By Ronald D. Willoughby, KEMA
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. New technology once was considered acceptable justification for upgrading or replacing automation equipment, but in recent years, projects having well-defined and measurable returns on investment get priority. Gone are the days when flashy displays are enough to justify projects.
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:
- Advanced metering that is bidirectional in energy and information flows. The communications network relies on open standards with the network being remotely upgradeable 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 and distribution (T&D) sensors that 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. The focus is on residential users and commercial installations (see Figure 1, page 54).
The challenge is to manage grid operations reliably 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 should be re-engineered with future staffing decisions in mind. This is particularly important in light of aging work force 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’s adjusting to integration of renewables and storage with grid operations (see Figure 2, page 52).
Use of wide-area measurement using phasor technology rapidly is becoming a national norm, driven by the Department of Energy and North American Electric Reliability Corp. Transmission operators will deploy phasor measurement unit or synchrophasor systems integrated into wide-area monitoring to enhance grid visibility, reliability and control.
At the distribution level, distribution management systems increasingly will 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 (see Figure 3). 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 continue to build bandwidth and connectivity to address wider acceptance of mobile connectivity. More locally intelligent devices that interact with the physical world, consumers or both 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 interaction 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 face 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 bidirectional data transmission, including real-time data flows, which can connect to individual meters. Utilities also must balance volume, latency and bandwidth service levels among meters, customer automation systems and essential T&D infrastructure. Expensive special-purpose networks must be justified for short-term business objectives and unique operational requirements. Backhaul communications (as to substations) must be designed and procured with an eye to significant traffic and bandwidth increases during its useful life.
Grid Re-engineering to Accommodate DG
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 re-construction and will have longer technical life spans.
The likely scenario for existing distribution circuits in suburban residential settings is a mixture of photovoltaic (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 might 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 adapt these protection and restoration schemes quickly to changed DG presence and real-time production, the work of digitizing protection and automating substations must be completed rapidly. Those distribution substations with remaining electromechanical protection or digital relaying but no substation automation must be converted. SA and DA systems will be integrated with back-office systems to monitor and adjust protection and restoration schemes as needed.
In addition, 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 be unable 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 necessities. 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.
Also, circuit- or substation-based storage might 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 volatility of renewables, especially wind, will lead to targeted deployment of flexible alternating current transmission system 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 such as 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 must be developed in conjunction with these enhancements.
Utility automation systems, including primary supervisory control and data acquisition 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 must continue driving incremental technology developments to meet industry needs best while satisfying bottom-line constraints.
Ronald Willoughby, is vice president of electric transmission and distribution for KEMA Inc. He is a professional engineer with more than 35 years of experience in electric power system planning and control, advanced technology applications and energy efficiency.
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