Integrated Control: DMS deployment increasing distribution network efficiency

DMS deployment increasing distribution network efficiency

While an interconnected grid has led to several benefits, it has also resulted in a number of complexities that did not exist in traditional girds. Centralised and distributed power generation, intermittent renewable power generation and bidirectional power flows are some of the challenges related to interconnected grid that need to be addressed through information technology (IT) and operations technology (OT).

Public as well as private discoms are undertaking distribution automation at various levels by deploying IT solutions. Given their poor financial health, state discoms are typically dependent on central government schemes like the Integrated Power Development Scheme, Deendayal Upadhyaya Gram Jyoti Yojana and National Smart Grid Mission for implementing the relevant IT systems in their distribution operations. Meanwhile, private discoms, which have been investing in IT systems in the past, are making substantial investments in technology upgrades.

A distribution management system (DMS) is a collection of applications that monitor and control the entire distribution network efficiently and reliably. It acts as a decision support system to assist the control room and field personnel in monitoring and controlling the power distribution system. Advanced DMS functions provide the best results when data from substations and feeders is fully integrated into the network control system. A comprehensive DMS can integrate data from across IT and OT systems. Advanced DMS combines DMS, supervisory control and data acquisition (SCADA) and outage management system (OMS) functionalities.

Functions of DMS

DMS implementation delays capacity investment by utilising voltage reduction, load transfers, distributed generation and demand response technologies. It also minimises the frequency and duration of outages while optimising field resources across services, maintenance, construction and outage management. It also increases system efficiency by reducing real power losses through system design and operations, and improves work process efficiencies through task automation. These systems also facilitate higher penetration of renewable and distributed energy resources in the grid. In addition, they provide better customer communication and improved management of field resources for customer service.

Outage management system

An OMS provides the capability to efficiently identify and reduce outages, and generate and report valuable historical information. It is a computer system used by electric distribution system operators to assist in the restoration of power. OMS anticipates and responds with greater agility to system outages to decrease the frequency and cost of interruptions. It provides accurate information on the extent of outages and the number of customers affected. The system reduces the number of outages through higher predictive maintenance and fewer asset failures. OMS is most helpful when there are many scattered outages. It quickly predicts the number of individual outage locations, the extent of each outage and the scope of the restoration effort as a whole. OMS prioritises restoration efforts and manages resources based on defined criteria such as the size of outages, and the location of critical facilities.

With much larger amounts of data being available through modern smart grid technologies, today’s OMSs are becoming more complex and robust, incorporating more features to better prevent outages and restore power more efficiently.


SCADA applications support the crucial operations of monitoring, recording and reporting network events while enabling the remote control of field equipment. The key objective of SCADA implementation along with DMS is to improve the reliability and efficiency of network operations and power supply. The use of real-time data also permits optimisation of the capital expenditure necessary for meeting the growing needs of the electric distribution system.

There are three key components of a SCADA system: host equipment, communications infrastructure and field devices. In the context of distribution networks, the host equipment installed at control centres typically includes SCADA servers, network-based communication front-end nodes, user interfaces, relational databases, data servers and web servers. Field devices are installed at substations and at select locations along the distribution line. These multi-featured installations provide specific functionalities, support system operations, enable fault detection, capture planning data and record power quality information. Field devices typically include sensors and actuators, remote terminal units, programmable logic controllers, feeder remote terminal units and intelligent electronic devices.

SCADA systems are crucial for improving and maintaining utility performance as they enable real-time data-based network management, help in implementing more efficient control paradigms, improve network safety and reduce operation costs.

In addition, SCADA deployment in the power distribution segment remains important as it is a part of the legacy systems that are essential for smart grid development.

IT-OT convergence in distribution

One of the key changes that utilities are currently experiencing is the convergence of IT and OT, which have traditionally occupied separate silos. OT represents a broad category of components that utilities depend on for ensuring safe and reliable generation and delivery of energy. IT, on the other hand, is typically associated with back-end functions that support business processes like billing, revenue collection, analytics, asset tracking and maintaining customer information.

Utilities can capitalise on operational efficiency savings by seamlessly integrating data from OT systems with their back-end IT systems to improve customer relationships, achieve cost savings, offer new services and manage internal changes within the organisation.

Driving the convergence of IT and OT is the need to integrate new types of assets into the network and make them operation-ready, taking into consideration all the complexities of operating interconnected electric systems. Further, there is a need to manage very large quantities of data from new devices and sensors spread throughout the power networks, metering devices and home area networks in near-real time. Moreover, the underlying technology of OT systems, spanning platforms, software, security and communications, is increasingly beginning to resemble IT systems, thus validating the case for IT integration in OT software management. Shared standards and platforms across IT and OT can enable utilities to reduce costs across the software management landscape, including enterprise architecture, support and security models, software configuration practices, and information and process integration.

For instance, metering was traditionally a part of the OT domain. Automated meter reading and advanced metering infrastructure solutions, which emerged from OT, are now connected to the IT domain. Billing, on the other hand, was typically an IT solution but, with the implementation of end-to-end smart metering, bills are now based on exact readings instead of estimates.

Going forward

Driven by needs like monitoring of energy consumption, tamper detection, reduction of aggregate technical and commercial losses, prepayment options, demand forecasting, time-of-day tariffs, outage management, and renewable energy integration, discoms have increasingly been deploying IT solutions and automating networks over the years. However, some of the key challenges they face pertain to platform integration, vendor support, financials risks, organisation transition and equipment availability.

Based on inputs from a presentation by Vijayan S.R., Assistant VP, Technology and Business Development, Smart Grid, Smart Cities and Cyber Security, ABB Limited, at a Power Line conference