Designing substations, transformers for bi-directional power flow, Part II

In a large commercial solar or wind farm, both the utility and the facility owner want to know how much power is flowing onto the grid.


This blog begins where last week’s blog left off.

("Designing Substations and Transformers for Bi-directional Power Flow.")

On a Nov. 8 Consulting-Specifying Engineer webcast I presented concepts regarding the interconnection of transformers in substations that need to accommodate the bi-directional flow of power, typically where large industrial concerns have co-generation or wind or solar facilities. (View the webcast here)

Last week I discussed protection and controls (and the pertinent standards in the IEEE C57 series), interconnections (governed by the IEEE 1547 series) and reference models for interoperability (provided by IEEE 2030). This week let’s tackle communications, time synchronization and cyber security.

Two parties – the utility and the substation owner – have communication needs. For example, in a large commercial solar or wind farm, both the utility and the facility owner want to know how much power is flowing onto the grid.

The consulting specifying engineer must decide on the protocol for communications. In most cases, on the utility connection, the utility will specify the protocol, whether it’s DNP3, IEC 61850, IEC 60870-5-101 or Modbus+. What media will be involved? Copper? Wireless? A local area network? This is typically a commercial decision based on the most cost-effective way for the substation to interface with the utility’s communications/SCADA system.

Another aspect is the communication equipment itself. IEEE 1613 defines the survivability requirements of communications equipment connected to transformers and in substations. Isolation is important, particularly where copper is entering or exiting your installation – the communication provider will want to be sure that proper isolation is there for your communication circuits.

Time synchronization is becoming easier and more cost effective to install. For higher power injection applications, utilities may require one-millisecond time synchronization between their clock and the transformer/substation’s clock. That too is covered by standards. (See my previous blogs for details, including “Addressing Time Synchronization Issues, Related Work,” “Assessing Vendor Claims on Time Resolution in IEDs” and “Designing a Time Synchronization Source.”)

Applicable standards include the IEEE C37 series (for synchrophasors), IEEE 1815 (DNP3), IEEE P1815.1 (exchanging information between networks), IEEE 1588 (time synchronization), IEEE C37.238 (precision time protocol in power system applications), IEEE 802 series (networking) and IEEE C37.1 (standard for SCADA and automation systems).

Cyber security concerns began at a high level with the Federal Energy Reliability Commission (FERC), but the North American Electric Reliability Corporation (NERC) picked up the mantle with its Critical Infrastructure Protection (CIP) requirements. It’s important for the consulting specifying engineer to understand that while some concern over external threats are reflected in these documents, they’re more focused on internal issues and not necessarily confined to intentional acts. Much of cyber security has to do with preventing the unintentional acts that bite us – whether it’s loading incorrect software, whether it’s changing configurations without going through the proper configuration management. In the past these issues have proven more pressing than external threats and will continue to be a focus of NERC CIP requirements.

A host of standards are relevant here: IEEE 1686 (Standard for substation IEDs’ cyber security capabilities); IEEE P37.240 (Standard for cyber security requirements for substation automation, protection and control systems); IEEE 1711 (Cryptographic protocol for cyber security of substation serial links); and IEEE 1402 (Standard for physical security of electric power substations).

I want to emphasize IEEE 1402, which addresses physical security, because cyber security without physically locking down the substation is ineffective. IEEE 1711 allows cryptographic protocols for the addition of cyber security on serial links. It’s not always important that the equipment – for instance, the transformer monitoring package – have security built in. Add-on products that follow an IEEE standard for cyber security and/or encryption are available.

(See my blog, “Substation Physical Security Back on Front Burner.”)

Addressing a utility’s need for situational awareness depends on how much power is being sent through the transformer and whether that’s at distribution or transmission levels. For large transmission-level injections, information could be needed for synchrophasors and remedial action schemes. Smaller distribution transformers may have a different requirement.

Addressing utility situational awareness involves knowing the isolating apparatus position for breakers and switches. The utility wants to know your substation’s volt/VAR capacities, even capacities for power generation itself – forecasts for wind power, for instance. Synchrophasors may be important at large power injection sites. Lockout and tag-out information is critical to the utility. When power is going to flow from the transformer back into the grid, you’ve got an operational issue. Utility crews will want to know: is the isolating switch locked out? Are they in a tag-out situation? How can that tag-out be released? You’ll need to get down into the operational aspects of the substation, as well as the purely technical ones. The utility will need to know how you’re designing an island with multiple distributed energy resources (DERs) to reconnect to the distribution grid, once power is restored to the substation.

The consulting specifying engineer will also deal with customer/owner situational awareness. Customer/owner information needed on that transformer may have to do with utility set points and substation status, price points being communicated, volt/VAR support and related issues. The customer/owner may need utility work orders. For instance, if line crews are out there, that substation may need to be put into a non-reclose position or some other change in the protection settings.

Sam Sciacca is an active senior member in the IEEE and the International Electrotechnical Commission (IEC) in the area of utility automation. He has more than 25 years of experience in the domestic and international electrical utility industries. Sciacca serves as the chair of two IEEE working groups that focus on cyber security for electric utilities: the Substations Working Group C1 (P1686) and the Power System Relay Committee Working Group H13 (PC37.240). Sciacca also is president of SCS Consulting.

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