Implementation of Remote Fault Indicators in Southern California Edison
By Burl Smith, Manuel Avendaño, Eric Nunnally, & Audel de la Torre
The Need for Smart Grid Sensors
The situational awareness of Southern California Edison (SCE) distribution system is becoming gradually challenging due to the rapidly increasing penetration of distributed energy resources (DERs), throughout our 50,000 square mile service territory. The upward trend in renewable-based DER is expected to continue as California recently set a target of 100% clean electricity by 2045. High penetration of DER (mainly solar PV generation) is causing bi-directional power flow and load masking on segments of our distribution system. Smart grid sensor technology can be utilized to maintain situational awareness on these high-penetration feeders and determine the actual load current which is the difference between measured load and native load current. Remote fault indicators (RFIs) are automated sensors that monitor distribution power flows and signal to grid operators in real time when there are system disruptions that could result in sustained outages. At SCE, real-time and near real-time distribution system status and metering are essential components of our comprehensive plan to improve safety and reliability and support integration of clean energy technologies, including solar, battery storage, and electric vehicles.
Deployment of RFIs in SCE’s Distribution Feeders
RFIs are strategically deployed on SCE’s distribution system to enhance situational awareness beyond the substation and to the distribution system. Current RFI technology deployment at SCE is limited to overhead distribution systems, but surface-mount and underground RFI technology is presently being evaluated and piloted. These overhead RFIs allow us to remotely monitor the three-phase load current magnitude and direction, three-phase fault current magnitude and indication, and conductor temperature.
Safety is improved by the deployment of RFI technology by remotely indicating when fault current has been identified at a particular location on the distribution system. Once identified, operational personnel can leverage this information to more quickly locate and isolate permanent faults on the distribution system, as compared to traditional mechanical fault indicators. More rapidly locating and isolating permanent faults limits the potential exposure of public and electrical worker safety to hazardous conditions and improves reliability by restoring unaffected customers faster after a disturbance through distribution system transfers. In addition to real-time or near real-time information, the historical information created by these smart grid sensors are also utilized for planning purposes, i.e., RFIs provide load current monitoring at circuit feeders lacking telemetry and identify segments of circuits where equipment may be thermally overloaded. We have installed 9,000 RFIs to date and our goal is to continue installation across much of the 90,401 miles of SCE distribution wires, replacing more than 14,000 mechanical fault indicators.
Remaining Challenges and Opportunities for RFIs
While useful in providing safety, reliability, and planning benefits, more robust monitoring is necessary to enable additional smart grid capabilities such as advanced analytics, distribution system state estimation, short-term forecasting, and advanced fault location, isolation, and service restoration (FLISR). More robust monitoring may include features such as directional fault indication, fault impedance, high impedance fault detection, total harmonic distortion (THD), and directional power (real, reactive, and apparent) for future overhead, surface-mount, and underground RFI technology.
Current RFI technology deployment at SCE is limited by several factors such as installation cost, complexity, and maintenance. For example, SCE has three key specifications for overhead RFIs: no more than two field personnel shall be required for installation, no external power source shall be needed, and no maintenance shall be required for 15 years. Today’s RFI technology requires a minimum threshold of load current for power harvesting in order to remain operational. In addition to this minimum loading requirement, the weight of current RFI technology due to the power harvester prevents the device from being deployed on small conductors that cannot support the additional weight. Future overhead RFI technology may need to be less restrictive in order to meet future smart grid needs.
Limitations in monitoring and deployment are not the only challenges we are experiencing with current RFI technology. An unexpected challenge we are facing in the deployment of RFI technology is the complications that occur with manual integration processes which could result in human error. To mitigate this challenge, SCE is developing a digital solution that will eliminate most manual processes which are involved in the integration of RFI technology and will ensure that all remaining manual processes have been completed correctly before finishing the deployment. Future RFI technology deployment, like any future smart grid technology, should consider the impact of manual processes and human errors on a successful technology deployment and integration, and offer digital solutions when applicable. Lastly, future RFI technology may inform advanced asset management analytic applications with the status and metering history that is developed post-deployment.
Burl Smith has worked at Southern California Edison since 2011 and is currently a Grid Technology Integration Engineer in Southern California Edison’s Grid Modernization organization. A 2013 graduate from California State Polytechnic University in Pomona, Burl is a licensed Professional Electrical Engineer and lives in Rialto, California.
Dr. Manuel Avendaño is the Senior Engineering Manager of Emerging Technologies Evaluation at Southern California Edison, the primary electricity supply company for much of Southern California. He is responsible for leading SCE’s effort to understand and test emerging smart grid technologies and determine their feasibility for demonstration projects and their potential impact to SCE’s Grid Modernization plan. Dr Avendaño earned a bachelor’s degree and a master’s degree in Electrical Engineering in Mexico and the PhD in Electrical Engineering in United Kingdom. Dr Avendaño has been a member of IEEE since 2006 and currently serves as Vice Chair of the IEEE Distribution Subcommittee and Editor for the IEEE Transactions on Power Delivery.
Audel de la Torre is a Senior Manager within Southern California Edison’s (SCE) Grid Modernization Organization responsible for the Technology Transfer Department. In that role his is responsible for the Grid Modernization efforts focused on new equipment automation, software tool development and the integration of new technology on the distribution grid. Audel began his career at SCE in 2004, and has held a number of roles including Distribution Engineer, Project Manager, and Engineer Manager. Audel earned a Bachelor of Science in Electrical Engineering at California State University Northridge (CSUN), a Master of Science in Engineering Management at CSUN, and received Project Management Certification from California Institute of Technology. Audel enjoys snowboarding, mountain biking, off-roading and taking his two young children to cheer on the Dodgers whenever possible.