Since the early 1990s, the U.S. electric utility industry environment has been evolving toward a greater reliance on intelligent electronic devices (IEDs) in substations. As a result, manufacturers progressively moved from none to single- to multi-use computer-based intelligent devices. National Grid (Westborough, Massachusetts, U.S.) has leveraged this enhanced technology to improve its substations.

National Grid's U.S. electricity delivery companies serve 3.2 million electricity customers in New England and upstate New York through more than 1200 substations.

Technology integration activity began at National Grid in the United States (then known as New England Electric System) in 1994 with its first use of a Programmable Logic Controller (PLC) in a distribution substation. This led to the creation of an Automation Study Team in 1996. In order to get input and direction from all stakeholders in National Grid's U.S. business, a Substation Integration Steering Committee was formed. The committee included Control Center Operations, Substation Operations & Maintenance, Substation Engineering & Design, Protection & Control Engineering, Relay Operations and Distribution Planning.

The Substation Integration Committee proved to be a good forum for cross-company debate on what integration technologies should be used. It also proved valuable in gaining stakeholder ownership of the design as it developed. The Substation Integration Committee, now called the Transmission & Distribution Technology Integration Steering Committee (TISC), has since expanded its scope beyond substation integration technology to include other similar technologies that can be applied to the transmission and distribution network, such as distribution automation.

In 1998, the first-generation automated substation standard was completed, and starting that year, 22 new distribution substations were designed to the standard. In 2000, evolutionary additions were made to the initial standard to accommodate the design needs of two transmission substations that were being refurbished. With the technology foundation established and successes realized, plans for a more ambitious second-generation standard were initiated in 2001.

The second-generation design is based on a breaker-and-a-half station (Fig. 1), which typically is employed in areas of high load density in National Grid's U.S. service territory.

The overall objective of the integrated substation design was to reduce the total life-cycle cost of the secondary systems within substations while increasing their functionality. This led to the replacement of many electromechanical devices in earlier designs with microprocessor-based devices and systems. An attempt was made to use digital devices, such as meters and relays that had self-diagnostics wherever possible, to take advantage of their functionality. This approach enabled data to be defined once and used many times through electronic transfer.

Principal Design Themes

As TISC continued to develop the integrated substation, six design themes were adopted:

1. Modularize the control and protection subsystems.

2. Maximize the use of protective relay data.

3. Minimize the amount of hardware and wiring.

4. Improve the capability and functionality of the substation user interface.

5. Increase system adaptability for support functions.

6. Enhance remote diagnostics, data collection and test capabilities.

As a result of the design themes, the following objectives and actions were taken in each area.

• Modularize the control and protection subsystems

  All protection and control functions for two bays, including the mimic and control handles, are in one modular cabinet. Bay A protection and control are located in the top portion with the mimic in the middle and Bay B on the bottom.

  Capacitor control also is modularized and can be built as a stand-alone unit if it is to be installed in an older station. If it is part of the integrated substation, it can use the station PLC; if it is stand-alone, it uses its own PLC.

  The modular approach to the integrated substation design provides the required flexibility to allow for expansion of a substation in the future, which is important if, for example, the station was built initially with only one bay.

• Maximize the use of protective relay data

  Wherever possible, the protection relay data has been collected once and used many times to provide information to various sources. For example, fault and meter data and breaker status are collected from the relays and displayed locally on the Human Machine Interface (HMI). The breaker and other time-critical data, accurate to 1 mS, are displayed on the Sequence of Events Recorder (SER). Distance-to-fault data, relay targets and fault type are bundled together and transmitted to the Energy Management System (EMS) for the control center's information and use.

• Minimize the amount of hardware and wiring

  Using the relay data and displaying the information on the HMI have eliminated the use of panel meters. The use of panel switches for Ground and Reclosing ON/OFF also has been eliminated, and the modular design has eliminated a substantial amount of inter-cabinet wiring.

  By using the PLC, auxiliary relays previously used for functions such as bus transfer schemes have been eliminated, along with timers and contact multipliers. However, protection system tripping remains hard-wired to the circuit breaker trip coils.

• Improve the capability and functionality of the substation user interface

  The functionality of the user interface, or HMI, has been improved over the first-generation design by taking another step forward and building in safety tagging. In this design, field staff carry out safety tagging on the HMI screen, which has built-in logic that prevents unwanted actions.

  Improvements also have been made in diagnostics and health checking by bringing a variety of IED status information to the HMI for display and alarms.

• Increase system adaptability for support functions

  The integration of technologies has enabled the creation of a platform for software support functions, such as auto polling of IEDs within the integrated substation, and other asset management tools such as transformer analysis and breaker wear recording.

  The use of the industrial automation data exchange technology, known as OPC, has opened up a means of efficient exchange of data between compliant software applications running in the substation PC.

• Enhance remote diagnostics, data collection and test capabilities

  The architecture of the substation allows for all devices to be remotely interrogated and diagnostics to be performed without the need to make an initial visit to a substation. This is clearly an advantage for remote substations or for out-of-normal business hours.

In addition to the diagnostic capability, the technology has introduced the ability to remotely upload updates to the PLC and HMI, thereby enabling more centralized support of the technology. This is highly beneficial since the penetration of the technology is dispersed across the company's service territory and the expertise to support it locally will take time to mature.

Substation Integration Architecture

The system architecture is designed with the objective of replacing traditional hard wire connections among substation devices with communications links. A general schematic of the system architecture is shown in Fig. 2. The communications topology involves several connection methods and protocols. A single interconnecting local area network (LAN), although a technical goal, cannot be achieved readily because of device limitations and the historical advantage of building on proven technology.

• The Modbus Plus protocol has been found to be robust and reliable and is a convenient way of communicating with the vendor's communication processor being used, the PLC, the backup HMI and the station computer. This protocol was used initially in the first integrated substation design and was carried into the second-generation to reduce development risks. Future integrated substation designs will move to an Ethernet-based architecture.

• The DNP protocol is used between the station communication processor, RTU and the station HMI, which allows the time tagging of data required for accurate sequence of events recording.

Benefits

The integrated substation has achieved many benefits including efficiencies, reduced costs and safety enhancements. Engineering and design time have been reduced and documentation in the form of design guidelines has been produced for guidance and continuity. Improvements, enhancements or corrections in control schemes are made easily using software and without hardware or wiring changes. Control elements are prepackaged as software functional objects, and software is designed once and replicated for specific projects.

The design offers efficient substation operations and maintenance practices, with embedded maintenance features. Dial-up access to the substation for monitoring, diagnostic and maintenance use reduces response time and travel costs.

On-site commissioning time is reduced with an internal Lab/Test environment that allows issues to be identified and resolved prior to the first installation.

With fewer cabinets in the modular design, a smaller footprint is achieved. The second-generation integrated substation design has reduced the footprint of a typical substation control system cabinet lineup from 178 sq ft to 75 sq ft (17 sq m to 7 sq m). This allows for a control house narrow enough to be built off-site and trucked in, which significantly speeds up construction.

The second-generation control system design has achieved a cost saving of 42% over the previous generation.

The smaller footprint has in some cases allowed for the upgrade of control systems of existing substations to the new design without building a new control house. Typically there is enough room in the control house to drop in the modular cabinets of the new design and perform a cutover prior to removing the old equipment.

The reduced number of panels also has allowed the same control panel designs to be installed in stations with primary designs that were built using the company's traditional outdoor low-profile design and metal clad stations.

The same design techniques have been applied in a transmission station, reducing panel space and achieving similar benefits and savings.

Currently, the design techniques used in the substations with the breaker-and-a-half configuration are being adapted for simpler straight bus configurations. The straight bus configuration does not require as much control logic as the breaker-and-a-half design, so location of the control logic elements may be moved from one device to another, for example, from the PLC to the relays themselves.

Installations

To date, there have been two successful installations of the new design in distribution substations with three more in progress. Some of these techniques are being incorporated into five transmission substations that are now in the design stage.

Future Challenges

With significant advances in manufacturer developments in substation integration over the past two years, an increasing number of solutions and options are becoming available. Going forward, the challenge with the integrated substation will be to successfully match the right number of devices with the optimal communications bus.

Now that substation information is becoming more readily available, attention needs to be given to the way that it is managed. Opportunities to mine this information using software agent technology are becoming increasingly available to enable faster and more accurate fault diagnosis for protection engineers and operations engineers, while providing smarter solutions for asset managers.

This newfound ability to remotely access and update components in the substation carries with it the need to focus on cyber-security measures in the substation environment. Consideration also must be given to the skill level of the support staff, how much support is required from the initial engineering design team, and at what level of penetration of these substations the field operations staff will be comfortable handling.

Integration of substation technology is an ongoing program of substation improvement and cost reduction in the face of technological and business change. National Grid has successfully commissioned several distribution stations using the first- and second-generation integrated substation designs, including four completed in 2003 in record time to meet summer load relief. Others are under construction or planned. Two transmission stations also have been built using the first-generation techniques, and components of the new design are being applied to transmission stations, with one currently under construction and four more in various stages of design.

Editor's Note

This article is based on papers presented at the 2004 DistribuTECH conference and the 2004 IEE conference in Developments in Power System Protection, Amsterdam, Netherlands.

Bryan Gwyn is manager of Protection Engineering for National Grid USA Service Co. Originally from Wales in the United Kingdom, Gwyn graduated from City University, London with a BSEE honors degree. He is a member of the Institution of Electrical Engineers and is a Chartered Engineer.
byran.gwyn@us.ngrid.com

William Panas is a consulting engineer for National Grid USA Service Co. Panas graduated from Rensselaer Polytechnic Institute in New York with BS and ME degrees in electric power engineering. He has worked as a protection engineer at National Grid USA Service Co. (formerly NEES) for 22 years and has been involved in substation integration for the past six years. He is a registered professional engineer in the state of Massachusetts.
william.panas@us.ngrid.com