The government has taken a number of initiatives to promote the installation of smart meters in India. In November 2015, under the Ujwal Discom Assurance Yojana, the government mandated the deployment of smart meters for all customers with monthly electricity consumption of over 200 units in the participating states. Amendments to the National Tariff Policy, in January 2016, reiterated this and specified the timelines for the installation of smart meters, based on the monthly consumption of consumers. It further envisaged the installation of smart meters through the entire chain of electricity distribution – from 132 kV transformers to distribution transformers at the 11 kV level, and further down to each consumer.
In August 2016, the Central Electricity Authority formulated the Functional Requirements of Advance Metering Infrastructure (AMI) in India guidelines. The key objective of these guidelines was to facilitate the roll-out of smart meters in the states as per the policy requirements. The guidelines define the minimum functionalities and performance of AMI systems proposed to be developed in India. It lists the general AMI system requirements, technical specifications for single-phase and three-phase smart meters, standards for communication networks and network security, and the role of meter data management systems (MDMS), among other things.
Smart Utilities presents the key features of these guidelines…
AMI implementing agency
AMI involves expertise in various different domains including metering, telecommunications and information technology (both software and hardware). Keeping in view the new technologies and the limited experience of the states, the guidelines envisaged the appointment of an AMI implementing agency (AIA) for providing end-to-end AMI solutions to the states/discoms. Some of the functions of the AIA include the installation of smart meters as per the rules and regulations and practices of the utility, the designing of a reliable, interference-free and robust communication network, keeping in view the site conditions, providing a suitable head-end system (HES) to support data collection and storage as per the defined performance levels for a given number of smart meters (with a facility for future expansion as per the requirement of the utility). The AIA will also be responsible for proper exchange of data among smart meters, data concentrator units (DCUs), MDMS, HES and other operational/requisite software as part of the AMI system.
The AMI system must support certain minimum functionalities including remote meter data reading, time-of-day/time-of-use (ToD/ToU) metering, prepaid metering, net metering, alarm/event detection, notification and reporting, remote load limiter, connection and disconnection based on demand and supply conditions, remote firmware upgrade, integration with other existing systems such as billing, collection and outage management systems, import of data from existing modules of the Restructured Accelerated Power Development and Reforms Programme wherever possible, and security features to prevent unauthorised access to the AMI. While these are the minimum functionalities that the AMI system must support, it should also be capable of supporting any other functionality that may be incorporated in the future, as per the requirement of utilities.
To support the above-mentioned functionalities, the AMI system would include smart meters, communication infrastructure, HES, MDMS, web applications, and mobile apps as its core components. The mobile app would enable consumers to see information related to their energy consumption and provide a platform for the implementation of the peak load management functionality.
The guidelines have laid down the technical specifications for single-phase and three-phase whole current smart meters. The minimum basic features that a single/three-phase smart meter must have include measurement of electrical energy parameters; bidirectional communication; integrated load limiting; detection, recording and reporting of tamper events; alarms for power events such as loss of supply and low/high voltage; net metering; and on-demand reading. The performance and testing of single-phase meters must conform to the IS 13779, IS 16444, IS 15884 and IS 15959 BIS standards (with latest amendments). Apart from these standards, three-phase current transformer (CT)-operated meters must also comply with IS 14697 till the relevant standards for CT-operated smart meters are available.
The communication infrastructure should either be based on a radio frequency (RF) mesh network/power line communication or a cellular network, or a combination of these. The communication network should be based on suitable standards for neighbourhood and wide area networks. The communication network should provide a reliable medium for two-way communication between various nodes (smart meter) and the HES. The RF-based network should use licence-free frequency bands available in India. A suitable network management system will be provided to monitor the performance of the communication network at all times.
The network should have adequate cybersecurity measures including secure access controls, authorisation controls, logging (maintenance of logs for all attempts to log on), hardening (disabling of unnecessary packages and insecure protocols), and firewalls and encryption. The guidelines also specify various requirements of the communication network (power supply, configuration, functionalities and interface) depending on the gateway of the communication of data used – DCU or router.
The main objective of the HES is to acquire meter data automatically while avoiding any human intervention and to monitor the data acquired from the meters. The guidelines have laid down suggested functionalities of the HES, including meter data acquisition on demand and at user-selectable periodicity, storage of raw data for a defined period, two-way communication with the meter/DCU, signals for connection and disconnection, logging of all events and alarms, and encryption of data for secure communication.
Further, the interface of the HES with the MDMS should comply with the International Electrotechnical Commission (IEC) 61968 standard or any other open standard and it should be service-oriented architecture (SoA) enabled.
The MDMS would be the central data repository of the AMI system and support storage, archiving, retrieval and analysis of meter data along with validation and verification algorithms. The MDMS should have the capability to import raw or validated data in defined formats and export the processed and validated data (such as billing, consumer information system, customer care, analytics, reporting, network planning and analysis, load analysis/forecasting, peak load management and outage management) to various other upstream systems in the agreed format. It should also allow the utility to choose the data to be maintained or archived or analysed as per the requirements at different points of time.
The MDMS should also be capable of supporting the future requirements of the utility and the integration of smart grid functionalities that may be implemented by the utility in the future, such as distribution transformer health monitoring system and self-healing system. The functional requirements of the MDMS as specified by the guidelines include asset management; collection, processing, storage, analysis, validation and reporting of meter data; configuration of multiple billing determinants such as ToD/ToU tariffs, power factor, slabs of consumption, exception management (ability to capture and log data exceptions and generate alerts); generation and sending of service orders via email or SMS; customer service support; and support for various smart grid functionalities.
The guidelines have also specified the average performance levels (over a period of a year, excluding force majeure events) for various functions of the AMI system. For instance, for the daily collection of the previous day’s interval energy data and total accumulated energy, all interval data from 95 per cent of meters should be collected within eight hours after midnight, and all interval data from 99.9 per cent of the meters within 24 hours after midnight. Similar performance levels have been specified for remote reading of meters, remote load control commands, remote connection/disconnection, detection of outages or loss of power supply, and updating of data on the consumer portal/app. Further, the guidelines have specified the criteria for performance testing of the user interface (UI) in terms of response time to various UI requirements.
While the guidelines specify the various minimum and desired functional requirements of AMI systems, the states/discoms may prepare a detailed plan for the installation of smart meters (creation of AMI) by 2019, in line with the provisions of the National Tariff Policy, 2016, and submit this to their respective electricity regulatory commissions for approval. The implementation of AMI may be taken up area-wise or feeder-wise, preferably in higher-loss areas initially.