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Why every grid modernization strategy should consider DA/ADMS

Credit: Photo by Dina Lydia on Unsplash

The modernization of the electricity distribution system has encompassed the transformation of decades-old manual, paper-driven business processes to electronic, computer-assisted decision-making. Indeed, a growing degree of automation has been developed to assist grid operators in managing increasingly complex electric distribution systems.

At the heart of this transformation is the Advanced Distribution Management System (ADMS) supported by a wide array of Distribution Automation (DA) technologies. DA/ADMS implementation helps electric utilities of all types and sizes to continuously monitor the conditions on the electric distribution system and make informed decisions to improve efficiency, reliability, and overall performance all the while maintaining and even improving workforce and customer safety and protecting equipment from damage.

DA/ADMS Defined

DA technologies provide a foundation upon which a grid modernization strategy can be built. They include intelligent devices such as energized power apparatus, controllers, and sensors, along with Remote Terminal Units (RTUs) and other Supervisory Control and Data Acquisition (SCADA) facilities that are implemented in distribution substations and on the feeders. These facilities provide system operators with visibility of electrical conditions and provide remote control capabilities for field equipment.

The ADMS is a centrally located computer system with a suite of software applications to assist the operators in monitoring and controlling the distribution system and managing outage response. Growing customer and regulator expectations and the increasing penetration of distributed energy resources (DER) that are connected to the electric distribution system, have significantly increased the complexity of the distribution networks.

ADMS software analyzes the information acquired from the field devices, alerts system operators to adverse electrical conditions and possible inefficiencies and reliability issues, and either advises the operators on ways to address these issues or performs recommended control actions automatically.

DA/ADMS Benefits

Improved “Visibility”

Typically, SCADA systems identify conditions at the substation at end of the feeder and possibly a few locations on the feeders where line reclosers are present. Another system, the ADMS online power flow (OLPF) can determine the electrical conditions (current, voltage, etc.) anywhere on the feeder on a nearly real-time basis so that adverse conditions are quickly identified.

Distribution System Optimization

Current practice is to maintain “acceptable” conditions during normal operation, whereas the DA/ADMS can assist the operator in achieving “optimal” system performance. For example, traditional volt/VAR control seeks to maintain service delivery voltage within the industry standard range (typically 114 V to 126V); DA/ADMS provides selectable volt-VAR optimization strategies such as conservation voltage reduction for energy savings and peak shaving, grid VAR support, and other business needs.

Accommodate High Penetration of DERs

In cases where DER supply more than 30% of the consumed energy, abnormal electrical conditions such as reverse power flow and high voltage may occur. DA/DMS can model the impact of DER so that such impacts can be considered in making operating decisions

Adapt Automatically When Changes Occur

When changes to feeder configuration occur, conventional control schemes may need to be disabled until the normal configuration is restored. DA/DSM functions use a dynamically updating “as-operated” model of the distribution system to ensure that these algorithms continue operating as changes occur.

Anticipate Evolving Problems

DA/DSM applications can also consider predicted conditions (such as increasing solar PV output in the morning or decreasing output in the afternoon). For example, the DA/ADMS may defer capacitor switching actions that may need to be undone when such changes occur. Another example is ADMS contingency analysis that identifies possible equipment failures that could result in widespread outages. Such “forward looking” applications allow operators to anticipate incipient problems by addressing plausible contingencies so that appropriate actions may be taken proactively to address an incipient problem before a more serious problem occurs.

Provide Simulation Capability

DA/ADMS includes a dispatcher training simulator (DTS) that provides effective training for operators of all experience levels. The DTS can be used to playback information from past event for review purposes as well as conduct simulated power system emergencies without impacting the actual power system.

DA/ADMS – Not a “One Size Fits All” Concept

While the DA/ADMS can perform a wide variety of functions, the system is highly configurable so that a distribution utility can implement the subset of functions that best satisfies it business needs. For example, some utilities may focus on implementing conservation voltage reduction (CVR) to reduce peak load and lower its monthly demand charges. Others may implement functions to manage the creation and validation of a high volume of complex switching orders. The specific functions performed by the DA/ADMS must be tied to the business needs and characteristics of the individual utilities and the expectations of their customers.

Strategy for Successful DA/ADMS Deployment

  1. Conduct a Needs Analysis — The DA/ADMS must address the firm’s short-term and long-term business needs. Hence, the first project activity must be a thorough needs assessment that includes the vision of top executives and the current and anticipated needs of first line operators and other stakeholders. The results of this assessment should be a target set of functions and technologies as well as specific goals and expectations for operational and business improvements.
  2. Determine Readiness for DA/ADMS Deployment — DA/ADMS deployments often fall short of expectations because core “enabling” technologies (field devices, measurement and modelling data and IT infrastructure) are not available. Utility companies should conduct studies early on to determine the “readiness” in each core technology area, and then adopt measures to improve readiness before embarking on the DA/ADMS project.
  3. Develop a Realistic Implementation Schedule — Phased implementation of DA/ADMS technologies is almost always the best approach due to resource constraints and the readiness of key technologies. The initial phase should include basic functions that build operator familiarity and confidence level with the new system and enable later deployment of more advanced functions. Following phases should be prioritized based on payback level and dependencies on other planned IT projects.
  4. Develop a Business Case — It is essential to develop a business case to confirm that the expected benefits outweigh the total cost of ownership of the DA/ADMS. This analysis will also identify post-implementation targets for measuring the success of the project. This analysis is key to gaining buy-in from project executives, regulators, and other high-level stakeholders.
  5. Create a Training and Change Management Strategy — A comprehensive training and change management program is needed to ensure that all project stakeholders are able to adapt to the new technologies so that these technologies will be “used and useful” at the earliest possible date.

Editor’s note: Ready to learn more? Author of this piece, Bob Uluski is offering an online course on this topic – just like the one he teaches at DISTRIBUTECH International. You can explore his teaching style in a free one-hour introductory course. Of his full 6-week course, he says you’ll learn “Everything you need to know to understand, implement and make the business case for distribution automation and advanced distribution management systems at your utility.” Learn more about all of the DTECH virtual courses here.