A centralized protection and control system using a well proven transmission class protection relay

Authors: Mital Kanabar and Jeff M, GE Renewable Energy - Grid Solutions, Canada

The historical evolution of protective relaying technology has significant influence from Electronics and Communication developments in the past. And, the next generation of digital protective relaying is also receiving directions from evolving technology trends of Industrial Internet of Things (IIoT), virtualization, digital interfaces of combined optical CT/VT and circuit breakers, as well as digitized primary equipment. Figure 2 illustrates the differences in various technology evolution cycles related to the substation protection, automation and control system.

The technologies of primary equipment and legacy system install-base stay in service around several decades before they are migrated to next generation technology. Ruggedized and digitized remote input/output hardware electronics including sensor circuits can be simplified and stretched to few decades to align with maintenance cycles of primary equipment. The cycles of software applications and communications technologies are typically evolving at a faster rate; whereas, cyber security applications and specific software/firmware may need an update more frequently depending upon specific requests or yearly feature update cycles.

Architecting Digital Substation PAC System

Figure 3 shows the hierarchical architecture of a digital substation PAC system, and divided into 3 existing levels: process, bay and station. Considering the technology cycles discussed earlier, the process level needs to ‘simplify’ with digitization using open standard data sharing communication interfaces (i.e. IEC 61850-9-2LE and/or IEC61869-9/13). Bay level should be able to ‘converge’ PAC applications and allows virtual isolation of PAC IEDs and equipment maintenance. The modularized hardware of PAC IEDs can provide completely independent communication ports to facilitate cyber security perimeter segregation for process bus and station bus. The station bus can ‘virtualize’ station applications for grid of the future readiness. As the grid evolves (e.g. Renewables penetration), the scalable substation control & automation platform may also allow future applications and solutions without replacing hardware and/or platform software.

The Process Interface Units (PIUs) installed close to primary equipment merely digitize the signal interface and communicates to process bus over interoperable IEC 61850-9-2 or IEC 61869-9/13 standards. The software and set tings at process level needs to be minimum or if possible, settingless with segregated layer-2 (Ethernet) level traffic. Easy to install and maintain hardware delivers higher reliability, and with interoperable protocols, this data would be available to any applications at bay or station level, and it will also allow virtual isolation using IEC 61850 Test/Sim mode explained later in this article.

The allocation of protection or related intelligent functions at the process level should be evaluated carefully by utility PAC leadership teams for air insulated substations (AIS) for T&D. The protection functions distributed across the switchyard would not only require extensive maintenance firmware/software upgrades, but also maintenance testing. The protection settings and related scheme logic need to be tested in the switchyard with the secondary injection test sets. Protection devices with OSI layer-3 (IP - Internet Protocol layer) interface availability may need considerations from a cyber security perspective as well. Therefore, instead of protection IED, the architecture should consider simplified PIU (only digitized CT/VT and circuit breaker) interfaces over standard communication protocol.

Evolution of digital interfaces readily available from the optical CT/VT, circuit breakers, and digitized primary equipment would eventually replace these simplified PIUs. Therefore, the future proof architecture should not include traditional protection functions and their scheme allocated at the process level. The performance of protection messages from PIUs, e.g. sampled value (SV) and GOOSE should be as fast & secure as possible. The reliability and dependency requirements on communication network at process level can be addressed with redundant streams of SV/GOOSE with advanced monitoring at bay level PAC IEDs. Furthermore, the point-to-point architecture can also eliminate the need of Ethernet switches and IEEE 1588 PTP clocks for higher resiliency for PAC applications.

If simplified protection functions with separation from automation are required, the converged-bay level protection functions concentrated into few hardware IEDs at bay level still have more advantages over the protection distributed across the switchyard.
Figure 4 illustrates the futureproof digital substation architecture, which not only reduces CAPEX with fast and easy installation, but also optimizes OPEX with virtual ized IED isolation for maintenance and testing.
Therefore, the drivers of the future substation are: simplify the process level; converge at bay level, and virtualize at station level.

BeijingSifang June 2016