OG&E Goes Wireless with Substation Monitoring

By Scott R. Milanowski, PE, OG&E Electric Services; Mark Peterson, PE, Cannon Technologies; and Michael Cannon, PE, Cannon Technologies

Critical substation equipment must be inspected periodically to ensure system reliability and efficient operation, but the application of technology allows utilities like OG&E to go beyond periodic inspections. Available communication tools, hardware platforms, integration techniques, sensors, video web-cameras, and web access now provide the foundation for real-time substation inspection and monitoring. Information retrieved from the substation by a remote server makes it possible to present information via a web browser, deliver alert messages for values that fall out of tolerance, and archive information for historical trending.

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Oklahoma Gas & Electric Co. has taken advantage of this type of technological advancement at a number of its T&D substations. These new tools have enabled OG&E to institute an asset management model that bases maintenance and operating decisions on real-time information, rather than periodic inspections.


OG&E’s first foray into substation monitoring began in 1999 with the construction of Robinson Substation, serving the Oklahoma City central business district. To augment the totally digital control and protection package, the Cannon Advisor system from Cannon Technologies Inc. was installed to provide equipment condition monitoring and trending. The system initially utilized a local HMI and computer with remote dial-up access, but was later upgraded to provide off-site data processing and web access.

In 2003, a team was formed to assess the capabilities, benefits and costs of on-line monitoring, and to develop a business case for implementation going forward. The desired attributes identified for a monitoring system included remote alarm notification, analysis ability, web-based accessibility, historical trending, and an open design that would support a variety of sensors. While the analysis indicated possible cost savings in a number of areas, the largest “bang for the buck” came from monitoring large power transformers with the intent of avoiding catastrophic failure. In its final report, the team recommended that monitoring be installed at various substations to reduce O&M costs, prevent catastrophic failures and improve system reliability.


The architecture used in the OG&E projects consists of a substation data gateway coupled to a remote monitoring server via the Internet. This architecture affords wide access to information without compromising the security of the energy management system, and it greatly simplifies and reduces the cost of the required installation at the substation control house. The architecture also utilizes wireless communication to the monitored equipment from the gateway, which eliminates the need for trenching and cabling between the monitored devices and the control house. Video installed as part of the monitoring system enables remote inspection during substation incidents.


Installation was accomplished by first building the server database and browser displays based on the equipment complement at a particular substation. With the database complete, on-site work began with installing the main data gateway and video equipment. Subsequently, the individual sensor packages and wireless equipment gateway hardware kits were installed on transformers and circuit breakers to be monitored. Sensor packages were easily installed, using techniques such as magnetic mounting brackets and designs that minimize disruption of existing field wiring. Finally, the devices were commissioned to verify correct point mapping, scaling and system operation.

The following examples demonstrate some of the benefits that OG&E has realized from the substation monitoring system.

Example 1: Chronic SF6 Leak on 345-kV Breaker.

When the monitoring system detects an alarm condition, an e-mail alert message is created describing the problem and providing a hyperlink to the website for further analysis. In this example, a gas-insulated circuit breaker had been leaking SF6 gas. Under normal circumstances, the control center would receive a low gas alarm via SCADA at some point, typically when the ambient temperature has cooled down in the middle of the night. Then, a technician would be dispatched on an emergency basis to re-fill the breaker.

With the new substation monitoring system in place, the chronic leak’s existence was not only detected, but the gas density trending allowed the low gas SCADA alarm condition to be predicted in advance, which allowed us to schedule equipment outages and crews during normal working hours. This not only reduced overtime costs but also improved the quality of life for the maintenance technicians.

Example 2: Load Tap Changer Controllers Gone Wild!

In this instance, an e-mail alert was received indicating that the LTC had operated 128 times the previous day. The normal operating frequency for this LTC had typically been approximately 20. A voltage technician was alerted, checked the device and found that the bandwidth setting was out of tolerance. The setting was adjusted, and the transformer LTC resumed normal operation.

Had there not been monitoring on this device, it could have operated with this condition undetected for an extended period of time, resulting in excessive wear and possible failure of the LTC.

Example 3: Neighboring Utility Inadvertently Overloads Bus Tie Transformer.

In May 2005, a line outage on a neighboring utility system caused excessive power to flow through a 345- to 138-kV bus tie transformer in eastern Oklahoma. The load surged from approximately 60 MW to 140 MW and remained at that level for approximately an hour. Correspondingly, the winding temperature reached 110 degrees Celsius. The transmission planning group was concerned that permanent damage might have been done to the transformer. Analytical data from the monitoring system helped reassure OG&E personnel that while the transformer did overheat, it was unlikely that permanent damage occurred due to the short duration of the temperature rise.

Had monitoring not been installed, a prolonged transformer outage might have been required to check for damage, which would have resulted in lost revenue for the company.

Example 4: Temperature Monitoring Saves Generator Step-up Transformer.

After a 500-MW generating unit was brought on-line after a two-day outage, the substation monitoring system issued an alert that the transformer was overheating. Crews were sent to investigate, but they reported that the winding temperature gauge mounted on the transformer indicated the temperature was normal (65 degrees Celsius). The issue was nearly dismissed, but crew members could feel heat radiating from the transformer tank. They also noted that one bank of oil circulating pumps was not running. The pumps were checked, and the controls were found to be placed on “automatic.” The pumps were switched on manually, and the transformer began to cool off immediately.

The cause of the problem was found to be a faulty thermocouple that controlled the temperature gauge and oil pumps. During this event, the transformer temperature reached 112 degrees Celsius and was still climbing. Transformer insulation begins aging exponentially at 120 degrees and failure occurs at 140 to 150 degrees. Had the monitoring system not been installed, it is likely that the generator step-up transformer would have been severely damaged or destroyed.

The on-line substation monitoring system provides numerous financial and operational benefits to the electric utility. The system provides real-time information on the electric power delivery system to reduce O&M costs and improve reliability.

Scott Milanowski is senior project leader and technology transfer, system integrity, for OG&E Electric Services. Mark Peterson is manager of Substation Advisor and Esubstation Services for Cannon Technologies. Michael Cannon is manager of Substation Systems for Cannon Technologies.

Benefits by Design: Integrating Substation Information and Enterprise Level Applications

By John McDonald, KEMA
Traditionally, substation data were acquired through RTUs and processed by SCADA applications in support of power system operations. The introduction of multi-function digital relays and other intelligent electronic devices (IEDs) at substations has made additional data available to help minimize system restoration time, reduce equipment maintenance costs, and improve equipment availability and system reliability.

Modern substation protection and control systems use local-area networking technology to interconnect computer-based IEDs that are able to communicate high-rate streams of electrical or other measurements (operational data) as well as records of how the devices and power apparatus reacted to faults, system disturbances and normal cycles of operation (non-operational data). This data is required to analyze the transient and long-term performance of the power system and its control systems. These new systems provide far greater quantities of valuable data than the older, non-intelligent systems.

Data marts and enterprise level integration schemes can now make telemetry data, equipment conditions, digital fault recorder and sequence of events data available to users and applications in a consistent, reliable fashion. This enables such performance enhancing strategies as condition-based inspection and condition-based maintenance to improve equipment and system availability while reducing O&M costs. Continuous monitoring of dissolved gas levels, oil temperature, vibration levels, and high-voltage transformer loading, for example, allows for the dynamic adjustment of equipment ratings to improve asset utilization and inspection or maintenance scheduling. Timely access to, and analysis of, digital fault recorder and sequence of events data allows quicker determination of fault location and quicker service restoration.

Some utilities that integrated or automated substations hoping to get information for better management now find themselves wrestling with overwhelming masses of data. IT systems that frequently are not designed to allow access to this data by engineering and O&M applications hinder a utility’s ability to benefit from substation data. Comprehensive enterprise level substation systems integration (ELSSI) initiatives can help electric utilities get their arms around the huge bodies of data now stranded in substations. Converting masses of operational and non-operational data into business intelligence, organizing this intelligence, and interfacing it with enterprise-level applications can yield operating and financial benefits.

The key is to give timely access to substation and equipment data to enterprise-wide users in planning, engineering, operations and maintenance. Utilities need to develop communications and processing systems that yield hard, timely, and succinct information for system operating security, economic operation, asset management, maintenance management, system planning, capital planning, and resource allocation. ELSSI adopters should understand key business metrics that support closed-loop business improvement processes. This makes it far easier to justify existing or new investments in substation automation and communications systems, and to reach the true payback promised by these substation systems.

The challenge is to bridge the gap between available substation data and the business goals. Utilities can bridge the gap by taking a number of interconnected steps including:

  • Road-mapping solutions based on long-term utility business objectives;
  • Planning communications system, data hosting, gathering, protection, and cyber security design;
  • Organizing and interfacing data to applications that extract information;
  • Selecting and developing applications that clearly and succinctly present all enterprise users with the levels and types of information they need to perform their jobs; and
  • Designing enterprise processes that close the loop between the management information ELSSI delivers and the business improvements that result, constantly detecting and correcting problems, and constantly improving the whole cycle of information processing and use.

John D. McDonald, P.E., is vice president, automation – Energy Systems Consulting for KEMA Inc. John is currently assisting electric utilities in substation automation, distribution SCADA, communication protocols and SCADA/DMS. He is also president of IEEE’s Power Engineering Society.

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