Generic Specification for EPM 1500/4500

Generic Specification For EPM 1500/4500

SECTION __1__, Electric Utility Metering System

GENERAL

2.1.1.DESCRIPTION

2.1.2.Work under this section is subject to the requirements of the Contract Documents, including the General Conditions and Supplementary Conditions.

2.1.3.Contractor shall provide the Automated Metering System in accordance with Contract Documents.

2.1.4.The property’s utility services shall be metered to measure electrical consumption and demand (optional). The system shall consist of digital, revenue grade electricity meters installed at each individual distribution panel or point to be metered, as noted in the electrical diagrams, necessary current transformers, potential taps, related wiring and accessories, and an optional central computer complete with modem or means of communication for Automatic Meter Reading (AMR). The electricity meters shall have the optional capability of reading pulse outputs from other types of meters in the system, such as BTU, water and/or gas meters.

2.1.5.Contractor shall furnish, install and verify as operational an electric, computerized metering system, which shall be microprocessor controlled, consisting of all solid-state components. Electricity meters shall be manually readable using local Liquid Crystal Display (LCD) via push-button and automatically readable utilizing Frequency Hopping Spread Spectrum Power Line Carrier Communication.

2.1.6.The meter shall be have the following approvals:

2.1.6.1.ANSI: C12.1 & C12.16 for accuracy

2.1.6.2.UL & CUL: Recognized under E204142

2.1.6.3.Industry Canada: MC# AE-1148

2.1.5The metering system shall consist of the EPM1500, EPM4500 & Transponder(s) and provided by GE.

SYSTEM REQUIREMENTS

3.1.The system shall be a fully automated, microprocessor-based electric utility measurement system. In minimum configuration, it will measure and record the usage of electricity in flash memory, and shall be capable of communicating the reading to an optional on-site or remote computer (i.e. the billing computer).

3.2.Each meter shall interface to the electrical load being measured with a direct voltage tap, up to 600VAC, and with 0.1 or 5 Amp split or solid core current transformers.

3.3.Each meter shall display its readings on a local LCD display. The consumption reading shall be up to nine (9) digits. In the default display, up to six (6) digits to the left of a decimal point shall be for kilowatt-hours, and digit (1) digits to the right of a decimal point shall be for watt-hours. Optical port. All meters shall have IEC type optical port capable of direct connection to a terminal or PC.

3.4.Each meter shall be equipped with a clock/calendar that automatically accommodates leap years. The clock/calendar shall be backed up by battery and continue operating during power outages. The time and date is automatically synchronized by the Transponder(s), and can be reset by the (optional) billing system computer.

3.5.Revenue related metering parameters (i.e. demand intervals) shall be permanent and stored in each individual meter. It shall not be possible to change metering parameters through unauthorized access to the system.

3.6.Each meter shall have the capability to measure and record kW Demand every 15 minutes and be classed as a mass memory interval meter. Peak demands (optional) shall be capable of being read and reset by the (optional) billing computer. The demand interval shall be factory programmed in each meter and shall be permanent.

3.7.Each meter shall maintain a minimum of sixty-(60) day log of daily Time-of-Use consumption, interval data and peak demand readings along with the time and date at which the daily peak demands occur. The consumption recorded shall be the reading at the end of the Time-of-Use period of the end of the day. The peak demand recorded in the log shall be the peak demand for the Time-of-Use period for that day.

3.8.Each meter shall perform Phase Diagnostics. Phase Diagnostic Registers shall include multipliers for amperage, voltage and watts, and line frequency. On a per phase basis Phase Diagnostics shall include voltage, VAR phase shift, accumulated kWh and kVARh, and instantaneous amps, watts, VAR’s, VA’s, phase angle (degrees displacement between current and voltage waveforms), and Power Factor.

3.9.Each meter shall perform Event Diagnostics. The Event Diagnostic Registers shall include Time and Date and the number of times the time has been changed, number of power downs, power ups and start ups with time and date of last occurrence, and the number of times the accumulated peak demand has been reset, also with the time and date of the last occurrence. Meters that communicate by Power Line Carrier shall also include counts of properly received messages, rejected messages and the number of transmissions without reply.

3.10. The system shall be capable of providing the following optional features:

3.10.1.Optional. Demand shall be recorded along with the time and date at which it occurs. Peak demands shall be capable of being read and reset by the billing computer. The demand interval shall be factory programmed in each meter and shall be permanent.

3.10.2.Each meter shall (optionally) be capable of reading dry contact, Form A pulse inputs to automate the reading of other utilities such as gas, water or BTU’s. Four (4) pulse inputs available on EPM1500 and up to forty eight (48) available on the EPM4500.

3.10.3.Modem. Individual meters shall (optionally) be capable of being equipped with a modem for direct connection to a telephone line. RS-232 Serial Port. All meters shall (optionally) be capable of being equipped with a local serial port for direct connection to a terminal or PC.

3.10.4.Each meter shall be capable of maintaining a minimum of (60) day log of fifteen (15) minute demands with time and date stamp.

3.11.The system shall be able to communicate with the billing computer by one or more of the methods noted below. Refer to electrical diagrams for specific configuration.

3.11.1.Power Line Carrier. Each meter shall be capable of communication over the billing’s electrical power wiring to a Scan Transponder via bi-directional, frequency hopping, spread spectrum power line carrier communications. These signals shall pass through transformers rated 600 kVA or less. The Scan Transponder and each meter shall select the best available combination of phase, frequency range and baud rate for communication at any given time.

3.11.2. RS-485. Four-wire dedicated interconnection.

3.12.The number of meters reporting to a single Scan Transponder is determined by the information to communicate and the amount of flash memory in the Scan Transponder. The range is from 1 to 200 meters. All communication shall be direct between a Scan Transponder and each meter, and under the control of the Scan Transponder. Meters will not repeat messages from other meters nor will message routing be determined by meters. One Scan Transponder shall be provided per electrical service at the site. One Scan Transponder at the site shall, optionally, be equipped with a Modem if the billing computer is remote. Multiple Scan Transponders shall be connected by Data Link (RS-485). Meters may also be connected to the Scan Transponder by Data Link.