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Bus Protection Fundamentals ABB Protective Relay School Webinar Series Bus Protection Fundamentals Jack Chang, RTM, CA Sept 09, 2014

Presenter Jack Chang is the regional technical manager for ABB Inc. in the Substation Automation Products BU serving customers in Canada and northern regions. He provides engineering, commissioning and troubleshooting support to customers applying ABB’s high-voltage protective and automation devices. Prior to joining ABB, Jack worked as a substation P&C project engineer in two specialized consulting firms and also as an engineering contractor to a public owned utility in their transmission expansion and upgrade projects. Jack is a registered professional engineer in the province of Alberta, Canada. Jack Chang ©ABB November 16, 2018November 16, 2018

Learning objectives Types of bus configurations Current transformer characteristics and their effect on bus protection Types of bus protection schemes Modern Numerical Bus Protection Features Questions: jack.j.chang@ca.abb.com, 403-923-4028 ©ABB November 16, 2018November 16, 2018

Why bus protection? Different configuration and design Usually very robust, high current faults Need to clear quickly A Delayed bus trip leads to: Network instability pole slip of nearby generators Possible system collapse Bigger fault related damages & risk to human life or injury Many bus faults caused during maintenance (eg. Arc flash) ©ABB November 16, 2018November 16, 2018

Bus fault protection Easy to detect because of robust nature Easy to protect for internal faults (87B) Summation of currents not equal to zero for internal fault External faults can cause current transformer saturation which results in unwanted differential currents Infrequent, but must be cleared with high speed Substation is well shielded Protected environment ©ABB November 16, 2018November 16, 2018

Bus configurations Single bus * Main and transfer bus Double bus, single breaker * Double bus, double breaker Breaker and a half * Ring bus * * Dentoes commonly seen configuration in NAM ©ABB November 16, 2018November 16, 2018

Single bus ©ABB November 16, 2018November 16, 2018

Main and transfer bus ©ABB November 16, 2018November 16, 2018

Double bus single breaker Typically seen in GIS SWGR Lots of feeders, seen mainly in big industrail plants and utility distribution stations Some types of dynamic zone switching scheme must be in place (modern low impedance bus differential IEDs) ©ABB November 16, 2018November 16, 2018

Double bus, double breaker ©ABB November 16, 2018November 16, 2018

Breaker and one half Typically seen in HV/EHV transmission and major power plant switching stations, quite popular in North America Dedicated bus protection each of two main bus bars Bus stubs are located in the line/transformer/reactor zones and no dedicated bus protection required. ©ABB November 16, 2018November 16, 2018

Ring bus Popular in North America (72, 138, 230 KV). Cheaper design than 1-1/2. same number of links as the number of breaker. less reliable. Usually no dedicated bus bar protection as the bus stubs are in the zones of line/transformer/reactor etc with redundant A/B All bus protection zones should be overlapped ©ABB November 16, 2018November 16, 2018

Main-Tie-Main Most popular for MV (15, 25 KV) small industrial/utrility distribution systems Dedicated bus diff. for each bus if so designed blocking scheme via communciation Some types of bus transfer scheme may be designed ©ABB November 16, 2018November 16, 2018

Some issues Availability of overlapping protection zones (CTs) Blind or end zone protection Will loads or sources be switched from one bus to the other Current transformer switching from one zone to another Open circuit current transformers CT Saturation ©ABB November 16, 2018November 16, 2018

Zones of protection Station B Station A Station C Station D G G G Bus protection Station D M ©ABB November 16, 2018November 16, 2018

Zones of protection CT for Green Zone CT for Blue Zone Green Zone Dead tank breaker, two CTs Occurrence so rare as the fault is inside the tank. Bus fault beside the CT and Breaker - BKR closed: both zones should operate in high speed to clear the fault - BKR open: tripping of blue relay is unnecessary. To avoid over tripping with breaker operated normally open, logics can be made to remove the two CTS to the bus relay when the breaker is open ©ABB November 16, 2018November 16, 2018

Zones of protection CT for Green Zone CT for Blue Zone Green Zone Live tank breaker, single CT Blue relays open the breaker, but Green relays don’t. That fault is still live Local breaker failure protection could be used as back-up if time delay is acceptable. Very rare in likelihood of occurrence * A faster solution is to “disconnect” the CT to the green relay when the breaker is open. Tripping for green relay will delay slightly but definitely faster than BF backup time. ©ABB November 16, 2018November 16, 2018

Ratings of concern for bus protection Current transformer Ratings of concern for bus protection Ratio: 200/5, 1200/5, …500/1 Burden capability: VA burden Accuracy Class: C800, K200, T400 Knee point, saturation voltage (can be derived from chart in C class CTs) CT availability IEEE Standard C57.13-1993 (R2003), IEEE Standard Requirements for Instrument Transformers IEEE Standard C37.110-1996, IEEE Guide for the Application of Current Transformers Used for Protective Relaying Purposes Accuracy Definition: For relaying CTs, ANSI/IEEE defines a limit of 10 percent for the ratio error for a steady-state, symmetrical (no dc offset) Bus faults tend to saturate the CT closest to the fault (external fault) secondary current equal to 20 times rated secondary current at the standard rated burden C: Leakage flux neglegiable. Eg. Multi-ratio bushing, window type CTs. CT Excitation chracteristic can be used to determine CT performance T: CT ratio error must be derived from test. CT transient behavior must take into account the system X/R ratio (dc offset, deteriorating) and remnant flux (derate rated votlage). Simply size CT according to the steady-state rating is not sufficient to avoid saturation, ©ABB November 16, 2018November 16, 2018

ANSI current transformer accuracy class Example 1200/5 C800 This current transformer will deliver 800 volts on its secondary when it is connected to a standard burden and 20 times rated current is flowing in the primary winding without exceeding 10% ratio error. ©ABB November 16, 2018November 16, 2018

Standard chart for class C current transformers ANSI accuracy class Standard chart for class C current transformers Relationshipo between the rated burden and rated terminal voltage of a C class CT is linear. The relationship of terminal rated voltages between different ratios of a multi-ratio CT is also linear (assuming uniformly distributed secondary winding) ©ABB November 16, 2018November 16, 2018

Knee point voltage Knee point Log-log plot Square decades I.e. (.01,1) – (.1,10) Tangent 45º line (knee pt) Exciting current vs exciting voltage plot (C Class CT) Knee points defined as “the voltage at the point where the tangent to the curve (on log-log axes) is at 45 degrees to the horizontal axis. - The saturation voltage (VSAT) is graphically found by locating the intersection of the straight portions of the excitation curve on log-log axes - Note that neither is the same as the rated voltage, eg, 10C400. 10% increase in voltage gives you 50% increase in excitation current in the saturation zone ©ABB November 16, 2018November 16, 2018

Differential measurement difficulties Three measuring conditions normal load flow - no differential current external fault - ideally no differential current internal fault - high differential current CT saturation causes false differential current for external faults ©ABB November 16, 2018November 16, 2018

CT saturation CT core may reach saturation flux density due to a combination of dc offset in the fault current, with possibility remnant flux (20-80%, no way to predict, but can be erased by demagenatizing) The output current suddenly changes from a proportional signal to zero DC saturation depends on system time constant (X/R)- large close to generating stations secondary burden ©ABB November 16, 2018November 16, 2018

CT saturation CT secondary model a perfect current source (infinite impedance) in parallel with an exciting impedance branch that drives proportional current Exciting impedance is normally very high At saturation, exciting impedance drops to a very low value the CT appears short-circuited neither delivers nor resists current flow Time to saturation is important in low impedance bus protection (ie. Saturation doesn’t come instantly) ©ABB November 16, 2018November 16, 2018

Issues affecting bus protection selection Bus arrangement Fixed Switchable Availability and characteristics of current transformers Performance requirements Speed Dependability Security Sensitivity (for high impedance grounded system) ©ABB November 16, 2018November 16, 2018

Types of bus protection Differential Differentially connected overcurrent Percentage-restrained differential (low Z) High impedance differential Partial differential Zone interlocked scheme Back up schemes (eg. local BF or remote over-reaching zones) ©ABB November 16, 2018November 16, 2018

Differentially connected overcurrent relay 51 ©ABB November 16, 2018November 16, 2018

TOTAL OUT OF BUS MINUS IE External fault case Protected Bus = FAULT LOCATION IE IT TOTAL OUT OF BUS MINUS IE TOTAL INTO BUS TOTAL OUT OF BUS Relay Id = IE IE is the exciting current loss due to slight CT saturation in high external fault level ©ABB November 16, 2018November 16, 2018

Internal fault case Protected Bus I1 I2 I3 I4 Id Id = I1+ I2 + I3 + I4

Overcurrent relay bus differential Application OK if: Symmetrical CT secondary current less than 100 Burden less than rated Typical pickup setting IPU > 10A Trip delay greater than 3 x primary time constant (L/R) Protected bus Id Essentially the CT must have matching characterisitcs and stringent sizing requirement to avoid saturation. If a 50 speed is desired, then the pick up set point must be above all possible CT measuring errors (less sensitive). No built-in protection to CT transient behavior (saturation) ©ABB November 16, 2018November 16, 2018

Resistor added to relay branch External fault Stabilizing resistor Rd Total primary contribution to external fault IF (out) through saturated ct RS ZE = 0 Overcurrent Relay Id IF (in) total from other cts Resistor reduces current in relay and increases current in RS (secondary and lead) Increases sensitivity to internal faults For external faults, ct saturation case, adding resistor to relay path will reduce current through the relay and push more current through the CT secondary, hence relay will become more stabilized for through faults. - Basically a high impedance bus differential relay ©ABB November 16, 2018November 16, 2018

Multiple restraint Percentage Differential (Legacy) PROTECTED BUS A B C D RESTRAINT R,S AND T ARE COILS All circuits have 10 Amp contribution Restraint = 60 Operate = 0 R S 10 10 10 30 Net restraint (0) T (20) 20 20 (40) ONLY ONE PHASE SHOWN OPERATE COIL External fault example – 4 circuit connection This is how the restraint feature was implemented in legacy bus differential relays. ©ABB November 16, 2018November 16, 2018

Multiple restraint Percentage Differential (Legacy) PROTECTED BUS A B C D RESTRAINT R,S AND T ARE COILS All circuits have 10 Amp contribution Restraint = 0 Operate = 40 R S 10 10 10 10 Net restraint (0) T (0) 20 20 (0) ONLY ONE PHASE SHOWN 40 OPERATE COIL Internal fault example – 4 circuit connection ©ABB November 16, 2018November 16, 2018

Torque for typical multi-restraint relay Operating Torque Two Restraint One Restraint 0 20 40 60 80 100 Amperes The amount of restraint current required to overcome a certain operating torque. Relays with two restraint windings can overcome higher amount of operating torques, improving security on minor CT saturation. ©ABB November 16, 2018November 16, 2018

Torque for typical multi-restraint relay 55 A. of restraint overcomes 7 A of operating current with one restraint winding Operating Two Restraint Torque One Restraint 7 55 0 20 40 60 80 100 Amperes A certain current restraint can overcome a certain amount of operating torgues. Similar to the modern numerical restraint-operating current characteristics shown in slopes. ©ABB November 16, 2018November 16, 2018

Multi-restraint percentage differential Good sensitivity Good security Allows other relays on the same CT core Different CT ratios with Aux CTs. Slow compared to high impedance Number of feeders limited by restraint windings Each CT is wired to relay (ca be used for other applications: BF, OC backup etc) Not easily extendable ©ABB November 16, 2018November 16, 2018

High impedance bus protection High resistor (R > 1500 ohm) in series with relay coil and a MOV to prevent over-voltages High voltage develops for internal faults. lower Voltage will develop on external faults where with ct saturation Voltage unit must be set higher than the maximum junction point voltage for any external fault The lowest achievable sensitivity must verified for the application Proven reliability and very sensitive Operating times of less than one cycle for internal faults R Depending on the relay design the stablizing resistor and metal oxide varistor (MOV) may locate in anther hardware, requiring space and external wiring Some applications connect 86 lockout relay contact in parallel with the relay coil and MOV to further limit the duration of over-voltages during fault. ©ABB November 16, 2018November 16, 2018

High impedance bus protection EXTERNAL FAULT - SECURITY Setting VR > K*(IF / N ) ( RL +R S) K = margin factor IF = Max external fault current RS = Ct secondary resistance RL = Lead resistance to junction box N = ct turns ratio INTERNAL FAULT - SENSITIVITY IM I N = (XIE + IR + IV ) N N = number of circuits IE = Ct exciting current at VR IR = resistor current at VR IV = Varistor current at VR R > 1500 W ©ABB November 16, 2018November 16, 2018

High impedance bus protection Criteria to be met Objective: Keep VR and Imin low Ct secondary loop resistance kept low Impedance from junction point to relay is of no consequence so good practice to parallel the CTs as close to the CTs as possible. Theoretically no limitations in the number of parallel CTs but sensitivity reduced. All cts should have the same ratio and magnetizing characteristics ©ABB November 16, 2018November 16, 2018

High impedance bus protection Criteria to be met Tapped CT’s may be interconnected with fixed ratio ct’s if attention is given to the autotransformer effect and the overvoltage protective characteristics of the relay A voltage setting NOT higher than the lowest of all of the relaying accuracy class voltages of the CT’s used in the scheme (400 V for a C400 CT). IE obtained from the excitation character contains large errors (saturated) , causing errors in Imin calculation (higher Imin, over-reaching) Voltage setting can be lowered by reducing CT lead resistance Tapped CT ratios has reduced voltage class rating Ie. The pickup shall not be set > than 800 volt for C800 CTs ©ABB November 16, 2018November 16, 2018

Differential comparator (Legacy, Static type) RADSS/REB103 Developed to lessen restrictions imposed by high impedance All CT secondary circuits connected via interposing cts Connection made using a special diode circuit producing rectified incoming, outgoing and differential currents IIN IOUT SR AUX CTs IDIFF DR ©ABB November 16, 2018November 16, 2018

Differential comparator Single phase connection IIN is sum of all feeder instantaneous positive values IOUT is sum of all feeder instantaneous negative values IDIFF = IIN - IOUT AUX CTs Start IDIFF VOp IOUT VRes Trip IIN ©ABB November 16, 2018November 16, 2018

Differential comparator Internal X L1 L2 L3 L4 X External External Internal ©ABB November 16, 2018November 16, 2018

Differential comparator Single phase connection IDIFF is typically small (normally 0) for external fault and restraint voltage, VRes, is greater than operating voltage, VOp. IDIFF is typically large for an internal fault and operating voltage, VOp, is greater than restraining voltage, VRes. This produces voltage across trip relay. AUX CTs Trip / LO Start Start IDIFF VOp Trip IOUT VRes Trip IIN ©ABB November 16, 2018November 16, 2018

Differential comparator All measurement decisions based on three quantities IDIFF - difference of input current and output current (IDIFF = IIN - IOUT) IIN - total input current S - % differential setting IDIFF > S x IIN e.g. for setting S=50%, differential current  50% of incoming current before operation ©ABB November 16, 2018November 16, 2018

Differential comparator Advantages over high impedance differential Lower ct requirements Allows much higher ct loop resistances Accommodate different CT ratios / auxiliary CTs Fast operating times for internal faults Detects internal 1 - 3 ms Before ct saturation ©ABB November 16, 2018November 16, 2018

Numerical differential comparator Analog input currents are instantaneously sampled and quantized to numerical number Similar technique to legacy differential comparator, but with measured sampled data Secondary circuit loop resistance no longer a critical factor Critical factor is time available to make the measurement, i.e. time to saturation. (only 3ms required to properly restrain for heavy external faults) Algorithms for Ct saturation Detection and CT state supervision ©ABB November 16, 2018November 16, 2018

Differential comparator Characteristic can be shown in a typical operate-restraint chart ©ABB November 16, 2018November 16, 2018

Quick operation for internal fault REB 670 detects that I_IN goes up while I_OUT goes down at the beginning of the internal fault and enables fast tripping When ID>Diff Operation Level trip is issued Small i: samples Capital I: Phasors ©ABB November 16, 2018November 16, 2018

Proper & secure restrain during external fault REB 670 detects this short interval when i_in=i_out (after every fault current zero crossing) and restrain properly during external fault REB 670 detects that I_IN=I_OUT at the beginning of the external fault Iin = Iout for a short duration before CT saturation, eg. CT saturation detection. The relay restrains properly. ©ABB November 16, 2018November 16, 2018

fulfilled & REB is blocked Fast open CT algorithm REB 670 detects that I_IN doesn't change while I_OUT goes down when some of the CTs is open/short circuited ID>Open CT Level second condition fulfilled & REB is blocked Diff Operation Level Must be set to higher value than Open CT Level The relay notices the trend and locus of these points and then makes the decision. The relay sees normal load conditions for 500msec and then sees a sudden drop in the current. ©ABB November 16, 2018November 16, 2018

Other Features in Modern Numerical Bus IEDs Each device capable of connecting multiple bays (eg. CTs) in 3- ph or 1-ph design Multiple differential zones, dynamic bay switching, zone interconnection, and check zone logics External fault/CT saturation detection, open CT detection algorithms Blind zone protection (see next 2 slides) End zone protection (see next 2 slides) Backup protection (eg. 50/51, 50BF) for each connected bay Modern substation automation communication (DNP 3.0, IEC61850) ©ABB November 16, 2018November 16, 2018

Blind zone detection Blind zone between live tank CT and breaker A fault in the blind zone makes operation in ZA unnecessary (tie breaker normally open) ZB cannot detect the fault Solution: connect BKR NC (open) status to the bay to remove this CT from ZA, ZB (software) Remove CT dynamically can force operation of ZB ©ABB November 16, 2018November 16, 2018

End Zone Protection red=measuring, blue= tripping zone CTs are used for both feeder and bus protection measurement (live tank CTs) Regions not overlapped by both red and blue boundaries are blind zones Bus Under-trip for 3. Inst. OC enabled after bkr is opened to send DTT (faster) BF to trigger DTT (slower) Feeder under-trip for 4. disconnect CT after bkr is opened to clear the bus (faster) BF to clear the bus for 4 (delayed) ©ABB November 16, 2018November 16, 2018

Other distribution (MV) bus protection methods Partial differential Blocking on feeder fault ©ABB November 16, 2018November 16, 2018

Partial differential Seen more in a main-tie-main bus configuration where you can connect the incoming source and the tie in a partial differential circuit to exclude faults in the adjacent bus in case the two buses are to be joined. In that way, each incoming transformer protection only have to coordinate with local bus feeders as if the tie is open. Also, saving a tie relay. In this case, multiple sources are bound together and must coordinate with downstream protection. ©ABB November 16, 2018November 16, 2018

Blocking scheme For MV or LV systems equipped with dedicated arc flash protection or arc flash not a concern (eg. GIS), no dedicated bus differential is really needed. This type of blocking scheme can provide fast bus bar protection, saving the cost of a dedicated differential relay.. ©ABB November 16, 2018November 16, 2018

Conventional Blocking Scheme Zone of protection T+100 ms 100 ms I> I>> blocking Traditional busbar protection based on upstream blocking Dedicated hard-wire signal paths needed Signal path delay needs to be considered, input and output delay + auxiliary relays Changes in the protection scheme may require re- wiring Typical needed delay in incoming relay is over 100 ms Delay setting with inst. O/C protection (conventional approach) Safety marginal, e.g. delay in operation due to CT saturation. 20…40 ms O/C protection start delay + output relay’s delay <40 ms Start delay with receiving relay + retarding time for the blocking signal *) ALL TOGETHER 100…120 ms Now we will shortly go though one example of using GOOSE in one protection schema Blocking based busbar protection Outgoing feeders sends over copper-wire a blocking signal to incoming source protection if there is fault on the line A certain delay introduced due to the communication latency and IED processing delays between IEDs

Blocking Scheme with IEC-61850 GOOSE Yes I am! I’ll block the Inst. O/C! Block-PHIPTOC! Delay setting with inst. O/C protection (REF615 GOOSE approach) Safety marginal, e.g. delay in operation due to CT saturation. 20…40 ms O/C protection start delay 20 ms Retardation time of inst. O/C stage blocking 5 ms GOOSE delay (Type 1A, Class P1) <10 ms ALL TOGETHER 55…75 ms IEC 61850-8-1 Who is interested? PHLPTOC-start! When same schema is executed with GOOSE blocking signal is sent over the Ethernet based station bus to incoming feeder Faster communication between IEDs due to the missing I/O output and input delays More protection scheme examples are shown in 615 series presentations

Bus protection comparison chart COST EASE OF USE SENSI- TIVITY DEPEND ABILITY SECURITY FLEXI- BILITY SPEED SIMPLE OVER-CURRENT LOW GOOD POOR   MULTIPLE RESTRAINT MED BEST HIGH IMPEDANCE FAST PERCENTAGE RESTRAINED DIFFERENTIAL HIGH PARTIAL DIFFERENTIAL BLOCKING ©ABB November 16, 2018November 16, 2018

Questions? Recommended reading ANSI C37.234 Guide for Protective Relay Applications to Power system Buses ©ABB November 16, 2018November 16, 2018

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