Electro Industries/GaugeTech

Electro Industries/GaugeTech

Version 1.01

October 10, 2007

Version 1.03

January 4, 2010

Doc# E154701 V.1.03

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Electro Industries/GaugeTech

1800 Shames Drive

Westbury, New York 11590

Tel: 516-334-0870

‹ Fax: 516-338-4741

[email protected]

‹ www.electroind.com

“The Leader in Power Monitoring and Control”

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Nexus® 1500 Meter

Installation and Operation Manual

V.1.03

Published by:

Electro Industries/GaugeTech

1800 Shames Drive

Westbury, NY 11590

All rights reserved. No part of this publication may be reproduced or transmitted in any form or by any means, electronic or mechanical, including photocopying, recording, or information storage or retrieval systems or any future forms of duplication, for any purpose other than the purchaser’s use, without the expressed written permission of

Electro Industries/GaugeTech.

© 2010

Electro Industries/GaugeTech

Nexus® is a registered trademark of

Electro Industries/GaugeTech.

Printed in the United States of

America

.

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Customer Service and Support

Customer support is available 9:00 am to 4:30 pm, Eastern Standard Time, Monday through

Friday. Please have the model, serial number and a detailed problem description available. If the problem concerns a particular reading, please have all meter readings available. When returning any merchandise to EIG, a return materials authorization number is required. For customer or technical assistance, repair or calibration, phone 516-334-0870 or fax 516-338-4741.

Product Warranty

Electro Industries/GaugeTech warrants all products to be free from defects in material and workmanship for a period of four years from the date of shipment. During the warranty period, we will, at our option, either repair or replace any product that proves to be defective.

To exercise this warranty, fax or call our customer-support department. You will receive prompt assistance and return instructions. Send the instrument, transportation prepaid, to EIG at 1800

Shames Drive, Westbury, NY 11590. Repairs will be made and the instrument will be returned.

Limitation of Warranty

This warranty does not apply to defects resulting from unauthorized modification, misuse, or use for any reason other than electrical power monitoring. The Nexus® 1500 meter is not a userserviceable product.

OUR PRODUCTS ARE NOT TO BE USED FOR PRIMARY OVER-CURRENT

PROTECTION. ANY PROTECTION FEATURE IN OUR PRODUCTS IS TO BE USED FOR

ALARM OR SECONDARY PROTECTION ONLY.

THIS WARRANTY IS IN LIEU OF ALL OTHER WARRANTIES, EXPRESSED OR

IMPLIED, INCLUDING ANY IMPLIED WARRANTY OF MERCHANTABILITY OR

FITNESS FOR A PARTICULAR PURPOSE. ELECTRO INDUSTRIES/GAUGETECH SHALL

NOT BE LIABLE FOR ANY INDIRECT, SPECIAL OR CONSEQUENTIAL DAMAGES

ARISING FROM ANY AUTHORIZED OR UNAUTHORIZED USE OF ANY ELECTRO

INDUSTRIES/GAUGETECH PRODUCT. LIABILITY SHALL BE LIMITED TO THE

ORIGINAL COST OF THE PRODUCT SOLD.

Statement of Calibration

Our instruments are inspected and tested in accordance with specifications published by Electro

Industries/GaugeTech. The accuracy and a calibration of our instruments are traceable to the

National Institute of Standards and Technology through equipment that is calibrated at planned intervals by comparison to certified standards.

Disclaimer

The information presented in this publication has been carefully checked for reliability; however, no responsibility is assumed for inaccuracies. The information contained in this document is subject to change without notice.

This symbol indicates that the operator must refer to an explanation in the operating instructions. Please see Chapter 3, Hardware Installation, for important safety information regarding installation and hookup of the

Nexus® 1500 Meter.

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Table of Contents

Chapter 1: Three-Phase Power Measurement

1.1: Three-Phase System Configurations

1.1.1: Wye Connnection

1.1.2: Delta Connection

1.1.3: Blondell’s Theorem and Three Phase Measurement

1.2: Power, Energy and Demand

1.3: Reactive Energy and Power Factor

1.4: Harmonic Distortion

1.5: Power Quality

Chapter 2: Nexus® 1500 Meter Overview

2.1: Nexus® 1500 Meter Features

2.2: DNP V3.00 Level 2

2.3: Flicker and EN61000 Analysis

2.4: Communications Options

2.5: V-Switch™ Technology

2.5.1: Obtaining a V-Switch™ Key

2.5.2: Enabling the V-Switch™ Key

2.6: Measurements and Calculations

2.7: Demand Integrators

2.8: Nexus® 1500 Meter Specifications

2.9: Compliance

Chapter 3: Hardware Installation

3.1: Mounting the Nexus® 1500 Meter

3.2: Meter and Panel Cut-out Dimensions

3.3: Mounting Instructions

3.4: Mounting the Optional External Output Modules

Chapter 4: Electrical Installation

4.1: Considerations When Installing Meters

4.2: 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

4.8: Wiring the Monitored Inputs - Vaux

4.9: Wiring the Monitored Inputs - Currents

4.10: Isolating a CT Connection Reversal

4.11: Instrument Power Connections

4.12: Wiring Diagrams

Chapter 5: Communication Wiring

5.1: Communication Overview

5.2: RJ45 Connection

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4-2

4-3

4-3

4-4

4-4

4-5

4-5

4-5

4-6

4-6

4-6

5-1

5-1

2-1

2-2

2-2

2-2

2-2

2-2

2-3

2-4

2-8

2-10

2-12

1-1

1-1

1-3

1-4

1-6

1-8

1-10

1-13

3-1

3-1

3-2

3-3 iii

5.3: RS232 Communication

5.4: USB Connection

5.5: RS485 Connection

5.5.1: Using the Unicom 2500

5.6: Remote Communication with RS485

5.7: Programming Modems for Remote Communication

5.8: Selected Modem Strings

5.9: High Speed Inputs Connection

5.10: IRIG-B Connections

Chapter 6: Using the Nexus® 1500 Meter’s Touch Screen Display

6.1: Overview

6.2: Fixed System Screens

6.3: Dynamic Screens

Chapter 7: Transformer Loss Compensation

7.1: Introduction

7.2: Nexus® 1500 Meter’s Transformer Loss Compensation

7.2.1: Loss Compensation in Three Element Installations

7.2.1.1: Three Element Loss Compensation Worksheet

Chapter 8: Time-of-Use Function

8.1: Introduction

8.2: The Nexus® Meter’s TOU Calendar

8.3: TOU Prior Season and Month

8.4: Updating, Retrieving, and Replacing TOU Calendars

8.5: Daylight Savings and Demand

Chapter 9: Nexus® 1500 Meter Network Communications

9.1: Hardware Overview

9.2: Specifications

9.3: Network Connection

Chapter 10: Flicker Analysis

10.1: Overview

10.2: Theory of Operation

10.3: Flicker Setting and Logging

10.4: EN61000 Flicker Polling Screen

10.5: Polling through Communications

10.6: Log Viewer

10.7: Performance Notes

Chapter 11: Using the Nexus® 1500 Meter’s I/O Option Cards and External Output

Modules

11.1: Overview

11.2: Installing Option Cards

11.3: Configuring Option Cards

11.4: Pulse Output/RS485 Option Card (485P)

11.4.1: Pulse Output/RS485 Option Card Wiring

11.5: Ethernet Option Card (NTRJ or NTFO)

11.6: Relay Output Option Card (6R01)

6-1

6-1

6-3

7-1

7-3

7-4

7-5

10-1

10-1

10-3

10-4

10-7

10-7

10-7

11-1

11-1

11-2

11-3

11-4

11-5

11-6

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8-1

8-2

8-2

8-2

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11.6.1: Relay Output Option Card Wiring

11.7: Digital Input Option Card (16DI1)

11.7.1: Digital Input Option Card Wiring

11.8: Optional External Output Modules

11.8.1: Port Overview

11.8.2: Installing Optional External Output Modules

11.8.3: Power Source for External Output Modules

11.8.4: Using PSIO with Multiple External Output Modules

11.8.4.1: Steps for Attaching Multiple External Output Modules

11.8.5: Factory Settings and Reset Button

11.8.6: Analog Transducer Signal Output Modules

11.8.6.1: Overview

11.8.6.2: Normal Mode

11.8.7: Digital Dry Contact Relay Output Module

11.8.7.1: Overview

11.8.7.2: Communication

11.8.7.3: Normal Mode

11.8.8: Digital Solid State Pulse Output Module

11.8.8.1: Overview

11.8.8.2: Communication

11.8.8.3: Normal Mode

11.8.9: Specifications

Appendix A: Installing the USB Virtual Comm Port

11-19

11-20

11-20

11-21

11-21

11-22

A.1: Introduction

A.2: Installing the Virtual Port’s Driver

A.3: Connecting to the Virtual Port

A-1

A-1

A-2

Appendix B: Power Supply Options

B-1

Glossary

GL-1

11-14

11-15

11-16

11-16

11-17

11-18

11-18

11-19

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Chapter 1

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.

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 Y (wye). Figure 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).

Phase B

Phase C

Phase A

The three voltages are separated by 120 o

electrically. Under balanced load conditions with unity power factor the currents are also separated by 120 o

. However, unbalanced loads and other conditions can cause the currents to depart from the ideal 120 o

separation.

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.

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Fig 1.2: Phasor Diagram Showing Three-phase Voltages and Currents

The phasor diagram shows the 120 o

angular separation between the phase voltages. The phase-to-phase voltage in a balanced three-phase Wye system is 1.732 times the phase-toneutral 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.

Phase to Ground Voltage Phase to Phase Voltage

120 volts

277 volts

2,400 volts

7,200 volts

7,620 volts

208 volts

480 volts

4,160 volts

12,470 volts

13,200 volts

Table 1.1: Common Phase Voltages on Wye Services

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 Figure 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, 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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1.1.2: Delta Connection

Delta connected services may be fed with either three wires or four wires. In a threephase 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.

Phase C

Phase B

Phase A

Figure 1.3: Three-Phase Delta Winding Relationship

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.

Figure 1.4 shows the phasor relationships between voltage and current on a three-phase

Delta circuit.

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.

Vca

Vbc

Ic

Ia

Ib

Vab

Figure 1.4: Phasor Diagram, Three-Phase Voltages and Currents Delta Connected.

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, four-wire, 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 threephase, four-wire Delta system.

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Fig 1.5: Phasor Diagram Showing Three-phase, Four-wire Delta Connected System

1.1.3: Blondell’s Theorem and Three Phase Measurement

In 1893 an engineer and mathematician named Andre E. Blondell 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 Blondell'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, Blondell'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.

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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.

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.

C

B

Phase B

Phase C

A

N

Phase A

Node “n”

Figure 1.6: Three-Phase Wye Load illustrating Kirchhoff’s Law

Figure 1.6: Three-Phase Wye Load Illustrating Kirchoff’s Law and Blondell’s Theorem

and Blondell’s Theorem

Blondell'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 Blondell'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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1.2: 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 kilowatt-hour 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).

Kilowatts

100

80

60

40

20

Time (minutes)

Figure 1.7: Power Use Over Time

Figure 1.7: Power Use Over Time

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Time Interval

(Minute) Power (kW) Energy (kW)

Accumulated

Energy (kWh)

Table 1.2: Power and Energy Relationship Over Time

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 15-minute intervals the total energy would be four times the measured value or 59.68 kWh. 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.

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Kilowatt-hours

100

80

60

40

20

Intervals

Figure 1.8: Energy Use and Demand

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.

1.3: 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 in-phase component and the component that is at quadrature (angularly rotated 90 o

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.

I

X

I

R

I

V

Figure 1.9: Voltage and Complex

Figure 1.9: Voltage and Complex

Angle

θ

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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.

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.

1500

1000

500

0

-500

-1000

-1500

1

A Phase Current

33

Figure 1.10: Nondistorted Current Waveform

65

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.

1500

1000

500

0

-500

-1000

-1500

1

Total A Phase Current with Harmonics

33

Figure 1.11: Distorted Current Wave

65

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 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.

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250

200

150

100

50

0

-50

-100

-150

-200

-250

2 Harmonic Current

7 Harmonic Current

Expanded Harmonic Currents

3 Harmonic Current

A Current Total Hrm

5 Harmonic Current

Figure 1.12: Waveforms of the Harmonics

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.

X

L

= j

ωL and

X

C

= 1/j

ωC

At 60 Hz, w = 377; but at 300 Hz (5th harmonic) w = 1,885. As frequency changes impedance changes and system impedance characteristics that are normal at 60 Hz may behave entirely differently 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, new-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.

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.

Cause Disturbance Type Source

Impulse Transient Transient voltage disturbance, sub-cycle duration

Oscillatory transient with decay

Sag/swell

Transient voltage, sub-cycle duration

Lightning

Electrostatic discharge

Load switching

Capacitor switching

Line/cable switching

Capacitor switching

Load switching

Remote system faults

Interruptions

RMS voltage, multiple cycle duration

RMS voltage, multiple second or longer duration

Undervoltage/

Overvoltage

Voltage flicker

RMS voltage, steady state, multiple second or longer duration

RMS voltage, steady state, repetitive condition

Harmonic distortion Steady state current or voltage, long term duration

System protection

Circuit breakers

Fuses

Maintenance

Motor starting

Load variations

Load dropping

Intermittent loads

Motor starting

Arc furnaces

Non-linear loads

System resonance

Table 1.3: Typical Power Quality Problems and Sources

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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.

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Chapter 2

Nexus

®

1500 Meter Overview

2.1: Meter Features

Electro Industries’ Nexus® 1500 meter is the latest in a generation of meters that combine high-end revenue metering with sophisticated power quality analysis. Meter features include:

• Advanced monitoring capabilities provide detailed and precise pictures of any metered point within a distribution network.

• Extensive I/O capability 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 Inputs card with 16 status inputs (up to 2 Digital Inputs cards can be installed in the meter).

- Optional External Output module: consisting of up to 4 Analog Output modules, 1 Digital Dry Contact Relay Output module, and up to 4 Digital

Solid State Pulse Output modules.

NOTE: See Chapter 11 for detailed information on the I/O options.

• Optional Communicator EXT software allows you to poll and gather data from multiple Nexus® meters installed at local or remote locations.

• Onboard mass memory (1 Gigabyte Compact Flash) enables the Nexus® 1500 meter to retrieve and store multiple logs.

• Standard 10/100BaseT RJ45 Ethernet allows you to connect to a PC via Modbus/TCP. A second, optional Ethernet connection can be either RJ45 or Fiber Optic.

• USB Virtual Com Port that is compatible with USB1.1/USB2.0.

• Optional RS485/Pulse Output card 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 includes measuring and recording Harmonics to the 255th order (and Real Time Harmonics to the 128 th

order).

• Multiple Protocols include DNP V3.00. See Section 2.2 for more details.

• 200msec High Speed Updates for control.

• V-Switch™ technology allows you to upgrade the meter in the field without removing it

from installation.

In addition, the Nexus® 1500 meter:

• Delivers laboratory-grade 0.06% Watt-hour accuracy in a field-mounted device.

• Auto-calibrates when there is a temperature change of more than 1.5 degrees Centigrade.

• Meets ANSI C12 and IEC 687 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.

• 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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2.2: DNP V3.00 Level 2

The Nexus® 1500 meter supports DNP V3.00 Level 2.

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 per-point basis.

• Freeze Commands: Freeze, Freeze/No-Ack, Freeze with Time, Freeze with Time/No-

Ack.

• Freeze with Time Commands enable the Nexus® meter to have internal time-driven

Frozen and Frozen Event data. When the Nexus® meter receives the Time and Interval, the data will be created.

For complete details, download the appropriate DNP User Manual from our website:

www.electroind.com.

2.3: V-Switch

Technology

The Nexus® 1500 meter is equipped with V-Switch™ technology, a virtual firmware-based switch that allows you to enable meter features through software communication. V-Switch™ technology allows the unit to be upgraded after installation without removing it from service.

Available V-Switch™ key upgrades:

V-Switch™ key 1 (V1): Standard meter with 128 Meg memory/512 samples per cycle.

V-Switch™ key 2 (V2): V1 plus 1 Gig memory/1024 samples per cycle.

V-Switch™ key 3 (V3): V2 plus 10MHz transient recording.

2.3.1: Obtaining a V-Switch

Key

Contact EIG’s inside sales staff at [email protected] or by calling (516) 334-0870 (USA) and provide the following information:

1. Serial Number or Numbers of the meters you are upgrading.

2. Desired V-Switch™ key.

3. Credit Card or Purchase Order Number.

EIG will issue you the V-Switch™ key.

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2.3.2: Enabling the V-Switch

Key

1. Install Communicator EXT 3.0 on your computer, or open the already installed software

application.

2. Power up your meter.

3. Connect to the Nexus® 1500 meter through Communicator EXT.

4. Click Tools>Change V-Switch from the Title Bar. A screen opens, requesting the encrypted

key.

5. Enter the V-Switch™ key provided by EIG.

6. Click the OK button. The V-Switch™ key is enabled and the meter is reset.

See the Communicator EXT User’s Manual for additional information.

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2.6: Measurements and Calculations

The Nexus® 1500 meter measures many different power parameters. Following is a list of the formulas used to conduct calculations with samples for Wye and Delta services.

Samples for Wye: van, vbn, vcn, ia, ib, ic, in

Samples for Delta: vab, vbc, vca, ia, ib, ic

Q

Root Mean Square (RMS) of Phase to Neutral Voltages: n = number of samples

For Wye: x = an, bn, cn

V

RMS x

=

t n

= 1

v

2

x

(

t

)

n

Q

Root Mean Square (RMS) of Currents:

n = number of samples

For Wye: x=a, b, c, n

For Delta: x = a, b, c

I

RMS x

=

t n

= 1

i

2

x

(

t

)

n

Q

Root Mean Square (RMS) of Phase to Phase Voltages:

n = number of samples

For Wye: x, y= an, bn or bn, cn or cn, an

V

RMS xy

=

t n

=

1

(

v x

(

t

)

v y

(

t

)

)

2

n

For Delta: xy = ab, bc, ca

V

RMS xy

=

t n

= 1

v

2

xy

(

t

)

n

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Q

Power (Watts) per phase:

For Wye: x = a, b, c

W

X

=

t n

= 1

v xn

(

t

)

i x

(

t

)

n

Q

Apparent Power (VA) per phase:

For Wye: x = a, b, c

VA x

=

V

RMS

XN

I

RMS

X

Q

Reactive Power (VAR) per phase:

For Wye: x = a, b, c

VAR x

=

VA x

2 −

Watt x

2

Q

Power (Watts) Total:

For Wye:

W

T

=

W a

+

W b

+

W c

For Delta:

W

T

=

t n

= 1

(

v

AB

(

t

)

i

A

(

t

)

n

v

BC

(

t

)

i

C

(

t

)

)

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Q

Reactive Power (VAR) Total:

For Wye:

VAR

T

=

VAR

A

+

VAR

B

+

VAR

C

For Delta:

VAR

T

(

V

RMS

AB

I

RMS

A

)

2

t n

= 1

v

AB

(

t

)

n

i

A

(

t

)

2

+

(

V

RMS

BC

I

RMS

C

) 2 −

t n

= 1

v

BC

(

t

)

n

i

C

(

t

)

2

Q

Apparent Power (VA) Total:

For Wye:

VA

T

=

VA

A

+

VA

B

+

VA

C

For Delta:

VA

T

=

W

T

2 +

VAR

T

2

Q

Power Factor (PF):

For Wye: x = A, B, C, T

For Delta: x = T

PF x

=

Watt x

VA x

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Q

Phase Angles:

∠ = cos

− 1

(

PF

)

Q

% Total Harmonic Distortion (%THD):

For Wye: x = VAN, VBN, VCN, IA, IB, IC

For Delta: x = IA, IB, IC, VAB, VBC, VCA h = harmonic number

THD

=

127

h

= 2

(

RMS x h

) 2

RMS x

1

Q

K Factor:

x = IA, IB, IC h = harmonic number

KFactor

=

127

h

= 1

(

h

RMS x h

127

h

= 1

(

RMS x h

)

2

)

2

Q

Watt hour (Wh):

t = time in seconds

Wh

=

t n

= 1

W

T

(

t

)

3600 sec/

hr

Q

VAR hour (VARh):

t = time in seconds

VARh

=

t n

= 1

VAR

T

(

t

)

3600 sec/

hr

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2.7: Demand Integrators

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 Nexus® 1500 meter supports the following most popular conventions for averaging demand and peak demand: Thermal Demand, Block Window Demand, Rolling

Window Demand

and Predictive Window Demand. You can program and access all conventions concurrently with the Communicator EXT software (see the Communicator EXT User Manual).

Q

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

Nexus® 1500 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.

Q

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 (11:45-12:00, 12:00-

12:15, 12:15-12:30, etc.).

Q

Rolling (Sliding) Window Demand

: Rolling demand functions like multiple, overlapping Block demand. You define the subintervals at which an average of demand is calculated. An example of

Rolling demand would be

Example:

A 15-minute Demand block using 5-minute subintervals, thus providing a new demand reading every 5 minutes, based on the last 15 minutes

Q

Predictive Window Demand

: Predictive Window Demand enables you to forecast average demand for future time intervals. The Nexus® 1500 meter uses the delta rate of change of a Rolling

Window Demand

interval to predict average demand for an approaching time period. You can set a relay or alarm to signal when the Predictive Window reaches a specific level, thereby avoiding unacceptable demand levels. The Nexus® 1500 meter calculates Predictive Window Demand using the formula shown on the next page.

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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 12:00-12:05 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 predistion for the remainder of the subinterval, 4/5 of the 120% of the 12:05-12:10 subinterval.

# of Subintervals = n

Subinterval Length = Len

Partial Subinterval Length = Cnt

Prediction Factor = Pct

Subn

Len

...

Sub1

Len

Sub0

Len

Sub

=

Len i

= 0

− 1

Value i

Len

Partial

=

Cnt i

=

− 1

0

Value i

Cnt

Partial

+

n i

= 0

2

Value i n

×

1 −

⎢⎣

Len

Len

Cnt

⎥⎦

×

Pct

+

n i

= 0

2

n

Sub i

− 1

+

Sub

0

2

x

(

n

Sub n

− 1

− 1 )

×

⎢⎣

Len

Len

Cnt

⎥⎦

×

Pct

Partial

Cnt

Predict

Len

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2.8: Nexus® 1500 Meter Specifications

Power Supply

Power Consumption: (18 to 25)VA, (15 to 17)W - depending on the

Connection: 3 Pin 0.300” Pluggable Terminal Block

AWG#12-24, Solid or Stranded

NOTES:

• EIG recommends the use of an EMI Clamp with the Power Supply. The recommended EMI Clamp is the Star-Tec round cable snap ferrite with safety key technology, manufactured by Wurth Electronics (part # 74271131). Attach the clamp snugly onto the Power Supply cable within 0.3 meters of the Nexus®

1500 meter.

• Branch circuit protection size should be 15 Amps.

Voltage Inputs

UL Measurement Category: Category III

Phase to Neutral (Va, Vb, Vc,Vaux to Neutral):

(5 to 347)VAC

Phase to Phase (Va to Vb, Vb to Vc, Vc to Va):

Supported hookups: 3 Element Wye, 2.5 Element Wye, 2 Element

Delta, Delta

Burden: 0.072VA/Phase Max at 600 Volts; 0.003VA at

Connection:

Reading:

6 Pin 0.600” Pluggable Terminal Block

Stranded

Programmable Full Scale to any PT Ratio

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Current Inputs

Class 20:

Burden:

Pickup Current:

Connections:

5A Nominal, 20A Maximum

0.008VA Per Phase Max at 20 Amps

0.1% of nominal

O Lug or U Lug Electrical Connection (Diagram

4.1)

Wire, /

Quick Connect, 0.25” Male Tab (Diagram 4.3)

Reading: Programmable Full Scale to any CT Ratio

Continuous Current Withstand: 20 Amps. For sustained loads greater than

Pass-through (see

Frequency

Range: 45.0-69.9Hz

Optional RS485 Port Specifications

RS485 Transceiver; meets or exceeds EIA/TIA-485 Standard:

Min. Input Impedance: 96kΩ

Max. ±60mA

Isolation

All Inputs to Outputs are isolated to 2500VAC

Environmental Rating

(-30

0

C

(-20

0

C

Measurement Methods

Update Rate

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Communication

Standard:

1. 10/100BaseT Ethernet

2. ANSI Optical Port

3. USB 1.1/2.0 Port, Full speed

Optional, through I/O card slot:

Dual RS485 Serial Ports

Second 10/100BaseT Ethernet or 100Base-FX Fiber Optic Ethernet

Protocols: Modbus RTU, Modbus ASCII, DNP 3.0

Com Port Baud Rate:

Com Port Address:

9,600 to 115,200 bps

1-247 - Modbus protocol

1-65535 protocol

Data Format: 8 Bit, No Parity

Mechanical Parameters

Dimensions: see Chapter 3.

2.9: Standards Compliance

I

• UL Listing: USL/CNL E250818

• CE (EN61326-1, FCC Part 15, Subpart B, Class A) •

• IEC 687 (0.2% Accuracy)

• ANSI C12.20 (0.2% Accuracy) •

• ANSI (IEEE) C37.90.1 Surge Withstand rele • ANSI C62.41 (Burst) •

IEC 687 to be supplied before document

• IEC 1000-4-2 - ESD

• IEC 1000-4-3 - Radiated Immunity

• IEC 1000-4-4 - Fast Transient

• IEC1000-4-5 - Surge Immunity

• EN61000-4-7 - Harmonics

• EN61000-4-15 - Flicker

ANSI C12.20 to be supplied before

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Chapter 3

Hardware Installation

3.1: Mounting the Nexus

®

1500 Meter

The Nexus® 1500 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

3.2: Meter and Panel Cut-out Dimensions

Meter Front View

Meter Back View

Meter Side View

Figure 3.1: Nexus® 1500 Meter Dimensions

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Figure 3.2: Optional Panel Cut-out Dimensions: Octagon (left) or Rectangle (right)

3.3: Mounting Instructions

Grooves

Panel

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.

4. Secure the meter to the panel with lock washer

and a #8 screw in each of the 4 mounting

brackets.

5. Tighten the screws with a #2 Philips screwdriver.

Do not over-tighten.

NOTE: If necessary, replacement Mounting Brackets

#8 Screw

(Part number E145316) may be purchased from EIG.

Figure 3.3: Mounting the Meter

Mounting

Bracket

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2 x 1.125”

(2.85cm)

3.4: Mounting the Optional External Output Modules

Secure the mounting brackets to the Output 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 Output modules are connected together, as shown in Figure 3.4, secure a mounting bracket to both ends of the group. The Nexus® 1500 meter does not have internal power for

Output modules: use an additional power supply, such as the EIG PSIO. Connect multiple

Output modules using the RS485 side ports. See Chapter 11 for additional information.

1.25” (3.175cm)

Per Module

Mounting Bracket

0.125”

(.3175cm)

Mounting Bracket

Mounting Bracket

Mounting Bracket

Figure 3.4: External Output Modules Mounting Diagram, Overhead View

4.2” (10.77cm)

Figure 3.4: External Output Modules Mounting Diagram, Overhead View

Female RS485

Side Port

Output

Port

Mounting Brackets

Male RS485 Side Port

Figure 3.5: External Output Module Communication Ports

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Mounting Bracket (MBIO)

Mounting Bracket

(MBIO)

1.25” (3.175 cm) + Y

Per Module

2.20”

(5.58cm)

3.43”

(8.712cm)

2 x 1.10”

(2.79cm)

Y

1.25” (3.175cm)

Per Module

.605”

(1.53cm)

Figure 3.6: External Output Modules Mounting Diagram, Front View

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Chapter 4

Electrical Installation

4.1: Considerations When Installing Meters

Installation of the Nexus

®

1500 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 Nexus

®

1500 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.

EIG recommends the use of Shorting Blocks and Fuses for voltage leads and power supply to prevent hazardous voltage conditions or damage to CTs, if the meter needs to be removed from service. CT grounding is optional.

Branch circuit protection size should be 15 Amps.

For sustained loads greater than 10 Amps, the CT wires should be wired directly through the

CT opening (pass-through wiring method - see Section 4.3), 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.

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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.

4.2: CT Leads Terminated to Meter

The Nexus® 1500 meter is designed to have Current Inputs wired in one of three ways.

Diagram 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 Studs (Current Gills) 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.

Other current connections are shown in Figures 4.2 and 4.3. Voltage and RS485/KYZ

Connection is shown in Figure 4.4.

Nickel-plated

Brass Stud

Current Gills

Figure 4.1: CT Leads terminated to Meter, #8 Screw for Lug Connection

Wiring Diagrams are shown in Section 4.12 of this chapter; Communications Connections are detailed in Chapter 5.

NOTE:

For sustained loads greater than 10 Amps, use pass-through wiring method (Section

4.3), using 10 AWG wire.

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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.

CT wire passing through meter with

Current gills removed

Detailed

View of CT

Openings

Figure 4.2: Pass-Through Wire Electrical Connection

NOTE:

For sustained loads greater than 10 Amps, use 10 AWG wire.

4.4: Quick Connect Crimp-on Terminations

For Quick Termination or for Portable Applications, 0.25” Quick Connect Crimp-on

Connectors can also be used.

Quick Connect

Crimp-on

Terminations

Figure 4.3: Quick Connect Electrical Connection

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4.3), using 10 AWG wire.

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

Communicator EXT software; see the Communicator EXT User Manual for details.

10/100BaseT

Ethernet

RS485

Connections

Fiber Optic

Connection

IRIG-B

Voltage

Connections

Power Supply

Connection

8 High-Speed

Inputs

4 Pulse Outputs

Relay Outputs

Optional Second

Ethernet Card

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

The cable required to terminate the voltage sense circuit should have an insulation rating greater than 600V AC and a current rating greater than 0.1 Amp.

Voltage inputs:

- Wire type: Solid or stranded

- Wire gauge: 12-24 AWG for either solid or stranded wire

- Strip length: 7-8 mm

- Torque: 5Lb-In.

Power supply connections:

- Wire gauge: 12-18 AWG for either solid or stranded wire

- Torque: 4kgf.cm/M3.

Branch circuit protection size should be 15 Amps.

4.6: Ground Connections

The meter’s PE GND terminal should be connected directly to the installation’s protective earth ground. Use AWG#12/2.5mm

2 wire for this connection.

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4.7: Fusing the Voltage Connections

For accuracy of the readings and for protection, EIG requires using 0.25-Amp rated fuses on all voltage inputs.

The Nexus® 1500 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.

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.

EIG Recommendations

CT Size (VA) Maximum distance from CT to Nexus® 1500 Meter (Feet)

2.5 10

5 15

7.5 30

10 40

15 60

30 120

WARNING! DO NOT leave the secondary of the CT open when primary current is

flowing. This may cause high voltage, which will overheat the CT. 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 Nexus® 1500 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, EIG recommends using shorting blocks to allow removal of the Nexus® 1500 meter from an energized circuit, if necessary.

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4.10: Isolating a CT Connection Reversal

For a Wye System, you may either:

• Check the current phase angle reading on the Nexus® 1500 meter’s display (see Chapter

6). If it is negative, reverse the CTs.

• Go to the Phasors screen of the Communicator EXT software (see the Communicator

EXT 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 Communicator EXT software program (see the

Communicator EXT User Manual for instructions). The current should be 30 degrees off the phase-to-phase voltage.

4.11: Instrument Power Connections

The Nexus® 1500 meter requires a separate power source.

1. Connect the line supply wire to the L+ terminal

2. Connect the neutral supply wire to the N- terminal on the Nexus® 1500 meter.

3. Connect the PE GND terminal to earth ground.

EIG recommends that you fuse the power supply connection with a 5 Amp fuse.

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 EIG for a Custom connection diagram.

Service PTs CTs

44W Wye/Delta 0, Direct Connect 3(4*)

Measurement Method

3 Element

Figure No.

1

44W Wye/Delta 3 3(4*) 3 Element 2

44W Delta 0, Direct Connect 3(4*) 3 Element 1 or 6

4W Delta 3 3(4*) 3 Element 2 or 5

4W Wye

4W Wye

3W Open Delta

2

0, Direct Connect

2

3W Open Delta 0, Direct Connect

3

3

2(3*)

2(3*)

2.5 Element

2.5 Element

2 Element

2 Element

3

4

5

6

*With optional CT for current measurement only.

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Figure 4.5: 4-Wire Wye or Delta, 3-Element Direct Connect with 4 CTs

* See Section 4.8.

** Optional extra CT for current measurement only.

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* See Section 4.8.

Figure 4.6: 4-Wire Wye or Delta, 3-Element with 3 PTs and 4 CTs

** Optional extra CT for current measurement only.

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* See Section 4.8.

Figure 4.7: 4-Wire Wye, 2.5-Element with 2 PTs and 3 CTs

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* See Section 4.8.

Figure 4.8: 4-Wire Wye, 2.5-Element Direct Connect with 3 CTs

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* See Section 4.8.

Figure 4.9: 3-Wire, 2-Element Open Delta with 2 PTs and 2 CTs

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* See Section 4.8.

Figure 4.10: 3-Wire, 2-Element Open Delta Direct Voltage with 2 CTs

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Chapter 5

Communication Wiring

5.1: Communication Overview

This chapter contains instructions for using the Nexus® 1500 meter’s standard and optional communication capabilities. The Nexus® 1500 meter offers the following communication modes:

„ RJ45 connection (Standard)

„ Optical Port (Standard)

„ USB connection (Standard)

„ RS485 communication (Optional)

„ Second Ethernet connection – either RJ45 or Fiber Optic (Optional)

5.2: RJ45 Connection

The standard RJ45 connection allows a Nexus® 1500 meter to communicate with multiple PC’s simultaneously. The RJ45 jack is located on the back of the meter. The Nexus® 1500 meter’s

Ethernet port conforms to the IEEE 802.3, 10BaseT and 100BaseT specifications using unshielded twisted pair (UTP) wiring. EIG recommends CAT5 for cabling. For details on this connection, see Chapter 9.

5.3: Optical Port

The optical port allows the Nexus® 1500 meter to communicate with one other device, e.g., a PC.

Located on the left side of the meter’s face, it provides infrared communication with the meter through an ANSI C12.13 Type II Magnetic Optical Communications Coupler, such as either:

An A7Z Communication Interface connected to the RS232 port of the

PC.

An A9U Communication Interface connected to the USB port of the

PC.

You can then program the meter through the optical port using Communicator EXT software.

5.4: USB Connection

Figure 5.1: A7Z and A9UCommunication Interfaces

The USB connection is used to connect the Nexus® 1500 meter to 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 so that it appears to a computer as a simple COM port with a baud rate of up to 921,600 baud. 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 5.2: USB Type B Plug

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EIG provides a driver for PC compatible computers. The driver configures the computer’s USB

Host port as a virtual serial port compatible with the Nexus® 1500 meter’s USB device port. See

Appendix A for instructions on installing the driver.

5.5: RS485 Connection

The Optional RS485 connection allows multiple Nexus® 1500 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 (1220 m). RS485 Ports 1 and 2 on the Nexus® 1500 meter are optional two-wire, RS485 connections with a baud rate of up to 115,200 baud. RS485 allows you to connect one or more

Nexus® meters to a PC or other device, at either a local or remote site. All RS485 connections are viable for up to 4000 feet (1219.20 meters).

You need to use an RS485 to RS232 converter, such as EIG’s Unicom 2500. See Section 5.4 for information on using the Unicom 2500 with the Nexus® 1500 meter.

Figure 5.3 shows the detail of a 2-wire RS485 connection.

Meter’s RS-485 connections

From other RS-485 device

Connect :

( ) to ( )

(+) to (+)

Shield(SH) to Shield(SH)

(-)

(+)

SH

B(-)

(+)

SH

120

.

0

120

.

0

120

.

0

Figure 5.3: 2-wire RS485 Connection

NOTES: For All RS485 Connections:

• 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.

• You may 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 19 of the Communicator EXT 3.0

User’s Manual for instructions.

• Protect cables from sources of electrical noise.

• Avoid both “Star” and “Tee” connections (see Figure 5.5).

• No more than two cables should be connected 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

(1219.20 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.

Figure 5.4 shows a representation of an RS485 Daisy Chain connection. Refer to following

Section 5.5.1 for details on RS485 connection for the Unicom 2500.

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Master device

R

T

SH (+) B(-)

Slave device 1

SH (+) B(-)

Slave device 2

SH (+) B(-)

Last Slave device N

R

T

SH (+) B(-)

Twisted pair, shielded (SH) cable Twisted pair, shielded (SH) cable

Earth Connection, preferably at single location

Figure 5.4: RS485 Daisy Chain Connection

Slave device 1

SH (+) B(-)

Twisted pair, shielded (SH) cable

Long stub results “T” connection that can cause interference problem!

Master device

R

T

SH (+) B(-)

Slave device 2

SH (+) B(-)

Last Slave device N

R

T

SH (+) B(-)

Twisted pair, shielded (SH) cable

Earth Connection, preferably at single location

Twisted pair, shielded (SH) cable

Twisted pair, shielded (SH) cable Twisted pair, shielded (SH) cable

Twisted pair, shielded (SH) cable

Slave device 1

SH (+) B(-)

Slave device 3

SH (+) B(-)

Master device

SH (+) B(-)

Slave device 2

B(-) (+) SH

“STAR” connection can cause interference problem!

SH (+) B(-)

Slave device 4

Twisted pair, shielded (SH) cable Twisted pair, shielded (SH) cable

Figure 5.5: Incorrect “T” and “Star” Topologies

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5.5.1: Using the Unicom 2500

The Unicom 2500 provides RS485/RS232 connection, allowing a Nexus® 1500 meter with the optional RS485 port to communicate with a PC. See the Unicom 2500 Installation and Operation

Manual for additional information.

Figure 5.6 illustrates the Unicom 2500 connections for RS485.

RS-232 Port

UNICOM 2500

PC

TX( ) RX( ) TX(+) RX(+) SH

B( )

SH

A(+)

Jumpers:

Short TX( ) to RX( ) becomes B( ) signal

Short TX(+) to RX(+) becomes A(+) signal

SH

A(+)

B( )

120

.

0

120

.

0

120

.

0

Figure 5.6: Unicom 2500 with Connections

The Unicom 2500 can be configured for either 4-wire or 2-wire RS485 connections. Since the

Nexus® 1500 meter uses a 2-wire connection, you need to add jumper wires to convert the

Unicom 2500 to the 2-wire configuration.

As shown in Figure 5.6, you connect the “RX -” and “TX -” terminals with a jumper wire to make the “B(-)” terminal, and connect the “RX +” and “TX +” terminals with a jumper wire to make the “A(+)” terminal.

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5.6: Remote Communication with RS485

Use either optional RS485 port on the Nexus® 1500 meter. The link using RS485 is viable for up to

4000 feet (1219 meters).

Use Communicator EXT software to set the port's baud rate to 9600 and enable Modbus ASCII protocol. See the Communicator EXT User Manual for instructions.

PC at office

Originate

Modem

Telephone Line

Remote

Modem

RS485

Nexus

®

1500

Meter

NULL Modem Adapter

(Required if 232/485 Converter does not support DTE/DCE reconfiguration)

RS232 to RS485

Converter

(Modem Manager

Recommended)

Figure 5.7: RS485 Remote Communication

You must use an RS485 to RS232 converter and a Null Modem. EIG recommends using its Modem

Manager, a sophisticated RS232/RS485 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.

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5.7: Programming Modems for Remote Communication

When a modem speaks to most RS485 or RS232-based devices, it must be programmed for the communication to work. This task is often quite complicated because modems can be unpredictable when communicating with remote devices.

If you are not using the EIG Modem Manager device, you must set the following strings to communicate with the remote Nexus® meter(s). Consult your modem’s manual for the proper string settings or see

Section 5.8 for a list of selected modem strings.

Q

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.

• 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 ensure connection with the originate modem.

• Set modem to enable Flow Control. This is necessary to communicate with remote modem connected to the Nexus® 1500 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.

Q

Modem Connected to the Nexus

® 1500 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 Nexus® 1500 meter to ensure connection with originate modem.

• Set modem to disable Flow Control.

• 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 Nexus

® 1500 meter’s baud rate.

NOTE: The Nexus

® meter protocol must be set to Modbus ASCII when accessing via a modem

or wireless cell modem. Additionally, EIG highly recommends using a Modem Manager serial converter which requires almost no configuration and is more reliable.

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5.8: Selected Modem Strings

Modem

Cardinal modem:

String/Setting

AT&FE0F8&K0N0S37=9

Zoom/Faxmodem VFX V.32BIS(14.4K): AT&F0&K0S0=1&W0&Y0

Zoom/Faxmodem 56Kx Dual Mode:

USRobotics Sportster 33.6 Faxmodem:

DIP switch setting:

USRobotics Sportster 56K Faxmodem:

DIP switch setting:

AT&F0&K0&C0S0=1&W0&Y0

AT&F0&N6&W0Y0 (for 9600 baud)

Up Up Down Down Up Up Up Down

AT&F0&W0Y0

Up Up Down Down Up Up Up Down

5.9: High Speed Inputs Connection

The built-in Nexus® 1500 meter’s High Speed Inputs can be used in many ways:

Attach the KYZ HS Outputs from other meters for totalizing.

Attach relaying contacts for breaker status or initiated logging.

Set as an Input Trigger for logging.

Refer to the Communicator EXT User Manual for information on programming the High Speed Inputs.

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 24V DC. No user programming is necessary to use either wet or dry field contacts.

Figure 5.8: High Speed Inputs

(location pointed out by the arrow)

8

7

6 5 4 3 2 1 C

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IRIG-B is a standard time code format that synchronizes event timestamping to within 1 millisecond.

An IRIG-B signal-generating device connected to the GPS satellite system can be used to synchronize Nexus® 1500 meters located at different geographic locations.

Nexus® meters use an Unmodulated signal from a satelite-controlled clock (such as Arbiter 1093B).

The meter’s IRIG-B port has a 2.2k minimum input impedance and is optically isolated.

For details on installation, refer to the User’s Manual for the satellite-controlled clock in use. Below are basic installation steps.

GPS

Satellite

Connection

Nexus

®

1500 Meter’s IRIG-B Port

+

-

+

-

IRIG-B Time

Signal

Generating

Device

Figure 5.10: IRIG-B Connection

Installation:

Set Time Settings for the meter being installed.

1. From the Communicator EXT Device Profile menu: a. Click General Settings>Time Settings>one of the Time Settings lines, to open the Time

Settings

screen. b. Set the Time Zone and Daylight Savings (Select AutoDST or Enable and set dates). c. Click Update Device Profile to save the new settings. (See the Communicator EXT User’s

Manual

for details.)

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 meter to the (+) terminal of the signal generating device; connect the (-) terminal of the meter to the (-) terminal of the signal generating device.

Troubleshooting Tip: The most common source of problems is a reversal of the two wires. If you have a problem, try reversing the wires.

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Chapter 6

Using the Nexus

®

1500 Meter’s Touch Screen Display

6.1: Introduction

The Nexus® 1500 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 five Fixed System screen options: Device

Information, Communication Settings, Board Settings, System

Message, and Touch Screen Calibration. 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.

NOTES:

• You will only see the System Message option if there are

messages for you to view. See the next page 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 next page for instructions on using the Touch Screen

Calibration screen.

Device Information

This screen displays the following information about the Nexus®

1500 meter:

- 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

- V-switch™ level enabled currently

- Sealing switch status

- Security (Password) status

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See the example screen on the previous page. 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 on the right. 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

- 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 on the right. The Back button

returns you to the initial Fixed System screen.

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 on the right. The Back button

returns you to the initial Fixed System screen.

NOTE: This option will only appear 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 on the right, showing the first of

the four messages.

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When all four calibrations have been performed, a

Calibrating Test screen is shown. 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 will cause the calibration process to start again.

See the example screen on the right.

NOTE: See page 6-1 for instructions on accessing Touch

Screen Calibration.

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.

Logo 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.

EIG Logo: the Dynamic Main screen.

(Dynamic) Main Screen: This is a navigation screen for the

Dynamic screens that are in scroll mode. Touch the button of the screen you want to access. Each of the screens is described in the following sections.

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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 Phase-to-Earth readings.

. o 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 Logo screen. o 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 PH-N Readings.

- Touch the Home button to go to the Dynamic

Logo screen.

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o 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

Logo 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. o 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

Logo screen.

Real Time Power: Real Time Power

Readings Details

• Instant Watt/VAR/VA/PF

• Thermal Watt/VAR/VA/PF

• Predicted Watt/VAR/VA

Power screen (shown on the next page).

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Demand Power: Demand Power Readings

Details

• Thermal Window Average Maximum

+Watt/+VAR/CoIn VAR

• Block (Fixed) Window Average Maximum

+Watt/+VAR/CoIn VAR

• Predictive Rolling (Sliding) Window Maximum

+Watt/+VAR/CoIn VAR

Touch the R/T button 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)

Accumulations screen.

TOU: Brings you to Accumulations 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 Quadrants 1 & 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.

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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: o Phase Angle or Magnitude Van/bn/cn o Phase Angle or Magnitude Ia/b/c o 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:

%THD

• TDD (Current only)

• KFactor

• Frequency

• Phase A – N voltage

- Touch the Waveform button to see the channel’s

waveform.

- Touch the Volts B button to view the Harmonics screen for

Phase B – N voltage.

- Use the Radio Buttons to select the mode of the directional arrows. If Scroll is selected, the directional arrows will move the axes horizontally/vertically. If Zoom is selected, the directional arrows will 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 the Spectrum button to see the Harmonic

Spectrum Analysis screen for the channel.

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- Touch the Volts B button to view the Harmonics screen for Phase B – N voltage.

Alarms: 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.

Flicker - Brings you to Flicker Instantaneous Information, consisting of the following:

• Time Start/Reset, Stop, Current, Next PST, PLT

• Status (Active or Stopped)

• Frequency

• Base Voltage

• Voltage Readings

other Flicker screens.

the Stop button displays if the Status is “Active.”

Flicker - Short Term - Displays the following information:

• Volts A/B/C

• Max Volts A/B/C

• Min Volts A/B/C

other Flicker screens.

the Stop button displays if the Status is “Active.”

Flicker - Long Term - Displays the following information:

• Volts A/B/C

• Max Volts A/B/C

• Min Volts A/B/C

the Stop button displays if the Status is “Active.”

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NOTE: If password protection is enabled for the meter a keyboard screen displays when you press any action button (Reset/Stop).

Use the keyboard to enter the password. If a valid password is entered, the requested Flicker action (Stop/Reset) 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 Arrow buttons to move the

vertical axis up/down.

- Touch the

+/-

buttons to zoom in/out.

- Touch the Show All button to display all of the

bars in the screen.

- Touch the Volts PH-PH button to view the

Voltage Phase-to-Phase Bargraph screen.

- Touch the Current button to view the Amps

Bargraph screen. (The Current button is displayed

on the Voltage Phase-to-Phase Bargraph screen.)

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.

1. Touch the box(es) to select the Reset you want to perform.

2. Touch the Reset button. All boxes are unchecked after a

reset is performed and a check mark is displayed next to

each item that was reset.

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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.

Trends - Brings you to the Trends Setting Screen. From this

screen, you can set the following for viewing:

1. Interval Log 1 or 2: touch the radio button of the log you

want.

2. Channel: select a channel by touching its button.

You will see the Trends - Graphic screen.

NOTES:

o The Active Channel appears at the lower right

of the display. o Data from the previously Active Channel is

lost if the Channel is changed.

Real Time Trending Graphic Screen:

Trending for the channel selected from the Trends -

Setting screen is shown on this screen.

• 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

the Table Button to view the Trends - Table screen.

• Touch Setting to select another log and/or channel.

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Real Time Trending Table screen:

A Table of logs for the selected channel

(Volts AN is shown here).

• Touch Graphic to return to the Trending - Graphic

screen.

• Touch Setting to select another log and/or channel.

NOTE: 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.

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

• Memory Used.

Use the Directional Arrow buttons to view additional logs.

Firmware Version - This screen displays the current

firmware version for the Nexus® 1500 meter, as well as the

meter designation and serial number. The following information

is displayed:

• Device Name

• Serial Number

• Comm Boot: 1_33

• Comm Runtime: 0001_0151

• DSP1 Boot: L

• DSP1 Runtime: CF

• DSP2: RE0021

• FPGA: 0.1.A

• Touch Screen: 7.3

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SETTINGS (LCD Screen) - Brings you to a screen where

you can configure settings for the display. Set the following:

• Contrast: touch Left/Right Arrow buttons to increase/decrease the contrast for the display.

• Backlight: the number of minutes after use that the display's backlight turns off.

1. Touch Left/Right Arrow buttons to

increase/decrease settings.

switch on the front panel beside the display

• Volume: touch Left/Right Arrow buttons to increase/decrease the speaker volume.

• Press the Next/Prev arrows to go to the Serial Setting/Network setting screens.

NEXUS® Serial Communication Settings -

Select the serial communication mode you want to configure, by checking the Radio Button next 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)

Press the Next/Prev arrows to go to the Network Setting/Display Setting screens.

NEXUS® 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. o IP Address o Subnet Mask o Default Gateway o MAC Address

Press the Next/Prev arrows to go to the Display Setting/Serial

Setting screens.

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Chapter 7

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 I

2

R 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 Figure 7.1.

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.

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 Figure 7.2.

M

Point of Ownership

Change

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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 Nexus

® meter. Refer to Appendix B of the Communicator EXT User

Manual for detailed explanation and instructions for using the Transformer Line Loss

Compensation feature of the Nexus

® 1500 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 Nexus

® 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 losses are equal to 20kW 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.

Nexus

® 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.

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• 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 Demands

• Energy Accumulations

• KYZ Output of Energy Accumulations

NOTE: Loss Compensation is disabled when the meter is placed in Test Mode.

7.2: Nexus

®

1500 Meter’s Transformer Loss Compensation

The Nexus

® 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 EIG Loss Compensation Calculator in Microsoft Excel

• By figuring the values from the worksheet shown here and in Appendix B of the

Communicator EXT User Manual.

Either way, the derived values are entered into the Communicator EXT software through the

Device Profile Transformer and Line Loss Compensation screen.

The Communicator EXT 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 Communicator EXT 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 phase-to-neutral voltage and the phase current; in two-element meters the installation must be normalized to the phase-tophase voltage and the phase current. This process is described in the following sections.

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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.

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 Nexus

® 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

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7.2.1.1: Three-Element Loss Compensation Worksheet

Date

Trf Manf

Calculation by

Trf. Bank No.

Trf Serial No.

Transformer Data (from Transformer Manufacturer’s Test Sheet)

Winding Voltage MVA Connection

HV – High ∆-Y

Xv – Low

YV – Tertiary

Value

3-Phase

Watts Loss

1-Phase

∆-Y

∆-Y

1-Phase kW

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

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

Test Voltage (volts)

Full Load Current (Amps)

Test Voltage is generally Phase-to-Phase for three-phase transformers. Calculate Phase-to-

Neutral Voltage by dividing Phase-to-Phase Voltage by √3. Calculate Full Load Current by dividing the (1-Phase kW Self-Cooled Rating) by the (Phase-to-Neutral Voltage) and multiplying by 1000.

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Meter/Installation Data

Instrument Transformers Numerator Denominator Multiplier

Potential Transformers

Current Transformers

Power Multiplier [(Pt Multiplier) times (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) 5

Base Conversion Factors

Quantity Transformer Meter Base Meter/Trf

Voltage

Current

120

5

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

No-Load Loss VAR (kVAR) = SQRT((No-Load Loss kVA)

2

SQRT((_________________)

- (No-Load Loss kW)

2

2

)

- (________________)

2

)

= SQRT((__________________) - (_________________))

= SQRT (_________________)

= ____________________

Full-Load Loss Watts (kW) = 1-Phase Kw Load Loss = ______________

Full-Load Loss VA (kVA) = (%Impedance) * (1-Phase kVA Self-Cooled Rating) / 100

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Full-Load Loss VAR (kVAR)

= SQRT((__________________) - (_________________))

= SQRT (_________________)

= _________________

Normalize Losses to Meter Base

Quantity

Value at

Trf Base

= (______________) * (________________) / 100

= SQRT((Full-Load Loss kVA)2 - (Full-Load Loss kW)2)

= SQRT((_________________)2 - (________________)2)

M/T

Factor

M/T

Factor

Value Exp

M/T

Factor w/Exp Value at Meter Base

No-Load Loss kW

No-Load Loss kVAR

V

V

٨2

٨4

Load Loss kW

Load Loss kVAR

1

1

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

No-Load Loss kVAR

Load Loss kW

Load Loss kVAR

% Loss Watts FE

% Loss VARs FE

% Loss Watts CU

% 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 Nexus

® meter using Communicator EXT software. Refer to Appendix B of the Communicator EXT User Manual for instructions.

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Chapter 8

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 Nexus® 1500 meter’s TOU function, available with the

Communicator EXT

software, is designed to accommodate a variety of programmable rate structures. The Nexus® meter’s TOU function accumulates data based on the time-scheme programmed into the Nexus® meter.

See Chapter 10 of the Communicator EXT User Manual for details on programming the

Nexus® meter’s 20 Year TOU calendar and retrieving TOU data.

8.2: The Nexus

®

Meter’s TOU Calendar

A Nexus® TOU calendar sets the parameters for TOU data accumulation. You may store up to twenty calendars in the Nexus® 1500 meter and an unlimited amount of calendar files on your computer.

The Nexus® 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 Nexus® 1500 meter stores:

• Accumulations on a seasonal basis, up to four seasons per year;

• Accumulations on a monthly basis.

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 will end 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.

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8.3: TOU Prior Season and Month

The Nexus® 1500 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 becomes stored as the prior. 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

Communicator EXT software retrieves TOU calendars from the Nexus® 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 Nexus® 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 the

Communicator EXT 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.

8.5: Daylight Savings and Demand

To use Daylight Savings Time, you must enable it in the Nexus® meter’s Device Profile

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 the Communicator EXT User Manual for instructions.

To set Demand Intervals, from the Device Profile menu click Revenue and Energy

Settings

/Demand Integration Levels and set the desired intervals. See the Communicator

EXT 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 the Communicator EXT User Manual for instructions.

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10/100BasetT

RJ45

Chapter 9

Nexus

®

1500 Meter Network Communications

9.1: Hardware Overview

The Nexus® 1500 meter gives you the capability of connecting to multiple PC’s via

Modbus/TCP over the Ethernet and providing a DNP LAN/WAN connection.

Modbus/TCP or

DNP 3.0 Over

Ethernet

Figure 9.1: Nexus

®

1500 Meter Connected to Network

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The Nexus® 1500 meter’s Network is an extremely versatile communications tool. It:

• Adheres to IEEE 802.3 Ethernet standard using TCP/IP

• 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 Nexus® meter. You can access the Nexus® meter with SCADA, MV90 and RTU simultaneously.

Multiple users can run Communicator EXT software to access the meter concurrently.

9.2: Specifications

The Nexus® 1500 meter’s Main Network Card (standard) has the following specifications at

25 o

C:

Number of Ports: 1

Operating Mode: 10/100BaseT

Connection type: RJ45 modular (Auto-detecting

transmit 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 the

(optional) Network Card 2.)

9.3: Network Connection

Use Standard RJ45 10/100BaseT cable to connect with the Nexus® 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 Communicator EXT 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.

NOTE: The settings shown below are the default settings of the Main Network

Card. See Chapter 11 for the default settings of the optional Network Card 2.

IP Address: 192.168.0.50

Subnet Mask: 255.255.255.0

Default Gateway: 192.168.0.1

NOTES:

You may use different settings for the Main Network Card (check with your Network administrator for the correct settings).

The Main Network Card and Network Card 2 must be in different subnets.

Once the above parameters have been set, Communicator EXT will connect via the network using a Device Address of “1” and the assigned IP Address when you follow these steps:

1. Open Communicator EXT.

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2. Click the Connect icon in the icon tool bar. The Connect screen opens.

3. Click the Network button at the top of the screen. Enter the following information:

Device Address: 1

Host: IP Address

Network Port: 502

Protocol: Modbus TCP

4. Click the Connect button at the bottom of the screen. Communicator EXT connects to the

meter via the network.

You can see and/or configure the Network settings through the meter’s Touch Screen display:

1. From the Main screen, select Setting.

2. Press the Next button twice to go to the Network Settings screen (shown below).

3. Click the button next to Network 1 to see/change the settings for the standard Ethernet connection. Click the button next to Network 2 to see/change the settings for the second, optional Network card, if installed.

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Chapter 10

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 Nexus® 1500 meter has compliance for Flicker and other power quality measurements.

Refer to Chapters 16 and 17 of the Communicator EXT 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, shown on page 10-3.

Block 1 consists of scaling circuitry and an automatic gain control function that normalizes input voltages to Blocks 2, 3 and 4. For the specified 50 Hz operation, the voltage standard is

230 V RMS.

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.

The configuration consists of a .05 Hz Low High Pass filter and a 6 Pole Butterworth Low

Pass filter located at 35 Hz. 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.

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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 and it 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 1000-3-3. 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:

P st

=

0 .

0314

P

0 .

1

+

0 .

0525

P

1

s

+

0 .

0657

P

3

s

+

0 .

28

P

10

s

+

0 .

08

P

50

s

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 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:

P lt

=

3

i

N

=

1

3

P sti

N

Where Psti (i = 1, 2, 3, ...) are consecutive readings of the short-term severity Pst.

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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

Block 2

Simulation Of Eye Brain Response

Block 3 Block 4 Block 5 Block 1

Voltage

Detector and Gain

Control

Input

Voltage

Adaptor

Square

Law

Demodulator

High Pass

Filter

(DC

Removal)

Low

Pass Filter

(Carrier

Removal

Weighting

Filter

Squaring

Multiplier

1st

Order

Sliding

Mean

Filter

A/D

Converter

Sampling

Rate

>50Hz

Minimum

64 level

Classifier

Output

Interface

Programming of short and long observation periods

Output Recording

Instantaneous Flicker in

Perceptibility Units

(Pinst)

Output and Data Display

Pst Max/Min Pst

Plt Max/Min Plt

Figure 10.1: Simulation of Eye Brain Response

10.3: Flicker Setting and Logging

The Nexus® 1500 meter can record Flicker values in an independent log. When Flicker is on, entries are made into the log in accordance with the times that associated values occur. Pst, Pst

Max, Pst Min, Plt, Plt Max, Plt Min, Start/Reset and Stop times are all recorded. All values can be downloaded to the Log Viewer where they are available for graphing or export to another program, such as Excel. Refer to Chapter 8 of the Communicator EXT User Manual for additional information on viewing logs.

You must set up several parameters to properly configure Flicker logging.

1. Select the Profile icon from Communicator EXT’s Icon bar.

2. From the Device Profile screen, double-click Power Quality and Alarm

Settings>EN61000 Flicker. You will see the screen shown on the next page.

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• Click the Auto-Configure button to automatically set the PQ Log and Historical Log 2 to record

EN61000 Flicker readings.

• From the drop-down menu, select the number of

Fast Voltage Fluctuations (FVF) that are acceptable each day.

• From the Sync Connection drop-down menu, select Yes for a system with a synchronous connection to another system; select No if there is no synchronous connection.

• Select the frequency of operation. 50 Hz is the approved frequency according to Flicker standards. A 60 Hz implementation is available and can be selected.

• For the Nominal Voltage in Secondary enter the value for that you want to use in the analysis; for example, 120V for a 60Hz frequency or 230V for a 50Hz frequency.

• Select a Pst time range from 1 to 10 minutes. The standard measurement period is nominally 10 minutes.

• Select a Plt time range from 1 to 240 minutes. The standard measurement is nominally

12 Pst periods (120 minutes). Plt time must always be equal to or great than and a multiple of Pst time. This is reflected in the available selections.

3. Press OK when you are finished.

10.4: EN61000 Flicker Polling Screen

1. From the Communicator EXT Title bar, select Real-Time Poll>Power Quality and

Alarms>Flicker. You will see the screen shown below.

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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 and restarts the Flicker Pst and Plt timers. A Start of

Flicker is also equivalent to a Reset in that the PST and PLT are restarted and the

Max/Min Values are cleared.

Stop corresponds to the time when Flicker is turned off.

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. Stopped = Off.

Frequency:

Base is the operating frequency (50 or 60 Hz) selected in the EN50160 Flicker screen

(see Section 12.3).

Current is the real-time frequency measurement of the applied voltage.

Base Voltage:

• The normalized voltage for the selected frequency (230 V for 50 Hz or 120 V for

Flicker Monitoring:

• Clicking on Stop causes Flicker to stop being processed and freezes all the current values. Stop Time is recorded and the current Max/Min values are cleared.

• Clicking on Start starts Flicker processing. Start Time is recorded.

• Clicking on Reset causes the Max/Min values to be cleared and restarts the Flicker Pst and Plt timers.

Use the tabs at the top of the screen to navigate to the Instantaneous, Short Term, and Long

Term Readings views, shown on the right side of the screen.

Instantaneous Readings:

NOTE: The Instantaneous view is the default of this screen. (See the screen pictured 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.

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Short Term Readings:

Click on the Short Term tab to access a screen containing three groups of 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.

Long Term Readings:

Click on the Long Term tab to access a screen containing three groups of 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.

2. Click OK to exit the EN61000 Flicker screen; click Help for more information on this topic; click Print to print all of the Readings views.

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10.5: 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 Nexus® 1500 meter’s Modbus and DNP Mapping manuals for register assignments and data definitions.

10.6: Log Viewer

1. Open Log Viewer by selecting the Open Logs icon from Communicator EXT’s Icon bar.

2. 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.

NOTE: Max and Min values are only displayed; they cannot be graphed. However, Max and

Min values are available for export.

10.7: 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 on 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 and former IEC 868. Refer to those specifications for more details, if needed. Refer to chapters 16 and 17 in the

Communicator EXT User Manual for additional information.

• Operation is at 230V for 50Hz and 120V for 60Hz as per specification. If the input voltage is different, the system will normalize it to 230V or 120V for computational purposes.

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Chapter 11

Using the Nexus® 1500 Meter’s I/O Option Cards and

External Output Modules

11.1: Overview

The Nexus® 1500 meter offers extensive I/O expandability. Using the four Option card slots, the unit can be easily configured to accept new I/O Option cards even after installation, without your needing to remove the meter. The Nexus® 1500 meter autodetects any installed Option cards. The meter also offers multiple optional External

Output modules. All of these options are explored in this chapter.

11.2: Installing Option Cards

The Option cards are inserted into their associated Option card slots in the back of the

Nexus® 1500 meter.

NOTE: Remove Voltage Inputs and power supply terminal to the meter before performing card installation.

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.

CAUTION! 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 on the next page.

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Figure 11.1: I/O Option Card Installation

11.3: Configuring Option Cards

CAUTION! FOR PROPER OPERATION, RESET ALL PARAMETERS

IN THE UNIT AFTER HARDWARE MODIFICATION.

The Nexus® 1500 meter auto-detects any Option cards installed in it. Configure the Option cards through Communicator EXT software. Refer to Chapter 19 of the Communicator EXT

User’s Manual for detailed instructions.

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11.4: Pulse Output/RS485 Option Card (485P)

Pulse Output/RS485 Port Specifications

Dual RS485 Transceiver; meets or exceeds EIA/TIA-485 Standard:

Min. Input Impedance: 96kΩ

Max. ±60mA

Isolation Between Channels AC 1500V

Wh Pulse

4 KYZ output contacts

Pulse Width:

Form:

Contact type:

Full Scale Frequency:

Programmable from 5msec to 635msec

100Hz

Selectable from Form A or Form C

Solid State – SPDT (NO – C – NC)

Peak switching voltage:

Continuous load current:

Peak load current:

On resistance, max.:

DC ±350V

120mA

350mA for 10ms

35Ω

Reset State: (NC - C) Closed; (NO - C) Open

General Specifications for Pulse Output/RS485 Board:

Operating Temperature:

Storage Temperature:

(-20 to +70) o

C

(-30 to +80) o

C

Relative Air Humidity: Maximum 95%, non-condensing

EMC - Immunity Interference: EN61000-4-2

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

18 pin, 3.5 mm pluggable terminal block

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11.4.1: Pulse Output/RS485 Option Card (485P) Wiring

Refer to Chapter 5 for RS485 Settings

Instructions

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11.5: Ethernet Option Card: RJ45 (NTRJ) or Fiber Optic (NTFO)

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: Refer to Chapter 19 of the Communicator EXT User’s 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: of 1

Diagnostic feature:

Number of simultaneous Modbus

connections:

Status LEDs for LINK and ACTIVE

8 (Includes 8 total connections over both

Number of simultaneous DNP

connections:

The general specifications are as follows:

2 TCP and 1 UDP per communication channel

Operating Temperature:

Storage Temperature:

Relative air humidity:

EMC - Immunity Interference:

(-20 to +70) °C

(-30 to +80) °C

Maximum 95%, non-condensing

EN61000-4-2

Dimensions (inches) W x H x L:

I/O Card slot:

0.75” x 4.02” x 5.49”

Option Slot 2

Connection modular (Auto-detecting transmit and

Fiber Optic Specifications are as follows:

Connector: ST

Default Configuration

The Nexus® 1500 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:

Mask: 255.255.255.0

NOTE: The IP addresses of the Nexus® 1500 meter’s standard Main

Network Card and optional Network Card 2, must be in different subnets.

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11.6: Relay Output Option Card (6RO1)

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: 0.320W internal

Relay outputs.

Number of outputs: 6

Switching voltage: AC 250V / DC 30V

Mechanical 5

5 switching operations at rated current

Breakdown voltage:

Isolation:

Reset/Power down state:

AC 1000V between open contacts

AC 2500V surge system to contacts

No change - last state is retained

The general specifications are as follows:

Operating temperature: (-20 to +70) °C

Storage temperature:

Relative air humidity:

EMC - Immunity Interference:

(-30 to +80) °C

Maximum 95%, non-condensing

EN61000-4-2

Dimensions (inches) W x H x L: 0.75” x 4.02” x 4.98”

I/O Card slot:

External connection:

Option Slot 3 and 4

Wire range - 16 to 26 AWG

Strip .250”

18 pin, 3.5 mm pluggable terminal block

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11.6.1: Relay Output Option Card (6RO1) Wiring

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11.7: Digital Input Option Card (16DI1)

The Digital Input Option card offers 16 wet/dry contact sensing digital inputs.

The technical specifications at 25 °C are as follows:

Power consumption: 0.610W of 16

Sensing type:

Wetting voltage:

Input current:

Minimum input voltage:

Maximum input voltage:

Wet or dry contact status detection

DC (12-24)V, internally generated

1.25mA – constant current regulated

0V (input shorted to common)

DC 150V (diode protected against polarity

reversal)

Detection scan rate: 20ms

AC system

The general specifications are as follows:

Operating temperature:

Storage temperature:

(-20 to +70) °C

(-30 to +80) °C

Relative air humidity:

EMC - Immunity Interference:

Maximum 95%, non-condensing

EN61000-4-2

Dimensions (inches) W x H x L: 0.75” x 4.02” x 4.98”

I/O Card slot:

External connection:

Option Slot 3 and 4

Wire range - 16 to 26 AWG

Strip .250”

18 pin, 3.5 mm pluggable terminal block

NOTE: This feature allows for either status detect or pulse counting. Each input can be assigned an independent label and pulse value.

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11.7.1: Digital Input Option Card (16DI1) Wiring

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11.8: Optional External Output Modules

All Nexus® External Output 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 Nexus® 1500 meter’s Port 3 or 4 or to another module’s female RS485 side port. See Figure 11.2 for wiring details.

Output 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, signal that the module is functioning.

Mounting Brackets (MBIO): used to secure one or more modules to a flat surface.

Female RS485

Side Port

LEDs

Output Port

(Size and Pin

Configuration

Vary)

Reset Button

Figure 11.1: Output Module Components

Mounting Brackets

(MBIO)

Integrated

Fastening

System

Male RS485

Side Port

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11.8.1: Port Overview

All of the optional External Output Modules have ports through which they interface with other devices. The port configurations are variations of the three types shown below.

Four Analog Outputs Eight Analog Outputs Four Relay Outputs

(0-1mA and 4-20mA) (0-1mA and 4-20mA) or Four KYZ Outputs

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11.8.2: Installing Optional External Output Modules

„ Output modules must use the Nexus® 1500 meter’s Port 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 11.3, below. See Section 11.8.4.1 for details on using multiple Output modules.

LEDs

Male Side Port on

Nexus® Output Module

Power Source

(12-20V DC)

EIG

PSIO**

EIG

PSIO**

**NOTE: EIG recommends the PSIO or

PB1 Power supply.

**NOTE: EIG recommends the

PSIO or PB1

Power supply.

R

T

*

R

T

*

(Typically for runs longer

(Typically for runs longer than 500 feet)

Nexus

®

Meter’s

Port 3 or 4

Figure 11.3: Meter Connected to Output Module

*

NOTE: Termination Resistors are only needed, typically, with runs of more than 500 feet. The meter has some level of termination internally that are sufficient for shorter distances.

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11.8.3: Power Source for External Output Modules

„ The Nexus® 1500 meter does not have internal power for the External Output modules. You must use a power supply, such as the EIG PSIO to power any modules you are installing.

You must also do the following:

1. Connect the A(+) and B(-) terminals on the Nexus® meter to the A(+) and B(-) terminals of the male RS485 port.

2. Connect the shield to the shield (S) terminal. The (S) terminal on the Nexus® meter is used to reference the Nexus® 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 A(+) and B(-) lines. RT is ~120

Ohms.

4. Connect a power source to the front of the module.

SIDE LABEL

4.08”/10.36cm

3.42”/8.69cm

Figure 11.4: The PSIO Power Source (Side View)

Showing Male RS485 Side Port

1.72”/

4.37cm

TOP LABEL

Figure 11.6: Labels for PSIO

Figure 11.5: Power Flow from PSIO to Output d l

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1.8.4: Using PSIO with Multiple Output Modules

Figure 11.7: Using PSIO with Multiple External Output Modules

NOTE: PSIO must be to the right of the Output Modules, when viewing its side label (as shown in the figure above).

11.8.4.1: Steps for Attaching Multiple Output Modules

1. Each Output module in a group must be assigned a unique address. See the Communicator

EXT User Manual for instructions on configuring and programming the Output Modules.

2. Starting with the left module and using a slotted screwdriver fasten the first Output 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 Output module to the left module. Fasten together enough to grab but do not tighten, yet

One by one combine the modules together using the Integrated Fastening System (See

Figure 11.2).

Attach a PSIO (power supply) to the right of each group of 4 Output Modules (see Figure

11.7, above).

4. Once you have combined all of the Output Modules together for the group, fasten them tightly. This final tightening locks the group together as a unit.

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5. Attach the right Mounting Bracket to the right side of the group using the small Phillips Head screws provided.

6. 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 Output Modules are shipped with a preset address and a baud rate of 57600. See the following list.

1mAON4

1mAON8

20mAON4

20mAON8

0±1mA, 4-Channel Analog Output

0±1mA, 8-Channel Analog Output

4–20mA, 4-Channel Analog Output

4–20mA, 8-Channel Analog Output

128

128

132

132

„ 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 will reset to a default address of

247 at 57600 baud rate for 30 seconds.

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11.8.6: Analog Transducer Signal Output Modules

Accuracy

Scaling

Analog Transducer Signal Output Modules Specifications

Model Numbers

Over-Range

Communication

Power Requirement

Operating Temperature

Maximum Load Impedance

Factory Settings

1maAON4: 4-Channel Analog Output, 0±1mA

1mAON8: 8-Channel Analog Output, 0±1mA

20mAON4: 4-Channel Analog Output, 4–20mA

20mAON8: 8-Channel Analog Output, 4–20mA

0.1% of Full Scale

± 20% of full Scale

Programmable

RS485, Modbus RTU

Programmable Baud Rates: 4800, 9600, 19200, 57600

12–20VDCV at 50–200mA

(-20 to 70)°C / (-4 to +158)°F

0±1mA: 10k Ω; 4–20mA: 500 Ω

Modbus Address:

1mAON4, 0-1mA: 128 1mAON8, 0-1mA: 128

20mAON4, 4–20mA: 132, 20mAON8, 4-20mA: 132

Baud Rate: 57600

Transmit Delay Time: 0

Default Settings

(Reset Button)

Modbus Address: 247

Baud Rate: 57600

Transmit Delay Time: 20 msec

11.8.6.1: Overview

The Analog Transducer Signal Output Modules (0

±

1mA or 4–20mA) are available in either a 4- 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).

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11.8.6.2: Normal Mode

Normal Mode is the same for the 0-1mA and the 4-20mA 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 0-1mA module includes one more process in its Normal Mode:

3. Read and average the A/D and adjust values for Process 2, above.

The device operates with the following default parameters:

Baud Rate

57600

Transmit Delay Time 20 msec

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11.8.7: Digital Dry Contact Relay Output (Form C) Module

Digital Dry Contact Relay Output (Form C) Module Specifications

4RO1: 4 Latching Relay Outputs

Model Number

0.1% of Full Scale

Accuracy

Programmable

Scaling

RS485, Modbus RTU

Programmable Baud Rates: 4800, 9600, 19200, 57600

Communication

12–20VDC at 50–200mA

Power Requirements

(-20 to 70)°C / (-4 to +158)°F

Operating Temperature

Factory Settings

Modbus Address: 156

Baud Rate: 57600

Transmit Delay Time: 0

Modbus Address: 247

Default Settings

(Reset Button)

Baud Rate: 57600

Transmit Delay Time: 20 msec

11.8.7.1: 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 Communicator EXT software. See the Communicator EXT User

Manual for details on programming limits.

Each latching relay will hold its state in the event of a power loss.

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11.8.7.2: Communication

Maximum registers per request, read or write, is 4 registers.orm

The device operates with the following default parameters:

Baud Rate

57600

Transmit Delay Time 20 msec

11.8.7.3: Normal Mode

Normal Mode consists of one process: the device accepts new commands to control the

relays.

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11.8.8: Digital Solid State Pulse Output (KYZ) Module

Model Number

Digital Solid State Pulse Output (KYZ) Module Specifications

4PO1

RS485, Modbus RTU

Communication

Programmable Baud Rates: 4800, 9600, 19200, 57600

Power Requirement

12–20V DC at 50–200mA

Operating Temperature

(-20 to 70)°C / (-4 to +158)°F

Up to 300V DC

Voltage Rating

Commands Accepted

Read and Write with at least 4 registers of data per command

Memory

256 byte I2C EEPROM for storage of

Programmable Settings and Nonvolatile Memory

Factory Settings

Modbus Address: 160

Baud Rate: 57600

Transmit Delay Time: 0

Modbus Address: 247

Default Settings

(Reset Button)

Baud Rate: 57600

Transmit Delay Time: 20 msec

11.8.8.1: 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.

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11.8.8.2: Communication

Maximum registers per request, read or write, is 4 registers.orm

The device operates with the following default parameters:

Baud Rate

57600

Transmit Delay Time 20 msec

11.8.8.3: 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 - 04112. Writes can be up to four registers long and should end on the fourth register of a group (register 04100, or registers 04103-04112 or registers 04109-04112). 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.

3. 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 is not maxed, then

Residual is decremented appropriately and the Pending Pulses 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 Pulses Pending 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

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11.9: 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 (1 module can be used.)

4RO1: 4 Relay Outputs 10 Amps, 125Vac, 30Vdc, Form C.

Digital Solid State Pulse Outputs (Up to four modules can be used.)

4PO1: 4 Solid State Pulse Outputs, Form A KYZ pulses.

Other Output Module Accessories

PSIO: External Power Supply, which is necessary whenever you are connecting an External Output modules to a Nexus® 1500 meter.

MBIO: Bracket for surface-mounting External Output modules to any enclosure.

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Appendix A

Installing the USB Virtual Comm Port

A.1: Introduction

As mentioned in Chapter 5, EIG provides a driver that allows you to configure the Nexus® 1500 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 Nexus® 1500 Meter CD into your PC’s CD drive.

2. Open the CD drive through My Computer and double-click on the USB_Virtual_Comm_Port

folder to open it.

3. Double-click on the CDM 2.02.04 VCP Setup.exe icon.

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 will close.

6. Plug a USB cable into your PC and the Nexus® 1500 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.

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A.3: Connecting to the Virtual Port

1. Open Communicator EXT.

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: a. On your PC, click Start>Settings>Control Panel. b. Double-click on the System folder. the tab. You will see the screen shown on the right. d. Click the Device Manager button. You will see a list of your computer’s hardware devices. e. 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 bottom, right.

In the example, COM8 is the Virtual port: COM8 is the port

you would select in the Connect screen.

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Appendix B:

Power Supply Options

The Nexus® 1500 meter offers the following power supply options:

Option Description

115AC UL Rated AC Power Supply (100-240)VAC

High-Voltage DC (100-240)VDC, (90-265)VAC D2

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Glossary

0.1 Second Values:

1 Second Values:

Alarm:

Annunciator:

Average (Current):

These values are the RMS values of the indicated quantity as calculated after approximately 50 milliseconds (3 cycles) of sampling.

These values are the RMS values of the indicated quantity as calculated after one second (60 cycles) of sampling.

An event or condition in a meter that can cause a trigger or call-back to occur.

A short label that identifies particular quantities or values displayed, for example kWh.

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 15-minute interval. The thermal average rises to 90% of the actual value in each time interval. For example, if a constant 100amp 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 When applied to Input Pulse Accumulations, the “Average” refers to the block

Accumulations): (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 15-minute interval. The thermal average rises to 90% of the actual value in each time interval. For example, if a constant 100kW load is applied, the thermal average will indicate 90kW after one time interval, 99kW after two time intervals and 99.9kW 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: The Block (Fixed) Window Average is the average power calculated over a

(Power) 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.)

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Byte:

CBEMA Curve:

Channel:

Cold Load Pickup

EEPROM:

Energy Register:

Ethernet:

A group of 8 binary digits processed as a unit by a computer (or device) and used especially to represent an alphanumeric character.

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.)

The storage of a single value in each interval in a load profile.

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 tranformer.

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:

Display:

DNP 3.0:

A specified time over which demand is calculated.

User-configurable visual indication of data in a meter.

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. The Nexus

®

1500 meter supports Level 2.

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.

Programmable record that monitors any energy quantity. Example: Watthours,

VARhours, VAhours.

A type of LAN network connection that connects two or more devices on a common communications 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.

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Exception Response: Error Code (Modbus communication) transmitted in a packet from the Slave to the Master if the Slave has encountered an invalid command or other problem.

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:

Heartbeat Pulse:

Measuring values of the fundamental current and voltage and percent of the fundamental.

Energy indicator on the face of the Nexus

®

1500 meter; pulses are generated per the programmed Ke value.

I

2

T Threshold:

Integer:

Data will not accumulate until current reaches programmed level.

Any of the natural numbers, the negatives of those numbers or zero.

Invalid Register:

ITIC Curve:

In the Nexus

® 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.

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.

kWh per pulse; i.e. the energy.

Ke: kWh:

KYZ Output:

Modbus RTU:

Kilowatt hours; kW x demand interval in hours.

Output where the rate of changes between 1 and 0 reflects the magnitude of a metered quantity.

Liquid Crystal Display.

LCD:

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).

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.

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Network:

NVRAM:

Optical Port:

Packet:

Percent (%) THD:

Protocol:

A communications connection between two or more devices to enable those devices to send and receive data to one another. In most applications, the network will be either a serial type or a LAN type.

Nonvolatile Random Access Memory is able to keep the stored values in memory even during the loss of circuit or control power. High speed NVRAM is used in the Nexus

® meter to gather measured information and to insure that no information is lost.

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 Communicator

EXT software.

A short fixed-length section of data that is transmitted as a unit. Example: a serial string of 8-bit bytes.

Percent Total Harmonic Distortion. (See THD.)

A language that will be spoken between two or more devices connected on a network.

PT Ratio:

Pulse:

Q Readings:

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.

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 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

Watt and VAR flow is typically represented usng an X-Y coordinate system.

The four corners of the X-Y plane are referred to as quadrants. Most power

Values and Factors applications label the right hand corner as the first quadrant and number the on the Nexus

TM

Meter) 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.

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Reset:

Rolling Window

Average (Power):

RS232:

RS485:

Sag:

Secondary Rated:

Serial Port:

Swell:

TDD:

Logs are cleared or new (or default) values are sent to counters or timers.

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.

A type of serial network connection that connects two devices to enable communication between 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 Nexus

®

1500 meter.

A type of serial network connection that connects two or more devices to enable communication between the devices. An RS485 connection will allow multidrop 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.

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.

Any Register or pulse output that does not use any CT or VT Ratio.

The type of port used to directly interface with a PC.

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.

The Total Demand Distortion of the current waveform. The ratio of the rootsum-square 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 Communicator EXT software, using the Max Average Demand..

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THD:

Time Stamp:

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 Nexus

® meter.

A stored representation of the time of an event. Time Stamp can include year, month, day, hour, minute and second and Daylight Savings Time indication.

Time of Use.

TOU:

Uncompensated

Power: VA, Watt and VAR readings not adjusted by Transformer Loss Compensation.

V

2

T Threshold:

Voltage Imbalance:

VT Ratio:

Voltage, Vab:

Voltage, Van:

Voltage, Vaux

Data will stop accumulating when voltage falls below programmed level.

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 will track include sags, swells, interruptions and imbalances.

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.

Vab, Vbc, Vca are all Phase-to-Phase voltage measurements. These voltages are measured between the three phase voltage inputs to the meter.

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.

This is the fourth voltage input measured from between 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.

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