ELEC 4302/7311POWER SYSTEM PROTECTION: PROTECTION SETTINGS BY MOHD MOIZUDDIN1
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 2
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
Protection Settings: Introduction Below Fig. 1 is an typical example of power system sections with their protection systems. Where: G1 is a generator. T1 is a transformer. B1,...,B5 are bus bars. L45 is a transmission line (TL). RG is a generator protective relay. RT is a transformer protective relay. RB is a bus protective relay. RL-4,...,RL-9 are TL protective relays. C1,..., C9 are CBs. 4Fig. 1 Protection of power system sections
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
FUNCTIONS OF EQUIPMENTPROTECTIONProtection schemes are generally divided into equipmentprotection and system protection.The main function of equipment protection is to selectivelyand rapidly detect and disconnect a fault on the protectedcircuit 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
FUNCTIONS OF PROTECTIVERELAYS 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
…FUNCTIONS OF PROTECTIVERELAYS 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 9 deficiency inherent within the design of the relay.
…FUNCTIONS OF PROTECTIVERELAYS 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
REQUIRED INFORMATION FORPROTECTIVE SETTINGLine 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 11 consideration.
…REQUIRED INFORMATION FORPROTECTIVE SETTING Transformer Parameters: The manufacturers positive and zero sequence impedance test values have to be obtained. The transformer nameplate normally provides the manufacturers 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
…REQUIRED INFORMATION FORPROTECTIVE SETTINGFault 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 13 load currents on site and comparing with a known ratio.
…REQUIRED INFORMATION FORPROTECTIVE 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 14 correct unmatched ratios.
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. 15
Fig. 2 Information flow during protection settings preparationProject leader of the ProtectionSettings team determines scope IED manufacturers provide bayof work and target dates specific IED details Engineering team provides bay specific proformas and drawings Corrective actions and re-issue ofSummary and comparison of inputs drawings OK Not OKStudy new protection and createnecessary setting templates inliaison with engineering team andIED manufactureres Interface with the Expansion Planing team and IED manufacturers to obtainCalculation and verification of settings relevant equipment parameters for correct system modellingSettings stored in central database Centralised Settings Managementand formal document issued System sends the action documents to the field staffImplementation date and responsiblefield person stored in the centraldatabase -> implementation actionImplementation sheet completed Corrective actions required to 16by field staff and returned to ensure implementationProtection Settings team
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 17 (action element) operates.
Sequence of protection operation initiated by a fault is shown in Fig. 3. Pickup of Operation ofFault protection element protection element Assertion of relay Action of relay trip logic signal trip contact Circuit breaker Fault cleared opening Fig. 3 Sequence of operation. 18
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 19 direction.
…OPERATING CHARACTERISTICSOF 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. 20
OVERCURRENT AND DIRECTIONALPROTECTION 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 21 of current flow.
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. 22
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 23 prove to be quite costly.
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. 24
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 minimizeFig. 4: Use of direction element amount of circuitry that isexample isolated in order to clear a fault. 25
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: TA = VBC • I A • cos(∠VBC − ∠I A ) TB = VCA • I B • cos(∠VCA − ∠I B ) TC = V AB • I C • cos(∠V AB − ∠I C ) 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 26 inside directional element.
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. 27
…DISTANCE PROTECTION FUNCTION Fig. 5 Distance protection principle of operation. In Fig. 5 the impedance measured at the relay point A is Z = ( R + jω L) x , where x is the distance to the fault (short in circuit), and R and L are transmission line parameters in per unit length. The line length is l in the fig.. 28
…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. 29
…DISTANCE PROTECTION FUNCTION X Region of Line Q non-operation 120% B outside the circle 80% Zone 2 Line P Z RS Load Region of region operation Zone 1 A R Fig. 6 Mho positive-sequence R-X operating characteristic of a distance element. 30
…DISTANCE PROTECTIONFUNCTION 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 Z RS = hs Z L , 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 31 impedance hsZL.
…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. 32
…DISTANCE PROTECTIONFUNCTION 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. 33