1.1.2 - Chapter 2 - Circuit Breaker Fundamentals

Introduction

This chapter presents a basic introduction to power circuit breakers, including:

• Interruption theory
  • Operating Mechanisms
  • Insulating Media
  • Trouble and Failure Modes
  • Life-Limiting Factors
  • Specifics of Circuit Breaker Interruption
• Oil circuit breakers
• Air-blast circuit breakers
• Air and SF₆ compressors and their associated air and gas systems

Interruption Theory

A power circuit breaker is a device for making, maintaining, and breaking (interrupting) an electrical circuit between separable contacts under both load and fault conditions.

Interruption of electrical circuits has been a necessary part of electric utility systems since the first use of electricity. Initially, this interruption was achieved simply by separating the contacts in air. As current levels became higher, arcing between the opening contacts presented greater problems that required the development of methods to deal with plasma arcs that occur during the opening process. The problem is more severe during faults or short-circuits, at which times rapid, practically instantaneous, interruption of current is necessary as a protective measure for the connected apparatus and system security.

By the late 1920s, all principal methods of arc interruption had been developed with the exception of the SF₆ types, which came into being in the late 1950s. Oil, air-magnetic, air-blast, and vacuum methods were all in use by 1930. Many of the principles of these first modern breakers are still used in today’s more highly developed breaker designs.

Basics of Circuit Breaker Interruption

When a switching-device conducting alternating current is in the act of opening, an arc is formed. The arc commences as the last metal-to-metal electrical contacts separate. An arc is a conductor. A number of factors must work together to extinguish an arc and interrupt a circuit. These factors include velocity, distance, cooling, current zero, and dielectric strength.

Velocity. The speed at which the circuit breaker contacts separate is an important part of circuit interruption. The faster the contacts separate, the less time the arc has to heat the space and other materials between the parting contacts, thereby reducing the conducting ability of the space. The slower the movement of the moving contact, the greater the ability of the arc to maintain itself.

Distance. As the distance increases between the contacts as they open the arc is stretched. As the arc stretches, the voltage, termed the arc-voltage, attempts to maintain current flow, but with the increasing distance of the parting contacts, the arc becomes more vulnerable to the other factors mentioned.

Cooling. Interrupter cooling is a physical effect that removes heat created by an arc within a circuit breaker interrupter. Increasing the temperature of gases causes them to become more conductive.

Therefore, cooling methods such as introducing forced air, gas, or insulating oil into the area of the arc are important to arc extinction.

Current Zero. Alternating current changes polarity, from positive to negative or negative to positive, 120 times a second in a 60-Hz (cycle) sine wave (100 at 50 Hz). At the time the polarity changes, there is no flow of current. The instant an arc ceases is termed “current zero.” This provides the opportunity for interrupting the arc.

Dielectric strength. Dielectric strength is the ability of an insulating medium to withstand a given voltage over a given distance without conducting. As previously mentioned, circuit breakers utilize different interrupting media of varying dielectric strengths. The dielectric strength of insulating oil is many times greater than that of air at atmospheric pressure; however, the dielectric strength of air (as well as other gases) increases when pressurized. The dielectric strength of a hard vacuum also exceeds the dielectric strength of air at atmospheric pressure.

When, at a current zero, a circuit breaker attempts to interrupt either load or fault current, a voltage is generated across the open contacts of the circuit breaker to oppose this change in current. This voltage, the transient recovery voltage (TRV), is equal to the difference in the voltages on the load side and source side of the circuit breaker after the breaker contacts have parted and the current interrupted. The wave shape and magnitudes of these voltages depend on the system configuration both before and immediately after the contacts open and the current ceased.

As the contacts continue to open, the distance between them increases, stretching the arc. The stretching and cooling enables the arc to be quenched at current zero. As the contacts continue to move (open), the arc extinguishes at each current zero crossing. The arc will remain extinguished if the improving dielectric strength of the medium between the contacts is greater than the rising voltage across the open contacts.

If the dielectric strength across the contacts is not sufficient to withstand this voltage, a re-ignition will occur and the arc will be reestablished. At the next zero crossing, the arc will again extinguish and, dependent on the type of circuit breaker, this process will continue until the dielectric strength necessary to withstand the voltage across the distance between the parted contacts is reestablished. Modern designs interrupt within two, sometimes three, zero crossings following the contacts parting and they have no capability beyond this. Figure 2-1 shows the relative dielectric strengths of oil, air, and SF_6.

The heart of the circuit-breaker is the interrupter. When the circuit-breaker contacts open, the interrupter

• Interrupts the path of the resulting arc and
• Directs the interrupting medium (oil/air/gas) to cool and replace the arc column.

In this way it extinguishes the arc at a current zero after contact separation. The exact manner in which circuit breakers and other switching devices achieve this is detailed elsewhere.

Operating Mechanisms

Operating mechanisms provide the power to enable the interrupter to perform the mechanical closing and opening, and hence the electrical making and breaking, function of circuit breakers. On some designs, energy from the closing operation is stored in the mechanism for the next opening operation, such as charging opening springs during the closing operation. Other designs make use of stored energy from a single source for opening as well as closing. There are four types of mechanisms used in transmission class circuit breakers:

• solenoid mechanisms
• spring mechanisms
• pneumatic mechanisms
• hydraulic mechanisms

All these mechanisms are characterized as being trip-free and, usually, the control circuitry is what is termed “antipumping.”

The trip-free characteristic requires the circuit breaker to open at any instant that a trip command is issued to the unit, even if the circuit breaker is in the process of closing. To achieve this, the mechanism, interrupters and drive system must be able to withstand the forces of the sudden change of direction. In some cases a circuit breaker must reach the contact make position before it opens. In other cases, the mechanism can trip free (open) at any point during a closing operation. This mechanical travel characteristic can be checked with a timing instrument as a maintenance activity.

The antipumping characteristic signifies that the circuit–breaker will not repeatedly open and close if the electrical open and close commands are applied to the circuit-breaker simultaneously and maintained. This prevention is usually achieved within the control circuitry. The antipumping circuit in the circuit breaker requires that the electrical close command be removed before the unit can be closed a second time. This characteristic can also be checked as a maintenance testing activity.

Solenoid Mechanisms

In the solenoid type mechanism, a solenoid supplies the energy to close the circuit breaker. A spring, which is charged during the closing operation, is used to open the unit. The closing solenoid potential is supplied from either the station battery or by station ac rectified voltage. The closing and opening times of circuit breakers with this type of mechanism are quite slow, with closing times as long as 40 cycles.

This type of mechanism is the oldest (and simplest) of the four described in this subsection, but due to its relatively slow closing times it has been largely replaced with one of the other types. It is a typical mechanism type for the earlier designs of bulk oil circuit breakers, especially at the lower system voltages.

Spring Mechanisms

In the spring type of mechanism, the energy to close the circuit-breaker is stored in a large spring, which is usually compressed, but on some designs may be extended, by a motor immediately following each close operation. A smaller spring, which is charged during the closing operation, is used to open (trip) the breaker. This type of mechanism provides faster operating times than solenoid mechanisms, but has duty cycle limitations (one open-close-open cycle) due to the lack of energy storage. The motor that provides the force to charge the closing spring is usually a low-power, single-phase, ac motor, although dc motors are available. This type of mechanism is typical of the earlier designs of bulk oil circuit breakers and a few designs of SF₆ single-pressure (puffer) from the 1980s. With the recent developments in SF₆ interrupter technology, spring mechanisms are now more widely used. The energy demand is lowered by these interrupter improvements. In addition, spring technology and materials have improved.

Pneumatic Mechanisms

A pneumatic mechanism uses compressed air for the energy source to close, and dependent on the type, open the circuit-breaker. The mechanism is supplied with air from an air receiver tank. This tank is the energy storage reservoir and is charged by the compressed air supplied from either a local air-compressor or from a substation (switchyard) centrally located compressed air system. The reservoir normally contains enough stored air to complete several successful close-open cycle operations. To close the circuit breaker, pressurized air is directed under the mechanism’s main piston by means of a closing control valve (which is solenoid operated). Dependent on the design, the circuit breaker may be opened pneumatically (air-blast and some SF₆ types) or by a spring that is charged during the closing operation (bulk oil types). Circuit breakers equipped with a pneumatic mechanism have the ability to open and close rapidly, resulting in interrupting times of 3 to 5 cycles for bulk oil types (depending on the circuit breaker type). Air-blast and SF₆ types are faster. Typical air system operating pressures range from those for mechanisms for bulk oil and two-pressure SF₆ circuit breakers that are at 1.03 to 2.76 MPa (150 to 400 psig), up to 3 MPa to 9 MPa (450 to 1200 psig) for the range of air-blast circuit breakers. Where used for the early designs of single-pressure SF₆ the operating pressure is typically from 2.0 to 3.0 MPa (300 to 450 psig). See Figure 2-2 for a simplified flow diagram.

Air-blast breaker operating mechanisms are an integral part of the breaker. Each manufacturer uses a design unique to the specific circuit-breaker type. There are two basic air-blast concepts, and the mechanism arrangement is different for both.

The early designs are used up to 300 kV and were installed into the early 1960s, mainly from European manufacturers. These designs have series interrupters mounted on insulating supports. These interrupters are forced open by a blast of high-pressure air from the air receiver via a blast valve. The blast-valve is housed between the air-receiver tank and the base of each support insulator. A pilot valve itself operated by the opening coil initiates the blast valve operation. When these interrupters are open a separate air-motor is operated to open a switch-arm that, when fully open, provides electrical isolation (although because it cannot be locked open it is not usually used as a disconnector {disconnect switch}). When this is complete the blast valve is shut off and the interrupters are returned to the closed position by small springs incorporated into each set of contacts. The circuit breaker is closed by operation of the switch-arm air-motor only. This drives the switch-arm closed and as the interrupters are already closed this action makes the electrical circuit. It is a rapid operation and the arm and contacts are capable of making the rated short-circuit current.

Later designs, those developed and installed from the early to mid-1960s until the late 1970s when the single pressure SF₆ designs became available, had a variety of interrupting techniques. Generally these operated by a mechanism moving a control rod system to operate a control valve mounted at each interrupter. On the larger 420 kV designs this could involve a single mechanism and 36 interrupters.

In more detail the later designs of air-blast circuit breaker operation is initiated by the energization of the appropriate open/trip or close coil. Energizing the trip coil pushes the pilot valve, which allows high-pressure air to activate the control valve. The control valve then lets the pressurized air move the actuating piston. In turn, the piston pulls or pushes the insulated operating rod (via a series of linkages, rods, and cranks) to operate the closing or opening valves in the interrupters.

A number of variations exist dependent on whether the air is used in the mechanism to move the control rods to close and open, or just close with the opening action being derived from a spring following de-latching of the control rods by a trip coil and pilot valve system.

Multiple operations are usually possible without recharging the local air system receiver (tank).

As can be seen the ways in which the interrupters are operated and the mechanism is used to close and/or open them are as varied as the circuit breakers themselves. It is interesting to note that not all air-blast circuit breakers used pneumatic mechanisms, one US manufacturer produced a limited number of air-blast breakers with a mechanism that utilized energy in a charged spring for the closing operation.

Hydraulic Mechanisms

Hydraulic mechanisms act in a manner that is similar to the later air-blast and other pneumatic designs. The circuit breaker is closed by the hydraulic system. On bulk oil and double-pressure SF₆ circuit breaker types the interrupters are usually opened by a spring. Where used on single-pressure SF₆, both closing and opening is by the hydraulic system. In all types the hydraulic system utilizes an energy store within an accumulator. Here the pressure on the hydraulic oil is maintained by compressing nitrogen to 20.7 to 34.5 MPa (3000 to 5000 psig) or by compressing a spring mounted behind a piston. On some designs the nitrogen is contained within a bag held within the accumulator (as illustrated in Figure 2-3), in others the accumulator is divided by a free-piston that separates the oil from the nitrogen. This piston is free to move with the changing pressure conditions within the accumulator. These mechanisms are capable of providing the circuit breaker with very short interrupting times. As with pneumatic mechanisms, sufficient energy can be stored to allow multiple open-close cycles without the pump running. See Figure 2-3 for a sample flow diagram.

Insulating Media

The insulating medium in a transmission circuit breaker can be oil, air, or SF₆ gas. All media types perform the functions of insulation and arc interruption.

Oil

General. The use of oil as an interrupter medium has been common since the first application of circuit breakers. During the early part of this century, oil breaker design was refined and, especially in North America, quickly became the dominant circuit breaker for many years. In Europe and elsewhere it was in competition with air-blast and later minimum oil designs.

The principle behind oil circuit breakers relies on the fact that an electric arc developed across contacts immersed in oil causes the oil to decompose and release hydrogen gas. Hydrogen is known to be an excellent arc-extinguishing medium and has excellent dielectric properties. In addition hydrogen rises rapidly drawing in fresh, cool, oil from the main tank into the arcing zone.

Excessive water or carbon content reduces the dielectric strength of oil. This degrades its interrupting ability, the general dielectric strength of the whole circuit breaker and causes corrosion of metallic components. Visual inspection of a sample of the oil can be used to assess excessive water or carbon content. When moisture and/or carbon contamination is identified, it must be recognized that this can lead to trouble by contaminating the internal insulating components such as lift rod, lift rod guide, interrupters, tank liners, and phase barriers. Excessive moisture in the oil alone tends to make samples look cloudy. Carbon darkens oil to the point where the oil actually turns black. The photograph in Figure 2-4 shows oil in various stages of carbon contamination. Test tube A is oil that has been filtered for both moisture and carbon. Tubes B and C show successive degrees of carbonization, with Tube D showing oil from a breaker that has interrupted one or two fault currents. For the most highly stressed designs an oil quality test may be more appropriate than a visual inspection.

Filtration. If a breaker operates a few times a year for switching (no faults or heavy load conditions), the oil should not contain enough carbon to warrant filtering. If, however, one or more faults are interrupted, the oil could become dark immediately (see Tube D) and filtering should be planned for an early date. Abnormal visible moisture indicates a problem. Even if the dielectric breakdown test is acceptable, free moisture indicates a failure of the weatherproofing of the circuit breaker. Where seal leaks exist they must be corrected. There are filter materials for removal of water and carbon. These materials must be used separately to effectively remove both carbon and water from circuit breaker oil.

Entry Bushing Oil. Of particular concern are the bushings of bulk oil circuit breakers, especially the free breathing barrier-board type. Poor maintenance of the breathing air-way and inadequate monitoring of the oil condition, may have enabled moist air, or in the extreme, water, ingress. This moisture reduces the dielectric strength of the barrier board insulation to the extent that electrical tracking can occur which can rapidly develop into complete failure of the insulation and hence the bushing. The early signs of such failure mechanisms can be detected by dissolved gas analysis (DGA) of the oil. Oil sampling of bushings is not straightforward as a sample is required from the bottom to ensure the possible presence of water is detected. An acceptable method is to use a long tube and a syringe, although extreme care is needed to ensure that other contamination is not introduced.

Compressed Air

Description. The compressed air used for operation, insulation and interruption in air-blast circuit breakers is dry air. The degree of this dryness, its relative humidity, is dependent on the design requirements of the circuit breaker and a number of measures are taken to achieve it.

In general the humidity requirements for the compressed air used for operation only, such as for bulk oil and two-pressure SF₆ types, is much lower and only simple measures are taken to achieve acceptable levels in these designs.

For air-blast circuit breakers of the earliest types, it is not normal that the air is specially dried. In these designs the natural drying achieved by compression is considered sufficient and the storage and usage pressures are chosen by the manufacturer to ensure the level is adequate. Typically a ratio of approximately 2:1 between storage and usage is adequate to prevent condensation at low ambient temperature as the high-pressure air is not used for insulation, only interruption. On these early designs a low-pressure conditioning-air circuit within the porcelain enclosures of the circuit breaker prevents condensation to retain dielectric strength and this air is much drier. This being achieved by the further drop in pressure giving a ratio of the order of 60:1.

For the later designs of air-blast circuit breakers the air is used as the insulation as well as the interrupting and operating medium. For these designs a much drier air is required. This is achieved in two stages, as before with a higher storage than usage pressure, but in addition, the high-pressure air is dried before storage. The stored air is itself at 3 to 6 times the operating pressure and the air in the circuit breaker is such that condensation does not occur when the ambient temperature falls to the lowest specified value, typical -25°C (-13°F) (but other service temperatures are specified).

Sulfur Hexafluoride (SF₆)

Description. Sulfur Hexafluoride (SF₆) is an excellent gaseous dielectric for high-voltage power application. In its normal state SF₆ is odorless, tasteless, nontoxic, non-corrosive, nonflammable, and chemically inert. SF₆ serves as an insulating and arc-extinguishing media. The dielectric strength of SF₆ is 2–3 times that of air (see Figure 2-1), and SF₆ has high thermal stability. These properties make it useful in gas-insulated buses and compartments that contain substation electrical components. In circuit breakers, its self-healing properties enable SF₆ to regenerate itself from the plasma present following arc interruption.

Unfortunately, SF₆ also has properties that impact on the environment. Reflecting its stable chemistry and efficient absorption of infrared energy at certain wavelengths, it is very long-lived in the upper atmosphere (estimated to be about 3200 years). SF₆ is considered the most potent of all known greenhouse gases, having a global warming potential 23,900 times greater, per molecule, than that of carbon dioxide. SF₆ was among six types of greenhouse gases targeted for emissions reductions at the 1997 Kyoto Summit. In October 1998, the U.S. Environmental Protection Agency began promoting voluntary emissions prevention agreements with industries that are the largest emitters of these gases [1, 2]. Some doubt regarding the extent to which this would be pursued was introduced in 2001 when the U.S. government failed to ratify the Kyoto documentation. It is understood, however, that the electrical supply industry in the United States, like those in the international community, have recognized the problem and have continued to aim at containing SF₆ and reducing losses. To this end EPRI has been active in supporting users by study, sponsorship and development work in this area.

The electric industry is the major user of SF₆ [1, 2].Over 50 electric utilities have signed Memoranda of Understanding with the US EPA under which they will [3, 4]:

• Voluntarily reduce their SF₆ emissions,

• Make a benchmark estimation of their SF₆ emissions,

• Complete an emission inventory each year,

• Come up with strategies for replacing old equipment that is at risk of leaking SF₆,

• Develop plans to recycle SF₆,

• Train their employees in the proper handling of SF₆-containing equipment, and

• Submit annual progress reports to the US EPA.

SF₆ as obtained from a commercial supplier should meet the present specification outlined in ASTM Standard D 2472 (or IEC 376-1971 as appropriate). Where re-cycled gas is to be used the quality levels identified by CIGRE 23.10.01 are considered acceptable by many users and are given here following some of the property requirements given in D 2472:

Sulfur Hexafluoride, minimum, wt %	99.8
Air, expressed as N2, maximum, wt %	0.05
Carbon tetrafluoride, maximum, wt %	0.05
Hydrolyzable fluorides, expressed as HF acidity, maximum, ppm by weight	0.3
Water content, maximum dew point, °C	-62
Corresponds to water content of 8.0 ppm by volume at 1.0135 X 105 Pa.

CIGRE Task Force 23.10.01 has developed the following standards for reuse of SF₆ gas [5].

The vapor pressure characteristics of SF₆ are such that at a temperature of below 10°C at a pressure of about 1.5 MPa (220 psig) the gas becomes a liquid. On the lower end of the vapor pressure curve the gas becomes a liquid at -29°C at 414 kPa (60 psig). This characteristic becomes an important consideration as the dielectric strength of the gas and its arc extinguishing density will be reduced as the gas liquefies. Circuit breakers operating at the higher pressure, and the early two-pressure types, have heaters to maintain SF₆ in a gaseous state. Typically circuit breakers without heaters have an SF₆ gas pressure of 0.7 MPa for a normal ambient temperature range of -25°C to +40°C (-13°F to +104°F).

SF₆ Leak Detection. Leak detection of SF₆ gas in electrical apparatus can be quite simple and straightforward. A refrigerator-type Freon detector can be used. This is a flameless unit that will detect leak rates as small as 1 pound (0.45 kilograms) per year. Many utilities, however, require a higher degree of detection and a variety of methods exist with the relevant degree of precision, ranging from laboratory style detectors to more robust purpose-made units designed for field use.

EPRI’s technology transfer efforts in the area of SF₆safety and handling also include laser camera technology for locating the source of gas leaks. EPRI worked with the manufacturer to enhance a prototype design and make it more suitable for substation use [2]. The camera is based on CO₂ laser back-scattering technology. It employs an infrared detector to identify leaks of SF₆ around equipment seals, joints, and bushings. It can even identify small casting voids in solid metal walls. Because SF₆ absorbs but does not emit infrared light, the laser can bounce precisely tuned infrared energy off equipment behind an SF₆ leak for detection by the camera. The leak appears as an inky black plume against a lighter background on a black-and-white video display. Leak detection is given further consideration later.

Contaminant	Main Origin	Deteriorating effect on	Maximum tolerable impurity levels in equipment	Impurity levels for reclaimed SF6 to be reused	Practical impurity detection levels
Air CF2	Handling Switching arcs	Switching Gas Insulation	3% vol	2% vol	< 1% vol
Humidity	Desorption from surfaces and from polymers	Surface insulation by liquid condensation	200 ppmv at 2 Mpa1 800 ppmv at 500 kPa1 4000mppmv at 100 kPa1	120 ppmv compressed to liquefaction2 320 ppmv at 500 kPa3 1600 ppmv at 100 kPa3	< 25 ppmv < 25 ppmv < 25 ppmv
SF4, WF6, SOF4 SOF2, SO2, HF, SO2F2	Arcing, Partial discharges Secondary reactions	Surface insulation Toxicity	100 ppmv 2000 ppmv	50 ppmv total7	< 10 ppmv total
CuF2, WO3, WO2F2, WOF4 AlF3	Contact erosion in switchgear Internal arcing	Toxicity	Non-crit5	No value5	Detection not practical
Carbon Metal dust/particles	Polymer carbonization Mechanical wear	Surface insulation Gas insulation	Low4	No value5	Detection not practical
Oil	Pumps and lubrication	Surface insulation	Low4	No value5	Detection not practical

1. Based on IEC 694, draft revision 1996.

2. Based on IEC 376 for new gas compressed to liquefaction at 0°C.

3. Only applicable if gas is reused at a pressure equal to or below specified reference pressure.

4. Cannot be quantified.

5. No value required, contaminant to be removed by dust filter of 1 μm pore size.

6. No value given, oil contamination has to be (and can be) avoided.

7. Or 12 ppmv SO₂ + SOF₂

Contamination. An SF₆ system has a high degree of reliability if the purity of the gas is maintained during installation, operation, and maintenance. SF₆ as received from the supplier is in a pure state and is practically free from contamination. However, in the factory some contamination may be introduced to the circuit breaker enclosure during the preparation of gas-filled components for shipment. To minimize contamination, SF₆ handling procedures, usually prepared by the manufacturer, must be followed, not only in the factory but also at site whenever access is necessary for installation and maintenance purposes.

There are five principal contaminants that must be identified and reduced or eliminated: all, not only conducting, particles, moisture, oil contamination, gaseous contamination, and arc-decomposition products.

Moisture in SF₆. Commercially available SF₆ gas has a very low moisture content, less than 40 parts per million by volume (ppmv). But unless the circuit breaker is thoroughly evacuated before filling with SF₆ gas, water molecules adhering to the solid surfaces inside the system will diffuse into the gas. A low level of moisture does not degrade the dielectric strength of the gas. However, at about 50% relative humidity, enough moisture is absorbed on the surface of the spacer insulators to decrease flashover voltage slightly. At over 90% relative humidity, a flashover across the surface of the insulators is almost certain to occur at operating voltage. Normally, gas-insulated systems are evacuated to about 26.7 Pa (0.2 mm Hg) before filling with SF₆, then checked for moisture content a few days thereafter. The likelihood of excessive moisture in SF₆ systems is very low. It should be recognized that the relative humidity will change with variations in temperature and pressure. The moisture content of the gas is higher in summer when ambient temperature is high, and lower in winter when more moisture adheres to solid surfaces. The acceptable moisture level is normally such that this moisture will become a frost rather than a liquid at the condensation temperature (frost-point).

Particles. Particles are a particular problem in metal-enclosed designs where the gas forms the insulating medium to earth in a highly stressed arrangement. Obviously any metallic and other clearly conducting particles are likely to cause problems where they contaminate solid insulation. Where such particles are in the form of light, long (25mm or 1 inch) slithers of materials such as aluminum then they can be lifted into the highly stressed gas gap by the electric field and cause a flash-over. This can also happen, more vigorously in fact, with similar sized plastic shavings, especially where they themselves have attracted some conducting dust.

SF₆ decomposition products. SF₆ is chemically inert up to 150°C and will not attack metals, plastics, and other substances commonly used in the construction of high-voltage circuit breaker components. However, at the high temperature caused by power arcs, it decomposes into various components, which are principally SF₄ and SF₂, together with small amounts of S₂, F₂, S, F, etc., which are in part corrosive to both glass and metals in the presence of moisture. The substances formed by the combination of such elements with vaporized metals appear as a whitish powder that has good insulating properties. The breaker contacts are designed with a wiping action to ensure self-cleaning of the contacts’ current-carrying surfaces.

Filters currently installed in most SF₆ breakers are aimed at reducing these by-products to undetectable levels in normal service. Upon internal faulting or failure caused by arcing or corona discharge, the filters cannot effectively absorb the large amounts of SF₆ decomposition products that are formed, and they reach abnormally high detectable levels. Under certain conditions, the decomposition products can be hazardous. Accordingly, all manufacturer safety procedures should be followed.

EPRI has developed a Practical Guide to SF₆ Handling Practices that is intended for use as a reference in formulating utility-specific policies that will improve SF₆ handling practices. Information in the guide can be adopted as-is or modified according to the circumstances of an individual utility. The contents are suggestions that should be used in conjunction with manufacturers’ recommendations, and where applicable, with national, state or provincial, and local regulations [2].

Disulfur decafluoride (S₂F₁₀) has been detected in SF₆ decomposed by power arcs. S₂F₁₀ is extremely toxic; although very unstable in most situations, it may exist and hence proper precautions should always be taken to avoid contact with arc products.

Trouble and Failure Mechanisms, and Life-Limiting Factors

Trouble and Failure Mechanisms

The following is an overall summary of trouble and failure mechanisms and what have been termed the life-limiting factors for circuit breakers of rated voltages from 63 kV. The trouble and failure modes given here in table form are a summary of those reported to CIGRE (International Conference on Large High-Tension Electric Systems) from two worldwide surveys [6, 7].

See Tables 2-2 through 2-5.

	Voltages (kV)
	63 to 100	100 to 200	200 to 300	300 to 500	Over 500
Total number reported	138	273	177	177	100
Mechanical problems	70.2%	62.6%	75.1%	77.1%	76.9%
Electrical problems (main circuit)	10.7%	14.7%	7.9%	6.2%	23.1%
Electrical (aux. and control circuit)	19.1%	22.7%	17.0%	16.7%	0.0%

	Voltages (kV)
	63 to 100	100 to 200	200 to 300	300 to 500	Over 500
Total number reported	138	437	257	283	116
Components at Service Voltage
Making/breaking units	9.5%	15.8%	15.0%	11.3%	14.7%
Auxiliary interrupters (making and breaking) and resistors	0.0%	2.3%	4.2%	6.7%	15.5%
Capacitors	0.0%	1.6%	1.9%	1.1%	4.3%
Control and main valves together with other operating mechanism components	2.9%	19.0%	25.0%	21.6%	28.4%
Terminals and connections between the above subassemblies	0.0%	2.1%	0.0%	1.8%	1.7%
Main insulation to earth (including pull rods and pipes, etc.)
Ceramic components	0.0%	3.7%	2.7%	3.5%	3.4%
Non-ceramic components	1.5%	3.0%	4.2%	2.5%	0.9%
Gas/liquid insulant	0.7%	0.7%	0.0%	0.7%	0.9%
Structure (earthed)
Gas/liquid tanks	0.0%	4.3%	3.1%	6.4%	8.6%
Frame/foundation	0.0%	0.5%	0.0%	0.4%	0.0%
Housings and covers	0.0%	0.0%	0.0%	1.1%	0.0%
Electrical Control and Auxiliary Circuits
Trip and closing coils, wiring, and terminals	6.6%	5.3%	6.9%	10.6%	1.7%
Auxiliary switches and associated drives	2.8%	4.3%	4.6%	1.8%	4.3%
Contactors, relays, heaters, thermostats, fuses, etc.	13.1%	6.6%	5.8%	5.6%	7.8%
Other switches	0.0%	1.6%	1.9%	2.5%	0.0%
Operating Mechanism (earthed)
Reclosers, actuating mechanisms toggles etc.	16.1%	3.7%	4.2%	6.0%	0.0%
Metallic operating rods, bell cranks and levers, etc.	11.9%	3.4%	2.7%	1.1%	1.7%
Control and main valves	11.9%	7.3%	9.6%	9.2%	3.4%
Auxiliary Plant
Compressors, motors, pumps	10.9%	5.9%	1.9%	0.7%	0.9%
Valves, gauges	2.9%	4.6%	2.7%	2.8%	1.8%
Pipe work, fittings	9.2%	4.3%	3.6%	2.6%	0.0%

	Voltages (kV)
	63 to 100	100 to 200	200 to 300	300 to 500	Over 500
Total number reported	408	561	351	266	16
Mechanical problems	88.2%	84.3%	83.6%	86.7%	90.0%
Electrical problems (main circuit)	2.4%	0.9%	4.1%	5.4%	0.0%
Electrical (aux. and control circuit)	9.4%	14.8%	12.3%	7.9%	10.0%

	Voltages (kV)
	63 to 100	100 to 200	200 to 300	300 to 500	Over 500
Number of answers	409	581	359	275	17
Components at Service Voltage
Making/breaking units	4.2%	7.5%	5.7%	11.7%	0.0%
Auxiliary interrupters (mak­ing and breaking) and resistors	0.2%	0.3%	1.1%	4.5%	0.0%
Capacitors	0.0%	3.4%	2.2%	2.7%	0.0%
Control and main valves to­gether with other operating mechanism components	1.2%	10.4%	7.9%	8.6%	16.7%
Terminals and connections between the above subassemblies	0.9%	0.7%	1.4%	1.4%	0.0%

Life-Limiting Factors

Trouble and failure modes can mainly be dealt with by the normal inspection and maintenance activity or by some limited enhancement of it. In this way a circuit breaker can be kept in service. These modes do not necessarily cause the end of life of the circuit breaker however, and in general the program of maintenance/overhaul activity is only sufficient to ensure that the circuit breaker achieves the commercial book life required by the user.

Where a strict book-life replacement policy is not to be followed and life extension is sought, the criteria for the end of life have to be established. To do this a definition is required. For some transmission assets the end of life is relatively easily determined, and hence predictable, as there are no, or few, sub-components to consider, e.g. bus-bars and conductors, or they are essentially static items, e.g. cables and capacitors. For the dynamic, multi-component switching-devices, a more complex definition of end-of-life is required. The most complex air-blast circuit breakers with 36 interrupters have in excess of 20,000 component parts, of which 1500 are moving (dynamic) and 2500 items are seals in various forms. In general it is a combination of individual failure modes occurring at an increasing rate or unexpectedly on such a combination of sub-components that renders the circuit breaker, or other switching-device, increasingly unreliable. This eventually becomes an unacceptable level of unreliability rather than total failure and is taken as the end of life for such complex items. The reason is clear in that for an item of transmission plant a ‘replace on failure’ strategy cannot be supported. As the device approaches this period these events cause increasing disruption to the system and a high resource cost for the repair and maintenance commitment to keep it in service. It is recognized that this end of life is not therefore a clear, single point in time. It is more a range of ages existing for all similar assets dependent on the historic and present usage, the exposure to the natural and industrial atmospheric conditions, the strengths and weaknesses of the original design and the level and quality of the present and historic maintenance activity. This range can be characterized for the family of the generic design-type from the earliest to the latest onset of significant unreliability. To be able to estimate when these ages are likely to occur requires some knowledge and understanding of the weaknesses and the condition of the assets. The Condition Assessment process gathers such information from inspections and maintenance, condition monitoring but also from basic generic knowledge of the design types and this latter consideration is developed in this guideline as the factors that limit the further use, the life-limiting-factors. These are documented in the Replacement/Refurbishment section of this document.

Specifics of Circuit Breaker Interruption

The four different types of circuit breakers are described in more detail in the following sections. Their air and gas systems are also detailed in a separate section:

• Oil Circuit Breakers (bulk and minimum/small oil volume)

• Air-Blast Circuit Breakers [both early and later (pressurized-head) designs]

• Sulfur Hexafluoride (SF₆) Two-Pressure Circuit Breakers

• Sulfur Hexafluoride (SF₆) Single-Pressure (Puffer) Circuit Breakers (including Auto-puffer or Self-blast)

• Air and SF₆ Gas Systems and their Associated Compressors

Oil Circuit Breakers - Description

Introduction

Historically, bulk oil circuit breakers have been commonly used at voltages up to 230 kV, and on some systems up to 345 kV. For lower ratings—up to 69 kV—oil circuit breakers often have all three phases housed in a single tank; the higher rated units described here have three tanks, a single tank for each pole (phase). See Figure 2-5. Minimum-oil (also termed small oil volume) circuit breakers have been used at voltages up to the higher levels of transmission voltages but as they do have some application limitations, which will be dealt with later, they are mainly applied to under 170 kV. They were extensively developed during the 1960s as an alternative to the bulk oil type, with its large oil volume, and the air-blast, with its need for expensive compressed air plant. They also competed with the then new technology of the two-pressure SF₆ types. Although widely used at 170 kV and below, many were found to be unreliable in service particularly when switching capacitive currents. Those designs in service that are sound have given good service and refurbishment programs exist.

Interrupter Functions

Bulk-oil. As with all circuit breakers, the interrupter is a critical part of the oil circuit breaker. The most common method of interruption used in oil circuit breakers, shown in Figure 2-6, is called by several names, e.g., crossblast or oil blast interrupter. In these designs the arc is drawn in front of a series of lateral vents often called the grid assembly. The heat of the arc vaporizes the oil in the assembly and the gases (mainly hydrogen) form a bubble that increases the pressure against the arc, finally forcing it to be blown into the grid vents.

When the pressure inside the interrupter becomes sufficiently high and the length of the arc is adequately extended at current zero, the arc is extinguished.

The arc is always confined inside a bubble of gas formed from the oil, and this bubble extends and expands through the grid vents and the surrounding shell vents to the outside of the two or more interrupter assemblies in each pole (phase). The hot gases emerging from the vents are initially still ionized. It is essential to ensure, by correct grid design, that dielectric breakdowns do not occur between the outer vents of the shell system external to the interrupter assemblies. Preventing dielectric breakdowns is particularly important for higher voltage interrupters where multiple series grid arrangements are used. It is equally important that the shell vents in the same pole (phase) tank face away from each other.

Please note that this figure includes a silica gel drier on the breaker tank vent. In some more damp and humid locations this drier has been found to help minimize moisture accumulation; however, for most applications this has not been necessary.

At the time the arc is being extinguished, fresh oil is drawn into the interrupter grid assembly to replace the arc-affected oil and thus cooling the arc zone and restoring the dielectric integrity of the system.

Minimum-oil (also termed small-oil volume). The principle of interruption is that of oil pump forcing clean oil into the interrupter to quench the arc. The used oil is retained within the interrupter zone limiting the number of the short-circuit clearances possible before oil maintenance/overhaul is required.

The arc is quenched in a similar manner to that of the bulk Oil design but here the cool oil is forced into the arcing chamber by a pumping action derived from the opening movement of the contact drive shaft.

The interrupter is housed inside a porcelain enclosure as a live tank design usually as a single vertical arrangement per pole (phase) on top of the mechanism and in some cases the supporting insulator column is replaced by a current transformer.

Air-Blast Circuit Breakers – Description

Introduction

Air-blast breakers were being developed in parallel with oil breakers, mainly in Europe during the 1940s and 1950s when oil was scarce. During the 1950s they were installed in many parts of the world in competition with the oil designs. There are two basic design types and for the purpose of this document they will be termed the early and the later, or pressurized-head, types.

It is the later design that formed the basis of many of the international grid systems of the mid 1960s when system voltages of 400 kV and higher and up to 4000A continuous current and 63 kA short circuit were required. Due to these ever-increasing power-system voltages, the physical size limitations of oil breakers, coupled with the large quantities of insulating oil that would be required at the higher voltages, the use of oil circuit breakers became unrealistic. Development of the existing air-blast technology was necessary. Ultimately these pressurized-head later design-types of air-blast circuit breakers ranged in voltage class from 115 to 800 kV and in interrupting rating from 40,000 to 80,000 amperes. These air-blast circuit breakers have extremely rapid interrupting times, typically opening the main contacts within 2 cycles (40ms at 50 Hz or 33.3 ms at 60 Hz) from trip initiation.

During opening operations, the early designs direct a blast of high-pressure air from a ground-mounted receiver-tank to an interrupter assembly mounted on support columns. These circuit breakers are of the ‘live tank’ type. The term “live tank” means that, with the breaker energized, the chambers containing the interrupting apparatus (the heads) will be at the potential of the system’s voltage. With the interrupters open, a separate switching arm is then rapidly opened and the interrupters re-close as the blast is shut off. The interrupters are not permanently pressurized.

Even though various designs exist the later, pressurized-head, air-blast circuit breakers are also of the “live-tank” type. On these design-types the high-pressure air is used for electrical insulation and arc extinguishing purposes, hence the term pressurized-head type.

Interruption

Early Design Types

As described above, a blast of high-pressure dry air is directed onto the interrupters. This high-pressure air is directed up a tube housed within the interrupter unit support column. It forces the interrupters open and quenches the arc at the appropriate current zero, simultaneously an air-motor is used to open a separate switch-arm to provide an open atmospheric air gap and enable the interrupters to be returned to the closed position when the air-blast is shut off. This switch-arm provides the open condition. To close the circuit breaker the air-motor is driven back to drive the switch-arm into the closed position and so make the circuit.

Later, Pressurized Head Type

These air-blast circuit breakers utilize dry air under pressure to quench the arc that is formed during an opening operation. This air is stored around the contacts within one of the numerous series heads that make up a pole (phase) of the circuit breaker. As the contacts separate and the current attempts to maintain its flow, an arc is formed. However, by design, the arc is directed in a designated course. With precision timing, a valve within the interrupting chamber opens, allowing some of the air contained within the breaker to exhaust to atmosphere directly through the path of the arc. At the opening of the blast valve, the interior of the breaker rapidly becomes somewhat depressurized. This depressurization results in a blast of air that cools the arc, forcing it away from the parting contacts and out the arc chutes or arcing tubes. The arc is eliminated by being elongated and cooled beyond its ability to maintain itself. With adequate dielectric strength between the open contacts, the exhaust valve is closed and the head re-pressurized from the local receiver.

On all air-blast circuit breakers, the interrupter heads are modular. Normally a particular interrupting head can be transferred from one position or breaker to another position or breaker if the current-carrying capacity, interrupting capability, and the accessory equipment are the same. The move could be successfully accomplished even if accessories are added, removed, or changed to meet the requirements of the new position, as long as the ratings are the same at both locations. Because of the modular design, all that is required of the manufacturer to increase the voltage of a particular type of breaker is to add the modular interrupter heads in series, within a phase, to give the breaker the desired capability. Of course, the insulation level from phase to ground has to be increased as well. Therefore, the height of the interrupter support columns and drive rods must be increased. The added height is required due to the basic insulation level necessitated by the increased voltage. Interrupter support columns are hollow ceramic insulators of high mechanical (as well as electrical) strength. The interrupter operating rods pass through the opening of the center of the support column. In some cases this contains high-pressure air, in others the high-pressure air is within a separate tube itself housed within the support column. The zone between the tube and the column is kept dry by a low pressure conditioning air system. In one manufacturer’s design, the space is filled with SF₆ gas, as electrical insulation. As an example of the difference in stack height, a typical 800-kV breaker reaches 12.5 meters (41 feet) feet from ground level to the top of the interrupter (and depending upon the version of the breaker, uses either four or five interrupters per phase). In contrast, a 138-kV breaker of the same type is less than 6 meters (20 feet) to the top (and has only one interrupter per phase, but of the same basic type as the 800-kV breaker).

Interrupter Types

There are two ways in which a blast of compressed air can be directed onto an arc: transversely (at right angles) to act as a crossblast, or longitudinally along the arc’s length as an axial blast. The crossblast method has generally been found to be unsuitable for high-power, high-voltage applications. Accordingly, all modern air-blast interrupters employ the axial blast principle by forcing the arc to burn on a line parallel with the axis of the contacts’ travel. On some designs the arc is initiated transversely before transferring to become axial prior to extinction. The later designs of the pressurized-head air-blast interrupters became extremely complex in order to achieve the high short-circuit interruption levels and rapid operating times. These are too complex to describe in detail and the principle is adequately explained by consideration of the simplest forms. In these there are two basic axial nozzle systems:

• A mono-blast or single-flow system in which the air subjects the arc to one single directional blast, and
• A duo-blast or double-flow system in which the air blast is divided equally through two nozzles. The blast flows into the arc chamber from opposite directions, and is exhausted through ports in line with the contact movement.

A variant of this system is the duo-blast system in which one nozzle orifice is made smaller than the other is. Figure 2-7 shows the mono-blast and the partial-duo-blast systems.

The mono-blast or partial-duo-blast systems are built into an insulating enclosure, which is supplied with compressed air. The air supply to the nozzles is controlled by a blast valve placed on the upstream side of the contacts, somewhere between the nozzle(s) and the supply source.

The exhaust passage(s) downstream are controlled by exhaust ports or valves. Each of these arrangements must admit compressed air to the nozzles while the exhaust passages are open and then shut off the air supply to prevent the pressure reservoirs from being exhausted. This minimum requirement can be met in all cases by blast valves placed in the duct leading to the nozzles as shown or across the electrodes just upstream from the nozzles. In the former case, one blast valve may be arranged to serve a number of interrupters at the same time and the interrupter chambers are pressurized outside the interrupter. In the latter case, one blast valve can serve only one interrupter and the interrupter chambers are permanently pressurized up to the Valve.

Where the interrupters are pressurized in the open position only, both the blast valves and the exhaust valves are used. The former admit the air to the nozzles, the latter stop the flow and keep the interrupter pressurized. One blast valve may again supply more than one interrupter at a time and one exhaust valve may be arranged to control two adjacent exhaust passages in a twin interrupter unit. Where the interrupter chambers are permanently pressurized (i.e., in closed and open positions), exhaust valves are used. The exhaust valves are used either on their own or in combination with blast valves placed across the electrodes. One exhaust valve may again serve two interrupters, but separate blast valves must, in this case, be provided for each interrupter.

In so far as nozzle systems and pressurization are concerned, air-blast interrupters can be divided into nine types, i.e., mono- or partial-duo- or duo-blast, each pressurized in one of the three ways:

• During interruption only
• During interruption and in the open position
• Permanently

Two other terms, axial flow and radial flow, are sometimes used in descriptions or classification of air-blast interrupters. Axial flow usually refers to interrupter constructions where, due to an arrangement of the upstream passages, the predominant direction of the air flow approaching the nozzles is parallel to the axis of the interrupter as in Figure 2-7, Detail A. Radial flow usually refers to constructions where most of the air tends to approach the nozzles centripetally as between the duo-blast electrodes in Figure 2-7, Detail B, or as would be the case if the mono-blast electrodes in Figure 2-7, Detail A, were placed in the center of an air receiver. Neither of these terms invalidates the axial-blast principle.

In circuit breakers that have both high-pressure air and SF₆ gas separated by gaskets, there can be a leakage of high-pressure air into the SF₆ gas space. The high-pressure air contains far greater amounts of moisture than the SF₆ gas spaces are intended to contain. Therefore, leakage of air into these spaces can set up the potential for a catastrophic failure. In some designs such leaks are from seals that are difficult to replace under normal maintenance. In such cases this leaking seal may be considered in the later section on Condition Assessment as a life-limiting-factor because it can be expected to involve major dismantling to correct the seal, the disruption and cost may indicate that replacement is more sensible.

Further, with any air-blast circuit breaker, moist air entry into dry air chambers will degrade the insulating quality and arc quenching capability. Wet air can cause flashovers, restrikes, or a slow deterioration of insulated parts within the circuit breaker. If slow deterioration occurs and plastics are involved, there may be corrosive gases formed that will attack copper, aluminum, or silver-plated surfaces. This corrosion can include contacts, valves, seating surfaces, and all interior parts.

Auxiliary Interrupter Components

Accessories utilized for an interrupter also are dependent upon the voltage at which the breaker is designed to operate, as well as the individual usage of the breaker. Following are descriptions of interrupter accessories that may or may not be part of a breaker, depending upon its application.

Grading Capacitors and Resistors

Grading capacitors can be used in parallel with the interrupter contacts to provide nearly uniform voltage distribution of all contacts within a phase. This grading effect prevents the contacts nearest the end or outside of a phase from being subjected to the majority of the duty while the innermost contacts see a reduced amount of burden. Each manufacturer’s capacitor design is different, some are inside the interrupter chamber and some are bolted on externally. Normally, capacitors used internally have relatively low voltage withstand. These internal capacitors should not be exposed to extended periods of energization with the breaker’s main contacts open and with potential across the capacitor. When open, the circuit breaker’s associated disconnect–switches (disconnector) should be opened to protect the capacitors. Grading capacitors designed for mounting external to the interrupter often have greater electrical strength; opening the disconnects (disconnectors) may not be a requirement for capacitor protection.

On a breaker with several interrupters per phase, the capacitor values may differ dependent on the design. It is important that proper interrupter assembly includes an ordered placement of capacitors. Normally, higher capacitance values are placed on the outside ends of the interrupter breaks of a phase, decreasing in value toward the center of the phase. Improper capacitor association may cause trouble and ultimately could cause failure of the circuit breaker.

Grading resistors are usually only found on the earlier designs of air-blast circuit breaker. They are very high value and act in the same way as grading capacitors by sharing the voltage across the series interrupters of the circuit breaker to make it as near equal across each gap as possible. These resistors also cause a phase shift easing the opening duty for the switch arc contacts.

These resistors should not be confused with the opening (tripping) resistors used on the later designs of air-blast (pressurized-head) circuit breakers.

Opening Resistors

Opening resistors, or tripping resistors, are used to distribute the voltage during interruptions of high short-circuit current and to dampen oscillations created by a breaking operation under the specific short line fault condition. The resistor-switches that insert and remove the resistors are timed to open their contacts a few milliseconds after the main contacts have parted. They are usually re-closed with, or just before, the main contacts during a closing operation, although a few designs close them early during the opening (tripping) operation. The value of these opening resistors is chosen to match the surge impedance of the line construction.

Closing Resistors

Closing resistors are normally utilized on breakers associated with long transmission lines. The resistors are used to dampen the over voltage transients that occur when energizing long, unloaded transmission lines. The closing resistors are inserted just prior to main contact closure and the value is chosen to match the line length and construction. They may also be rated to withstand auto-reclose operation.

Mufflers (Silencers)

During the 1970s it became necessary for manufacturers to develop sound mufflers (silencers) to lessen the audible impact of the air blast. Depending upon the circuit breaker configuration, one or more mufflers (silencers) are added to an interrupter in order to reduce the operational noise to reasonable level.

Current Transformers

Current transformers (CTs) associated with air-blast circuit breakers are, like the breakers themselves, quite varied in design. CTs are used for relaying purposes and some contain a winding with metering sensitivity. Many CTs are free standing and are not integral to the circuit breaker. Current transformers are located at the end of an interrupter head or string of interrupter heads, and normally one is required for each phase. There are also circuit breakers that have multiple current transformers per phase. The early air-blast designs integrated the CT into the design as the outgoing post-support for the switch-arm of the design-type.

Freestanding current transformers can be utilized at any air-blast breaker location. Current transformers of different manufacturers or types can be mixed on different phases of the same breaker if properly applied. Many freestanding current transformers are filled with insulating oil. Ceramic porcelain is used as chambers to contain the oil and to pass the primary leads through. However, some are filled with SF₆ gas and may utilize a composite application of plastics and silicone for the material to house the SF₆ gas insulation. Where these devices were integral with the circuit breaker they used the porcelain SF₆ chamber as an interrupter support column, as well as the chamber through which the primary leads passed. Because these CTs are part of the circuit breaker, they do not lend themselves well to relocation and they complicate the refurbish/replace debate.

Sulfur Hexafluoride (SF₆) Two-Pressure Breakers - Description

Introduction

The first double-pressure SF₆ circuit breakers were developed in the United States and use the structural concepts of bulk oil breakers.

Interruption Process and Mechanism

The following describes dead-tank and live-tank breakers and auxiliary interrupter components.

“Dead Tank” Breakers

In this type of breaker the extinguishing chambers and the contacts of each phase are housed in an earthed (grounded) steel, or later aluminum, tank. These circuit breakers are called “dead-tank” breakers because the tank is at earth (ground) potential. Completely sealed and self-contained unit construction has been adopted for all SF₆ circuit breakers. The seal between the different sections uses ethylene-propylene-rubber (EPR) gaskets and PTFE (Teflon) (the arc-resistant synthetic insulating material poly tetra fluor-ethylene) rings. Arcing does not significantly reduce the dielectric and arc-quenching properties of SF₆. Contact designs have been developed that can be subjected to repeated arc interruptions equivalent to many years of service. Over 30 years of service experience has shown that hermetically sealed SF₆ circuit-breakers need not be opened for inspection and maintenance except at long intervals, in the order of 10 to 15 years for these two-pressure designs.

The contacts are immersed for insulation purposes in an atmosphere of SF₆ at a pressure of approximately 0.2 MPa (30 psig). The bushing internal conductors are insulated from the steel tank enclosure by the same insulating atmosphere. Contacts are constructed to minimize erosion due to arcing on the portions of the contacts that conduct current in the closed position of the breaker. The current is directed through the sidewalls of the fixed contact and into a set of fingers, which are part of the moving contact. An arcing horn, located within the finger cluster, projects a short distance beyond the end of the fingers and into a cavity in the end of the moving contact. On opening, the arc quickly transfers from the end of the finger cluster to the centrally located arcing horns and to the end of the moving contact. Both contacts have surfaces that are faced with arc-resistant material.

The interrupting function is performed by a high-velocity flow of SF₆ through a PTFE (Teflon) ring in an orifice or nozzle located inside the arc-extinguishing chamber. (See Figure 2-8) The gas is maintained at approximately 1.5 MPa (220 psig) within a high-pressure reservoir during normal operation. At the start of contact movement in an opening operation, the blast valve opens under control of a pilot valve and allows high-pressure gas to flow through an insulating tube to the interrupting orifice, thereby extinguishing the arc as the moving contact moves to the open position. As the contact linkage reaches the open position, the pilot valve closes the main blast valve and conserves gas pressure for the next operation.

After each interruption, a compressor system pumps the low-pressure gas from the circuit breaker tanks to the high-pressure reservoir via a filter containing activated alumina. Because the gas liquefies at approximately 10°C at 1.6 MPa (235 psig), a heating arrangement is provided around the high-pressure reservoir to keep its temperature above this point.

Capacitor assemblies provide uniform distribution of voltage across each of the breaks. Electrostatic shields around the metal portions of the assembly maintain control of the electric field between the interrupter and the tank.

In these breakers, the contacts are actuated mechanically by a pneumatic operating mechanism, that drives a mechanical linkage and bell crank drives mounted one each pole (phase) tank. These bell crank drives are the mechanical link with the contact mechanism, and they also operate the gas blast valves. Compression-type accelerating springs, mounted close to the contacts, drive the breaker to the open position and are latched by a roller trip system in the operating mechanism.

“Live Tank” Breakers

A live-tank breaker is one in which the tank or interruption chamber is at line potential. The same principle of interruption applies to live-tank circuit breakers. In these breakers, contacts are actuated mechanically by a pneumatic operating mechanism, fitted on each pole, that drives a mechanical linkage and bell crank drives mounted at the top of the columns. These bell crank drives are the mechanical link with the contact mechanism, and they also operate the gas blast valves. Compression-type accelerating springs, mounted close to the contacts, drive the breaker to the open position and are latched by a roller trip system in the operating mechanism.

The interrupting units and the hollow porcelain columns are filled with SF₆ at a pressure of approximately 200 kPa (30 psig), constituting the low-pressure system. A high-pressure reservoir operating at approximately 1.5 MPa (220 psig) is accommodated in the breaker chassis at ground potential and is connected via high-pressure pipe run through the hollow column to a receiver tank located in the distribution head.

The blast valves, which are mounted in the upper receiver tanks, are opened when the breaker is tripped. The high-pressure SF₆ then flows at a high velocity through short pipes to the interrupter nozzles and into the low-pressure chambers. A compressor located in the breaker chassis pumps the gas back to the high-pressure reservoir through filters containing activated alumina. The reservoir is heated to keep the gas temperature above 10°C in ambient temperatures as low as -35°C. The modular construction facilitates the use of the same interrupting unit with higher voltage breakers. A good example of this principle is represented by the circuit breakers built in the United States for 3- and 2-cycle interruption for 335 GVA at 500 kV with three double-break units supported by three porcelain columns. The tank forming the central section of the modular unit is part of the low-pressure system, is pressurized at approximately 0.3 MPa (45 psig), and provides gas storage in close proximity to the interrupters. The cross-arm is hollow, forming the gas passage to the two interrupting gaps, and surrounds a section of the blast valve containing high-pressure gas. When the blast valve is opened, it discharges SF₆ radially outward directly through the hollow cross arm to the contacts and interrupting chambers so that the pressure drop is smaller overall.

A switching system is used to damp current surges. The system closes a contact during closing and inserts a resistor during the final part of the closing stroke. During the opening movement, the resistor circuit is opened throughout the cycle.

The blast valve opens rapidly and remains open until the contacts approach the fully open position. The blast valve does not operate during a closing operation.

Gas released by the blast valve flows into an insulating chamber in which the arc is drawn. The gas blasts sweep the arc away from the fingers where they are initiated and into the interior of the vent passages. The gas is then discharged into the surrounding chamber, which is the principal container for the low-pressure gas. The fine dust particles formed from the materials vaporized by the arc are also deposited in this chamber. A fine metallic filter at the top of the vertical porcelain column confines the dust to the modular unit.

Filled with low-pressure gas, the support column acts as a part of the low-pressure reservoir in addition to the tube through which the SF₆ gas, at low pressure, returns to ground potential. The column also contains and protects the vertical operating rod and an insulating tube, which conducts high-pressure gas from the large reservoir at ground potential to the smaller reservoir in the modular unit.

The high-pressure reservoir is equipped with heaters and with thermal insulation, and thermostats on the bottom of each tank control the heaters of the three reservoirs. As the thermostats respond to temperatures of both the tank and of any condensate existing in it, they are set to turn on the heaters at a temperature somewhat higher than that at which condensate is formed.

An interrupting time of 2 to 3 cycles can be obtained with a pneumatic operating mechanism using a high-speed latching device, arranged to reduce the inertia of the parts that must be moved during the tripping operation and equipped with flux diverting trip gear.

The arcing time ranges from 5–10 ms at full breaking current, with arc lengths of 15–50 mm.

Auxiliary Interrupter Components

Closing resistor. A preinsertion resistor is sometimes provided (depending on manufacturer and type) across each break for reducing switching surge voltage and is driven by the blast valve simultaneously with the moving contacts. The mechanism is provided to insert the closing resistor prior to breaker contact closing. The mechanism disengages the resistor when the breaker is in the closed position so that the resistor is not in the circuit during the breaker opening.

Voltage grading capacitors. Shunt capacitors are sometimes provided across each break for proper voltage division purposes, but also for line side transient recovery voltage (TRV) control for the short-line fault condition.

Line-to-ground capacitors. Line-to-ground capacitors are sometimes connected between line side terminals and earth (ground) to control the transient or recovery voltage.

On feeder breakers both these capacitors are usually needed on the line side only. The source side may have no capacitors. On tie-breakers both sides may have line-to-ground capacitors.

Sulfur Hexafluoride (SF₆) Single-Pressure (Puffer) Breakers - Description

Introduction

The SF₆ serves as both an interrupter and insulating medium in this class of circuit breaker, generally referred to as “single-pressure” breakers because the SF₆ in the breaker remains at a constant pressure—usually in the 0.4- to 0.7-MPa (60- to 100-psig) range. During the opening operation, the gas contained in the interrupter chamber is compressed by a moving cylinder or piston, forcing the SF₆ through the interrupting nozzle to quench the arc. This impulse or sudden gas flow across the arc space is the reason for the names “impulse” and “puffer.” These names were originally used in the United States for forced-blast oil circuit breakers and for early SF₆ breakers of low- or moderate-interrupting capacity at low-voltage levels.

Single-pressure SF₆ circuit breakers are designed for a much higher range of voltage and current service than the two-pressure designs, as high as 800 kV and 4000 amperes. Puffer circuit breakers have an interrupting rating up to 63 kA, although some SF₆ puffer circuit breakers have been supplied for 80 kA. It can be expected that higher ratings will soon be required for some systems and further developments in this and linked SF₆ technology are likely to provide the solutions.

The puffer circuit breakers are manufactured in both dead-tank and live-tank design. At voltages up to 300 kV, both the dead-tank and live tank circuit breakers have just one interrupter contained within a tank on each phase, while those produced for 300 kV in the late 1970s had two interrupters per phase. For the higher voltages and currents the number of interrupters per pole (phase) has reduced dramatically during the twenty years from 1980 to 2000 with a typical 400 kV 63 kA circuit breaker reducing from six to four to two and now a single gap. At up to 170 kV interrupters may also be clustered, so that all three poles (phases) are contained within one single tank, the interrupters being separated by insulation.

The live-tank breakers have been designed in a “T” or “Y” module configuration, similar to the live-tank dual-pressure breaker, or in a “candlestick” configuration, with the interrupters mounted within a vertical, insulated interrupter chamber on a single support column. In all cases, as with the metal-enclosed dead-tank designs, the number of interrupters per pole (phase) has reduced from four to two for the highest voltages and currents. The single gap live tank is limited in rating because of the size requirements, particularly external creepage length, of the porcelain or composite enclosure for one gap.

Puffer Interrupters

A simplified diagram of one of the two basic design concepts of a puffer interrupter is shown in Figure 2-9, the other is shown in Figure 2-10. In both of these basic concepts the puffer interrupter is designed with a stationary piston within a moveable cylinder that is attached to, and moves with, the moveable contacts (Figure 2-9 and 2-10, Detail A). As the moveable contacts are driven at high speed toward the open position, the gas within the compressible portion of the piston/cylinder arrangement is pressurized (Figure 2-9 and 2-10, Detail B).

In the most commonly applied design, that of Figure 2-9, the main current-carrying contacts separate first, while the arcing contacts are still engaged. Then, as the mechanism drives the breaker further toward the open position, the arcing contacts part, forming an arc (Figure 2-9, Detail C). This arc is contained within a specially designed arcing nozzle (which is non-metallic and relatively heat resistant), typically PTFE (Teflon).

The gas is compressed as the contacts move toward the open position because the volume between the piston and cylinder is diminished. When the arcing contacts begin to separate, the gas is released and forced across the parting contacts at high velocity. The arc, still confined within the nozzle, is cooled by the gas flow. As the current in the circuit reaches current zero, and when the contacts have traveled a sufficient distance to provide the post interruption dielectric strength to withstand the transient recovery voltage (TRV), arc extinction takes place (Figure 2-9, Detail D).

In the other basic design form, that shown in Figure 2-10, a set of contacts bridges a gap between two fixed contacts when in the closed position. At this time the puffer cylinder is around all of these contacts. As the interrupter opens the contacts, together with the cylinder, slide along the fixed out-board and in-board contact tubes in the direction of the fixed piston. At contact separation, the gas within the cylinder has been compressed by the reduced volume as the cylinder moves against the piston, and is forced through the opening developing between the moving contacts and one of the out-board fixed contact(s). The flow of gas is initially into the center of the fixed contacts. With further movement the cylinder volume continues to decrease and the gas flow encourages the arc to root between both fixed contacts, in the flow of gas, until extinction at the appropriate current zero.

Self-Blast (Also Termed Auto-Puffer) Design Types

A relatively new development in puffer circuit breaker interrupter design is the self-blast, auto-puffer or self-generated pressure interrupter. These types of interrupters were, at first, primarily used on lower voltages; however, design changes have resulted in their being used at 69 kV and higher. In the early versions the arc initially generated forms an envelope that expands and thereby extinguishes the arc between the main contacts. See Figure 2-11.

In the latest designs the puffer cylinder is in two parts with a one-way valve system set in the dividing plate between them. With a large short-circuit current arc the pressure rise within the first section is sufficient to close the valves. This and the rising pressure as the energy in the current cycle rises to a peak increases the pressure further, providing a higher pressure gas flow as the arc column then reduces towards zero. When the short-circuit current is small or a load is being switched, the valve system stays open by spring pressure and the interrupter operates as a normal puffer type using the full volume of the cylinder at a lower pressure. See Figure 2-12.

Auxiliary Interrupter Components

Capacitors. On multi-gap circuit breakers capacitors may be required in parallel with the interrupter contacts to provide nearly uniform voltage distribution across all contacts within a pole (phase). This grading prevents the contacts nearest the end, or outside, of a phase from being subjected to the majority of the duty while the innermost contacts see a reduced amount of burden. Grading capacitors are used on both dead- and live-tank designs. Each manufacturer’s capacitor design is unique, some being used internally to the interrupter, and some designed to be connected externally.

Historically capacitors used internally had a rather low voltage withstand although present designs are equally as highly stressed as externally mounted ones. For all grading capacitors it is now considered sensible to limit the exposure to extended periods of energization with the circuit breaker’s main contacts open and with system or near system voltage across the capacitor. In this condition, the circuit breaker’s disconnects (disconnectors) should be opened to protect the capacitors. As capacitor failures have occurred this is a safety issue governed by judgment.

Grading capacitors are also used to assist the circuit breaker to interrupter the higher levels of short-circuit current, especially for controlling the transient recovery voltage (TRV) during the short-line fault condition.

Opening Resistors. Opening resistors are not used with these interrupters.

Closing Resistors. Closing resistors are normally utilized on breakers associated with long transmission lines. The resistors are used to dampen the voltage surges, or “spikes,” that occur when energizing long, unloaded transmission lines. The closing resistors are preinserted just prior to main contact closure. Again, the timing of the resistor switches, although short in duration, is very important to the proper functioning of the interrupter and, therefore, to the circuit breaker. The value of the resistors is dependent on the line length and construction and will also be influenced by any requirement for auto-reclosure of the line. In this a second duty is inflicted on the resistor before the heating effects of the first have fully dissipated.

Air and Gas Systems - Description

Introduction

This section describes the various compressed air systems and the associated compressors used on all types of circuit breaker used at transmission voltage levels, together with the basic SF₆ gas system of the two-pressure type and the associated gas compressor. It does not cover the mobile nitrogen compressors used for filling the pre-charge energy storage of some designs of hydraulic mechanism nor the mobile SF₆ gas compressors used with the single pressure SF₆ circuit breakers. It covers both the small dedicated air and SF₆ gas systems mounted at or on the individual circuit breakers and the central facilities consisting of a whole substation/switchyard installation capable of supplying the air needs for air, oil or SF₆ circuit breakers or their mechanisms across the site.

This section may repeat details given elsewhere.

Air and Gas System

For Air-Blast Circuit Breakers

For these circuit breakers the air is used for operation, interruption and insulation purposes. The air used for interruption and insulation within the circuit breaker must contain only a relatively small amount of moisture, because of the requirement of the breaker to maintain proper dielectric strength. The dielectric strength of the air is necessary to prevent flashover between areas of differing voltage potential, whether during normal in-service use, or during any system switching requirements.

Compression of air from atmospheric pressure is a natural method of moisture removal, as air under compression freely gives up its water molecules. The greater the amount of compression, the more moisture removed. The typical operating pressures of the early, non-pressurized designs were of the order of 2.5 MPa (360psig) whilst the later pressurized-head designs operate at up to 8.0 MPa (1200 psig). The air for all air-blast circuit breakers is compressed to a pressure higher the operating pressure and stored either locally at the circuit breaker or in a central location for the whole substation. The air storage pressure for both basic air-blast types ranges from 4 MPa (600 psig) to 21 MPa (3000 psig) and higher. Most earlier air-blast breakers depended solely upon compression for moisture removal, but even under this compression pressure moisture remained requiring draining from the storage where it condensed on cooling. This air is suitable for the early designs where the air is used for interruption from a blast valve mounted in the base receiver/tank. Air for insulation is at a much reduced pressure of the order of 0.1 MPa (15 psig) and hence much dryer.

Moist air could not be permitted to enter the interrupting portions of the later pressurized-head circuit breakers as in this case the compressed air is the insulating medium to earth (ground) and between the open contacts. In order for more complete moisture removal, dryers were developed. Earlier dryers passed the compressed air through a drying agent of silica gel that, after accepting the allotted amount of moisture, could be regenerated by heating the dryer and back flowing previously dried air at a very low flow rate. Later dryers utilized a molecular sieve as a drying agent, which did not require heat; only the backflow of dry air was required to complete the regeneration process. These dryers were normally installed between the compressors and the air-storage tanks (receivers). The storage air is then required to be reduced to the pressure at which the breaker operates. Each design has its particular requirements. Some operate at pressures in excess of 3.5 MPa (500 psig), some as low as 2.5 MPa (360 psig). The pressure reduction takes place in one or two stages, again depending on the manufacturer’s design.

Mechanisms for Bulk Oil, Two-Pressure and Single-Pressure SF₆ Circuit Breakers

For operating mechanisms the quality of the air is less important and need only be dry enough to prevent internal corrosion of the various valve components and more importantly to prevent frost damage during winter operations.

In the basic arrangement these air systems are often no more than a compressor mounted at or on the individual circuit breakers with a local air receiver (tank) to store sufficient air for the number of multiple operations specified and for the size and consumption of the circuit breaker mechanism.

Other systems employ air compressors at a central substation location usually two or three with a greater delivery capability (depending upon the needs of the user), situated in a location accessible enough to supply all the breakers in a particular substation yard. These central systems are normally contained within a house, either an existing house modified for that purpose or within a house specifically designed for that purpose.

There is also the hybrid system, which has one or more banks of two compressors, each of which supplies a small number of circuit breakers. These compressors are not normally contained within a house but are often in weatherproof cabinets. The decision to use one system over the others is governed by the philosophy of the power system’s management.

SF₆ Gas Systems

The SF₆ gas system has two functions. First, it provides the dielectric strength that is necessary to prevent flashovers between areas of differing voltage potential, whether during normal in-service use, or during any system switching requirements or other system disturbance. Second, it is used to interrupt the arc that occurs during opening operations. The SF₆ within the circuit breaker must contain only a minimal amount of moisture, because of the requirement of the breaker to maintain proper dielectric strength. In most breakers the SF₆ gas system consists of a filter system that removes moisture, oil, gaseous and solid arc decomposition products. A compressor is used to charge the high-pressure system. Various devices are used for adjusting and maintaining proper gas pressure, pressure alarms and gauges, and heaters. Contamination by air will reduce the dielectric and arc-quenching capabilities of the gas and will also introduce oxygen, which may promote oxidization degradation.

Because of the environmental concerns (Kyoto 1997 etc.) associated with the release of SF₆ to the atmosphere, all practical efforts to avoid any unnecessary releases should be made. During maintenance, recycling of the SF₆ gas should be performed. Today, virtually all utilities with SF₆-insulated equipment use a movable recycling cart with a pump, transfer hoses, and a large tank that temporarily holds the gas while equipment repairs are made. This increasingly common practice, which EPRI has helped to promote through workshops and training for utility personnel, is believed to have cut utility SF₆ emissions in half just by itself [1].

Alternatively, a small recovery plant can be used to extract and store the gas for transport to an off-site re-cycling installation. New or re-cycled gas is used for re-filling. Information on handling SF₆-containing equipment can be found in Practical Guide to SF₆ Handling Practices (EPRI, 2002) [2].

The main cause for concern about the gas system in SF₆ breakers is leakage of gas to atmosphere. Problems caused by unrepaired leakage are as follows:

• Moisture entry into the breaker. Moisture-laden, atmospheric air is drawn in as the pressurized SF₆ leaks out.
• System integrity. Continued SF₆ leakage will eventually affect the availability of the breaker, requiring unplanned maintenance to be performed, sometimes at the worst possible times, and many times at great cost.
• Environmental effect. SF₆ is considered the most potent of all known greenhouse gases, having a global warming potential 23,900 times greater, per molecule, than that of carbon dioxide [1].

Air and Gas Compressors

The air compressor systems for air-blast circuit breakers offer an array of differing types and styles. As stated above, some breakers were sold with an air compressor as part of the circuit breaker package, that is, one compressor for each circuit breaker. For these the maintenance activity is closely linked to that of the circuit breaker. For the centrally located large compressors a pattern of maintenance is linked to the needs of the individual machine and is generally not linked to the restrictions of power-system access.

For the many types of circuit breaker using pneumatic mechanisms, and the air-blast types, the compressor is one of the most important components to be considered for circuit breaker maintenance, but also for consideration during life estimation and the refurbish/replace debate linked to life extension. Most compressors require a dedicated maintenance regime in order to ensure a reliable air system and hence reliable circuit breaker operation. Generally, as with other plant, compressors should be maintained as recommended by the compressor manufacturer, keeping in mind that the duty requirements and the ambient environment will have an effect on the frequency of that maintenance and system access may be a restriction.

Air leaks in the associated valves, piping, pressure switches, and gauges are an occasional problem and should be corrected as soon as possible after detection. If not repaired, the leaks could cause excessive compressor run time, and hence additional maintenance, but more importantly an excessive leak on an air system on a circuit breaker could possibly lead to the failure of the breaker to close or open correctly when required. At the very least leaks on these local systems may force the need for an additional maintenance power-system access to repair it, depending on its location.

Two-pressure SF₆ circuit breakers generally have two compressors, one for the SF₆ system and one for the operating mechanism’s compressed air system. The SF₆ compressor works in a closed loop. It is designed to take its input from the low pressure SF₆ of the circuit breaker main tank, re-compress it after filtration and deliver it to the high-pressure storage tank of the circuit breaker.

References

1. Moore, Taylor. 1999. Seeing SF₆ in a New Light. EPRI Journal (Summer): 26-31.
2. Practical Guide to SF₆ Handling Practices. 2002. Palo Alto, CA: EPRI. TR-1001945.
3. Utilities, EPA Agree on Voluntary Program to Cut Emissions of Sulfur Hexafluoride. 1999. Daily Environmental Reporter (15 April): AA-1-2.
4. SF₆ Emissions Reduction Partnership for Electric Power Systems – List of Partners (July 23, 1999). [US EPA on-line], accessed on 21 December 1999; available from http://www.epa.gov/appdstar/body_SF₆.html; Internet.
5. CIGRE Task Force 23.10.01. SF₆ Recycling Guide: Re-Use of SF₆ Gas in Electrical Power Equipment and Final Disposal Guide.
6. CIGRE. 1981. Study and Conclusions from the Results of the Enquiry on Insulators: Information on Damages. CIGRE Electra 79 (December): 21–91.
7. Mazza, G., and R. Michaca. 1981. The First International Enquiry on Circuit Breaker Failures and Defects in Service. CIGRE Electra 79 (December). Report covers defects in service observed during the period 1974–1977.

1.1.3 - Chapter 3 - Circuit Breaker Diagnostic testing

Introduction

This draft chapter describes and explains a series of diagnostic tests for circuit breakers. Diagnostic testing was selected as the first chapter to be written on the basis of input from EPRI members who identified a pressing need for better information and guidance on the efficacy of different diagnostic tests.

Tests Inlcuded

To develop the foundation for this chapter, in 2014 descriptions of six established diagnostic tests were adapted from Effectiveness Assessment of Circuit Breaker Diagnostics: Characterization of Established Diagnostic Tests and Simulator Development. EPRI, Palo Alto, CA: 2014. 3002004007.

In 2015, this material was extensively revised to enhance clarity and accuracy, and new information was added to explain how test results are interpreted. In addition, descriptions of six non-established diagnostic tests were added to the chapter.

Established Diagnostic Tests

1. Timing

2. Travel and Velocity

3. Static Contact Resistance Measurement

4. Power Factor

5. Hi-Pot Testing

6. Oil Dielectric Breakdown

7. Dissolved Gas in Oil Analysis

8. Moisture in Oil Analysis

9. SF₆ Gas Analysis Tests

   • SF₆ Gas Moisture Content
   • SF₆ Gas Purity
   • SF₆ Gas By-product Analysis

Non-established Diagnostic Tests

10. First Trip
11. Dynamic Contact Resistance Measurement
12. Detection of Acoustic Emissions from Partial Discharge
13. Vibration
14. Radiography (X-ray) of Contacts
15. Particles and Metals in Oil Analysis

Test Characterization

For each test, the following questions are answered and, where appropriate, examples are provided:

• What is the test?

• What are the test’s objectives?

• What does the test check/test/measure/evaluate?

• What are the test’s limitations?

• When does the test need to be performed?

• Which type of circuit breakers is the test used on?

• How is the test performed?

• How are the test results interpreted?

1. Timing

What is the test? The timing test measures the operating times of various components of the circuit breaker during open, close, close-open and open-close operations.

What are the test’s objectives? The objectives of the timing test are to assist in making an assessment of the performance and condition of the operating mechanism in the circuit breaker. The various measured operating times are compared to the circuit breaker manufacturer’s specifications to see if the circuit breaker is performing correctly. The operating times are also compared to previous test results from the same circuit breaker to determine if the measurements are remaining constant or changing significantly. It is not unusual for timing test results to vary slightly from test to test or between poles. In general, circuit breaker timing test results are acceptable if they are within the manufacturer’s upper and lower limits. If the timing measurements are not within the circuit breaker manufacturer’s specifications, corrective action may be needed. For example, a marked increase in the operating times may indicate a worn or binding mechanism or a possible lack of mechanism lubrication.

What does the test check/test/measure/evaluate? The timing test measures the times that the main contacts and resistor switch contacts (when they exist) of the circuit breaker take to operate during open (trip), close, close-open (trip-free) and open-close (reclose) operations. These times can be measured in milliseconds or in cycles (based upon 60 cycles per second). Also, some timing test sets record the waveforms of the trip circuit current and the close circuit current. The definitions of these measurements are listed below:

Main Contact Opening Time – With the circuit breaker starting in the closed position, this is the time from open (trip) command initiation until the main contact being measured first parts. Normally, each main contact in the circuit breaker is measured at the same time for this test. If there is one main contact per phase on the circuit breaker, one measurement will be made per phase and all three measurements will be made during the test. If there are two main contacts in series per phase and the mid-point between the two main contacts is accessible for testing, two measurements will be made per phase and all six measurements will be made during the test. If there are three main contacts in series per phase and the points between the main contacts are accessible for testing, three measurements will be made per phase and all nine measurements will be made during the test. This process can be continued up to circuit breakers with 6 or more main contacts in series per phase.

Main Contact Opening Time Synchronization in Module – For circuit breakers with main contacts contained in two or more tanks, sometimes called “heads” on live-tank circuit breakers, in series per phase with each tank containing two series main contacts with the mid-point accessible for testing, this is the measurement of the difference in time, sometimes called the “delta”, from the fastest main contact opening time in that tank or module to the slowest main contact opening time in that tank or module.

Main Contact Opening Time Synchronization in Phase – For circuit breakers with two or more main contacts in series per phase, this is the measurement of the difference in time, sometimes called the “delta”, from the fastest main contact opening time on that phase to the slowest main contact opening time on that phase.

Main Contact Opening Time Synchronization in Breaker – This is the measurement of the difference in time, sometimes called the “delta”, from the fastest main contact opening time of all the main contacts in the circuit breaker to the slowest main contact opening time of all the main contacts in the circuit breaker.

Main Contact Opening Time of Breaker – With the circuit breaker starting in the closed position, this is the time from open (trip) command initiation until the main contacts on all poles of the circuit breaker have parted.

Main Contact Closing Time – With the circuit breaker starting in the open position, this is the time from close command initiation until the main contact being measured first touches. Normally, each main contact in the circuit breaker is measured at the same time for this test. If there is one main contact per phase on the circuit breaker, one measurement will be made per phase and all three measurements will be made during the test. If there are two main contacts in series per phase and the mid-point between the two main contacts is accessible for testing, two measurements will be made per phase and all six measurements will be made during the test. If there are three main contacts in series per phase and the points between the main contacts are accessible for testing, three measurements will be made per phase and all nine measurements will be made during the test. This process can be continued up to circuit breakers with 6 or more main contacts in series per phase.

Main Contact Closing Time Synchronization in Module – For circuit breakers with main contacts contained in two or more tanks, sometimes called “heads” on live-tank circuit breakers, in series per phase with each tank containing two series main contacts with the mid-point accessible for testing, this is the measurement of the difference in time, sometimes called the “delta”, from the fastest main contact closing time in that tank or module to the slowest main contact closing time in that tank or module.

Main Contact Closing Time Synchronization in Phase – For circuit breakers with two or more main contacts in series per phase, this is the measurement of the difference in time, sometimes called the “delta”, from the fastest main contact closing time on that phase to the slowest main contact closing time on that phase.

Main Contact Closing Time Synchronization in Breaker – This is the measurement of the difference in time, sometimes called the “delta”, from the fastest main contact closing time of all the main contacts in the circuit breaker to the slowest main contact closing time of all the main contacts in the circuit breaker.

Main Contact Closing Time of Breaker – With the circuit breaker starting in the open position, this is the time from close command initiation until all the main contacts in the circuit breaker have touched and established metallic continuity.

Close-Open (Trip-Free) Dwell Time (also Close-Open (Trip-Free) Dwell Time in Breaker) – This is the measurement of the difference in time from when the fastest main contact of all the main contacts in the circuit breaker first touches on the closing operation until the slowest main contact of all the main contacts in the circuit breaker first parts on the opening operation.

Close-Open (Trip-Free) Dwell Time in Phase – For circuit breakers with two or more main contacts in series per phase, this is the measurement of the difference in time from when the fastest main contact on that phase first touches on the closing operation until the slowest main contact on that phase first parts on the opening operation.

Close-Open (Trip-Free) Dwell Time in Module – For circuit breakers with main contacts contained in two or more tanks, sometimes called “heads” on live-tank circuit breakers, in series per phase with each tank containing two series main contacts with the mid-point accessible for testing, this is the measurement of the difference in time from when the fastest main contact in that tank or module first touches on the closing operation until the slowest main contact in that tank or module first parts on the opening operation.

Open-Close (Reclose) Time (also Open-Close (Reclose) Time in Breaker) – This is the measurement of the difference in time from when the slowest main contact of all the main contacts in the circuit breaker first parts on the opening operation until the fastest main contact of all the main contacts in the circuit breaker first touches on the closing operation.

Open-Close (Reclose) Time in Phase – For circuit breakers with two or more main contacts in series per phase, this is the measurement of the difference in time from when the slowest main contact on that phase first parts on the opening operation until the fastest main contact on that phase first touches on the closing operation.

Open-Close (Reclose) Time in Module – For circuit breakers with main contacts contained in two or more tanks, sometimes called “heads” on live-tank circuit breakers, in series per phase with each tank containing two series main contacts with the mid-point accessible for testing, this is the measurement of the difference in time from when the slowest main contact in that tank or module first parts on the opening operation until the fastest main contact in that tank or module first touches on the closing operation.

Resistor Switch Contact Opening Time Relative to Test Initiation – With the circuit breaker starting in the closed position, this is the time from open (trip) command initiation until the resistor switch contact being measured first parts. Normally, each resistor switch contact in the circuit breaker is measured at the same time for this test. If there is one resistor switch contact per phase on the circuit breaker, one measurement will be made per phase and all three measurements will be made during the test. If there are two resistor switch contacts in series per phase and the mid-point between the two resistor switch contacts is accessible for testing, two measurements will be made per phase and all six measurements will be made during the test. If there are three resistor switch contacts in series per phase and the points between the resistor switch contacts are accessible for testing, three measurements will be made per phase and all nine measurements will be made during the test. This process can be continued up to circuit breakers with 6 or more resistor switch contacts in series per phase.

Resistor Switch Contact Opening Time Relative to Test Initiation Synchronization in Module – For circuit breakers with resistor switch contacts contained in two or more tanks, sometimes called “heads” on live-tank circuit breakers, in series per phase with each tank containing two series resistor switch contacts with the mid-point accessible for testing, this is the measurement of the difference in time, sometimes called the “delta”, from the fastest resistor switch contact opening time relative to test initiation in that tank or module to the slowest resistor switch contact opening time relative to test initiation in that tank or module.

Resistor Switch Contact Opening Time Relative to Test Initiation Synchronization in Phase – For circuit breakers with two or more resistor switch contacts in series per phase, this is the measurement of the difference in time, sometimes called the “delta”, from the fastest resistor switch contact opening time relative to test initiation on that phase to the slowest resistor switch contact opening time relative to test initiation on that phase.

Resistor Switch Contact Opening Time Relative to Test Initiation Synchronization in Breaker – This is the measurement of the difference in time, sometimes called the “delta”, from the fastest resistor switch contact opening time relative to test initiation of all the resistor switch contacts in the circuit breaker to the slowest resistor switch contact opening time relative to test initiation of all the resistor switch contacts in the circuit breaker.

Resistor Switch Contact Closing Time Relative to Test Initiation – With the circuit breaker starting in the open position, this is the time from close command initiation until the resistor switch contact being measured first touches. Normally, each resistor switch contact in the circuit breaker is measured at the same time for this test. If there is one resistor switch contact per phase on the circuit breaker, one measurement will be made per phase and all three measurements will be made during the test. If there are two resistor switch contacts in series per phase and the mid-point between the two resistor switch contacts is accessible for testing, two measurements will be made per phase and all six measurements will be made during the test. If there are three resistor switch contacts in series per phase and the points between the resistor switch contacts are accessible for testing, three measurements will be made per phase and all nine measurements will be made during the test. This process can be continued up to circuit breakers with 6 or more resistor switch contacts in series per phase.

Resistor Switch Contact Closing Time Relative to Test Initiation Synchronization in Module – For circuit breakers with resistor switch contacts contained in two or more tanks, sometimes called “heads” on live-tank circuit breakers, in series per phase with each tank containing two series resistor switch contacts with the mid-point accessible for testing, this is the measurement of the difference in time, sometimes called the “delta”, from the fastest resistor switch contact closing time relative to test initiation in that tank or module to the slowest resistor switch contact closing time relative to test initiation in that tank or module.

Resistor Switch Contact Closing Time Relative to Test Initiation Synchronization in Phase – For circuit breakers with two or more resistor switch contacts in series per phase, this is the measurement of the difference in time, sometimes called the “delta”, from the fastest resistor switch contact closing time relative to test initiation on that phase to the slowest resistor switch contact closing time relative to test initiation on that phase.

Resistor Switch Contact Closing Time Relative to Test Initiation Synchronization in Breaker – This is the measurement of the difference in time, sometimes called the “delta”, from the fastest resistor switch contact closing time relative to test initiation of all the resistor switch contacts in the circuit breaker to the slowest resistor switch contact closing time relative to test initiation of all the resistor switch contacts in the circuit breaker.

Resistor Switch Contact Opening Time Relative to Main Contact – With the circuit breaker starting in the closed position, this is the time from when the main contact associated with the resistor switch contact being measured first parts until the resistor switch contact being measured first parts. Normally, each resistor switch contact in the circuit breaker is measured at the same time for this test. If there is one resistor switch contact per phase on the circuit breaker, one measurement will be made per phase and all three measurements will be made during the test. If there are two resistor switch contacts in series per phase and the mid-point between the two resistor switch contacts is accessible for testing, two measurements will be made per phase and all six measurements will be made during the test. If there are three resistor switch contacts in series per phase and the points between the resistor switch contacts are accessible for testing, three measurements will be made per phase and all nine measurements will be made during the test. This process can be continued up to circuit breakers with 6 or more resistor switch contacts in series per phase.

Resistor Switch Contact Opening Time Relative to Main Contact Synchronization in Module – For circuit breakers with resistor switch contacts contained in two or more tanks, sometimes called “heads” on live-tank circuit breakers, in series per phase with each tank containing two series resistor switch contacts with the mid-point accessible for testing, this is the measurement of the difference in time, sometimes called the “delta”, from the fastest resistor switch contact opening time relative to main contact in that tank or module to the slowest resistor switch contact opening time relative to main contact in that tank or module.

Resistor Switch Contact Opening Time Relative to Main Contact Synchronization in Phase – For circuit breakers with two or more resistor switch contacts in series per phase, this is the measurement of the difference in time, sometimes called the “delta”, from the fastest resistor switch contact opening time relative to main contact on that phase to the slowest resistor switch contact opening time relative to main contact on that phase.

Resistor Switch Contact Opening Time Relative to Main Contact Synchronization in Breaker – This is the measurement of the difference in time, sometimes called the “delta”, from the fastest resistor switch contact opening time relative to main contact of all the resistor switch contacts in the circuit breaker to the slowest resistor switch contact opening time relative to main contact of all the resistor switch contacts in the circuit breaker.

Resistor Switch Contact Closing Time Relative to Main Contact – With the circuit breaker starting in the open position, this is the time from when the main contact associated with the resistor switch contact being measured first touches until the resistor switch contact being measured first touches. Normally, each resistor switch contact in the circuit breaker is measured at the same time for this test. If there is one resistor switch contact per phase on the circuit breaker, one measurement will be made per phase and all three measurements will be made during the test. If there are two resistor switch contacts in series per phase and the mid-point between the two resistor switch contacts is accessible for testing, two measurements will be made per phase and all six measurements will be made during the test. If there are three resistor switch contacts in series per phase and the points between the resistor switch contacts are accessible for testing, three measurements will be made per phase and all nine measurements will be made during the test. This process can be continued up to circuit breakers with 6 or more resistor switch contacts in series per phase.

Resistor Switch Contact Closing Time Relative to Main Contact Synchronization in Module – For circuit breakers with resistor switch contacts contained in two or more tanks, sometimes called “heads” on live-tank circuit breakers, in series per phase with each tank containing two series resistor switch contacts with the mid-point accessible for testing, this is the measurement of the difference in time, sometimes called the “delta”, from the fastest resistor switch contact closing time relative to main contact in that tank or module to the slowest resistor switch contact closing time relative to main contact in that tank or module.

Resistor Switch Contact Closing Time Relative to Main Contact Synchronization in Phase – For circuit breakers with two or more resistor switch contacts in series per phase, this is the measurement of the difference in time, sometimes called the “delta”, from the fastest resistor switch contact closing time relative to main contact on that phase to the slowest resistor switch contact closing time relative to main contact on that phase.

Resistor Switch Contact Closing Time Relative to Main Contact Synchronization in Breaker – This is the measurement of the difference in time, sometimes called the “delta”, from the fastest resistor switch contact closing time relative to main contact of all the resistor switch contacts in the circuit breaker to the slowest resistor switch contact closing time relative to main contact of all the resistor switch contacts in the circuit breaker.

Trip Circuit Maximum Current – This is the maximum dc control current measured in the trip circuit. The Trip Circuit Schematic for the circuit breaker should be referenced to see how it is configured. On most circuit breakers, the trip circuit consists of just the circuit breaker’s single trip coil. In this case, the trip circuit maximum current measurement is the trip coil’s maximum current. On circuit breakers with one trip coil per phase, the three trip coils will either be configured all three trip coils in series or all three trip coils in parallel. For the case where all three trip coils are configured in series, the trip circuit maximum current measurement is equal to the maximum current of the trip coil series circuit. For the case where all three trip coils are configured in parallel, the trip circuit maximum current measurement is equal to the sum of each trip coil’s maximum current. If the resistance of each of the three parallel trip coils is the same, the maximum current of each trip coil is equal to one third of the trip circuit maximum current measurement.

Close Circuit Maximum Current – This is the maximum dc control current measured in the close circuit. The Close Circuit Schematic for the circuit breaker should be referenced to see how it is configured. On most circuit breakers, the close circuit consists of a 52X relay to energize the close coil(s), the close coil(s) themselves and a 52Y anti-pumping relay. Normally, the Close Circuit Maximum Current is a measurement of the currents in the 52X and 52Y relays and not the current in the close coil(s). This is due to the 52X relay contacts shorting out the close current measurement channel of the test set when it picks up to energize the close coil(s). The Close Circuit Schematic needs to be carefully reviewed to see if this is the case.

Main Contact Bounce – This is the multiple opening and closing of the circuit breaker’s main contacts observed on the main contact’s open/closed recording trace. This is most commonly seen during a closing operation but may be present during an opening operation. This can be caused by misaligned or damaged moving and/or stationary main contacts.

Resistor Switch Contact Bounce – This is the multiple opening and closing of the circuit breaker’s resistor switch contacts observed on the main contact’s/resistor switch contact’s open/closed recording trace. This is commonly seen during a closing operation but may be present during an opening operation. This can be caused by small imperfections in the surfaces of the resistor switch contacts.

What are the test’s limitations? This test requires the breaker to be taken out on clearance for several hours and knowledge of the detailed breaker control wiring configuration. The clearance procedure usually involves operating the breaker, which will exclude finding most lubrication problems associated with the speed of operation (see First Trip test). While this test is effective in measuring the operating times of the circuit breaker, it is limited in information to explain possible causes of operating times that are outside of the manufacturer’s specifications or various problems with arc suppression components. Additional testing with other test methods will be necessary for a more complete analysis. For example, possible slow operating velocity or mechanism binding can be determined with travel and velocity measurements. Also, different test equipment manufacturers have different resistance values and debounce times to determine when the circuit breaker contacts are open or closed. This can result in inconsistent timing test results and detection of contact bounce between different model test sets. This test does not measure the breaker load interrupting time which ANSI/IEEE C37.04-1999, clause 5.6, defines “rated interrupting time” as “the maximum permissible interval between the energizing of the trip circuit at rated control voltage and rated operating pressure for mechanical operation, and the interruption of the current in the main circuit in all poles.”

When does the test need to be performed? This test needs to be performed upon the initial commissioning of the circuit breaker to verify that it conforms to the manufacturer’s specifications and to collect baseline test data. This test may include obtaining measurements at minimum control voltage with normal mechanism energy and at normal control voltage with minimum mechanism energy in addition to the measurements at normal control voltage with normal mechanism energy. The manufacturer’s instruction manual should be consulted to see if these additional tests are available. Future test data can be compared to the commissioning test data to see if any deviations have occurred and if any corrective actions may be required. These future tests may be regular periodic maintenance tests, service duty triggered maintenance tests, protective relay slow speed alarms, SCADA algorithms and/ or special investigative tests which may be required due to a misoperation, an in-service failure or a perceived problem of the circuit breaker. Also, tests should be performed after any work is performed on the mechanism, interrupters or any other component of the circuit breaker which may affect timing. The regular periodic maintenance tests are normally performed at fixed time intervals that have been selected by the owner and/or operator of the circuit breaker. These fixed time intervals are not standardized across the industry and can vary from 2 years to 10 years or more. Many factors go into the selection of the fixed time interval chosen for each circuit breaker. Condition based triggers may supplement the time-based triggers to help factor the breaker exposed service conditions. These factors are explained in more detail elsewhere in this guidebook.

Which type of circuit breakers is the test used on? This test is used on all types of circuit breakers including air, oil, SF₆ gas and vacuum breakers.

How is the test performed? This test is performed with the circuit breaker de-energized and out of service (off-line). Normally, all external high voltage connections are left connected to the circuit breaker during the test. Grounds are connected to one side of the circuit breaker to drain off any static charge from effecting the timing measurements, damaging the inputs to the field timing test set, and for personal safety. Current transformers in use on the circuit breaker are left connected to their protective relays and meters. Unused current transformers should have their secondaries shorted and grounded. The dielectric medium in the circuit breaker needs to be at proper levels. On oil circuit breakers, the oil level in each tank needs to be within the limits on the oil level gauge. On SF₆ gas circuit breakers, the SF₆ gas pressure in each tank needs to be within the limits specified by the manufacturer. These limits are normally shown on the circuit breaker’s nameplate. Surface moisture on the bushings has very little effect on timing measurements therefore the test can be performed in humid or wet weather conditions if necessary. The top terminals of the bushings should also be inspected and cleaned to insure a good connection point for the test equipment leads. The circuit breaker manufacturer’s instruction manual should be consulted for the limits for the various timing measurements and for any special requirements for performing the timing test.

The following are the general steps required to measure the timing of a circuit breaker. A test sequence of close, reclose, trip, trip-free is commonly used for these measurements. A minimum of three complete sequences is recommended to check for consistency in the various operating times. Also, if the circuit breaker has two trip coils, three additional sequences should be performed using the second trip coil. The control voltage should be at normal levels for these tests. The manufacturer’s instructions should always be consulted for the specific operating requirements of each field test set.

1. Properly identify the circuit breaker on which the test is to be performed. This is done by locating the circuit breaker with the correct manufacturer’s name, manufacturer’s serial number and owner’s equipment identification (ID) number in the substation. If a permanent owner’s equipment identification (ID) number label is absent, the three-line drawing of the substation can be referenced to determine the location of the circuit breaker. A temporary label can be attached to the circuit breaker for use during the test. It should be replaced with a permanent label as soon as practical.

2. Check that the circuit breaker has been properly removed from service, lock out and tag out procedures have been followed and the circuit breaker is safe to work on.

3. Install grounds on the external high voltage leads to Bushing Numbers 1, 3 and 5 (reference Figure 3-1 Circuit Breaker Bushing and Pole Numbering Convention for Timing Measurements).

4. Properly identify which primary phase is connected to each pole of the circuit breaker. It is a best practice to permanently label the primary phase marking on the tanks, stands or enclosures of each circuit breaker when it is commissioned. If these permanent primary phase markings are absent, the three-line drawing or phasing drawing of the substation can be referenced to determine which primary phase is connected to which pole of the circuit breaker. Temporary labels can be attached to the circuit breaker for use during the test. These should be replaced with permanent labels as soon as practical.

5. Note: The following assumptions have been made for this test plan: Phase A is connected to Pole 1, Phase B is connected to Pole 2 and Phase C is connected to Pole 3.

6. Connect the ground lead from the timing set to the substation ground connection to the circuit breaker.

7. For timing sets with two test leads marked to measure the timing of Phase A, connect one test lead to the top of Bushing Number 1 and the second test lead to the top of Bushing Number 2. Note: For timing sets with on test lead per phase and one common test lead, install the common lead to the top of Bushing Number 4 and attach jumpers from the top of Bushing Number 4 to the top of Bushing Numbers 2 and 6.

8. For timing sets with two test leads marked to measure the timing of Phase B, connect one test lead to the top of Bushing Number 3 and the second test lead to the top of Bushing Number 4.

9. For timing sets with two test leads marked to measure the timing of Phase C, connect one test lead to the top of Bushing Number 5 and the second test lead to the top of Bushing Number 6.

10. The timing set will have two test leads marked for the Open (or Trip) Command. Connect these two test leads across the trip contact on the Trip Pushbutton or Trip Control Switch at the circuit breaker. If these test leads are polarity sensitive, check that the (+) test lead is connected to the (+) side of the trip contact and the (-) test lead is connected to the (-) side. Note: If there are two trip coils on the circuit breaker, connect these leads to Trip Coil Number 1 for the first series of tests.

11. The timing set will have two test leads marked for the Close Command. Connect these two test leads across the close contact on the Close Pushbutton or Close Control Switch at the circuit breaker. If these test leads are polarity sensitive, check that the (+) test lead is connected to the (+) side of the close contact and the (-) test lead is connected to the (-) side.

12. Check that the circuit breaker is in the open position.

13. Turn on the timing set.

14. If the timing set can store circuit breaker nameplate information and manufacturer’s timing specifications, enter them into the test set and save them.

15. Perform a Close Operation. Record the closing times of each phase or save them in the timing test set.

16. Perform a Reclose Operation. Record the reclosing times of each phase or save them in the timing test set.

17. Perform a Trip Operation. Record the tripping times of each phase or save them in the timing test set.

18. Perform a Trip-Free Operation. Record the trip-free dwell time of the circuit breaker or save it in the timing test set.

19. Repeat Steps 15-18 a minimum of two more times.

20. Turn off the timing set.

21. If the circuit breaker has only one trip coil, proceed to Step 27. If the circuit breaker has two trip coils, remove the two Open (or Trip) Command test leads from the Trip Coil Number 1 circuit and reconnect them to the Trip Coil Number 2 circuit. If these test leads are polarity sensitive, check that the (+) test lead is connected to the (+) side of the trip contact and the (-) test lead is connected to the (-) side.

22. Check that the circuit breaker is in the open position.

23. Turn on the timing set.

24. Retrieve the circuit breaker data entered in Step 14 above.

25. Repeat Steps 15-19 but record that the measurements are for Trip Coil Number 2.

26. Turn off the timing set.

27. Remove all the timing set’s test leads from the circuit breaker.

28. Leave the circuit breaker in the same position (open or closed) that it was found before these tests.

How are the test results interpreted? The test results are reviewed one set of measurements at a time. A circuit breaker needs to pass each individual set of measurements for it to pass the entire timing test. For a circuit breaker with one contact per phase, one trip coil and without closing resistors, the individual measurements to be reviewed are:

1. Main Contact Opening Time
2. Main Contact Opening Time Synchronization in Breaker
3. Main Contact Closing Time
4. Main Contact Closing Time Synchronization in Breaker
5. Close-Open (Trip-Free) Dwell Time (also Close-Open (Trip-Free) Dwell Time in Breaker)
6. Open-Close (Reclose) Time (also Open-Close (Reclose) Time in Breaker)
7. Trip Circuit Maximum Current
8. Close Circuit Maximum Current
9. Main Contact Bounce

The Main Contact Opening Times from the three trip tests are compared to each other one phase at a time. Usually, the test results of a given phase will be very close to each other. They also should be within the manufacturer’s limits which are usually found in the circuit breaker’s instruction manual. Next, the test results of the individual phases are compared to each other one test at a time. Usually, one of the phases will repeatedly have the fastest Main Contact Opening Time and another phase will repeatedly have the slowest time. Subtract the test result of the slowest phase from the test result of the fastest phase to obtain the Main Contact Opening Time Synchronization in Breaker. The values from each of the three tests should be very close to each other and within the manufacturer’s limits in the instruction manual. Table 3-1 shows an example of trip timing test results that are within manufacturer’s limits.

Test ID	Phase A Opening Time (msec.)	Phase B Opening Time (msec.)	Phase C Opening Time (msec.)	Manufacturer’s Opening Time Limits (msec.)	Opening Time Synch. in Breaker (msec.)	Manufacturer’s Opening Time Synch. in Breaker Limit (max.) (msec.)
Trip 1	26.2	26.1	27.0	17.0-30.0	0.9	2.7
Trip 2	26.3	26.3	27.1	17.0-30.0	0.8	2.7
Trip 3	26.0	26.1	26.8	17.0-30.0	0.8	2.7
Trip Average	26.2	26.2	27.0	17.0-30.0	0.8	2.7

The Main Contact Closing Times from the three close tests are compared to each other one phase at a time. Usually, the test results of a given phase will be very close to each other. They also should be within the manufacturer’s limits which are usually found in the circuit breaker’s instruction manual. Next, the test results of the individual phases are compared to each other one test at a time. Usually, one of the phases will repeatedly have the fastest Main Contact Closing Time and another phase will repeatedly have the slowest time. Subtract the test result of the slowest phase from the test result of the fastest phase to obtain the Main Contact Closing Time Synchronization in Breaker. The values from each of the three tests should be very close to each other and within the manufacturer’s limits in the instruction manual. Table 3-2 shows an example of close timing test results that are within manufacturer’s limits.

Test ID	Phase A Closing Time (msec.)	Phase B Closing Time (msec.)	Phase C Closing Time (msec.)	Manufacturer’s Closing Time Limits (msec.)	Closing Time Synch. in Breaker (msec.)	Manufacturer’s Closing Time Synch. in Breaker Limit (max.) (msec.)
Close 1	74.4	73.6	73.9	60.0-95.0	0.8	2.7
Close 2	74.3	73.8	73.6	60.0-95.0	0.7	2.7
Close 3	74.6	74.0	73.8	60.0-95.0	0.8	2.7
Close Average	74.4	73.8	73.8	60.0-95.0	0.6	2.7

The Close-Open (Trip-Free) Dwell Times from the three trip-free tests are compared to each other. The values from each of the three tests should be very close to each other and within the manufacturer’s limits in the instruction manual. Some test sets measure only the Close-Open (Trip-Free) Dwell Time in the breaker. Other test sets also measure the Close-Open (Trip-Free) Dwell Time of each of the three phases. Table 3-3 shows an example of trip-free timing test results that are within manufacturer’s limits.

Test ID	Phase A Trip-Free Dwell Time (msec.)	Phase B Trip-Free Dwell Time (msec.)	Phase C Trip-Free Dwell Time (msec.)	Manufacturer’s Phase Trip-Free Dwell Time Limits (msec.)	Trip-Free Dwell Time in Breaker (msec.)	Manufacturer’s Trip-Free Dwell Time in Breaker Limits (msec.)
Trip-Free 1	20.2	21.1	21.7	20.0-38.0	21.8	20.0-38.0
Trip-Free 2	20.2	20.8	21.8	20.0-38.0	21.8	20.0-38.0
Trip-Free 3	20.1	21.8	22.1	20.0-38.0	22.5	20.0-38.0
Trip-Free Average	20.2	21.2	21.9	20.0-38.0	22.0	20.0-38.0

The Open-Close (Reclose) Times from the three reclose tests are compared to each other. The values from each of the three tests should be very close to each other and within the manufacturer’s limits in the instruction manual. Some test sets measure only the Open-Close (Reclose) Time in the breaker. Other test sets also measure the Open-Close (Reclose) Time of each of the three phases. Table 3-4 shows an example of reclose timing test results that are within manufacturer’s limits.

Test ID	Phase A Reclose Time (msec.)	Phase B Reclose Time (msec.)	Phase C Reclose Time (msec.)	Manufacturer’s Phase Reclose Time Limit (min.) (msec.)	Reclose Time in Breaker (msec.)	Manufacturer’s Reclose Time in Breaker Limit (min.) (msec.)
Reclose 1	348.3	346.8	347.0	300.0	346.8	300.0
Reclose 2	348.4	347.0	346.7	300.0	347.0	300.0
Reclose 3	348.3	346.9	346.9	300.0	346.9	300.0
Reclose Average	348.3	346.9	346.9	300.0	346.9	300.0

All circuit breaker timing test equipment from basic timers to advanced breaker analyzers provide the above timing measurements. If the circuit breaker timing test set being used measures Trip Circuit Maximum Current, the values from each of the three trip tests should be compared. Usually, they will be very close to each other. The same holds true to the Close Circuit Maximum Current values from the three close tests. They usually will be very close to each other as well. Manufacturer’s limits are not normally given for these values.

Main Contact Bounce can only be determined if the circuit breaker timing test set being used has the feature of displaying the open/closed recording trace of each of the main contacts during each of the tests. Normally, each of the main contacts will transition from open to closed in a clean step function. If one of the recording traces shows a main contact closing then opening briefly and then closing again, a Main Contact Bounce on closing is being observed. The same holds true on opening. Normally, each of the main contacts will transition from closed to open in a clean step function. If one of the recording traces shows a main contact opening then closing briefly and then opening again, a Main Contact Bounce on opening is being observed.

After the above measurements have been reviewed for this series of tests, they should be compared to the same measurements from previous tests. Are they staying fairly the same? Are they slowly increasing? Are they slowly decreasing? Have there been any large changes in the measurements? Trends which are fairly constant are normal. Trends which are slowly increasing or slowly decreasing do not normally require corrective action but may warrant a shorter time interval until the next series of timing tests. Trends with large changes are usually not normal and may require corrective action.

For circuit breakers with two trip coils, the above analysis is performed again on the tests performed using the second trip coil.

For circuit breakers with two or more main contacts in series per phase, the additional individual measurements to be reviewed are:

1. Main Contact Opening Time Synchronization in Phase

2. Main Contact Closing Time Synchronization in Phase

3. Close-Open (Trip-Free) Dwell Time in Phase

4. Open-Close (Reclose) Time in Phase

The Main Contact Opening Times Synchronization in Phase from the three trip tests are compared to each other one phase at a time. Usually, the test results of a given phase will be very close to each other. They also should be within the manufacturer’s limits which are usually found in the circuit breaker’s instruction manual. These values are not compared between phases. They are only compared within a phase.

The Main Contact Closing Times Synchronization in Phase from the three close tests are compared to each other one phase at a time. Usually, the test results of a given phase will be very close to each other. They also should be within the manufacturer’s limits which are usually found in the circuit breaker’s instruction manual. These values are not compared between phases. They are only compared within a phase.

The Close-Open (Trip-Free) Dwell Times in Phase from the three trip-free tests are compared to each other one phase at a time. Usually, the test results of a given phase will be very close to each other. They also should be within the manufacturer’s limits which are usually found in the circuit breaker’s instruction manual. These values are not compared between phases. They are only compared within a phase.

The Open-Close (Reclose) Times in Phase from the three reclose tests are compared to each other one phase at a time. Usually, the test results of a given phase will be very close to each other. They also should be within the manufacturer’s limits which are usually found in the circuit breaker’s instruction manual. These values are not compared between phases. They are only compared within a phase.

For circuit breakers with main contacts contained in two or more tanks, sometimes called “heads” on live-tank circuit breakers, in series per phase with each tank containing two series main contacts with the mid-point accessible for testing, the additional individual measurements to be reviewed are:

1. Main Contact Opening Time Synchronization in Module

2. Main Contact Closing Time Synchronization in Module

3. Close-Open (Trip-Free) Dwell Time in Module

4. Open-Close (Reclose) Time in Module

The Main Contact Opening Times Synchronization in Module from the three trip tests are compared to each other one module at a time. Usually, the test results of a given module will be very close to each other. They also should be within the manufacturer’s limits which are usually found in the circuit breaker’s instruction manual. These values are not compared between modules. They are only compared within a module.

The Main Contact Closing Times Synchronization in Module from the three close tests are compared to each other one module at a time. Usually, the test results of a given module will be very close to each other. They also should be within the manufacturer’s limits which are usually found in the circuit breaker’s instruction manual. These values are not compared between modules. They are only compared within a module.

The Close-Open (Trip-Free) Dwell Times in Module from the three trip-free tests are compared to each other one module at a time. Usually, the test results of a given module will be very close to each other. They also should be within the manufacturer’s limits which are usually found in the circuit breaker’s instruction manual. These values are not compared between modules. They are only compared within a module.

The Open-Close (Reclose) Times in Module from the three reclose tests are compared to each other one module at a time. Usually, the test results of a given module will be very close to each other. They also should be within the manufacturer’s limits which are usually found in the circuit breaker’s instruction manual. These values are not compared between modules. They are only compared within a module.

For a circuit breaker with one contact per phase and with closing resistors, the additional individual measurements to be reviewed are:

1. Resistor Switch Contact Opening Time Relative to Test Initiation

2. Resistor Switch Contact Opening Time Relative to Main Contact

3. Resistor Switch Contact Opening Time Relative to Test Initiation Synchronization in Breaker

4. Resistor Switch Contact Opening Time Relative to Main Contact Synchronization in Breaker

5. Resistor Switch Contact Closing Time Relative to Test Initiation

6. Resistor Switch Contact Closing Time Relative to Main Contact

7. Resistor Switch Contact Closing Time Relative to Test Initiation Synchronization in Breaker

8. Resistor Switch Contact Closing Time Relative to Main Contact Synchronization in Breaker

9. Resistor Switch Contact Bounce

The Resistor Switch Contact Opening Times Relative to Test Initiation from the three trip tests are compared to each other one resistor switch contact at a time. Usually, the test results of a given resistor switch contact will be very close to each other. They also should be within the manufacturer’s limits which are usually found in the circuit breaker’s instruction manual. These values are not compared between resistor switch contacts. They are only compared with the same resistor switch contact.

The Resistor Switch Contact Opening Times Relative to Main Contact from the three trip tests are compared to each other one resistor switch contact at a time. Usually, the test results of a given resistor switch contact will be very close to each other. They also should be within the manufacturer’s limits which are usually found in the circuit breaker’s instruction manual. These values are not compared between resistor switch contacts. They are only compared with the same resistor switch contact.

The Resistor Switch Contact Opening Times Relative to Test Initiation Synchronization in Breaker from the three trip tests are compared to each. The values from each of the three tests should be very close to each other and within the manufacturer’s limits in the instruction manual.

The Resistor Switch Contact Opening Times Relative to Main Contact Synchronization in Breaker from the three trip tests are compared to each. The values from each of the three tests should be very close to each other and within the manufacturer’s limits in the instruction manual.

The Resistor Switch Contact Closing Times Relative to Test Initiation from the three close tests are compared to each other one resistor switch contact at a time. Usually, the test results of a given resistor switch contact will be very close to each other. They also should be within the manufacturer’s limits which are usually found in the circuit breaker’s instruction manual. These values are not compared between resistor switch contacts. They are only compared with the same resistor switch contact.

The Resistor Switch Contact Closing Times Relative to Main Contact from the three close tests are compared to each other one resistor switch contact at a time. Usually, the test results of a given resistor switch contact will be very close to each other. They also should be within the manufacturer’s limits which are usually found in the circuit breaker’s instruction manual. These values are not compared between resistor switch contacts. They are only compared with the same resistor switch contact.

The Resistor Switch Contact Closing Times Relative to Test Initiation Synchronization in Breaker from the three close tests are compared to each. The values from each of the three tests should be very close to each other and within the manufacturer’s limits in the instruction manual.

The Resistor Switch Contact Closing Times Relative to Main Contact Synchronization in Breaker from the three close tests are compared to each. The values from each of the three tests should be very close to each other and within the manufacturer’s limits in the instruction manual.

Resistor Switch Contact Bounce can only be determined if the circuit breaker timing test set being used has the feature of displaying the open/closed recording trace of each of the resistor switch contacts during each of the tests. Normally, each of the resistor switch contacts will transition from open to closed in a clean step function. If one of the recording traces shows a resistor switch contact closing then opening briefly and then closing again, a Resistor Switch Contact Bounce on closing is being observed. The same holds true on opening. Normally, each of the resistor switch contacts will transition from closed to open in a clean step function. If one of the recording traces shows a resistor switch contact opening then closing briefly and then opening again, a Resistor Switch Contact Bounce on opening is being observed.

For circuit breakers with two or more main contacts in series per phase and with closing resistors, the additional individual measurements to be reviewed are:

1. Resistor Switch Contact Opening Time Relative to Test Initiation Synchronization in Phase

2. Resistor Switch Contact Opening Time Relative to Main Contact Synchronization in Phase

3. Resistor Switch Contact Closing Time Relative to Test Initiation Synchronization in Phase

4. Resistor Switch Contact Closing Time Relative to Main Contact Synchronization in Phase

The Resistor Switch Contact Opening Times Relative to Test Initiation Synchronization in Phase from the three trip tests are compared to each other one phase at a time. Usually, the test results of a given phase will be very close to each other. They also should be within the manufacturer’s limits which are usually found in the circuit breaker’s instruction manual. These values are not compared between phases. They are only compared within a phase.

The Resistor Switch Contact Opening Times Relative to Main Contact Synchronization in Phase from the three trip tests are compared to each other one phase at a time. Usually, the test results of a given phase will be very close to each other. They also should be within the manufacturer’s limits which are usually found in the circuit breaker’s instruction manual. These values are not compared between phases. They are only compared within a phase.

The Resistor Switch Contact Closing Times Relative to Test Initiation Synchronization in Phase from the three close tests are compared to each other one phase at a time. Usually, the test results of a given phase will be very close to each other. They also should be within the manufacturer’s limits which are usually found in the circuit breaker’s instruction manual. These values are not compared between phases. They are only compared within a phase.

The Resistor Switch Contact Closing Times Relative to Main Contact Synchronization in Phase from the three close tests are compared to each other one phase at a time. Usually, the test results of a given phase will be very close to each other. They also should be within the manufacturer’s limits which are usually found in the circuit breaker’s instruction manual. These values are not compared between phases. They are only compared within a phase.

For circuit breakers with main contacts contained in two or more tanks, sometimes called “heads” on live-tank circuit breakers, in series per phase with each tank containing two series main contacts with the mid-point accessible for testing and with closing resistors, the additional individual measurements to be reviewed are:

1. Resistor Switch Contact Opening Time Relative to Test Initiation Synchronization in Module

2. Resistor Switch Contact Opening Time Relative to Main Contact Synchronization in Module

3. Resistor Switch Contact Closing Time Relative to Test Initiation Synchronization in Module

4. Resistor Switch Contact Closing Time Relative to Main Contact Synchronization in Module

The Resistor Switch Contact Opening Times Relative to Test Initiation Synchronization in Module from the three trip tests are compared to each other one module at a time. Usually, the test results of a given module will be very close to each other. They also should be within the manufacturer’s limits which are usually found in the circuit breaker’s instruction manual. These values are not compared between modules. They are only compared within a module.

The Resistor Switch Contact Opening Times Relative to Main Contact Synchronization in Module from the three trip tests are compared to each other one module at a time. Usually, the test results of a given module will be very close to each other. They also should be within the manufacturer’s limits which are usually found in the circuit breaker’s instruction manual. These values are not compared between modules. They are only compared within a module.

The Resistor Switch Contact Closing Times Relative to Test Initiation Synchronization in Module from the three close tests are compared to each other one module at a time. Usually, the test results of a given module will be very close to each other. They also should be within the manufacturer’s limits which are usually found in the circuit breaker’s instruction manual. These values are not compared between modules. They are only compared within a module.

The Resistor Switch Contact Closing Times Relative to Main Contact Synchronization in Module from the three close tests are compared to each other one module at a time. Usually, the test results of a given module will be very close to each other. They also should be within the manufacturer’s limits which are usually found in the circuit breaker’s instruction manual. These values are not compared between modules. They are only compared within a module.

2. Travel and Velocity

What is the test? The travel and velocity test measures the operating motion and speed of the circuit breaker during open, close, close-open and open-close operations. This Test is usually part of the timing set equipment and is performed at the same time that timing test is performed.

What are the test’s objectives? The objectives of the travel and velocity test are to assist in making an assessment of the performance and condition of the operating mechanism in the circuit breaker by providing operating motion and speed measurements of the circuit breaker. These measurements are then compared to the circuit breaker manufacturer’s specifications to see if the circuit breaker is performing correctly. The measurements are also compared to previous test results from the same circuit breaker to determine if they are remaining constant or changing. For example, a marked decrease in the velocity measurements may indicate a worn or binding mechanism or a possible lack of mechanism lubrication. If the travel and/or velocity measurements are not within the circuit breaker manufacturer’s specifications, corrective action will be needed.

What does the test check/test/measure/evaluate? The travel and velocity test measures the operating motion and speed of the mechanical operator for the main contacts and resistor switch contacts (when they exist) of the circuit breaker during open (trip), close, close-open (trip-free) and open-close (reclose) operations. The travel distances can be measured in inches or in millimeters. The velocity rates can be measured in feet per second or in meters per second. Analysis of the travel and velocity waveforms can detect such problems as excessive friction in the contacts, trip latch or mechanism, improper contact velocity, malfunctioning shock absorbers, dash pots or buffers, incorrect stop adjustments, incorrect spring adjustments, incorrect contact wipe adjustments and worn contacts. The definitions of the travel and velocity measurements are listed below:

Opening Average Velocity – This is the calculated speed of the circuit breaker’s main contacts during an opening operation derived by taking the distance traveled by the circuit breaker’s main contacts divided by the time measured to travel that distance through an area or zone of the travel curve. This area or zone (sometimes called the Arcing Zone) is usually specified by the circuit breaker’s manufacturer. It will normally be an area containing the middle of the travel curve where the velocity is fairly constant and exclude both ends of the curve where accelerations and decelerations are occurring.

Opening Total Travel – This is the total distance, sometimes called the stroke, which the circuit breaker’s main contacts travel from their initial resting place to their final resting place during an opening operation.

Opening Overtravel – This is the maximum distance that the circuit breaker’s main contacts travel in the forward direction beyond their final resting place during an opening operation.

Opening Rebound – This is the maximum distance that the circuit breaker’s main contacts travel in the reverse direction from their final resting place during an opening operation.

Closing Average Velocity – This is the calculated speed of the circuit breaker’s main contacts during a closing operation derived by taking the distance traveled by the circuit breaker’s main contacts divided by the time measured to travel that distance through an area or zone of the travel curve. This area or zone is usually specified by the circuit breaker’s manufacturer. It will normally be an area containing the middle of the travel curve where the velocity is fairly constant and exclude both ends of the curve where accelerations and decelerations are occurring.

Closing Total Travel – This is the total distance, sometimes called the stroke, which the circuit breaker’s main contacts travel from their initial resting place to their final resting place during a closing operation.

Closing Overtravel – This is the maximum distance that the circuit breaker’s main contacts travel in the forward direction beyond their final resting place during a closing operation.

Closing Rebound – This is the maximum distance that the circuit breaker’s main contacts travel in the reverse direction from their final resting place during a closing operation.

Contact Wipe – This is the measurement, taken during an opening operation of the circuit breaker, of the physical distance that the moving contact travels from the fully closed position until it first parts with the stationary contact and loses its electrical continuity. Another method of obtaining this measurement, taken during a closing operation of the circuit breaker, is to measure the physical distance that the moving contact travels from when it first touches the stationary contact and has electrical continuity until the moving contact is in the fully closed position. Both measurements can be made with a travel and velocity test set.

Contact Penetration (also Contact Insertion) – This is the measurement, taken inside of the circuit breaker during a slow-closing operation, of the physical distance that the tip of the moving contact travels from when it is even with the leading edge of the stationary contact until the moving contact is in the fully closed position. Another method of obtaining this measurement is to fully close the circuit breaker, place a mark on the moving contact where the leading edge of the stationary contact touches it, slowly open the circuit breaker and measure the distance from the mark on the moving contact to the tip of the moving contact. This is a manual measurement and cannot be made with a travel and velocity test set.

Linear Travel – This is the type of mechanical motion that moves in a straight line which is to be monitored with a travel transducer during the opening and closing operations of the circuit breaker.

Rotary Travel (also Angular Travel) – This is the type of mechanical motion that moves in a circle which is to be monitored with a travel transducer during the opening and closing operations of the circuit breaker.

What are the test’s limitations? One major challenge is to determine a means of attaching the travel transducer to the circuit breaker. In some cases, this is a major challenge. The mounting bracket for the travel transducer must be rugged enough and securely attached to the circuit breaker so that it does not move when the circuit breaker is opened and closed. Another challenge is to match the motion of the circuit breaker to the motion of the transducer. Measurement accuracies are introduced when rotary circuit breaker motion is measured with a linear travel transducer and vice versa. This test usually requires the breaker to be taken out on clearance for several hours and knowledge of the detailed breaker control wiring configuration. The clearance procedure usually involves operating the breaker, which will exclude finding most lubrication problems associated with the speed of operation (see First Trip test). This is a no-load test and as such misses various problems that can exist with arc suppression components.

When does the test need to be performed? This test needs to be performed upon the initial commissioning of the circuit breaker to verify that it conforms to the manufacturer’s specifications and to collect baseline test data. Future test data can be compared to the commissioning test data to see if any deviations have occurred and if any corrective actions may be required. These future tests may be regular periodic maintenance tests, triggered by SCADA time algorithm, microprocessor relay operational time alarm, or special investigative tests that may be required due to a misoperation, an in-service failure or a perceived problem of the circuit breaker. The regular periodic maintenance tests are normally performed at fixed time intervals that have been selected by the owner and/or operator of the circuit breaker. These fixed time intervals are not standardized across the industry and can vary from 2 years to 10 years or more. Many factors go into the selection of the fixed time interval chosen for each circuit breaker. Condition based triggers may supplement the time-based triggers to help factor the breaker exposed service conditions. These factors are explained in more detail elsewhere in this guidebook.

Which type of circuit breakers is the test used on? This test is used on all types of circuit breakers including air, oil, SF₆ gas and vacuum breakers.

How is the test performed? This test is performed in conjunction with timing tests. A timing test set with provisions for an input from a travel transducer is required. Also, a travel transducer is required. The motion of the travel transducer should match the travel of the point on the circuit breaker’s operating mechanism where the travel transducer will be attached. The two choices are a linear travel transducer or a rotary travel transducer. Mismatching the motion of the travel transducer with the motion of the operating mechanism can result in travel and velocity measurement errors. The scaling of the travel of the transducer to the travel of the operating mechanism will need to be entered and saved into the circuit breaker manufacturer’s travel and velocity specifications section of the timing test set (if available). One set of travel and velocity measurements is required for each mechanism on the circuit breaker. Most circuit breakers have only one mechanism to operate all three poles of the circuit breaker. On independent pole circuit breakers, there is one mechanism per pole therefore three sets of travel and velocity measurements, one per pole, are required. The circuit breaker manufacturer’s instruction manual should be consulted for the limits for the various travel and velocity measurements and for any special requirements for performing these tests.

The general steps listed in Timing should be followed to measure the travel and velocity of the circuit breaker at the same time that each of the timing measurements are being made.

How are the test results interpreted? The test results are reviewed one set of measurements at a time. A circuit breaker needs to pass each individual set of measurements for it to pass the entire travel and velocity test. For a circuit breaker with the operating linkages on each of the three phases mechanically ganged together and one common operating mechanism, the individual measurements to be reviewed are:

1. Opening Average Velocity

2. Opening Total Travel

3. Opening Overtravel

4. Opening Rebound

5. Contact Wipe

6. Closing Average Velocity

7. Closing Total Travel

8. Closing Overtravel

9. Closing Rebound

The Opening Average Velocity from the three trip tests are compared to each other. Usually these test results will be very close to each other. They also should be within the manufacturer’s limits which are usually found in the circuit breaker’s instruction manual.

The Contact Wipe from the three trip tests are compared to each other one phase at a time. Usually, the test results of a given phase will be very close to each other. They also should be within the manufacturer’s limits which are usually found in the circuit breaker’s instruction manual. Next, the test results of the individual phases are compared to each other one test at a time. Usually, one of the phases will repeatedly have the shortest Contact Wipe and another phase will repeatedly have the longest Contact Wipe.

An example of trip velocity and contact wipe test results that are within manufacturer’s limits is shown in Table 3-5.

Test ID	Opening Average Velocity (ft./sec.)	Manufacturer’s Opening Average Velocity Limits (ft./sec.)	Phase A Contact Wipe (inches)	Phase B Contact Wipe (inches)	Phase C Contact Wipe (inches)	Manufacturer’s Contact Wipe Limit (inches)
Trip 1	13.20	12.47-16.08	1.684	1.667	1.790	None
Trip 2	13.13	12.47-16.08	1.672	1.672	1.781	None
Trip 3	13.11	12.47-16.08	1.702	1.687	1.814	None
Trip Average	13.15	12.47-16.08	1.686	1.675	1.795	None

The Opening Overtravel from the three trip tests are compared to each other. Usually these test results will be very close to each other. They also should be within the manufacturer’s limits which are usually found in the circuit breaker’s instruction manual.

The Opening Rebound from the three trip tests are compared to each other. Usually these test results will be very close to each other. They also should be within the manufacturer’s limits which are usually found in the circuit breaker’s instruction manual.

The Opening Total Travel from the three trip tests are compared to each other. Usually these test results will be very close to each other. They also should be within the manufacturer’s limits which are usually found in the circuit breaker’s instruction manual.

Table 3-6 presents an example of trip overtravel, rebound and total travel test results that are within manufacturer’s limits.

Test ID	Opening Overtravel (inches)	Manufacturer’s Opening Overtravel Limit (max.) (inches)	Opening Rebound (inches)	Manufacturer’s Opening Rebound Limit (max.) (inches)	Opening Total Travel (inches)	Manufacturer’s Opening Total Travel Limit (max.) (inches)
Trip 1	0.016	0.196	0.101	0.196	4.047	4.449
Trip 2	0.019	0.196	0.097	0.196	4.037	4.449
Trip 3	0.019	0.196	0.100	0.196	4.051	4.449
Trip Average	0.018	0.196	0.099	0.196	4.045	4.449

Figure 3-2 shows an example of typical trip timing, travel and velocity test waveforms of a circuit breaker.

The Closing Average Velocity from the three close tests are compared to each other. Usually these test results will be very close to each other. They also should be within the manufacturer’s limits which are usually found in the circuit breaker’s instruction manual.

The Closing Total Travel from the three close tests are compared to each other. Usually these test results will be very close to each other. They also should be within the manufacturer’s limits which are usually found in the circuit breaker’s instruction manual.

An example of close velocity and total travel test results that are within manufacturer’s limits is shown in Table 3-7.

Test ID	Closing Average Velocity (ft./sec.)	Manufacturer’s Closing Average Velocity Limits (ft./sec.)	Closing Total Travel (inches)	Manufacturer’s Closing Total Travel Limit (max.) (inches)
Close 1	7.42	5.58-7.55	4.039	4.449
Close 2	7.39	5.58-7.55	4.032	4.449
Close 3	7.41	5.58-7.55	4.036	4.449
Close Average	7.41	5.58-7.55	4.036	4.449

The Closing Overtravel from the three close tests are compared to each other. Usually these test results will be very close to each other. They also should be within the manufacturer’s limits which are usually found in the circuit breaker’s instruction manual.

The Closing Rebound from the three close tests are compared to each other. Usually these test results will be very close to each other. They also should be within the manufacturer’s limits which are usually found in the circuit breaker’s instruction manual.

Table 3-8 shows an example of close overtravel and rebound test results that are within manufacturer’s limits.

Test ID	Closing Overtravel (inches)	Manufacturer’s Closing Overtravel Limit (max.) (inches)	Closing Rebound (inches)	Manufacturer’s Closing Rebound Limit (max.) (inches)
Close 1	0.009	0.236	0.015	0.138
Close 2	0.012	0.236	0.016	0.138
Close 3	0.009	0.236	0.019	0.138
Close Average	0.010	0.236	0.017	0.138

An example of typical close timing, travel and velocity test waveforms is shown in Figure 3-3.

The Closing Average Velocity, Opening Average Velocity and Closing Total Travel from the three trip-free tests are compared to each other, as mentioned above.

An example of trip-free closing velocity, opening velocity and closing total travel tests that are within manufacturer’s limits is shown in Table 3-9.

Test ID	Closing Average Velocity (ft./sec.)	Manufacturer’s Closing Average Velocity Limits (ft./sec.)	Opening Average Velocity (ft./sec.)	Manufacturer’s Opening Average Velocity Limits (ft./sec.)	Closing Total Travel (inches)	Manufacturer’s Closing Total Travel Limit (max.) (inches)
Trip-Free 1	6.94	5.58-7.55	15.43	12.47-16.08	3.566	4.449
Trip-Free 2	7.21	5.58-7.55	15.71	12.47-16.08	3.582	4.449
Trip-Free 3	6.87	5.58-7.55	15.26	12.47-16.08	3.559	4.449
Trip-Free Average	7.01	5.58-7.55	15.47	12.47-16.08	3.569	4.449

Figure 3-4 shows an example of typical trip-free timing, travel and velocity test waveforms.

The Closing Average Velocity, Opening Average Velocity and Closing Total Travel from the three reclose tests are compared to each other, as mentioned above.

Table 3-10 shows an example of reclose opening velocity, closing velocity and opening total travel test results that are within manufacturer’s limits.

Test ID	Opening Average Velocity (ft./sec.)	Manufacturer’s Opening Average Velocity Limits (ft./sec.)	Closing Average Velocity (ft./sec.)	Manufacturer’s Closing Average Velocity Limits (ft./sec.)	Opening Total Travel (inches)	Manufacturer’s Opening Total Travel Limit (max.) (inches)
Reclose 1	13.15	12.47-16.08	7.36	5.58-7.55	4.079	4.449
Reclose 2	12.89	12.47-16.08	7.48	5.58-7.55	4.081	4.449
Reclose 3	12.88	12.47-16.08	7.48	5.58-7.55	4.082	4.449
Reclose Average	12.97	12.47-16.08	7.44	5.58-7.55	4.081	4.449

An example of typical reclose timing, travel and velocity test waveforms is shown in Figure 3-5

After the above measurements have been reviewed for this series of tests, they should be compared to the same measurements from previous tests. Are they staying fairly the same? Are they slowly increasing? Are they slowly decreasing? Have there been any large changes in the measurements? Trends which are fairly constant are normal. Trends which are slowly increasing or slowly decreasing do not normally require corrective action but may warrant a shorter time interval until the next series of travel and velocity tests. Trends with large changes are usually not normal and may require corrective action.

For a circuit breaker with one operating mechanism per phase (or three total per circuit breaker), the individual measurements to be reviewed are the same as those listed above but with a different analysis (except for Contact Wipe).

The Opening Average Velocity from the three trip tests are compared to each other one phase at a time. Usually, the test results of a given phase will be very close to each other. They also should be within the manufacturer’s limits which are usually found in the circuit breaker’s instruction manual. These values are not compared between phases. They are only compared within a phase.

The Opening Total Travel from the three trip tests are compared to each other one phase at a time. Usually, the test results of a given phase will be very close to each other. They also should be within the manufacturer’s limits which are usually found in the circuit breaker’s instruction manual. These values are not compared between phases. They are only compared within a phase.

The Opening Overtravel from the three trip tests are compared to each other one phase at a time. Usually, the test results of a given phase will be very close to each other. They also should be within the manufacturer’s limits which are usually found in the circuit breaker’s instruction manual. These values are not compared between phases. They are only compared within a phase.

The Opening Rebound from the three trip tests are compared to each other one phase at a time. Usually, the test results of a given phase will be very close to each other. They also should be within the manufacturer’s limits which are usually found in the circuit breaker’s instruction manual. These values are not compared between phases. They are only compared within a phase.

The Contact Wipe from the three trip tests are compared to each other one phase at a time. Usually, the test results of a given phase will be very close to each other. They also should be within the manufacturer’s limits which are usually found in the circuit breaker’s instruction manual. Next, the test results of the individual phases are compared to each other one test at a time. Usually, one of the phases will repeatedly have the shortest Contact Wipe and another phase will repeatedly have the longest Contact Wipe.

The Closing Average Velocity from the three close tests are compared to each other one phase at a time. Usually, the test results of a given phase will be very close to each other. They also should be within the manufacturer’s limits which are usually found in the circuit breaker’s instruction manual. These values are not compared between phases. They are only compared within a phase.

The Closing Total Travel from the three close tests are compared to each other one phase at a time. Usually, the test results of a given phase will be very close to each other. They also should be within the manufacturer’s limits which are usually found in the circuit breaker’s instruction manual. These values are not compared between phases. They are only compared within a phase.

The Closing Overtravel from the three close tests are compared to each other one phase at a time. Usually, the test results of a given phase will be very close to each other. They also should be within the manufacturer’s limits which are usually found in the circuit breaker’s instruction manual. These values are not compared between phases. They are only compared within a phase.

The Closing Rebound from the three close tests are compared to each other one phase at a time. Usually, the test results of a given phase will be very close to each other. They also should be within the manufacturer’s limits which are usually found in the circuit breaker’s instruction manual. These values are not compared between phases. They are only compared within a phase.

After the above measurements have been reviewed for this series of tests, they should be compared to the same measurements from previous tests. Are they staying fairly the same? Are they slowly increasing? Are they slowly decreasing? Have there been any large changes in the measurements? Trends which are fairly constant are normal. Trends which are slowly increasing or slowly decreasing do not normally require corrective action but may warrant a shorter time interval until the next series of travel and velocity tests. Trends with large changes are usually not normal and may require corrective action.

3. Static Contact Resistance Measurement

What is the test? The static contact resistance measurement test measures the high current DC micro-ohm resistance (Ductor) of the circuit breaker in the closed position from one end of each pole to the other. (See Figure 3-6, Circuit Breaker Bushing and Pole Numbering Convention for Static Contact Resistance Measurements.)

What are the test’s objectives? The objectives of the static contact resistance measurement test are to assist in making an assessment of the condition of the main current path of each pole in the circuit breaker. These measurements are then compared to the circuit breaker manufacturer’s specifications to see if the circuit breaker is performing correctly. The measurements are also compared to previous test results from the same circuit breaker to determine if the measurements are remaining constant or changing. For example, a marked increase in the static contact resistance measurement may indicate worn or misaligned main and/or arcing contacts. If the static contact resistance measurements exceed the circuit breaker manufacturer’s specifications, corrective action may be needed.

What does the test check/test/measure/evaluate? The static contact resistance measurement test evaluates the connections in the primary current path of the circuit breaker by taking an overall resistance measurement per phase. These connections include:

• Main moving contact to main stationary contact
• Arcing moving contact (when present) to arcing stationary contact (when present)
• Bushing connections to moving contacts
• Bushing connections to stationary contacts
• Sliding primary current transfer contacts (when present)
• Internal bus work

Of the above connections, the main contacts and the arcing contacts are normally the components which wear and deteriorate with use. Occasionally, this test detects problems in the remaining connections listed above.

What are the test’s limitations? This test requires a breaker clearance and produces very limited information on the electrical condition of the breaker (path resistance only) and no information on the mechanical condition. Also, when current transformers are present on the circuit breaker and are located such that the DC current used for the static contact resistance measurement will pass through them, unwanted protective relay operations can occur if improperly filtered DC power supplies are used in the test set. This problem has been known for many years now and many static contact resistance measurement test sets manufactured today have properly filtered DC power supplies. Another technique used in modern test sets is to have the DC power supply slowly ramp the DC test current up before the measurement and slowly ramp the DC test current down after the measurement at a rate that the protective relays will not respond to.

Another issue that involves the current transformers is that when they are present in the static contact resistance measurement test circuit, they will influence the measurement. This influence can result in an increase in the measurement. The best practice when current transformers are present in the test circuit is to leave the test run and to monitor the measurement until it stabilizes. This can take up to a minute or more. During this time, the DC test current will cause the magnetic cores of the current transformers to saturate and to reduce their influence on the static contact resistance measurement.

When does the test need to be performed? This test needs to be performed upon the initial commissioning of the circuit breaker to verify that it conforms to the manufacturer’s specifications and to collect baseline test data. Future test data can be compared to the commissioning test data to see if any deviations have occurred and if any corrective actions may be required. These future tests may be regular periodic maintenance tests or special investigative tests which may be required due to a misoperation, an in-service failure, unbalanced infrared temperatures, or a perceived problem of the circuit breaker. The regular periodic maintenance tests are normally performed at fixed time intervals that have been selected by the owner and/or operator of the circuit breaker. These fixed time intervals are not standardized across the industry and can vary from 2 years to 10 years or more. Many factors go into the selection of the fixed time interval chosen for each circuit breaker. Condition based triggers may supplement the time-based triggers to help factor the breaker exposed service conditions. These factors are explained in more detail elsewhere in this guidebook.

Which type of circuit breakers is the test used on? This test is used on all types of circuit breakers including air, oil, SF₆ gas and vacuum breakers.

How is the test performed? This test is performed with the circuit breaker de-energized and out of service (off-line). Normally, the grounded external high voltage connections are removed from one side of the circuit breaker and are left connected on the other side of the circuit breaker for the test. However, there are field test sets now available which state that they can accurately measure the static contact resistance with both sides of the circuit breaker connected and grounded. Current transformers in use on the circuit breaker are left connected to their protective relays and meters. Unused current transformers should have their secondaries shorted and grounded. The dielectric medium in the circuit breaker has very little effect on static contact resistance measurements therefore it does not need to be at proper levels. If necessary, static contact resistance measurements can be made without any oil or SF₆ gas in the circuit breaker. It is very important that the top terminals of the bushings be inspected and cleaned to insure a good connection point for the test equipment leads. Poor contact resistance between the test equipment leads and the top terminals of the circuit breaker can result in abnormally high readings and possibly indicate a problem with the internal breaker contacts which does not exist. Surface moisture on the bushings has very little effect on static contact resistance measurements therefore the test can be performed in humid or wet weather conditions if necessary. However, since resistance values vary with temperature, the ambient air temperature should be recorded at the time of the test. The test current used for the static contact resistance measurement is normally specified by the circuit breaker manufacturer in DC amps in their instruction manual. Test current values of 10 amps DC or 100 amps DC are frequently specified. The field test set most commonly used for static contact resistance measurements is a Digital Low Resistance Ohmmeter or DLRO. It consists of two larger size cables (normally red and black) to inject the DC test current into the circuit breaker and two smaller size cables (normally red and black) to measure the DC voltage drop across the circuit breaker. One phase (or pole) is measured at a time.

The following are the general steps required to measure the static contact resistance of a circuit breaker with a field DLRO test set. Three measurements will be made (one per phase) with the circuit breaker in the closed position. The manufacturer’s instructions should always be consulted for the specific operating requirements of each field test set.

1. Properly identify the circuit breaker on which the test is to be performed. This is done by locating the circuit breaker with the correct manufacturer’s name, manufacturer’s serial number and owner’s equipment identification (ID) number in the substation. If a permanent owner’s equipment identification (ID) number label is absent, the three-line drawing of the substation can be referenced to determine the location of the circuit breaker. A temporary label can be attached to the circuit breaker for use during the test. It should be replaced with a permanent label as soon as practical.

2. Check that the circuit breaker has been properly removed from service, lock out and tag out procedures have been followed and the circuit breaker is safe to work on.

3. Install grounds on the external high voltage leads to Bushing Numbers 1 through 6 (reference Figure 3-6 Circuit Breaker Bushing and Pole Numbering Convention for Static Contact Resistance Measurements).

4. Connect the ground lead from the DLRO set to the substation ground connection to the circuit breaker.

5. Remove the external high voltage connection and ground from Bushing Number 1.

6. Connect one of the current test leads (larger cable) from the DLRO set to the top of Bushing Number 1.

7. Connect the voltage test lead (smaller cable) of the same color from the DLRO set just below the current test lead on the top of Bushing Number 1. Check that the voltage lead is making a good connection. Clean the connection point on the top of the bushing with a wire brush if necessary.

8. Connect the other current test lead (larger cable) from the DLRO set to the top of Bushing Number 2 (leave the external high voltage connection and ground connected to Bushing Number 2).

9. Connect the voltage test lead (smaller cable) of the same color from the DLRO set just below the current test lead on the top of Bushing Number 2. Check that the voltage lead is making a good connection. Clean the connection point on the top of the bushing with a wire brush if necessary.

10. Check that the circuit breaker is in the closed position.

11. Turn on the DLRO set.

12. Select the test current level specified by the circuit breaker manufacturer.

13. Select the test duration time. Note: For circuit breakers with current transformers, select a test duration time of at least one minute to allow time for the current transformers to saturate and give an accurate resistance measurement. For circuit breakers without current transformers, 8-10 seconds is usually long enough to obtain an accurate resistance measurement. The key is to allow enough time for the resistance measurement to stabilize before ending the test.

14. Perform the resistance measurement. Note: The resistance measurement is made by the DLRO set by dividing the voltage reading across the voltage test leads by the test current. If a high resistance measurement is observed, check the connections of the voltage test lead clamps with the top of the bushings and repeat the test.

15. Record the resistance measurement, test current level and ambient temperature for the test.

16. Turn off the DLRO set.

17. Remove the voltage test lead and current test lead from the DLRO set from Bushing Number 2.

18. Connect this current test lead (larger cable) from the DLRO set to the top of Bushing Number 4 (leave the external high voltage connection and ground connected to Bushing Number 4).

19. Connect this voltage test lead (smaller cable) of the same color from the DLRO set just below the current test lead on the top of Bushing Number 4. Check that the voltage lead is making a good connection. Clean the connection point on the top of the bushing with a wire brush if necessary.

20. Remove the voltage test lead and current test lead from the DLRO set from Bushing Number 1.

21. Reconnect the external high voltage connection and ground to the top of Bushing Number 1.

22. Remove the external high voltage connection and ground from Bushing Number 3.

23. Connect the current test lead (larger cable) from the DLRO set just removed from Bushing Number 1 to the top of Bushing Number 3.

24. Connect the voltage test lead (smaller cable) of the same color from the DLRO set just removed from Bushing Number 1 to just below the current test lead on the top of Bushing Number 3. Check that the voltage lead is making a good connection. Clean the connection point on the top of the bushing with a wire brush if necessary.

25. Turn on the DLRO set.

26. Select the test current level specified by the circuit breaker manufacturer. (Same as the measurement for Pole 1.)

27. Select the test duration time. (Same as the measurement for Pole 1.)

28. Perform the resistance measurement. If a high resistance measurement is observed, check the connections of the voltage test lead clamps with the top of the bushings and repeat the test.

29. Record the resistance measurement, test current level and ambient temperature for the test.

30. Turn off the DLRO set.

31. Remove the voltage test lead and current test lead from the DLRO set from Bushing Number 3.

32. Reconnect the external high voltage connection and ground to the top of Bushing Number 3.

33. Remove the external high voltage connection and ground from Bushing Number 5.

34. Connect the current test lead (larger cable) from the DLRO set just removed from Bushing Number 3 to the top of Bushing Number 5.

35. Connect the voltage test lead (smaller cable) of the same color from the DLRO set just removed from Bushing Number 3 to just below the current test lead on the top of Bushing Number 5. Check that the voltage lead is making a good connection. Clean the connection point on the top of the bushing with a wire brush if necessary.

36. Remove the voltage test lead and current test lead from the DLRO set from Bushing Number 4.

37. Connect this current test lead (larger cable) from the DLRO set to the top of Bushing Number 6 (leave the external high voltage connection and ground connected to Bushing Number 6).

38. Connect this voltage test lead (smaller cable) of the same color from the DLRO set just below the current test lead on the top of Bushing Number 6. Check that the voltage lead is making a good connection. Clean the connection point on the top of the bushing with a wire brush if necessary.

39. Turn on the DLRO set.

40. Select the test current level specified by the circuit breaker manufacturer. (Same as the measurement for Poles 1 and 2.)

41. Select the test duration time. (Same as the measurement for Poles 1 and 2.)

42. Perform the resistance measurement. If a high resistance measurement is observed, check the connections of the voltage test lead clamps with the top of the bushings and repeat the test.

43. Record the resistance measurement, test current level and ambient temperature for the test.

44. Turn off the DLRO set.

45. Remove the voltage test lead and current test lead from the DLRO set from Bushing Number 6.

46. Remove the voltage test lead and current test lead from the DLRO set from Bushing Number 5.

47. Reconnect the external high voltage connection and ground to the top of Bushing Number 5.

48. Remove grounds from the external high voltage leads to Bushing Numbers 1 through 6.

49. Leave the circuit breaker in the same position (open or closed) that it was found before these tests.

How are the test results interpreted? First, the resistance measurements from each of the three phases should be compared to each other. Normally, the values of these resistance measurements will be fairly close to each other. If one measurement is not fairly close to the other two, it is a good practice to repeat the measurements to verify their accuracy. Second, the resistance measurements from each of the three phases should be compared to previous measurements. This involves comparing the recent resistance measurements of Pole 1 with all previous Pole 1 measurements, Pole 2 with Pole 2 and Pole 3 with Pole 3. Observe the trend of the resistance measurements on each pole. Are they staying fairly the same? Are they slowly increasing? Have there been any large changes in the readings? Trends which are constant or slowly increasing are usually normal and rarely require corrective action. Trends with large changes are usually not normal and may require corrective action. Third, the resistance measurements from each of the three phases should be compared to the circuit breaker manufacturer’s limit. This value is usually found in the circuit breaker’s instruction manual. If any of the resistance measurements are very near to or exceed this limit, corrective action is normally required.

Table 3-11 presents an example of the Phase C static contact resistance measurement slowing increasing over time and then exceeding the manufacturer’s limit.

Test Date	Phase A Static Contact Resistance (micro-ohms)	Phase B Static Contact Resistance (micro-ohms)	Phase C Static Contact Resistance (micro-ohms)	Manufacturer’s Static Contact Resistance Limit (max.) (micro-ohms)
3/19/91	140	137	142	200
2/21/95	146	140	148	200
5/23/01	150	155	162	200
6/1/05	158	151	188	200
4/15/12	155	160	243	200

4. Power Testing

What is the test? The power factor test measures the capacitance and watts loss levels of various insulating components in the circuit breaker.

What are the test’s objectives? The objectives of the power factor test are to assist in making an assessment of the condition of the insulating components in the circuit breaker. These measurements are then compared to the circuit breaker manufacturer’s specifications, when they exist, to see if the circuit breaker’s insulating components are deteriorating. Most commonly, circuit breaker manufacturers do not have power factor test specifications and the measurements are compared to previous test results from the same circuit breaker to determine if they are remaining constant or changing. Conversely, oil-filled condenser bushing manufacturers do provide power factor and capacitance factory test measurements on their nameplates. For example, a marked increase in the capacitance measurements of an oil-filled condenser bushing may indicate a defect or deterioration internal to the bushing. If this measurement exceeds the manufacturer’s specifications, the bushing may need to be replaced.

What does the test check/test/measure/evaluate? The power factor test evaluates the condition of insulation systems by measuring the capacitances and losses of the system. These two values are then used to calculate the power factor of the insulation system. The following insulation systems can be measured in circuit breakers:

• Porcelain
• Solid composites
• Oil
• Paper and oil
• Wood

The power factor test is not very effective in measuring the losses of vacuum or SF₆ gas. However, it can be used to evaluate insulating components of these types of circuit breakers. The following is a listing of components in all types of circuit breakers which can be power factor tested:

• Bushings
• Grading or TRV capacitors
• Internal support insulators
• External support insulators
• Operating rods

What are the test’s limitations? This test requires a breaker clearance, is very time consuming, requires extensive operator training, and produces limited information on the electrical condition of the breaker (electrical insulating condition only) and no information on the mechanical condition. (This is a good example of test cost versus test results. The results of the test may not support performing the test as part of the normal maintenance program.) This test has limited effectiveness in detecting moisture in the insulation system when the temperature of the insulation system is below freezing. When water turns into ice its watts loss readings decrease to such low levels that it becomes difficult for the power factor test set to detect it. Whenever possible, the insulation system should be warmed up to above freezing and time allowed for the possible presence of ice to melt before performing this test.

Another limitation is performing power factor measurements on insulation systems in high humidity environments or in the rain. The presence of surface moisture on the insulation system can show up as elevated watts loss readings during the power factor test. This can result in a healthy insulation system appearing to be deteriorated when it is not. This can also mask a problem in the insulation system. Attempting to analyze power factor measurements during these conditions is challenging and may lead to numerous retests. It is best to avoid them whenever possible.

The insulation systems of most modern SF₆ gas circuit breakers have very low losses. The losses of the SF₆ gas itself is so low that most power factor test sets cannot accurately measure it. However, the solid insulation systems inside of SF₆ gas circuit breakers can be measured and trended. These measurements are very low and sometimes are lower than the sensitivity of the power factor test set. For this reason, some people have chosen not to periodically perform power factor measurements on SF₆ gas circuit breakers. It is not clear that this is a proper course of action. More research is needed on the effectiveness of power factor testing on SF₆ gas circuit breakers.

When does the test need to be performed? This test needs to be performed upon the initial commissioning of the circuit breaker to collect baseline test data. Future test data can be compared to the commissioning test data to see if any deviations have occurred and if any corrective actions may be required. These future tests may be regular periodic maintenance tests or special investigative tests which may be required due to an in-service failure or a perceived problem of the circuit breaker. The regular periodic maintenance tests are normally performed at fixed time intervals that have been selected by the owner and/or operator of the circuit breaker. These fixed time intervals are not standardized across the industry and can vary from 2 years to 10 years or more. Many factors go into the selection of the fixed time interval chosen for each circuit breaker. These factors are explained in more detail elsewhere in this guidebook.

Which type of circuit breakers is the test used on? This test is used on all types of circuit breakers including air, oil, SF₆ gas and vacuum breakers.

How is the test performed? This test is performed with the circuit breaker de-energized and out of service (off-line). Normally, external high voltage connections are removed from the circuit breaker so that only the circuit breaker itself is being tested and to minimize the risk of flashing across the open circuit breaker disconnect switches or current leakage over bus insulators during the test. Current transformers in use on the circuit breaker are left connected to their protective relays and meters. Unused current transformers should have their secondaries shorted and grounded. The dielectric medium in the circuit breaker needs to be at proper levels. On oil circuit breakers, the oil level in each tank needs to be within the limits on the oil level gauge. On SF₆ gas circuit breakers, the SF₆ gas pressure in each tank needs to be within the limits specified by the manufacturer. These limits are normally shown on the circuit breaker’s nameplate. The outside surfaces of the bushing insulation (normally porcelain or solid composite material) should be inspected and cleaned if necessary before performing the test. The top terminals of the bushings should also be inspected and cleaned to insure a good connection point for the test equipment leads. Surface moisture and/or contamination on the bushings can have a negative impact on the test so it is preferred to thoroughly clean the bushings and not perform this test in rain, snow or high humidity conditions. The test voltage used for the power factor test is normally 10 kV rms. The power factor test is a non-destructive test in that the test voltage used is always less than the rating of the insulation under test. For insulation systems less than 10 kV rms, test values lower than the rating of the insulation are used. There is extensive information available on power factor testing from the manufacturers of this test equipment. This information includes power factor testing theory, recommended test voltage levels and recommended testing configurations for various electrical substation equipment. Interpretation of some of the test results may be confusing and require outside expertise.

The following are the general steps required to measure the power factor of a circuit breaker rated above 10 kV rms with a field power factor test set. Six measurements will be made (one per bushing) of the overall circuit breaker’s insulation system with the circuit breaker in the open position. Three measurements will be made (one per phase) of the overall circuit breaker’s insulation system with the circuit breaker in the closed position. Twelve measurements will be made (two per bushing) of the bushings’ insulation systems (this applies to condenser bushings). The manufacturer’s instructions should always be consulted for the specific operating requirements of each field test set.

1. Properly identify the circuit breaker on which the test is to be performed. This is done by locating the circuit breaker with the correct manufacturer’s name, manufacturer’s serial number and owner’s equipment identification (ID) number in the substation. If a permanent owner’s equipment identification (ID) number label is absent, the three-line drawing of the substation can be referenced to determine the location of the circuit breaker. A temporary label can be attached to the circuit breaker for use during the test. It should be replaced with a permanent label as soon as practical.

2. Check that the circuit breaker has been properly removed from service, lock out and tag out procedures have been followed and the circuit breaker is safe to work on.

3. Install grounds on the external high voltage leads to Bushing Numbers 1 through 6 (reference Figure 3-7 Circuit Breaker Bushing and Pole Numbering Convention for Power Factor Testing).

4. Connect the ground lead from the power factor set to the substation ground connection to the circuit breaker.

5. Remove the external high voltage connections and grounds from Bushing Numbers 1 and 2.

6. Connect the high voltage lead from the power factor set to Bushing Number 1.

7. No connections are to be made to Bushing Number 2 (left floating).

8. Check that there is sufficient electrical clearance from the disconnected external high voltage leads to the top of Bushing Numbers 1 and 2.

9. Check that the circuit breaker is in the open position.

10. Turn on the power factor set.

11. Select Test Mode: GST (Grounded Specimen Test) – Ground Red and Blue Low Voltage Test Leads. (Note: The red and blue low voltage test leads are not used for this test.) This test mode measures the capacitance and watts loss of the insulation system from Bushing Number 1 to ground with the circuit breaker in the open position.

12. Slowly raise the output voltage of the power factor set to 10 kV rms. (For automated power factor sets, program the set for 10 kV rms test voltage level.)

13. Record the milliamps, watts, and capacitance and % PF (power factor) readings from the measurement.

14. Slowly lower the output voltage of the power factor set to zero.

15. Close the circuit breaker.

16. Select Test Mode: GST (Grounded Specimen Test) – Ground Red and Blue Low Voltage Test Leads. (Note: The red and blue low voltage test leads are not used for this test.) This test mode measures the capacitance and watts loss of the insulation system from Bushing Numbers 1 and 2 to ground with the circuit breaker in the closed position.

17. Slowly raise the output voltage of the power factor set to 10 kV rms. (For automated power factor sets, program the set for 10 kV rms test voltage level.)

18. Record the milliamps, watts, and capacitance and % PF (power factor) readings from the measurement.

19. Slowly lower the output voltage of the power factor set to zero.

20. Turn off the power factor set.

21. Remove the high voltage lead from the power factor set from Bushing Number 1.

22. No connections are to be made to Bushing Number 1 (left floating).

23. Connect the high voltage lead from the power factor set to Bushing Number 2.

24. Open the circuit breaker.

25. Turn on the power factor set.

26. Select Test Mode: GST (Grounded Specimen Test) – Ground Red and Blue Low Voltage Test Leads. (Note: The red and blue low voltage test leads are not used for this test.) This test mode measures the capacitance and watts loss of the insulation system from Bushing Number 2 to ground with the circuit breaker in the open position.

27. Slowly raise the output voltage of the power factor set to 10 kV rms. (For automated power factor sets, program the set for 10 kV rms test voltage level.)

28. Record the milliamps, watts, and capacitance and % PF (power factor) readings from the measurement.

29. Slowly lower the output voltage of the power factor set to zero.

30. Turn off the power factor set.

31. Remove the high voltage lead from the power factor set from Bushing Number 2.

32. No connections are to be made to Bushing Number 2 (left floating).

33. Remove the external high voltage connections and grounds from Bushing Numbers 3 and 4.

34. Connect the high voltage lead from the power factor set to Bushing Number 4.

35. No connections are to be made to Bushing Number 3 (left floating).

36. Check that there is sufficient electrical clearance from the disconnected external high voltage leads to the top of Bushing Numbers 3 and 4.

37. Leave the ground lead from the power factor set connected to the substation ground connection to the circuit breaker.

38. Check that the circuit breaker is in the open position.

39. Turn on the power factor set.

40. Select Test Mode: GST (Grounded Specimen Test) – Ground Red and Blue Low Voltage Test Leads. (Note: The red and blue low voltage test leads are not used for this test.) This test mode measures the capacitance and watts loss of the insulation system from Bushing Number 4 to ground with the circuit breaker in the open position.

41. Slowly raise the output voltage of the power factor set to 10 kV rms. (For automated power factor sets, program the set for 10 kV rms test voltage level.)

42. Record the milliamps, watts, and capacitance and % PF (power factor) readings from the measurement.

43. Slowly lower the output voltage of the power factor set to zero.

44. Close the circuit breaker.

45. Select Test Mode: GST (Grounded Specimen Test) – Ground Red and Blue Low Voltage Test Leads. (Note: The red and blue low voltage test leads are not used for this test.) This test mode measures the capacitance and watts loss of the insulation system from Bushing Numbers 3 and 4 to ground with the circuit breaker in the closed position.

46. Slowly raise the output voltage of the power factor set to 10 kV rms. (For automated power factor sets, program the set for 10 kV rms test voltage level.)

47. Record the milliamps, watts, and capacitance and % PF (power factor) readings from the measurement.

48. Slowly lower the output voltage of the power factor set to zero.

49. Turn off the power factor set.

50. Remove the high voltage lead from the power factor set from Bushing Number 4.

51. No connections are to be made to Bushing Number 4 (left floating).

52. Connect the high voltage lead from the power factor set to Bushing Number 3.

53. Open the circuit breaker.

54. Turn on the power factor set.

55. Select Test Mode: GST (Grounded Specimen Test) – Ground Red and Blue Low Voltage Test Leads. (Note: The red and blue low voltage test leads are not used for this test.) This test mode measures the capacitance and watts loss of the insulation system from Bushing Number 3 to ground with the circuit breaker in the open position.

56. Slowly raise the output voltage of the power factor set to 10 kV rms. (For automated power factor sets, program the set for 10 kV rms test voltage level.)

57. Record the milliamps, watts, and capacitance and % PF (power factor) readings from the measurement.

58. Slowly lower the output voltage of the power factor set to zero.

59. Turn off the power factor set.

60. Remove the high voltage lead from the power factor set from Bushing Number 3.

61. No connections are to be made to Bushing Number 3 (left floating).

62. Remove the external high voltage connections and grounds from Bushing Numbers 5 and 6.

63. Connect the high voltage lead from the power factor set to Bushing Number 5.

64. No connections are to be made to Bushing Number 6 (left floating).

65. Check that there is sufficient electrical clearance from the disconnected external high voltage leads to the top of Bushing Numbers 5 and 6.

66. Leave the ground lead from the power factor set connected to the substation ground connection to the circuit breaker.

67. Check that the circuit breaker is in the open position.

68. Turn on the power factor set.

69. Select Test Mode: GST (Grounded Specimen Test) – Ground Red and Blue Low Voltage Test Leads. (Note: The red and blue low voltage test leads are not used for this test.) This test mode measures the capacitance and watts loss of the insulation system from Bushing Number 5 to ground with the circuit breaker in the open position.

70. Slowly raise the output voltage of the power factor set to 10 kV rms. (For automated power factor sets, program the set for 10 kV rms test voltage level.)

71. Record the milliamps, watts, and capacitance and % PF (power factor) readings from the measurement.

72. Slowly lower the output voltage of the power factor set to zero.

73. Close the circuit breaker.

74. Select Test Mode: GST (Grounded Specimen Test) – Ground Red and Blue Low Voltage Test Leads. (Note: The red and blue low voltage test leads are not used for this test.) This test mode measures the capacitance and watts loss of the insulation system from Bushing Numbers 5 and 6 to ground with the circuit breaker in the closed position.

75. Slowly raise the output voltage of the power factor set to 10 kV rms. (For automated power factor sets, program the set for 10 kV rms test voltage level.)

76. Record the milliamps, watts, and capacitance and % PF (power factor) readings from the measurement.

77. Slowly lower the output voltage of the power factor set to zero.

78. Turn off the power factor set.

79. Remove the high voltage lead from the power factor set from Bushing Number 5.

80. No connections are to be made to Bushing Number 5 (left floating).

81. Connect the high voltage lead from the power factor set to Bushing Number 6.

82. Open the circuit breaker.

83. Turn on the power factor set.

84. Select Test Mode: GST (Grounded Specimen Test) – Ground Red and Blue Low Voltage Test Leads. (Note: The red and blue low voltage test leads are not used for this test.) This test mode measures the capacitance and watts loss of the insulation system from Bushing Number 6 to ground with the circuit breaker in the open position.

85. Slowly raise the output voltage of the power factor set to 10 kV rms. (For automated power factor sets, program the set for 10 kV rms test voltage level.)

86. Record the milliamps, watts, and capacitance and % PF (power factor) readings from the measurement.

87. Slowly lower the output voltage of the power factor set to zero.

88. Turn off the power factor set.

89. If the circuit breaker’s bushings have test taps (condenser bushings), continue on to Step 90. If not, reconnect the external high voltage connections to Bushing Numbers 1 through 6 and remove the grounds to complete the test.

90. Leave the high voltage lead from the power factor set connected to the top of Bushing Number 6.

91. Unscrew the test tap cover on the flange of Bushing Number 6.

92. Connect the red low voltage lead from the power factor set to the test tap on Bushing Number 6.

93. Turn on the power factor set.

94. Select Test Mode: UST (Ungrounded Specimen Test) – Red Low Voltage Test Lead. (Note: Only the red low voltage test lead is used for this test.) This test mode measures the capacitance and watts loss of the insulation system from the center conductor of Bushing Number 6 to the bushing’s test tap. This is called the C1 insulation of the bushing.

95. Slowly raise the output voltage of the power factor set to 10 kV rms. (For automated power factor sets, program the set for 10 kV rms test voltage level.)

96. Record the milliamps, watts, and capacitance and % PF (power factor) readings from the measurement.

97. Slowly lower the output voltage of the power factor set to zero.

98. Turn off the power factor set.

99. Remove the red low voltage lead from the power factor set from the test tap on Bushing Number 6.

100. Remove the high voltage lead from the power factor set from the top of Bushing Number 6.

101. Connect the red low voltage lead from the power factor set to the top of Bushing Number 6.

102. Connect the high voltage lead from the power factor set to the test tap on Bushing Number 6. (Note: A short clip jumper may be helpful in making this connection.)

103. Check that there is sufficient electrical clearance from the energized end of the high voltage lead from the power factor set to the grounded metal around the test tap of Bushing Number 6.

104. Turn on the power factor set.

105. Select Test Mode: GST (Ungrounded Specimen Test) – Guard Red Low Voltage Test Lead. (Note: Only the red low voltage test lead is used for this test.) This test mode measures the capacitance and watts loss of the insulation system from the test tap of Bushing Number 6 to the grounded flange. This is called the C2 insulation of the bushing.

106. Slowly raise the output voltage of the power factor set to 2 kV rms (for bushings rated 115 kV rms and above) or to 500 V rms (for bushings rated less than 115 kV rms). (For automated power factor sets, program the set for 2 kV rms or 500 V rms test voltage level.)

107. Record the milliamps, watts, and capacitance and % PF (power factor) readings from the measurement.

108. Slowly lower the output voltage of the power factor set to zero.

109. Turn off the power factor set.

110. Remove the high voltage lead from the power factor set from the test tap on Bushing Number 6.

111. Install the test tap cover on Bushing Number 6.

112. Remove the red low voltage lead from the power factor set from the top of Bushing Number 6.

113. Reconnect the external high voltage connection and ground to the top of Bushing Number 6.

114. Connect the high voltage lead from the power factor set to the top of Bushing Number 4.

115. Repeat Steps 91-113 except perform the tests on Bushing Number 4.

116. Connect the high voltage lead from the power factor set to the top of Bushing Number 2.

117. Repeat Steps 91-113 except perform the tests on Bushing Number 2.

118. Connect the high voltage lead from the power factor set to the top of Bushing Number 1.

119. Repeat Steps 91-113 except perform the tests on Bushing Number 1.

120. Connect the high voltage lead from the power factor set to the top of Bushing Number 3.

121. Repeat Steps 91-113 except perform the tests on Bushing Number 3.

122. Connect the high voltage lead from the power factor set to the top of Bushing Number 5.

123. Repeat Steps 91-113 except perform the tests on Bushing Number 5.

124. Remove grounds from the external high voltage leads to Bushing Numbers 1 through 6.

125. Leave the circuit breaker in the same position (open or closed) that it was found before these tests.

How are the test results interpreted? The test results are reviewed one set of measurements at a time. A circuit breaker needs to pass each individual set of measurements for it to pass the entire power factor test. For a dead-tank circuit breaker with bushings that do not have test taps, the individual measurements to be reviewed are:

1. Circuit Breaker Open – Bushing Number 1

2. Circuit Breaker Open – Bushing Number 2

3. Circuit Breaker Open – Bushing Number 3

4. Circuit Breaker Open – Bushing Number 4

5. Circuit Breaker Open – Bushing Number 5

6. Circuit Breaker Open – Bushing Number 6

7. Circuit Breaker Closed – Pole 1 (Bushing Numbers 1-2)

8. Circuit Breaker Closed – Pole 2 (Bushing Numbers 3-4)

9. Circuit Breaker Closed – Pole 3 (Bushing Numbers 5-6)

10. Tank-Loss Index – Pole 1 (Bushing Numbers 1-2)

11. Tank-Loss Index – Pole 2 (Bushing Numbers 3-4)

12. Tank-Loss Index – Pole 3 (Bushing Numbers 5-6)

The Circuit Breaker Open test results from all six bushings are reviewed by first comparing the microamp readings from each bushing to each other. Usually, the microamp readings from Bushing Numbers 1, 3 and 5 will be very close to each other and the microamp readings from Bushing Numbers 2, 4 and 6 will be very close to each other. On some circuit breakers, all six microamp readings will be very close to each other. This pattern will depend upon the internal construction of the circuit breaker. Therefore, circuit breakers of the same manufacturer and model number will have a similar pattern. Next, the power factor readings from each bushing of the Circuit Breaker Open test results are compared to each other. Usually, all six readings will be fairly close to each other. They also should be within the circuit breaker manufacturer’s power factor limits, if they exist. Whether manufacturer’s power factor limits exist or not, the microamp and power factor readings should be compared one phase at a time to previous tests of the same circuit breaker to establish trends. Are they staying fairly the same? Are they slowly increasing? Are they slowly decreasing? Have there been any large changes in the measurements? Trends which are fairly constant are normal. Trends which are slowly increasing or slowly decreasing do not normally require corrective action but may warrant a shorter time interval until the next series of power factor tests. Trends with large changes are usually not normal and may require corrective action.

The Circuit Breaker Closed test results from all three poles are reviewed by first comparing the microamp readings from each pole to each other. Usually, the three readings will be very close to each other. Next, the power factor readings from each pole are compared to each other. Usually, all three readings will be very close to each other. They also should be within the circuit breaker manufacturer’s power factor limits, if they exist. Whether manufacturer’s power factor limits exist or not, the microamp and power factor readings should be compared one phase at a time to previous tests of the same circuit breaker to establish trends. Are they staying fairly the same? Are they slowly increasing? Are they slowly decreasing? Have there been any large changes in the measurements? Trends which are fairly constant are normal. Trends which are slowly increasing or slowly decreasing do not normally require corrective action but may warrant a shorter time interval until the next series of power factor tests. Trends with large changes are usually not normal and may require corrective action.

The Circuit Breaker Open test results from all six bushings are reviewed by first comparing the microamp readings from each bushing to each other. Usually, the microamp readings from Bushing Numbers 1, 3 and 5 will be very close to each other and the microamp readings from Bushing Numbers 2, 4 and 6 will be very close to each other. On some circuit breakers, all six microamp readings will be very close to each other. This pattern will depend upon the internal construction of the circuit breaker. Therefore, circuit breakers of the same manufacturer and model number will have a similar pattern. Next, the power factor readings from each bushing of the Circuit Breaker Open test results are compared to each other. Usually, all six readings will be fairly close to each other. They also should be within the circuit breaker manufacturer’s power factor limits, if they exist. Whether manufacturer’s power factor limits exist or not, the microamp and power factor readings should be compared one phase at a time to previous tests of the same circuit breaker to establish trends. Are they staying fairly the same? Are they slowly increasing? Are they slowly decreasing? Have there been any large changes in the measurements? Trends which are fairly constant are normal. Trends which are slowly increasing or slowly decreasing do not normally require corrective action but may warrant a shorter time interval until the next series of power factor tests. Trends with large changes are usually not normal and may require corrective action.

The Tank-Loss Index (TLI) in watts is calculated for each pole using the following formula:

TLI = (Circuit Breaker Closed watts) – (Sum of two Circuit Breaker Open watts)

For most circuit breakers, a TLI between +0.05 watts and -0.10 watts is considered normal.

For most circuit breakers, a TLI between +0.10 watts and +0.05 watts or between -0.10 watts and -0.20 watts is considered slightly abnormal. Corrective action is not normally required but a shorter time interval until the next series of power factor tests may be warranted.

For most circuit breakers, a TLI above +0.10 watts or below -0.20 watts is considered not normal and corrective action may be required.

Since some circuit breakers do not follow these limits, it is very important to compare the TLI values to previous tests of the same breaker to establish norms and trends.

For a dead-tank circuit breaker with bushings that do have test taps, the additional individual measurements to be reviewed are:

1. C1 Test – Bushing Number 1

2. C1 Test – Bushing Number 2

3. C1 Test – Bushing Number 3

4. C1 Test – Bushing Number 4

5. C1 Test – Bushing Number 5

6. C1 Test – Bushing Number 6

7. C2 Test – Bushing Number 1

8. C2 Test – Bushing Number 2

9. C2 Test – Bushing Number 3

10. C2 Test – Bushing Number 4

11. C2 Test – Bushing Number 5

12. C2 Test – Bushing Number 6

The C1 Test capacitance and power factor measurements for Bushing Number 1 are compared to the values on its nameplate which were measured at the time that the bushing was manufactured. They should also be compared to the same measurements from previous tests. Are they staying fairly the same? Are they slowly increasing? Are they slowly decreasing? Have there been any large changes in the measurements? Trends which are fairly constant are normal. Trends which are slowly increasing or slowly decreasing do not normally require corrective action but may warrant a shorter time interval until the next series of timing tests. Trends with large changes, such as a measurement of twice the nameplate power factor value or a measurement of 110% of the nameplate capacitance value, are usually not normal and may require corrective action.

The process above is used for the C1 Test results of the remaining bushings.

The C2 Test capacitance and power factor measurements for Bushing Number 1 are compared to the values on its nameplate which were measured at the time that the bushing was manufactured. They should also be compared to the same measurements from previous tests. Are they staying fairly the same? Are they slowly increasing? Are they slowly decreasing? Have there been any large changes in the measurements? Trends which are fairly constant are normal. Trends which are slowly increasing or slowly decreasing do not normally require corrective action but may warrant a shorter time interval until the next series of timing tests.

Trends with large changes, such as a measurement of twice the nameplate power factor value or a measurement of 110% of the nameplate capacitance value, are usually not normal and may require corrective action. Some bushing designs result in C2 capacitance and power factor measurements when installed in equipment that do not agree with the bushing’s nameplate. Usually, this is noted in the bushing manufacturer’s instruction manual. In this case, the initial measurements made when the bushing is placed in service are used as the reference or baseline measurements. The bushing manufacturer should be consulted if there are any questions or concerns.

The process above is used for the C2 Test results of the remaining bushings.

Table 3-12 provides an example of power factor test results of an oil circuit breaker with bushings that do have test taps that does not have issues.

Test ID	microamps	Watts	% Power Factor	Capacitance (pF)
CB Open Tests
Bushing 1	1872	0.071	0.381	496.1
Bushing 2	1844	0.069	0.374	488.7
Bushing 3	1882	0.069	0.366	498.7
Bushing 4	1860	0.067	0.360	492.9
Bushing 5	1866	0.070	0.377	494.5
Bushing 6	1882	0.050	0.265	499.5
CB Closed Tests
Bushings 1-2	3650	0.100	0.273	967.2
Bushings 3-4	3660	0.096	0.269	969.9
Bushings 5-6	3670	0.100	0.272	972.5
Tank-Loss Index
Bushings 1-2	—	-0.040	—	—
Bushings 3-4	—	-0.040	—	—
Bushings 5-6	—	-0.020	—	—
Bushing C1 Tests
Bushing 1	1434	0.054	0.376	381
Bushing 2	1408	0.046	0.326	368
Bushing 3	1434	0.050	0.348	380
Bushing 4	1414	0.046	0.325	375
Bushing 5	1420	0.046	0.323	376
Bushing 6	1444	0.049	0.339	383
Bushing C2 Tests
Bushing 1	7894	0.402	0.509	2092
Bushing 2	9658	0.511	0.529	2559
Bushing 3	7415	0.363	0.490	1965
Bushing 4	7336	0.404	0.551	1944
Bushing 5	8725	0.453	0.519	2312
Bushing 6	7668	0.383	0.499	2032

An example of power factor test results of an oil circuit breaker with an elevated C1 power factor on Bushing 4 is shown in Table 3-13. Note that the elevated power factor on the Bushing 4 C1 Test also shows up as an elevated power factor on the Bushing 4 CB Open Test. This is due to the fact that both these tests measure the condition of Bushing 4.

Test ID	Microamps	Watts	% Power Factor	Capacitance (pF)
CB Open Tests
Bushing 1	1872	0.071	0.381	496.1
Bushing 2	1844	0.069	0.374	488.7
Bushing 3	1882	0.069	0.366	498.7
Bushing 4	1860	0.251	1.349	492.9
Bushing 5	1866	0.070	0.377	494.5
Bushing 6	1882	0.050	0.265	499.5
CB Closed Tests
Bushings 1-2	3650	0.100	0.273	967.2
Bushings 3-4	3660	0.285	0.779	969.9
Bushings 5-6	3670	0.100	0.272	972.5
Tank-Loss Index
Bushings 1-2	—	-0.040	—	—
Bushings 3-4	—	-0.035	—	—
Bushings 5-6	—	-0.020	—	—
Bushing C1 Tests
Bushing 1	1434	0.054	0.376	381
Bushing 2	1408	0.046	0.326	368
Bushing 3	1434	0.050	0.348	380
Bushing 4	1414	0.230	1.627	375
Bushing 5	1420	0.046	0.323	376
Bushing 6	1444	0.049	0.339	383
Bushing C2 Tests
Bushing 1	7894	0.402	0.509	2092
Bushing 2	9658	0.511	0.529	2559
Bushing 3	7415	0.363	0.490	1965
Bushing 4	7336	0.404	0.551	1944
Bushing 5	8725	0.453	0.519	2312
Bushing 6	7668	0.383	0.499	2032

An example of power factor test results of an SF₆ gas circuit breaker that does not have issues is shown in Table 3-14. Note that the microamps and watts readings on Bushing Numbers 1, 3 and 5 are similar and the same readings on Bushing Numbers 2, 4 and 6 are similar but different from the odd numbered bushings. This is due to the differences in the internal construction of the circuit breaker.

Test ID	Microamps	Watts	% Power Factor	Capacitance (pF)
CB Open Tests
Bushing 1	361	0.0056	0.155	95.7
Bushing 2	524	0.0072	0.137	138.9
Bushing 3	361	0.0050	0.139	95.7
Bushing 4	526	0.0078	0.148	139.4
Bushing 5	360	0.0052	0.144	95.4
Bushing 6	525	0.0076	0.145	139.1
CB Open Tests
Bushings 1-2	9	0.0002	—	2.4
Bushings 3-4	10	0.0002	—	2.6
Bushings 5-6	9	0.0000	—	2.4

5. Hi-Pot Testing

What is the test? The Hi-pot test measures the dielectric withstand capability or electrical strength of the insulation systems in the circuit breaker. “Hi-Pot” is a shortened version of “High-Potential”. This test is either conducted using a DC or AC output high voltage Hi-pot test set.

What are the test’s objectives? The objectives of the Hi-pot test are to assist in making an assessment of the condition of the insulation systems in the circuit breaker. This is done by determining whether or not these insulation systems can withstand the magnitude of the applied test voltage for the time duration of the test (normally 1 minute). This is a Pass/Fail test. There are no test measurements to be trended or compared with previous tests. When possible, the circuit breaker’s instruction manual or manufacturer should be consulted for the values of the voltage and time duration of the test. If the insulation system breaks down (shorts out) before the test time has been completed, the test is considered “Failed”. The test needs to be repeated after repairs or replacement of the insulation system have been made. A “Pass” is needed before placing the equipment into service.

What does the test check/test/measure/evaluate? The Hi-pot test evaluates the electrical strength of insulation systems. The overall circuit breaker insulation system can be tested or the following individual components:

• Vacuum interrupters
• Bushings
• Grading or TRV capacitors (only using a dc hi-pot)
• Internal support insulators
• External support insulators
• Operating rods

What are the test’s limitations? This is a Pass/Fail test and requires the breaker to be taken out on clearance for the test. There are no test measurements to be trended or compared with previous tests. There are no test measurements that could be used to grade or to rate the quality of the insulation system. The insulation system either passes the test or it fails. Additional testing of the insulation system, such as power factor measurements, is usually performed when supplemental information is needed to assess the condition of the insulation system.

The DC Hi-pot test requires a slower voltage ramp up time then the AC tester and does not stress the insulation with both polarities. The AC Hi-pot test results in higher normal leakage currents which could lead to more destruction if the insulation fails during the test. The DC Hi-pot is the only option for testing some internal components (e.g. capacitors).

Another limitation is the cost of the Hi-pot test equipment. For example, the cost of a 310 kV AC Hi-pot test set to test a 145 kV circuit breaker may exceed the maintenance budgets of most users. For this reason, they may choose to rent a test set when needed or to not perform the test at all.

When does the test need to be performed? All circuit breaker manufacturers perform Hi-pot testing on each new circuit breaker before it leaves the factory, as required by IEEE Standards. However, Hi-pot testing practices in the field are not standardized across the industry and vary widely. The following is a listing of when Hi-pot testing may be performed in the field.

When maintenance work or inspection and minor adjustments have been made but neither the internal or external ground insulation has been disturbed, no dielectric proof test is required. However, it is may be necessary to proof the test to determine that there is no foreign material left in the circuit breaker and that the internal insulation is dry (i.e., the internal portions of the bushing, high pressure gas feed tubes and operating rods).

A dielectric proof test is required:

1. As an acceptance or commissioning test of a new circuit breaker.

2. As part of a condition assessment of an old, service-aged circuit breaker.

3. As part of a condition assessment after a circuit breaker has been exposed to severe stress such as a lightning strike or an interruption of high fault current.

4. As part of a condition assessment after an internal inspection resulting in major replacement of operating linkages parts, etc.

5. As part of a condition assessment after a component of the main insulation system, such as a bushing or lift rod, has been replaced.

6. Restoration to service of a circuit breaker that has been de-energized for more than x months (typically 12 months).

7. As a pass/fail test of vacuum bottles.

For vacuum bottles, this test needs to be performed upon the initial commissioning of the circuit breaker and as regular periodic maintenance tests. Also, special investigative tests may be required due to an in-service failure or a perceived problem of the circuit breaker. The regular periodic maintenance tests are normally performed at fixed time intervals that have been selected by the owner and/or operator of the circuit breaker. These fixed time intervals are not standardized across the industry and can vary from 2 years to 10 years or more. Many factors go into the selection of the fixed time interval chosen for each circuit breaker. Condition based triggers may supplement the time-based triggers to help factor the breaker exposed service conditions. These factors are explained in more detail elsewhere in this guidebook.

Which type of circuit breakers is the test used on? This test is used on all types of circuit breakers including air, oil, SF₆ gas and vacuum breakers.

How is the test performed? This test is performed with the circuit breaker de-energized and out of service (off-line). Normally, external high voltage connections are removed from the circuit breaker so that only the circuit breaker itself is being tested and to minimize the risk of flashing across the open circuit breaker disconnect switches or their insulators during the test. Current transformers in use on the circuit breaker are left connected to their protective relays and meters. Unused current transformers should have their secondaries shorted and grounded. The dielectric medium in the circuit breaker needs to be at proper levels. On oil circuit breakers, the oil level in each tank needs to be within the limits on the oil level gauge. On SF₆ gas circuit breakers, the SF₆ gas pressure in each tank needs to be within the limits specified by the manufacturer. These limits are normally shown on the circuit breaker’s nameplate. The outside surfaces of the bushing insulation (normally porcelain or composite material) should be inspected and cleaned if necessary before performing the test. The top terminals of the bushings should also be inspected and cleaned to insure a good connection point for the test equipment leads. Surface moisture on the bushings can have a negative impact on the test so it is preferred to not perform this test in rain, snow or high humidity conditions. The test voltage used for the Hi-pot test varies depending upon the purpose of the test. For routine tests, such as vacuum bottle Hi-pot testing, the test voltage level is normally listed in the circuit breaker’s instruction manual. For acceptance or commissioning testing of the dielectric withstand capability of the entire circuit breaker, test voltage levels between 75-80% of factory test values are commonly used. For example, a 145 kV circuit breaker is tested at 310 kV rms at the power system frequency at the factory. An acceptance or commissioning test value between 232.5 and 248.0 kV rms at the power system frequency would be used. For condition assessment testing of the circuit breaker, a test voltage level of 110-120% of normal in-service phase-to-ground voltage is commonly used. For example, a 145 kV circuit breaker on a 138 kV system would be tested at a value between 88-96 kV rms (110-120% of 80 kV phase to ground system voltage) at the power system frequency. The circuit breaker manufacturer should be consulted whenever Hi-pot test voltages are not listed in their instruction manual. Note that if a DC Hi-pot test set is used the equivalent peak voltage is equal to 1.414 times the AC RMS (root mean squared) voltage.

The following are the general steps required to measure the dielectric withstand capability of the circuit breaker with a field Hi-pot test set. Six measurements will be made (one per bushing) with the circuit breaker in the open position. Three measurements will be made (one per phase) with the circuit breaker in the closed position. The manufacturer’s instructions should always be consulted for the specific operating requirements of each field test set.

1. Properly identify the circuit breaker on which the test is to be performed. This is done by locating the circuit breaker with the correct manufacturer’s name, manufacturer’s serial number and owner’s equipment identification (ID) number in the substation. If a permanent owner’s equipment identification (ID) number label is absent, the three-line drawing of the substation can be referenced to determine the location of the circuit breaker. A temporary label can be attached to the circuit breaker for use during the test. It should be replaced with a permanent label as soon as practical.

2. Check that the circuit breaker has been properly removed from service, lock out and tag out procedures have been followed and the circuit breaker is safe to work on.

3. Install grounds on the external high voltage leads to Bushing Numbers 1 through 6 (reference Figure 3-8 Circuit Breaker Bushing and Pole Numbering Convention for Hi-pot Testing).

4. Connect the ground output of the Hi-pot set to the substation ground connection to the circuit breaker.

5. Remove the external high voltage connection and ground from Bushing Number 1.

6. Connect the high voltage output of the Hi-pot set to Bushing Number 1 with solid bare copper wire (16 AWG wire size is often used for this).

7. Check that the high voltage output bare copper wire has sufficient electrical clearance from the disconnected external high voltage lead and from nearby leads, structures and equipment.

8. Check that the circuit breaker is in the open position.

9. Turn on the Hi-pot set and slowly raise the output voltage to the desired test level.

10. Maintain the desired test voltage level for one minute while continuously monitoring the output voltage (and current if available) and time duration of the test.

11. If there is a breakdown in the dielectric strength of the circuit breaker’s insulation during the test, the output voltage of the Hi-pot set will suddenly decrease. Immediately reduce the output voltage of the Hi-pot set to zero and record the time duration into the one minute test when the breakdown occurred and the voltage (and current if available) at the time of the breakdown.

12. If there is no breakdown in the dielectric strength of the circuit breaker’s insulation by the end of the one minute test interval, slowly lower the output voltage of the Hi-pot set to zero and turn it off. Record the test voltage level (and current if available) for the test.

13. Remove the external high voltage connection and ground from Bushing Number 2.

14. Check that there is sufficient electrical clearance from the top of Bushing Number 2 to the disconnected external high voltage lead and from nearby leads, structures and equipment.

15. Close the circuit breaker.

16. Repeat the Hi-pot test by following Steps 9-12 above.

17. Remove the high voltage output of the Hi-pot set from Bushing Number 1.

18. Reconnect the external high voltage connection and ground to Bushing Number 1.

19. Connect the high voltage output of the Hi-pot set to Bushing Number 2.

20. Check that the high voltage output bare copper wire has sufficient electrical clearance from the disconnected external high voltage lead and from nearby leads, structures and equipment.

21. Leave the ground output of the Hi-pot set connected to the substation ground connection to the circuit breaker.

22. Open the circuit breaker.

23. Repeat the Hi-pot test by following Steps 9-12 above.

24. Remove the high voltage output of the Hi-pot set from Bushing Number 2.

25. Reconnect the external high voltage connection and ground to Bushing Number 2.

26. Remove the external high voltage connection and ground from Bushing Number 4.

27. Connect the high voltage output of the Hi-pot set to Bushing Number 4.

28. Check that the high voltage output bare copper wire has sufficient electrical clearance from the disconnected external high voltage lead and from nearby leads, structures and equipment.

29. Leave the ground output of the Hi-pot set connected to the substation ground connection to the circuit breaker.

30. Check that the circuit breaker is in the open position.

31. Repeat the Hi-pot test by following Steps 9-12 above.

32. Remove the external high voltage connection and ground from Bushing Number 3.

33. Check that there is sufficient electrical clearance from the top of Bushing Number 3 to the disconnected external high voltage lead and from nearby leads, structures and equipment.

34. Close the circuit breaker.

35. Repeat the Hi-pot test by following Steps 9-12 above.

36. Remove the high voltage output of the Hi-pot set from Bushing Number 4.

37. Reconnect the external high voltage connection and ground to Bushing Number 4.

38. Connect the high voltage output of the Hi-pot set to Bushing Number 3.

39. Check that the high voltage output bare copper wire has sufficient electrical clearance from the disconnected external high voltage lead and from nearby leads, structures and equipment.

40. Leave the ground output of the Hi-pot set connected to the substation ground connection to the circuit breaker.

41. Open the circuit breaker.

42. Repeat the Hi-pot test by following Steps 9-12 above.

43. Remove the high voltage output of the Hi-pot set from Bushing Number 3.

44. Reconnect the external high voltage connection and ground to Bushing Number 3.

45. Remove the external high voltage connection and ground from Bushing Number 5.

46. Connect the high voltage output of the Hi-pot set to Bushing Number 5.

47. Check that the high voltage output bare copper wire has sufficient electrical clearance from the disconnected external high voltage lead and from nearby leads, structures and equipment.

48. Leave the ground output of the Hi-pot set connected to the substation ground connection to the circuit breaker.

49. Check that the circuit breaker is in the open position.

50. Repeat the Hi-pot test by following Steps 9-12 above.

51. Remove the external high voltage connection and ground from Bushing Number 6.

52. Check that there is sufficient electrical clearance from the top of Bushing Number 6 to the disconnected external high voltage lead and from nearby leads, structures and equipment.

53. Close the circuit breaker.

54. Repeat the Hi-pot test by following Steps 9-12 above.

55. Remove the high voltage output of the Hi-pot set from Bushing Number 5.

56. Reconnect the external high voltage connection and ground to Bushing Number 5.

57. Connect the high voltage output of the Hi-pot set to Bushing Number 6.

58. Check that the high voltage output bare copper wire has sufficient electrical clearance from the disconnected external high voltage lead and from nearby leads, structures and equipment.

59. Leave the ground output of the Hi-pot set connected to the substation ground connection to the circuit breaker.

60. Open the circuit breaker.

61. Repeat the Hi-pot test by following Steps 9-12 above.

62. Remove the high voltage output of the Hi-pot set from Bushing Number 6.

63. Reconnect the external high voltage connection and ground to Bushing Number 6.

64. Remove grounds from the external high voltage leads to Bushing Numbers 1 through 6.

65. Leave the circuit breaker in the same position (open or closed) that it was found before these tests.

How are the test results interpreted? This is a Pass/Fail test. In order for the component(s) of the circuit breaker being tested to pass the test, they must withstand the test voltage for the entire test period (normally 1 minute). If the insulation system breaks down (shorts out) before the end of the test period, the test has failed. A circuit breaker needs to pass each individual test for it to pass the entire Hi-pot test.

6. Oil Dielectric Breakdown

What is the test? The oil dielectric breakdown test measures the dielectric strength of the insulating oil in the circuit breaker.

What are the test’s objectives? The objectives of the oil dielectric breakdown test are to assist in making an assessment of the condition of the insulating oil in the circuit breaker. This is done by accurately measuring the level, in AC kilovolts, where a sample of the oil from the circuit breaker breaks down when exposed to a high voltage. These measurements are then compared to the circuit breaker manufacturer’s specifications to see if the oil is suitable to perform its insulating and arc extinguishing functions. The measurements are also compared to previous test results from the same circuit breaker to determine if the measurements are remaining constant or changing. For example, a marked decrease in the oil dielectric breakdown measurement may indicate that a high level of carbon has developed in the oil from arc interruptions. If the oil dielectric breakdown measurements are less than the circuit breaker manufacturer’s minimum specifications, corrective action, such as filtering the oil, is needed. If the breaker has internal wood or fiber components and the dielectric is lowered by moisture then an internal inspection and/or power factor test is advisable and the source of the moisture corrected.

What does the test check/test/measure/evaluate? The oil dielectric breakdown test evaluates the condition of the insulating oil in the circuit breaker by measuring its electrical strength.

What are the test’s limitations? One test may not be representative of the actual condition of the oil. Performing multiple tests is preferred. The results of the multiple tests can then be analyzed to better assess the condition of the oil. There are two ASTM standards for measuring the dielectric breakdown levels of insulating oil, D-877 and D-1816. The D-877 standard is not very sensitive to low levels of contaminants or moisture. The D-1816 standard is very sensitive to dissolved gases in oil to the point of failing an acceptable sample of oil when excessive amounts of dissolve gases are present.

When does the test need to be performed? This test needs to be performed upon the initial commissioning of the circuit breaker to collect baseline test data. Future test data can be compared to the commissioning test data to see if any deviations have occurred and if any corrective actions may be required. These future tests may be regular periodic maintenance tests or special investigative tests which may be required due to an in-service failure or a perceived problem of the circuit breaker. The regular periodic maintenance tests are normally performed at fixed time intervals that have been selected by the owner and/or operator of the circuit breaker. These fixed time intervals are not standardized across the industry and can vary from 2 years to 10 years or more. Many factors go into the selection of the fixed time interval chosen for each circuit breaker. This test has also been performed based upon the service duty of the breaker (e.g. number of fault interruptions, total load current interruptions since last test, etc.). These factors are explained in more detail elsewhere in this guidebook. Which type of circuit breakers is the test used on? As the name implies, this test is only used on oil circuit breakers.

How is the test performed? This test is performed with the circuit breaker de-energized and out of service (off-line). A sample of the circuit breaker’s insulating oil is required for this test. If the circuit breaker has one tank per phase, then three oil samples are required. If the circuit breaker has all three phases contained in one tank, then only one oil sample is required. The sample is analyzed at the substation with a field test set which measures the dielectric breakdown of the oil. There are two ASTM standards for measuring the dielectric breakdown levels of insulating oil, D-877 and D-1816. The D-877 standard uses a test cell consisting of two 1.0 inch (25.4 mm) diameter flat disc electrodes with a 0.1 inch (2.54 mm) gap. One of the electrodes is fixed and the other is adjustable to provide the required gap. The rate of rise of the voltage for the D-877 standard test is 3000 volts per second. The D-1816 standard uses a test cell consisting of two VDE (mushroom cap shape) 36 mm (1.42 inch) electrodes with either a 1.0 mm (0.04 inch) gap or a 2.0 mm (0.08 inch) gap. One of the electrodes is fixed and the other is adjustable to provide the required gap. The choice of the 1.0 mm gap or the 2.0 mm gap depends upon the circuit breaker manufacturer’s requirements or the practice of the owner of the circuit breaker. The rate of rise of the voltage for the D-1816 standard test is 500 volts per second. The D-1816 standard test cell contains a circulating system to stir the oil before and during the test. A circulating system is not used in the D-877 standard test cell. Most modern field test sets are capable of performing the D-877 or the D-1816 standard tests by using two different test cells.

The following are the general steps required to measure the dielectric breakdown level of the insulating oil with a field test set. The manufacturer’s instructions should always be consulted for the specific operating requirements of each field test set.

1. Properly identify the circuit breaker from which the oil sample is to be obtained. This is done by collecting the manufacturer’s name, manufacturer’s serial number, substation name and owner’s equipment identification (ID) number on the circuit breaker. If a permanent owner’s equipment identification (ID) number label is absent, the three-line drawing of the substation can be referenced to determine the location of the circuit breaker. A temporary label can be attached to the circuit breaker for use during the test. It should be replaced with a permanent label as soon as practical.

2. If three oil samples are required from the circuit breaker, properly identify which primary phase is connected to each pole of the circuit breaker. It is a best practice to permanently label the primary phase marking on the tanks, stands or enclosures of each circuit breaker when it is commissioned. If these permanent primary phase markings are absent, the three-line drawing or phasing drawing of the substation can be referenced to determine which primary phase is connected to which pole of the circuit breaker. Temporary labels can be attached to the circuit breaker for use during the test. These should be replaced with permanent labels as soon as practical.

3. The oil sample is collected from the oil drain valve on each tank of the circuit breaker.

4. Place oil absorbing mats under the sampling area.

5. Have clean dry rags on hand.

6. Place a clean empty one gallon bucket under the oil drain valve.

7. Slowly open the oil drain valve until oil begins to flow into the one gallon bucket.

8. Allow the oil to drain into the one gallon bucket watching for signs of water droplets or bubbles in the oil through the tygon tubing or the oil in the one gallon bucket.

9. Close the oil drain valve as the one gallon bucket becomes full.

10. Empty the oil from the one gallon bucket into a larger storage vessel for transportation and disposal off site.

11. Continue to drain the oil until water droplets or bubbles are no longer seen in the oil. Some utilities have installed sampling lines and valves on the equipment to reduce the possibility of contamination. In this case just draw the sample into a sampling vial. This also reduces the time required to perform the task.

12. After water droplets or bubbles are no longer seen in the oil, drain two more gallons of oil.

13. Collect enough oil in the one gallon bucket or sampling vial to fill the oil test cell of the field test set.

14. Close the oil sampling valve.

15. To perform a D-877 standard test:

    a. Configure the test cell with two 1.0 inch (25.4 mm) diameter flat disc electrodes with a 0.1 inch (2.54 mm) gap.

    b. Transfer the oil sample from the one gallon bucket or sampling vial into the oil test cell.

    c . Let the oil stand in the test cell for 2.0 minutes before performing any tests.

    d. Set the rate of rise for the test voltage to 3000 volts per second.

    e. Perform the test.

    f. Record the breakdown voltage in AC kilovolts.

    g. Let the oil stand for 1.0 minute.

    h. Perform the test.

    i. Record the breakdown voltage in AC kilovolts.

    j. Let the oil stand for 1.0 minute.

    k. Repeat for a total of five tests.

    l. Empty the oil in the oil test cell into a larger storage vessel for transportation and disposal off site.

1. To perform a D-1816 standard test:

   a. Configure the test cell with two VDE (mushroom shaped) 36 mm (1.42 inch) sphere electrodes with either a 1.0 mm (0.04 inch) gap or a 2.0 mm (0.08 inch) gap. (The choice of the 1.0 mm gap or the 2.0 mm gap depends upon the circuit breaker manufacturer’s requirements or the practice of the owner of the circuit breaker.)

   b. Transfer the oil sample from the one gallon bucket into the oil test cell.

   c. Some utilities have installed sampling lines and valves on the equipment so as to reduce the possibility of contamination. In this case just draw the sample into a sampling vial. This also reduces the time required to perform the task.

   d. Let the oil stand in the test cell for 3.0 minutes with the oil circulation system in operation before performing any tests.

   e. Set the rate of rise for the test voltage to 500 volts per second.

   f. Perform the test with the oil circulation system in operation.

   g. Record the breakdown voltage in AC kilovolts.

   h. Let the oil stand for 75 seconds with the oil circulation system in operation.

   i. Perform the test with the oil circulation system in operation.

   j. Record the breakdown voltage in AC kilovolts.

   k. Let the oil stand for 75 seconds with the oil circulation system in operation.

   l. Repeat for a total of five tests.

   m. Empty the oil in the oil test cell into a larger storage vessel for transportation and disposal off site.

How are the test results interpreted? First, the circuit breaker manufacturer’s oil dielectric breakdown (sometimes called dielectric strength) limits need to be obtained from the circuit breaker’s instruction manual. There is normally a minimum oil dielectric breakdown level for new oil and a lower minimum oil dielectric breakdown level for the periodic testing of the oil after the circuit breaker has been placed into service. The circuit breaker manufacturer should also specify the dielectric test method for their limits. For example, if the manufacturer states: “The dielectric strength of new oil should be at least 26,000 volts when tested with 1” disc terminals 0.1” apart”, this refers to the ASTM D-877 standard test. Care must be taken to match the ASTM standard test method used to test the oil with the ASTM standard test method stated in the circuit breaker manufacturer’s limits. The oil dielectric breakdown test results and limits are not the same between the different ASTM standard test methods for a given oil sample. The circuit breaker manufacturer must describe or state the ASTM standard test method to be used for his limits. Second, the average value of the five oil dielectric breakdown tests for each oil tank should be compared to the circuit breaker manufacturer’s limits. The new oil limit should be used for new oil and the service-aged oil limit for service-aged oil. If the average oil dielectric breakdown test value is very near to or below the appropriate limit, corrective action such as filtering the oil in that tank is normally required. Third, the average value of the five oil dielectric breakdown tests for each oil tank should be compared to previous test results for that oil tank. Observe the trend of the test results for each tank. Are they staying fairly the same? Are they slowly decreasing? Have there been any large changes in the readings? Trends which are constant or slowly decreasing are usually normal and rarely require corrective action. Trends with large changes are usually not normal and may require corrective action.

Table 3-15 shows an example of typical results from an oil dielectric breakdown test.

Table 3-16 shows an example of oil dielectric breakdown test results of an oil circuit breaker decreasing below the manufacturer’s minimum limit over time.

Test ID	Oil Dielectric Breakdown Level (kV)
Test 1	39
Test 2	25
Test 3	30
Test 4	31
Test 5	32
Average	31.4

Test Date	Average Oil Dielectric Breakdown Level (kV)	Manufacturer’s Oil Dielectric Breakdown Level Limit (min.) (kV)
3/19/91	45	26
2/21/95	40	26
5/23/01	36	26
6/1/05	30	26
4/15/12	22	26

7. Dissolved Gas in Oil Analysis

What is the test? The dissolved gas in oil analysis test measures the levels, in ppm, of specific gases dissolved in the oil of the circuit breaker.

What are the test’s objectives? The objectives of the dissolved gas in oil analysis test are to assist in making an assessment of the condition of the arcing and main contacts in the circuit breaker. This is done by accurately measuring the levels, in ppm, of key gases dissolved in the insulating oil of the circuit breaker. Circuit breaker manufacturers do not have dissolved gas in oil analysis test specifications. Therefore, the measurements are compared to statistical data from dissolved gas in oil analysis test results from similar circuit breakers and to previous test results from the same circuit breaker to determine if they are elevated, remaining constant or changing. Also, ratios of certain gases may be compared as part of the analysis.

What does the test check/test/measure/evaluate? The dissolved gas in oil analysis test evaluates the condition of the insulating oil in the circuit breaker by measuring the levels, in ppm, of the following key gases which are dissolved in the oil:

• Hydrogen (H₂)
• Methane (CH₄)
• Ethane (C₂H₆)
• Ethylene (C₂H₄)
• Acetylene (C₂H₂)
• Oxygen (O₂)
• Nitrogen (N₂)

The relative levels of these gases individually, and in ratios, can be used to detect problems inside of the circuit breaker such as degradation of the main and/or arcing contacts.

What are the test’s limitations? Gassing patterns can vary between different types of oil circuit breakers. A sizeable quantity of dissolved gas in oil analysis test results are required to establish valid patterns in the gasses generated in each type of oil circuit breaker. Also, different gassing patterns can exist within one type of oil circuit breaker due to the use of different materials in the main contacts, arcing contacts and interrupters.

There are no Standards or Guides in the industry for analyzing or interpreting the test results of dissolved gas in oil analysis in circuit breakers.

Most oil circuit breakers do not have oil sampling valves built into their drain valves. This presents a challenge to properly obtain an oil sample for dissolved gas in oil analysis.

When does the test need to be performed? This test needs to be performed upon the initial commissioning of the circuit breaker to collect baseline test data. Future test data can be compared to the commissioning test data to see if any deviations have occurred and if any corrective actions may be required. These future tests may be regular periodic maintenance tests or special investigative tests which may be required due to an in-service failure or a perceived problem of the circuit breaker. The regular periodic maintenance tests are normally performed at fixed time intervals that have been selected by the owner and/or operator of the circuit breaker. These fixed time intervals are not standardized across the industry and can vary from 3 months to 3 years or more. Many factors go into the selection of the fixed time interval chosen for each circuit breaker. This test has also been performed based upon the service duty of the breaker (e.g. number of fault interruptions, total load current interruptions since last test, etc.). These factors are explained in more detail elsewhere in this guidebook.

Which type of circuit breakers is the test used on? As the name implies, this test is only used on oil circuit breakers.

How is the test performed? This test can be performed with the circuit breaker either energized and in service (on-line) or with it de-energized and out of service (off-line). A sample of the circuit breaker’s insulating oil is required for this test. The sample will be sent to a laboratory for the analysis to be performed. If the circuit breaker has one tank per phase, then three oil samples are required. If the circuit breaker has all three phases contained in one tank, then only one oil sample is required. Each oil sample is collected in a glass syringe. The size of the glass syringe is normally 100 cc. If moisture in oil analysis is also to be performed on the oil sample, 100 cc is normally sufficient for both analyses.

The following steps are required to properly obtain an oil sample in a syringe:

1. Properly identify the circuit breaker from which the oil sample is to be obtained. This is done by collecting the manufacturer’s name, manufacturer’s serial number, substation name and owner’s equipment identification (ID) number on the circuit breaker. If a permanent owner’s equipment identification (ID) number label is absent, the three-line drawing of the substation can be referenced to determine the location of the circuit breaker. A temporary label can be attached to the circuit breaker for use during the test. It should be replaced with a permanent label as soon as practical.

2. If three oil samples are required from the circuit breaker, properly identify which primary phase is connected to each pole of the circuit breaker. It is a best practice to permanently label the primary phase marking on the tanks, stands or enclosures of each circuit breaker when it is commissioned. If these permanent primary phase markings are absent, the three-line drawing or phasing drawing of the substation can be referenced to determine which primary phase is connected to which pole of the circuit breaker. Temporary labels can be attached to the circuit breaker for use during the test. These should be replaced with permanent labels as soon as practical.

3. The oil sample is collected from the oil drain valve on each tank of the circuit breaker. This drain valve is not normally equipped with a sampling valve. A sampling valve can be permanently added to the drain valve or attached temporarily when the oil sample is obtained. One method of attaching a sampling valve to a drain valve is to use a series of reducers to step the size of the drain valve down to the size of the sampling valve. Obtaining an oil sample directly from the drain valve is not recommended. A very slow oil flow rate is needed to properly obtain an oil sample. This flow rate cannot be properly controlled with the drain valve. Also, the oil sample syringe needs to be connected to the valve with a short piece of tubing. The oil sampling valve provides a place to connect this tubing whereas the drain valve does not. Some utilities have installed sampling lines and valves on the equipment so as to reduce the possibility of contamination. In this case just draw the sample into a sampling vial. This also reduces the time required to perform the task.

4. Place oil absorbing mats under the sampling area.

5. Have clean dry rags on hand.

6. Connect a short section of tygon tubing to the oil sampling valve.

7. Place the other end of the tygon tubing into a clean empty one gallon bucket.

8. Open the oil sampling valve.

9. Slowly open the oil drain valve until oil begins to flow into the one gallon bucket.

10. Allow the oil to drain into the one gallon bucket watching for signs of water droplets or bubbles in the oil through the tygon tubing or the oil in the one gallon bucket.

11. Close the oil sampling valve as the one gallon bucket becomes full.

12. Empty the oil from the one gallon bucket into a larger storage vessel for transportation and disposal off site.

13. Continue to drain the oil until water droplets or bubbles are no longer seen in the oil.

14. After water droplets or bubbles are no longer seen in the oil, drain two more gallons of oil.

15. Close the oil sampling valve.

16. Measure the temperature of the oil in the one gallon bucket and record it on the oil sample sheet that will be sent to the laboratory with the oil sample syringe.

17. Check that the plunger on the syringe is pushed in.

18. Remove the end of the tygon tubing from the one gallon bucket and connect it to the stopcock on the syringe.

19. Turn the syringe so that the plunger is facing down and the stopcock is facing up.

20. Slowly open the oil sampling valve.

21. Turn the stopcock on the syringe to allow oil to flow into the syringe.

22. Pull down slowly on the plunger.

23. Fill the syringe to slightly past the last demarcation line on the syringe.

24. Turn the stopcock to stop filling the syringe.

25. Turn the stopcock to drain oil from the syringe into the one gallon bucket.

26. Slowly push the plunger in to expel any air bubbles that may be present in the oil in the syringe. Stop when the air bubbles have been removed.

27. Turn the stopcock on the syringe to allow oil to flow into the syringe.

28. Pull down slowly on the plunger.

29. Fill the syringe to the last demarcation line on the syringe but not past it.

30. Turn the stopcock to the closed position.

31. Close the oil sampling valve.

32. Close the oil drain valve.

33. Disconnect the tygon tubing from the stopcock.

34. Disconnect the tygon tubing from the oil sampling valve.

35. Fill in the oil sample sheet provided by the laboratory:

    a. Substation Name

    b. Circuit Breaker Equipment ID Number

    c. Circuit Breaker Phase Identifier (When required)

    d. Circuit Breaker Serial Number

    e. Sample Date

    f. Sample Oil Temperature

    g. Tests Required: Dissolved Gas Analysis (DGA) – ASTM D-3612

36. Send the filled syringe and filled-in oil sample sheet to the laboratory for analysis. Provide contact information as to where the test results need to be sent.

How are the test results interpreted? There are no Standards or Guides in the industry for the interpretation of dissolved gas in oil analysis of circuit breakers. Widely used limits for the individual gases do not exist. Also, since the level of each gas generated in an oil circuit breaker varies between different types of oil circuit breakers and within one type of oil circuit breaker when different materials are used in the main contacts, arcing contacts and interrupters, it is preferred that the owner and/or operator of the oil circuit breaker establish their own limits for each gas for each common group of oil circuit breakers. This process involves performing a statistical analysis of the dissolved gas in oil analysis test results for a common group of oil circuit breakers. The larger the number of test results that are analyzed, the more accurate the statistical analysis will be. Usually, 100 or more test results are desired for a good statistically analysis. Statistical analysis can be performed on few test results than this, but the accuracy of the analysis will be reduced.

Once the statistical analysis has been performed, information on the actual physical erosion or damage of the main contacts, arcing contacts and interrupters needs to be obtained. This is done by performing internal inspections of these components in the oil circuit breakers with the highest levels of dissolved gases in oil. This will help in understanding the relationship between the physical erosion or damage to these components and the levels of the various gases dissolved in the oil. It will also help in establishing the levels for each gas where internal inspections of main contacts, arcing contacts and interrupters in oil circuit breakers are warranted.

Another valuable statistical analysis is to analyze the ratios of certain gases. Some common ratios which are analyzed are:

• Ethylene (C₂H₄)/Acetylene (C₂H₂)
• Methane (CH₄)/Acetylene (C₂H₂)
• Nitrogen (N₂)/Oxygen (O₂)

The first two ratios above are used to predict erosion or damage to the main contacts, arcing contacts and interrupters. The third ratio is used to predict blocked vents on free-breathing oil circuit breakers.

Once the action levels for each gas and gas ratio has been established for each common group of oil circuit breakers, the dissolved gas in oil analysis test results are compared to these levels. If the action levels for one or more individual gases or gas ratios have been exceeded, an internal inspection of the main contacts, arcing contacts and interrupters may be warranted.

An example of dissolved gas in oil analysis results of an oil circuit breaker over time is shown in Table 3-17.

Sample Date	10/24/00	10/16/01	10/9/02	10/1/03	10/4/04
Hydrogen (H2) (ppm)	37	27	14	16	18
Methane (CH4) (ppm)	17	70	283	278	378
Ethane (C2H6) (ppm)	2	49	168	619	1082
Ethylene (C2H4) (ppm)	36	327	737	1812	2911
Acetylene (C2H2) (ppm)	204	305	169	279	372
CH4/C2H2	0.083	0.230	1.675	.996	1.016
C2H4/C2H2	0.176	1.072	4.361	6.495	7.825
Oxygen (O2) (ppm)	13382	21312	20761	10352	16928
Nitrogen (N2) (ppm)	82281	66655	61664	52794	46840
N2/O2	6.149	3.128	2.970	5.100	2.767

8. Moisture in Oil Analysis

What is the test? The moisture in oil analysis test measures the level, in ppm, of moisture in the oil of the circuit breaker.

What are the test’s objectives? The objectives of the moisture in oil analysis test are to assist in making an assessment of the condition of the insulating oil in the circuit breaker. This is done by accurately measuring the level, in ppm, of moisture in the insulating oil of the circuit breaker. These measurements are then compared to the circuit breaker manufacturer’s specifications, when they exist, to see if the circuit breaker’s insulating oil is deteriorating. Most commonly, circuit breaker manufacturers do not have moisture in oil analysis test specifications. Therefore, the measurements are compared to previous test results from the same circuit breaker to determine if they are remaining constant or changing. For example, a marked increase in the moisture in oil measurement may indicate that a leak has developed in one of the bushing flange gaskets.

What does the test check/test/measure/evaluate? The moisture in oil analysis test evaluates the condition of the insulating oil in the circuit breaker by measuring the level, in ppm, of the moisture in the oil.

What are the test’s limitations? This test is very sensitive to sampling technique. Most oil circuit breakers do not have oil sampling valves built into their drain valves. This presents a challenge to properly obtain an oil sample for moisture in oil analysis while not introducing additional moisture.

When does the test need to be performed? This test needs to be performed upon the initial commissioning of the circuit breaker to collect baseline test data. Future test data can be compared to the commissioning test data to see if any deviations have occurred and if any corrective actions may be required. These future tests may be regular periodic maintenance tests or special investigative tests which may be required due to an in-service failure or a perceived problem of the circuit breaker. The regular periodic maintenance tests are normally performed at the same time as other oil tests are being performed (e.g. dielectric, dissolved gas, particles, etc.).

Which type of circuit breakers is the test used on? As the name implies, this test is only used on oil circuit breakers.

How is the test performed? This test can be performed with the circuit breaker either energized and in service (on-line) or with it de-energized and out of service (off-line). A sample of the circuit breaker’s insulating oil is required for this test. The sample will be sent to a laboratory for the analysis to be performed. If the circuit breaker has one tank per phase, then three oil samples are required. If the circuit breaker has all three phases contained in one tank, then only one oil sample is required. Each oil sample is collected in a glass syringe. The size of the glass syringe is normally 100 cc. If dissolved gas in oil analysis is also to be performed on the oil sample, 100 cc is normally sufficient for both analyses.

The following steps are required to properly obtain an oil sample in a syringe:

1. Properly identify the circuit breaker from which the oil sample is to be obtained. This is done by collecting the manufacturer’s name, manufacturer’s serial number, substation name and owner’s equipment identification (ID) number on the circuit breaker. If a permanent owner’s equipment identification (ID) number label is absent, the three-line drawing of the substation can be referenced to determine the location of the circuit breaker. A temporary label can be attached to the circuit breaker for use during the test. It should be replaced with a permanent label as soon as practical.

2. If three oil samples are required from the circuit breaker, properly identify which primary phase is connected to each pole of the circuit breaker. It is a best practice to permanently label the primary phase marking on the tanks, stands or enclosures of each circuit breaker when it is commissioned. If these permanent primary phase markings are absent, the three-line drawing or phasing drawing of the substation can be referenced to determine which primary phase is connected to which pole of the circuit breaker. Temporary labels can be attached to the circuit breaker for use during the test. These should be replaced with permanent labels as soon as practical.

3. The oil sample is collected from the oil drain valve on each tank of the circuit breaker. This drain valve is not normally equipped with a sampling valve. A sampling valve can be permanently added to the drain valve or attached temporarily when the oil sample is obtained. One method of attaching a sampling valve to a drain valve is to use a series of reducers to step the size of the drain valve down to the size of the sampling valve. Obtaining an oil sample directly from the drain valve is not recommended. A very slow oil flow rate is needed to properly obtain an oil sample. This flow rate cannot be properly controlled with the drain valve. Also, the oil sample syringe needs to be connected to the valve with a short piece of tubing. The oil sampling valve provides a place to connect this tubing whereas the drain valve does not.

4. Place oil absorbing mats under the sampling area.

5. Have clean dry rags on hand.

6. Connect a short section of tygon tubing to the oil sampling valve.

7. Place the other end of the tygon tubing into a clean empty one gallon bucket.

8. Open the oil sampling valve.

9. Slowly open the oil drain valve until oil begins to flow into the one gallon bucket.

10. Allow the oil to drain into the one gallon bucket watching for signs of water droplets or bubbles in the oil through the tygon tubing or the oil in the one gallon bucket.

11. Close the oil sampling valve as the one gallon bucket becomes full.

12. Empty the oil from the one gallon bucket into a larger storage vessel for transportation and disposal off site.

13. Continue to drain the oil until water droplets or bubbles are no longer seen in the oil.

14. After water droplets or bubbles are no longer seen in the oil, drain two more gallons of oil.

15. Close the oil sampling valve.

16. Measure the temperature of the oil in the one gallon bucket and record it on the oil sample sheet that will be sent to the laboratory with the oil sample syringe.

17. Check that the plunger on the syringe is pushed in.

18. Remove the end of the tygon tubing from the one gallon bucket and connect it to the stopcock on the syringe.

19. Turn the syringe so that the plunger is facing down and the stopcock is facing up.

20. Slowly open the oil sampling valve.

21. Turn the stopcock on the syringe to allow oil to flow into the syringe.

22. Pull down slowly on the plunger.

23. Fill the syringe to slightly past the last demarcation line on the syringe.

24. Turn the stopcock to stop filling the syringe.

25. Turn the stopcock to drain oil from the syringe into the one gallon bucket.

26. Slowly push the plunger in to expel any air bubbles that may be present in the oil in the syringe. Stop when the air bubbles have been removed.

27. Turn the stopcock on the syringe to allow oil to flow into the syringe.

28. Pull down slowly on the plunger.

29. Fill the syringe to the last demarcation line on the syringe but not past it.

30. Turn the stopcock to the closed position.

31. Close the oil sampling valve.

32. Close the oil drain valve.

33. Disconnect the tygon tubing from the stopcock.

34. Disconnect the tygon tubing from the oil sampling valve.

35. Fill in the oil sample sheet provided by the laboratory:

    a. Substation Name

    b. Circuit Breaker Equipment ID Number

    c. Circuit Breaker Phase Identifier (When required)

    d. Circuit Breaker Serial Number

    e. Sample Date

    f. Sample Oil Temperature

    g. Tests Required: Moisture Content – ASTM D-1533b

Send the filled syringe and filled-in oil sample sheet to the laboratory for analysis. Provide contact information as to where the test results need to be sent.

How are the test results interpreted? First, the moisture in oil analysis test results should be compared to the oil circuit breaker manufacturer’s limits. Most commonly, circuit breaker manufacturers do not have limits for this test. Some oil circuit breaker owners and/or operators use a limit in the range of 60 ppm for the moisture in oil test. If this limit is exceeded, follow-up action such as oil dielectric breakdown testing to confirm the problem and/or filtering of the oil to remove the moisture may be required. Second, the test results should also be compared to the same results from previous tests. Are they staying fairly the same? Are they slowly increasing? Are they slowly decreasing? Have there been any large changes in the measurements? Trends which are fairly constant are normal. Trends which are slowly increasing or slowly decreasing do not normally require corrective action but may warrant a shorter time interval until the next moisture in oil analysis. Trends with large changes are usually not normal and may require corrective action such as locating the source(s) for water to enter the oil tank.

Table 3-18 shows an example of moisture in oil analysis results of an oil circuit breaker over time.

Sample Date	6/6/01	6/17/02	6/30/03	6/4/04	5/30/05
Oil Temperature (ºC)	20	30	25	32	30
Moisture (ppmv)	38	49	24	42	57
Relative Saturation (%)	69	58	35	46	68
Dew Point (ºC)	12	17	2	14	21

9. SF₆ Gas Analysis Tests

SF₆ gas analysis tests include the following:

• SF₆ Moisture Content
• SF₆ Gas Purity
• SF₆ Gas By-Products

SF₆ Gas Moisture Content

What is the test? The SF₆ gas moisture content test measures the level, in ppm, of moisture vapor in the SF₆ gas of the circuit breaker.

What are the test’s objectives? The objectives of the SF₆ gas moisture content test are to assist in making an assessment of the condition of the SF₆ gas in the circuit breaker and as an indicator of possible leaks in the SF₆ gas system. This is done by accurately measuring the level, in ppm by volume, of moisture vapor in the SF₆ gas of the circuit breaker. These measurements are then compared to the circuit breaker manufacturer’s specifications to see if the SF₆ gas is suitable to perform its insulating and arc extinguishing functions. The measurements are also compared to previous test results from the same circuit breaker to determine if the measurements are remaining constant or changing. For example, a marked increase in theSF₆ gas moisture content measurement may indicate that a leak has developed in the SF₆ gas system. If the SF₆ gas moisture content measurements exceed the circuit breaker manufacturer’s specifications, corrective action is needed.

What does the test check/test/measure/evaluate? The SF₆ gas moisture content test evaluates the condition of the SF₆ gas in the circuit breaker by measuring the level, in ppm, of the moisture vapor in the SF₆ gas.

What are the test’s limitations? The accuracy of the measurements taken with test sets in the field is of concern. Often SF₆ gas moisture content measurements vary widely between test sets. Two main reasons for this are the sensor technology used by the various test sets and infrequent or improper calibration of the test sets.

When does the test need to be performed? This test needs to be performed upon the initial commissioning of the circuit breaker to collect baseline test data. Future test data can be compared to the commissioning test data to see if any deviations have occurred and if any corrective actions may be required. These future tests may be regular periodic maintenance tests or special investigative tests which may be required due to an in-service failure or a perceived problem of the circuit breaker. The regular periodic maintenance tests are normally performed at fixed time intervals that have been selected by the owner and/or operator of the circuit breaker. These fixed time intervals are not standardized across the industry and can vary from 2 years to 10 years or more. Many factors go into the selection of the fixed time interval chosen for each circuit breaker. These factors are explained in more detail elsewhere in this guidebook.

Additional SF₆ gas moisture content measurements are required 2 or 3 days after the circuit breaker has been filled with SF₆ gas. This is to allow time for the moisture in the SF₆ gas that was used to fill the circuit breaker to reach a stabilization point with the desiccant that is in a small replaceable bag(s) inside of the circuit breaker. The manufacturer’s instruction manual should be consulted for their requirements as to when this additional measurement should be taken.

It is also a good practice to measure the SF₆ gas moisture content of each cylinder of SF₆ gas that is going to be used to fill or add make-up gas to an SF₆ gas circuit breaker. This ensures that unwanted moisture is not injected into the circuit breaker and that the SF₆ gas supplier is supplying dry gas.

Which type of circuit breakers is the test used on? As the name implies, this test is only used on SF₆ gas circuit breakers.

How is the test performed? This test can be performed with the circuit breaker either energized and in service (on-line) or with it de-energized and out of service (off-line). The industry preference is to perform this test with the circuit breaker de-energized and out of service (off-line) to maximize the safety of the personnel performing the test. A sample of the circuit breaker’s SF₆ gas is required for this test. The sample can then be analyzed at the substation with a field test set which measures the moisture content in SF₆ gas or it can be sent to a laboratory for the analysis to be performed. The field test set can be the type which tests for just moisture in SF₆ gas (electronic hygrometer) or it can be the type that tests multiple items of the SF₆ gas (for example moisture and purity). If the circuit breaker has one tank per phase with no interconnecting piping or header between phases, then three SF₆ gas samples are required. If the circuit breaker has all three phases contained in one tank or one tank per phase with interconnecting piping or header between the phases, then only one SF₆ gas sample is required. Some field test sets collect and store the SF₆ gas in the test set while performing the measurement. Afterwards, the SF₆ gas is pumped back into the circuit breaker or remains in the test set for future transfer to a waste SF₆ gas storage cylinder. Other field test sets discharge the SF₆ gas into the atmosphere during the measurement. In this case, it is required to capture the discharged SF₆ gas in a discharge recovery bag rather than to discharge the SF₆ gas into the atmosphere. If the SF₆ gas sample is going to be analyzed in a laboratory, each sample is collected in one or more stainless steel mini-cylinders. The number of mini-cylinders to be filled for each sample will depend upon the volume of SF₆ gas required by the laboratory to perform all of the tests specified for the sample. Often multiple laboratory tests are performed on an SF₆ gas sample, such as moisture, purity and SF₆ by-product gases, not just a single test.

The following are the general steps required to measure the moisture content of SF₆ gas with a field test set. The manufacturer’s instructions should always be consulted for the specific operating requirements of each field test set:

1. Properly identify the circuit breaker from which the SF₆ gas measurement is to be made. This is done by collecting the manufacturer’s name, manufacturer’s serial number, substation name and owner’s equipment identification (ID) number on the circuit breaker. If a permanent owner’s equipment identification (ID) number label is absent, the three-line drawing of the substation can be referenced to determine the location of the circuit breaker. A temporary label can be attached to the circuit breaker for use during the test. It should be replaced with a permanent label as soon as practical.

2. If three SF₆ gas measurements are required from the circuit breaker, properly identify which primary phase is connected to each pole of the circuit breaker. It is a best practice to permanently label the primary phase marking on the tanks, stands or enclosures of each circuit breaker when it is commissioned. If these permanent primary phase markings are absent, the three-line drawing or phasing drawing of the substation can be referenced to determine which primary phase is connected to which pole of the circuit breaker. Temporary labels can be attached to the circuit breaker for use during the test. These should be replaced with permanent labels as soon as practical.

3. The SF₆ gas measurement is normally taken from the fill valve on each tank of the circuit breaker.

4. Connect one end of the flexible tubing supplied with the field test set to the SF₆ gas fill valve. This may require a combination of adapters and reducers to transition the valve size down to the tubing size. If flexible tubing is not supplied with the field test set, ¼ inch flexible stainless steel tubing is recommended. The tubing length should be kept as short as possible to minimize the amount of waste SF₆ gas during the measurement.

5. Connect the other end of the flexible tubing to the inlet or measurement port of the field test set.

6. Turn on the field test set and perform any calibration checks required by the manufacturer.

7. Slowly open the SF₆ gas fill valve until SF₆ gas begins to flow into the field test set. Normally, only a slow flow rate is needed to obtain a measurement. Consult the field test set’s instructions for the required flow rate.

8. Monitor the moisture in SF₆ gas reading on the field test set until it is no longer changing and stabilizes. This may take several minutes.

9. Record the stabilized moisture reading and the measurement units. The most common measurement units are parts per million water vapor by volume (ppmv).

10. Close the SF₆ gas fill valve.

11. Turn off the field test set.

12. Disconnect the flexible tubing from the SF₆ gas fill valve.

13. Disconnect the flexible tubing from the field test set.

The following are the general steps required to obtain an SF₆ gas sample. The sample kit’s instructions should always be consulted for the specific sampling requirements:

1. Properly identify the circuit breaker from which the SF₆ gas sample is to be obtained. This is done by collecting the manufacturer’s name, manufacturer’s serial number, substation name and owner’s equipment identification (ID) number on the circuit breaker. If a permanent owner’s equipment identification (ID) number label is absent, the three-line drawing of the substation can be referenced to determine the location of the circuit breaker. A temporary label can be attached to the circuit breaker for use during the test. It should be replaced with a permanent label as soon as practical.

2. If three SF₆ gas samples are required from the circuit breaker, properly identify which primary phase is connected to each pole of the circuit breaker. It is a best practice to permanently label the primary phase marking on the tanks, stands or enclosures of each circuit breaker when it is commissioned. If these permanent primary phase markings are absent, the three-line drawing or phasing drawing of the substation can be referenced to determine which primary phase is connected to which pole of the circuit breaker. Temporary labels can be attached to the circuit breaker for use during the test. These should be replaced with permanent labels as soon as practical.

3. The SF₆ gas sample is normally collected from the fill valve on each tank of the circuit breaker.

4. The sample kit will contain a valve and pressure gauge assembly which is used to connect the mini-cylinder for collecting the SF₆ gas sample to the circuit breaker’s SF₆ gas fill valve. This assembly consists of a pressure regulator valve on the inlet, a pressure gauge in the middle and a valve on the outlet.

5. Connect the inlet of the valve and pressure gauge assembly to the SF₆ gas fill valve. This may require a combination of adapters and reducers to transition the valve size down to the tubing size.

6. Connect the outlet of the valve and pressure gauge assembly to the purge bag supplied with the sample kit.

7. Check that the valves are closed on the valve and pressure gauge assembly.

8. Slowly open the valve on the purge bag.

9. Slowly open the outlet valve on the valve and pressure gauge assembly.

10. Slowly open the SF₆ gas fill valve on the circuit breaker.

11. Slowly open the pressure regulator valve on the valve and pressure gauge assembly inlet.

12. As soon as the purge bag starts to inflate, close the outlet valve on the valve and pressure gauge assembly.

13. Continue to slowly open the pressure regulator valve on the valve and pressure gauge assembly inlet until the pressure gauge reads the sample kit’s recommended sampling pressure.

14. Slowly open the outlet valve on the valve and pressure gauge assembly and allow the valve and pressure gauge assembly to purge into the purge bag.

15. Close the outlet valve on the valve and pressure gauge assembly.

16. Close the valve on the purge bag.

17. Disconnect the purge bag from the valve and pressure gauge assembly.

18. Connect the inlet of the mini-cylinder to the outlet of the valve and pressure gauge assembly.

19. Connect the outlet of the mini cylinder to the purge bag.

20. Slowly open the outlet valve on the valve and pressure gauge assembly.

21. Slowly open the valve on the purge bag.

22. Slowly open the inlet valve on the mini-cylinder.

23. Slowly open the outlet valve on the mini-cylinder.

24. Collect the SF₆ gas sample into the mini-cylinder while purging excess SF₆ gas into the purge bag.

25. Close the inlet valve on the mini-cylinder.

26. Close the outlet valve on the mini-cylinder.

27. Close the valve on the purge bag.

28. Close the outlet valve on the valve and pressure gauge assembly.

29. Disconnect the purge bag from the mini-cylinder.

30. Disconnect the mini-cylinder from the valve and pressure gauge assembly.

31. Close the SF₆ gas fill valve on the circuit breaker.

32. Slowly open the outlet valve on the valve and pressure gauge assembly.

33. Drain the pressure off of the valve and pressure gauge assembly.

34. Disconnect the valve and pressure gauge assembly from the SF₆ gas fill valve.

35. Close the valves on the valve and pressure gauge assembly.

36. Fill in the SF₆ gas sample sheet provided by the laboratory:

    a. Substation Name

    b. Circuit Breaker Equipment ID Number

    c. Circuit Breaker Phase Identifier (When required)

    d. Circuit Breaker Serial Number

    e. Sample Date

    f. Tests Required: Moisture Content

Send the filled mini-cylinder and filled-in SF₆ gas sample sheet to the laboratory for analysis. Provide contact information as to where the test results need to be sent.

How are the test results interpreted? First, the circuit breaker manufacturer’s SF₆ gas moisture content limit needs to be obtained from the circuit breaker’s instruction manual. This is normally given in ppm by volume (ppmv). If this value is not listed in the instruction manual, the circuit breaker manufacturer should be contacted to obtain it. Second, each SF₆ gas moisture content measurement taken on the circuit breaker should be compared to the circuit breaker manufacturer’s limit. If the SF₆ gas moisture content measurement is very near to or above the limit, corrective action is normally required. Third, the SF₆ gas moisture content measurement(s) for each circuit breaker should be compared to the previous measurements for that circuit breaker. Observe the trend of the measurements. Are they staying fairly the same? Are they slowly increasing? Have there been any large changes in the measurements? Trends which are constant or slowly increasing are usually normal and rarely require corrective action. Trends with large changes are usually not normal and may require corrective action.

Table 3-19 shows an example of SF₆ gas moisture content test results of a gas circuit breaker over time.

Test Date	5/1/95	4/17/00	10/8/05	5/20/10
Ambient Temperature (ºF)	53	44	60	63
SF6 Gas Pressure (psig)	76	74	78	79
Moisture Content (ppmv)	0	5	20	50
Manufacturer’s Moisture Content Limit (ppmv)	300	300	300	300

SF₆ Gas Purity

What is the test? The SF₆ gas purity test measures the level, in percent by volume, of SF₆ gas in the circuit breaker.

What are the test’s objectives? The objectives of the SF₆ gas purity test are to assist in making an assessment of the condition of the SF₆ gas in the circuit breaker, as an indicator of possible leaks in the SF₆ gas system and as an indicator of the presence of possible elevated levels of SF₆ gas by-products. This is done by accurately measuring the level, in percent by volume, of SF₆ gas in the circuit breaker. These measurements are then compared to the circuit breaker manufacturer’s specifications to see if the SF₆ gas is suitable to perform its insulating and arc extinguishing functions. The measurements are also compared to previous test results from the same circuit breaker to determine if the measurements are remaining constant or changing. For example, a marked decrease in the SF₆ gas purity may indicate that a leak has developed in the SF₆ gas system. If the SF₆ gas purity measurements are less than the circuit breaker manufacturer’s specifications, corrective action is needed.

What does the test check/test/measure/evaluate? The SF₆ gas purity test evaluates the condition of the SF₆ gas in the circuit breaker by measuring the level, in percent by volume, of SF₆ gas.

What are the test’s limitations? This test only measures the percentage by volume of SF₆ gas present in the sample. It does not indicate what types of other gases are present. Additional testing of the SF₆ gas, such as SF₆ gas by-product analysis, is usually performed when supplemental information is needed.

When does the test need to be performed? This test needs to be performed upon the initial commissioning of the circuit breaker to collect baseline test data. Future test data can be compared to the commissioning test data to see if any deviations have occurred and if any corrective actions may be required. These future tests may be regular periodic maintenance tests or special investigative tests which may be required due to an in-service failure or a perceived problem of the circuit breaker. The regular periodic maintenance tests are normally performed at fixed time intervals that have been selected by the owner and/or operator of the circuit breaker. These fixed time intervals are not standardized across the industry and can vary from 2 years to 10 years or more. Many factors go into the selection of the fixed time interval chosen for each circuit breaker. These factors are explained in more detail elsewhere in this guidebook.

It is also a good practice to measure the SF₆ gas purity of each cylinder of SF₆ gas that is going to be used to fill or add make gas to an SF₆ gas circuit breaker. This ensures that unwanted gases are not injected into the circuit breaker and that the SF₆ gas supplier is supplying high purity gas.

Which type of circuit breakers is the test used on? As the name implies, this test is only used on SF₆ gas circuit breakers.

How is the test performed? This test can be performed with the circuit breaker either energized and in service (on-line) or with it de-energized and out of service (off-line). The industry preference is to perform this test with the circuit breaker de-energized and out of service (off-line) to maximize the safety of the personnel performing the test. A sample of the circuit breaker’s SF₆ gas is required for this test. The sample can then be analyzed at the substation with a field test set which measures the level, in percent by volume, of SF₆ gas in the circuit breaker or it can be sent to a laboratory for the analysis to be performed. The field test set can be the type which tests for just the level, in percent by volume, of SF₆ gas in the circuit breaker or it can be the type that tests multiple items of the SF₆ gas (for example moisture and purity). If the circuit breaker has one tank per phase with no interconnecting piping or header between phases, then three SF₆ gas samples are required. If the circuit breaker has all three phases contained in one tank or one tank per phase with interconnecting piping or header between the phases, then only one SF₆ gas sample is required. Some field test sets collect and store the SF₆ gas in the test set while performing the measurement. Afterwards, the SF₆ gas is pumped back into the circuit breaker or remains in the test set for future transfer to a waste SF₆ gas storage cylinder. Other field test sets discharge the SF₆ gas into the atmosphere during the measurement. In this case, it is required to capture the discharged SF₆ gas in a discharge recovery bag rather than to discharge the SF₆ gas into the atmosphere. If the SF₆ gas sample is going to be analyzed in a laboratory, each sample is collected in one or more stainless steel mini-cylinders. The number of mini-cylinders to be filled for each sample will depend upon the volume of SF₆ gas required by the laboratory to perform all of the tests specified for the sample. Often multiple laboratory tests are performed on an SF₆ gas sample, such as moisture, purity and SF₆ by-product gases, not just a single test.

The following are the general steps required to measure the level, in percent by volume, of SF₆ gas in the circuit breaker with a field test set. The manufacturer’s instructions should always be consulted for the specific operating requirements of each field test set.

1. Properly identify the circuit breaker from which the SF₆ gas measurement is to be made. This is done by collecting the manufacturer’s name, manufacturer’s serial number, substation name and owner’s equipment identification (ID) number on the circuit breaker. If a permanent owner’s equipment identification (ID) number label is absent, the three-line drawing of the substation can be referenced to determine the location of the circuit breaker. A temporary label can be attached to the circuit breaker for use during the test. It should be replaced with a permanent label as soon as practical.

2. If three SF₆ gas measurements are required from the circuit breaker, properly identify which primary phase is connected to each pole of the circuit breaker. It is a best practice to permanently label the primary phase marking on the tanks, stands or enclosures of each circuit breaker when it is commissioned. If these permanent primary phase markings are absent, the three-line drawing or phasing drawing of the substation can be referenced to determine which primary phase is connected to which pole of the circuit breaker. Temporary labels can be attached to the circuit breaker for use during the test. These should be replaced with permanent labels as soon as practical.

3. The SF₆ gas measurement is normally taken from the fill valve on each tank of the circuit breaker.

4. Connect one end of the flexible tubing supplied with the field test set to the SF₆ gas fill valve. This may require a combination of adapters and reducers to transition the valve size down to the tubing size. If flexible tubing is not supplied with the field test set, ¼ inch flexible stainless steel tubing is recommended. The tubing length should be kept as short as possible to minimize the amount of waste SF₆ gas during the measurement.

5. Connect the other end of the flexible tubing to the inlet or measurement port of the field test set.

6. Turn on the field test set and perform any calibration checks required by the manufacturer.

7. Slowly open the SF₆ gas fill valve until SF₆ gas begins to flow into the field test set. Normally, only a slow flow rate is needed to obtain a measurement. Consult the field test set’s instructions for the required flow rate.

8. Monitor the percent by volume of SF₆ gas reading on the field test set until it is no longer changing and stabilizes. This may take several minutes.

9. Record the stabilized percent by volume of SF₆ gas reading.

10. Close the SF₆ gas fill valve.

11. Turn off the field test set.

12. Disconnect the flexible tubing from the SF₆ gas fill valve.

13. Disconnect the flexible tubing from the field test set.

The following are the general steps required to obtain an SF₆ gas sample. The sample kit’s instructions should always be consulted for the specific sampling requirements.

1. Properly identify the circuit breaker from which the SF₆ gas sample is to be obtained. This is done by collecting the manufacturer’s name, manufacturer’s serial number, substation name and owner’s equipment identification (ID) number on the circuit breaker. If a permanent owner’s equipment identification (ID) number label is absent, the three-line drawing of the substation can be referenced to determine the location of the circuit breaker. A temporary label can be attached to the circuit breaker for use during the test. It should be replaced with a permanent label as soon as practical.

2. If three SF₆ gas samples are required from the circuit breaker, properly identify which primary phase is connected to each pole of the circuit breaker. It is a best practice to permanently label the primary phase marking on the tanks, stands or enclosures of each circuit breaker when it is commissioned. If these permanent primary phase markings are absent, the three-line drawing or phasing drawing of the substation can be referenced to determine which primary phase is connected to which pole of the circuit breaker. Temporary labels can be attached to the circuit breaker for use during the test. These should be replaced with permanent labels as soon as practical.

3. The SF₆ gas sample is normally collected from the fill valve on each tank of the circuit breaker.

4. The sample kit will contain a valve and pressure gauge assembly which is used to connect the mini-cylinder for collecting the SF₆ gas sample to the circuit breaker’s SF₆ gas fill valve. This assembly consists of a pressure regulator valve on the inlet, a pressure gauge in the middle and a valve on the outlet.

5. Connect the inlet of the valve and pressure gauge assembly to the SF₆ gas fill valve. This may require a combination of adapters and reducers to transition the valve size down to the tubing size.

6. Connect the outlet of the valve and pressure gauge assembly to the purge bag supplied with the sample kit.

7. Check that the valves are closed on the valve and pressure gauge assembly.

8. Slowly open the valve on the purge bag.

9. Slowly open the outlet valve on the valve and pressure gauge assembly.

10. Slowly open the SF₆ gas fill valve on the circuit breaker.

11. Slowly open the pressure regulator valve on the valve and pressure gauge assembly inlet.

12. As soon as the purge bag starts to inflate, close the outlet valve on the valve and pressure gauge assembly.

13. Continue to slowly open the pressure regulator valve on the valve and pressure gauge assembly inlet until the pressure gauge reads the sample kit’s recommended sampling pressure.

14. Slowly open the outlet valve on the valve and pressure gauge assembly and allow the valve and pressure gauge assembly to purge into the purge bag.

15. Close the outlet valve on the valve and pressure gauge assembly.

16. Close the valve on the purge bag.

17. Disconnect the purge bag from the valve and pressure gauge assembly.

18. Connect the inlet of the mini-cylinder to the outlet of the valve and pressure gauge assembly.

19. Connect the outlet of the mini cylinder to the purge bag.

20. Slowly open the outlet valve on the valve and pressure gauge assembly.

21. Slowly open the valve on the purge bag.

22. Slowly open the inlet valve on the mini-cylinder.

23. Slowly open the outlet valve on the mini-cylinder.

24. Collect the SF₆ gas sample into the mini-cylinder while purging excess SF₆ gas into the purge bag.

25. Close the inlet valve on the mini-cylinder.

26. Close the outlet valve on the mini-cylinder.

27. Close the valve on the purge bag.

28. Close the outlet valve on the valve and pressure gauge assembly.

29. Disconnect the purge bag from the mini-cylinder.

30. Disconnect the mini-cylinder from the valve and pressure gauge assembly.

31. Close the SF₆ gas fill valve on the circuit breaker.

32. Slowly open the outlet valve on the valve and pressure gauge assembly.

33. Drain the pressure off of the valve and pressure gauge assembly.

34. Disconnect the valve and pressure gauge assembly from the SF₆ gas fill valve.

35. Close the valves on the valve and pressure gauge assembly.

36. Fill in the SF₆ gas sample sheet provided by the laboratory:

    a. Substation Name

    b. Circuit Breaker Equipment ID Number

    c. Circuit Breaker Phase Identifier (When required)

    d. Circuit Breaker Serial Number

    e. Sample Date

    f. Tests Required: SF₆ gas Purity

Send the filled mini-cylinder and filled-in SF₆ gas sample sheet to the laboratory for analysis. Provide contact information as to where the test results need to be sent.

How are the test results interpreted? First, the circuit breaker manufacturer’s SF₆ gas purity limit needs to be obtained from the circuit breaker’s instruction manual. This is normally given in percent by volume. If this value is not listed in the instruction manual, the circuit breaker manufacturer should be contacted to obtain it. Second, each SF₆ gas purity measurement taken on the circuit breaker should be compared to the circuit breaker manufacturer’s limit. If the SF₆ gas purity measurement is very near to or below the limit, corrective action is normally required. Third, the SF₆ gas purity measurement(s) for each circuit breaker should be compared to the previous measurements for that circuit breaker. Observe the trend of the measurements. Are they staying fairly the same? Are they slowly decreasing? Have there been any large changes in the measurements? Trends which are constant or slowly decreasing are usually normal and rarely require corrective action. Trends with large changes are usually not normal and may require corrective action.

Table 3-20 shows an example of SF₆ gas purity test results of a gas circuit breaker over time.

Test Date	5/1/95	4/17/00	10/8/05	5/20/10
Ambient Temperature (ºF)	53	44	60	63
SF6 Gas Pressure (psig)	76	74	78	79
Purity (%)	99.9	99.9	99.8	99.7

SF₆ Gas By-Product Analysis

What is the test? The SF₆ gas by-product analysis test measures the levels, in ppm, of specific gases in the SF₆ gas of the circuit breaker. This analysis can also include an SF₆ gas purity measurement and an SF₆ gas moisture content measurement.

What are the test’s objectives? The objectives of the SF₆ gas by-product analysis test are to assist in making an assessment of the condition of internal components of the circuit breaker such as interrupter nozzles, main and arcing contacts and solid insulation materials as well as the SF₆ gas itself. This is done by accurately measuring the levels, in ppm, of key gases in the SF₆ gas of the circuit breaker. Most commonly, circuit breaker manufacturers do not have SF₆ gas by-product analysis limits for these key gases. Therefore, the measurements are compared to statistical data from SF₆ gas by-product analysis test results from similar circuit breakers and to previous test results from the same circuit breaker to determine if they are elevated, remaining constant or changing.

What does the test check/test/measure/evaluate? The SF₆ gas by-product analysis test evaluates the condition of the SF₆ gas in the circuit breaker by measuring the level, in ppm, of the following key gases which may or may not be present in the SF₆ gas:

• SO₂ (Sulfur Dioxide)
• SOF₂ (Thionyl Fluoride)
• HF (Hydrolyzable Fluorides)
• CF₄ (Carbon Tetrafluoride)
• Air

What are the test’s limitations? Gassing patterns can vary between different types of SF₆ gas circuit breakers. A sizeable quantity of SF₆ gas by-product analysis test results are required to establish valid patterns in the gasses generated in each type of SF₆ gas circuit breaker.

Many SO₂ tests do not distinguish between SO₂ and SOF₂. The SOF₂ hydrolyzes (reacts with water) as the test is set-up.

The evolved gases from faults are very unstable and the levels will go down after time.

When does the test need to be performed? This test needs to be performed upon the initial commissioning of the circuit breaker to collect baseline test data. Future test data can be compared to the commissioning test data to see if any deviations have occurred and if any corrective actions may be required. These future tests may be regular periodic maintenance tests or special investigative tests which may be required due to an in-service failure or a perceived problem of the circuit breaker. The regular periodic maintenance tests are normally performed at fixed time intervals that have been selected by the owner and/or operator of the circuit breaker. These fixed time intervals are not standardized across the industry and can vary from 2 years to 10 years or more. Many factors go into the selection of the fixed time interval chosen for each circuit breaker. This test has also been performed based upon the service duty of the breaker (e.g. number of or after a fault interruption/s, total load current interruptions since last test, etc.). These factors are explained in more detail elsewhere in this guidebook.

Which type of circuit breakers is the test used on? As the name implies, this test is only used on SF₆ gas circuit breakers.

How is the test performed? This test can be performed with the circuit breaker either energized and in service (on-line) or with it de-energized and out of service (off-line). The industry preference is to perform this test with the circuit breaker de-energized and out of service (off-line) to maximize the safety of the personnel performing the test. A sample of the circuit breaker’s SF₆ gas is required for this test. The sample can then be analyzed at the substation with a field test set which measures specific SF₆ by-product gases, such as SO₂ (Sulfur Dioxide), or it can be sent to a laboratory for the analysis to be performed. The field test set can be the type which tests for just SO₂ (Sulfur Dioxide) or it can be the type that tests multiple items of the SF₆ gas (for example SO₂ (Sulfur Dioxide), moisture and purity). If the circuit breaker has one tank per phase with no interconnecting piping or header between phases, then three SF₆ gas samples are required. If the circuit breaker has all three phases contained in one tank or one tank per phase with interconnecting piping or header between the phases, then only one SF₆ gas sample is required. Some field test sets collect and store the SF₆ gas in the test set while performing the measurement. Afterwards, the SF₆ gas is pumped back into the circuit breaker or remains in the test set for future transfer to a waste SF₆ gas storage cylinder. Other field test sets discharge the SF₆ gas into the atmosphere during the measurement. In this case, it is required to capture the discharged SF₆ gas in a discharge recovery bag rather than to discharge the SF₆ gas into the atmosphere. If the SF₆ gas sample is going to be analyzed in a laboratory, each sample is collected in one or more stainless steel mini-cylinders. The number of mini-cylinders to be filled for each sample will depend upon the volume of SF₆ gas required by the laboratory to perform all of the tests specified for the sample. Often multiple laboratory tests are performed on an SF₆ gas sample, such as moisture, purity and SF₆ by-product gases, not just a single test.

The following are the general steps required to measure SF₆ by-product gases with a field test set. The manufacturer’s instructions should always be consulted for the specific operating requirements of each field test set.

1. Properly identify the circuit breaker from which the SF₆ gas measurement is to be made. This is done by collecting the manufacturer’s name, manufacturer’s serial number, substation name and owner’s equipment identification (ID) number on the circuit breaker. If a permanent owner’s equipment identification (ID) number label is absent, the three-line drawing of the substation can be referenced to determine the location of the circuit breaker. A temporary label can be attached to the circuit breaker for use during the test. It should be replaced with a permanent label as soon as practical.

2. If three SF₆ gas measurements are required from the circuit breaker, properly identify which primary phase is connected to each pole of the circuit breaker. It is a best practice to permanently label the primary phase marking on the tanks, stands or enclosures of each circuit breaker when it is commissioned. If these permanent primary phase markings are absent, the three-line drawing or phasing drawing of the substation can be referenced to determine which primary phase is connected to which pole of the circuit breaker. Temporary labels can be attached to the circuit breaker for use during the test. These should be replaced with permanent labels as soon as practical.

3. The SF₆ gas measurement is normally taken from the fill valve on each tank of the circuit breaker.

4. Connect one end of the flexible tubing supplied with the field test set to the SF₆ gas fill valve. This may require a combination of adapters and reducers to transition the valve size down to the tubing size. If flexible tubing is not supplied with the field test set, ¼ inch flexible stainless steel tubing is recommended. The tubing length should be kept as short as possible to minimize the amount of waste SF₆ gas during the measurement.

5. Connect the other end of the flexible tubing to the inlet or measurement port of the field test set.

6. Connect the field test set discharge line to a SF₆ gas recovery bag

Some utilities have installed sampling lines and valves on the equipment so as to reduce the possibility of contamination. In this case just draw the sample into a sampling vial. This also reduces the time required to perform the task.

7. Turn on the field test set and perform any calibration checks required by the manufacturer.

8. Slowly open the SF₆ gas fill valve until SF₆ gas begins to flow into the field test set. Normally, only a slow flow rate is needed to obtain a measurement. Consult the field test set’s instructions for the required flow rate.

9. Monitor the reading(s) of the SF₆ by-product gas(es) on the field test set until they are no longer changing and stabilize. This may take several minutes.

10. Record the stabilized reading(s) of each SF₆ by-product gas and their measurement units. The most common measurement units are parts per million by volume (ppmv). Alternatively, measurement units of parts per million by weight (ppmw) may be used.

11. Close the SF₆ gas fill valve.

12. Turn off the field test set.

13. Disconnect the flexible tubing from the SF₆ gas fill valve.

14. Disconnect the flexible tubing from the field test set.

The following are the general steps required to obtain an SF₆ gas sample. The sample kit’s instructions should always be consulted for the specific sampling requirements.

1. Properly identify the circuit breaker from which the SF₆ gas sample is to be obtained. This is done by collecting the manufacturer’s name, manufacturer’s serial number, substation name and owner’s equipment identification (ID) number on the circuit breaker. If a permanent owner’s equipment identification (ID) number label is absent, the three-line drawing of the substation can be referenced to determine the location of the circuit breaker. A temporary label can be attached to the circuit breaker for use during the test. It should be replaced with a permanent label as soon as practical.

2. If three SF₆ gas samples are required from the circuit breaker, properly identify which primary phase is connected to each pole of the circuit breaker. It is a best practice to permanently label the primary phase marking on the tanks, stands or enclosures of each circuit breaker when it is commissioned. If these permanent primary phase markings are absent, the three-line drawing or phasing drawing of the substation can be referenced to determine which primary phase is connected to which pole of the circuit breaker. Temporary labels can be attached to the circuit breaker for use during the test. These should be replaced with permanent labels as soon as practical.

3. The SF₆ gas sample is normally collected from the fill valve on each tank of the circuit breaker.

4. The sample kit will contain a valve and pressure gauge assembly which is used to connect the mini-cylinder for collecting the SF₆ gas sample to the circuit breaker’s SF₆gas fill valve. This assembly consists of a pressure regulator valve on the inlet, a pressure gauge in the middle and a valve on the outlet.

5. Connect the inlet of the valve and pressure gauge assembly to the SF₆ gas fill valve. This may require a combination of adapters and reducers to transition the valve size down to the tubing size.

6. Connect the outlet of the valve and pressure gauge assembly to the purge bag supplied with the sample kit.

7. Check that the valves are closed on the valve and pressure gauge assembly.

8. Slowly open the valve on the purge bag.

9. Slowly open the outlet valve on the valve and pressure gauge assembly.

10. Slowly open the SF₆ gas fill valve on the circuit breaker.

11. Slowly open the pressure regulator valve on the valve and pressure gauge assembly inlet.

12. As soon as the purge bag starts to inflate, close the outlet valve on the valve and pressure gauge assembly.

13. Continue to slowly open the pressure regulator valve on the valve and pressure gauge assembly inlet until the pressure gauge reads the sample kit’s recommended sampling pressure.

14. Slowly open the outlet valve on the valve and pressure gauge assembly and allow the valve and pressure gauge assembly to purge into the purge bag.

15. Close the outlet valve on the valve and pressure gauge assembly.

16. Close the valve on the purge bag.

17. Disconnect the purge bag from the valve and pressure gauge assembly.

18. Connect the inlet of the mini-cylinder to the outlet of the valve and pressure gauge assembly.

19. Connect the outlet of the mini cylinder to the purge bag.

20. Slowly open the outlet valve on the valve and pressure gauge assembly.

21. Slowly open the valve on the purge bag.

22. Slowly open the inlet valve on the mini-cylinder.

23. Slowly open the outlet valve on the mini-cylinder.

24. Collect the SF₆ gas sample into the mini-cylinder while purging excess SF₆ gas into the purge bag.

25. Close the inlet valve on the mini-cylinder.

26. Close the outlet valve on the mini-cylinder.

27. Close the valve on the purge bag.

28. Close the outlet valve on the valve and pressure gauge assembly.

29. Disconnect the purge bag from the mini-cylinder.

30. Disconnect the mini-cylinder from the valve and pressure gauge assembly.

31. Close the SF₆ gas fill valve on the circuit breaker.

32. Slowly open the outlet valve on the valve and pressure gauge assembly.

33. Drain the pressure off of the valve and pressure gauge assembly.

34. Disconnect the valve and pressure gauge assembly from the SF₆ gas fill valve.

35. Close the valves on the valve and pressure gauge assembly.

36. Fill in the SF₆ gas sample sheet provided by the laboratory:

    a. Substation Name

    b. Circuit Breaker Equipment ID Number

    c. Circuit Breaker Phase Identifier (When required)

    d. Circuit Breaker Serial Number

    e. Sample Date

    f. Tests Required: SF₆ gas By-product Analysis (or ASTM D-2472 if moisture and purity are also required)

Send the filled mini-cylinder and filled-in SF₆ gas sample sheet to the laboratory for analysis. Provide contact information as to where the test results need to be sent.

How are the test results interpreted? First, the circuit breaker manufacturer’s in-service SF₆ gas by-product analysis limits need to be obtained, if they exist. IEEE and ASTM do not have in-service SF₆ gas by-product analysis limits. CIGRE offers suggested limits in their “SF₆ Recycling Guide 117” dated August 1997. Also, SF₆ gas analysis laboratories may suggest in-service SF₆ gas by-product analysis limits (often based upon the CIGRE Guide). The suggested in-service SF₆ gas by-product analysis limits from one laboratory are:

• SO₂ (Sulfur Dioxide) 2000 ppmv maximum
• SOF₂ (Thionyl Fluoride) 1600 ppmv maximum
• HF (Hydrolyzable Fluorides) 2000 ppmv maximum Con Ed 8 ppm after fault operation
• CF₄ (Carbon Tetrafluoride) 30,000 ppmv maximum
• Air 30,000 ppmv maximum

Second, the SF₆ gas by-product analysis test results are compared to the in-service limits. If the in-service limit for one or more individual gases has been exceeded, corrective action, such as reclamation of the SF₆ gas and/or an internal inspection of the main contacts, arcing contacts and nozzles, may be warranted. Third, the test results should also be compared to the same results from previous tests. Are they staying fairly the same? Are they slowly increasing? Have there been any large changes in the measurements? Trends which are fairly constant or slowly increasing are normal and rarely require corrective action. Trends with large changes which can be correlated with fault interruptions by the circuit breaker are usually normal and may require more frequent SF₆ gas sampling as the gas levels approach their in-service limits. Trends with large changes which cannot be correlated with fault interruptions by the circuit breaker are usually not normal and may require corrective action such as and internal inspection.

An example of SF₆ gas by-product analysis results of a non-failed gas circuit breaker is shown in Table 3-21.

SF6 Purity (% v/v)	99.9
Air (ppm v/v)	780
CF4 (R-14, ppm v/v)	26
Moisture Content (ppm v/v)	14
Hydrogen (H2, ppm v/v)	54
Carbon Dioxide (CO2, ppm v/v)	nd
Sulfur Dioxide (SO2, ppm v/v)	nd
Carbonyl Sulfide (COS, ppm v/v)	nd
Thionyl Fluoride (SOF2, ppm v/v)	nd
Hydrolyzable Fluorides (HF, ppm v/v)	nd

10. First Trip

What is the test? The first trip test measures the trip coil current signature, the DC supply voltage signature and the main contact opening times of a circuit breaker during an opening operation while it is energized and carrying load. The phrase “first trip” comes from the practice that this test is performed on the first opening of the circuit breaker after is has been inactive in the closed position for an extended period, usually on the order of months or years.

What are the test’s objectives? The objectives of the first trip test are to assist in making an assessment of the condition of the electrical trip components and circuitry and of the mechanical operating mechanism and linkage of the circuit breaker. This is done by comparing the trip coil current and DC supply voltage signatures as well as the main contact opening time measurements to previous signatures and measurements from the same circuit breaker to determine if they are remaining constant or changing. Most commonly, close attention is paid to the opening times of the circuit breaker to see if they are slower than desired. There are problems, such as some lubrication issues, that are evident only during the first opening of the circuit breaker and that cannot be detected with subsequent conventional tests.

What does the test check/test/measure/evaluate? The first trip test measures and records the waveforms of the trip coil current and DC supply voltage during an opening operation. The trip coil current waveform provides information on the current magnitude and time required to operate the trip latch, the maximum trip current magnitude, the time that the 52A auxiliary contact operates to de-energize the trip coil and the time it takes the trip coil current to return to zero. The DC supply voltage waveform provides information on the amount of DC ripple present, pre-operation voltage and the voltage drop during the operation of the trip coil. Excessive ripple, low voltage, and/or voltage drop can cause a circuit breaker to operate slowly or to not operate at all. The first trip test also measures the load current in each of the three phases of the circuit breaker and records when each of them change to zero. This provides the time when each of the main contacts has opened and the electrical arc is extinguished. These times can be measured in milliseconds or in cycles (based upon 60 cycles per second). Analysis of the waveforms and timing measurements can detect such problems as trip latch wear and/or adjustment issues, trip coil issues, 52A auxiliary contact issues, trip circuit voltage drop/high resistance issues, control battery issues, lubrication issues, operating linkage excessive wear/friction issues. Note that current interrupting times may vary in relationship to the magnitude of the load and should be considered in the analysis.

Although most circuit breakers are normally closed while they are in service, it is possible to collect “First Close” data on circuit breakers which are normally in the open position. In this case, current and voltage data is collected from the close coil and its circuitry as well as the closing times of the circuit breaker’s main contacts during a closing operation. Note that the “First Close” test addresses 52B auxiliary contact issues and does not have varying times caused by the electrical arc extinguishing time.

What are the test’s limitations? The test must be performed on the first opening or closing operation of the circuit breaker after an extended period of no operation. Measurements made of the second, third or more opening operations may not capture all of the issues that are present during the first opening operation. Each breaker to be tested would either be prewired for easily connection to the test equipment or a person very familiar with each breaker control wiring would need to perform temporary energized wiring connections while the breaker is in service or risk disabling the breaker protection by de-energizing the circuits for connection. Also, if clamp-on meters are used the load current on the circuit breaker must be greater than the minimum sensitivity of the AC clamp-on current probes of the test set to correctly record the opening times of the circuit breaker’s main contacts. First trip testing may not be possible during light load conditions using clamp-on meters.

When does the test need to be performed? This test should be performed upon the initial commissioning of the circuit breaker to verify that it conforms to the manufacturer’s specifications and to collect baseline test data. If a baseline first trip signature was not obtained when the circuit breaker was first commissioned, recent first trip test data such as trip coil current signatures and main contact operating time measurements can be compared to similar data from the same circuit breaker from previous timing tests using conventional test instruments. If previous data is not available from the same circuit breaker, conventional or first trip data from similar model circuit breakers may be used. Future test data can be compared to the commissioning test data to see if any deviations have occurred and if any corrective actions may be required. These future tests may be regular periodic maintenance tests or special investigative tests which may be required due to a misoperation (such as a slow trip),an in-service failure or a perceived problem of the circuit breaker. Also, tests should be performed after any work is performed on the mechanism, interrupters or any other component of the circuit breaker which may affect timing. The regular periodic maintenance tests are normally performed at fixed time intervals that have been selected by the owner and/or operator of the circuit breaker. These fixed time intervals are not standardized across the industry and can vary from 2 years to 10 years or more. Many factors go into the selection of the fixed time interval chosen for each circuit breaker. The use of microprocessor relay and/or SCADA information could provide slow operating times analysis each time the breaker is operated which could trigger this test in lieu of fixed time intervals. These factors are explained in more detail elsewhere in this guidebook.

Which type of circuit breakers is the test used on? This test is used on all types of circuit breakers including air, oil, SF₆ gas and vacuum breakers.

How is the test performed? This test is performed with the circuit breaker energized and in service (on-line). The dielectric medium in the circuit breaker needs to be at proper levels. On oil circuit breakers, the oil level in each tank needs to be within the limits on the oil level gauge. On SF₆ gas circuit breakers, the SF₆ gas pressure in each tank needs to be within the limits specified by the manufacturer. These limits are normally shown on the circuit breaker’s nameplate. The circuit breaker manufacturer’s instruction manual should be consulted for the limits for the Main Contact Opening Time. The circuit breaker manufacturer normally does not have limits for the trip coil current and voltage waveforms or the 52A auxiliary contact operating time. Comparisons with same model breaker times maybe useful when a normal bandwidth of time is established for that model.

The following are the general steps required to perform a first trip test of a circuit breaker using portable clamp-on meters, procedures using microprocessor relays and SCADA information will be added to this guide after they are developed and tested. If the circuit breaker has two trip coils, both coils should be tested at commissioning and future first trip tests alternated between the two trip coils. Each test must be properly labeled as to which trip coil was tested. The control voltage should be at normal levels for this test. The manufacturer’s instructions should always be consulted for the specific operating requirements of each field test set.

1. Properly identify the circuit breaker on which the test is to be performed. This is done by locating the circuit breaker with the correct manufacturer’s name, manufacturer’s serial number and owner’s equipment identification (ID) number in the substation. If a permanent owner’s equipment identification (ID) number label is absent, the three-line drawing of the substation can be referenced to determine the location of the circuit breaker. A temporary label can be attached to the circuit breaker for use during the test. It should be replaced with a permanent label as soon as practical.

2. Check that the circuit breaker’s frame and control cabinet are properly grounded.

3. Check that the oil level(s) on oil circuit breakers are at the proper level and the SF₆ gas pressure(s) on SF₆ gas circuit breakers are at the proper pressure.

4. In the circuit breaker’s control cabinet, properly identify the trip coil to be tested. Connect the DC clamp-on current probe to one side of the trip coil. Connect the two DC voltage probes to the DC supply to the trip coil being tested. Take care to connect the positive DC voltage probe to the positive terminal block and to connect the negative DC voltage probe to the negative terminal block. Also take care to keep a safe working distance from any mechanism or other moving parts. Reference the circuit breaker’s DC schematic and wiring diagrams as necessary to properly make these connections.

5. In the circuit breaker’s control cabinet, properly identify the secondary current transformer (CT) wiring for each of the three phases. Reference the circuit breaker’s AC schematic and wiring diagrams as necessary to properly make the following connections:

   a. Connect the Phase A AC clamp-on current probe to the Phase A CT secondary wiring. b. Connect the Phase B AC clamp-on current probe to the Phase B CT secondary wiring. c. Connect the Phase C AC clamp-on current probe to the Phase C CT secondary wiring.

6. Turn on the first trip test set.

7. If the first trip test set can store the substation name and circuit breaker information, enter them into the test set and save them.

8. Follow the first trip test set manufacturer’s instructions to properly configure it to trigger and to record the data from the test.

9. Arm the first trip test set.

10. Electrically trip the circuit breaker. A mechanical trip will not trigger the first trip test set.

11. Check that data was recorded by the first trip test set.

12. Turn off the first trip test set.

13. Remove the three AC clamp-on current probes.

14. Remove the two DC voltage probes.

15. Remove the DC clamp-on current probe.

16. Remove the temporary open and/or close initiating connections.

17. Electrically close the circuit breaker.

How are the test results interpreted? The test results are reviewed one set of measurements at a time. The Main Contact Opening Times are compared to the circuit breaker manufacturer’s limits. Then, each measurement is compared to the same measurement from previous tests. Are they staying fairly the same? Are they slowly increasing? Are they slowly decreasing? Are there any large changes in the measurements? Trends which are fairly constant are normal. Trends which are slowly increasing or slowly decreasing do not normally require corrective action but may warrant a shorter time interval until the next first trip test. Trends with large changes are usually not normal and may require corrective action.

Also, the trip coil current waveforms are compared to each other and the DC supply voltage waveforms are compared to each other. Are the shapes staying the same? Are there increases or decreases in the magnitudes? Are there increases or decreases in the timing? Waveforms which are fairly constant are normal. Waveforms which are slowly changing do not normally require corrective action but may warrant a shorter time interval until the next first trip test. Waveforms with large changes are usually not normal and may require corrective action.

Figure 3-9 illustrates trip coil current magnitudes and times measured during first trip test of a circuit breaker.

Table 3-22 shows an example of typical first trip test results of a circuit breaker.

Parameter	TestResult	Parameter Description
MCon A (ms)	16.5	Main contact operation time for Phase A
MCon B (ms)	16.4	Main contact operation time for Phase B
MCon C (ms)	16.1	Main contact operation time for Phase C
Spread (ms)	0.4	Maximum spread of Phase A, Phase B and Phase C main contact operation times
Latch (ms)	n/a	Time when trip coil plunger strikes trip latch
Bffr (ms)	4.4	Time when trip coil plunger reaches end of its motion and strikes buffer
ACon (ms)	11.2	Auxiliary 52a contact (in trip coil circuit) operation time
End (ms)	14.0	Time when trip coil current reaches zero
Ipk1 (amps dc)	4.1	Trip coil current magnitude at first peak
Iplt (amps dc)	10.1	Trip coil maximum current magnitude of plateau after first peak
Vini (volts dc)	132.7	Trip coil initial voltage (before breaker operation)
Vmin (volts dc)	126.7	Trip coil minimum voltage (during breaker operation)

An example of typical first trip test waveforms of a circuit breaker is shown in Figure 3-10.

11. Dynamic Contact Resistance Measurement

What is the test? The dynamic contact resistance measurement test measures the DC resistance of the circuit breaker typically using 100 amps of current and measuring very low resistive values in micro ohms at normal operating speeds, from one end of each pole to the other, during an opening operation or during a closing operation. (See Figure 3-11 Circuit Breaker Bushing and Pole Numbering Convention for Dynamic Contact Resistance Measurements.)

What are the test’s objectives? The objectives of the dynamic contact resistance measurement test are to assist in making an assessment of the condition of the arcing contacts and main contacts while in motion in the circuit breaker. This is done by collecting a series of contact resistance measurements while the circuit breaker is in an opening operation or in a closing operation and generating a plot of these resistance values versus time. These plots are compared to previous plots from the same circuit breaker to determine if the measurements are remaining constant or changing. For example, a marked increase in the resistance measurements at one or more time intervals may indicate wear or arcing damage to the arcing contacts or main contacts in the circuit breaker.

What does the test check/test/measure/evaluate? The dynamic contact resistance measurement test evaluates the connections in the primary current path of the circuit breaker by taking an overall resistance measurement per phase while the main and arcing moving contacts are in motion. These connections include:

• Main moving contact to main stationary contact
• Arcing moving contact to arcing stationary contact
• Bushing connections to moving contacts
• Bushing connections to stationary contacts
• Sliding primary current transfer contacts
• Internal bus work

Of the above connections, the main contacts, the arcing contacts and the sliding primary current transfer contacts are the only connections which are in motion during the test. These are the connections which generate the changes in the resistances values measured during the test. Of these connections, the main contacts and the arcing contacts are normally the components which wear and deteriorate with use.

What are the test’s limitations? This test requires the breaker to be taken out on clearance. The clearance procedure usually involves operating the breaker which will exclude finding most lubrication problems associated with the speed of operation (see First Trip test). The interpretation of the resistance versus time plots can be very challenging. It is difficult to determine from the plots at what time the main contacts separate and only the arcing contacts remain in the measuring circuit during the test. Since the main contacts and arcing contacts are in parallel and the main contacts open first, it is possible for the arcing contacts to mask problems with the main contacts during the test. Resistance measurements while the circuit breaker is in an opening operation tend to be more repeatable than those recorded in the closing operation. There are no industry standards as to what determines a bad or failed dynamic resistance measurement test from a good one.

When current transformers are present on the circuit breaker and are located such that the DC current used for the dynamic contact resistance measurement will pass through them, unwanted protective relay operations can occur if improperly filtered DC power supplies are used in the test set. This problem has been known for many years now and most dynamic contact resistance measurement test sets manufactured today have properly filtered DC power supplies. Another technique used in modern test sets is to have the DC power supply slowly ramp the DC test current up before the measurement and slowly ramp the DC test current down after the measurement at a rate that the protective relays will not respond to.

Another issue that involves the current transformers is that when they are present in the dynamic contact resistance measurement test circuit, they will influence the measurement. This influence can result in an increase in the measurement. The best practice when current transformers are present in the test circuit is to first perform a static contact resistance measurement and to leave the test run while monitoring the measurement until it stabilizes. This can take up to a minute or more. During this time, the DC test current will cause the magnetic cores of the current transformers to saturate and to reduce their influence on the static and dynamic contact resistance measurements.

When does the test need to be performed? This test needs to be performed upon the initial commissioning of the circuit breaker to collect baseline test data. Future test data can be compared to the commissioning test data to see if any deviations have occurred and if any corrective actions may be required. These future tests may be regular periodic maintenance tests or special investigative tests which may be required due to a misoperation, an in-service failure or a perceived problem of the circuit breaker as found in other tests (timing/travel, first trip, etc.). The regular periodic maintenance tests are normally performed at fixed time intervals that have been selected by the owner and/or operator of the circuit breaker. These fixed time intervals are not standardized across the industry and can vary from 2 years to 10 years or more. Fixed time intervals may be replaced or supplemented in the future by triggering on in-service operating times measured using microprocessor protective relays and/or SCADA time stamps. Many factors go into the selection of the fixed time interval chosen for each circuit breaker. These factors are explained in more detail elsewhere in this guidebook. Currently, most utilities are not including this test as part of their regular periodic maintenance testing program.

Which type of circuit breakers is the test used on? This test is currently used on SF₆ gas “puffer” type circuit breakers which have parallel sliding main and arcing contact assemblies.

How is the test performed? This test is performed with the circuit breaker de-energized and out of service (off-line). Normally, the grounded external high voltage connections are removed from one side of the circuit breaker and are left connected on the other side of the circuit breaker for the test. Current transformers in use on the circuit breaker are left connected to their protective relays and meters. Unused current transformers should have their secondaries shorted and grounded. The SF₆ gas pressure in each tank needs to be within the limits specified by the manufacturer. These limits are normally shown on the circuit breaker’s nameplate. It is very important that the top terminals of the bushings be inspected and cleaned to insure a good connection point for the test equipment leads. Poor contact resistance between the test equipment leads and the top terminals of the circuit breaker can result in abnormally high readings and possibly indicate a problem with the internal breaker contacts which does not exist. Surface moisture on the bushings has very little effect on dynamic contact resistance measurements therefore the test can be performed in humid or wet weather conditions if necessary. However, since resistance values vary with temperature, the ambient air temperature should be recorded at the time of the test. The test current used for the dynamic contact resistance measurement can vary from 100 amps DC to several hundred amps DC. A test current value of 100 amps DC is frequently used. Most field test sets used for dynamic contact resistance measurements utilize a Digital Low Resistance Ohmmeter or DLRO. It consists of two larger size cables (normally red and black) to inject the DC test current into the circuit breaker and two smaller size cables (normally red and black) to measure the DC voltage drop across the circuit breaker. One phase (or pole) is measured at a time.

The following are the general steps required to perform the dynamic contact resistance measurements of a circuit breaker with a field test set. Three measurements will be made (one per phase) during an opening operation of the circuit breaker. The manufacturer’s instructions should always be consulted for the specific operating requirements of each field test set.

1. Properly identify the circuit breaker on which the test is to be performed. This is done by locating the circuit breaker with the correct manufacturer’s name, manufacturer’s serial number and owner’s equipment identification (ID) number in the substation. If a permanent owner’s equipment identification (ID) number label is absent, the three-line drawing of the substation can be referenced to determine the location of the circuit breaker. A temporary label can be attached to the circuit breaker for use during the test. It should be replaced with a permanent label as soon as practical.

2. Check that the circuit breaker has been properly removed from service, lock out and tag out procedures have been followed and the circuit breaker is safe to work on.

3. Install grounds on the external high voltage leads to Bushing Numbers 1 through 6 (reference Figure 3-11 Circuit Breaker Bushing and Pole Numbering Convention for Dynamic Contact Resistance Measurements).

4. Connect the ground lead from the field test set to the substation ground connection to the circuit breaker.

5. Remove the external high voltage connection and ground from Bushing Number 1.

6. Connect one of the current test leads (larger cable) from the field test set to the top of Bushing Number 1.

7. Connect the voltage test lead (smaller cable) of the same color from the field test set just below the current test lead on the top of Bushing Number 1. Check that the voltage lead is making a good connection. Clean the connection point on the top of the bushing with a wire brush if necessary.

8. Connect the other current test lead (larger cable) from the field test set to the top of Bushing Number 2 (leave the external high voltage connection and ground connected to Bushing Number 2).

9. Connect the voltage test lead (smaller cable) of the same color from the field test set just below the current test lead on the top of Bushing Number 2. Check that the voltage lead is making a good connection. Clean the connection point on the top of the bushing with a wire brush if necessary.

10. Check that the circuit breaker is in the closed position.

11. Turn on the field test set.

12. Select the test current level (100 Amps DC is frequently used).

13. For circuit breakers with current transformers, a static contact resistance measurement test needs to be performed first to saturate the current transformers on that pole. Select a test duration time of at least one minute to allow time for the current transformers to saturate and give an accurate resistance measurement. The key is to allow enough time for the resistance measurement to stabilize before ending the test. For circuit breakers without current transformers, go to Step 16.

14. Set the Test Mode of the field test set to Static Contact Resistance Measurement and perform the test. Note: The resistance measurement is made by the field test set by dividing the voltage reading across the voltage test leads by the test current. If a high resistance measurement is observed, check the connections of the voltage test lead clamps with the top of the bushings and repeat the test.

15. Record the static contact resistance measurement, test current level and ambient temperature for the test.

16. Set the Test Mode of the field test set to Dynamic Contact Resistance Measurement Opening Operation and perform the test.

17. Review the test results to see if a resistance versus time plot was recorded.

18. Close the circuit breaker.

19. Repeat Steps 16-18 a minimum of two more times.

20. Turn off the field test set.

21. Remove the voltage test lead and current test lead from the field test set from Bushing Number 2.

22. Connect this current test lead (larger cable) from the field test set to the top of Bushing Number 4 (leave the external high voltage connection and ground connected to Bushing Number 4).

23. Connect this voltage test lead (smaller cable) of the same color from the field test set just below the current test lead on the top of Bushing Number 4. Check that the voltage lead is making a good connection. Clean the connection point on the top of the bushing with a wire brush if necessary.

24. Remove the voltage test lead and current test lead from the field test set from Bushing Number 1.

25. Reconnect the external high voltage connection and ground to the top of Bushing Number 1.

26. Remove the external high voltage connection and ground from Bushing Number 3.

27. Connect the current test lead (larger cable) from the field test set just removed from Bushing Number 1 to the top of Bushing Number 3.

28. Connect the voltage test lead (smaller cable) of the same color from the field test set just removed from Bushing Number 1 to just below the current test lead on the top of Bushing Number 3. Check that the voltage lead is making a good connection. Clean the connection point on the top of the bushing with a wire brush if necessary.

29. Turn on the field test set.

30. Select the test current level (100 Amps DC is frequently used).

31. For circuit breakers with current transformers, a static contact resistance measurement test needs to be performed first to saturate the current transformers on that pole. Select a test duration time of at least one minute to allow time for the current transformers to saturate and give an accurate resistance measurement. The key is to allow enough time for the resistance measurement to stabilize before ending the test. For circuit breakers without current transformers, go to Step 34.

32. Set the Test Mode of the field test set to Static Contact Resistance Measurement and perform the test. Note: The resistance measurement is made by the field test set by dividing the voltage reading across the voltage test leads by the test current. If a high resistance measurement is observed, check the connections of the voltage test lead clamps with the top of the bushings and repeat the test.

33. Record the static contact resistance measurement, test current level and ambient temperature for the test.

34. Set the Test Mode of the field test set to Dynamic Contact Resistance Measurement Opening Operation and perform the test.

35. Review the test results to see if a resistance versus time plot was recorded.

36. Close the circuit breaker.

37. Repeat Steps 34-36 a minimum of two more times.

38. Turn off the field test set.

39. Remove the voltage test lead and current test lead from the field test set from Bushing Number 3.

40. Reconnect the external high voltage connection and ground to the top of Bushing Number 3.

41. Remove the external high voltage connection and ground from Bushing Number 5.

42. Connect the current test lead (larger cable) from the field test set just removed from Bushing Number 3 to the top of Bushing Number 5.

43. Connect the voltage test lead (smaller cable) of the same color from the field test set just removed from Bushing Number 3 to just below the current test lead on the top of Bushing Number 5. Check that the voltage lead is making a good connection. Clean the connection point on the top of the bushing with a wire brush if necessary.

44. Remove the voltage test lead and current test lead from the field test set from Bushing Number 4.

45. Connect this current test lead (larger cable) from the field test set to the top of Bushing Number 6 (leave the external high voltage connection and ground connected to Bushing Number 6).

46. Connect this voltage test lead (smaller cable) of the same color from the field test set just below the current test lead on the top of Bushing Number 6. Check that the voltage lead is making a good connection. Clean the connection point on the top of the bushing with a wire brush if necessary.

47. Turn on the field test set.

48. Select the test current level (100 Amps DC is frequently used).

49. For circuit breakers with current transformers, a static contact resistance measurement test needs to be performed first to saturate the current transformers on that pole. Select a test duration time of at least one minute to allow time for the current transformers to saturate and give an accurate resistance measurement. The key is to allow enough time for the resistance measurement to stabilize before ending the test. For circuit breakers without current transformers, go to Step 52.

50. Set the Test Mode of the field test set to Static Contact Resistance Measurement and perform the test. Note: The resistance measurement is made by the field test set by dividing the voltage reading across the voltage test leads by the test current. If a high resistance measurement is observed, check the connections of the voltage test lead clamps with the top of the bushings and repeat the test.

51. Record the static contact resistance measurement, test current level and ambient temperature for the test.

52. Set the Test Mode of the field test set to Dynamic Contact Resistance Measurement Opening Operation and perform the test.

53. Review the test results to see if a resistance versus time plot was recorded.

54. Close the circuit breaker.

55. Repeat Steps 52-54 a minimum of two more times.

56. Turn off the field test set.

57. Remove the voltage test lead and current test lead from the field test set from Bushing Number 6.

58. Remove the voltage test lead and current test lead from the field test set from Bushing Number 5.

59. Reconnect the external high voltage connection and ground to the top of Bushing Number 5.

60. Remove grounds from the external high voltage leads to Bushing Numbers 1 through 6.

61. Leave the circuit breaker in the same position (open or closed) that it was found before these tests.

How are the test results interpreted? First, the resistance versus time plots from the above tests for Pole 1 are compared to each other. Usually, the plots of a given pole will be very close to each other. Next, the plots from Pole 1 are compared to the plots from Pole 1 from previous tests. Are the plots staying fairly the same? Are there any changes in the plots? At which times are the changes occurring? Changes in the resistance values near the right side of the plot may indicate a problem in the arcing contacts since the main contacts are normally open at this point in time. Changes in the resistance values near the left side of the plot are harder to interpret as both main and arcing contacts are closed at this point in time. Changes in the resistance values near the middle of the plot are also harder to interpret as the point when the main contacts open is hard to determine. Small changes in the plots do not normally require corrective action. Large changes in the plots may require follow-up actions such as repeating the test after a period of time to see if there are any further changes in the plot or performing an internal inspection of the main and arcing contacts.

The same process above is used for interpreting the Pole 2 and Pole 3 resistance versus time plots.

Figure 3-12 is an example of normal dynamic contact resistance measurement test waveforms of during a trip operation of one phase of an SF₆ gas circuit breaker.

Figure 3-13 presents a comparison of dynamic contact resistance measurement test waveforms during a trip operation of all three phases of an SF₆ gas circuit breaker with normal differences.

12. Detection of Acoustic Emissions from Partial Discharge

What is the test? The detection of acoustic emissions from partial discharge test determines if there is partial discharge activity inside of the high voltage tank or compartment of a circuit breaker.

What are the test’s objectives? The objective of the acoustic partial discharge test is to assist in making an assessment of the condition of the insulation systems in the circuit breaker. This is done by measuring the presence and frequency of occurrence of acoustic activity in the circuit breaker.

What does the test check/test/measure/evaluate? The partial discharge test evaluates the relative condition of insulation systems by determining partial discharge activity inside of the circuit breaker. Some of the components which can generate partial discharge activity are:

• Internal support insulators
• Operating rods
• Bushings
• Loose or poor connections

What are the test’s limitations? Significant acoustic signal can be generated by external sources such as corona on lines, loose nameplates, storms, and noises from passing equipment such as trucks. An internal source of acoustic signal is the operation of the breaker. These sources of acoustic signal can result in incorrect conclusions. One possibility to filter these false signals is to use an electrical trigger from the power system frequency.

No absolute value of partial discharge activity can be determined from acoustic emission measurements made in the field. Partial discharge level may be masked by its location, e.g. inside interrupters, vs. close to the acoustic sensor. It is also influenced by the pre-amplifiers and amplifiers used in signal processing.

The frequency of the signal may be influenced by the sensor used. Many of the sensors used for field tests are resonant sensors. An analogy could be the noise from a drum, which is the resonant frequency of the drum rather than the frequency of hitting the drum.

There are no industry standards as to what determines a bad or failed partial discharge measurement test from a good one.

When does the test need to be performed? This test is usually performed as a special investigative test, which may be required due to a misoperation, an in-service failure or a perceived problem of the circuit breaker. Currently, most utilities are not including this test as part of their regular periodic maintenance testing program.

Which type of circuit breakers is the test used on? This test is more commonly used on dead-tank SF₆ gas circuit breakers. It can also be used on air, oil and vacuum breakers where the high voltage tank or compartment is of a grounded or dead-tank design and safely assessable while the circuit breaker is energized.

The following section on WARNINGS is from C57.127 Guide for the Detection and Location of Acoustic Emissions from Partial Discharges in Oil\-Immersed Power Transformers and Reactors. The same precautions should be observed for acoustic test activities conducted on circuit breakers.

WARNINGS

1. The transformer tank must be connected to a low resistance ground to limit the extremely high voltages being induced into the ground circuit and the tank if a high voltage to ground failure occurs. The personnel risk is very high if the transformer fails to ground. Even when grounded properly, the voltage on the tank to a different ground source may be LETHAL at the instant the failure occurs.

2. If the transformer is being energized or de-energized, or there is another type of power system voltage, all personnel should maintain a reasonable distance from the transformer and equipment electrically connected to the tank due to the possibility of a failure. It is recommended that acoustic measurement equipment connected to the tank be electrically isolated from the transformer tank, e.g., by optical means or by high-voltage electrical insulation, when measuring during transient events to eliminate the danger to the equipment or operators.

3. It is preferable to make all connections to the tank with the transformer de-energized, but in no case should the transformer voltage be above normal voltage while the sonic measuring devices are installed. Personnel must not access areas where high voltages are within minimum approach distance, such as on top of energized transformers or in bushing compartments.

4. The transformer ground circuit must never be changed (connected or disconnected) while the transformer is energized. Even with the transformer de-energized, it is possible to have circulating currents in substation ground circuits; therefore, appropriate care should be exercised when connecting or disconnecting ground circuits.

How is the test performed? This test is normally performed with the circuit breaker energized and in service (on-line). It can also be performed with the circuit breaker out of service (off-line) and temporarily energized from a Hi-pot test set. The dielectric medium in the circuit breaker needs to be at proper levels. On oil circuit breakers, the oil level in each tank needs to be within the limits on the oil level gauge. On SF₆ gas circuit breakers, the SF₆ gas pressure in each tank needs to be within the limits specified by the manufacturer. These limits are normally shown on the circuit breaker nameplate. Since the circuit breaker is in service for this test, the dielectric medium is usually at proper levels. This will be checked and recorded as part of the testing procedure below. Surface moisture on the bushings can generate unwanted external partial discharge activity so it is preferred to not perform this test in rain, snow or high humidity conditions.

The following are the general steps required to measure the partial discharge activity of a circuit breaker. Measurements will be performed on each of the grounded high voltage tanks or compartments. The manufacturer’s instructions should always be consulted for the specific operating requirements of each field test set.

1. Properly identify the circuit breaker on which the test is to be performed. This is done by locating the circuit breaker with the correct manufacturer’s name, manufacturer’s serial number and owner’s equipment identification (ID) number in the substation. If a permanent owner’s equipment identification (ID) number label is absent, the three-line drawing of the substation can be referenced to determine the location of the circuit breaker. A temporary label can be attached to the circuit breaker for use during the test. It should be replaced with a permanent label as soon as practical.

2. If the circuit breaker has three high voltage tanks, properly identify which primary phase is connected to each tank of the circuit breaker. It is a best practice to permanently label the primary phase marking on the tanks, stands or enclosures of each circuit breaker when it is commissioned. If these permanent primary phase markings are absent, the three-line drawing or phasing drawing of the substation can be referenced to determine which primary phase is connected to which pole of the circuit breaker. Temporary labels can be attached to the circuit breaker for use during the test. These should be replaced with permanent labels as soon as practical.

3. Record the oil levels or SF₆ gas pressures on each of the high voltage tanks.

4. Record the ambient air temperature, relative humidity level and weather conditions at the substation

5. Draw a hand sketch of the circuit breaker to record where the acoustic partial discharge sensors are located for each test.

6. Check that the circuit breaker’s frame and tank(s) are properly grounded.

7. Attach the acoustic partial discharge sensor(s) to the high voltage tank(s) or compartment(s). Normally, only one sensor per tank is required. Use a good quality silicone or fluorosilicone grease between the sensor and the tank to enhance the transmission of the partial discharge noises in the tank to the sensor and to help block external noises from entering the sensor.

8. Attach electrical trigger if that method of filtering is chosen.

9. Record the location of the sensor(s) and the Test ID Number on the hand sketch drawn in Step 5.

10. Connect the wire or optical cable from each sensor to the partial discharge test set.

11. Turn on the test set.

12. If the test set has recording capability, record the measurements. If the test set does not have recording capability, manually record the magnitude and frequency of occurrence of any spikes that are observed as well as the readings of the background noise when no spikes are present. A recording period in the range of 10 to 20 minutes should be used. The length of the recording period should be the same for each test.

    • Partial discharge may only be present during specific circumstances, e.g. when load is light and voltage is high. The test period may have to be substantially longer than the nominal 10 to 20 minutes cited above in order to detect partial discharge activity.

13. Turn off the test set.

14. Remove the acoustic partial discharge sensor(s) from the circuit breaker.

15. Keep a log of the Test ID Number, date and time of test for each test.

16. Repeat Steps 7–13 until each high voltage tank or compartment has been tested.

How are the test results interpreted? In general, a more intense partial discharge source will typically produce a higher acoustic emission magnitude and count rate than a weak source. This is because at the site of an intense discharge there may be multiple locations or perturbations that are producing higher energy partial discharge and acoustic emissions.

The three measurements of circuit breakers with three high voltage tanks can be compared to each other. Are all three phases fairly the same? Is one phase significantly noisier than the other two phases? A significantly noisier phase is usually not normal and may require corrective action.

The detection of internal partial discharge in circuit breakers should be a cause for further investigation.

An example of waveforms showing acoustic emissions from partial discharges of one tank (phase) of a three-tank SF₆ gas circuit breaker is shown in Figure 3-14.

13. Vibration

What is the test? The vibration test measures the mechanical vibration of the circuit breaker during open, close and close-open operations.

What are the test’s objectives? The objectives of the vibration test are to assist in making an assessment of the performance and condition of the operating mechanism and interrupters in the circuit breaker. These measurements are then compared to previous measurements from the same circuit breaker or compared to measurements from similar circuit breakers to see if components in the circuit breaker’s operating mechanism or interrupter may be damaged or deteriorating.

What does the test check/test/measure/evaluate? The vibration test measures and records the waveforms of the mechanical vibrations present in the circuit breaker when it is operating. The operations normally recorded are open (trip), close and close-open (trip-free). The unit of measurement of the magnitude of the waveforms is gravity or g. The units of time of the waveforms are milliseconds or microseconds. Analysis of the vibration waveforms can detect possible contact misalignments, improper mechanical adjustments, malfunctioning shock absorbers or dash-pots. Changes in the time of occurrence of vibration events may indicate worn or binding linkages or lubrication issues.

What are the test’s limitations? Determining the proper locations for the installation of the accelerometers to record the vibration signals is a challenge. It is desired to place the accelerometers at the locations of maximum vibration. Often this is not known and several locations may need to be tried to find the optimal location. Other times the design of the circuit breaker may limit the number of available locations for accelerometer installation and prevent an accurate vibration measurement.

Changes in temperature may influence vibration frequencies and levels.

Another challenge is the interpretation of the vibration versus time plots. For example, which changes in the waveforms should be a cause for concern? There are no industry standards as to what determines a bad or failed vibration test from a good one.

When does the test need to be performed? This test needs to be performed upon the initial commissioning of the circuit breaker to collect baseline test data. Future test data can be compared to the commissioning test data to see if any deviations have occurred and if any corrective actions may be required. These future tests may be regular periodic maintenance tests or special investigative tests which may be required due to a misoperation, an in-service failure or a perceived problem of the circuit breaker. The regular periodic maintenance tests are normally performed at fixed time intervals that have been selected by the owner and/or operator of the circuit breaker. These fixed time intervals are not standardized across the industry and can vary from 2 years to 10 years or more. Many factors go into the selection of the fixed time interval chosen for each circuit breaker. These factors are explained in more detail elsewhere in this guidebook. Currently, most utilities are not including this test as part of their regular periodic maintenance testing program.

Which type of circuit breakers is the test used on? This test is used on all types of circuit breakers including air, oil, SF₆ gas and vacuum breakers.

WARNINGS: the same warnings apply as noted in Section 13.

How is the test performed? This test is normally performed with the circuit breaker de-energized and out of service (off-line). The dielectric medium in the circuit breaker needs to be at proper levels. On oil circuit breakers, the oil level in each tank needs to be within the limits on the oil level gauge. On SF₆ gas circuit breakers, the SF₆ gas pressure in each tank needs to be within the limits specified by the manufacturer. These limits are normally shown on the circuit breaker’s nameplate. Surface moisture on the bushings has very little effect on vibration measurements therefore the test can be performed in humid or wet weather conditions if necessary.

The following are the general steps required to perform the vibration test of a circuit breaker with a field test set. A test sequence of close, trip, trip-free is commonly used for these measurements. A minimum of three complete sequences is recommended to check for consistency in the measurements. The control voltage should be at normal levels for these tests. The manufacturer’s instructions should always be consulted for the specific operating requirements of each field test set.

1. Properly identify the circuit breaker on which the test is to be performed. This is done by locating the circuit breaker with the correct manufacturer’s name, manufacturer’s serial number and owner’s equipment identification (ID) number in the substation. If a permanent owner’s equipment identification (ID) number label is absent, the three-line drawing of the substation can be referenced to determine the location of the circuit breaker. A temporary label can be attached to the circuit breaker for use during the test. It should be replaced with a permanent label as soon as practical.

2. Check that the circuit breaker has been properly removed from service, lock out and tag out procedures have been followed and the circuit breaker is safe to work on.

3. If the circuit breaker has three high voltage tanks, properly identify which primary phase is connected to each tank of the circuit breaker. It is a best practice to permanently label the primary phase marking on the tanks, stands or enclosures of each circuit breaker when it is commissioned. If these permanent primary phase markings are absent, the three-line drawing or phasing drawing of the substation can be referenced to determine which primary phase is connected to which pole of the circuit breaker. Temporary labels can be attached to the circuit breaker for use during the test. These should be replaced with permanent labels as soon as practical.

4. Draw a hand sketch of the circuit breaker to record where the accelerometers are located for each test and permanently mark the locations or install the accelerometer plastic bases on the breaker.

5. Install the accelerometers on the circuit breaker. Normally, each accelerometer screws into its own plastic base. These plastic bases are attached to the circuit breaker with cement and can be reused for future tests. Suggested locations for accelerometers are:

   a. On the operating mechanism and in line with the motion of the main operating crank.

   b. On the end of each tank of a dead tank SF₆ gas circuit breaker and in line with the motion of the main contact operating rod.

   c. On the top of each tank of a dead tank oil circuit breaker and in line with the motion of the main contact operating rod.

6. Record the location of the accelerometers on the hand sketch drawn in Step 4.

7. Connect the wire from each accelerometer to the vibration test set.

8. Turn on the test set.

9. Record the vibration measurements of a close operation.

10. Record the vibration measurements of a trip operation.

11. Record the vibration measurements of trip-free operation.

12. Review each of the three plots to see if the accelerometers being used have the proper range. If the vibrations are greater than the range of the accelerometer, change it to one with a larger range. If the vibrations are very small, change to an accelerometer with a smaller range. Repeat Steps 9-11 if any of the accelerometers are changed. Use the same accelerometers for all tests.

13. Repeat Steps 9-11 at least two more times.

14. Turn off the test set.

15. Remove the wires to each accelerometer.

16. Remove the accelerometers from the circuit breaker.

17. Leave the circuit breaker in the same position (open or closed) that it was found before these tests.

How are the test results interpreted? The vibration versus time plots from each accelerometer location are reviewed one location at a time. First, the plots of the three close tests are compared to each other. Usually, these plots will look fairly close to each other. They should also be compared to previous close test plots from the same location. Are the plots staying fairly the same? Are there any changes in the plots? At which times are the changes occurring? Small changes in the plots do not normally require corrective action. Large changes in the plots may require follow-up actions such as repeating the test after a period of time to see if there are any further changes in the plot or performing an inspection of the mechanism components. Next, the plots of the three trip tests are compared to each other in the same manner as the close tests above. The plots of the three trip-free tests are also compared to each other in the same manner as the close tests above with the additional comparisons of the first half of the trip-free test plots to the close test plots above and the second half of the trip-free test plots to the trip test plots above.

This comparison of the close test plots, the trip test plots and the trip-free test plots is performed again for each accelerometer location.

For circuit breakers with accelerometers in the same location on each of the three phases and where previous plots do not exist, the plots of the three phases can be compared to each other. Are all three phases fairly the same? Is one phase significantly different than the other two phases? A significantly different phase is usually not normal and may require corrective action.

For circuit breakers with accelerometers in locations other than each of the three phases and where previous plots do not exist, the plots of these accelerometers can be compared with other circuit breakers of the same model and vintage. Is the plot fairly the same as the other breakers? Is the plot significantly different than the other breakers? A significantly different plot is usually not normal and may require corrective action.

Table 3-23 shows an example of normal trip vibration test results of a three-tank SF₆ gas circuit breaker.

Test ID	Phase A Maximum Opening Vibration (g)	Phase B Maximum Opening Vibration (g)	Phase C Maximum Opening Vibration (g)
Trip 1	28.55	24.00	18.85
Trip 2	31.45	23.41	18.70
Trip 3	30.33	22.78	18.18

An example of normal trip vibration test waveforms (top three traces) of a three-tank SF₆ gas circuit breaker is shown in Figure 3-15.

An example of normal close vibration test results of a three-tank SF₆ circuit breaker is shown in Table 3-24.

Test ID	Phase A Maximum Closing Vibration (g)	Phase B Maximum Closing Vibration (g)	Phase C Maximum Closing Vibration (g)
Close 1	7.94	8.69	5.15
Close 2	11.69	13.75	6.98
Close 3	13.29	11.94	7.39

Figure 3-16 shows an example of normal close vibration test waveforms (top three traces) of a three-tank SF₆ gas circuit breaker.

Test ID	Phase A Maximum Close-Opening Vibration (g)	Phase B Maximum Close-Opening Vibration (g)	Phase C Maximum Close-Opening Vibration (g)
Trip-Free 1	34.75	46.59	23.55
Trip-Free 2	30.14	44.10	25.15
Trip-Free 3	31.35	40.73	21.17

14. Radiography (X-Ray) of Contacts

What is the test? The radiography (X-ray) of contacts test views the profile of the contact assembly inside of a circuit breaker from outside of the interrupter tank.

What are the test’s objectives? The objectives of the radiography (X-ray) of contacts test are to assist in making an assessment of the condition of the arcing and main contacts in the circuit breaker. This is done by taking radiographic images of the contact assemblies with the circuit breaker in the open position. These images are then compared to images of healthy contact assemblies of similar circuit breakers and/or manufacturer’s dimensional drawings to determine if contact wear or erosion is present.

What does the test check/test/measure/evaluate? The radiography (X-ray) of contacts test evaluates the physical condition and proper installation of the components of the interrupter assembly. These items include:

1. Main moving contact wear, erosion or proper installation (tightness)

2. Main stationary contact wear, erosion or proper installation (tightness)

3. Main moving contact to main stationary contact proper alignment

4. Arcing moving contact wear, erosion or proper installation (tightness)

5. Arcing stationary contact wear, erosion or proper installation (tightness)

6. Arcing moving contact to arcing stationary contact proper alignment

7. Interrupter nozzle wear, erosion or proper installation (tightness)

8. Sliding primary current transfer contacts wear, erosion or proper installation (tightness)

9. Bolts that have loosened but are still in place

10. Bolts that are missing

11. Bolts that have detached and fallen into an undesirable area of the circuit breaker

12. Debris in the bottom of the interrupter tank

Of the above items, the main contacts, the arcing contacts and the interrupter nozzle are normally the components which wear and deteriorate with use. Occasionally, this test detects problems with the remaining items listed above.

What are the test’s limitations? This test requires a breaker clearance and may be very time consuming. Proper knowledge of and experience with taking radiographic images of circuit breakers and working in an energized substation is essential for the successful execution of this test. Utilities do not have this skill in house requiring that this test be performed by an outside contractor. These contractors will normally require that no one be living or working within a large radius (50 feet or more) from where they will be using their X-ray equipment. Nearby homes or businesses which are inside of this radius may prohibit this test from being performed. Also, other work inside of the substation may not be possible due to the presence and use of X-ray equipment. These contractors may require that adjacent equipment be taken out of service for them to safely perform their test. If this equipment cannot be taken out of service, the contractor may not be able to perform this test.

The interpretation of the radiographic images can be very challenging. Some circuit breaker manufacturers may specify only 1 mm or 2 mm wear as the threshold to replace contacts or interrupter nozzles. This is very difficult to determine on the radiographic images as they will be much larger than the actual component itself. This is due to the fact that the X-ray transmitter is on the outside of one side of the interrupter tank and the plate to collect the image is on the outside on the other side of the interrupter tank. This results in an amplification of the component’s image. Also, the actual dimensions of these components are not normally given in the circuit breaker manufacturer’s instruction manual. This requires that the actual dimensions be obtained from the circuit breaker manufacturer. Verification of proper installation tightness may also be difficult.

When does the test need to be performed? This test needs to be performed upon the initial commissioning of the circuit breaker to collect baseline test images. Future test images can be compared to the commissioning test images to see if any deviations have occurred and if any corrective actions may be required. These future tests may be regular periodic maintenance tests or special investigative tests which may be required due to a misoperation, an in-service failure or a perceived problem of the circuit breaker. The regular periodic maintenance tests are normally performed at fixed time intervals that have been selected by the owner and/or operator of the circuit breaker. These fixed time intervals are not standardized across the industry and can vary from 2 years to 10 years or more. Many factors go into the selection of the fixed time interval chosen for each circuit breaker. These factors are explained in more detail elsewhere in this guidebook. Currently, most utilities are not including this test as part of their regular periodic maintenance testing program.

Which type of circuit breakers is the test used on? This test is currently used on SF₆ gas “puffer” type circuit breakers which have parallel sliding main and arcing contact assemblies and with the three phases separated into individual interrupter tanks.

How is the test performed? This test is performed with the circuit breaker de-energized and out of service (off-line). All external high voltage connections are left connected to the circuit breaker during the test.

The following are the general steps required to perform the radiography (X-ray) of contact test.

1. Properly identify the circuit breaker on which the test is to be performed. This is done by locating the circuit breaker with the correct manufacturer’s name, manufacturer’s serial number and owner’s equipment identification (ID) number in the substation. If a permanent owner’s equipment identification (ID) number label is absent, the three-line drawing of the substation can be referenced to determine the location of the circuit breaker. A temporary label can be attached to the circuit breaker for use during the test. It should be replaced with a permanent label as soon as practical.

2. Check that the circuit breaker has been properly removed from service, lock out and tag out procedures have been followed and the circuit breaker is safe to work on.

3. Install grounds on the external high voltage leads on both sides of the circuit breaker.

4. Properly identify which primary phase is connected to each pole of the circuit breaker. It is a best practice to permanently label the primary phase marking on the tanks, stands or enclosures of each circuit breaker when it is commissioned. If these permanent primary phase markings are absent, the three-line drawing or phasing drawing of the substation can be referenced to determine which primary phase is connected to which pole of the circuit breaker. Temporary labels can be attached to the circuit breaker for use during the test. These should be replaced with permanent labels as soon as practical.

5. Check that the circuit breaker is in the open position.

6. Erect a safety zone barrier around the circuit breaker. The radius will be specified by the contract radiographer and can be 50 feet or more.

7. Check that the contractor sets up X-ray radiation monitors in the safety zone.

8. Check that everyone working in the safety zone is wearing their personal X-ray radiation monitors.

9. The contract radiographer normally has only one X-ray transmitter and one image plate. This means that the X-ray transmitter and image plate will be relocated for each required image.

10. Two images of each contact, taken at 90 degree angles from each other, are required to obtain a 360 degree representation of the contact. This means that four images are required per phase on circuit breakers which have two contacts in series.

11. Additional images can be taken of the remainder of the interrupter assembly and of possible debris in the bottom of the interrupter tank if desired.

12. Exposure times for each image will vary and make take from 4 minutes to 11 minutes or more. Proper exposure is critical for the success of this test. Digital imaging systems are essential so that each image can be verified for proper exposure before repositioning the X-ray transmitter and image plate for the next image. Underexposure results in poor definition of the internal components making measurements impossible. Overexposure results in the internal components appearing larger than they actually are making measurements inaccurate.

13. Dismantle the safety zone barrier around the circuit breaker when the contract radiographer has completed the imaging and indicates that it is safe to do so.

14. Remove the grounds on the external high voltage leads on both sides of the circuit breaker.

How are the test results interpreted? The images of each arcing contact tip are reviewed one arcing contact at a time. If previous images are available, they are compared to the recent images. If previous images are not available, the recent images can be compared to the images of the other arcing contacts in the circuit breaker. Is the profile of the arcing contact tip the proper shape? Are pits or erosion observed? Next, the images are compared to the manufacturer’s dimensional drawings to determine the exact amount of arcing contact tip erosion if any. If the manufacturer’s dimensional drawings are not available, the exact amount of contact tip erosion may be difficult to determine. If it can be determined that the amount of erosion of the arcing contact tip exceeds the circuit breaker manufacturer’s limits, then an internal inspection of the circuit breaker may be warranted to see if the arcing contact indeed needs replacement.

This same review process is followed for the remaining arcing contacts, main contacts, interrupter nozzles and other components of the interrupter. If any abnormalities are observed, an internal inspection may be warranted.

Figure 3-18 shows a typical radiography setup.

Figure 3-19 is a photograph of a 69 kV SF₆ gas circuit breaker and radiograph of one of its interrupters.

Figure 3-20 is a radiograph of 115 kV SF₆ gas circuit breaker interrupter.

15. Particles and Metals in Oil Analysis

What is the test? The particles and metals in oil analysis test measures the quantity of different sized particles, the type of particles and the levels, in ppm, of specific metals in the oil of the circuit breaker.

What are the test’s objectives? The objectives of the particles and metals in oil analysis test are to assist in making an assessment of the condition of the arcing and main contact tips and of the arc suppression grids in the circuit breaker. For the arcing and main contact tips, this is done by accurately measuring the levels, in ppm, of specific metals in the oil. For the arc suppression grids, this is done by accurately measuring the quantity of different sized particles in the oil as well as determining the percentage of these particles which are fibrous. Circuit breaker manufacturers do not have particles and metals in oil analysis test specifications. Therefore, the measurements are compared to statistical data from particles and metals in oil analysis test results from similar circuit breakers and to previous test results from the same circuit breaker to determine if they are elevated, remaining constant or changing. Also, ratios of certain particle size counts may be compared as part of the analysis.

What does the test check/test/measure/evaluate? The particles and metals in oil analysis test evaluates the condition of the arc suppression grids in the circuit breaker by first measuring the quantity of particles in specific size ranges in a specific volume, normally 10 milliliters, of oil. An example of the specific size ranges used by one laboratory are:

• Between 6 and 10 micrometers
• Between 10 and 14 micrometers
• Between 14 and 25 micrometers
• Between 25 and 50 micrometers
• Between 50 and 100 micrometers
• Greater than 100 micrometers

As an arc suppression grid deteriorates, cellulose and carbon particles are generated. These particles increase in size as the deterioration of the arc suppression grid increases. By monitoring the increase of the ratios of the larger size particle quantities to the smaller size particle quantities, an estimation of arc suppression grid deterioration can be made.

Another measurement of the particles and metals in oil analysis test is the breakdown, in percent, of the particle materials. An example of the materials classified by one laboratory are:

• Fibrous Particles (from the arc suppression grids)
• Metal Particles (from bearing surfaces, the arcing and main contact tips)
• Carbon Particles (from the arc when the circuit breaker’s contacts part)
• Other Particles

Carbon particles are very common in the oil in a circuit breaker. As the arc suppression grids deteriorate, the fibrous particles increase. As the arcing and main contact tip erosion increases or bearing surfaces wear, the metal particles increase.

In addition to the metal particles measured above, the particles and metals in oil analysis test also measures the levels, in ppm, of the following key metals dissolved in the oil:

• Silver (Ag)
• Copper (Cu)
• Tungsten (W)
• Chromium (Cr)
• Nickel (Ni)
• Lead (Pb)
• Tin (Sn)
• Silica in oil circuit breakers

The above metals are normally used in circuit breaker bearings, arcing and main contact tips. The levels of these metals in the oil increase as the tips or bearings erode. Therefore, an estimate of the erosion of the arcing and main contact tips can be made my monitoring the ppm levels of the key metals dissolved in the oil and the percentage of metal particles in the oil.

What are the test’s limitations? Particle size and type patterns can vary between different types of oil circuit breakers. Also, dissolved metals in oil patterns can vary between different types of oil circuit breakers. A sizeable quantity of particles and metals in oil analysis test results are required to establish valid patterns in each type of oil circuit breaker. Also, different patterns can exist within one type of oil circuit breaker due to the use of different materials in the main contacts, arcing contacts and arc suppression grids.

If oil is not agitated before taking samples, particles may not be present in the sample.

There are no Standards or Guides in the industry for analyzing or interpreting the test results of particles and metals in oil analysis in circuit breakers.

Most oil circuit breakers do not have oil sampling valves built into their drain valves. This presents a challenge to properly obtain an oil sample for particles and metals in oil analysis.

The particles and metals in oil analysis test alone does not provide sufficient data to make a reliable assessment of the circuit breaker’s arcing and main contact tips and of the arc suppression grids. The reliability of the assessment is greatly improved when the data from the particles and metals in oil analysis test are combined with the data from the dissolved gas in oil analysis test and the moisture in oil analysis test. This allows patterns to be developed where elevated levels of key dissolved gases in oil are correlated with particle count, size and material to more accurately predict levels of erosion of arcing and main contact tips and of arc suppression grids.

When does the test need to be performed? This test needs to be performed upon the initial commissioning of the circuit breaker to collect baseline test data. Future test data can be compared to the commissioning test data to see if any deviations have occurred and if any corrective actions may be required. These future tests may be regular periodic maintenance tests or special investigative tests which may be required due to an in-service failure or a perceived problem of the circuit breaker. The regular periodic maintenance tests are normally performed at fixed time intervals that have been selected by the owner and/or operator of the circuit breaker. These fixed time intervals are not standardized across the industry and can vary from 3 months to 3 years or more. Many factors go into the selection of the fixed time interval chosen for each circuit breaker. Condition based triggers may supplement the time-based triggers to help factor the breaker exposed service conditions. These factors are explained in more detail elsewhere in this guidebook.

Which type of circuit breakers is the test used on? As the name implies, this test is only used on oil circuit breakers.

How is the test performed? This test can be performed with the circuit breaker either energized and in service (on-line) or with it de-energized and out of service (off-line). A sample of the circuit breaker’s insulating oil is required for this test. The sample will be sent to a laboratory for the analysis to be performed. If the circuit breaker has one tank per phase, then three oil samples are required. If the circuit breaker has all three phases contained in one tank, then only one oil sample is required. Each oil sample is collected in a glass or plastic jar. The size of the glass or plastic jar is normally 1 pint.

The following steps are required to properly obtain an oil sample in a jar:

1. Properly identify the circuit breaker from which the oil sample is to be obtained. This is done by collecting the manufacturer’s name, manufacturer’s serial number, substation name and owner’s equipment identification (ID) number on the circuit breaker. If a permanent owner’s equipment identification (ID) number label is absent, the three-line drawing of the substation can be referenced to determine the location of the circuit breaker. A temporary label can be attached to the circuit breaker for use during the test. It should be replaced with a permanent label as soon as practical.

2. If three oil samples are required from the circuit breaker, properly identify which primary phase is connected to each pole of the circuit breaker. It is a best practice to permanently label the primary phase marking on the tanks, stands or enclosures of each circuit breaker when it is commissioned. If these permanent primary phase markings are absent, the three-line drawing or phasing drawing of the substation can be referenced to determine which primary phase is connected to which pole of the circuit breaker. Temporary labels can be attached to the circuit breaker for use during the test. These should be replaced with permanent labels as soon as practical.

3. If possible, operate the breaker several times to create movement of the oil in an attempt to get a valid sample.

4. The oil sample is collected from the oil drain valve on each tank of the circuit breaker. This drain valve is not normally equipped with a sampling valve. A sampling valve can be permanently added to the drain valve or attached temporarily when the oil sample is obtained. One method of attaching a sampling valve to a drain valve is to use a series of reducers to step the size of the drain valve down to the size of the sampling valve. Obtaining an oil sample directly from the drain valve is not recommended. A very slow oil flow rate is needed to properly obtain an oil sample. This flow rate cannot be properly controlled with the drain valve. Also, a short piece of tubing will be used to collect the oil sample. The oil sampling valve provides a place to connect this tubing whereas the drain valve does not.

5. Place oil absorbing mats under the sampling area.

6. Have clean dry rags on hand.

7. Connect a short section of tygon tubing to the oil sampling valve.

8. Place the other end of the tygon tubing into a clean empty one gallon bucket.

9. Open the oil sampling valve.

10. Slowly open the oil drain valve until oil begins to flow into the one gallon bucket.

11. Allow the oil to drain into the one gallon bucket watching for signs of water droplets or bubbles in the oil through the tygon tubing or the oil in the one gallon bucket.

12. Close the oil sampling valve as the one gallon bucket becomes full.

13. Empty the oil from the one gallon bucket into a larger storage vessel for transportation and disposal off site.

14. Continue to drain the oil until water droplets or bubbles are no longer seen in the oil.

15. After water droplets or bubbles are no longer seen in the oil, drain two more gallons of oil.

16. Close the oil sampling valve.

17. Measure the temperature of the oil in the one gallon bucket and record it on the oil sample sheet that will be sent to the laboratory with the oil sample jar.

18. Rinse out the sample bottle twice with oil from the oil sampling valve.

19. Fill the sample bottle to near the top with oil from the oil sampling valve.

20. Close the oil sampling valve.

21. Close the oil drain valve.

22. Install the lid on the sample bottle.

23. Disconnect the tygon tubing from the oil sampling valve.

24. Fill in the oil sample sheet provided by the laboratory:

    a. Substation Name

    b. Circuit Breaker Equipment ID Number

    c. Circuit Breaker Phase Identifier (When required)

    d. Circuit Breaker Serial Number

    e. Sample Date

    f. Sample Oil Temperature

    g. Tests Required:

    • Particle Count

    • Microscopic Particle Characterization

    • Metals

Send the filled syringe and filled-in oil sample sheet to the laboratory for analysis. Provide contact information as to where the test results need to be sent.

How are the test results interpreted? There are no Standards or Guides in the industry for the interpretation of particles and metals in oil analysis of circuit breakers. Widely used limits for the individual particle sizes, particle types and dissolved metal in oil levels do not exist. Also, since the level of each particle size, particle type and dissolved metal in oil generated in an oil circuit breaker varies between different types of oil circuit breakers and within one type of oil circuit breaker when different materials are used in the main contacts, arcing contacts and arc suppression grids, it is preferred that the owner and/or operator of the oil circuit breaker establish their own limits for each of these quantities for each common group of oil circuit breakers. This process involves performing a statistical analysis of the particles and metals in oil analysis test results for a common group of oil circuit breakers. The larger the number of test results that are analyzed, the more accurate the statistical analysis will be. Usually, 100 or more test results are desired for a good statistically analysis. Statistical analysis can be performed on few test results than this, but the accuracy of the analysis will be reduced.

Once the statistical analysis has been performed, information on the actual physical erosion or damage of the main contacts, arcing contacts and arc suppression grids needs to be obtained. This is done by performing internal inspections of these components in the oil circuit breakers with the highest levels of particles and metals in oil. This will help in understanding the relationship between the physical erosion or damage to these components and the levels of the various particles and metals in the oil. It will also help in establishing the levels for each of these quantities where internal inspections of main contacts, arcing contacts and arc suppression grids in oil circuit breakers are warranted.

Once the action levels for each particle size, particle type and dissolved metal in oil has been established for each common group of oil circuit breakers, the particle and metals in oil analysis test results are compared to these levels. If the action level for one or more of these quantities has been exceeded, an internal inspection of the main contacts, arcing contacts and arc suppression grids may be warranted.

Table 3-26 is an example of particles in oil analysis of an oil circuit breaker.

Table3-27 is an example of metals in oil analysis of an oil circuit breaker.

Particle Size	Particle Count
6-10 micrometers (um)	7833
10-14 micrometers (um)	981
14-25 micrometers (um)	702
25-50 micrometers (um)	113
50-100 micrometers (um)	25
>100 micrometers (um)	0
Particle Type	Particle %
Fibrous Particles (%)	15
Metal Particles (%)	0
Carbon Particles (%)	80
Other Particles (%)	5

Silver (Ag) (ppm)	< 0.5
Chromium (Cr) (ppm)	< 0.5
Copper (Cu) (ppm)	< 0.5
Nickel (Ni) (ppm)	< 0.5
Lead (Pb) (ppm)	< 0.5
Tin (Sn) (ppm)	< 0.5
Tungsten (W) (ppm)	< 0.5

1.1.4 - Chapter 4 - Investigating and Understanding Circuit Breaker Problems and Failures

Introduction and Overview

This chapter is directed to utility engineering staff involved in maintenance of high voltage circuit breakers. The objective is to provide information and guidance to support effective practices that maintain service reliability and extend breaker life. The work complements other EPRI efforts associated with circuit breaker knowledge capture, training, field guide development, and maintenance.

One important aspect of an effective circuit breaker maintenance program is the identification of failures and problems that can occur during a circuit breaker’s lifetime. These failures and problems vary for each circuit breaker depending on such factors as type of interrupting medium (oil, vacuum or SF₆ gas), type of operating mechanism (pneumatic, hydraulic or spring), type of bushings (oil-filled capacitor, SF₆ gas filled or solid), differences in manufacturer’s designs, operating and environmental conditions as well as the circuit breaker’s maintenance program. Improvements in the effectiveness of the circuit breaker’s maintenance program can be made by identifying failures and problems that can occur to that circuit breaker and to develop a maintenance program that will detect and prevent or minimize damage from these events occurring.

Another important aspect of an effective circuit breaker maintenance program is the timely, careful and thorough investigation of circuit breaker failures. If the failure has created the possibility of continuing corrosive or degradation processes, there is an advantage to do the investigation immediately after it occurs. The purpose of this investigation is to identify the root cause of the failure. After this step has been completed, a review of the maintenance program for the failed and similar circuit breakers should be made to determine if changes or additions are needed to prevent this failure from occurring in the future.

This multi-year research initiative is designed to improve the maintenance of circuit breakers to achieve reliable performance with reduced costs. The focus is to identify and list possible failures and problems of various components and systems of vacuum, oil and SF₆ gas circuit breakers. Also, the steps and processes necessary to perform a root cause of failure investigation are developed. The ultimate goal is to provide utilities with information and guidance to assist them in developing and performing a successful condition-based preventive maintenance program.

Researchers followed a multistep approach in the development of this chapter.

Identify existing industry standards and guides. Perform a search of existing industry standards and guides on the subjects of vacuum, oil and SF₆ gas circuit breaker failures, problems and failure investigations. Use pertinent information from these standards and guides in the preparation of this chapter. Identify gaps and outdated information in these standards and guides. Provide new and updated information in this chapter of the guidebook.

Solicit utility experiences and input. Gather information of utilities’ experiences with vacuum, oil and SF₆ gas circuit breaker failures, problems and failure investigations. Organize this information and present it in a clear and concise manner in this chapter of the guidebook.

This chapter describes and explains vacuum, oil and SF₆ gas circuit breaker failures, problems and failure investigations. The section organization is as follows:

Section 1: Introduction and Overview

Section 2: Definitions

Section 3: Failure Characteristics

Section 4: Failure Modes, Effects and Causes

Section 5: Problems

Section 6: Investigations

Section 7: Failure Investigation Examples

Definitions

Note: Applicable IEC definitions will be included in future editions of the Guide.

Failure

Termination of the ability of an item to perform its required functions. (IEEE Std C37.10-2011)

Failure Analysis

The logical, systematic examination of an item or its diagram(s) to identify and analyze the probability, causes, and consequences of potential and real failure. (See The IEEE Standards Dictionary: Glossary of Terms & Definitions.)

Failure cause (Root cause)

The circumstances during design, manufacture, or use that have led to failure. (See The IEEE Standards Dictionary: Glossary of Terms & Definitions.)

Failure characteristic (Failure pattern)

A description of the conditional probability of failure against operating age for an electrical or mechanical item. (IEEE Std C37.10.1-2000)

Failure effect

A description of what actually happens when a failure mode occurs. (IEEE Std C37.10.1-2000)

Failure mode

The manner in which failure occurs; generally categorized as electrical, mechanical, thermal, and contamination (IEEE Std C37.10-2011)

Failure Modes and Effects Analysis (FMEA)

A process of identifying potential failures and their corresponding effects on the product or process under consideration – generally a design tool; however, it can also be used for failure analysis. (IEEE Std C37.10-2011)

Analysis based on that defined component or subassembly level where the basic failure criteria (primary failure modes) are available. Starting from the basic element failure characteristics and the functional system structure, the FMEA determines the relationship between the element failures and the system failures, malfunctions, operational constraints, and degradation of performance or integrity. To evaluate secondary and higher-order system and subsystem failures, the sequences of events in time may also have to be considered. (IEEE Std C37.10.1-2000)

Functional Failure (also see Failure)

The inability of a system to meet a specified performance standard

Hidden Failure

A functional failure that cannot be seen or detected during normal operation of a system(Note: There must be hidden failure finding tasks in a comprehensive preventive maintenance program.)

Investigation

A process to make a systematic, detailed and careful examination about something to try to discover the facts in order to learn how it happened, why it happened, etc.

Major failure (of a circuit breaker)

Failure of a circuit breaker that causes the termination of one or more of its fundamental functions, which necessitates immediate action. (IEEE Std C37.10-2011)

Major failure-replacement (of a circuit breaker)

A major failure of a circuit breaker that results in the complete removal of the existing circuit breaker and the installation of another circuit breaker in its place.

Minor failure (of a circuit breaker)

Any failure of a part or a sub-assembly that does not cause a major failure of a circuit breaker. (IEEE Std C37.10-2011)

Problem

A question or matter that is a source of trouble or concern which, if left unchecked, may lead to failure

Root cause failure analysis (RCFA)

A method or series of actions taken to find out why a particular failure or problem exists and to correct those causes; investigative techniques applied to the determination of factors leading to the initiating or original failure. (IEEE Std C37.10-2011

Failure Characteristics

Introduction

A failure characteristic, also known as a failure pattern, as defined by IEEE, is a description of the conditional probability of failure against operating age for an electrical or mechanical item. In graphical form, the probability of failure is shown along the y axis and the operating age of the equipment is shown along the x axis. In written form, the shape of the characteristic is described as the age of the equipment increases.

However, failures also occur vs. number of operations, design, materials used in manufacture, type of installation, e.g. capacitor bank service, and exposure to fault currents.

Generic failure characteristics

Bathtub Curve

One observed failure rate characteristic is the bathtub curve. This curve describes the combination of numerous individual failure rates of a group of components into one curve. It is characterized by high initial failure rates at the beginning of life called infant failures or infant mortality. Next the failure rates gradually decline to a low level. This low level slowly increases over the life of the equipment. Near the end of life of the equipment, the failure rates increase until the equipment fails of one or more accumulated failure causes. This curve is shown in Figure 4-1 below.

IEEE Standard C37.10.1-2000 Guide for the Selection of Monitoring for Circuit Breakers contains a table displaying graphs and written descriptions of some known failure characteristics.

Common circuit breaker failure characteristics

Infant Mortality

Infant mortality is a failure of the circuit breaker the instant that it is first energized or a failure very early in its life. These failures are usually due to design or manufacturing issues at the factory or installation issues at the substation. Circuit breaker manufacturers cover their liability for infant mortality failures with a warranty. These warranties are normally for one year or several years as most infant mortalities occur during this time frame.

Infant mortality failures are more common on circuit breakers of newer designs than ones of older designs. For this reason, some circuit breaker purchasers prefer to buy circuit breakers of an established design and with a low failure rate history. These circuit breakers have had a chance for any design problems to be worked out. Purchasers of newer design circuit breakers may request longer manufacturer warranty periods to protect themselves against the unknown problems and failures of a newer design.

Random Failures

Random failures are primarily characterized by their unpredictability. There are normally no precursors or warnings that the failure is going to happen. They just happen independently of age. Some examples of random failures are internal flashovers inside interrupter tanks or compartments, broken operating linkages and trip coil failures. Due to the randomness of this type of failure, they may not be detected with a preventive or predictive maintenance program.

Tip-up Curve

The most common failure characteristic for circuit breakers is the tip-up curve. This curve begins with a low failure rate at the beginning of the circuit breaker’s life. This failure rate remains low, or increases very slowly, over the life of the circuit breaker. At some point in the circuit breaker’s life, the failure rate has a noticeable change or tip-up and begins increasing. The rate of the increase can vary. One of the main objectives of a good circuit breaker maintenance program is to periodically test and check the circuit breaker for evidence that a tip-up has occurred in some part of the breaker. Once the tip-up is discovered, follow up actions are normally required to retest and recheck the circuit breaker again after a fairly short time to establish the rate that the failure is increasing. In general, tip-ups with a rapidly increasing failure rate will require corrective action. Tip-ups with moderate or slowly increasing failure rates are closely monitored to determine if and when corrective action may be required. Examples of tip-up curves with high, medium and low failure rates are shown in Figure 4-2 below.

Step-up Curve

The step-up curve also begins with a low failure rate at the beginning of the circuit breaker’s life. What is unique about this curve is that the failure rate increases as a step function and those steps are associated with the operation of the circuit breaker. Prime examples of this are the circuit breaker’s arcing contacts. Each time the circuit breaker interrupts fault current; there is metal erosion of the arcing contacts. Each time the circuit breaker interrupts load current; there is also metal erosion of the arcing contacts but to a much smaller degree. The arcing contact metal erosion is cumulative. This means that the arcing contacts will eventually need to be replaced. Once the arcing contacts have been replaced with new contacts, the step-up curve starts over again.

Another unique detail about the step-up curve is that it is not time dependent even though it occurs over time. It is dependent upon the operation of the circuit breaker. An example of a step-up curve is shown in Figure 4-3 below. It is important to note that time-dependent failure mechanisms are also likely present and that the overall circuit breaker failure rate is the result of a combination of multiple component rates.

Failure Modes, Effects and Causes

Introduction

Understanding the failure modes, failure effects and failure causes of circuit breakers is one important key to having an effective, cost efficient circuit breaker maintenance program. By studying the various components of circuit breakers, how they work together and what can happen when they do not work properly, a maintenance plan can be developed that periodically checks and monitors these components for deterioration. The goal of an effective maintenance program is to discover problems with components and correct those problems before they become failures. The goal of a cost efficient maintenance program is to focus the limited funds available for maintenance on preventing the failures which have the greatest risk impact on the owner.

This section contains a series of tables which list various circuit breaker failure modes. Each table then lists the effect(s) of that failure mode. Finally, listings of possible causes of that failure mode are presented.

Circuit breaker fails to open on command

Failure mode	Failure effect	Failure cause
Fails to open on command	Breaker does not open the circuit to interrupt current	Trip latch: Inappropriate lubrication Inadequate lubrication Inappropriate adjustment Surface wear Surface deformation Deteriorated bearings
		Trip mechanism: Inappropriate lubrication Inadequate lubrication Inappropriate adjustment Linkage deformation Linkage binding Linkage breakage Deteriorated bearings
		Control circuit: Open trip coil Shorted trip coil Defective 52a auxiliary contact(s) in trip circuit Open trip circuit fuse or breaker Defective breaker control switch Low control voltage Defective control battery charger Defective control battery Defective wiring Operation legitimately blocked due to low operating mechanism energy Operation legitimately blocked due to low SF6 gas pressure Operation incorrectly blocked due to defective control circuit device
		Pneumatic operating mechanism low air pressure due to: Leak Defective air compressor Defective air compressor motor Defective air compressor drive belt Defective air compressor starter air pressure switch
		Hydraulic operating mechanism low hydraulic oil pressure due to: Leak Defective hydraulic oil pump Defective hydraulic oil pump motor Defective hydraulic oil pump starter oil pressure switch Defective accumulator Water in hydraulic fluid causing foaming
		Spring operating mechanism low spring pressure due to: Defective spring Defective spring charging motor Defective spring charging drive chain Broken or binding spring charging mechanism Inappropriate or inadequate lubrication of spring charging mechanism Defective spring charging motor starter micro-switch
		Magnetic operating mechanism low energy due to: Defective circuit board Defective proximity sensor
		Mechanism cabinet below required temperature: Cabinet heater failure Inadequate cabinet insulation
		Stationary and movable main contacts welded together

Circuit breaker opens, but fails to remain open

Failure mode	Failure effect	Failure cause
Opens but fails to remain open	Breaker opens and then closes again	Mechanism failure Linkage breakage Defective opening shock absorber
	Breaker opens and then repeatedly closes and opens	Anti-pumping scheme failure Defective anti-pump relay Defective auxiliary contact(s) in anti-pump circuit

Circuit breaker opens, but fails to interrupt

Failure mode	Failure effect	Failure cause
Opens but fails to interrupt current	Fault or load current is not interrupted and the circuit breaker interrupter has a major failure	Air-Blast circuit breaker specific: Low air pressure Loss of air pressure High moisture in air Blast valve failure
		Oil circuit breaker specific: Low oil dielectric strength Low oil level Loss of oil Defective interrupter
		SF6 gas circuit breaker specific: Low SF6 gas pressure or density Loss of SF6 gas pressure Puffer failure Nozzle failure Interrupter tank below required temperature (tank heater failure)
		Vacuum circuit breaker specific: Loss of vacuum
		Mechanical failure: Insufficient contact opening distance
		Misapplication or other situation beyond circuit breaker’s capability

Circuit breaker opens, but fails to maintain open contact insulation

Failure mode	Failure effect	Failure cause
Opens but fails to maintain open contact insulation	Breaker fails to provide required dielectric isolation of contacts immediately after the opening operation	Air-Blast circuit breaker specific: Low air pressure Loss of air pressure High moisture in air Deteriorated internal solid insulation components across open contacts
		Oil circuit breaker specific: Low oil dielectric strength Low oil level Loss of oil
		SF6 gas circuit breaker specific: Low SF6 gas pressure or density Loss of SF6 gas pressure High moisture in SF6 gas Conductive particles in SF6 gas Deteriorated internal solid insulation components across open contacts
		Vacuum circuit breaker specific: Loss of vacuum
		Mechanism does not travel complete opening distance
		Dielectric stress exceeds the circuit breaker’s capability
		Lightning

Circuit breaker opens without command

Failure mode	Failure effect	Failure cause
Opens without command	Circuit is unintentionally interrupted with possible safety and economic damage issues	Trip latch not secure
		Trip circuit: Unwanted ground Stray current or transient surge Defective control circuit device Operated correctly due to low control voltage trip
		Self-protective feature of some circuit breakers: Low operating mechanism energy trip Low SF6 gas pressure or density trip

Circuit breaker fails to close on command

Failure mode	Failure effect	Failure cause
Fails to close on command	Breaker does not close the circuit to conduct current	Close latch: Inappropriate lubrication Inadequate lubrication Inappropriate adjustment Surface wear Surface deformation Deteriorated bearings
		Close mechanism: Inappropriate lubrication Inadequate lubrication Inappropriate adjustment Linkage deformation Linkage binding Linkage breakage Deteriorated bearings
		Control circuit: Open close coil Shorted close coil Defective 52b auxiliary contact(s) in close circuit Open close circuit fuse or breaker Defective breaker control switch Defective synchronous controller Low control voltage Defective control battery charger Defective control battery Defective wiring Operation legitimately blocked due to low operating mechanism energy Operation legitimately blocked due to low SF6 gas pressure Operation incorrectly blocked due to defective control circuit device
		Pneumatic operating mechanism low air pressure due to: Leak Defective air compressor Defective air compressor motor Defective air compressor drive belt Defective air compressor starter air pressure switch
		Hydraulic operating mechanism low hydraulic oil pressure due to: Leak Defective hydraulic oil pump Defective hydraulic oil pump motor Defective hydraulic oil pump starter oil pressure switch Defective accumulator Water in hydraulic fluid causing foaming
		Spring operating mechanism low spring pressure due to: Defective spring Defective spring charging motor Defective spring charging drive chain Broken or binding spring charging mechanism Inappropriate or inadequate lubrication of spring charging mechanism Defective spring charging motor starter micro-switch
		Magnetic operating mechanism low energy due to: Defective circuit board Defective proximity sensor
		Mechanism cabinet below required temperature Cabinet heater failure Inadequate cabinet insulation

Circuit breaker with synchronous controller closes, but not within limits

Failure mode	Failure effect	Failure cause
Synchronous close occurs but not within limits	Breaker closes before or after desired operating window in one or more poles	Defective synchronous controller
		Inappropriate contact adjustment

Circuit breaker closes, but fails to remain closed

Failure mode	Failure effect	Failure cause
Closes but fails to remain closed	Breaker closes then opens again	Trip latch fails to properly latch: Inappropriate adjustment Surface wear Surface deformation
		Mechanism failure: Linkage breakage

Circuit breaker closes, but fails to conduct current

Failure mode	Failure effect	Failure cause
Closes but fails to conduct current	Breaker does not close the circuit to conduct current in one or more poles	Main contacts burnt away (from electrical arc erosion)
		Broken mechanical linkage to contacts
		Loss of overtravel preventing contacts from closing fully

Circuit breaker closes without command

Failure mode	Failure effect	Failure cause
Closes without command	Circuit is unintentionally closed with possible safety and economic damage issues	Close latch not secure
		Close circuit: Unwanted ground Stray current or transient surge Defective control circuit device
		Pneumatic operating mechanism: Pilot valve not secure
		Spring operating mechanism: Spring release mechanism worn

Circuit breaker fails to conduct continuous or momentary current (while already closed)

Failure mode	Failure effect	Failure cause
Fails to conduct continuous or momentary current (while already closed)	Breaker does not conduct current with resulting thermal damage to contact assemblies	Main contacts: High contact resistance Contact ablation Broken or missing contacts Contact spring failure
		Loss of contact closing force due to loss of overtravel

Circuit breaker fails to provide insulation

Failure mode	Failure effect	Failure cause
Fails to provide insulation	Short circuit on power system with possible safety and economic damage issues; interruption of power system components	Air-Blast circuit breaker specific: Low air pressure Loss of air pressure High moisture in air Deteriorated internal solid insulation components
		Oil circuit breaker specific: Low oil dielectric strength Low oil level Loss of oil Low lift rod dielectric strength
		SF6 gas circuit breaker specific: Low SF6 gas pressure or density Loss of SF6 gas pressure High moisture in SF6 gas Conductive particles in SF6 gas Deteriorated internal solid insulation components
		Vacuum circuit breaker specific: Loss of vacuum Deteriorated solid insulation components
		Bushings: Deteriorated internal insulation External insulation contamination Physical damage to external insulation
		Wildlife
		Lightning
		System transient overvoltage
		Water infiltration
		Airborne foreign material

Circuit breaker fails to provide insulation across open contact

Failure mode	Failure effect	Failure cause
Fails to provide insulation across open contact	Circuit is unintentionally closed with possible safety and economic damage issues; may result in a major failure of circuit breaker interrupter	Air-Blast circuit breaker specific: Low air pressure Loss of air pressure High moisture in air Deteriorated internal solid insulation components across open contacts
		Oil circuit breaker specific: Low oil dielectric strength Low oil level Loss of oil
		SF6 gas circuit breaker specific: Low SF6 gas pressure or density Loss of SF6 gas pressure High moisture in SF6 gas Conductive particles in SF6 gas Deteriorated internal solid insulation components across open contacts
		Vacuum circuit breaker specific: Loss of vacuum
		Wildlife
		Lightning
		System transient overvoltage
		Dielectric stress exceeds the circuit breaker’s capability
		Airborne foreign material
		Water infiltration
		External insulation: Contamination Physical damage

Circuit breaker fails to contain insulating medium

Failure mode	Failure effect	Failure cause
Fails to contain insulating medium	Loss of insulating medium to environment	Air-Blast circuit breaker specific: Failure of seals, O-rings and gaskets Porosity of welds Corrosion Physical damage Pressure relief device operation
		Oil circuit breaker specific: Failure of seals and gaskets Corrosion Physical damage
		SF6 gas circuit breaker specific: Failure of seals, O-rings and gaskets Porosity of castings Porosity of welds Corrosion Physical damage Rupture disk operation
		Vacuum circuit breaker specific: Failure of seals Corrosion Physical damage

Circuit breaker fails to indicate correct condition or position

Failure mode	Failure effect	Failure cause
Fails to indicate correct condition or position	Operation of power system with a circuit breaker that is incapable or has reduced capacity to perform its functions	Air-Blast circuit breaker specific: Stuck, broken or defective air pressure switch Air pressure switch not set correctly or out of calibration Stuck, broken or defective air pressure gauge
		Oil circuit breaker specific: Stuck, broken or defective interrupter tank oil level indicator
		SF6 gas circuit breaker specific: Stuck, broken or defective SF6 gas pressure or density switch SF6 gas pressure or density switch not set correctly or out of calibration Stuck, broken or defective SF6 gas pressure or density gauge
	Defective condition or position indicator causing operator to undertake inappropriate actions	Pneumatic operating mechanism specific: Stuck, broken or defective air pressure switch Air pressure switch not set correctly or out of calibration Stuck, broken or defective air pressure gauge
		Hydraulic operating mechanism specific: Stuck, broken or defective hydraulic oil pressure switch Oil pressure switch not set correctly or out of calibration Stuck, broken or defective hydraulic oil pressure gauge
		Spring operating mechanism specific: Stuck, broken or defective spring charged/discharged indicator
		Stuck, broken or defective circuit breaker open/closed position indicator
		Stuck, broken or defective circuit breaker operations counter

Circuit breaker fails to provide for safety in operation

Failure mode	Failure effect	Failure cause
Fails to provide for safety in operation	Hazard to personnel	Live tank SF6 gas circuit breaker specific: Overpressure of porcelain interrupter Defects in porcelain Improper filling with SF6 gas Loss of SF6 gas and need to isolate
		Dead tank SF6 gas circuit breaker specific: Overpressure of porcelain bushings Defects in porcelain Overpressure of interrupter tank Improper filling with SF6 gas Loss of SF6 gas and need to isolate
		Pneumatic operating mechanism specific: Overpressure of air system
		Hydraulic operating mechanism specific: Overpressure of hydraulic oil system Improper filling with hydraulic oil
		Spring operating mechanism specific: Overpressure of spring charging system
		Failure of interlocks

Problems

Introduction

For the purposes of this section and chapter, a problem is defined as a question or matter that is a source of trouble or concern which, if left unchecked, may lead to failure. In other words, a problem can be looked at as a precursor to a failure. One reason that a problem needs to be differentiated from a failure is that different actions are taken for each. Whereas failures warrant corrective actions, problems need to be reviewed to determine:

• Does the problem warrant corrective action?

• Does the problem need to be monitored?

• Can the problem be ignored?

This section contains a series of tables which list various circuit breaker problems and causes. The tables are arranged in alphabetical order by component name or assembly name (such as cabinets or interrupter tanks). The assembly tables are further broken down by component. Problem causes are generally grouped into one of the following categories:

• Electrical

• Mechanical

• Physical

• Thermal

• Contamination

Air (Air-Blast Circuit Breakers)

Problem	Cause
Moisture in air measurements (dew point) do not meet manufacturer’s specifications	Leaks Defective drying system on compressor

Bushings – Oil-filled Capacitor

Problem	Cause
Low oil level/Leaks	Failure of seals, O-rings and gaskets
Power factor measurements that are changing with time	Moisture ingress Contaminant
Capacitance measurements that are changing with time	Shorted capacitor layers
Chips or cracks in porcelain weathersheds	Vandalism Airborne debris Manufacturing defect
Cracks in polymer weathersheds	Manufacturing defect
Tracking on weathersheds	Manufacturing defect Contaminant Corona
Contamination on weathersheds	Salt spray Pollutant from nearby industry
Elevated top terminal temperature (from infrared scan)	Loose/Poor connection
Discolored oil in sight glass	Moisture ingress

Bushings – SF₆ Gas-filled

Problem	Cause
Leaks	Failure of seals, O-rings and gaskets
Chips or cracks in porcelain weathersheds	Vandalism Airborne debris Manufacturing defect
Cracks in polymer weathersheds	Manufacturing defect
Tracking on weathersheds	Manufacturing defect Contaminant Corona
Contamination on weathersheds	Salt spray Pollutant from nearby industry
Elevated top terminal temperature (from infrared scan)	Loose/Poor connection

Bushings – Solid

Problem	Cause
Chips or cracks in porcelain weathersheds	Vandalism Airborne debris Manufacturing defect
Cracks in polymer weathersheds	Manufacturing defect
Tracking on weathersheds	Manufacturing defect Contaminant Corona
Contamination on weathersheds	Salt spray Pollutant from nearby industry
Elevated top terminal temperature (from infrared scan)	Loose/Poor connection

Cabinets - Control and Mechanism

Component	Problem	Cause
Doors	Water leaks Corrosion Dirt/Dust inside cabinet Bent	Defective/missing weather stripping: Deteriorated paint Physical damage
Hinges and Latches	Bent/broken Missing Corrosion Non-operable	Physical damage Deteriorated paint Inadequate lubrication
Cabinet	Dirt/Dust Insects and nests Rodents and nests Corrosion	Defective/missing conduit filler plates Deteriorated conduits Deteriorated paint
Relays	Do not pick up when energized Do not dropout when de-energized Closed contacts do not conduct current Broken or cracked base Elevated temperature (infrared scan)	Open/shorted coils Mechanical binding Contact corrosion/erosion Welded contacts Loose/Poor wire terminations Physical damage
Control Switches	Handle does not turn Handle turns but contacts do not change state Closed contacts do not conduct current Elevated temperature (infrared scan)	Mechanical binding Welded contacts Contact corrosion/erosion Physical damage Loose/Poor wire terminations
Indicating Lights	Lamp does not illuminate	Defective bulb Defective socket Loose wire terminations
Test Switches	Blades do not open Closed contacts do not conduct current Broken or cracked base Elevated temperature (infrared scan)	Mechanical binding Welded contacts Contact corrosion/erosion Physical damage Loose/Poor wire terminations
Terminal Blocks	Broken or cracked base Elevated temperature (infrared scan)	Physical damage Loose/Poor wire terminations
Fuses and Circuit Breakers	Broken or cracked base Elevated temperature (infrared scan)	Physical damage Loose/Poor wire terminations
Cabinet Lights	Lamp does not illuminate Broken or cracked base	Defective bulb Defective socket Loose/Poor wire terminations Physical damage
Receptacles	Broken or cracked	Physical damage
Heaters	Not producing heat Visibly broken element Broken or cracked mounting Missing protective guard Cracked/deteriorated wire insulation Premature lubrication failure	Blown fuse Loose/Poor wire terminations Physical damage Wrong type of wire used Normal ageing Abnormal heating
Conduits	Water leaks	Defective seals
Control Cables	Cracked/deteriorated insulation Missing insulation by rodents Corroded crimp terminals Elevated temperature (infrared scan)	Normal ageing Abnormal heating Physical damage Loose/Poor wire terminations
Wiring	Cracked/deteriorated insulation Missing insulation by rodents Corroded crimp terminals Elevated temperature (infrared scan)	Normal ageing Abnormal heating Physical damage Loose/Poor wire terminations
Annunciators	Not indicating correctly Not indicating at all Broken or cracked Elevated temperature (infrared scan)	Loose/Poor wire terminations Defective power supply/Blown fuses Physical damage
Vents	Clogged/Blocked	Insects Dirt/Dust

Capacitors – Grading

Problem	Cause
Power factor measurements that are changing with time	Moisture ingress Contaminant
Capacitance measurements that are changing with time	Shorted capacitor layers
Chips or cracks in porcelain weathersheds	Vandalism Airborne debris Manufacturing defect
Cracks in polymer weathersheds	Manufacturing defect
Tracking on weathersheds	Manufacturing defect Contaminant Corona
Contamination on weathersheds	Salt spray Pollutant from nearby industry
Oil leaks	Failure of seals, O-rings and gaskets
Elevated temperature (infrared scan)	Shorted capacitor layers Loose/Poor connection

Capacitors - TRV (Transient Recovery Voltage)

Problem	Cause
Power factor measurements that are changing with time	Moisture ingress Contaminant
Capacitance measurements that are changing with time	Shorted capacitor layers
Chips or cracks in porcelain weathersheds	Vandalism Airborne debris Manufacturing defect
Cracks in polymer weathersheds	Manufacturing defect
Tracking on weathersheds	Manufacturing defect Contaminant Corona
Contamination on weathersheds	Salt spray Pollutant from nearby industry
Oil leaks	Failure of seals, O-rings and gaskets
Elevated temperature (infrared scan)	Shorted capacitor layers Loose/Poor connection

Current Carrying Paths

Problem	Cause
Static contact resistance measurements do not meet manufacturer’s specifications	High main contact resistance: High resistance at lower bushing connection High resistance at upper bushing connector High resistance at contact support assembly High resistance at internal bus connections
Elevated temperature (infrared scan)	Loose/poor connection

Current Transformers

Problem	Cause
Ratio test results do not meet manufacturer’s specifications	Shorted turns: Open turns Shorted leads Open leads
Secondary excitation current test results do not meet manufacturer’s specifications	Shorted turns: Open turns Shorted leads Open leads
Secondary winding DC resistance test results do not meet manufacturer’s specifications	Shorted turns: Open turns Shorted leads Open leads Loose connection
Secondary winding insulation resistance test results do not meet industry standards	Deteriorated wire: Deteriorated terminal blocks
Cracked/deteriorated wire insulation	Normal ageing: Abnormal heating

Draw-out Switchgears

Component	Problem	Cause
Draw-out Mechanisms	Binding Deformation Breakage Wear	Physical damage Out of alignment
Shutter Mechanisms	Binding Deformation Breakage Wear	Physical damage Out of alignment
Lifting Mechanisms	Binding Deformation Breakage Wear	Physical damage Out of alignment
Lifting Mechanism Motors	Does not operate	Open winding Shorted winding Loose connection Blown fuse

High Voltage Air-Insulated Compartments (Medium Voltage Circuit Breakers)

Component	Problem	Cause
High Voltage Bus	Dirt/Corrosion Discoloration from overheating	Missing/Deteriorated vent filters Deteriorated seals Inadequate heaters Loose connection(s)
Solid Insulation	Dirt/Corrosion Cracks/Chips Deterioration Tracking	Missing/Deteriorated vent filters Deteriorated seals Inadequate heaters Physical damage Manufacturing defect Corona
Condensation Heaters	Not producing heat Visibly broken element Broken or cracked mounting Missing protective guard Cracked/deteriorated wire insulation	Blown fuse Loose wire terminations Physical damage Wrong type of wire used Normal ageing Abnormal heating
Vents	Blocked/Clogged	Insects Dirt/Dust

Hydraulic Fluid

Problem	Cause
Dirty/Contaminated	Failure of seals, O-rings and gaskets Missing/Defective oil filter Excessive moisture in oil

Interrupters

Component	Problem	Cause
Contacts - Arcing	Dynamic Contact Resistance Measurements (DRM) that indicate possible arcing contact wear/erosion	Normal wear/erosion from interrupting fault and load currents Abnormal wear from contact misalignment or looseness
	Dissolved gas in oil analysis test results that indicate possible excessive arcing contact erosion	Normal wear/erosion from interrupting fault and load currents Abnormal wear from contact misalignment
Contacts - Main	Static contact resistance measurements do not meet manufacturer’s specifications	Loose connection Normal wear Abnormal wear from contact misalignment
	Elevated interrupter tank temperature (from infrared scan)	Loose/Poor connection High contact resistance from normal wear High contact resistance from abnormal wear
Air Blast Valves	Binding Erosion	Abnormal wear Misalignment Breakage Normal erosion from interrupting fault and load currents Abnormal wear from improper installation or poor material
Oil Baffles/Interrupters	Erosion	Normal erosion from interrupting fault and load currents Abnormal wear from improper installation or poor material
Operating/Lift Rods	Power factor Tank-Loss Index measurements of operating rods and /or internal insulation do not meet industry limits	Excessive carbon and/or moisture on internal components Internal component deterioration due to other factors
SF6 Gas Puffers	Binding	Abnormal wear Misalignment Breakage
SF6 Gas Nozzles	Erosion	Normal erosion from interrupting fault and load currents Abnormal erosion from improper installation or poor material
Vacuum Bottles	Cracks/Chips Elevated temperature (infrared scan)	Manufacturing defect Physical damage Loose/Poor connection

Interrupter Tanks – Air (Air-Blast Circuit Breakers)

Component	Problem	Cause
Solid Insulating Materials	Corrosion Cracks/Chips Deterioration Tracking	Deteriorated seals Physical damage Manufacturing defect Corona

Interrupter Tanks – Oil

Component	Problem	Cause
Breathers/Vents	Blocked/Clogged	Insects Bird/Animals Dirt/Dust
Tank Liners	Wet Deteriorated	Excessive moisture in oil Blocked/Clogged vent Normal deterioration Poor material
Drain Valves	Leaks Valve inoperable	Failure of seals, O-rings and gaskets Physical damage Corrosion Binding
Internal Insulation	Power factor Tank-Loss Index measurements of operating rods and /or internal insulation do not meet industry limits	Excessive carbon and/or moisture on internal components Internal component deterioration due to other factors

Interrupter Tanks - SF₆ Gas

Component	Problem	Cause
Solid Insulating Materials	Dirt/Corrosion Cracks/Chips Deterioration Tracking	Deteriorated seals Inadequate heaters Physical damage Manufacturing defect Corona
Filling Valves	Leaks Valve inoperable	Failure of seals, O-rings and gaskets Physical damage Corrosion Binding
Tank heaters	Not producing heat Broken or cracked mounting Dirt/Corrosion Cracked/deteriorated wire insulation	Blown fuse Loose wire terminations Physical damage Wrong type of wire used Normal ageing Abnormal heating

Oil

Problem	Cause
Dielectric strength measurements do not meet manufacturer’s specifications	High moisture in oil High carbon in oil Other contaminant in oil
Power factor measurements that are changing with time	High moisture in oil High carbon in oil Other contaminant in oil
Moisture in oil measurements do not meet industry limits	Excessive moisture in internal solid material components Blocked/Clogged vent

Operating Mechanisms - General

Problem	Cause
Opening times do not meet manufacturer’s specifications	Improper mechanism energy Improper mechanism lubrication Improper mechanism adjustment Mechanism binding
Closing times do not meet manufacturer’s specifications	Improper mechanism energy Improper mechanism lubrication Improper mechanism adjustment Mechanism binding
Trip free dwell times do not meet manufacturer’s specifications	Improper mechanism energy Improper mechanism lubrication Improper mechanism adjustment Mechanism binding
Reclosing times do not meet manufacturer’s specifications	Improper mechanism energy Improper mechanism lubrication Improper mechanism adjustment Mechanism binding
Opening velocities do not meet manufacturer’s specifications	Improper mechanism energy Improper mechanism lubrication Improper mechanism adjustment Mechanism binding
Closing velocities do not meet manufacturer’s specifications	Improper mechanism energy Improper mechanism lubrication Improper mechanism adjustment Mechanism binding
Total travel distances do not meet manufacturer’s specifications	Improper mechanism energy Improper mechanism lubrication Improper mechanism adjustment Mechanism binding
Rebound distances do not meet manufacturer’s specifications	Improper mechanism energy Improper mechanism lubrication Improper mechanism adjustment Mechanism binding Low or no oil in opening dashpot Defective closing shock absorber
Overtravel distances do not meet manufacturer’s specifications	Improper mechanism energy Improper mechanism lubrication Improper mechanism adjustment Mechanism binding Low or no oil in opening dashpot Defective closing shock absorber
Contact wipe does not meet manufacturer’s specifications	Improper mechanism energy Improper mechanism lubrication Improper mechanism adjustment Mechanism binding

SF₆ Gas

Problem	Cause
SF6 gas purity measurements do not meet manufacturer’s specifications	Excessive air or other foreign gas in SF6 gas Excessive by-product gases in SF6 gas Excessive moisture in SF6 gas Leaks
SF6 gas moisture measurements do not meet manufacturer’s specifications	Leaks Excessive moisture in make-up SF6 gas
SF6 gas by-product analysis measurements do not meet industry limits	Internal flashover Excessive erosion of interrupter nozzle Excessive interruptions of fault and load currents

Support Frames and Structures

Component	Problem	Cause
Foundation	Deterioration Does not support breaker frame Sinking or shifting	Normal degradation Abnormal degradation due to poor material or workmanship Physical damage Improper foundation preparation
Breaker Frame	Corrosion Bent/Damaged Does not support breaker securely	Deteriorated paint Physical damage Poor design, material, workmanship

Investigations

Introduction

Investigating the root cause of circuit breaker failures is a very important part of a circuit breaker maintenance program. Not only does a proper investigation identify what, why and how something failed, it also can provide very useful information that can identify type issues or be used to modify the existing maintenance programs so that they can detect, prevent or minimize damage from these events occurring again in the future. While the maintenance programs of circuit breakers exactly like the one that failed are normally reviewed after a failure, other circuit breakers with similar components or characteristics of the failed one should also be reviewed.

IEEE Standard C37.10-2011 Guide for Investigation, Analysis, and Reporting of Power Circuit Breaker Failures is a good reference on this topic. It contains checklists, tables and forms as well as information that can be useful in the failure investigation process.

Organization

The first step of the investigation process is to identify the objective(s) of the investigation. Normally, one objective is to identify the root cause of the failure, which is the circumstances and sequence of events that led up to the failure. An investigative team is often assembled to identify the objective(s) of the investigation as well as develop the investigation plan. Investigative team members can include maintenance engineers, maintenance managers, equipment Subject Matter Experts (SMEs), maintenance mechanics and technicians, consultants and manufacturers. The manufacturer of the failed equipment should always be notified of the failure and included in the investigation when it is covered by a warranty.

Planning

The planning process usually begins with identifying which documents, information and equipment are needed for the investigation. Documents commonly needed for an investigation are listed in Table 4-37 below.

Item No.	Description
1	Manufacturer’s instruction manuals
2	Manufacturer’s drawings
3	Owner’s substation drawings (schematics, wiring, etc.)
4	One-line drawing of substation
5	Owner’s inspection, maintenance and test records
6	Owner’s maintenance procedures
7	Manufacturer’s or Owner’s failure investigation form
8	Work permit/switching order giving isolation or clearance to perform investigation on failed breaker

Information commonly needed for an investigation is listed in Table 38 below.

Item No.	Description
1	Substation name
2	Owner’s equipment identification number
3	Nameplate data
4	Date and time of failure
5	Weather conditions at time of failure
6	Electric system conditions at time of failure
7	Initial observations of failure
8	Circuit breaker position (open or closed) before, during and after failure
9	Readings on operation counters, pressure gauges, etc. at or immediately after time of failure
10	Alarms received at time of failure
11	Relay targets
12	Digital fault records
13	Sequence of events records
14	Fault history of circuit breaker
15	List of tests needed for investigation
16	Results of investigative tests
17	List of samples needed for investigation
18	Results of sample analyses

Chapter 5 of IEEE C37.10-2011 contains several tables listing suggested diagnostic tests for various types of circuit breakers. Each table contains the characteristic to be tested, whether the test is performed in service or out of service, the parameter measured and what the test assesses.   Equipment commonly needed for an investigation is listed in Table 4-36 below.

Item No.	Description
1	Personal Protective Equipment (PPE)
2	Personal safety grounds
3	Test equipment
4	Sample jars, bags, containers, labels
5	Camera
6	Flashlights, portable lighting
7	Tools
8	Rulers, scales, tape measures
9	Man lift, scaffolding, ladders
10	Crane, boom truck
11	Clean up materials
12	Disposal bags, containers, labels

An investigation plan is developed next. This plan lists the sequence and time frame of each step of the investigative process. These steps include such items as the investigative tests required, the material samples required, the partial or complete disassembly of components required and the data required to complete the investigation. The steps and their sequence can vary from investigation to investigation due to the various types and conditions of failures. Therefore, the investigation team should develop an investigation plan that is appropriate for each failure.

Collection and Preservation of Data and Samples

Any data that is subject to change with time must be collected and preserved as quickly as possible after the failure. Additionally, any material sample that is subject to deterioration or change with time must also be collected and preserved as quickly as possible after the failure. This collection and preservation may need to be performed by the first responders to the failure. In these cases, it is beneficial to have training and procedures in place detailing what actions are needed to collect and preserve volatile data and samples after a failure.

The collection of non-volatile data and samples should be performed in the order listed in the investigation plan. This also applies to all investigative tests. The non-volatile data, the non-volatile samples and the results of the investigative tests are also important to the investigation and need to be preserved as well.

Data and Sample Analysis

It is best that the analysis of data be performed by individuals familiar and competent with the information. This may require several people to be involved in analyzing all of the data associated with the investigation. For example, a relay engineer may be required to analyze the relay targets and digital fault records of the failure while a system operation engineer may be required to analyze the electric system conditions at the time of the failure. These individuals may be part of the investigation team or simply provide their analyses to the team.

The same is true of the analysis of the material samples. Laboratories and analysts familiar and competent with the material should be used for the sample analysis. These individuals are not normally part of the investigation team. Therefore, it is important that the investigation team communicate with the laboratory to specify what information is required from each material sample and which laboratory tests can best make that determination. The results of these tests along with a written analysis should be provided to the investigation team by the analysts at the laboratory.

Report Preparation

The preparation of the investigation report is the final step in the investigation process. This report may be prepared by the investigation team or by other persons who present the report to the team for review and approval. Some key items that should be included in the investigation report are listed below.

1. Members of the investigative team
2. Investigation objective(s)
3. Investigation plan
4. Documents used
5. Data used
6. Data analysis results
7. Material samples collected
8. Laboratory analysis results
9. Field tests performed
10. Field test results and analysis
11. Conclusions
12. Recommendations

The conclusions section should contain the root cause of the failure and how it was determined. This includes the circumstances and sequence of events that led to the failure. It is helpful to list alternative possible causes of failure and to explain why they were eliminated in this case. This often helps to strengthen the selection of the final root cause of failure.

The recommendations section should include the actions to be taken with the failed circuit breaker. Is it to be repaired or is it to be replaced? If the failure was related to the manufacturing of the circuit breaker, a recommendation should be made that the manufacturer be notified of the failure. The expectation is that they would develop a corrective action plan for future products from their factory as well as a corrective action plan for their products that are still in service. This may result in a service advisory from the manufacturer.

Failure Investigation Examples

This section presents examples of failure investigations performed by utilities. Each example includes:

• Initial Indication of the Failure

• Investigative Steps

• Cause of Failure

• Failure Resolution

• A Photograph of the Failure

Example 1 – Operating Linkage Failure

Initial Indication of Failure

The initial indication of failure was a flashover of a circuit breaker disconnect switch while opening it to isolate a circuit breaker.

Investigative Steps

A review of the events leading up to the flashover as well as an interview with the observers of the failure was performed. The vacuum circuit breaker was in the process of being taken out of service. A trip operation was performed to open the circuit breaker. Its position indicator was checked and it showed that the circuit breaker was in the “Open” position. A flashover occurred while the first disconnect switch was being opened to isolate the circuit breaker.

The next step was to perform a continuity check of the circuit breaker to see if the contacts on each phase were actually open. The test indicated that two phases were indeed open but the center phase measured closed. The disconnect switch was inspected and the flash marks were also on the center phase.

Next, the operating linkage of the circuit breaker was inspected. A threaded rod was found broken off of the bottom of the insulated operating rod for the center phase (see Figure 7-1). This center operating rod was also found in the closed position. The operating rods on the remaining two phases and the operating mechanism itself were all found in the open position and undamaged.

The access panel to the high voltage compartment was removed. An inspection of the components in the high voltage compartment was performed. No visible damage was observed. An attempt was made to operate the center phase vacuum bottle to the open position from inside the high voltage compartment. It would not open. This indicated that the vacuum bottle contacts were welded closed.

Cause of Failure

The cause of the operating rod failure was welded vacuum bottle contacts. The cause of the welded vacuum bottle contacts was not determined.

Failure Resolution

The failure resolution was to replace the defective vacuum bottle and the broken operating rod.

Example 2 – Vacuum Bottle Deterioration

Initial indication of failure

The initial indication of failure was a “popping” sound heard coming from the high voltage compartment of a 34.5 kV circuit breaker.

Investigative steps

The circuit breaker was removed from service. The access cover was removed from the high voltage compartment and an inspection of the components inside was performed. Evidence of tracking across the outside of one vacuum bottle was observed.

The next step was to determine why the tracking had occurred. The events leading up to the discovery of the “popping” sound were reviewed. It was found that this circuit breaker was a bus tie breaker and it was normally operated in the open position. It was also found that nothing unusual had happened in the time leading up to the discovery of the “popping” sound.

Next, the design of the circuit breaker was reviewed. It was found that this circuit breaker consisted of two vacuum bottles connected in series per phase. The operating mechanism was connected to insulated operating rods for each phase. These insulated operating rods were each connected to the center linkage between the two vacuum bottles. This particular design resulted in the center linkage between the two vacuum bottles on each phase “floating” when the circuit breaker was energized and in the open position. While in the open position, leakage current across the outside surface of the vacuum bottle was attempting to charge the floating end of the insulated operating rod. As the outside surface of the vacuum bottle deteriorated, the leakage current increased resulting in observable tracking on the outside surface and audible “popping” sounds.

Cause of Failure

The cause of failure was vacuum bottle insulation deterioration due to leakage currents attempting to charge the “floating” center operating linkage.

Failure Resolution

The short term failure resolution was to replace the damaged vacuum bottle. The long term failure resolution was to replace the entire circuit breaker with one designed to better withstand operating voltages in the normally open position.

Example 3 – Internal Flashover from Lightning Strike

Initial Indication of Failure

The initial indication of failure was the unexpected tripping of the circuit breaker followed by the inability to close the circuit breaker.

Investigative Steps

The initial review of the protective relay targets indicated an internal failure of the circuit breaker. Testing of the SF₆ gas in the circuit breaker confirmed the internal failure.

Next the application of the circuit breaker was determined. It was found to be a circuit breaker in a transmission line position.

A review of oscillographic data from the protective relays identified which phase had failed. It also indicated that after the circuit breaker had successfully opened from the initial lightning strike, a second lightning strike hit the circuit breaker while it was in the open position causing the internal flashover.

A review of the lightning protection on the incoming transmission line connected to the circuit breaker showed the use of air (or spark) gaps. Air gaps are very ineffective in protecting SF₆ gas circuit breakers from lightning overvoltages. The best protection from lightning overvoltage is modern metal oxide surge arresters.

Cause of Failure

The cause of failure was dielectric breakdown of the SF₆ gas due to a lightning strike.

Failure Resolution

The failure resolution was to replace the entire circuit breaker with another SF₆ gas circuit breaker and to add metal oxide surge arresters to the incoming transmission line.