Substation automation retrofit: modernizing a SAS

When an automation system reaches the end of its life

A substation automation system (SAS) ages faster than the primary equipment. A transformer or a breaker can last several decades; a numerical relay, an RTU or an HMI runs out of spare parts and support much sooner, because it depends on electronics and software the manufacturer stops producing.

Signs that it is time to plan the retrofit:

• No spare parts or support from the manufacturer for relays, RTUs or cards.
• Configuration software that only runs on old operating systems or on a single computer.
• Repeated failures of power supplies, communication cards or displays.
• Serial protocols the control center no longer wants to receive or that do not allow adding signals.
• New requirements from the utility: more signals, time synchronization, cybersecurity, fault records.
• Extensions that force current equipment to be integrated with the existing one.
• Cybersecurity that cannot be maintained on devices without updates.

The options

Bay by bay. The protection and control of one bay are replaced in each maintenance window. It is the most common option. It requires the new and old systems to coexist for months or years, with station interlocking and control center signals working in both.

In parallel. The complete new system is installed next to the existing one and the bays are moved over one at a time. It shortens each outage, but requires space, more temporary cables and strict discipline to avoid leaving duplicate signals.

Bridging gateway. A new gateway integrates the old devices (over 103, 101, Modbus or contacts) and the new ones (over IEC 61850) and delivers everything to the control center. It allows bay-by-bay modernization without the control center noticing the transition. The protocol scenarios are in migrating legacy protocols to IEC 61850.

Complete substation. Only when there is a long outage or a temporary substation. It is the cleanest option technically and the least frequent.

What is surveyed before designing

A retrofit starts by knowing what is really installed. Differences between the drawings and reality are the norm.

• Drawings and wiring of each panel, verified on site.
• Settings and logic of the existing relays, extracted from the device and not only from the project file.
• Interlocks, hardwired or programmed, with their table of conditions. Our free interlocking table tool helps document them by configuration.
• Signal list to the control center, with addresses and meaning. See substation signal list.
• Station service: battery and charger capacity for the new equipment.
• Network and time synchronization available.

Risks

• Losing undocumented functions. A hardwired logic nobody remembers (a blocking, a transfer, a transfer trip) disappears when the panel is replaced.
• Incomplete station interlocking during coexistence: the new bay does not know the position of a disconnector in the old bay.
• Signals that change address at the control center without the operator knowing.
• Settings carried over without review. A new relay is not set by copying the values of the old one: the algorithms, curves and available functions change.
• Open CT circuits during relocations, a hazard for people and equipment.
• Outage windows that run long because the bay test was not prepared in advance.

Coexistence of the new and old systems

For months, sometimes years, the substation operates with bays of two generations. That period concentrates the risks and is best planned as a project stage, not as an inconvenience:

• Station interlocking. The new bays need to know the position of the disconnectors in the old bays, and vice versa. It is solved with hardwired signals between panels, with the gateway or with a temporary controller, and each solution must be tested.
• Bus protection and breaker failure. If the bus differential is replaced last, it must receive the currents and trips of both old and new bays throughout the transition.
• Control center. The operator must see the complete substation without gaps. A new gateway that integrates both systems from the start simplifies this stage.
• Documentation by stage. Each outage window changes the drawings and the signal list; they are updated at the time, not at the end.

Testing

Each modernized bay is treated as a new commissioning. First, a FAT of the panel and of the integration with the gateway, if possible with a simulator of the bays still in service. Then, on site, commissioning of the bay during the outage window:

• wiring tests from the yard and verification of CT and VT polarities;
• protection tests by secondary injection;
• functional tests of trip, close, reclose and interlocking;
• point-to-point signals up to the HMI and the control center;
• energization under load and verification of differential protection stability.

The order of the stages and the applicable standards are in standards for commissioning, FAT and SAT.

What you gain

A well-executed retrofit does more than replace equipment: it delivers a documented system, with a current signal list and SCD, fault records accessible remotely and secure remote access for maintenance. That last point, secure remote access, is the one that most reduces response times afterwards. For the new system to arrive that way, the specification must require it; see specifying a SAS.

We help you with your retrofit

At Tiza Group we configure and test relays, bay controllers and gateways of the main brands in retrofits of medium, high and extra-high voltage substations and of industry. With remote relay configuration we prepare the settings and logic of each bay before the outage window, to shorten it. For on-site integration and testing, see control, protection and communications configuration, in Colombia, or elsewhere on request.

Related guides

• Migrating from 103, 101 or Modbus to IEC 61850
• Substation RTU and gateway
• Bay control unit (BCU)
• Substation signal list
• IED and SCD configuration management
• Interlocking tests
• Substation commissioning: stages and tests
• IEC 61850, IEC 104, DNP3 and Modbus: which one to use

References

• CIGRE, Technical Brochure 246, The automation of new and existing substations: why and how, WG B5.07, 2004.
• CIGRE, Technical Brochure 637, Acceptance, commissioning and field testing techniques for protection and automation systems, 2015.
• IEC 61850-4, System and project management.
• IEEE C37.233, Guide for Power System Protection Testing.

Frequently asked questions