Understanding infrared thermography reading 6 chapter 4

NDTHBV3-Chapt14+2 Elect.Power-IR.C16→Electric Power Applications of IRT Testing 很棒的教材-可惜仅仅只下载, 二十讲课里的第十六课. 努力搜索中.

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番鸭 Cairina moschata

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番鸭 Cairina moschata –上海酱鸭

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番鸭 Cairina moschata – 较喜欢的卤鸭 (五香粉酱油烧)

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O3

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PART 1. Thermographic Systems for Power Generation and Distribution 1.0 Introduction All utilities and their customers depend on system reliability. When outages occur, utilities are forced to produce and distribute power that is more expensive. In the past, the best means of reducing the number of forced outages was through preventive maintenance, which required the replacement of specific components after a certain life span, whether the component needed replacement or not. Although better than breakdown maintenance, preventive maintenance often leaves components untouched that should be replaced. Many utilities have discovered that the best way to reduce outages is to find and correct failing components before they become major problems that cause interruption in service. One of the easiest and most cost effective methods is predictive maintenance with infrared thermography. All equipment that conducts, consumes or generates power will also emit heat as a result of energy loss in the system.

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Typically, when these components become less efficient at doing their job, the heat they emit will increase.

Often, the temperature of a faulty component will increase rapidly before failure. Thermography lets plant engineers evaluate the thermal condition of a wide variety of plant and substation equipment through the use of infrared cameras that produce high resolution thermal video images in color or black and white. These images can quickly and easily uncover potential problems in electrical and mechanical systems.

An increasing number of plant maintenance teams now use thermal imaging systems to evaluate and predict the failure of many types of equipment within power generation and distribution systems. Today’s portable thermal imaging measurement systems can provide high resolution live images that can be stored on conventional videotape recorders or on built-in floppy disk drives.

These images can be retrieved for later analysis in personal computer based image processing programs. Some systems even allow detailed playback analysis within the basic system electronics.

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1.1 Range of Applications Thermography is cost effective within the power generation and distribution industries because of its multitude of applications, ranging from the monitoring of electrical connections and switching equipment to the evaluation of mechanical equipment and fluid transfer systems.

One of the most common applications involves monitoring electrical distribution systems, from transmission lines to motor control centers.

Electrical systems typically suffer from problems such as loose connections, load imbalances and corrosion. These problems cause an increase in impedance to current, resulting in resistive heating. If left unchecked, this heat can build to a point at which connections melt — breaking the circuit and in some cases creating fires. Thermography is well suited to this application because thermography quickly locates hot spots and determines the severity of the problem and how soon the equipment should be repaired. Some microprocessor based quantitative infrared test systems can perform trend analysis, letting the maintenance team set up periodic intervals for equipment inspections.

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The data are then stored in a database of thermal images, which logs images and corresponding test data. The program then displays multiple images of the same component surveyed over a period of several months. The temperature rise of the object is plotted to determine the temperature increase trend. When the slope of the temperature rise curve changes suddenly, this change typically indicates an impending failure (Fig. 1).

Thermographic trend analysis can be applied to indoor components such as motor control centers, breaker panels and disconnect switches and transformers, as well as on outdoor components in substations — switchgear, transformers and output current boosters. Utilities including Pacific Gas and Electric (San Francisco, California), Florida Power and Light (Miami, Florida), Northern States Power (Minneapolis, Minnesota) and Texas Utility Systems (Dallas, Texas), have adopted programs for regularly surveying their substations with thermal imaging equipment in an effort to maximize efficiency and reliability.

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FIGURE 1. Absolute temperature measurements of loose connection over six months: (a) thermograms; (b) graph. Component should be repaired at point where curve rises rapidly, that is, when temperature rises abruptly.

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FIGURE 1. Absolute temperature measurements of loose connection over six months: (a) thermograms; (b) graph. Component should be repaired at point where curve rises rapidly, that is, when temperature rises abruptly.

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Thermography is also highly effective in evaluating a utility’s many miles of transmission and distribution lines. Modular thermographic systems where the camera is separate from the electronics are ideal for surveys conducted from either a mobile land or airborne vehicle. In these cases, the camera is mounted outside the vehicle and the controller and display are used inside the vehicle. Images can be stored on videotape or on disk for analysis after the survey has been conducted.

Longwave (8 to 12 Îźm) systems are typically preferred for these applications because they can be used during the day without picking up false readings as a result of reflections from the sun.

Northeast Utilities, Berlin, Connecticut, pioneered a technique of mobile power line scanning. They have developed several customized vans incorporating popup periscopes housing infrared systems and video cameras.

The cameras are controlled by a motorized pan-and-tilt device operated by a technician within the van. Also, built into the rear of the van is a workstation with two monitors for display of the visual and thermal images, a laptop computer for storing statistical data and a video printer for generating repair reports.

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The high scan speed and the long wave detector of the infrared systems allow the technicians to travel at reasonable road speeds and, for some applications, to work day or night.

Scanning powerlines and equipment over long distances can be expedited by using a technique called thresholding. Thresholding allows the instrument to display an easily recognizable black-and-white image with the hottest regions of the image colorized in red. With this feature, operators can set a threshold temperature; any objects exceeding this temperature will be readily noticed by the operator when red appears in the display. Systems incorporating this feature along with high speed scanning at television rates increase the number of miles that can be covered in a day with a thermographic system.

Telescopes and electrooptical zoom features are frequently required when scanning small connections over long distances. It is important to understand the spatial resolution limitations of the instrument in use. Systems with high spatial resolution have the benefit of being able to view small objects at long distances. (IFOVgeo?)

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1.2 Mechanical Systems and Rotating Equipment Analysis There are numerous applications for predictive maintenance with thermography on mechanical systems and rotating equipment. These systems typically fail as a result of (1) excessive vibration or (2) poor lubrication, resulting in an increase in temperature.

Thermography is frequently used as a screening tool for vibration equipment.

Electrical motors, pumps and solenoids can be evaluated quickly for abnormal conditions. These studies can also be conducted over time to look for temperature increase trends. In electrical motors, thermography can be used to detect deteriorating insulation, poor windings and bad brushes. Many electric motor rework facilities also use thermography to evaluate motor armature conditions. In this application, it is helpful if the thermographic equipment operates at a multiple of the motor speed, that is, 60 Hz or 50 Hz, to accommodate international applications. The motor can be viewed easily while it is running because the system provides a strobe effect, slowing the apparent rotation so it can be analyzed. (how?)

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Strobe Effect

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As bearings lose lubrication, vibration occurs and heat builds to the surface of the object, where it can be detected with thermography. In Fig. 2, an air compressor and motor are evaluated. As expected, the compressor head is warm as a result of the compression process. The center of the compressor pulley is also abnormally warm, indicating a poorly lubricated or failing bearing. The visible light and infrared images were both gathered during the survey and subsequently transferred to an image processing system. In the image processor, the images are displayed side by side and a temperature cursor is placed on the hot spot. A repair report can then be generated directly from the image processor.

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FIGURE 2. Compressor bearing overheating. Abnormal hot spot on drive pulley indicates poor lubrication on sheave bearing.

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1.3 Analysis Thermography can also be used to evaluate fluid transfer systems such as pumps, steam traps and underground steam lines. Heat transfer systems such as heat exchangers, cooling towers and air conditioning systems can be inspected for blockages and poor thermal distribution. Insulated pipes can be assessed for heat loss or leakages. Plant buildings can be studied for insulation voids and roof leaks with this type of equipment.

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1.4 Equipment Selection There is a wide range of thermographic equipment available on the market and it is important to find the best equipment for each customer’s set of applications. Basically, a thermal imaging system performs two primary functions: (1) imaging and (2) temperature measurement.

It is important to evaluate carefully the quality of the thermal image. This includes factors such as spatial resolution (IFOV) , scan speed (responsiveness) and thermal sensitivity. The temperature measurement capability should be accurate and repeatable. It is important that a system maintain its accuracy over a wide range of operating conditions. The wavelength band that the instrument operates in is an important consideration.

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Short wave instruments are more significantly influenced by humid air and reflections from the sun.

Longwave systems are typically not affected by these factors and can provide a higher resolution image. (?)

Instrument portability and ruggedness are also considerations. Modular systems generally provide the most flexibility because they can be used in a wide variety of configurations.

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ď Ž Short wave instruments are more significantly influenced by humid air and reflections from the sun. ď Ž Longwave systems are typically not affected by these factors and can provide a higher resolution image.

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Data storage and image processing capabilities are also important factors. It is best to have the option of both digital and videotape storage and analysis.

The image processing system should be able to handle visual and thermal images simultaneously. An image archiving database capability is useful for implementing a structured maintenance program. Other factors such as availability of accessories, training and rapid service should also be considered carefully when selecting a thermal imaging system.

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Atmospheric Spectrum (transmittance)

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Atmospheric Spectrum (transmittance) Short wave instruments

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Long wave instruments

Atmospheric Spectrum (transmittance)

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Atmospheric Spectrum (absorption)

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Atmospheric Spectrum (absorption)

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PART 2. Infrared Thermography in Electrical Maintenance 2.0 Introduction Thermography is one of the most powerful tools available for electrical maintenance. With professional training and some experience a thermographer can quickly locate high resistance connections, load imbalances and overloads while the system is in operation. This can all be accomplished without direct contact to the energized system. Electrical inspections have typically produced remarkable returns, with documented returns of 30 to 1 on the part of a major industrial insurer. Prevention of catastrophic failures and unscheduled outages often results in cost savings far in excess of the cost of the test equipment and program. Today’s economic climate, however, demands even greater assurances for reliability from maintenance thermographers than in the past. Experience can reveal the inspection program’s successes and limitations.

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Some limitations to thermographic tests of electrical equipment are quite obvious. Some problems are inherent to the laws of physics and must be lived with or worked around. Others are related to environmental or operating conditions. The latest infrared test equipment is no longer a limiting factor — it will do more than usually needed. But inadequate data collection procedures and a poor understanding of how to use the information gathered are very much limiting factors. The following discussion indicates ways to improve electrical inspections by dealing with these limitations.

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2.1 Limitations from Physics ■ Reflected or Background Radiation ρ The radiometer sees the combined radiosity (exitance) of both radiated and reflected energy. Only the emitted energy indicates the temperature of the component. The reflected energy can make a shiny component appear hot when it is not. Solar reflections are a problem especially outside. Reflections of cooler ambient backgrounds may make a warm component seem cool when it is really quite warm. The solution is to be aware of the thermal background when viewing shiny surfaces.

■ Shiny Surfaces A much more serious problem on shiny surfaces is that they simply give little visible indication of their actual temperature. Polished aluminum, for instance, emits so little energy that even at temperatures in excess of 373 K (100 °C = 212 °F) it may look like it is at ambient temperature because of a ε = 0.03 emissivity value. When looking at shiny surfaces, remember that they will not appear as warm (or cold) as they really are. It is not possible to find hot spots on shiny surfaces until the surfaces are very hot.

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â– Measurements on Low Emissivity Surfaces So little radiation is emitted by shiny surfaces that trying to convert the radiometric data into accurate temperature information is typically impossible on a repeatable basis in the field. Many professionals do not recommend measuring temperatures with emissivity values lower than about 0.5. Although the emissivity value can be set for less than 0.5 in most systems, beware of the accuracy of measurement using values that small. â– Emissivity Determination Emissivity values can be taken from predetermined tables but such values should be used with a great deal of care. They are usually generic and may not be accurate for the waveband or temperature range under examination.

They are also each averaged over a waveband. If very accurate temperature data are needed, calculate the emissivity value of the actual surface being measured with the system. Whenever possible, measure temperatures only on highly emissive surfaces, such as electrical tape applied to the surface, using known, tested emissivity correction values. When this is not possible, measure the value of the surface.

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To determine the emissivity value of a surface, follow the procedure recommended in the training manual or the equipment operator manual. Note, however, that these techniques will probably not be accurate for shiny surfaces. The best bet, whenever possible, is to measure temperatures only on surfaces of high or known emissivity or to use contact measurement devices such as thermocouples. ■Angle of Interrogation θ Emissivity also changes with the angle of viewing. For instance cylindrical surfaces, such as a tubular bus or the barrel of a cylindrical fuse, emit and reflect thermal radiation over a wide range of values. What is seen is not necessarily a true representation of the problem. Always try to face the target directly. Try to stay within 45 degrees of normal. On curved surfaces make several measurements, if necessary moving each time to be directly in front of a small section of the curve.

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â– Emissivity Variations Temperatures measured on components with several emissivities may be incorrect. Those parts with high emittance may appear to have a different temperature than parts with lower emittance. A piece of tape or a sticker on a shiny bus bar, for instance, will almost always appear warmer than the bus bar itself, which has a low emissivity is reflecting the normally cooler surroundings. Be cautious when dealing with a surface that has several different emissivity values. While they may all be the same temperature, they will probably not appear the same. Emissivity changes may not be obvious.

Cracks, scratches, bolt threads and holes will all typically have higher emissivities than the surfaces they are in and will appear to be at a different temperature.

A hole is actually a good place to measure an accurate temperature because it has a very high emissivity. A hole that is seven times deeper than it is wide has an emissivity of 0.98.

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■ Cases Where Surface Is Measured, Not Heat Source Failure of electrical components is usually related to excessive heat, especially that caused by high resistance. Heat is transferred from this internal source to the outer surface visible to the infrared camera. For small electrical parts the source and the surface may be in very close proximity and of similar temperatures. But in most cases there can be a significant difference in temperature between the heat source and the measured surface.

Many factors influence the rate at which the heat is transferred to the surface.

For example, on a load break elbow, variations in the thickness of the electrical insulation alone, because it is also a fairly good thermal insulator, can cause up to a ±11 K (11 °C = 20 °F) variation in surface temperature.

Test the component as close to the heating source as possible. Where this is not possible, actual problems will always be more severe than are indicated.

The effects of the materials acting as thermal insulation must also be considered. The greater these effects are, the less indication there will be of the actual temperature at the heat source.

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2.2 Environmental or Generating Conditions ■Defining Delta Measurements ΔT Delta temperatures are sometimes reported as a difference between the component and the ambient temperature. Yet the term ambience, which actually means surroundings, is typically not well defined. Does it mean air temperature? Or the temperature in an electrical panel? Is the panel temperature measured immediately on opening it or after a while?

Inaccuracies can result if ambient is not clearly defined or understood. Delta measurements, when used, should be the temperature difference from one phase to another (if loads are equal) or to a similar piece of equipment under the same influences.

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Defining Delta Measurements ΔT Delta measurements, when used, should be the temperature difference from one phase to another (if loads are equal) or to a similar piece of equipment under the same influences.

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■ Environmental Conditions Environmental conditions can make it difficult to see or correctly interpret problems, that is, operational dysfunctions 机能障碍 caused by material anomalies. This is especially true for problems with a low temperature difference. Despite what people may think, these problems can be extremely dangerous.

A problem with a low temperature difference will tend to be hidden, masked or understated in the following environmental cases: where components are heated by the sun; in ambient extremes, either hot or cold; when components are cooled by the wind or other convection; when surfaces are wet; and when components are lightly loaded thermally.

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Low temperature problems may be hidden by the environment — do not assume they disappear. They will be back when conditions change.

Whenever possible conduct surveys under optimum conditions. Wet conditions, hot or sunny afternoons and winds greater than 16 km·h–1 (10 mi·h–1) should be avoided. Be aware also that the wind will cool off the abnormal phase. For a valid inspection, however, normal phases just a few degrees above ambient on inspected surfaces should not have cooled below ambient. The stronger the wind, the more misleading are measurements of temperature differences.

Keypoint: Wind speed is limited to 15~16 Km/hr

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â– Inservice Inspection Equipment must be under load, preferably normal operating loads. The correction factors based on the power formulas commonly used in the industry are not recommended. Although they will accurately predict the changing heat output, they will not predict the component temperature.

Inspect equipment when load is either 40 percent of design or the highest anticipated load — whichever is greater. If loads are less than this, problems may exist that cannot be detected or that will give very little warning before failure. ■Variations in Ambient Temperature Thermal tests must also take into account changes in ambient air temperature, especially from summer to winter extremes. A problem identified during winter is more likely to fail during summer conditions. Whenever possible, conduct tests under worst case conditions. This usually means at peak load during hot weather. If this is not possible, interpret the results with care.

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2.3

Data Interpretation

â– Criteria for Assembling Data The greatest mistakes during an infrared inspection of an electrical circuit are probably made in interpretation and handling of the data after the inspection.

Temperature is not always the most important datum required to understand the problem. What other factors should be considered when determining the seriousness of a problem? This question is probably best addressed by a group of people involved in the various levels of maintenance operations and management at the work site.

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Factors to be considered may include the following: 1.

2.

3.

4.

5.

6.

7.

8.

9.

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11.

12.

safety, cost of preventive maintenance, criticality of equipment, increases in electrical load, changing trend of temperatures, history of the equipment or similar equipment, availability of spare parts and repair personnel, cost of an unscheduled outage or run to failure, ability to reduce loads until scheduled outage, ability to monitor the condition of equipment, accuracy of test data, especially temperature, and availability of repair opportunity.

These criteria can be incorporated into a weighted matrix that will suggest an appropriate course of action. Compare the predictions with the actual results, to improve the matrix.

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â– Thermographer Qualification Inaccurate results from infrared and thermal testing of electrical systems and components are often caused by a poorly qualified thermographer. Bad inspection practices, lack of information and misunderstanding of what the data really indicate are all factors. A thermographer qualified at Level I is not supposed to interpret data. That is a duty reserved for someone with Level II training and experience. Inspectors must get training, experience and support to do the job.

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PART 3. Predictive Maintenance of Nuclear Reactor Components 3.0

Introduction

Nuclear reactors are composed of a number of components to which many nondestructive testing methods are applied for inspection during operation as well as shutdown. However, it is difficult to apply most of the methods to components where access is restricted because of the radioactive environment where access by inspectors is restricted. The infrared and thermal test method is an efficient remote sensing device when used to diagnose and inspect the reactor components of nuclear reactors. Infrared thermography has been widely applied to inspect components of nuclear reactors :

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for example: (1) leakage and overheating areas at joints, shaft and bearings, (2) abnormal parts in piping, valve, flange and nozzle, (3) internal discontinuities in the containment vessel and piping such as corrosion, separation and cracks, (4) leakage of cooling fluid in reactor core and its components, (5) deteriorated and anomalous areas in metallic and nonmetallic joints and bushings in the highly radioactive environment, (6) continuous monitoring of cooling towers under reactor operation (7) overheated areas of main circulation pumps and (8) deterioration and anomalies of electric and electronic control components.

Described next are a few techniques for detecting and evaluating the integrity of components of the Japan Materials Testing Reactor: (1) (2) (3) (4)

decay heat monitoring of an irradiated capsule, monitoring of cooling towers under reactor operation, detection of overheating of main circulation pumps and maintenance of the reactor canal wall.

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Nuclear Components

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Nuclear Components

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Nuclear Components

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Nuclear Components

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Nuclear Components

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Described next are a few techniques for detecting and evaluating the integrity of components of the Japan Materials Testing Reactor: (1) (2) (3) (4)

decay heat monitoring of an irradiated capsule, monitoring of cooling towers under reactor operation, detection of overheating of main circulation pumps and maintenance of the reactor canal wall.

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Nuclear Reactor

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Nuclear Reactor

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3.1 Decay Heat Monitoring of Irradiated Capsule under Operation The Japan Materials Testing Reactor, whose thermal output is 50 MW, is used to irradiate test fuels and materials of a capsule inserted in the reactor core and reflector zone with the fast and thermal neutron flux of 1 × 1014 to 4 × 1014 cm–2·s–1 and neutron fluence of 1021 to 1022. The capsule tube is 30 to 80 mm (1.2 to 3.2 in.) in diameter and 750 mm (30 in.) in length. Fuels and materials are placed in the tube for irradiation. The reactor is operated for 28 days of each cycle. The volumetric heat generation of the capsule in the reactor is 10 W·cm–3 (164 W·in. –3) maximum during the operation. The reactor pressure vessel is submerged in an open water container.

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The irradiated capsule is transferred from the reactor core via an open water canal of square cross section directly connected to the pool during the shutdown period and is stored under water near the side of the canal wall.

The irradiated fuel and material in the capsule generate the decaying gamma radiation heat. Some capsules emit gamma radiation. Radioactivity at the capsule surface is so high after irradiation that water is circulated in the canal to cool the radiation generated heat for 1 to 3 mo. After the radioactivity of the capsule becomes lower than an allowable value, the capsule is transferred to the hot laboratory building.

A monitoring test is used during thermography to detect a small temperature rise of the water surface caused by the decay heat from the irradiated capsule.

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Figure 3 shows a thermal image of the water canal above the capsule after irradiation for four days. In general, the emissivity of the water surface at nearly ambient temperature approaches unity and the radiation temperature of the water measured by thermography becomes equal to the real temperature of the surface. The thermal image of the water surface in the canal becomes uniform before the transfer operation. However, thermal images of the canal water near the irradiated capsule show that the surface temperature of the water above the irradiated capsule becomes nonuniform and exceeds water temperature without the capsule (Fig. 3). A temperature rise of +0.1 K (0.1 째C = 0.18 째F) observed on the water surface above the capsule indicates the warming of the water because of radiation decay heating of the irradiated capsule. The decayed heat becomes negligibly smaller than that generated just after the irradiation.

Continuous monitoring on the water surface of the canal using the infrared thermography is useful to monitor the decay heat behavior of the irradiated capsule. Thermographic data on the temperature rise of the capsule make it possible to determine the time to transfer the irradiated capsule from the canal.

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FIGURE 3. Thermograms of water surface with irradiated capsule: (a) left; (b) right.

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FIGURE 3. Thermograms of water surface with irradiated capsule: (a) left; (b) right.

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Radioactive Decay

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3.2 Continuous Monitoring of Cooling Tower under Reactor Operation A water cooling removes the heat generated in the nuclear reactor and transmits it to the air. The cooling tower consists of four cross flow and draft units that remove the thermal heat of 12.5 MW per unit. The flow rate of the water is 3900 m3·h–1. The cold ambient air supplied from the bottom intake of the tower flows upward. The injected water droplets are cooled by evaporation and flow down to the bottom of the pool. Hot water at about 315 K (42 °C = 108 °F) in inlet is flashed from the upper nozzle and transfers its heat to the cold air. The outlet temperature of the water becomes 306 K (33 °C = 91 °F) as the evaporation of the water droplets heat the air. As fine water droplets cover the wooden cooling panel, the measured radiation temperature of the outer wall of the tower becomes equal to the real temperature.

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Figure 4 shows thermograms, or thermal images, of the cooling tower units.

Three cooling units (the first, third and fourth from the left) are in operation and the second unit from the left in suspension to control the removable power. The surface radiation temperatures of the center panel of the four units are, from the left, 312.5, 313.2, 312.6 and 312.4 K (39.4, 40.1, 39.5 and 39.3 째C; 102.9, 104.2, 103.1 and 102.7 째F). The panel temperatures of the first, third and fourth units from left are lower than that of the second one, in suspended operation. The surface temperature difference between the surface temperature of the panel in operation and one in suspension becomes 0.7 K (0.7 째C = 1.3 째F), because a panel in operation releases heat by evaporation. To summarize, thermographic temperature measurements are useful for qualitative evaluation of the operating condition of the nuclear reactor from the exterior of the reactor installation. Continuous monitoring of the radiation temperature of the cooling tower unit uses thermography to evaluate the operating condition of the reactor. Infrared thermography can also be used remotely to assess the heat removing capacity of the cooling towers during operation from a location safe from radiation.

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FIGURE 4. Cooling towers under reactor operation: (a) left, units 1 and 2; (b) right, units 3 and 4.

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FIGURE 4. Cooling towers under reactor operation: (a) left, units 1 and 2; (b) right, units 3 and 4.

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3.3 Detection of Overheating of Main Circulation Pumps The thermal output of 50 MW is removed from the reactor core to the secondary loop through a heat exchanger. Main circulation pumps with a flow rate of 556 L·s–1 (2000 m3·h–1 = 19.6 ft3·s–1) and a water pressure head of 60 m (197 ft) are installed in the secondary circulation loop of the reactor to circulate the cooling water. Three pumps are connected to the main piping system in parallel. Figure 5 shows the thermography of the vertical flange of the pump shaft 85 mm (3.4 in.) in diameter, which connects the motor and pump casings by a driven shaft. The upward vertical shaft is connected to the driving motor and downward shaft of the pump impeller by a flange. Figure 5a shows the flange and shaft in operation and Fig. 5b shows them in suspended operation.

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FIGURE 5. Thermography of main circulating pump: (a) operating; (b) idle.

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FIGURE 5. Thermography of main circulating pump: (a) operating; (b) idle.

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Radiation temperatures of the lower flange and shaft under the operation are 308.7 K (35.5 °C = 95.9 °F) and 316.7 K (43.5 °C = 110.3 °F), respectively.

The temperature of the shaft is higher than that of the flange. The circulating water absorbs heat by conduction. The temperature difference between the temperature of shaft and flange is ±8 K (8 °C = 14.4 °F). Temperatures of the lower flange and shaft in suspended operation are 305.3 K (32.1 °C = 89.8 °F) and 304.3 K (31.1 °C = 88.0 °F), respectively.

The temperature of the shaft is lower than that of the flange because the water is not flowing. The radiation temperature difference ΔT between the shaft and flange is 1 K (1 °C = 1.8 °F). Two pumps are always circulating during reactor operation and the third auxiliary pump is on standby. When one of the main pumps stops because of a malfunction, the auxiliary pump immediately starts up so that the reactor continues to be operated continuously without a decrease in water flow rate. The temperature distribution of the shaft and flange is continuously recorded by an infrared radiometer. The thermographic system is useful for detecting abnormal conditions of pump components, like excess heating of the driving motor, misalignment of the shaft flange, water leakage from the sealing unit and so on.

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3.4 Reactor Canal Wall Maintenance The canal pool connects the reactor container to the hot laboratory to transfer the irradiated fuels and materials through the water canal. The water canal is directly connected from the reactor core to the hot laboratory. Predictive maintenance work has been carried out to inspect for deterioration of the outside concrete wall of the canal. Figure 6 shows the thermography of the east concrete wall of the canal taken from the outside area of the canal building in the morning and evening. The wall is heated by the sun in the morning and cooled as the wall radiates in the evening. The thermal images show several streaks in the radiation temperature on the wall, streaks invisible to the naked eye. The temperature of the streaks is higher than that of the wall surface in the morning and vise versa in the evening. These streaks on the wall were caused by a mortar layer applied during repair work several years before, because surface cracks on the concrete wall had developed through environmental deterioration.

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FIGURE 6. Reactor canal wall: (a) at 10:00 a.m.; (b) at 16:40.

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FIGURE 6. Reactor canal wall: (a) at 10:00 a.m.; (b) at 16:40.

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The concrete cracks under the mortar layer are filled with air. Thermal conductivity ka of air is less than thermal conductivity kc of the concrete.

Thermal image analysis is carried out by numerical calculation to solve the two-dimensional conduction equation. The analysis predicts that the temperature difference of the streak on the wall is caused by the difference of the thermal conductivity between the concrete and air in the crack. If the water permeates into the buried crack through the mortar layer, the radiation temperature of the streaks is lower than that of the wall in the morning and vise versa in the evening, because the thermal conductivity of the water is larger than that of the air.

The positive and negative temperature differences induced on the surface above a crack in the morning and evening indicate the location and dimension of the crack and whether it contains water. Thermography and the related thermal image analysis are useful tools of predictive maintenance for detecting cracks, determining their dimensions, determining whether they are filled with air or water and monitoring crack growth.

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PART 4. Infrared Thermography for Nuclear Fusion Reactor 4.0 Introduction Research and development projects have been carried out to develop the International Thermonuclear Experimental Reactor to maintain continuity with Tokamak type reactors and to develop fusion plasma technology. The armor of the first wall and diverters of the fusion reactor are fabricated from high temperature materials to be resistant against the plasma of 1 × 108 K (about 1 × 108 °C = of 1.8 × 108 °F) in a high vacuum.17 The role of the diverters reduce the amount of plasma flowing directly into the first wall as a result of plasma disruption. Plasma disruption would take place if the plasma in the fusion reaction confined by the magnetic field were disrupted for any reason.

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Fusion Reactor

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Fusion Reactor

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Fusion Reactor

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Fusion Reactor

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Fusion reaction is maintained by controlling the magnetic field around the diverter in such a way that the impurities in the plasma and those generated during the control procedure are removed through the diverter. The normal operation period of the reactor is 2000 s per pulse. The heat flux originating from the plasma, which is to be 1 MW·m–2 at its maximum, is injected into the first wall and the diverter at 400 K (127 °C = 260 °F) and at 1200 K (927 °C = 1700 °F), respectively. It is essential to control impurities in the plasma to maintain the operation temperature. The diverter absorbs gas impurities on its surface at high temperatures. Diverter plates are installed at the bottom of the doughnut shaped vacuum vessel of the fusion reactor. One design for the diverter is for carbon-to-carbon composite armor tiles brazed to copper heat sink plates. The armor tile is required to be made of materials with high thermal conductivity and good thermal shock resistance.

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The composite-to-copper joint structure of the diverter is required to maintain its structural integrity under high thermal loads. In the event of plasma disruption armor tiles may be exposed to high heat flux of 100 to 200 GW·m–2 (3.17 × 1010 BTUTC·h–1·ft–2) for a very short period, suffering some damage.

Damaged tiles must be replaced. Research and development determines the optimum design for replacement technology as well as for inspection after the replacement. Infrared thermography can be used for remote nondestructive testing of the diverter joint structure. Model diverter specimens are heated using a halogen lamp, high temperature combustion gas or hot water. The heating technique using the hot water is best for the nondestructive test of the diverter joint structure.

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4.1 Radiation Properties of Carbon-to-Carbon Composites A schematic of experimental apparatus for measuring radiation temperature of carbon-to-carbon composites is shown in Fig. 7. A plate specimen is placed on the plate heater. Temperature of the specimen Ts is controlled from 303 K (30 °C = 86 °F) to about 373 K (100 °C = 212 °F) with a gradient of 10 K (10 °C = 18 °F). A water tank with a pyramidal hood is placed in the space between the specimen and aninfrared radiometer. The interior of the hood is lined with black velvet to approximate a blackbody surrounding with a constant temperature. The ambient temperature Ta is controlled by changing the water temperature in the tank. After Ts and Ta are kept constant, the radiation energy from the specimen surface is measured to obtain data on its emissivity and radiosity coefficient. On one side of the hood an infrared radiometer whose sensor is cooled with liquid nitrogen measures the radiation energy in the wavelength range from 8 to 13 μm to give a twoimensional thermal image on a television monitor or cathode ray tube.

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FIGURE 7. Radiometric test apparatus.

Screen

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The temperature of the specimen surface is determined by using K type thermocouples embedded to the side of the specimen. The energy Js flowed into the sensor from the specimen surface and the surrounding wall is expressed by the following equation, taking into account the wavelength dependence of the radiometer. (Eq.1)

Here, Ts is apparent radiation temperature, εs is emissivity, ρs is reflectivity, subscript s indicates the specimen and σ is the Stefan-Boltzmann constant.

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The radiation temperature measured by the radiometer is determined by the energy radiated from the specimen surface which includes both the energy inherent to the specimen and that incident on the specimen from its surroundings. If the gray color approximation is assumed, that is, ﾎｵs + ﾏ《 = 1, emissivity is generally obtained from the equation: (EQ.2)

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The relation between the true temperature and emissivity is shown in Fig. 8 for the carbon-to-carbon specimen surface. Open symbols represent values calculated on the basis of the radiosity coefficient for the carbon-to-carbon composite. The emissivity of the surface decreases with increasing true temperature of the specimen. Experimental data obtained at environmental temperatures of 298, 303 and 313 K (25, 30 and 40 째C; 77, 86 and 104 째F) for the carbon-to-carbon composite are fitted to a solid line. The solid line in the figure represents the relationships obtained by a least squares technique: (EQ.3)

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FIGURE 8. Emissivity of carbon-to-carbon composite.

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FIGURE 8. Emissivity of carbon-to-carbon composite.

The radiation temperature differs from the true temperature of the surfaces of the carbon-to-carbon composite and differs also for a surface painted black.

Radiation temperatures were measured at environmental temperatures of 298, 303 and 313 K (25, 30 and 40 째C; 77, 86 and 104 째F) for carbon-to-carbon composite and again for black paint. The radiation temperature of the black paint is nearly equal to the true temperature. For the carbon-to-carbon composite, however, the difference between radiation temperature and the true temperature increases with increasing true temperature.

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4.2 Test Apparatus Using Artificial Heaters A configuration of model diverter specimens with a cooling tube is shown in Fig. 9. These specimens consist of carbon-to-carbon composite tiles brazed to the copper heat sink with different brazed area ratios. The tile is composed of a carbon fiber reinforced composite with high thermal conductivity, as shown in Table 1. To prepare the joint of carbon-to-carbon composite tiles and copper heat sink, the model specimen is heated in a vacuum furnace at 1120 K (847 °C = 1556 °F). The separation area ratio is defined by the ratio of the unbrazed area to the total tile area. Separation area ratios of the tiles are 100, 75, 50, 25 and 0 percent. Three types of model specimens shown in Figs.

9a, 9b and 9c are used in this experiment. The test specimens were heated using a halogen lamp, high temperature combustion gas or hot water.20 The radiation temperature distribution on the tile surface of the specimen is measured by an infrared radiometer covering a wavelength range from 8 to 13 Îźm.

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TABLE 1. Thermal characteristics of carbon fiber reinforced composite.

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FIGURE 9. Configuration of model divertor specimen: (a) side view of specimen 3; (b) unbrazed ratio of specimen 1; (c) unbrazed ration of specimen 2; (d) unbrazed ratio of specimen 3.

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FIGURE 9. Configuration of model divertor specimen: (a) side view of specimen 3; (b) unbrazed ratio of specimen 1; (c) unbrazed ration of specimen 2; (d) unbrazed ratio of specimen 3.

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FIGURE 9. Configuration of model divertor specimen: (a) side view of specimen 3; (b) unbrazed ratio of specimen 1; (c) unbrazed ration of specimen 2; (d) unbrazed ratio of specimen 3.

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FIGURE 9. Configuration of model divertor specimen: (a) side view of specimen 3; (b) unbrazed ratio of specimen 1; (c) unbrazed ration of specimen 2; (d) unbrazed ratio of specimen 3.

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The minimum detectable temperature difference of the radiometer is ±0.2 K (0.2 °C = 0.36 °F). A schematic of the experimental apparatus for heating with a halogen lamp is shown in Fig. 10a. The halogen lamp with a gold plated parabolic reflector projects thermal radiation on the specimen. The infrared radiometer measures the radiation temperature of the specimen for 1 s with a heating duration of 8 s after a shutter in front of the specimen is removed. The lamp provides a step function heat pulse of about 10 kW·m–2 (3172 BTUTC·h–1·ft–2). A schematic of the experimental apparatus for a heating means using high temperature combustion gas is shown in Fig. 10b.

Combustion gas at 400 to 430 K (127 to 157 °C; 260 to 315 °F) is directed onto the specimen by a gas heater after the shutter in front of the specimen is removed. Heat flux applied to the tile of the test specimen is about 5 kW·m–2 (1600 BTUTC·h–1·ft–2) at maximum.

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A schematic of an experimental apparatus for the hot water technique is shown in Fig. 10c. The specimen is placed in contact with the hot and cold water jackets enclosed by the insulation plate. The specimen is mounted in front of the infrared radiometer. The cooling tube is initially filled with water of 283 K (10 째C = 50 째F). The specimen is heated by flowing warm water of 303 K (30 째C = 86 째F) in the cooling tube. Thermal images of the tile surface are obtained by the infrared radiometer from 1 to 8 s after the start of heating.

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FIGURE 10. Test setups for heating techniques: (a) heating with halogen lamp; (b) heating with high temperature gas; (c) heating with hot water.

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FIGURE 10. Test setups for heating techniques: (a) heating with halogen lamp; (b) heating with high temperature gas; (c) heating with hot water.

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FIGURE 10. Test setups for heating techniques: (a) heating with halogen lamp; (b) heating with high temperature gas; (c) heating with hot water.

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4.3 Detection Limit of Brazed Tile Elements ■ Halogen Lamp Heating Test Thermal images obtained by the heating technique using the halogen lamp for the tiles with separation area ratios of 100, 75, 50 and 0 percent at 8 s after the start of heating are shown in Fig. 11. The difference ΔT between the radiation temperatures becomes 3.8, 1.7 and 0.9 K (3.8, 1.7 and 0.9 °C; 6.8, 3.0 and 1.6 °F) depending on the separation area ratios. Difference ΔT becomes larger with increasing separation area ratio because the separation layer is filled with air and thermal flow through this area decreases compared with that through brazed area. The radiation temperature distribution on the tile surface along the cursor line has been measured with the heating time as a parameter. The temperature distribution of the tile of 100 percent separation becomes convex at 2 s after the start of heating and the difference between the maximum and minimum temperatures on the distribution increases with increasing heating time.

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FIGURE 11. Thermal images of model divertor specimen 8 s after start of heating by halogen lamp: (a) specimen 1; (b) specimen 2; (c) specimen 3.

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FIGURE 11. Thermal images of model divertor specimen 8 s after start of heating by halogen lamp: (a) specimen 1; (b) specimen 2; (c) specimen 3.

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FIGURE 11. Thermal images of model divertor specimen 8 s after start of heating by halogen lamp: (a) specimen 1; (b) specimen 2; (c) specimen 3.

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■ Hot Gas Heating Test Thermal images obtained by the heating technique using high temperature combustion gas for the tiles with separation area ratios of 100 percent and 0 percent are shown in Fig. 12. The difference ΔT between the temperature of tiles of 100 percent and that of 0 percent becomes ±1.4 K (1.4 °C = 2.5 °F) at the maximum. However, ΔT between the temperature of tiles of 75, 50 and 25 percent and that of 0 percent becomes zero, giving no detectability for these tiles. Moreover, the radiation temperature distribution on the tile surface is not uniform because of turbulent jet flow of gas. Stable temperature distribution on the thermal image is measured at 60 s after the start of cooling. In this case, the temperature of tile with 100 percent separation area at 60 s after the start of cooling becomes smaller than that of 0 percent separation because of the heat released from the tile to ambient air during cooling.

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FIGURE 12. Thermal images of model divertor specimen heated by high temperature gas: (a) 60 s after start of heating; (b) 3 s after start of cooling; (c) 60 s after start of cooling.

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FIGURE 12. Thermal images of model divertor specimen heated by high temperature gas: (a) 60 s after start of heating; (b) 3 s after start of cooling; (c) 60 s after start of cooling.

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FIGURE 12. Thermal images of model divertor specimen heated by high temperature gas: (a) 60 s after start of heating; (b) 3 s after start of cooling; (c) 60 s after start of cooling.

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■ Hot Water Heating Test Thermal images obtained by the heating technique with hot water for the tiles at 1 and 8 s after the start of heating are shown in Fig. 13. The temperature difference of the 100 percent separation tile becomes smaller than that of 0 percent and 75 percent separation tiles. Therefore, both tiles with separation area ratios of 0 percent and 25 percent are detectable by thermography.

Values of ΔT for tiles of 100 percent separation are 3.8 K (3.8 °C = 6.8 °F).

Values of ΔT for tiles of 75 percent separation are 1.0 K (1.0 °C = 1.8 °F).

The tiles with 50 percent and 25 percent separation can be detected from the temperature difference ΔT smaller than that for 100 percent separation.

Values of ΔT are 0.4 and 0.3 K (0.4 and 0.3 °C; 0.7 and 0.5 °F) for 50 and 25 percent, respectively.

The radiation temperature distribution of the tile surface along the cursor line is shown in Fig. 14 with heating time as a parameter. The temperature distribution of the tile of 100 percent separation becomes concave at 2 s after the start of heating and the difference between the maximum and minimum temperatures on the distribution increases with increasing heating time.

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FIGURE 13. Thermal Images of model divertor specimen heated by hot water: (a) 1 s after start of heating; (b) 8 s after start of heating.

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FIGURE 13. Thermal Images of model divertor specimen heated by hot water: (a) 1 s after start of heating; (b) 8 s after start of heating.

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FIGURE 14. Radiation temperature distribution of tile surface heated by hot water.

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4.4 Image Analysis of Internal Separations in Brazed Tiles Image analysis is carried out numerically to determine the temperature distribution around an internal discontinuity in the brazed tile element. A nonsteady heat conduction equation of a composite model is solved by a differential control volume technique.21 Temperatures of armor tiles with and without the separation have been numerically calculated and experimentally measured. Numerical calculations of temperature changes are close to experimental data. Figure 15 summarizes the heat flow and generated temperature distribution around the internal separation. The difference ΔT between the temperature of the surface above the internal separation and that of the surface of the brazed area is caused mainly by the difference in thermal conductivity between the composite material km and the separation kd. The temperature distribution on the surface during the heating and cooling becomes convex and concave, respectively, because thermal conductivity km of the composite is larger than thermal conductivity kd of the separation.

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FIGURE 15. Heat flow and temperature distribution through specimen of material with conductivity km around internal discontinuity of conductivity kd: (a) heated surface, km > kd; (b) cooled surface, km > kd; (c) heated surface, km < kd; (d) cooled surface, km < kd.

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FIGURE 15. Heat flow and temperature distribution through specimen of material with conductivity km around internal discontinuity of conductivity kd: (a) heated surface, km > kd; (b) cooled surface, km > kd; (c) heated surface, km < kd; (d) cooled surface, km < kd.

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4.5 Detection Performance with Three Heating Means Detection performance is summarized in Table 2 for the three active heating means where the separation area ratio is chosen as a parameter. The halogen lamp technique can detect separation up to 50 percent. The combustion gas technique can detect 100 percent separation. The hot water technique can detect all the separations examined here. The heating time is a parameter in obtaining the absolute value of the difference in the surface temperature between tiles with 100 percent and 0 percent separations. The absolute value has been obtained by numerical computation using the difference technique for the nonsteady heat conduction equation. Heating and boundary conditions of a numerical computation for a conceptual model is the same as that of the present experiments. Numerical data for heating using the halogen lamp, high temperature gas and hot water are shown in solid, broken and dotted lines, respectively. The temperature difference increases with increasing heating time.

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TABLE 2. Detector performance for separation area ratio of three active heating techniques, with temperature difference Î&#x201D;T.

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The temperature difference obtained by the hot water technique is the greatest among the three techniques. The tendency of the absolute difference in the temperature obtained from the numerical computation is in accord with the experimental results of the detection performance for three heating means (Table 2).

The hot water technique is the most appropriate for the nondestructive testing of the diverter joint structure with cooling pipes, judging from its detectability and the simplicity of the apparatus for the measurement. This technique is believed to be applicable to the nondestructive testing of the diverter of nuclear fusion reactors. Although only some examples of fusion reactor components have been described in this paragraph, it is believed that the present technique can be applicable to any discontinuities in the weldments and brazed joints in any components. In this sense the technique has a wide variety of possible applications.

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PART 5. Infrared Thermography of Power Generation Subsystems 5.1 Thermography of Boilers Infrared and thermal testing has the advantage that it is non-contacting and can rapidly inspect large areas of a component. The method is therefore ideal for the inspection of boilers and process heaters used in steam generation power plants. Here, temperatures are high and access is generally limited to one side of the boiler or boiler tube. Infrared thermography has a prominent role in the nondestructive testing of electrical generating plants.

Thermography can detect high resistance (faulty) electrical connection problems and overloads. Thermal techniques are used to locate problems in boilers and process heaters.

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Technological advances in infrared thermography can save time and money in the power generation industry. Infrared cameras are sensitive to wavelengths of radiation in the 2 to 14 Âľm region of the electromagnetic spectrum. They convert this heat energy to a visible light display, which a trained operator (thermographer) analyzes and documents. Qualitative thermography is used to locate significant heat differences, whereas quantitative thermography assigns accurate temperatures to the problems found. Because many developing problems in machinery increase temperature, thermography is an ideal tool for predicting when a component is approaching failure.

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â&#x2013; Boiler Applications Boilers are vessels used to transfer heat from the fire to water flowing through the boiler tubes. As such, their efficient and safe operation depends on several factors. First, the boiler must be insulated to minimize heat loss through the walls and to protect the tube surfaces on the combustion side.

Second, the vessel should be as airtight as possible to prevent uncontrolled air from entering or exiting. Third, the water in the tubes must be unrestricted to prevent overheating and to allow for maximum heat transfer. Infrared thermography can play a key role in ensuring the performance of these three functions of a boiler.

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â&#x2013; Insulation Boiler insulation, called refractory, can fail in various ways. The refractory can pull away from the walls and fall onto the boiler floor. Other times, the brick or batt insulation separates from its wall anchors, allowing the hot gases to flow behind the insulation. When a boiler is inspected with infrared thermography from the outside, these failures show up as hot spots, provided there is not an air space between the external cladding and the insulation. Figure 16 shows such a hot spot, which has been marked with paint on the outside of the boiler.

This hot spot, will be monitored on a regular basis to track deterioration, which is indicated by an increasing skin temperature. Engineers set maximum temperature limits at which the metal will be permanently damaged or a burn through is imminent. The goal is to monitor the problem and keep the boiler safely on line until the next scheduled shutdown. Before the shutdown, engineers will use the thermographic data to determine the extent of damaged refractory so that maintenance workers can order repair materials and accurately schedule crews to minimize the downtime. Savings can be tremendous and the safety of boiler operation and attendant workers is ensured.

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FIGURE 16. Damaged refractory on inside of this boiler has created skin temperature of 465 K (192 째C = 377 째F): (a) photograph; (b) thermogram.

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FIGURE 16. Damaged refractory on inside of this boiler has created skin temperature of 465 K (192 째C = 377 째F): (a) photograph; (b) thermogram.

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â&#x2013; Boiler Casing Leaks Boiler casing leaks can be a serious and costly problem for power plants. In positive pressure systems, ash and coal can emerge through tiny pinholes in the boiler to erode boiler tubes and reduce efficiency. These leaks are often very difficult and time consuming to detect visually. However, these pinholes leak very hot combustion gases, which in turn heat up the external cladding of the boiler. Thermographers can detect these hot air leaks, which have a different pattern than conduction problems caused by damaged insulation.

The outer covering and insulation are removed and the leak is located and repaired, saving significant amounts of troubleshooting time and increasing boiler efficiency and tube life. As a side benefit, before and after thermograms can be taken (see Fig. 17) to give repair crews proof that the job was (or was not) properly done. Worker morale and quality of repairs increases when inspection reports are provided with infrared thermography. Besides casing leaks, air can escape from the boiler at other locations, such as expansion joints, access doors and view ports. Infrared thermography is suited for locating these hot air leaks, too.

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FIGURE 17. Thermograms prove that repairs have corrected boiler casing leak: (a) before repair; (b) after repair.

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FIGURE 17. Thermograms prove that repairs have corrected boiler casing leak: (a) before repair; (b) after repair.

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■ Boiler Tube Blockages As mentioned previously, water within the boiler tubes must flow freely to permit efficient heat transfer. When foreign materials inside a tube impede this circulation, the tube overheats and, if hot enough, will burst and force an unscheduled shutdown. Tube temperatures can be monitored when the boiler is in operation (as discussed later) but often many of the problems occur when bringing the boiler back on line after a shutdown. Failure analysis of many of these failures has yielded some interesting findings. Many of the blockages are caused by improper paper left in the tubes by welders after they have completed their repairs. When the boiler is brought back on line, scale or magnetite is trapped by this paper, creating flow restrictions. One power company has used thermography before boilers are brought back on line. Condensate at 366 K (93 °C = 200 °F) is cycled through the tubes and viewed with an infrared camera from inside the boiler. Figure 18 shows a tube that is cooler (darker) than the adjacent tubes, indicating a fluid flow restriction. After implementing a thermographic inspection program, the company saved millions of dollars because virtually no premature failures have been caused by ruptured tubes.

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FIGURE 18. Dark boiler tube in center is cooler because 366 K (93 째C = 200 째F) condensate flow is blocked.

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â&#x2013; Overview of Boiler Applications Infrared thermography can be used to increase the efficiency and safety of boilers in generating plants. Successful programs require highly trained infrared thermographers who are knowledgeable about the construction and operation of these vessels. Some of the applications described are physically demanding and require specialized equipment but the returns on the investment will pay for the inspection program many times over.

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5.2 Temperature Modulation Case History of Closed Cooling Heat Exchanger A closed cooling heat exchanger at a generating station did not properly control shell side water temperature under certain conditions. It was hypothesized that the source of the problem was a leaking three-way valve.

Infrared thermography was used to confirm this hypothesis. The results of the investigation proved, first, that the three-way valve was not leaking. Using the same technology, the investigation went on to definitively prove that the problem was actually the configuration of the bypass line from the three-way valve back to the heat exchanger outlet. The purpose of the heat exchanger is to cool various critical mechanical loads within the plant, with a minimum required shell side temperature of 286 K (13 째C = 55 째F). The tube side of the subject heat exchanger is cooled by circulated water from a nearby lake.

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This provides a direct, ultimate heat sink for the water on the shell side (Fig. 19a). A recent design change installed a three-way valve for the purpose of modulating shell side water flow rate through the heat exchanger (the rest bypassing it), thus controlling the temperature of the water in the shell side. In the winter months when the lake temperature is near 273 K (0 째C = 32 째F) and minimum loads are on the heat exchanger, the temperature of the water in the shell side cannot be maintained above 286 K (13 째C = 55 째F), even with the three-way valve in the full bypass position (Fig. 19b).

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FIGURE 19. Heat exchanger: (a) without shell side bypass; (b) with shell side bypass.

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FIGURE 19. Heat exchanger: (a) without shell side bypass; (b) with shell side bypass.

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â&#x2013; Infrared Testing Initially, the obvious and reasonable explanation for the anomaly seemed to be that the bypass valve was not sealing tightly when fully closed, allowing shell side water to pass through the shell. This hypothesis conveniently and easily explained how the water was being cooled even when in full bypass.

Given the fact that the bypass valve was new and would be very costly to replace, the prudent course of action was to prove this theory before valve replacement could be considered. Thermography was determined to be the technology that would most likely be able to validate the theory. The technology is fast, cost effective, non-intrusive and ideally suited to the very thermal nature of this investigation. A test was devised to verify the isolation capability of the three-way valve. In the three-way valve, the shell side water enters from the left and is modulated straight through (to the right) into the heat exchanger shell or is diverted to bypass (down). The nature of the test was to circulate warm shell side water with the three-way valve in the full bypass position. At the same time cooler lake water would be circulating through the tube side. Infrared imaging of the valve body would show the characteristics of the resulting temperature differential across the valve and therefore the degree of integrity of the valveâ&#x20AC;&#x2122;s seating surface.

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At the time of the test, lake water temperature was at about 289 K (16 °C = 61 °F). Before the test, the cold lake water was allowed to circulate through the tubes, cooling the stagnant water in the heat exchanger shell to 289 K (16 °C = 61 °F). The shell side water in the rest of the system was also left static and in thermal equilibrium with the environment 294 K (21 °C = 70 °F). The thermal imaging system was trained on the valve before the test was started, with the analog color output routed to a video recorder. The shell side pump was then started in full bypass, circulating the warmer shell side water through the bypass side of the three-way valve and on to the rest of the system. Thermography proved that the shell side water was not flowing into the heat exchanger shell through the three-way valve when in full bypass.

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This revelation regarding the integrity of the three-way valve suddenly made the issue much more complex. What was causing the cooling of the shell side water? Fortunately, the answer was not far away. At the end of the test described above, a thermal scan was conducted on the entire heat exchanger and local piping. An anomaly was discovered at the heat exchanger outlet that appeared to hold the answer. The piping configuration at the heat exchanger discharge is shown in Fig. 20a. The shell side discharge is at the right side of the picture, traversing out and immediately into a T. The bypass flow from the three-way valve traverses in from the lower left of the picture, rising and turning into the same T. These two flows join in the T, constituting the shell side return traversing to the left and then up.

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FIGURE 20. Shell side discharge piping: (a) visible light photograph; (b) thermogram at â&#x20AC;&#x201C;9 min; (c) thermogram at +5 min.

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FIGURE 20. Shell side discharge piping: (a) visible light photograph; (b) thermogram at â&#x20AC;&#x201C;9 min; (c) thermogram at +5 min.

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FIGURE 20. Shell side discharge piping: (a) visible light photograph; (b) thermogram at â&#x20AC;&#x201C;9 min; (c) thermogram at +5 min.

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Once again, the 289 K (16 °C = 61 °F) lake water was allowed to circulate through the tubes and cool the stagnant shell side water. And as before, the shell side water was left at thermal equilibrium with the environment at 294 K (21 °C = 70 °F). This time, however, the thermal imaging system was trained at the shell side discharge. The analog color output was again directed to video recording. The shell pump was then started with the system in full bypass, circulating the warmer shell water through the bypass side of the three-way valve and on to the rest of the system. Figures 20b and 20c show the thermal image at time T = –9 min and T = +5 min, respectively. Upon examination of these thermal images, there are several observations worthy of note. The first is the obvious warming of the shell side return line, caused by the warmer water traversing the bypass line. Second, it should be noted that the overall shell temperature does not appear to have changed. The third and most significant observation is the warm area that appears above and around the shell side exit pipe. The real time video tape shows this area forming seconds after the start of the shell side pump, starting as a stripe running straight up the shell.

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Figure 20a indicates the path that the bypass flow had to follow to get back to the shell side return line. The water must navigate two quick 90 degree turns to make the return. After that first turn, this high velocity water would more likely take the short straight path straight into the heat exchanger. Despite the fact that this path was dead headed, it is apparent that this was occurring.

Figure 21 represents the phenomenon schematically. It is unknown whether or not mass exchange (water mixing) was actually occurring because this has been argued as a very unusual situation. It is clear, however, that a thermal exchange was occurring between the bypass water and the water in the shell.

The magnitude of this interaction was so significant that the shell side return water temperature could not be maintained above the required minimum in winter.

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FIGURE 21. Thermal mixing in shell of heat exchanger.

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■ Case History Summary The closed cooling heat exchanger in this case history did not maintain shell side water temperature above the required minimum of 286 K (13 °C = 55 °F) when lake temperature was near freezing. For this specific situation, it is definitively proven that the cause was not a leaking or malfunctioning threeay valve. It has also been shown that the cause of the problem was the piping configuration at the heat exchanger shell side discharge. This configuration caused shell side bypass water to exchange heat with the cooler water inside the shell, lowering the overall shell side water temperature below the minimum required.

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5.3 Detection of Wall Thinning in Service Water Piping Service water piping systems at electric power plants provide cooling for a variety of safety and nonsafety related components and systems. Reliability of service water piping systems is a key consideration for safe and reliable plant operations. Under accident conditions in a nuclear power plant, the service water piping system provides cooling water to components and systems that are critical to a safe plant shutdown.25 Assessing integrity of the service water piping system includes detection and analysis of pipe wall thinning.

Conventional test methods usually entail the time intensive process of ultrasonic thickness measurements, based on a grid system, of the entire pipe length. An alternative to this process may lie in the use of active infrared thermography techniques for detection of thin wall areas in the pipe. Infrared thermography has been widely used by utilities for a variety of predictive maintenance applications including evaluation of mechanical, electronic and electrical components.

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These applications use infrared and thermal testing in a passive mode to identify anomalies in the characteristic thermal pattern of an operating component in order to determine its suitability for continued service. Unlike these components, service water piping has no faulty electrical connections, misaligned bearings or other discreet, inherent sources of thermal energy to be observed. For assessment of service water piping, an active infrared technique, thermal injection, can be used.26,27 This process involves injection of a controlled amount of thermal energy into the exterior pipe wall.

Anomalies in the resultant thermal pattern, as detected by the infrared system, are then evaluated to determine their origin. Similar infrared nondestructive test techniques have been successfully used for evaluation of composite materials in the aerospace industry. Application of these infrared nondestructive testing techniques for material evaluation can provide rapid screening for identification of thin wall areas in service water piping.

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A preliminary evaluation of this technology was conducted on mockups at Vermont Yankee Nuclear Power Plant. Based on the promising results, the infrared thermal injection technique was optimized for service water piping applications. The primary goals of this effort were to determine the practical depth resolution capabilities of the thermal injection technique in carbon steel and also to minimize the effects of pipe curvature on detection capabilities.

Both of these efforts were subject to the constraint that the system be sufficiently portable for use in an electrical power plant, where space and access to the pipe surface is often limited. A thermographic system was used to evaluate a 9.525 mm (0.375 in.) thick, flat carbon steel plate and 0.3 m (12 in.) diameter, schedule 40 pipe. (Schedule 40 pipe is black, galvanized pipe made for ordinary uses in steam, water, gas, and air lines according to ASTM A 53.28) Back drilled holes in both targets, ranging in diameter from 1.59 to 6.35 mm (0.0625 to 0.250 in.) and depths representing about 10 to 90 percent through-wall loss, were used to simulate wall thinning. Evaluation of the flat plate indicated that targets with a specified diameter-to-depth ratio can be reliably detected using the thermographic system. A similar evaluation of the 0.3 m (12 in.) diameter pipe was completed to address curvature effects on detection capabilities.

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Initial investigation of the pipe mockup indicated a significant drop in returned thermal energy away from the longitudinal axis of the pipe and therefore a significant loss of detection capability for areas beyond Âą30 degrees of top dead center. Two modified flash hoods, using reflective schemes to optimize both energy input to the off-axis regions of the pipe and to increase energy input to the camera from these regions, were constructed and tested. The larger unit, using strategically located gold front surface mirrors for both input and output coupling, increased the effective detection angle to Âą50 degrees and was able to remove spatial distortion on the peripheral regions of the pipe.

A smaller unit that used reflectors for increased input coupling provided a coverage angle of only Âą40 degrees but without compensation for curvature effects on the periphery of the pipe. Although the larger unit offered better performance with respect to curvature compensation, the smaller unit offered better resolution of deeply buried targets.

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As a followup to the laboratory investigation, this infrared system and thermal injection technique will be applied at an operating nuclear power plant for verification of test techniques and detection capabilities on service water piping systems.

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PART 6. Infrared Thermography for Distribution Systems 6.1 Applications for Thermographic Software Municipal electric power distribution systems are often built underground and use different components from those of the bulk power system. Infrared surveys for these systems require a portable and smart infrared instrument.

Infrared surveys are an increasingly accepted method to provide early detection of incipient faults in many types of industrial plants, including large installations in the bulk electrical power system. In the 1990s, the Canadian Electrical Association conducted a research program to extend the technique for use in municipal distribution systems, which are often built underground and which use different components from the bulk power systems. An additional challenge in distribution system work is the lack of training of the linemen in infrared work. To provide assistance to relatively untrained operators, the Canadian Electrical Association sponsored development of a computer based smart infrared instrument.

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â&#x2013; Load Break Elbows Methodology development focused on load break elbows, which are designed to literally unplug the power to a shopping mall or a residential neighborhood.

Because the elbows may be unplugged with up to 27 kV still applied there is a risk of a safety incident if they are faulty. Therefore, one objective of the research project was to provide advance warning of discontinuities so that such electrical fault conditions do not occur. Load break elbows contain metal conductors inside a thick layer of rubber or plastic insulation. The insulation is used for electrical isolation but it also has thermal insulation properties.

Because of the thermal insulation, temperatures measured on the surface by an infrared camera need to be transformed into internal temperatures to assess the interior condition of the component. Heat conducted into the elbow from the transformer on which it is mounted is one of several effects that can be taken into account by mathematical modeling. In this way it can be determined if a hot spot adjacent to the transformer is caused by the transformer or by a poor electrical contact inside the elbow. Pattern recognition has been pioneered on the thermal profile scanned along the center line of an elbow to assess its condition.

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â&#x2013; Modeling Software has been developed to take thermograms with a computer vision system and to analyze them in terms of a thermal model. This analysis amounts to a preprocessing stage, which presents condensed results to a decision making routine. A decision making routine to classify suspect components into one of four categories has been tested on actual good and anomalous load break elbows. Work has been done on cooling by wind. A significant effect due to wind direction has been noted on insulated components in addition to the effect of wind speed. (For uninsulated, all-metal components such as bolted clamps on overhead power lines, it is expected that the lee side and the windward side would have the same temperature.)

Solar heating has also been modeled. Simulations demonstrate that infrared radiation from the sun is reflected as well as absorbed, even for the highly absorbing outer material used on load break elbows.

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These heating and cooling effects will not apply to components in underground or room vaults but they do affect temperature measurements of the insulated components located under the cover of outdoor pad mount installations. To obtain a good estimate of temperatures before the elbow is exposed to sun or wind, the operator may focus the camera on the pad mount cover before opening it and then capture an image as soon as the cover is opened. Heating of a load break elbow by the warm transformer on which it is mounted can also be modeled mathematically. By this means, for example, it is possible to distinguish between an elevated temperature in the bushing area because of heat from the transformer and one due to high contact resistance in the knurled joint of the bushing. A potential confounding influence in infrared thermography is variations in the infrared emissivity of the surface. Such variations throw confusion into temperature readings, because the brightness of a spot in an infrared picture of an object at a given temperature is proportional to the emissivity at that spot. An emissivity study was performed on 15 load break elbows removed from service for various reasons. The final conclusion was that a standard emissivity value of 0.91 could be used for all load break elbows.

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The error in surface temperature which results from using this fixed value of emissivity is expected to be ±1 K (±1 °C; ±2 °F) or less. The fact that the apparent temperature could be ±1 K (±1 °C; ±2 °F) different from the true temperature demands a robust analysis algorithm to avoid misleading results.

The same statement holds for the environmental influences mentioned above that perturb the actual temperature. A further quantity of direct importance is the load current. Load current is difficult to ascertain in some instances. The approach taken in this project is to blend two means of analysis: temperature measurements and thermal profile recognition. Temperature measurement techniques in thermographic literature consist of absolute temperature assessment and relative temperatures, in which two or more similar components are compared. These techniques are incorporated in the software. The aging properties of the materials of construction of load break elbows have been studied to understand failure mechanisms and support decision making software based on temperature measurements.

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Another approach in the electric power industry uses pattern recognition, where the inspector seeks to understand the shape of the thermal profile scanned along the center line of a component. Shape means a scale invariant shape not influenced by, for example, overall emissivity or load current. The computational feasibility of this technique relies on separability of the problem. It has been shown that the final mathematical model can accurately be taken as a linear combination of an independent solution for each source of heat. With proof that this fundamental solution technique is accurate, a relatively simple linear regression model can be used to fit the observed thermal profile and dissect it into the various root causes of heating.

In this way, anomalous internal electrical connections can be detected. An example of the methodology is given in Fig. 22, where an anomalous load break elbow is assessed with a 50 percent fused analysis based on temperature and shape of the thermal profile. The basic steps to perform an assessment are as follows.

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1. Acquire a thermogram (infrared image calibrated in terms of temperature) and manually designate two or three key points on it to define a path along which a thermal profile should be taken (Fig. 22). This step uses the human operator to recognize the load break elbow. This is a task that a human can perform intuitively but has been hard to automate.

2. After the path has been designated, the software gathers a thermal profile by reading the temperature values along the path. To remove distance effects on the apparent size of the object, the position on the object at which each temperature reading is taken is scaled as a percentage of the distance between the key points. The actual pose or orientation of the object is not critical provided its surface is a dielectric, because then its infrared emissivity is nearly omnidirectional.

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3. Process the raw data, which consist of the thermal profile and information about the conditions under which the thermogram was obtained such as ambient temperature and wind speed. These data are preprocessed into a small number of attributes.

4. Classify the repair status of the component given its make and model, load current and the attributes generated by the preprocessor step. The output statement indicates the urgency of repair.

An expert thermographer knows when thermography is being performed outside of its limits of validity. Software can also provide warning statements

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â&#x2013; Software Summary Distribution system thermogram analysis software can incorporate repair urgency guidelines for transmission system components where the same components are used in distribution systems. In addition, a technique has been developed to handle insulated distribution system components and has been applied to load break elbows. Laboratory tests indicate that the technique is successful. Dead break tees, insulated splices and essentially all distribution system components can receive similar attention.

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6.2 Transmission Line Failures In the 1990s an electric utility in Michigan had a transmission system that consisted of 6920 km (4300 mi) of 23 and 46 kV, 5890 km (3660 mi) of 138 kV lines and 2900 km (1800 mi) of 345 kV lines. When a transmission line meets an obstruction, such as a wooded area or lake, it is rerouted around the obstruction. When the line angle is great enough, the conductors are dead ended and jumpered around. Aluminum strands can be damaged by lightning or vandalism. Before infrared and thermal testing was implemented, burnt off jumpers and full tension sleeves were a frequent cause of transmission line outages. It was decided by the transmission department to use an infrared testing company to fly in an aircraft and test 46 kV lines with a high outage history. To no oneâ&#x20AC;&#x2122;s surprise, numerous anomalies were identified and later replaced on the 46 kV system only. Higher voltages were not inspected.

However, because of the lack of inspections, many outages were related to burnt off jumpers and full tension sleeves.

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â&#x2013; Transmission Material Failures The following are cases of failed components detected by infrared thermography.

1. One compression sleeve failed as a result of installing two dissimilar materials together in an aluminum compression sleeve and joining them together with a 19 mm (0.75 in.) or 25 mm (1.0 in.) copper adapter. The cable was a 46 kV steel reinforced aluminum conductor.

2. An aluminum conductor was compressed into an aluminum sleeve. On the opposite end of the sleeve was a 25 mm (1.0 in.) copper adapter. The copper adapter was then inserted into the two-hole compression spade, bolted to a brass plate and then attached to the rack in a substation. The termination eventually failed.

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3. A tapoff point joined a 46 kV aluminum conductor steel reinforced main line and an aluminum conductor steel reinforced lateral line. The weak link in the installation was the 19 mm (0.75 in.) copper adapter that joined the three aluminum conductors.

4. A termination consisted of a 46 kV aluminum conductor steel reinforced cable inserted into an aluminum two-hole compression spade. The spade was then bolted with steel bolts and nuts to a brass plate on the air break switch. The failure was attributed to not using a bimetallic plate between two dissimilar metals. The failed termination was removed from an air break switch feeding a substation in a highly populated industrial and commercial area.

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5. Transmission lines constructed several years ago were designed without a static wire to protect them from lightning strokes. Later, new lines were constructed with a static wire at the top of the pole. Occasionally for various reasons, the conductors were dead ended and jumpered around to the other side of the structure. The static wire was not jumpered because there was no insulation between the conductor and the structure and there was continuity through the hardware. Return current through the static wire caused failure on the dead end shoe. The small contact where the dead end shoe touched the clevis pin was relied on for continuity. When there was not enough contact the shoe failed. Jumpers were installed to prevent future failures.

6. One failure resulted from installing a copper conductor and an aluminum conductor and joining the two dissimilar metals together in another copper adapter.

7. In a corner tower two steel reinforced aluminum conductors of different thicknesses were joined together with a transition sleeve and a copper adapter joining the aluminum sleeves.

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8. As a result of one airborne infrared inspection of a transmission line, the following components were removed from service: a damaged 46 kV steel reinforced aluminum conductor jumper and a two-hole compression spade 46 kV copper conductor compressed into an aluminum sleeve. The hot spot was attributed to a copper conductor in an aluminum sleeve. The steel core was carrying most of the current and made the jumper very hot.

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â&#x2013; Ground versus Helicopter Based Inspection In cities, where helicopters cannot fly at low altitudes, the unit is mounted on a four-wheel drive vehicle. The camera is mounted on an A frame assembly attached to a trailer hitch on the rear of the vehicle. The vehicle is also equipped with a 12 to 28 V inverter system to power the systemâ&#x20AC;&#x2122;s electronics and infrared imager. This converter is identical to that used in F-16 jet fighter aircraft. The electronic system is positioned between the driver and the thermographer in the front seat. A ground level infrared testing crew consists of a driver and thermographer. Helicopter inspections are more economical than ground based inspections because they can fly close to the line and cover more area in the same amount of time. In the United States in the 1990s, most 23, 46, 138 and 345 kV power lines were being inspected every year by helicopter based thermography.

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â&#x2013; System Electronics The interface distribution processing module is the central point for transfer of all commands and data. The system control unit features a gray scale (infrared white or black hot) switch and focus adjustments. The visible spectrum circuit integrates a charge coupled device camera. The cameraâ&#x20AC;&#x2122;s precision pointing system incorporates a gyro stabilized in both azimuth and elevation. The camera has a germanium lens and is attached to the belly of the helicopter by way of a dovetail mount. The imager unit incorporates a high resolution monochrome or color charge coupled device camera, 4Ă&#x2014; zoom lens, the infrared detectors, high speed scan assembly, cooling optics and associated electronics. For video display, two units are in the helicopter operation: one on the hand held system control unit and one on the console in the front seat for the observer and pilot.

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These units supply the operator with 1. a visible light image or thermal image and 2. Greenwich mean time.

A satellite based global positioning system developed by the United States Department of Defense provides a consistent, accurate technique of navigation. Originally designed for military applications, it also provides commercial and recreational users with 24 h, worldwide navigation coverage with accuracy to 15 m (49 ft). A thermometer measures outside ambient temperature.

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■ Navigation Each morning, the observer contacts the transmission maintenance personnel to find out if there were any line operations since close of business of the previous day. If so, then that line or lines will be inspected both visually to identify the cause for the operation or outage. The line or lines will also be inspected with infrared thermography. Of course, if the line is out of service an infrared test will not be completed. Following the inspection of that line, other lines in the area will be inspected to eliminate excessive ferry time. The average speed during an airborne infrared inspection is about 72 to 80 km·h–1 (45 to 50 mi·h–1) at treetop level on 23 or 46 kV lines and 121 to 129 km·h–1 (75 to 80 mi·h–1) on lines of higher voltages lines.

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The speed increases on higher voltage lines because these lines have fewer corners and have wider and clearer rights of way, tapoffs and other complications in their directions. Also the towers are taller than the trees, so the inspection can proceed faster. The video recorder records constantly from substation to substation. The recorder can be set to record in gray scale or visible light, in either 1Ă&#x2014; or 4Ă&#x2014; telephoto. It can also record all cockpit communication, vital information such as: (1) (2) (3) (4) (5)

line name, structure number, affected phase conductor, actual anomalous material and outside ambient temperature.

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All this information is recorded on tape and also documented on the helicopter observer patrol report. The thermographer records the Greenwich mean time on a notepad. This will assist in the processing stage of the operation later on. Total weekly inspection miles may vary depending on ferry time, weather or other factors. For example, inspection crews may fly from 323 km (200 mi) to 805 km (500 mi) per week. The airplane used is classified as a light jet. With the infrared equipment and the thermographer, a full capacity of jet fuel is impossible. So normally, a little more than 2 h is the norm when flying lines. The 46 kV system has been inspected for four years.

The number of anomalies may vary from as few as zero and as many as four in one day.

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The 138 kV system has not been inspected as often. As many as 12 anomalies have been found in one day. Most anomalies identified have been processed on Monday of the following week. The processing equipment consist of the following: VHS video recorder/player, personal computer, monitor, printer, high resolution 8 mm video recorder, portable television and proprietary analysis software, Infrared tests and replacing or monitoring the anomalous materials have effected huge savings in maintenance by utility companies and service hours for customers. It does not seem affordable for a utility not to perform infrared tests as part of preventive maintenance.

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FIGURE 22. Load break elbow profile.

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FIGURE 22. Load break elbow profile.

Legend: 1. Internal temperature predicted with three-dimensional modeling.

2. Temperatures measured along center line path on load break elbow.

3. Best fit, linear combination of single source contributions from transformer, normal load break elbow, bushing resistance and corner resistance, added to ambient temperature.

4. Ambient temperature.

5. Bushing â&#x20AC;&#x201D; bad contact where probe contacts bushing.

6. Normal â&#x20AC;&#x201D; best fit contribution to skin temperature for single heat source of normal load break elbow without discontinuity.

7. Corner â&#x20AC;&#x201D; best fit contribution to skin temperature for single heat source of anomalous electrical connection at corner, where probe connects to copper top connector.

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PART 7. Helicopter Based Thermography of Power Lines 7.1 Goals of Testing Because of resistance, electric current generates heat in conductors, increasing the temperature of the conductor above the ambient temperature.

Joints and clamps have normally lower resistance and larger area than the conductor itself and are hence colder than the conductor. With the passage of time and for various reasons the resistance over a joint may increase and cause a temperature higher than the temperature of the conductor. Hot joints will deteriorate in time and will eventually fail as the mechanical strength of the material decreases with increasing temperature. Suspension joints (Figs.

23 and 24) and hot tension joints (Figs. 25 and 26) are detectable with thermography.

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Infrared imaging can identify hot joints, clamps and other fittings and help to estimate how critical these hot joints are for a safe line. The procedures described below are intended for inspection only of electrical loaded bare overhead conductors for distribution lines and transmission lines of 10 kV and above. They are intended to support other data to decide how quickly a joint should be scheduled for repair. Other data such as current load, wind speed, geometrical design of the joint and consequences of phase dropping are needed to determine whether a joint needs to be repaired immediately. Do not use this procedure for inspection of discontinuities that do not cause overheating â&#x20AC;&#x201D; for example corona or corrosion insulator discontinuities. Do not attempt this procedure unless at least three of the conditions listed in Table 3 are fulfilled.

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TABLE 3. Conditions affecting quality of helicopter based thermography of power lines.

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FIGURE 23. Hot suspension joint: (a) original thermogram; (b) joint magnified to show digitization. Brightest pixel may be used to measure temperature accurately. Power line is easy to see in original image but disappears in noise of closeup.

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FIGURE 23. Hot suspension joint: (a) original thermogram; (b) joint magnified to show digitization. Brightest pixel may be used to measure temperature accurately. Power line is easy to see in original image but disappears in noise of closeup.

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FIGURE 24. Hot joint and warm suspension clamps close to tower. Induction normallywarms line suspension clamps.

Legend 1. Warm suspension clamp.

2. Hot joint.

1.

2.

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FIGURE 25. Hot tension joint: (a) one of several common designs; (b) thermogram; (c) closer view from different angle; (d) closeup.

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FIGURE 25. Hot tension joint: (a) one of several common designs; (b) thermogram; (c) closer view from different angle; (d) closeup.

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FIGURE 25. Hot tension joint: (a) one of several common designs; (b) thermogram; (c) closer view from different angle; (d) closeup.

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FIGURE 25. Hot tension joint: (a) one of several common designs; (b) thermogram; (c) closer view from different angle; (d) closeup.

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FIGURE 26. Tension joints in tower: (a) in example of symmetry, six equally hot fittings; (b) one hot tension joint.

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FIGURE 26. Tension joints in tower: (a) in example of symmetry, six equally hot fittings; (b) one hot tension joint.

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â&#x2013; Reasons for Thermographic Testing A thermographic test gives information about the condition of these components and important information for refurbishment planning. Three occasions call for thermographic testing of transmission lines.

1. After a new transmission line has been constructed thermal infrared testing can be used as a quality control technique to make a delivery test before the line is taken over by the line owner.

2. Aging of joints and fittings is one of the circumstances that most reduce the life of components in a transmission line. An inspection using infrared and thermal testing gives information about the condition of these components and important information for refurbishing planning.

3. If the resistance over a joint has started to increase it will eventually be so high that the temperature in the joint will cause a phase drop. The consequences are known by all owners of transmission lines. The most serious phase drops that must be prevented are in urban areas, at street crossings and over distribution lines.

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The ultimate goal is to inform the line owner where hot joints are located in its power lines and if possible estimate the overheating relative to the conductor.

One very important fact easily overlooked is that to determine the overheating of a joint it first must be observed during flight or during the examination of the video recording because it is not practically possible to measure the temperature of all individual joints on the transmission line. The hot joint must therefore present a contrast with the conductor or the background. If the emissivity of the joint is lower than unity, the cold sky is partially reflected in the joint and thereby sometimes effectively masks the anomalous joint.

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7.2 Materials and Failure Mechanisms â&#x2013; Power Line Materials In power lines, there are two kinds of conductors: 1. In all aluminum conductors and all aluminum alloy conductors, the aluminum wires carry both the current as well as the mechanical load.

2. In aluminum coated steel reinforced conductors, the steel core carries the mechanical load and the aluminum wires conduct the current.

The joints for these two conductors are accordingly of different design.

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The joints on power transmission lines built from aluminum core steel reinforced conductors are more complex than joints on all aluminum and all aluminum alloy transmission lines. The aluminum core steel reinforced conductor joint consists of at least two concentric tubes. The inner steel tube is the joint of the steel core; the outer steel tube is the joint on the aluminum strands. Therefore the joint can electrically be simplified to one aluminum and one steel path for the current acting in parallel. The aluminum path consists of the aluminum strands of the conductors, the aluminum tube and the interfaces between the aluminum strands and the aluminum tube. The steel path consequently consists of steel cores, the steel joint tube and the interfaces between the steel joint tube and the steel cores. Because of the larger cross section area of the aluminum path and the much lower resistivity of the aluminum metal compared to the steel, the current is unequally divided between the two paths.

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The high resistance of the steel path forces more than 99 percent of the current through the aluminum path. An increase in the resistance of the steel path therefore has a negligible effect on the total heat evolved. Despite the low resistivity of the aluminum metal, the large current results in 99.5 percent of the heat being evolved in the aluminum strands and the aluminum tube.

Compared to the conductor, the larger cross section of the aluminum tube causes less heat to be produced per unit length. The larger diameter and consequently larger cooling surface results in more efficient cooling by convection and radiation per unit length. Taken together these two processes result in a joint tube having a surface temperature lower than that of the conductor. If the resistance in a new joint is 20 μΩ the contact resistance represents only a smaller part of that, maybe only 1 to 2 μΩ. The resistance of a joint is only about 50 percent of the resistance of an equal length of the conductor. When viewed using an infrared imager, the joints therefore appear colder than the conductor.

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■ Resistance If the resistance in a new joint is 20 μΩ the contact resistance only represents a smaller part, maybe only 1 to 2 μΩ. The resistance of a joint is only about 50 percent of the resistance of an equal length of the conductor. That is the reason why the joint is cooler than the conductor itself. The evolved heat is conducted to the surface so that the outer surface at the two ends of the joint becomes warmer than the connecting line. Although only a fraction of the current is carried by steel, the hottest part of the joint will be the steel tube that connects to the two steel cores. Because of the lack of radial heat conductivity between the two tubes, heat from the steel parts of the joint must pass through the hot contact surface between the aluminum strands and the aluminum tube. Some of the heat is conducted away from the joint along the conductor. Therefore, when the conductor nearest to the joint is heated up enough to overcome the shadowing influence of the cold sky, bright tails seem to be growing out from the joint. With increasing resistance the joint becomes warmer and eventually the whole joint is hotter than the conductor and appears bright.

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â&#x2013; Joint Life It is not possible to predict exactly when a joint will fracture after overheating is discovered. The strength of a joint depends on the temperature and decreases with increasing temperature. The fracture will occur when the temperature is so high that the joint strength has dropped to the conductor tension. During current cycling tests in the laboratory it has been shown that the temperature of the joint develops as follows. (In the laboratory, one cycle is full current load during 1 h followed by 1 h cooling period.) During the first long period of the jointâ&#x20AC;&#x2122;s life the temperature is very stable. As the joints are aging the resistance and hence the temperature will increase slowly in some of them. This process is not stable. Melting at a microscopic scale inside the joint in the boundary between the wires and aluminum pipe will from time to time build up current bridges where the current passes and the resistance will drop until that bridge has oxidized and the current will find other paths. Later in the jointâ&#x20AC;&#x2122;s life these changes seem more dramatic.

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The inspector does not know the entire temperature history and so cannot judge the remaining lifetime of the joint. The aluminum-to-aluminum interfaces oxidize or corrode as a line ages. The result is an increase in the resistance of the aluminum path and heat being generated at the surface between the aluminum strands and the aluminum tube. Usually the contact resistances differ between the two ends of the joint. Tests demonstrate that emissivity increases in corrosive environments (Fig. 27). The last period in the life of each joint is unstable. Periods of rapidly increasing resistance can be followed by periods with no increase or even decreases in resistance. One theory that explains the phenomenon is that micromelting inside the joint in the boundary between the wires and aluminum pipe will build up current bridges over which the current passes. The resistance will drop. Because of the relatively high temperature these bridges will oxidize and cut off the current bridge. The resistance will increase until a new current bridge has developed.

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FIGURE 27. Emissivity increases for joints exposed to corrosive environment.

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7.3 Procedure â&#x2013; Safety Special rules for airborne surveys of transmission lines differ from country to country and must be followed. To avoid collision all crossing power lines and towers higher than the line to be inspected must be identified before inspection. Crossing lines must be identified during the briefing with the pilot.

Keep contact with a power company representative during the inspection.

This person must be contacted immediately before takeoff and after landing.

This person must also know which part of the line will be inspected and also the time expected for landing. If there is no contact within 30 min after expected landing time the helicopter is supposed to be in emergency.

Airborne thermographic surveys are performed only in daylight to reduce the risk of collision with crossing lines, with cables that anchor towers and with other elevated structures.

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â&#x2013; Training and Equipment Details of the infrared imaging system are given in Table 4. The camera is mounted on a platform under the fuselage of the helicopter (Fig. 28). It is recommended to use long wave equipment, 8 to 12 Îźm. During high humidity conditions, rain, snow and fog the absorption of the infrared radiation in the atmosphere is not as high for long wave detectors as for short wave detectors.

Spatial resolution is the most important criterion for equipment settings. A conductor is a very lean component, with diameter from 10 to 40 mm (0.4 to 1.4 in.).

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FIGURE 28. Helicopter installation of thermographic system: (a) diagram of components; (b) camera mounted on platform under fuselage of helicopter.

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FIGURE 28. Helicopter installation of thermographic system: (a) diagram of components; (b) camera mounted on platform under fuselage of helicopter.

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â&#x2013; Preplanning The following steps are among those needed for someone planning thermographic tests of power lines from a helicopter.

1.

2.

3.

4.

5.

6.

7.

Persons should not attempt to perform this inspection unless they are properly trained and certified.

Get a list of all transmission lines to be inspected and line maps covering these areas.

Give the customer the criteria for a successful inspection.

Confirm with the customer the day or week for the inspection.

Ask for a contact person and phone number.

Write down voltage; conductor area and type (aluminum coated steel reinforced or aluminum alloy); line configuration; installation year; and expected current load during inspection.

Check that the system has sufficient cooling capacity for the inspection.

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8.

Use the thermographic system’s control panel to check that the detector is sufficiently cooled. When the system test is activated a gray scale is visible on the monitor. The gray scale on some systems is used to adjust the brightness and contrast on the monitor. The controls must never be adjusted on the monitor to improve the picture during testing without using the system test. This step applies only to certain system designs.

9. For some systems, turn offset and gain on the system control panel until optimum brightness and contrast are reached.

10. Read in time and date; inspector’s, navigator’s, pilot’s and customer’s names; code for the lines to be inspected; and current.

11. Press stop, rewind and play the recording. Check that both voice and image have been recorded. Press stop after passing the end of the recording. Some systems use flash memory instead of requiring this step.

12. The system may now be switched off. Having performed these steps, the inspector can be confident that the inspection will proceed as desired after takeoff.

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â&#x2013; Steps before Takeoff 1. Check installation and wire connections. Check that the camera is properly mounted to the fuselage and that cooling capacity is sufficient for the testing. Remember to remove the lens cap.

2. Confirm with the contact that the helicopter is ready for takeoff and ask for air current at that moment.

3. As soon as the helicopter engine is started turn on the camera system and video recording system.

4. Insert the video tape in the recorder, press counter reset to zero and start the recording. Make sure the remaining tape length is adequate. A total of 60 min will, as an average, last for a 50 km (31 mi) inspection.

5. If the camera is remotely controlled see that it follows the inspectorâ&#x20AC;&#x2122;s signals. 6. Inform the pilot that the inspector is ready for takeoff.

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■ Steps in Air 1. As the helicopter approaches the power line to be inspected, start the system once again. Target distance could be as far as 200 m (650 ft).

2. Turn offset and gain until optimum brightness and contrast is reached.

3. Record weather conditions, temperature wind speed and direction, atmospheric conditions; type and amount of clouds, lines to be inspected and the first tower number. This must be the tower being simultaneously watched in the monitor.

4. The inspector and pilot must now choose the optimum camera angle and speed over ground for an inspection that is both safe and reliable. As a guideline every part of the conductor should be at least 1.6 to 1.8 s in the monitor to not fatigue the inspector’s eyes too much (Fig. 29). Usually all phases can be inspected simultaneously. The maximum speed of the helicopter should not exceed 56 km·h–1 (35 mi·h–1). A conductor is a narrow component, with a diameter from 10 to 40 mm (0.4 to 1.6 in.) and should be inspected from a distance not closer than 40 m (132 ft), generally from a helicopter traveling at 48 to 64 km·h–1 (30 to 40 mi·h–1).

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FIGURE 29. Power lines visible from moving helicopter: (a) each part of conductor in monitor for 1.6 to 1.8 s; (b) example of indication.

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FIGURE 29. Power lines visible from moving helicopter: (a) each part of conductor in monitor for 1.6 to 1.8 s; (b) example of indication.

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5.

6.

7.

8.

9.

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11.

Record at least every fifth tower number and identify it by number on the video recorderâ&#x20AC;&#x2122;s audio channel.

As soon as a hot joint is observed turn around the helicopter to get a view from different directions. Try to hover to get as close a look as possible of the joint for later analysis.

While getting a closer view, the inspector should check that the video is running, record the tower number and section and record oral observations. For later convenience it is recommended that the inspector make a written note at what band time each such observation is made.

If the system includes measurement instruments it would be good to get some pictures of the sky. This will help to get correct values for the background temperature. When the helicopter is turning around point the camera to the side that faces the sky.

When the last tower of the line is passed rewind the video tape and take it out, turn of the systems and return to base.

Mark the video tape with the proper identification.

Immediately after landing call the ground contact and confirm the safe landing.

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■ Documentation of Results Make copies of the data sheet, one copy for each indication or location. Every data sheet shall contain following information: name or symbol of the inspection company, customer’s name, inspector’s name, date of test, line identification, type or area of the conductor, conductor configuration (simple, duplex, triplex or quadruple), year of construction, voltage, current load, maximum load for the conductor, wind speed, ambient temperature, atmospheric conditions (percentage of sky covered by clouds or if the atmosphere is diffuse what percentage of blue sky color is absorbed). If a video print will simplify location of hot joint, use it. Documentation with video printout is recommended if there are suspension towers with more than one line (Figs. 24 and 26). Infrared and thermal testing is useful in detecting joints and fittings with increased temperature. The summary should include the number of hot joints discovered and an explanation if no indication was found.

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â&#x2013; Qualitative Evaluation Steps To classify a hot joint according to different degrees of overheating requires long experience and much feedback from resistivity measurements from detected joints.

1. Insert the video tape in the recorder, reset the counter to zero and press play. Complete the data sheet with information recorded on the tape.

Check the line map to check the correct tower number.

2. Identify the hot joint or fitting.

3. Now analyze the thermogram to decide if this observation is a hot joint or a joint that looks hot because of other effects â&#x20AC;&#x201D; for example, dead weights warmed by induction (Fig. 30). Examine all fittings in a tower or several joints if one line span looks hot. If the temperature over joints and fittings changes stepwise the apparent overheating is probably due to differences in emission factor between conductor and joint. Make no registration on these joints.

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FIGURE 30. Warm dead weights glow because of induced current.

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4. If the differences in temperature can be attributed to differences in emission factor, it is not a hot observation. If it is not possible to measure the hot spots, then a qualitative evaluation may be performed. Observe that this estimation only gives a very rough idea of how hot the joints are.

The two parameters are the current load and the length of the warm zone in the conductor.

5. On the X axis mark the actual current load and on the Y axis the length of the heated zone in joint length units.

6. If the wind is stronger than 8 m·s–1 (18 mi·h–1) add one unit in the temperature grade (alt class). Write the temperature class in the data sheet.

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â&#x2013; Quantitative Evaluation Steps Although qualitative evaluation often gives an idea about the condition in the joint it is not possible to judge how many degrees overheating it represents.

This quantitative figure gives a stronger indication of the urgency of repair and is the most important criterion for the equipment to use.

1. Select the most likely emissivity factor and enter the value in the computer.

2. Fast forward the video tape to an image of the sky.

3. Make a measurement of the average temperature over a representative frame.

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4.

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9.

10.

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Select the measured temperature and enter the value in the computer.

Choose the frame where the hot observation is.

Measure the temperature at the hottest point and note the temperature.

Measure the temperature of the conductor at an unaffected point.

Fill in the data sheet for the overheating Î&#x201D;T measured (Kelvin).

Solve the Î&#x201D;T at maximum load (Eq. 4).

Fill in the data sheet for overheating at maximum load.

Mark on the data sheet at what tower or between which towers each hot fitting or joint is located. Indicate the phase and line (if more than one in each section) in the data sheet and mark with an X the relative position of the indication (Fig. 31). The inspector may add other figures for the tower in the inspected line.

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FIGURE 31. Example of chart that inspector may use to mark approximate location of indication relative to towers.

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â&#x2013; Verification Infrared and thermal testing has proven very reliable but precise verification of a thermal test is impossible because the many variables cannot be controlled.

It is recommended however that the line owner should measure the joint resistance over both halves of the joint and compare it to the total joint resistance when the replacement is made. To test one certain joint where the line crosses a highway or distribution line, a place where people stay or for other reason an alternative means is to use a hand held camera and inspect from the ground. That test procedure is not described in this procedure. It is also possible to measure the actual resistance using a microohm meter. This technique is recommended for correction with replacement of hot joints. It can also be used as a first check if no other techniques are available. The ultimate goal is to help the line owner decide whether the joint needs maintenance work and give an indication about how critical the joint is. Results of thermal testing on a joint must be compared carefully with results of a resistance measurement perhaps one year later. The temperature measured depends on many parameters, few of which the inspector can control.

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7.4 Indications ■ Evaluation of Indications Thermograms must be analyzed to decide if each indication is a hot joint or merely appears hot because of other effects. On very reflective conductors joints may look warm because of effects other than resistive heating. In one case of a duplex line, two joints appeared to be hot joints. The conductors and the joints had a surface as delivered, very reflective. The test was made in the afternoon a sunny and clear day. The sky temperature was between 233 K (–40 °C = –40 °F) and 223 K (–50 °C = –58 °F). The joints were reported as hot but the resistance measured one week later showed normal values. The conditions for a reliable inspection were in this test not fulfilled.

There are however some circumstances in the thermogram that indicate that these are not hot joints. In the case of a rapid temperature drop, there is no temperature rise in the conductor outside the joint.

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The temperature in a warm joint should change gradually from the hottest area on the joint to the conductorâ&#x20AC;&#x2122;s normal working temperature. A steep change in radiosity is normally caused by contrasting emissivity. If the warm zone looks like a rocket fume it is likely a hot joint. Although the experienced inspector will discover all hot spots in an transmission line it is difficult for the line owner to decide what joints to repair first and how critical they are. The decision to test or not depends on external conditions that may be quantified.

A simple mathematical formula incorporating some yes or no conditions would be of great help.

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â&#x2013; Indications That Cause Temperature Changes Several discontinuities in power lines cause temperature changes in components. Broken sheds cause a temperature rise in line post insulators.

Cracks in pin post insulators cause a temperature drop on insulator surfaces.

Other discontinuities such as strong corrosion attack in aluminum core steel reinforced conductors may also cause temperature rise. The tension joint, used in tension towers, can have a large variety of designs (Figs. 25 and 26).

In some lines, tension joints are more likely to be hot than suspension joints.

There are three areas where the resistance may increase in a tension joint: in the span conductor side, in the bolted connection and in the jumper conductor.

It is often possible to determine in which part the heat is produced by seeing how the heat spreads from the hot part. Figure 24 shows a hot joint close to a tower with warm suspension clamps.

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â&#x2013; Nonindications That Cause Temperature Changes The anomalies above occur only in joints, clamps and fittings where a temperature rise is caused by an increase of resistance, detectable from a distance up to 200 m (656 ft). There are also natural temperature rises in components such as the temperature rise in dead weights on jumpers and heat produced by wind induced vibration. For example, when wind causes conductor vibrations where the conductor enters the suspension or tension clamp sleeve, then friction makes wire temperature rise. Neighboring joints are called symmetrical if they appear to have exactly the same temperature.

They also look the same at both ends and seem to have same temperature along the whole length of the joint. Figure 26a shows a case of symmetry for all six fittings in a tower. Dead weights on jumpers may become warm if they are made of a magnetic material. Figure 30 shows dead weights warmed by induced current. Bright jumpers can be used to confirm that the line is electrically loaded. Loading can be checked this way during testing of two parallel lines when only one is loaded.

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7.5 Weather The inspector needs to describe the atmospheric conditions. Cloudiness is quantified from 0 to 100 â&#x20AC;&#x201D; from 0 for completely clear blue sky to 100 percent covered by clouds. If there are cloud of cumulus type, the inspector looks at the sky and estimates how much of the entire sky is covered by clouds. If there are cirrus clouds, which are more transparent than cumulus clouds, it can be estimated how much of the blue color is absorbed by the clouds. The time of day affects the amount of thermal clutter in the image, from the ground.

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1. On a typical morning, all details in nature have about the same temperature, so it is possible to use high sensitivity on the camera; the gain covers from 280 to 286 K (7 to 13 °C; 45 to 55 °F).

2. By midday, when the sun has warmed up the environment, the temperature range is much larger. For example from 291 to 301 K (18 to 28 °C; 64 to 82 °F). At this time the inspector must use a lower sensitivity, covering from 291 to 301 K (18 to 28 °C; 64 to 82 °F).

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3. For afternoon on a sunny day, the sensitivity (gain) during the test depends on the temperature range in the surroundings. The gain setting must cover from the hottest to the coldest area the camera is facing. In the afternoon rocks and stones on the ground may be warmer than the conductor and will therefore appear brighter on the monitor. The chances of discovering hot joints has now dropped dramatically. The inspector should consider stopping the test because it is possible that joints must be extremely hot to be discovered.

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■ Great Temperature Differences in Ground Reflective conductors require optimal external circumstances. Atmospheric conditions have an especially strong influence on test quality as the sky reflects in the conductor. Clouds are major sources of infrared radiation in the sky. The clouds adopt the same temperature as the temperature of the surrounding air. Therefore depending on the height of clouds the radiation from the clouds have different temperatures. On a cloudy day with low ceiling the radiation from the sky is almost the same as from the ground but on clear winter days it may be 223 K (–50 °C = –58 °F). If there is an overcast sky the temperature could be only a few degrees below the ambient temperature and this is much more favorable for the test. The temperature difference needed varies with emissivity of the joint and blackbody temperature of the radiation from the sky. Because the joint emissivity is lower than unity, the cold sky is partially reflected in the joint and so can sometimes effectively mask the anomalous joint.

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To show this effect, critical overheating can be plotted against the undertemperature of the sky. The undertemperature of the radiating sky is the blackbody temperature difference between the radiation from the ground and the sky. It is possible to plot diagrams showing the relationship between the undertemperature of the sky and the overheating at which the anomalous joint can be observed. By plotting these parameters another benefit is achieved; the diagrams are almost identically independent of ground temperature. Very dry and clear days may have sky undertemperatures as low as 233 K (–40 °C = –40 °F). On such days, critical overheating of the joint can be as great as 40 K (40 °C = 76 °F) before it can be easily detected.

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■ Clear Days Clear, cloud free days are excellent for helicopter flying but in general are not favorable for power line surveys. This atmospheric condition is the factor that most limits test times. Clear days are also deceptive because the improvement in picture quality in the monitor does not also give unambiguous indications. If a clear day is expected the test should start immediately at sunrise when the surroundings are in thermal balance, that is, when all details have same temperature after the night. During these early hours it is possible to use a high gain, which means that the temperature window is very narrow, from 2 to about 8 K (2 to about 8 °C; 3.6 to about 14.4 °F). During these unfavorable conditions the inspector can only be sure to find anomalous joints with an overheating greater than 12 K (12 °C = 22 °F). All details on the ground appear with low contrast as they have almost the same temperature.

Because of sky under temperature, a joint with only a few degrees overheating will shine very brightly in the monitor and hence be easy to detect.

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Later in the day when the sun has been up for some hours the inspector has to reduce the gain to get an acceptable picture quality. The window must increase from 283 to 313 K (10 to maybe 40 째C; 50 to 104 째F) to give a picture acceptable to examine. Vegetation, stones and other details in the background will now appear brighter and sharper in the monitor. Stones will shine because the sun has warmed them up to higher temperature than the conductor. At this time hot joints are less likely to be detected, so the inspector has a strong reason to stop testing.

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7.6 Errors There are two groups of errors connected to the measurement of a jointâ&#x20AC;&#x2122;s overheating. The first is the measurement of the radiation temperature and the degradation of image quality because of limitations in the system. The second is errors in the estimation of emissivity and sky temperature when the observed radiosity is translated to temperature. â&#x2013; Resolution Related Errors Errors in the measurement of the radiation temperature of the joint and the conductor are due mainly to limited resolution and digitization effects that tend to shift the measured temperatures toward the temperature of the background.

There are basically two causes of degradation of image quality and measurement accuracy.

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1. Resolution may be limited by optical effects (point spreading) and limitations in the detecting system.

2. Image quality is degraded when the image is digitized for analysis, transmission or storage. The magnitude of the digitization error can only be determined by measuring the temperature at neighboring picture elements.

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It must be understood that there is a fundamental difference between what can be detected on the image and what can be measured accurately. To be able to see an object reasonably clearly 10 percent of the contrast may be enough but to measure the temperature accurately more than 90 percent of the contrast must be transferred in the image. The limitations in resolution cause a small sharp dot to be depicted as a diffuse blob (Fig. 32a) and a sharp edge as a gradual increase in intensity. The digitization is ideally a process that forms a mean value of intensity over each picture element, or pixel. Depending on the system such a digitized picture usually consists of 100 Ă&#x2014; 100 pixels to 500 Ă&#x2014; 500 pixels. The more pixels, the smaller the area averaged to form the pixel. It can also be a sampling of the intensity at different positions on the image. The final result is the same; a picture built up from small squares with uniform intensity over the area of each square. In Fig. 32b, the original picture is a diagonal line from top left to bottom right.

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FIGURE 32. Effects of limitations in resolution: (a) small object appearing as diffuse blob; (b) digitization resulting in image consisting of squares each with uniform intensity.

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FIGURE 32. Effects of limitations in resolution: (a) small object appearing as diffuse blob; (b) digitization resulting in image consisting of squares each with uniform intensity.

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The resolution of the imaging system and the resolution of the digitization are two different entities, with the digitization convoluting the original image.

Therefore the only way the digitization can contribute to the image detail is to the worse. If the resolution of the imaging system is higher than the resolution of the digitization, the intensity of the object is smeared out over the pixel in proportion to the amount covered by the pixel. If the resolution of the digitization is higher than the resolution of the imaging system, the smooth intensity profile acquires a step shape that can give a false impression of high resolution (Fig. 33). For these reasons when images are used for measurements high resolution is needed for both the imaging system and the digitization.

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FIGURE 33. Digitization can create false appearance: (a) smooth intensity profile; (b) digitized illusion of high resolution.

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Other factors that depend more on the viewing situation than on the thermal imaging system and influence the resolution are characteristics of the zoom lens, the focusing and to a slight extent also of the differences in distance between the imager and the object and between the imager and the background. The ability of the zoom lens to transfer the contrast varies somewhat with the focal length setting. This means that a 4Ă&#x2014; zoom lens does not make it possible accurately to measure objects 4Ă&#x2014; smaller with the telephoto setting than with the wide angle setting. Incorrect focusing spreads the image in the same way as defocusing a camera lens and thereby decreases the measured temperature difference. It is furthermore difficult to focus a high resolution scanner to its ultimate resolution because of the limited resolution of the monitor.

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A phenomenon related to incorrect focusing is that, when the lens is focused on the joint, the background is not in focus and its intensity has a tendency to bleed slightly into the sharp image and thereby reduce the contrast (Fig. 34).

Because of spreading, there is no way to tell the exact temperature of a very small object because the measured temperature difference for those objects will be the product of area and temperature. At a great distance, the measured temperature will be lower than the true temperature. The relative seriousness of the problem joints will not be changed and, because of relatively constant viewing parameters, the measured temperature will be directly proportional to the true temperature (see Fig. 23b).

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FIGURE 34. In example of overbleeding, warm roof increases apparent temperature of conductor.

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For example, the digitized image of a thermal imaging system consists of 520 × 520 pixels. Using the longest focal length at 20 m (66 ft) distance each pixel corresponds to a 4 × 4 mm (0.16 × 0.16 in.) square. Objects this small cannot be measured. However experiments with slits show that at 20 m (66 ft) an object with 27 mm (1.1 in.) cross section can be measured with good accuracy (90 percent of the true temperature difference between object and background). This cross section is about as large as a cross section of the conductor and half the size of the joint. Figure 23b shows the joint in Fig. 23a magnified to show the digitization. The brightest pixel will give a sufficiently accurate temperature. Even though the conductor is easy to see on the original image, it disappears in the noise.

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The radiation from a warm structure on the ground can overbleed into the image of the target. Figure 34 shows an example of overbleeding, in which a warm roof increases the apparent temperature of the conductor. the shape of the curves are almost identical, independent of the sky temperature and the temperature of the joint, if the temperature difference between the line and the joint is constant. The error is furthermore almost linearly proportional to the temperature difference between the joint and the conductor. For normally occurring values the spread in the difference is less than 0.2 K (0.2 째C = 0.36 째F) because of this very constant shape, which means that ideally one diagram covering all usual situations could be used.

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â&#x2013; Errors in Emissivity and Estimated Sky Temperature When analyzing the temperature image, errors in the emissivity and error in the estimated sky temperature causes error in the determined overheating of the joint. Usually the measurement of the joint overheating is performed using the conductor as a reference. The most common source of error is the estimation of material emissivity. The diagram in Fig. 35 shows the measurement error due to incorrect guesses for different emissivities.

Diagrams such as the one in Fig. 35, plotted for different temperatures, show some important properties of this error. A lower background temperature results in a marginally smaller error due to incorrect guess of emissivity. A larger error is introduced by guessing an emissivity too low rather than too high. The error is influenced more by sky temperature if the estimated emissivity is lower than true emissivity.

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FIGURE 35. Error in measurement because of incorrect guess of emissivity for different true emissivities. Difference is temperature obtained with guessed values minus temperature obtained with true values. In this case, joint temperature is 283 K (10 °C = 50 °F), conductor temperature is 273 K (0 °C = 32 °F) and temperature of sky is 268 K (–5 °C = 23 °F).

Charlie Chong/ Fion Zhang

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The diagram in Fig. 36 shows the error in the measurement as a result of incorrect estimation of the blackbody temperature of the sky for different emissivities of the joint. The true blackbody temperature of the sky is 268 K (– 5 °C = 23 °F). Negative values mean that the measured temperature is lower than the true temperature. Overlaid in the diagram is an estimation of sky temperature to be 288 K (15 °C = 59 °F) when the true sky temperature was 268 K (–5 °C = 23 °F), which results in a measured temperature 0.83 K (0.83 °C = 1.5 °F) lower than the true joint temperature. Note the relatively small effect on the measurement from the error of estimating a too low blackbody temperature of the sky. Figures 36 and 37 show some important properties of the error introduced when estimating the sky temperature. The slope of the curves are steeper on the high temperature side which means that it is better to use a sky temperature too low than too high.

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FIGURE 36. Diagram showing error in measurement as result of incorrect estimation of blackbody temperature of sky for different emissivities of joint.

True blackbody temperature of sky is 248 K (–5 °C = –13 °F).

Charlie Chong/ Fion Zhang

Charlie Chong/ Fion Zhang

Below the correct sky temperature, to the left in the diagrams, the shape of the curves are almost identical, independent of the sky temperature and the temperature of the joint, if the temperature difference between the line and the joint is constant. The error is furthermore almost linearly proportional to the temperature difference between the joint and the conductor. For normally occurring values the spread in the difference is less than 0.2 K (0.2 째C = 0.36 째F) because of this very constant shape, which means that ideally one diagram covering all usual situations could be used.

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End Of Reading Four

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Good Luck

Charlie Chong/ Fion Zhang

Good Luck

Charlie Chong/ Fion Zhang

https://www.yumpu.com/en/browse/user/charliechong Charlie Chong/ Fion Zhang