Protection primer

Editor's Notes

• #3: Why protection is needed Faults and damage to people and equipment Principles and elements of the protection system Main goals Protection zones, primary and backup protection Basic protection schemes Overcurrent protection and coordination in radial systems Directional overcurrent protection Distance relay principles, operation, and connections Line pilot protection schemes Differential relay principles and applications Digital relay advantages and enhancements
• #4: The variation in system parameters because of normal small disturbances is handled by the power system controls. Large disturbances such as faults cannot be handled by the control system. Instead, a separate protection system is required whose goal is not to maintain system parameters within acceptable limits, but to prevent or minimize damage to the system and to remove hazardous conditions.
• #5: We need to balance reliability and cost in designing a power system. While it is impossible to avoid the occurrence of faults and other abnormal operation conditions that produce large power system disturbances, a protection system is intended to take preventive or corrective actions in such cases. The first line of defense is the protection of power system elements. The function of this type of protection is to detect faults and abnormal conditions and to disconnect the faulted element in order to prevent further damage in the element or a system disturbance. Modern power systems operate near the security limits. The system also needs protection functions at the system level that can include low frequency or low voltage load shedding among others. Protection operation disconnects system elements. It is then important to provide automatic restoration functions. Among these functions, we might mention automatic reclosing of transmission lines, automatic transfer to alternate power supplies, and automatic synchronization.
• #6: Electric power systems span vast geographical areas, and they are exposed to various external agents.
• #14: This is a summary of protection system elements.
• #16: This is a typical simplified dc tripping system. The normally open 52a breaker contact is closed when the breaker is closed. Relay operation for a fault implies the closing of the relay contact. This completes the circuit and establishes current through the breaker trip coil, 52TC. When the breaker trips, the opening of the 52a contact interrupts the tripping current, protecting the relay contact. Relay contacts can often make, but not break, the tripping current, creating the need for a more robust contact to interrupt the highly inductive dc current. Interruption of the dc current in this circuit is the function of the 52a contact. A contact-sealing auxiliary relay, SI, provides additional protection to the relay contact. The seal-in contact (SI) closes when the tripping current begins to flow, bypassing the relay contact. The action of the seal-in contact prevents the relay contact from interrupting the tripping current under any circumstances. The auxiliary contact, 52a, is mechanically coupled to the main contacts. When the circuit breaker completely opens its main contacts, 52a opens the tripping circuit, de-energizing the trip coil. The red light has two functions. On one side, it indicates if the breaker is open (52a open, light off) or closed (52a closed, light on). On the other side, if the circuit breaker trip coil’s circuit gets accidentally open, the red light will remain off even when the circuit breaker is closed. This serves to indicate that there is a problem in that circuit.
• #23: There are several protection requirements. The most important of these are reliability, selectivity, speed, and sensitivity. We may also mention simplicity and economics. Reliability is the ability of a protection system to operate correctly. A reliable system is one that trips when required (dependability) but does not trip when not required (security). Selectivity is the ability of a protection system to eliminate a fault in the shortest possible time with the least disconnection of system components. We also use the term coordination for selectivity. Protection coordination implies that primary protection eliminates the faults, and that backup protection operates only when primary protection fails. We also call coordination the process a protection engineer uses in calculating relay settings. Speed is the ability of the protection system to operate in a short time after fault inception. This is important in preserving system stability, reducing equipment damage, and improving power quality. Relaying system operation time includes relay and breaker operation time. We typically measure relaying system operation time in cycles (periods of the power system frequency [1 cycle = 16.67 ms in a 60 Hz system]). Breaker operation times are from 2 cycles to 8 cycles. Instantaneous relay operating times are about 1 cycle. For example, a 1-cycle relay and a 2-cycle breaker provide a fault clearing time of 3 cycles (about 50 ms). Sensitivity is the ability of the protection system to detect even the smallest faults within the protected zone. It is important to ensure the detection of high-impedance faults or the reduced contribution to faults from small, dispersed generators.
• #24: Short-circuit protection includes two protection systems: primary and backup protection. Primary protection is the first line of defense. The figure shows the one-line diagram of a power system section. We may observe that we use breakers to connect adjacent system elements. Using the breakers in this manner permits the protection system to completely isolate a faulted element. An exception is the case of the generator-transformer units. Generators have dedicated step-up transformers in this arrangement, and we may omit the breaker between them. The zones indicated with dotted lines are the primary protection zones. The significance of these zones is that a fault inside a zone implies the tripping of all the breakers belonging to that zone. Protective relays define these zones. Adjacent protection zones overlap to provide full primary protection coverage in the power system. A fault in the overlapping areas produces the tripping of more breakers than the breakers needed to isolate the fault. We need the overlapping areas to be as small as possible. Primary protection operation should be as fast as possible, preferably instantaneous, for stability and power quality reasons.
• #25: Protective relays define the primary protection zones. Relays use system currents and voltages as input signals. We will see during the course that current information is instrumental for the relays in determining fault location. Then, current transformer location defines the limits of the primary protection zones in many cases. In lower-voltage systems, we use bushing-type current transformers installed inside breaker and transformer bushings. In this case, protection zones overlap around the breaker, and the breaker lies in the ovelapping zone. A breaker fault produces the tripping of all breakers at both zones. In higher-voltage installations, we use multiwinding current transformers. We use different secondary windings for the relays of the two protection zones. The overlapping zone is inside the current transformer. The probability of an overlapping-zone fault is very low. The price we pay for this arrangement is that it could be necessary to trip some Zone B breakers with Zone A relays to completely disconnect some Zone B faults.
• #26: To increase the reliability of a protection system, a backup system is intended to operate in case one or more of the main protection elements fail. The figure shows the one-line diagram of a power system and helps illustrate the concept of backup protection. The tie circuit breaker (T) is assumed to work normally closed. For a fault at CD, Line Breakers 5 and 6 should operate as the primary protection. If Protection 5 fails to operate, with existing technology we have two possibilities for cutting the fault current contribution from A, B, and F: open Breakers 1, 3, and 8; or open Breakers 2 and T. In any case, backup protection needs time delay. The primary protection needs to be given an opportunity to operate before using the decision of a backup operation.
• #27: About 80 percent to 85 percent of short circuits involve ground. This is why we use separate ground-fault protection in the power system. The highly dangerous three-phase fault is a less frequent fault. A particular three-phase fault that presents special protection problems is that created by maintenance personnel leaving grounding switches or grounding equipment connected after line maintenance. About 80 percent of short circuits in overhead transmission lines are temporary. Automatic reclosing reconnects the line when protection trips the breaker and the fault dissapears. Many faults can evolve. These begin as single-line-ground faults, evolve into line-line-ground faults, and eventually become three-phase faults. There are also combined faults. A broken conductor can touch a line tower or ground on one side, for example, creating a combination open phase and ground fault at the same point.
• #29: Recall that the symmetrical components method is used to analyze unbalances in power systems. Any three-phase set of unbalanced currents, or voltages, can be decomposed in three sets of currents, or voltages, with the following characteristics: One three-phase BALANCED set with POSITIVE-sequence rotation, a-b-c by convention One three-phase BALANCED set with NEGATIVE-sequence rotation, a-c-b One three-phase with the three currents that are equal in magnitude and in phase. This set is called ZERO-sequence. The convention rules are as follows: For a system with a-b-c rotation, the positive-sequence set will have a-b-c rotation. The negative-sequence set will have a-c-b rotation. For a system with a-c-b rotation, the positive-sequence set will have a-c-b rotation. The negative-sequence set will have a-b-c rotation.
• #30: We use four protection principles for distribution and transmission lines. Overcurrent protection, the simplest and most economical of these principles, is limited to radial lines. Overcurrent protection has found widespread use in distribution utility and industrial systems. The addition of directionality extends the application of overcurrent protection to looped lines. We use distance protection in many transmission lines. In order to increase operating speed, we may use a communications channel to exchange information between directional or distance elements. This type of arrangement is directional comparison pilot protection. Finally, we may apply the differential principle to transmission lines over a communications channel. This arrangement offers the best protection. A variant of the differential principle is the phase comparison principle, in which we compare the phase angles of the currents at both line ends. Historically, the current-balance principle served to protect parallel transmission lines. This principle involved comparing the magnitudes of the currents of both lines. A fault at one of the lines created a difference between these currents.
• #31: Knowing that the current decreases as the distance increases, it is possible to draw a relay curve as shown in the figure. This indicates that the operation time of the relay will be larger as the current is farther from the source. This is one of the advantages of inverse-type overcurrent relays.
• #32: Operating time of inverse-time overcurrent relays increases when the fault current diminishes or, in an equivalent situation, when the electrical distance to the fault increases. In the bottom diagram, we show the inverse-time relay operating time as a function of the electrical distance. Note that each curve begins at the relay location and extends beyond the end of the adjacent line. This means that the 51 elements provide primary protection to the protected line and backup protection to the adjacent line(s). We need to leave a selectivity or coordination interval T between the curves of the primary and backup relays to ensure coordination. The value of T should include: 1) the breaker operation time; 2) the electromechanical relay overtravel time (0.1 s typically); and 3) a security factor. Typical T values are 0.2 s to 0.4 s. Note that the relay time-distance curves diverge, so the minimum separation occurs at the beginning of the backed-up line. This happens when the primary and the backup relays are of the same type. If the relay types are different, the minimum separation between curves could occur at some other point. The basic idea of coordination is that the backup relay should be slower than the primary relay, with a minimum separation of T between curves calculated as follows: tbackup = tprimary + T
• #33: If an instantaneous element is added to the inverse relay, the protection is even more effective, since it would be possible to have very short operation times for faults close to the source.
• #34: As indicated before, we should add instantaneous (50) overcurrent elements to reduce the fault clearing times in the primary protection zones. The 50 element pickup current needs to be greater than the maximum line-end fault current. This avoids 50 element misoperation for faults beyond the remote bus. Setting the 50 element pickup in this manner is necessary for coordination, because 50 elements have no time delay to coordinate with the relays of the adjacent lines. We represent the 50 element characteristics by dashed lines in the figure. Note that 50 elements underreach the remote bus, but these elements cover a significant percentage of the protected line, especially for maximum generation coorditions. For lower generation conditions, the current-distance curve takes a lower position and the 50 element reach pulls back. The effect of 50 elements could even dissapear for minimum generation conditions.
• #35: The addition of a directional element eliminates the restriction of applying overcurrent protection only to radial lines. Directional overcurrent protection can be applied to systems with several generation sources or looped systems. The arrows shown in the figure are used to represent the protection tripping direction. Note that the relays are oriented towards the protected lines. This orientation divides the system protection into two independent groups: the relays “looking” to the right and those “looking” to the left. The directionality divides the coordination process into two independent processes. A relay only needs to be coordinated with the other relays in its group. The system shown in the lower figure is a single ring with only one source. In this case, all the relays are directional except the relays adjacent to the generation bus. For line faults close to the generation bus, the system is inherently directional. That is, fault current can only flow out of the bus and into the lines. Thus, there is no need for a directional relay. Note: The time dial settings of the relays at locations K and L should be set to the minimum value. Can you explain why?
• #36: Now that it has been determined that directional relays are needed, how is the protection accomplished? A classical directional element responds to the phase shift between the relay voltage and current. For faults on the protected line (forward faults), the current lags the voltage. The angle between voltage and current corresponds to the angle of the fault-loop impedance. For faults on the adjacent line (reverse faults), the voltage angle remains almost unchanged and the current angle changes approximately 180 degrees. The directional element uses this information to discriminate between forward and reverse faults. Observe that the voltage input signal acts as an angular reference. This signal is referred to as the relay polarizing quantity. The current input signal contains information about the fault location and is referred to as the relay operating quantity.
• #37: As the system topology behind the substation bus changes, ZS1 changes. As a result, the relay “reach” will change. The only way to avoid nonselective operations for faults beyond the remote bus is to calculate the instantaneous setting for the worst case value of ZS1, which results in a shorter reach of the instantaneous element for all other system configurations. It is highly probable that the system presents the worst case value for relatively short periods of time, meaning that the relay reach will be permanently sacrificed for a situation that occurs for short periods. This is a disadvantage of instantaneous overcurrent relays.
• #38: Suppose that it is possible to design a relay that operates not when the current is larger than a given threshold, but when the phase voltage is less than the current times a constant, as shown in the figure. This relay requires voltage and current information.
• #39: A plain impedance relay will operate for any apparent impedance whose magnitude is less than, or equal to, the relay setting. In the complex plane, this is represented by the region within a circle with radius equal to the relay setting. The border of the circle represents the operation threshold of the relay.
• #42: There are three traditional distance elements: impedance-type, reactance-type, and mho-type distance elements. The figure shows the operation equation and operating characteristic of a mho distance element. The characteristic is the locus of all apparent impedance values for which the relay element is on the verge of operation. The operation zone is located inside the circle, and the resraint zone is the region outside the circle. The mho characteristic is a circle passing through the origin of the impedance plane. The mho element operates for impedances inside the circle. The characteristic is oriented towards the first quadrant, which is where forward faults are located. For reverse faults, the apparent impedance lies in the third quadrant and represents a restraint condition. The fact that the circle passes through the origin is an indication of the inherent directionality of the mho elements. However, close-in bolted faults result in a very small voltage at the relay that may result in a loss of the voltage polarizing signal. This needs to be taken into consideration when selecting the appropriate mho element polarizing quantity. There are typically two settings in a mho element: the characteristic diameter, ZM, and the angle of this diameter with respect to the R axis, MT. The angle is equivalent to the maximum torque angle of a directional element. The mho element presents its longest reach (greatest sensitivity) when the apparent impedance angle  coincides with MT. Normally, MT is set close to the protected line impedance angle to ensure maximum relay sensitivity for faults and minimum sensitivity for load conditions.
• #43: So far, a directional distance relay, which operates instantaneously and is set to reach less than 100% of the protected line, has been described. Two important principles of protection have been missing: What happens for a fault on the protected line that is beyond the reach of the relay? If the relay operates instantaneously, it cannot be used as a remote backup for a relay protecting a line adjacent to the remote substation. These two problems are overcome by adding time-delay distance relays. This is accomplished by using the distance relay to start a definite-time timer. The output of the timer can then be used as a tripping signal. The figure shows how a second zone (or step) is added to each of the directional impedance relays. A third zone, with a larger delay, can also be added. The operation time of the second zone is usually around 0.3 s, and the third zone around 0.6 s. However, the required time depends on the particular application. The ohmic reach of each zone also depends on the particular power system. The figure and the next slide show a typical reach scheme for three zones.
• #44: The figure is an impedance-plane representation of a line protection scheme using mho distance relays (both directions). A longitudinal system is formed by transmission lines AB, BC, AD, and DE. The line impedances are plotted on the complex plane, using substation A as the origin of coordinates for convenience. The mho circles represent the three zones of the distance schemes at both ends of line AB.
• #45: The figure shows several commonly used circular distance relay characteristics. For analog relays, these characteristics can be obtained with phase and/or magnitude comparators. In microprocessor-based relays, they are implemented through the use of mathematical algorithms.
• #46: Here is another group of traditional distance relay characteristics. The use of one characteristic or another depends on several factors associated with the power system. These factors will be studied during this course.
• #47: In summary, distance protection uses current and voltage information to make a direct, or indirect, estimate of the distance to the fault. Phase distance elements (21) are more sensitive than phase directional overcurrent elements (67). On the other hand, ground distance elements (21N) are less sensitive than ground directional overcurrent elements (67N). A widely used combination for transmission line protection uses 21 elements for phase fault protection and 67N elements for ground fault protection.
• #48: The figure shows a schematic diagram of a directional comparison system. This system uses directional or directional-distance relay elements to distinguish internal from external faults. For an internal fault, both relays see the fault in the forward (tripping) direction; for an external fault, one relay sees the fault in the reverse (nontripping) direction. Although the relays use current and voltage information to determine the fault direction, the communications channel is used to exchange information about relay contact status. In traditional systems, the relay interface to the communications channel equipment is via contact inputs and outputs. The two-state type of information requires very low channel throughput (about 1000 Hz bandwidth). For these systems, the relay has no information about the channel health.
• #49: At the minimum, a POTT scheme requires a forward overreaching element at each end of the line. This is typically provided by a Zone 2 element set to reach about 120%–150% of the line length, or 200% if a dedicated element for pilot protection is used. If each relay sees the fault in the forward direction, then the fault can be determined to be internal to the protected line. Relay 3 will key permission if it sees the fault in a forward direction. Relay 4 will be allowed to trip if it sees the fault in a forward direction AND it receives permission from Relay 3. A reverse element is required for reasons that we will describe shortly. This is typically provided by a Zone 3 element set in the reverse direction. It is important that the reach of the reverse Zone 3 element be set for the element to always pick up for faults that can be seen by the remote Zone 2 overreaching element. It is important to note that in all of these schemes, an underreaching Zone 1 element is typically used to trip independent of the pilot protection scheme. POTT communications can be achieved with ON/OFF or FSK. However, FSK is the most common protocol.
• #50: The basic logic for a POTT scheme looks like this. A trip requires pickup of Zone 2 overreaching elements AND receipt of permission (RCVR) from the remote end. Pickup of Zone 2 overreaching elements keys transmission of permission to trip (Key XMTR) to the remote end.
• #51: In a directional comparison blocking scheme, each line terminal has reverse looking elements (Zone 3) and forward overreaching elements (Zone 2). The relay will send a block signal to the remote end if it sees the fault in the reverse direction. Relay detection of a fault in the reverse direction indicates that the fault is outside of the protected zone. The logic allows the relay to trip if it sees the fault in the forward direction and does not receive a blocking signal from the remote end.
• #52: The figure shows the fundamental logic involved. Pilot tripping occurs for an internal fault if the local Zone 2 forward-overreaching element operates and the remote Zone 3 reverse-reaching element does not send a block signal within a settable time. The channel coordination delay must allow time for the block signal to be received before the tripping element can operate. If the block does not arrive, or is late, a DCB scheme may overtrip. This scheme is often used with power line carrier and an ON/OFF transmitter because the only time the signal must get through is when the fault is not on the protected line. One way to speed up the issuance of the blocking signal is to use nondirectional carrier start. In this case, a high-speed overcurrent element detects the fault and keys the transmitter. Then the slower directional element will stop the signal if the fault is forward. If the directional element detects that the fault is reverse (out of zone), the blocking signal has already been sent. This can reduce the required carrier coordination delay, resulting in increased security.
• #53: The figure shows the behavior of a simple differential scheme during an external fault. If the current transformers are considered ideal and identical, the primary and secondary currents at both sides of the protected equipment are equal. There will be no difference, and the relay will not operate.
• #54: For an internal fault, the secondary currents are 180° out of phase and produce a differential current through the overcurrent relay. If this differential current is larger than the pickup for the relay, the relay will trip both circuit breakers instantaneously. The characteristics of differential protection can be summarized as follows: Simple concept: Measure current entering and exiting the zone of protection If currents are not equal, a fault is present Provides: High sensitivity High selectivity Result: Relatively high speed
• #55: All differential protection must deal with the challenge of being secure for large through-faults. During a severe external fault, a CT may saturate and supply less than its ratio current. In this case, the currents do not sum to zero, and a false differential current results.
• #56: A common variation on the differential concept is the percentage restraint differential relay. The differential elements compare an operate quantity with a restraint quantity. In this scheme, the relay operates when the magnitude of the secondary operating current, ĪOP = ĪS + ĪR, is larger than a given proportion of the secondary restraining current, IRT. For this particular scheme, the restraint current is chosen to be IRT = (| ĪS |+| ĪR |)/2. The proportionality constant, k, sometimes called the slope, may be adjustable and have typical values from 0.1 to 0.8 (or 10 percent to 80 percent). The operating principle of the percentage differential protection is the same as that for the simple differential overcurrent protection. However, in the percentage differential scheme, for a severe external fault, the restraining current becomes large. Then, even if there is a significant operating current, the restraint will be large enough to prevent the relay from operating. When the fault is internal, the operation current is considerably larger than the restraint current, resulting in relay operation. Note: The student should understand the common conventions used in differential protection analysis. The primary currents are generally drawn to indicate current flowing into the protected equipment from both terminals. As a result, the two currents will have neither the same sign nor the same angle during normal operation. In reality, during normal operation, the two currents will have the same magnitude, but the phasors will be 180° apart, assuming properly sized CTs. You should also be aware that some authors use a different convention.
• #57: Differential protection can be applied to the protection of practically any power equipment. In each case, the scheme design is adapted to respond properly to a unique application. For example, a simple differential scheme with equal current transformers at each terminal, such as the one described here, can be applied to protect a series reactor or a generator, but it cannot be used to protect a transformer. Current transformers must have different ratios when applied to transformer protection. Other particularities of the transformer differential protection will be described later.
• #59: Previously, we have studied differential relays that determine the existence of an internal fault by comparing the magnitudes of two currents entering and leaving the protected equipment. The differential protection verifies adherence to Kirchoff’s current law. If the current entering the protected zone is equal to the current leaving that zone, then there is no problem. If this balance is not maintained, then there must be a leak or an internal fault. This same principle can be applied to protect buses and three-winding transformers, as shown above. In these cases, more than two currents per phase must be compared. These are called multiple input differential schemes.
• #60: The most important advantages of digital relays are the following: Multifunctionality Protection and control Measurement Fault recording Communications capability Compatibility With Digital Integrated Systems High Reliability Relays (integration, self-testing) Protection system (supervised by the relays) Sensitivity and Selectivity New protection principles New relay operating characteristics Maintenance-free Reduced burden on CTs and VTs Adaptive protection Low cost
• #61: By providing a view of the power system, taken at the same point in time throughout the system, synchrophasors can improve our understanding of the state of the system. The result is more accurate models, which lead to an optimal use of available resources.