WiseOwl^™
                                        The Secure Automation Developer's Resource

by John T. Tengdin -- Editor-in-Chief
November 1999

In this month’s Publisher’s Corner, our Publisher has laid out - in detail - the role of a system integrator in the procurement and acceptance testing of a substation automation system (SAS). Starting with a utility’s vision of what they expect to achieve with the SAS, he then describes the many and varied responsibilities of the system integrator.

Quoting from his article, the vision statement might state:

“Substation automation shall be implemented as a distributed open system to ensure a graceful transition from existing substation configurations, and to provide a cost effective evolution for implementing future substation automation technologies. The system will implement peer-to-peer communications between IEDs so as to guarantee that no single point of failure will jeopardize the integrity of the protection scheme. An open communication system between IEDs will require vendors to implement either approved standards, de facto-standards, or to publish their application program interface, and thereby ensure interoperability and interchangeability of IEDs purchased from different manufacturers, and to provide for third party maintenance of the communication system. Furthermore, the future substation automation system will provide for a common graphical user interface for all users, and a common substation configuration schema for configuring, commissioning and maintaining the substation IEDs.”

 Based on the vision statement, a number of specifications should be prepared – and before any vendor is selected. These include the target architecture (with migration strategies for the future), a listing of the applicable compliance documents, the system test plans and procedures, a definition of the common graphical user interface to be used, the procedures for configuration management, and the four areas of operational control – access control, settings management, report management, and time synchronization.

 Every utility has legacy devices that may exist as a part of a new substation integrated protection, control, and monitoring system. Unless their usage and migration strategies are defined in advance, the vendors cannot incorporate them in their proposals. Similarly, for a given substation (or substation class), the utility must define its requirements for redundancy (if any) in the substation communications system.

These are but a few of the questions to be answered when the target architecture is defined, and must be done before a vendor is selected.

 There are many standards or other compliance documents that could be referenced. Unless the list is completely defined in advance, the risk is great for future misunderstandings.

 If time critical functions are a part of the SAS, it is essential that all parties know in advance how system level tests are to be performed. Special test equipment may be required, or “hooks” be provided in the vendor supplied application software so that the testing can be accomplished. In addition, stress test scenarios need to be developed to confirm how the SAS will perform when a major substation event occurs and the LAN may be flooded with update information. These may be a part of either factory or site acceptance tests.

 Each utility has its own past practices and screen displays for the Graphical User Interface, so these need to be well defined to the vendors.

 A substation LAN environment imposes new requirements in configuration management.  Now both the substation configuration and the LAN must be maintained in an accessible data base.

 The area of operational control is clearly one that must be well specified in advance of procurement. In fact, it may become a screening criteria if all vendors are not able to meet the requirements. With the advent of remote access to a substation LAN, the specifics of access control at the IED level has become extremely important. Settings management is an issue whether one or many vendors are supplying the IEDs. Many parts of a utility will be interested in the reports that may be generated by a substation automation system, so it is important that its report management system have the required flexibility. Finally, the issue of IED time (or more correctly, clock) synchronism must be defined in advance. It seems obvious that, if the utility’s requirement is time stamping to one millisecond across the substation, the IED clocks must be settable an order of magnitude more precise (to 0.1 ms). Yet that fact does not seem to be well understood.

 The new role of the system integrator is to address all these issues, and do so before procurement has begun. Even if a utility intends to deal with primarily one vendor for the substation automation system, a clear definition of all the requirements and expectations, as outlined above, will smooth the road for all concerned.

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