GR1009503B - A method to promptly identify voltage instability using transmission line protection relays - Google Patents

Abstract

A measurement-based method in form of a protective relay function takes advantage of the numerical capabilities of modern microprocessor-based transmission line protective relays by sampling analogue voltage and current and calculates in real-time, after properly filtering the intermediate quantities, a Local Relay-based Index (RLI)for local voltage instability identification and alarm. An alarm signal is issued when RLI becomes negative and can be sent to the control centre for voltage stability monitoring enhanced capability, as well as to provide a means for system operators to anticipate line disconnections due to undesired relays operation under any power system operation conditions.

Description

Method for early detection of voltage instability using power transmission line protection relays

PER I GRAF H

The present invention is related to the operation of the Electric Power Systems (PSS) and the protection relays (N/N), with which the power transmission lines of a power station are equipped. Specifically, the invention concerns the development of a method that utilizes the advanced capabilities of modern digital E/N protection of transmission lines in measuring, sampling and processing analog electric field quantities in real time, in order to detect conditions of long-term voltage instability in weak areas of a power plant, as well as conditions of unwanted disconnection of transmission lines within the problem areas during voltage instability or, in general, during other situations of particularly increased system loading.

The above method is implemented as an internal protection function, which can be integrated into existing digital transmission line protection I/Os. Transmission line protection I/Os are installed at each end of a transmission line and accept at their input analog measurements of voltage and current from the field through transformers (M/S) of voltage and current respectively, connected locally to the corresponding end of the transmission line. A digital protection I/O samples the measured analog voltage and current signals at a high sampling rate and calculates the corresponding voltage and current phasors. The method of the present invention processes in real time the E/N calculated voltage and current phasitometers and calculates an index, hereinafter referred to as the E/N Local Measurement Based Index (DBTMH), with a dual purpose: (i) the detection of long-term voltage instability, which evolves in real time, (ii) the avoidance of unwanted disconnection of the transmission line due to incorrect E/N protection action during the development of a voltage instability phenomenon or particularly increased loading of the CHP.

Most of the existing measurement-based voltage instability detection methods [1]-[6] estimate the Thevenin equivalent of the CHP upstream of a load bus, as "seen" by the bus, from local bus voltage and current measurements. According to the impedance matching theorem, when the impedance of the Thevenin equivalent and the apparent impedance downstream of the even load become equal, voltage instability is expected. However, these methods only perform well in radial networks feeding a constant power factor load and only when the Thevenin impedance estimate is accurate and time-invariant[2].

In references [3] - [4], instead of the impedance matching principle, the measurement of the rate of change of power with respect to conductance is used to determine the distance from breakdown. Additionally, the paper [3] includes generator excitation systems and frequency and voltage dependence of loads in the Thevenin equivalent circuit parameter estimation process.

In the aforementioned methods, recursive numerical algorithms are used to estimate the parameters of the Thevenin equivalent circuit. Variability between voltage and current measurements is therefore required in order to estimate the parameters of the Thevenin equivalent circuit. Also, the parameter estimation process is sensitive to small and high-frequency changes of the measurements, which is also a major drawback of these methods.

A different non-recursive identification approach based on Tellegen's theorem and inverse networks is applied in work [5] to estimate the parameters of the Thevenin equivalent circuit. For the same purpose, in paper [6] a decoupled equivalent network is determined for each even load. Finally, in [5] and [6] the instability detection is based on the impedance matching theorem.

In the paper [7], the impedance matching theorem is applied by monitoring the apparent impedance of the load from a high-voltage intermediate busbar instead of a load busbar. In addition, the proposed method effectively filters the fast oscillations of real-time local measurements. However, the measurements are taken by PMUs and not by protection I/O.

A decentralized method based on the fact that near the voltage collapse point all the increase in power consumption measured at the departure end of a transmission line is due to the losses of the line itself is applied in the paper [8]. The main disadvantage of this method is that it requires an additional check to see if the line is loaded below its natural load.

Some more recent methods based on real-time measurements [9] calculate a generalized CHP equivalent and analyze the conditions of maximum power transfer in this equivalent network. The main drawback of these methods is that they assume constant power factor loads, which is very rarely the case in a real system. Also, they are based on measurements from many points of the SIE, requiring telecommunication equipment.

The present invention is a method that calculates ΔBTMH, which is an early detection indicator of long-term voltage instability in real time. The method is implemented as an internal I/O protection function, which implies that the DBTMH can be calculated in any digital transmission line protection I/O that will have incorporated this function in its microprocessor. The method processes the voltage and current phasors that the line's E/N calculates in real time from the analog voltage and current signals it receives at its input from the corresponding measurement M/S. The protection equipment required by the method (protection I/O, voltage and current I/O) is already installed at each end of the transmission line and consequently no additional equipment or telecommunication link between the I/O and other devices is required for the calculation of DBTMI from the local line protection I/O.

The effectiveness of the method proposed by the present invention does not depend on the type of system loads, as it is based solely on real-time voltage and current measurements. Therefore, the nature of the system loads is reflected in the measurements taken in real time and thus the method adjusts its operation accordingly.

Based on the value of the DBTMH indicator, an alarm signal is activated, giving the system operator the necessary time to take measures to deal with the long-term voltage instability that has been identified. In addition, the alarm signal gives the system operator the necessary time to recognize other undesirable conditions in the system, during which successive disconnections of transmission lines may occur. In this way, the information obtained from the DBTMI helps to prevent a generalized blackout of the system.

Figure 1 schematically shows how a digital transmission line protection I/O with built-in internal DBTMH index calculation function can communicate with the remote energy control center to send the alarm signal. At this point it is important to mention again that, while telecommunication is required to send the alarm signal to the energy control center, no communication of the local protection I/O with other devices is required to calculate the DBTMH. The calculation of ΔBTMHI is based exclusively on local measurements received by the transmission line protection N/O from the field through the voltage and current M/S (characterized as VT and CT respectively in Figure 1. In the modern substations (Y/S) of In a CHP there is usually a Central Protection and Control System (CPS), which in the simplest implementation usually consists of an industrial computer, which already communicates with the remote energy control center. In these cases, the only requirement is to send the signal of an alarm from the line protection computer to the PC's control panel, both of which are located in the same PC's building.

The present invention can be utilized to (1) increase the protection capabilities of digital I/O, (2) enhance the ability of the system operator to monitor the system voltage stability at the power control center in real time, and (3) to provides an early indication to the operator of the NPP for possible disconnections of transmission lines due to undesirable actions of the E/N protection lines under conditions of particularly increased system loading (during which long-term voltage instability may have additionally occurred).

The detailed embodiment of the present invention is presented below. Each transmission line in a CHP is protected against short circuits by E/N protection R, which is installed at each end of the line. Figure 2 illustrates a transmission line connecting the i and j busses of the system. In this example, the apparent power Sij flows from bus i to bus j. Each line protection I/O receives as inputs the analog values of voltages and currents (Figure 2), from the corresponding voltage and current M/S installed at the corresponding end of the line. Regarding the voltage M/S, Figure 2 shows that two alternative ways of connection can be applied to CHPs: either the voltage M/S is connected to the terminal bus of the line measuring the voltage of the specific bus (VTm and VTn in the example of Figure 2) either the voltage M/S is connected to the end of the line measuring the voltage at that end (VTkn and VTnk in the example of Figure 2). These alternative ways of connecting the voltage M/S are also shown in Figure 1. Hereinafter it is assumed that the voltage M/S are always connected to the terminal busbars of the transmission line unless otherwise noted.

The protection function proposed by the present invention takes advantage of the capabilities of modern digital transmission line protection I/O, which, among other advanced digital signal processing capabilities, is to sample the incoming analog voltage and current signals at a high rate and calculate the of corresponding voltage and current phasities respectively in real time. From these sequentially calculated phasitets three derivative quantities are calculated by H/N in real time.

The first quantity is the outgoing active power Pij (respectively arriving power Pji) of the line, as calculated by the protection N/N of the line Rij near the departure I (respectively by the N/N Rji at the arrival even]).

where iz, Vj and Iij, Iji are the phasitets of the line voltages and currents of the corresponding end, as they are calculated by the digital line protection I/O from the measurements of the corresponding analog quantities through the voltage and current M/S.

The second quantity calculated is the apparent resistive conductance G, i.e. the resistive conductance as "seen" by the transmission line protection N/Os at the respective ends (Gij the resistive conductance "seen" by the N/O at the departure end and Gjiη resistive conductance respectively "seen" by the E/N at the arrival end of the line).

The third quantity is the apparent impedance, i.e. the impedance that the I/O "sees" at the corresponding end of the transmission line:

In transmission line protection N/A terminology, positive active power means that the end-of-line protection N/A "sees" active power entering the busbar into the line. In this way the apparent impedance corresponding to positive active power is assigned to the right complex half-plane of resistances, while the apparent impedance corresponding to negative active power is assigned to the left half-plane of resistances.

Based on the aforementioned convention, when the calculated active power turns out to be positive, ABTMHy (i.e. the ΔBTMHy calculated by the I/O at the outgoing end of the line) monitors the change of two filtered quantities, namely the change of the filtered active power sent (as this is measured by H/NRy), to the change in the filtered apparent resistive conductance ΔGij, i.e.:

In this case ABTMHy also includes the line losses.

When I/O is at the arrival end of the line, the active power Pji, flows from the line to the arrival bus and is therefore negative. In this case the direction of the current reference is changed (so that Pjjna is positive when power flows from the line to the arriving busbar) and ΔBTMHI is calculated as in the case of the leaving end using relation (7). With the above consideration, ΔBTMH always refers to the flow of active power, regardless of whether the N/N is at the departure or arrival end of the transmission line.

To calculate the changes in filtered active power and apparent resistive conductance the H/N performs a series of prerequisite calculations.

For ease of presentation, let's consider the change in active power ΔPij and apparent resistive conductance as ΔGij "seen" by H/N Ry.

Obviously, similar calculations to those that will follow also apply to H/NRji. For the purposes of calculating the ΔBTMH index, the active power Pij (see (1)) and the apparent conductivity Gy (see (3)) are sampled at equidistant moments of time, based on the filtering requirements, forming the discrete quantities Pij(n) ( respectively Gij(n)), where η is a variable that corresponds to the discrete time, i.e. it corresponds to the time instant Δt. It should be noted that the above phasit sampling procedure is not related to that of the A/N to construct the phasit of the measured signals Pij and Gij, which are calculated from the analog measurements of the voltage and current M/S, but refers exclusively to the method of the present invention.

To account for the artificial noise amplification resulting from the division of the differences ΔPij and ΔGij, a filtering method based on the Short Time Fourier Transform (STFT) is applied independently to both discrete signals. The STFT transform determines the spectral content of segments of an indefinite duration discrete input signal. In practice, the active power and apparent resistivity input signals of indefinite duration are subdivided into packets of a fixed number of samples and multiplied by a window function at regular and equally spaced time intervals. The window function used is expressed by the following relation:

The product Py(n)-w(n) (respectively Gy(n)-w(n)) is a processed form of the original input data packet of length M samples of the active power (respectively the apparent resistive conductance). The calculation of the STFT transform is done at prescribed regular intervals, e.g. for each M/2 new samples. However, a total of M samples are considered to calculate the STFT transform. In the case of the present invention there is a 50% overlap between the processed data packets. Nevertheless, the parameters of the STFT transformation can be adjusted in order to best suit the needs of each transmission line, given the characteristics of the wider region of the CHP, in which it is located. Rhop is the parameter that defines the time interval in number of samples between two consecutive STFT calculations and should be an integer multiple of the sample rate.

From the calculated spectrum of the processed input data packet, the method retains only the direct current (DC) component and thereby reproduces the DC response of the active power and apparent resistive conductance, i.e. PiJ and Gij respectively. These quantities do not contain noise and show the continuous behavior of the original signal in a discrete manner (see Figure 3).

By applying the STFT transformation to the active power flowing in the transmission line and the apparent resistive conductance at regular time instants (multiples of the filter sampling rate), the change in active power between two time instants can be calculated as follows:

Corresponding relations arise for the case of the apparent resistive conductance, forming the quantity ΔGij, as well as for the filtered changes of active power ΔPij and apparent resistive conductance at the arrival end of the line.

The division of the quantities ΔPij(k) and ΔGij(k) takes place if and only if the quantity ΔGij(k) is greater than a strictly positive lower bound n:

and, in addition, only if the change in active power ΔPij(k) is neither too small nor too large, i.e.:

in order for the DBTMI to respond to an expected change in load demand and not to noise or short-term transient phenomena of the system, i.e. in cases that do not concern the purposes of applying the present method.

Finally, the q most recent calculations of the ΔBTMH index are weighted equally (their average value is calculated), in order to further reduce the transitory fluctuations of the calculated index, forming the relationship

(7).

The flow diagram of the calculation method of the DBTMH index is shown in Figure 4.

As long as the weighted DBTMI remains positive, the CHP response is considered stable, as the increased apparent resistive conductance, which reflects the electrical demand downstream of the transmission line, is accompanied by increased active power flow through the line. When the weighted DBTMI becomes negative, expected long-term voltage instability is detected and an alarm signal is sent. The information from DBTMI can possibly be combined with other indicators to further ensure the detection of voltage instability.

With (12), the DBTMH can recognize a long-term voltage instability situation early enough, additionally providing an alarm signal to the control center, in order to take automated actions to avoid a possibly upcoming generalized blackout.

In addition, the DBTMI aims to contribute to the avoidance of uncontrolled disconnections of transmission lines due to an unwanted action of their protection E/Ns, due to a constantly increasing electrical demand in an already highly loaded CHP, a situation that may be misdiagnosed by the protection E/Ns of the transmission lines lines as a remote short circuit. Uncontrolled disconnections of transmission lines must be avoided during the development of such phenomena, as it is possible to cause the disconnection of several transmission lines in succession.

In these cases, the DBTMI provides an early warning, in the form of an alarm signal, which can be used by the transmission line protection I/O to inhibit the line disconnection command. If the alarm signal is activated only at the protection N/A at one end of the line, then the inhibit signal can be sent by telecommunication to the N/A at the other end of the line.

At the same time, it should be ensured that the DBTMH will not raise false alarm signals during a remote short circuit (eg a short circuit within zone-2 or zone-3 of the line's I/O). Bearing in mind that the phenomenon of voltage instability is symmetrical, the possibility of a false alarm is completely avoided in the case of asymmetrical faults (i.e. two-phase, two-phase to earth and single-phase short-circuit) since the described internal operation of the I/O is only active in symmetrical conditions of NPP.

There are several methods for a transmission line protection I/O to detect unbalanced operating conditions. The present invention considers that the H/N during the calculation of ΔBTMH monitors the three individual apparent impedances of the phases, which it calculates from measurements at the corresponding end of the line according to (5) - (6). If these impedances are not equal to each other, unbalance is recognized in the system.

With regard to three-phase (symmetrical) short circuits, appropriate settings are calculated in each E/N, which will be adapted to the characteristics of each transmission line and will result from preliminary studies, in order to avoid false alarms. The extremely low incidence of three-phase faults in CHPs is noteworthy.

A representative example of the efficiency of the DBTMH concerns the case of simulating a long-term voltage instability event in a model NPP of the Institute of Electrical and Electronics Engineers (IEEE), (Figure 5). A power flow corridor between the northern and central regions of the aforementioned CHP is delineated in Figure 5 with the help of the dashed lines, which separate the two regions. It is assumed that digital protection I/Os are installed at the departure ends of each line belonging to in the hallway. Each of these N/A calculates the DBTMH according to the described methodology. Since the central area of the system enters power from the north, all installed A/Ns in the corridor measure positive active power flows.

In the considered scenario, it is assumed that a symmetrical three-phase short circuit is applied very close to busbar 4041 (ie close to the arrival end of one of the lines connecting busbars 4031-4041), which lasts for 100ms, followed by clearing and disconnection of the faulty line. Disconnection of the faulty line reduces the active power carrying capacity of the remaining CHP. The electrical demand is fully restored through the action of various power restoration mechanisms, such as that of self-restoration of the load and the action of the On-Load Voltage Switching Systems (SOLVS), but as a result the maximum power transmission capacity is exceeded, creating conditions of long-term voltage instability.

Based on the sensitivity analysis, the calculation of which is obtained with full supervision and accurate assessment of the system state, it is determined that the system response becomes unstable at time t = 68 s and then collapse occurs at time t = 188 s. Figure 6 illustrates the DBTMHs calculated by the protection N/Os at the outgoing ends of the transmission lines connecting busbars 4021-4032, 4021-4042, 4031-4041, 4032-4042 and 4032-4044. From Figure 6 it is evident that each DBTMH can independently diagnose the impending long-term voltage instability, which is due to the inability of each individual transmission line of the corridor to further increase the transmitted active power to the central area of the CHP under consideration. The identification of the instability is made at the moment when the respective DBTMI goes from a positive to a negative value. Based on the aforementioned methodology, at the given times, the corresponding N/A raises an alarm signal. It is clear that the alarm signals are activated after the time when the system has entered unstable mode (t = 68 s), but nevertheless each detection takes place well before the system collapse (t = 188 s). Therefore the early alarm can prevent the upcoming voltage instability by pointing out the need to take appropriate countermeasures, as well as prevent any possible consecutive disconnection of the transmission line due to unwanted activation of some line protection I/O.

A NAFO R ES

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[2] C. D. Vournas, C. Lambrou, P. Mandoulidis, "Voltage Stability Monitoring from a Transmission Bus PMU", IEEE Transactions on Power Systems, 2016.

[3] D. E. Julian, R. P. Schulz, K. T. Vu, W. H. Quaintance, N. B. Bhatt, and D. Novosel, "Quantifying proximity to voltage collapse using the voltage instability predictor (VIP)," in Proc. IEEE Power Eng. Soc. Summer Meeting, Seattle, WA, Jul. 2000, vol.

2, pp. 931-936.

[4] M. H. Haque, "On-line monitoring of maximum permissible loading of a power system within voltage stability limits," Proc. Inst. Elect. Eng., Gen., Transm., Distrib., vol. 150, no. 1, pp. 107-112, lav. 2003.

[5] I. Smon, G. Verbic, and F. Gubina, "Local Voltage-Stability Index Using Tellegen's Theorem," IEEE Trans. Power Syst., vol. 21, no. 3, pp. 1267-1275, Aug. 2006.

[6] W. Li, T. Chen, W. Xu, "On impedance matching and maximum power transfer," Electric Power Systems Research, Vol. 80, No. 9, pp. 1082-1088, Sep. 2010.

[7] S. Corsi, and G. N. Taranto, "A Real-Time Voltage Instability Identification Algorithm Based on Local Phasor Measurements," IEEE Trans.Power Syst., vol. 23, no. 3, p.

1271-1279, Aug. 2008.

[8] G. Verbic and F. Gubina, "A new concept of voltage-collapse protection based on local phasors," IEEE Trans. Power Del., vol. 19, no. 2, pp. 576-581, Apr. 2004.

[9] F.Hu, K. Sun, A. Del Rosso, E. Farantatos, N. Bhatt, "Measurement-based read-time voltage stability monitoring for load areas", IEEE Trans. Power Systems, in press.

Claims (7)

VALUE OSE I S The following are claimed: 1. A method incorporated as an internal protection function in a standard transmission line protection synchronous digital relay (D/N) to detect long-term voltage instability conditions in weak areas of a power system (PSE), as well as to prevent unwanted transmission line disconnections within the weak areas of the system during the development of voltage instability or in general in conditions of highly charged operation of the system. The method calculates in real-time an index, called the Local Measurement-Based I/O Index (LOMI), from voltage and current measurements, OL taken from the transmission line through standard voltage and current transformers (M/S) respectively. The H/N processes the measurements and uses them to determine the DBTMH, based on the method, as follows: where the quantity ΔΠij is the filtered change in the active power flowing (as measured and processed by the protection N/O Rij) from the departure bus ί to the arrival bus] of a transmission line ij, ΔGij is the filtered change in the apparent resistive conductance of the load of line ij as seen from the departure even of line ith and q is the number of most recent calculations of ΔBTMHy for weighting and smoothing purposes. 2. A method according to claim 1, in which all the primary measurements from the transmission line field for the calculation of ΔBTMH are taken exclusively from the local voltage and current M/S, which are anyway installed at each end of the transmission line. 3. A method, according to claim 1, which for the calculation of the DBTMH by the protection computer does not require any kind of additional equipment nor any kind of communication between the computer that calculates the DBTMH and other devices. 4. A method, according to claim 1, which makes no assumption as to the nature of the electrical charges, because it is purely based on real-time voltage and current measurements. Therefore, regardless of the nature of the electrical charge, its characteristics are reflected in the measurements taken by the method, which in this way adjusts accordingly. 5. A method, according to claim 1, in which the sampling of the measurements, their processing and the filtering process for calculating the real-time ΔBTMH are implemented within the U/N, following specific steps, which compose an integrated internal PC protection function: Step 1. Calculation of the required quantities, according to the following formulas, using the line voltage and current phasitometers, previously sampled and constructed by H/N based on the local analog voltage and current measurements: Step 2. Application of the Short-Time Fourier Transformation (STFT) to the processed input data packets of the sizes P, and G, at specific equidistant moments in time (integer multiples of the sampling time), to deal with noise amplification generated by calculating the changes in the input signals. Then, retaining only the DC component from the spectrum of each input data packet. Step 3. Reconstruction of the equivalent direct current (DC) and denoised signal of active power and apparent resistive load conductance, i.e. Pij and Gij, which trace the original signals Pij and Gij respectively. Step 4. Calculation of the differences ΔPij and ΔGij from the two most recently reconstructed equivalent direct current (DC) signals, namely: Step 5. If the following relationships hold: i.e. there is an increase in demand above a minimum lower limit and the change in active power on the line is neither too small nor too large, then and only then is the calculation of the ΔBTMHI performed. This is done in order for the indicator to respond to a real change in demand and not to negligible changes due to the presence of noise in the calculated signal of the apparent resistive conductivity, as well as so that the indicator does not respond to network disturbances, which do not concern the purposes of applying this method. Step 6. Calculation of the weighted ΔBTMH using the q most recent calculated values, according to the formula: 6. A method according to claim 1, wherein an alarm signal is raised and sent via telecommunications to the system control center when the weighted DBTMH becomes negative, providing an indicator that improves the system operator's ability to monitor voltage stability and simultaneously it enables him to predict possible disconnections of transmission lines due to undesired activations of line protection I/Os under any operating conditions of the system (that is, whether during the development of a voltage instability phenomenon or not). 7. A method according to claim 1, which can be incorporated into existing or future technology transmission line protection digital computers, increasing the protection capabilities of the computers.