Power System Automation
By Ronald D. Willoughby, P.E
For more than two decades, electric power system automation has been undergoing a slow but steady transformation. In the 1980s and 1990s, the most significant issues were rooted in technology changes, such as the transformation from electromechanical to digital, from mini-computers to workstations, and from workstations to PCs. New technology was once considered acceptable justification for upgrading or replacing automation equipment, but in recent years, projects having well-defined and measurable returns on investment (ROI) get priority. Gone are the days when flashy displays are enough to justify projects.
Perhaps more than any other industry, electric power has been dominated by custom solutions, often developed by utilities themselves, or in conjunction with consortiums, or through direct third-party contracts. Integration of the pieces has become the dominant challenge. Communications technologies working with a myriad of increasingly sophisticated intelligent electronic devices (IEDs) made possible the collection of large amounts of data in near real time. Processing into practical, efficient, and actionable instructions is now the challenge. Specialists with proven abilities to manage large projects and combine these multiple technologies to make the pieces work as an integrated whole is what’s needed.
Figure 2. Communications Building Blocks
Figure 3. Energy Management System
The technologies include advanced databases, communication structures, control options, and application schemes. The process of seamlessly working together as an integrated whole must also satisfy business needs (business enterprise), functional needs (substation and feeder automation), and operation’s needs (supervisory control and data acquisition, or SCADA, system). Figure 1 offers a graphical illustration of the pieces.
As the number of devices that need to communicate with each other increases, the complexity of information exchange increases. An illustrated by the “communication building blocks” in Figure 2, each level requires more and more sophistication, as you move from one device acting alone, to multiple devices working together on a single distribution feeder, to multiple devices in a substation, to multiple devices between substations, and to the entire system working as in integrated whole.
As complexity grows and response times decrease, so do demands on the infrastructure. As more critical functions are automated, heightened security of information becomes more important. Common protocols and open architecture become important as inter-operability between different devices and manufacturers becomes a necessity.
Transmission and Distribution Infrastructure
Increasing pressures from residential and commercial distributed generation and energy management systems are forcing the grid to evolve in ways that facilitate better collection and processing of vast amounts of information. Key drivers include the following:
- Advanced metering that is bidirectional in both energy and information ﬂows. The communications network relies on open standards, with the network being remotely upgradable to take advantage of future technologies. Key features include current limiting capability, interval consumption and power factor measurement, remote reconnect capability, on-demand read capability and more.
- Transmission & distribution (T&D) sensors collect real-time power ﬂows from generators, substations, and line equipment. Optimization becomes possible as the digitally enabled grid collects information on system operation and equipment condition. Sensors communicate via wireless, broadband over power line, and other communications media.
- Data display capabilities exist throughout the power system, including home and office locations.
- System integration of customer energy management systems (EMS) with grid operations (Figure 3), with a focus on residential users and commercial installations
Transmission and Distribution Operation
The challenge is to reliably manage grid operations while new technologies are implemented throughout the power system. For example, transformers and switchgear equipped with sensor capabilities, either embedded or through retroﬁt.
Field force operations reengineered with future staffing decisions in mind. This is particularly important in light of aging workforce issues. Training can help relay operators better understand analog control technology, a skill no longer taught in university electrical engineering programs. Training in digital technology controls, man-machine interfaces, and information processing are other important areas.
Sophisticated asset management programs are needed to exploit equipment condition monitoring and make better use of real-time data.
Control and Management Technology
At the transmission and substation level, today’s paradigm of managing congestion by adjusting production to accommodate the grid is changing to one of the grid adjusting to integration of renewables and storage with grid operations.
Use of wide area measurement using phasor technology is rapidly becoming a national norm, driven by Department of Energy (DOE) and North American Electric Reliability Corporation (NERC). Transmission operators will deploy phasor measurement unit (PMU) or synchrophasor systems integrated into wide area monitoring to enhance grid visibility, reliability, and control (Figure 4).
At the distribution level, distribution management systems will increasingly incorporate real time network analysis and optimization, including protection/automation scheme adjustment in real time, to manage overloads, apparatus problems, and outage isolation and restoration. The bulk of network analysis will occur in the utility central offices as the algorithms and methodologies mature enough to be fully autonomous in substations.
Communications companies (as well as Google and Microsoft) continue to build out bandwidth and connectivity to address wider acceptance of mobile connectivity. More locally intelligent devices that interact with the physical world and/or consumers are connecting to the Internet instead of continuing to use legacy schemes with limited bandwidth. Consumers (and commercial facilities) are installing Internet connection points throughout their homes as consumer interactions with “society” and “business” moves to the web with greater frequency.
“Less intelligent” devices with limited information to exchange are using short range wireless and “wired power” technologies, such as dynamic Radio Frequency Identiﬁcation (RFID) to communicate. Dynamic RFIDs ﬁnd niche applications in critical infrastructure monitoring and become an option for utility apparatus as well.
Utilities are faced with additional communication challenges as they deploy Advanced Metering Infrastructure (AMI) and Distribution Automation (DA) capabilities to accommodate distributed generation (DG) penetration. The network must enable bi-directional data transmission, including real-time data ﬂows, which can connect to individual meters. Utilities must also balance volume, latency, and bandwidth service levels between meters, customer automation systems, and essential T&D infrastructure. Expensive special purpose networks have to be justiﬁed for short-term business objectives and unique operational requirements. Backhaul communications (as to substations) have to be designed and procured with an eye to significant traffic and bandwidth increases during its useful life.
Grid Re-Engineering to Accommodate Distributed Generation
Significant DG penetration on the distribution system introduces significant engineering challenges. Fault current limiters (FCLs) are needed along with evolving protection schemes that can adjust to pre-fault levels of DG output. Information from the AMI system about DG status must be coordinated in the back-ofﬁce with adaptive protection schemes. Digital protection and substation automation technologies exist today. Back-ofﬁce systems to adapt protection schemes to DG status require software development and systems integration. Substation automation (SA) and FCL retroﬁts are far less expensive than circuit reconstruction and will have longer technical life spans.
The likely scenario for existing distribution circuits in suburban residential settings is a mixture of PV and “legacy” installations. More sophisticated re-engineering of the distribution system and its operation to take advantage of DG (such as isolated local circuit operation post fault based on DG capacity) is probably too difficult to achieve technically and commercially.
Small commercial and higher density residential settings may additionally see “shared” PV/DG installations. This will add some complexity, possibly, to the AMI functionality, but will lead to the same conclusions about the distribution circuit and automation/protection.
Increased DG presence will cause adverse changes in fault levels, and the tendency of consumers to install DG without utility involvement will force utilities to develop and deploy FCLs and other advanced distribution reliability enhancements. To quickly adapt these protection and restoration schemes to changed DG presence and real time production, the work of digitizing protection and automating substations will have to be rapidly completed. Those distribution substations with remaining electromechanical protection or with digital relaying but no substation automation will have to be converted. SA and DA systems will be integrated with back-ofﬁce systems so as to monitor and adjust protection and restoration schemes as needed.
Figure 4. Distributed Power System
Potential versus Real Peak Load. Heavy DG and storage penetration in a distribution circuit creates a situation where the circuit peak load is less than it might be if the entire connected load is “on” and none of the DG/Storage is producing, or worse if the storage is charging. Faced with such a situation, utilities will not be able to build circuit and substation capacity to handle classically defined “peak load.” DSM (as a peak constraint integrated with DG), load automation and storage will be a necessity. This is already the case in some large urban areas where conversion of major buildings from class “C” to class “A” real estate doubles the energy demand and the underground network cannot be expanded to handle the additional load under any realistic scenario. These buildings embrace DG but pose a potential peak the system cannot accommodate. Therefore, integration of building automation with grid operation becomes mandatory. This integration is being pioneered in large older urban high-rise situations.
Circuit or substation-based storage may be a cost effective alternative to consumer-side storage. This, however, requires additional information and control integration with customer-side DG.
Large scale, centralized renewable production will alter transmission grid utilization with attendant changes in congestion. The inverters and inherent volatility of renewables, especially wind, will lead to targeted deployment of Flexible Alternating Current Transmission System (FACTS) devices and storage (as is the case even now in Texas) to manage renewable impacts on the grid.
High temperature superconductors become practical for certain high value, short distance transmission projects, especially in urban areas where underground cable is mandatory.
Most utilities will require significant adaptations to their planning methodologies and tools to accommodate changes in grid engineering. Training programs and continuous learning will have to be developed in conjunction with these enhancements.
Utility automation systems, including primary SCADA and T&D management, as well as geospatial and secondary field automation offer smart, cost-efficient ways to bridge the chasm between long-term infrastructure improvements and the immediate need for system reliability and operational integrity. As the industry deals with unprecedented challenges brought on by a constantly changing business and technological environment, we will need to continue driving incremental technology developments to best meet industry needs while satisfying bottom-line constraints . . . a tall order for sure!
Ronald D. Willoughby, P.E, is DNV KEMA Energy & Sustainability’s vice president for Electric Transmission & Distribution.