T&D World Magazine

Wired for Success

KCP&L is retrofitting Midtown Substation with updated communications protocols as part of a DOE smart grid demonstration project.

The smart grid may seem like a high-tech concept of the distant future to some, but Kansas City Power & Light is bringing it into the present with its smart grid demonstration project. The U.S. Department of Energy (DOE) awarded a US$24 million grant to Kansas City Power & Light (KCP&L), to be matched by the utility and its vendor partners. The DOE demonstration project will help the utility gain knowledge about customer needs and usage patterns while improving service reliability and power delivery, resulting in more efficient energy delivery and consumption for an entire demonstration area within the city's urban core.

End-to-End Demonstration

Like many other smart grid initiatives nationwide, KCP&L's DOE award originated with the American Recovery and Reinvestment Act of 2009. The two largest elements of this funding are the Smart Grid Investment Grant program and the Smart Grid Demonstration Program. The latter focuses on 32 projects demonstrating new, more cost-effective smart grid technologies, tools, techniques and system configurations. Of these, half are energy-storage demonstrations; the other half, including Kansas City's project, are regional smart grid demonstrations “to verify smart grid viability, quantify smart grid costs and benefits, and validate new smart grid business models at scales that can be readily replicated across the country,” according to a DOE statement.

Demonstration grants are designed to test cutting-edge technologies or new customer pricing concepts, and the KCP&L initiative stands out nationally as a fast-tracked, end-to-end, fully integrated effort. KCP&L's demonstration includes nearly all elements commonly considered part of the smart grid, with a heavy focus on implementing emerging standards and security measures. The utility conceived the distribution component of its smart grid demonstration project around an upgraded smart substation that features a local distributed control system based on International Electrotechnical Commission (IEC) 61850 protocols and control processors. Created as a framework for the design of electrical substation automation, IEC 61850 addresses the requirements for interoperability of intelligent electronic devices.

Green Impact Zone

KCP&L's demonstration project focuses on disadvantaged neighborhoods in the Midtown section of Kansas City's urban core known as the Green Impact Zone. This 150-block area has experienced economic decline and some abandonment. As a national model for place-based investment, the Green Impact Zone strategy aims to concentrate resources — through public and private partnerships — to transform homes and businesses into a thriving, sustainable community. In addition to housing renovations and property maintenance, efforts include services, job training and placement, and health and wellness programs. The smart grid serves an essential function in this transformation.

Deploying IEC 61850

One of the most significant developments for the smart grid now is the application of information technology to help optimize grid performance. Ideally, what this provides is more reliable power on a grid that could evolve to be self-healing. Soon, the grid will be intelligent enough to recognize a fault and restore it automatically without customers having to wait for a technician to service each individual failure. In many ways, the smart grid is a new frontier in power — challenging and full of opportunities for perpetual learning.

To achieve its objectives of improving service reliability, KCP&L identified four IEC 61850-based substation automation schemes to implement at its Midtown Substation in the Green Impact Zone:

  • Automatic load transfer upon transformer lockout

  • Faster clearing of the bus upon feeder breaker failure

  • Backup overcurrent protection in the bus differential relay

  • Cross triggering of all devices for distribution system events.

These schemes leverage IEC 61850's object-oriented communications-centric design technologies that originated in the information technology industry and are now being applied to power delivery. KCP&L partnered with Burns & McDonnell to assist in implementing these automation applications. As a result, KCP&L will be able to implement schemes that restore service automatically, reduce equipment stress and provide information about protection events that previously were not economically justifiable or widely deployed.

Load Transfer

The load-transfer scheme restores service to customers by automatically closing the tie breaker upon lockout of the transformer. The Midtown Substation design consists of two four-position buses fed from a dual-wound distribution transformer. Tie buses are used for maintenance and emergency backup of station operations when the transformer is removed from operation. The combined load of the two buses can be above the two-hour power rating for the transformer on many of the buses.

In the past, a dedicated programmable logic controller (PLC) was used at these locations to calculate the optimal feeder configuration to transfer to the tie bus before the tie breaker was closed. As part of the upgrade, KCP&L wanted this logic to be moved into the relay logic, eliminating the need for the PLC and additional wiring. This objective was achieved through the use of automation logic in a SEL-451 relay, with the real-time event notification capabilities of IEC 61850 generic object-oriented substation event (GOOSE) messaging for inter-relay communications.

Project objectives were achieved by programming the feeder relays (SEL-751) to publish the individual feeder loads and the total tie-bus transformer load (SEL-487) using IEC 61850 GOOSE messages. The main relay (SEL-451) subscribes to these analog values along with status messages for bus lockout, which triggers the scheme. The main breaker relay continually computes and publishes the optimal feeder configuration to transfer if a fault occurs, based on each feeder's load and available capacity.

When each feeder relay sees the scheme-enabled GOOSE message sent, it opens if it is to be shed before the bus tie breaker is closed. This scheme uses the two-hour overload power rating for the tie bus transformer, which gives the distribution operator two hours to reconfigure distribution feeders, thereby relieving the overload condition while continuing to provide service to customers on the affected bus.

Faster Overcurrent Tripping

Implementing a communications-based breaker failure scheme instead of relying on time overcurrent values resulted in the faster overcurrent tripping of main and tie breakers upon feeder breaker failure. When a feeder breaker trips, it sends a GOOSE message to the main and tie breakers indicating an operation where a stuck breaker timer is initiated. If a follow-up breaker-open message is not received within this time, the main and tie breakers trip, thereby clearing the fault. This faster overcurrent tripping scheme and subsequent schemes reduce wear on equipment, decreasing the likelihood of equipment failure and improving customer reliability.

Backup Overcurrent Tripping Scheme

Backup overcurrent protection in the bus differential relay provides redundancy to the logic, sensors and wiring in the feeder relays, allowing them to trip a feeder with a reclosing function if the feeder relay fails to detect or clear a fault. The bus differential relay uses its current circuit and sensor to monitor the feeder, and it is programmed to send a GOOSE-based trip message to the feeder relay, clearing the fault if the feeder relay has not already done so.

This scheme and the previous scheme could have been implemented using pre-IEC 61850 protection and control designs and techniques, but they were not cost effective to implement. Using the common communications bus reduces the cost of implementing these additional schemes to programming and testing. Once the schemes are initially developed as part of this pilot, they can be used for future projects at a marginal cost.

Cross Triggering

Cross triggering of all devices for every distribution system event and at a specific time each day provides the engineering department with detailed oscillography and event information. This information explains how the protection and control functions worked under fault conditions. Previously, event information was only available from fault recorders, which were not cost-effective for distribution substations.

KCP&L's design leverages the power of relays for recording waveforms and IEC 61850 GOOSE messages to cross trigger devices, enabling station-wide awarenesss that had been impossible in the past. Analyzing this information allows schemes and settings to be optimized, providing customers with more reliable service.

Robust Ethernet Communications

Reliable communication is required for IEC 61850 operation. As part of the pilot, the Midtown Substation was retrofitted with a redundant Ethernet communications network with hardware from two switch vendors (RuggedCom and Cisco) for protection operation. Using two vendors allowed KCP&L to evaluate the products simultaneously to determine which was best suited for substation protection and control networks.

Each vendor's equipment was used to build a ring in the substation, and each relay has an interface connected to both rings. The rings are interconnected at two points for redundancy. The core ring was built using gigabit fiber connections. The relays each have two 100-Mbps Ethernet interfaces used in a hot standby configuration. Each vendor has its own proprietary protocol for blocking loops from forming in the Ethernet network while recovering from a link failure in less than 50 msec. In between the rings, rapid spanning tree protocol was used to provide failover in less than 250 msec.

In addition to a protection local area network (LAN) within the substation, a firewall was used to isolate a separate LAN for substation automation equipment. A third LAN was used to create a secure enclave for communication outside the fence to an Ethernet-based wireless mesh for field device communications. KCP&L was able to follow the National Institute for Standards Interagency Report (NISTIR) 7628 standards for smart grid security by segmenting the substation LANs. This design also provided an operational benefit by grouping devices by operational priority, allowing more changes to be made to the automation LAN without consideration for scheduling an outage on the protection LAN.

All relays except the transformer protection relays were installed on the doors of switchgear cubicles. The fiber jumpers running between the cubicles from relay to switch are subject to more fatigue than normal designs for jumpers. As a result, a crush-resistant jacket from the Optical Cable Corp. was specified to cover the jumper. Coloring the jackets red or blue simplifies identification of the two separate rings. The same jacket was used on a 12-fiber multimode jumper with mechanical transfer push-on/off (MTP) connectors used for cabling between the various breaker lineups and the station control house.

To fan out the MTP connector into little connectors, a pre-terminated cartridge was used to provide 12 little connectors on the front and a MTP connection on the back. Two 12-fiber jumpers were run to each switchgear, providing redundant connectivity. Using a hardened pre-terminated fiber system reduces outage duration by eliminating any field terminations and special training for the electricians performing the relay replacement. The hardened cable eliminates the need for inner ducts to identify and protect the fiber cables, allowing them to be installed in the cable trays and trenches with other control cables.

Primary operator monitoring and control of the substation will be through a centralized distribution management system (DMS) and a local SICAM PAS controller from Siemens in the station. The SICAM will communicate with the relays using the IEC 61850 manufacturing messaging specification (MMS). During the pilot, serial communications will be maintained to each relay from the substation remote terminal unit to support dual communications with the relays from the existing energy management system (EMS).

This second channel will provide backup capabilities for substation control based on a proven technology from the existing utility operation systems. This will allow flexibility with the management of the DMS during the pilot. Such an approach also simplifies the security measures required to maintain secure communications with the EMS, which is a North American Electric Reliability Corp. (NERC) critical infrastructure protection critical asset.

Local clocks in each switchgear lineup will provide time coordination to the relays. Once precision time protocol is supported in relays, a single network-connected clock could be used to provide time coordination through the redundant fiber Ethernet connections, eliminating additional wiring.

Ready for IEC 61850?

Deploying IEC 61850 requires coordination and cross-training from at least four areas of the organization: protection and control, information technology, security and compliance, and maintenance. By forming a cross-functional team that leverages each organization's expertise, the collective can work efficiently and effectively, and make decisions about what technology to deploy.

Establishing a combined lab where equipment can be staged and tested is key to educating all affected departments on the new technology. It also can be used to validate both the equipment and the design in a controlled environment before it is installed in the field. Burns & McDonnell's Smart Grid Lab was used to test communications and relay settings during design while KCP&L was developing its own lab.

Beyond the Fence

In addition to using IEC 61850 for communications within the substation, KCP&L plans to implement the MMS protocol outside the substation for supervisory control and data acquisition (SCADA) communication between the field devices and substation-based distribution automation controller and the DMS. Initially, field devices will be deployed using distributed network protocols, which will be converted to MMS protocols as it becomes available in field device controls.

Using an IP mesh network in the field reclosers, capacitors and fault indicators provides a low latency wideband communications path for beyond-the-fence communication. This capability paves the way for future improvements, such as high-speed bus transfer schemes using GOOSE messages in the field area network. These messages could be used to isolate faults and close tie switches, transferring the load in real time and, thereby, eliminating momentary outages, which are becoming a bigger concern for customers.

A Smart Grid Future

IEC 61850 is often considered for new substation construction, but this project showed that it brings the same benefits to an existing substation. Using IEC 61850 in a retrofit application allowed KCP&L to retain its existing wired controls and test the standard while retaining the existing protection and control design. Once the final bus is complete in 2012, KCP&L will benefit from the values of the increased information processing in the station.

KCP&L's demonstration project is modernizing power delivery in its demonstration area by leveraging the knowledge and capabilities of information processing to restore service and protect equipment from failure. Deploying new technology, especially in a traditional utility environment, is filled with challenging growth opportunities that require innovation, teamwork and vigilance.


The authors would like to acknowledge Dave Rucker and Tim Hinken of KCP&L, and Chad Stilwell and Meghan Lyons of Burns & McDonnell for contributing to this article.

Ed Hedges ([email protected]) is manager of smart grid technology planning at Kansas City Power & Light. He is responsible for developing near- and long-term technology plans to guide the development of KCP&L's vision for the future energy distribution network or smart grid. He is the lead technology planner for KCP&L's Department of Energy-funded regional smart grid demonstration project. Hedges earned a BSEE degree from the University of Illinois. He is a registered professional engineer in Wisconsin.

Matthew Olson ([email protected]) is an associate project manager in the T&D division at Burns & McDonnell. He has worked to deploy IEC 61850 and packet-based utility networks supporting the smart grid, and has 10 years of experience designing and managing the deployment of private communications networks. Olson earned BSEE and MSEE degrees from the University of Tulsa and is a registered professional engineer in Kansas and New Jersey.

Ethernet Communications Simplifies Substation Control

Using a converged Ethernet network for all substation communications leverages Ethernet's high-throughput, low-latency and peer-to-peer communications to support multiple conversations using different protocols simultaneously on the same wire. This simplifies substation control by allowing the network to serve as an open, standards-based communications platform to build upon. It supports SCADA via the widely used Distributed Network Protocol 3.0 (DNP 3.0) while, at the same time, serves as a platform for emerging peer-to-peer protocols like IEC 61850, engineering remote access and timing.

Adding switching to Ethernet made it deterministic, which was required for its use in industrial control. The switch changed the physical layout of the network from a shared physical bus to a point-to-point star configuration. This allows for full duplex operation and the ability to queue packets in the switch. Queuing provides Quality of Service (QoS) by giving priority to time-dependent applications like protection and control. Other modifications include standards based fiber interfaces and ability to support redundant interfaces on a device at a cost-effective price point (due to its near-universal implementation in other industries). These technology advancements at a cost-effective price point are increasing its usage in substations.

The benefits of Ethernet-based communications outweigh the training and compliance costs associated with using Ethernet instead of serial communications. Securing Ethernet can be done more cost-effectively than securing serial communications and provides security and not just compliance.

Companies mentioned:

Burns & McDonnell www.burnsmcd.com

Cisco | www.cisco.com

Kansas City Powel & Light www.kcpl.com

North American Electric Reliability Corp. www.nerc.com

Optical Cable | www.occfiber.com

RuggedCom | www.ruggedcom.com

Schweitzer Engineering Laboratories www.selinc.com

Siemens | www.siemens.com

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