Systems and methods for operating overhead power lines

Abstract

A system and method for the operation of power lines, such as electric wires, in an electrical transmission or distribution network. The system and method may include the use of sensors, such as distributed and non-distributed sensors, to collect data on the power lines and use that data to take action on the power lines, such as improving transmission efficiency or mitigating power outages.

Description

[Technical Field]

[0001] This disclosure relates to the field of overhead power lines and to methods for the operation and management of overhead power lines within power grids. [Overview of the project]

[0002] In one embodiment, a method for operating an overhead power line is disclosed. The method comprises collecting distributed condition data from an optical fiber sensor extending along the length of an overhead electrical cable at a first time while the overhead power line is energized. The overhead electrical cable comprises a fiber-reinforced composite strength member and an electrical conductor surrounding the fiber-reinforced composite strength member. The distributed condition data includes at least one of distributed cable temperature data and distributed cable strain data. The method also comprises adjusting the current in the overhead electrical cable from a first current to a second current, thereby reducing the absolute difference between the first current and the allowable current.

[0003] The aforementioned methods have undergone several improvements, characterizations, and implementations, which may be applied individually or in any combination to the aforementioned methods. In one feature, the method further comprises a current determination step of determining the allowable current for the overhead electrical cable from the distributed condition data. In one improved form, the allowable current is greater than the first current, and the current adjustment step includes a step of increasing the current in the overhead electrical cable.

[0004] In one improved embodiment, the allowable current is less than the first current, and the current adjustment step includes reducing the current in the overhead electrical cable. In one embodiment, the current adjustment step includes diverting power from the overhead wire to a second overhead wire or to ground.

[0005] In another feature, the method further comprises a step of collecting non-distributed condition data associated with the overhead electrical cable, and the allowable current determination step includes a step of supplementing the distributed condition data with the non-distributed condition data. In one implementation, the non-distributed condition data includes one or more of ambient temperature, wind speed, solar radiation values, and precipitation values.

[0006] In another feature, the distributed condition data includes one or more distributed cable temperature data. In one implementation, the cable temperature data includes local temperature values ​​in the overhead electrical cable.

[0007] The distributed condition data includes at least distributed cable strain data. In one implementation, the distributed cable strain data includes local strain values ​​in the overhead electrical cable.

[0008] In another feature, the optical fiber sensor is embedded within the fiber-reinforced composite strength member. In another feature, the distributed condition data acquisition step includes receiving distributed condition data from an OTDR (Time-Domain Optical Reflectometer) operably mounted on the optical fiber sensor. In one implementation, the OTDR is a Brillouin Time-Domain Optical Reflectometer (BOTDR). In a further implementation, the OTDR is operably connected to a Remote Terminal Unit (RTU), which transmits the distributed condition data to a Data Acquisition Server (DAS). In a further implementation, the DAS transmits the data to a Supervisory Control and Data Acquisition (SCADA) system.

[0009] In another embodiment, a system for determining the power rating of a power line is disclosed. This system comprises an optical fiber sensor extending along the length of an overhead electrical cable in a power line, the overhead electrical cable comprising a fiber-reinforced composite strength member and an electrical conductor surrounding the strength member, and the optical fiber sensor is configured to provide distributed condition data along the length of the overhead electrical cable. An interrogation device is operably connected to the optical fiber sensor and configured to interrogate the optical fiber sensor and collect the distributed condition data from the optical fiber sensor, the distributed condition data including at least distributed temperature data. A data acquisition server (DAS) is configured to receive and analyze the distributed condition data from the interrogation device.

[0010] The aforementioned system has undergone several improvements, characterizations, and implementations, which may be applied to the aforementioned system individually or in any combination. In one feature, the DAS is configured to receive and analyze the distributed condition data by calculating the allowable current for the overhead electrical cable based on the distributed condition data and outputting the allowable current to a control device. In one implementation, the DAS is configured to receive and analyze the distributed condition data by calculating the real-time current carrying capacity of the overhead electrical cable and calculating the rate of change of the temperature of the overhead electrical cable as a function of the rate of change of the current flowing through the overhead electrical cable.

[0011] In another feature, the DAS is configured to receive and analyze second distributed condition data from the interrogation device, the second distributed condition data being collected by the interrogation device at a later time than the collection of the first distributed condition data.

[0012] In another feature, the control device is a human-machine interface (HMI) device. In another feature, the control device is an automatic controller programmed to adjust the current in the overhead electrical cable based on the calculated allowable current.

[0013] Another feature is that the DAS is operablely integrated with a Supervisory Control and Data Analysis (SCADA) system. In another feature, the interrogation device is further configured to collect distributed conditional data, which further includes distributed strain data.

[0014] In another feature, the optical fiber sensor is embedded within the fiber-reinforced composite strength member. In another feature, the interrogation device is a time-domain optical reflectometer (OTDR). In one implementation, the interrogation device is a Brillouin time-domain optical reflectometer (BOTDR).

[0015] In another feature, the DAS receives the distributed condition data from the interrogation device via a remote terminal unit (RTU). In another embodiment, a method for operating a power grid comprising overhead power lines is disclosed. The overhead power lines comprise overhead electrical cables having fiber-reinforced composite strength members and electrical conductors surrounding the fiber-reinforced composite strength members. The method comprises the step of determining at least a first environmental condition state from a geographical area, wherein at least a portion of the overhead power lines is located within the geographical area. Distributed condition data is collected from distributed sensors associated with the overhead electrical cables while the overhead power lines are energized, and the distributed condition data includes one or more of cable temperature data, cable strain data, and cable vibration data from at least the portion of the overhead power lines located within the geographical area. The environmental condition state and the distributed condition data are provided to a virtual model of the power grid.

[0016] The foregoing method is subject to several improvements, characterizations, and implementations, which may be applied to the foregoing method individually or in any combination. In another feature, the environmental condition state includes one or more of an ambient temperature value, a wind speed value, a solar radiation value, and a precipitation value.

[0017] In another feature, the environmental condition state is determined from a non-distributed sensor. In one implementation, the non-distributed sensor is selected from a temperature sensor, a wind sensor, a solar radiation sensor, and a precipitation sensor.

[0018] In another feature, the environmental condition state is determined from a weather report. In another feature, the distributed condition data collection step includes a step of collecting distributed cable temperature data.

[0019] In another feature, the distributed condition data collection step includes a step of collecting distributed cable strain data. In another feature, the distributed condition data collection step includes a step of collecting distributed cable vibration data.

[0020] In another feature, the virtual model updates historical model data within the virtual model based on the environmental condition state and the distributed condition data input to the virtual model. In one implementation, the update to the historical model data includes the step of correlating the environmental condition state with the distributed condition data. In a further implementation, the method further comprises the steps of determining the voltage or current in at least the portion of the overhead power lines within the geographical area, and correlating the determined voltage or current in the portion of the overhead power lines with the distributed condition data. In a further implementation, the method further comprises the steps of receiving a future weather forecast for the geographical area, and modeling further power line conditions in the virtual model of the power grid based on the future weather forecast, including the application of the correlated environmental condition state to the distributed condition data. In yet another implementation, the modeling determines an expected voltage or expected current value for the portion of the overhead power lines within the geographical area, wherein the expected voltage or expected current value is determined so as not to exceed a pre-selected temperature of the overhead power lines.

[0021] In another embodiment, a system for real-time temperature measurement in an overhead power line is disclosed. The system comprises an overhead power cable comprising a fiber-reinforced composite strength member and an electrical conductor surrounding the composite strength member, the overhead power cable being stretched between a plurality of support towers. An optical fiber sensor is embedded within the composite strength member and extends along the length of the composite strength member, comprising a glass fiber core and a polymer coating surrounding the glass fiber core having a thickness of approximately 250 μm or more, and having an outer diameter of approximately 600 μm or more. An optical time-domain reflectometer (OTDR) is operably mounted on a first end of the optical fiber sensor and is configured to measure at least a temperature profile along the length of the optical fiber sensor.

[0022] The aforementioned system has undergone several improvements, characterizations, and implementations, which may be applied to the aforementioned system individually or in any combination. In another feature, the polymer coating surrounding the glass fiber core has a thickness of approximately 300 μm or more. In yet another feature, the optical fiber sensor has an outer diameter of approximately 700 μm or more.

[0023] In another feature, the polymer coating surrounding the glass fiber is made from a thermoplastic polymer. In one implementation, the thermoplastic polymer is selected from the group consisting of polyaryl ether ketone (PAEK), liquid crystal polymer, polyamide-imide, and polybenzimidazole. In a further implementation, the thermoplastic polymer is a PAEK polymer. In yet another implementation, the PAEK polymer is selected from the group consisting of polyether ketone (PEK), polyether ether ketone (PEEK), polyether ketone ketone (PEKK), polyether ether ketone ketone (PEEKK), and polyether ketone ether ketone ketone (PEKEKK). In yet another implementation, the PAEK polymer includes PEEK.

[0024] In another feature, the end of the optical fiber sensor extends beyond the first end of the composite strength member. In one implementation, the OTDR is operably mounted to the end of the optical fiber sensor. In a further implementation, the OTDR is a Brillouin optical time-domain reflectometer (BOTDR).

[0025] In another feature, the system includes a remote terminal unit (RTU) that operably communicates with the OTDR. In one implementation, the RTU operably communicates with a data acquisition server (DAS) to enable the RTU to transmit the temperature profile data to the DAS along the length of the optical fiber sensor.

[0026] In another feature, the OTDR communicates wirelessly with the DAS. In another feature, the OTDR communicates with the DAS via an optical ground wire (OPGW). In another feature, the DAS is configured to convert the temperature profile data into readable temperature measurements and to transmit the readable temperature measurements to a human-machine interface (HMI). In one implementation, the HMI includes a processor programmed to overlay the readable temperature measurements onto a geographic map.

[0027] In another feature, the optical fiber sensor is a single optical fiber sensor embedded within the composite strength member. In another feature, the OTDR is configured to measure strain profile data along the length of the optical fiber sensor.

[0028] In another feature, the fiber-reinforced composite strength member includes carbon-reinforced fibers in a polymer matrix. In another feature, the fiber-reinforced composite strength member comprises an insulating layer surrounding the carbon-reinforced fibers. In another feature, the electrical conductor comprises a plurality of aluminum strands wound around the composite strength member.

[0029] These and other embodiments, characterizations, and implementations of the system and method will become apparent from the following description. [Brief explanation of the drawing]

[0030] [Figure 1] A diagram showing a portion of an overhead power line. [Figure 2] Cross-sectional view of an assembled dead end terminal. [Figure 3] Perspective view of an assembled and crimped dead end termination device. [Figure 4] A cross-sectional view of a splice, useful for connecting two electrical cable segments. [Figure 5A] Perspective view of an overhead electrical cable including a fiber-reinforced composite strength member. [Figure 5B] Perspective view of an overhead electrical cable including a fiber-reinforced composite strength member. [Figure 6A] Cross-sectional view of a fiber-reinforced composite strength member incorporating optical fibers embedded within a fiber-reinforced composite material. [Figure 6B] Cross-sectional view of a fiber-reinforced composite strength member incorporating optical fibers embedded within a fiber-reinforced composite material. [Figure 7] A perspective view of an overhead electrical cable with optical fibers incorporated into the surface of a structural member. [Figure 8] A perspective view of a portion of a transmission line incorporating several non-distributed sensors. [Figure 9] Cross-sectional view of a non-distributed sensor placed inside a dead-end device. [Figure 10] A schematic diagram illustrating an interaction system that shows communication between various components of a system. [Figure 11] A diagram illustrating an interaction system equipped with non-distributed sensors fixed to an electrical cable. [Modes for carrying out the invention]

[0031] A power grid is a networked system that generates and supplies electricity, or power, to end users. Broadly speaking, a power grid consists of power sources that generate power, transmission lines for transmitting power at high voltage over long distances, substations equipped with transformers for reducing or increasing voltage, and distribution lines for distributing power to end users at lower voltages. Transmission lines are primarily overhead transmission lines consisting of multiple electrical cables suspended from support towers, also known as steel towers. Suspended electrical cables conduct electricity at relatively high voltages, for example, about 60 kV or more. Since electricity in a power grid is transmitted primarily in the form of alternating current (AC), each transmission line consists of three or more electrical cables to transmit electricity in three phases. Each set of three electrical cables is characterized as a single electrical circuit. A transmission line may consist of a single electrical circuit, or it may consist of two or more electrical circuits, i.e., two or more overhead lines.

[0032] Similarly, distribution wiring is typically configured to carry electricity over shorter distances at lower voltages, such as less than approximately 60kV, using overhead electrical cables in an AC configuration.

[0033] This disclosure relates, for example, to systems and methods for the operation of overhead power lines as components of a power grid. The following disclosure primarily refers to the transmission and / or distribution of electricity in a three-phase AC configuration, but the systems and methods disclosed herein may also be applicable to DC (direct current) power lines. Thus, as used herein, the term overhead power line encompasses both overhead transmission lines and overhead distribution lines, and is used to refer to a single electrical cable in the case of DC power, or three electrical cables forming an electrical circuit in the case of AC power. In either case, overhead power lines comprise long electrical conduction cables supported to the ground by a series of support towers. As will be discussed later, overhead power lines also comprise other important components, such as hardware for attaching the electrical cables to the support towers, and insulators to prevent current leakage from the electrical cables to the terrain below.

[0034] Figure 1 shows such an overhead power line 10, more specifically an overhead transmission line. The transmission line 10 comprises overhead electrical cables that conduct electricity and are supported above the terrain by two or more support towers, such as support towers 12a / 12b / 12c. More specifically, the transmission line 10 comprises two electrical circuits, each circuit comprising three electrical cables for transmitting AC power. The transmission line can extend for several kilometers and requires extremely long lengths of electrical cable. As a result, the electrical cable typically consists of two or more electrical cable segments that are electrically joined together to form a continuous electrical path along the transmission line.

[0035] As mentioned above, one function of a support tower is to safely lift electrical cables above the terrain. In this regard, electrical cables are attached to the support tower using different types of hardware. Some of the support towers are called dead-end towers or anchor towers, such as tower 12a. Dead-end towers are located at termination points, e.g., substations or where power lines are routed underground. Dead-end towers, such as tower 12a, may also be required where electrical cables change direction (e.g., bend), cross roads or other structures where there is a high risk of damage or injury if the electrical cables fail, or at regular intervals along long straight routes. In such cases, two electrical cable segments are mechanically attached to a dead-end tower under high tension and electrically connected to form a continuous electrical path. As shown in Figure 1, electrical cable segment 11a is fixed (e.g., anchored) to tower 12a using a dead-end termination 13 (e.g., tension clamp) and electrically connected to an adjacent electrical cable segment 11b via an electrical jumper 14. The electrical cable segments 11a / 11b are insulated from the support tower 12a by an insulating string 15.

[0036] Another hardware component that can be used as a power line is called a splice. While a single overhead cable segment can be several thousand meters long, a transmission line can extend for hundreds of kilometers over which power must be transmitted. To cover these distances, overhead line workers must sometimes join two electrical cable segments together, for example, between support towers. In this case, one or more splices may be used to join the two electrical cable segments. A splice functions as a mechanical joint that holds the two ends of an electrical cable segment together, and also as an electrical joint that allows current to flow through the splice. As shown in Figure 1, splice 16 operably connects electrical cable segment 11c to electrical cable segment 11d, forming a mechanical joint and a continuous electrical path.

[0037] Figure 2 shows a cross-section of an assembled termination device (e.g., a dead end), such as the dead end 13 shown in Figure 1. The dead end 20 shown in Figure 2 is similar to those shown and described in Bryant's International Publication No. 2005 / 041358 and U.S. Patent No. 8,022,301 by Bryant et al. (each incorporated herein by reference in its entirety).

[0038] Broadly characterized, the dead end 20 comprises a gripping assembly 21 and a connector 22 for anchoring the dead end 20 to a tower, for example, as shown in Figure 1, with a fastener 23 positioned at the base end of the dead end 20. At the tip of the dead end 20 opposite the fastener 23, the dead end 20 is operably connected to an overhead electrical cable segment 11, which comprises an electrical conductor 24 supported by a strength member 25, for example, a fiber-reinforced composite strength member sometimes called a core.

[0039] The gripping assembly 21 firmly grips the reinforcing member 25 to secure the overhead electrical cable segment 11 to the dead end 20. As shown in Figure 2, the gripping assembly 21 comprises a compression type fitting (e.g., a wedge fitting), more specifically, a collet 26 having a collet lumen 27 (e.g., a bore) that surrounds and grips the reinforcing member 25. The collet 26 is positioned in a collet housing 28, and as tension is applied to the electrical cable segment 11 (e.g., pulled towards a support tower), friction is generated between the reinforcing member 25 and the collet 26 as the collet is further pulled towards the collet housing 28. The outer conical shape of the collet 26 and the fitting inner funnel shape of the collet housing 28 increase the compression on the reinforcing member 25, ensuring that the reinforcing member does not slip out of the collet 26 and thus the overhead electrical cable segment 11 is secured to the dead end 20.

[0040] The connector 22 comprises a fastener 23 (e.g., an eyebolt) and a gripping assembly threaded portion 34 located on the gripping assembly end 36 of the connector body 35. The gripping assembly threaded portion 34 is configured to operably engage with a connector threaded portion 37 on the inner surface of the collet housing 28, facilitating the movement of the connector 22 relative to the collet 26, and the engaging threaded portions 34 and 37 push the collet 26 into the collet housing 28 as the connector 22 rotates relative to the collet housing 28. This enhances the compressive grip of the collet 26 against the strength member 25, further securing the overhead electrical cable 11 to the dead end 20. The fastener 23 is configured to be mounted on the dead end tower, as shown in Figure 1, to secure the dead end 20 and, therefore, the electrical cable 11 to the dead end tower.

[0041] As shown in Figure 2, the outer sleeve 29 is positioned over the gripping assembly 21 and the end of the electrical cable segment 11. The outer sleeve 29 includes a conductive body 30 to facilitate a continuous electrical path between the electrical conductor 24 and the jumper plate 31. An inner sleeve 32 (e.g., a conductive inner sleeve) may be positioned between the conductor 24 and the conductive body 30 to facilitate the electrical connection between the conductor and the conductive body. The conductive body 30 may be manufactured from aluminum, and the jumper plate 31 may be formed integrally with the conductive body or welded onto the conductive body. The jumper plate 31 is mounted on a connector plate 33 and configured to facilitate the formation of an electrical path through a jumper cable between the electrical cable segment 11 and another electrical cable segment (not shown), for example, as shown in Figure 1.

[0042] Figure 3 shows a perspective view of a crimped (e.g., compressed) dead end 13 on an overhead electrical cable segment 11. The dead end 13 includes a connector having a fastener 23 extending outward from the base end of an outer sleeve 29. The jumper plate 31 is formed integrally with the outer conductive sleeve body 30 for electrical connection to the connecting plate, as shown in Figure 2. As shown in Figure 3, the outer conductive sleeve body 30 is crimped (e.g., crimped over) two regions of the substructure, namely, the crimped sleeve body region 30a and the crimped sleeve body region 30b. The crimped sleeve body region 30b is generally located over the middle portion of the lower connector, and the crimped sleeve body region 30a is generally located over a portion of the electrical cable segment 11 (see, for example, Figure 2). The compressive force applied to the outer sleeve body 29 during the crimping operation is transmitted to the lower components, namely the connector below the crimping area 30b and a portion of the electrical cable segment 11 below the crimping area 30a, permanently securing the conductive body 30 to the electrical cable segment 11 and the lower connector.

[0043] The dead ends broadly described with respect to Figures 2 and 3 can be used with various overhead electrical cable configurations. The dead ends shown in Figures 2 and 3 are particularly useful for overhead electrical cables having fiber-reinforced composite strength members. For example, a compression wedge gripping element having a collet positioned in a collet housing (e.g., Figure 2) allows the fiber-reinforced composite strength member to be gripped under high compressive forces without a significant risk of fracturing the composite material. However, those skilled in the art will recognize that other configurations for such dead ends have been disclosed in the art, and the foregoing examples are merely one example of a configuration that may be used to secure overhead electrical cable segments to structures such as support towers.

[0044] Figure 4 is a cross-sectional view of splice 16, for example, a splice as shown in Figure 1. As shown in Figure 1, the splice is configured to mechanically and electrically connect the ends of two overhead cable segments to form a continuous electrical path between the two cable segments. As shown in Figure 4, splice 16 connects two electrical cable segments 11a and 11b. Splice 16 includes gripping assemblies 21a and 21b that operably grip the electrical cable segments 11a and 11b, respectively. The gripping assemblies may include, for example, a collet and housing configuration as shown in Figure 2. To mechanically join the two electrical cable segments, the gripping assemblies 21a / 21b are connected to a single connector 22, which is, for example, screwed in. To form a continuous electrical path between electrical cables 11a / 11b, for example between two electrical conductors 24a / 24b, a conductive outer sleeve 29 is positioned on the substructure and crimped to at least the connector body 22 and the ends of the electrical cables 24a and 24b. Conductive inner sleeves 32a / 32b may be inserted between the conductors 24a / 24b and the outer sleeve 29 to facilitate a robust electrical connection between them. As with the dead ends shown in Figures 2 and 3, those skilled in the art will understand that other configurations of splices are disclosed in the art and the foregoing examples are merely examples of what may be used to electrically and mechanically connect two electrical cable segments.

[0045] The systems and methods disclosed herein may be implemented by wires incorporating overhead electrical cables having various configurations. One conventional configuration is called an aluminum conductor steel reinforced cable (ACSR) cable, in which an outer aluminum conductor strand is supported by a strength member having multiple steel wires, which are twisted together, for example, to form the strength member. Other configurations that implement a strength member formed from multiple twisted metal wires include an aluminum core steel supported (ACSS) cable. These and similar configurations are known to those skilled in the art.

[0046] The systems and methods disclosed herein may be implemented by wires incorporating these conventional overhead electrical cables, but in certain embodiments, the systems and methods are particularly useful when the wires incorporate one or more electrical cable segments utilizing fiber-reinforced composite strength members. As used herein, a fiber-reinforced composite strength member is a strength member comprising elongated structural elements with reinforcing fibers in the bonding matrix. Such composite materials offer many advantages compared to metallic strength elements, such as steel wire, including lightweight and favorable mechanical properties such as high tensile strength and a low coefficient of thermal expansion (CTE). Such strength members may comprise a single (i.e., one or fewer) fiber-reinforced strength element (e.g., a one-part fiber-reinforced composite strength member), or may consist of several fiber-reinforced composite strength elements combined (e.g., twisted, braided, or bundled together) to form a strength member. Thus, the terms strength member and strength element may be used interchangeably in this disclosure, particularly when the strength member comprises a single strength element.

[0047] The systems and methods disclosed herein may be used in conjunction with a wire having a strength member and one or more electrical cable segments incorporating one or more dispersed sensing elements. The dispersed sensing element is a long wire or strand that enables the acquisition of location-specific data along the length of the dispersed sensing element. In one particular feature, the dispersed sensing element includes one or more optical fibers, e.g., optical fiber sensors. As used herein, the term optical fiber refers to a long, continuous fiber configured to transmit incident light along the length of the fiber. Typically, a glass optical fiber comprises a transparent core and a cladding layer surrounding the core, manufactured from different materials (e.g., having different refractive indices) to reduce the loss of light exiting the transparent core and passing through the outside of the optical fiber. The optical fiber can be a single-mode optical fiber or a multimode optical fiber. A single-mode optical fiber has a small-diameter transparent core (e.g., with a diameter of about 9 μm) surrounded by cladding and having a total diameter of about 125 μm. A single-mode fiber is configured to allow only one mode of light to propagate. Multimode optical fibers have a larger transparent core, for example, with a diameter of about 50 μm or more, which allows multiple modes of light to propagate. Multimode optical fibers also have a cladding surrounding the transparent core. Optical fibers may be manufactured entirely from one or more polymers. However, polymer optical fibers may not have sufficient optical attenuation and adequate heat resistance to withstand the manufacture and / or use of structural members incorporating the optical fiber. In this regard, glass optical fibers are preferred for use as optical fiber sensors, for example, due to their low attenuation.

[0048] In one feature, the optical fiber may be characterized as having a glass fiber core and a polymer coating surrounding the glass fiber core having a thickness of approximately 250 μm or more, and the optical fiber having an outer diameter of approximately 600 μm or more. For example, the polymer coating surrounding the glass fiber core may have a thickness of approximately 300 μm or more. In another example, the outer diameter of the optical fiber is approximately 700 μm or more, for example, approximately 800 μm or more. The polymer coating surrounding the glass core may be advantageously manufactured from a thermoplastic polymer, in one configuration, the thermoplastic polymer is selected from the group consisting of polyaryl ether ketone (PAEK), liquid crystal polymer, polyamide-imide, and polybenzimidazole. For example, the PAEK polymer may be a PAEK polymer selected from the group consisting of, for example, polyether ketone (PEK), polyether ether ketone (PEEK), polyether ketone ketone (PEKK), polyether ether ketone ketone (PEEKK), and polyether ketone ether ketone ketone (PEKEKK).

[0049] While this disclosure intends to describe the use of other types of distributed sensing elements, it generally refers to the use of optical fiber sensors. However, it should be understood that this disclosure is not strictly limited to the use of optical fiber as a distributed sensing element, and other distributed sensing elements may be used.

[0050] As described above, overhead electrical cables typically comprise a central reinforcing member and electrical conductors arranged around and supported by the reinforcing member. While reinforcing members have traditionally been made from steel, such steel reinforcing members are increasingly being replaced by reinforcing members made from composite materials, particularly fiber-reinforced composites, which offer many important advantages. Such fiber-reinforced composite reinforcing members may comprise a single fiber-reinforced composite reinforcing element, as shown in Figure 5A. Alternatively, the composite reinforcing member may consist of a plurality of individual fiber-reinforced composite reinforcing elements (e.g., individual rods) that are operably combined (e.g., twisted or braided) to form a reinforcing member, as shown in Figure 5B.

[0051] Referring to Figure 5A, the overhead electrical cable 11A comprises an electrical conductor 24A having a layer of first conductive strands 40a spirally wound around a fiber-reinforced composite strength member 25A having a single fiber-reinforced composite strength element. A second layer of conductive strands 40b is spirally wound around the first conductive strands 40a to increase the volume of the electrical conductor 24A. The conductive strands 40a / 40b may be manufactured from a conductive metal such as copper or aluminum, and are typically manufactured from aluminum, e.g., hardened aluminum, annealed aluminum, and / or aluminum alloys, for use in exposed overhead electrical cables. The conductive material (e.g., aluminum) does not have sufficient mechanical properties (e.g., sufficient tensile strength) to self-support when stretched between support towers, and therefore requires the use of the strength member 25A. In the configuration shown in Figure 5A, the fiber-reinforced composite strength member 25A comprises a single strength element having a high-tensile strength portion 41a (e.g., containing carbon fibers) surrounded by a galvanic layer 42a that prevents harmful reactions between carbon and aluminum strands 40a in the high-tensile strength portion 41a. The galvanic layer 42a also contains glass fibers arranged in a bonding matrix and is formed integrally with the high-tensile strength portion 41a, for example by pultrusion. Alternatively, the galvanic layer may be formed around the high-tensile strength portion by wrapping tape around it or by arranging a polymer.

[0052] Figure 5B shows an embodiment of an overhead electrical cable 11B similar to the electrical cable shown in Figure 5A, where the reinforcing member 25B comprises a plurality of individual fiber-reinforced reinforcing elements (e.g., reinforcing elements 43B) twisted together to form the reinforcing member 25B. Although Figure 5B shows one containing seven individual reinforcing elements, a multi-element reinforcing member may contain any number of reinforcing elements suitable for a particular application. The individual reinforcing elements may be formed of carbon fibers, and each element may have a galvanic layer as shown in Figure 5A. Alternatively, or in addition to this, the bundle of reinforcing elements may be completely surrounded by a galvanic layer 42a, for example, by wrapping insulating tape around the bundle of reinforcing elements. Examples of such multi-element composite strength members include, but are not limited to, the multi-element aluminum matrix composite strength member shown in U.S. Patent No. 6,245,425 by McCullough et al., the multi-element carbon fiber strength member shown in U.S. Patent No. 6,015,953 by Tosaka et al., and the multi-element strength member shown in U.S. Patent No. 9,685,257 by Daniel et al. Each of these U.S. patents is incorporated herein by reference in its entirety. Other configurations of fiber-reinforced composite strength members may be used in electrical cables.

[0053] As described above, the fiber-reinforced composite material from which the fiber-reinforced strength member is manufactured contains reinforcing fibers operably arranged in a bonding matrix. The reinforcing fibers are typically substantially continuous reinforcing fibers extending along the length of the fiber-reinforced composite material, but the fiber-reinforced composite material may also contain short reinforcing fibers (e.g., fiber whiskers or chopped fibers) dispersed through the bonding matrix. The reinforcing fibers may be selected from a wide range of materials, including but not limited to carbon, glass, boron, metal oxides, metal carbides, high-strength polymers such as aramid fibers or fluoropolymer fibers, and basalt fibers. Carbon fibers are particularly advantageous due to their very high tensile strength and / or their relatively low coefficient of thermal expansion (CTE).

[0054] The bonding matrix may include, for example, a plastic (e.g., a polymer) such as a thermoplastic polymer or a thermosetting polymer. The bonding matrix may also be a metal matrix, such as an aluminum matrix. One example of an aluminum matrix fiber-reinforced composite is illustrated in U.S. Patent No. 6,245,425 by McCullough et al., which is incorporated herein by reference in its entirety.

[0055] One particularly advantageous composite strength member configuration for overhead electrical cables is the ACCC® composite configuration, available from CTC Global Corporation in Irvine, California, and shown in U.S. Patent No. 7,368,162 by Hiel et al., as described above. In commercial embodiments of ACCC® electrical cables, the strength member is a single-element strength member with a substantially circular cross-section, comprising an inner core of substantially continuous reinforced carbon fibers arranged in a polymer matrix. The carbon fiber core is surrounded by a rigid insulating layer of glass fibers, which are arranged in the polymer matrix and selected to insulate the carbon fibers from surrounding conductive aluminum strands. See Figure 5A. The glass fibers also have a higher modulus of elasticity than the carbon fibers and provide flexibility so that the strength member and electrical cable can be wound onto spools for storage and transport.

[0056] While the above-described properties of the fiber-reinforced strength members are disclosed as desirable for use in overhead electrical cables, similar properties may be desired when the strength members disclosed herein are used in other structures such as bridge cables and messenger cables.

[0057] In certain embodiments, but not limited to, systems and methods for operating overhead power lines rely on the implementation of one or more distributed sensors, such as optical fiber sensors. As used herein, a distributed sensor is a sensor capable of taking data, for example, measurements, along a substantially continuous length of the sensor. For example, an optical fiber sensor extending along the length of an electrical cable allows for the detection of temperature and / or strain along substantially the entire length of the electrical cable. Thus, the data collected and analyzed from the distributed sensor may include the identification of measurement locations along the distributed sensor. The distributed sensor may be associated with an electrical cable by being placed within the electrical cable. For example, the distributed sensor may be placed within a conductive strand along the length of the electrical cable. In one feature, the optical fiber is associated with a reinforcing member of one or more electrical cable segments. By operably associating the optical fiber with the reinforcing member, it may be possible to determine some important properties of the reinforcing member, such as the strain the reinforcing member is experiencing at a particular location.

[0058] In this regard, one or more elongated continuous optical fibers (e.g., optical fiber sensors) may be operably associated with a fiber-reinforced composite strength member. In one configuration, the optical fiber sensor may be embedded within the fiber-reinforced composite (e.g., within the bonding matrix). The optical fiber sensor may extend from a first end to a second end of the strength member, for example, so that the entire length of the optical fiber sensor and substantially the entire length of the overhead electrical cable can be interrogated through the optical fiber sensor. By appropriate selection of the type of optical fiber sensor and its arrangement, the strength member and electrical cable segments can be interrogated to evaluate the conditions of the strength member. A single optical fiber sensor may be used in the overhead electrical cable, but the effectiveness of the systems and methods disclosed herein can be improved by providing multiple optical fiber sensors, one or more of which are associated with the strength member.

[0059] Referring to Figures 6A and 6B, cross-sectional views of a single-element fiber-reinforced composite strength member are shown. The configuration of the fiber-reinforced strength member is similar to that of the strength element shown in Figure 5A, and includes an inner portion of high-tensile strength fibers surrounded by an outer layer of insulating material, and an inner portion of carbon fibers surrounded by an outer galvanic layer containing glass fibers, for example. As shown in Figure 6A, the fiber-reinforced composite strength member 25A includes a single optical fiber sensor 44a located at the center of the strength member 25A, i.e., at the center of the high-strength portion 41A. In other words, the optical fiber sensor 44a is positioned substantially along the central axis of the strength member 25A. In the configuration shown in Figure 6B, the strength member is configured similarly to the configuration shown in Figure 6A. As shown in Figure 6B, the strength member 25B includes a second optical fiber sensor 44b in addition to the optical fiber sensor 44a. The optical fiber sensor 44b is offset from the optical fiber sensor 44a, i.e., offset from the central axis of the strength member 25B. In any case, the arrangement of one or more optical fiber sensors along the central axis of the strength member can advantageously reduce or eliminate the effects of bending modes on the optical fiber sensors. Examples of various configurations of optical fibers embedded in fiber-reinforced composite strength members are shown in U.S. Patent Application Publication No. 2021 / 0048469 by Dong et al., which is incorporated herein by reference in its entirety.

[0060] Figures 6A and 6B are merely examples of possible configurations in which the optical fiber sensor is operably associated with the fiber-reinforced composite strength member. For example, the fiber-reinforced strength member may incorporate more than one or two optical fiber sensors, such as three, four, or more optical fiber sensors. Such additional optical fiber sensors may be used to increase measurement sensitivity, for redundancy, or for other reasons. In any case, certain advantages can be realized by incorporating the optical fiber sensor within the fiber-reinforced composite strength member (e.g., within the bonding matrix). For example, the optical fiber sensor is completely protected from the external environment by the bonding matrix (e.g., shielded), ensuring that natural or artificial environmental factors (e.g., impact stress) do not significantly impair the performance of the optical fiber sensor. Furthermore, the optical fiber sensor is physically and tightly coupled to the matrix within the fiber-reinforced composite so that forces acting on the fiber-reinforced composite strength member (e.g., tensile strain) are fully and consistently transmitted to the optical fiber sensor along the entire length of the strength member, ensuring accurate dispersed measurements.

[0061] Distributed sensing elements (e.g., fiber optic sensors) may also be associated by alternative means with fiber-reinforced strength members and, therefore, with electrical cables containing strength members. For example, one or more fiber optic sensors may be attached to the outer surface of a strength member along its length. Figure 7 shows a perspective view of one exemplary embodiment of an overhead electrical cable 711 and a cross-sectional view of a strength member assembly 725 relating to this structure. The electrical cable 711 comprises a strength member assembly 725 having a strength member 725a having a high-tensile strength fiber-reinforced composite core 725b having a galvanic layer 725c of carbon fibers and glass fibers in a bonding matrix. Electrical conductors 724 surround the strength member assembly 725. In the embodiment shown in Figure 7, the strength member assembly 725 includes fiber optic sensors 744 arranged linearly along the outer surface of the strength member 725a. A tape layer 725d is wound around the strength member 725a and the fiber optic sensors 744 to connect the fiber optic sensors to the strength member and form the strength member assembly 725. More specifically, the tape layer 725d comprises a strip of tape spirally wound around the reinforcing member 725a such that the tape overlaps itself along the seam, so that the tape layer 725d covers the entire reinforcing member (e.g., virtually without gaps) and the optical fiber sensor 744, and that the tape layer 725d is positioned between the optical fiber sensor 744 and the electrical conductor 724 along its length. It is recognized that the structure shown in Figure 7 is merely illustrative, and that the optical fiber sensor may be associated with the electrical cable using other structures. Examples of such other structures are disclosed in International Publication No. WO2021 / 222663, which is incorporated herein by reference in its entirety.

[0062] The fiber-reinforced strength elements described above may be manufactured by means known to those skilled in the art. In one example, a fiber-reinforced composite strength member is formed by a pultrusion process in which a tow of continuous reinforcing fibers (e.g., carbon fibers and glass fibers) is pulled through a bonding matrix material (e.g., through an epoxy resin bath), and then cured to bond the fibers together and form a fiber-reinforced composite. Optical fibers are supplied by manufacturers in continuous lengths (e.g., several thousand meters) on a spool by a similar method to that used for fiber tows (e.g., carbon fiber tows and glass fiber tows). Thus, optical fibers can be integrated into the pultrusion process together with the reinforcing fibers.

[0063] One reason why fiber optic sensors are preferred is that devices and methods for collecting distributed data from optical fibers are known in the art. For example, a fiber optic sensor may be operably coupled to an interrogation device comprising a coherent light source (e.g., a pump laser source) that allows light to be controlled and passed through to the fiber optic sensor (e.g., pulsed). The light source may be configured to transmit a signal (e.g., pulse) to the fiber optic sensor, and the interrogation (e.g., measurement) of conditions in the fiber optic sensor is performed by analyzing the light backscattered by the optical fiber. In this regard, the interrogation device may include a signal detector, such as an interferometer, configured to detect the backscattered light signal.

[0064] For example, the components of backscattered light can be classified into Rayleigh, Brillouin, and Raman components. The backscattered Rayleigh component has the same frequency (i.e., the same wavelength) as the primary light source and has a relatively high intensity. The backscattered Rayleigh component can be analyzed to determine the length of the optical fiber by using optical time-domain reflectivity measurement (OTDR). Therefore, the backscattered Rayleigh component may be used to detect breaks in the optical fiber that indicate potential damage to the fiber-reinforced composite strength member. However, the backscattered Rayleigh component cannot provide further important information about the condition of the optical fiber.

[0065] In one feature, the interrogation device implements OTDR analysis of at least one of the following: Raman backscattered light components (e.g., Raman dispersive sensors) and Brillouin backscattered light components (e.g., Brillouin dispersive sensors). Both Raman dispersive and Brillouin dispersive sensor systems use a nonlinear interaction between a primary optical signal and an optical fiber. When a primary optical signal of a known wavelength is input to an optical fiber, a very small amount of the optical signal is backscattered at every point along the optical fiber (e.g., a backscattered light signal). The backscattered light contains components that are shifted at different wavelengths than the primary optical signal. The optical component shifted to a longer wavelength (i.e., lower energy) is called the Stokes component, and the optical component shifted to a shorter wavelength (i.e., higher energy) is called the anti-Stokes component. By detecting and analyzing these shifted backscattered light components, it is possible to obtain information about the local conditions of the optical fiber, such as its strain and temperature, at different points along the length of the optical fiber.

[0066] In one configuration, one or more optical fibers are used as a Raman dispersive temperature sensor. In a Raman dispersive temperature sensor, the interaction between the primary optical signal (e.g., a pump laser signal) and optical phonons in the optical fiber material (e.g., silica glass) generates two backscattered light components in the backscattered light spectrum: Raman-Stokes and Raman-Anti-Stokes. The Raman-Anti-Stokes component is temperature-dependent; that is, the intensity of the Raman-Anti-Stokes component increases with increasing temperature of the sensing optical fiber. As a result, the relative intensities of the Raman-Stokes and Raman-Anti-Stokes backscattered light components can be measured and used to determine the temperature of the optical fiber sensor. The Raman-Stokes and Raman-Anti-Stokes backscattered light components can be detected by a signal detector such as an interferometer or a dispersive spectrometer, which may be a component of an interrogation device.

[0067] The position of temperature readings along the length of the optical fiber can also be determined from the Raman backscattered light component. When a pulsed optical signal is used to interrogate the optical fiber, the backscatter intensity of the Raman-Stokes and Raman-anti-Stokes backscattered light components can be recorded as a function of time (e.g., "round trip" time), enabling the capture of a temperature profile along the length of the optical fiber sensor, i.e., along the length of the fiber-reinforced composite strength member.

[0068] In one example, a fiber-reinforced composite strength member and a operably associated fiber optic sensor include a multimode fiber. A multimode fiber optic sensor with a high numerical aperture can increase the intensity of backscattered light, which can be important due to the relatively small magnitude of the Raman backscattered light signal.

[0069] In another configuration, the interrogation device incorporates Brillouin dispersive sensing to interrogate the fiber optic sensor. Brillouin dispersive sensing utilizes Brillouin backscattering, which is the result of the interaction between the primary optical signal and time-dependent optical density fluctuations (i.e., acoustic phonons) within the fiber optic sensor. The acoustic phonons generate periodic modulation of the refractive index (e.g., optical density) of the fiber optic sensor material. Brillouin scattering occurs when the propagating primary optical signal is diffracted back by this moving "lattice," resulting in a backscattered optical signal with frequency and wavelength-shifted components.

[0070] As the temperature of the optical fiber sensor increases, the wavelength of the back-Brillouin scattering component shifts further away from the primary wavelength. This wavelength shift can be used to determine the temperature of the optical fiber sensor. Similar to Raman dispersive temperature sensors, the position of the temperature reading along the length of the optical fiber sensor can be determined using the time-of-flight information of the backscattered light signal.

[0071] However, unlike Raman dispersion sensors, Brillouin dispersion sensors can also be used to detect strain (e.g., tensile strain) in optical fiber sensors. That is, changes in strain within an optical fiber sensor also cause a wavelength shift in the Brillouin backscatter component due to changes in the optical density of the optical fiber sensor. As a result, the strain experienced by the optical fiber sensor at any point along its length can be determined, and therefore the strain experienced by the fiber-reinforced composite strength member can also be determined.

[0072] Brillouin dispersive sensors may be configured to implement techniques based on natural Brillouin, i.e., Brillouin time-domain reflectivity measurement (BOTDR), or techniques based on stimulated Brillouin, i.e., Brillouin time-domain analysis (BOTDA). One advantage of a BOTDR configuration is that a single coherent pump light source can be utilized, i.e., at one end of the optical fiber sensor. In certain systems, BOTDR also provides the ability to simultaneously measure temperature and strain in a single optical fiber sensor. However, the detected backscattered light signal is typically very weak and requires signal processing and long integration times.

[0073] In another configuration, a Brillouin dispersive interrogation device implements BOTDA technology. BOTDA uses a backpropagating input optical signal (sometimes called a "probe" or "counterwave" signal) with a wavelength difference equal to the Brillouin shift. This probe signal enhances the phonon ensemble in the optical fiber sensor, resulting in a higher signal-to-noise ratio. If the primary (pump) optical signal is a short pulse and its reflected intensity is analyzed with respect to time-of-flight and wavelength shift, it is possible to obtain a profile of the Brillouin shift along the length of the optical fiber sensor. BOTDA technology generally requires that the wavelengths of the two optical signals propagating in opposite directions are very stable (e.g., synchronized laser sources). Advantageously, temperature resolutions of less than 1.0°C or even less than 0.5°C may be achieved. Furthermore, very small strain shifts experienced by the optical fiber sensor may be detected.

[0074] Therefore, interrogation devices implementing Brillouin dispersion sensing are useful for temperature monitoring and are particularly well-suited for strain measurement. In this regard, it is typically necessary to know the wavelength shift of the optical fiber at a reference temperature in order to calculate the absolute temperature at any point along the optical fiber. Also, it is typically necessary to know the wavelength shift of a strain-free fiber in order to enable absolute strain measurement. In any case, determining the strain over its length in an overhead electrical cable, for example in a structural member, can be used to determine the tension in the electrical cable. The tension can then be used to determine, for example, the deflection along the electrical cable, and whether the deflection is due to a thermal load or a mechanical load, such as icing. Cable deflection can result in contact between the electrical cable and an object beneath it. If the slack across three cables in a single circuit is not uniform, one electrical cable may come into contact with another cable directly below it, causing a flashover.

[0075] In addition to temperature and strain, optical fibers can be used as dispersed acoustic sensors, such as vibration sensors, to detect events such as Aeolian oscillations, galloping, and corona discharge. Aeolian oscillations are caused by low-speed crosswinds hitting overhead cables. This results in low-amplitude, high-frequency vibrations in the cable that can cause fatigue damage. Galloping is a large-amplitude, low-frequency motion of waves passing through a cable, typically caused by moderately strong and steady crosswinds acting, for example, on an asymmetrically iced conductor surface. Galloping can cause cable damage and, if the wave amplitude is excessive, can also cause flashover. Dispersed acoustic sensing optical fibers may be operablely connected to an interrogation device, such as an interrogation device configured to detect Rayleigh backscatter components from an optical fiber.

[0076] According to this disclosure, the characteristics of one or more overhead electrical cable segments may be interrogated (e.g., monitored) in real time during the operation of the power line, for example, during the operation of a power distribution network, thereby enabling the systems and methods disclosed herein to actively monitor and operate the power line in real time. As used herein, the term “real time” is not necessarily limited to an immediate response time of a few seconds, but is broadly interpreted to mean that when an operator is receiving information quickly from distributed sensors, for example, when querying an interrogation device within 30 minutes or less, characteristics are measured and action can be taken within a relatively short time, for example, within 1 hour or less. Such systems and methods may include, for example, continuous or semi-continuous querying of overhead electrical cables to detect temperature conditions, strain conditions, vibrations, mechanical loads, and / or extensions of the overhead electrical cables, and acting in response to specific identified conditions. From the determination of these conditions, other conditions and / or states, such as deflection of a particular electrical cable segment or current carried by the electrical cable segment, may be determined.

[0077] Distributed sensing elements, such as optical fiber sensors, are preferred for implementing the methods of this disclosure, but this disclosure is not limited to such devices and systems. For example, in some embodiments, non-distributed sensors may be used independently or in conjunction with distributed sensors. Non-distributed sensors are sensors spaced along wires, for example, along electrical cables. Examples of non-distributed sensors that may be useful for obtaining the temperature of an electrical cable include, but are not limited to, thermocouples and infrared cameras. Furthermore, environmental sensors, such as wind stations and humidity sensors, may be incorporated to collect data, for example, to further refine the measurements.

[0078] Figure 8 shows a portion of an overhead power line incorporating several nondistributed sensors. The power line 810 comprises a segment of overhead electrical cable 811 located between two support towers 812a and 812b. A first nondistributed sensor 882 is directly attached to the electrical cable 811. The nondistributed sensor 882 may be characterized as a multifunction sensor, for example, a sensor capable of detecting two or more characteristics of the electrical cable 811. Examples of such multifunction sensors include the TLM transmission line monitor available from Lindsey Manufacturing, Inc. in Azusa, California, and the multifunction sensor described in U.S. Patent Application Publication 2020 / 0209283 by Mohr et al. (which is incorporated herein by reference in its entirety). Such multifunction sensors may be capable of detecting cable clearance on terrain, cable deflection (e.g., using a tilt sensor), current, and temperature. These units are self-powered, drawing power from, for example, electrical cables, and typically include an antenna for data transmission, for example, using satellite or wireless communication technology.

[0079] In some features, the non-dispersive sensor is not directly attached to the overhead electrical cable. For example, Figure 8 also shows a camera 886 mounted on a support tower 821b so as to enable the camera to image the overhead electrical cable 811. Camera 886 may have infrared capabilities so as to enable the camera to detect the temperature of the electrical cable 811. Camera 886 may also have visible imaging capabilities so as to enable, for example, image analysis to show the deflection of the electrical cable 811. Similar to the multifunction sensor 882, camera 886 may have an antenna or similar device for wireless data transmission.

[0080] It is also recognized that non-distributed sensors may be used to collect data that cannot be obtained directly from overhead electrical cables. For example, Figure 8 shows a weather station 884 operably mounted on a support tower. Such a weather station 884 may be capable of detecting ambient conditions such as wind speed, wind direction, solar radiation level, and humidity. Since these ambient conditions can affect the conditions of the electrical cables, knowledge of these conditions may be useful, for example, to evaluate the characteristics of the electrical cables using distributed sensors.

[0081] Other non-distributed sensors may be mounted on electrical cables to protect them from the external environment and / or to enable them to detect specific conditions of the electrical cable. Figure 9 shows one embodiment of such a non-distributed sensor. As shown in Figure 9, a dead-end device 920 secures an overhead electrical cable 911, similar to the dead-end device shown in Figure 2, for example. A gripping assembly 921 is fixed to a strength member 925, for example, to a segment of the strength member from which the electrical conductor 924 has been stripped to expose the strength member. A sensor 982 is mounted directly to its exposed portion of the strength member 925, for example using epoxy or other mounting means. In one feature, the sensor 982 is a strain sensor capable of measuring the strain of the strength member when coupled to it. Since the sensor 982 is positioned between the gripping assembly 921 and the electrical conductor 924, the strain beneath the sensor indicates the strain on the entire electrical cable 911. Furthermore, when the dead-end device is installed, it is also advantageous that the sensor 982 is protected from the environment by, for example, an outer sleeve 929. In this regard, access to the sensor 982 may be provided by wires 983a / 983b, for example, ported through the outer sleeve 929 as shown, or ported through the gripping assembly 921 and connector 922 for access through port 984.

[0082] The aforementioned components of the interlogging system may be integrated using various communication and control protocols to enable a user, such as a utility operator, to effectively manage power lines and, consequently, the power distribution network including the power lines. For example, an interlogging device along a power line (e.g., an OTDR) may be operably connected to a remote terminal unit (RTU), which is configured to communicate with a server, such as a data acquisition server (DAS), by transmitting data to such a server. The OTDR may be internally connected to the RTU, for example, if the RTU is built into the OTDR, or it may be connected to an external RTU. In any case, the RTU may communicate with the server using one or more communication protocols, including wireless protocols such as cellular and / or satellite communications, or wired protocols, such as by directly connecting the RTU to an optical grounding wire (OPGW) including communication fiber.

[0083] A server, for example, a DAS, may include a (e.g., programmed) logical processor configured to convert raw data, such as distributed temperature and / or strain data received from an RTU, into readable measurements of temperature and strain values. For example, the DAS may calculate the temperature along an overhead cable as a function of location. These values ​​may then be transmitted to a human-machine interface (HMI), such as a computer or other device, which can display information for observation and / or action to be taken. In one implementation, the HMI is configured to overlay the temperature and / or strain values ​​onto a geographic map display representing the power grid or a portion of the power grid.

[0084] Figure 10 shows a schematic diagram of one such system. As shown in Figure 10, the DAS and HMI may be standalone systems or may be integrated with a user's database system, such as a Supervisory Control and Data Acquisition (SCADA) system. SCADA systems are widely implemented throughout the utility industry, and the integration of distributed data from OTDR to such SCADA systems is advantageous in that it allows operators to refine their control over power lines, and thus the power grid or any part thereof, by collecting and analyzing distributed data essentially in real time, for example, the data may include temperature and / or strain profiles across power lines. While systems and methods are frequently described herein as being implemented with SCADA systems, it is recognized that, for example, communication of data from an interaction device may be made to any kind of database system for data storage and / or to notify actions such as control operations.

[0085] In one particular embodiment, a method for operating overhead power lines is disclosed. The overhead power lines may be components of transmission lines or distribution lines. Broadly characterized, the method may comprise collecting distributed condition data from optical fiber sensors extending along the length of the overhead electrical cable while the overhead power line is energized. The collected data may include distributed cable temperature data and / or distributed cable strain data. Subsequently, based on the collected distributed condition data, the current (e.g., amperes) in the overhead electrical cable is adjusted from a first current to a second current, for example, the adjustment of the current reduces the absolute difference (e.g., |xy|) between the first current and the allowable current. Using distributed sensors to collect distributed condition data in near real-time is advantageous because it allows the operator to know the actual temperature of the electrical cable and take immediate action based on that data. For example, if the ambient temperature surrounding overhead power lines is very low and / or strong crosswinds are blowing across the lines, the operator may be able to increase the amperage of the lines without exceeding the absolute maximum operating temperature of the lines. Conversely, if the ambient temperature is very high and / or solar radiation is very high, the operator may use near real-time temperature data to reduce the amperage to a safer level so that the line temperature decreases.

[0086] For example, this method may include a step of determining the allowable current of an overhead electrical cable at a first time from distributed condition data, for example, a step of determining the allowable current from the near real-time temperature of the overhead electrical cable. If the allowable current is greater than the first current, for example, if the wire is operating below the temperature rating of the electrical cable (e.g., below its rated capacity), the step of adjusting the current in the overhead electrical cable may include, for example, increasing the current in the overhead electrical cable so that the temperature of the electrical cable rises closer to the temperature rating of the electrical cable. If the allowable current is less than the first current, for example, if the wire is operating near or above its temperature rating, the step of adjusting the current in the overhead electrical cable may include decreasing the current in the overhead electrical cable. In certain features, the step of adjusting the current in the overhead electrical cable may include stopping the current by, for example, diverting power from the overhead wire to a second overhead wire or electrical ground.

[0087] In one implementation, the method may include a step of collecting non-distributed condition data associated with the overhead electrical cable. For example, the step of determining the allowable current of the overhead electrical cable may include supplementing distributed condition data with non-distributed condition data to calculate the allowable current, for example. The non-distributed condition data may include one or more of the following: ambient temperature, wind speed, solar radiation value, and precipitation values ​​such as rainfall and / or snowfall.

[0088] As described above, distributed condition data may include distributed cable temperature data. Since the data is inherently distributed, the cable temperature data may include local temperature values ​​in the overhead electrical cable, for example, the temperature of the cable at a specific location along the cable, which may differ from the average temperature of the cable due to defects in the cable or local weather events.

[0089] Furthermore, as mentioned above, distributed condition data may include distributed cable strain data. Similar to cable temperature data, cable strain data may include local strain values ​​in overhead electrical cables, for example, strain experienced by the cable at a specific location along the cable, and this strain may differ from the mean strain in the cable due to defects in the cable or local events such as strong winds or icing that put a load on the cable.

[0090] The features described above regarding the configuration of the cable and interrogation system may be implemented by this method. For example, the optical fiber sensor may be embedded in a fiber-reinforced composite strength member. In another example, the step of collecting distributed condition data includes receiving distributed condition data from an OTDR operably mounted to the optical fiber sensor. The OTDR may be a BOTDR. Furthermore, certain steps of the method may be performed using a system comprising a DAS and an HMI, for example, schematically shown in Figure 10.

[0091] In another embodiment, a system for determining the power rating of a power line is disclosed. The system may include an optical fiber sensor extending along the length of an overhead electrical cable in the power line, the overhead electrical cable comprising a fiber-reinforced composite strength member and an electrical conductor surrounding the strength member, and the optical fiber sensor is configured to provide distributed condition data along the length of the overhead electrical cable. An interrogation device is operably connected to the optical fiber sensor and configured to interrogate the optical fiber sensor and collect distributed condition data from the optical fiber sensor, the distributed condition data including at least distributed temperature data. A data acquisition server (DAS) is configured to receive and analyze the distributed condition data from the interrogation device. Such a system may, advantageously, be configured to implement the aforementioned methods for operating overhead power lines.

[0092] The DAS may be configured to receive and analyze distributed condition data by calculating the allowable current of overhead power lines based on distributed condition data and outputting the allowable current to a control device. In one implementation, the DAS is configured to receive and analyze distributed condition data by, for example, calculating the real-time current carrying capacity of overhead power cables based on near real-time cable temperature and calculating the rate of change of the overhead power cable temperature as a function of the change of current flowing through the overhead power cable.

[0093] The DAS may also be configured to receive and analyze second distributed condition data from an interrogation device, which is collected by the interrogation device at a later point in time than the collection of the first distributed condition data. This process may be repeated, for example, to continuously collect temperature data over time in order to correlate cable temperature with current (amperes) in the wire.

[0094] The control device may be a human-machine interface (HMI) device. In another feature, the control device may be an automatic controller programmed to adjust the current in an overhead electrical cable based on a calculated allowable current. For example, programming instructions for adjusting the current may be stored in a non-temporary medium such as a memory storage device, e.g., a solid-state or magnetic memory storage device. The DAS may also be operablely integrated with a Supervisory Control and Data Analysis (SCADA) system.

[0095] The interrogation device may also be configured to collect distributed condition data, which is distributed strain data. The strain data may be useful in identifying cable slack, such as thermal deflection or icing load deflection, so that an operator can take action to mitigate the detrimental effects of deflection. Actions may be similar to those described above in terms of adjusting or eliminating current in an electrical cable, for example, manually or through a programmed automatic controller, using a control device.

[0096] As described above, the optical fiber sensor may be embedded in a fiber-reinforced composite strength member. The interrogation device may be an optical time-domain reflectometer (OTDR), such as a Brillouin optical time-domain reflectometer (BOTDR). The DAS may receive distributed condition data from the interrogation device, for example, through a remote terminal unit (RTU).

[0097] In another embodiment, the systems and methods disclosed herein may be implemented to collect data and feed it into a virtual model (e.g., a “digital twin”) of a power grid. The virtual model is a virtual (e.g., digital) representation of a physical system that serves as a digital counterpart to the physical system for purposes such as operation, simulation, testing, monitoring, and maintenance. Broadly characterized, the virtual model may be used to predict future events under a given set of conditions and to take or suggest preemptive actions when necessary. However, the effectiveness of the virtual model is limited by its quality, e.g., the granularity of the data fed into the virtual model.

[0098] For applications to power grids, physical assets such as power plants, substations with transformers, and power lines may be represented or "twinned" as virtual assets in a virtual model. The virtual model may also include a virtual representation of the environment in which the assets are located, such as terrain, waterways, streets, and bridges. Data such as cable temperature data may be acquired from non-distributed sensors and input into the virtual model, and a graphical representation of the physical assets may be output, for example, to an HMI, to show the operator the real-time temperature of the power lines, or simply to indicate that the power lines are operating outside a pre-selected temperature range, for example, by issuing an alarm. The operator may have the ability to change system parameters, such as by reducing the voltage or current across the power lines in response, and / or the virtual model may be configured to facilitate automatic adjustments to the power lines.

[0099] A virtual model of the power grid may be updated, for example, continuously or intermittently with new data. For example, the virtual model may collect and store data over time, called historical data. This historical data may be analyzed and correlated so that the virtual model can perform a simulation of the physical system. In other words, historical data can be used to predict future behavior based on correlations with past data.

[0100] In current practice, data is collected from power lines using non-distributed cable sensors, as shown and explained above with respect to Figure 8, and input into a virtual model. For example, as shown in Figure 11, a non-distributed cable temperature sensor 1182 may be attached to an overhead electrical cable 1111 to determine the temperature of the electrical cable at that location. However, that temperature may not represent the temperature of the entire electrical cable, even at a relatively short distance from the non-distributed sensor 1182. As shown in Figure 11, for example, segment 1111a of electrical cable 1111 may be significantly warmer than nearby segment 1111b due to a localized rain shower or other precipitation event on segment 1111b. However, non-distributed sensors do not provide this information unless many sensors are placed along the electrical cable. Furthermore, other non-distributed environmental sensors, such as ambient temperature sensors or wind sensors, may not be placed sufficiently in the same location as the non-distributed cable sensors to provide useful data with a high level of granularity.

[0101] According to this disclosure, distributed data, such as distributed cable temperature data, cable strain data, and / or cable vibration data, is supplied to a virtual model. Advantageously, the distributed data supplied to the virtual model may include location data associated with the temperature data. That is, the virtual model may be supplied with enough location data to enable the virtual model to show temperature over the length of the wire. Any anomalies detected in the strain values ​​of the wire may be similarly localized and taken action by an operator as necessary.

[0102] In one embodiment, the overhead power line includes an overhead electrical cable having a fiber-reinforced composite strength member and an electrical conductor surrounding the fiber-reinforced composite strength member, as described above. The method includes, for example, determining at least a first environmental condition state from a geographical area where at least a portion of the overhead power line is located. Distributed condition data is collected from one or more distributed sensors associated with the overhead electrical cable while the overhead power line is energized. The collected distributed condition data may include one or more of cable temperature data, cable strain data, and cable vibration data.

[0103] Subsequently, environmental condition data and distributed condition data are provided to a virtual model of the power grid, for example, by communication. Environmental conditions are qualitative or quantitative values ​​related to the environmental conditions under which power lines are installed, such as ambient conditions. For example, environmental conditions may be qualitative, such as a determination that it is raining, or quantitative, such as temperature values, such as ambient temperature values, wind speed values, wind direction values, solar radiation values, or precipitation values, such as precipitation amount or precipitation rate over a period of time. In one implementation, environmental conditions are determined quantitatively, for example, from non-distributed sensors such as temperature sensors, wind sensors, solar radiation sensors, and precipitation sensors. In another implementation, environmental conditions are determined qualitatively or quantitatively from weather reports, such as weather radar data that may indicate the presence of precipitation, wind speed, ambient temperature, etc.

[0104] In one implementation, the virtual model updates, for example, historical model data within the virtual model based on environmental conditions and distributed condition data input to the virtual model. Updating the historical model data may also include, for example, correlating environmental conditions with distributed condition data so that the historical data can be used to run simulations in the virtual model. In addition, voltage or current may be determined for at least a portion of the overhead power lines within the geographical area. This voltage or current value may then be correlated with distributed condition data and / or environmental conditions. In a further implementation, the virtual model may receive future weather forecasts for the geographical area and virtually model future power line conditions based on the future weather forecasts. This modeling may include applying correlated environmental conditions to distributed condition data. Furthermore, the modeling may output predicted voltage or current values ​​for portions of the overhead power lines within the geographical area, where the predicted voltage or current values ​​do not exceed a pre-selected temperature for the overhead power lines, e.g., the maximum allowable temperature.

[0105] In the embodiments described above in which a virtual model is generated and / or updated, the results may be output to a graphical user interface (GUI) for observation and / or interaction by an operator. Such a GUI may include illustrations of lower ground elements such as streets, highways, bodies of water, bridges, buildings, and topographic information such as elevation. Distribution network infrastructure such as power generation facilities, transmission lines, substations, distribution lines, and support towers may be laid on top of these elements. In this way, the status of transmission lines and / or distribution lines can be graphically shown to the operator, for example, so that the operator can easily check the temperature and / or strain of a particular wire.

[0106] It is well known that increasing the current applied to an electrical cable causes its temperature to rise due to Joule heating. Electrical cables have an absolute maximum operating temperature called a "temperature rating." The "ampere capacity" of a given electrical cable is the maximum current in amperes that the cable can continuously carry without exceeding its temperature rating, for example, without damaging the cable due to the increased heat.

[0107] Therefore, the amperage capacity of an electrical cable limits the amount of current that an operator can continuously apply to the wires through which the electrical cable is installed. While electric current can be stepped up almost instantaneously across a wire, the resulting temperature rise in the electrical cable is delayed, and the final steady-state temperature of the electrical cable with the increased current is not reached until a certain period of time has elapsed. The rate of change of electrical cable temperature (ΔT) associated with the step-up of current is given by the current. c The current is approximately exponential and can be quantified using the thermal time constant (τ), which is typically around 5 to 20 minutes for most transmission lines. Therefore, operators may take advantage of this transient (e.g., transient) condition to apply a current exceeding the maximum allowable current under steady-state conditions.

[0108] However, known techniques for determining the amperage that can be safely applied over a selected period are based on the assumption that other factors that may affect cable temperature, such as ambient temperature, wind speed, wind direction, and solar radiation, are constant. In reality, these factors can vary considerably over time and over the length of the cable. This requires operators to have simultaneous data on these factors in order to make an accurate assessment of the maximum allowable applied current. Such simultaneous data is typically collected using non-dispersive sensors.

[0109] In one embodiment, a method for operating a power line includes enabling the safe operation of the power line under transient conditions over a desired period (t) so as to ensure that steady-state constraints are not exceeded. As applied to the above scenario, the method allows a line operator to temporarily increase the amperage of the applied current on the power line to a value that would result in a cable temperature exceeding a desired maximum temperature when the system is allowed to enter steady-state conditions. In this way, the operator may temporarily apply a current higher than would otherwise be permissible to the power line without exposing the power line to an operating temperature exceeding a desired maximum temperature. In one implementation, the method may be carried out using distributed sensors associated with the power line, which may reduce or eliminate the need for non-distributed sensors. The use of distributed sensors allows for accurate and near real-time temperature measurement of the power line, which can be applied in a manner that does not rely on knowledge of ambient conditions to accurately determine the amount of rising current that can be applied, since ambient conditions are taken into account in the distributed sensor measurement.

[0110] When used in this specification, "maximum desired temperature" (T c ) is an arbitrary temperature value selected by the operator as the upper limit of the line temperature. The maximum desired temperature may be the temperature at which the wire is most likely to suffer permanent damage, for example, the temperature rating of the electrical cable mentioned above, but the operator may select a different upper limit of the maximum desired temperature. Thus, for the remainder of this description, the temperature rating of the electrical cable is referred to as the maximum desired temperature, but other temperatures may be selected by the operator for the maximum desired temperature.

[0111] In one embodiment, a method for temporarily operating overhead power lines under transient conditions is disclosed, which allows the transient conditions to be utilized without exceeding the upper steady-state conditions. In this embodiment, the applied current amperage (I f Once the temperature rating (T) is determined and the current is applied for a sufficient amount of time to reach a steady state condition, the applied current is equal to the temperature rating (T) of the wire. c) exceeds. That is, the electric wire may be operated with a current that results in a steady-state temperature that exceeds the temperature rating of the electrical cable, except for short periods that do not allow the electric wire to reach its steady-state temperature. In other words, the value of I f is determined when I f causes the electrical cable to reach its temperature rating within the allotted time for the electrical cable.

[0112] This method may include the step of determining the steady-state thermal time constant (τ) of the overhead electrical cable for at least a first cable temperature (T1) and a second cable temperature (T2). In one implementation, the steady-state thermal time constant is determined from data previously collected for the electric wire. In this implementation, the collected data points include the temperature of the electrical cable that correlates to the number of amperes in the electrical cable. The collection of this data eliminates the need for knowledge of ambient conditions. As a result, the thermal time constant can be determined from two previously collected data points, for example, a temperature T1 that correlates to the number of amperes I1 and a temperature T2 that correlates to the number of amperes I2.

[0113] When correlation data is not available, for example, during the initial stages of operation of the electric wire, the thermal time constant τ is determined by applying two different numbers of amperes to the electric wire I i and I f to allow the electric wire to reach a steady state and measuring the corresponding temperatures T i and T f .

[0114] The thermal time constant can be determined using the following formula.

[0115]

Equation

[0116] Here, τ = thermal time constant of the electrical cable T i = initial cable temperature T f = final cable temperature m=mass C p = heat capacity R(T c ) = conductor temperature T c AC resistance of the conductor in I f = final current I i = Initial current.

[0117] Using a known thermal time constant, the initial cable temperature (T i ) is measured using a distributed sensor associated with the electrical cable, and the initial line current (I) associated with the initial line temperature is measured. i ) is determined. Advantageously, the current in the electrical cable can also be determined using a distributed sensor, for example, using a BOTDR, by analyzing the Brillouin frequency shift and correlating the frequency shift with the amperage.

[0118] The period (t) for operating with the increased current is selected, for example, by the line operator. Then, the final steady-state temperature (T) is determined. f ) but τ, t, T i and T c It is determined using the following:

[0119]

number

[0120] T f Once the value is determined, the final current (I f ) can be determined as follows:

[0121]

number

[0122] Next, the operator checks the thermal rating T of the electrical cable. c The current I increased for a time t without exceeding a certain value. f You may apply it. Various embodiments of methods and systems for operating electric wires have been described in detail, and it will be apparent that modifications and adaptations of these embodiments will be conceivable to those skilled in the art. However, it is expressly understood that such modifications and adaptations are within the spirit and scope of this disclosure.

Claims

1. A method for operating overhead power lines, A distributed condition data collection step comprising: collecting distributed condition data from an optical fiber sensor extending along the length of an overhead electrical cable in a first time period while the overhead power line is energized with a first current, wherein the overhead electrical cable comprises a fiber-reinforced composite strength member and an electrical conductor surrounding the fiber-reinforced composite strength member, and the distributed condition data includes at least one of distributed cable temperature data and distributed cable strain data; A method comprising: a step of adjusting a first current in an overhead electrical cable from a first current to a second current, wherein the current adjustment step reduces the absolute difference between the first current and the allowable current.

2. The method according to claim 1, further comprising a step of determining the allowable current for the overhead electrical cable from the distributed condition data.

3. The allowable current is greater than the first current. The method according to claim 1 or 2, wherein the current adjustment step includes a step of increasing the current in the overhead electrical cable.

4. The allowable current is less than the first current, The method according to claim 2, wherein the current adjustment step includes a step of reducing the current in the overhead electrical cable.

5. The method according to claim 4, wherein the current adjustment step includes a step of distributing power from the overhead power line to a second overhead power line or to ground.

6. The method according to any one of claims 1 to 5, comprising the step of collecting non-distributed condition data associated with the overhead electrical cable, wherein the allowable current determination step includes the step of supplementing the distributed condition data with the non-distributed condition data.

7. The method according to claim 6, wherein the non-dispersive condition data includes one or more of ambient temperature, wind speed, solar radiation value, and precipitation value.

8. The method according to any one of claims 1 to 7, wherein the distributed condition data includes one or more distributed cable temperature data.

9. The method according to claim 8, wherein the cable temperature data includes local temperature values ​​in the overhead electrical cable.

10. The method according to any one of claims 1 to 9, wherein the distributed condition data includes at least distributed cable strain data.

11. The method according to claim 10, wherein the distributed cable strain data includes local strain values ​​in the overhead electrical cable.

12. The method according to any one of claims 1 to 11, wherein the optical fiber sensor is embedded in the fiber-reinforced composite strength member.

13. The method according to any one of claims 1 to 12, wherein the distributed condition data acquisition step includes the step of receiving distributed condition data from an OTDR (time-domain optical reflectometer) operably attached to the optical fiber sensor.

14. The method according to claim 13, wherein the OTDR is a BOTDR (Brillouin optical time-domain reflectometer).

15. The method according to claim 13 or 14, wherein the OTDR is operably connected to a remote terminal unit (RTU), and the RTU transmits the distributed conditional data to a data acquisition server (DAS).

16. The method according to claim 15, wherein the DAS transmits data to a monitoring, control and data acquisition (SCADA) system.

17. A system for determining the power rating of electric wires, An optical fiber sensor extending along the length of an overhead electrical cable in an electric wire, wherein the overhead electrical cable comprises a fiber-reinforced composite strength member and an electrical conductor surrounding the strength member, and the optical fiber sensor is configured to provide distributed condition data along the length of the overhead electrical cable. An interrogation device operably connected to the optical fiber sensor and configured to interrogate the optical fiber sensor and collect the distributed condition data from the optical fiber sensor, wherein the distributed condition data includes at least distributed temperature data. A system comprising: a data acquisition server (DAS) configured to receive and analyze the distributed conditional data from the interrogation device.

18. The system according to claim 17, wherein the DAS is configured to receive and analyze the distributed condition data by calculating the allowable current for the overhead electrical cable based on the distributed condition data and outputting the allowable current to a control device.

19. The system according to claim 18, wherein the DAS is configured to receive and analyze the distributed condition data by calculating the real-time current carrying capacity of the overhead electrical cable and calculating the rate of change of the temperature of the overhead electrical cable as a function of the rate of change of the current flowing through the overhead electrical cable.

20. The system according to any one of claims 17 to 19, wherein the DAS is configured to receive and analyze second distributed condition data from the interrogation device, the second distributed condition data being collected by the interrogation device at a later time than the collection of the first distributed condition data.

21. The system according to any one of claims 17 to 20, wherein the control device is a human-machine interface (HMI) device.

22. The system according to any one of claims 18 to 21, wherein the control device is an automatic controller programmed to adjust the current in the overhead electrical cable based on the calculated allowable current.

23. The system according to any one of claims 17 to 22, wherein the DAS is operably integrated with a monitoring, control and data analysis (SCADA) system.

24. The system according to any one of claims 17 to 23, wherein the interrogation device is further configured to collect distributed conditional data, the distributed conditional data further comprising distributed strain data.

25. The system according to any one of claims 17 to 24, wherein the optical fiber sensor is embedded in the fiber-reinforced composite strength member.

26. The system according to any one of claims 17 to 25, wherein the interrogation device is an optical time-domain reflectometer (OTDR).

27. The system according to any one of claims 17 to 25, wherein the interrogation device is a Brillouin optical time-domain reflectometer (BOTDR).

28. The system according to any one of claims 17 to 27, wherein the DAS receives the distributed condition data from the interrogation device via a remote terminal unit (RTU).

29. A method for operating a power grid equipped with overhead power lines, wherein the overhead power lines comprise an overhead electrical cable having a fiber-reinforced composite strength member and an electrical conductor surrounding the fiber-reinforced composite strength member, and the method is A step of determining at least a first environmental condition state from a geographical area, wherein at least a portion of the overhead power lines are located within the geographical area. A distributed condition data collection step, which involves collecting distributed condition data from distributed sensors associated with the overhead electrical cable while the overhead power line is energized, wherein the distributed condition data includes one or more of the following from at least a portion of the overhead power line located within the geographical area: cable temperature data, cable strain data, and cable vibration data. A method comprising the step of providing the aforementioned environmental conditions and the distributed condition data to a virtual model of the power grid.

30. The method according to claim 29, wherein the environmental conditions include one or more of the ambient temperature, wind speed, solar radiation, and precipitation values.

31. The method according to claim 29 or 30, wherein the aforementioned environmental conditions are determined from a non-dispersive sensor.

32. The method according to claim 31, wherein the non-dispersive sensor is selected from a temperature sensor, a wind sensor, a solar radiation sensor, and a precipitation sensor.

33. The method according to claim 29 or 30, wherein the aforementioned environmental conditions are determined from a weather report.

34. The method according to any one of claims 29 to 33, wherein the distributed condition data acquisition step includes a step of acquiring distributed cable temperature data.

35. The method according to any one of claims 29 to 34, wherein the distributed condition data acquisition step includes a step of acquiring distributed cable strain data.

36. The method according to any one of claims 29 to 35, wherein the distributed condition data acquisition step includes a step of acquiring distributed cable vibration data.

37. The method according to any one of claims 29 to 36, wherein the virtual model updates the historical model data within the virtual model based on the environmental conditions and the distributed condition data input to the virtual model.

38. The method according to claim 37, wherein the update to the historical model data includes the step of correlating the environmental condition state with the distributed condition data.

39. A step of determining the voltage or current in at least a portion of the overhead power line located within the geographical area, The method according to claim 38, further comprising the step of correlating the determined voltage or current in the portion of the overhead power line with the distributed condition data.

40. The process of receiving future weather forecasts for the aforementioned geographical area, The method according to claim 38 or 39, further comprising the step of modeling further power line conditions in the virtual model of the power grid based on future weather forecasts, the step of applying the correlated environmental condition states to the distributed condition data.

41. The method according to claim 40, wherein the modeling determines an expected voltage value or expected current value for a portion of the overhead power line in the geographical area, and the expected voltage value or expected current value is determined so as not to exceed a predetermined temperature of the overhead power line.

42. A system for real-time temperature measurement in overhead power lines, An overhead electrical cable comprising a fiber-reinforced composite strength member and an electrical conductor surrounding the composite strength member, the overhead electrical cable being stretched between a plurality of support towers, An optical fiber sensor embedded within the composite strength member and extending along the length of the composite strength member, comprising a glass fiber core and a polymer coating surrounding the glass fiber core having a thickness of approximately 250 μm or more, and having an outer diameter of approximately 600 μm or more, A system comprising: an optical time-domain reflectometer (OTDR) operably mounted on the first end of the optical fiber sensor, the OTDR being configured to measure at least a temperature profile along the length of the optical fiber sensor.

43. The system according to claim 42, wherein the polymer coating surrounding the glass fiber core has a thickness of approximately 300 μm or more.

44. The optical fiber sensor has an outer diameter of approximately 700 μm or more, according to the system according to claim 42 or 43.

45. The system according to any one of claims 42 to 44, wherein the polymer coating surrounding the glass fiber is manufactured from a thermoplastic polymer.

46. The system according to claim 45, wherein the thermoplastic polymer is selected from the group consisting of polyaryletherketone (PAEK), liquid crystal polymer, polyamideimide, and polybenzimidazole.

47. The system according to claim 46, wherein the thermoplastic polymer is a PAEK polymer.

48. The system according to claim 47, wherein the PAEK polymer is selected from the group consisting of polyether ketone (PEK), polyether ether ketone (PEEK), polyether ketone ketone (PEKK), polyether ether ketone ketone (PEEKK), and polyether ketone ether ketone ketone (PEKEKK).

49. The system according to claim 48, wherein the PAEK polymer comprises PEEK.

50. The system according to any one of claims 42 to 49, wherein the end of the optical fiber sensor extends beyond the first end of the composite strength member.

51. The system according to claim 50, wherein the OTDR is operably mounted on the end of the optical fiber sensor.

52. The system according to any one of claims 42 to 51, wherein the OTDR is a Brillouin optical time-domain reflectometer (BOTDR).

53. The system according to any one of claims 42 to 52, further comprising a remote terminal unit (RTU) that operably communicates with the OTDR.

54. The system according to claim 53, wherein the RTU communicates operably with a data acquisition server (DAS) to enable the RTU to transmit the temperature profile data to the DAS along the length of the optical fiber sensor.

55. The system according to any one of claims 42 to 52, wherein the OTDR communicates wirelessly with the DAS.

56. The system according to any one of claims 42 to 52, wherein the OTDR communicates with the DAS via an optical grounding wire (OPGW).

57. The system according to any one of claims 54 to 56, wherein the DAS is configured to convert the temperature profile data into readable temperature measurements and to transmit the readable temperature measurements to a human-machine interface (HMI).

58. The system according to claim 57, wherein the HMI comprises a processor programmed to overlay the readable temperature measurements onto a geographic map.

59. The system according to any one of claims 42 to 58, wherein the optical fiber sensor is a single optical fiber sensor embedded in the composite strength member.

60. The system according to any one of claims 42 to 59, wherein the OTDR is configured to measure strain profile data along the length of the optical fiber sensor.

61. The fiber-reinforced composite strength member is the system according to any one of claims 42 to 60, wherein the polymer matrix contains carbon-reinforced fibers.

62. The system according to claim 61, wherein the fiber-reinforced composite strength member comprises an insulating layer surrounding the carbon-reinforced fibers.

63. The system according to any one of claims 42 to 62, wherein the electrical conductor comprises a plurality of aluminum strands wound around the composite strength member.

64. A method for increasing the current in an electric wire, At least the first temperature (T １ ) and the second temperature (T ２ The process involves determining the steady-state thermal time constant (τ) for the overhead power line, The initial temperature of the overhead power line (T) is determined using a distributed sensor associated with the overhead power cable. ｉ The process of measuring ) and The initial temperature (T ｉ The initial current (I ｉ The initial current measurement process involves measuring the following: The thermal time constant (τ), the desired application time (t), and the initial line temperature (T) ｉ ) and maximum desired temperature (T ｃ ) from steady state cable temperature (T ｆ The process of determining ) The step of determining the final current (I ｃ ), which can be applied to the overhead wire, before the maximum desired temperature (T ｆ ) of the overhead wire exceeds within the desired application time (t). For a period not exceeding the desired application time (t), the current in the electric wire is set to I ｆ A method comprising the process of increasing the amperage to a certain value.

65. The method according to claim 64, wherein the initial current measurement step includes the step of measuring the initial current using a BOTDR.

66. The steady-state cable temperature (T ｆ )teeth, [Math 2] It was decided from here, τ = Thermal time constant of the electrical cable t = Desired application time T ｉ = Initial cable temperature T ｃ = Desired maximum temperature T ｆ = Steady-state cable temperature The method according to claim 64 or 65.

67. The applied current I ｆ teeth, [Math 3] This is determined using, where, I ｆ = Final applied current in the overhead electrical cable I ｉ = Initial current in the overhead electrical cable T ｆ = Final temperature of the electrical cable T ｉ = Initial temperature of the electrical cable m = mass of the electrical cable C ｐ = Heat capacity of the aforementioned electrical cable R(T) ｃ ) = Temperature T of the electrical cable ｃ AC resistance in The method according to any one of claims 64 to 66.

68. The method according to any one of claims 64 to 67, wherein the thermal time constant τ is determined from existing data that correlates known temperature values ​​with known current values.

69. The method according to any one of claims 64 to 68, wherein the distributed sensor comprises at least a first optical fiber.

70. The method according to claim 69, wherein a Brillouin optical time-domain reflectometer (BOTDR) is operably connected to at least the first optical fiber.

71. The method according to any one of claims 64 to 70, wherein the electrical cable comprises a fiber-reinforced composite strength member.

72. The method according to claim 71, wherein the dispersed sensor is embedded in the fiber-reinforced composite strength member.

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