Power electronic sources such as Type 3 wind turbine generators and static synchronous compensators (STATCOM) interface to the grid through, partial- or full-scale, power converters that have inherently fast switching capability to control their output current during short circuits. The short circuit current is a function of the specific converter control algorithm and differs significantly from the conventional rotating machine sources without converter interfaces. Therefore, if a transmission line protection scheme is designed for conventional sources, (not taking into account these differences in short circuit current characteristics), reliability can be at risk. Using real life short circuit currents on lines supplied by sources having a power converter interface, this paper illustrates the reliability risk to conventional line protection schemes, in particular to those which use negative sequence quantities for detection of unbalanced faults. The paper discusses the protection schemes, adopted by BC Hydro – a large Canadian Electric Utility, for transmission lines interconnecting Type 3 wind turbine and STATCOM sources. Their application for ground faults is independent of the converter control algorithm as long as the source is interconnected to the grid via a transformer which is a source of zero sequence current.

A BC Hydro regional system experienced a blackout after multiple 500 kV lines, sharing the same transmission corridor, were subjected to lightning strikes in the time span of about three minutes. These lines connect two large generating stations, regional loads and five non-utility generators to the rest of the BC Hydro system. The protection scheme on the first line tripped three-phase and initiated autoreclose as designed. However immediately after three-phase opening, high magnitudes of low-frequency (about 9 Hz) currents appeared in the line shunt reactor, causing a protection trip and aborting the autoreclose. Subsequent lightning strikes coupled with a pre-existing line outage disconnected both generating stations from each other as well as from the integrated system. The larger of two generating stations and almost all regional load formed an islanded subsystem, which eventually collapsed and blacked out. During the restoration of the subsystem, the system operator inadvertently picked up the entire regional system without load, causing steady-state resonant overvoltages higher than 145% and damaging a transmission customer. This paper shares lessons learned from forensic analysis of disturbances leading to regional blackout and describes the risk of unsafe overvoltages from near power frequency resonant condition during restoration process.

The BC Hydro transmission network includes 33 wholly owned 500 kV circuits and three 500 kV interconnections with other utilities. Eleven of these lines include series compensation, and many were upgraded to provide single-pole tripping (SPT) capability to improve power transfer capability and stability margins. To reduce construction costs, the majority of these lines are not shielded, which increases the probability of low-grade, single-line-to-ground faults due to high tower grounding resistance. Over the years, BC Hydro has developed strict performance specifications for both sensitivity and speed of protection systems based upon fault location and fault type. We also have a well-developed process for model power system testing of protection systems to verify conformance to these performance specifications. In this paper, we discuss the lessons learned in applying protection systems and optimizing protection sensitivity and speed for these challenging applications. We also discuss a number of problems and challenges discovered in real-world experiences and during simulation, many of which are associated with discerning the difference between normal system unbalances and/or unbalances caused by operation of series capacitor protection and resistive ground faults up to 300 Omega. The paper includes a discussion of the impact of reclosing control and automatic reinsertion control of series capacitors on protection systems. The paper also includes a number of digital fault recorder (DFR) records for actual power system faults on series-compensated lines.

In the ever-evolving tapestry of modern electricity grids, microgrids emerge as dynamic and resilient contributors, reshaping the narrative of energy distribution. The inception of distributed energy resource grid architecture and microgrids can be traced to the landmark Public Utility Regulatory Policies Act (PURPA) of 1978. Born out of the energy crisis in the 1970s, this groundbreaking legislation aimed to steer dependence away from oil toward renewables, fostering energy conservation and sustainable practices. Before this pivotal act, electricity utilities maintained a vertical integration monopoly over generation, transmission, and distribution ( Figure 1 ). The act revolutionized this entrenched model, mandating nondiscriminatory grid access for small power producers and laying the foundation for both a decentralized energy landscape and the rise of microgrids ( Figure 2 ).

On March 31, 2019, a 500 kV air-core, shunt reactor at a large generating station in BC Hydro was damaged shortly after four unit transformers were simultaneously energized from a 500 kV series and shunt compensated line source. Forensic investigations revealed that the controlled switching system, controlling the instant at which each breaker phase closes during energization to minimize inrush current, had failed. Uncontrolled closing led to under-damped, high-magnitude and sub-synchronous currents. Protection tripped and isolated the four transformers, followed shortly by shunt reactor protection tripping. Before the reactor could be isolated by circuit breakers, a damaging internal fault developed. This paper presents forensic investigation describing sequence of events leading up to reactor damage and shares the lessons learned with the peer utilities having similar installations.