Craig M. Preuss

INTRODUCTION
Utility substation integration programs have continued to grow since the 1990s. Although most utilities claim to have substation integration at some level, some have simply continued to install electromechanical relays and RTUs. Others have created one or more pilot projects with varying success to prove out new substation technology that is rapidly changing. Still other utilities have developed multi-year integration programs into second, third, and even fourth generations, rolling out multiple substation integration schemes across a large
number of substations.

While much attention has been given to the potential costs, benefits, and architectures of substation integration technologies, little focus has been given to “how” a business case and new design is developed. With technology changing at an unprecedented rate just as many of the most experienced engineers have retired or are preparing to leave the workforce, even utilities with decades of experience in substation integration may encounter difficulties planning, developing and implementing substation projects that properly fit their current - and especially their future - technical, organizational and operational needs.

This two-part article will address the engineering standards, processes and best practices for substation integration and answer many of the most common questions as well as some more subtle aspects of intelligent substation planning, preparation and design. For example, what are the front-end engineering processes that result in the dramatic transformation of a blank sheet of paper and a good idea into the wiring, schematics, elevations, point lists, and test procedures that result in a successful project? What are the steps required? What are the issues and considerations in planning for the implementation? What are the potential risks and pitfalls? Can those risks and pitfalls be mitigated or avoided entirely?

This first part of the article outlines the standards and frames the engineering process. In part two, we will illustrate how Black & Veatch implemented this engineering process in a case study fashion, demonstrating the issues and implications of substation integration in an actual
utility project.

DRAWING A BLANK
Substation integration isn’t a defined product or service. So when you’re starting with a blank sheet of paper, how do you draw integration and automation? How is it possible to transform a traditional substation design with control switches, panel mimic buses, RTUs, interposing relays and transducers into an intelligent substation?

The upcoming revision to IEEE standard C37.1¹, otherwise known as “The SCADA Standard,” loosely defines an iterative process that is used to accomplish substation integration, or the connecting of IEDs together using one or more communication networks to distribute RTU functionality and enable automation. Notably, this process is not part of IEC 61850 “Communication Networks and Systems in Substations.” However, the draft of IEEE C37.1 presents these steps:
1. Define near-term and long-term system functionality (system requirements)
2. Select the protocol(s) (both inside and outside the substation)
3. Select the IEDs
4. Select the system architecture
5. Secure the system
6. Define performance requirements

Each step depends on the others, which makes the process iterative. System functionality impacts IED selection, which can impact the architecture and even make your system vulnerable to cyber attacks if such risks are not taken into account at the outset. System performance requirements can also impact system architecture, which in turn, can impact protocol selection. These are just a few examples of how the process becomes iterative.

These steps may occur in a different order than shown above. IED selection typically comes first, primarily because relays and meters already exist, allowing the electrical system to be protected and measured. Thus, we often find that the paper is perhaps not as blank as originally perceived. That is, some IEDs may have already been selected, and a certain degree of system functionality is most likely desired.

There may also be some pre-existing ideas and preferences for what protocols will be selected/supported and what general security requirements need to be applied.

In today’s utility market, many utilities are seeking to move the substation design from a mix of electromechanical and microprocessor relays with no uniform backbone communications architecture to an integrated substation that supports automation implementations easily and economically. From a design standpoint, it would be nice to start from scratch, but in reality, most utilities don’t have that luxury.

Many utilities are already extending their corporate WAN (Wide Area Network) to their substations, so they want Ethernet; but specifically how does one bring Ethernet into the substations? Other utilities may have equipment preferences for key elements (e.g., protective relays) because they already have a certain type of equipment in place; but what is the best way to select a protocol? Utilities know that a substation is a harsh environment requiring equipment compliant to IEEE Standard 1613² and IEC 61850³; but what else is required to protect these substantial investments of time, money and other resources in addition to the equipment itself? These are but a few of the many questions that any substation integration project manager must be prepared to answer.

SUBSTATION INTEGRATION
Getting started might sound easy, but from the start, utility personnel must be familiar with the concepts and issues in order to make the process smoother. How do you get experienced personnel who intimately know SCADA masters and IT networks to also understand substations with their protection and control schemes, RTUs, transformers, breakers, capacitor banks, and switches, let alone understand substation integration and automation? And what about the other way around? How do you get those intimately familiar with the substation site and environment to understand the greater SCADA and IT network issues? Black & Veatch recommends substation integration training in these situations to introduce utility personnel from across the enterprise to the equipment, concepts, issues, justification, costs, risks, benefits, and process of substation integration. Inviting everyone to the table is usually not possible, but representation from key business and operational departments is essential.

FUNCTIONAL REQUIREMENTS
A series of meetings and supporting discussions are usually necessary to determine the system functional requirements. These requirements may be driven by a variety of technical and organizational needs, but will almost certainly include those defined in IEEE Standard C37.1. These include I/O, protection, ancillary services, time synchronism and programmed logic functions. Typical examples of technical performance criteria from IEEE Standard C37.1 are requirements for:
• Update Periodicity
• Latency (Seconds)
• Time skew (Seconds)
• Accuracy
• Resolution (%)
• Availability (Hours/month)

SOLUTION COMPONENTS
The solution components are selected specifically for the best possible combination of cost, flexibility and applicability to the substation environment; a brief discussion of this selection process follows.

Input/Output (I/O) and Measurements
The I/O (input-output) scheme is broken down into measurements, status, and control. By defining an I/O scheme that shows where the data sources are for the substation devices, several issues within each category can be discovered and resolved.

With regard to measurements, on the transmission and distribution side the accuracy of metering from relays can be an important consideration. The number and type of meters and the metering data needed are also important, along with consideration of backup sources. In addition to these standard metering quantities, some examples of other analog quantities to be gathered from the substation might include transformer LTC (Load Tap Changer) controller, battery charger (battery DC voltage), control house temperature, transformer DGA (dissolved gas analysis) and transformer temperature monitor (winding temperature).

A large number of SCADA device status points are usually envisioned as well. These might include selected relay targets and IED, communications and security status points. Several IEDs (i.e., primary and backup relays) can provide the status of breakers. A relay can be out of service for a variety of reasons while the breaker is still in service or requires operation.

Combinational logic can be used to create a voting scheme that has a high reliability of reporting the actual state. However, this approach results in making the system more complex and can be avoided by using distributed I/O wired directly to the breaker status contacts along with the breaker alarms.

Protection and Control
Control of substation devices is typically assigned to the primary and backup relays. More complex designs will assign SCADA control to the primary relays and HMI (human-machine interface) control to the backup relays. In addition, there is usually a desire to have a manual backup and
“SCADA-disable” functionality in the control house. For substation control, dedicated distributed I/O can also be used when control would otherwise be lost whenever the relays are out of service. Distributed I/O devices are very common in the industrial world, but these industrial devices can have problems with temperature, power, and communication port ratings, depending on the suppliers and products selected. In recent years, several vendors have introduced distributed I/O devices designed to mitigate these problems.

Protective functions remain in the relays with traditional hardwiring of protective control outputs and inputs. The anticipated use or future migration to IEC 61850 will provide the capability for high-speed protection using the substation LAN, an important consideration in defining the system architecture.

Time Synchronization and Programmed Logic
Time synchronization is important because during catastrophic events it is best to have as much synchronized data as possible to help speed up and optimize data analysis and event correlation. IEDs should be time synchronized using the most accurate method supported by each IED.

Programmed logic is the basis for most substation automation. Each type of IED usually supports native programmed logic associated with the I/O for each device or device class. In order to support system-wide functionality, a high-speed peer-to-peer network is required. While IEC 61850 supports this requirement using high-speed messages with guaranteed performance, DNP3 can also be used over Ethernet for non-protective functions. This could be accomplished by IEDs broadcasting data to multiple masters or multiple masters polling the same slaves. Because this testing of programmed logic can be a significant issue during commissioning, ample time must be allocated in advance to ensure proper operation.

Ancillary Services and Security
Ancillary services are those services left over from the previous discussion; i.e., IED configuration, file transfer, log and data capture and diagnostic observation. Support for these services requires a high-speed network that supports more than two simultaneous connections. Performance can be improved by prioritizing these services; thus, limiting bandwidth usage by lower priority tasks (i.e., given that IEDs by themselves generally do not support prioritization).

Achieving data security in today’s environment must adequately address evolving NERC CIP requirements. Security strategies for both physical and data security will drive approaches for security in substation integration. Requirements here may include monitoring of existing physical security systems in place and the flexibility to integrate future systems, as well as strategies for network and data separation from the corporate network.

IEDs, ARCHITECTURE & PROTOCOL SELECTIONS
Often utilities will already have an idea of which vendor(s) will supply the IEDs even before system design begins. Yet even in those situations, reviewing IED selections can be a time-consuming process because there are so many types and suppliers of IEDs available for the broad range of applications in the substation. (The IED selection process for these areas will be addressed in more detail in the second part of this article.)

Architecture selection is a fundamental consideration, but this is another example where there are typically legacy issues that must be dealt with in many cases. Selection of the best-fit architecture can be significantly influenced by the networks already in place, along with the strengths and weaknesses they bring to the situation. Overall system reliability objectives will also drive considerations and strategies for redundancy.

In many if not most cases, there are a number of factors influencing protocol selection. Experience, knowledge, and comfort level with installed protocols is important, but the availability to interface both existing and planned IEDs is also critical. This is another example of the need for an iterative process in design and how decisions in each area can impact choices for other design elements.

SYSTEM PERFORMANCE
System availability is vital and must be carefully addressed by using substation-hardened equipment in all aspects of system design. All critical equipment should meet IEEE Standard 1613, which may also include the substation computer. The definition of critical IEDs is very important as it will increase system cost whenever substation-hardened IEDs are selected to replace non-compliant devices.

System flexibility considerations include ease of expansion, provision of spare capacity, ease of replacement and ease of maintenance. System maintenance considerations can include items such as changing operational parameters as well as the configuration. With a modular system being supported by multiple vendors, changes to some IEDs will be easier than others, depending upon the evaluation criteria. Generally speaking, however, selected IEDs must support user interfaces that in turn, provide an easy and intuitive way to make system changes and adjustments.

1 “Standard for SCADA and Automation Systems”
2 “IEEE Standard Environmental and Testing Requirements for Communications Networking Devices in Electric Power Substations”
3 “Communication Networks & Systems in Substations”

LOOKING AHEAD…
In Part 2 of this article, “Project Execution” (appearing in the March/April issue of EET&D) the author will present a case study explaining in more detail how the substation integration design process actually plays out, based on experience with an operating utility in the Northeastern U.S. – Ed.

ABOUT THE AUTHOR
Craig Preuss is the Engineering Manager for Utility Automation at Black & Veatch Corporation where he is involved in virtually all facets of substation integration and automation. Craig earned his bachelor’s degree in electrical engineering from Valparaiso University in Valparaiso, IN and a master’s degree in power systems from the Illinois Institute of Technology and is a registered professional engineer in the states of Illinois and Washington.

During his 18-year career in the utility engineering and automation field he has authored several papers, presentations, and articles on topics dealing with substation integration and automation. Craig is an active member of the IEEE where he serves as the new working group chair for IEEE Standard C37.1. He was also involved in the writing of IEEE Standard 1615 and IEEE Standard 1686 as well as participating in other IEEE working groups. He is also a member of the ISA (Instrumentation, Systems, and Automation Society).