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James Formea, IEEE member; John Gadbury, PE and IEEE member
Abstract— Supervisory control and data acquisition (SCADA) systems date back to the early 1960s and have been widely used by large utilities since the 1980s to remotely monitor systems in real time. Through the data provided by SCADA systems, investor-owned utilities have been able to improve grid reliability, proactively detect and resolve problems, meet power quality requirements, and support strategic decisions.
However, SCADA systems no longer need to be relegated to control room settings that support large systems with dedicated staff. The basic technology that supports SCADA can now be cost-effectively scaled to smaller systems with as few as just one substation.
This paper will highlight how smaller utilities may benefit from SCADA functionality, perceived barriers to implementation, typical requirements, technical considerations, and best practices for engaging engineering and construction partners from recent projects.
Index Terms—data acquisition, controller, supervisory, intelligent electronic device, SCADA, municipal utilities, cooperative utilities
I. INTRODUCTION
Large-scale applications of SCADA systems have improved safety and reliability, enhanced utility metrics, and benefited the bottom line. Historically, only investorowned and other large utilities have taken advantage of SCADA systems to build an adaptable, secure, and responsive infrastructure by continuously monitoring status and measurement data from substation and pole-mounted equipment. Yet even today, many municipal and cooperative utilities have not enjoyed the same benefits. It is possible to implement SCADA systems, even for utilities with as few as one or two substations, in a cost-effective and simplified manner.
Today’s small-scale SCADA systems gather and record information to support intelligent decisions without needing a major financial investment. Through the information provided in this white paper, municipal and cooperative utilities can harness the potential of automated information gathering to improve decision-making, troubleshooting, and system analysis while reducing maintenance and repair costs.
Any SCADA implementation — whether a new install or an in-place upgrade — must be customized to address a utility’s unique needs. The key aspects of these systems are common and include:
Successful deployments, demonstrated by recent projects, highlight the need for solutions and services that easily integrate existing equipment with new systems. This requires hardware designed to achieve interoperability and interconnectivity of intelligent electronic devices (IEDs) with a wide range of communications protocols. Software solutions coupled with newly deployed SCADA solutions must provide data access, management, security, redundancy and scalability to support any necessary system functions. It is important to consider engaging an expert team to provide turnkey project management, communications expertise, and implementation support to ensure successful project deployment, providing design, planning implementation, and training for utility staff.
II. SCADA SYSTEMS ENABLE REAL VISIBILITY TO SUPPORT POWER RELIABILITY
In general terms, the goal of the electric utility is to provide “safe and reliable electric power at a reasonable cost. The challenge is to find the right balance between low cost and high service quality.” 1 Further, as utilities are assessed based on their rates and reliability, actions taken and systems implemented to improve reliability can directly impact the bottom line.
To provide reliable service, it is critical to understand how the distribution grid is operating with accurate real-time data. This information provides the basis required to make effective decisions. While smaller utilities often rely on regular onsite system inspections by operators sent to the field to gather data points, larger utilities have used a variety of monitoring and control systems to gather equivalent data from multiple geographic locations in a continuous fashion. Utilities can rely on immediate, consistent, and historical data delivered by a SCADA system to make smart, efficient decisions that reduce the duration and frequency of power outages. With solid information, utilities can direct inspections and maintenance more effectively, based on real-time information reflective of what customers are experiencing.
Operational data can be used to significantly impact the utility’s System Average Interruption Duration Index (SAIDI), System Average Interruption Frequency Index (SAIFI) and Momentary Average Interruption Frequency Index (MAIFI). For example, SAIDI can be improved via remote collection of event recorder data by allowing the SCADA operator to provide basic fault data, such as impacted phases and fault current levels, to trouble crews, better equipping them to quickly locate, isolate, and restore faulted circuits. In addition, auxiliary automation applications, such as Fault Location, Isolation, and Restoration (FLISR), may be used in conjunction with a SCADA system to further automate and shorten the fault restoration process. Even the simple ability to remotely operate a single substation breaker can significantly impact the number of affected customers in an outage event by directing field crews to sectionalize the feeder at a midline switch and remotely re-energize it up to the newly created open point. When no outages are present, the SCADA system can further be leveraged to perform Volt/VAR Optimization (VVO) to improve distribution system efficiency. Improvements to SAIFI and MAIFI can be realized through analysis of historical alarm and event data to proactively address recurring momentary faults caused by tree contacts, leaking insulators, etc.
The data collected by SCADA provides utilities with greater visibility and control of their electrical distribution system. This allows for personnel to monitor and interact with equipment at the substation or distribution pole level from a safe distance, avoiding arc flash risks, and in many cases, the need to don cumbersome personal protective equipment (PPE). This visibility into the system also allows utilities to support more robust system monitoring. For instance, door alarms, video surveillance, and access control can be used in conjunction with IED alarming to detect unauthorized substation access, avoiding potential copper thefts, equipment vandalism, and other physical security concerns.
Large, investor-owned utilities have integrated their SCADA systems with real-time network connectivity modeling, enabling power system simulation engines to identify potential outages at the device level before they occur. Examples may include the prediction of transformer and conductor overload conditions, or detection of potential miscoordination events. This allows utility operations to be coordinated between engineering, planning, and field operations staff to prevent outages from occurring and enable prompt restoration in the event they do occur.
Without an effective SCADA system in place, utilities are forced to identify and address power system issues after an outage occurs, often sending personnel to a substation unnecessarily without any guidance on the root cause of the issue. This approach can add hours to the outage duration before the proper equipment and appropriately trained personnel are even dispatched. With up-to-date information in hand, utilities can dispatch personnel more efficiently in response to system events — in many cases avoiding the drive to the substation altogether.
III. FULL-SIZE SCADA SYSTEM BENEFITS CAN BE FOUND IN SMALL-SCALE INSTALLATIONS
Utilities have long relied on SCADA systems to collect event information. These systems were part of the electrical infrastructure prior to recent “smart grid” initiatives, and the benefits that large utilities have realized from their SCADA systems year after year can now be effectively scaled for smaller systems. Any distribution system can benefit from accurate, up-to-date information about system devices — even those with only a single substation. But, how can these operational benefits be realized efficiently and costeffectively?
Utilities with a relatively small number of substations have often resisted implementing SCADA systems because their design, implementation, and operation have been perceived as significant barriers to entry. SCADA systems have also been considered “too expensive” for smaller utilities, which may be unable to support complex systems requiring dedicated staff. One often-cited barrier to SCADA deployment is communications. How does data get from the field device to the “back room”? Where dial-up modems, leased lines, and private radio networks were the norm of years passed, recent technological advancements have paved the way for multiple cost-effective, scalable options with systems that can transform the communications-related investment from an upfront capital expense into an ongoing operational expense that directly correlates with the data usage and application requirements.
The basic SCADA system architecture is provided in Fig. 1. At the substation level, data from IEDs is typically collected by gateway or data concentrator devices, usually connected via copper or fiber optic cabling. The substation gateways, and other pole-line devices such as reclosers, voltage regulators, and capacitor bank controls, which provide critical data points on the feeder, are often connected into the system through cellular, multipoint radio, or fiber optic communications paths. With all data made available to the SCADA system in a centralized location, additional applications, including data trending/analysis tools, humanmachine interfaces (HMI), and automation schemes such as FLISR and VVO, can easily interface with the system.
IV. TECHNICAL CONSIDERATIONS AND REQUIREMENTS FOR SMALL-SCALE SCADA
Like nearly any successful engineering project, gathering of system requirements in advance of implementation is crucial — not only in controlling short-term costs, lead time, and project scope, but also in ensuring the long-term scalability and viability of the system. While most available SCADA solutions bring a certain amount of flexibility, it is still critical to establish system requirements and desired functionality in advance of selecting or installing a solution, to avoid potentially costly last-minute changes and scope creep.
While many important requirements must be developed, perhaps one of the earliest to be considered is communications capability and required functionality. While specific features can be scaled to meet future needs and growth, available communications bandwidth needed to support any supplementary features should be taken into consideration upfront. A well-designed SCADA communications system can be leveraged for other applications such as physical access control, video surveillance, and metering or demand response backhaul. These auxiliary system integrations can be implemented after initial project deployment, so long as the communications system does not become a limiting factor. Another important consideration in choosing a communications methodology is the availability of utility resources to support and maintain the chosen infrastructure. For instance, if fiber optics or traditional SCADA radio are used, the utility may or may not be in a position to construct, maintain, and support this infrastructure in the near and distant future.
There are a number of additional important considerations to take into account when designing a SCADA system that will be effective in meeting the utility’s established operational goals while remaining future-proof.
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