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The Next Phase of Development for Distribution Systems Part II

April 1, 2019
What are the most important innovations affecting distribution systems?

Many emerging technologies will have an impact on the grid and on other key elements of our electrical systems, electrical operations and the broader infrastructure. One of the most important types of these emerging technologies rely on solid-state power electronics and which provide more precise Volt-VAR optimization and greater efficiency. However, these solid-state technologies are in the later stages of development and demonstration.

Among the various technologies are a few that are the focus of significant research and development — and are, in some special cases, in very early stages of commercial use.

Here is a list of some of the most important innovations:

1. Designing computer models for new technologies, which can then be incorporated into planning tools

While the industry is rapidly expanding its knowledge and experience in planning and operating large HVAC and HVDC systems with increasing levels of DERs, there are several areas where further research and development is needed. Power systems planners use computer models of components to design power systems. As new technologies evolve, there is an opportunity to develop robust data sets on the performance of those technologies under an array of conditions. This data can then be used for accurately modeling the new power system. For many of these new technologies, there isn't sufficient data to develop such models. This hampers the planner’s ability to design tomorrow’s grids for reliability and availability, and to assess the range of configurations available so as to establish optimal designs.

2. Developing alternative micro-grid architectures

Recent storms and the resultant extensive blackouts have raised the question as to what impact would expanding the use of micro-grids have and what would their preferred architectures be in order to enable their functionality and integration into the grid, during normal and emergency operation.

3. Deploying advanced power electronics

As mentioned above, increasing penetration of DERs, especially solar photovoltaic (PV) systems on the distribution power grid is introducing newer grid integration challenges for utility engineers. The focus in some places is to develop solid-state power electronics that can be deployed on distribution systems in ways which manage power flows, optimize voltage and reactive power to reduce generation requirements and improve power quality. These are also being deployed on data centers and industrial facilities to ensure power quality and reliability for sensitive applications.

4. Adding sophisticated distribution management systems into the next generation grid

One critical gap is in the capability of the Distribution Management Systems (DMS) which are used to monitor and control distribution systems. While the state of DMS technology available to electric utilities is evolving from existing components, it is not clear whether such an evolutionary development will keep pace with emerging requirements to manage distributed energy technologies.

DMS contain a number of elements. Critical among these is an Outage Management System (OMS). An OMS  is used to manage and restore service to customers following major storms and other events. Reliance on traditional OMS has become more inefficient, especially as utilities deploy more SCADA systems across their distribution grids. Existing systems do not incorporate on-the-ground conditions in real-time, tapping into relevant data sources.

The need for an integrated, real-time DMS — one with computer-aided tools for switching, load flow analysis, fault location and isolation — is prompting utilities to move toward advanced DMS. Advanced DMS will support and enable the smart grid, becoming the single repository of certain real-time and near-real-time data, as well as, the power system connectivity model (asset characteristics, connectivity, and renderings). Current DMS are not tracking net load at the customer level in near-real time; and are not providing an integrated near-real-time model of transmission and distribution power flows; or dispatching or supporting distribution level markets to manage the operation of distributed energy technologies. The DMS, in conjunction with the OMS, becomes an information foundation to support the smart grid.

What benefits can these new tools and technologies deliver? Here’s a short list of some of the value which can generated:

  • Faster simulation and modeling: If/when it works, this improves situational awareness and decision support.
  • Self-configuring grid: Fault location information, in combination with knowledge of electric connectivity and switch status/remote controllability, can allow the DMS to develop a new configuration, minimizing the extent of outages.
  • Condition-based maintenance: Usage and response data inform a condition-based maintenance application to analyze and develop different maintenance strategies.

These strategies can be tested in a study environment within the DMS on the as-operated model, or on the as-built model.

Subtle differences exist between DMS products, since they have developed from different starting points, either SCADA or OMS, and because they have evolved into their current forms. These different origins have influenced product capabilities. Products derived from SCADA started with schematic one-lines and they remain device-centric. These provide switch execution linked to supervisory control systems in native mode, and advanced supervisory control device configuration capabilities. These DMS provide real-time architecture for tracking device configurations and managing centrally controlled distribution devices.

Alternatively, products developed from OMS remain more customer and outage oriented. This path has provided more experience with distribution processes and provide crew management capabilities in native mode, but their SCADA/tagging capabilities are often somewhat cumbersome. These differences are beginning to blur as DMS mature and offerings become more comprehensive.

Current DMS offerings serve to integrate certain information and operational systems and to handle the significant quantity of data characterizing the real-time management of the system. A fully functional DMS, given current technology, would consist of a single user interface for SCADA, OMS, distribution system state and switching information, distribution automation applications, and advanced analytics.

Systems that include dynamic transmission and distribution topologies, and DERs will require more transparent and integrated planning along with more detailed real-time operational management and coordination.

Operating systems in which DERs impact transmission and distribution system operations require the availability of the following:

  • A federated control architecture which connects transmission and distribution operations;
  • Integrated modeling and state estimation, to give transmission and distribution operators real-time awareness of power flows across transmission and distribution systems;
  • A flexible, advanced information architecture to manage a large expansion in operational data, to integrate an evolving set of information systems and applications, while maintaining cybersecurity;
  • The ability to commit and dispatch or forecast and coordinate the operation of large numbers of distributed technologies. This enables the dynamic management of the topology of mesh-based or microgrid-based distribution networks, optimizing voltage, and simultaneously maintaining phase balance across the distribution system;
  • Ultimately, distribution level market structures that can coordinate settlement of transactions.

These requirements, in part, parallel the types of systems that were developed for the operation of RTOs and ISOs. However, efficient operation of a more highly distributed system will have to accommodate a larger number of control points and manage greater complexity. The extent to which control of such systems should be distributed and how such a distributed control system might operate are open research questions. The development of such systems will require significant, multi-year RD&D investments. And there is a limited market to support entirely private sector development of such systems.

A variety of economic factors and policies will continue to drive the deployment of distributed energy technologies. There could be significant reliability and economic costs if control systems do not advance at a pace adequate to efficiently manage a more distributed energy system. Some in the United States have argued that, as the country cedes a leadership role in the development of such technologies, one result will be increased cyber-security vulnerabilities for power systems. Therefore, some organizations are placing a high priority on RD&D for those information and control systems which support efficient integration, enabling a more dynamic transmission and distribution grid and larger-scale deployment of distributed energy technologies.

5. Demonstrating power electronics enhanced transformers

Conventional transformers suffer from poor energy conversion efficiency at partial loads, use liquid dielectrics that can result in costly spill cleanups, and provide only one function – stepping voltage. These transformers do not provide real-time voltage regulation or monitoring capabilities, and do not incorporate a communication link. At the same time, they require costly spare inventories for multiple unit ratings, do not allow supply of three-phase power from a single-phase circuit, and are not parts-wise repairable. Future distribution transformers will also need to be an interface point for distributed resources, from storage to plug-in hybrid electric vehicles.

The intelligent universal transformer (IUT) is a first-generation, power-electronic replacement of conventional distribution transformers. The Electric Power Research Institute (EPRI) has developed an IUT which can serve as a “Renewable Energy Grid Interface” (REGI). The new concept includes a bi-directional power interface that provides direct integration of photovoltaic systems, storage systems, and electric vehicle charging. It will also incorporate command and control functions for system integration, local management, and islanding.

6. Developing Phasor Measurement Units (PMUs) for distribution systems

With the increasing number of DERs, many of which are variable and low inertia, the application of PMUs at the distribution system needs research around the applications and modeling for real-time applications. Micro-PMUs can provide real-time data and visibility for electric distribution participants and systems to use for diagnostic and control applications for supporting the integration of distributed energy resources. Because of the relatively small angles and high noise-to-signal- ratios on the electric distribution system, the demands on micro-PMU technology design and performance at the distribution level are about an order of magnitude higher than those for transmission. Research and development work is now underway on micro-PMUs; demonstrations of prototypes are in startup phases at universities and selected utilities in the United States. For example, under ARPA-E Award #DE-AR0000340, Micro-Synchrophasors in distribution systems, the California Institute for Energy and Environment/ University of California Berkeley, in conjunction with Power Standards Lab and Lawrence Berkeley National Lab, are conducting a three-year research project to develop a high-precision micro-synchrophasor, or μPMU, to study its applications for diagnostic and control purposes in distribution systems.

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