Uncovering the Potential of Centralized Protection and Control

Authors: Jani Valtari, Sushil Joshi, ABB, Finland

The latest report of the Intergovernmental Panel on Climate Change (IPCC) emphasizes that to fight climate change our energy system needs to be completely reshaped at an unprecedented speed. New renewable and intermittent energy resources will be connected to the energy system, consumption will be managed with demand responses, and new storage devices will be deployed and used. All this needs to happen without risking the security of the power supply. It means that the protection and control functionality of our power networks must be enabled to manage continuous changes during the lifetime of devices. This is a tremendous challenge to the protection and control system, which needs to become more flexible and be able to reconfigure faster.
The requirement for increased flexibility creates a need to also evaluate substation protection and control architectures with different design principles. In computer science, separation of concern (SoC) is a design principle which simplifies development and maintenance by splitting the overall functionality into individual sections, which can be reused, as well as developed and updated individually. One of the key benefits is the ability to improve or modify without having to know the details of other sections, and without having to make corresponding changes to those sections. Conventionally the sections in substation automation architectures have been physically separated to different protection and control relays. However, the availability of Centralized Protection and Control (CPC) units makes software managed sections available too, with the aim of increased flexibility and more reliable and quicker deployment of protection and control systems. Figure 1 outlines the separation of concern design principle.

History of Centralized Protection and Control
Protection in power systems has been subject to several technological advancements. From electromechanical mechanisms to the microprocessor intelligent electronic device (IED), relaying has been an essential aspect to the continuing development of a more flexible, interconnected and smart power system.  As mentioned in IEEE PES PSRC WG K15 working group report, the CPC system architecture for the secondary system is not a new concept and dates back almost to the beginning of the widespread adoption of computers for business with the first proposal published in 1969, and the first installation as a field proof concept in 1971.
In the beginning of 1970s, the application of centralized substation protection based on a centralized computer system was proposed. This constitutes an important milestone in the history of power system protection. However, the idea has not been widely applied beside few exceptions in low voltage (LV) systems with an integrated approach, since there were no available computer hardware/software or communication technologies to support such an idea. In recent years, the dramatic growth in the signal processing capability of relay platforms, and the availability of suitable communication standards for electric substations, have provided a new opportunity to revisit the concept of the centralized protection and control system. Figure 2 shows the different eras of protection relays. 

Enablers for Centralized Protection & Control
Electrical substations play a major role in building a reliable power network. Their basic functions have remained unchanged for years. There is a need to monitor, control and protect different elements of a distribution network. The technical solutions on the other side are constantly changing e.g., the technology for data processing and communication. The key technical enablers supporting the emergence of centralized protection and control are described below.
IEC 61850 Station and Process Bus: IEC 61850 standard have made fast and standardized Ethernet-based communication more available. The station bus as defined in IEC 61850-8-1 allows for the elimination of copper wires between numerical protection relay units on the horizontal level i.e. relay-to-relay communications. The process bus as defined in IEC 61850-9-2 allows sharing of digitized information from instrument transformers or sensors in a standardized way to other relays and/or CPC units. This has enabled shifting of protection and control functions between different relays and/or CPC units at the substation level.

Merging Unit: The interface of the instrument transformers (both conventional and non-conventional) with a relay and CPC unit is through a device called Merging Unit (MU). Intelligent Merging Unit (IMU) has also been proposed as a general term for relay with MU capabilities.  MU is defined in IEC 61850-9-1 as interface unit that accepts current transformer (CT)/voltage transformer (VT) and binary inputs (BI) and produces multiple time synchronized digital outputs to provide data communication via the logical interfaces. IEC 61850-9-2LE or IEC 61869-9 defines a sampling frequency of 4 kHz (in 50 Hz networks) and 4.8 kHz (in 60 Hz networks) for raw measurement values to be sent to subscribers. Apart from acting as interface unit between primary equipment and CPC or relay, MU can also host IOs (input/output) to handle feeder based digital signals. It can communicate the digital status of primary equipment, like the circuit breaker, isolator, earthing switches, to network devices as well as receive trip and open or close signals from an external unit.

Substation Time Synchronization: With Ethernet-based technology it is possible to achieve software-based time synchronization with an accuracy of 1 ms quite easily, and without any help from HW. This is also what the IEC 61850 standard refers to as the basic time synchronization accuracy class (T1). An older and more common protocol is the SNTP (Simple Network Time Protocol), which is suitable for local substation synchronization in relatively small systems. However, if the SNTP server is behind multiple Ethernet nodes, the latency increases, which reduces the accuracy of the time synchronization. Therefore, SNTP is not an ideal solution for system-wide implementation. Normally a GPS or equivalent time synchronization resource is required in every substation. IEEE 1588v2 and IEC 61850-9-3 deal with these issues and makes it possible to achieve a time synchronization accuracy of 1 µs. This is required if an IEC 61850-9-2 process bus is used.

Communication Redundancy: High availability and high reliability of a communication network are two very important parameters for architectures utilizing a CPC system. IEC 61850 standard recognizes this need, and specifically defines in IEC 61850-5 the tolerated delay for application recovery and the required communication recovery times for different applications and services. The tolerated application recovery time ranges from 800 ms for SCADA, to 40 µsec for sampled values. The required communication recovery time ranges from 400 ms for SCADA, to 0 for sampled values. To address such time critical need for zero recovery time networks, IEC 61850 standard mandates the use of IEC62439-3 standard wherein clause 4 of the standard defines Parallel Redundancy Protocol (PRP) and Clause 5 defines High-Availability Seamless Redundancy (HSR). Both methods of network recovery provide “zero recovery time” with no packet loss in case of single network failure.

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