best practices for using infrared thermography for condition monitoring of oil-filled utility...

7/27/2019 Best Practices for Using Infrared Thermography for Condition Monitoring of Oil-Filled Utility Assests

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2005 Snell Infrared 800-636-9820 www.snellinfrared.com

Best Practices for using Infrared Thermography for

Condition Monitoring of Oil-filled Utility AssetsJohn Snell

Snell Infrared

PO Box 6Montpelier, VT 05601-0006800-636-9820

[email protected]

Abstract:Infrared thermography is being used more and more often as a tool to monitor the condition of utility

assets, including transformers and other oil-filled devices. When conditions are right and thethermographer is qualified, the results are remarkable: locating problems and potential problems long

before they fail. This enables system owners to manage further diagnosis or repairs in a timely, cost-effective manner. This paper will discuss the current best practices for using thermography for

condition monitoring of utility assets, guidelines for success and an overview of mistakes that arecommonly made.

Keywords:

ASNT, condition monitoring electrical, utilities, emissivity, infrared, thermography, transformers

Introduction:

We have all grown dependent on power being delivered reliably and

continuously whenever we need or want it. Many utility systemassets are both aging and being loaded past anything previously

imagined. Replacements, especially transformers, are months oryears in construction and delivery. The cost of a failure in the grid

can, as a result, have costly, even devastating, consequences.

Utilities have long practiced preventive maintenance (PM), buteconomic pressure on all line items in a budget has not spared

maintenance where cost reductions have been considerable. The useof condition monitoring technologies, such as dissolved gas-oil

analysis (DGA), airborne ultrasound, and infrared thermography,have not only helped reduce unnecessary PMs, but have also offered

greater assurance that assets are performing as they should.

What is infrared thermography?

This remarkable technology utilizes electronic imaging cameras that

detect infrared radiation in much the same way that conventionalcamcorders see visible light. Both detect forms of electromagnetic

energy that are radiated by all objects above absolute zero. Onceradiated, that energy is also reflected by many types of surfaces and


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transmitted by a few. Infrared radiation is defined as waves that are 2-14 micrometers in length and,thus, is longer than visible light. As surfaces increase in temperature they emit more infrared radiation.

Surfaces emit with different efficiencies, termed their emissivity; unpainted metals are inefficient andhave low emissivity values. In addition, low emissivity surfaces are typically highly reflective of the

radiant energy of their surroundings.

Special lenses focus the infrared energy on a multi-element detector array producing an electricalresponse that is converted into a visible image, or thermogram, portraying the thermal patterns. Todays

cameras can see temperature difference as small as 0.5C on a high-emissivity surface at 30C. Someinfrared cameras are specially designed and calibrated so that detected radiation can be converted into a

radiometric temperature measurement. When properly used, these systems can consistently yield non-

contact measurements accurate to 2 C or 2% of the measurement range. Unfortunately, it is

extremely difficult to make accurate, repeatable measurements of unpainted metal surfaces under fieldconditions.

Condition monitoring of utility assets:

In order for thermal images of utility assets to have diagnostic value, it is necessary to (1) know how theasset is constructed and function, (2) to understand how it fails and what the thermal signature of that

failure is, and (3) to understand how system and ambient conditions will affect the thermal signature.

The vast majority of failures in utility assets result from either (1) abnormal high-resistance heating at apoint of electrical contact or (2) overheating of the asset as a whole due to a failure of the cooling

system. When conditions are right, a thermal signature precedes these failures. The value ofthermography, then, is being able to locate these problems in advance of failure. While the surface

temperature is important, many influences affect surface temperature other than the severity of theproblem. Once a suspect component or problem area is located, additional tests may prove more

valuable to identify the exact nature or the condition or to determine how advanced it is.

We will look at what assets can be monitored with thermography and at the conditions required to do sosuccessfully. We will also discuss the mistakes that are most commonly made in the process.

What to inspect:

Utility assets are a diverse group of complex devices. For the purposes of discussion we can look atthese more generically and divide them into several groups that include oil-filled transformers, oil-filleddevices, surge protection, disconnects, lines and connectors. More and more assets are also gas-

insulated; this creates unique difficulties for thermographers that are beyond the discussion of this paper.

Oil-filled transformers produce heat in normal operation. Failure to disperse this heat adequately resultsin premature failure. Failures can also occur when connections points themselves overheat due to

abnormal high-resistance heating. When these are internal to the transformer, they can be very difficultor impossible to detect; DGA would be a far more diagnostic tool.

Transformer tank: Baseline thermal signatures of all sides of the tank may have some limited value

for trending changes over time. Two problems exist: first, changes to the thermal signature that areindicative will often be extremely subtle because of the massive nature of the tank. Second, it is difficult


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to see all surfaces on most transformers and those that can be seen are subject to considerable influencesin heat transfer that are difficult to characterize.

That said, it is still typically a simple matter to gather and store baseline images of each side of the

transformer under known ambient conditions and at maximum loading. These can be compared to

updated images on an annual basis or as needed. While there may be some merit in comparing thesignatures of similar transformers, transformers more often than not have unique signatures.

Cooling systems: Inspection of cooling systems can haveimmense returns, even if the simple technique is often

unappreciated and undervalued. A normal pattern for aconvective system is warmer fluid at the top and cooler at the

bottom with an even thermal gradient between the two. A setof thermal images of the cooling system can clearly show

anomalous patterns that may not be indicated by an oil-temperature gauge. The most common anomalies show cool

tubes related to lack of oil circulation; this is most oftencaused by a low oil condition, either normal or abnormal.

Lack of circulation has also been associated with out-of-levelpads, inverted riser tubes, closed valves, and blockage in the

tubes or headers. Reduced oil circulation during summer peakconditions will result in a transformer that overheats and that

can dramatically reduce its life cycle.

Cooling fans and oil circulation pumps, if present, can also be inspected. Fans in particular are oftenneglected in routine PM. Both should be place into operation for approximately fifteen minutes prior to

an inspection. Fans can show several signatures; when operating normally, the fan motor will appearwarm. When the motor has failed, it will be cold by comparison. Fan and pump motors that are seized or

that have failing bearings (or pump seals) will appear warmer than normal. It may even be possible tolocate fans or pumps that are running backwards or that are valved off. Fans and pumps represent the

Achilles Heel of the transformer: they are designed to operate only when worst-case conditions existso that, if they fail, serious repercussions, i.e. heat-related damage or failures, are almost guaranteed.

Cooling system inspections should be scheduled prior to summer peak and, as necessary, during summer

peak to insure all is operating as designed. Inspections after any repairs or maintenance work candocument running conditions and minimize problems such as inadvertently leaving a valve closed or a

fan running backwards.

Bushings: Both high- and low-side bushings can be profitably inspectedwith thermography. When under load, anomalous conditions can be found on

the line-side connections, as well as internal connections, both in the bushinghead and in the connections to the coils. A direct view of the line-side

connections is necessary and simple comparisons among the phases shouldbe made. A normal signature is at or close to ambient air temperature. Any

unexplained, anomalous thermal signature or rise over ambient/another phaseis considered indicative and warrants further investigation.


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Internal faults will be indicated by much more subtle signatures due to the large thermal gradient that

exists between the connection itself and the observed surfaces. While a fairly direct view of the bushinghead is usually possible, it is not possible to see the internal connections to the coil directly; here a

signature, when warm enough, will show up at the base of the bushing as heat is conducted up the

bushing stud itself from the coil connection. Even to be able to gain a view of this part of thetransformer, especially large ones, while standing on the ground can be challenging.

Tap changers: Most, but not all, tap changer compartments run at the same temperature as the tank orslightly cooler. Abnormally overheated tap connections under oil will often generate enough heat to

cause the entire changer compartment to overheat. A tap changer that appears warmer than the tank,unless normal by design, is cause for further investigation. Unfortunately, the faulty tap may not be

energized at the time of the inspection finding a problem is not assured. Regular DGA is still ofimmense value.

Connectors: A normally operating connector will typically operate at the same temperature as the line

or slightly cooler. Connectors with abnormal resistance will heat up compared to those that are normal.The often-massive connectors used on many utility assets may dissipate heat effectively enough that the

thermal signature will be difficult to detect until damage is significant. Evidence of this is readily seenby damage to internal contact surfaces while external surfaces appear fine.

Failing connections on the grounding system may also have detectable thermal signatures. Whether it is

the connection point itself or a failing ground mat itself, current flow in such situations will oftenproduce enough heat to be seen in the image.

Surge protection: Surge protection in and around a substation can vary widely by design. Most

commonly it is a high-resistance path connected to ground. Normally surge protection will operate atambient air temperatures because there is no current flow. A breakdown of the resister will result in a

small leakage of current to ground at all times, even when a surge is not present; this, in turn, will causethe arrestor to heat continuously, typically in small sections defined by its structure and at only a few

degrees above ambient. Despite this seemingly insignificant signature, arrestor failure may be imminent;because failure is often catastrophic and dangerous to any nearby personnel, these early warnings should

not be ignored.

Insulators: Normally, insulators operate at or near ambientair temperatures. The only other normal thermal signature

shown by an insulator is one caused by solar absorption; heredarker insulators will often be warmer than lighter colored

ones. Cracked or dirty insulators may indicate a subtlethermal signature due to the slight current leakage that

occurs over the resulting high-resistance pathway to ground.These signatures can change or disappear with changes in

ambient conditions or as the insulator is washed by rain, sothe lack of a signature is not positive proof that a problem

might not exist at another time.

* 1 .1F

*

7 0 . 07 5 . 08 0 . 08 5 . 09 0 . 0

9 5 . 01 0 0 . 01 0 5 . 0


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Associated switches and disconnects: High-resistance heating problems are common in all types ofswitching and disconnect mechanisms. A normal device will operate at or near ambient air temperatures.

A simple comparison over the device and/or among phases will quickly reveal problems. It must benoted, however, that in some cases where a device can be feed from two sides, such as a yoke

disconnect, the cooler side may represent the actual problem. In such cases one side may be warm

because current is shunted to that side, away from a high resistance point of contact on the other side.Often a visual inspection or resistance test will reveal this, but one should not jump to the conclusionthat the hot spot is the problem.

Optimally, all switch/disconnect devices should be inspected after they are put back into operation. Even

slight heating (approximately 200F) over time can result in annealing damage that will be exacerbatedquickly into a device that has significant damage to contact surfaces or, in the worst case, has welded

itself together.

Conditions for inspection:

For the most part thermography cameras see surfaces; the radiant energy seen is a combination of both

energy emitted by the surfacethis tells us something about its temperatureand energy that isreflected by the surface, which tells us nothing about its temperature. Unpainted metals have a low

efficiency of emission while at the same time having a high reflectivity. This means they dont revealmuch about their true thermal nature and mask over the little information that is there with other

information. Ideally we can correct the readings in radiometric infrared cameras for both emissivity andbackground reflected temperature; unfortunately, and this despite what the literature and the suppliers

would have us believe, for all but the most corroded of metals, measurement error is unacceptably large.

The reality of looking at unpainted metal surfaces in most utility assets is that we will have someevenif subtleindication of abnormal heating if other conditions are conducive. Every effort must be made,

then, to have the right conditions. The accuracy and repeatability of radiometric measurements is alsovery low, even if temperature differences (phase to phase or rise over ambient) are measured rather than

actual temperatures. When the emissivity of a surface is below approximately 0.6, measurements, evenif corrected, are not recommended. This flies in the face of what most of the industry considers a best

practice.

Given this, we must recognize that even small temperature increases may indicate severe heating. Whenconditions change, the signature may fall below the threshold of detection. What changes are

significant?

System load: As load increases heat output rises at the square of that increase; a tripling load, notuncommon in a distribution substation, will result in a nine-fold increase of heat being produced. If the

system is inspected when loads are light, some anomalies will have thermal signatures below thethreshold of detection and others, though detectable, will be cooler than they will be when loads increase

at later, peak periods.

While some standards suggest that 40% of design load is an acceptable condition, an analysis ofpotential fault current suggests it is the bare minimum and, especially when loads will greatly increase

beyond that, inspections are better done under worst case conditions whenever possible. Some in theindustry feel it is possible to predict temperatures at a future load based on the present measurement; this


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methodology is highly unreliable and not recommended except in limited circumstances with significantinput from knowledgeable heat transfer engineers. It is clear, regardless, that as loads will increase so

will deterioration of an anomalous asset.

Convection/wind: The most significant of the limitations to using infrared thermography is typically

convective cooling by the wind. Convective cooling results in two issues; first, connections that areearly in the failure cycle, i.e. only slightly warmer than normal, will often be cooled below the thresholdof detection. Second, anomalies that are found are being cooled, often significantly, and will heat up

when the wind lessens.

Many thermographers have used several commonly accepted rulesof thumb to attempt to correct for wind. Unfortunately, these simple

measures are inadequate. Low temperature problems will still not bemade visible, and the complexities of convective heat transfer do not

always lend themselves to simple corrections for understanding moreadvanced problems.

Wind speeds as small as 1-5mph can have a significant cooling effect

on a thermal signature. Wind speeds above 5 mph can, depending on

other conditions, reduce the temperature difference between the

abnormal component and ambient to a few degrees or less.Inspections when winds exceed 15 mph should be avoided; when

they must be conducted in these adverse conditions, attention shouldbe paid to any and all findings, as they will increase in temperature

when the wind speed is reduced. The two images of a set of OCBs(left) were taken under similar loading and ambient air conditions; in

the top image the wind was blowing at 15mph while in the lower

image it had dropped to 2mph.

Classic heat transfer methodology may be useful to create a thermal model to explore the range of

temperatures expected with changes in convection. For instance IEEE Standard 738 does this for bareoverhead conductors by taking into account the appropriate thermodynamic and fluid equations for

taking wind speed into account, as well as natural convection and radiant cooling effects. It is notpossible, however, to apply this same model to all assets under the widely varying situations

encountered in the field.

Ambient conditions: The impact of changes in ambient may also be significant and difficult toquantify. The primary factors, aside from wind, are changes in air temperature, the impact of solar

heating, and the presence of precipitation.

The exact impact of changing air temperatures is difficult to predict, Clearly, an increase in air

temperature will result in an increase in the measured temperature of a component. Thus, becausewarmer summer air has less cooling capacity, a high resistance connection will become hotter during hot

months. A 70-100F difference in air temperatures between the summer and winter extremes is notunusual. During cold weather, problems that are only slightly warm may be cooled below a point where

detection is reliable or even possible.


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Solar heating of component, especially those with a high absorptivity of the suns energy (such as aged

conductors and dark insulators/bushings), will mask over small thermal differences. Late afternooninspections during the summer months are particularly problematic and should be avoided if possible.

Precipitation in any form, whether snow, rain or fog, will often result in evaporative coolingespeciallyof the abnormally warm component where there is enough heat energy to power evaporation.Evaporative cooling can result in temperatures falling below ambient air temperature. Again, anomalies

that are only slightly warm may be cooled below a point where they can be detected.

Other oil-filled assets:

Many of the same techniques and problems apply to other oil-filled utility assets, such as oil-filled

circuit breakers, voltage regulators, and re-closers. In these cases, however, heat is not normallygenerated in the same degree as is in transformers. The tanks, thus, will run much closer to ambient air

temperature. When any unexplained deviation in tank temperatures among the three phases occurs, it iscause for concern and, often, immediate action to determine the root cause. The reason for this is that the

abnormal heating, even if slight, is caused by a small high-resistance heat source (an internalconnection), that must be very hot in order to change the temperature of an entire tank of oil.

As with transformers, bushing connections can also exhibit heating either internally and externally, the

former being much more difficult to detect and, typically, more serious to rectify. DGA testing can bevery useful to better understand many internal faults that are located with thermography.

Common problems with many inspection methodologies:

Far too many of the inspections being conducted today fail to achieve best practices. The most commonissues are as follows:

A focus on radiometric temperature measurements: As has been shown, the surface temperature

represented in a thermal signature can vary widely with a number of variables, most of which aredifficult to characterize and quantify. Most practitioners fail to pay attention to the influences of ambient

and system conditions. As a result, many problems are not detected while others that are detected, aremisdiagnosed.

Basic thermodynamics: Even without an advanced degree in heat transfer, a simple understanding of

the relationship between the source of heating (most often internal to some degree) and the surface wesee in the thermal image (most often external) is essential. Many factors affect exactly what the surface

temperature will be at any given moment. The precise relationship between that moving target and theinternal heating source is often just as complex, especially when the thermal gradient is very large as is

the case with any oil-filled device.

A thermal image alone is not sufficient to make sense of the radiometric data. Ambient influences, suchas wind and air temperature, should be carefully measuredat the location of the anomalyand

recorded along with the thermal data. Similarly, all relevant system influences, such as load and circuitconfiguration, should also be noted and recorded.


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All this points to two things often ignored by thermographers. First, we must work with conditions suchthat, if there is an anomaly, we will be able to see it. Less than optimum conditions will often result in

many important anomalies being at or just above the threshold of detection, i.e. with a very low rise overambient or similar assets. Second, the radiometric temperature of an anomaly is not a reliable indicator

of its progress toward failure.

Thermal gradient: Thermal energy seen by the system radiates from the components surface. Theheat of high resistance almost always is being generated at some point internal to the surface. There

exists a thermal gradient between the hottest spot inside the splice and the surface being viewed. Thisgradient can be very large, on the order of hundreds of degrees. In fact, some splices are designed

specifically to dissipate heat. Some research has attempted to estimate what impact the thermal gradientmay have4; it would be useful to accurately model this specifically for typical splice components.

The relationship between temperature and electrical resistance: A widely unappreciated, yet

important, relationship exists between electrical resistance and temperature. As an abnormally high-resistance component begins to heat up, resistance increases which, in turn, results in additional heating

and, as a consequence, in a further increase in temperature. In other words, a bad situation gets worse,often quickly! An increase in component temperature of 10C results in a 4% increase in resistance. This

accelerating deterioration is one of the reasons why components often fail shortly after they are firstdetected or when they finally reach a runaway stage.

Current shunting: Also commonly overlooked are situations

where a warm component or asset may be the normal one, while thecooler one may be have a higher resistance. The most basic example

is the barber pole effect often seen on multi-strand conductors.This occurs when several strands are broken or isolated electrically

by corrosion, the remainder of the strands must care the entire loadand, thus, appear warmer. Current is shunted away from cool

strands that, because of their higher resistance, do not functionproperly. A similar situation can often be seen to exist on many

yoke-type disconnects (left).

On a larger, and much more significant scale, are any double fed circuits, such as a ring-bus, where highresistance on one side will cause current to shunt to the other side of the circuit; this additional current,

in turn, will cause any high-resistance anomalies, even if only slightly so, to heat. If the circuit is openedto repair these false positives, all current will flow through the side of the circuit with high resistance,

often with disastrous results. Extreme care must be given to analyzing any problems found on a double-fed circuit and, due to the potential complexities and consequences of a failure, qualified engineering

support is probably more often warranted than not.

Emissivity and reflected background: A best practice for radiometric temperature measurementsuggests that none be made until an anomaly is located. Even then, attention must be given to low

emissivity surfaces as they will fail to emit strongly and may also offer confusing reflections. When asuspect asset is located, a careful evaluation should be made of the emissivity of the surface(s) in

question. Emissivity correction value look-up tables can be helpful, but, in the end, the qualifiedthermographer will need to adjust many of these values to fit reality. Many components will exhibit a


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fairly high-degree of cavity radiation despite their otherwise low-emissivity characteristics. Once asuitable value has been determined, an appropriate background reflected temperature compensation

value must also be determined. This is typically a fairly simple matter for a qualified thermographer,even if not without pitfalls.

Two, additional important, but impossible questions: How hot is too hot? and How long will itlast? Unfortunately, little is know about the temperature/time relationship for failures caused by high-resistance heating at a small contact surface. What we do know it that the process often proceeds slowly;

even if early heating does not appear severe, pitting and melting occurs at a micro-site inside the point ofcontact. This, in turn, results in increase heating and resistance and oxidation. Annealing begins to occur

at fairly low temperatures (200F) over a fairly short period of time (30 days). Once the metals have losttheir temper, a run away condition, at which point more melting occurs, can result quickly.

It must be noted that the heating is concentrated on an area that is most often extremely small; this has

little to do with a temperature-based specification that typically accompanies all assets. The asset itselfwill probably not be heated greatly, but temperatures at the localized, high-resistance hotspot will, given

time and the right conditions, certainly reach the melting point of the metal.

While it is not possible to answer either question, it can be guaranteed that high-resistance hot spots willnot get better without intervention, at least not permanently! In extreme circumstances heating may

cause re-welding of a hot connection that may, in turn, result in a temporary improvement andreduction in resistance, heating and temperature. Clearly this condition would most often be considered

extremely dangerous and warrant immediate corrective action.

Limitations of the infrared system: While the utility asset and the surrounding environment present anumber of difficulties for thermographers, the infrared system itself has inherent limitations many of

which are poorly understood by thermographers. All optical systems, including infrared, have limits totheir abilities to resolve data. Thermographers must deal with both spatial and measurement resolution.

Spatial resolution is a function of the detector size and the optical

path of the system, including the lens. Longer lenses can improveresolution, but result in a narrower field of view. Moving closer, if

an option, achieves the same results. Distance and object size arethe two variables. It is common that systems used for utility

inspections have spatial resolutions in the range of approximately1.2mRad. This means that a typical component that is two inches

in diameter can be detected, if hot enough, from a maximumdistance of 138 feet. A one-inch component could be seen from

half that distance. The two images (left) clearly show how movingcloser allows us to see more detail; changing to a telephoto lens

would produce similar results.

The measurement resolution of an infrared system is less than itsspatial resolution, typically by a factor of between two and four. It

is, therefore, common to be able to see hot spots while still beingoutside of the measurement resolution for the system.


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Measurements taken beyond the limits of resolution typically appear less than they actually are becausethe hot spot is averaged together with the cooler sky temperature that often makes up the rest of the field

of view. The apparent temperatures of problems are thus often underestimated. The only solution is towork well within the limits of measurement resolution, either by being closer or using a lens or system

that has a more favorable resolution. Unfortunately most infrared system suppliers do not provide the

specification for measurement resolutions so it must be derived from practice.

One other system factor that should be considered is the waveband being detected. Most infrared

systems used for utility inspections detect radiation between 8-15 micrometers or the long wave band.This band is relatively insensitive to false positives resulting from reflected solar energy or solar glint.

In the past systems that sensed in the midwave band, 2-5 micrometers, were common. Problems withsolar glint are much more common and this waveband is no longer widely used as a result.

Qualifying thermographers: Too many thermographers are not adequately qualified and the results

are, on the one hand, less than optimum returns on the investment or, on the other, dangerous errors andomissions in their work.

Qualification of thermographers is best defined by the personnel qualification guidelines of the

American Society for Nondestructive Testing (ASNT) SNT-TC-1A. Qualification is based on training,experience and testing. Clearly the skills required to perform high quality utility asset inspections are

considerable; some are general to the field of thermography while others require specialized knowledgeof the assets themselves.

Level I thermographers are qualified to gather data; certification entails a week of training and three

months experience, at a minimum. At Level II thermographers may also interpret the recorded data. Tobe certified at Level II requires an additional week of training and up to nine months additional

experience. Training at both levels should follow the training outlines prescribed in SNT-TC-1A.Performance-based testing, including a practical examination, should be done for general knowledge as

well as knowledge specific to utility applications.

Educate users of thermography services: Too often the expectations of users of thermographyinspection services are not based on the reality of heat transfer and radiation physics. Disappointment is

the only thing that can be assured! The popular press has done little to dispel the many industry mythsthat contribute to this unfortunate situation.

A pre-inspection meeting can establish the requirements necessary for condition monitoring as well as

define the limits of the technology. If work must be done with less than ideal conditions, as is often thecase, expectations can be adjusted appropriately, and provisions made for completing the inspection at a

later date.

Unfortunately very few industry standards exist.ASTM E1934, Standard guide for examining electrical

and mechanical equipment with infrared thermography can provide some minimal guidance even if it is

not specific to utility assets; it is in the process of a major revision at this time. Some thermographers

use rules of thumb that masquerade as standards; some are even now incorporated into formalstandards despite the fact that they are not based in science. This situation is problematic and costly for

all. Until this changes, we can expect continued problems with achieving anticipated results.


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A sample Best Practice

for the use of infrared thermography

for condition monitoring of utility assets

Inspections will be conducted with appropriate precaution, planning and attention to safely. Ifcircumstances change such that safety is an issue, the inspection will be curtailed immediately until

plans can be revised or circumstances change.

Inspections will be conducted at peak loading conditions with a wind no greater than 5-10 mph. Any andall differences in temperature among phases or similar components are noted for follow-up to determine

the root cause and, as appropriate, any corrective actions that should be taken. When inspection must beconducted with higher wind speeds, it must be recognized that some anomalies may not be detectable

and those detected may be hotter than they appear when winds are reduced.

Baseline inspections will be conducted for all newly installed assets. Whenever damage occurs, repairsare performed or destructive testing done, follow-up monitoring will be done to assure the condition is

normal. Periodic monitoring of asset condition will be scheduled on a frequency based on risk and astatistical analysis of current condition. If resources do not allow for optimum implementation, the

deviation shall be noted and overall maintenance investments adjusted to accommodate as required.

Thermographers will be qualified to use the infrared system and to understand the findings or work withsomeone who can do so. Thermographers will work within their limits and have the support of a

qualified, knowledgeable engineering staff.

Radiometric temperatures will be measured when conditions allow, the correct emissivity andbackground reflected temperature and working within the measurement resolution of the system being

used. If necessary, supplemental lenses will be employed to improve resolution. The IR system will bechecked regularly to ensure it is within calibration.

When possible, the emissivity of surfaces will be increased by applying high-emissivity targets, such as

a light colored paint or a grease, to improve measurement reliability. Temperatures will be reported inthree ways (1) corrected, (2) rise over similar component and (3) rise over ambient. Generally

measurements will be made using a small area measurement rather than a single spot.

All relevant system and environmental influences will be measured and noted, including current andfuture loading, asset data, wind, ambient air temperature, precipitation, etc.

All components will be viewed directly if possible, and, even so, the thermal gradient of the component

will be taken into account when evaluating the thermal data. For components with no direct view, suchas an internal fault in any oil-filled device, any abnormal rise in temperature will suggest immediate

further diagnostics such as a visual inspection, airborne ultrasound or DGA testing.

All will agree that the primary purpose of an infrared inspection is to monitor the condition of all assetsand locate any that are not performing adequately. Thermography provides a snapshot picture in time;


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while it may be possible to understand changes to thermal signatures, doing so accurately typicallyrequires a very sophisticated modeling and engineering study. Trending changes in temperature may

have limited value given that a number of variables, aside from degradation, can influence temperature.Recommendations for repair will be based on all relevant factors rather than on temperature alone.

These may include such factors as criticality, history, current and future duty/load cycles, age, operating

environment, and other test data.

Conclusions:

Thermography is a powerful tool for monitoring the condition of many utility assets. When properlyused it can validate operating condition and help to locate and, in some cases, diagnose, anomalous

conditions. Thermography is often poorly used with the result being that detectable failures continue tooccur unnecessarily. Qualifying thermographers and educating customers will go a long way to

achieving success.

Author:John Snell, president and founder of Snell Infrared, has been

teaching people to use this remarkable technology since 1983. Hewas the first person in the world to receive an ASNT Level III

certificate in the thermal/infrared method and continues to be veryactive professionally on numerous standards committees and at

conferences. To learn more about thermography and Snell Infrared

visit http://www.snellinfared.com or call 800-636-9820.

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