The Revitalization, Modernization of the Aging Transmission System

by Dwayne Stradford, Science Applications International Corp. (SAIC)

As electricity demand continues to rise and renewable energy mandates become more stringent, energy providers have placed an increased focus on the integration of baseload and renewable generation on the bulk electric system (BES).

Capital constraints and lack of investments in new transmission infrastructure continue to introduce barriers for generation and transmission providers in their ability to build a reliable infrastructure to meet the demands of the 21st century.

Growing evidence suggests private and public action is needed to ensure our transmission system will continue to meet the nation’s needs for reliable and affordable electricity.

Planning Approach

Aging infrastructure, poor operations and maintenance practices and the need to integrate new generation projects introduce serious grid reliability challenges.

The framework to improve the nation’s electric system might look similar to the overhaul of a major two-lane highway with a host of freeway interchanges and stoplights.

The goal is to alleviate power flow congestion while improving the overall transmission reliability and enable cohesive integration of new green energy and accompanying storage facilities with existing generation.

Revitalization of the nation’s transmission system will require transmission providers to consider:

  • Construction of new bulk power corridors near new generation projects. Long-range capital and operational transmission-planning groups must explore construction of new bulk power corridors near new baseload generation projects in conjunction with potential renewable energy projects to minimize transmission construction and costs required to interconnect new power sources to the grid.
  • Conversion of dated technology and equipment to new and improved corporate standards. A well-defined replacement plan, based upon each company’s new preferred device platforms and equipment vendors, should be developed for legacy equipment, eliminating the ongoing maintenance of outdated technology. Transmission field crews should be in position to convert their existing, outdated station and line equipment to the newer, advanced technology during upcoming scheduled transmission maintenance activities or after catastrophic failures of transmission line and station equipment.
  • Use of phasor-measuring unit technology. In the United States, there has been a moderately paced implementation of phasor measurement unit (PMU) technology on the bulk power system. Accordingly, new applications are being developed and implemented in control rooms nationwide to increase situational awareness, including techniques for improving the accuracy of energy management systems (EMS) and transmission settlement models. In addition, it is important for transmission companies that already use PMU technology to consider using protective relaying containing PMU capability within its suite of operating features.

Transmission Line Construction

The following factors should be considered in the construction of new transmission corridors while planning existing upgrades:

  • Use of fiber-optic shield wires on the transmission lines. These secure and high-capacity communication paths can be established along transmission corridors and between load centers to the operations center by using the fiber-optic shield wires with all new transmission circuit construction. Use of these fiber-optic paths establish direct communications for transmission line protective relaying between stations, retrieval of PMU statistical data and supervisory control and data acquisition (SCADA) data, along with the implementation of special protection schemes, if warranted.
  • Wireless technology at remote sites. Microwave radio frequency and cellular communications antennas atop transmission poles or towers can provide another layer of wireless voice and data communications on the BES. Line interference can affect the quality of the communications systems leveraging the available tower space.
  • Dynamic thermal circuit-rating technology. Transmission line technologies exist to measure real-time thermal circuit capacity directly, as opposed to fixed calculated transmission circuit ratings that get entered into the EMS models.
  • Weather-monitoring equipment. The installation of weather-oriented stations to aid in the monitoring of weather events and real-time conditions could be beneficial in partnership with the installation of dynamic thermal circuit-rating equipment on transmission paths across the network. The accuracy in transmission line ratings would improve significantly, thus leading to full utilization of the transmission’s operating capacity. This technology should be installed at the substation control houses and can be equipped with solar panels to provide backup power.

Substation Construction

Construction of a ring bus or a breaker-and-a-half scheme configuration provides greater flexibility to add new station equipment and perform periodic routine maintenance while minimizing reliability exposure to the remainder of the grid.

If such configurations are not used, the installation of automatic sectionalizing equipment, such as circuit breakers and motor-operated air-break switches, can improve system operation agility greatly, permitting:

  • Increased flexibility in isolating station equipment after the transmission system has experienced a fault (temporary or permanent),
  • Allow for the remote isolation of station equipment for crews to perform maintenance from the operations center, and
  • Provide the opportunity to test and restore portions of the bulk power grid after a system disturbance.

Further enhancements might include the installation of a station-monitoring display to reveal the real-time flows, voltages and equipment status (open or close state) within the control house to aid in troubleshooting station issues and increase situational awareness.

Utilities also should consider deploying near real-time archival systems for asset managers and transmission operations.

This will provide valuable intelligence regarding the detection of system disturbances, pre- and poststatistical data for the system events, and potential formulation of automated North American Electric Reliability Corp. (NERC) reliability compliance reports.

In addition, this would enable capture of relaying control targets, along with pre- and postevent transmission statistics, such as currents and voltages, for each event.

Establishing an independent, stand-alone revenue-metering system at each station can benefit transmission system providers.

Companies with revenue-based equipment supplied by protective relaying devices occasionally experience serious metering inaccuracies with the changing of current transformer (CT) or potential transformer (PT) ratios’ not being communicated properly.

Consequently, that has been one of the critical pitfalls of piggybacking revenue-metering systems off of the station’s protective relaying equipment.

Determination of Reactive Resource Requirements

Documented operational performance and load growth forecasts will be some of the driving factors dictating the placement and sizing of reactive resources across the transmission network.

Therefore, it is imperative to maximize the full capability of the SCADA monitoring system and the capture of all essential transmission data.

Critical transmission factors that should be monitored include:

  • Transformer power factor calculations. Monitoring and evaluating transformer power factors, particularly on distribution transformers, will help determine whether there are adequate reactive resources downstream supplying power to the internal load demand. Utilities also should consider the installation of distribution bus capacitors or distribution feeder regulators to aid in distribution voltage support.
  • Transmission surge impedance loading. Typically, transmission surge impedance loading (SIL) is an underrated transmission-monitoring factor, but the thought behind using this operating metric is simple.

Transmission circuits that regularly are heavily loaded beyond their SIL should be considered for the following transmission improvements:

  1. Re-conductoring, replacement of the existing transmission circuit or circuits or both;
  2. Construction of a parallel transmission circuit; and
  3. Circuit in question and surrounding circuit or circuits upgraded to a higher transmission voltage level.

The SIL on heavily loaded circuits also could help identify the placement of shunt-reactive devices across the system.

Evaluating the historical directional MVAR reactive power flow on these heavily loaded circuits in conjunction with the overall area voltage profile will indicate the location of future shunt capacitor banks and shunt reactors.

The areas electrically on the sink or load side of these circuits, loaded beyond their SIL, would be prime areas to install reactive resources.

Some companies have made it a standard practice to terminate shunt reactors to an extra-high-voltage (EHV) circuit through a manually operated switch.

It can be beneficial to attach these reactors to the bulk power system through a circuit breaker, preferably using zero-impedance crossing technology or the like to reduce the adverse surge exposure on this sectionalizing equipment.

With the installation of circuit breakers on the line shunt reactors, transmission service providers could realize several advantages, including:

  1. Isolation of the line shunt reactors for maintenance without having to open up bulk power transmission paths on the transmission grid;
  2. Upon the failure of this equipment, the local circuit breaker would clear the line shunt reactor from the transmission system without having to send somebody to isolate the shunt reactor manually from the EHV circuit; and
  3. As necessitated, the reactor could be taken offline or brought online for managing reactive flows and area voltages remotely from the control center without interrupting service to a major bulk power corridor.

EMS and SCADA Applications

To properly examine the vital signs of the transmission system, assessment of the flexibility and capability of each transmission provider’s SCADA system will be essential.

The following SCADA system characteristics should be evaluated:

  • Capability to properly archive the transmission data. This will be used for future load forecasting and determining the priority of future transmission projects.
  • Creation of offline load flow models. The EMS and SCADA system should be able to take real-time snapshots of the current and past grid conditions to readily create offline load flow models in at least the Siemens-Power Technologies Inc. PSS/E or the General Electric PSLF power load flow formats.
  • Use of historical real-time data for transmission operator simulators. New NERC reliability compliance standards require the use of some type of simulation technology to train system operators in dealing with Interregional Reliability Operating Limits (IROLs), black start plans and other companies’ BES-specific, reliability-related tasks.

Each company also should address:

♦ Implementation of RTUs at every BES location. Remote terminal units (RTUs) will be an important feature in new transmission station construction. Each company might need to find economical means to retroactively upgrade, replace or install RTUs at its existing stations on the BES. This will improve each company’s situational awareness for impending transmission challenges, but it greatly will enhance each reliability coordinator’s wide-angle view of the system. All real-time operational entities will benefit significantly by having this comprehensive view of the BES.

♦ Transmission measurements. With the adequate sizing of RTUs, it becomes essential to retrieve the entire suite of transmission station data measurements from each station. For example, it would be desired to retrieve all three phase voltages, three phase currents, transformer power data (MW, MVAR and MVA), and transmission circuit power data (MW, MVAR and MVA), along with all statuses of station breakers and switches.

♦ Distribution load management systems. Improving the sophistication and functionality of the distribution feeder relaying systems will allow greater flexibility to install the transmission and distribution reliability systems, including:

  • Underfrequency load shedding (UFLS),
  • Undervoltage load shedding (UVLS),
  • Voltage reduction for 3 and 5 percent reductions, and
  • Automatic load shedding per predefined and individual transmission contingencies.

The steps in this article are merely the starting point to develop a comprehensive plan for transmission providers. The lessons learned will aid in developing the nation’s transmission system improvement blueprint.

Author

Dwayne Stradford is a senior transmission planning engineer at SAIC. He has more than 17 years’ experience in real-time transmission operations and bulk power security, NERC reliability compliance, transmission planning, work force development, demand response, smart grid and managing energy projects.

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