Interview with Michael I. Henderson on Planning Issues for HVDC

Michael I. HendersonMichael I. Henderson received two Master of Engineering degrees, Electrical Power Engineering in 1977 and Electrical Engineering in 1976, both from Rensselaer Polytechnic Institute, USA. In 1975, he earned a Bachelor of Science in Electrical Engineering from Polytechnic Institute of New York (now NYU) where he served as an Adjunct Lecturer from 1993 through 1999. In July 2016 Mike became the Editor in Chief of Power and Energy Magazine and, since July 1999, he has been a Director in the System Planning Department at ISO New England.

Previously, he had more than 22 years of experience at the New York Power Authority, Long Island Lighting Company, and American Electric Power.

Mike has presented technical seminars as well as over six-dozen panel, technical papers, and tutorials at IEEE and other forums. Mike is a registered Professional Engineer, an IEEE Fellow, and a native son of Brooklyn, New York.

In this interview, Michael Henderson answers questions as a follow up to his IEEE Power & Energy technical webinar, Planning Issues for HVDC. To view this webinar on-demand, visit the IEEE PES Resource Center here.

Q: What are typical distances where the HVDC become more economic than the AC system?

A: Transmission costs can vary by region, use of technology, power rating, and right of way availability. For an equivalent amount of power transfer HVDC line costs are typically lower, but the additional costs of the HVDC terminal equipment must also be considered. Like all transmission projects, the economic assessment should compare the costs of alternative plans of the transmission expansion and the potential benefits accruing from differences in various metrics with and without the project (such as the differences between the costs of production, resource capacity, ancillary services, losses, etc.). An old rule of thumb used to be that overhead line distances over 500miles and underground distances of over 50 miles required use of HVDC, but longer distances may be now be possible using newer ac technologies.

Q: Are the HVDC station service facilities automated?

A: Station service facilities include valve cooling systems, protection and control, and other ancillary facilities. Sometimes a simulator is included for training purposes as a supplement to the control room facilities. Local auxiliary equipment is fully automated and personnel can usually operate facilities offsite (monitor alarms, change schedule, etc.). It is possible to operate the HVDC facilities without personnel onsite, requiring attendance at site only for routine maintenance.

Q: What is meant by merchant transmission?

A: In several places transmission companies have full monopolies over all electric transmission facilities within their service territories. These companies are allowed a specific regulated rate of return. Other places allow for merchant transmission where specific investors own transmission facilities and sell transmission rights. The rules of merchant transmission vary by region, including the extent of their open access obligations, but all areas typically have reliability requirements that must be met.

Q: Please expand on 'multiple controllers could trip for single system event'?

A: Converter terminals, where dc is converted to ac, may temporarily or even permanently “block” (stop transmitting power) for low voltage events on the ac system. Multiple HVDC terminals in close electrical proximity could thus all stop operation for a common mode fault on the ac system, which would require consideration when planning new facilities. For example, there are places (such as China) where the system was fractionalized (split apart) to prevent several HVDC ties from all tripping simultaneously.

It is important to understand that the converters sense single phase voltages but stability programs typically model three phase systems. It is necessary to accurately model and assess the voltages at the converter terminals and the HVDC controls to fully understand the HVDC and overall system response. Fortunately, modern stability programs can now iterate between transient models of the single phase system and the three phase stability programs.

Q: Please describe applications multiterminal HVDC systems.

A: Multitermnal HVDC systems have three or more terminals. Power balance of transfers plus losses is achieved by coordinating the controls of all terminals. Recent developments in HVDC circuit breakers will likely facilitate the use of multiterminal HVDC transmission applications, including HVDC networks. A multiterminal system may be applied in areas such as city infeed, where a source of energy outside may be injected at several locations around a city, or in remote community supply (as an alternative to local diesel generators for example), where a more efficient source of energy may be fed to several remote locations in a region.

Q: Does ISO New England have plans for multi-terminal HVDC applications?

A: The Phase I/Phase II HVDC project interconnects Quebec with New England. It originally had 5 terminals (3 in Quebec, 2 in New England), but could only operate with 2 or 3 in service at any given time. Two terminals have since been retired. Through the years there have been several discussions of new multiterminal HVDC projects, but none have fully approved plans as of today.

Q: How can ancillary services provided by HVDC be considered in the economic evaluation? How can you add value to those services? How can you “measure” those advantages?

A: HVDC schedules can change rapidly, which can provide ancillary services. For example, asynchronous HVDC ties and long HVDC lines provide opportunities for providing power-frequency regulation. This is because the interconnecting systems may have a diversity of resources (such as mostly hydro versus thermal units) or load diversity (across time zones, etc.). Large changes in MW schedules can affect ac system voltage performance, but opportunities for VAR control also exist. Voltage source converters can provide voltage regulation at their terminals and line commutated converters may have additional equipment at their terminals that can provide voltage support (such as synchronous condensers or SVCs).

The economics of using HVDC installations to provide ancillary services must be weighed against alternatives. For example, ties across asynchronous systems provide opportunities for sharing generator power-frequency control from thermal units.

Q: How should field tests be conducted?

A: All operating and planning personnel must fully coordinate field tests and key personnel must be fully trained in the operation of the HVDC. The expected control system performance should be closely monitored and compared with simulation results. Actual field tests vary and typically include changes in MW schedules. Accessing inputs to control systems, such as providing low voltage inputs, can verify control system performance. Capacitors, transformers, or lines can be switched in or out of service. Some courageous owner operators have conducted staged fault tests.

It is vital to monitor HVDC performance and compare it to the simulated response for actual system events once the facility is declared fully commercial.

Q: Please comment on what it takes to obtain siting and permitting for large electrical transmission projects.

A: Often different governmental agencies are responsible for siting and permitting construction of transmission projects. For example, states in the US generally have responsibility, but several areas fall under federal jurisdiction, such as federally owned lands and rivers. In the US, the siting processes are public and those in opposition to the project have the opportunity to be heard. The need for the project must be established first, which also should show why it is the best alternative. Details of environmental assessments are then evaluated that could include everything from visual impacts to effects on endangered species. The siting and permitting process can be quite involved and typically involve attorneys, environmental specialists, and a full team of engineers, and these processes typically take between 1 to 3 years to complete

Q: Can you briefly compare HVDC TO HVAC?

A: AC transmission can more easily interconnect different voltage classes (using transformers) and integrates with the overall performance of the network. AC equipment, such as circuit breakers, is usually simpler, less expensive, and more familiar to the workforce than equipment associated with HVDC. As compared to ac transmission HVDC has the ability to:

  • Transmit more power in less right-of-way
  • Provide point sink/sources of power
  • Control steady state power flows
  • Allow for longer underground/undersea cable lengths (because there is no line charging)
  • Provide frequency regulation
  • Damp dynamic oscillations
  • Stabilize transient stability swings
  • Tie asynchronous interconnections
  • Provide transmission over long distances
  • Bypass network congestion and inject power
  • Limit short circuit contributions

Q: Can ac lines be converted to HVDC?

A: Yes! This has been an exciting area of technical development and most recently shown as an area of increased interest as availability of new rights-of-way becomes more difficult to obtain.


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