A1800 Technical Manual_rev.02.pdf

A1800 ALPHA Meter Technical Manual Rev.02 10-2011

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Technical manual

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Contents

Technical manual

Contents

Contents

1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-1 A1800 ALPHA meter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-1 Standards Compliance . . . . . . . . . . . . . . . . . . . . . . . . . . 1-2 IEC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-2 IEEE/ANSI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-2 DIN . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-2 Benefits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-3 Reliability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-3 Maintainability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-3 ANSI standard communication open protocol . . . . . . 1-4 Adaptability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-4 Economy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-4 Security . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-4 Accuracy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-4 Meter types . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-5 Meter series . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-6

2 Product description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-1 Physical description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-1 Optical port . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-3 LCD . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-3 Nameplate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-3 Utility information card . . . . . . . . . . . . . . . . . . . . . . . . 2-4 Communications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-4 Battery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-5 Cover tamper detection switches . . . . . . . . . . . . . . . . . 2-5 Terminal configurations . . . . . . . . . . . . . . . . . . . . . . . . 2-6 Communication protocols . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-6 System architecture . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-6 General theory of operation . . . . . . . . . . . . . . . . . . . . . . . . . . 2-7 Power supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-7 Main power supply . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-7 Auxiliary power supply . . . . . . . . . . . . . . . . . . . . . . . . 2-7 Current and voltage sensing . . . . . . . . . . . . . . . . . . . . . . 2-7 Meter engine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-8 Microcontroller . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-8 EEPROM . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-8 Billing data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-9 Metered energy and demand quantities . . . . . . . . . . . . . 2-9 Average power factor . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-9 Demand calculations . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-9 Rolling interval . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-10 Block interval . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-10 Thermal time constant . . . . . . . . . . . . . . . . . . . . . . . . 2-11 Maximum demand . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-11 Cumulative maximum demand . . . . . . . . . . . . . . . . . . . 2-11 Continuous cumulative maximum demand . . . . . . . . . 2-11 Coincident demand or power factor . . . . . . . . . . . . . . . 2-12

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Demand forgiveness . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-12 Primary and secondary metering . . . . . . . . . . . . . . . . . 2-12 TOU data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-12 Power failure data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-13 Logs and data sets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-13 Event log . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-14 History log . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-14 Self reads . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-14 Load profiling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-15 Load profiling pulse divisor . . . . . . . . . . . . . . . . . . . . 2-15 Instrumentation profiling . . . . . . . . . . . . . . . . . . . . . . . 2-16 TRueQ Log . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-17 Voltage sag log . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-17 User-defined tables . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-17 Physical dimensions and mass . . . . . . . . . . . . . . . . . . . . . . 2-18

3 Operating instructions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-1 Indicators and controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-1 LCD . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-1 Quantity identifier . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-2 Display quantity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-2 Phase indicators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-2 Energy direction indicators . . . . . . . . . . . . . . . . . . . . . 3-2 Power/energy units identifier . . . . . . . . . . . . . . . . . . . . 3-3 Alternate display indicator . . . . . . . . . . . . . . . . . . . . . . 3-3 Error indicator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-3 Low battery indicator . . . . . . . . . . . . . . . . . . . . . . . . . . 3-3 Active COM port indicator . . . . . . . . . . . . . . . . . . . . . 3-3 Display indicators . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-3 Push buttons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-4 RESET button . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-4 * button . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-5 Using the backlight . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-6 Operating modes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-7 Normal mode . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-7 Alternate mode . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-8 Test mode . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-8 Demand reset . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-9 Demand reset lockout . . . . . . . . . . . . . . . . . . . . . . . . . . 3-10 Demand reset data area . . . . . . . . . . . . . . . . . . . . . . . . . 3-10

4 Meter tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-1 System instrumentation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-1 System service tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-5 Service voltage test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-5 System service locking . . . . . . . . . . . . . . . . . . . . . . . . 4-5 Initiating service voltage tests . . . . . . . . . . . . . . . . . . . 4-7 Restarting the service voltage test in diagnostic mode 4-9 Service current test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-9 Initiating the service current test . . . . . . . . . . . . . . . . 4-10 System service error codes . . . . . . . . . . . . . . . . . . . . . . 4-10 TRueQ monitoring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-12 TRueQ timing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-12 TRueQ display items . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-12 TRueQ and relays . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-12 TRueQ log . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-13 Voltage sags . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-13 Voltage sag counter and timer . . . . . . . . . . . . . . . . . . 4-13 TRueQ tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-13

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TRueQ event counters and timers . . . . . . . . . . . . . . . 4-15 Security . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-25 Meter passwords . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-25 Anti–tampering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-26 Program protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-26

5 Outputs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-1 Relay outputs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-1 Energy pulse outputs . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-3 Using pulse divisor . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-3 Using pulse value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-4 Relay-related alarms . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-4 LED pulse outputs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-6 Output specifications . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-6

6 Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-1 Meter self test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-1 Codes and warnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-2 Error codes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-2 Warning codes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-5 Communication codes . . . . . . . . . . . . . . . . . . . . . . . . . 6-8 Meter shop testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-9 Test equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-9 Test setup . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-9 Meter testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-10 Using relay outputs for testing . . . . . . . . . . . . . . . . . . 6-10 Using LCD pulse count for testing . . . . . . . . . . . . . . 6-10

7 Installation and removal. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-1 Preliminary inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-1 Placing the meter into service . . . . . . . . . . . . . . . . . . . . . . . . 7-1 Installing a TOU battery . . . . . . . . . . . . . . . . . . . . . . . . . 7-3 Troubleshooting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-4 Initial setup . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-4 Marking the utility information card . . . . . . . . . . . . . . . . 7-5 Removing the meter from service . . . . . . . . . . . . . . . . . . . . . 7-6 Removing the battery . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-6

8 Loss compensation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-1 What is Loss Compensation? . . . . . . . . . . . . . . . . . . . . . 8-1 Availability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-1 Software support . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-1 Calculating the correction values . . . . . . . . . . . . . . . . . . . . . 8-1 Gather necessary data . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-2 Calculate the meter configuration parameters . . . . . . . . 8-2 Calculating line loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-5 Gather necessary data . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-5 Calculation example . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-7 Gather necessary data . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-8 Enter Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-12 Internal meter calculations . . . . . . . . . . . . . . . . . . . . . . . . . 8-12 Meter outputs affected by compensation . . . . . . . . . . . . . . . 8-15 Testing a meter with compensation . . . . . . . . . . . . . . . 8-15

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Contents

A Glossary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1

B Display table . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .B-1 Display format . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .B-1 Display list items . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .B-2 Default display formats . . . . . . . . . . . . . . . . . . . . . . . . . .B-3 LCD test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .B-3 General meter information . . . . . . . . . . . . . . . . . . . . . . .B-4 Meter configuration . . . . . . . . . . . . . . . . . . . . . . . . . . . .B-4 Status . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .B-5 Metered quantities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .B-6 Average power factor . . . . . . . . . . . . . . . . . . . . . . . . . . .B-8 Coincident demand and power factor . . . . . . . . . . . . . . .B-8 Cumulative demand . . . . . . . . . . . . . . . . . . . . . . . . . . . .B-9 System instrumentation . . . . . . . . . . . . . . . . . . . . . . . . . .B-9 System service tests . . . . . . . . . . . . . . . . . . . . . . . . . . .B-11 Errors and warnings . . . . . . . . . . . . . . . . . . . . . . . . . . .B-12 Communication codes . . . . . . . . . . . . . . . . . . . . . . . . . .B-12

C Nameplate and style number information . . . . . . . . . . . . . . . .C-1 Nameplate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .C-1 Utility information card . . . . . . . . . . . . . . . . . . . . . . . . . . . . .C-2 Style number information . . . . . . . . . . . . . . . . . . . . . . . . . . .C-3

D Wiring diagrams . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . D-1 Direct connected . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . D-1 CT-connected meters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . D-2

E Technical specifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . .E-1 Absolute maximums . . . . . . . . . . . . . . . . . . . . . . . . . . . .E-1 Operating ranges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .E-1 Operating characteristics . . . . . . . . . . . . . . . . . . . . . . . . .E-1 General performance characteristics . . . . . . . . . . . . . . . .E-2 Dimensions and mass . . . . . . . . . . . . . . . . . . . . . . . . . . .E-2

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Disclaimer of Warranties and Limitation of Liability There are no understandings, agreements, representations, or warranties either expressed or implied, including warranties of merchantability or fitness for a particular purpose, other than those specifically set out by any existing contract between the parties. Any such contract states the entire obligation of the seller. The contents of this technical manual shall not become part of or modify any prior or existing agreement, commitment, or relationship. The information, recommendations, descriptions, and safety notices in this technical manual are based on Elster Metronica, OOO experience and judgment with respect to the operation and maintenance of the described product. This information should not be considered as all–inclusive or covering all contingencies. If further information is required, Elster Metronica, OOO should be consulted. No warranties, either expressed or implied, including warranties of fitness for a particular purpose or merchantability, or warranties arising from the course of dealing or usage of trade, are made regarding the information, recommendations, descriptions, warnings, and cautions contained herein. In no event will Elster Metronica, OOO be held responsible to the user in contract, in tort (including negligence), strict liability, or otherwise for any special, indirect, incidental, or consequential damage or loss whatsoever, including but not limited to: damage or loss of use of equipment, cost of capital, loss of profits or revenues, or claims against the user by its customers from the use of the information, recommendations, descriptions, and safety notices contained herein.

Safety Information Installation, operation, and maintenance of this product can present potentially hazardous conditions (for example, high voltages) if safety procedures are not followed. To ensure that this product is used safely, it is important that you: Review, understand, and observe all safety notices and recommendations within this manual. Do not remove or copy individual pages from this manual, as this manual is intended for use in its entirety. If you were to remove or copy individual pages, cross references and safety notices may be overlooked, possibly resulting in damage to the equipment, personal injury, or even death. Inform personnel involved in the installation, operation, and maintenance of the product about the safety notices and recommendations contained in this manual. Within this manual, safety notices appear preceding the text or step to which they apply. Safety notices are divided into the following four classifications:

Notice is used to alert personnel to installation, operation, or maintenance information that is important but not hazard related.

Caution is used to alert personnel to the presence of a hazard that will or can cause minor personal injury, equipment damage, or property damage if the notice is ignored.

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Warning is used to alert personnel to the presence of a hazard that can cause severe personal injury, death, equipment damage, or property damage if notice is ignored.

Danger is used to alert personnel to the presence of a hazard that will cause severe personal injury, death, equipment damage, or property damage if the notice is ignored.

.

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1-1

1 Introduction

A1800 ALPHA meter The A1800 ALPHA meter family provides a platform that supports a variety of metering requirements. The A1800 ALPHA meter family is a totally electronic polyphase electricity meter and integral register for commercial and industrial applications. The meter is available in 3- and 4-wire configurations for 3 phases. See Figure 1-1 for an illustration of an A1800 ALPHA meter.

Figure 1-1. A1800 ALPHA meter

+ Q -P

+P - Q

L1 L2 L3 COM 0 1 2

T1 T2 T3 T4 T5 T6

T7 T8 EOI LC TC TST

T YP E A1800 M ODEL

3x 58/100...277/480V, 50Hz 1(10)A

ELSTERSAMPLE

5,000 imp/kWh 5,000 imp/kVarh

0 .2 S

CT

A

VT

V

imp/kWh(kVARh)

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Standards Compliance IEC. The A1800 ALPHA meter meets or exceeds the following IEC standards for electricity metering.

Table 1-1. IEC standards supported by the A1800 ALPHA meter Number

Date

Edition

62052-11

2003

1

General requirements, tests and test conditions.

62053-21

2003

1

Particular requirements-static meters for active energy (Classes 1.0 and 2.0)

62053-22

2003

1

Particular requirements-static meters for active energy (classes 0,2 S and 0,5 S)

62053-23

2003

1

Particular requirements-static meters for reactive energy (classes 2 and 3)

62053-31

1998

1

Particular requirements-pulse output devices for electromechanical and electronic meters (two wires only)

62053-61

1998

1

Particular requirements-power consumption and voltage requirements

62056-211

2002

1

Electricity metering-data exchange for meter reading, tariff and load control-direct local data exchange

62052-21

2004

1

Title

Electricity metering-tariff and load controlparticular requirements for time switches

Complies with optical port requirements only.

IEEE/ANSI. The A1800 ALPHA meter meets or exceeds the following IEEE/ANSI standards for electricity metering, and it is intended for use by commercial and industrial utility customers.

Table 1-2. IEEE/ANSI standards supported by the A1800 ALPHA meter Number

Date

Title

IEEE 1701/ ANSI C12.18

1996

Protocol Specification for ANSI Type 2 Optical Port

IEEE 1377/ ANSI C12.19

1997

Utility Industry End Device Data Tables

IEEE 1702/ ANSI C12.21

1999

Protocol Specification for Telephone Modem Communications

DIN. The A1800 ALPHA meter meets or exceeds the following DIN standards for electricity metering. Table 1-3. DIN standards supported by the A1800 ALPHA meter1 Number

Date

Title

DIN 43857 Part 2

1978

Watthour meters in moulded insulation case without instrument transformers, up to 60 A rated maximum current; principal dimensions for polyphase meters.

1

For meter width and location of lower mounting holes

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Benefits Reliability. The A1800 ALPHA meter, part of the ALPHA line of meters, uses the patented ALPHA meter technology for measurement and accurate calculation of energy quantities. With over 3 million ALPHA polyphase meters in operation throughout the world, the A1800 ALPHA continues the tradition of reliable electronic meters. The power supply in the meter operates from any available phase. A three-phase, four-wire A1800 ALPHA meter maintains operation if the neutral line and any one or two of the line voltages become disconnected. The meter can also operate using the auxiliary power supply, which can power the meter from an independent power source in the situation where main power is unavailable. The A1800 ALPHA meter can use its internal crystal oscillator or the power line frequency to maintain time and date functions. The crystal oscillator can be used when the power line frequency is known to be too unstable for accurate timekeeping. The A1800 ALPHA meter has been designed to function to provide long battery life. Because of the low current drain, the service life of the lithium battery can exceed the life of the meter. The A1800 ALPHA meter uses nonvolatile memory to store billing and other critical data. The data is preserved even if the power fails.

Maintainability. The A1800 ALPHA meter is easy to maintain. Meter register functions and communication interfaces are fully integrated on a single, surface-mount technology circuit board. The meter firmware resides in flash memory, allowing the firmware to be upgraded in the field.

Introduction

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Introduction

ANSI standard communication open protocol. The A1800 ALPHA meter complies with the ANSI C12.18, C12.19, and C12.21 standards. These standards include communication protocols for a wide range of metering products. They are the basis for common industry data structures and a common protocol for transporting the data structures. Supporting the ANSI protocols makes it easier to add products to existing systems and provide an open standard for meter data communications.

Adaptability. The A1800 ALPHA meter allows configuration for custom TOU rates (tariffs), offering a broad range of demand and TOU operations. Most common services and mounting configurations are supported, and functional upgrades are easily performed as new situations arise. The wide operating range allows installation at any of the common meter voltages. Additionally, the factory-configurable optical port accommodates IEC standard. The 16-segment character liquid crystal display (LCD) improves readability and provides flexibility for displaying meter information. As an added feature, the main meter circuit board provides selectable, independent, serial remote interfaces for RS-232 or RS-485 communication.

Economy. The A1800 ALPHA meter saves both time and money. It can increase personnel productivity because of the following features: • no user calibration required (factory calibrated) • reduced testing times • fewer styles to learn and maintain • dual serial communications interfaces on the main meter circuit board • automated data retrieval • system service verification • on-site instrumentation displays • tamper restraint and quality monitoring (TRueQ™) tests • event logging

Security. The A1800 ALPHA meter is tamper-resistant. Passwords may be specified that prevent unauthorized access to meter data. The standard TRueQ feature or the optional instrumentation profiling (or both) can be used to detect possible tampering of energy measurements. All A1800 ALPHA meters provide auditing capabilities that can be used to indicate potential meter tampering like terminal cover open detection and per phase outage recording. The A1800 ALPHA meter can be ordered with a partially-transparent terminal cover, making it easier to see obvious tampering.

Accuracy. The A1800 ALPHA meter meets or exceeds requirements of IEC standards.

Configuration

IEC 62053-22 /GOST R 52323-2005/ Class 0.2 S

1

direct connect

transformer-rated 1 Actual



IEC 62053-21 /GOST R 52322-2005/

IEC 62053-231 /GOST R 52425-2005//

Class 0.5 S

Class 1.0

Class 1.0

Class 2.0

















reactive energy accuracy is substantially better than required by the standard.

The meter precisely measures demand and energy across a wide range of voltage and current despite variations in temperature and power factor. The low current sensor burden may also improve the accuracy of external current transformers when measuring light loads.

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Introduction

Meter types Different meters within the A1800 ALPHA meter family have specific capabilities (see Table 1-4 and Figure 1-2). Note: Throughout this manual, the term A1800 ALPHA is used to describe any meter in the meter family. When necessary, a specific meter designation will be used to indicate that the description applies to only one meter in the meter family.

Table 1-4. Meter designations of the A1800 ALPHA meter family Meter

Market segment

Class

A1802

Interchange meter/ Large C&I

0.2S

• 1 communications port (RS-232 or RS-485) • internal 128 KB (256KB) memory • auxiliary power supply • 4 relays • TRueQ • multitariffs • LCD backlight • Class 0.2 accuracy

• transformer and line loss compensation (V) • 4-quadrant metering (A) • extended 1 MB memory (X) • load and instrumentation profiling (L) • add 1 communication port • Multi-protocol communications (Modbus, DNP 3.0)

A1805

Large C&I/ Mid C&I

0.5S

• 1 communications port (RS-232 or RS-485) • internal 128 KB (256KB) memory • auxiliary power supply • 4 relays • TRueQ • multitariffs • LCD backlight • Class 0.5 accuracy

• transformer and line loss compensation (V) • 4-quadrant metering (A) • extended 1 MB memory (X) • instrumentation profiling (L) • load and instrumentation profiling (L) • add 1 communication port • Multi-protocol communications (Modbus, DNP 3.0)

A18101

Small C&I/ Mid C&I

1.0

• 1 communications port (RS-232 or RS-485) • internal 128 KB (256KB) memory • auxiliary power supply • 4 relays • TRueQ • LCD backlight • multitariffs

• transformer and line loss compensation (V) • 4-quadrant metering (A) • extended 1 MB memory (X) • instrumentation profiling (L) • load and instrumentation profiling (L) • add 1communication port

A18202

Small C&I

0.5S

• 1 communications port (RS-232 or RS-485) • internal 128 KB (256KB) memory • 4 relays • TRueQ • LCD backlight • Class 0.5 accuracy

• • • • •

extended 1 MB memory (X) instrumentation profiling (L) load profiling (L) add 1communication port multitariffs (T)

A18213

Small C&I

1.0

• 1 communications port (RS-232 or RS-485) • internal 128 KB (256KB) memory • 4 relays • TRueQ • LCD backlight

• • • • •

extended 1 MB memory (X) instrumentation profiling (L) load profiling (L) add 1communication port multitariffs (T)

1

Standard features

Contact Elster Metronica for availability. Contact Elster Metronica for DC connected meter availability. 3 Contact Elster Metronica for DC connected meter availability. 2

Optional features

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Figure 1-2. A1800 ALPHA meter family application pyramid

A1 80 0A LP HA

me ter fam ily

Interchange metering A1802 Large C & I A1805 Mid C & I A1810 Light C & I A1810 A1820 Residential

Introduction

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2 Product description

Physical description The A1800 ALPHA meter is designed for indoor mounting. The cover assembly of the A1800 ALPHA meter exceeds the environmental requirements of IEC 62053-11. The case of the A1800 ALPHA meter provides an IP54 degree of protection for the meter. The physical components of the A1800 ALPHA meter consist of the following: • terminal cover • long terminal cover (see Figure 2-1) • short terminal cover (see Figure 2-2)1 • partially-transparent terminal cover • meter cover assembly • inner cover assembly • base electronic assembly

Figure 2-1. Front view of the A1800 ALPHA meter

1 Contact

Elster Metronica for availability.

Product description

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Product description

The terminal cover and meter cover assembly are manufactured using a UV-protected polycarbonate plastic. The terminal cover is available in either the long version or the short version. The meter cover assembly has a clear plastic window that allows the meter LCD and nameplates to be viewed.

Figure 2-2. Front view of A1800 ALPHA meter with short terminal cover (transformer rated)1

The A1800 ALPHA meter can be sealed using any or all of the following methods: Seal location

Purpose

Meter cover screws (certification)

Prevents access to the meter except for the main connections, relay connections, communication interface connections, and nameplate. Also can prevent reprogramming and recalibration of the meter.

Terminal cover screws (utility)

Prevents non-utility access to the main connections, relay connections, and utility information card

RESET push button

Prevents unauthorized manual demand resets

The four cover screws can be individually sealed (Figure 2-1). The two terminal cover screws limit access to the main terminals and auxiliary wiring connections only. Therefore, only the terminal cover seals must be broken to access these connections. The two meter cover screws are located on the lower front of the meter under the terminal cover. Sealing these screws seals the main enclosure and limits access to the metering circuit board and sensing elements. For maximum protection of the metering components, seal all four screw seals.

1

Contact Elster Metronica for availability.

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Figure 2-3. A1800 ALPHA meter with cover removed (transformer rated)

Optical port. The A1800 ALPHA meter provides an optical port that can be ordered with IEC-compliant interface (see Figure 2-4). To use Elster meter support software to read or program the meter through the optical port, an optical probe is required. This probe connects from the serial port of the computer to the optical port on the meter.

Figure 2-4. IEC-compliant optical port interface

IEC-compliant optical interface

Elster Metronica recommends use of the AE-1 optical probe to reliably read the A1800 ALPHA meter. For information on ordering the AE-1 optical probe, visit www.izmerenie.ru or contact your local Elster Metronica representative.

LCD. The A1800 ALPHA meter is equipped with a 16-segment character liquid crystal display. See “Indicators and controls” on page 3-1 for details. Nameplate. Elster Metronica installs the nameplate at the factory. See Appendix C, “Nameplate and style number information,” for details on the nameplate.

Product description

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Product description

Utility information card. The utility information card is removable (after the terminal cover has been removed) and allows the utility to enter meter site-specific information. See “Utility information card” on page C-2 for more information. Figure 2-5. Removing the utility information card

Communications. The A1800 ALPHA meter (“-G” suffix) provides remote communications interfaces on the main meter circuit board for RS-232 or RS-485 serial communication. Physical outputs exist for both RS-232 and RS-485 interfaces; however, only one can be used at any given time. No configuration is necessary to switch between an RS-232 and RS-485 selection. Additionally, the A1800 ALPHA meter (“-S”, “-B” suffixs) provides a second, independent serial communication port that supports either RS-232 (see Figure 2-6) or RS-485 (see Figure 2-7). See Chapter 5, “Outputs,” for more information on the RS-232 or RS-485 ports. Figure 2-6. A1800 ALPHA meter (-S suffix) with RS-232 as second communication port

RS-232 connector (optional)*

Pulse output relay (optional)

RS-485 terminals

RS-232 connector

*Present when optional second communication port is installed

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Product description

Figure 2-7. A1800 ALPHA meter (-B suffix) with RS-485 as second communication port

RS-485 connector (optional)*

Pulse output relay (optional)

RS-485 terminals

RS-232 connector *Present when optional second communication port is installed

Battery. The terminal block has a battery well and connector for the optional TOU battery. Cover tamper detection switches. When either the terminal cover or the meter cover is opened, a detection switch is activated. (See Figure 2-8 for an illustration of the terminal cover detection switch; the meter cover detection switch is similar.) When either detection switch is activated, the TC indicator on the LCD turns on and remains on while the cover is removed. The date and time of the cover removal is logged in the event log. See “Event log” on page 2-14 for more information. Figure 2-8. Terminal cover detection switch

Cover closed

Cover opened

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Product description

Terminal configurations. The A1800 ALPHA meter supports the following terminal configurations: • 10 A transformer-rated (sequential) • 100 A direct connect-rated (sequential)

System architecture The A1800 ALPHA meter main circuit board contains all the electronics that make up the meter registers and communication interfaces. See for the meter circuit board block diagram. The circuit board as shown in contains the following: • meter engine • microcontroller • EEPROM • resistive dividers for the 3 phase voltages • load resistors for the 3 current sensors • power supply • high frequency crystal oscillator • 32 kHz low power timekeeping crystal oscillator • optical port components • liquid crystal display (LCD) interface • RS-232 and RS-485 communication interfaces • option board interface • pulse outputs

Figure 2-9. Meter block diagram Phase A voltage Phase B voltage

Non volatile supply

5 V linear power supply

Wide input power supply

Phase C voltage Battery Precision reference

LCD

Resistive divider

Low power crystal

Power Fail Resistive divider

2x Line Freq A

Resistive divider Phase A current

Current sensor

Phase B current

Current sensor

Phase C current

Current sensor

Meter engine

B C Wh Del

Microcontroller

Wh Rec varh Del varh Rec Clock

Crystal

EEPROM

Option connector

Optical Remote Pulse port port 1/2 outputs

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General theory of operation The A1800 ALPHA meter’s engine receives analog inputs of voltages and current to calculate the desired metered quantities. The meter engine samples the input voltages and current 66 to 88 times per cycle. The actual sampling frequency is based on whether 50 Hz or 60 Hz1 power systems are being measured. Using these input signals, the meter engine calculates root mean square (rms) values of voltage and current, and the meter engine uses the sampled signals to compute Wh, VAh, and VArh quantities for each phase. These individual phase quantities are summed, and the totals are transmitted to the microprocessor. The microprocessor processes and stores the data into memory according to the user-specified program. Once stored, data values are available to be displayed and communicated as required by the utility or other meter user. The very high sampling rate inherent in the meter engine and the additional over sampling techniques used in the A1800 ALPHA meter results in very high accuracy regardless of harmonic content, phase angle, or point on the load curve. The meter engine accumulates and recalculates all quantities after every line cycle. This provides the ability to include the effect of harmonics up to and beyond the 33rd harmonic. Individual harmonics up to and including the 15th harmonic are displayable items and are included in distortion measurements. Further advanced electronic techniques are used to provide extreme stability of accuracy over time and over an exceptionally wide range of operating and load conditions. The A1800 ALPHA meter can accommodate various tariff structures. The meter also supports a variety of communication options that allow the meter to be read remotely or manually. In addition, relays may be used for pulse outputs of user-selected quantities or for signaling the start of a tariff period.

Power supply Main power supply. Power is supplied to the A1800 ALPHA meter using a wide voltage range power supply that accepts voltages from 49 V to 528 V AC. At least two lines must be present to power the meter circuitry. The output from the power supply is then fed to a low voltage linear regulator to attain the low level voltage.

Auxiliary power supply. The A1800 ALPHA meter may be ordered with an auxiliary power supply. The auxiliary power supply allows the A1800 ALPHA meter to be powered by a separate AC or DC power source, such as substation’s independent power lines. Should the main power supply be unavailable, the meter will be fully operational provided the independent power is still available. The A1800 ALPHA meter can also be connected to both the main power source and auxiliary power source, providing uninterrupted power in the event that the main power becomes unavailable. The auxiliary power supply accepts the following voltages: • For independent AC power, from 57 V rms to 240 V rms (115V nominal) • For independent DC power, from 80 V to 340 V Note: When using independent DC power, the A1800 ALPHA meter’s auxiliary power supply is polarity independent. The meter will operate properly without regard to which wire is positive and which wire is negative. The output from the independent power supply is then fed to a low voltage linear regulator to attain the low level voltage.

Current and voltage sensing Power line currents and voltages are sensed using specialized current sensors and resistive dividers, respectively. Multiplication and other calculations are performed using a custom integrated circuit (called the meter engine).

1

Contact Elster Metronica for availability.

Product description

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The meter receives each phase current through a precision-wound current sensor that reduces the line current proportionally. The meter engine samples the individual phase currents to provide accurate current measurement. The meter receives each phase voltage through resistive dividers. This ensures that a linear low level voltage is maintained. It also serves to minimize phase shift over a wide dynamic range. The meter engine samples the scaled inputs provided by the resistive dividers to provide accurate voltage measurements.

Meter engine Multiplication and other calculations are performed using a custom integrated circuit, called the meter engine. The meter engine contains the digital signal processor (DSP) with built-in analog-to-digital (A/D) converters capable of sampling each current and voltage input. The A/D converters measure the voltage and current inputs for a given phase. The DSP multiplies the signals appropriately, using the factory-programmed calibration constants.

Microcontroller The microcontroller performs many different functions, for example: • communicates with the DSP and EEPROM • provides for serial communication over the optical port • provides for serial communication over the remote ports • generates optical output pulses • controls the LCD • controls any option boards The microcontroller and the meter engine communicate with each other constantly to process voltage and current inputs. When the microcontroller detects a power failure, it initiates the shutdown and stores billing and status information in EEPROM.

EEPROM The A1800 ALPHA meter uses electrically erasable programmable read only memory (EEPROM) for nonvolatile storage of manufacturing data, meter configuration data, and energy measurement values. The A1800 ALPHA meter is provided with either 128 KB or 256 KB of main board memory. See “Style number information” on page C-3 for information regarding how to identify the amount of main board memory on your meter. The EEPROM provides storage of all information needed to ensure the integrity of the demand or energy calculations, including the following: • configuration data • billing data • all TOU data • log and profiling data • meter status • constants • energy usage • maximum demand • cumulative demand

Product description

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Billing data Metered energy and demand quantities All A1800 ALPHA meters are capable of measuring delivered and received kWh energy and kW demand. The A1800 ALPHA meters can also measure reactive and apparent energy and demand. The meter engine samples the voltage and current inputs and sends these measurements to the microcontroller. In the meter engine, each pulse is equal to one Ke defined as one of the following: • secondary rated Wh per pulse • secondary rated varh per pulse • secondary rated VAh per pulse The following list shows the available metered quantities for the A1800 ALPHA meter. Basic metered quantities (indicated by * in Table 2-1) can be selected as a source for relay outputs. The remaining metered quantities are calculated from 2 or more basic metered quantities.

Table 2-1. Metered energy and demand quantities • • • • • • • • • • • •

kVAh delivered (Q1 + Q4) kVAh Q1 kVAh Q2 kVAh Q3 kVAh Q4 kVAh received (Q2 + Q3) kVAh sum (delivered + received) kvarh (Q1 - Q4) kvarh (Q1 + Q4)* kvarh (Q2 - Q3) kvarh (Q2 + Q3)* kvarh (Q3 - Q2)

• • • • • • • • • • • •

kvarh delivered (Q1 + Q2)* kvarh net kvarh Q1* kvarh Q2* kvarh Q3* kvarh Q4* kvarh received (Q3 + Q4)* kvarh sum (delivered + received)* kWh delivered* kWh net kWh received* kWh sum*

Average power factor The A1800 ALPHA meter can calculate the average power factor (AvgPF) using kWh and kvarh values since the last demand reset.

AvgPF 

kWh k var h 2  kWh 2

The meter can store up to two average power calculations, which can be configured in Elster’s meter support software. Average power factor is calculated every second. Upon a demand reset, the values used in this calculation are set to zero and the AvgPF will be set to 1.000.

Demand calculations Demand is the average value of power over a specified time interval. The A1800 ALPHA meter supports three different methods for demand calculation: • rolling interval • block interval • thermal time constant An interval is the time over which demand is calculated. The length of a demand interval is programmable using Elster meter support software, but the value must be evenly divisible into 60 minutes. Common demand interval lengths are 15 or 30 minutes.

Product description

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Product description

Rolling interval. Rolling demand interval is defined by two parameters: • the demand interval length - specified in minutes and may be any value that is evenly divisible into 60 • subinterval length - also specified in minutes and may be any value that is evenly divisible into the interval length Both of these values are configurable by Elster meter support software. The demand is calculated at the end of each subinterval, resulting in overlapping demand intervals (or a “rolling” demand). For example, the A1800 ALPHA meter can be configured for a 15-minute demand interval length and a 5-minute subinterval length. In this case, the demand is calculated every 5 minutes based on the 3 previous subintervals (see Figure 2-10).

Figure 2-10. Rolling demand intervals 15-minute interval 15-minute interval 15-minute interval subinterval 0

subinterval 5

subinterval

subinterval

10 15 Time (minutes)

subinterval 20

25

The rolling interval calculates demand by using the following equation:

D

total accumulated energy t hours

For example, if the demand interval is 15 minutes and the total accumulated energy is 50 kWh, then the demand is 200 kW.

D

50 kWh  200 kW 0.25 h

Block interval. Block demand interval is a special case of rolling interval demand in which the subinterval is the same size as the interval (see Figure 2-11).

Figure 2-11. Block demand intervals

0

interval

interval

interval

interval

subinterval

subinterval

subinterval

subinterval

15

30 45 Time (minutes)

60

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Thermal time constant. The A1800 ALPHA meter can perform thermal demand emulation. The meter calculates demand based on a logarithmic scale that accurately emulates thermal demand meters. The thermal demand time constants vary depending upon the operational mode of the meter. • Normal mode time constant is 15 minutes. • Test mode time constant is 1 minute. See “Operating modes” on page 3-7 for more information.

Maximum demand Maximum demand (also referred to as indicating or peak demand) is the highest demand value that occurs in a billing period. The demand for each demand interval is calculated and compared to an earlier maximum demand value. If the new interval demand exceeds the previous maximum demand, then the new demand is stored as the maximum demand (see Figure 2-12). When a demand reset occurs, the maximum demand is reset to zero. The demand for the first full interval after a demand reset becomes the maximum demand.

Figure 2-12. Maximum demand New maximum Earlier maximum demand (9.9 kW) demand (9.9 kW) Earlier maximum demand (9.7 kW)

Interval 6 demand (9.2 kW)

Interval 7 demand (9.9 kW)

Interval 8 demand (9.5 kW)

In addition to maximum demand, the A1800 ALPHA meter also stores either the cumulative or continuous cumulative demand. A1800 ALPHA meters can be programmed to trigger the recording of a coincident demand or power factor (see “Coincident demand or power factor” on page 2-12).

Cumulative maximum demand Using cumulative maximum demand, a demand reset adds the current maximum demand value to the cumulative maximum demand. This feature is used to calculate the previous maximum demand when the demand may have had an unauthorized reset. Since the cumulative demand is not reset to zero, unauthorized demand resets do not cause a loss of the maximum demand data. To determine the maximum demand for a billing period after a demand reset, subtract the previous cumulative demand from the current cumulative demand.

Continuous cumulative maximum demand Continuous cumulative maximum demand works similarly to cumulative maximum demand. Continuous cumulative demand, however, is always equal to the sum of the previous billing period continuous cumulative demand and the current maximum demand. This feature is used to calculate the previous maximum demand when the demand may have had an unauthorized reset.

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Coincident demand or power factor The number of coincident values that may be captured by the A1800 ALPHA meter depends on whether or not the 4-quadrant metering (“-A” suffix) option is present. • A1800 ALPHA meters without 4-quadrant metering record 2 coincident values. • A1800 ALPHA meters with 4-quadrant metering record up to 4 coincident values. Coincident demand refers to a demand value that occurs at the same time as another demand reaches its peak value. For example, an electric utility may want to record the kvar demand at the time of a maximum kW demand. This requires that kvar demand be stored and reported during the same interval as the maximum kW demand. Similarly, coincident power factor refers to a power factor that occurs at the same time as a demand value reaches its peak value. For example, an electric utility may want to record the power factor at the time of a maximum kvar demand. This requires the power factor be stored and reported during the same interval as the maximum kvar demand.

Coincident PF 

kWh kvarh 2  kWh 2

Demand forgiveness Demand forgiveness is the time during which demand is not calculated or stored after a qualified power outage. Demand forgiveness has two programmable settings: • outage time: the number of minutes a power outage must last to qualify for demand forgiveness (0 to 15 minutes) • time: the number of minutes that demand is not calculated or stored (0 to 255 minutes) following a qualified power outage; zero disables demand forgiveness

Primary and secondary metering The A1800 ALPHA meter can be programmed for either primary or secondary metering. When configured for primary metering, the A1800 ALPHA meter internally converts the measured energy, demand and instrumentation quantities to primary units using the voltage transformer ratio and the current transformer ratio. These ratios are programmed using Elster meter support software. The metered quantities reflect energy, demand and instrumentation on the primary side of the instrument transformers. When configured for secondary metering, the A1800 ALPHA meter does not use the voltage transformer ratio or the current transformer ratio to adjust the metered quantities. The metered quantities reflect the energy, demand and instrumentation on the secondary side of the instrument transformers even if the voltage and current ratios are programmed into the meter.

TOU data All A1800 ALPHA meters store the total (single-rate) data for energy and demand. TOU meters can store the total data and the data for up to 4 rates. TOU rates can be based on any combination of day (up to 4 day types), time (up to 132 switch times), or season (up to 12 seasons). The switch points for energy and demand may be configured independently of each other. All selected metered quantities are stored according to the TOU rate. The meter stores the energy, demand, and average power factor for each rate.

Product description

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Product description

Power failure data The A1800 ALPHA meter monitors and records the total power failure data. The following information is recorded: • cumulative number of minutes of all power failures • start date and time of the most recent power failure • end date and time of the most recent power failure These values can be programmed to display on the LCD. See Appendix B, “Display table,” for more information about displayable items. See “Event log” on page 2-14 for information on loss of phase voltage.

Logs and data sets All A1800 ALPHA meters are equipped with EEPROM. As shown in Figure 2-13, a small portion of this main board memory is permanently reserved (called “reserved memory”) by the meter to store the main billing and configuration information. The remainder of the memory (called “shared memory”) is used to store the following logs and data sets: • event log • history log • self reads • load profiling • instrumentation profiling • TRueQ log • voltage sag log All of the logs and data sets share the meter’s memory. Using Elster meter support software, the sizes of each log or data set can be configured to allow more room for a different log or data set. For example, self reads can be configured to store less data so that the load profiling can store more data.

Figure 2-13. Allocation of meter memory Main circuit board memory (128 KB or 256 KB)

Billing data, Configuration data, Manufacturing info, etc.

Reserved memory**

Event, History, TRueQ, Voltage sag

Extended memory option board (1 MB)

Self read, LP,* IP*

IP,* LP*

Shared memory

Notes *Extended memory used only when requested number of days exceeds the capacity of main board memory. If meter support software is set to maximize data storage, then the extended memory option board would always be used for LP and IP data storage. **Size of reserved memory is fixed and may vary with each firmware release.

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In most cases, the 128 KB or 256 KB option is sufficient to meet data logging and profiling requirements. In some cases (for example, if extensive instrumentation profiling is desired), more memory may be required. When the data storage cannot be met with the 256 KB main memory option, extended memory can be used to add shared memory to the A1800 ALPHA meter.

Event log All A1800 ALPHA meters have an event log. The A1800 ALPHA meter stores the date and time that events occur. Elster meter support software is used to define and program the number of event log entries that the meter will record. Events that can be included in the event log are as follows: • power fail start and stop (2 event log entries) • date and time change information (2 event log entries) • date and time of demand resets (1 event log entry) • date and time of event log reset (1 event log entry) • date and time of test mode activity (2 event log entries) • start and stop time when the current TOU rate is overridden by the alternate TOU rate schedule (2 event log entries) • start and stop time of per phase outage (2 event log entries) • date and time of terminal cover removal (1 event log entry) • date and time of main cover removal (1 event log entry) Note: The meter will detect and log the removal of either the terminal cover or main cover even when the meter is not powered (provided the TOU battery is functioning). After the maximum number of entries has been stored, the meter will begin overwriting the oldest entries. The event log can be disabled through Elster meter support software.

History log All A1800 ALPHA meters have a history log that stores table information and procedure ID for configuration-altering writes to the meter. The A1800 ALPHA meter records a sequential listing of records, along with the date and time. The meter records this information as an audit trail, maintaining a history of programming changes made to the meter. After the maximum number of entries has been stored, the meter will begin overwriting the oldest entries. The history log can be disabled through Elster meter support software.

Self reads All A1800 ALPHA meters can support self reads. A self read captures the current period billing data and stores it in memory. The A1800 ALPHA meter can store up to 35 self reads can be stored depending on memory requirements for logs, data, etc. This data can be retrieved later for analysis or billing. If the meter has recorded the maximum number of self reads, the next self read will overwrite the oldest copy. Self reads are events that can be triggered by any of the following: • scheduled calendar events • every demand reset • communication procedure Self reads are different from previous billing data copies. The previous billing data copy stores only one copy of billing data at a time and only when a demand reset occurs. See “Demand reset data area” on page 3-10 for more information.

Product description

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Product description

Load profiling For meters with load profiling capabilities (designated with an “-L” suffix), the A1800 ALPHA meter is capable of recording 8 channels of information.

Table 2-2. Load profiling sources • • • • • • • • • • • •

kVAh delivered (Q1 + Q4) kVAh Q1 kVAh Q2 kVAh Q3 kVAh Q4 kVAh received (Q2 + Q3) kVAh sum kvarh (Q1 - Q4) kvarh (Q1 + Q4) kvarh (Q2 - Q3) kvarh (Q2 + Q3) kvarh (Q3 - Q2)

• • • • • • • • • • • •

kvarh delivered (Q1 + Q2) kvarh net kvarh Q1 kvarh Q2 kvarh Q3 kvarh Q4 kvarh received (Q3 + Q4) kvarh sum kWh delivered kWh net kWh received kWh sum

Load profiling has its own, separate interval length that is configured independently from the demand interval length. The length of the load profiling interval must adhere to the following rules: • the length must be between 1 and 60 minutes • the time must be evenly divisible into an 60 minutes Table 2-3 show the number of days of load profiling available. These values are estimates and may vary depending on the firmware used in the meter. Data in Table 2-3 are based on the following settings: • load profiling at 15-minute intervals • no instrumentation profiling • the meter is programmed for 6 metered quantities, 2 average power factors, and 4 coincident values The first number shows the number of days of load profiling, assuming all other logs and self reads record the maximum number of entries. The second number shows the number of days of load profiling, assuming all other logs and self reads record the minimum number of entries.

Table 2-3. Estimated days of load profiling storage per number of channels Days of storage (max./ min.)

Number of channels 1

2

3

4

5

6

7

8

128 KB

199/320

106/171

81/130

60/96

51/81

41/66

37/59

32/51

256 KB

594/714

317/381

242/291

178/214

151/182

124/149

110/133

95/114

1 MB

3177

1696

1294

954

812

664

592

509

Note: The actual number of days stores varies based on meter firmware release and other options programmed using Elster meter support software. See the documentation for the meter support software for more information regarding memory allocation.

Load profiling pulse divisor. A pulse divisor is used to scale down the number of pulses recorded in each load profiling interval. This allows recording of data that may exceed the maximum number of pulses that can be stored in each load profiling interval (each interval can store 32,767 pulses before overflowing). The range for the value of the load profiling pulse divisor is 1 (default) to 255.

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Product description

Instrumentation profiling In meters with instrumentation profiling, the meter has two sets of instrumentation profiling. Each set can record up to 16 channels from the sources listed in Table 2-4. Also, instrumentation profiling can use the sources listed in Table 2-2 for more extensive load profiling.

Table 2-4. Instrumentation profiling sources • • • • • • • • • • • • • •

frequency per phase current per phase voltage per phase watts per phase VA per phase voltage angle with respect to line 1 voltage per phase fundamental (1st harmonic) current magnitude per phase fundamental (1st harmonic) voltage magnitude per phase 2nd harmonic current magnitude per phase 2nd harmonic voltage magnitude per phase voltage % total harmonic distortion (THD) per phase current % THD per phase harmonic current (sum of 2nd through 15th) per phase current angle with respect to line 1 voltage

• • • • • • • • • • • • • •

per phase vars (vectorial) per phase 2nd harmonic voltage % per phase total demand distortion (TDD) per phase PF per phase PF angle system watts system VA (arithmetic) system PF (arithmetic) system PF angle (arithmetic) system vars (vectorial) system VA (vectorial) system var (arithmetic) system PF (vectorial) system PF angle (vectorial)

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Each channel can be configured to record the instrumentation profiling using any one of following four algorithms (see Table 2-5):

Table 2-5. Instrumentation profiling recording algorithms Item

Description

Minimum

The meter samples the selected quantity over the instrumentation interval. The minimum value of all the samples is recorded.

Maximum

The meter samples the selected quantity over the instrumentation interval. The maximum value of all the samples is recorded.

Average

The meter samples the selected quantity over the instrumentation interval. The average value of all the samples is recorded.

End

The meter samples the selected quantity over the instrumentation interval. The last value of all the samples is recorded.

Each set of instrumentation profiling has its own, separate interval length that is configured independently from the demand interval length. The length of the instrumentation profiling interval must adhere to the following rules: • the length must be between 1 and 60 minutes • the time must be evenly divisible into an 60 minutes

TRueQ Log The A1800 ALPHA meter has a TRueQ log that records TRueQ test failures. Elster meter support software is used to define and program the number of TRueQ log entries that the meter will record. Elster meter support software is also used to define which tests can record failures in the TRueQ log. The A1800 ALPHA meter can record the following data associated with the TRueQ test: • the date and time when the TRueQ monitor first detects a qualified failure and the identifier of the TRueQ test (1 TRueQ log entry) • the date and time when the TRueQ monitor no longer detects a failure and the identifier of the TRueQ test (1 TRueQ log entry) Note: See “TRueQ event counters and timers” on page 4-15 for information on qualification time For each TRueQ log entry, the meter also records an instrumentation measurement related to the TRueQ test. When the maximum number of entries has been stored, the meter will begin overwriting the oldest entries. See “TRueQ monitoring” on page 4-12 for more information.

Voltage sag log The meter has a voltage sag log. The A1800 ALPHA meter records the date, time, and phases of any detected voltage sag. The log records a maximum of 1 entry per second. When the maximum number of entries has been stored, the meter will begin overwriting the oldest entries. See “Voltage sags” on page 4-13 for more information.

User-defined tables User defined tables offer specific data retrieval options for A1800 ALPHA meters. User defined table configuration may be requested at the time of purchase, and the specific configuration may be programmed at the factory. An AMR system can then be configured to retrieve the user defined table information from the meter instead of individual table reads. This reduces the total communications time.

Product description

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Product description

Physical dimensions and mass The approximate dimensions of the meter correspond to DIN 43-857 part 2 (excluding the meter hanger). See the following figures for illustrations of the meter and its dimensions.

Figure 2-14. A1800 ALPHA meter, standard terminal cover 89 22

204

224* 307

*This represents hanger in center position.

150

5

Approximate dimensions in millimeters

170

Figure 2-15. A1800 ALPHA meter, short terminal cover1 89 22*

213*

224* 240

*This represents hanger in center position

150 170

1

Contact Elster Metronica for availability.

5 Approximate dimensions in millimeters

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Product description

Figure 2-16. A1800 ALPHA meter, back of meter

202

150

Approximate dimensions in millimeters.

Figure 2-17. A1800 ALPHA meter, bottom view (direct connect1 and transformer rated) 170

170

6.2

5.4

Ø 10 Direct connect meter

Transformer rated meter Approximate dimensions in millimeters.

Table 2-6. Approximate mass Elements

Direct connect

Transformer rated

2-element

1.6 kilograms

1.3 kilograms

3-element

1.7 kilograms

1.3 kilograms

1

Contact Elster Metronica for availability.

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Product description

Technical manual

Technical manual

3-1

Operating instructions

3 Operating instructions

Indicators and controls LCD The liquid crystal display (LCD) is used to display meter data and status information. Figure 3-1 shows the dimensions of the LCD.

Figure 3-1. LCD dimensions 85 77

1.4

3.5

+ Q -P

7

+P - Q

27 9.5

5

Approximate dimensions in millimeters

2

Viewing area

As shown in Figure 3-2, the LCD is divided into different display regions.

Figure 3-2. LCD regions Low battery indicator

Phase indicators (3)

Error/warning indicator

Quantity identifier

+ Q

Energy direction indicator

-P

+P - Q

L1L2 L3 COM 0 1 2

Alternate mode indicator

Display quantity Comm. port indicator Power/energy units identifier Tariff indicators 1 to 8 (left to right) EOI indicator LC indicator

Test mode indicator Cover removed indicator

32

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Operating instructions

All A1800 ALPHA meters have a backlight option for the LCD. The LCD can be illuminated by pressing one of the push buttons, making it easier to read the LCD in no-light or low-light conditions. The backlight option must be specified at the time of ordering. See “Using the backlight” on page 3-6 for more information.

Quantity identifier. This 7-digit region identifies the displayed quantity as defined and programmed with Elster meter support software. An identifier can be assigned to most display quantities in the display sequence. See Appendix B, “Display table,” for more information.

Display quantity. This 8-digit display on the LCD shows either metered quantities or other displayable information, depending upon how the A1800 ALPHA meter has been programmed. The displayable digits are definable using Elster meter support software for both energy and demand readings. From 3 to 8 digits with up to 4 decimal places can be used. These digits are also used to report error codes for the following error conditions: • operational errors (E1, E2, or E3) • system instrumentation and service test errors (SE) • warnings (W1 or W2) • communication codes (COM 0, COM 1, COM 2) For instrumentation values and tests, numeric values may be replaced by or mixed with alphabetic characters to better define the value. See Appendix B, “Display table,” for more information.

Phase indicators. Each phase indicator (L1, L2, and L3) corresponds to a line voltage (Line 1, Line 2, and Line 3, respectively) present on the A1800 ALPHA meter connections. The state of the indicators correspond to the following: • If the indicators are on, then all expected line voltages are present. • If an indicator is blinking, then that expected line voltage is either missing or below the defined threshold for voltage sag detection. • If an indicator is off, the line is not expected for the configured meter type. See “Voltage sags”for more details on momentary voltage sag detection and the phase indicators.

Energy direction indicators. The energy direction indicators display the quadrant and direction of the last Wh (active) and varh (reactive) energy flow. Positive energy flow is energy delivered to the consumer load, while reverse energy flow is energy received from the consumer load. Figure 3-3 shows the meaning of each energy direction indicator. The energy direction indicators turn on to display energy flow direction when any of the meter phases are measuring energy flow (that is, when one of the line currents is above the meter starting threshold).

Figure 3-3. Energy direction indicators Positive reactive energy Reverse active energy

Positive active energy

Reverse reactive energy

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On meters with the Always Positive option, the +P indicator is on continuously whenever kWh flow of any direction is detected. The –P indicator is inoperative for this meter configuration (see “Always Positive” on page 2-13 for more information).

Power/energy units identifier. The power/energy units identifier is used to indicate the unit of measurement for the quantity displayed on the meter’s LCD. In some cases, it may not be possible to represent the displayed quantity using the power/energy units identifier. If this is the case, then the power/energy units identifier will not be used. Instead, the quantity will be identified either using the quantity identifier or appending the unit to the display quantity.

Alternate display indicator. This indicator (*) displays when the A1800 ALPHA meter is operating in alternate mode. This indicator also displays during the all segment test of the LCD. See “Operating modes” on page 3-7 for more information on the different operating modes.

Error indicator. The error indicator flashes when any error condition is present or remains on if a warning condition is present. When the error indicator is on, the LCD will also display the appropriate error or warning code. See “System service error codes” on page 4-10 and “Codes and warnings” on page 6-2 for details. Note: This indicator also turns on during the LCD all-segments test.

Low battery indicator. The low battery indicator is turned on when the TOU battery voltage is low or when the TOU battery is missing. Additionally, the low battery warning display item (if included in the display list) also is displayed. Note: This indicator also turns on during the LCD all-segments test.

Active COM port indicator. The active COM port indicator indicates that a communication session is in progress and which COM port is being used.

Table 3-1. Port codes Code

Port

COM 0

Optical port

COM 1

Remote port 1

COM 2

Remote port 2

See “Communication codes” on page 6-8 for additional details.

Display indicators. The 12 display indicators () are used to more precisely identify the information displayed on the meter’s LCD. Note: These identifiers may be shown individually or in combination to describe a particular displayed quantity. Note: The manufacturer’s nameplate details the meaning of the display indicators. See Appendix C, “Nameplate and style number information.” Tariff indicators. The tariff indicators (T1, T2, T3, and T4) indicate the current tariff. If the displayed quantity is a TOU item (for example, tariff 1 total kWh), the corresponding indicator (T1) turns on. If the quantity’s tariff is active at the time, the tariff indicator flashes. Note: The active tariff indicators also turns on during the LCD all-segments test. EOI indicator. The end-of-interval (EOI) indicator is used to verify the timing of the demand interval. Ten seconds before the end of the demand interval, the EOI indicator will be turned on and remain on until the end of the interval.

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3-4

For rolling demand, the EOI indicator turns on for 10 seconds before the end of each subinterval. Transformer and line loss compensation indicator. The loss compensation (LC) indicator indicates the meter is currently compensating for transformer and line loss. Cover tamper indicator. The cover tamper (TC) indicator indicates that either the terminal cover or the meter cover is removed. This may indicate that tampering has occurred on the meter. The TC indicator turns off when all the covers are in place. See “Cover tamper detection switches” on page 2-5 for additional information. Test mode indicator. The test (TST) mode indicator indicates that the meter is currently operating in test mode. See “Test mode” on page 3-8 for details.

Push buttons The following push buttons are located on the front of the A1800 ALPHA meter: • RESET (sealable) • * (ALT) If sealed, the RESET button is only accessible after breaking the seal; the button is always accessible.

Figure 3-4. A1800 ALPHA meter push buttons

* (ALT) button

RESET button (sealable)

RESET button. To activate the RESET button, it may be necessary to break the seal that locks the RESET button in the inactive position. After the seal is broken, rotate the push button 90 ° in either direction and press the push button (see Figure 3-5). Pressing the RESET button performs a demand reset (see “Demand reset” on page 3-9 for a description on what happens during a demand reset). The RESET button performs differently depending on the A1800 ALPHA operating mode, as shown in Table 3-2.

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Table 3-2. RESET button behavior Mode

Description

Normal

Performs a demand reset

Alternate

Returns to normal mode and performs a demand reset

Test

Resets test value and remains in test mode

To seal the RESET button, rotate the RESET button 90 ° back to the inactive position and apply the seal.

Figure 3-5. RESET button positions

Inactive position RESET button cannot be pressed

Active position RESET button can be pressed

Using to lock service. Pressing the RESET button will accept and lock the detected service when the service test lock mode has been set to manual and the system service voltage test has just been performed by the A1800 ALPHA meter. See “Manual lock” on page 4-6 for more details.

Using the RESET button to lock the service will not perform a demand reset unless it is pressed a second time. * button. Pressing the button normally initiates the alternate mode (see “Operating modes” on page 3-7 for more information about the A1800 ALPHA operating modes). The * button performs differently depending on the operating mode, as shown in Table 3-3. Note: All the A1800 ALPHA meter have the backlight display option, therefore the * button can be used to illuminate the display. See “Using the backlight” on page 3-6 for more information.

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Operating instructions

Table 3-3. * button function in different operating modes Mode

Press method

Description

Normal

Less than 1 second

Enters alternate mode, LCD displays one cycle of the alternate display list, and returns to normal mode.

Alternate

Continuous

Scrolls quickly through the alternate display list while pressed; locks LCD on a display quantity when released.

Press and release

If the LCD is locked on a display quantity, each press steps to the next quantity in the alternate display list.

Continuous

Scrolls quickly through the test mode display list while pressed; locks LCD on a display quantity when released.

Press and release

If the LCD is locked on a display quantity, each press steps to the next quantity in the test display list.

Test

Using the backlight. All the A1800 ALPHA meter have the backlight for the LCD. Once the backlight is turned on, the LCD will be illuminated for two minutes.

To illuminate the LCD, use the following process (see Figure 3-6): 1. Press either the * button or the RESET button. The backlight turns on for the specified illumination time. 2. While the LCD is illuminated, the push buttons will operate as follows: • The RESET button operates as specified in Table 3-2. • The * button operates as specified in Table 3-3. 3. The backlight will turn off at the end of the illumination time. Pressing either the * button or the RESET button restarts the process, beginning with step 1.

The A1800 ALPHA meter can be ordered with the backlight always turned on. With this option, the LCD backlight will always be illuminated, and the RESET and * buttons will operate as specified in Table 3-2 and Table 3-3, respectively.

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Operating instructions

Figure 3-6. Using the backlight on the A1800 ALPHA meter LCD (default operating mode)

Backlight off

Any button is pressed

Backlight on Enter alternate mode

Yes, *

Perform demand reset Button pressed while LCD lit?

Yes, RESET

No Has time expired?

No

Yes

Operating modes The A1800 ALPHA meter operates in one of the following modes: • normal mode • alternate mode • test mode

As part of its function, the meter performs self tests to make sure it is operating normally. The self test ensures that the A1800 ALPHA meter is functioning properly and that its displayed quantities are accurate. If the self test indicates an error, the LCD displays the error indicator. In addition, the meter can be programmed to “lock” the error code on the display. The meter attempts to function normally, however, the meter data may be suspect. See “Meter self test” on page 6-1 for more information on self tests and errors.

Normal mode Normal mode is the default operation mode for the A1800 ALPHA meter. It is generally used to display billing data on the LCD. The meter is fully operational in this mode, and it will process and store data while the LCD scrolls through the normal display list quantities. The LCD test will always appear immediately after power is connected to the A1800 ALPHA meter or after a power restoration from an outage.

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Typically, the normal mode display cycle begins with an LCD test which turns on all of the display segments. This is recommended because it provides a quick way to determine if the LCD is functioning properly. The LCD test can be disabled using Elster meter support software. The normal display cycle will scroll through all programmed display quantities before beginning the cycle again. While in normal mode, the LEDs transmit pulses proportional to metered energy. See “LED pulse outputs” on page 5-6 for details on the LEDs.

Alternate mode Alternate mode can be programmed with Elster meter support software to display a second set of quantities on the LCD. Alternate mode is most often used for displaying non-billing data, but it can be programmed to display any of the available quantities. This mode is activated in one of the following ways: • pressing the * button on the A1800 ALPHA meter • after power up for one cycle of the alternate display list Note: This feature can be disabled using Elster’s meter support software. The meter is fully operational while in alternate mode. While in alternate mode, the alternate display indicator is turned on. Additionally, the LEDs transmit pulses (see “LED pulse outputs” on page 5-6). There are several different ways to exit alternate mode. Whenever exiting the alternate mode, the meter returns to normal mode.

Table 3-4. Exiting alternate mode Method

Description

Wait for the end of the alternate display list

If the meter is scrolling through the alternate display list automatically, the meter exits alternate mode after the last item is displayed.

Press the RESET button

Exits alternate mode and performs a demand reset.

Wait for the timeout

If the LCD remains on a quantity, the meter exits alternate mode after 2 minutes of inactivity. If the LCD remains on a pulse line cumulative counter, the meter will exit the alternate mode at midnight.

Power failure occurs

Exits alternate mode; when power is restored, the meter's display is in normal mode.

At midnight

Exits alternate mode at the next midnight crossing.

Test mode The A1800 ALPHA meter enters test mode by a command through the optical port. While in test mode, the test mode indicator (TST) will flash on the meter’s LCD. Test mode displays test readings without affecting the present energy usage and billing data values in the A1800 ALPHA meter. Shorter demand intervals may be used in test mode to reduce demand test time and will not interfere with billing data. When normal mode is resumed, readings taken during test mode will be discarded and present energy usage and billing data values will be restored. The status of the meter (including billing data, profiling data, errors, and warnings) before the meter entered test mode is restored. While in test mode, the optical port transmits test pulses proportional to metered energy (see “LED pulse outputs” on page 5-6).

Operating instructions

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Test mode is entered using Elster meter support software. The meter exits test mode under any of the following conditions:

Table 3-5. Exiting test mode Method

Description

Test mode expires

Automatically after a programmable timeout has expired (between 1 and 255 test mode intervals)

Send an exit command

Using Elster meter support software, send an exit command over the optical port.

Automatically after 24 hours Automatically after a programmable timeout (1-255 test mode intervals). Power failure occurs

Exits test mode; when power is restored, the meter's display is in normal mode.

Demand reset A demand reset can be performed one of three ways: • pressing the RESET button • issuing a command over the optical or remote ports • as a scheduled calendar event Regardless of how the demand was reset, the meter performs many different functions, including the following: • the present billing data is copied to the demand reset data area • the billing data’s present maximum demand is added to the cumulative demand, and then the billing data’s present maximum demand is reset to zero • the billing data’s dates and times of the maximum demands are reset to zero • the billing data’s present coincident values are reset to zero • all demand calculations are reset to zero and a new demand interval is started • previous interval demands are reset to zero • present interval demands are reset to zero • all average power factor calculations are restarted • pulse line cumulative counters are cleared • current conditions for certain errors or warnings are cleared

As a security feature, the meter records these values: • the cumulative number of demand resets (rolls over to zero after 255) • the cumulative number of manual demand resets (pressing the RESET button or issuing a command) • date and time of last demand reset • number of days since the last demand reset • the method of the most recent demand reset (for example, button press, procedure, or calendar) • if configured, the event log records every demand reset

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Demand reset lockout Through Elster meter support software, a demand reset lockout time can be defined. The demand reset lockout can remain in effect for up to 255 minutes after a demand reset (regardless of the method of demand reset). During the demand reset lockout, subsequent demand resets will be ignored by the meter. This prevents subsequent demand resets (for example, accidental or tamper-related demand reset presses). If a power failure occurs during the demand reset lockout period, the lockout is released upon power restoration.

Demand reset data area In all demand reset occurrences, the meter copies the present billing data and stores it in the demand reset data area. This data is referred to as the previous billing data because its general purpose is to preserve the data as one billing period ends and the next billing period begins. The meter stores only one copy of the previous billing data. The next demand reset overwrites whatever is currently stored as the previous billing data. Previous billing data is different from self reads, which can store multiple copies of the billing data. See “Self reads” on page 2-15 for more information.

Operating instructions

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Technical manual

4-1

Meter tools

4 Meter tools

System instrumentation System instrumentation is a collection of displayable items designed to assist in evaluating a service by providing real time analysis of the conditions present at the A1800 ALPHA installation. Instrumentation quantities should not be confused with billing quantities because they are intended for an entirely different purpose. System instrumentation quantities are measured instantaneously while billing quantities are measured and averaged over a number of minutes. Instrumentation quantities are generally provided on a per phase basis, while billing quantities represent a combination of all present phases. This can result in discrepancies between similar billing and instrumentation data, and this is to be expected. The instrumentation measurements are near instantaneous. Using Elster meter support software, instrumentation quantities may be placed in normal, alternate, or test mode display sequences. The alternate mode display sequence is recommended because it is generally not necessary for these quantities to be displayed at all times. Most instrumentation quantities are true root mean square (rms) measurements over an even number of line cycles, but others are compound quantities. Compound quantities require multiple measurements at slightly different times with the results calculated from these multiple measurements. Instrumentation quantities can also round or restrict the quantity to a desirable value under certain system conditions. See Table 4-1 for more information about how the instrumentation quantities are obtained.The quantities that are indicated by a footnote are updated about every second; the remaining quantities are updated about every 5 seconds.

Table 4-1. Description of system instrumentation quantities Instrumentation quantity

Description

Frequency1

Measured on line 1 voltage.

System kW

The signed sum of the kW measurement on each phase taken only moments apart

System kVA (arithmetic)

The signed sum of the kVA measurement on each phase taken only moments apart

System kvar (arithmetic)

Calculated using the following equation:

kvar  (system kVAarith ) 2 - (system kW) 2 System power factor (arithmetic)

System kW divided by system kVA (arithmetic)

System power factor angle (arithmetic)

The arccosine of system power factor (arithmetic)

1

Measured directly by meter engine

Phase kW and kVA

1

Phase kvar (vectorial)

Calculated using the following equation (where kVA and kW are measured simultaneously):

kvar  kVA 2 - kW 2 The result is then signed based on the kvar direction. System kvar (vectorial)

Sum of the per phase kvar (vectorial)

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Meter tools

Table 4-1. Description of system instrumentation quantities Instrumentation quantity System kVA (vectorial)

Description Calculated using the following equation:

kVAvect  system kW 2  (system kvarvect ) 2 System power factor (vectorial)

System kW divided by system kVA (vectorial)

System power factor angle (vectorial)

The arccosine of system power factor (vectorial)

Phase voltages and

currents1

True rms values measured by meter engine

Phase voltage angle relative to line 1 voltage1

Each voltage angle is measured relative to line 1 voltage zero crossings and rounded to 30°

Phase current angle relative to line 1 voltage

Each current angle is measured relative to line 1 voltage zero crossings

Phase power factor

Phase kW divided by phase kVA, both measured simultaneously. Phase power factor is set to 1.00 if phase current is less than the absolute minimum current (twice starting amps).

Phase power factor angle1

The power factor angle is the arccosine of the phase power factor

Phase 1st harmonic (fundamental) voltage magnitude

The per phase magnitude of the fundamental voltage

Phase 1st harmonic (fundamental) current magnitude

The per phase magnitude of the fundamental current

Phase 2nd harmonic voltage magnitude

The per phase magnitude of the 2nd harmonic voltage

Phase 2nd harmonic current magnitude

The per phase magnitude of the 2nd harmonic current

Phase 2nd harmonic voltage percentage

Per phase, the 2nd harmonic voltage magnitude divided by the fundamental voltage magnitude

Phase total harmonic current magnitude

Per phase, the square root of the sum of the 2nd - 15th harmonic currents squared. In other words:

THC 

i 15

 HCi

2

i 2

where HCi = ith harmonic current Phase total harmonic distortion percentage (voltage or current)

Calculated by using:

THD 

rms 2 - fundamental 2 fundamental

 100

where: rms represents an unfiltered rms phase voltage or current fundamental represents the fundamental rms phase voltage or current Per phase total demand distortion

Calculated by using: i 15

 HCi

TDD 

2

i2

Maximum amps

where HCi represents the ith harmonic current. 1 Updated

about every 1 second.

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Voltage, current, kW, kvar, and kVA instrumentation quantities have an error of less than ±0.25 %. Accuracy will diminish as the value of the quantity becomes smaller. The meter’s LCD can be programmed with Elster’s meter support software to display primary instrumentation values.

If the LCD remains on an instrumentation quantity while in alternate or test mode, the displayed instrumentation quantity updates once per second. See “* button” on page 3-5 for more information on locking the LCD on a desired quantity. The quantity identifier gives information about the quantity being displayed on the A1800 ALPHA meter LCD, as indicated in Table 4-2.

Table 4-2. System instrumentation quantity identifiers Quantity identifier

Description

L123

System instrumentation measurements

L1

Line 1 measurements

L2

Line 2 measurements

L3

Line 3 measurements

L1 H2-15

Line 1 total harmonic distortion

L2 H2-15

Line 2 total harmonic distortion

L3 H2-15

Line 3 total harmonic distortion

L1 H1

Line 1 1st harmonic

L2 H2

Line 2 1st harmonic

L3 H2

Line 3 1st harmonic

L1 H2

Line 1 2nd harmonic

L2 H2

Line 2 2nd harmonic

L3 H2

Line 3 2nd harmonic

L1 TDD

Line 1 total demand distortion

L2 TDD

Line 2 total demand distortion

L3 TDD

Line 3 total demand distortion

The display quantity will show a measurement and a unit of measure on the A1800 ALPHA meter LCD. See Figure 4-1 and Figure 4-2 for examples showing system instrumentation quantities. See Appendix B, “Display table,” for information about displayable items.

Figure 4-1. Instrumentation line 1 voltage +P

L1 L2 L3

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Figure 4-2. Instrumentation system kVA +P

L1 L2 L3

Immediately before displaying a system instrumentation quantity, the meter begins to measure that quantity. If the result of the instrumentation measurement is not immediately available, dashes (-) will be shown in the display quantity until the measurement is complete. See Figure 4-3 and Figure 4-4 for examples of system instrumentation display quantities while the measurement is in progress and when a result is available.

Figure 4-3. Instrumentation line 2 current in progress +P

L1 L2 L3

Figure 4-4. Instrumentation line 2 current measurement (secondary) +P

L1 L2 L3

Figure 4-5. Instrumentation line 2 current measurement (primary) +P

L1 L2 L3

If an A1800 ALPHA meter is programmed to display a system measurement quantity for a phase that does not exist (for example, Line 2 on a two-element meter), then that display quantity will be skipped automatically. This allows different meter types to be programmed with similar configurations using Elster meter support software.

Meter tools

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System service tests System service tests can be performed to determine the validity of the electrical service that the A1800 ALPHA meter is metering. The system service tests consist of a service voltage test and a service current test.

Service voltage test The service voltage test is intended to assist in identifying the following: • incorrectly wired or misapplied voltage transformers • open or missing line fuses The following are validated by this test: • phase voltages • phase voltage angles • phase rotation The meter measures each phase voltage and phase voltage angle and attempts to match the measurements to a stored list of valid services. • If the service voltage test is successful, the validated service is shown on the meter’s LCD and the meter will continue to the next display quantity in the sequence. • If the test is not successful, a warning is set. Also, the LCD will indicate a service error by displaying SE plus a code on the LCD. See “System service error codes” on page 410 for more information about system service error codes. The following conditions can cause the service voltage test to fail: • phase voltage angles not within ±15° of the expected service phase angles • phase voltage magnitudes not within the tolerance of the nominal service voltages programmed into the meter with Elster meter support software

System service locking. Once a service voltage test has detected a valid service, it can be locked into the A1800 ALPHA meter memory. A locked valid service is used as a basis for future system service tests and TRueQ tests. The following information will be stored in the meter when the service is locked: • service type identification • nominal service voltage • voltage phase rotation • service voltage and current limits • voltage sag detection threshold The A1800 ALPHA meter can lock a valid service in either of these ways: • smart autolock • manual lock (on default) To indicate that a service voltage test is complete, the LCD displays the following (an example is shown in Figure 4-6): • phase rotation (for example, L1-2-3 or L3-2-1) • voltage magnitude (for example, 120 or 240) • service type showing the number of wires and the service type, for example: • 1L is a single phase service • 3 is a 3-wire delta service • 4Y is a 4-wire wye service

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Figure 4-6. Sample service voltage test result +P

L1 L2 L3

The voltage magnitude and service type are surrounded by brackets to indicate that the service is locked (see Figure 4-7).

Figure 4-7. Sample display of locked service voltage +P

L1 L2 L3

Smart autolock. When smart autolock is enabled through Elster meter support software, the A1800 ALPHA meter will attempt to lock the service automatically once it is determined to be valid. Both the voltage magnitude and phase angle of the service are compared to a table of valid relationships stored within the meter memory. The meter accepts the service that most closely matches one of the stored values in the A1800 ALPHA meter. The A1800 ALPHA meter periodically checks the service. Under certain conditions, the smart autolocked service may lock on a different service. This is useful because the meter may have been moved to a new service. The service voltage test will be performed and the service may be changed in response to the following events: • power up • exit of test mode • after a data-altering communication session If a new, valid service is detected, the meter locks on the new service. If a valid service cannot be detected, the meter responds in the following manner: • the meter remains locked on the last known valid service • the LCD displays an error code Manual lock. When configured through Elster meter support software for manual lock, the A1800 ALPHA meter will detect and evaluate the service in the same manner as it does when autolock is enabled. The identified service information will also be shown on the LCD; however, the RESET button must be pressed in order to lock the detected service (see “Using to lock service” on page 3-5). When the service type has been detected, the phase rotation, voltage magnitude, and the service type will be displayed on the LCD. If the RESET button is not pressed to accept the service, the LCD will alternate between L1-2-3 ------ and the detected service information until the service has been manually locked.

Once manually locked, the service never unlocks automatically. To move the A1800 ALPHA meter to a new installation with a different type of service, the service must be unlocked using Elster meter support software. The new service type can then be detected and manually locked.

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Initiating service voltage tests. When enabled, the service voltage test is initiated at any of the following times: • after power up, a data-altering communications session, or exiting test mode • at midnight Service voltage tests can also be initiated at any of these times, depending on meter configuration: • as a display item • as a TRueQ test (for meters with TRueQ capabilities) The behavior of the service voltage test depends on these factors: • the event that initiates the service voltage test • the state of the service lock After power up, data-altering communications session, or exiting test mode. The following table explains meter behavior when the service voltage test is performed after any of the following: • power is applied to the meter • data-altering communications session • exiting test mode

Smart autolock

Manual lock Current state is locked

Manual lock Current state is unlocked

1 The meter initiates the service voltage test. 2 The meter attempts to detect a valid service. • If a valid service is detected, the meter automatically locks on the detected service. The LCD displays the locked valid service. • If a valid service cannot be found, the meter displays SE 555000. The meter restarts the service voltage test in diagnostic mode (see “Restarting the service voltage test in diagnostic mode” on page 4-9). However, the meter remains locked on the last valid service until a new valid service is detected.

1 The meter initiates the service voltage test. 2 The phase indicator voltage threshold levels are based on the currently locked service. 3 The meter attempts to match the service. • If the service matches the presently locked service, then the LCD displays the locked valid service. • If the service does not match the presently locked service, then the LCD displays the service test error. The meter restarts the service voltage test in diagnostic mode (see “Restarting the service voltage test in diagnostic mode” on page 4-9).

1 The meter initiates the service voltage test. 2 The phase indicator voltage thresholds are set at the default values. 3 The meter attempts to detect a valid service. • If a valid service is found, the LCD displays the data for the service it detected. • If a valid service is not found, the LCD displays SE 555000. The meter restarts the service voltage test until a valid service is found. 4 While a valid service is displayed, the user can manually lock the service. • The user presses the RESET button to lock the service. The LCD displays the locked service. • If the user does not lock the service, the meter returns to the service test until a valid service is found and locked.

If the service voltage test is interrupted (for example, the button is pressed or there is a communications session), the meter restarts the service voltage test after handling the interruption.

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At midnight. If the service is locked, the meter checks the service at midnight. The meter always does the following when the service voltage test is run at midnight: Smart autolock

Manual lock Current state is locked

1 The meter initiates the service test. 2 The phase indicator voltage threshold levels are based on the currently locked service. 3 The meter attempts to match the service. • If the service matches the presently locked service, then the LCD displays the locked valid service. • If the service does not match the presently locked service, then the LCD displays SE 555000. The meter restarts the service voltage test in diagnostic mode (see “Restarting the service voltage test in diagnostic mode” on page 4-9). However, the lock remains on the last valid service until a new valid service is detected.

1 The meter initiates the service test. 2 The phase indicator voltage threshold levels are based on the currently locked service. 3 The meter attempts to match the service. • If the service matches the presently locked service, then the LCD displays the locked valid service. • If the service does not match the presently locked service, then the LCD displays a service test error. The meter restarts the service voltage test in diagnostic mode (see “Restarting the service voltage test in diagnostic mode” on page 4-9). However, the lock remains on the last valid service until a new valid service is detected.

If the service test is interrupted (for example, the button is pressed or there is a communications session), the meter restarts the service test after handling the interruption. If the service has not been locked, the test is not performed and the LCD displays SE 555000. As a display item in a display sequence. Using Elster meter support software, the service voltage test can be programmed as a displayable quantity in any display sequence. The service test is initiated when the service test quantity is displayed on the LCD.

Smart autolock 1 The meter initiates the service test. 2 The meter attempts to match the service. • If the service detected matches the presently locked service, then the LCD displays the locked valid service. • If the service does not match the presently locked service, then the LCD displays a service test error. 3 After the LCD displays the locked valid service or the service test error, the LCD continues to the next item in the display sequence.

Manual lock Current state is locked The service test is performed as the autolock.

Service locking disabled 1 The meter initiates the service test. • If a valid service is detected, the LCD displays the valid service. • If a valid service cannot be found, the meter displays SE 555000. 2 After the LCD displays the valid service or the service test error, the LCD continues to the next item in the display sequence.

As a TRueQ test. When the service voltage test is programmed as a TRueQ test, the service test is performed only if the service is locked. TRueQ tests are available only on meters with TRueQ capabilities. See “Service voltage test” on page 4-5 for more information.

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Restarting the service voltage test in diagnostic mode. Depending on how the service voltage test was started, the test restarts in diagnostic mode if the test fails. The A1800 ALPHA meter uses the diagnostic mode if the service voltage test was started in these ways: • after power up, data-altering communications session, or exiting test mode • at midnight The diagnostic mode cycles through performing the service voltage test and displaying information about the service that may be useful in determining why the test failed, as listed below: 1. Perform the service voltage test. 2. Display line 1 voltage. 3. Perform the service voltage test. 4. Display line 2 voltage. 5. Perform service voltage test. 6. Display line 3 voltage. 7. Perform service voltage test. 8. Display line 2 voltage angle. 9. Perform service voltage test. 10. Display line 3 voltage angle. If at any point a valid service is found and locked, the meter displays the locked service on the LCD and continues to the next item in the display sequence. Otherwise, the cycle restarts at step 1.

Service current test The service current test validates system currents and is intended to assist in identifying the following: • incorrectly wired or misapplied current transformers • open or missing load-side fuses If the service current test is successful, L1-2-3 OK is shown on the A1800 ALPHA meter LCD. The meter will continue to the next item in the display sequence. See Figure 4-8 for an example of a successful service current test.

Figure 4-8. Service current test successful completion +P

L1 L2 L3

If the test is not successful, a warning is set. Also, the LCD will indicate a service error by displaying SE and a code, an example of which is shown in Figure 4-9. See “System service error codes” on page 4-10 for more information. The following conditions can cause the service current test to fail: • current remains on one phase while no current is on any other phase • current on any single phase is below the programmed low current limit • current on any phase is greater than the programmed absolute maximum • current is negative on any phase (reverse power) • power factor on any phase is less than the limit set for leading or lagging power factor

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If all phases are below the absolute minimum current threshold, the low and missing current failure will not be reported. It is assumed that this is a valid, no-load condition. In this case, the low and zero current warnings will display if the condition exists.

Figure 4-9. Service current test error

L1 L2 L3

+P

Initiating the service current test. The service current test can be initiated in any of the following ways: • the service current test may be placed in any display sequence. The service current test will be performed when the quantity is displayed in the display sequence. • the service current test may be included in the TRueQ tests if the A1800 ALPHA meter is equipped with this feature. The results of the TRueQ test will not be seen on the LCD. See “TRueQ monitoring” on page 4-12 for more details on TRueQ. • the service current test may be programmed to be performed after successful service voltage tests that perform automatically (but not as part of a display list) If the A1800 ALPHA meter does not have a locked service, then the system service current test will be skipped regardless of how the test is initiated. Parameters regarding the system service current tests can be changed without requiring the meter to be unlocked and then relocked or requiring the meter to be reset. These parameters (configurable with Elster meter support software) include the following: • enable or disable per phase reverse power tests • absolute minimum current • per phase low currents • absolute maximum current • per phase leading and lagging power factor limits

System service error codes When SE is shown on the LCD, the displayed quantity is a numeric code representing a system service error. This indicates that there is a service problem detected by the A1800 ALPHA meter. Table 4-3 and Table 4-4 show all possible system service error codes.

Table 4-3. System service voltage test error codes Error code Service error condition (SE)

Voltage phase L1

L2

L3

Low nominal voltage on line 1

1

0

0

0

0

0

Low nominal voltage on line 2

0

1

0

0

0

0

Low nominal voltage on line 3

0

0

1

0

0

0

High nominal voltage on line 1

2

0

0

0

0

0

High nominal voltage on line 2

0

2

0

0

0

0

High nominal voltage on line 3

0

0

2

0

0

0

Unrecognized service

5

5

5

0

0

0

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Table 4-3. System service voltage test error codes Error code Service error condition (SE)

Voltage phase L1

L2

L3

Bad phase angle on line 1

8

0

0

0

0

0

Bad phase angle on line 2

0

8

0

0

0

0

Bad phase angle on line 3

0

0

8

0

0

0

Low voltage & bad phase angle on line 1

9

0

0

0

0

0

Low voltage & bad phase angle on line 2

0

9

0

0

0

0

Low voltage & bad phase angle on line 3

0

0

9

0

0

0

High voltage & bad phase angle on line 1

A

0

0

0

0

0

High voltage & bad phase angle on line 2

0

A

0

0

0

0

High voltage & bad phase angle on line 3

0

0

A

0

0

0

Table 4-4. System service current test error codes Error code Service error condition (SE)

Current phase L1

L2

L3

Missing line 1 current

0

0

0

1

0

0

Missing line 2 current

0

0

0

0

1

0

Missing line 3 current

0

0

0

0

0

1

Low line 1 current

0

0

0

2

0

0

Low line 2 current

0

0

0

0

2

0

Low line 3 current

0

0

0

0

0

2

Missing and low current on line 1

0

0

0

3

0

0

Missing and low current on line 2

0

0

0

0

3

0

Missing and low current on line 3

0

0

0

0

0

3

Low PF on line 1

0

0

0

4

0

0

Low PF on line 2

0

0

0

0

4

0

Low PF on line 3

0

0

0

0

0

4

Reverse power on line 1

0

0

0

5

0

0

Reverse power on line 2

0

0

0

0

5

0

Reverse power on line 3

0

0

0

0

0

5

Low PF & low current on line 1

0

0

0

6

0

0

Low PF & low current on line 2

0

0

0

0

6

0

Low PF & low current on line 3

0

0

0

0

0

6

Reverse power & low current on line 1

0

0

0

7

0

0

Reverse power & low current on line 2

0

0

0

0

7

0

Reverse power & low current on line 3

0

0

0

0

0

7

Excess current on line 1 current

0

0

0

8

0

0

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Table 4-4. System service current test error codes Error code Service error condition (SE)

Current phase L1

L2

L3

Excess current on line 2 current

0

0

0

0

8

0

Excess current on line 3 current

0

0

0

0

0

8

Excess current & low PF on line 1

0

0

0

C

0

0

Excess current & low PF on line 2

0

0

0

0

C

0

Excess current & low PF on line 3

0

0

0

0

0

C

Excess current & reverse power on line 1

0

0

0

d

0

0

Excess current & reverse power on line 2

0

0

0

0

d

0

Excess current & reverse power on line 3

0

0

0

0

0

d

If service current errors are present on more than one phase, a single error code is displayed to represent all detected errors. For example, SE 000308 indicates missing current on line 1 and excess current on line 3.

TRueQ monitoring All A1800 ALPHA meters are equipped with the tamper restraint and quality (TRueQ) monitoring features that can monitor circuit parameters on a cyclic basis, 24 hours a day throughout the billing period. TRueQ tests may be turned on or off through Elster meter support software. TRueQ tests will recognize any deviation beyond the thresholds. When shipped, the meter is stored with default values for the thresholds. Using Elster meter support software, these thresholds can be edited. Most TRueQ tests are performed individually so that circuit parameters are not being monitored continuously. Each subsequent test will begin immediately after the previous one has ended. The momentary voltage sag test, however, uses the per phase rms voltage calculation which is part of the voltage sensing process within the meter engine. The rms voltages are calculated once every 2 line cycles, so the momentary voltage sag test is capable of recognizing any phase voltage deviation that remains below a specified threshold for as few as 2 line cycles.

TRueQ timing In addition to defining thresholds for each test, a minimum time may also be defined. Once the monitored parameter falls outside the threshold and remains there longer than the minimum time, the failure will be stored and the cumulative count will increment by one. A cumulative timer will also be activated and will run for as long as the event is detected. The cumulative count and timer for each test can be retrieved through Elster meter support software.

TRueQ display items The meter can be programmed to display a warning code on the LCD when a TRueQ test fails. Warning codes can be enabled or disabled on a test-by-test basis using Elster meter support software.

TRueQ and relays If one or more relays are installed in the A1800 ALPHA meter, the relay can be programmed to close when the failure occurs. When a failure condition is no long present, the warning code will automatically clear; and any relays will open.

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TRueQ log All A1800 ALPHA meters record TRueQ events in the TRueQ log. Meters with TOU capability will also record the date and time of any TRueQ failure in the TRueQ log. See “TRueQ log” on page 2-17 for more information about the TRueQ log.

A qualified TRueQ failure causes the W2 020000 warning code to be shown on the LCD. See “W2 020000: TRueQ test failure warning” on page 6-7 for more details.

Voltage sags A momentary sag in voltage can reset process control equipment and computer systems. The momentary voltage sag monitor watches for decreases in voltage that last for a measured number of cycles. This monitor can detect any voltage decrease that falls below a programmed threshold for as few as 2 line cycles. Threshold and duration are defined using Elster meter support software. The voltage sag threshold is defined as a percentage of the lowest nominal per phase voltage and recommended to be in the range of 60 % to 99.9 %. A sag is defined as a drop in phase voltage below the threshold for a duration greater than the sag minimum time and less than the sag maximum time. If the condition exceeds the maximum sag time, it will not be considered a sag event. The sag times can be configured to a resolution of 8 milliseconds. The minimum time range can be from 32 milliseconds to 2.04 seconds. The maximum time range can be a time up to 546 seconds. The potential indicators on the A1800 ALPHA meter LCD will indicate when voltage is below the sag level threshold. When a phase voltage drops below the voltage sag threshold, the corresponding potential indicator will blink.

Voltage sag counter and timer. Each phase voltage has a voltage sag counter and timer associated with it. Each counter can accumulate up to 65,535 before rolling over to zero. Each cumulative timer can record time for 414 days. A voltage sag event is only counted if the voltage remains below the voltage sag threshold for more than the minimum time and less than the maximum time. A voltage that remains below the voltage sag threshold for longer than the maximum time is considered to be a low voltage condition, and it is not counted by the momentary voltage sag monitor. The counter and timer for each phase are maintained within the A1800 ALPHA meter memory. These values can be reported and can be reset through Elster meter support software. See “Voltage sag log” on page 2-17 for more information about the log of momentary voltage sag events.

TRueQ tests TRueQ tests do not interfere with any meter functions related to energy measurement. These tests run separately from the metering functions. Table 4-5 shows the available tests for TRueQ, along with their description.

Table 4-5. TRueQ tests TRueQ

Test name

Configuration based upon

Test 1

Service voltage test

System service voltage test thresholds

Test 2

Low voltage test

A specified low voltage threshold

Test 3

High voltage test

A specified high voltage threshold

Test 4

Reverse power test & PF

Service current test thresholds

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Table 4-5. TRueQ tests TRueQ

Test name

Configuration based upon

Test 5

Low current test

Service current test thresholds

Test 6

Power factor (PF)

A specified threshold for leading and lagging

Test 7

Second harmonic current test

A specified current threshold

Test 8

% Total harmonic distortion (THD) current

Specified THD percentage

Test 9

% Total harmonic distortion voltage

Specified THD percentage

Test 10

Voltage imbalance

Minimum high voltage threshold and imbalance threshold

Test 11

Current imbalance

Minimum high current threshold and imbalance threshold

Test 12

% total demand distortion (TDD)

Specified TDD percentage

The following TRueQ tests are available on all A1800 ALPHA meters programmed with Metercat release 2.3 or later:

Table 4-6. Enhanced TRueQ tests TRueQ

Test name

Configuration based upon

Test 13

Low voltage (Line 1)

Specified low voltage threshold

Test 14

Low voltage (Line 2)

Specified low voltage threshold

Test 15

Low voltage (Line 3)

Specified low voltage threshold

Test 16

High voltage (Line 1)

Specified high voltage threshold

Test 17

High voltage (Line 2)

Specified high voltage threshold

Test 18

High voltage (Line 3)

Specified high voltage threshold

Test 19

Low voltage and current present (Line 1)

Specified thresholds for low voltage and high current

Test 20

Low voltage and current present (Line 2)

Specified thresholds for low voltage and high current

Test 21

Low voltage and current present (Line 3)

Specified thresholds for low voltage and high current

Test 22

Current missing (Line 1)

Specified thresholds for voltage and current

Test 23

Current missing (Line 2)

Specified thresholds for voltage and current

Test 24

Current missing (Line 3)

Specified thresholds for voltage and current

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During the low current and reverse power and power factor tests, there will be no event detected if all measured line currents drop below the absolute minimum current threshold. An event will be detected if any single phase or two phases drop below the programmed threshold for the qualification time. This eliminates false detection when the load is dramatically reduced or turned off. TRueQ event counters and timers. Each TRueQ test has its own event counter associated with it. Each counter can accumulate to a maximum of 65,535 before rolling over to zero. For each TRueQ test, an event occurring on one phase or across multiple phases is counted as a single event. The momentary voltage sag monitor, however, records counters and timers for each phase. See “Voltage sag counter and timer” on page 4-13 for details. The cumulative timer for each monitor can record time over 20 years. To increase the cumulative counter or timer, the TRueQ test must fail for a period greater than the qualification time. The cumulative timer includes the qualification time for the test (see Figure 4-10). The qualification time is defined as zero to 60 minutes where zero causes the event to be recognized immediately as it is detected.

Figure 4-10. Total TRueQ test failure time TRueQ failure

Qualification time

Remaining time

Time recorded by meter

An event ends when the condition is no longer present. If an event occurs but does not last for the qualification time, then neither the counter nor timer will reflect the event having occurred. The counter and timer for each monitor are maintained within the A1800 ALPHA meter memory. These values can be reported and can be reset through Elster meter support software.

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Test Formula

1

Name

Meter tools

Service voltage test

(VL1 or VL2 or VL3 )  Specified low voltage threshold

Variable

Based on service test thresholds

Default value

Based on service test thresholds

Configuration based on

System service voltage test thresholds

Description

This test continually monitors service voltage. Voltage fluctuations outside the programmed limits are detected and can indicate one of the following: • improper voltage transformer operation • inappropriate transformer tap settings • equipment failure All voltage magnitudes and phase angles must fall within the thresholds for the locked service. The thresholds are defined by the service voltage configuration. Programming the service voltage as a TRueQ test allows it to continually run and create a log of the results.

Stored value

None

Test Formula

2

Name

Low voltage test

(VL1 or VL2 or VL3 )  Specified low voltage threshold

Variable

0 % to 99.9 %

Default value

94.0 %

Configuration based on

A specified low voltage threshold

Description

This test checks the per phase voltages for values that fall below a specified limit. Each phase threshold can be set individually and can be set at a value higher or lower than the limits selected for the service voltage test. This allows a more thorough study of the voltage changes. The threshold is defined as a percentage of the expected per phase nominal voltage (recommended to be in the range of 60 % to 99.9 %). The percentage for each phase can be individually defined. The test fails if any phase voltage exceeds the threshold.

Stored value

Line 1 voltage (even if line 2 or line 3 causes the test to fail)

Test Formula

3

Name

High voltage test

(VL1 or VL2 or VL3 )  Specified high voltage threshold

Variable

100.1 % to 200.0 %

Default value

106.0 %

Configuration based on

A specified high voltage threshold

Description

This test checks the per phase voltages for values that exceed a specific limit. The threshold values can be set at a value higher or lower than the limits selected for the service voltage test. This allows a more thorough study of the voltage changes. The threshold is defined as a percentage of the expected per phase nominal value. The percentage for each phase can be individually defined. the test fails if any phase voltage exceeds the threshold.

Stored value

Line 1 voltage (even if line 2 or line 3 causes the test to fail)

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Test

4

Name

Meter tools

Reverse power test and power factor test

Formula Variable

Based on service test thresholds

Default value

Based on service test thresholds

Configuration based on

Service current test thresholds

Description

This test recognizes any condition where the current transformer may be wired incorrectly or where may tampering may have occurred. The power factor (PF) threshold in this test is typically set to a very low value to detect only abnormal conditions. The PF thresholds are defined with the system service current test definition. Using the service current test definition permits independent PF settings to be set for each service type. Each service type can have individual leading and lagging thresholds. Testing for reverse power can only be enabled or disabled for all phases simultaneously.

Stored value

None

Test Formula

5

Name

Low current test

(I L1 or I L2 or I L3 )  Specified low current threshold

Variable

Based on service test thresholds

Default value

Based on service test thresholds

Configuration based on

Service current test thresholds

Description

This test checks the service current for values that fall below a specified limit. This test will check for erroneous operation or failure of a current transformer and can detect signs of meter tampering. If all phase currents fall below the limit on an initial no-load or test condition, then no warning or indication will be provided. A warning will be issued when one or more phase currents fall below the threshold value for the qualification time while the remaining phase currents stay above the limits. This threshold is defined as a percentage of the A1800 ALPHA meter Class ampere rating from the system service test definition. This percentage is applied on a per phase basis. The thresholds are defined by the service current configuration.

Stored value

None

Test

6

Name

Power factor test

Formula Variable

0.00 to 1.00 for minimum leading power factor (per phase) 0.00 to 1.00 for minimum lagging power factor (per phase)

Default value

0.20 for minimum leading power factor (per phase) 0.20 for minimum lagging power factor (per phase)

Configuration based on

Specified thresholds for leading and lagging power factors

Description

This test checks the power factor for any deviation beyond the programmed threshold. This monitor may be used alone to monitor rate-based conditions or in conjunction with the reverse power test and PF monitor to provide a more thorough analysis of power factor fluctuations. The leading and lagging thresholds are individually defined for each phase. These settings may be different than those defined in the service current configuration.

Stored value

None

Technical manual

Test Formula

4-18

7

Name

Meter tools

Second harmonic current test

2 nd harmonic current  2 nd harmonic current magnitue threshold

Variable

0.00 % to 100.00 %

Default value

Transformer-rated: 2.50 % of Class amps (per phase) Self-contained: 1.25 % of Class amps (per phase)

Configuration based on

A specified current threshold

Description

This test checks for the presence of second harmonic current. The second harmonic current may be created by equipment on the line or may indicate the presence of DC on the system. The threshold is defined as values in AC amperes according to the meter class. The test fails if any phase exceeds the threshold. To prevent the monitor from creating a false alarm from legitimate second harmonic current sources, the recommended qualification time is 15 minutes.

Stored value

Line 1 second harmonic magnitude (even if line 2 or line 3 causes the test to fail)

Test

8

Name

% total harmonic distortion current test

Formula Variable

0.0 % to 99.9 % of the fundamental current

Default value

30.0 % of the fundamental current (per phase)

Configuration based on

A specified THD percentage

Description

As the load on electrical systems becomes more saturated with electronic control devices (such as computers and communications systems), there is a growing concern with the harmonics that these devices can contribute to the electrical system. Total harmonic distortion, expressed as a percentage of the fundamental, is measurement of the power quality of the circuit under these conditions. The total harmonic distortion current test measures the per phase THD current and can alert the utility to conditions that may be harmful or dangerous to the system or other equipment. The threshold is defined as a percentage of the fundamental. The thresholds are defined by the service voltage configuration. The test phases if any phase exceeds the threshold.

Stored value

Line 1 THD (even if line 2 or line 3 causes the test to fail)

Test

9

Name

% total harmonic distortion voltage test

Formula Variable

00.0% to 99.9 % of the fundamental voltage

Default value

30.0 % of the fundamental voltage (per phase)

Configuration based on

A specified THD percentage

Description

As the load on electrical systems becomes more saturated with electronic control devices (such as computers and communications systems), there is a growing concern with the harmonics that these devices can contribute to the electrical system. Total harmonic distortion, expressed as a percentage of the fundamental, is a measurement of the power quality of the circuit under these conditions. The total harmonic distortion voltage test measures per phase THD voltage and can alert the utility to conditions that may be harmful or dangerous to the system or other equipment. The threshold is defined as a percentage of the fundamental. The thresholds are defined by the service voltage configuration. The test fails if any phase exceeds the threshold.

Stored value

Line 1 THD voltage (even if line 2 or line 3 causes the test to fail)

Technical manual

Test Formula

4-19

10

Name

Meter tools

Voltage imbalance test

(VL1 or VL2 or VL3 )  minimum voltage threshold and lowest per phase voltage  imbalance threshold highest per phase voltage

Variable

Minimum voltage threshold: 0.00 % to 100.00 % of the nominal Imbalance threshold: 0.00 % to 100.00 %

Default value

Minimum voltage threshold: 80.00 % of the nominal Imbalance threshold: 90.00 %

Configuration based on

Minimum high voltage threshold and imbalance threshold

Description

This test checks for an imbalance between phase voltages. The test first measures and normalizes each per phase voltage. The voltages are normalized to account for different per phase nominal voltages as specified by the locked service. To qualify as a failure, both the following conditions must exist: The highest normalized per phase voltage must be greater than the minimum voltage threshold The ratio of the lowest normalized per phase voltage to the highest (low/high) must be less than the imbalance threshold Using Elster meter support software, the minimum voltage threshold is defined as a percentage of the nominal voltage, and the imbalance threshold is a fraction (0 to 1).

Stored value

None

Test Formula

11

Name

Current imbalance test

(I L1 or I L2 or I L3 )  minimum current threshold and lowest per phase current  imbalance threshold highest per phase current

Variable

Minimum current threshold: 0.00 % to 100.00 % of Class amperes Imbalance threshold: 0.00 % to 100.00 %

Default value

Minimum current threshold: 1.25 % of the Class amperes Imbalance threshold: 5.00 %

Configuration based on

Minimum high current threshold and imbalance threshold

Description

This test checks for an imbalance between phase currents. To qualify as a failure, both the following must exist: • The highest per phase current must be greater than the minimum current threshold • The ratio between the lowest per phase current to the highest (low/high) must be less than the imbalance threshold Using Elster meter support software, the minimum current threshold is defined as a percentage of Class amperes, and the imbalance threshold is a fraction (0 to 1).

Stored value

None

Technical manual

Test Formula

4-20

12

Name

Meter tools

Total demand distortion

TDD  threshold

Variable

0.00 % to 100.00 % of the class amperes (per phase)

Default value

10.00 % of the Class amperes

Configuration based on

Specified TDD threshold

Description

This test checks the per phase total demand distortion (TDD) and makes sure that the TDD is less than the threshold. TDD measures the harmonic current distortion on each phase in percentage of the maximum demand load current (Class amperes).

Stored value

Line 1 % TDD (even if it is line 2 or line 3 that causes the test to fail)

Test Formula

13

Name

Low voltage (Line 1)

VL 1  Specified voltage threshold

Variable

0.0 % to 99.9 % of nominal

Default value

60.0 %

Configuration based on

A specified voltage threshold

Description

This test checks Line 1 voltage for values that fall below a specified limit. The threshold is defined as a percentage of the expected Line 1 nominal voltage. The test fails if Line 1 voltage falls below the voltage threshold.

Stored value

Line 1 voltage

Test Formula

14

Name

Low voltage (Line 2)

VL 2  Specified voltage threshold

Variable

0.0 % to 99.9 % of nominal

Default value

60.0 %

Configuration based on

A specified voltage threshold

Description

This test checks Line 2 voltage for values that fall below a specified limit. The threshold is defined as a percentage of the expected Line 2 nominal voltage. The test fails if Line 2 voltage falls below the voltage threshold.

Stored value

Line 2 voltage

Technical manual

Test Formula

4-21

15

Name

Meter tools

Low voltage (Line 3)

VL 3  Specified voltage threshold

Variable

0.0 % to 99.9 % of nominal

Default value

60.0 %

Configuration based on

A specified voltage threshold

Description

This test checks Line 3 voltage for values that fall below a specified limit. The threshold is defined as a percentage of the expected Line 3 nominal voltage. The test fails if Line 3 voltage falls below the voltage threshold.

Stored value

Line 3 voltage

Test Formula

16

Name

High voltage (Line 1)

VL 1  Specified voltage threshold

Variable

100.1 % to 200.0 % of nominal

Default value

115.0 %

Configuration based on

A specified voltage threshold

Description

This test checks Line 1 voltage for values that exceed a specified limit. The threshold is defined as a percentage of the expected Line 1 nominal voltage. The test fails if Line 1 voltage exceeds the voltage threshold.

Stored value

Line 1 voltage

Test Formula

17

Name

High voltage (Line 2)

VL 2  Specified voltage threshold

Variable

100.1 % to 200.0 % of nominal

Default value

115.0 %

Configuration based on

A specified voltage threshold

Description

This test checks Line 2 voltage for values that exceed a specified limit. The threshold is defined as a percentage of the expected Line 2 nominal voltage. The test fails if Line 2 voltage exceeds the voltage threshold.

Stored value

Line 2 voltage

Technical manual

Test Formula

4-22

18

Name

Meter tools

High voltage (Line 3)

VL 3  Specified voltage threshold

Variable

100.1 % to 200.0 % of nominal

Default value

115.0 %

Configuration based on

A specified voltage threshold

Description

This test checks Line 3 voltage for values that exceed a specified limit. The threshold is defined as a percentage of the expected Line 3 nominal voltage. The test fails if Line 3 voltage exceeds the voltage threshold.

Stored value

Line 3 voltage

Test Formula

19

Name

Low voltage and current present (Line 1)

VL1  Specified voltage threshold and I L1  Specified high voltage threshold

Variable

0.0 % to 99.9 % of nominal for Line 1 voltage 0.0003 to 1000.0000 amperes for Line 1 current

Default value

78.0 % for voltage threshold 0.0015 amps for current threshold

Configuration based on

Specified thresholds for voltage and current

Description

This test checks voltage and current on Line 1 to detect possible theft or VT problems on Line 1. This test fails if the following conditions are present: • Current on Line 1 is greater than a specified current threshold, and • Voltage on Line 1 is less than a specified voltage threshold

Stored value

Line 1 voltage

Test Formula

20

Name

Low voltage and current present (Line 2)

VL2  Specified voltage threshold and I L2  Specified high voltage threshold

Variable

0.0 % to 99.9 % of nominal for Line 2 voltage 0.0003 to 1000.0000 amperes for Line 2 current

Default value

78.0 % for voltage threshold 0.0015 amps for current threshold

Configuration based on

Specified thresholds for voltage and current

Description

This test checks voltage and current on Line 2 to detect possible theft or VT problems on Line 2. This test fails if the following conditions are present: • Current on Line 2 is greater than a specified current threshold, and • Voltage on Line 2 is less than a specified voltage threshold

Stored value

Line 2 voltage

Technical manual

Test Formula

4-23

21

Name

Meter tools

Low voltage and current present (Line 3)

VL3  Specified voltage threshold and I L3  Specified high current threshold

Variable

0.0 % to 99.9 % of nominal for Line 3 voltage 0.0003 to 1000.0000 amperes for Line 3 current

Default value

78.0 % for voltage threshold 0.0015 amps for current threshold

Configuration based on

Specified thresholds for voltage and current

Description

This test checks voltage and current on Line 3 to detect possible theft or VT problems on Line 3. This test fails if the following conditions are present: • Current on Line 3 is greater than a specified current threshold, and • Voltage on Line 3 is less than a specified voltage threshold

Stored value

Line 3 voltage

Test Formula

22

Name

Current missing (Line 1)

(VL1 or VL2 or VL3 )  specified voltage threshold and I L1  specified current threshold and (I L2 or I L3 )  specified current threshold

Variable

5.0 % to 100.0 % of nominal for Line 1 voltage threshold 5.0 % to 100.0 % of nominal for Line 2 voltage threshold 5.0 % to 100.0 % of nominal for Line 3 voltage threshold 0.0003 A to 1000.0000 A for Line 1 current threshold 0.0010 A to 1000.0000 A for Line 2 current threshold 0.0010 A to 1000.000 A for Line 3 current threshold

Default value

60.0 % of nominal for Line 1 voltage threshold 60.0 % of nominal for Line 2 voltage threshold 60.0 % of nominal for Line 3 voltage threshold 0.0015 A for Line 1 current threshold 0.0750 A for Line 2 current threshold 0.0750 A for Line 3 current threshold

Configuration based on

Specified thresholds for voltage and current

Description

This test checks voltage and current on all phases to help detect possible theft or CT problems on Line 1. This test fails if the following conditions are present: • Voltage is present on any phase, and • Current is at or above a specified threshold on Line 2 or Line 3, and • Current is below a specified threshold on LIne 1

Stored value

Line 1 current

Technical manual

Test Formula

4-24

23

Name

Meter tools

Current missing (Line 2)

(VL1 or VL2 or VL3 )  specified voltage threshold and I L2  specified current threshold and (I L1 or I L3 )  specified current threshold

Variable

5.0 % to 100.0 % of nominal for Line 1 voltage threshold 5.0 % to 100.0 % of nominal for Line 2 voltage threshold 5.0 % to 100.0 % of nominal for Line 3 voltage threshold 0.0010 A to 1000.0000 A for Line 1 current threshold 0.0003 A to 1000.0000 A for Line 2 current threshold 0.0010 A to 1000.000 A for Line 3 current threshold

Default value

60.0 % of nominal for Line 1 voltage threshold 60.0 % of nominal for Line 2 voltage threshold 60.0 % of nominal for Line 3 voltage threshold 0.0750 A for Line 1 current threshold 0.0015 A for Line 2 current threshold 0.0750 A for Line 3 current threshold

Configuration based on

Specified thresholds for voltage and current

Description

This test checks voltage and current on all phases to help detect possible theft or CT problems on Line 2. This test fails if the following conditions are present: • Voltage is present on any phase, and • Current is at or above a specified threshold on Line 1 or Line 3, and • Current is below a specified threshold on LIne 2

Stored value

Line 2 current

Technical manual

4-25

Test

24

Formula

Name

Meter tools

Current missing (Line 3)

(VL1 or VL2 or VL3 )  specified voltage threshold and I L3  specified current threshold and (I L1 or I L2 )  specified current threshold

Variable

5.0 % to 100.0 % of nominal for Line 1 voltage threshold 5.0 % to 100.0 % of nominal for Line 2 voltage threshold 5.0 % to 100.0 % of nominal for Line 3 voltage threshold 0.0010 A to 1000.0000 A for Line 1 current threshold 0.0010 A to 1000.0000 A for Line 2 current threshold 0.0003 A to 1000.000 A for Line 3 current threshold

Default value

60.0 % of nominal for Line 1 voltage threshold 60.0 % of nominal for Line 2 voltage threshold 60.0 % of nominal for Line 3 voltage threshold 0.0750 A for Line 1 current threshold 0.0750 A for Line 2 current threshold 0.0015 A for Line 3 current threshold

Configuration based on

Specified thresholds for voltage and current

Description

This test checks voltage and current on all phases to help detect possible theft or CT problems on Line 3. This test fails if the following conditions are present: • Voltage is present on any phase, and • Current is at or above a specified threshold on Line 1 or Line 3, and • Current is below a specified threshold on LIne 3

Stored value

Line 3 current

Security All A1800 ALPHA meters include features that help prevent unauthorized access to meter data and record events that may indicate meter tampering.

Meter passwords Access to the A1800 ALPHA meter is protected through the use of passwords. When establishing communication with the meter, the meter will request a password. If the correct password is not supplied, the meter will not communicate or perform the commands that it is issued. Passwords help ensure that the meter data is protected and that the programming cannot be altered without proper authorization. The A1800 ALPHA meter uses three passwords to control access to the meter. As shown in Table 4-7, each password allows different activities that can be performed on the meter. For more information regarding passwords, see the documentation that comes with the Elster meter support software.

Table 4-7. A1800 ALPHA meter passwords Password

Allowed activity

Read only

The meter can be read. No alteration of data or programming is allowed.

Billing read

The meter can be read. Some basic data-altering activity relating to billing functions is allowed.

Unrestricted

The meter can be read. Full programming of the meter is allowed.

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4-26

Meter tools

When communicating with the A1800 ALPHA meter remotely, the A1800 ALPHA meter supports the password encryption standards in accordance with ANSI C12.21. In accordance with ANSI C12.18, the password is not encrypted when communicating using the optical port. The meter records the number of failed password attempts that were used in trying to access the meter. An internal warning will be generated if 10 failed password attempts occur since the last demand reset. This warning can be used to control a relay output or to trigger an alarm call.

Anti–tampering All A1800 ALPHA meters provide auditing capabilities that can be used to indicate potential meter tampering. These capabilities can record such items as the following: • programming changes • power outages • number of days since last pulse • number of manually-initiated demand resets • number of days since last demand reset • reverse energy flow • history log • cover removal detection

Program protection As a security feature, the A1800 ALPHA meter can be ordered with program protection. Program protection prevents metrological parameters from being altered. Some data and configuration parameters can be altered while in program protection.1 These alterable items must be specified at ordering and can include the following: • communication parameters • TRueQ parameters • time of day (TOU or load profiling configurations) • switch times (TOU configurations) • special dates list (TOU or load profiling configurations) All other parameter changes require the meter to exit program protect mode. To temporarily disable program protection: 1. Break the terminal cover seals and remove terminal cover. The TC indicator will turn on. 2. Break the meter cover seals and lift the meter cover. 3. At this point, you can perform any of the data or program altering operations available using the Elster meter support software. 4. Close the meter cover and install the seals. 5. Install the terminal cover and seals. The TC indicator will turn off. If programmed to do so, changes in the state of the terminal cover and the meter cover are logged in the event log. See “Event log”on page 2-14 for details.

1 On

meters with a history log, it may be possible to change certain metrological parameters while in program protection. For more information, see “History log”on page 2-14.

Technical manual

Technical manual

5-1

Outputs

5 Outputs

Relay outputs All A1800 meters are equipped with 4 relay outputs. The A1800 ALPHA meter can be ordered with 6 relays.1

A1800 ALPHA meter with RS-232 as second communication port

RS-232 connector (optional)*

Pulse output relay (optional)

RS-485 terminals

RS-232 connector *Present when optional second communication port is installed Pulse output relay default values

RS-485 connections 4-wire Tx+

A

B

C

RxTx-

D

Rx+

2-wire A = Wh del B = varh del C = Wh rec D = varh rec

1

-bias

+ -

+bias

RS-232 connector 1

1 2 3 4 5

3

2 6

7

= = = = =

NC Rx Tx DTR GND

5

4 8

9 6 7 8 9

= = = =

DSR RTS NC NC

Support for up to 6 relays on A1800 ALPHA meter is a future option. Contact Elster Metronica for availability.

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5-2

Outputs

Figure 5-1. A1800 ALPHA meter with RS-485 as second communication port

RS-485 connector (optional)*

Pulse output relay (optional)

RS-485 terminals

RS-232 connector *Present when optional second communication port is installed Pulse output relay default values

RS-485 connections 4-wire Tx+

A

B

C

Rx-

1

Rx+

2-wire -bias

+ -

+bias

1 2 3 4 5

3

2 6

D Tx-

A = Wh del B = varh del C = Wh rec D = varh rec

RS-232 connector 7

= NC = Rx = Tx = DTR = GND

5

4 8

9 6 = DSR 7 = RTS 8 = NC 9 = NC

For more information about relay outputs and communications, see the instructional leaflet (IL) that comes with the option board. The output relays on the main circuit board can switch up to 125 VAC or 180 VDC at up to 70 mA. See Appendix D, “Wiring diagrams.” With the A1800 ALPHA meter, all relay outputs are fully programmable using Elster meter support software. Sources for relay outputs are listed in Table 5-1.

Table 5-1. Source for relay operation and output specifications Relay source

Relay output specification

Energy pulse

For each pulse of the selected basic metered quantity (see “Metered energy and demand quantities” on page 2-10), the relay will do either of the following: • toggle (that is, turn on and off) • pulse for a specified length of time

Load control

The relay closes when the demand exceeds the specified demand threshold, and it remains closed for the duration of the interval. The relay will open after the demand remains below the threshold for one full interval.

EOI indication

The relay closes for 5 seconds after the end of each interval or subinterval.

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5-3

Outputs

Table 5-1. Source for relay operation and output specifications Relay source

Relay output specification

Demand forgiveness (cold load pickup)

The relay closes while demand forgiveness is in effect. The relay will open after the demand forgiveness time has expired.

TRueQ tests failure

Relay closes as long as the specified TRueQ tests continue to fail (see “TRueQ monitoring” on page 412).

Specified errors, warnings, and meter events

The relay closes for as long as the specified errors, warnings, or events persist (see “Relay-related alarms” on page 5-4).

TOU switches to a specific tariff The relay closes for the duration of the specified tariffs.

Figure 5-2. Toggle relay output

On

½

½

½

½

½

½

Pulse Off

Pulse period

Pulse period

Pulse period

In toggle mode, a relay changes state for each energy pulse received from the meter engine.

Figure 5-3. Pulse relay output (default pulse width) 10 msec.

10 msec.

Pulse period

Pulse period

On

10 msec.

Pulse Off

Pulse period

In pulse mode, a default pulse width of 10 milliseconds is generated for each energy pulse received from the meter engine. Using Elster meter support, the width can be programmed with a value from 1 millisecond to 255 milliseconds.

Energy pulse outputs When a relay is used to echo energy pulses for a basic metered quantity, each pulse is equal to a specified amount of energy. Using Elster meter support software, there are two methods for specifying the weight of each pulse.

Using pulse divisor. Program the energy pulse divisor with an integer value between 1 and 999.

Energy pulse divisor 

Pulse constant Relay constant

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5-4

The pulse constant (also known as the meter constant) for the A1800 ALPHA meter is as follows: • For transformer rated meters: 40,000 pulses per kWh For example, the desired relay constant is 1000 pulses per 1 kWh and the pulse constant is 40,000 pulses per 1 kWh:

Energy pulse divisor 

40000  40 1000

Using Elster meter support software, program the energy pulse divisor of 40 into the meter. Note: If the energy pulse divisor is not an integer, then the exact desired output is not possible. • For direct connect-rated meters: 4000 pulses per kWh For example, the desired relay constant is 1000 pulses per 1 kWh and the pulse constant is 4000 pulses per 1 kWh:

Energy pulse divisor 

4000 4 1000

Note: If the energy pulse divisor is not an integer, then the exact desired output is not possible.

Using pulse value. Program the energy pulse value with a value between 0.000001 kWh and 100 kWh to represent the amount of energy per pulse (in kilo units). For example, to have one energy pulse represent 2 Wh (0.002 kWh), you would use an energy pulse value of 0.002. Note: The pulse value method is available from the Tools > System Preferences > Programming Options command in Metercat. Note: Elster recommends that the pulse value should not be used when verifying meter accuracy. Use the pulse divisor method when verifying meter accuracy.

Relay-related alarms The A1800 ALPHA meter periodically performs a self test to determine if it is operating properly. If any errors are detected, the meter can respond in any or all of the following ways: • display an error or a warning (see “Codes and warnings” on page 6-2) • initiate a telephone call using a modem • trigger a relay See Table 5-2 for errors, warnings, and events that can trigger a relay.

Table 5-2. Errors, warnings, and events that can trigger a relay Condition

Description

Carryover error

See “E1 000001: Carryover error” on page 6-3.

Clock error

See “E3 030000: Clock error” on page 6-5.

Crystal oscillator error

See “E1 000010: Crystal oscillator error” on page 6-4.

Demand overload warning

See “W1 100000: Demand overload warning” on page 6-7

EEPROM access error

See “E1 010000: EEPROM access error” on page 6-4.

End of calendar warning

See “W2 200000: End of calendar warning” on page 68.

Event log wrap event

The event log has exceeded the maximum number of entries, and the oldest records will be overwritten.

Outputs

Technical manual

5-5

Table 5-2. Errors, warnings, and events that can trigger a relay Condition

Description

General configuration error

See “E1 100000: General configuration error” on page 6-4.

History log wrap warning

The history log has exceeded the maximum number of entries. Depending on programming, the meter will either lock the history log or start overwriting the oldest records. If the history log is locked, no further changes to the meter are allowed until the history log has been read.

Improper meter engine operation warning

See “W1 000010: Improper meter engine operation warning” on page 6-6

Instrumentation profiling set 1 wrap imminent event

Set 1 of the instrumentation profiling log is within 2 days of overflowing. Data will be lost if the instrumentation profiling log is not read within 2 days.

Instrumentation profiling set 2 wrap imminent event

Set 2 of the instrumentation profiling log is within 2 days of overflowing. Data will be lost if the instrumentation profiling log is not read within 2 days.

Internal communication error

See “E1 001000: Internal communication error” on page 6-4.

Low battery warning

See “W1 000001: Low battery warning” on page 6-6.

Possible tamper warning

This condition indicates possible tampering of the meter because a specified number of invalid passwords used to access the meter has been used (called “tamper detect warning” in this manual). This condition does not generate an error or warning code on the LCD.

Potential indicator warning

See “W1 010000: Potential indicator warning” on page 6-7.

Power fail data save error

See “E2 200000: Power fail data save error” on page 65.

Pulse profiling wrap imminent event

The pulse profiling log is within 2 days of overflowing. Data will be lost if the pulse profiling log is not read within 2 days.

Rate override warning

The current TOU rate is being overridden by the alternate TOU rate schedule.

Reverse energy flow warning

See “W1 000100: Reverse energy flow warning” on page 6-7.

Service current test failure warning

See “W2 000002: Service current test failure warning” on page 6-7.

Service voltage test failure warning

The service voltage test was unable to find a valid service or the measured service does not match the locked service.

Outputs

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5-6

Outputs

LED pulse outputs The A1800 ALPHA meter has two energy light emitting diodes (LEDs), which are permanently configured as follows: • active LED - indicates active (Wh) energy import or export • alternate LED - indicates alternate (varh/VAh) energy import or export The LEDs emit pulse outputs that can be used to test the A1800 ALPHA meter in the field without removing the meter from service or breaking the seal.

Figure 5-4. LEDs Active energy LED

Alternate energy LED

Output specifications The LEDs support up to 120 pulses per second.The pulse width is fixed at 8 msec. Depending on the operating mode of the meter, the LEDs are programmed at the factory to emit a pulse as follows:

Table 5-3. Transformer rated meter LED output specifications Operating mode

Pulse rate

Pulse divisor

Normal

5000 pulses/kWh or 5000 pulses/kvarh

8

Alternate

5000 pulses/kWh or 5000 pulses/kvar

8

Test

40,000 pulses/kWh or 40,000 pulses/kvarh

1

Table 5-4. Direct connect-rated meter LED output specification Operating mode

Pulse rate

Normal

500 pulses/kWh or 1000 pulses/kvarh

8

Alternate

500 pulses/kWh or 1000 pulses/kvarh

8

Test

4000 pulses/kWh or 4000 pulses/kvarh

1

For alternate pulse rates, contact your Elster Metronica representative.

Pulse divisor

Technical manual

Technical manual

6-1

6 Testing

A1800 ALPHA meters are factory calibrated and tested to provide years of trouble-free service. No field calibrations or adjustments are required to ensure accurate operation of the meter. It is normal, however, to test installed A1800 ALPHA meters periodically to ensure accurate billing. The A1800 ALPHA meter performs its own self tests. Additionally, the system instrumentation and TRueQ features provide valuable information about the meter service. See Chapter 4, “Meter tools,” for more information about the instrumentation and power quality features of the meter. Testing procedures are the same regardless of the type of meter being tested.

Meter self test The A1800 ALPHA meter periodically performs a self test to determine if it is operating properly. The self test ensures that the A1800 ALPHA meter is functioning properly and its displayed quantities are accurate. Any errors encountered will be displayed on the LCD. Certain errors may also initiate a telephone call via a modem or trigger a relay. • For LCD errors and warnings, see “Codes and warnings” on page 6-2. • For relay alarms, see “Relay-related alarms” on page 5-4. The meter self test will be performed automatically under the following conditions: • when the meter is initially installed and after any power restoration • at midnight • immediately after a data-altering communication session The self test incorporates a series of electronic analyses verifying many aspects of the A1800 ALPHA meter. Continuity checks and communications checks are made between various key circuits of the electronics, and parity checks are made of memory and data locations. After the meter passes its self test upon power restoration, all of the LCD segments will be turned on briefly before beginning the normal display sequence. The following is a list of the specific tests performed during a self test: • verification of the configuration data and checksums • confirmation of the crystal oscillator accuracy • detection of low battery voltage • detection of low Read without Power battery voltage • maximum lifetime usage of the Read without Power battery • verification of normal microcontroller function • detection of unexpected meter engine resets (for multiple tariff configurations) • detection and identification of user-defined warning conditions

Testing

Technical manual

6-2

Codes and warnings There are 3 types of codes: • error codes • warning codes • communication codes The A1800 ALPHA meter displays error codes and warnings as an indication of a problem that may be adversely affecting its operation. The meter will continue to function as normally as possible when displaying an error or warning. The * and RESET buttons operate differently if an error or warning is displayed. See “Push buttons” on page 3-4 for information on how the push buttons operate when an error or warning is displayed. Error codes indicate conditions that may be affecting billing data. It is not recommended to operate the A1800 ALPHA meter for an extended time when it is displaying an error code. Warning codes indicate conditions that may be of concern but do not affect the integrity of billing data. Communication codes generally indicate a condition affecting communications with the meter through the optical port or remote port. Not all communication codes indicate potential problems; some codes provide an indication of the present communication process.

Error codes. Error codes override any other item that is being displayed on the LCD. Using Elster support software, error codes can be configured to “lock” the display, preventing other items from being displayed, and the error indicator turns on. There are exceptions to errors locking the display: • The normal and alternate display sequence can be viewed even when an error code locks the display. See “* button” on page 3-5 for more information. • Warning codes can be programmed to display an error code. When the condition causing the warning code is clear, the error code is no longer displayed. See “E3 300000: Display locked by warning” on page 6-5 for more information. Communication codes are temporarily displayed on the LCD even when the LCD is “locked” by an error code. After the communication code clears, LCD returns to showing the error code. Error codes are indicated on the LCD by a group code and a numerical code. The group code makes it easier to identify the error on the LCD. The numerical code indicates the specific condition that has occurred. See Figure 6-1 for a sample error code displayed on the meter LCD. Table 6-1 through Table 6-3 describe the different error conditions and their codes.

Figure 6-1. Sample error code displayed on the LCD +P

L1 L2 L3

Testing

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6-3

Testing

Table 6-1. Group E1 error conditions and codes Condition

Code

Carryover error

0

0

0

0

0

1

Crystal oscillator error

0

0

0

0

1

0

Table CRC error

0

0

0

1

0

0

Internal communication error

0

0

1

0

0

0

EEPROM access error

0

1

0

0

0

0

General configuration error

1

0

0

0

0

0

Table 6-2. Group E2 error conditions and codes Condition

Code

Security configuration error

0

0

0

0

0

2

Password table CRC error

0

0

0

0

2

0

Encryption key table CRC error

0

0

0

2

0

0

ROM fail error

0

2

0

0

0

0

Power fail data save error

2

0

0

0

0

0

Table 6-3. Group E3 error conditions and codes Condition

Code

Clock error

0

3

0

0

0

0

Display locked by warning

3

0

0

0

0

0

Error codes of the same group are displayed in combination (E1 001010, for example), indicating that more than one error condition has been detected. If errors exist in more than one group, the meter will continually cycle through the different groups. Any problems must be corrected before normal operation can continue. In some cases, the meter may need to be reprogrammed or returned to the factory for repair or replacement. E1 000001: Carryover error. This code indicates a failure of a RAM checksum test on data stored in the meter’s volatile RAM during a power outage. When a loss of line voltage occurs, the meter’s RAM is maintained by the super capacitor and the TOU battery. If both of these fail, the data stored in RAM is lost. Billing data is stored in nonvolatile EEPROM and will still be available.1 The push buttons and communications ports will function normally.

Since shipping can take several days, this error will likely be seen on meters shipped without a connected battery. The meter battery may need to be replaced, and the error will need to be reset through Elster meter support software. If the error code is still shown after using Elster meter support software, the meter must be returned to the factory for repair or replacement. 1 Billing

data is always stored in nonvolatile memory. Depending on meter configuration, other data may be stored in RAM, which uses a battery to preserve memory. If the battery fails, this data would be lost.

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E1 000010: Crystal oscillator error. This codes indicates a problem with the crystal oscillator. The A1800 ALPHA meter must be returned to the factory for repair or replacement. E1 000100: Table CRC error. This code indicates a possible error in the A1800 ALPHA meter’s programming. This code might appear if a communications interruption occurs during meter programming. Depending on which area of the meter is affected, billing data may not be reliably accumulated while this error condition exists. The push buttons and optical port will continue to function normally. Reprogramming the meter with Elster meter support software may correct the problem. If the error code is displayed after reprogramming, the A1800 ALPHA meter should be returned to the factory for repair or replacement. E1 001000: Internal communication error. This code indicates the meter had an internal communication error. The A1800 ALPHA meter must be returned to the factory for repair or replacement. E1 010000: EEPROM access error. This code indicates the meter had a problem accessing its nonvolatile EEPROM. The A1800 ALPHA meter should be returned to the factory for repair or replacement. E1 100000: General configuration error. This code indicates a problem with the meter’s configuration or program. The meter can usually be reprogrammed using Elster meter support software to correct the errors. E2 000002: Security configuration error. This code indicates an error is present in the meter’s security configuration. Contact Elster if this error is displayed on the LCD.

If this error occurs, the meter is vulnerable to tampering. Prompt correction of the error will maximize the A1800 ALPHA meter’s security protection. E2 000020: Password table CRC error. This code indicates a CRC error is present in the meter’s ANSI C12.21 password configuration table. Contact Elster if this error is displayed on the LCD.

If this error occurs, the meter is vulnerable to tampering. Prompt correction of the error will maximize the A1800 ALPHA meter’s security protection. E2 000200: Encryption key table CRC error. This code indicates a CRC error is present in the meter’s ANSI C12.19 encryption key configuration table. Encryption keys are used for secure access to the meter’s data and configuration through the remote communication port. Contact Elster if this error is displayed on the LCD.

If this error occurs, the meter is vulnerable to tampering. Prompt correction of the error will maximize the A1800 ALPHA meter’s security protection.

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Testing

E2 020000: ROM fail error. This code indicates an incomplete attempt to flash the meter firmware. This code will exist on the meter if Elster firmware flash software did not complete the upgrade process. All meter functionality is halted until this error is resolved. Use Elster firmware flash software to attempt repair. If this fails, the meter must be returned to the factory for repair or replacement. E2 200000: Power fail data save error. This code indicates that the data saved in the nonvolatile EEPROM during a power fail may be invalid. This error will be displayed when power is restored to the meter, and a self check has discovered an error with the EEPROM data. The A1800 ALPHA meter must be returned to the factory for repair or replacement. E3 030000: Clock error. This code indicates an error with the meter’s timekeeping ability. When a carryover error occurs (see “E1 000001: Carryover error” on page 6-3), reference to real time is lost. The meter battery may need to be replaced, and the error will need to be reset through Elster meter support software. If the error code is still present, the meter must be returned to the factory for repair or replacement. TOU features cannot be performed when time is lost. Previously accumulated data is stored in nonvolatile EEPROM and will still be available. E3 300000: Display locked by warning. This code indicates that one or more warning codes (see “Warning codes” on page 6-5) has locked the display. The A1800 ALPHA meter can be programmed to lock the display if a warning condition is present. Elster meter support software is used to select the individual warnings that will cause this error code to display. If the condition causing the warning clears, the error code will also clear.

Warning codes. Warning codes indicate conditions of concern that do not yet affect the integrity of billing data. When the condition is present, a warning code is automatically inserted as the last item in the normal and alternate display sequences. When the condition clears, the warning code, is removed from the display sequence. Elster meter support software can be used to select individual warnings that will lock the display as an error. See “Error codes” on page 6-2 for more information. Warning codes are indicated on the LCD by a group code and a numerical code. The group code makes it easier to identify the error on the LCD. The numeric code indicates the specific condition that has occurred. See Figure 6-2 for a sample warning code displayed on the LCD. Table 6-4 and Table 6-5 describe the different warning conditions and their codes.

Figure 6-2. Sample warning code +P

L1 L2 L3

Table 6-4. Group W1 warning codes Condition

Code

Low battery warning

0

0

0

0

0

1

Improper meter engine operation warning

0

0

0

0

1

0

Reverse energy flow warning

0

0

0

1

0

0

Potential indicator warning

0

1

0

0

0

0

Demand overload warning

1

0

0

0

0

0

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Testing

Table 6-5. Group W2 warning codes Condition

Code

Service current test failure warning

0

0

0

0

0

2

Demand threshold exceeded warning

0

0

0

2

0

0

Line frequency warning

0

0

2

0

0

0

TRueQ test failure warning

0

2

0

0

0

0

End of calendar warning

2

0

0

0

0

0

Warning codes of the same group are displayed in combination (for example, W2 202000), indicating that one or more warning conditions are present. If warnings exist in more than one group, the meter displays each group at the end of the display sequence before returning to the first item in the display sequence. W1 000001: Low battery warning. This warning code indicates a low battery voltage or missing battery. A1800 ALPHA meters having realtime TOU functionality require a battery to maintain date and time over an extended power outage. For timekeeping configurations, the meter should be de-energized and the battery should be replaced. Once the new battery has been installed and the meter is energized, the code is automatically cleared. See “Removing the battery” on page 7-6 and “Installing a TOU battery” on page 7-3 for instructions on replacing batteries. Note: In addition, the low battery indicator will display on the LCD (see “Low battery indicator” on page 3-3). W1 000010: Improper meter engine operation warning. This code indicates that the meter engine program may be corrupt or is not executing correctly. This warning condition is typically triggered when the microcontroller reinitializes the meter engine. An unstable or noisy electrical environment at the A1800 ALPHA meter installation can interfere with this operation. If the meter engine is successfully reinitialized, then the warning code will be automatically cleared from the LCD. If the code continues to be displayed on the LCD, the A1800 ALPHA meter should be returned to the factory for repair or replacement.

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W1 000100: Reverse energy flow warning. This warning code indicates that reverse energy flow has been detected equivalent to twice the Kh since the last reset. It may be an indication of tampering with the A1800 ALPHA meter installation. If reverse energy flow is expected, then this warning code can be disabled through Elster meter support software. If the service being metered is not expected to return energy to the utility, further investigation is required. In some cases, it may be necessary to return the A1800 ALPHA meter to the factory for repair or replacement. The code is cleared by these methods: • performing a demand reset • issuing the clear values and status command through Elster meter support software W1 010000: Potential indicator warning. This code indicates that one or more of the phase potentials are missing or below the defined threshold for voltage sag detection. This code will display at the same time as one or more of the potential indicators blink. See “Phase indicators” on page 3-2 and “Voltage sags” on page 4-13 for more details on potential indicators and voltage sags. The code is automatically cleared when the phase potential returns a value within the programmed thresholds. W1 100000: Demand overload warning. This code indicates that the demand value exceeded the programmed overload value. It is generally intended to inform a utility when the installation is requiring more power than the service equipment was originally designed to handle. If the demand overload value has been set lower than appropriate for the installation, the A1800 ALPHA meter may be reprogrammed with a higher threshold value. The code is cleared by these methods: • performing a demand reset • issuing the clear values and status command through Elster meter support software W2 000002: Service current test failure warning. This code indicates that the most recently performed service current test has failed. See “Service current test” on page 4-9 for more information. The code is cleared by these methods: • the service current test is performed again and the test does not fail • issuing the clear values and status command through Elster meter support software W2 000200: Demand threshold exceeded warning. This code indicates that the demand has exceeded one of the programmed demand thresholds. This warning follows the state of any relay programmed for demand threshold operation. It is set once the demand threshold has been exceeded and only cleared after one complete demand interval during which the threshold is not exceeded. W2 002000: Line frequency warning. If a meter is configured to use the line frequency instead of the crystal oscillator as the time base, this code indicates that the line frequency is off by ±5 % of its programmed setting. When this condition occurs, the meter switches timekeeping to the crystal oscillator. The code will be automatically cleared once the line frequency returns to within 5 % of the nominal frequency. This warning will never appear on meters configured for constant timekeeping operation from the internal crystal. W2 020000: TRueQ test failure warning. This code indicates that one or more TRueQ tests have detected a value outside the programmed thresholds. Use the meter system instrumentation displays or Elster meter support software to gain additional information on the specific TRueQ test causing the problem. The code will be automatically cleared once TRueQ conditions return to a value within the programmed thresholds.

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Testing

W2 200000: End of calendar warning. This code indicates that the meter calendar has expired or is about to expire. The date at which this code appears is configurable using Elster meter support software. Program a new calendar using Elster meter support software. The code is cleared by these methods: • performing a demand reset • issuing the clear values and status command through Elster meter support software

Communication codes. Communication codes temporarily override any other item that is being displayed on the LCD (including error codes). Communication codes are indicated on the LCD by a port code and a numerical code. The port code identifies the affected port. The numerical code indicates the status of the communication session. See Figure 6-3 for a sample communication code displayed on the meter’s LCD. See Table 6-6 for the communication codes that can be displayed. Figure 6-3. Sample communication code +P

L1 L2 L3

Table 6-6. Communication codes Condition

Code

CRC error

C

0

0

1

0

1

Syntax error

C

0

0

1

0

3

Framing error

C

0

0

1

0

4

Timeout error

C

0

0

1

0

5

For most communication errors, Elster recommends you attempt the communication again. You may need to cycle power to the A1800 ALPHA meter or to reattempt the Elster meter support software function. If communication errors persist, return the meter to the factory for repair or replacement.

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Meter shop testing Test equipment Typically, meter shops develop testing procedures specific to their own needs and have the test equipment needed. Below is a list of standard test equipment required for testing the A1800 ALPHA meter: • a stable mounting fixture for the meter and a means to temporarily make the proper power connections to the meter • a reliable power supply that should be able to do the following: • provide a voltage source for energizing the meter at its rated voltage (if desired, the meter can be tested using a lower source voltage if that voltage is within the wide operating voltage range of the A1800 ALPHA meter) • provide a variable load current at unity power factor (PF) • provide a variable load current at a lagging power factor for varh testing; the power supply should be capable of delivering load current at PF = 0.0 (90 ° lagging) or PF = 0.5 (60 ° lagging) • a precision Wh reference standard with ±0.002 % accuracy • a precision varh reference standard with ±0.002 % accuracy • a phantom load device or other loading circuit capable of handling the test current • one of the following: • a photoelectric pickup to sense test pulses from the LED and a device capable of counting pulses • a low voltage (12 VDC to 24 VDC), low-power pulse sensor to capture and count pulses from the meter output relay (the pulse sensor should provide a low voltage source to the pulsing relay as well as detect and count contact closures of the output relay) • test equipment for measuring, counting, and timing pulse outputs • control equipment that can provide switching between the meter source voltage and precision reference standard • precision voltage and current transformers • voltmeters, ammeters, phase angle meters, power factor meters, and any other measuring equipment that might be required

Test setup Before testing the A1800 ALPHA meter, check the nameplate for the following: • Meter class for expected accuracy • Test amperes (In or Ib) The specific test ampere value is not critical as long as the applied current does not exceed the Imax current rating of the meter. Normally, a value of approximately 20 % to 25 % of Imax is used for basic tests, with additional test points at 5 %, 10 %, and 100 % of Imax also required by most legal authorities. Note: The A1800 ALPHA meter has a flat, linear load curve accuracy response. Therefore, when allowed by local legislation, meter accuracy testing can be accomplished by checking the meter accuracy at two typical points. For example, test the meter with In equal to 10 % of Imax, at both 100 % and 20 % PF. Historical data from testing the A1800 ALPHA meter confirms that if these test points are within the required accuracy, the entire range of loads is within the required accuracy. • Operating voltage range • Any other important specifications for the meter being tested

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Risk of personal injury or death! Use only authorized personnel and proper test procedures to test metering equipment. Dangerous voltages are present. Personal injury, death, or equipment damage can result if safety precautions are not followed. To set up the A1800 ALPHA meter for testing: 1. Install the meter in the stable mounting fixture. 2. Place the precision Wh or varh reference standard and precision voltage and current transformers (as required) in series with the meter being tested. If voltage transformers are not required, then the meter source voltage should be placed in parallel with the Wh or VARh reference standards. See Appendix D, “Wiring diagrams,” for appropriate wiring diagrams for the A1800 ALPHA meter. 3. Connect the control equipment for switching the source voltage to the precision reference standard. 4. Connect the measuring equipment for counting the standard’s output pulses. 5. Apply the rated test current and voltage to the terminals of the meter.

Meter testing Since no adjustments are required for the A1800 ALPHA meter in the field, meter testing is done primarily to verify that the meter is operating within its specifications. Typically, meter specifications are verified by checking the meter calibration. The accuracy of the A1800 ALPHA meter remains consistent over a wide range of ambient temperatures. Nevertheless, for precise test results, meters should be tested in an environment where the meter and test equipment are at the same ambient temperature, ideally 22 °C (72 °F). The test voltage should be applied to the meter for at least ten seconds prior to making test measurements. This allows the power supply circuitry to stabilize. When testing meters for Class 0.2 accuracy, a test cycle time of at least one minute is recommended at In and with PF = 1.0. When using current values lower than In for testing, test errors may occur because not enough time is allowed for the test. When using a lower test In, increase the test time proportionally. The preferred test method is to apply full 3-phase voltage and current to both the meter and the precision reference standard. Nevertheless, if required, polyphase meters can be tested with single phase loading. Single phase loading is done by connecting the voltage inputs in parallel and the current sensors in series to combine element operation. The accuracy test results for single phase and polyphase loading will be virtually identical and well within A1800 ALPHA meter specifications.

Using relay outputs for testing. The relay outputs can be used instead of the LED to test meter calibration. To do so, the relay outputs need to be configured for pulse output. When using the relay outputs for testing, testing time should exceed 20 seconds for accurate results at normal test current values of Ib or In. If more accurate testing is required, use longer testing times. If precision testing is required, testing times should be as long as it takes to attain a stable accuracy level when comparing the meter under test to the precision standard. The testing time may vary because of the characteristics of the precision reference standard and the amount of power flowing through the test circuits. Some experimentation may be required to determine the testing time needed to reach a stable accuracy level.

Using LCD pulse count for testing. For test shops that do not have photoelectric pulse sensors and related counters and do not want to use relay outputs for testing, the LCD can provide a pulse count that reflects the energy measured during a test. Use the LCD pulse count to determine the energy measured during the test cycle and compare it with the energy delivered by precision reference standard.

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Wiring a portable device into an energized metering circuit must be done with extreme care, using only authorized procedures. If high voltage connected current transformers are accidentally open circuited, the voltages at the secondary open terminals can rise to the primary voltage level, creating an extremely hazardous condition, leading to possible property damage, personnel injury or death. To test the meter using the LCD pulse count, the meter display must be configured to display a test pulse count. Use the Elster meter support software to communicate to the meter through the optical port and place it in test mode. In test mode, the LCD display can be cycled to display the pulse count accumulated during a test cycle. After meter testing is complete, use the meter software to restore the meter to normal mode. If a meter is programmed to display energy pulse counts when it is in the alternate display mode, a similar procedure also can be used to test a meter while it is in service at a customer site. When testing a meter in service, follow the safety procedures specified by the utility. Wire a portable precision reference standard into the circuit in series with the billing meter. After the portable precision reference standard is in the circuit, the energy value determined from the pulse count displayed on the LCD over the test interval can be compared with the energy value displayed on the portable reference standard. If this test method is used while the meter is in alternate mode, any energy consumed by the customer during the test is registered in the normal manner.

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Testing

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7 Installation and removal

Preliminary inspection

Circuit-closing devices must be used on current transformer secondaries. Dangerous currents and voltages are present if secondaries are open-circuited. Equipment damage, personal injury, or death can result if circuit-closing devices are not used. The A1800 ALPHA meter is calibrated and tested at the factory, and it is ready for installation. Follow proper installation and removal procedures for personal safety and protection of the meter. Before installing and applying power to the A1800 ALPHA meter, a quick inspection of the meter itself is recommended. Check for some of the following items: • no broken or missing parts • no missing or broken wiring • no bent or cracked components • no evidence of overheating • check the nameplate to make sure it is appropriate for the service Physical damage to the outside of the A1800 ALPHA meter could indicate potential electronic damage in the inside of the meter. Do not connect power to a meter that is suspected to have unknown internal damage. Contact your local Elster Metronica representative if you suspect your meter may be damaged.

Placing the meter into service See Appendix D, “Wiring diagrams,” for illustrations of both internal and connection wiring diagrams.

Circuit-closing devices must be used on current transformer secondaries. Dangerous currents and voltages are present if secondaries are open-circuited. Personal injury, death, or equipment damage can result if circuit-closing devices are not used.

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Make sure to install the correct meter for the service type, maximum current, and capacity required. Always verify that the maximum meter voltage and current ratings are equal to or greater than the maximum service voltage and current. Installing inappropriate meters can damage equipment. To use the A1800 ALPHA meter effectively and safely, follow this procedure: 1. Make sure that the meter hanger, located on the base of the A1800 ALPHA meter, is in the desired position. Sliding the hanger down to the hidden position will hide the top supporting screw. 2. Use at least an M6 screw for the top supporting position and hang the meter on it, making sure it is level. The meter will operate correctly in any position, but failing to mount the meter in a proper vertical position will place the other mounting holes at the wrong place on the mounting panel. 3. Use at least an M6 screw in each of the bottom supporting screws to secure the A1800 ALPHA meter enclosure; the mounting holes are 7.1 mm (0.28 inches) in diameter.

Before wiring the meter into the power circuit, use authorized utility procedures to install proper ground connections on all appropriate VT and CT circuits and on the meter ground terminals. Also, be certain that CTs on energized lines are securely short-circuited either with circuit-closing test switches or with properly installed conductors. Dangerous voltages can be present. Personal injury, death, or equipment damage can result from wiring an ungrounded meter or mishandling improperly grounded metering transformer circuits. 4. Install the ground connections.

A1800 ALPHA meter terminals are designed for optimum use with copper wiring. For direct connect-rated meters, aluminum wiring can be used but if so, it is extremely important to use proper aluminum wiring practices. Aluminum wiring compound or wiring paste (grease) should be used when attaching the bottomconnected terminals. Tighten the connections, allow them to relax for a few minutes, then tighten them again. This will minimize the cold-flow effects of aluminum cable. Failure to observe correct practices for installing aluminum wiring could lead to overheating of the terminals, equipment failures, or damaging fires. Where possible, Elster recommends copper-compatible meter terminals and aluminum wire. Such adapters also can provide for use or larger aluminum conductors that can be otherwise used in the terminals of the A1800 ALPHA meter. 5. Ensure that primary or system voltages are either disconnected from a power source or that utility safety practices for handling live circuits are strictly followed. 6. If applicable, ensure that any current transformers are de-energized with no highvoltage primary voltage connected to their primaries and no primary current circulating through them. If primary current and voltage are present in the current transformers, it is extremely important to verify that safety shorting connections are in place on all secondary winding connections prior to handling CT connections to the meter.

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7. Wire the meter using color-coded wire according to locally applicable specifications. The terminal block dimensions on the A1800 ALPHA meter support cable sizes of approximately 5 mm in diameter for transformer rated connections (10 mm in diameter for direct connect). Standard wiring diagrams are shown in Appendix D, “Wiring diagrams.” 8. After wiring the meter and making any communication and relay connections, assemble the terminal cover and apply power. For information on communication and relay connections, see Chapter 5, “Outputs.”

Figure 7-1. A1800 ALPHA meter mounting screw locations Hanger screw mount

Screw mounts

Installing a TOU battery The TOU battery is replaceable without breaking the meter seal. Use only Elsterrecommended TOU batteries. See your Elster Metronica representative for details.

The meter should be de-energized before installing the battery. Dangerous voltages are present; and equipment damage, personal injury, or death can result if safety precautions are not followed. Use authorized procedures to install the battery while power is removed from the meter. Before installing the battery, the A1800 ALPHA meter must have been energized for at least 1 minute within the preceding 60 minutes. This ensures that the supercapacitor is properly charged and that the battery is not immediately drained upon installation. If this is not done, then the battery may be damaged and the meter may not function correctly. While the meter is powered, verify that the LCD is active and functioning. To install the battery: 1. If the meter has not been energized for at least 1 minute during the previous 60 minutes, energize the meter for 1 minute. If the meter has been energized for at least 1 minute during the previous 60 minutes, proceed to step 2.

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Installation and removal

2. De-energize the meter. 3. Remove the terminal cover screws and seals. 4. Remove the terminal cover to expose the battery well.

Figure 7-2. Battery well and connector

TOU battery

5. Slide the battery leads into the connector to the right of the battery well. 6. Place the battery firmly in the battery well. 7. Replace the terminal cover. 8. Energize the meter and verify that the LCD becomes active and functioning properly. Verify that the low battery symbol on the meter LCD is not displayed. See “Indicators and controls” on page 3-1 for details. 9. Replace the terminal cover screws and seals. 10. Reprogram the meter or clear the errors (as necessary).

Troubleshooting.

Not following this procedure can cause the meter to function improperly. In case a battery has been installed correctly and the meter is not functioning properly (for example, display is blank but the meter is powered), use the following procedure. 1. De-energize the meter and let it sit without power for 48 to 72 hours. This provides sufficient time for the supercapacitor to discharge and for the microcontroller to shut down.1 2. Energize the meter for at least 1 minute. The microcontroller should power up correctly and the supercapacitor will charge. Verify that the LCD becomes active and functioning correctly. 3. De-energize the meter and insert the battery, following the instructions earlier in this section. If the meter still does not function properly, then it should be returned to the factory.

Initial setup After installing and powering the A1800 ALPHA meter, verify the following: • The system service voltage test (if enabled) shows the valid service for this installation. The phase rotation, service voltage, and service type should be indicated on the LCD. Other validation information can be obtained using the system instrumentation display quantities. 1 If

the battery was installed with the polarity reversed, the battery should not be damaged. If the battery was installed without having the meter properly energized, then the battery will lose approximately 8.5 % of its service life each day.

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• All potential indicators (from L1 to L3 depending on the wiring) are present and are not blinking. A blinking indicator means that the phase is missing the required voltage or is below the programmed minimum voltage threshold value. • The LEDs are blinking and the energy direction indicators on the LCD show the correct energy flow direction. • Required meter seals are in place. • Any information (such as registration and location of the meter) has been recorded.

If the meter is not working correctly after it has been installed, then check for improper installation or wiring. If the installation and wiring are correct, then verify these other areas: • the meter installation matches the meter nameplate • the correct type of A1800 ALPHA meter is installed in the existing service • no evidence of mechanical or electrical damage to either the meter or the installation location • the service voltage falls within the operating range as indicated on the nameplate • the optical port is free of dirt or other obstructions

Marking the utility information card The utility information card can be removed without breaking seals and removing the meter cover screws. Note that the direct connect meter uses a blank card. To remove the utility information: 1. Remove the terminal cover as described above. 2. Grasp the protruding utility information card tab firmly and pull the card out slowly from under the meter cover. 3. Mark the card as needed.

Figure 7-3. Removing the utility information card

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Removing the meter from service Use the appropriate procedure when removing an A1800 ALPHA meter from service.

Use authorized utility procedures to remove metering equipment. Dangerous voltages are present, and equipment damage, personal injury, or death can result if safety procedures are not followed.

Circuit-closing devices must be used on current transformer secondaries. This applies to CT-connected meters. Dangerous currents and voltages are present if secondaries are open-circuited. Equipment damage, personal injury, or death can result if circuit-closing devices are not used. If it becomes necessary to remove an A1800 ALPHA meter from service, use the following procedure: 1. Before disconnecting the meter, make sure that the existing meter data has been copied, either manually or electronically using Elster meter support software. 2. Remove the voltage and disconnect the current circuits. 3. Break the seal holding the A1800 ALPHA meter terminal cover in place. 4. Remove the terminal cover screws and take off the terminal cover. 5. Disconnect the wiring. 6. Remove the lower supporting screws. 7. Lift the meter off the top supporting screw.

Removing the battery

The meter should be de-energized before removing the battery. Dangerous voltages are present; and equipment damage, personal injury, or death can result if safety precautions are not followed. Use authorized procedures to remove the battery while power is removed from the meter. Use the following procedure to remove a battery from an A1800 ALPHA meter: 1. De-energize the meter. 2. Remove the terminal cover to expose the battery well. 3. Firmly grasp the battery and lift it from the well. 4. Disconnect the battery leads from the connector. 5. Replace the terminal cover and ensure the seals are in place. If the removed battery is still in working condition, it can be stored safely for future use. Non-functioning batteries should be disposed of according to local laws, regulations, or electric utility policies.

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Loss compensation

8 Loss compensation

Introduction What is Loss Compensation? The Handbook for Electricity Metering defines loss compensation as follows: A means for correcting the reading of a meter when the metering point and the point of service are physically separated resulting in measurable losses including I2R losses in conductors and transformers, and iron-core losses. These losses may be added to, or subtracted from the meter registration.1 For example, it may be desirable to measure the energy usage on the low voltage side of a distribution transformer that serves an industrial customer even though the end-point customer actually owns the transformer and is responsible for any transformer losses. In this case, the utility billing point is actually the high voltage side of the transformer. Using loss compensation, the meter on the low voltage side of the transformer can actively adjust the energy registration to account for the losses in the transformer.

Availability The loss compensation functionality is available only on the following CT-connected A1800 ALPHA (“-V” suffix) meter configurations: • 2-element • 3-element

Software support A meter with loss compensation must first be programmed with the proper utility rate configuration using Elster meter support software just as you would with any other A1800 ALPHA meter. Next, a special programming step is performed to load the proper loss constants into the meter. This is done with special Windows-based software titled A1800 ALPHA Meter Loss Compensation Tool.

Calculating the correction values To configure the loss compensation feature of an A1800 ALPHA meter you must input the following values into the loss compensation software. These values are site specific and must be uniquely determined for each loss compensation application. Parameter

Description

%LWFe

Iron watts correction percentage

%LWCu

Copper watts correction percentage

%LVFe

Iron vars correction percentage

%LVCu

Copper vars correction percentage

1

Edison Electric Institute, Handbook for Electricity Metering, 10th edition, Washington, DC: Edison Electric Institute, 2002, p. 16.

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Parameter

Description

Meter current

Meter current when power transformer is operating at maximum rating

Meter voltage

Meter voltage when power transformer is operating at rated voltage

These values must be calculated on the basis of the power transformer test report and, if line losses are to be included, the characteristics of the primary/secondary conductors at the specific site in question. The following sections describe these calculations. Calculation of loss compensation parameters is dependent on the location of the meter with respect to the power transformer. The rated voltage and rated current used in the calculations must represent the values on the same side of the power transformer as the meter is located. • If the meter is located on the secondary side of the power transformer, then the rated voltage and rated current used in the calculations must be secondary values. • If the meter is located on the primary side of the power transformer, then the rated voltage and rated current used in the calculations must be primary values.

Gather necessary data The following information is necessary to calculate the loss compensation configuration parameters. Parameter

Description

KVArated

Rated kVA of power transformer

Vpri L-L

Primary line-to-line voltage of power transformer

Vsec L-L

Secondary line-to-line voltage of power transformer

LWCu

Full load watts loss of power transformer (copper or winding losses)

LWFe

No load watts loss of power transformer (iron or core losses)

%EXC

Percent excitation current of the power transformer

%Z

Percent impedance of the power transformer

CTR

Current transformer ratio for instrument transformers supplying current to the meter

VTR

Voltage transformer ratio for instrument transformers supplying voltage to the meter

Elements

Number of meter elements (use 3- for all 2 ½-element meters)

Note: There may be one 3-phase transformer or a bank of three single phase transformers. If there are three single phase transformers then test data is needed for all three.

Calculate the meter configuration parameters Step 1. Calculate the following quantities. Parameter

Description

VAphase

Per phase VA rating of power transformer

Vsec rated

Rated secondary voltage of power transformer

Isec rated

Rated secondary current of power transformer

Vpri rated

Rated primary voltage of power transformer

Ipri rated

Rated primary current of power transformer

LWFe

No load watt loss of power transformer (loss watt iron)

Loss compensation

Technical manual

8-3

Loss compensation

Parameter

Description

LWCu

Full load watt loss of power transformer (loss watt copper)

LVAFe

No load VA loss of power transformer (loss VA iron)

LVACu

Full load VA loss of power transformer (loss VA copper)

LVFe

No load var loss of power transformer (loss var iron)

LVCu

Full load var loss of power transformer (loss var copper)

Parameter

Equation

VAphase

If bank of 3 transformers

VA phase  KVArated  1000

If one 3-phase transformer

VA phase  Vsec rated

For 2 element, 3-wire delta applications For 3 element, 4-wire wye applications

Vpri rated

For 2 element, 3-wire delta applications For 3 element, 4-wire wye applications

Isec rated

( kVArated  1000 ) 3

V secrated  V secL- L

V secrated 

V secL- L 3

V pri rated  V pri L- L

V pri rated 

V pri L- L

All applications

I secrated  Ipri rated

All applications

I pri rated 

3

3  VA phase V secL- L

3  VA phase V pri L- L

Note: For a bank of three single phase transformers the below calculations should be performed independently for each transformer and then summed to obtain the total losses. LWFe

Take directly from power transformer test report.

LWCu

Take directly from power transformer test report.

LVAFe

 %EXC  kVArated  1000     100 

Technical manual

Parameter LVACu

8-4

Equation

 %Z  kVArated  1000     100 

LVFe

LVAFe2 - LWFe2 LVCu

LVCu 2 - LWCu 2

Step 2. If it is desired to compensate for line losses then calculate the full load watt line loss and the full load var line loss values (see next section for details on line loss calculation). Parameter

Description

LiWTOT

Total full load watt line loss (line loss watt)

LiVTOT

Total full load var line loss (line loss var)

Step 3. Calculate the per element % correction factors, the meter voltage, and the meter current. These are the values that must be entered into the loss compensation software to configure the meter properly. • If the meter is on the primary side of the power transformer, then Vrated = Vpri rated and Irated = Ipri rated. • If the meter is on the secondary side of the power transformer, then Vrated = Vsec rated and Irated = Isec rated.

Parameter %LWFe

%LWCu

Equation

LWFe 100 Vrated  I rated  Elements

LWCu  LiWTOT  100 V rated  I rated  Elements

%LVFe

%LVCu

LVFe 100 Vrated  I rated  Elements

LVCu  LiVTOT  100 Vrated  I rated  Elements

Meter current

I rated CTR

Loss compensation

Technical manual

Parameter Meter voltage

8-5

Equation

V rated VTR

Calculating line loss Compensation for line losses may include primary losses, secondary losses, or both depending on the application.

Gather necessary data The following information is necessary to calculate the line losses. Parameter

Description

f

Frequency

n

Number of conductors

L

Line length (units compatible with conductor resistance) Conductor resistance (/meter or /kilometer)

Ra 1

GMR

Geometric mean radius of the phase conductors (in meters)

Xa1

Inductive reactance of the conductor at 1ft. spacing (/meter or /kilometer) 1

Either GMR or Xa is required, but not both. The available information determines which is used in the calculations.

Step 1. Calculate line resistance and line reactance The equations below should be applied individually to the primary and the secondary conductors. Parameter

Description

RL

Line resistance ()

XL

Line reactance ()

Deq

Geometric mean distance between phase conductors (in meters)

DL1,L2

Distance between Line 1 and Line 2 (in meters)

DL2,L3

Distance between Line 2 and Line 3 (in meters)

DL3,L1

Distance between Line 3 and Line 1 (in meters)

Parameter

Equation

RL

L  Ra

Calculating the reactive component of the impedance is not as straight forward as the resistance calculation, and the calculation depends on the wiring configuration. The most common configuration is one where the wires are unbundled and the spacing between wires

Loss compensation

Technical manual

8-6

is uniform. Other types of wiring, such as bundled conductors, will not be discussed in this document. Two equations can be used to calculate line reactance. The choice of which equation to use is based on the whether GMR or Xa is available. Item

Equation

XL

If using GMR

If using Xa

 Deq   f   L  0.2794     Log  60   GMR      f  L   X a  0.2794     LogDeq    60    

where:

Deq  3 DL 1,L 2  DL 2 ,L 3  DL 3 ,L 1 Step 2. Calculate the line losses. Item

Description

LiWTOT

Total full load watt line loss (line loss watt)

LiVTOT

Total full load var line loss (line loss var)

Vpri L-L

Primary line-to-line voltage of power transformer

Vsec L-L

Secondary line-to-line voltage of power transformer

Ipri rated

Rated primary current of power transformer

Isec rated

Rated secondary current of power transformer

Note: Vpri L-L, Vsec L-L, Ipri rated, and Isec rated are the same values as used in calculation of transformer losses (see previous section). When compensating for both transformer and line losses: Item LiWsec

LiVsec

LiWpri

LiVpri

LiWTOT

LiVTOT

Equation 2 I sec rated  RL sec  n

2 I sec rated  X L sec  n

2 I pri rated  RL pri  n

2 I pri rated  X L pri  n

LiW sec  LiW pri LiV sec  LiV pri

Loss compensation

Technical manual

8-7

Loss compensation

Note: In the special case that you are compensating only for line loss (no transformer losses), then the values for Ipri rated and Isec rated must be directly specified by the user. Typically, these two values will be inversely proportional to the rated secondary and primary voltages of the power transformer. That is,

I pri rated I secrated



V secrated V pri rated

Step 3. If compensating for both transformer and line losses, return to Step 3 of the previous section using the above calculated line losses to help calculate the %LWCu and %LVCu values. If compensating only for line losses use the following equations to calculate the per element % correction factors, the meter voltage and the meter current for entry in the loss compensation software. • If the meter is on the primary side of the power transformer, Irated = Ipri rated. • If the meter is on the secondary side of the power transformer, Irated = Isec rated. Vrated is the nominal voltage seen on the high side of the instrument transformer supplying voltage to the meter. Parameter

Equation

%LWFe

0

%LWCu

%LVFe %LVCu

Meter current

Meter voltage

LiWTOT  100 Vrated  I rated  Elements 0

LiVTOT  100 Vrated  I rated  Elements

I rated CTR Vrated VTR

Calculation example The following example can be used as a guideline. This is based on the sample transformer data for loss compensation shown in chapter 10 of the Handbook for Electricity Metering (10th edition).2 Application notes: • The application is a bank of three single-phase power transformers. 2 Edison Electric Institute, Handbook for Electricity Metering, tenth edition, Washington, DC: Edison Electric Institute, 2002, Chap-

ter 10, “Special Metering,” pp. 249-88.

Technical manual

8-8

Loss compensation

• The metering occurs on the low (secondary) side of a power transformer, and losses will be added to the measured energy. • There is a delta connection on the secondary of the power transformer and thus a 2element meter will be used to measure the service. • Losses are being compensated for the power transformer only (no line losses).

Gather necessary data Power transformer data (from transformer manufacturer) Parameter

Value Line 1

Line 2

Line 3

KVArated

3333

3333

3333

Vpri L-L

115000

115000

115000

Vsec L-L

2520

2520

2520

LWCu

18935

18400

18692

LWFe

9650

9690

9340

%EXC

1.00

1.06

0.91

%Z

8.16

8.03

8.12

Instrument transformer data: Parameter

Value

CTR

3000  600 5

VTR

2400  20 120

Meter data: Parameter

Value

Elements

2

Step 1. Calculate the quantities Because the metering is on the secondary side of the power transformer, all references to rated voltage and rated current refer to the secondary rated values. Parameter

Description

VAphase

bank of three transformers:

kVArated  1000  3333  1000  3,333,000 Vrated

secondary side, 2-element delta application:

V secL- L  2520

Technical manual

8-9

Parameter

Description

Irated

secondary side application:

3

VA phase V secL- L

 3

3 ,333 ,000  2290.84 2520

Phase 1. Calculations Parameter

Value

LWFe

9650

LWCu

18935

LVAFe

LVACu

 %EXC  kVArated  1000     100   1.00  3333  1000     33 ,330  100   %Z  kVArated  1000     100   8.16  3333  1000     271 ,973  100 

LVFe

LVFe2 - LWFe2 35 ,330 2  9690 2  33 ,975 LVCu

LVACu 2 - LWCu 2 271,923 2  18 ,935 2  271,313 Phase 2. Calculations Parameter

Value

LWFe

9690

LWCu

18400

LVAFe

 % EXC  kVArated  1000     100   1.06  3333  1000     35 ,330  100 

Loss compensation

Technical manual

Parameter LVACu

8-10

Value

%Z  kVArated  1000     100   8.03  3333  1000     267 ,640  100 

LVFe

LVAFe2 - LWFe2 35 ,330 2  9690 2  33 ,975 LVCu

LVACu 2 - LWCu 2 267 ,640 2  18 ,400 2  267 ,007

Phase 3. Calculations Parameter

Value

LWFe

9340

LWCu

18,692

LVAFe

LVACu

 % EXC  kVArated  1000     100   0.91  3333  1000     30 ,330  100   %Z  kVArated  1000     100   8.12  3333  1000     270 ,640  100 

LVFe

LVAFe2 - LWFe2 33 ,330 2  9340 2  28 ,856 LVCu

LVACu 2 - LWCu 2 270 ,640 2  18 ,692 2  269 ,993

Loss compensation

Technical manual

8-11

From the above: Parameter

Value

LWFe

9650 + 9690 + 9340 = 28,680

LWCu

18,935 + 18,400 + 18,692 = 56,027

LVAFe

33,330 + 35,330 + 30,330 = 98,990

LVACu

271,973 + 267,640 + 270,640 = 810,253

LVFe

31,902 + 33,975 + 28,856 = 94,734

LVCu

271,313 + 267,007 + 269,993 = 808,313

Step 2. Compensate for line loss (if needed). Per the stated assumptions, there is no compensating for line losses: Parameter

Value

LiWTOT

0

LiVTOT

0

Step 3. Now the per element % correction factors may be calculated: Parameter %LWFe

%LWCu

Value

LWFe 100 Vrated  I rated  Elements 28 ,680  100  0.2484 2520  229084  2

LWCu  LiWTOT  100 Vrated  I rated  Elements 56 ,027  100  0.4853 2520  2290.84  2

%LVFe

%LVCu

LVFe 100 Vrated  I rated  Elements 94 ,734  100  0.8205 2520  2290.84  2

LVCu  LiVTOT  Vrated  I rated  Elements 808 ,313  100  7.0009 2520  2290.84  2

Meter current

I rated 2290.84   3.82 A CTR 600

Loss compensation

Technical manual

Parameter Meter voltage

8-12

Loss compensation

Value

Vrated 2520   126 V VTR 20

Enter Data Summary of calculated values to enter in A1800 ALPHA Meter Loss Compensation Tool Parameter

Value

Registration

Add losses

Iron watts correction % (%LWFe)

0.2484

Copper watts correction % (%LWCu)

0.4853

Iron vars correction % (%LVFe)

0.8205

Copper vars correction % (%LVCu)

7.0009

Meter current

3.82

Meter voltage

126

Internal meter calculations To understand the loss compensation calculations, it is first necessary to understand a little bit about how the A1800 ALPHA meter engine operates. Internal to the meter engine, Vrms and Irms are measured independently on each phase every two line cycles. These values are used to perform the normal energy calculations on each phase every two line cycles. The individual phase measurements are then summed. This drives an internal accumulator in the meter engine that generates a pulse to the microcontroller when a threshold level is reached. The threshold level at which a pulse is generated is known as the meter Ke (energy per pulse). There are separate calculations, separate accumulators and separate Ke pulses generated for each measured energy quantity (for example, kWh-delivered, kvarh-delivered). When loss compensation is turned on, additional calculations are performed. Every two line cycles on each phase, the Vrms and Irms values used in the normal energy calculations are also used to calculate a watt compensation value and a var compensation value. The following equations indicate the compensation terms that are calculated and applied to the normal energy measurements every two line cycles. For a 3-element meter, watts and vars are compensated every two line cycles according to the following equations: Compensation W

var

Equation

 G  V

 

R  I L1 meas2  I L2 meas2  I L3 meas2 

 B  V

2 L1 meas

V

2 L2 meas

V

2 c meas



X  I L1 meas2  I L2 meas2  I L3 meas2  4 L1 meas

 V L2 meas4  Vc meas4



Technical manual

8-13

Loss compensation

For a 2-element meter, watts and vars are compensated every two line cycles according to the following equations: Compensation W

var

Equation

 G  V

 

R  I L1 meas2  I L3 meas2 

 B  V

2 L1 meas

 Vc meas2



X  I L1 meas2  I L3 meas2  4 L1 meas

V

4 c meas



Where:

Term

Description

R

Per element resistance

G

Per element conductance

X

Per element reactance

B

Per element susceptance

Ixmeas

Per phase rms current

Vxmeas

Per phase rms voltage

The A1800 ALPHA Meter Loss Compensation Tool calculates R, G, X, and B using the following formulas and then programs these values into the meter. Item R

G

X

B

Equation

%LWCu  Meter voltage Meter current 100 %LWFe  Meter current Meter voltage 100

%LVCu  Meter voltage Meter current 100 %LVFe Meter current Meter voltage3  100

The compensation terms will be either positive or negative depending on whether losses are configured to be added or subtracted from the energy measurements. So, the key difference on meters with loss compensation is that every two line cycles on each phase, the calculated W compensation value is summed with the normal Wh energy calculations. Similarly, the var

Technical manual

8-14

compensation term is summed per phase every two line cycles with the normal varh energy calculations. From that point everything is essentially the same (individual phases are then summed to drive an accumulator). Note regarding two-element meters: Two-element ALPHA meters are unique in that they create an artificial internal reference that is used to measure the phase voltages. For example, line 3 experiences a loss of voltage while the meter remains powered (either from line 1 or from an auxiliary supply) the internal meter engine will still measure a line 3 voltage equal to one-half of the line 1 voltage. In applications where loss compensation is not applied this has no impact on the measurement of energy because no power will be drawn by the load on line 3. That is, line 3 current equals zero and so the net energy measured on line 3 is accurately calculated as zero. However, in the special case of a meter that is compensating for transformer losses, the no-load compensation terms are based solely on the measured voltage on each phase (see above formulas). Therefore, on 2-element ALPHA meters with loss compensation enabled, if line 3 voltage is lost while the meter remains powered, the no load compensation terms for line 3 will be in error because they will be calculated based on onehalf the line 1 voltage. The same situation would result if line 1 experiences a loss of voltage.

Loss compensation

Technical manual

8-15

Meter outputs affected by compensation When loss compensation is enabled on an A1800 ALPHA meter, all of the following collected data use the compensated values: • all register billing data • all pulse profile data • all KYZ pulse outputs • all test pulses (both in the LCD and on the LED) Compensation does not affect instrumentation values or the meter features that use instrumentation values. Regardless of the status of loss compensation, all instrumentation values reflect the actual measured values as seen at the meter terminals. For example, per phase voltage values are not affected (whether displayed on the LCD or reported in meter support software). Likewise TRueQ functions and instrumentation profiling values are not affected when compensation is active.

Testing a meter with compensation The LEDs on A1800 ALPHA meters always reflect the current measurement algorithm in the meter engine. That is, if compensation is turned on then the LEDs will indicate compensated energy. If compensation is turned off then the LEDs will indicate uncompensated energy. Because the LED always reflects the state of the compensation it reduces the chance that a meter with active compensation is accidentally installed unknowingly. Using the A1800 ALPHA Meter Loss Compensation Tool, it is possible to configure the meter to automatically turn off compensation whenever the meter enters test mode. This may or may not be desired depending on utility testing practices. The loss compensation software also permits the A1800 ALPHA meter loss compensation function to be manually turned off and turned on without altering the loss compensation parameters configured in the meter. Utilities may desire to calculate the expected test results of a compensated meter and then test the meter with active compensation to verify that the expected results are obtained.

Loss compensation

Technical manual

8-16

Loss compensation

Technical manual

Technical manual

A-1

A Glossary

* button. The push button that activates the alternate mode. It also can be used to control the scrolling of display quantities in the different operating modes. Alpha Keys. A system combining hardware and software to upgrade existing A1800 ALPHA meters. Keys allow addition of new functionality to an existing meter for an additional fee. alternate mode. The operating mode in A1800 ALPHA meters used to display a second set of display quantities on the LCD. It is generally activated by pressing the Q button on the meter. A typical use of the alternate mode is to display non-billing data as programmed by Elster meter support software. AvgPF. see average power factor. average power factor. Calculated once every second, when the meter is not in test mode, using the following formula:

AvgPF 

kWh kvarh 2  kWh 2

billing data. The measured quantities recorded and stored by the meter for use in billing the consumer. May also be referred to as tariff data. bit. Short for binary digit. It is the smallest information unit used in data communications and storage. coincident. Information regarding one parameter occurring at the same time as another. For example, coincident kvar demand is the kvar demand occurring during the interval of peak kW demand. communication session count. The number of data-altering communications occurring since the A1800 ALPHA meter was last programmed or a clear of the values and status. complete LCD test. A display showing 8 in all the display areas and all identifiers on the LCD turned on. This confirms that all segments are operating properly. continuous cumulative. A display technique used with demand calculations and similar to cumulative demand except continuous cumulative demand is updated constantly. CTR. see current transformer ratio. cumulative. A display technique used with demand calculations. Upon a demand reset, the present maximum demand is added to the sum of the previous maximum billing period demand values. current transformer ratio. The ratio of the primary current to the secondary current of a current transformer. For example, 400 A to 5 A would have a current transformer ratio of 400:5 or 80:1.

Glossary

Technical manual

A-2

data-altering communication. Any communication that performs any of the following actions: • writes to a meter table • clears data • resets log pointers or data set pointers • resets the demand • performs a self read • performs a season change del. see delivered. delivered. Used to specify the energy delivered (provided) to an electric service. demand. The average power computed over a specific time. demand forgiveness. The number of minutes that demand will not be calculated following a recognized power outage. This provides a time period immediately following the restoration of power during which startup power requirements will not be included in the calculated demand. demand interval. The time period over which demand is calculated. Demand interval must be evenly divisible into 60 minutes. demand reset. The act of resetting the present maximum demand to zero. demand reset count. The total number of demand resets since the meter was last programmed. demand reset date. The date of the last demand reset. demand threshold. The present value of demand which when reached initiates a relay closure or other programmed action. display quantity. Any value available for display on the LCD. EEPROM. Acronym for electrically erasable programmable read only memory. This memory retains all information even when electric power is removed from the circuit. EOI. see end of interval. end of interval. The indication that the end of the time interval used to calculate demand has occurred. An EOI indicator is on the LCD and an optional relay can be supplied to provide an EOI indication. energy. Power measured over time. error display. The method by which the meter displays an error message which consists of E and numeric codes. The code indicates a condition or conditions that can adversely affect the proper operation of the meter. event log. The event log provides a record of entries that date and time stamp specific events such as: • power outages • demand resets • entering test mode • time changes external display multiplier. Used when the transformer factor is larger than can be stored within the A1800 ALPHA meter. When programmed with Elster meter support software for an external display multiplier, display quantities read from the meter LCD must be manually multiplied by this value to yield proper readings.

Glossary

Technical manual

A-3

Glossary

factory default. Operating parameters that are programmed into the meter at the factory and assure that the meter is ready for correct energy measurement when installed. four quadrant metering. See Figure A-1 for an illustration of energy relationships for delivered and received real power (kW), apparent power (kVA), and reactive power (kVAR).

Figure A-1. Four quadrant metering quantity relationships

kvar Delivered

Lag

Q2 Q2

Q1 Q1

Q3 Q3

Q4 Q4

Lead

kVA Delivered kW Delivered

kVA Received kW Received

Lag

Lead

kvar Received

IC. see integrated circuit. instrument transformer. A transformer used to reduce current and voltage to a level which does not damage the meter. Meter readings will need to be increased by the transformer ratios to reflect the energy and demand values on the primary side of the instrument transformer. integrated circuit. Generally used to reference the custom meter circuit used in the A1800 ALPHA meter for per phase voltage and current sampling plus energy measurements. Ke. The smallest discrete amount of energy available within the meter. It is the value of a single pulse used between the meter IC and the microcontroller. kW overload value. The kW threshold which, when exceeded, will cause the display of the kW overload warning message. LC. see load control. LCD. see liquid crystal display. LP. see load profile. line frequency. The frequency of the AC current on the transmission line, often used in timekeeping applications in lieu of the internal oscillator. On default the line frequency is 50Hz. liquid crystal display. The LCD allows metered quantities and other information about the A1800 ALPHA meter and installed service to be viewed. Display quantities are programmable through Elster meter support software. load control. Used to describe a relay dedicated to operate based upon entering a specific TOU rate period or when a demand threshold is reached.

Technical manual

A-4

load profiling. Load profiling records energy usage per a specific time interval while the meter is energized. Load profiling data provides a 24 hour record of energy usage for each day of the billing period. maximum demand. The highest demand calculated during any demand interval over a billing period. microcontroller. A single chip that contains the following components: • main processor • RAM • ROM • clock • I/O control unit nonrecurring dates. Holidays or other specific dates that are not based upon a predictable, repeated pattern. normal mode. The default operating mode for the A1800 ALPHA meter. Typically, normal mode displays billing data on the LCD following a programmed sequence. optical port. A photo-transistor and an LED on the face of the meter that is used to transfer data between a computer and the meter via pulses of light. outage log. Display quantity that shows the cumulative total outage time in minutes. P/R. see pulse ratio. previous billing data. Used to describe the billing data recorded at the demand reset. See also self read. previous season data. Used to describe the billing data for the season preceding the present billing season. primary rated. A condition where the energy and demand as measured by the meter are increased by the current and voltage transformer ratios. Meter data will reflect the energy and demand actually transferred on the primary side of the instrument transformers. program change date. The date when the meter program was last changed. program mode. The operating mode of the meter in which full reprogramming of metrological parameters is permitted. pulse ratio. Pulses per equivalent disk revolution. On ALPHA meters, 1 revolution is equal to 1 Kh period. pulse relay. A relay used with the meter to provide output pulses from the meter to an external pulse collector. Each pulse represents a specific amount of energy consumption. rec. see received. received. Used to specify the energy received by the utility at an electric service. recurring dates. Holidays or other special dates that occur on a predictable basis. self read. The capturing of current billing data and storing it in memory. Self reads are scheduled events that can be triggered by the specific day of month, every set number of days, or command by Elster meter support software. See also previous billing data. tariff data. See billing data. TOU. see time-of-use. TOU meter. A meter that records energy usage and demand data on a time-of-use basis.

Glossary

Technical manual

A-5

test mode. The test mode stores billing data in a secure memory location while the meter measures and displays energy and demand data for testing purposes. The TEST identifier will flash while the test mode is active. When test mode is exited, the accumulated test data is discarded and the original billing data is restored. timekeeping. The ability of the meter to keep a real time clock, including date and time. time-of-use. A billing rate that records energy usage and demand data related to specific times during the day. See also timekeeping. transformer-rated. A meter designed to work with current or voltage transformers. The maximum current of a transformer-rated A1800 ALPHA meter is typically 10 A. voltage transformer ratio. The ratio of primary voltage to secondary voltage of a transformer. For example, 12,000 V to 120 V would have a voltage transformer ratio of 100:1. VTR. see voltage transformer ratio. watthour constant. A meter constant representing the watthours per output pulse on the LED. Historically, the constant represents the energy equivalent to one revolution of an electromechanical meter.

Glossary

Technical manual

A-6

Glossary

Technical manual

Technical manual

B-1

Display table

B Display table

Display format Displayable items are described in “Display list items” on page B-2. The A1800 ALPHA meter supports up to 64 quantities for display on the LCD. The LCD can be divided into different regions, as described in Table B-1. See “Indicators and controls” on page 3-1 for more detailed information on the LCD regions.

Figure B-1. A1800 ALPHA meter LCD Low battery indicator

Phase indicators (3)

Error/warning indicator Energy direction indicators

Quantity identifier

Alternate mode indicator Comm. port indicator

Display quantity

Power/energy units identifier Tariff indicators 1 to 4 (left to right)

Reserved

EOI indicator

Test mode indicator Cover removed indicator

LC indicator

Table B-1. LCD regions Item

Description

quantity identifier

identifies the displayed quantity. Using Elster meter support software, an identifier can be assigned to most quantities. For instrumentation quantities, the identifiers are fixed.

alternate display indicator

indicates that the meter is currently displaying items in the alternate display list (see “* button” on page 3-5)

active COM port indicators

indicates that a communication session is in progress and the communication port that is being used: either COM 0, COM 1, or COM 2

power/energy units identifier

indicates the unit of measurement for the quantity currently displayed on the LCD.

display indicators

indicates whether the meter is currently doing the following: • accumulating in tariff (T1 - T4) • has reached the end of an interval (EOI) • compensating for transformer line loss (LC) • indicating that either the terminal cover or the meter cover has been removed • is operating in test mode (see “Test mode” on page 3-8)

Technical manual

B-2

Table B-1. LCD regions Item

Description

display quantity

Shows metered quantities or other displayable information. From 3 to 8 total digits with up to 9 decimal places can be used. These digits are also used to report the following: • operational errors • system instrumentation and service test errors • warnings • communication codes

display identifiers

more precisely identifies the information presented on the LCD.

energy direction indicators

indicates the directions of active (P) and reactive (Q) energy flow (positive energy flow is energy delivered to the consumer load, while reverse energy flow is energy received from the consumer load)

error indicator

indicates either of the following: • flashes when any error flag is set • remains on if a displayable warning flag is set and no error exists

low battery indicator

if the indicator is turned on, the battery warning flag has been set.

phase indicators

L1, L2, and L3 (Line 1, Line 2, and Line 3, respectively) correspond to a phase voltage present on the A1800 ALPHA meter connections. • If the indicators are on, then all phase voltages are present. • If an indicator is blinking, then that phase voltage is either missing or below the defined threshold for voltage sag detection.

Display list items The display list items for the normal mode, alternate mode, and test mode are programmed from the 64 available items. The display format for all displayable items can be programmed using Elster meter support software. The A1800 ALPHA meter LCD is capable of supporting the following characters and symbols: • all numbers (0 to 9) • all Latin-based alphabetical characters • symbols such as ° (degree), * (asterisk), [ (left bracket), and ] (right bracket) Additional display items may also be available depending upon the version of Elster meter support software. See the software documentation for a list of the displayable items. Displayable items can be grouped into the following categories: • LCD test • general meter information • meter configuration • status • metered quantities • average power factor • coincident demand and power factor

Display table

Technical manual

B-3

Display table

• system instrumentation • system service test • errors and warnings • communication codes

Default display formats The display areas on the LCD (such as the display quantity and display identifier) are programmable through Elster meter support software. See “Display format” on page B-1 for more information. The following sections describe the default behavior of the A1800 ALPHA meter display. See Table B-2 for a description of some of the special characters that have been used in the display quantity examples.

Table B-2. Characters in display quantity examples Character

Represents Blank (space)

.

Decimal

-

hyphen; represents testing in progress

*

asterisk; represents all 16 character segments on

:

colon; separates time units (hh:mm), etc.

a

Any alphanumeric character displayable on the LCD.

dd

Numeric character; represents day (01 to 31)

H

Indicates the day type is holiday

hh

Numeric character; represents time in hours (01 to 24)

mm

Numeric character; represents time in minutes (00 to 59)

MM

Numeric character; represents month (01 to 12)

x

Any numeric character.

ss

Numeric character; represents time in seconds (00 to 59)

YY

Numeric character; represents two digit year (00 to 99)

LCD test The A1800 ALPHA meter tests the LCD by displaying all the identifiers, as shown in Figure B-2. The meter tests the LCD for 3 seconds after power up.

Figure B-2. LCD all segment test + Q -P

+P - Q

L1 L2 L3 COM 0 1 2

Technical manual

Display description LCD test [all segment test]

B-4

Display table

Display quantity

Quantity ID

Units ID

*******

********

[all segments]

General meter information General meter information quantities are items that are not associated with any particular pulse or instrumentation source. Display description

Display quantity

Quantity ID

Identifier String 1 [Account:1]

aaaaaaaa

ID 1-1 of 4

Identifier String 1 [Account:2]

aaaaaaaa

ID 1-2 of 4

Identifier String 1 [Account:3]

aaaa

ID 1-3 of 4

Identifier String 1 [Account:4]

ID 1-4 of 4

Identifier String 2 [Meter ID:1]

aaaaaaaa

ID 2-1 of 4

Identifier String 2 [Meter ID:2]

aaaaaaaa

ID 2-2 of 4

Identifier String 2 [Meter ID:3]

aaaa

ID 2-3 of 4

Identifier String 2 [Meter ID:4] Meter type

Units ID

ID 2-4 of 4 A1800

TYPE

Firmware product

xxx

FW

Firmware version

xxx

FWV

Firmware revision

xxx

FWR

Hardware version

xxx

HDWV

Hardware revision

xxx

HDWR

DSP code

xxx

DSP

DSP code revision

xxx

DSPR

Meter Programmer ID

xxxxxxxx

LCD test [all segment test]

*******

********

[all segments]

Display quantity

Quantity ID

Units ID

Program ID

xxxxxxxx

PRG ID

Pulse ratio (P/R)

x.xxxxxxx

P/R

Pulse output ratio [imp/kWh]

xxxxx.xxx

imp/kWh

Current transformer (CT) ratio

xxxxxxxx

CT

Voltage transformer (VT) ratio

xxxxxxxx

VT

Demand interval - normal mode

xxxxxxxx

INTERV

Demand interval - test mode

xxxxxxxx

INTERVT

Watthours per pulse (Ke)

xxxxxxxx

Wh/Imp

Meter Kh

xxxxxxxx

Kh

Transformer factor (CT × VT)

xxxxxxxx

CTxVT

External multiplier

xxx.xxxxx

ExtMult

Meter configuration Display description

Technical manual

Display description

B-5

Display table

Display quantity

Quantity ID

xxxxx.xxx

DmdOvld

Display quantity

Quantity ID

Communication session count (port 1)

xxxxxxxx

Com1No

Communication session count (port 2/optical)

xxxxxxxx

Com2No

Days since demand reset

xxxxxxxx

ResDays

Days since input pulse

xxxxxxxx

ImpDays

Number of manual demand resets

xxxxxxxx

RstPress

Number of all demand resets

xxxxxxxx

DmdRes

Power outage count

xxxxxxxx

Outages

Initial remote baud (port 1)

xxxxxxxx

COM1bps

Initial remote baud (port 2)

xxxxxxxx

COM2bps

Transformer Loss Comp Status

xxxxxxxx

Demand overload value

Units ID

Status Display description

TRueQ Status (On/Off)

On Off

Outage Log Program Change Date (port 1)

MM:dd:YY

Program Change Date (port 2/optical)

MM:dd:YY

Last Elster configuration change date

MM:dd:YY

CnfDate

Demand reset date

MM:dd:YY

DmdRes

Last power outage start date

MM:dd:YY

Outage

Last power outage start time

hh:mm

Outage

Last power outage end date

MM:dd:YY

Restore

Last power outage end time

hh:mm

Restore

Present date

MM:dd:YY

Date

Present time

hh:mm

Time

Present day of week

aaaaaaaa

Day

Present season

aaaaaaaa

Season

MM:dd:YY

TblActv

hh:mm

Sub Int

Pulse count for quantity (Wh-delivered)

xxxxxxxx

ImpWhD

Pulse count for quantity (alternate-delivered)

xxxxxxxx

ImpE2D

Pulse count for quantity (Wh-received)

xxxxxxxx

ImpWhR

Pulse count for quantity (alternate-received)

xxxxxxxx

ImpE2R

Date of last pending table activation Time Left in interval

Self Read Date

MM:dd:YY

Effective Date for Rates/Special Dates

MM:dd:YY

Number of Write Sessions (port 1)

xxxxxxxx

Number of Write Sessions (port 2/optical)

xxxxxxxx

Units ID

Technical manual

B-6

Display table

Metered quantities A1800 ALPHA meters can measure two quantities. Meters with the optional 4-quadrant metering can measure eight quantities. The A1800 ALPHA meter can display the available metered quantities for each meter type. To indicate a self read quantity, the LCD will use the last two characters of the quantity identifier to indicate the last self read number (01 to 35). Display description

Display ID

Display quantity

Quantity ID

Units ID

Current billing, Previous billing, Previous season, Last self read Total energy

xxxxxxxx

Deliver Receive Q1 Q2 Q3 Q4

kWh/kVAh/kvarh

Maximum demand

xxxxxxxx

Del MD Rec MD Q1 MD Q2 MD Q3 MD Q4 MD

kW/kVA/kvar

Date of maximum demand

MM:dd:YY

MD Date

Time of maximum demand

hh:mm

MD Time

xxxxxxxx

Del CMD Rec CMD Q1 CMD Q2 CMD Q3 CMD Q4 CMD

kW/kVA/kvar

Cumulative demand

Tariff 1 energy

T1

xxxxxxxx

Deliver Receive Q1 Q2 Q3 Q4

kWh/kVAh/kvarh

Tariff 1 maximum demand

T1

xxxxxxxx

Del MD Rec MD Q1 MD Q2 MD Q3 MD Q4 MD

kW/kVA/kvar

Tariff 1 date of maximum demand

T1

MM:dd:YY

MD Date

Tariff 1 time of maximum demand

T1

hh:mm

MD Time

Tariff 1 cumulative demand

T1

xxxxxxxx

Del CMD Rec CMD Q1 CMD Q2 CMD Q3 CMD Q4 CMD

kW/kVA/kvar

Technical manual

B-7

Display description

Display ID

Display table

Display quantity

Quantity ID

Units ID

Current billing, Previous billing, Previous season, Last self read Tariff 2 energy

T2

xxxxxxxx

Deliver Receive Q1 Q2 Q3 Q4

kWh/kVAh/kvarh

Tariff 2 maximum demand

T2

xxxxxxxx

Del MD Rec MD Q1 MD Q2 MD Q3 MD Q4 MD

kW/kVA/kvar

Tariff 2 date of maximum demand

T2

MM:dd:YY

MD Date

Tariff 2 time of maximum demand

T2

hh:mm

MD Time

Tariff 2 cumulative demand

T2

xxxxxxxx

Del CMD Rec CMD Q1 CMD Q2 CMD Q3 CMD Q4 CMD

kW/kVA/kvar

Tariff 3 energy

T3

xxxxxxxx

Deliver Receive Q1 Q2 Q3 Q4

kWh/kVAh/kvarh

Tariff 3 maximum demand

T3

xxxxxxxx

Del MD Rec MD Q1 MD Q2 MD Q3 MD Q4 MD

kW/kVA/kvar

Tariff 3 date of maximum demand

T3

MM:dd:YY

MD Date

Tariff 3 time of maximum demand

T3

hh:mm

MD Time

Tariff 3 cumulative demand

T3

xxxxxxxx

Del CMD Rec CMD Q1 CMD Q2 CMD Q3 CMD Q4 CMD

kW/kVA/kvar

Tariff 4 energy

T4

xxxxxxxx

Deliver Receive Q1 Q2 Q3 Q4

kWh/kVAh/kvarh

Tariff 4 maximum demand

T4

xxxxxxxx

Del MD Rec MD Q1 MD Q2 MD Q3 MD Q4 MD

kW/kVA/kvar

Technical manual

B-8

Display description

Display ID

Display table

Display quantity

Quantity ID

Units ID

Current billing, Previous billing, Previous season, Last self read Tariff 4 date of maximum demand

T4

MM:dd:YY

MD Date

Tariff 4 time of maximum demand

T4

hh:mm

MD Time

Tariff 4 cumulative demand

T4

xxxxxxxx

Del CMD Rec CMD Q1 CMD Q2 CMD Q3 CMD Q4 CMD

kW/kVA/kvar

Display quantity

Quantity ID

Units ID

xxxxxxxx

AvgPF

Present Interval (current billing only) Previous Interval (current billing only)

Average power factor For each average power factor, the following items are available for display. Display description

Display ID

Average power factor Tariff 1 average power factor

T1

xxxxxxxx

AvgPF

Tariff 2 average power factor

T2

xxxxxxxx

AvgPF

Tariff 3 average power factor

T3

xxxxxxxx

AvgPF

Tariff 4 average power factor

T4

xxxxxxxx

AvgPF

Coincident demand and power factor The A1800 ALPHA meters can measure two coincident quantities. Additionally, meters with the 4-quadrant metering option can measure four coincident quantities. Coincident quantities are configurable with Elster meter support software to be any demand or average power factor value captured at the time of a maximum demand value. For each coincident value, the following items is available for display: Display description

Display ID

Coincident demand

Display quantity

Quantity ID

Units ID

xxxxxxxx

CoinDmd

kW/kVA/kvar

Tariff 1 coincident demand

T1

xxxxxxxx

CoinDmd

kW/kVA/kvar

Tariff 2 coincident demand

T2

xxxxxxxx

CoinDmd

kW/kVA/kvar

Tariff 3 coincident demand

T3

xxxxxxxx

CoinDmd

kW/kVA/kvar

Tariff 4 coincident demand

T4

xxxxxxxx

CoinDmd

kW/kVA/kvar

x.xxx

CoinPF

kW/kVA/kvar

Coincident power factor Tariff 1 coincident power factor

T1

x.xxx

CoinPF

kW/kVA/kvar

Tariff 2 coincident power factor

T2

x.xxx

CoinPF

kW/kVA/kvar

Tariff 3 coincident power factor

T3

x.xxx

CoinPF

kW/kVA/kvar

Tariff 4 coincident power factor

T4

x.xxx

CoinPF

kW/kVA/kvar

Technical manual

B-9

Display table

Cumulative demand The A1800 ALPHA meter records either the cumulative or continuous cumulative demand. Display description

Display ID

Cumulative demand

Display quantity

Quantity ID

Units ID

xxxxxxxx

CumDmd

kW/kVA/kvar

Tariff 1 cumulative demand

T1

xxxxxxxx

CumDmd

kW/kVA/kvar

Tariff 2 cumulative demand

T2

xxxxxxxx

CumDmd

kW/kVA/kvar

Tariff 3 cumulative demand

T3

xxxxxxxx

CumDmd

kW/kVA/kvar

Tariff 4 cumulative demand

T4

xxxxxxxx

CumDmd

kW/kVA/kvar

System instrumentation The A1800 ALPHA meter can display system instrumentation quantities. See “System instrumentation” on page 4-1 for a listing of the instrumentation quantities that can be displayed. Display description

Display quantity

Quantity ID

xx.xxHz

L123

Line 1 voltage (secondary) Line 1 voltage (primary)

xxx.xxx V xxx.xxxkV

L1

Line 2 voltage (secondary) Line 2 voltage (primary)

xxx.xxx V xxx.xxxkV

L2

Line 3 voltage (secondary) Line 3 voltage (primary)

xxx.xxx V xxx.xxxkV

L3

Line 1 current (secondary) Line 1 current (primary)

xxx.xxx A xxx.xxxkA

L1

Line 2 current (secondary) Line 2 current (primary)

xxx.xxx A xxx.xxxkA

L2

Line 3 current (secondary) Line 3 current (primary)

xxx.xxx A xxx.xxxkA

L3

Line 1 power factor

xx.xx

L1 COS

Line 2 power factor

xx.xx

L2 COS

Line 3 power factor

xx.xx

L3 COS

Line 1 power factor angle

xxx.xx°

L1

Line 2 power factor angle

xxx.xx°

L2

Line 3 power factor angle

xxx.xx°

L3

Line 1 voltage phase angle

xxx.xx°V

L1

Line 2 voltage phase angle

xxx.xx°V

L2

Line 3 voltage phase angle

xxxx.x°V

L3

Line 1 current phase angle

xxx.x°A

L1

Line 2 current phase angle

xxx.x°A

L2

Line 3 current phase angle

xxx.x°A

L3

Line 1 kW (primary) Line 1 kW (secondary)

xxxx.xxxx xxx.xxx

L1

kW MW

Line 2 kW (primary) Line 2 kW (secondary)

xxxx.xxxx xxx.xxx

L2

kW MW

Line frequency

Units ID

Technical manual

B-10

Display description

Display table

Display quantity

Quantity ID

Units ID

Line 3 kW (primary) Line 3 kW (secondary)

xxxx.xxxx xxx.xxx

L3

kW MW

Line 1 kvar (primary) Line 1 kvar (secondary)

xxxx.xxxx xxx.xxx

L1

kvar Mvar

Line 2 kvar (primary) Line 2 kvar (secondary)

xxxx.xxxx xxx.xxx

L2

kvar Mvar

Line 3 kvar (primary) Line 3 kvar (secondary)

xxxx.xxxx xxx.xxx

L3

kvar Mvar

Line 1 kVA (primary) Line 1 kA (secondary)

xxxx.xxxx xxx.xxx

L1

kVA MVA

Line 2 kVA (primary) Line 2 kA (secondary)

xxxx.xxxx xxx.xxx

L2

kVA MVA

Line 3 kVA (primary) Line 3 kA (secondary)

xxxx.xxxx xxx.xxx

L3

kVA MVA

System kW (primary) System kW (secondary)

xxxx.xxxx xxx.xxx

L123

kW MW

System kvar (primary) (arithmetic) System kvar (secondary) (arithmetic)

xxxx.xxxx xxx.xxx

L123

kvar Mvar

System kVA (primary) (arithmetic) System kVA (secondary) (arithmetic)

xxxx.xxxx xxx.xxx

L123

kVA MVA

xx.xx

L123.COS

xx.xx °

L123

System kvar (primary) (vectorial) System kvar (secondary) (vectorial)

xxxx.xxxx xxx.xxx

L123

kvar Mvar

System kVA (primary) (vectorial) System kVA (secondary) (vectorial)

xxxx.xxxx xxx.xxx

L123

kVA MVA

xx.xx

L123.COS

xx.xx °

L123

Line 1 voltage % total harmonic distortion (THD)

xx.xx%V

L1.H2-15

Line 2 voltage % total harmonic distortion (THD)

xx.xx%V

L2.H2-15

Line 3 voltage % total harmonic distortion (THD)

xx.xx%V

L3.H2-15

Line 1 current % total harmonic distortion (THD)

xx.xx%A

L1.H2-15

Line 2 current % total harmonic distortion (THD)

xx.xx%A

L2.H2-15

Line 3 current % total harmonic distortion (THD)

xx.xx%A

L3.H2-15

Line 1 total demand distortion (TDD)

xx.xx A

L1 TDD

Line 2 total demand distortion (TDD)

xx.xx A

L2 TDD

Line 3 total demand distortion (TDD)

xx.xx A

L3 TDD

Line 1 fundamental voltage magnitude (secondary) Line 1 fundamental voltage magnitude (primary)

xxx.xxx V xxx.xkV

L1 H1

Line 2 fundamental voltage magnitude (primary) Line 2 fundamental voltage magnitude (secondary)

xxx.xxxkV xxx.x V

L2 H1

Line 3 fundamental voltage magnitude (primary) Line 3 fundamental voltage magnitude (secondary)

xxx.xxxkV xxx.x V

L3 H1

Line 1 fundamental current magnitude (primary) Line 1 fundamental current magnitude (secondary)

xxx.xxxkA xxx.x A

L1 H1

System power factor (arithmetic) System power factor angle (arithmetic)

System power factor (vectorial) System power factor angle (vectorial)

Technical manual

B-11

Display description

Display table

Display quantity

Quantity ID

Line 2 fundamental current magnitude (primary) Line 2 fundamental current magnitude (secondary)

xxx.xxxkA xxx.x A

L2 H1

Line 3 fundamental current magnitude (primary) Line 3 fundamental current magnitude (secondary)

xxx.xxxkA xxx.x A

L3 H1

Line 1 2nd harmonic voltage magnitude (primary) Line 1 2nd harmonic voltage magnitude (secondary)

xxx.xxxkV xxx.x V

L1 H2

Line 2 2nd harmonic voltage magnitude (primary) Line 2 2nd harmonic voltage magnitude (secondary)

xxx.xxxkV xxx.x V

L2 H2

Line 3 2nd harmonic voltage magnitude (primary) Line 3 2nd harmonic voltage magnitude (secondary)

xxx.xxxkV xxx.x V

L3 H2

Line 1 2nd harmonic current magnitude (primary) Line 1 2nd harmonic current magnitude (secondary)

xxx.xxxkA xxx.x A

L1 H2

Line 2 2nd harmonic current magnitude (primary) Line 2 2nd harmonic current magnitude (secondary)

xxx.xxxkA xxx.x A

L2 H2

Line 3 2nd harmonic current magnitude (primary) Line 3 2nd harmonic current magnitude (secondary)

xxx.xxxkA xxx.x A

L3 H2

Line 1 2nd harmonic voltage % distortion

xx.xx%V

L1 H2

Line 2 2nd harmonic voltage % distortion

xx.xx%V

L2 H2

Line 3 2nd harmonic voltage % distortion

xx.xx%V

L3 H2

Line 1 harmonic current distortion (2nd - 15th) (primary) Line 1 harmonic current distortion (2nd - 15th) (secondary)

xxx.xxxkA

L1 H2-15

Line 2 harmonic current distortion (2nd - 15th) (primary) Line 2 harmonic current distortion (2nd - 15th) (secondary)

xxx.xxxkA

Line 3 harmonic current distortion (2nd - 15th) (primary) Line 3 harmonic current distortion (2nd - 15th) (secondary)

xxx.xxxkA

Units ID

xxx.x A L2 H2-15

xxx.x A L3 H2-15

xxx.x A

System service tests The A1800 ALPHA meter can display the validity of the electricity service where it is installed. See “System service tests” on page 4-5 for more information. Display description

Display quantity

Quantity ID

Service Voltage Test

--------

TEST V

xxxxxxxx

SE

Service Current Test

OK --------

TEST I

System Service Type

xxx 4Y xxx 3 xxx 1L

L1-2-3 L3-2-1

[xxx 4Y] [xxx 3] [xxx 1L]

L1-2-3 L3-2-1

System Test Error

Currently locked service

Units ID

Technical manual

B-12

Errors and warnings The A1800 ALPHA meter displays error codes and warning codes as an indication of a problem that may be affecting its operation. See “Error codes” on page 6-2 and “Warning codes” on page 6-5 for more information.

Communication codes The A1800 ALPHA meter indicates the status of a communication session by displaying it on the LCD. See “Communication codes” on page 6-8.

Display table

Technical manual

Technical manual

C-1

Nameplate and style number information

C Nameplate and style number information

Nameplate The nameplate provides important information about the meter. The nameplate can be configured to meet the needs of the utility company; however, Figure C-1 is an illustration of a A1800 ALPHA nameplate for both transformer rated and direct connected meters.

Figure C-1. Sample nameplates

Elster Metronica style number

LCD indcator labels

LED pulse settings

Voltage rating and frequency Nominal (max) current and frequency

Accuracy Class 0.2S (active) and GOST no.

Isolation Class 2 symbol

Accuracy Class 0.5 (reactive) and TU no.

Number of elements

Pulse output settings

Current and voltage transformer ratios Customer name or Elster Metronica on default Meter serial number and barcode

Elster Metronica style number Voltage rating and frequency

Certification symbols Elster logo Year and place of manufacture

LCD indcator labels

LED pulse settings

Nominal (max) current and frequency Isolation Class 2 symbol Number of elements Pulse output settings Customer name or Elster Metronica on default Meter serial number and barcode

Accuracy Class 1 (active) and GOST no. Accuracy Class 2 (reactive) and GOST no.

Certification symbols Elster logo Year and place of manufacture

Technical manual

C-2

Utility information card The removable utility information card provides a place for the utility to enter meter sitespecific information (for example, CT, VT, etc.). Figure C-2 is an example of a utility information card.

Figure C-2. Utility information card (transformer rated)

CT

A

VT

V

imp/kWh(kVARh)

Figure C-3. Utility information card (direct connect rated)

Nameplate and style number information

Technical manual

C-3

Nameplate and style number information

Style number information The following table lists the commonly used styles for the A1800 ALPHA meter and the options that are available. Style numbers are subject to change without notice. Contact Elster Metronica for availability.

Table C-2. Meter style numbers for the A1800 Alpha meter

For example: А1802RALXQVM – Р4GB – DW – 4 А18

02 RALXQVM -

P4

G

B

-

D

W

-

4

3 Two-Element (3-phase, 3-wire, 4 delta) Three-Element (3-phase, 4-wire, wye) W

Auxiliary Power Supply

D LCD Backlight B Second communication port RS485 S Second communication port RS232 E Second communication port Ethernet G First communication port (RS485 or RS232) Р1- Р6 Pulse output relays (16) Both active and reactive energy metering, multi-tariff (active energy metering only, multi-tariff) Both delivered and received energy metering А Both load and instrumentation profiling L X Extended memory, 1 МB Instrumentation measurements with standardized error Q Loss compensation V Theft-resistant measurement of active energy М 02 Class 0.2S, transformer rated meters 05 Class 0.5S, transformer rated meters 10 Class 1, transformer rated meters 20 Class 0.5S, direct connect meters 21 Class 1, direct connect meters A1800 ALPHA meter R(T)

A18

Note: 1. If A1800 meter has not additional functions such as "А", "L", "X", "Q", "V", "М", "D", "W", then these suffixs shuld not be at nameplate. If A1800 meter has not "Q" suffix it is instrumentation measurements without standardized error. 2. If A1800 meter has not RS485, RS232 or Ethernet second communication ports, then "В", "S" or "E" suffixs should not to be at nameplate.

Technical manual

C-4

Nameplate and style number information

Technical manual

Technical manual

D-1

D Wiring diagrams

Refer to the wiring diagram on the nameplate of each meter for specific terminal assignments. All connections are equipped with combination-head screws that accept either a slotted or Phillips screwdriver.

Direct connected Figure D-1. 3-element, 4-wire wye or 4-wire delta

Figure D-2. 2-element, 3-wire delta or 3-wire network

Wiring diagrams

Technical manual

D-2

CT-connected meters Figure D-3. 2-element, 3-wire delta, transformer connected

Figure D-4. 3-element, 4-wire current transformer, sequential connection with 0,4kV

Wiring diagrams

Technical manual

D-3

Wiring diagrams

Figure D-5. 3-element, 4-wire instrument transformer, sequential connection with insulated neutral and grounded “B” phasel

Figure D-6. 3-element, 4-wire instrument transformer, sequential connection with grounded neutral

Technical manual

D-4

Wiring diagrams

Figure D-7. 3-element, 3-wire delta, transformer connected

Figure D-8. 3-element, 3-wire delta, instrument transformer connected with grounded “B” phase

Technical manual

D-5

Wiring diagrams

Figure D-9. 3-element, 3-wire delta, current transformer, 0,22kV with insulated neutral

Figure D-10. 2-element, 3-wire delta, current transformer, 0,22kV with insulated neutral

Technical manual

D-6

Wiring diagrams

Figure D-11. 2-element, 3-wire delta instrument transformer connected with grounded “B” phase

Figure D-12. 3-element, 2-wire, transformer connected

Technical manual

E-1

Technical specifications

E Technical specifications

Absolute maximums Continuous 528 VAC

Surge voltage withstand

Test performed Oscillatory (IEC 61000-4-12) Fast transient (IEC 61000-4-4) Impulse voltage test (IEC 60060-1)

Technical manual

Voltage

AC voltage (insulation) test Current

Results 2.5 kV, 60 seconds 4 kV 12 kV @ 1.2/50 µs 450  (8 kV with option boards) 4 kV, 50 Hz for 1 minute

Continuous at Imax Temporary (0.5 seconds) at 2000 % of Imax (transformer rated) ½ cycle at 30 × Imax (direct connect-rated)

Operating ranges Voltage Nameplate nominal 58 V to 400 V Operating range 49 V to 528 V Auxiliary power supply range

For AC power: 57 V rms to 240 V rms, 115V (nominal) For DC power: 80 V to 340 V

Current

0 A to 10 A (transformer rated) 0 A to 120 A (direct connect rated)

Frequency

Nominal 50 Hz, 60 Hz1 ± 5 %

Temperature range

-40 °C to +65 °C

Humidity range

0 % to 98% noncondensing

1

Contact Elster Metronica for availability.

Operating characteristics Power supply burden

Less than 3 W

Per phase current burden

Less than 0.01 VA (transformer rated and direct connect-rated) 1

Per phase voltage burden

0.008 W at 120 V

0.03 W at 240 V

0.04 W at 480 V

0.5 % (IEC 62053-22)

1.0 % (IEC 62053-21)

Accuracy Active energy 0.2 % (IEC 62053-22) Reactive energy 2.0 % (IEC 62053-23) 1

Actual accuracy is better than 0.5 % for 0.2 % accuracy meters

Conforms to IEC 62053-61 (Electricity Metering Equipment, Power Consumption and Voltage Requirements)

Technical manual

E-2

Technical specifications

General performance characteristics Starting current CT-connected 1 mA Direct-connected < 40 mA (Ib = 10A) Creep 0.000 A (no current)

No more than 1 pulse per quantity, conforming to IEC 62053 requirements

Internal clock accuracy

Better than 0.5 seconds/day (while powered), while conforming to IEC 62054-21

Outage carryover capacity

LiSOCl2 battery rated 800 mAhr, 3.6 V and shelf life of 15+ years. 5 years continuous duty at 25 °C. Supercapacitor is expected to provide carryover power for all normal power outages for a period of at least 6 hours at +25 °C. The battery is not under load except when supercapacitor is discharged or when a programmed meter is stored for an extended period without line power. Based on this low duty cycle, the projected life of the battery in normal service is expected to be greater than 20 years.

Communications rate Optical port 1200 to 28,800 bps

Physical components meet IEC 62056-21 or ANSI C12.18

Serial ports 1200 bps to 19,200 bps

Dimensions and mass For the dimensions and mass of the A1800 ALPHA meter, see “Physical dimensions and mass” on page 2-18.

© Elster Metronica OOO 10-2011 Printing in Russia # 22002/E

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