Transmission automation and distribution emerging trends

In July 2009, the US Department of Energy released its first “Smart Grid System Report” to Congress as required by the Energy Independence and Security Act of 2007. The report contained key findings in distributed energy resources, electricity infrastructure, business and policy, and high-tech culture change.

 

Two of the key findings the DOE centered on the continued automation of the US electricity infrastructure. The DOE report stated that “transmission substation automation remains strong with greater levels of information exchanged with control centers” and that “cost/benefit thresholds are now encouraging greater levels of automation at the distribution substation level.”

 

The level of attention and investment that transmission and distribution automation are experiencing coupled with the rise of information technologies for use in the grid has led to the emergence of a number of interesting trends within the transmission automation and distribution automation sectors.

 

Transmission Substation Automation

Substation Automation is a growing trend amongst electric utilities. According to interviews conducted by the DOE as part of its recent report, “28% of the total substations owned were automated.”  The DOE also notes that other recent research has shown that “84% of utilities had substation automation and integration plans underway in 2005.” In pursuing Substation Automation, US utilities are getting more and more interested in learning what the EU utilities are doing. IEC 61850, which grew from earlier efforts in the US, has gained a lot of momentum and is now of the hottest items in substation automation.

 

In many ways IEC 61850 is the culmination of a number of ideas and efforts aimed at developing a unified protocol that have finally evolved. The emerging trend among US utilities is to adopt DNP 3.0 and deploy Substation Automation with the option of being able to migrate to IEC 61850. US utilities are watching, learning and waiting for the right opportunity to make the transition from using DNP protocol as part of their Substation Automation solution to using IEC 61850 in the future.

 

Furthermore, Sensors and Relays are going digital with the result that substations are getting more and more automation. Today’s’ modern substation has its own LAN where Intelligent Electronic Devices (includes the family of Relays) can all “talk” with each other using a variety of architectures.

Relay Coordination and Sensors

Protection is a fundamental aspect of electric power systems operations. The philosophy of Protection is to isolate faulty parts of the network so as to ensure that the remaining part of the network stays healthy. In other words, “cutting off the infected arm before the infection spreads to other healthy body parts.” While the actual switching is accomplished by Circuit Breakers, the brains behind the circuit breakers are the Relays as they are responsible for making the decision. Sensors provide the Relays critical electrical information so that these Relays may process the information and send out the appropriate signals for the Circuit Breakers to open, thus isolating a fault.

 

Relay coordination at the system level is the orchestration of all the relays in the power system to achieve the desired objective: Protection. What is changing today is that relays are becoming smarter in the sense that they are able to do a lot of processing and lots of horsepower at the same time (in fact much, much more horsepower than is actually utilized). In turn, many utilities are phasing out old electromechanical relays for a host of reasons like age, lack of vendor support, lack of spares (and spare-parts), as well as the opportunity to adopt new technologies.

 

The result is that major deployments of relays and sensors are taking place silently as business cases for Relay Replacement are well documented and most utilities are proceeding with such work as and when they figure they need to replace their existing electro-mechanical relays.

 

Coordinated action at Control Centers (based on recent Situational Awareness developments and NERC studies on additional need for on-line Advanced Network applications)

Transmission Control Centers serve a critical function in today’s power systems monitoring and control operations. The North American Electric Reliability Corporation (NERC) has recognized that critical function and made control centers a mandatory critical asset under NERC Critical Infrastructure Protection standard CIP-002-1.

Control Centers operated by companies conducting key NERC reliability functions perform vital activities on a daily basis and around the clock.

 

Key activities include planning for power transfers across self contained and interconnected transmission grids, committing the right amount of generation to meet expected load demand, and coordinating the power output of generators in real time. All of these activities must be carried out in addition to the responsibility of re-configuring the grid topology to mitigate service interruption risks, minimize transmission and distribution losses and power production costs, as well as restoring the restoring grid to normal operating states in cases of systems disturbances and events as soon as possible.

 

Over the decades, these functions and their control centers, have evolved from small rooms manned by a few dispatchers coordinating field-deployed personnel using radio and telephone communications devices, to substantially larger and more complex information nerve centers, dependent on the latest technologically advanced Energy Management Systems (EMS) to assist professionally trained and specialized Systems Operators in carrying their much different duties.

 

Modern Energy Management Systems have helped expand the oversight of Control Center staff from small local centers with jurisdiction over smaller segments of the transmission grid, to regional and even national control centers with a hierarchical oversight of their entire grids, including in certain cases the grids of their neighbors. This additional responsibility complicates the Control Center’s duties and requires even more complex and effective tools to execute their mission.

 

As a result, EMS have evolved from basic remote control equipment to provide Supervisory Control and Data Acquisition (SCADA systems), to adding Load Frequency Control to assist the Control Center in balancing load demand with power generation in real time, to Automatic Generation Control systems (AGC) that allowed economics to enter the decision making process for generation control decisions, to adding computer based power and network analysis tools to help predict the behavior of the transmission grid under different load, generation and system topology scenarios.

 

It is in this latter area that a new wave of advanced network analysis applications continues to evolve from tools exclusively used by engineers with complicated user interfaces in back-office study mode applications looking at time periods well in the future, to becoming on-line tools with much friendlier user interfaces to allow fast configuration and set-up of near real time what if scenarios and at the disposal of the on-shift Control Center staff. In short, the emerging trend is the implementation of control center systems that provide data in a systematic, visually-intuitive format.

 

In North America, the era of the so called Control Center Situational Awareness was borne out of the findings of the U.S.-Canada Power System Outage of the August 14, 2003[1]. A key conclusion of the analysis of those events identifies as a contributor of the events the “lack of situational awareness and inadequate reliability tools.[2]” That investigation also notes “the need for visualization display systems to monitor system reliability.”

 

A NERC appointed task force made several recommendations to NERC for additional reliability requirements and standards that mandate the following changes in Control Center tools and processes to enhance the Situational Awareness of its operators and staff [3]:

 

First, define a minimum set of tools referred to as the “Reliability Toolbox” and require that all Transmission Control Centers have the following five real-time tools in operation at all times as well as performance and availability metrics and maintenance practices for each of those tools: The required tools are:

• Telemetry data systems

• Alarm tools

• Network topology processor –

  • this makes sure online and real-time information being presented in the control center is accurate with what is going on in the field

• State estimator –

  • Predicts power flows

  • In the past this tool was not utilized in real time. Rather it was used in a ‘study mode’ by an engineer

  • The tool has evolved in to provided data every five minutes on the ‘state’ and provides the info to the operator

• Contingency analysis

Second, require Enhanced Operator Situational Awareness by defining standards and guidelines for the adoption of minimum situational awareness practices, including:

• Power-flow simulations

• Conservative operations plans

• Load-shed capability awareness

• Critical applications and facilities monitoring

• Visualization techniques

And thirdly, the NERC The task force also recommended that NERC address the following six major issues to enhance the effectiveness of real-time tools:

• Definition of the bulk electric system

• Definition of the wide-area-view boundary

• Development of system models and standards for exchange of model information

• Specification of acceptable reactive reserves

• Determination of adequate load-shed capability

• Provision of adequate funding and staffing for maintaining and upgrading real-time tools

KEMA expects the continued evolution of Control Center coordination issues framed by the outcome of these recommendations and the impact of other related issues such as the explosion of Smart Grids implementations, the enactment of stricter Energy Sustainability policies and the diversification of renewable and distributed generation resources. KEMA will also continue monitoring and actively participating in future discussion of these topics in its role as the Chair for the Real-Time Tools Standard Authorization Requests (SAR) Drafting Team.

 

Distribution Automation

Distribution automation has been on-going since the 1990s (despite major cost obstacles in the mid-1990s) and has recently seen an increase in activity, deployment, and investment. Concurrently, substation automation has been growing as well. Key drivers for the increase in distribution automation include stimulus funding to cover investment issues, Advance Metering Infrastructure deployment to help with communication issues, as well as the development of more creative and advanced technologies.

 

One of the emerging trends in distribution automation is the importance of functionality in distribution management as utilities face huge data issues created by an abundance of data and a lack of functional tools to manage it. Further complicating the issue is the fact that many utilities do not realize that their data issues until they try to leverage their data systems. Consequently, vendor offerings in distribution automation are a mixed bag with no clearly defined offerings. Some vendors offer product that work; others offer the promise of their technologies works but do not deliver.

 

In addition, modern Geographic Information Systems (GIS) have become a major data port for utilities. GIS provides functionality for automated mapping and facilities management. The interesting twist is that GIS is now a central source of data for distribution applications. While GIS is great for collecting data, it struggles with the engineering side of the things (load flows for example).

 

Feeder-Load Balancing

Unbalanced load flows planning tools have been around for a long time. The big change is that these tools are now offered and utilized in a real-time environment rather than a planning environment. Furthermore, grid optimization applications are offering utilities the ability to reconfigure the feeders to maintain highest efficiency in real-time, all the time so that utilities now run feeders for the most bang for their buck.

 

Capacitor switching

Volt VAR has been tested out significantly and is now in use for capacitor switching with a second evolution into feeders ongoing and feeder optimization down the road. The key again is functionality and utilities are now discussing the possibilities and KEMA is working with utilities to test it.

 

Restoration

Restoration tools sit at the nexus of the debate between central control versus local control where devices and applications in the field would have access to real-time configuration and potential control of the distribution network.  At the local level, it is now becoming possible for fault isolation services to identify circuits with problems, intelligent switches to communicate the problem, and feeders to restore it automatically. For now, the trend that is emerging is a hybridized control system with central controls still dominant and local control systems expanding in the field.