filter
implementation of this function is as specified in IEC 61000-4-15.
• Block 4 is composed of a squaring multiplier and a Low Pass filter. The human
flicker sensation via lamp, eye and brain is simulated by the combined non-linear
response of Blocks 2, 3 and 4.
• Block 5 performs an online statistical cumulative probability analysis of the flicker
level. Block 5 allows direct calculation of the evaluation parameters Pst and Plt.
Flicker evaluation occurs in the following forms: Instantaneous, Short Term or Long Term.
Each form is detailed below:
Instantaneous Flicker Evaluation
An output of 1.00 from Block 4 corresponds to the reference human flicker perceptibility
threshold for 50% of the population. This value is measured in perceptibility units (PU) and
is labeled Pinst. This is a real time value that is continuously updated.
Short Term Flicker Evaluation
An output of 1.00 from Block 5 (corresponding to the Pst value) corresponds to the
conventional threshold of irritability per IEC 61000-3-3:2008 edition 2 and EN61000-33:2008. In order to evaluate flicker severity, two parameters have been defined: one for the
short term called Pst (defined in this section) and one for the long term called Plt (defined in
the next section).
The standard measurement time for Pst is 10 minutes. Pst is derived from the time at level
statistics obtained from the level classifier in Block 5 of the flicker meter. The following
formula is used:
Pst = 0.0314 P0.1 + 0.0525 P1s + 0.0657 P3 s + 0.28 P10 s + 0.08 P50 s
(EQ 10.1)
where the percentiles P(0.1), P(1), P(3), P(10), P(50) are the flicker levels exceeded for 0.1, 1, 2,
20 and 50% of the time during the observation period. The suffix S in the formula indicates
that the smoothed value should be used. The smoothed values are obtained using the
following formulas:
P(1s) = (P(.7) + P(1) + P(1.5))/3
P(3s) = (P(2.2) + P(3) + P(4))/3
P(10s) = (P(6) + P(8) + P(10) + P(13) + P(17))/5
P(50s) = (P(30) + P(50) + P(80))/3
The .3-second memory time constant in the flicker meter ensures that P(0.1) cannot
change abruptly and no smoothing is needed for this percentile.
Long Term Flicker Evaluation
The 10-minute period on which the short-term flicker severity is based is suitable for short
duty cycle disturbances. For flicker sources with long and variable duty cycles (e.g., arc
furnaces) it is necessary to provide criteria for long-term assessment. For this purpose, the
10–2
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CHAPTER 10: FLICKER ANALYSIS
long-term Plt is derived from the short-term values over an appropriate period. By
definition, this is 12 short-term values of 10 minutes each over a period of 2 hours. The
following formula is used:
N
Plt =
3
P
3
sti
i =1
N
(EQ 10.2)
where Psti (i = 1, 2, 3...) are consecutive readings of the short-term severity Pst.
10.2.1 Summary
Flicker = changes in the illumination of light sources due to cyclical voltage variations
Pinst = instantaneous flicker values in perceptibility units (PU)
Pst = value based on 10-minute analysis
Plt = value based on 12 Pst values
Measurement Procedure
1.
Original signal with amplitude variations
2.
Square demodulator
3.
Weighted filter
4.
Low pass filter 1st order
5.
Statistical computing
Data available
• Pst, Pst Max, Pst Min values for long term recording
• Plt, Plt Max, Plt Min values for long term recording
Figure 10-1: Simulation of Eye Brain Response
Simulation Of Eye Brain Response
Block 1
Block 2
Voltage
Detector
and Gain
Control
Square
Law
Demodulator
Input
Voltage
Adaptor
Block 3
High Pass
Filter
(DC
Removal)
Low
Pass Filter
(Carrier
Removal
Weighting
Filter
Block 4
Squaring
Multiplier
1st
Order
Sliding
Mean
Filter
Block 5
A/D
Converter
Sampling
Rate
>50Hz
Output
Interface
Programming of short and
long observation periods
Output Recording
Instantaneous Flicker in
Perceptibility Units
(Pinst)
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
Minimum
64 level
Classifier
Output and Data Display
Pst Max/Min Pst
Plt Max/Min Plt
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CHAPTER 10: FLICKER ANALYSIS
10.3 EN50160/IEC61000-4-30 Flicker Logging
The EPM 9900 meter can record flicker values in independent logs. When flicker recording
is enabled, entries are made into the logs in accordance with the times the associated
values occur. Pst, Pst Max, Pst Min, Plt, Plt Max, Plt Min, and Reset times are all recorded.
You can download the Flicker logs to the Log Viewer and graph or export the data to
another program, such as Excel. Refer to Chapter 9 of the GE Communicator User Manual
for detailed information on retrieving and viewing logs with the Log Viewer.
You must set up several parameters to properly configure flicker logging:
10–4
1.
Select the Profile icon from GE Communicator's Icon bar.
2.
From the Device Profile screen, double-click Power Quality and Alarm
Settings>EN50160/IEC61000-4-30. Depending on your current setting, you
will see one of the following screens.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 10: FLICKER ANALYSIS
3.
The EPM 9900 meter uses Historical logs 7 and 8 to record the data required
for EN50160 report generation when EN50160/IEC61000-4-30 logging has
been enabled (if it has not been enabled Historical logs 7 and 8 function in the
same way as the other Historical logs). You will see the first screen if EN50160/
IEC61000-4-30 logging has not been enabled for the meter; you will see the
second screen if it has already been enabled.
•
If you see the first screen, click Auto-Configure. Historical logs 7 and 8 will
now be used for EN50160/IEC61000-4-30 logging, only.
It takes a week for the meter to collect all the necessary data for the analysis.
Note
NOTE
Note
NOTE
If EN50160/IEC61000-4-30 recording is already active and you want to disable it, click
Enable Logs 7 and 8. This will disable the EN50160/IEC61000-4-30 logging in
Historical logs 7 and 8.
4.
Make the following selections/entries:
IEC 61000-4-30 Class A:
• Enter the nominal Voltage in secondary (range from 40V to 600V).
• Select the frequency (50 or 60Hz).
IEC 61000 4-30 Flicker:
• Select the short term test time (1-10 minutes, in minute increments).
• Select the long term test time (10-240 minutes, in ten minute increments).
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CHAPTER 10: FLICKER ANALYSIS
EN 50160:
• Select the number of allowed rapid Voltage changes per day (1- 50).
• Select the synchronous connection status (Yes or No: Yes for a system with
a synchronous connection to another system, No if there is no such
synchronous connection).
• Select the number of allowed long interruptions (0-100).
• Select how often RMS is updated for rapid Voltage data source (1 cycle or
10/12 cycles)
• Select the upper limit for the supply Voltage unbalance (less than or equal
to 2% or 3%).
• Select the Voltage dip concern threshold (greater than or equal to 10%85%).
• Select the first day of the week (Sunday or Monday).
• Enter the Mains signalling threshold.
• Enter the Mains signalling Interharmonic frequency.
Phase Conductors to Earth Thresholds in percentage of Full Scale:
• Enter the value for A-E, B-E, and C-E.
• Enter the value for N-E.
5.
6.
10–6
Click OK.
Click Update Device to send the new settings to the meter and return to the
main GE Communicator screen.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 10: FLICKER ANALYSIS
10.4 IEC61000-4-30 Harmonic and Interharmonic Limits
Screen
In order to adhere to the IEC61000-4-30 Class A Flicker Meter standard, the EPM 9900
meter calculates group and sub-group values for harmonics and interharmonics, up to the
51st order. You can also set thresholds for these readings. The thresholds are used to trip a
flag (a bit inside the status reading, mapped into the modbus register). The sub-group
readings and over-threshold status are available through the Flicker logs and Modbus
register.
1.
Click in a field to enter a threshold for that reading (use the scroll bars to view
all of the readings). Whenever the meter’s reading goes above the threshold,
the flag (status bit) is tripped.
2.
Click OK to save your settings.
3.
Click Update Device to send the new settings to the meter and return to the
main GE Communicator screen.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
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CHAPTER 10: FLICKER ANALYSIS
10.5 EN50160/IEC61000-4-30 Flicker Polling Screen
From the GE Communicator Title bar, select Real-Time Poll>Power Quality and
Alarms>Flicker. You will see the screen shown below.
Main screen
This section describes the Main screen functions. These functions are found on the left side
of the screen.
Time
• Start/Reset is the time when flicker was started or reset. A reset of flicker causes
the Max/Min values to be cleared. A reset should be performed before you start
using Flicker logging, to update the Start time.
• Current is the current clock time.
• Next Pst is the countdown time to when the next Pst value is available.
• Next Plt is the countdown time to when the next Plt value is available.
Status
• Indicates the current status: Active = on.
Frequency
• Base is the operating frequency (50 or 60 Hz) selected in the EN50160 Flicker
screen (see Section 10.3).
• Current is the real time frequency measurement of the applied Voltage.
Base Voltage
• The Voltage reference based on the Standard’s specification, calculated
automatically by the EPM 9900 meter.
Flicker Monitoring
• Click Reset to cause the Max/Min values to be cleared.
10–8
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 10: FLICKER ANALYSIS
The Reset function may be restricted to a level 2 password. If so, and if you have not
signed on with a level 2 password, you will not see the Reset button.
Note
NOTE
Use the tabs at the top of the screen view to the Instantaneous, Short Term, and Long Term
readings.
Instantaneous Readings
Note
NOTE
The Instantaneous view is the default of this screen (see the screen shown on the
previous page). If you are in the Short or Long Term views, click on the Instantaneous
tab to display this view.
• The PU values, Pinst for Voltage Inputs Va, Vb and Vc are displayed here and are
continuously updated. The corresponding current Voltage values for each channel
are displayed for reference.
Short Term Readings
Click on the Short Term tab to view the Pst readings.
Pst Readings Displayed:
• Current Pst values for Va, Vb and Vc and the time of computation.
• Current Pst Max values for Va, Vb and Vc since the last reset and the time of the
last reset.
• Current Pst Min values for Va, Vb and Vc since the last reset and the time of the last
reset.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
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CHAPTER 10: FLICKER ANALYSIS
Long Term Readings
Click on the Long Term tab to view the Plt readings.
Plt Readings Displayed:
• Current Plt values for Va, Vb and Vc and the time of computation.
• Current Plt Max values for Va, Vb and Vc since the last reset and the time of the last
reset.
• Current Plt Min values for Va, Vb and Vc since the last reset and the time of the last
reset.
Click OK to exit the EN50160/IEC61000-4-30 Flicker Polling screen; click Print to print all of
the Readings views.
10–10
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 10: FLICKER ANALYSIS
10.6 Polling through Communications
The Pinst, Pst, Pst Max, Pst Min, Plt, Plt Max, Plt Min values can be polled through the
communications port. Refer to the EPM 9900 meter's Modbus and DNP Mapping manuals
for register assignments and data definitions.
10.7 Log Viewer
1.
Click the Open Log icon from GE's Communicator Icon bar.
2.
Log Viewer opens. Using the menus at the top of the screen, select a meter,
time ranges and values to access.
3.
Click the Flicker icon.
The values and the associated time stamps (when the values occurred) are displayed in a
grid box. Use the buttons at the bottom of the screen to create a graph or export the data
to another program.
•
Graphed values include Pst and Plt Va, Vb and Vc.
•
Displayed values include Pst and Plt Max and Min for Va, Vb and Vc.
Max and Min values are only displayed; they cannot be graphed. However, Max and
Min values are available for export.
Note
NOTE
10.8 Performance Notes
• Pst and Plt average time are synchronized to the clock (e.g. for a 10 minute
average, the times will occur at 0, 10, 20, etc.). The actual time of the first average
can be less than the selected period to allow for initial clock synchronization.
• If the wrong frequency is chosen (e.g. 50Hz selection for a system operating at
60Hz), flicker will still operate but the computed values will not be valid. Therefore,
you should select the frequency setting with care.
• User settings are stored. If flicker is enabled and power is removed from the meter,
flicker will still be on when power returns. This can cause gaps in the logged data.
• The Max and Min values are stored, and are not lost if the unit is powered down.
• Flicker meets the requirements of IEC 61000-4-15, IEC61000-4-30 and former IEC
868. Refer to those specifications for more details, if needed. Refer to chapters 16
and 17 in the GE Communicator User Manual for additional information.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
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CHAPTER 10: FLICKER ANALYSIS
10–12
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
GE Energy
EPM 9900 Electronic Meter
Chapter 11: Using the I/O Options
Using the I/O Options
11.1 Overview
The EPM 9900 meter offers extensive I/O expandability. With its four Option card slots, you
can easily configure the meter to accept new I/O Option cards without removing it from its
installation. The EPM 9900 meter auto-detects any installed Option cards. The meter also
offers multiple optional external I/O modules.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
11–1
CHAPTER 11: USING THE I/O OPTIONS
11.2 Installing Option Cards
The Option cards are inserted into their associated Option card slots in the back of the EPM
9900 meter.
Note
IMPORTANT! Remove Voltage inputs and power supply to the meter before performing
card installation.
Figure 11-1: Inserting an I/O Card into the Meter
I/O Card Guide Track
Slide I/O card in track
I/O Card Guide Track
Note
1.
Remove the screws at the top and the bottom of the Option card slot covers.
2.
There is a plastic "track" on the top and the bottom of the slot. The Option
card fits into this track.
Make sure the I/O card is inserted properly into the track to avoid damaging the card's
components.
3.
Slide the card inside the plastic track and insert it into the slot. You will hear a
click when the card is fully inserted. Be careful: it is easy to miss the guide
track. Refer to Figure 11-1.
11.3 Configuring Option Cards
FOR PROPER OPERATION, RESET ALL PARAMETERS IN THE UNIT AFTER HARDWARE
MODIFICATION.
The EPM 9900 meter auto-detects any Option cards installed in it. Configure the Option
cards through GE Communicator software. Refer to Chapter 5 of the GE Communicator
User Manual for detailed instructions.
11–2
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 11: USING THE I/O OPTIONS
11.4 Pulse Output/RS485 Option Card (S Option)
Pulse Output/RS485 Port Specifications
Dual RS485 Transceiver; meets or exceeds EIA/TIA-485 Standard
Type:
Two-wire, half duplex
Min. Input Impedance:
96 kΩ
Max. Output Current:
±60 mA
Isolation Between Channels
AC 1500 V
Wh Pulse
4 KYZ output contacts
Pulse Width:
Programmable from 5 msec to
635 msec
Full Scale Frequency:
100 Hz
Form:
Selectable from Form A or Form C
Contact type:
Solid State - SPDT (NO - C - NC)
Relay type:
Solid state
Peak switching voltage:
DC ±350 V
Continuous load current:
120 mA
Peak load current:
350 mA for 10 ms
On resistance, max.:
35Ω
Leakage current:
1 µ[email protected] V
Isolation:
AC 2500 V
Reset State:
(NC - C) Closed; (NO - C) Open
General Specifications for Pulse Output/RS485 Board
Operating Temperature:
(-20 to +70) °C
Storage Temperature:
(-30 to +80) °C
Relative Air Humidity:
Maximum 95%, non-condensing
EMC - Immunity Interference:
EN61000-4-2
Weight:
2.4 oz
Dimensions (inches) W x H x L:
0.75" x 4.02" x 4.98"
I/O Card slot:
Option slot 1
External Connection:
Wire range: 16 to 26 AWG
Strip Length: 0.250"
Torque: 2.2 lb-in
18 pin, 3.5 mm pluggable terminal
block
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
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CHAPTER 11: USING THE I/O OPTIONS
11.4.1 Pulse Output/RS485 Option Card (S Option) Wiring
SLOT 1
RS-485
RX
TX
1
2
A(+)
*
C
O
M
1
A(+)
*
C
O
M
2
B(-)
SH
B(-)
SH
NO
4
C
NC
NO
3
C
NO
NC
NO
2
C
RELAY CONTACTS
C
NC
NO
1
NC
C
NC
PULSE
OUTPUTS
* NOTE: Refer to the Communication Installation chapter for RS485 setting instructions.
Note
NOTE
11–4
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 11: USING THE I/O OPTIONS
11.5 Ethernet Option Card: RJ45 (E1) or Fiber Optic (E2)
The Ethernet Option card provides data generated by the meter via Modbus. It can be
factory configured as a 10/100BaseT or as a 100Base-FX Fiber Optic communication port.
Note
NOTE
Refer to Chapter 5 of the GE Communicator User Manual for instructions on performing
Network configuration. See Chapter 9 of this manual for details on configuring the
standard main Network card.
The technical specifications at 25 °C are as follows
Number of Ports: 1
Operating rate: 10/100Mbit
Diagnostic feature: Status LEDs for LINK and ACTIVE
Number of 8 (Includes 8 total connections over both
simultaneous Ethernet connections.)
Modbus
connections:
Number of 2 TCP and 1 UDP per communication channel
simultaneous DNP
connections:
The general specifications are as follows
Operating Modes: 10/100BaseT or 100Base-FX
Operating (-20 to +70) °C
Temperature:
Storage (-30 to +80) °C
Temperature:
Relative air Maximum 95%, non-condensing
humidity:
EMC - Immunity EN61000-4-2
Interference:
Weight: 2.3 oz
Dimensions 0.75" x 4.02" x 5.49"
(inches) W x H x L:
I/O Card slot: Option slot 2
Connection Type: RJ45 modular (Auto-detectingtransmit and
receive) 10/100BaseT
OR
Duplex ST Receptacle - 100Base-FX
Fiber Optic Specifications are as follows
Connector: ST
Fiber Mode: Multimode Fiber 62.5/125 um
Wavelength: 1310 nm
Max. Distance: 2 km
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
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CHAPTER 11: USING THE I/O OPTIONS
Default Configuration
The EPM 9900 meter automatically recognizes the installed Option card during power-up.
If you have not programmed a configuration for the Ethernet card, the unit defaults to the
following configuration:
Main Network card 1 (E1):
IP Address: 10.0.0.1
Subnet Mask: 255.255.255.0
Default Gateway: 0.0.0.0
Optional Network card 2 (E2):
IP Address: 10.0.1.1
Subnet Mask: 255.255.255.0
Default Gateway: 0.0.0.0
The IP addresses of the EPM 9900 meter's standard main Network card and optional
Network Card 2 must be in different subnets.
Note
NOTE
11.6 Relay Output Option Card (R1)
The Relay Output card has 6 relay contact outputs for load switching. The outputs are
electrically isolated from the main unit.
The technical specifications at 25 °C are as follows
Power consumption: 0.320 W internal
Relay outputs:
Number of outputs: 6
Contact type: Changeover (SPDT)
Relay type: Mechanically latching
Switching voltage: AC 250 V / DC 30 V
Switching power: 1250 VA / 150 W
Switching current: 5 A
Switching rate max: 10/s
Mechanical life: 5 x 107 switching operations
Electrical life: 105 switching operations at rated
current
Breakdown voltage: AC 1000 V between open
contacts
Isolation: AC 2500 V surge system to
contacts
Reset/Power down No change - last state is retained
state:
11–6
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 11: USING THE I/O OPTIONS
The general specifications are as follows
Operating (-20 to +70) °C
temperature:
Storage (-30 to +80) °C
temperature:
Relative air humidity: Maximum 95%, non-condensing
EMC - Immunity EN61000-4-2
Interference:
Weight: 2.7 oz
Dimensions (inches) 0.75" x 4.02" x 4.98"
W x H x L:
I/O Card slot: Option slots 3 and 4
External connection: Wire range: 16 to 26 AWG
Strip length: 0.250"
Torque: 2.2 lb-in
18 pin, 3.5 mm pluggable
terminal block
11.6.1: Relay Output Option Card (6RO1) Wiring
11.6.1 Relay Output Option Card (R1) Wiring
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
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CHAPTER 11: USING THE I/O OPTIONS
11.7 Digital Input Option Card (D1)
The Digital Input Option card offers 16 wet/dry contact sensing digital inputs.
The technical specifications at 25 °C are as follows
Power consumption: 0.610 W
Number of inputs: 16
Sensing type: Wet or dry contact status detection
Wetting voltage: DC (12-24) V, internally generated
Input current: 1.25 mA - constant current regulated
Minimum input 0 V (input shorted to V-)
voltage:
Maximum input DC 150 V (diode protected against polarity
voltage: reversal)
Filtering: De-bouncing with 10 ms delay time
Detection scan rate: 20 ms
Isolation: AC 2500 V system to inputs
The general specifications are as follows
Operating (-20 to +70) °C
temperature:
Storage temperature: (-30 to +80) °C
Relative air humidity: Maximum 95%, non-condensing
EMC - Immunity EN61000-4-2
Interference:
Weight: 2.4 oz
Dimensions (inches) 0.75" x 4.02" x 4.98"
W x H x L:
I/O Card slot: Option slots 3 and 4
External connection: Wire range: 16 to 26 AWG
Strip length: 0.250"
Torque: 2.2 lb-in
18 pin, 3.5 mm pluggable terminal block
This feature allows for either status detect or pulse counting. Each input can be assigned
an independent label and pulse value.
Note
NOTE
11–8
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 11: USING THE I/O OPTIONS
11.7.1 Digital Input Option Card (D1) Wiring
)NPUTS
n
&ORDRYCONTACTS
6
)NPUTS
n
&ORWETCONTACTS
6
6,OOP
n 6
n
6,OOP
!LTERNATE
FORWETCONTACTS
)NPUTS
n
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
11–9
CHAPTER 11: USING THE I/O OPTIONS
11.8 Optional External I/O Modules
All EPM 9900 external I/O modules have the following components:
• Female RS485 Side Port: use to connect to another module's male RS485 side port.
• Male RS485 Side Port: use to connect to the EPM 9900 meter's Port 3 or 4 or to
another module's female RS485 side port. See Figure 11-2 for wiring details.
• I/O Port: used for functions specific to the type of module. Size and pin
configuration vary depending on the type of module.
• Reset Button: press and hold for three seconds to reset the module's baud rate to
57600, and its address to 247 for 30 seconds.
• LEDs: when flashing, the LEDs signal that the module is functioning.
• Mounting Brackets (MBIO): used to secure one or more modules to a flat surface.
Figure 11-2: I/O Module Components
Mounting Brackets (MBIO)
Female RS485
Side Port
I/O Port
LEDs
(Size and Pin
Configuration Vary)
Male RS485
Side Port
Reset Button
11–10
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 11: USING THE I/O OPTIONS
11.8.1 Port Overview
All of the optional external I/O modules have ports through which they interface with other
devices. The port configurations are variations of the four types shown below.
Figure 11-3: External I/O Module Ports
Four Analog Outputs
(0-1mA and 4-20mA)
Eight Analog Outputs
(0-1mA and 4-20mA)
0-1mA
Analog Output
Module
0-1mA
Analog Output
Module
COM
COM
OUT 1
OUT 1
OUT 2
OUT 2
OUT 3
OUT 3
OUT 4
OUT 4
OUT 5
OUT 6
OUT 7
OUT 8
RESET
RESET
Eight Analog Inputs
(0-1mA, 0-20mA, 0-5Vdc,
Four Relay Outputs
or Four KYZ Pulse Outputs
0-10Vdc) or Eight Status Inputs
NO
0-1mA
Analog Input
Module
C
1
NO
COM
INPUT 1
INPUT 2
INPUT 3
INPUT 4
INPUT 5
INPUT 6
NO
K
Y
Z
C
2
NO
O
U
T
P
U
T
S
NO
C
3
NO
NO
INPUT 7
C
INPUT 8
RESET
4
NO
RESET
11.8.2 Installing Optional External I/O Modules
I/O modules must use the EPM 9900 meter's ports 3 or 4. Six feet of RS485 cable harness is
supplied. Attach one end of the cable to the port (connectors may not be supplied); insert
the other end into the communication pins of the module's male RS485 side port (see
Figure 11-2). See Section 11.8.4.1 for details on using multiple I/O modules.
Installing the External I/O Modules
1.
Connect the (+) and (-) terminals on the EPM 9900 meter to the (+) and (-)
terminals of the male RS485 port.
2.
Connect the shield to the shield (S) terminal. The (S) terminal on the EPM 9900
meter is used to reference the EPM 9900 meter's port to the same potential as
the source. It is not an earth to ground connection. You must also connect the
shield to earth-ground at one point.
3.
Put termination resistors at each end, connected to the (+) and (-) lines. RT is
~120 Ohms.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
11–11
CHAPTER 11: USING THE I/O OPTIONS
4.
Connect a power source to the front of the module.
11.8.3 Power Source for External I/O Modules
The EPM 9900 meter does not have internal power for the external I/O modules. You must
use a power supply, such as the GE Digital Energy PSIO, to power any external I/O modules.
Figure 11-4: PSIO Side View
Figure 11-5: PSIO Side and Top Labels
On
Power In
N(-)
!
L(+)
DANGER
PowerPSIO
Supply
Max Power: 12 VA
Input Voltage: 12-60V DC
90-240V AC/DC
Output Voltage: 12V DC
POWER +
POWER -
11–12
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 11: USING THE I/O OPTIONS
11.8.4 Using PSIO with Multiple I/O Modules
PSIO must be to the right of the I/O modules, when viewing its side label (as shown in the
figure below).
Note
NOTE
Figure 11-6: PSIO with Multiple External I/O Modules
0-1mA
Analog Input
Module
CT
RX
TX
RX
TX
0-1mA
Analog Output
Module
CT
CT
TX
Female
RS485
Side Port
Communication
ONLY
(A+, B- and
Shield)
RX
LEDs
On
0-1mA
Analog Input
Module
COM
COM
COM
OUT 1
INPUT 1
INPUT 1
OUT 2
INPUT 2
INPUT 2
OUT 3
INPUT 3
INPUT 3
Power In
N(-)
OUT 4
RESET
L(+)
DANGER
PowerPSIO
Supply
INPUT 4
INPUT 4
INPUT 5
INPUT 5
-AX0OWER6!
INPUT 6
INPUT 6
)NPUT6OLTAGE6$#
INPUT 7
INPUT 7
6!#$#
INPUT 8
INPUT 8
/UTPUT6OLTAGE6$#
RESET
Control
Power
RESET
%LECTRO)NDUSTRIES'AUGE4ECH
Reset Button
Mounting Bracket
I/O Port (Size and pin configuration vary)
Steps for Attaching Multiple I/O Modules
I/O Module Dimensions
Figure 11-7: I/O Modules, Top View
5.629”/14.30cm
3X 1.301”/3.305cm
1.125”/2.858cm
Mounting Bracket
.090”/.229cm
Mounting Bracket
4.188”/10.638cm
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
11–13
CHAPTER 11: USING THE I/O OPTIONS
Figure 11-8: I/O Modules, Front View
Mounting Bracket
Mounting Bracket
6.879”/13.088cm
/N
0OWER)N
.
,
3.437”/8.729cm
$!.'%2
0OWER3UPPLY
03)/
2.200”/5.588cm
-AX0OWER6!
)NPUT6OLTAGE6$#
1.100”/2.54cm
6!#$#
/UTPUT6OLTAGE6$#
.618”/1.570cm
1.301”/3.305cm
1.
Each I/O module in a group must be assigned a unique address. See the GE
Communicator User Manual for instructions on configuring and programming
the I/O modules.
2.
Starting with the left module and using a slotted screwdriver, fasten the first I/
O module to the left mounting bracket. The left mounting bracket is the one
with the PEM. Fasten the internal screw tightly into the left mounting bracket.
3.
Slide the female RS485 port into the male RS485 side port to connect the next
I/O module to the left module. Fasten together enough to grab but do not
tighten, yet.
4.
Combine the modules together, one by one.
5.
Attach a PSIO (power supply) to the right of each group of I/O modules it is
supplying with power (see Figure 11-6). The PSIO supplies 12 VA at 125 V AC/
DC. See sections 11.8.6 - 11.8.8 for I/O modules power requirements.
6.
Once you have combined all of the I/O modules together for the group, fasten
them tightly. This final tightening locks the group together as a unit.
7.
Attach the right mounting bracket to the right side of the group using the
small Phillips Head screws provided.
8.
Mount the attached group of modules on a secure, flat surface. This insures
that all modules stay securely connected.
11.8.5 Factory Settings and Reset Button
Factory Settings
All external I/O modules are shipped with a preset address and a baud rate of 57600. See
following sections for I/O Module addresses.
Reset Button:
If there is a communication problem or if you are unsure of a module's address and baud
rate, press and hold the Reset button for 3 seconds; the module resets to a default address
of 247 at 57600 baud rate for 30 seconds.
11–14
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 11: USING THE I/O OPTIONS
11.8.6 Analog Transducer Signal Output Modules
Analog Transducer Signal Output Module Specifications
Model Numbers
1mAON4: 4-channel analog output 0±1 mA
1mAON8: 8-channel analog output 0±1 mA
20mAON4: 4-channel analog output 4-20 mA
20mAON8: 8-channel analog output 4-20 mA
Accuracy
0.1% of Full Scale
Over-range
±20% of Full Scale
Scaling
Programmable
Communication
RS485, Modbus RTU
Programmable Baud Rates: 4800, 9600, 19200, 38400, 57600
Power Requirement
12-20 VDC @50-200 mA
Operating Temperature
(-20 to +70) °C/(-4 to +158) °F
Maximum Load Impedance
0±1mA: 10k Ohms; 4 to 20mA: 500 Ohms
Factory Settings
Modbus Address: 1mAON4: 128; 1mAON8: 128; 20mAON4: 132;
20mAON8: 132
Baud Rate: 57600
Transmit Delay Time: 0
Default Settings (Reset Button)
Modbus Address: 247
Baud Rate: 57600
Transmit Delay Time: 20 msec
Overview
The Analog Transducer Signal Output modules (0±1 mA or 4 to 20 mA) are available in
either a 4-channel or 8-channel configuration. Maximum registers per request, read or
write, is 17 registers.
All outputs share a single common point. This is also an isolated connection (from ground).
Normal Mode
Normal mode is the same for the 0 to 1 mA and the 4 to 20 mA Analog Output modules
except for the number of processes performed by the modules.
Both devices:
1.
Accept new values through communication
2.
Output current loops scaled from previously accepted values
The 0 to 1 mA module includes one more process in its Normal mode:
3.
Reads and averages the A/D and adjust values for Process 2, above
The device operates with the following default parameters:
Address: 247 (F7H)
Baud Rate: 57600 Baud
Transmit Delay Time: 20 msec
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
11–15
CHAPTER 11: USING THE I/O OPTIONS
11.8.7 Digital Dry Contact Relay Output (Form C) Module
Only one of these modules may be connected to an EPM 9900 meter.
Note
Digital Dry Contact Relay Output Module Specifications
NOTE
Model Number
4RO1: 4 matching relay outputs
Contact Type
Changeover (SPDT)
Relay Type
Mechanically latching
Communication
RS485, Modbus RTU
Programmable Baud Rates: 4800, 9600, 19200, 38400, 57600
Power Requirement
12-20VDC @50 to 200 mA
Operating Temperature
(-20 to +70) °C / (-4 to +158) °F
Switching Voltage
AC 250 V / DC 30 V
Switching Power
1250 VA / 150 W
Switching Current
5A
Switching Rate Max.
10/s
Mechanical Life
5 x 107 switching operations
Electrical Life
105 switching operations at rated current
Breakdown Voltage
AC 1000 V between open contacts
Isolation
AC 2500 V surge system to contacts
Reset/Power Down State
No change - last state is retained
Factory Settings
Modbus Address: 156
Baud Rate: 57600
Transmit Delay Time: 0
Default Settings (Reset Button)
Modbus Address: 247
Baud Rate: 57600
Transmit Delay Time: 20 msec
Overview
The Relay Output module consists of four latching relay outputs. In Normal mode, the
device accepts commands to control the relays. Relay Output modules are triggered by
limits programmed with the GE Communicator software. See the GE Communicator User
Manual for details on programming limits.
Each latching relay will hold its state in the event of a power loss.
Communication
Maximum registers per request, read or write, is 4 registers.
The device operates with the following default parameters:
Address: 247 (F7H)
Baud Rate: 57600 Baud
Transmit Delay Time: 20 msec
Normal Mode
Normal mode consists of one process: the device accepts new commands to control the
relays.
11–16
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 11: USING THE I/O OPTIONS
11.8.8 Digital Solid State Pulse Output (KYZ) Module
Digital Solid State Pulse Output Module Specifications
Model Number
4PO1
Communication
RS485, Modbus RTU
Programmable Baud Rates: 4800, 9600, 19200, 38400, 57600
Power Requirement
15-20 VDC @50-200 mA
Operating Temperature
(-20 to +70) °C/(-4 to +158) °F
Voltage Rating
Up to 300 VDC
Commands Accepted
Read and Write with at least 4 registers of data per command
Memory
256 Byte IC EEPROM for storage of programmable settings and nonvolatile memory
Factory Settings
Modbus Address: 160
Baud Rate: 57600
Transmit Delay Time: 0
Default Settings (Reset Button)
Modbus Address: 247
Baud Rate: 57600
Transmit Delay Time: 20 msec
Overview
The KYZ Pulse Output modules have 4 KYZ pulse outputs and accept Read and Write
commands with at least 4 registers of data per command. Digital Solid State Pulse Output
(KYZ) modules are user programmed to reflect VAR-hours, WATT-hours, or VA-hours.
NC = Normally Closed; NO = Normally Open; C = Common.
Communication
Maximum registers per request, read or write, is 4 registers.
The device operates with the following default parameters:
Address: 247 (F7H)
Baud Rate: 57600 Baud
Transmit Delay Time: 20 msec
Normal Mode
Energy readings are given to the device frequently. The device generates a pulse at each
channel after a certain energy increase.
Normal operation consists of three processes:
1.
The first process accepts writes to registers 04097 to 04112. Writes can be up
to four registers long and should end on the fourth register of a group (register
04100, or registers 04103 to 04112 or registers 04109 to 04112). These writes
can be interpreted as two-byte, four-byte, six-byte or eight-byte energy
readings. The reception of the first value for a given channel provides the
initial value for that channel. Subsequent writes will increment the residual for
that channel by the difference of the old value and the new value. The
previous value is then replaced with the new value. Attempting to write a
value greater than the programmed rollover value for a given channel is
completely ignored and no registers are modified. If the difference is greater
than half of the programmed rollover value for a given channel, the write does
not increment the residual but does update the last value. Overflow of the
residual is not prevented.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
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CHAPTER 11: USING THE I/O OPTIONS
2.
The second process occurs in the main loop and attempts to decrement the
residual by the programmed Energy/Pulse value. If the residual is greater than
the programmed Energy/Pulse value and the Pending Pulses value for that
channel has not reached the maximum limit, then residual is decremented
appropriately and the Pending Pulses value is incremented by two, signifying
two more transitions and one more pulse.
3.
The third process runs from a timer that counts off pulse widths from the
Programmable Minimum Pulse Width values. If there are pulses pending for a
channel and the delay has passed, then the Pending Pulses value is
decremented for that channel and the output relay is toggled.
Operation Indicator (0000H = OK, 1000H = Problem):
Bit 1: 1 = EEPROM Failure
Bit 2: 1 = Checksum for Communications settings bad
Bit 3: 1 = Checksum for Programmable settings bad
Bit 4: 1 = 1 or more Communications settings are invalid
Bit 5: 1 = 1 or more Programmable settings are invalid
Bit 6: 1 = 1 or more Programmable settings have been modified
Bit 7: 1 = Forced default by reset value
Bit 15: 1 = Normal operation of the device is disabled
11.8.9 Analog Input Modules
Up to four of these modules may be connected to an EPM 9900 meter.
Note
Analog Input Module Specifications
NOTE
Model Numbers
8AI1: 8-channel analog input 0±1 mA
8AI2: 8-channel analog input 0±20 mA
8AI3: 8-channel analog input 0±5 VDC
8AI4: 8-channel analog input 0±10 VDC
Accuracy
0.1% of Full Scale
Scaling
Programmable
Communication
RS485, Modbus RTU
Power Requirement
15-20 VDC @50-200 mA
Operating Temperature
(-20 to +70) °C/(-4 to +158) °F
Programmable Baud Rates: 4800, 9600, 19200, 38400, 57600
Maximum Load Impedance
0±1 mA: 10 k Ohms; 4-20 mA: 500 Ohms
Factory Settings
Modbus Address: 8AI1: 136; 8AI2: 140; 8AI3: 144; 8AI4: 148
Baud Rate: 57600
Transmit Delay Time: 0
Default Settings (Reset Button)
Modbus Address: 247
Baud Rate: 57600
Transmit Delay Time: 20 msec
Overview
The Analog Input Modules (0±1 mA, 0±20 mA, 0±5 Vdc and 0±10 Vdc) are available in 8channel format. Maximum registers per request, read or write, is 17 registers.
11–18
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER 11: USING THE I/O OPTIONS
All inputs share a single common point. This is also an isolated connection (from ground).
Normal Mode
In Normal Mode, the Input Module:
1.
Reads and averages the A/D and adjusts values for process 2.
2.
Calculates the percentage of Input Value.
The percentage value of the Input is stored in Input Value Registers (Registers 04097 to
04104).
Note
NOTE
The device operates with the following default parameters:
Address: 247 (F7H)
Baud Rate: 57600 Baud
Transmit Delay Time: 20 msec
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
11–19
CHAPTER 11: USING THE I/O OPTIONS
11.9 Additional External I/O Module Specifications
Analog Transducer Signal Outputs (Up to four modules can be used.)
1mAON4: 4 Analog Outputs, scalable, bidirectional
1mAON8: 8 Analog Outputs, scalable, bidirectional
20mAON4: 4 Analog Outputs, scalable
20mAON8: 8 Analog Outputs, scalable
Digital Dry Contact Relay Outputs (One module can be used.)
4RO1: 4 Relay Outputs 10 Amps, 125 Vac, 30 Vdc, Form C
Digital Solid State Pulse Outputs (Up to four modules can be used.)
4PO1: 4 Solid State Pulse Outputs, Form A KYZ pulses
Analog Transducer Inputs (Up to four modules can be used.)
•
8AI1: 8 Analog Inputs 0 to 1 mA, scalable and bidirectional
•
8AI2: 8 Analog Inputs 0 to 20 mA, scalable
•
8AI3: 8 Analog Inputs 0 to 5 V DC, scalable
•
8AI4: 8 Analog Inputs 0 to 10 V DC, scalable
Other I/O Module Accessories
MBIO: Bracket for surface-mounting external I/O modules to any enclosure
PSIO: 12 V external power supply, which is necessary whenever you are connecting an
external I/O module to a EPM 9900 meter.
11–20
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
GE Energy
EPM 9900 Electronic Meter
Chapter A: Installing the USB
Virtual Comm Port
Installing the USB Virtual Comm Port
A.1
Introduction
As mentioned in Chapter 5, GE Digital Energy provides a driver (for operating systems
earlier than Windows® 7) that allows you to configure the EPM 9900 meter's USB port as a
Virtual Serial port. The driver is on the CD that came with your meter. Follow the
instructions in this chapter to install the driver and connect to the meter's Virtual port.
A.2
Installing the Virtual Port's Driver
1.
Insert the EPM 9900 Meter Series CD into your PC's CD drive. The screen
shown below opens in your Browser.
2.
Click the EPM 9900 Technical Documents button. The following screen opens
in your browser.
3.
Click the Software button at the top of the screen and click USB Driver.
4.
The setup program opens a DOS command screen on your PC, as shown
below. You will see a message indicating that the driver is being installed.
Once the driver installation is complete, you will see the following message on
the DOS command screen.
5.
Press Enter. The DOS screen closes.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
A–1
CHAPTER A: INSTALLING THE USB VIRTUAL COMM PORT
6.
A–2
Plug a USB cable into your PC and the EPM 9900 meter's USB port. You will
see pop-up message windows telling you that new hardware has been found
and that it is installed and ready to use.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER A: INSTALLING THE USB VIRTUAL COMM PORT
A.3
Connecting to the Virtual Port
1.
Open GE Communicator.
2.
Click the Connect icon. You will see the Connect screen, shown on the right.
3.
Click the Serial Port and Available Ports radio buttons and select the virtual
COM Port. To determine which COM Port is the USB virtual COM port, follow
these steps:
i
On your PC, click Start>Settings>Control Panel.
ii
Double-click on the System folder.
iii
Click the Hardware tab. You will see the screen shown on the right.
iv
Click the Device Manager button. You will see a list of your computer's
hardware devices.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
A–3
CHAPTER A: INSTALLING THE USB VIRTUAL COMM PORT
v
Click the plus sign next to Ports (COM & LPT). The COM ports will be
displayed. The USB Serial Port is the Virtual port. See the example screen
shown on the next page.
In this example, COM8 is the Virtual port: COM8 is the port you select in
the Connect screen.
A–4
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
GE Energy
EPM 9900 Electronic Meter
Chapter B: Power Supply Options
Power Supply Options
B.0.1
Power Supply
Options
The EPM 9900 meter offers the following power supply options:
Option
Description
AC
UL Rated AC Power Supply (100-240) VAC
HI
High-Voltage DC (100-240)VDC, (90-265) VAC
LD
UL rated Low-Voltage Power Supply (18-60)VDC
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
B–1
CHAPTER B: POWER SUPPLY OPTIONS
B–2
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
GE Energy
EPM 9900 Electronic Meter
Chapter C: Using the IEC 61850
Protocol Ethernet
Network Server
Using the IEC 61850 Protocol Ethernet Network Server
C.1
Overview of IEC 61850
With Software Options B and C, the EPM 9900 meter’s Main Network card has the ability to
function as an IEC 61850 Protocol Ethernet Network server. With the IEC 61850 Protocol
Ethernet Network server added to the EPM 9900 meter, the unit becomes an advanced
intelligent Device that can be networked on a IEC 61850 standard network within an
electrical distribution system.
IEC 61850 is a standard for the design of electrical substation automation, including the
networking of substation devices. The IEC 61850 standard is part of the International
Electrotechnical Commission's (IEC) Technical Committee 57 (TC57). It consists of a suite of
protocols (MMS, SMV, etc.) and abstract definitions that provide a standardized method of
communication and integration to support intelligent electronic devices from any vendor,
networked together to perform protection, monitoring, automation, metering and control
in a substation environment. For more information on IEC 61850 go to http://
iec61850.ucaiug.org/.
IEC 61850 was developed to:
•
Specify a design methodology for automation system construction.
•
Reduce the effort for users to construct automation systems using devices from
multiple vendors.
•
Assure interoperability between components within the automation system.
•
“Future-proof” the system by providing simple upgrade paths as the underlying
technologies change.
•
Communicate information rather than data that requires further processing. The
functionality of the components is moved away from the clients (requesters) toward
the servers (responders).
IEC 61850 differs from previous standards in that:
•
It specifies all aspects of the automation system from system specifications, through
device specifications, and then through the testing regime.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
C–1
CHAPTER C: USING THE IEC 61850 PROTOCOL ETHERNET NETWORK SERVER
•
The IEC 61850 standard specifies a layered approach to the specification of devices.
The layered approach allows “future-proofing” of basic functionality by allowing
individual “stack” components to be upgraded as technology progresses.
•
The individual objects within devices are addressed through a hierarchy of names
rather than numbers.
•
Each object has precise, standard terminology across the entire vendor community.
•
Devices can provide an online description of their data model.
•
A complete (offline) description language defines the way all of the parts of the system
are handled, giving a consistent view of all components within the system.
•
The IEC 61850 standard was developed for electrical substation automation, but has
been applied to Distributed Energy resources, distribution line equipment, hydroelectric power plants, and wind power plants.
C.1.1
Relationship of Clients and Servers in IEC 61850
The understanding of the roles of clients and servers and publishers and subscribers is key
to the use of IEC 61850 devices.
A client is the requester (sink) of information while the server is the responder (source) of
information. Information generally flows on a request-response basis with the client
issuing the request and the server issuing the response. However, the concept of servers is
extended to provide autonomous transmissions when “interesting” events occur within the
server. This information flow is always to the client requesting this “interesting
information.” Clients are the devices or services which “talk” to IEC 61850 servers. The
function of the client is to configure the server “connection,” set up any dynamic
information in the server, enable the reporting mechanisms, and possibly interrogate
specific information from the server. Most clients are relatively passive devices which await
information from the server but perform little direct ongoing interactions with them except
for control operations.
Some clients are used for diagnostic purposes. These devices generally perform ongoing
direct interrogation of the servers. A specific example is the “desktop client,” where the
engineer remotely diagnoses system problems or retrieves data which is not normally sent
from the server (for example, power quality information).
IEC 61850 clients are highly interoperable with IEC 61850 servers. Clients are able to
retrieve the server object directory (when needed) and then perform any allowable
operation with that server.
Example clients include: Omicron IED scout, SISCO AX-S4 61850, TMW Hammer, KalkiTech
gateway, Siemens DIGSI.
C–2
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER C: USING THE IEC 61850 PROTOCOL ETHERNET NETWORK SERVER
An example of the object model display on a diagnostic client is shown in Figure C-1:
Object Model Display Example.
Figure C-1: Object Model Display Example
Note
NOTE
There is an additional relationship in IEC 61850, known as publisher and subscriber. The
publisher/subscriber relationship differs from the client/server in that there is no explicit
one-to-one relationship between the information producer and consumer. Publishers issue
data without knowledge of which devices will consume the data, and whether the data
has been received. Subscribers use internal means to access the published data. From the
viewpoint of IEC 61850, the publisher/subscriber mechanism uses the Ethernet multicast
mechanism (i.e., multicast MAC addresses at layer 2). The communication layer of the
system is responsible for transmitting this information to all interested subscribers and the
subscribers are responsible for accepting these multicast packets from the Ethernet layer.
The publish/subscribe mechanism is used for GOOSE and Sampled Value services. Note
that GOOSE and Sampled Value services are not currently available with the EPM 9900
meter’s IEC 61850 Protocol Ethernet Network server.
C.1.2
Structure of IEC 61850 Network
As mentioned before, IEC 61850 lets you set up an automated communication structure
for devices from any vendor. In order to set up this network, IEC 61850 renames devices
(e.g., meters), measured parameters (e.g., Phase to Phase Voltage), and functions (e.g.,
reporting) into a specific language and file structure. This way all of the elements of the
network can function together quickly and effectively. The language that the IEC 61850
network uses is structured, that is it is very specific in how the system information is
entered, and hierarchical, which means that it has different levels for specific information;
for example, meter information is entered on one level, and the information about the
actual physical connection between meters and other hardware is entered on another
level.
The structure of the IEC 61850 network is composed of different kinds of files, each
containing information that the system needs in order to function. IEC 61850 configuration
uses text-based (XML) files known as the System Configuration Language (SCL). SCL files
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use the concept of an XML schema, which defines the structure and content of an XML file.
The schema used by SCL files describes most (though not all) of the restrictions required to
ensure a consistent description file. An SCL file superficially looks like an HTML file. It
consists of 6 parts:
•
Prologue: XML declaration, (XML) namespace declarations, etc.
•
Header element: Names the system and contains the file version history
•
Substation element: defines the physical structure of the system
•
Communication element: defines all device-to-device communication aspects
•
IED element: defines the data model presented by each communicating device
•
DataTypeTemplates element: contains the detailed definition of data models.
•
After it is written, the XML file can be checked by "validators" against the schema
using freely available tools.
The IEC 61850 network uses four types of SCL files, each with identical structure:
•
SSD - System Specification Description: used during the specification stage of a
system to define physical equipment, connections between physical equipment, and
Logical Nodes which will be used by each piece of equipment.
•
ICD - IED Capability Description: this is provided by the communication equipment
vendor to specify the features of the equipment and the data model published by the
equipment. Each of the devices in the network has an ICD file which describes all of
the information about the device, for example, IP address on the network and Com
ports. The (vendor supplied) ICD variation of the SCL file contains a Communication
section specifying the lower-layer selectors and default addressing and also an IED
section containing the data model of the device. See the Configuring the Meter on the
IEC 61850 Network section for information on the EPM 9900 meter’s .icd file.
•
SCD - System Configuration Description: a complete description of the configured
automation system including all devices (for example, meters, breakers, and relays)
and all needed inter-device communications (for example, the measured parameters
and the actions to be performed, such as turning on a relay when a certain reading is
obtained). It can also include elements of the SSD file. The SCD file is created by a
System Configurator, which is a software application that takes the information from
the various devices along with other configuration parameters and generates the SCD
file.
•
CID - Configured IED Description: the file used to configure an individual device. It is a
pure subset of the SCD file. The device may also have a CID file, which is a smaller
subset of the device’s ICD file. The CID file describes the exact settings for the device in
this particular IEC 61850 network. The EPM 9900 meter’s IEC 61850 Protocol Ethernet
Network card uses a CID file. See the Configuring the Meter on the IEC 61850 Network
section for instructions for uploading the EPM 9900 meter’s .cid file.
Each type of SCL file has different required elements with only the prologue and Header
element required in every file type.
Elements of an IEC 61850 Network
C–4
•
A physical device has a name (IEDname) and consists of one or more AccessPoints.
•
An AccessPoint has an IP address and consists of one or more Logical Devices
•
A Logical Device contains LLN0 and LPHD1 and optional other Logical Nodes.
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•
LLN0 (Logical Node Zero) is a special object which "controls" the Logical Device. It
contains all of the datasets used for unsolicited transmission from the device. It also
contains the report, SV, and GOOSE control blocks (which reference the datasets).
•
LPHD1 (Physical Device) represents the hardware "box" and contains nameplate
information.
•
Logical Nodes (LNs) are standardized groups of "Data Objects" (DOs). The grouping is
used to assemble complex functions from small groups of objects (think of them as
building blocks). The standard defines specific mandatory and optional DOs for each
LN. The device may instantiate multiple LNs of the same type differentiated by either a
(named) prefix or (numerical) suffix.
•
Data Objects represent "real-world" information, possibly grouped by electrical object.
The IEC 61850 standard has specific semantics for each of the DOs. For example, the
DO named "PhV" represents the voltage of a point on a three-phase power system.
The DOs are composed of standardized Common Data Classes (CDCs) which are
groups of low-level attributes of the objects. For example, the DO named "Hz"
represents system frequency and is of CDC named "MV" (Measurement Value).
•
Common Data Classes (CDCs) consists of standardized groups of "attributes" (simple
data types). For example, the attribute "instMag" represents the instantaneous
magnitude of the underlying quantity. The standard specifies mandatory and optional
attributes for each CDC. For example, the DO named "Hz" in Logical Node class MMXU
contains a mandatory attribute named "mag" which represents the deadbanded
value of the frequency. The physical device contains a database of data values which
map to the various structures described above. The database values are manipulated
by the device to perform actions such as deadbanding (holding a constant value until
the underlying value changes by more than a specified amount) or triggering of
reports.
C.1.3
Steps to Configuring an IEC 61850 Network
1.
The first thing needed is the SSD for physical connections, then the vendor-provided
ICD files which are combined into a SCD file by a vendor-independent System
Configurator. The System Configurator assigns addresses to the equipment and sets
up datasets, reports, etc. for inter-device communication. The system configurator will
create an "instance" of the configured device by applying the following information:
•
The name of the device
•
The IP address, subnet mask, and IP gateway of the device
•
Datasets: the user must decide which information within the IED will be included in
reports, etc. and place this information into datasets. The System Configurator should
allow the selection of information using a "pick list" from information within the ICD
file.
2.
The resulting SCD file is then imported by vendor-specific tools into the various
devices. Some vendors add the additional step of filtering the SCD file into a smaller
file containing only information needed by the specific device, resulting in a CID file
which is used to configure the device. The actual configuration of the device is left
unspecified by IEC 61850 except to require that the SCD file remains the source of the
configuration information. In this way, consistency of the information across the
whole system is maintained.
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See Figure C-2: IEC Network Configuration Process Example for a graphical illustration of
the process.
Figure C-2: IEC Network Configuration Process Example
Referring to Figure C-2: IEC Network Configuration Process Example:
In step 1, the IED template is provided by the vendor (or sometimes created by a vendor
tool). This file is imported into the vendor-independent tool, the System Configurator, along
with other device templates. The System Configurator uses these templates to set up the
correct number of IEDs in the system and then provides configuration information. The
configuration information consists of providing addresses for all IEDs in the system,
creation of datasets, configuring control blocks, and setting individual device parameters
such as analog deadbands. The System Configurator then creates a SCD file with a
consistent view of the entire system.
In step 2, the SCD file is used to configure each device using vendor-supplied tools.
Vendors are free to choose the configuration mechanism, but the configuration
information MUST be derived from the SCD file.
NoteNOTE:
NOTE
In the EPM 9900 meter’s IEC 61850 Protocol Ethernet Network server implementation,
every service and object within the server is defined in the standard (there is nothing nonstandard in the device).
Also in step 2, the user sets up report control blocks, buffered and unbuffered, for each of
the clients. Setup information includes the dataset name, a report identifier, the optional
fields to be used in the report, the trigger options, buffer time (delay from first event to
report issuance), and integrity time (server periodic reports of all data in dataset). The
decision whether to use buffered or unbuffered must be decided by the user.
Finally, in step 2 the System Configurator performs a consistency check and then outputs
the SCD file. The SCD file is imported by the "ScdToCid" tool where the user specifies the
device name.
The resulting CID file is then imported into the target device.
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C.1.4
GE Digital Energy’s Implementation of the IEC 61850 Server
Following are features of Digital Energy’s IEC 61850 implementation:
•
The lower-level addressing uses PSEL=00000001, SSEL=0001, and TSEL=0001.
•
At the server level, each implements a single Logical Device name formed by
concatenating the IED name (chosen by the System Configurator) and "Meas"
(e.g.,"MyDeviceMeas").
•
The Logical Nodes implemented within the Logical Device include the standard LLN0
and LPHD1 with optional standard logical nodes in the "M" class (e.g., "MMXU") and "T"
class (e.g., "TVTR"). Each Logical Node contains only standardized objects of
standardized types (Common Data Class, CDC). The device is based upon the first
edition of the IEC 61850 standards.
Examples of Logical Nodes within the EPM 9900 family include eneMMTR1 (energy
metering) and nsMMXU1 (normal speed Measurement Unit).
•
The EPM 9900 device will get its IED name from the first <IED> section in the
configuration file (.cid). This name will be used for accessing its access point (IP
address) and its single Logical Device named "Meas". The IED name can be composed
of any string of up to 32 (alphanumeric only) characters.
•
The logical nodes implemented in the EPM 9900 meter are listed below:
• The node LLN0 keeps common information for the entire logical device. In this
node Datasets and Reports can be defined, based on the limitations provided in
the ICD file: the EPM 9900 meter supports up to 32 datasets with up to 256
attributes each, and up to 16 report control blocks. The report control blocks and
datasets must be configured in the CID file, although the options, triggers and
integrity period can be dynamically configured by the IEC client. (The EPM 9900
meter does not support Goose nor Journals.)
• The node LPHD1 defines physical parameters such as vendor, serial number,
device name plate and the software revision number.
• The node nsMMXU1 contains the "normal-speed" basic electrical measurements
such as Volts / Amps / Watts / VARs / Frequency / Power Factor / etc. The electrical
measurements are data objects in hierarchical structure as per the IEC 61850
specifications.
For example, Phase A voltage:
• which is in the object "PhV"
• which is of type "WYE_ABC_mag_noDC"
• which in turn has the object "phsA"
• which again has an attribute named "instVal" to represent instantaneous
values, and also the "mag" attribute, which represents the magnitude as
an analog magnitude, with the attribute "f" to get the value in 32-bit
floating point.
Thus the voltage of phase A, would be referred in this nested structure as "Meas/
nsMMXU1.PhV.phsA.instVal.mag.f".
•
The node hsMFLK1 is used for short term flicker (per phase) and long term flicker (per
phase); hs stands for "high speed" (200msec).
•
The node nsMHAI1 groups together the THD per phase measurements taken at
normal speed.
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Following the previous example, the THD for phase A would be referred as "Meas/
nsMHAI1.ThdPhV.phsA.instCVal.mag.f".
•
The node 1sMSQI1 is used for voltage/current symmetrical components perphase
(zero, positive and negative); 1s stands for “low speed” (3 seconds).
•
The node eneMMTR1 groups together all measurements related to energy counters,
like +/- Watt;hours, +/- VAr-hours and Total VA-hours.
•
The node intGGIO1 is used for the built-in high-speed digital inputs; the node extGGIO1
is used for the slot 3 option board’s digital inputs; the node extGGIO2 is used for the
slot 4 option board’s digital inputs.
•
The nodes setTCTR1, setTCTR2, setTCTR3 and setTCTR4 contain the ratio of the current
used by the measuring device, for phases A,B,C and Neutral, respectively. In this way,
the user can take the IEC measurements (primary) and convert them to Secondary
using the ratios contained in these nodes.
•
The nodes setTVTR1, setTVTR2 and setTVTR3 contain the ratio of the voltage used by
the measuring device.
•
Any of the defined objects/ attributes can be placed within a dataset.
•
The normal-speed in the EPM 9900 meter is measurements taken every second. The
energy counters are also updated every second.
The configuration of the devices takes place by converting the SCD file exported by the
System Configuration tool into a CID file. This CID file contains all of the information from
the SCD file which is needed for configuration by the GE device. The tool is named
"SCDtoCIDConverter" and is a simple, publicly available program. The resulting CID file is
then sent to the GE device using HTTP file transfer.
EPM 9900 Server Configuration
The configuration file (CID) should be stored in the EPM 9900 meter in order to configure
the server. At power up the server reads the file, parses it and configures all the internal
settings for proper functionality.
Storing the CID file in the EPM 9900 meter is accomplished through its webpage. The
webpage allows the user to locate the CID file, and submit it to the EPM 9900 meter for
storage.
After storing the CID file, access the EPM 9900 meter’s webpage again, to make sure that
the file has been stored, and to see if there is any problem with it, by checking its status.
The CID file will be successfully updated if the IP address inside the .cid file matches with
the one programmed into the device profile.
C–8
•
A common problem is IP mismatch (the IP address in the CID file does not match the IP
configured in the EPM 9900 meter’s device profile). In this case the EPM 9900 meter
will use the IP address from its device profile, and the IEC Server will work only with
that address.
•
If there is a critical error in the stored CID file, which prevents the IEC Server from
running, the CID file will not be used, and instead the Default CID file (embedded in the
server) will be used. The webpage will alert you to this situation.
•
If further details are needed, for example, information on the reason the CID storage
failed, the web server provides a link to the system log. In the system logscreen you
can view messages from the IEC 61850 parser, and you can take actions to correct the
error.
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See C.2 Using the EPM 9900 Meter’s IEC 61850 Protocol Ethernet Network Server for
instructions on configuring the EPM 9900 meter’s IEC 61850 Protocol Ethernet Network
server.
C.1.5
Reference Materials
Following is a list of background information on IEC 61850 that is available on the Internet:
•
• http://www.sisconet.com/downloads/
IEC61850_Overview_and_Benefits_Paper_General.pdf
•
http://www.sisconet.com/downloads/CIGRE%202004%20Presentations.zip
(IEC618650 Presentation IEC 61850 û Data Model and Services.pdf)
•
http://www.ucaiug.org/Meetings/Austin2011/Shared%20Documents/IEC_61850Tutorial.pdf (pages 24-32 and 40-161)
•
http://brodersensystems.com/wordpress/wp-content/uploads/DTU-Master-ThesisRTU32.pdf (pages 9-36)
Additionally, there is a good article on the predecessor to IEC 61850 (UCA 2.0) at http://
www.elp.com/index/display/article-display/66170/articles/utility-automationengineeringtd/volume-5/issue-2/features/uca-20-for-dummies.html.
Another good article on multi-vendor IED integration can be found at http://
www.gedigitalenergy.com/smartgrid/Aug07/EIC61850.pdf.
C.1.6
Free Tools for IEC 61850 Start-up
The Internet also provides some free IEC 61850 configuration tools:
•
Schema validation tools: http://notepad-plus-plus.org/go to plug-in manager and
install XML tools (however, there is no (legal) public copies of the schema available).
However, a web search file the filenameSCL_Basetypes.xsd turns up many copies and
the entire set of XSD file is often nearby.
•
http://opensclconfig.git.sourceforge.net/ Apparent open-source project, not tested
•
http://www.sisconet.com/downloads/SCDtoCIDConverter0-9.exe filters SCD file to a
CID file
•
http://www.sisconet.com/downloads/skunkworks2-8.exe Ethernet analyzer
C.1.7
Commercial Tools for IEC 61850 Implementation
Following is a list of tools for IEC 61850 configuration which you can purchase:
•
http://www.sisconet.com/ax-s4_61850.htm Client for IEC 61850
•
http://products.trianglemicroworks.com/documents
TMW%2061850%20Test%20Suite%20Combined.pdf
Clients and servers for IEC 61850
•
http://www.omicron.at/en/products/pro/communication-protocols/iedscout/test
client
•
http://kalkitech.com/products/sync-6000-series-scl-manager--iec61850-substationdesign-tool
SCL editing tool
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C.2 Using the EPM 9900 Meter’s IEC 61850 Protocol
Ethernet Network Server
This section contains instructions for understanding and configuring the EPM 9900 meter’s
IEC 61850 Protocol Ethernet Network server.
C.2.1
Overview
The IEC 61850 Protocol Ethernet Network card is a EPM 9900 standard I/O board. It is
available via Ethernet port 1 with Software Options B and C. The IEC 61850 Protocol
Ethernet Network server has the following features:
•
Standard Ethernet 10/100 Mbps connector is used to link the unit into an Ethernet
network.
•
Standard operation port 102, which can be reconfigured to any valid TCP/IP port.
•
Up to 6 simultaneous connections can be established with the unit.
•
Configurable via the .CID file (XML formatted)
•
Embedded Capabilities File (.ICD downloadable from the unit)
•
Supports MMS protocol.
•
Supports the following Logical Nodes:
• LLN0 (with predefined Sets and Reports)
• LPHD (Identifiers)
• MMXU with
• Phase-to-N Voltages
• Phase-to-Phase Voltages
• Phase Currents
• Per Phase VA
• Total VA
• Per Phase Var
• Total Var
• Per Phase W
• Total W
• Per Phase PF
• Total PF
• Frequency
• MHAI with Per Phase THD for voltage and current
• MSQI with
• Voltage symmetrical components per phase (zero, positive and negative)
• Current symmetrical components per phase (zero, positive and negative)
• MMTR with
• Demand Wh
• Supplied Wh
• Demand Varh
• SuppliedVArh
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• Total VAh
• GGIO with built-in and option board digital inputs and virtual inputs
•
Supports polled (Queried Requests) operation mode.
•
Supports Buffered Reports
•
Supports Unbuffered Reports
C.2.2
Configuring the IEC 61850 Protocol Ethernet Network Server
You need to configure the IEC 61850 Protocol Ethernet Network server for communication,
both from the standpoint of the device (the Device Profile) and of the network (the SCL
configuration file, which is a .cid file uploaded to the meter).
Configuring the Device Profile IEC 61850 Protocol Ethernet Network Server Settings
You use the GE Communicator application to set the card’s network parameters. Basic
instructions are given here, but you can refer to the GE Communicator software User
Manual for additional information. You can view the manual online by clicking
Help>Contents from the GE Communicator software main screen.
1.
Using GE Communicator software, connect to the meter through its USB port, RS485
serial port, or Ethernet 2 port (see Chapter 5 for instructions on connecting to your
meter with GE Communicator software).
2.
Click the Profile icon to open the meter’s Device Profile screen. The profile is retrieved
from the EPM 9900 meter. Double-click General Settings, Communications, and then
one of the lines under Communications, to display the screen shown below.
3.
Click the Advanced Settings button next to the Main Network Card. You will see the
next screen shown.
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4.
Make sure the Web Server and FTP Server checkboxes are selected, as shown below;
then click the IEC 61850 tab at the top of the screen.
5.
Make sure the checkbox to enable the IEC 61850 Protocol Network server is selected,
as shown below.
6.
Click OK and then click Update Device to send the settings to the EPM 9900 meter. The
meter will reboot. The IEC 61850 Protocol Ethernet Network server is now configured
properly to work on an IEC 61850 network.
Configuring the Meter on the IEC 61850 Network
The System Integrator must configure the EPM 9900 meter within the substation IEC
61850 network. To do this, the System Integrator needs the EPM 9900 capabilities file (.icd)
(as well as information about the rest of the devices on the network).
This .icd file, as mentioned earlier, is the SCL file that contains the IEC 61850 nodes, objects,
and parameters implemented in the EPM 9900 meter, including the Network IP address.
The IP address for the EPM 9900 meter is contained in the Communication section of this
.icd file. See the example Communication section, below.
<Communication>
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<SubNetwork name="Subnet_MMS" type="8-MMS">
<BitRate unit="b/s" multiplier="M">10</BitRate>
<ConnectedAP iedName="EPM9900IECSRV" apName="S1">
<Address>
<P type="OSI-PSEL" xsi:type="tP_OSI-PSEL">00000001</P>
<P type="OSI-SSEL" xsi:type="tP_OSI-SSEL">0001</P>
<P type="OSI-TSEL" xsi:type="tP_OSI-TSEL">0001</P>
<P type="IP" xsi:type="tP_IP">172.20.167.199</P>
</Address>
</ConnectedAP>
</SubNetwork>
</Communication>
The node <P type="IP" xsi:type="tP_IP"> (bolded in the example above) defines the meter’s
IP address. This IP address must be the same as the IP address configured in the meter’s
Device Profile.
The EPM 9900 meter’s .icd file (EPM9900.icd) can be downloaded directly from the meter.
To download the file, use FTP to access the file: the file is located in the meter’s compact
flash under C:\IEC61850\SCL folder. This folder contains both the meters .icd file and its
default .cid file. See the instructions that follow.
NoteNOTE:
NOTE
The most recent version of a EPM 9900 meter’s default .icd file can be downloaded directly
from GE Digital Energy’s website: http://www.gedigitalenergy.com/multilin/catalog/
epm9900.htm
1.
Open the FTP application and select the Connect option. See the example screen
below.
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C–14
2.
You will be prompted for the connection information - meter’s Main Ethernet card’s IP
address, username and password (the default value is anonymous/anonymous), etc.
See the example screen on the next page.
3.
The FTP application will connect to the meter and you will folders contained in the
Ethernet card. Double-click the C folder.
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4.
The screen will now show the folders contained in the C folder. Double-click the
IEC61850 folder.
5.
The screen will show the contents of the IEC61850 folder. Double-click the SCL folder.
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C–16
6.
The screen will show two files - EPM9900.CID which is the default CID file, and
EPM9900.ICD which is the file you want to download and edit.
7.
Make sure the left side of the screen has the location on your PC that you want to copy
the .icd file. Then right-click on EPM9900.ICD and select Download.
8.
The file will be downloaded to your PC, in the location specified. To edit the .cid file,
open it in Notepad or any text editor. See the example below.
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9.
The .cid file will open in Notepad.
An example of a downloaded .icd file is shown below.
<?xml version="1.0" encoding="UTF-8"?>
<SCL xmlns="http://www.iec.ch/61850/2003/SCL" xmlns:xsi="http://www.w3.org/2001/
XMLSchema-instance" xsi: schemaLocation="http://www.iec.ch/61850/2003/SCL.xsd"
xmlns:ext="http://nari-relays.com">
id="EPM 9900 ICD" nameStructure="IEDName" version="1.0" revision="">
<History>
<Hitem version="0.1" revision="13" when="9-May-2012" who="BAM" what="initial draft"
why="initial ICD">
</Hitem>
</History>
</Header>
<Communication>
<SubNetwork name="Subnet_MMS" type="8-MMS">
<BitRate unit="b/s" multiplier="M">10</BitRate>
iedName="EPM 9900IECSRV" apName="S1">
<Address>
<P type="OSI-PSEL" xsi:type="tP_OSI-PSEL">00000001</P>
<P type="OSI-SSEL" xsi:type="tP_OSI-SSEL">0001</P>
<P type="OSI-TSEL" xsi:type="tP_OSI-TSEL">0001</P>
<P type="IP" xsi:type="tP_IP">10.0.0.24</P>
</Address>
</ConnectedAP>
</SubNetwork>
</Communication>
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<IED name="EPM 9900IECSRV" desc="GE Digital Energy EPM 9900" type="E9900"
manufacturer="GE DIGITAL ENERGY" configVersion="1.00">
<Services>
<DynAssociation/>
10. You need to make the following changes to the .cid file:
• Change "TEMPLATE" to the iedName alphanumeric string in 2 places:
• In <Communication>
<SubNetwork name="Subnet_MMS" type="8-MMS">
<BitRate unit="b/s" multiplier="M">10</BitRate>
<ConnectedAP iedName="alphanumeric string" apName="S1">
• <IED name="alphanumeric strin" desc="GE Digital Energy EP9900" type="EPM
9900" manufacture="GE Digital Energy" configVersion="1.00"
•
Change the IP address to the IP address of the meter’s Main Ethernet card:
<Communication>
<SubNetwork name="Subnet_MMS" type="8-MMS">
<BitRate unit="b/s" multiplier="M">10</BitRate>
<ConnectedAP iedName="EP9900IECSRV" apName="S1">
<Address>
<P type="OSI-PSEL" xsi:type="tP_OSI-PSEL">00000001</P>
<P type="OSI-SSEL" xsi:type="tP_OSI-SSEL">0001</P>
<P type="OSI-TSEL" xsi:type="tP_OSI-TSEL">0001</P>
<P type="IP" xsi:type="tP_IP">192.168.0.50</P>
• Any modifications needed for your specific configuration: creating datasets, reports, etc.
11. When you have made your changes to the file, save it as a txt file but with the
extension .ICD, as shown below.
12. Once the System Integrator has processed the EPM 9900 meter's .icd file and the
information of the other devices on the network (using either automated tools or
manually), the final result is a configuration file with the extension ".cid". This file must
now be uploaded to the EPM 9900 meter's IEC 61850 Protocol Ethernet network card.
C–18
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER C: USING THE IEC 61850 PROTOCOL ETHERNET NETWORK SERVER
13. You upload the .cid file to the meter via its webpage. To do this, use a web browser
and key: http://aa.bb.cc.dd/
- where aa.bb.cc.dd is the IP address assigned to the main Network card, which is
acting as the IEC 61850 Protocol Ethernet Network server.
Section 9.4.1 details the meter’s webpages.
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Click Tools
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| Privacy | Terms
Contact Information
14. From the right side of the screen, click Tools to display the webpage shown below.
Home | Volts/Amps | Power/Energy | Power Quality | Pulse Accumulation | Inputs | Meter Information | Emails | Diagnostic | Tools
Webtools
Firmware Upgrade
IEC-61850 SCL Upgrade
Click
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Contact Information | Privacy | Terms
15. Click the IEC-61850 SCL Upgrade line. A screen will open asking for a username and
password. If none has been set, you can use the default which is anonymous for both
the username and password. Then click OK.
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
C–19
CHAPTER C: USING THE IEC 61850 PROTOCOL ETHERNET NETWORK SERVER
16. You will see the screen shown below. Click the Browse button to locate the .cid file you
want to upload and click Update SCL File to upload it to the meter.
IMPORTANT NOTES!
• The IP address configured into the IEC 61850 Protocol Ethernet Network server with the
GE Communicator software must be the same as the IP address configured in the .cid file.
This is necessary to insure proper communication. If there is a communication problem it
will be reported on the touch screen display’s IEC 61850 screen (see Chapter 6) and on the
IEC 61850 Protocol Ethernet Network server’s Diagnostic screen. You access this screen by
clicking Diagnostic from the left side of the Web server webpage, and then clicking the IEC61850 line. See the example screens that follow.
Home | Volts/Amps | Power/Energy | Power Quality | Pulse Accumulation | Inputs | Meter Information | Emails | Diagnostic | Tools
Diagnostic Screens
System
Firmware
Memory
CPU
Ethernet I/O
Ethernet Hardware
Modbus Communication
Modbus TCP Server
Web Server
FTP Server
DNP LAN/WAN
Task Info
IEC-61850
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Contact Information | Privacy | Terms
C–20
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
CHAPTER C: USING THE IEC 61850 PROTOCOL ETHERNET NETWORK SERVER
IEC-61850
IEC-61850
SERVER STATE
Server successfully initialized.
[The default's CID file has IP address mismatch.]
SERVER STATISTICS
TIMER:
Server initialization time (seconds): 0.931703
MEMORY:
Memory Allocated (bytes): 4534104
Memory Free (bytes): 421855
Number of Memory Allocated: 7420
Number of Memory Free: 6971
Total Memory Allocated (MBytes): 3.921746
Total Memory Allocated for all Data-set (bytes): 40869
Number of Data-set Success to Allocate: 2
Number of Data-set Fail to Allocate: 0
SCL PARSER MESSAGE
#001:
#002:
#003:
#004:
#005:
#006:
#007:
#008:
#009:
#010:
#011:*
STACK INDICATION
#001: ==>> Connect indication
#002: ==>> Abort indication
#003: ==>> Connect indication
#004: ==>> Connect indication
#005: ==>> Abort indication
#006: ==>> Abort indication
#007: ==>> Connect indication
•
The sAddr fields in each object of the .icd file must be preserved when generating the
.cid file. Do not change these, because they are used internally by the IEC 61850
server.
•
Do not use non-ASCII characters in your .cid file (such as punctuation marks). NonASCII characters can cause the parsing of the .cid file to fail.
•
If the uploaded .cid file has non-critical errors, the IEC 61850 Protocol Ethernet
Network server will use the file anyway and will start up. Any errors can be seen in the
Start Up log (see instructions below).
•
If the uploaded .cid file has critical errors, the IEC 61850 will use the default .cid file
(not the uploaded file) and it will start up. The errors can be seen in the IEC 61850
Diagnostic webpage, described on the previous page, and on the touch screen
display’s IEC 61850 screen (see Chapter 6).
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
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CHAPTER C: USING THE IEC 61850 PROTOCOL ETHERNET NETWORK SERVER
C.3
Testing
You can use any IEC 61850 certified tool to connect to the EPM 9900 meter and test out
the IEC 61850 protocol (see example screen below). There are numerous commercial tools
available for purchase.
C–22
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
GE Energy
EPM 9900 Electronic Meter
Chapter D: Manual Revision
History
Manual Revision History
D.1
Release Notes
Table D–1: Release Dates
MANUAL
GE PART NO.
RELEASE DATE
GEK-113631
1601-0036-A1
April 2012
GEK-113631A
1601-0036-A2
February 2014
GEK-113631B
1601-0036-A3
July 2014
GEK-113631C
1601-0036-A4
December 2014
Table D–2: Major Updates for 1601-0036-A4
SECT
(A2)
SECT
(A3)
DESCRIPTION
Title
Title
Manual part number to 1601-0036-A4.
N/A
N/A
IEC-61850 option throughout manual.
Ch. C
Ch. D
renamed existing Chapter C to Chapter D
N/A
Ch. C
Added new Chapter C for IEC-61850 Option
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
D–1
CHAPTER D: MANUAL REVISION HISTORY
Table D–3: Major Updates for 1601-0036-A3
SECT
(A2)
SECT
(A3)
DESCRIPTION
Title
Title
Manual part number to 1601-0036-A3.
Cover
Cover
Updated format
N/A
N/A
Added LD Low-Voltage power supply option throughout manual.
N/A
2.5.3
Added EPM Accessories section
4.11
4.11
Added power supply connections for all three options (AC, HI, LD).
Table D–4: Major Updates for 1601-0036-A2
SECT
(A1)
D–2
SECT
(A2)
DESCRIPTION
Title
Title
Manual part number to 1601-0036-A2.
Cover
Cover
Updated format
2.5
2.5.2
Added order codes for external modules
N/A
N/A
Updated references to the GE Communicator User Manual
EPM 9900 MULTI-FUNCTION POWER METERING SYSTEM – USER GUIDE
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