Building Brains Behind the Smart Grid

By Hormoz Kazemzadeh, Accenture Smart Grid Services

Progress Energy cut the System Average Interruption Duration Index (SAIDI) 20 percent. CPS Energy united supervisory control and data acquisition (SCADA) and outage management systems (OMS), allowing operators to monitor and control the distribution system more efficiently via one user interface. A distribution management system (DMS) rests behind both achievements.

DMS operates intelligent devices, sensors and advanced analysis applications. It can push automation technology to all distribution substations and onto the feeders with automated reclosers, switches, regulators, capacitors and other smart devices. DMS is a central platform for integrating and leveraging data from utility systems and is fundamental in any utility’s plans to build a smarter grid.

Every utility should think about DMS components, advantages and how to deploy the system.

DMS Functionality

Distribution control center operators use DMS to operate the distribution network reliably, efficiently and securely. DMS provides functionality to:

  • Maintain the as-operated model of the network–reflecting device operations, temporary network changes (line cuts, phase changes, etc.) and information tags on the network model.
  • Monitor and control the distribution network–monitoring the network’s electrical state, processing alarms and issuing controls.
  • Manage outage restoration processes–receiving outage notifications, managing the restoration process and estimating restoration times.
  • Dispatch the right crew to the right job–monitoring crew status and location in the field, dispatching assignments and managing crew activity.
  • Locate and isolate faults and restore service–receiving and processing fault information from devices and fault-location applications and developing switching schemes to isolate the fault and restore service.
  • Manage planned switching–receiving and processing switching requests, creating and validating switching schemes, notifying affected customers and executing switch orders.
  • Communicate timely and accurate information to stakeholders–capturing and calculating information to communicate to customers, management, service representatives and media.
  • Exchange data seamlessly with the enterprise–sending and receiving data and transactions to support enterprise systems and applications.

These capabilities provide greater grid insight than is currently available. In turn, a better system view enables the operators to respond quicker and more effectively to outages and contingencies, providing more reliable, efficient service to residential and commercial customers.

Agents of Change

Utilities have been able to operate without DMS because traditional characteristics held true:

  • Power flowed in one direction,
  • Energy supplies from large generators followed demand,
  • Infrastructure had a large capacity margin, and
  • Operators knew the system thoroughly.

In the future distribution utility, however, power will flow in two directions. Energy supplies will come from new technologies and suppliers connected anywhere on the network. Customers must adjust demand to respond to supply constraints, and infrastructure will be pushed to higher loading levels and lower margins.

DMS will be crucial for demand response, renewable and distributed generation, and battery storage. These resources are dispatched without the need for real-time distribution network analysis. As the penetration and size of these resources grow, however, system operators must know system connection details. DMS will show them.

DMS Data Model

The core of DMS is a detailed, accurate distribution network model highly dependent on data from a geographic information system (GIS), customer information system (CIS) and other sources. The data required include:

  • Infrastructure data (e.g., equipment instance, type, location, rating),
  • Metadata (e.g., element naming, type data, limit data, analysis parameters),
  • Network topology (e.g., connectivity, phasing, normal device states),
  • Customer data (e.g., name, address, phone, meter, type),
  • Customer to network link (via service drop or transformer), and
  • Engineering data (e.g., impedances, connections, settings, sensing node).

The network data for the model typically are maintained in a GIS, which goes beyond mapping to network information such as connectivity. A DMS network model also requires engineering data, such as impedances of lines and transformers, as well as data about connections and settings of transformers, regulators, line drop compensators and capacitors.

Advanced DMS applications may require even more data, such as short-circuit capacity at distribution sources. These data may exist in different databases and must be considered in DMS data interface design. Data quality is most critical in a DMS implementation project.

Architecture Matters

The core components of distribution management are SCADA, operating model, user interface, outage management and advanced DMS applications. While the ideal architecture consists of one solution that enables all these components, utilities and vendors are creating varied solutions based on current investments and business drivers.

A single solution for SCADA/DMS/OMS presents the most effective architecture because it eliminates the need to maintain and synchronize multiple operating models and provides a single user interface. The challenge is ensuring best-of-breed functionality and features. A single solution brings big changes and requires a transition program.

Some utilities have opted for one solution for SCADA/DMS along with an existing or upgraded OMS, which reduces the amount of change utility workers must accommodate at one time. It requires, however, that the operating models for OMS and DMS are updated from GIS simultaneously to ensure consistency. That affects the DMS-OMS interface design. Another drawback: Operators must interact with two systems.

Because DMS is a real-time system, performance is another issue to consider. High availability and disaster recovery are vital, too. Distribution systems are not part of North American Electric Reliability Council (NERC) critical infrastructure protection (CIP) requirements, but utilities are increasingly placing equal importance on distribution system security.

Integrated Throughout

Distribution management touches many business processes, exchanging data and transactions with numerous other enterprise systems such as GIS, CIS, interactive voice response, AMI/ meter data management, mobile data system, SCADA/EMS and work management systems.

Many connections have been implemented as custom or point-to-point interfaces. With increased distribution management complexity, a structured and standards-based approach becomes crucial. The enterprise application integration (EAI) is an open, standards-based platform designed to ease integration of systems and applications, creating cohesive enterprise architecture. This platform uses service-oriented architecture and enterprise service bus. EAI minimizes the need for custom interfaces.

It will be at least five years before DMS becomes a common and major undertaking for most organizations. It isn’t too early, however, to start thinking of which applications will benefit utility applications.

When Progress Energy cut SAIDI 20 percent eight years ago, it used a fault-location application to cut windshield time for restorations with feeder lock-outs. At the time, Progress Energy Carolinas had an average feeder length of 43 miles. More recently, Progress Energy has targeted peak capacity savings of 247 MW through distribution voltage reduction.

With DMS applications, utilities can drop voltage while maintaining the minimum. Volt/VAR applications intelligently control capacitors and voltage regulators to maintain the required profile. By fine-tuning voltage throughout the circuit, the utility has the option to lower peak demand overall.

As utilities deploy smart meters that can record voltage, system operators can check voltage readings to validate network and engineering data accuracy. This also can be used to confirm volt/VAR control applications are working properly. Some utilities use meter data to predict cable and equipment failure or flag phasing issues, as well.

Advanced network analysis and optimization applications continuously analyze the state of the network to improve operation. Basic applications being implemented are:

  • Distribution power flow,
  • Distribution state estimation,
  • Fault location,
  • Simulation,
  • Restoration switching,
  • Switching reconfiguration,
  • Fault location, isolation and service restoration (FLISR), and
  • Volt/VAR optimization.

Other applications are under development to further improve distribution network operations.

DMS will impact many utility departments and customers. A long-term, comprehensive approach to distribution management includes enterprise architecture, data management, change management and security. These protect against silo solution implementation, costly integration and maintenance issues, and obsolete investments. The core DMS technology and many best practices already exist. Utilities must understand how to use DMS to build smart grid foundations

Hormoz Kazemzadeh is Accenture Smart Grid Services’ senior manager. He specializes in electric utility network operations and has developed applications and managed large system implementation projects.

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