Digital Secondary Systems

Digital secondary systems—also called digital substations—use IEDs and digital communications to protect, monitor, and control a substation's primary equipment and power lines. These systems offer many benefits in both the control house and the substation yard, including:

• Secure data concentration, event collection, system visualization, and engineering access to improve situational awareness and asset management.
• Reduced engineering cost per project through reproducible system designs that can be applied across new and existing substations.
• Improved system availability and extended maintenance intervals through self-diagnostic tests and alerts when a failure or an abnormality is detected in the secondary system.
• Replacing long runs of bulky copper wiring in the substation yard with a small number of fiber-optic cables, which carry no current and are immune to electromagnetic interference.
• Lower construction and maintenance costs due to reduced copper wiring and simplified field wiring, as well as fewer safety incidents and wiring-related malfunctions.

Digital secondary systems can be composed of both process bus and station bus communications. Each is a separate but overlapping and interconnected communications system designed to perform different functions in the substation.

Station bus communications are used for substation automation schemes, SCADA communications, secure engineering access, local HMIs, and more. Station bus systems facilitate the monitoring and control of primary and secondary systems.

Process bus communications enable digital devices in the yard to transfer status signals and primary system measurements—like voltage, current, and breaker status—to protective devices in the control house. The devices in the yard, such as merging units, interface directly with primary equipment to measure and digitize process-level data at high speeds as well as receive and act on control signals transferred from relays.

Process bus systems can also be applied as part of a centralized protection and control (CPC) solution.

Digital communications over a network or direct connections allow devices to share process-level information from primary equipment and coordinate protective actions. Networked communications must have appropriately high bandwidth, low latency, and maximum availability.

Merging units (or process interface units) convert analog signals from primary equipment to digital data, then transmit those data to protective devices over fiber-optic cable. Merging units may be standalone devices that perform A/D conversion then stream the data, or they may be intelligent merging units that perform local logic and protection. Merging units may also actuate field devices because of local decisions and perform D/A conversion of signals received in digital messages.

Protective devices analyze signals sent by the merging units and send command signals back to the merging units. Time synchronization is necessary when protection data are gathered from multiple points.

Ancillary data, such as temperature, status, and alarms, are collected by other digital devices and made available to protective devices through direct connections or a substation network.

SEL offers process bus solutions with two different methods of exchanging control signals and sampled analog values from primary equipment: 

• Sampled Values (SV)-based systems that use IEC 61850 SV, GOOSE, and Precision Time Protocol (PTP) protocols. 
• Time-Domain Link (TiDL)-based systems that use the SEL T-Protocol. 

These systems can be applied within the same substations and use other digital devices and protocols for ancillary data and station bus communications. Alternatively, SEL relays can also be installed directly in the yard to achieve many of the same benefits as a process bus solution, such as reduced copper cabling.

Process bus implementations should minimize complexity wherever possible. To meet this goal, a design must consider interoperability, networking, time synchronization, cybersecurity, and any necessary ancillary data collection.

A substation may include process bus systems using a variety of protocols. The IEC 61850 standard, which defines protocols like IEC 61850-9-2 SV and GOOSE messages, helps ensure that devices from various suppliers use a common set of protocols and function together in a process bus system. SV-enabled relays also communicate with TiDL-enabled relays and other devices over station bus communications using common protocols. This flexibility allows substations to integrate process bus systems with a variety of station bus protocols, such as DNP3, FTP, Telnet, HTTP, IEC 61850 MMS, and GOOSE.

Process bus communications must satisfy rigorous privacy, security, and performance requirements. A strong cybersecurity posture is required to prevent unauthorized access to systems protecting critical infrastructure.

Because relays and merging units are in constant communication, process bus networks must have a high bandwidth and fast failover times to ensure that control commands are delivered at protection speeds. Direct connections, such as those used in TiDL systems, meet performance and security requirements for protection communications without requiring network engineering.

Networked, Ethernet-based systems meet performance requirements using methods such as VLANs to segment traffic, the SEL operational technology (OT) software-defined networking (SDN) solution to achieve fast failover times, and duplicate networks with the PRP protocol to ensure availability. While traditional PRP duplication technology may mask failures and introduce “dangerous undetectable faults,” as defined by IEC 61508, SEL PRP enhancements detect and self-alarm message failure, prompting corrective action and improving reliability.

Learn More About OT SDN

From our knowledge base:

• Using Software-Defined Networking to Build Modern, Secure, IEC 61850-Based Substation Automation Systems
• Improve Protection Communications Network Reliability Through Software-Defined Process Bus

Networked process bus systems require time-aligned protection data to generate trip and control signals that are both accurate to the nature of a fault and timely to the occurrence of a fault. Accurate time synchronization may be achieved via external satellite clocks and PTP or IRIG-B protocols.

Using deterministic, nonroutable protocols—such as the SEL T-Protocol used in TiDL systems—synchronizes the sampled analog data coming from merging units, removing the need for an external time source to distribute time to the merging unit.

From our knowledge base:

• Growing Your Time Synchronization Solutions

Cybersecurity is a vital consideration in process bus systems. However, because OT and IT systems have different purposes, the cybersecurity solutions for one may not be the most appropriate for the other.

Preserve availability with privacy methods

Networks use privacy methods to preserve the availability of data and restrict access. Direct connections provide privacy by physically isolating communications paths, while SDN solutions provide privacy by denying all network communications that do not match a predefined set of rules. In traditional Ethernet architectures, security gateway devices deny access to outside traffic using features like a VLAN, a VPN, firewalls, virus and malware detection, password management, and user-based access permissions.

Private links between devices enable immediate detection of intentional or unintentional disturbances to data flows. Devices that detect these disturbances may issue alarms or perform automatic corrective action to maintain privacy.

SEL SDN technology is purpose-engineered to meet the cybersecurity requirements of OT applications, such as process bus networks.

Secrecy methods reduce availability

Network connections that are not engineered to maintain privacy often require coordinated secrecy methods like TLS within each device to obscure data, generally by encryption, making them unreadable to other devices and unauthorized users. This method is undesirable in secondary systems because the additional processing load and time required to encrypt and decrypt data can slow protective action. Encryption also makes data unavailable to engineers, technicians, other devices, and systems that lack the appropriate decryption capabilities. 

In addition, the increased frequency of firmware updates required to stay current with secrecy technologies poses a serious obstacle for maintaining system availability, requires that devices be updated simultaneously, and introduces new supply chain and personnel vulnerabilities. Unintended consequences that affect protection reliability include device down time during firmware upgrades to address security vulnerabilities and a lack of communications among devices until they are all upgraded to the same firmware version. 

From our knowledge base:

• Do IT Cryptographic Security Controls Work for Energy Systems?
• Defense-in-Depth Security for Industrial Control Systems

Protection, control, and monitoring devices collect and digitize data such as temperature, status, alarms, and more to supplement the digitized current and voltage data provided by merging units. 

Most SEL protection, control, and monitoring devices support traditional CT/PT and digital message inputs, and many SEL devices also support low-energy analog (LEA) and Rogowski coil inputs. These devices can publish this information via digital messages to other IEDs as needed.

Digital secondary system implementations can be as simple or sophisticated as an application demands, but many important factors must be considered in designing the system.

Partner with SEL Engineering Services to create a turnkey solution that addresses the needs of your system and puts you in control. SEL application engineers provide thorough training in all products applied in a solution, ensuring that you are able to achieve your operational goals once a system is in place.

We've collaborated closely with our customers since the company was founded over 40 years ago—a major reason why we’re North America’s most trusted provider of protective relays and ranked #1 by international utilities in price, service, and support.