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Stuart Borlase
Stuart Borlase
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Next Generation Distribution Management Systems

Written by: Robert Uluski and Stuart Borlase, ESTA International

ESTA International is a leading provider of consulting services to the utility and energy industry worldwide with broad capabilities in strategy, technology, implementation and management consulting. We focus on industry transformational change, technology-driven innovation and business resiliency to ensure growth and success of our clients. ESTA specializes in the areas of smart grid, grid modernization, operational and enterprise technologies, DERs, microgrids, cybersecurity, grid resiliency, advanced protection, control and automation, digital transformation, energy markets, energy transition, business digitalization, asset management, smart cities, and other related areas. www.ESTAInternational.com

No portion of the power grid has been impacted more by grid modernization than the electric distribution system. Grid modernization is transforming distribution system operations from manual, paper-driven business processes that have existed for many years, to electronic, computer-assisted decision-making with a high degree of automation. The grid is transforming from a more centralized generation system to one with a significant portion of demand supplied by Distributed Energy Resources (DERs) and enhanced grid resiliency and reliability with the addition of microgrids. The next generation distribution management system will need to incorporate more intelligence and advanced functionality to support these changes in the operation, monitoring and control of the future distribution grid. ESTA’s concept of the “DER-Enabled ADMS” will likely play an increasingly important role in the management of the distribution grid of the future.

1. Present-Day Distribution Management Systems

Many utilities have implemented or plan to implement an Advanced Distribution Management System (ADMS). ADMS refers to a DMS (Distribution Management System) that incorporates OMS (Outage Management System) functionality and advanced “model-driven” distribution applications like on-line powerflow and volt-VAr optimization (VVO). Currently, the ADMS includes a variety of applications and functions to increase situational awareness, enable proactive response to incipient problems, and promote optimal reliability, efficiency, and overall performance of the electric distribution system. The ADMS typically includes SCADA facilities for distribution assets (transformers, switchgear, etc.), advanced applications for near-real-time analysis and optimization of the distribution system and outage management functionality, plus interfaces to external systems such as GIS and AMI that furnish information required by the ADMS applications. The ADMS is a decision support system to assist the distribution control room personnel with the monitoring and control of the electric distribution system in an optimal manner while improving safety and asset protection. Figure 1 shows the building blocks of a present-day ADMS.

Figure 1: Present-Day ADMS Building Blocks

2. Distribution Grid Operating Challenges and Needs

DERs are non-traditional energy resources either connected directly to the distribution primary circuit and owned by the distribution operator, or connected behind the meter and owned by commercial, industrial or residential customers. Non-traditional energy resources include generation powered by renewable sources (e.g., solar power), customer cogeneration facilities, backup diesel generators, energy storage (including battery energy storage systems (BESS) and EVs with vehicle-to-grid (V2G) capabilities), and controllable loads (demand response/load management including electric vehicle chargers).

Possible operating problems that may be experienced at higher DER penetration levels include (but are not limited to):

  • Load “Masking”: Feeder load measurements that are available on the ADMS for the substation end of a feeder are actually “net” loads (actual customer load – load supplied by DERs). Since distributed generators may trip offline when a fault occurs, load transferred by automatic sectionalizing schemes will be higher than expected, which could possibly overload backup sources.

  • Reverse Power Flow: If DER output (distributed generation output or energy storage discharging) on a feeder exceeds total feeder load (which may occur during lightly loaded conditions), reverse power flow (back toward the substation) can occur. Reverse power flow produces a voltage rise effect which may result in high voltage conditions on portions of the feeder.

  • Voltage Fluctuations and Excessive Voltage Regulator Operation: Distributed generators with intermittent output level (such as solar PV generators on a partly cloudy day) can produce voltage fluctuations on the feeder, which, in turn, result in power quality problems and a significant increase in voltage regulator tap changing operations.

  • Protection System Coordination Difficulties: High penetrations of distributed generators may produce a significant amount of fault current that can alter the coordination of feeder protection systems and distribution automation schemes, causing possible mis-operation of these systems and unnecessary customer outages.

  • Localized Overloading Due to EV Chargers: Heavy electrical vehicle charging activities can produce localized equipment overloading, especially at public charging stations and neighborhoods where clusters of EV chargers exist.

Smart inverters based on the IEEE 1547 standard offer new ways to help manage DER impact on distribution circuits and allow customer sited generation to act more in concert with the existing grid, providing support for grid reliability, voltage management, and interactive communications.

Distribution grids will need to support the requirements for microgrids to transition between grid-connected (grid-paralleled) mode and islanded mode. Microgrids that require “seamless” transitions without power interruption may require changes to the distribution utility’s automatic reclosing philosophy and other operating practices. Therefore, microgrid monitoring and management is expected to be part of the next generation distribution management system responsibilities, focusing on grid resiliency, reliability and outage management. While feeder protection and control schemes will need to account for DER and microgrid operating conditions, the next generation distribution management system may need to provide some overall integration, coordination and optimization of protection and control schemes on a substation or feeder basis, or in specific service areas. If the future distribution energy markets evolve to include transactive energy trading (peer-to-peer transactions) among customers on the distribution system, the next generation distribution management system may also need to play a role in the technical aspect of the energy transaction, such as verifying that the distribution electrical conditions and load flow will physically allow the commercial energy transaction to occur under current and forecasted system operating conditions.

More cost-effective sensors and enhanced protection control devices will increase visibility of the distribution system and will allow utilities to monitor and control the grid-edge in real-time, such as DER and microgrid connections and the customer interface. An IoT (Internet of Things) will be created by the ubiquitous deployment of these devices, which will require a significant investment in the communications infrastructure and advanced processing for edge-computing. Apart from an increase in the visibility of the distribution grid down to the customer, the next generation distribution management system will also have access to more data on the operating condition of the distribution assets and can make this data available to asset condition monitoring and asset management systems. With the increase in the number and interconnectivity of monitoring, protection and control devices, there are now more entry points for cybersecurity threats, and there will be more emphasis on data and communications security in the next generation distribution management system.

It is unlikely that the next generation distribution management system will incorporate all the monitoring, protection and control functionality for the distribution system, but it may include a hierarchical and distributed software architecture to provide more computing and data analytics capabilities at the grid-edge and support the necessary technical and commercial functions to operate the future grid.

3. Shortcomings of Current Solutions for DER Management

One part of present-day ADMS functionality that has not been fully deployed in today’s ADMS is the modelling and management of Distributed Energy Resources (DERs), mostly due to limited utility awareness and level of sophistication of vendor offerings. Currently, lack of DER awareness by the ADMS has not been a major problem because the DER penetration level (penetration level defined as total electrical capacity (MW or MWh) of the DERs as a percentage of the total energy consumption by the load) at many electric utilities is too small (<10%) to have significant impact on distribution system electrical conditions. However, as the DER penetration level increases, the impact on distribution feeder electrical conditions can be significant. Determining the DER penetration level at which significant operating problems can occur requires an engineering design analysis. However, as a rule of thumb, DERs may become a significant operating concern when the DER penetration level exceeds 30%. In addition, FERC 2222 requires that electric distribution companies ensure that the addition of DERs do not impact system reliability, power quality, and safety.

A Distributed Energy Resource Management System (DERMS) provides centralized monitoring and control of DERs connected to a distribution grid by forecasting, monitoring, and managing the operation of each DER to satisfy operating and business objectives. The DERMS also manages the operation of DERs based on directives from the grid control entity or regulatory body and handles compensation of DER asset owners for their participation in grid control events. The current approach to monitoring and control of DERs by the ADMS is typically limited to near-real-time metering and “transfer-tripping” larger (utility scale) generators that are required (by IEEE 1547) to disconnect during distribution line outages to avoid “islanded” operation. Monitoring and control of other DERs (including smaller DERs such as rooftop solar generators, controllable loads, and energy storage) is usually not implemented in the ADMS for the following reasons:

  • Most DERs are customer owned and operated and customers are not obligated (by standard connection agreements) to supply the utility with remote monitoring and control capability for these DERs.

  • Adding remote monitoring and control facilities (including communication equipment) for many small-scale DERs would be cost prohibitive for the utility, especially if the DERs are located on the customer side of the meter (“behind the meter”).

  • ADMS has not been designed to handle the commercial aspects of DER management, such as registration of customers, verification of customer participation in system events, and compensation for participating customers.

  • Most DERs do not support communication protocols such as DNP3 that are commonly used by SCADA systems. Typically, DERs will support protocols and standards that are designed specifically for DER monitoring and management, such as OpenADR and IEEE 2030.5, and industrial standards like Modbus.

A DERMS should include both “technical” and “commercial” functions:

  • Technical Functions

    • Monitor the current operating status and output of all DER

    • Forecast future DER availability and output

    • Broadcast control commands/requests to participating DERs across the grid as required during grid events

    • Verify that DERs have provided the expected response

  • Commercial Functions

    • Register new participants

    • Manage customer “opt in” and “opt out” requests

    • Handle incentive payments to customers

To date, DERMS functionality has most commonly been implemented in a “standalone” system by third party aggregators that specialize in the grid-level management of customer owned assets. Aggregators enable owners of small scale DERs that do not meet minimum asset size requirements to participate in regional power grid markets, such as frequency regulation and other ancillary services. Aggregators serve as a “middle-man” between the end customer and the grid market operator to insulate customers from the complex rules for metering and verification and to handle incentive payments. In this approach, aggregators and distribution operators each need some level of DERMS functionality to manage the commercial and technical functionality of DERMS.

A standalone DERMS provides services for managing grid level events, but does not have the capability to manage localized distribution feeder problems and optimize the reliability, efficiency, and performance of individual substations and feeders. The latter capability is primarily the responsibility of the ADMS. Many of the ADMS applications require near-real-time information about the capacity, operating status and electrical outputs of DERs to accurately determine the distribution feeder electrical conditions and identify control strategies that may be used to avoid or mitigate the consequences of any operating problems. Most currently available ADMS solutions do not have enough near-real-time information about DER contributions to support these capabilities. For this reason, ESTA International introduced a new concept – the “DER Enabled ADMS” – which combines the best features of DERMS and ADMS to differentiate it from separate “stand-alone” ADMS and DERMS.

4. The “DER-Enabled ADMS”

Incorporating detailed, real-time DER information in the ADMS electrical model improves situational awareness and ensures that the electrical impacts of all types of DERs are accurately accounted for in the ADMS advanced applications. ESTA International’s concept of the DER-Enabled ADMS is depicted conceptually in Figure 2 below.

 

Figure 2: ESTA’s Concept of the “DER-Enabled ADMS”

There are three basic approaches to accomplish the DER-Enabled ADMS:

  1. Add DERMS Functionality to Existing ADMS Application Suite: With this approach, the complete set of DERMS capabilities would be fully and seamlessly integrated as another application on the vendor’s standard ADMS suite of applications. The benefit of this approach would be simplified and efficient access to DER models and information by the ADMS advanced application function, plus a similar user interface to all functions that provides a consistent look and feel for all applications used by the distribution operator. The downside of this approach would be a significant software development effort (with the associated risk), including adding the capability to communicate with potentially millions of customer owned DERs. The result would be a product that is significantly less mature than existing standalone DERMS products.

  2. Add ADMS Functionality to Existing DERMS Application Suite: With this approach, the complete set of ADMS application functions (including electrical model) would be added to an existing standalone DERMS product. The benefits of this approach, a fully integrated product suite, would be similar to approach 1 above. However, this approach also has a similar downside; a significant and risky development effort would be required that results in immature ADMS functionality.

  3. Interface Separate DERMS with ADMS (“Bolt On” solution): This approach would interface an ADMS from an established ADMS vendor with a DERMS system from an established DERMS supplier. This interface would enable the ADMS to receive DER information and initiate DER control actions when needed. The DERMS would handle the functionality that it was designed for, including communicating with potentially millions of DERs and handling the commercial aspects of DERMS, such as customer registration and incentive payments. The ADMS applications would benefit from having detailed information about DERs, such as DER status and output and forecasted capabilities, which would be included in the ADMS electrical model.

The distribution grid will continue to become more complex as the number of DERs and microgrids increase. Distribution management systems will need to be more responsive and proactive in the real-time monitoring and control of the distribution grid to manage constantly changing operating conditions, such as bidirectional power flows and weather-related outages, while ensuring reliability and quality of service to customers. The “DER-Enabled” ADMS will likely play an increasingly important role in the management of the distribution grid of the future.