WO2001082444A1 - Generator protection apparatus - Google Patents

Abstract

An embedded generator protection apparatus and method to more accurately detect 'islanding' or 'loss of mains' in which measurements of operational parameters of the local electricity supply, in particular rate of change of frequency or vector shift, are made at two separate locations on the grid, and the measurements compared to determine whether or not a measured fault in the vicinity of the generator is a local or a system wide disturbance, thereby avoiding inadvertent or unnecessary operation of the generator protection. A signal sending relay (34) at a first location, such as a major substation (30), monitors the local rate of change of frequency of the supply and issues a signal to protection apparatus (44) and (54), at a second location, in the vicinity of an embedded generator (42) and (52), in dependence on supply characteristics at the first location. The receipt of the signal by the protection apparatus may simply indicate that the protection is not to operate, or alternatively the signal may be used to determine whether to operate protection or not.

Description

GENERATOR PROTECTION APPARATUS

Background of the Invention

This application relates to embedded generators connected to the mains system and, more specifically, to embedded generator protection apparatus.

Embedded generators are connected to the mains in order to supplement the electricity drawn from the mains. An electricity customer may install such a generator to reduce his electricity demand or even to sell power. It might also benefit a Regional Electricity Company (REC) to install a new embedded generator in response to the opening of a manufacturing plant or other industrial concern, for example, which is expected to make a large demand on the electricity supply. In this way the REC does not need to buy in so much electricity from the national grid or re-enforce its system and can therefore manage its costs more efficiently.

The electricity produced by an embedded generator is supplied at distribution voltages and is not intended to be stepped up to the much higher voltages required for transmission on the supergrid, i.e. the grid above the level of most substations.

Occasionally embedded generators may become isolated from the mains system by faults or spurious switchgear operation. They may however continue to operate stably and continue to supply local load if there is a close match between generation and load. This situation is known as "loss of mains' or 'islanding' and an isolated generator supplying local load is known as a Power island' .

"Power islands' present a number of problem^'s and potential dangers. They may energise apparatus that would otherwise be dead, and thereby present an electric shock hazard to staff; they may further cause damage to themselves and the distribution system as a whole if they are reconnected without first re-establishing synchronisation between the isolated generator and the mains .

Large power stations are protected against such dangers by having sophisticated protection and control systems; the cost of such systems is high however, and it can rarely be justified for smaller generators, which consequently must rely on more simple and cheaper means of protection. Embedded generation normally has protection that operates if the generator voltage and frequency violate pre-selected, specified limits over a set period of time. Typical limits are ±10% of declared voltage and +14% or - 6% of declared frequency. A time delay, typically of 0.5s, before the protection operates avoids operation of protection systems during brief transients but ensures disconnection of the embedded generator before the operation of auto-reclose and possible re-connection out of synchronisation. Protection systems for embedded generators mostly operate by disconnecting the generator if 'loss of mains' is detected. The most common protection system is the ROCOF (Rate Of Change Of Frequency) system, which operates by measuring the rate of change of frequency of the embedded generator and operating the protection if the rate of change of frequency exceeds a preselected threshold value. It is assumed that the frequency of an 'islanded' generator is less stable than when it is connected to the rest of the system, due to the mismatch between generation and demand.

ROCOF protection is popular as it is simple to install and operates quickly; however it cannot ^' always discriminate between changes in frequency due to 'loss of mains' and changes that might occur for other reasons, such as system wide disturbances, and so might unnecessarily operate. Disconnecting a generator often results in a great deal of cost and inconvenience. Some consequences of generator disconnection are listed below.

1. A site being supplied by an embedded generator suffering loss of supply. (In this case supply could include heat or steam as well as electricity if the embedded generator is part of a Combined Heat and Power (CHP) plant;

2. Unnecessary stress being caused to the plant, thereby reducing its working life; 3. Loss of revenue due to a reduction in electricity sales or an increase in import of electricity;

4. The system as a whole suffering voltage dips and possible overloads as the support of embedded generation is withdrawn. We have appreciated that it is therefore highly desirable to provide a generator with protection that can better discriminate between 'loss of mains' and other disturbances that might inadvertently trip protection.

Next, other widely known methods to detect 'loss of mains' will be discussed. The methods can be grouped into two distinct categories: passive methods and active methods .

Passive Methods

1. General These measure voltage, current and frequency and do not disturb the system to which they are connected.

2. Reverse Power

If the embedded generator is installed at a site and designed or operated normally not to export power to the mains, then reverse power protection, which detects exported power due to loss of mains, can be used. However, this cannot be used for embedded generation which is designed to supply power to the system. - A -

3. Reactive Export Error Detection (REED)

This assumes that the trapped load in the power island operates at a lagging power factor and that the embedded generation is designed or operated not to normally export reactive power. Loss of mains causes the embedded generation to export reactive power to the trapped load, operating the protection.

The protection often has a time delay of about 3 seconds to avoid operation due to reactive power export during faults or other transients such as the sudden switching of reactive load. It is therefore normally used as back-up protection.

4. ROCOF & Vector Shift

Operation assumes that the loss of mains causes a sudden change in frequency due to the mismatch of load and generation within the 'power island' so formed. ROCOF responds to the consequent rate of change of frequency, and vector shift responds to the accompanying change in phase of the mains voltage phasor. However neither can reliably discriminate between changes due to loss of mains and changes due to other disturbances. Embedded generation may therefore trip unnecessarily with the serious consequences identified earlier.

5. Change in System Impedance Loss of mains reduces the fault level at the terminals of the embedded generator effectively increasing the system impedance. Various protection schemes are under development to detect this .

One passive method makes use of changes in power flow arising naturally from changes in demand. The protection measures the power output of the generator, the site load and the power flow from or to the mains With the mains connected, the mains largely supplies any changes in load. Without the mains, the generator has to supply the entire load. The protection therefore operates if a change in load is met by the generator rather than the mains. Though feasible, the protection relies upon a convenient change in site load and may not therefore operate quickly.

Active Methods

1. Change in System Impedance

One method involves deliberately connecting a known reactive load and measuring the change in voltage. This method is not favoured by RECs since it imposes a disturbance on the mains, even though the disturbance is claimed to be below the threshold for flicker of lights.

A second method periodically injects a current pulse into the mains and measures the change in voltage.

2. Frequency Shift

This is suitable for embedded generators using inverters to match a variable source of electrical energy (eg photovoltaics, wind turbines) to the mains. The free running frequency of the inverter is set to run differently to the nominal mains frequency. When the mains is present, the inverter frequency locks to that of the mains but when the mains is lost the abrupt change in frequency operates protection.

There are a number of drawbacks with active methods of protection.

First, active measurement can disturb the system and the RECs object to this, even though the disturbances are claimed not to affect other equipment. The disturbances could be made much less frequent by carrying out measurements only when a loss of mains is suspected, eg following a sudden change in voltage, frequency of current. Secondly the interaction of different designs of active protection is hard to predict but tests have shown such interaction can prevent detection of loss of mains.

None of these methods, however, overcome the problem of unnecessary protection tripping.

A known power system protection relay, which employs some of the techniques outlined above, is described in the P&B Engineering Publication entitled "MRMF, MRFT, MRVT, MROS Mains Protection Relays". We have appreciated that the problem of unnecessary protection tripping is likely to get worse, as embedded generation becomes more widespread and more relied upon by Regional Electricity Companies (RECs), and that a more reliable and more economic form of protection is needed.

Summary of the Invention

According to a preferred embodiment of the invention there is provided a generator protection apparatus comprising: a local detector for determining one or more operating parameters of the local electricity supply in proximity to a generator connected to an electricity grid, the local detector having an output; a remote detector for determining one or more operating parameters of the remote electricity supply elsewhere on the grid to which the generator is connected, the remote detector having an output; and local generator protection means coupled to the outputs of the local and remote detectors; the local generator protection means being operable in dependence on the output of the local detector and on the output of the remote detector. Preferably, the remote detector responds to a smaller deviation from normal operating conditions than the local detector, so that there is time for a blocking signal to travel from the remote transmitter to the local receiver. The remote signal transmitter may transmit test signals to the local receiver, the local detector being operable, such that should the local generator protection means not receive the test signals the pre-determined normal operating values used in the local determination are such that it is easier for the one or more operating parameters of the local electricity supply to lie outside the pre-determined normal values than when the test signals are being received.

Preferably, either of the remote or local detector are operable to detect rate of change of frequency of the electricity supply, or are operable to detect a vector shift of the electricity supply.

The present invention therefore provides generator protection that operates in dependence on a comparison between the operating characteristics of the supply at the embedded generator and the operating characteristics of the supply at a remote site, and which can thereby distinguish more effectively between system wide disturbances and disturbances that stem from 'loss of mains' at the embedded generator. The present invention therefore provides the owners of generators with a more effective way of protecting their apparatus and revenue from the costly consequences of unnecessary generator disconnection while still offering protection against reconnection out of synchronisation.

The present invention also, therefore, provides Regional Electricity Companies with a more effective way of protecting their networks and therefore their revenue from the costly consequences of needless generator disconnection.

Brief Description of the Drawings

The present invention will now be described in more detail by way of example with reference to the drawings, in which: Figure 1 illustrates the preferred protection system and an electrical mains system to which an embedded generator is connected;

Figure 2 illustrates the system of Figure 1 in which the embedded generator has become isolated from the rest of the mains system;

Figure 3 is a schematic diagram of the MRMF relay which forms part of the preferred system;

Figure 4a shows the input transformers of the MRMF relay in Star Configuration;

Figure 4b shows the input transformers of the MRMF relay in Delta Configuration;

Figure 5a shows a circuit and phasor diagram of a generator exporting power, at a slightly lagging power factor;

Figure 5b shows the circuit of Figure 5a in which a breaker trip has occurred and the corresponding voltage phasor diagram for this situation;

Figure 6a shows a circuit in which a generator is providing power to a load in parallel with a mains supply infeed;

Figure 6b shows the phasor diagram before and after loss of mains supply occurs in the circuit of Figure 6a; and Figure 7 shows the effect of a phasor shift on a voltage time base.

Description of the preferred embodiment

Referring to Figure 1, there is shown a preferred protection system 10. A major substation 30 is connected to the National Grid 20 at transmission line 32 and is provided with a Comparison of Rate of Change of Frequency (COROCOF) sending relay 34. The major substation 30 is connected to subsequent local substations 40 and 50 by lines 36 and 38 which terminate at power lines 46 and 56 respectively of the local substations. It is understood that between the major substation and the local substations there maybe transformer apparatus to transform the voltages of the power lines, although this is not shown. Local substations 40 and 50 are provided with generators 42 and 52, COROCOF protection apparatus 44 and 54, and are connected to local loads 48 and 58. The COROCOF sending relay 34 at the major substation is linked to the local COROCOF protection apparatus 44 and 54 by signal line 35. Figure 2 shows a similar arrangement with major substation, local substations and protection means disposed as in Figure 1, and given the same reference numbers. In this case however, local generator 40 is shown isolated from the major substation 30 and the National Grid 20, by a break in line 36. The break might be due to the operation of switchgear (not shown) , and could be intentional or due to faults or spurious operation. It will be appreciated that there are other instances in which a break could occur isolating the local generator from the rest of the grid, and that these instances need not be discussed here.

Figure 3 shows, in detail, a known protective relay device 60 which is used as part of the preferred protection system 10. The device shown is the MRMF relay from P&B Engineering. It is a generator protection relay, and offers a wide range of protective functions in one compact unit.

The MRMF unit fundamentally comprises a power supply module 62 with live and neutral connections 90 and 92 and earth connection, and a microprocessor unit (not shown) . The MRMF relay receives incoming mains voltage inputs via external voltage transformers 70, 72, and 74. These inputs are converted to internal signals in proportion to the external voltages via shunt resistors 80, 82 and 84 and internal input transducers (not shown) . Noise signals caused by inductive and capacitive coupling are suppressed by an analogue RC filter circuit (not shown) . The analogue signals are sampled and fed to the A/D converter of the microprocessor and transformed to digital signals through sample hold circuits (not shown) in known manner. The input transformers in Figure 3 are connected in the Star configuration as shown in Figure 4a, but it is appreciated that it would possible to connected them in the Delta configuration as shown in Figure 4b.

The MRMF unit has five output relays comprised of single or dual pole change-over contacts: 'tripping' relay 100, 'indication of under and over voltage' relay 102 and 'indication of over and under frequency' relay 104 each have two such contacts 110 and 112, 114 and 116, and 118 and 120 respectively; 'indication of vector surge or df/dt' relay 106 and 'self-supervision alarm' relay 108 however, have only a single contact 122 and 124 respectively. Each relay gives a trip signal based upon the determination of a different analysis. This is discussed later. The MRMF unit is further provided with auxiliary terminals 94, 96 and 98 for receiving external command voltages. A voltage applied to terminals 94 and 96 is used to effect an external reset of the device. A voltage applied to terminals 96 and 98 is used to effect the blocking of certain functions of the MRMF relay, to prevent a trip signal from being given.

The operation of the preferred embodiment, as illustrated, will now be described in more detail with reference to the drawings. The preferred system 10 measures the rate of change of frequency of the electricity supply at two locations, and then makes a comparison between the measurements to decide whether an observed disturbance is system wide or local. If a disturbance is deemed system wide, then local protection apparatus is instructed not to operate and unnecessary tripping is avoided. Figure 1 shows a major substation 30, comprising COROCOF sending relay apparatus 34. The sending relay is connected to local COROCOF protection apparatus 44 and 54, situated at local substations 40 and 50, by signal line 35.

Preferably, the sending relay is located where there is always check synchronizing protection between that location and the embedded generation. This prevents power islands being formed without check synchronizing protection available to prevent reconnection out of synchronism.

The COROCOF sending relay 34 constantly measures the rate of change of frequency of the electricity supply at the major substation to determine whether or not it exceeds pre-selected normal operational thresholds. If the measured rate of change of frequency is found to violate normal parameters the COROCOF sending relay 34 transmits a signal, along line 35, to the COROCOF protection apparatus 44 and 54 at the local substations. Referring momentarily to Figure 3, which shows a preferred relay device used as part of the COROCOF protection apparatus, it will be understood that the signal from the COROCOF sending relay 34 will be received by the COROCOF protection apparatus 44 and 54 at terminals 96 and 98 of the MRMF relay 60.

Referring once more to Figure 1, COROCOF protection apparatus 44 and 54 at the local substations 40 and 50, in similar fashion to the COROCOF sending relay 34, measures the local rate of change of frequency of electricity supply. However, in addition, the local protection 44 and 54 also constantly monitor inputs received via line 35 and terminals 96 and 98 from the COROCOF sending relay 34. Providing that no signal is received at terminals 96 and 98, the MRMF relay of the local COROCOF protection apparatus, on sensing that the local rate of change of frequency violates pre-selected normal operational parameters, activates the protection and disconnects the generator. If however, a signal is received from the COROCOF sending relay 34, then the protection will be inhibited. The signal sent by the COROCOF sending relay, is therefore, a blocking signal, which instructs local generator protection not to operate in response to disturbances which are also manifest at locations distant from the generator.

Figure 1 shows the grid system in a state where the embedded generator is connected and functioning normally. In this example, any deviations in the rate of change of frequency at the local generator are assumed to be system wide, and so detected by both the local protection apparatus 44 and 54 and the COROCOF sending relay 34. Though the local protection apparatus 44 and 54 detects that the rate of change of frequency exceeds the preselected threshold, the protection does not operate because the sending relay, having made the same determination, sends a blocking signal to terminals 96 and 98 of the local apparatus and prevents the protection from tripping.

Figure 2 however shows the situation in which the embedded generator has become isolated or 'islanded' . In this example, the frequency of the 'islanded' generator 42 fluctuates and is detected as violating normal operational limits by the local protection apparatus 44. This time however, the COROCOF protection apparatus 44, does not receive a blocking signal from the COROCOF sending relay 34 since, at the major substation, the situation remains normal. The local protection 44, therefore trips, disconnecting the generator.

In order to ensure that the blocking signal' is received by the local generator protection apparatus 44 and 54 in time to stop it operating in response to system wide disturbances, the rate of change of frequency threshold and the time delay parameters of the COROCOF sending relay 34 are set lower than those of the COROCOF protection at the generator.

The use of a blocking signal, as so described, has the advantage of ensuring that, if the blocking signalling fails, the protection system fails safely, that is, the protection essentially defaults to ordinary ROCOF protection which still operates in response to a loss of mains that causes a change in frequency exceeding accepted normal operation thresholds . Of course, if the blocking signal relay should fail, then, as with known protection systems, there is a high risk of nuisance tripping in response to changes in frequency that occur for reasons other than loss of mains. The COROCOF sending relay 34 of the preferred system 10, therefore, is configured to periodically transmit test signals to the local COROCOF protection apparatus 44 and 54. COROCOF protection apparatus 44 and 54 constantly monitor the test signals and in the event that they are not received, default to higher threshold settings than those normally employed, thus ensuring some additional security against unnecessary tripping in the event that the sending relay 34 or the signalling system should fail.

Preferably, the blocking signal is modulated or encoded according to the phase and frequency measured by the COROCOF sending relay at the major substation, and the local COROCOF protection apparatus is configured to make a comparison between the phase and frequency characteristics of the supply at the major substation with that at the local means. If this comparison, which may be based on frequency, phase, rate of frequency change or vector shift for example, indicates that the embedded generator is still connected to the mains then the protection ^• is blocked from operating. Thus, incorrect blocking of the protection apparatus, that might occur for example if a power island was formed at the same time that the rest of the system suffered a disturbance in frequency, may be avoided.

Although in Figure 1, the blocking signal is shown as being transmitted via a separate line 35, it could be transmitted using various signalling methods. These include AC or DC signalling over private pilot wires, voice frequency signalling, optical fibres, power line communication (sometimes called "mainsborne") , radio and microwave links. Brief loss of the signalling channel, e.g. for maintenance, could be tolerated as the protection would "fail safe" by defaulting to ordinary ROCOF protection.

The blocking signal may be transmitted using existing protection signalling methods. COROCOF blocking signals would be brief and infrequent (a few seconds a month) and so the communication system could be use for other traffic with starting relays switching the system over to COROCOF signalling as required.

For large embedded generators an economic method may be audio frequency signalling over rented telephone circuits. This can be installed quickly and uses existing technology.

For smaller generators, however, the costs of audio frequency signalling are not economical, and the challenge is to communicate cheaply, quickly and reliably to thousands of embedded generators. This could be done using some form of broadcast system such as power line communication or radio signalling. Power line communication signalling uses audio or radio frequency signals sent along the mains conductors.

Another possible method of signalling is Automatic Meter Reading (AMR) systems which are being developed to read tariff meters remotely and transmit tariff information. These systems could be used to transmit a COROCOF blocking signal especially as loss of mains protection is often applied at the commercial boundary of the embedded generator's site, as is the tariff meter. Preferred alternative modes of signalling will be described next. In a preferred embodiment, a power line communication transmitter is installed at the HV/LV transformer to relay the blocking signal from a substation with check synchronising protection.

The mains is an obvious choice of communication channel as it already exists and can serve all generators connected to it. It also offers a fail safe feature: loss of mains would prevent the blocking signal reaching the generator COROCOF protection. The protection would still trip in response to a rate of change of frequency due to loss of mains. A blocking system also avoids unnecessary disconnection of embedded generation due to failure of the power line communication transmitter.

Power line communication signalling over the whole of an LV distribution system requires power equal to 0.1 to 0.3% of the load. A 1 MVA LV distribution system would therefore need about 2kVA which is feasible. As the_, blocking signal would be brief and infrequent the equipment need only be short time rated and the financial cost of the energy may be neglected. Some of the signal would pass into the HV network but its presence would not necessarily compromise operation of COROCOF protection connected to neighbouring substations. The signal would merely confirm that blocking is needed. Use of different signals at nearby substations would solve problems of interference. The COROCOF protection would be designed to block in response to receiving any of several signals used. This would allow for abnormal operation of the system causing the embedded generator to be connected to a different substation. It may be possible to transmit a power line communication signal from the nearest substation with check synchronising protection to generators connected to it. In the UK such substations would be 132kV to lower voltages, supplying typically 60 MVA of load. This would need about 120 kVA of power line communication signal though, as described earlier, this would be brief and infrequent.

Widespread application of power line communication signalling would impose a significant extra demand on the system during frequency changes but this would be preferable to losing the contribution from embedded generation.

Power line communication signalling also has the advantage that the blocking signal need not be modulated or encoded according to the phase and frequency of the supply measured at the remote COROCOF sending relay to avoid incorrect blocking at the local protection apparatus. Loss of mains in this case would result in the loss of the communication link for the blocking signal, thereby preventing incorrect blocking during frequency disturbances in the rest of the system. Thus, in this mode of signalling the blocking signal need only indicate that a change in frequency that exceeds the relay setting has occurred. As the size of the change need not be communicated, the signal may be a simple on/off signal. This advantage would be lost however, if there was cross talk available to couple the signal from the rest of the system to the power island, thereby allowing incorrect blocking to occur.

In another embodiment, radio signalling is used. Radio signalling is a good alternative if power line communication signalling proved impractical or uneconomic. Radio signalling can be applied quickly to cover a wide area using established techniques and commercially available equipment. Satellite systems could also be used. For reliable protection signalling at least two radio transmitters on different frequencies are needed to cover an area to allow for one radio transmitter being out of service. The protection receives signals from all radio transmitters used and restrains if it received at least one blocking signal. The blocking signal may also be transmitted to carry frequency and phase information of the local mains at the radio transmitter. Normally the local frequency and phase would be that of the system as a whole but would not be so if the radio transmitter were operating on emergency generation. In that case, the blocking signalling equipment would have to be switched off and protection would rely on other radio transmitters. Alternatively, the blocking signal could be transmitted according to signals received along a suitable signal line from a COROCOF sending relay at a major substation.

A suitable method would be phase modulation of low frequency radio broadcasts using similar techniques to radio teleswitching. In the UK, radio teleswitching uses the BBC Radio 4 low frequency transmissions on 198 kHz to control suitably equipped loads and manage system demand. Phase modulation of the carrier transmits coded information and this method could be extended to transmit a blocking signal. Phase modulation does not interfere with the programme being broadcast. Tests have shown that low frequency phase modulated signals can be received reliably in most locations, including deep within buildings. This contrasts with other forms of radio communication. For example, AMR systems operate in frequency bands between 900 MHz (USA) and 184 MHz (UK) but they need a reasonably clear radio transmission path.

Suitable low frequency radio transmitters comprise: a) Phase modulation of broadcast transmitters including BBC Radio 4 198 kHz, the presently unused UK 225 kHz allocation, and European transmitters which can be received in the UK. In the latter case, the blocking signal could be sent using audio frequency signalling by telephone from the UK to those transmitters . This principle could be extended to other European power systems by using low frequency broadcast transmitters to transmit blocking signals from several power systems. The blocking signals would be coded to identify the systems experiencing changes of frequency. b) Decommissioned low frequency navigation systems. These include the Decca Navigator low frequency transmitters, 70-130 kHz and marine radio direction finding (RDF) beacons 270-430 kHz. These systems are being superseded by the Global Positioning System (GPS) and will cease operation by March 2000. Afterwards the frequencies could be used to transmit blocking signals . Existing power line carrier protection signalling systems presently in use would not be suitable.

Regulations restrict the transmission of carrier to avoid interference with other services and carrier systems have been designed accordingly. They would not therefore be suitable for broadcasting blocking signals as the power levels are too low, typically 10W, and the power lines make poor aerials.

Both power line communication and radio signalling are vulnerable to interference but, suitable modulation and encoding techniques can be used to reduce the effects of interference.

Radio signalling would probably be the cheapest method for a REC. About 2 kVA of power line communication signalling would be needed for a 1 MVA distribution system whereas a 2 kW radio transmitter would serve many such distribution systems. Power line communication signalling would probably be the cheapest method for embedded generators as only the mains voltage waveform need be measured and this would be done anyway for voltage and frequency protection. However radio signalling would also need a radio receiver.

Costs would be even lower if the COROCOF blocking signalling could be incorporated into AMR systems.

An alternative mode of signalling will be described next, in which the blocking signal is transmitted continuously using any of the transmission methods described above. In this mode, the presence of the blocking signal is not interpreted by the local protection apparatus as an instruction to restrict operation. Instead, the blocking signal is a signal which corresponds to the phase of the system voltage and the generator protection is configured to compare the frequency and phase of this signal with the frequency and phase of the local mains and to trip if the comparison indicates a loss of mains. Preferably, this signal, termed the "VPC (Voltage Phase Comparison) signal" is transmitted according to the system voltage measured at a major substation or similar location chosen as being reasonably representative of the system "infinite busbar" voltage. One or more VPC signals may be transmitted from one or more such locations .

A suitable VPC signal would be one modulated to identify the positive and negative zero crossing points of the system voltage. For example, a square wave with leading and trailing edges corresponding to the positive and negative zero crossing points.

This mode of signalling is advantageous since there is no need to detect a frequency disturbance of the system as a whole and to transmit a blocking signal in response. This avoids the delay, and possible unreliability of such detection since no starting relays to establish communication when frequency disturbances are detected are required. Neither is there any need to transmit test blocking signals to confirm that the transmitter is working. A drawback is that the signal would have to be transmitted continuously making it harder to share a communication channel with other traffic.

Continuous transmission of the VPC signal would benefit other forms of protection and control, especially "pole-slipping" protection. Pole-slipping occurs when a generator loses synchronism with the rest of the system yet remains connected to it. Sometimes, system conditions prevent unambiguous detection of pole-slipping. For example, large generators connected to weak systems can pole-slip but pole-slipping protection installed at the generator terminals may fail to detect this. By contrast, voltage phase comparison protection offers a way of detecting pole-slipping by comparing the phase of the local mains with the phase of the system as a whole. Interference with the VPC signal, malicious or otherwise, could upset the phase and frequency comparison and trip generation unnecessarily. Therefore, comparison may have to be confined to discriminate between a loss of mains, pole-slipping and other system disturbances. One strategy would be for VPC generator protection to measure the rate of change and frequency, or vector shift, of the local mains. If it detected either, it would compare the frequency and phase of the local mains with the VPC signal and trip if the comparison indicated a loss of synchronisation.

Preferably, VPC protection is configured to revert to ROCOF (rate of change of frequency) or vector shift protection following corruption or even loss of the VPC signal. This risk would be reduced by using more than one VPC transmitter and basing operation on the VPC signal received that corresponds most closely to the local mains. Interference could be detected by measuring the phase of the VPC signal to see if it indicated system conditions that were not credible, for example frequency well outside declared limits, or dramatic changes in frequency or phase not possible in a real system. Preferably, in such circumstances, the protection scheme is adapted to default to detecting ROCOF or vector shift. This would be necessary as telecommunication systems could introduce sudden changes in phase of the VPC signal. Telecommunications companies sometimes re-route circuits without notice and this can introduce unpredictable changes in propagation delay affecting the phase of the VPC signal.

The cost of transmitting a VPC signal continuously could be defrayed by using it to send messages. Suitable modulation would allow this without compromising its protection function. This would be of considerable benefit to network operators who will face the challenge of accommodating, or even controlling, hundreds of thousands of embedded generators. Control would imply some form of communication, at least one-way, between the network operator and the generators. As this progresses, there will be an increasing need to communicate with such generators for the safe and efficient operation of the system.

Suitable modulation of the voltage phase comparison signal would allow communication of additional information, adding value to the VPC signalling system. This may include: demand side management signals similar in objectives to the radio teleswitching service; "Day ahead" real time pricing information to allow customers and generators to plan their consumption and generation; quickly updating prices, for example to raise prices in response to the sudden loss of generation, encouraging other generators to increase output and customers to reduce load; time signals for synchronizing and correcting clocks in tariff metering systems and elsewhere; and third party messages. Despite employing the measures described earlier it is still possible that local fluctuations in the mains might inadvertently trip generator protection. One such possibility is that brief local changes in voltage phase angle, caused, for example, by switching of load or generation would be detected by the protection apparatus 44 and 54 as apparent changes in local frequency. Since such changes are local by their very nature, no blocking signal would be received from the COROCOF sending relay 34 at the major substation 30 and the local protection could operate unnecessarily. Suitable protection systems would avoid such operation in the manner discussed as follows: In most systems the impedance of the supply is less than 0.15 pu ('per unit') on the rating of the generator or load ( 'Per Units' are a system of units commonly used in the field of Electrical Engineering, in which actual values are expressed as fractions of reference values, such as rated of full load values) . The impedance avoids excessive voltage changes during changes of generation or load. For example a load of 1 pu operating at a power factor of 0.8 would take reactive power of 0.6 pu. Assuming that the impedance X is entirely reactive, the change in voltage ΔV due to a change in reactive load Q is given by:

AV = XQ

V

If V, the voltage at the load is 0.94 pu, ie at the lower limit of -6% then ΔV = 0.096 pu, or 9.6%. This change would normally be corrected by transformer tap changing which is typically +/-10% with some of this range allowing for changes in the HV system, typically +/-6%.

The phase angle δ between the load voltage and the voltage of the source is given by:

PX sin-- — Where P is the active power of the load and E is the voltage of the source. If the load is operating at unity power factor then P is 1 pu. If E and V are both 0.94 pu, i.e. both at the lower limit of -6% then the change in phase angle due to the sudden disconnection of the load, due to a fault for example, is 9.8°. Similar reasoning applies to generation.

Therefore, changes in voltage phase angle are not likely to exceed 10 degrees in most cases and typically occur within 100ms; this is the usual time taken to switch the load and for transients to decay.

In the case of a high impedance plant, such as that used to limit fault current, the change in the phase angle will be increased following disconnection of load. The COROCOF protection may therefore need to be set up to ignore changes of greater than 12° in such cases.

The COROCOF protection should therefore be set to ignore brief changes in frequency that do not produce a specified change in voltage phase angle within a certain time. This is implicit in some relay designs, in particular, for example, the WH Allen relay for which the recommended settings correspond to 12° over 0.6s which, in a 50Hz system, is equivalent to a rate of change in frequency of 0.093 Hz s^"1. Next the preferred sensing apparatus, the MRMF, will be described.

The essential component of the MRMF relay is a power micro-controller. All of the operations, from the analogue digital conversion to the relay trip decision, are carried out by the micro-controller digitally. The relay program, located in EPROM, allows the CPU of the micro-controller to calculate the voltage values ^' in order to detect a possible fault.

The MRMF can analyse the operating parameters or characteristics of the electricity supply in a number of ways, each of which will described below. For the calculation of the measured values, an efficient digital filter, based on the Fourier Analysis (DFFT - Discrete Fast Fourier Transformation) , is applied to suppress high frequency harmonics and DC components caused by fault induced transients or other system disturbances. The actual calculated values are compared with the relay settings. When a measured value exceeds the starting value the unit starts the corresponding time delay calculation. When the set time delay has elapsed, a trip signal is give at the relevant output relays 100, 102, 104, or 106.

The related setting values for all parameters are stored in EPROM, so that the actual relay settings cannot be lost, even in the event of auxiliary supply interruption. The micro-processor is supervised through a built in "Watch-dog" timer. Should a failure occur the watch-dog timer resets the micro-processor and gives an alarm signal via the self supervision output relay 108.

The various protection functions and methods of the MRMF relay will be described next.

Voltage Supervision

The MRMF relay is equipped with a two stage, independent, three phase overvoltage (U>, U>>) and undervoltage (u<, U«) characteristic, with completely separate time and voltage settings.

In Delta connection, the phase to phase voltages, and in Star connection, the phase to neutral voltages, are continuously compared with the pre-set thresholds.

For overvoltage supervision, the highest voltage of each phase is relevant, whilst for undervoltage supervision, the lowest voltage in each phase is relevant. Frequency Supervision

The MRMF relay is equipped with multiple stage independent over frequency and under frequency protection with separate time and frequency settings. The principle behind frequency supervision is based upon the time taken for a complete cycle, the influence of harmonics is therefore minimised.

To avoid tripping during normal operation due to voltage transients or phase transients, the MRMF relay is equipped with an adjustable repeat measurement function. Each cycle where the pre-set threshold is reached, an internal counter is increased until the set point of the repeat measuring function is reached; at this point the relay trips. With each cycle without any fault the counter is decreased and for the case of normal operation the counter is decreased to zero. In the case of very low input voltages (5-100% of U_n adjustable, where U_n is the nominal input voltage) the frequency measuring is automatically inhibited to avoid failure tripping. This same inhibit may also take place (and continues for 1 second) when the auxiliary supply or measuring voltage is initially switched on.

Vector Surge Supervision

Vector surge supervision protects synchronous generators in parallel operation from faults by very fast decoupling. In the case of mains failure where the mains voltage could return in 300ms, this could hit the generator in asynchronous mode which can be very dangerous. The same fast decoupling is also necessary in the case of transients. Generally there are two different applications:

1. Mains Parallel Operation without Island

Operation - In this application the vector surge supervision protects the generator by tripping the generator circuit breaker in the case of mains failure. 2. Mains Parallel Operation with Island Operation - In this application the vector surge supervision trips the mains circuit breaker ensuring that the gen-set is not blocked when required as the emergency set. Very fast decoupling in the case of mains failures for synchronous generators is difficult to achieve as voltage supervision alone cannot be used. This is because the synchronous alternator as well as the unit impedance supports the decreasing voltage. Because this voltage reaches the threshold of the voltage supervision after 200ms, safe detection for auto-reclosing of the mains is not possible with single voltage supervision units.

Also frequency supervision alone cannot be used, as even a fully overloaded generator decreases in speed after 100ms. Current protection relays can detect the fault by the existence of short circuit currents as can power sensing relays but neither can avoid the decreasing change of power to short circuit power. A further problem is the failure tripping of these devices due to the sudden change in the loading of the generator.

The MRMF relay can detect mains failure in less than 60ms due to its specialised design for this specific application. The total tripping time is within 150ms even when the circuit breaker time and the relay time are taken into consideration. A change in power of only 10% or more will cause the relay to trip whereas slow changes in the system frequency such as controlling of the governor will not cause the relay to trip. A short circuit in the mains may also trip the relay if a vector surge higher 'than the pre-set threshold is detected. The value of the vector surge is dependent upon the distance of the short circuit in the generator. This function has the advantage that the mains short circuit capacity and hence the energy feeding the short circuit can be limited.

Vector surge supervision should only be used in mains parallel operation. In single operation the auxiliary supply must be switched to the blocking input, terminals 96 and 98.

Next, the way in which changes in load are detected by voltage supervision will be discussed in more detail and with reference to the drawings. When a synchronous machine (generator) is under load, the terminal voltage (relaying point) differs from the actual generator internal voltage. This volt drop results from current flow through the internal generator impedance (and external impedance if fitted) . A simplified phasor diagram of a generator exporting power, at a slightly lagging p.f. is shown in Figure 5a.

It should be noted that a leading power factor will still produce an angular difference v between phasors .

If the current is reduced to zero (say by a breaker trip) , then V_g and V_term would become co-phasor (as shown in Figure 5b) since V_drop would no longer be present. A vector shift of v would be "seen" by the protection relay, and if above the setting or threshold level would initiate a trip. Where a generator provides power in parallel with a mains supply infeed, as shown in Figure 6, any loss of mains supply, say through a distant outage, will cause an increase in the load "seen" by the generator. This change of load will again cause a vector shift. If the shift is in excess of the set value the relay will trip.

Typically a current of approximately 5% of Full Load with typical generator parameters will produce sufficient phasor shift for reliable operation and a mid-range setting. The phasor shift effect is shown in Figure 7 on a voltage-time base. The cycle time is compared with a quartz clock reference. A phasor shift will cause a change in the zero crossing point which will in turn cause a trip of the relay if the trip angle ΔΘ has been exceeded.

df/dt Measurement Principles

When a synchronous machine (generator) is under any load, the mechanical power provided by the prime mover supplies the electrical output of the machine, the machine losses and the stored energy contained within the rotating mass.

If a sudden change in load occurs the electrical output of the machine changes, whilst in the short term both the mechanical power and the losses remain approximately unchanged. This change in power therefore produces a net acceleration or deceleration in the rotating mass. The rotational velocity of the mass is directly related to the frequency of the generated voltage. Thus an increase or decrease of the system frequency (df/dt) can be directly related to a sudden change of load on a machine. This can usually be attributed to a loss of mains supply, where either the load is reduced giving an increase in speed of the machine or an additional load (other grid loads etc.) Where a decrease in speed of the machine may be noted. The setting of df/dt is dependant upon

1] The normal export/import level of the generator/grid arrangement.

2] The inertia of the machine (or inertia constant H) .

3] The type of motion imparted by the primary mover i.e. if a diesel (reciprocating) engine is used the pulsating torque may produce significant df/dt under normal but high load conditions.

A typical setting of df/dt for a stiff system with little normal export of power and large machine inertia is df/dt = 0.2 Hz/sec. A typical setting of df/dt for a weak system with considerable normal export of power and a low machine inertia is df/dt = 0.4Hz/sec.

For reciprocating drives a figure is guided by the above recommendations but modified to insure that no spurious operation takes place due to the nature of the prime mover is typical.

Although in the embodiment described an MRMF relay is preferred as the sensing relay, it is to be understood that any device which can analyse the operating parameters of the electricity supply and give an alarm if normal preset thresholds are violated, and which can be inhibited by the application of an external signal to block operation, could equally be used. In the manner herein described the preferred protection system addresses the problem of protection tripping unnecessarily and thereby improves upon existing protection systems.

Claims

1. A generator protection apparatus comprising: a local detector for determining one or more operating parameters of the local electricity supply in proximity to a generator connected to an electricity grid, the local detector having an output; a remote detector for determining one or more operating parameters of the remote electricity supply elsewhere on the grid to which the generator is connected, the remote detector having an output; and local generator protection means coupled to the outputs of the local and remote detectors; the local generator protection means being operable in dependence on the output of the local detector and on the output of the remote detector.

2. Apparatus according to claim 1 wherein the local generator protection means are, in use, de-activated when both the local detector and the remote detector determine that the one or more operating parameters of the electricity supply lie outside pre-determined normal values .

3. Apparatus according to claim 2 further comprising: a comparator, coupled to the outputs of the local detector and the remote detector, and coupled to the local generator protection means, for providing a comparison signal dependent on the compared outputs; wherein, if the outputs of the local and remote detector indicate that the local generator protection means should be de-activated, the comparison signal is checked and the generator protection means are deactivated only if the comparison signal indicates that the remote electricity and the local electricity supply are in synchronisation .

4. Apparatus according to claim 1 further comprising: a comparator, coupled to the outputs of the local detector and the remote detector, and coupled to the local generator protection means, for providing a comparison signal dependent on the compared outputs; wherein the local generator protection means are operated in dependence on the comparison signal.

5. Apparatus according to claim 2 wherein, in use, the remote detector provides a continuous output, and the comparator is operable to continuously provide a comparison signal, the local generator protection means being operated when the comparison signal indicates that the local electricity supply and the remote electricity supply are not in synchronisation.

6. Apparatus according to any of claims 1, 2 or 3 in which the remote detector is operable to output a signal only when it determines that the one or more operating parameters of the remote electricity supply lie outside pre-determined normal values.

7. Apparatus according to claim 6 in which the signal from the remote detector is transmitted by power line communication methods.

8. Apparatus according to claim 6 in which the signal from the remote detector is transmitted by radio signalling, fibre optic communications, pilot wire communication or by audio frequency signalling.

9. Apparatus according to any of claims 6, 7 or 8, in which the pre-determined normal operating values of the remote detector and the pre-determined normal operating values of the local detector are chosen such that the signal from the remote detector may reach the local generator protection means in time to de-activate the protection means.

10. Apparatus according to any of claims 6 to 9, wherein: the remote detector is operable to transmit test signals to the local generator protection means; and the local detector is operable, such that while the local generator protection means receives test signals the pre-determined normal operating values used in the local determination are different to those used when the test signals are not being received.

11. Apparatus according to claim 10 wherein the local detector is further operable to give an alarm signal should the test signals not be received.

12. Apparatus according to any preceding claim in which either the remote detector or local detector are operable to detect rate of change of frequency of the electricity supply.

13. Apparatus according to any preceding claim in which either the remote detector or local detector are operable to detect the vector shift of the electricity supply.

14. The generator protection apparatus of claim 2, wherein the one or more operating parameters used in the determination by the local or remote detector are one or more of the rate of change of frequency and vector shift of the electricity supply.

15. The generator protection apparatus of claim 3 or 14, wherein the comparison signal is generated in dependence on one or more of the frequency and phase of the electricity supply.

16. The generator protection apparatus of any preceding claim in which the output of the remote detector is encoded or modulated to carry additional control signals and information.

17. The generator protection apparatus of any preceding claim wherein the remote detector is located at a substation on the grid to which the generator is connected.

18. A method of protecting a generator comprising the steps of: a) determining, at a first location in proximity to a generator connected to an electricity grid, one or more operating parameters of the local electricity supply; b) determining, at a second location elsewhere on the grid to which the generator is connected, one or more operating parameters of the remote electricity supply; and c) operating, at the first location, local generator protection means in dependence on the determination made for the local electricity supply and on the determination made for the remote electricity supply.

19. The method of claim 18 wherein step c) includes deactivating the local generator protection means when it is determined that both the one or more operating parameters of the local and the remote electricity supply lie outside pre-determined normal values.

20. The method of claim 19 wherein step c) further comprising the steps of: i) generating a comparison signal dependent on the compared outputs, if the local and remote determinations indicate that the local generator protection means should be de-activated; and ii) blocking the generator protection means only if the comparison signal indicates that the remote and the local electricity supply are in synchronisation.

21. The method of claim 18 wherein step c) includes the step of: i) generating a comparison signal based on the determinations for the remote electricity supply and the local electricity supply; and ii) operating the local generator protection in dependence on the comparison signal.

22. The method of claim 21 wherein step i) includes generating the comparison signal continuously; and step ii) includes operating the local generator protection means when the comparison signal indicates that the local electricity supply and the remote electricity supply are not in synchronisation.

23. The method of any of claims 18 to 20 wherein step b) includes the step of: transmitting the results of the determination at the second location from the second location to the first location only when it is determined that the one or more operating parameters of the remote electricity supply lie outside pre-determined normal values.

24. The method of claim 23 in which the results of the determination are transmitted from the second location to the first location by power line communication methods.

25. The method of claim 23 in which the results of the determination signal is transmitted from the second location to the first location by radio signalling, fibre optic communications, pilot wire communications or audio frequency signalling along telephone circuits.

26. The method of claim 25 in which the pre-determined normal operating values used in the remote determination and the pre-determined normal operating values used in the local determination are chosen such that the signal may travel from the second location to the first location in time to de-activate the local generator protection means.

27. The method of claims 23 to 26, further comprising the step of transmitting test signals to the local generator protection means; wherein, while the test signals are being received the pre-determined normal operating values used in the local determination are different to those used when the test signals are not being received.

28. The method of claim 27 further comprising the step of giving an alarm signal should the test signals not be received.

29. The method of any preceding claim in which either the remote determination or local determination are based on detecting the rate of change of frequency of the electricity supply.

30. The method of any preceding claim in which either the remote determination or local determination are based on detecting the vector shift of the electricity supply.

31. The method of claim 19, wherein the one or more operating parameters used in the local and remote determinations are one or more of the rate of change of frequency and vector shift of the electricity supply.

32. The method of claim 20 or 31, wherein the comparison signal is generated based on one or more of the frequency and phase of the electricity supply.

33. The method of any preceding claim further comprising the step of transmitting a signal from the second location to the first location and encoding the signal to carry control signals and information.