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ELEC 4302

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    1. ELEC 4302/7311 Power System Protection: Protection settings Dr. Ramesh Bansal School of Information Technology and Electrical Engineering, Axon Bldg, 47/212 The University of Queensland, St Lucia, 4072 Australia Ph: +61 (07)33653394 Fax: +61 (07) 336 54999 1

    2. Contents Introduction Functions of Equipment Protection Functions of Protective Relays Required Information for Protective Setting Protection Settings Process Functional Elements of Protective Relays Operating Characteristics of Protective Relays Overcurrent and Directional Protection Elements Distance Protection Function Transmission Line Protection Setting Transformer Protection Settings 2

    3. Protection Settings: Introduction A power system is composed of a number of sections (equipment) such as generator, transformer, bus bar and transmission line. These sections are protected by protective relaying systems comprising of instrument transformers (ITs), protective relays, circuit breakers (CBs) and communication equipment. In case of a fault occurring on a section, its associated protective relays should detect the fault and issue trip signals to open their associated CBs to isolate the faulted section from the rest of the power system, in order to avoid further damage to the power system. 3

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    5. Protection Settings: Introduction Maximum fault clearance times are usually specified by the regulating bodies and network service providers. The clearing times are given for local and remote CBs and depend on the voltage level and are determined primarily to meet stability requirements and minimize plant damage. The maximum clearance times of the backup protection are also specified. e.g. the clearing times for faults on the lines specified by one network service provider in Australia are presented in Table I (next slide). 5

    6. Table I: Fault clearance times 6

    7. Functions of Equipment Protection Protection schemes are generally divided into equipment protection and system protection. The main function of equipment protection is to selectively and rapidly detect and disconnect a fault on the protected circuit to: ensure optimal power quality to customers; minimize damage to the primary plant; prevent damage to healthy equipment that conducts fault current during faults; restore supply over the remaining healthy network; sustain stability and integrity of the power system; limit safety hazard to the power utility personnel and the public. 7

    8. Functions of Protective Relays The protection functions are considered adequate when the protection relays perform correctly in terms of: Dependability: The probability of not having a failure to operate under given conditions for a given time interval. Security: The probability of not having an unwanted operation under given conditions for a given time interval. Speed of Operation: The clearance of faults in the shortest time is a fundamental requirement (transmission system), but this must be seen in conjunction with the associated cost implications and the performance requirements for a specific application. 8

    9. Functions of Protective Relays Selectivity (Discrimination): The ability to detect a fault within a specified zone of a network and to trip the appropriate CB(s) to clear this fault with a minimum disturbance to the rest of that network. Single failure criterion: A protection design criterion whereby a protection system must not fail to operate even after one component fails to operate. With respect to the protection relay, the single failure criterion caters primarily for a failed or defective relay, and not a failure to operate as a result of a performance deficiency inherent within the design of the relay. 9

    10. Functions of Protective Relays The setting of protection relays is not a definite science. Depending on local conditions and requirements, setting of each protective function has to be optimized to achieve the best balance between reliability, security and speed of operation. Protection settings should therefore be calculated by protection engineers with vast experience in protective relaying, power system operation and performance and quality of supply. 10

    11. required information for Protective Setting Line Parameters: For a new line: final total line length as well as the lengths, conductor sizes and tower types of each section where different tower types or conductors have been used. This information is used to calculate the parameters (positive and zero sequence resistance, reactance and susceptance) for each section. Maximum load current or apparent power (MVA) corresponding to the emergency line which can be obtained from the table of standard conductor rating (available in each utility). The number of conductors in a bundle has to be taken into consideration. 11

    12. required information for Protective Setting Transformer Parameters: The manufacturer's positive and zero sequence impedance test values have to be obtained. The transformer nameplate normally provides the manufacturer's positive sequence impedance values only. Terminal Equipment Rating: The rating of terminal equipment (CB, CT, line trap, links) of the circuit may limit its transfer capability therefore the rating of each device has to be known. Data can be obtained from the single line diagrams. 12

    13. required information for Protective Setting Fault Studies Results of fault studies must be provided. The developed settings should be checked on future cases modelled with the system changes that will take place in the future (e.g. within 5 years). Use a maximum fault current case. CT & VT Ratios: Obtain the CT ratios as indicated on the protection diagrams. For existing circuits, it is possible to verify the ratios indicated on the diagrams by measuring the load currents on site and comparing with a known ratio. 13

    14. required information for Protective Setting Checking For CT Saturation: Protection systems are adversely affected by CT saturation. It is the responsibility of protection engineers to establish for which forms of protection and under what conditions the CT should not saturate. CTs for Transformer Differential Protection: MV, HV and LV CTs must be matched as far as possible taking into consideration the transformer vector group, tap changer influence and the connection of CTs. CTs for Transformer Restricted Earth Fault (REF) Protection: All CT ratios must be the same (as with the bus zone protection), except if the relay can internally correct unmatched ratios. 14

    15. Relay Information All required information to calculate protection settings have to be obtained such as: all available setting options of the relays used; firmware and software versions for all relays; setting ranges of all relays or functions; configuration of the relays and scheme. 15

    16. Protection Drawings The specific drawings are the reference of how the scheme is designed, and how it works. The following information should be on the drawings: The panel layout, showing all the relays and switches used; The AC key diagrams showing primary plant arrangement, CT and VT ratios used, and the associated AC wiring; The DC key diagrams showing the wiring of functional arrangements of the scheme, including tripping and closing; The supervisory key diagrams showing all the alarms and supervisory controls associated with the scheme; The protection equipment reference diagram which is an index of all equipments used; and The cabling diagram which is the summary of all external wiring. 16

    17. Protection settings process The Protection Settings team obtains all the information necessary for correct setting calculations. The settings are then calculated according to the latest philosophy, using sound engineering principles. Pre-written programs may be used as a guide. After calculation of the settings, it is important that another competent person checks them. The persons who calculate and who check the settings both sign the formal settings document. The flowchart in Fig. 2 indicates information flow during protection setting preparation for commissioning of new Transmission plant. 17

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    19. Functional elements of protective relays To achieve maximum flexibility, relays is designed using the concept of functional elements which include protection elements, control elements, input and output contacts etc. The protection elements are arranged to detect the system condition, make a decision if the observed variables are over/under the acceptable limit, and take proper action if acceptable limits are crossed. Protection element measures system quantities such as voltages and currents, and compares these quantities or their combination against a threshold setting (pickup values). If this comparison indicates that the thresholds are crossed, a decision element is triggered. This may involve a timing element, to determine if the condition is permanent or temporary. If all checks are satisfied, the relay (action element) operates. 19

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    21. Configuration mechanisms of the functional elements for Multifunctional digital relays Numerical Settings for Protection & Control elements: This is a basic configuration level available in any generation of numerical protective relays. User Programmable Protection Curves: Numerous protection functions such as time overcurrent, under- and over-voltage, and volts-per-hertz use inverse time characteristics. Typically, several standard curves are provided, so user may select the desired characteristic. Multiple Operating Modes: Often, several modes of operation of a given protection or control element are available to a user. For example A time overcurrent element may respond to the true RMS value (appropriate for thermal protection) or to phasor magnitude (appropriate for overcurrent protection), etc. 21

    22. Configuration mechanisms of the functional elements for Multifunctional digital relays Multiple Setting Groups: Multiple selectable setting groups have become standard. A modern relay allows a user to enter several values of the same setting, typically organizing the entries into groups, and provides a programmable mechanism to switch the groups based on various conditions such as state of protection and control elements, input contacts, keypad commands, communications ports, self-monitoring alarms, etc. It is expected that the use of multiple setting groups to perform adaptive protection functions will increase in use in the near future. 22

    23. Configuration mechanisms of the functional elements for Multifunctional digital relays Programmable Logic: Programmable logic has become a standard feature for microprocessor-based relays. It permits a user to perform some basic control functions and to build an application from elements available in a relay by combining the outputs from the protection elements into auxiliary signals to be used within the relay and to be interfaced with output contacts or sent to other equipment over communications channels. A typical set of functions consists of gates, latches, timers, edge detectors, and counters. 23

    24. Configuration mechanisms of the functional elements for Multifunctional digital relays Configurable Output Contacts: Configurable output contacts provide the convenience to drive the contact from any variable within the programmable logic. Configurable Analogue Inputs: Any protection or control element available on a relay can be configured to respond to any of the existing analogue input signals (sources). 24

    25. Configuration mechanisms of the functional elements for Multifunctional digital relays Configurable Display Messages, Target LEDs and Event Logs: Modern relays allow the user to specify for each protection and control element whether upon pickup, dropout or operation of the element a target LED should be fired and/or an event log should be created. For example, the SEL-421 includes 16 programmable status and trip target LEDs, as well as eight programmable direct-action control pushbuttons on the front panel. These targets are shown in Fig. 25

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    27. Conditions during faults and disturbances sensed by protection elements Overcurrent: On a healthy system, the flow of current is a function of electrical load. A short-circuit is a breakdown in insulation which results in an abnormal flow of current limited only by the impedance of the electrical system. Overload: It is the condition defined as excessive load demand into the power system. The undesirable aspect of overload is purely thermal heating in conductors and transformers. Open Circuit: This condition is of a concern in rotating machines (motors and generators) where it translates into abnormal rotor heating for which these equipments have little tolerance. 27

    28. Conditions during faults and disturbances sensed by protection elements Abnormal Voltage or Frequency: Abnormal voltage or frequency usually is a consequence of some form of overall system distress, and while these symptoms may appear following failure of a power system component, this is usually indicative of some undesirable consequence of that system failure rather than a direct result of the failure itself. Undervoltage can result in overload-like thermal heating, while overvoltage can shorten insulation life and accelerate insulation failure. Abnormal frequency usually is indicative of an imbalance between load and generation. 28

    29. Operating characteristics of protective relays Protective relays respond and operate according to defined operating characteristic and applied settings. Each type of protective relay has distinctive operating characteristic to achieve implementation objective: sensitivity, selectivity, reliability and adequate speed of operation. Basic operating characteristics of protective elements is as follows: Overcurrent protection function: the overcurrent element operates or picks up when its input current exceeds a predetermined value. Directional function: an element picks up for faults in one direction, and remains stable for faults in the other direction. 29

    30. Operating characteristics of protective relays Distance protection function: an element used for protection of transmission lines whose response is a function of the measured electrical distance between the relay location and the fault point. Differential protection function: it senses a difference between incoming and outgoing currents flowing through the protected apparatus. Communications-Assisted Tripping Schemes: a form of the transmission line protection that uses a communication between distance relays at opposite line ends resulting in selective clearing of all line faults without time delay. 30

    31. Overcurrent and Directional Protection Elements An overcurrent condition occurs when the maximum continuous load current permissible for a particular piece of equipment is exceeded. A phase overcurrent protection element continuously monitors the phase current being conducted in the system and issue a trip command to a CB when the measured current exceeds a predefined setting. The biggest area of concern for over-current protection is how to achieve selectivity. Some possible solutions have been developed, including monitoring current levels (current grading), introducing time delays (time grading) or combining the two as well as including a directional element to detect the direction of current flow. 31

    32. Current grading Current grading will achieve selectivity by determine the location of a fault using purely magnitude of current. It is difficult to implement this in practice unless feeder sections have sufficient differences in impedance to cause noticeable variations in fault current. In a network where there are several sections of line connected in series, without significant impedances at their junctions there will be little difference in currents, so discrimination or selectivity cannot be achieved using current grading. 32

    33. time delays An alternate means of grading is introducing time delays between subsequent relays. Time delays are set so that the appropriate relay has sufficient time to open its breaker and clear the fault on its section of line before the relay associated with the adjacent section acts. Hence, the relay at the remote end is set up to have the shortest time delay and each successive relay back toward the source has an increasingly longer time delay. This eliminates some of the problems with current grading and achieves a system where the minimum amount of equipment is isolated during a fault. However, there is one main problem which arises due to the fact that timing is based solely on position, not fault current level. So, faults nearer to the source, which carry the highest current, will take longer to clear, which is very contradictory and can prove to be quite costly. 33

    34. directional elements Selectivity can be achieved by using directional elements in conjunction with instantaneous or definite-time overcurrent elements. Directional overcurrent protection schemes respond to faults in only one direction which allows the relay to be set in coordination with other relays downstream from the relay location. This is explained using example in Fig. 4. 34

    35. directional elements By providing directional elements at the remote ends of this system, which would only operate for fault currents flowing in one direction we can maintain redundancy during a fault. This is in line with one of the main outcomes of ensuring selectivity, which is to minimize amount of circuitry that is isolated in order to clear a fault. 35

    36. direction of current flow In AC systems, it is difficult to determine the direction of current flow and the only way to achieve this is to perform measurements with reference to another alternating quantity, namely voltage. The main principle of how directional elements operate is based on the following equations for torque: If current is in the forward direction, then the sign of the torque equation will be positive and as soon as the direction of current flow reverses, the sign of the torque equation becomes negative. These calculations are constantly being performed internally inside directional element. 36

    37. SEL421 relay overcurrent elements As an example, SEL421 relay implements instantaneous overcurrent elements for: phase (P), residual ground (G); vector sum of currents in all three phases, and negative-sequence (Q) quantities. 37

    38. Time Grading using Inverse-Time Overcurrent Elements By analysing the laws of definite time grading, it is now possible to examine a more appropriate grading scheme, by combining current and time grading to form a relationship between the two. In networks where the source impedance ZS at the input end of a protected section is small compared to the impedance of the protected section ZPS , the current level of faults will vary with their position along the line. The following equation provides a means for calculating the current at the relay: 38

    39. Time Grading using Inverse-Time Overcurrent Elements If for example ZPS= 5 ZS, the current for a near-end fault will be six times that for a fault at the remote end of the line. In this instance, a relay with an inverse-time characteristic would operate at a speed of 1/6th that of a fault at the remote end. 39

    40. Distance protection function A distance protection element measures the quotient V/I (impedance), considering the phase angle between the voltage V and the current I. In the event of a fault, sudden changes occur in measured voltage and current, causing a variation in the measured impedance. The measured impedance is then compared against the set value. Distance element will trip the relay (a trip command will be issued to the CB associated with the relay) if the measured value of the impedance is less then the value set. 40

    41. Distance protection function In Fig. 5 the impedance measured at the relay point A is , where x is the distance to the fault (short circuit), and R and L are transmission line parameters in per unit length. The line length is l in the fig.. 41

    42. Distance protection function We can see that the impedance value of a fault loop increases from zero for a short circuit at the source end A, up to some finite value at the remote end B. We can use this principle to set up zones of distance protection as well as to provide feedback about where a fault occurred (distance to fault). Operating characteristics of distance protection elements are usually represented using R-X diagrams. Fig. 6 shows an example of Mho R-X operating characteristic. The relay is considered to be at the origin. 42

    43. Distance protection function 43

    44. Distance protection function The need for zones shown in Fig. 6 arises from the need of selective protection; i.e. the distance element should only trip faulty section. We can set the distance element to only trigger a trip signal for faults within a certain distance from the relay, which is called the distance element reach. The setting impedance is represented by , where ZL is the line impedance. The distance element will only trip when the measured impedance ZR is less than or equal to the setting impedance hsZL. 44

    45. Distance protection function Typically hs is set to protect 80% of the line between two buses and this forms protection Zone 1. Errors in the VTs and CTs, modeled transmission line data, and fault study data do not permit setting Zone 1 for 100% of the transmission line. If we set Zone 1 for 100% of the transmission line, unwanted tripping could occur for faults just beyond the remote end of the line. 45

    46. Distance protection function Zone 2 is set to protect 120% of the line, hence making it over-reaching, because it extends into the section of line protected by the relay at point B. To avoid nuisance tripping, any fault occurring in Zone 1 is cleared instantaneously, while faults which occur in Zone 2 are cleared after a time delay in order to allow relay B to clear that fault first. This provides redundancy in the protection system (backup), whilst maintaining selectivity. 46

    47. Transmission line protection: design and setting principles The transmission feeders are protected by two equivalent protection systems Main 1 and Main 2. For longer feeders (above 20km) two distance relays are usually installed. The distance relays should preferably be from different manufacturers. The rationale behind the selection practice is to select the most suitable product in terms of both performance and economic life cycle efficiency. Shorter feeders (below 20km) are often equipped with a combination of distance and differential relays to improve performance for high resistance faults. 47

    48. Main 1 and Main 2 protection systems Main 1 and Main 2 protection systems are fully segregated in secondary circuits: Relays are supplied from different cores of the instrument transformers (CTs and VTs). Protection panels are powered from two independent DC supplies. Main 1 and Main 2 use two different telecommunication media or at least different channels. Tripping is provided to independent circuit-breaker tripping coils. 48

    49. Main 1 and Main 2 protection systems For reliability, cross tripping between Main 1 and Main 2 relays is provided. The Main 1 and Main 2 relays back each other up, therefore there is no need for additional back-up protection. An additional earth-fault function is usually incorporated in the main protection relays It is common to have in these schemes: automatic circuit breaker reclosing, synchronising relay elements and single pole tripping to enhance stability margins and load transfer during disturbances. 49

    50. Zones of protection The minimum requirement for the protection of the line is two forward zones, one underreaching zone, and one overreaching zone. However, to cater for special circumstances over and above the protection requirements for the protected line, a third zone is often included. Each zone has the capability of issuing a trip command after its associated time delay, or with the time delay bypassed in accordance with the chosen communications-assisted tripping logic. 50

    51. Zones of protection Current reversal guard Where a permissive overreach scheme is used, current reversal guard is provided to avoid incorrect sequential tripping particularly on parallel lines. Switch-on-to-fault (SOTF) The SOTF protection caters for single and three-pole switch-on-to-fault conditions, and covers the full line length. 51

    52. Zones of protection Direct transfer tripping For transmission line protection applications, it is common that each of the tripping systems provides a direct transfer tripping facility with inputs derived from within the scheme or external to the scheme. Operation of this input initiates three-pole tripping without auto-reclose and initiates the circuit-breaker failure protection. 52

    53. Distance protection settings Distance protection functions should provide reliable protection against all possible short circuits, and are not set to provide overload tripping. Generally the distance relay settings are calculated in line with the manufacturers recommendations. 53

    54. Intertripping (communications-assisted tripping) scheme settings Both permissive under-reach (PUR) and permissive over-reach (POR) protection schemes are used on transmission lines. The POR scheme has superior performance for high resistance faults but requires duplicated communication channels. Most of the older electromechanical and early electronic relays are set in PUR. The most common present standard, since the introduction of digital relays, is the POR intertripping scheme. 54

    55. Zone 1 setting The zone 1 reach is based on line parameters considering the following limitations listed in order of priority: Zone 1 is normally set to 80% of the line positive sequence reactance to avoid possible incorrect operations due to compound measuring errors of relays, instrument transformers (CTs and VTs) and inaccuracies of line parameters. On relays that allow for a selection of resistive reach independent from other zones, ensure that the ground elements of zone 1 cover at least a resistance of 10 primary ohms. 55

    56. Zone 2 Setting Zone 2 reach is optimised based on fault studies for a particular application considering the following limitations, listed in order of priority: The minimum setting of zone 2 is 120% of the line positive sequence reactance. In cases where the above requirements can not be achieved, a time grading between Zone 2 at the local and Zone 2 at the remote busbar has to be provided. The Zone 2 time delay is normally set to 400 milliseconds. 56

    57. Zone 3, 4, 5 Setting The following tripping zones, Zone 3, 4, 5, can be configured independently or in some applications used for additional functions. Therefore the numbering of zones usually refers to back-up functionality rather than true numbering of zones on a particular relay. 57

    58. Power transformer protection settings The purpose of transformer protection is to detect faults and to initiate appropriate tripping action. Transformer internal and external faults are: Transformer internal faults winding failures tap changer failures inter-turn / low fault current faults Transformer external faults bushing failures surge arrestor failures transformer CT failures transformer overheating 58

    59. Transformer Unit Protection Unit protection operates only for faults in the protected zone, i.e. between the transformer CTs. The following protection relays are classified as transformer unit protection: Differential protection. Restricted earth-fault protection. HV instantaneous overcurrent protection. 59

    60. Differential protection Differential relay is used for protection. In case there is no internal fault and assuming CTs with matching ratios, currents measured at terminals are identical I1 = I2. Current in the relay operating coil is zero and relay does not operate. For the internal fault, I1 ?? I2, and differential current I1 I2 flows in the relay operating coil, which may cause the relay to operate. Since the relay operation depends on a differential current, it is called a differential relay. 60

    61. Differential protection Minimum operating current: Depending on the protection equipment, the operating current is either fixed (typically 20% of nominal current to cater for CT and relay errors) or variable (typically 10% to 50% of nominal current). Bias setting: The differential protection must not operate for the following conditions: Full load (throughout the entire tap range). Close-up through faults. Inrush currents. All relevant fault currents to evaluate the above requirements must be obtained from load flow and short circuit studies in the most onerous conditions. 61

    62. Differential protection Harmonic bias setting: Energization of a transformer may causes a temporary large inflow of magnetising inrush current. Magnetising inrush current may also be present due to energising of a parallel transformer. The magnetising inrush current usually yields over 30% second harmonic current during the first cycle of the inrush. A setting of 15% usually provides a safety margin for security to block the percentage differential element. 62

    63. Restricted Earth-fault Protection It is a circulating current unit protection intended to cover transformer earth-faults that can not be detected by the differential protection. The relays are usually high impedance and are voltage operated. Voltage setting of the Restricted Earth-fault Protection: Stability for through faults is based on an evaluation of the maximum voltage that can occur across the relay for the most onerous condition that requires the restricted earth-fault to remain stable; i.e. saturation of one CT during a through fault. Required primary operating current: Primary fault current should exceed the min. primary operating current for relay to operate. 63

    64. HV Instantaneous over-current protection HV Instantaneous over-current protection is considered to be unit protection because it is only intended to operate for faults between the transformer HV winding and the HV post type CT, including the HV bushings. The pick-up current should be selected to ensure that the HV instantaneous over-current protection operates for above-mentioned faults under minimum system conditions. The HV instantaneous over-current protection should not operate for the following conditions: Twice the full load current of the transformer HV winding. Transformer magnetising inrush current. HV and MV busbar faults. 64

    65. Transformer Non Unit Protection Non-unit protection operates for faults in the protected zone providing back-up to the transformer unit protection but also for faults outside of the protected zone protecting the transformer against uncleared external faults thus providing back-up for such faults. Following relays or functions are usually installed on transmission and sub-transmission transformers: Overcurrent protection: HV and MV IDMT overcurrent protection; Tertiary winding (LV) instantaneous and IDMT protection. Earth-fault protection: HV IDMT earth-fault; MV IDMT earth-fault; Sensitive earth-fault (SEF). 65

    66. References R. Zivanovic, Instrument Transformer Protection Settings, API notes 200. IEEE Power Systems Relaying Committee, CT Saturation Calculator: Excel Spread Sheet, 2002, Available: [Accessed April 20, 2009] RITZ Instrument Transformers publication, Medium Voltage Instrument Transformers, Rev 1, 2008, Available: [Accessed January 25, 2009] ABB publication, ABB Outdoor Instrument Transformers: Buyers Guide, Edition 5, Ludvika, Sweden, 2008, Available: [Accessed August 15, 2008] ABB publication, ABB Outdoor Instrument Transformers:Application Guide, Edition 2.1, Ludvika, Sweden, 2005, Available: [Accessed August 15, 2008] AREVA T&D publication, Network Protection & Automation Guide (NPAG): Chapter 6 Current and Voltage Transformers, 2008, Available: [Accessed September 18, 2008] Schweitzer Engineering Laboratories publication, SEL-7000 Integrated Substation System, Pullman, USA, 2006, Available: [Accessed August 20, 2008] Schweitzer Engineering Laboratories publication, SEL-421 Relay: Protection and Automation System Reference Manual, Pullman, USA, 2008, Available: [Accessed August 20, 2008] 66