SF6 circuit breaker maintenance: what should utilities be doing?

Author: Todd Rittenhouse

06/01/2005 - Volume II - Issue II

Background

 

SF6 circuit breaker technology was developed in the early 1960s to meet the growing demands for reliable high-voltage circuit breakers with interrupting mediums. The industry was ready for an alternative to the traditional mediums of mineral oil and/or air. Using SF6 as an interrupting medium had the advantages of being inflammable as well as having high dielectric strength and exceptional thermal stability. The first generation of SF6 circuit breakers was the lower voltage classes of 72kV and 145kV. As SF6 breaker technology improved, circuit breaker manufacturers introduced a dual pressure design for 145kV through 800kV applications, as well as air-blast breakers utilizing SF6 as the line-to ground dielectric insulation.

In the 1970s, both domestic and foreign breaker manufacturers looked for ways to improve breaker interrupting technology based on the unique properties of SF6 while also reducing costs. This improvement was the implementation of puffer interrupters that "snuff" out the arc versus the earlier design of dual pressure breakers that utilized a two stage (pressure) system. The dual pressure breakers (typically applied at 230kV and above) had a dielectric system pressure of approximately 40psig. They utilized a compressor arrangement to pressurize the arc extinguishing SF6 to a pressure of gas to enable multiple operations of this style of circuit breaker. This high pressure SF6 is released across the contacts by-way of a blast valve assembly, which is actuated during the mechanical operation of the breaker (either opening or closing). These dual pressure breakers were costly to build and costly to maintain. This was due to the complex systems required for operation as compared to a single pressure puffer breaker.

 

Puffer breakers, on the other hand, utilize a shaped nozzle and piston arrangement to trap a volume of SF6 and force it across the contacts during the stroke of the interrupter.

Dual pressure and puffer technology are utilized in both live and dead tank power circuit breaker configurations. Live tank breaker refer to equipment where the interrupter assembly (including the housing) is always at line potential voltage. "Dead" tank breakers refer to equipment where the interrupter is at line potential but the tank (housing) is at ground potential. The intrinsic similarities and differences of these two technologies will be discussed below.

 

Economics

 

Over the last 10 to 15 years, many utility and industrial users of SF6-filled power circuit breakers have been met with pressure to reduce costs while maintaining or even improving the operational reliability of their T&D infrastructure. In many cases, these requirements have forced maintenance managers and asset management organizations to reduce the overall frequency and scope of their high-voltage breaker maintenance. At the same time, the availability or "uptime" of the equipment has increased, along with system duty requirements due to load growth and increased generation input to the T&D grid. These requirements account for delayed or even reactive maintenance of this critical equipment. Many asset managers are implementing a diverse combination of time based maintenance (TBM), condition based maintenance (CBM), and reliablility centered maintenance (RCM) programs to ensure the "right" maintenance is being completed at the "right" interval on the "right" equipment.

 

Application and issues

 

SF6 breaker maintenance is dependent on many factors including:

 

  1. Application or duty - A circuit breaker can be a line position, high side generator protection breaker, bank or reactor switching, etc. The circuit breaker application can directly influence the amount and frequency of maintenance that the actual breaker should recieve throughout its service life.
  2. Environment - The environment where a circuit breaker is located can greatly affect the maintenance "demands" of these breakers. For example, coastal locations may require more rigorous external maintenance on seals systems, bushing insulators and hardware due to corrosion from exposure to salty air.
  3. Previous maintenance practices - What maintenance, if any, has been done to the breaker(s)? Are any records available from the last maintenance interval and/or startup/commissioning testing for reference, comparison, and trending?
  4. Knowledge - Do the local maintenance personnel have the expertise to adequately service the circuit breakers? The industry continues to experience an expertise "drain" due to retirement and consolidation of utilities. In most cases, having responsibility for a large and more diverse breaker population may compromise the effectiveness of the maintenance personnel.
  5. Parts - Reductions in owner's inventory levels, OEM upgrades to components, and extended "shelf-life" of the parts.
  6. Criticality of load served - The implications of an unplanned outage could lead to adopting various maintenance strategies for the same model of breaker applied on different portions of the grid. E.g. TBM might be appropriate for circuit breaker protecting the stock exchange while RCM may be appropriate approach for the same breaker protecting less critical load.

 

OEM maintenance recommendations

 

OEM breaker maintenance requirements vary widely by manufacturer and style, voltage class, and mechanism type. Most OEM's recommend a combination of time based as well as condition based maintenance. TBM of monthly visual inspections for the following: recording SF6 pressures (density), operational counter tracking and overall verification of breaker condition. On an annual basis, the verification of condition is made for anti-condensation cabinet heaters, general condition of control hardware and mechanism components within the breaker cabinet. The next TBM intervals (five to seven years) are for the following testing: timing, contact resistance, control and auxiliary alarms, SF6 moisture and low gas density alarms. Mechanism maintenance is also recommended during this interval. The next interval of 10 to 12 years is for "major" maintenance. Typically, it includes the earlier (5-7 years) maintenance and a visual inspection of the interrupter contacts and replacement of the disturbed seals and desiccant. The CBM recommendations "dove-tail" into the TBM practices stated above, but consider mechanical operations on the breaker (2000-2500) for inspection and maintenance. CBM recommendations also consider the amount (kA) of fault duty and number of fault clearing operations the breaker has been called upon to interrupt, either form installation or from the most recent breaker major maintenance or overhaul.

 

What should be done and when?

 

Equipment owners must consider all of these issues and conditions (and more, of course) when developing their breaker maintenance practices and policies. These practices can range from basic maintenance (when it fails), to exceeding the frequency and scope recommended by the OEM and obviously anywhere in between. There are some maintenance fundamentals, which should be considered:

 

  1. Periodic external inspections are a must! These can range from monthly visual inspections to multi-year testing regiments. Breaker monitors can only do so much.
  2. Breaker application directly affects its maintenance requirements. An infrequently operated breaker typically has more problems than a frequently operated breaker.
  3. Upgrades - Most OEMs have upgrades for breaker components or processes to ensure improved component life or functionality. Is the breaker owner aware of these?
  4. Maintenance technology - This runs the gambit from integrated maintenance management software to remote breaker monitoring.
  5. Live tank breakers vs. Dead tank breakers -  Live tank breakers typically perform better in switching applications and have a higher tolerance for arc by-products and contamination than the dead tank breakers. Dead tank SF6 breakers more closely resemble their predecessor (oil circuit breakers) and have a better fit and function from a protection perspective.
  6. Operating mechanism type - Below is a list of the most common operating mechanism types. All of them have inherent advantages and disadvantages, but most have been utilized in the industry for many years. The operating mechanism is the breaker component that will require the most frequent maintenance support.

          Spring/Spring (proper lubrication should be maintained)

          Spring/Hydraulic

          Hydraulic (leak correction, accumulator integrity)

          Pneumatic

          Spring/pneumatic (air system / compressor maintenance)

 

7. Auxiliary and controls components - These components (relays, timers, heaters, etc) should be tested periodically to ensure correct operation.

 

8. SF6 gas leakage - SF6 breakers (live and dead tank) typically have a combination of static seals (O-rings and gaskets) as well as dynamic seal assemblies where the mechanism energy is transferred through to the interrupter assembly. Over time, seals degrade due to environmental conditions and exposure and will need to be replaced. Recent non-evasive technologies such as laser leak detection have improved the ability to pinpoint the source of SF6 leaks so that corrective actions can be planned.

Summary

 

When considering high-voltage SF6 breaker maintenance, there are many factors to include in the maintenance "equation." Also, there is no "one size fits all" answer but rather data, OEM and owner's knowledge and experience, industry trends, and continuously improving technology and techniques to ensure continued circuit breaker reliability.