WO2004040322A1

WO2004040322A1 - Mutagenesis methods using ribavirin and/or rna replicases

Info

Publication number: WO2004040322A1
Application number: PCT/AU2003/001445
Authority: WO
Inventors: David Russell Murray; Gregory James Nunn; Luis Miguel Dejesus
Original assignee: Fault Detectors Pty Ltd
Priority date: 2002-11-01
Filing date: 2003-10-31
Publication date: 2004-05-13
Also published as: AU2002952426A0

Description

TITLE A SENSOR SYSTEM AND METHOD

FIELD OF THE INVENTION The present invention relates to sensing power system parameters in electrical distribution systems. In particular, although not exclusively, the present invention relates to sensing power system parameters using one or more ungrounded line sensors coupled to a data collector. The present invention has applications in power system monitoring, fault detection and location and power system characterization. However, it is envisaged that the present invention will have further applications.

BACKGROUND OF THE INVENTION To operate a medium voltage (1 V to 38kV) electrical distribution system a power utility needs to measure fundamental system parameters such as voltage, current and their phase relationship for a variety of purposes such as protection, fault location, network operation and network planning. The most common method to do this is to fit current and voltage transformers to electrical conductors of the distribution system and connect the transformer secondaries into special purpose equipment such as protection relays, SCADA system Remote Terminal Units (RTUs), metering equipment and the like.

To fit current transformers (CTs) to a power line it is necessary to address the problem of insulation from the high voltage line. In many situations this problem is already solved because of the needs of the rest of the equipment. For example, in metal clad sub-stations feeding underground cable networks the current transformers are located at cable entry points where the cable sheaths are grounded. Similarly, in pole-mounted switchgear, such as reclosers and load break switches, the current transformers can be incorporated into switchgear at grounded locations. In these cases current transformers are an excellent cost- effective solution. The problem occurs when there is no conveniently located grounded location to place the current transformer. In such instances an insulated transformer is required with significant cost and size increase, particularly in outdoor applications. Conventional wound voltage transformers inherently address the insulation problem in their design and are normally installed in sub-stations as required. However, wound voltage transformers are bulky and expensive and therefore, in some applications, such as pole-mounted switchgear, other methods of voltage measurement are sometimes employed. One such method is capacitive voltage dividers built into bushing systems, which can be provided at lower cost than wound transformers albeit with a lower accuracy.

Notwithstanding the above, there are situations where power system current and voltage measurement is desirable, but is too costly or cannot be achieved by any of the above means.

One such situation is overhead network fault detection at a location remote from a sub-station, such as at a power pole. In this case there is no grounded location to install current transformers so the cost of an insulated outdoor transformer would have to be incurred. Similarly the cost of a wound voltage transformer would be prohibitive. Another example is in the case of previously installed switchgear which is in service and has no provision for cost- effective retrofitting of current or voltage transformers. Therefore, special purpose equipment is used in these situations that has its own limitations. State of the art practice for fault detection in remote locations is to utilise line-attached sensors that operate electromagnetically or, more recently, electronically. On multi-phase lines these sensors may operate independently or may utilise short range radio systems to communicate to other equipment with remote communication capability. Electromagnetic line attached sensors suffer from low sensitivity and limited ways to display the fault occurrence. Electronic line attached sensors generally have the advantage of greater sensitivity and intelligence, but the disadvantage of employing batteries and/or solar cells as power sources which leads to reliability problems and therefore maintenance demands. A different type of fault detector attaches to the power pole and detects the combined magnetic/electric fields from the overhead lines. These pole-mounted fault detectors have difficulty in reliably detecting faults including failure to detect faults, false fault indication and cross-interference from multiple line installations. All of the above types of sensors suffer from the very significant limitation of providing either no or unreliable or insensitive earth fault detection and cannot sense the direction of phase or earth faults.

As a result of the limitations of the state of the art equipment, widespread use of these devices has been limited. However, in many countries there are now economic and regulatory pressures to install such equipment to improve network reliability and power quality and to do so with minimum disturbance to the energised network.

Another such situation is adding SCADA system monitoring to an existing sub-station. In this case it may be very costly to add the additional equipment to the substation because a) the station was not designed originally with this purpose in mind and b) disruption to service has to be at least minimised if not avoided.

Hence, there is a need for a system and/or method for sensing line parameters such as current and voltage and their phase relationship, which overcomes at least some if not all of the limitations of existing systems and methods described above.

SUMMARY OF THE INVENTION According to one aspect, although not necessarily the broadest aspect, the present invention resides in a sensor system for single or multi-phase power lines of an electrical network, the sensor system comprising: a line sensor attached to each power line without breaking the line to sample power line current at time intervals and digitize the current samples, each line sensor being ungrounded and floating at line voltage; each line sensor comprising a transmitter to transmit the digitized current data using an insulating transmission medium, the transmission occurring substantially simultaneously with sampling of the line current; a collector for receiving the data transmitted from each line sensor and for processing the data to derive power system parameters of the electrical network; wherein each line sensor is powered by a built-in power supply requiring no electrical connection external to the line sensor. The term "substantially simultaneously" used herein refers to transmissions where the data is transmitted within five seconds of the sampling taking place.

Preferably, the collector processes the line current data to determine one or more of the following line current parameters: instantaneous phase current,

RMS current, peak current, load current, fault current, fault X/R ratio, zero sequence current, positive sequence current, negative sequence current, fundamental frequency, harmonic content, quality of supply.

Suitably, the built-in power supply is in the form of a current transformer, the current transformer driven by a current flowing in the power line to which the line sensor is attached. Alternatively, the built-in power supply comprises a photovoltaic converter driven by a light source in the collector, which is connected to the sensor by optical fibre.

Preferably, each line sensor comprises a Rogowski coil to sample the line current.

Suitably, each line sensor pre-processes the current samples to optimise the transmission to the collector whilst maintaining integrity of the current samples. Alternatively each sensor processes the current samples to derive other data, the derived data being transmitted to the collector. Suitably, the digitized current data is transmitted from each line sensor to the collector using one of the following: radio signals, ultrasound, optical fibre. Suitably, the transmitter utilizes one or more of the following to permit substantially simultaneous radio transmission of the data from multiple line sensors attached to multiple power lines: frequency division multiplexing (FDM), direct sequence spread spectrum (DSSS), time division multiplexing (TDM), frequency hopping techniques.

Sampling of the line current by the line sensors may be synchronised by a timing source common to the line sensors. Alternatively, each line sensor may sample current asynchronously with respect to one or more other line sensors on multiple phase power lines and the collector corrects for sample timing differences between the samples by digital signal processing using one or more of the following: time of reception by the collector, a timing offset encoded by each sensor in its respective transmission, a time stamp encoded by each sensor in its respective transmission.

Preferably, for simple applications monitoring one or two multi-phase power lines the digitized current data is transmitted in bursts at a predetermined time relationship to a line current zero crossing point. Suitably, the sensor system may comprise up to six sensors attached to two connected branches of two multi-phase power lines, the power lines being monitored simultaneously by the collector.

Preferably, for more complex applications monitoring several multi-phase power lines transmission of the digitized data is controlled by more complex methods such as DSSS, TDM or frequency hopping.

Preferably, calibration of each line sensor takes place at time of manufacture, the calibration including measuring gain factors for each line sensor, deriving calibration constants and embedding the calibration constants in a line sensor serial number, the embedded calibration constants in the line sensor serial number being utilized by the collector to re-scale the line current data received from the sensor.

Optionally, the sensor system may be utilized for one or more of the following power system applications: fault detection, fault location, power system protection, distribution automation, monitoring, characterization, power quality determination.

Suitably, the line current signals are reproduced in the analogue domain.

Preferably, each line sensor comprises a voltage sensing electrode capacitively coupled to free space and to other objects at different electrical potential to the power line. This electrode is electrically coupled to the power line and is used to sense power system voltages.

Additionally, at time intervals, the line sensor samples the electric current flowing between the power line and the voltage sensing electrode, or its time integral, and digitizes the samples. Preferably, the line sensor comprises a transmitter to transmit the digitized power system voltage data using an insulating transmission medium to the collector. Suitably, the collector processes the digitized power system voltage data to determine one or more of the following power system line voltage parameters: instantaneous voltage, RMS voltage, peak voltage, zero sequence voltage, voltage sag, voltage surge, fundamental frequency, harmonic content, quality of supply.

Suitably, each line sensor pre-processes the voltage samples to optimise the transmission to the collector whilst maintaining integrity of the voltage samples. Alternatively, each sensor processes the voltage samples to derive other data, the derived data being transmitted to the collector. Suitably, the digitized data from a set of the sensors installed on a multiphase power line is processed to extract line-to-ground voltages of each phase by solving simultaneous equations with coefficients representing capacitive couplings between the voltage sensing electrode in each sensor and each of the other phases and between the voltage sensing electrode in each sensor and ground.

Suitably, the capacitive couplings between the voltage sensing electrode in each sensor and each of the other phases and between the voltage sensing electrode in each sensor and ground, are determined by an installation calibration procedure which does not require any disruption of said electrical network.

Suitably, the installation calibration procedure requires that the following are known at the start of said procedure: power system voltage at the installation site, minimum spacing between said power lines at the point of installation of the sensors, diameter of the line at the point of installation of the sensors. Suitably, the collector processes the power line current and voltage data to determine one or more of the following power system parameters: real power flow, reactive power flow, apparent power flow, fault impedance, fault direction, distance to fault, load impedance, line impedance and power quality.

Suitably, the sensor system is utilized for one or more of the following power system applications: fault detection, fault location, fault protection, distribution automation, monitoring, characterization, power quality determination. Suitably, each line sensor samples the electric current asynchronously with respect to one or more other line sensors on multiple phase power lines and the collector corrects for sample timing differences between said samples by digital signal processing using one or more of the following: time of reception by the collector, a timing offset encoded by each sensor in its respective transmission, a time stamp encoded by each sensor in its respective transmission.

Suitably, each line sensor also samples line temperature at time intervals.

According to another aspect, the present invention resides in a line sensor attachable to a power line of an electrical network without breaking the line to sample power, line current at time intervals and digitize the current samples, the line sensor being ungrounded and floating at line voltage, the line sensor additionally comprising a built-in power supply, a transmitter to transmit the digitized current data using an insulating transmission medium, the transmission occurring substantially simultaneously with sampling of the line current;

Suitably the built-in power supply is in the form of a current transformer, the current transformer being driven by a current flowing in the power line to which the line sensor is attached.

Preferably, a core of the current transformer comprises a split. Suitably, each end of the core is stepped such that a first end overlaps with a second end. Alternatively, each end of the core extends inwardly toward a centre of the core. Alternatively, the built-in power supply comprises a photovoltaic converter. Preferably, the line sensor further comprises a Rogowski coil to sample the line currents. Suitably, the Rogowski coil is fabricated by printed circuit methods.

Preferably, the Rogowski coil is deformable to fit around the power line. Preferably, the line sensor further comprises a voltage sensing electrode capacitively coupled to free space and to other objects at different electrical potential to the power line. Preferably, the voltage sensing electrode is electrically coupled to the power line.

Preferably, the line sensor further comprises a conductive elastomer to electrically couple the sensor to the power line. Preferably, the sensor samples the electric current flowing between the power line, or its time integral and the voltage sensing electrode at time intervals and digitizes the samples.

Preferably, the line sensor comprises a transmitter to transmit the digitized data using an insulating transmission medium to the collector.

Suitably, the voltage sensing electrode is utilized as a radio antenna for transmitting the data from the line sensor.

The voltage sensing electrode may be fabricated as part of an electronic circuit board or a core of the current transformer. Suitably, each line sensor samples line temperature at time intervals.

According to a further aspect, the present invention resides in a method of sensing power system parameters in an electrical network, the method including the steps of: attaching a line sensor to each power line of the electrical network without breaking the line, each line sensor being ungrounded and floating at line voltage and powered by a built-in power supply requiring no electrical connection external to the line sensor; sampling power line current at time intervals using each line sensor; digitizing the power line current samples; transmitting the digitized current data from each line sensor to a collector via an insulating transmission medium substantially simultaneously with sampling the line current; and processing the current data in the collector to derive power system parameters of the electrical network. The method may further include the collector processing the line current data to determine one or more of the following line current parameters: instantaneous phase current, RMS current, peak current, load current, fault current, fault X/R ratio, zero sequence current, positive sequence current, negative sequence current, fundamental frequency, harmonic content, quality of supply.

The method may further include each line sensor pre-processing the current samples to derive data and transmitting the derived data to the collector. Pre-processing the current samples may optimise transmission to the collector whilst maintaining integrity of the current samples.

The method may further include each line sensor transmitting the digitized current data to the collector using one of the following: radio signals, ultrasound, optical fibre.

The method may further include the transmitter utilizing one or more of the following to permit substantially simultaneous radio transmission of the data from multiple line sensors attached to multiple power lines: frequency division multiplexing (FDM), direct sequence spread spectrum (DSSS), time division multiplexing (TDM), frequency hopping techniques.

The method may further include synchronising sampling of the line current by the sensors using a timing source common to the sensors, such as a Global Positioning System (GPS).

The method may further include each line sensor sampling current asynchronously with respect to one or more other line sensors on multiple phase power lines and the collector correcting for sample timing differences between the samples by digital signal processing using one or more of the following: time of reception by the collector, a timing offset encoded by each sensor in its respective transmission, a time stamp encoded by each sensor in its respective transmission.

The method may further include transmitting the digitized current data in bursts at a predetermined time relationship to a line current zero crossing point. The method may further include the collector simultaneously monitoring up to six sensors attached to two connected power lines. The method may further include the collector re-scaling the line current data using a line sensor serial number, the line sensor serial number comprising embedded calibration data for each line sensor.

The method may be utilized for one or more of the following power system applications: fault detection, fault location, power system protection, distribution automation, monitoring, characterization, power quality determination.

The method may further include reproducing the line current signals in the analogue domain. The method may further include each sensor sampling electric current flowing between the power line and a voltage sensing electrode, or its time integral, of each sensor at time intervals and digitizing the samples, the electrode being capacitively coupled to free space and to other objects at different electrical potential to the power line, wherein the electrode is electrically coupled to the power line.

The method may further include transmitting the digitized data using an insulating transmission medium to the collector.

The method may further include the collector processing the digitized data to determine one or more of the following power system line voltage parameters: instantaneous voltage, RMS voltage, peak voltage, zero sequence voltage, voltage sag, voltage surge, fundamental frequency, harmonic content, quality of supply.

Suitably, the method may further include each line sensor pre-processing the digitized samples to optimise transmission to the collector whilst maintaining integrity of the samples.

Suitably, the method may further include each line sensor sampling electric current asynchronously with respect to one or more other line sensors on multiple phase power lines and said collector correcting for sample timing differences between the samples by digital signal processing using one or more of the following: time of reception by collector, a timing offset encoded by each sensor in its respective transmission, a time stamp encoded by each sensor in its respective transmission.

The method may further include the collector processing digitized data from a set of said sensors installed on a multi-phase power line to extract line-to- ground voltages of each phase by solving simultaneous equations with coefficients representing capacitive couplings between the voltage sensing electrode in each sensor and each of the other phases and between the voltage sensing electrode in each sensor and ground. The method may further include determining the capacitive couplings between the voltage sensing electrode in each sensor and each of the other phases and between the voltage sensing electrode in each sensor and ground, by an installation calibration procedure which does not require any disruption of said electrical network.

The method may further include the collector processing the power line current and voltage data to determine one or more of the following power system parameters: real power flow, reactive power flow, apparent power flow, fault impedance, fault direction, distance to fault, load impedance, line impedance and power quality.

The method may be utilized for one or more of the following power system applications: fault detection, fault location, fault protection, distribution automation, monitoring, characterization, power quality determination.

The method may further include each line sensor sampling line temperature at time intervals.

Further features of the present invention will become apparent from the following detailed description.

BRIEF DESCRIPTION OF THE DRAWINGS To assist understanding of the present invention and to enable one skilled in the art to put the invention into practical effect preferred embodiments of the invention will be described with reference to the accompanying drawings which are provided by way of example only, wherein:

FIG. 1 is a schematic overview of the sensor system according to the present invention;

FIG. 2 is schematic representation of an embodiment of a line sensor employed in the sensor system of FIG. 1 ; FIG. 3 is a representation of a power supply current transformer core with stepped ends;

FIG. 4 is a representation of a power supply current transformer core with returned ends;

FIG. 5 is a representation of the line sensor in an open position for attachment to a power line;

FIG. 6 is a representation of the line sensor in a closed position attached to the power line;

FIG. 7 is a schematic representation of electronics of the line sensor; FIG. 8 is a schematic representation of antenna and voltage sensor circuitry of the line sensor;

FIG. 9 is a schematic representation of current sensor circuitry of the line sensor; FIG. 10 is a schematic representation of electronics of the collector of the sensor system;

FIG.11 is a flowchart representing method steps for sensing power system parameters in accordance with the present invention;

FIG.12 is an illustration of an application of the sensor system according to the invention for remote overhead power line fault detection;

FIG.13 is a schematic representation of an application of the sensor system according to the invention in sub-station monitoring;

FIG.14 is a schematic plan representation of a part of a line current sensor in the form of a Rogowski coil fabricated as a printed circuit board; FIG. 15 is a timing diagram showing synchronisation of sensor transmissions to line current zero crossings;

FIG. 16 is a schematic representation of a part of an electrical network where the line divides;

FIG. 17 is a timing diagram showing transmissions of two sensors on a divided line;

FIG. 18 is a representation of a Rogowski coil made from a bent printed circuit board;

FIG. 19 represents sampling and transmission of data by a sensor;

FIG. 20 is a simplified representation of three power lines illustrating power system voltage sensing;

FIG. 21 is a flowchart representing method steps for determining line voltage; and

FIG. 22 is schematic representation of an alternative embodiment of the line sensor.

DETAILED DESCRIPTION OF THE INVENTION With reference to FIG.1, sensor system 2 according to the present invention for single or multi-phase power lines 8 of an electrical network is coupled directly to local applications 13 and/or to remote applications or users 6 via communications system 4. Applications or users 13, 6 utilize the output of sensor system 2. Applications local to collector 13 may be, for example fault detection and indication applications or electrical system protection applications. Communications system 4 may be a hard-wired system, a radio network or a global communications network such as the Internet or a combination off such systems. Remote user or application 6 may be, for example, a maintenance alert system for identifying and locating system faults or a database with load profile data that assists a system planner or a SCADA system or a protection system.

At time intervals, sensor system 2 samples current and/or voltage and/or temperature of power lines 8. Power lines 8 may be overhead power lines, bus bars, cables, or the like. One or more phases of power lines may be sampled using one or more line sensors 10. Sensors 10 are coupled to each line 8 and one sensor is employed for each phase being monitored. Sensors 10 are powered by the line to which they are coupled and no part of the sensor is electrically grounded, allowing the sensor assembly to float at line voltage. Sensors 10 sample current and/or voltage and/or temperature of the lines 8 to which they are coupled, digitize and pre-process the samples and transmit the results to collector 12 of the sensor system located in the vicinity of sensors 10.

In the embodiment shown in FIG.1, current, voltage and temperature data are transmitted to collector 12 using radio signals using low power methods in unlicensed channels of the radio spectrum. However, the invention is not limited to transmitting the data from line sensors 10 to collector 12 by this means and the data may alternatively be transmitted to the collector using any insulating transmission medium, such as ultrasound or optical fibres.

Collector 12 processes the line samples received from sensors 10 to derive power system parameters. The derived parameters may then be utilised by local applications 13 such as fault detection. The fault detection application may, for example, generate a local trip signal or may transmit results via communications system 4 to other applications or users 6 remote from collector 12, such as a fault management system. Alternatively, the power system parameters may be transmitted via communications system 4 to other applications or users 6, such as a SCADA system, remote from collector 12.

The construction of line sensors 10 will now be described with reference to FIGS. 2-9. FIG. 2 shows an embodiment of line sensor 10 that encircles power system lines 8 (not shown) once installed. Sensor 10 includes power supply current transformer (CT) core 15 about at least part of which is wound power supply CT coil 16. Core 15 and coil 16 are accommodated within housing 18 which also accommodates one or more printed circuit boards (PCB) 20 and a line current sensor in the form of a Rogowski coil 34. Note that electrical connections between parts have been omitted for clarity.

Power CT core 15 and/or housing 18 and/or one or more PCBs 20 and/or Rogowski coil 34 may be flexible. Core 15 is preferably made from mu-metal, but may be made from any other suitable alternative material known in the art. Power CT coil 16 comprises a standard bobbin and winding familiar to those skilled in the art. Electrical connection between power CT coil 16 and PCB 20 is omitted for clarity.

Housing 18 is preferably fabricated from suitable plastic material for its strength, UV stability and weatherproof characteristics. Housing 18 may suitably be made in multiple parts, which provide the opening and closing functionality required to couple the sensor 10 to the line 8 and to provide support of the other components. For clarity, the detail of housing 18 is not shown in FIG 2. FIG 2 also shows the components separated from each other. Rogowski coil 34 is preferably fabricated as a printed circuit, which is flexed circumferentially around the axis of the line 8. Electrical connection between Rogowski coil 34 and PCB 20 is omitted for clarity.

PCB 20 comprises electronic components, temperature sensor, a radio antenna (where radio communication to the collector 12 is employed) and other components for detection and pre-processing of line current, voltage and temperature samples of line(s) 8, and for transmission of the data to the collector 12, all of which will be described in detail hereinafter.

Power CT core 15, housing 18 and PCB 20 each comprise a split 26 in their perimeter to allow the line sensor to be coupled to line 8 without requiring the line to be disconnected. Line sensor 10 further comprises biasing means, such as clip 22, to maintain housing 18 in a closed position around the power line 8.

Line sensor 10 further comprises a means 201 to engage the power line to prevent significant movement of the sensor. In this embodiment, means 201 to engage the line is in the form of an elastomeric plug. The plug comprises a split 26 in the perimeter to allow the line sensor to be coupled to line 8 without requiring the line to be disconnected. The split 26 is held closed by the housing in the clipped position. Other methods of engaging the line can be envisaged and it will be appreciated by those skilled in the art that the line sensor is not limited to this particular embodiment. Plug 201 also provides a connection to the line for purposes of voltage sensing by being fabricated from conductive elastomer. This has the advantage of connecting to the line by capacitive coupling in circumstances where the line is contaminated or oxidised or insulated and a galvanic connection cannot be made. Other methods of connecting to the line can be envisaged and it will be appreciated by those skilled in the art that the line sensor is not limited to this particular embodiment. Electrical connection between conductive elastomeric plug 201 and PCB 20 is omitted for clarity.

Although the radio antenna is described as being incorporated in PCB 20, it will be appreciated by those skilled in the art that the line sensor is not limited to this particular embodiment.

Power CT core 15 is shown schematically in FIG 3. The construction of core 15 can take several forms. Preferably the core is made from laminated strips 213 to minimise eddy current losses and to permit the core to flex to enable introduction of the line 8. Preferably the laminated strips 213 are staggered or stepped at their ends 214, as shown in FIG 3, such that the two ends fit together leaving no gap. However, FIG 3 shows a small gap 26 between the ends 214 for clarity. The housing 18 and clip 22 holds the gap 26 closed when the sensor 10 is in the installed condition. An advantage of this design is the minimisation of core magnetic reluctance due to air gaps where the core ends 214 meet by reducing the number of laminations the flux must cross. Alternatively, the core 15 can be constructed as shown in FIG 4 where the ends 214 of the core may comprise downwardly extending portions 211, which function as an extended area for magnetic flux to cross the air gap. Although CT core 15 is shown as being octagonal in cross section, it will be appreciated by those skilled in the art that the line sensor is not limited to this particular shape. It will be appreciated by those skilled in the art that the line sensor CT core 15 is not limited to either of these particular embodiments.

With reference to FIG 5, line sensor 10 is installed on the line 8 by opening the housing 18, which consequently opens the split 26 in core 15, Rogowski coil 34 and line plug 201. The sensor 10 is slid over the line 8 and the housing is closed and clipped shut via clip 26. If the line 8 is energised a special purpose tool may be employed to do this to keep the installing personnel insulated from the line. FIG. 5 shows line sensor 10 in an open position ready to receive line 8. Housing 18 and PCB 20 have been omitted from FIG. 5 for clarity. Preferably, housing 18 (not shown) is made in sections, which pivot substantially about point 220. Alternatively, the housing 18 is made from flexible material and the pivot point is eliminated.

As shown in FIG. 6 when the housing 18 (not shown) is closed about the line 8 and secured by the clip 22 (not shown), the CT core 15, Rogowski coil 34 and elastomeric plug 201 are closed about the line, thus permitting correct operation of each of these parts. It will also be appreciated by those skilled in the art that CT core 15, Rogowski coil 34 and plug 201 may be engaged on line 8 using alternative means.

Sensor electronics will now be described with reference to FIGS. 7-9. FIG 7 shows a generalised schematic of the sensor system electronics. Line sensor 10 is powered by a built-in power supply requiring no electrical connection external to the line sensor. The power source is the current passing through line 8, which is coupled by CT core 15 and CT coil 16 to power supply module 32. Power supply module 32 suitably comprises rectifiers, capacitors, regulators and switching regulators as required to power the rest of the electronic circuitry. The combination of components required and their arrangement in power supply module 32 would be familiar to one skilled in the art. In the event of the line current falling below the minimum current required to operate the sensor 10, the sensor is powered by storage capacitors for a short time, suitably 100ms, which is a sufficient time to advise collector 12 of imminent shutdown. Alternatively, with reference to FIG 22, CT core 15 and CT coil 16 can be replaced by a photovoltaic converter 900 so that the sensor is powered by light incident on said photovoltaic converter 900. Preferably, the light is transmitted from collector 12 by an optical fibre 901. In FIG 22, electrical connection between PCB 20 and photovoltaic converter 900 is omitted for clarity.

Line sensor 10 incorporates a means of sensing current in the line 8. The preferred method is Rogowski coil 34, but other means could be used such as a conventional current transformer or a Hall effect device.

With reference to FIG 7, Rogowski coil 34 is coupled to current module 36, which is controlled by the control module 40. Analogue output of current module 36 is converted to digital signals by analogue to digital converter (ADC) 38 at time intervals controlled by the control module 40. The sampling rate depends on the particular application. Digital signals representing line current samples are input to control module 40 from ADC 38. Line voltage is sensed by at least one voltage sensor electrode 42, said electrode being coupled to voltage module 44, which is also coupled to the power line 8 to which the sensor is attached. Analogue output of voltage module 46 is converted to digital signals by analogue to digital converter (ADC) 46 at time intervals controlled by the control module 40. The sampling rate depends on the particular application. Digital signals representing line voltage samples are input to control module 40 from ADC 46.

Control module 40 applies any required processing to the digital signals to compress data, add timing information, derive other data and otherwise prepare the data for transmission. The digital data is then input to radio transmitter 48 and transmitted to collector 12 via radio antenna 50. Processing and transmission of the current and voltage samples is controlled by control module 40 via control signals to current module 36, voltage module 44, ADCs 38, 46 and radio transmitter 48. Suitable alternative transmitters familiar to those skilled in the art will be employed in embodiments utilizing alternative transmission means. With reference to FIG 8, which shows elements of voltage module 44 and radio transmitter 48, voltage sensing electrode 42 has capacitive coupling to free space (the isotropic capacitance), to other phase conductors, to nearby power lines and to grounded structures. If these structures are at a different electric potential to the conductor to which the sensor is attached then the capacitive coupling causes alternating current to flow through voltage sensing electrode 42 to line 8 via inductor 52 and voltage sensing capacitor 54. This alternating current is a function of the time differential of the potential of each of the above objects (free space, other phase conductors, nearby power lines and grounded structures) relative to the conductor to which the sensor 10 is attached, and the magnitude of the capacitive coupling to each of the above objects. This current develops a voltage across sensing capacitor 54, which is the integral of the current, said voltage being amplified by amplifier 56. The amplified voltage is converted to digital signals by ADC 46, which are input to control module 40. In this way it is seen that sensing capacitor 54 integrates the current from the voltage sensing electrode so that the sample data output from ADC 46 is representative of the power system phase voltages rather than their time differential. Persons skilled in the art would realise that alternative electronic methods might be used which omitted capacitor 54 so that the digitized data was representative of the time differential of the power system line voltages. In such a case integration of the data could be carried out by digital methods in either the sensor 10 or the collector 12 to recover the power system line voltages. With further reference to FIG. 8, it is shown that, in this embodiment, voltage sensing electrode 42 also functions as RF antenna 50, although it will be appreciated that the present invention is not limited to such a combined function. Blocking capacitor 53 prevents power line frequency current from flowing into RF power stage 58 and permits radio frequency current to flow from RF power stage 58 to antenna 50. Additionally, blocking inductor 52 prevents RF current flowing into capacitor 54 and permits power frequency current to flow into capacitor 54 from voltage sensing electrode 42. At the time when data samples are to be transmitted to collector 12, control module 40 outputs digital data modulated into RF signals from RF power stage 58 via capacitor 53 for transmission from antenna 50.

FIG. 9 shows a suitable arrangement of components in current module 36, which is coupled between Rogowski coil 34 and ADC 38. Current module 36 includes amplification stage 60 and integration stage 62 to yield analogue signals that correspond to the line current. ADC 38 converts the analogue output of amplifier arrangement 62 into digital current samples. Alternatively, integration of the signals of the Rogowski coil 34 may be implemented using digital techniques in sensor control module 40 or collector 12. The preferred embodiment of the Rogowski coil 34 is shown in FIGS 14 and 18, wherein the coil is made from a printed circuit board (PCB). The printed circuit board is made sufficiently flexible to be able to be bent into a hollow cylinder shape, as shown in FIG 18. FIG. 14 shows a plan view of a part of the Rogowski coil 34 before it is bent into the cylindrical shape shown in FIG 18. The Rogowski coil 34 comprises substrate 230 and tracks 33, 35. Tracks 33 are fabricated on a first side of substrate 230 and tracks 35 are fabricated on a second side of substrate 230. Tracks 33, 35 are connected by plated through holes 41. By virtue of the thickness of the PCB a coil winding is effected by the tracks, linking to the magnetic flux surrounding the power line and so forming a Rogowski coil. This method of making a Rogowski coil from a PCB is different from that disclosed in German patent application No. DE10161370 in the name of Phoenix Contact GmbH & co. KG and obviates the need for a hinging arrangement to introduce the line 8. The tracks 33, 35 and the plated through holes 41 are omitted in Fig 18 for clarity. The line sensors preferably employ time division multiplexing (TDM) so that multiple line sensors can transmit data signals on a single shared radio channel simultaneously without interfering with each other and only a single simple receiver is employed at the collector 12, this facilitates low power, low cost implementation. The preferred method for simple installations not monitoring multiple power lines of ensuring the transmissions from the sensors 10 do not interfere with each other is to synchronise the transmission from each sensor in a predetermined time relationship to the positive (or negative) zero crossing point of the line current which, in a multiphase system, will never coincide with each other. Furthermore, each sensor limits its transmissions to a short burst of less than 1/3 of the line current period. This is shown in FIG 15, which illustrates transmission at a predetermined time relationship 400 to the line current zero crossing point. The preferred data to be transmitted from the sensor 10 is shown in FIG 19. FIG 19 shows sampling current at time intervals to obtain current samples S-i-Ss in the upper diagram, transmitting data in the form of the digitized current samples S-i-Ss and a time delay 401 in the middle diagram and the on/off states of the transmitter in the lower diagram. The preferred data is a burst of sample data that has been buffered in the sensor 10 over the previous cycle of the line current as well as the time delay 401 , being the time delay from the last sample to the start of the transmission. The burst transfers all of the sample data Sι-S₈ and the time delay 401 within the transmitter on period shown in the lower diagram from the sensor 10 to the collector 12 without any loss of sample amplitude information and with sufficient timing information 401 for the collector 12 to correct for both the lack of synchronisation between the samples taken by each sensor and the delay in reception of the samples due the burst transmission, thus maintaining sample integrity. The maintenance of sample integrity allows the collector 12 to extract the maximum benefit from the sample data, such as: 2^nd harmonic content in order to provide transformer inrush restraint, the DC component of a fault to correct for transient overreach, and monitoring of sub-cycle sags or surges. As an alternative to maintaining sample integrity, each line sensor processes the sample data to derive other information, such as mean-square values, and this derived information is then transmitted to the collector 12 substantially simultaneously with the sampling allowing the collector to derive a more limited set of power system current and voltage parameters. However, this method will lose some of the line current information and limit the power system parameters that can be derived and so is not preferred.

A further refinement of the zero crossing transmission technique permits a single collector 12 to monitor two connected electrical distribution lines. This is illustrated in the example shown in FIG 16 where the electrical distribution lines are drawn as a single line diagram. Where a main electrical line 700 branches into a spur line 701 , one set of sensors Set 1 is placed on the main line 700 below the spur and a second set of sensors Set 2 is placed on the spur line 701. Each set of sensors is installed in the opposite direction to the other set. With reference to FIG 17, provided that each sensor limits its transmissions to a short burst of less than 1/6 of the line current period the transmissions from the sensors will not collide. In this way, main line 700 and a spur line 701 can be monitored with a single collector 12.

As an alternative to the burst transmission described above, frequency division multiplexing (FDM) can be employed by the sensors, whereby each sensor transmits on a different radio channel. This allows transmission of sample data at the instant of sampling and avoids interference between transmitters of different sensors on the occasions when transmitters turn on at the same time and avoids the need to transmit sample timing data 401. However, employing FDM uses more radio channels and a more complex receiver in the collector 12. Correction for lack of synchronisation between samples must still be carried out because the sampling is not synchronised between the three sensors 10.

As a further alternative, which may be suitable to applications where multiple power lines in the same area are being monitored by the collector such as in a sub-station, more sophisticated communication methods can be employed such as direct sequence spread spectrum (DSSS), or frequency hopping. These can be used to transmit the sample data from multiple line sensors 10 on multiple power lines to one or more collectors 12 substantially simultaneously. However these more sophisticated techniques have consequences of increased cost, complexity and power consumption. In particular these methods may require receivers to be incorporated into the sensors with the consequent increases in cost and power consumption.

Processing of sample data at the collector is simplified if the samples from each sensor are taken simultaneously. This can be achieved by each sensor 10 receiving timing signals from a common timing source such as the collector 12 or the Global Positioning System (GPS) and using said timing signals to synchronise their sampling. However incorporating receivers into the sensors is not a preferred implementation due to increased cost, complexity and power consumption.

Each sensor 10 may carry out some pre-processing of the current and/or voltage and/or temperature samples. Pre-processing may reduce the volume of data to be sent to the collector 12 compared to sending the raw samples and/or may reduce the processing that the collector is required to perform and/or may optimise the data for transmission without loss of sample integrity. Examples of such processing include: integration of current samples, non-linear encoding, scale and value encoding, data compression, delta encoding or encryption and/or the addition of: framing data, addressing data, identification data, error detector data and/or error correction data. These features will be familiar to someone skilled in the art and are not described further.

The sensor 10 can employ common electronic engineering practices to perform this pre-processing such as using microprocessors, application specific integrated circuits (ASIC), field programmable gate arrays (FPGA), programmable array logic (PAL) and so on.

To correctly determine all the desirable power system parameters the collector 12 must combine data from more than one sensor. In particular, this is required to obtain the zero sequence voltage and current of the power line. In order for this to be done successfully the timing relationship between the data from the various sensors must be maintained. To do this collector 12 utilises digital signal processing methods together with timing information to correct for timing differences between data received from different sensors. For example, in the case of burst transmission of data described above the sample data from each sensor can be re-timed to the time-base of the collector by noting the time of reception of the burst relative to the time-base of the collector and utilising this, together with the received sample time delay 401, to re-create a new set of samples synchronised to the collector time-base by linear interpolation. If this is done for all the sensors, the samples from all the sensors can be combined correctly. As another example of timing information sensors can use timing signals from a common timing source such as GPS to time-stamp data sent to the collector 12 so that the collector can correct for sample timing differences between sensors. Alternative and more sophisticated methods of signal processing to the example given above are well known to those skilled in the art of signal processing.

A preferred embodiment of collector 12 may comprise the modules shown in FIG. 10. Collector 12 may be considered as comprising processing module 70 coupled to power module 72, external communications module 74 and radio receiver module 93.

Power module 72 comprises battery 76, which stores energy supplied from mains power supply 78 and provides a back up if the mains power supply fails. Alternatively, power module 72 also comprises solar power supply 80 in the form of photovoltaic cells instead of mains power supply 78. Power module 72 provides power to processing module 70, radio receiver module 93 and external communications module 74.

In radio receiver module 93 radio signals from the sensors 10 are received by antenna 82, which is coupled to radio front end 83 and are then input to down converter 86, which converts the frequency of the radio signals to a lower frequency suitable for de-modulation in receiver 88. The outputs of receiver 88 are the digital data transmitted by each of the sensors along with the timing information of the instant of reception of the transmissions from each sensor. Where an alternative transmission means such as ultrasound is employed an appropriate alternative receiver module 93 will be utilized.

The digital data stream from the receiver 88 is fed into the processing module 70 wherein resides microprocessor 92 which further processes the current and voltage sample data from the three sensors to derive the power system parameter of interest.

In the preferred embodiment, microprocessor 92 processes the digital data stream from the sensors along with the timing information to first extract the data samples taken by each sensor and then from these samples determines the line current, voltage and temperature and other power system parameters required by various applications. Examples of such power system parameters include, but are not limited to: instantaneous phase current, instantaneous voltage, RMS Phase/Ground voltages; RMS Phase/Phase voltages all averaged over the relevant period for the application; RMS zero sequence voltage; RMS Phase currents and RMS zero sequence currents averaged over the relevant period for the application; RMS positive and negative sequence currents; real, reactive and apparent power flows; peak currents; DC current components; load impedance; fault impedance; fault duration; fault magnitude; fault X/R, distance to fault, voltage and current fundamental frequency; harmonic content; voltage sag and surge data. Methods to determine these power system parameters from line current and voltage sample data are well known and are not described here. Applications for such power system parameters are power system fault detection, fault location, protection, monitoring, characterisation and so on. These applications are well known and are not described here. The applications may reside in the collector 12 or elsewhere.

Where the applications do not reside in the collector 12 the derived power system parameters are sent to external communications module 74 for transmission via an appropriate communication network to one or more remote applications or users 6. External communications module 74 may comprise short-range transmitter module 94 employing a short-range communications protocol such as Bluetooth for transmissions to nearby, local applications. External communications module 74 may additionally or alternatively comprise longer range transmitter module 96 employing communications systems such as a cable modem, UHF radio, GSM or GPRS for transmissions to remote applications. Both transmitter modules 94, 96 are coupled to respective antennae 98, 100. Alternatively, collector 12 may reproduce the processed line current and voltage samples as analogue output signals using digital to analogue conversion and analogue conditioning circuitry. The analogue output signals can be utilized by other equipment and their relevant applications such as SCADA system RTUs or protection relays.

For useful measurement of ground current, line current measurement accuracy generally better than 0.5% of the phase current is required. In the preferred embodiment this is achieved by calibration of the line sensors in the factory at the time of manufacture. Calibration for current, voltage and temperature can be carried out for each sensor, which includes measuring gain factors therefore from which calibration data is derived. In the preferred embodiment, the calibration data is utilized by collector 12 to re-scale the raw data samples received from the line sensors 10. In such an embodiment, the calibration data may be encoded into a line sensor serial number, which is known to the collector. Alternatively, calibration data may be stored in the line sensors with sample correction taking place in the line sensors. Power system voltage sensing is now further explained with reference to FIG. 20 which shows a simplified representation of three power lines - line 610 carrying phase A, line 611 carrying phase B and line 612 carrying phase C. On line 610 is shown a sensor 10, the others two sensors on the other two lines being omitted for clarity. Also shown is voltage sensing electrode 42 which capacitively couples to free space, grounded objects, the adjacent power line 611 and the further power line 612. These couplings are represented in FIG. 20 by the capacitor symbols 600, 601 , 602 and 603 respectively. The relative magnitude of these couplings is dependent on the physical separation of the various objects, which will vary from installation to installation.

Voltage sensing electrode 42 is also electrically coupled to line 610 so that it is substantially at the same potential as line 610. As a consequence current flows through the voltage sensing electrode 42 driven by the time differential of the potential differences between line 610 and the said objects to which it is capacitively coupled. Voltage sensing capacitor 54 (shown in FIG 8) in the sensor integrates said current and the resulting voltage is sampled by the sensor and will be referred to as sensor voltage Va in the discussion below, i.e. the voltage measured by the sensor on phase A. The instantaneous value of Va is determined by the power system voltages as follows:

Va = [ (Kag x Vag) + (Kab x (Vbg - Vag)) + (Kac x (Vcg - Vag)) ] x G

where:

Va is the voltage measured by the voltage sensing electrode 42; Va, Vb, Vc are the instantaneous phase-to-ground voltages on phases A,

B and C respectively;

Kag, Kab, Kac are the magnitudes of the couplings from voltage sensing electrode 42 on the sensor on phase A, to ground, to phase B and to phase C respectively, which are referred to as the coupling constants from now on; and G is a system gain factor, which is a constant.

It will be noted that Va is a combination of the voltage on all three phases which is dependant on the coupling constants Kag, Kab, Kac which in turn depend on the specific site installation. Also it will be understood that the same situation applies for a sensor mounted on phase B on line 611 and for a further sensor mounted on phase C on line 612. Each of the other sensors will have a corresponding set of coupling constants all of which may be different from the coupling constants of the other sensors. The sensor voltages measured by the set of three sensors can therefore be represented as a set of three simultaneous equations as follows:

Va = [ (Kag x Vag) + (Kab x (Vbg - Vag)) + (Kac x (Vcg - Vag)) ] x G Vb = [ (Kbg x Vbg) + (Kbc x (Vcg - Vbg)) + (Kba x (Vag - Vbg)) ] x G

Vc = [ (Keg x Vcg) + (Kca x (Vag - Vcg)) + (Kcb x (Vbg - Vcg)) ] x G

Generally speaking Va, Vb and Vc are not useful since they are not attributes of the power system alone, but are attributes of the power system plus coupling constants, which will vary from installation to installation. To remove the coupling constants and recover Vag, Vbg, Vcg it is necessary to solve the differential equations above. Persons skilled in the art will know of several well- known methods for this such as matrix inversion or equation substitution.

Solving of the above equations takes place in the collector 12, which processes the received voltage data from the line sensors 10 substantially simultaneously with the data reception. The collector 12 solves the above equations to eliminate the coupling constants and recover Vag, Vbg and Vcg and from these determines the other power system parameters described earlier.

Persons skilled in the art will be aware that the formulation above can be expressed in a number of alternative ways without changing the generality of this disclosure. Persons skilled in the art will be aware that the integration carried out by voltage sensing capacitor 54 can alternatively be carried out by digital methods in the sensor or in the collector.

Solution of the simultaneous equations as described above can only take place if the set of nine coupling constants is known for the particular installation. Precise determination of these constants by calculation from the installation geometry could be achieved using software modelling methods. However, this is not practical since the cost and difficulty of determining the installation geometry would be prohibitive. Alternatively, empirical determination is possible by energisation of each phase in turn and measuring the sensor voltages with just one phase energised. However, this is highly undesirable since it will involve either disruption to the electrical network or an expensive procedure to avoid such disruption.

Preferably, a method of determination of these constants can be employed which requires no disruption to the electrical network, does not require difficult or expensive site measurements to be made and takes place automatically without requiring skilled intervention by installation personnel. One such method is described below which takes place automatically in the collector 12, requires little or no input from the installing personnel and does not require any disruption to the electrical network. The method assumes that the electrical network is energised and not faulted. The method also assumes that coupling between lines and sensors is symmetrical so that Kab = Kba, Kbc = Kcb and Kca = Kac and that the system voltage phasors are equally 120 degrees apart from each other. Furthermore, the method requires the following to be known: the power system line voltage at the point where the sensors are installed, the minimum line separation at the point where the sensors are installed and the line conductor diameter at the point where the sensors are installed. These parameters may be entered by the installer if known, or can be set to default values. If they are set to default values there will be some consequent reduction of accuracy of the calibration procedure if the actual installation deviates from the default values.

The preferred method is now described with reference to the flowchart in FIG 21.

Step 1 : Assume default values as follows Kag = Kbg = Keg = 1. Kab = Kbc = Kca = 0.

Step 2: Receive voltage data from sensor for a short period of time (suitably 1 second) and solve simultaneous equations to determine phasors for Vag, Vbg, Vcg. From this determine angles between Vag, Vbg and Vcg phasors. Also determine zero sequence voltage phasor and determine average magnitude of Vag, Vbg and Vcg Step 3: For any phases where the angle between the two phases is greater than 120 degrees increase the coupling coefficient between those two phases by a small incremental value.

Step 4: If the average magnitude of Vag, Vbg and Vcg is not equal to the known system line voltage then increase or decrease all phase-to-phase coupling coefficients by a small amount depending on whether the measured line voltage was lower or higher than the known line voltage.

Step 5: If the magnitude of zero sequence voltage phasor is greater than a small threshold value then increase the value of the phase-to-ground coupling coefficient by a small amount of the sensor whose line voltage phasor is closest to 180 deg out of phase with the zero sequence phasor. Step 6: Repeat steps 2 to 5 until the coefficients have stabilised. Step 7: Compare the highest value phase-phase coupling coefficient with the highest value expected which can be calculated from the known minimum line separation and line diameter. Take the difference between these two values and add it to 1 and set Kag = Kbg = Keg equal to this new value, also reset Kab = Kbc = Kca = 0.

Step 8: Repeat steps 2 to 5 until the coefficients have stabilised. The coupling coefficients are now determined. The method proceeds in three stages. In the first stage, steps 1 - 6, the cross-couplings between phases are adjusted by an iterative method so that the measured line-to-ground voltage phasors are all 120 degrees apart. At the same time the cross-couplings are adjusted so that the correct average line-ground voltage is measured. At the same time the phase-to-ground couplings are adjusted so that the measured zero sequence voltage is reduced to a very low value. However, this stage does not result in correct absolute values. Instead it results in coupling coefficient values where the phase-ground couplings are minimised and phase-phase couplings are maximised. In the second stage in step 7 the maximum cross-coupling is compared with a target value, said target value being derived from two simple parameters of installation geometry, namely the minimum conductor spacing and the conductor diameter. This derivation can be by pre-determined lookup table in the collector 12. The minimum conductor spacing at the point of installation and conductor diameter may be well known for the particular installation or my be relatively constant across most installations and can therefore be easily defaulted. From this target cross-coupling a new starting coupling coefficient the phase-ground couplings is derived and so, when the iterative method is repeated in the third stage, step 8, the result is the that all the couplings are adjusted to so that the desired maximum cross-coupling is achieved in addition to the correct line voltage being measured, zero sequence voltage being zeroed and all voltage phasors being at 120 degrees to each other.

Persons skilled in the art will know ways of determining said phasors and phase angles used in steps 2-5, one such method would be derivation of quadrature components of the line voltages relative to one voltage and determination of angles in Cartesian co-ordinate space.

Persons skilled in the art will realise that the steps given above are not the only way to achieve the calibration from the given assumptions and installation data.

Persons skilled in the art will realise that calibration can also be achieved with greater accuracy if the installer can provide more information such as the individual phase-to-ground voltages or if the installer can provide a different set of geometrical information. With reference to the flowchart in FIG. 11 , the method of sensing power system parameters in an electrical network according to the present invention will now be described. As represented by step 300, line sensors 10 are attached to power lines 8. As represented by step 302, line sensors 10 take line current, voltage and temperature samples at time intervals, which are then digitized, as represented by step 304. The digitized data is transmitted from the line sensors to the collector 12 as modulated UHF signals, as represented by step 306. The UHF signals are input to a receiver for demodulation to extract the digital data stream as transmitted by the sensors 10, as represented by step 308. As represented by step 310, the data received from the sensors is corrected for sample timing differences and is re-scaled using the line sensor calibration data. As specified above, calibration of the data may alternatively take place in the line sensors. Furthermore, the voltage data is processed to extract the line-to- ground voltage of each phase by solving simultaneous equations, as represented by step 312. The line current and voltage data are then used to calculate power system parameters, as represented by step 314. The power system parameters may then be employed to compute application-specific signals for, for example, fault detection, as represented by step 316. The application-specific signals may then be transmitted to remote applications or users via the external communications module 74 using the relevant communications system, as represented by step 318. Alternatively, the power system parameters may be transmitted to remote applications without any further local processing. Reproduction of the line current and/or voltage signals in the analogue domain may take place using digital to analogue conversion and analogue conditioning circuitry in the collector 12 or in a device coupled to the collector via a communications system as described above. The reproduced line current and/or voltage signals may be connected to other equipment such as a SCADA system RTU, as described in the example below.

An example of an application of the system of the present invention is shown in FIG. 12. FIG. 12 shows an existing power pole 110 supporting existing line insulators 112 which in turn support three existing power lines 8. A line sensor 10 in accordance with the invention is attached to each power line 8. A collector 12 of the system of the present invention is mounted on power pole 110. Collector 12 includes solar panel 114 comprising photovoltaic cells as a means of providing power for the collector circuitry. A mains power supply might alternatively be provided as described above.

In this example, collector 12 comprises a fault detector application and line sample signals are transmitted from line sensors 8 to collector 12 by a short range radio link 116 to enable collector 12 to generate fault detection specific signals. A long range radio link 118 is employed in this example for the transmission of fault detection specific signals from collector 12 to a remote fault location system (not shown). Another example of an application of the system of the present invention is shown in FIG. 13, which shows the present invention being employed in the monitoring of an existing sub-station. FIG 13 is shown as a single line diagram. FIG 13 shows incoming supply line 120 and three outgoing feeder lines 122. A set of three line sensors 500 according to the present invention are installed on incoming supply line 120 and on each outgoing feeder line 122. Line sample signals are transmitted to collector 12 from each line sensor set 500 using short range radio signals as described above. Collector 12 may be powered by the sub-station power supply 124. Collector 12 is coupled to a SCADA system RTU 126 via serial communications link 127 employing a standard protocol such as Distributed Network Protocol V.3 (DNP3). RTU 126 has hardwired connections to protection relay digital outputs (not shown) and is coupled to a master station (not shown) via communications link 128. In this example, the existing sub- station did not have monitoring capabilities and the cost of installing additional current and voltage transformers for monitoring would have been prohibitive. The sensor system of the present invention can be applied to pre-existing substations to produce efficient, cost-effective monitoring which can be installed with a minimum of disruption. The sensor system and method of the present invention thus addresses at least some of the problems of the prior art. The line sensors 10 of the present invention do not process the data samples to derive the desired power system parameters. Instead the sensors send their data to the collector so that the collector is provided with raw data (or conveniently pre-processed data) from all phases allowing the collector to derive the power system parameters, which would be impossible for any one sensor to derive alone. A further advantage arises from this method in that the processing and power requirements for the line sensors are reduced. This makes implementation cheaper and allows the sensors to be physically smaller devices. Since the line sensors do not have any electrical connections to ground, they can float at line voltage insulated by the surrounding air so there is no requirement for insulation systems for current transformers, power supplies, voltage sensors or communications, thus reducing cost. This has been achieved by use of a current transformer or photovoltaic cell powered from the collector for power supply, an electrode for voltage sensing and radio communications.

Dispensing with battery power sources for the sensors removes the need for batteries to be replaced. Furthermore, by dispensing with solar power sources operation can take place in locations with low levels of sunlight. Employing a Rogowski coil 34 for current sensing has the advantages of low cost, inherent linearity and wide dynamic range.

Employing an electrode for voltage sensing adds a significant degree of functionality to the sensor system so that applications which were not possible with the measurement of current alone now become possible. One of the most significant of these is the identification of earth fault direction.

The Rogowski coil, and the radio antenna can be incorporated into the one or more PCB assemblies to reduce cost. The dual function of the CT core as the voltage sensing electrode is a further cost-saving aspect of the present invention.

Furthermore, all the above features of the sensor are designed so that the sensor can be attached to the network without breaking the power lines or de- energising the power lines bringing significant reduction in the cost of installation to pre-existing electrical networks. Throughout the specification the aim has been to describe the invention without limiting the invention to any one embodiment or specific collection of features. Persons skilled in the relevant art may realize variations from the specific embodiments that will nonetheless fall within the scope of the invention.

Claims

CLAIMS:

1. A sensor system for single or multi-phase power lines of an electrical network, said sensor system comprising:

a line sensor attached to each power line without breaking said line to sample power line current at time intervals and digitize said current samples, each said line sensor being ungrounded and floating at line voltage;

each said line sensor comprising a transmitter to transmit said digitized current data using an insulating transmission medium, said transmission occurring substantially simultaneously with sampling of said line current;

a collector for receiving said data transmitted from each said line sensor and for processing said data to derive power system parameters of said electrical network;

wherein each said line sensor is powered by a built-in power supply requiring no electrical connection external to said line sensor.

2. The sensor system of claim 1 , wherein said collector processes said line current data to determine one or more of the following line current parameters: instantaneous phase current, RMS current, peak current, load current, fault current, fault X/R ratio, zero sequence current, positive sequence current, negative sequence current, fundamental frequency, harmonic content, quality of supply.

3. The sensor system of claim 1 , wherein said built-in power supply is in the form of a current transformer, said current transformer driven by a current flowing in said power line to which said line sensor is attached.

4. The sensor system of claim 1 , wherein said built-in power supply comprises a photovoltaic converter.

5. The sensor system of claim 4, wherein said photovoltaic converter is coupled to a light source in said collector by an optical fibre.

6. The sensor system of claim 1, wherein each said line sensor comprises a Rogowski coil to sample said line current.

7. The sensor system of claim 1 , wherein each line sensor processes said current samples to derive data, said derived data being transmitted to said collector.

8. The sensor system of claim 1 , wherein each line sensor pre-processes said current samples to optimise said transmission to said collector whilst maintaining integrity of said current samples.

9. The sensor system of claim 1 , wherein said digitized current data is transmitted from each said line sensor to said collector using one of the following: radio signals, ultrasound, optical fibre.

10. The sensor system of claim 1 , wherein said transmitter utilizes one or more of the following to permit substantially simultaneous radio transmission of said data from multiple line sensors attached to multiple power lines: frequency division multiplexing (FDM), direct sequence spread spectrum (DSSS), time division multiplexing (TDM), frequency hopping techniques.

11. The sensor system of claim 1 , wherein sampling of said line current by said line sensors is synchronised by a timing source common to said line sensors.

12. The sensor system of claim 1 , wherein each said line sensor samples current asynchronously with respect to one or more other line sensors on multiple phase power lines and said collector corrects for sample timing differences between said samples by digital signal processing using one or more of the following: time of reception by said collector, a timing offset encoded by each sensor in its respective transmission, a time stamp encoded by each sensor in its respective transmission.

13. The sensor system of claim 1 , wherein said digitized current data is transmitted in bursts at a predetermined time relationship to a line current zero crossing point.

14. The sensor system of claim 13, comprising up to six sensors attached to two connected power lines, said power lines being monitored simultaneously by said collector.

15. The sensor system of claim 1 , wherein each line sensor is calibrated by measuring gain factors for each line sensor, deriving calibration data from said gain factors and embedding said calibration data in a line sensor serial number, said line sensor serial number being utilized by said collector to re- scale said line current data received from said sensor.

16. The sensor system of claim 1 , utilized for one or more of the following power system applications: fault detection, fault location, power system protection, distribution automation, monitoring, characterization, power quality determination.

17. The sensor system of claim 1 , wherein said line current signals are reproduced in the analogue domain.

18. The sensor system of claim 1 , wherein each line sensor comprises a voltage sensing electrode capacitively coupled to free space and to other objects at different electrical potential to said power line.

19. The sensor system of claim 18, wherein said electrode is electrically coupled to the power line.

20. The sensor system of claim 19, wherein said line sensor samples at time intervals the electric current flowing between said power line and said electrode, or its time integral and digitizes said samples.

21. The sensor system of claim 20, wherein said line sensor comprises a transmitter to transmit said digitized data using an insulating transmission medium to said collector.

22. The sensor system of claim 21 , wherein said collector processes said digitized data to determine one or more of the following power system line voltage parameters: instantaneous voltage, RMS voltage, peak voltage, zero sequence voltage, voltage sag, voltage surge, fundamental frequency, harmonic content, quality of supply.

23. The sensor system of claim 20, wherein each line sensor pre-processes said digitized samples to optimise transmission to said collector whilst maintaining integrity of said samples.

24. The sensor system of claim 20 wherein each said line sensor samples said electric current asynchronously with respect to one or more other line sensors on multiple phase power lines and said collector corrects for sample timing differences between said samples by digital signal processing using one or more of the following: a time of reception by said collector, a timing offset encoded by each sensor in its respective transmission, a time stamp encoded by each sensor in its respective transmission.

25. The sensor system of claim 20, wherein said digitized data from a set of said sensors installed on a multi-phase power line is processed to extract line-to- ground voltages of each phase by solving simultaneous equations with coefficients representing capacitive couplings between said voltage sensing electrode in each sensor and each of the other phases, and between said voltage sensing electrode in each sensor and ground.

26. The sensor system of claim 18, wherein said capacitive couplings between said voltage sensing electrode in each sensor and each of the other phases, and between said voltage sensing electrode in each sensor and ground, are determined by an installation calibration procedure which does not require any disruption of said electrical network.

27. The sensor system of claim 26, wherein said installation calibration procedure requires that the following are known at the start of said procedure: power system voltage at installation site, minimum spacing between said power lines at point of installation of said sensors, diameter of said line at said point of installation of said sensors.

28. The sensor system of claim 20, wherein said collector processes said power line current and voltage data to determine one or more of the following power system parameters: real power flow, reactive power flow, apparent power flow, fault impedance, fault direction, distance to fault, load impedance, line impedance and power quality determination.

29. The sensor system of claim 18, utilized for one or more of the following power system applications: fault detection, fault location, fault protection, distribution automation, monitoring, characterization, power quality determination.

30. The sensor system of claim 1 , wherein each line sensor also samples line temperature at time intervals.

31. A line sensor attachable to an power line of an electrical network without breaking said line to sample power line current at time intervals and digitize said current samples, said line sensor being ungrounded and floating at line voltage, said line sensor comprising a built-in power supply, a transmitter to transmit said digitized current data using an insulating transmission medium, said transmission occurring substantially simultaneously with sampling of said line current.

32. The line sensor of claim 31 , wherein said built-in power supply is in the form of a current transformer, said current transformer being driven by a current flowing in said power line to which said line sensor is attached.

33. The line sensor of claim 32, wherein a core of said current transformer comprises a split.

34. The line sensor of claim 33, wherein each end of said core is stepped such that a first end overlaps with a second end.

35. The line sensor of claim 33, wherein each end of said core extends inwardly toward a centre of said core.

36. The line sensor of claim 31 , wherein said built-in power supply comprises a photovoltaic converter.

37. The line sensor of claim 31 , further comprising a Rogowski coil to sample said line currents.

38. The line sensor of claim 37, wherein said Rogowski coil is fabricated by printed circuit methods.

39. The line sensor of claim 37, wherein said Rogowski coil is deformable to fit around said power line.

40. The line sensor of claim 37, wherein said Rogowski coil comprises a split.

41. The line sensor of claim 31 , further comprising a voltage sensing electrode capacitively coupled to free space and to other objects at different electrical potential to said power line.

42. The line sensor of claim 41 , wherein said voltage sensing electrode is electrically coupled to said power line.

43. The line sensor of claim 42, further comprising a conductive elastomer to electrically couple said sensor to said power line.

44. The line sensor of claim 42, wherein said sensor samples at time intervals the electric current flowing between said power line and said voltage sensing electrode, or its time integral and digitizes said samples.

45. The line sensor of claim 44, wherein said line sensor comprises a transmitter to transmit said digitized data using an insulating transmission medium.

46. The line sensor of claim 41 , wherein said voltage sensing electrode is utilized as a radio antenna for transmitting said data from said line sensor.

47. The line sensor of claim 41, wherein said voltage sensing electrode is fabricated as part of one of the following: an electronic circuit board, a core of said current transformer.

48. The line sensor of claim 31 , wherein each line sensor samples line temperature at time intervals.

49. A method of sensing power system parameters in an electrical network, said method including the steps of:

attaching a line sensor to each power line of said electrical network without breaking said line, each said line sensor being ungrounded and floating at line voltage and powered by a built-in power supply requiring no electrical connection external to the line sensor;

sampling power line current at time intervals using each said line sensor;

digitizing said power line current samples;

transmitting said digitized current data from each said line sensor to a collector via an insulating transmission medium substantially simultaneously with sampling said line current; and

processing said current data in said collector to derive power system parameters of said electrical network.

50. The method of claim 49, further including said collector processing said line current data to determine one or more of the following line current parameters: instantaneous phase current, RMS current, peak current, load current, fault current, fault X R ratio, zero sequence current, positive sequence current, negative sequence current, fundamental frequency, harmonic content, quality of supply.

51. The method of claim 49, further including each line sensor processing said current samples to derive data and transmitting said derived data to said collector.

52. The method of claim 49, further including each line sensor pre-processing said current samples to optimise transmission to said collector whilst maintaining integrity of said current samples.

53. The method of claim 49, further including each line sensor transmitting said digitized current sample data to said collector using one of the following: radio signals, ultrasound, optical fibre.

54. The method of claim 49, further including said transmitter utilizing one or more of the following to permit substantially simultaneous radio transmission of said data from multiple line sensors attached to multiple power lines: frequency division multiplexing (FDM), direct sequence spread spectrum (DSSS), time division multiplexing (TDM), frequency hopping techniques.

55. The method of claim 49, further including synchronising sampling of said line current by said sensors using a timing source common to said sensors.

56. The method of claim 49, further including each said line sensor sampling current asynchronously with respect to one or more other line sensors on multiple phase power lines and said collector correcting for sample timing differences between said samples by digital signal processing using one or more of the following: time of reception by said collector, a timing offset encoded by each sensor in its respective transmission, a time stamp encoded by each sensor in its respective transmission.

57. The method of claim 49, further including transmitting said digitized current data in bursts at a predetermined time relationship to a line current zero crossing point.

58. The method of claim 57, further including said collector simultaneously monitoring up to six sensors attached to two connected power lines.

59. The method of claim 49, further including said collector re-scaling said line current data using a line sensor serial number, each line sensor serial number comprising embedded calibration data for each line sensor.

60. The method of claim 49, further including utilizing said method for one or more of the following power system applications: fault detection, fault location, power system protection, distribution automation, monitoring, characterization, power quality determination.

61. The method of claim 49, further including reproducing said line current signals in the analogue domain.

62. The method of claim 49, further including each said sensor sampling at time intervals electric current flowing between said power line and a voltage sensing electrode of each said sensor, or its time integral and digitizing said samples, each said electrode capacitively coupled to free space and to other objects at different electrical potential to said power line, wherein said electrode is electrically coupled to said power line.

63. The method of claim 62, further including transmitting said digitized data using an insulating transmission medium to said collector.

64. The method of claim 63, further including said collector processing said digitized data to determine one or more of the following power system line voltage parameters: instantaneous voltage, RMS voltage, peak voltage, zero sequence voltage, voltage sag, voltage surge, fundamental frequency, harmonic content, quality of supply.

65. The method of claim 62, further including each line sensor pre-processing said digitized samples to optimise transmission to said collector whilst maintaining integrity of said samples.

66. The method of claim 62 above, further including each said line sensor sampling said electric current asynchronously with respect to one or more other line sensors on multiple phase power lines and said collector correcting for sample timing differences between said samples by digital signal processing using one or more of the following: time of reception by said collector, a timing offset encoded by each sensor in its respective transmission, a time stamp encoded by each sensor in its respective transmission.

67. The method of claim 63, further including said collector processing said digitized data from a set of said sensors installed on a multi-phase power line to extract line-to-ground voltages of each phase by solving simultaneous equations with coefficients representing capacitive couplings between said voltage sensing electrode in each sensor and each of the other phases, and between said voltage sensing electrode in each sensor and ground.

68. The method of claim 62, further including determining said capacitive couplings between said voltage sensing electrode in each sensor and each of the other phases and between said voltage sensing electrode in each sensor and ground, by an installation calibration procedure which does not require any disruption of said electrical network.

69. The method of claim 68, wherein said installation calibration procedure requires that the following are known at the start of said procedure: power system voltage at installation site, minimum spacing between said power lines at the point of installation of the sensors, diameter of said line at said point of installation of said sensors.

70. The method of claim 64, further including said collector processing said power line current and voltage data to determine one or more of the following power system parameters: real power flow, reactive power flow, apparent power flow, fault impedance, fault direction, distance to fault, load impedance, line impedance and power quality.

71. The method of claim 62, further including utilizing said method for one or more of the following power system applications: fault detection, fault location, fault protection, distribution automation, monitoring, characterization, power quality determination.

72. The method of claim 49, further including each line sensor sampling line temperature at time intervals.