Abstract:
Apparatus for monitoring the temperature of a high voltage conductor includes an electrically and thermally conductive fixture for attachment to a high voltage conductor, and a high voltage insulator having a high voltage end and a reference potential end. The insulator is connected at the high voltage end to the fixture. The insulator contains a fiber optic cable in a fiber optic cable passageway from the reference potential end to the high voltage end. The cable extends beyond the insulator. An optical temperature sensor head is optically coupled to the cable the high voltage end. The sensor head includes a sensor crystal which transmits light that varies with temperature of the sensor crystal. An electrically and thermally conductive enclosure enclosing the sensor head is supported in the fixture for thermally conductive contact with the high voltage conductor effective to couple the temperature of the high voltage conductor to the sensor crystal. An optoelectrical unit powers and detects the optic signal carrying the information about the temperature of the high voltage conductor.

Description:
BACKGROUND OF THE INVENTION  
         [0001]    This invention relates to apparatus and systems for thermal measurement of high voltage electrical power transmission and distribution lines and related high voltage components and equipment such as occur in substations, and more particularly, to apparatus and systems that make use of contact thermal sensors for determining the temperature of the power lines and associated high voltage components and equipment.  
           [0002]    Demand for electric power has grown faster than the capability of the existing distributed power delivery assets to deliver it reliably. Since the mid-1990&#39;s, sales of power loaded onto the U.S. power transmission and distribution grids has increased 100-fold. Despite this unprecedented and growing demand for electrical power, erection of new transmission lines in the North America has not kept pace. New construction costs are high and lead times are long. Costs for the construction of new high voltage transmission capacity can range from $1,100,000 to $3,300,000 per circuit-mile. If land acquisition and/or establishment/extension of rights-of-way are involved, lead times can be as long as 4 years or more. Recent industry literature is replete with phrases such as, “construction of new transmission capacity is grinding to a halt.” On Jan. 1, 1992, 191,690 circuit-miles of transmission existed in North America. Ten-year plans ending 2002 called for 8.3% additions to transmission capacity through new construction. As of the end of 1998, approximately 30% of these additions had been built; the 207,586 circuit miles seen as required by 2002 had been whittled down to 202,196 circuit-miles, and completion of the additions had been pushed out 5 years to 2007. In 1998, the North American Electric Reliability Council (“NREC”), listed planned transmission additions (230 kV transmission systems and above) through 2007 of 6,588 circuit-miles.  
           [0003]    As a result, the electrical power distribution industry is faced with squeezing more current delivery out of existing infrastructure. Utilities are being tasked to operate existing power lines at previously unexplored operating levels for extended periods of time. Transmission systems are being operated in a manner for which control of them was not designed. Blackouts, equipment damage, and system disturbances are becoming widespread, with ever increasing frequency and effect.  
           [0004]    Electrical current flowing through a metallic conductor causes  1   2  R losses in the conductor, that is, heat generation in the conductor changes exponentially with changes in current load. The current/temperature relationship affects not only the high voltage lines but also system equipment, conductors, and components in the power line circuit. This includes buses, switches, cables, transformers, etc. in high voltage transmission and distribution substations. This relationship of conductor temperature to current impacts two factors that limit how much current a given high voltage transmission line can safely and reliably transmit or carry on a continuous basis: firstly, the clearance between the mid-point of the line (at a span between two transmission towers) and the ground beneath the mid-point (or a grounded object, e.g., a tree); secondly, the temperature at which the transmission line begins to undergo irreversible physical (mechanical and/or electrical) changes.  
           [0005]    Firstly, metals expand on heating. If too much current passes through a power line, the line may sag so close to the ground that it violates the mandated clearance for such lines. These clearances are regarded as ‘deadly serious’ by utilities. In some cases, the line may sag far enough to make contact with a grounded object. In such events, blackouts can and do result, and with these come losses: loss of equipment and property, loss of electric service to customers, lost utility revenues, customer manufacturing and product losses, productivity losses, and even loss life. Thus high line temperatures are a limiting factor of how much current a line can safely transfer.  
           [0006]    Secondly, if too much current passes through the line, the resulting temperature of the line will cause the aluminum conductor material to anneal. When aluminum anneals, its mechanical and electrical properties change irreversibly; annealed aluminum has higher resistivity and lower mechanical strength than ordinary aluminum. After annealing, electrical transmission losses increase via heat generation, and the amount of sag increases for any given amount of current passing through the conductor. Once a line is annealed, electric power companies generally cut back or limit power flow. The damaged line can bottleneck the entire circuit in which it resides. In some cases, it is necessary to replace the annealed transmission line.  
           [0007]    “Ampacity” is current carrying capability expressed in amperes. As a result of the effect of current on temperature and the effect of temperature on metal, manufacturers of high voltage lines, system equipment, conductors, and other components in the power line circuit thermally rate their products according to limiting ampacities. These name plate ratings are based on the characteristics of the materials used in the product and, at least in the case of transmission lines, on limited assumptions of environmental conditions (e.g., 90° C. and a crosswind of 2 feet per second for transmission lines). Power distribution companies may “de-rate” the nameplate value based on the intended use of the product, for example, because of predicted heating of the product by the environment in which it will operate. Environmentally caused heating is founded on historical information and assumptions of conditions such as wind speed and direction, ambient temperature, humidity, barometric pressure and incident solar radiation. Conservative safety factors (e.g., hottest day, little or no wind, etc.) are applied to reach the rating. Power distribution companies operate their equipment within the name plate ampacity ratings of the manufacturers to prevent the annealing and line sag problems mentioned. To do this, power companies measure current to indirectly gain a reading of percentage of name plate ampacity that a given power load represents.  
           [0008]    The ampacity of a power line varies according to the temperature component of the line imposed by actual environmental conditions under which a power line circuit is operating. More current can be transferred through a circuit when the lines are colder than when they are hotter. In order to transfer more current through existing lines without blackouts or system disturbances, power companies need to know in real time as conditions change, moment to moment, at any time, day or night, the dynamic actual ampacity of its equipment, not the static name plate ampacity predictively rated by the manufacturer. Knowing the dynamic actual ampacities, power loads can be safely, accurately, and reliably increased and adjusted within the real time current carrying capabilities of the power distribution system. As a result, the true capacity of the system at the moment can be utilized to safely and reliably deliver more power to customers than present static ratings and operational control methods allow.  
           [0009]    Dynamic actual ampacity can be determined by knowledge of actual moment to moment temperatures of the power line. In addition, by knowing actual equipment operating temperatures, substations can be operated and protected optimally based on the thermal state and history of equipment. Substation equipment is routinely tripped (i.e., taken off line in order to protect it) based on information from current sensors, without regard to actual equipment operating temperature. In many instances, such equipment is operating safely, from a thermal standpoint, and is not in danger of undergoing thermal damage. Continuous temperature monitoring allows such equipment to continue operating safely.  
           [0010]    In earlier years, in order to monitor power line sag, a number of diverse technologies were developed to monitor line temperatures directly or indirectly. Early methods provided electrical devices mounted on or nearby or moved along the power lines. Various thermocouple, resistance temperature monitors (RTD&#39;s), thermistor, solid state or other electromechanical transducer systems were suggested, typically employing radio frequency or other transmittal of sensed information, as represented by U.S. Pat. Nos. 4,268,818, 4,384,289; 4,635,055; 4,709, 339; 4,728,887; 4,801,937; 4,806,855; 4,818,990, 4,894,785, 4,904,996; 5,006,846; 5,029,101; 5,140,257; and 5,181,026; or a fiber optic link as in U.S Pat. Nos. 4,859,925 and 5,341,088. High voltage insulators have been developed containing fiber optics to link these traditional methods of measurement, as in U.S. Pat. Nos. 4,613,727; 4,802,731; and 5,594,827. These traditional methods of measuring temperature (thermocouples and thermistors) are not safe, accurate or reliable in the extremely high voltage environment. Susceptibility to intense electric fields in the high voltage environment inevitably results in damage and catastrophic failure of electronic sensors such as thermocouples and thermistors.  
           [0011]    Other methods, such as capturing an image of the line relative to the ground, and then using software to analyze the image for clearance, have been used to estimate the sag in a line. Alternatively, line tension monitors have been used to calculate sag, but installation requirements do not allow tension to be determined at every location; only certain spans can support a tension monitor. As a result, line tension is frequently determined for a span that is actually not the thermally limiting span, or it is determined so far from the thermally limiting span as to be of limited use insofar as the dynamic rating of the whole circuit is concerned.  
           [0012]    Optical fibers, due to dielectric construction, are free from electrical interference, and use of them as an intrinsic sensor has been made or suggested for sensing power line temperatures. A segment of the fiber serves as a sensor gauge while a long length of the same or another fiber conveys the sensed information to a remote station where the sensed information is decoded with reflectometric or interferometric technologies and used by computers to calculate temperatures. One such system using optical time domain reflectometry and measuring Raman backscatter as a temperature sensing principle is described in U.S. Pat. No. 6,167,525. Alternatively to Raman backscattering, the detection of changes in phase of light emerging from a single mode optical fiber has been employed for current and voltage control in high power cables, using interferometric schemes (Mach-Zehnder, Michelson, Fabry-Perot or Sagnac forms). The Raman backscattering and interferometric techniques, while offering good sensitivity and accuracy, are quite complicated and costly in terms of procurement, installation, operation, maintenance, and repair.  
           [0013]    Another kind of temperature sensor using optical fibers is an extrinsic sensor in which the temperature sensitive elements are distinct from the optical fiber itself. These type sensors basically fall into two groups: pyrometeric sensors used to remotely detect infrared radiations emitted from hot bodies, and contact sensors which rely on conductive heat transfer. Examples of extrinsic contact sensors are described in U.S. Pat. Nos. 4,409,476; 4,437,761; 4,575,259; 4,671,651; 4,689,483; 5,004,913; 5,036,194 and 5,062,686. The typical suggested applications for extrinsic contact sensors are aerospace, chemical process and other life intolerant environments.  
           [0014]    A simple, direct reading of a conductor temperature is a more accurate and relevant operating or condition parameter for determining ampacity than current load (i.e., amperes). A current overloaded object fails because of thermal damage, not because of current, per se. An accurate real time measure of temperature of components of electrical power distribution systems will give electric power companies the ability to have real time dynamic ampacity ratings of their systems.  
         BRIEF SUMMARY OF THE INVENTION  
         [0015]    It is a goal of this invention to provide accurate, continuous, real-time temperature monitoring of critical electrical power transmission system components and equipment.  
           [0016]    It is an object of this invention to enable dynamic thermal circuit rating and operation of electrical power transmission lines and systems.  
           [0017]    It is an object of this invention to enable temperature monitoring of existing transmission system assets (equipment, components, conductors, substations, etc.) to allow safe and reliable operation at higher-than-statically-rated amperages.  
           [0018]    In accordance with this invention, apparatus and systems are provided for inexpensively and reliably monitoring and detecting in real time the actual temperature of a high voltage conductor, unaffected by the electric field of the conductor, and for reporting such actual temperatures. From knowledge of this temperature, high voltage power lines can be operated more confidently to employ all the current carrying capacity of the power line within maximum safe limits.  
           [0019]    As used in this invention, the term “conductor” includes any electrically conductive component in an electric power transmission and distribution system, and includes transmission lines and components and equipment in substations.  
           [0020]    The invention for monitoring actual operating temperatures of high voltage conductors comprises a novel combination of (i) an electrically and thermally conductive fixture for attachment to a high voltage conductor, (ii) a high voltage insulator having a high voltage end and a reference potential end and a fiber optic cable passageway from the reference potential end to the high voltage end, the insulator being connected at the high voltage end to the fixture, (iii) a fiber optic cable within the passageway of the insulator, the cable extending beyond the insulator, (iv) an optical temperature sensor head optically coupled to the fiber optic cable, the sensor head comprising a sensor crystal which transmits light that varies with temperature of the sensor crystal, and (v) an electrically and thermally conductive enclosure for the sensor head, supported in the fixture for thermally conductive contact with the high voltage conductor effective to couple the temperature of the high voltage conductor to the sensor crystal.  
           [0021]    The apparatus of this invention allows extrinsic sensors optically coupled to optical fibers to be reliably used for contact thermal measurement of high voltage conductors despite the extremely high strength electric field that is generated by electric current as it flows through high voltage conductors.  
           [0022]    Typically, extrinsic fiber optic contact temperature sensors in various other applications are constructed of all (or mostly all) dielectric insulating materials. Extension of this construction experience to a high voltage electric field environment is intuitively logical, since intrinsic sensor systems rely on the dielectric characteristics of optical fiber for determination of temperature in this environment. However, sensors constructed of dielectric insulating materials almost certainly will fail due to electric field induced damage if placed in contact with or in proximity to a high voltage conductor. If sensor components, whatever they are, are housed in a polymer, glass, ceramic or other dielectric insulator, the presence of even one tiny air gap, micro-bubble, void, point of humidity ingress, or other like flaw, will become a hot-spot in the high voltage electric field due to electrically induced breakdown and will eventually cause the sensor to fail.  
           [0023]    The present invention avoids this high risk mode of failure from intense electric fields in the presence of high voltage conductors, surprisingly, by employing in the novel combination described above, an electrically conductive casing for the sensor head. Because electric fields cannot penetrate closed electrical conductors, the enclosed sensor heads components cannot be affected by the powerful and inexorable degenerative effects of the extremely high strength electric field that is generated by electric current as it flows through high voltage conductors. For the casing to be an electrical conductor, the casing is metallic. The casing preferably is aluminum, which among non-exotic metals is bested in thermal conductivity only by copper, but does not set up a galvanic reaction with the most commonly employed high voltage conductor materials to the extent that copper does. The metallic casing has the advantages of very small thermal mass and very low thermal impedance.  
           [0024]    The novel combination of fixture, insulator, one or more optical fibers, sensor head and the enclosure encasing the sensor head described above preferably is combined in a unitary structure embodiment, that is, the elements of the combination are unitized in one “monolithic” ready-to-install structure, which, for brevity of reference hereinafter is sometimes called the “unitary structure”. The unitary structure allows easy and rapid attachment to conductors, and holds the sensor head and insulator in rigid and intimate thermal, physical, and electrical contact with the conductor to be monitored. The fixture also shields the sensor head from dynamic external environmental effects (sunlight, precipitation/humidity, wind, ambient temperature) that could effect the temperature reading. The fixture is tailored to the size, type, and voltage class of the conductor type to be monitored. The unitary structure can be attached to conductors ranging in size and type, for example, from six inch aluminum buses in transmission substations to three-fourths inch diameter high voltage transmission line cables. As the specified operating voltage changes, the length of the insulator and necessary length of optical fiber used is changed accordingly. The one or more optical fibers sealed and supported by the insulator may be one optical fiber, two optical fibers, or an array of fibers in a fiber optic cable. Preferably standard, multi-mode, all-dielectric optical fiber is used. The fiber is very rugged, and provides for high reliability trouble-free installation and operation.  
           [0025]    The sensor head of the invention and the unitary structure embodiment comprises a sensor crystal that transmits light that varies as the temperature of the sensor crystal changes, and optionally includes with some crystals a reflector arranged adjacent the sensor crystal distally to the one or more optical fibers, for reflecting light back through the sensor crystal. The sensor crystal may be one of several types. It may be one which shifts the wavelength of light passing through it with changing temperature, or one which modulates the intensity of transmitted light according to a change in temperature of the sensor, or one having material that absorbs incident light and produces a luminescence of wavelength that changes according to the temperature of the sensor. The luminescence may be fluorescent or phosphorescent. Preferably a fluorescence crystal comprises a chromium doped beryllium aluminum oxide or chromium doped yttrium oxide single crystal material, such as Alexandrite. Where the sensor crystal modulates the intensity of transmitted light according to a change in temperature of the sensor, the sensor crystal preferably has an absorption band edge that is temperature sensitive in the range from about −80° C. to about 200° C.  
           [0026]    The sensor head suitably further comprises a gradient index lens (GRIN lens) having a focal plane parallel to and contacting the end face of the one or more optical fibers extending from the high voltage side of the insulator, with another focal plane parallel to and contacting the sensor crystal.  
           [0027]    The sensing element of the foregoing apparatus of this invention expresses its optical message suitably with light from a source radiating light through the one or more optical fibers. The kind and power of the light source affects the sensitivity of the sensor and allows it to measure temperatures over a selected temperature range. If it is un-necessary to measure temperature with high resolution, accuracy and precision over a large temperature range, the light source may be an incandescent lamp with a band pass filter or a light emitting diode. If it is desirable to measure temperature over a large range with high resolution, accuracy and precision, coherent light producing a narrow bandwidth is preferred. In such event, the light source advantageously is a diode laser that launches light in the near infrared spectrum, particularly a diode laser that has a coupling output of at least about 20 decibels above 1 milliwatt, that is, at least about 100 milliwatts. When used with a luminescent sensor crystal, a Q switched laser diode is suitably employed. Employing a light attenuating absorption edge optical sensor that is temperature sensitive in the range from about 0° to about 200° C. powered by a laser diode, temperature detection with a resolution of 0.5° C., at an accuracy of 1° C. and precision of 1° C. over a range of 0-160° C. is possible.  
           [0028]    A detector is optically coupled to an optical fiber carrying said return light from the sensor. The coupling is at an end of the fiber optic cable remote from where the cable exits the insulator member of the apparatus. The detector receives and converts the optical information in the return light into information in another form, for example, voltage, representative of the temperature of said high voltage conductor.  
           [0029]    For example, the temperature of the high voltage conductor to which the sensor head is fixed may be detected by employing a photodetector such as a photodiode for detecting the return light and converting it to electrical values which, if analog, are then converted to digital values and processed by a computer against calibration curves data which correlates to the temperature of the sensor. Alternatively, a spectrometer may be used in the case of wavelength shift crystals such as GaAs and the position of the absorption shift analyzed and correlated back to temperature. Or an optical comparator may be employed for comparing intensity of the light from the light source with intensity of the optical radiation radiated by the sensor crystal to produce a result of the comparison, and a converter for converting the result into a representation of sensed temperature of the high voltage conductor.  
           [0030]    A data processor suitably receives and processes the information from the detector to determine the temperature sensed by the sensor crystal. The processor communicates with machine readable data storage to which the data of temperature determined by the data processor are written and read, and one or more human readable output devices such as a printer or display monitor is accessed by the processor to report data of temperature determined by the data processor. 
       
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       [0031]    [0031]FIG. 1 in depicts a system for monitoring and detecting temperatures of a plurality of high voltage conductors.  
         [0032]    [0032]FIG. 2 a  is a side sectional view end of a unitary high voltage conductor temperature monitoring apparatus of this invention, with a bottom view of an insulator portion of the apparatus projected (by dashed line) below the side sectional view.  
         [0033]    [0033]FIG. 2 b  is an end sectional view of apparatus of FIG. 2 a , showing a bottom view of an insulator portion of the apparatus projected (by dashed line) below the end sectional view.  
         [0034]    [0034]FIG. 3 depicts in top view an optoelectronic detection component of the system of FIG. 1.  
         [0035]    [0035]FIG. 4 a  is a schematic side sectional view of optically coupled components of an enclosed sensor head of the temperature monitoring apparatus of FIGS. 2 a  and  2   b.    
         [0036]    [0036]FIG. 4 b  is a schematical side section view of a sensor head employed in the sensor head of the temperature monitoring apparatus of FIG. 4 a.    
         [0037]    [0037]FIG. 4 c  is a cross sectional view along the lines  4   c  - 4   c  of FIG. 4 a .  
         [0038]    [0038]FIG. 5 depicts major components of a system for detecting and reporting temperatures sensed by the apparatus of FIGS. 2 a  and  2   b.   
     
    
     DETAILED DESCRIPTION OF THE INVENTION  
       [0039]    Referring to FIGS. 1, 2 a  and  2   b , reference numeral  10  indicates a unitary insulator monitor apparatus for detecting the temperature of a high voltage conductor  12 . By high voltage is meant a voltage in excess of 1 kV, for example in excess of 8 kV and upwards, typically 15 kV or 25 kV, even to levels of 134 kV and higher. The term “insulator” is to be understood as including not only an electrical component that is made substantially entirely of insulating material, but also a component, such as a surge arrester, that, while having an insulating outer surface, at some stage of its operation may become conductive.  
         [0040]    Apparatus  10  comprises a high voltage insulator assembly indicated generally at  15  in FIG. 1 having a high voltage end  16  and a reference potential end  18 . Insulator assembly  15  is constructed of one or more elongate units  14  of a generally cylindrical insulating core or rod  20  and a plurality of circular insulating watersheds  22  integral therewith and extending radially therefrom and circumferentially therearound. The core rod  20  is cemented and/or mechanically secured to metal fitting  26  at the high voltage end  16  and a metal end fitting  28  at reference potential end  18 . The metal end fittings provide mechanical connection to the insulator. The watersheds  22  increase the creepage path length end-to-end between the conductive terminals  26  and  28  of the insulator assembly  14  and deflect, or shed, water and other electrically conductive contaminants therefrom, as well known for those skilled in the art. The length and diameter of the insulator rod  20 , the number of units  14 , and the number and diameter of the sheds  22  of each unit  14  are chosen in dependence on the operating voltage of the insulator and on its operating environment, those parameters increasing the higher the operating voltage and the more severe the operating environment, in terms of pollution due to water, acids, and salts for example, as known in the art.  
         [0041]    Insulator rod  20  has a fiber optic cable passageway  32  extending from reference potential end  18  to high voltage end  16 . A fiber optic cable  30  passes within passageway  32  of insulator rod  20  from outside passageway  32  at the reference potential end  18  of insulator assembly  15  (see FIG. 1). In the embodiment depicted, insulator rod  20  and end fittings  26 ,  28  contain an axial passage  32 . A portion of a length of optic fiber cable  30  threads through passage  32 . Alternatively, rod  20  may contain a groove suitably spiral formed on its exterior surface and fiber cable  30  may be routed in the groove between end fittings  26 ,  28  and protectively covered exteriorly by a suitable sealant. See for example, U.S. Pat. No. 5,594,827. Both a passageway through the body of rod  20  and a sealed groove along the exterior of rod  20  are intended included by the term “passageway.” 
         [0042]    Insulator assembly  15  is connected to high voltage conductor  12  by an electrically and thermally conductive “clam shell” fixture or assembly  34 . Clam shell assemblies  34  are well known for those skilled in the art, and comprise upper and lower half-rings,  36  and  38  held together by screws  40 . Flanges  42 ,  43  along the inner annulus of the rings contact conductor  12 . A clamping screw  44  in upper half-ring  36  is used hold clam shell fixture  34  firmly in place on conductor  12 .  
         [0043]    Upper or high voltage end fitting  26  of insulator unit  14  suitably is a collar that connects clam shell fixture  34  to insulator rod  20  of the uppermost insulator unit  14  of insulator assembly  15 . The passage  32  in upper end fitting  26  is enlarged at well  33  to accept a distal portion of a sensor head  50 . Lower ring  38  has a bore  37  penetrating it from top to bottom at the base of the ring. A proximal portion of sensor head  50  is received within bore  37 . The enlarged passage  33  of upper end fitting  26  is not deep enough to accept the distal end of sensor head  50  sufficiently to allow the proximal portion of sensor head  50  to reside entirely within bore  37 , and is coordinated with the distance between the inner and outer radii of flanges  42 ,  43  to cause the most proximal portions of sensor head  50  to project above the inner radius of lower ring  38  for firm contact with conductor  12  when rings  36 ,  38  are fastened together and clamping screw  44  is tightened to fix fixture  34  onto conductor  12 . A helical spring may be seated in bore  33  to press against the distal end of sensor head  50  to assure that proximal end  62  of sensor head  50  is held tightly against conductor  12 . The proximal end  62  of metal enclosure  60  of sensor head  50  is in contact with conductor  12 , and metal enclosure  60  in bore  37  is in contact with the metal that makes up fixture half-ring  38 , so conductor  12 , enclosure  60  and fixture  34  are all at the same voltage potential.  
         [0044]    The half rings  36  and  38  do not make contact with conductor  12  along their entire length. As best seen in FIG. 2 a , conductor contact is made only by the rings  36 ,  38  at inner flanges  42 ,  43 , leaving a non-contact annulus  45 . Gaskets  45 ,  46 , suitably of silicon manufacture, are located adjacent flanges  42 ,  43  to keep rain and other contaminants from entering annulus  45  and to prevent wind drafts from producing convective cooling. This arrangement of claim shell rings  36 ,  38  fully encloses and protects from the external environment the contact interface of sensor head  50  with conductor  12 .  
         [0045]    In accordance with the invention, optical temperature sensor head  50  is optically coupled to fiber optic cable  30 . Sensor head  50  comprises a sensor crystal  52  which transmits light that varies with the temperature of the sensor crystal. Referring now to FIGS. 4 a ,  4   b  and  4   c , in the described embodiment sensor crystal  52  is bonded to a gradient index (“GRIN”) lens rod  54 . Two optic fibers  30   a ,  30   b  are bonded to GRIN rod  54  using a ferrule  56 . Optic fibers  30   a ,  30   b  are encased in a jacket  31  and make up cable  30  that threads through passage  32  of each insulator unit  14  in insulator assembly  15 , exiting insulator assembly  15  adjacent reference potential end  18 . Ferrule  56  is configured to maintain fibers  30   a ,  30   b  equidistant from the optical axis of GRIN lens rod  54 , as shown in FIG. 4 c . A cylindrical sleeve  58  encircles and supports sensor crystal  52 , GRIN lens rod  54 , optic fibers  30   a ,  30   b , cable  30  and ferrule  56 .  
         [0046]    An electrically and thermally conductive enclosure  60  for sensor head  50  surrounds cylindrical sleeve  58 , which resides within an annulus  57  between the outer diameters of sensor crystal  52 , GRIN lens rod  54 , cable  30  and ferrule  56  and the inner diameter of cylindrical enclosure tube  60 , and encloses sensor head  50  at a proximal end  62  of enclosure  60  that has a contoured end surface  63  to maximize contact surface area for improving thermal contact to circular conductor  12 .  
         [0047]    As diagrammatically depicted in FIG. 4 a , light from the input fiber  30   a  (indicated by arrow  64 ) is collimated by GRIN rod  54 . The collimated light then passes through sensor crystal  52  and is reflected from the rear surface  53  of sensor crystal  52  to return through the body of sensor crystal  52  and then through GRIN lens rod  54 . The temperature of high voltage conductor  12  is thermally transmitted by metallic enclosure  60  to sensor crystal  52  and affects the light transmitting behavior of sensor crystal  52 . Suitably, sensor crystal  52  may be a crystal which, as temperature changes, shifts its transmission spectrum to different wavelengths (i.e., light that is not absorbed); for example, but not by way of limitation, it can be a gallium arsenide or silicon crystal. GaAs and Si crystals are advantageous in that the spectral shift properties of such crystals are well established. Since one is concerned only with absorption shift, signal intensity or attenuation is not of material concern. Alternatively, sensor crystal  52  may be selected to modulate intensity of light transmission in variance to temperature of element  52 . Further alternatively, sensor crystal  52  may comprise a material that absorbs incident light from fiber  30   a  and produces a luminescence of wavelength that changes according to the temperature of sensor crystal  52 , for example, but not by way of limitation, sensor crystal  52  may be a chromium doped beryllium aluminum oxide or chromium doped yttrium oxide crystal material and the luminescence may be fluorescence, as in Alexandrite crystals.  
         [0048]    The optical signal emerging from the body of sensor crystal  52  now including a representation of the temperature of conductor  12 , is focused by GRIN rod  54  into output fiber  30   b  in the return direction indicated by arrow  65 .  
         [0049]    Apparatus  10  suitably is monolithic, that is, it comprises the components described above as a single sealed unit.  
         [0050]    Referring back to FIG. 1, a temperature monitoring, detecting and reporting system comprises a plurality of insulator monitor apparatuses  10  for detecting the temperature of a high voltage conductor  12  connected, for example, to different segments of a high voltage power line  12 . Each of apparatus units  10  is connected by a fiber optic cable  30  to an optoelectronics module  68 . Three cables  30  are shown. In the depicted embodiment, typically up to eight apparatus units  10  with eight optical cables may be operated from a single optoelectronics module  68 . Optoelectronics module  68  generates the optical signal  64  that is sent to sensor crystal  52  inside apparatus unit  10 . The return optical signal  65  containing the temperature information about conductor  12  is detected at optoelectronics module  68  and converted into an electronic signal. The electronic signals are carried over a multi-wire cable  70  to a data processing computer  72 . Data processing computer  72  may have the capability to interface with more than one optoelectronics modules  68 .  
         [0051]    Referring to FIG. 5, the electronic signal carried by data cable  70  passes to an analog to digital converter  73  in computer  72 . Digital signal data processing computer  72  processes the digital signals at  74  using calibration data files  75 , archives the processed data in storage  76 , displays at monitor  77  the processed data locally, and may communicate the data to, and receive communications from, a distant control center over a communications link  78 .  
         [0052]    [0052]FIG. 5 also depicts in block diagram the major components of optoelectronics module  68 . FIG. 3 depicts optoelectronics module  68  in greater detail. Referring to FIG. 3, optoelectronics module  68  comprises a light source assembly  80  within an enclosure  79 . Light source assembly  80  comprises a laser diode  81  driven by a driver, and cooled using an integral thermoelectric cooler. The laser diode driver and TEC controller are represented at  82  in FIGS. 3 and 5. Laser diode  81  is installed in a first optical mount  83 . A lens  84  inside a threaded tube is contained in an adjustable (x-y) second optical mount  85 . A third optical mount  86  holds the end of an optical fiber bundle  87 . Fiber bundle  87  is terminated in a cylindrical ferrule  88 , which may be rotated inside third optical mount  86 . All three optical mounts  83 ,  85 ,  86  are attached to a common base plate  89 . This allows light source assembly  80  to be pre-aligned prior to installation in optoelectronics module  68 . A small fiber optic cable/detector (not shown) may also be included in the source assembly to monitor the laser diode intensity.  
         [0053]    The fiber optic bundle  87  depicted in FIG. 3 contains eight individual fiber optic cables. These are separated and connected to bulkhead feed-throughs  90  that allow the external cables  30  to sensor head  50  to be connected outside enclosure  79 . A suitable area is provided inside enclosure  79  to accommodate the bend radius of fiber optic bundle  87 . The return optical signals  65  in the eight fibers  30   b  of the arrayed units  10  are coupled to receptacle assemblies  91 . Integrated circuit board  92  contains combined photodetector and preamplifier components that convert the return optical signals into electrical signals. Such units are well known to those skilled in the art and are commercially available, for example, from Hamamatsu Corporation, 360 Foothill Rd., Bridgewater, N.J. 08807. The electrical signals are amplified on board  92  are conveyed by conductor  93  from board  92  to a multi-pin connector  94 , from which the electrical signals are passed by data cable  70  to computer  72 . Other signal processing electronics may also be mounted on board  92 . Electrical power to the unit is provided at connector  95 . This is fed by conductor  96  to power supply  97  that provides the correct electrical power by conductor  98  to laser diode driver/TEC controller  82 , by conductor  99  to preamplifiers  92 , and by conductor  100  to laser diode  81 .  
         [0054]    Very substantial benefits are realizable from this invention. By providing accurate, real-time temperature monitoring of critical transmission system components and equipment, the present invention facilitates extension of the useful lifetimes of existing transmission system assets. Existing lines/systems/equipment can continue to be used to serve growing consumer demand, and the costs and efforts of system upgrades and/or new construction can reduced or deferred.  
         [0055]    The present invention, by enabling accurate, real-time temperature monitoring of critical transmission system components and equipment, when coupled with use of existing current monitors, will permit current and temperature to be used in combination to protect expensive and/or operationally critical system equipment from thermal damage, while, at the same time, maximizing use of actual ampacity, optimizing system use, and maximizing or extending useful system lifetime. Additionally, continuous temperature monitoring could reduce the frequency of labor and time intensive required routine, periodic inspections, would gather equipment thermal history, enable predictive analysis (end-of-life or remaining life estimates), detect and warn of incipient or imminent failure, and allow indicated maintenance or repair to be scheduled more intelligently and cost effectively. Just-in-time maintenance could be implemented, without compromising safety or reliability.  
         [0056]    In summary, real-time temperature monitoring of critical transmission system components, including transmission line and substation components and equipment, in accordance with this invention will enable power companies to improve reliability and safely move more power over their existing systems than is presently allowable. As a direct result, more demand can be satisfied with existing assets, operating revenues could be increased, some demand-driven new construction and/or upgrade costs and efforts could be deferred, and, at the same time, transmission system operational safety, reliability, and power transfer capability would be improved.