Case Study: APS Gets a Modern Visualization Solution
By Jim Finch
In September 2011, an 11-minute system disturbance occurred in the Pacific Southwest, leading to cascading outages and leaving approximately 2.7 million customers without power from Arizona to Southern California. The Federal Energy Regulatory Commission’s (FERC’s) post event analysis traced the disturbance’s initiating event to what should have been a routine switching to isolate a capacitor bank in North Gila, Arizona. Despite careful planning for the switching, a simple human error—a skipped step in the process—created an arc over the switch and resulted in the automatic disconnection of the 500 kV Hassaympa-North Gila line.
While the loss of a single 500 kV transmission line at Arizona Public Service (APS) initiated the event, it was not the sole cause of the widespread outages. FERC also discovered that the September 2011 event stemmed primarily from weaknesses in two broad areas—operations planning and real-time situational awareness. Without adequate planning and situational awareness, entities responsible for operating and overseeing the transmission system could not ensure reliable operations within system operating limits (SOLs) or prevent cascading outages in the event of a single contingency.
Recognizing these limitations, APS improved its operations by improving operators’ visualization into contingency analysis and transmission grid situational awareness. The utility tapped the team at BRIDGE Energy Group to help it create the multiple complex data integrations required to deliver the vision. The team began by developing what would be the foundation for the project, including the integration of OSIsoft PI Historian and the architecture for AF Framework.
On July 7, 2014, FERC approved a consent agreement with APS that formalized a variety of mitigation tasks including expanded real-time contingency analysis (RTCA) to increase its situational awareness. The agreement came with an aggressive three-month timeline. The BRIDGE team worked closely with APS’s transmission energy control center (ECC) operators and engineers to build visualization solutions that display contingencies on a map instead of in a tabular format. Understanding that operators are loathe to adding additional screens, but unable to incorporate into existing energy management system (EMS) screens due to NERC CIP issues, the team set out to solve the business problem with these constraints in mind. In the end, the application and the information displayed were so compelling that the operators wanted the new application anyway. From use case development to specific graphical user interface details, the on-site development team leveraged the operators themselves as an integral part of the team. The result was the geospatial visualization system (GVS).
The ECC’s RTCA engine was designed to analyze more than 852 possible failures (N-1 events) once every three minutes and present the exceedance results in a tabular format. Working from those tabular results that changed once every three minutes, the ECC operators were required to track these potential exception events and restore the system to a secure N-1 state as soon as possible, but no longer than 30 minutes. The data rich, dense tabular format, however, made it difficult to quickly identify patterns or noteworthy inconsistencies in expected performances.
Through a series of workshops, the BRIDGE team worked closely with APS’s ECC operators to build a display that would clearly highlight the N-1 exceedances, but not obscure other transmission line characteristics. Some content is displayed on a wall map in the control room, but operators also receive additional details through their desktop interfaces as they drilled down into the data. As operators take mitigation actions in the EMS system, the next RTCA analysis shows either the exceedance was resolved or its next impact.
In addition, the BRIDGE team used SCADA and analytic data from the Siemens EMS system. This was imported into OSIsoft PI AF data structures, providing the team with data that could be easily displayed and translated into graphic formats. These data elements were then incorporated with other visualizations as map view layers, so the ECC operators can quickly gain context of that data prior to taking mitigating actions. This geospatial view of the transmission system allows operators to assess and respond to real-time conditions and real-time contingency results quicker, enhancing reliability.
The team noted, however, that not all data lends itself to geospatial representation. The greatest value comes from linking tabular and geospatial views. Moving beyond the initial implementation, the team provided the presentation of tabular data with full sort and filter capabilities. When referencing RTCA data, the operator can select a highlighted contingency on the map. This causes the RTCA Summary table to appear with that exceedance row highlighted. Conversely, the operator can select an exceedance row on the RTCA Summary table and highlight the exceedance’s location on the map.
Once a mitigation is implemented on the EMS system, the associated contingency is no longer flagged as harmful in RTCA and is then removed from the RTCA summary table.
The FERC-NERC staff report on the 2011 outage also highlighted the impact caused from having no situational awareness of the phase angle on the disrupted 500 kV line. ECC operators thought they could reestablish that line quickly, however, the phase angle had moved more than 70 degrees immediately following the disruption. To address this scenario, the new solution includes near real-time phase angle displays between phase angle pair connectors. This information is used to determine when a transmission line has exceeded its maximum closing angle.
One of the key features delivered in the new system is the ability for ECC operators to select their own combinations of information and zoom-level to be displayed on their individual monitors. Instead of being constrained by general use parameters, the ECC operator can select the characteristics and the level of detail to be displayed.
In Figure 1, the ECC operator has chosen to select all transmission voltage lines, their associated near real-time currents and their asset designations (names). The ECC operator could have, however, easily restricted the display to just 500 kV and 345 kV lines.
APS ECC operators identified other geospatial components they wanted to integrate into the GVS application. In the map view, fire and fire perimeter information from the national wildfire information clearinghouse (GeoMAC) is automatically uploaded into GVS. The ECC operator can zoom into that location and view locations of nearby transmission towers.
As noted previously, not all information benefits from map/geospatial displays. The team, therefore, identified such information and associated it in relational “dashboard” and “summary” displays. Figure 2 is one of the several dashboards built into the GVS to centralize related data for operator viewing.
This view presents automatic generation control (AGC) data and information that allows the ECC operators to quickly assess generation-load-interchange balancing. In addition to the numeric data, the operator also can see the trending of many key measurements including frequency, area control error and generation among other things.
Working sessions, which occurred regularly throughout the development and delivery processes, were key to refining the concepts and displays. Efforts by APS, BRIDGE Energy Group and other technology partners resulted in a world class visualization system for system operations that will benefit APS now and in the future, said Sarah Kist, director of transmission operations and maintenance at APS.
“GVS provides our operators with greater situational awareness by providing a geospatial view of our transmission system,” said Kist. “This allows the operators to assess and respond to real-time conditions and real-time contingency results more rapidly, enhancing reliability for our customers.” UP
Jim Finch, principal consultant at BRIDGE Energy Group, has more than 20 years of program and project management experience with complex, multivendor integration projects in energy space as well as across a wide variety of business verticals. Mr. Finch’s recent electric utility projects have focused on situational awareness visualization and data analytics in both distribution (smart grid, OMS and EMS) and transmission (EMS, Synchrophasors) environments.