Fundamentals of generator_protection[1]

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Fundamentals of generator_protection[1]

  1. 1. g GE Energy Services Fundamentals of Generator Protection by Abdul Wahab Memon 11/11/2001 Abdul Wahab 1
  2. 2. g Single Line and Three Line Diagrams GE Energy Services • Single line and three diagrams are schematics used by Power Systems Engineers to indicate the interconnections of the different power systems components. They will be used through the presentation to illustrate the basic components of the Generator Protection System. • Single line diagrams are drawings that show in a “single phase format” the interconnection of different power systems components. They are intended to provide a “general picture” of the power system. • Three lines diagrams show a detailed interconnection of all of the three phases of the different power system components. 11/11/2001 Abdul Wahab 2
  3. 3. g 11/11/2001 Single Line Diagram Abdul Wahab GE Energy Services 3
  4. 4. g 11/11/2001 Three Line Diagram Abdul Wahab GE Energy Services 4
  5. 5. g 11/11/2001 Three Line Diagram Abdul Wahab GE Energy Services 5
  6. 6. g Protective Relaying Components GE Energy Services • The basic components of a protective relaying systems are – Instrument Transformers • Current Transformers (CTs) • Potential Transformers (PTs) – Relays • Digital Generator Protection (DGP) • Electromechanical Relays – Other Components • Circuit Breakers • Control and Trip Circuits • Terminal blocks and control wires – Equipment to be Protected 11/11/2001 Abdul Wahab 6
  7. 7. g Instrument Transformers GE Energy Services Instrument transformers, in general, are electromagnetic devices designed to electrically isolate the high voltage power system from the low voltage control circuits. They are designed to reduce the magnitude of the power system currents and voltages to levels that the protective relaying devices can safely manage. 11/11/2001 Abdul Wahab 7
  8. 8. g 11/11/2001 Current Transformers Abdul Wahab GE Energy Services 8
  9. 9. Current Transformers g Ip = Primary Current Equivalent Circuit Ip • • I /N p N Turns Is = Secondary Current I Zl + Zm I e - s V Ie = Magnetizing Current Ve = EMF + V e GE Energy Services Z s b N = Nominal current ratio Zl = Leakage Impedance Zw Zm = Magnetizing Impedance Zb = Burden Impedance Zw = Wire impedance 11/11/2001 Abdul Wahab 9
  10. 10. g Current Transformers GE Energy Services • The rated secondary current, in most applications, is either 5A or 1A. In the US, the great majority of the installations use 5A rated CTs. • As a rule of thumb, the rated primary current of the current transformer is normally chosen as 1.5 times the maximum anticipated steady state load current. • Typically a # 10 wire (~ 1 ohm per 1000 ft) is used to connect the secondary side of the CTs to the load. • The burden impedance is the total impedance connected to the CT terminals excluding the impedance of the wire. The impedance of the DGP is 0.022 ohms @ 5° for 5A relays. 11/11/2001 Abdul Wahab 10
  11. 11. Current Transformers g GE Energy Services Polarity marks are used to indicate the direction of the flow of current in the secondary side of the current transformer (critical for some relaying applications such as differential and reverse power relays). The nomenclature used is such that if the primary current leave (enter) the current transformer through the polarity mark, it will enter (leave) the current transformer through the polarity mark in the secondary circuit. The flow of current in the secondary side is such that the magnetic flux that they produce will oppose the one produced by the primary current. • • • • • • • 11/11/2001 Abdul Wahab • 11
  12. 12. g Current Transformers Saturation Curves • From the equivalent circuit of the CT: Vs V GE Energy Services Is = Ip/N - Ie • Adequate selection of current transformers will warrant that knee Is ~ Ip/N (Ie ~ 0) but if the Vs exceeds the knee point voltage of the current transformer, saturation will occur. Under saturation, Ie could no longer be neglected. I 11/11/2001 e Abdul Wahab 12
  13. 13. g Current Transformers GE Energy Services • The accuracy class of current transformers for protective relaying is defined in ANSI standard C57.13 by two symbols: a letter designation and a voltage rating. • We will focus on letter designation “C” which – C: indicates that the transformer ratio can be calculated. This classification covers bushing current transformers and any others whose core leakage flux has no effect in the ratio. • The secondary terminal voltage rating is the voltage the transformer will deliver to a standard burden at 20 times secondary current without exceeding a 10% ratio error. • A transformer with accuracy class C-100 will not exceed a 10% ratio error when the secondary current is in between 1 to 20 times rated if the secondary impedance does not exceeds 1 ohm. • C-800, C-400, and C-200 are also examples. 11/11/2001 Abdul Wahab 13
  14. 14. g Current Transformers GE Energy Services Saturation curves are also used to estimate the current transformer performance. They show in a log-log scale, the excitation current for a given applied RMS secondary voltage as it is varied from 1% of the accuracy class secondary voltage to a voltage (not to exceed 1600 volts) that will cause an excitation current of 5 times normal secondary current while keeping the primary open circuited. 11/11/2001 Abdul Wahab 14
  15. 15. Current Transformers R In s t r u m e n t T r a n s f o r m e r s , In c . P .O . B O X 7 1 8 0 , C l e a r w a t e r , F l . , 3 4 6 1 8 This test report is in accordance with ANSI/IEEE C57.13 1993 DATE: EXCITATION CURVE 5121A32040 DRAWING NO. 01/08/01 ENTERED BY: MODEL ABOVE THIS LINE THE VOLTAGE FOR A GIVEN EXCITING CURRENT FOR ANY UNIT WILL NOT BE LESS THAN 95% OF THE CURVE VALUE GE Energy Services REVISION g BKH CHECKED BY: 0121B08567-69/0121A28579-06 (TYPICAL) 10000 BELOW THIS LINE THE EXCITING CURRENT FOR A GIVEN VOLTAGE FOR ANY UNIT WILL NOT EXCEED THE CURVE VALUE BY MORE THAN 25% s 0121B08567-69 (50 Hz) 1000 CURRENT RATIO TURNS RATIO SEC RES.* 6000:5 1200:1 1.52 1200:1 1.20 0121A28579-06 (50 Hz) 6000:5 0121A28579-06 SECONDARY EXCITING RMS VOLTAGE, - E 0121B08567-69 100 10 * OHMS AT 75 C. 1 .001 11/11/2001 .002 .005 .01 .02 Abdul Wahab .05 0.1 0.2 SECONDARY EXCITING RMS AMPS, - I 0.5 1.0 2 5 10 e 15
  16. 16. Current Transformers g GE Energy Services Wye connection • Relay currents in phase with system currents R • • • • R • • R R •Respond to all system loads or fault geometries • Fake residual currents due to CT behavior 11/11/2001 Abdul Wahab 16
  17. 17. g Current Transformers GE Energy Services Delta connection R R • • • 11/11/2001 • • • Abdul Wahab R 17
  18. 18. g Current Transformers GE Energy Services Delta Connected • • Current transformers sometimes are connected delta to meet the requirements of the relays connected to them. For balance three phase loads or faults: – Is = (Ip/N) * SQRT 3 • SQRT = Square Root For phase to phase loads or faults – Is = (Ip/N) * (SQRT 3)/2 (in two phases) – Is = (Ip/N) * SQRT 3 (in one phase) • The secondary currents are shifted 30°relative to the primary for three phase faults or loads 11/11/2001 Abdul Wahab 18
  19. 19. g 11/11/2001 Potential Transformers Abdul Wahab GE Energy Services 19
  20. 20. g Potential Transformers GE Energy Services • Potential transformers (PTs), also known as voltage transformers, are normal transformers whose primary windings are connected directly to the high voltage power system and its secondary windings are rated at 69.3 V for phase to neutral voltages or 120 V for phase to phase voltages. The performance and equivalent circuit are similar to those of a power transformer. • Since the burden impedance of the relays connected to the secondary side of the PTs is normally high, they behave like ideal transformers: Vp/Vs = Np/Ns where Vp = Primary Voltage ; Vs = Secondary Voltage; Np = # turns of the primary windings and Ns = # turns of the secondary winding. 11/11/2001 Abdul Wahab 20
  21. 21. Potential Transformers g Np I Ns p Equivalent Circuit I p • + V Z •+ - N p - Np N I l • Vp, Ip, Np = Primary voltage, current and # turns s + Ns p GE Energy Services V p Z m Ie Vs Z b - s • Polarity marks are used to indicate which terminals are positive at the same time when voltage is applied to either winding. • Since high impedance loads are normally connected to the secondary side of the PT, Abdul Wahab • Zl = Leakage Impedance • Zm = Magnetizing Impedance • Ie = Magnetizing current Vs ~ Ns/Np * Vp 11/11/2001 • Vs, Is, Ns = Secondary voltage, current and # turns 21
  22. 22. Potential Transformers g GE Energy Services Wye Connected PT • The secondary voltages are a true representation of all three phase to ground voltages. a b c • • D • • 11/11/2001 • • Abdul Wahab • Three sets of PTs are required. G P 22
  23. 23. Potential Transformers g GE Energy Services Open Delta Connected PT •Line to neutral voltages are not available. a b • Only two sets of PTs are required. c • • D • • G P 11/11/2001 Abdul Wahab 23
  24. 24. g Digital Generator Protection 11/11/2001 Abdul Wahab GE Energy Services 24
  25. 25. g 11/11/2001 Single Line Diagram Abdul Wahab GE Energy Services 25
  26. 26. g 11/11/2001 DGP Connection Diagram Abdul Wahab GE Energy Services 26
  27. 27. Differential Protection (87) g • Ip • I’p ~ Is I’s R I’ - I s R GE Energy Services • • R Restrain Coil O Operating Coil O s • During normal operation or faults outside of the CTs (differential zone) no current flows through the Operating Coil. Only for internal faults will Is be different than I’s. • Two identical CTs are required 11/11/2001 Abdul Wahab 27
  28. 28. Ground Fault Protection (64G) g GE Energy Services • Most generators are grounded via a distribution transformer. The load (resistor R) connected on the transformer secondary is designed to limit the fault current between 5- 10 A. Fault currents greater than 10 A do significant burning damage. ~ • 59 is a sensitive voltage relay (typically 5 volts pick up) tuned to respond only to the fundamental frequency voltage with a time delay of 3-5 sec. The 59 relay protects 95% of the stator winding. R 11/11/2001 59 Abdul Wahab 28
  29. 29. Over excitation Protection (24) GE Energy g Services V/Hz (PU) • The magnetic flux in the generator is proportional to the ratio of the generator terminal voltage to the generator frequency. • Excessive over excitation (above 1.10 pu) increases core losses and could result in a breakdown of the inter-laminar insulation which could lead to a core melt down. 1.18 Trip 1.10 1.05 ALARM Continuos Operation 2 11/11/2001 45 Time (sec) • Over excitation could be the result of a regulator failure, a sudden load rejection, or a decrease in the operating speed Abdul Wahab 29
  30. 30. Over Voltage Protection (59) g • • GE Energy Services • • The over voltage relay is used as a back up for the over excitation protection. • • Generally speaking, it is set as follows - Alarm: ~ 11/11/2001 59 Relay 1.05 < V < 1.10 - Inverse Trip: 1.10 < V < 1.18 - Inst. Trip: Abdul Wahab V > 1.18 30
  31. 31. Motoring / Reverse Power Protection (32) g GE Energy Services • Motoring can occur as a result of the loss of the prime mover • – If the field is energized the generator will behave as a synchronous motor. The generator will not experience damage but the turbine. – If the field is open the generator will behave as a induction motor. In addition to the possible damage to the turbine (steam), the induced Eddy currents will produced overheating that could result in rotor damage. Sensitivity Prime Mover Gas Turbine, 1 shaft Gas Turbine, 2 shaft Hydro, run of river Hydro, dam Steam turbine, conventional 11/11/2001 Abdul Wahab Motoring Power (%) 60-100 10-15 2-10 50-100 1-4 31
  32. 32. g Loss of Excitation (40) GE Energy Services • Loss of excitation can occur by accidentally tripping the field breaker, open or short circuits in the field winding, regulator failure, or loss of power to the field. • When a synchronous generator losses the field it will behave like an induction generator. The generator will run above normal speed, it will operate at a reduced power and it will absorb reactive power from the network. • Since the generator is rotating at slip frequency, currents will be induced in the rotor body and wedges. Also an alternating torque will appear in the generator shaft. The result of this off frequency operation could be rotor overheating and even rotor failure. 11/11/2001 Abdul Wahab 32
  33. 33. Loss of Excitation (40) g X Normal Load R GE Energy Services • The loss of excitation relay is a mho type set to the following values: Diameter = 1.0 p.u Offset = 1/2 X’d Delay = 0.05 sec Diameter = Xd Offset = 1/2 X’d Delay= 0.5 sec 11/11/2001 Abdul Wahab 33
  34. 34. g Negative Sequence (46) GE Energy Services • Negative sequence currents could result from - Unbalanced loads - Asymmetrical faults. - Open phase conditions • Exposure to negative sequence currents could cause overheating of the rotor body, retaining rings and slot wedges. 11/11/2001 Abdul Wahab 34
  35. 35. g Negative Sequence (46) GE Energy Services • The negative sequence protection will permit operation up to the generator continuous negative sequence limit but trip the unit if the level exceeds this value long enough to reach the permissible (I2 )² t limit. t ANSI Limit on I2²t Trip Alarm ANSI Continuous Limit on I2 I2 11/11/2001 Abdul Wahab 35
  36. 36. g Negative Sequence Protection (46) Energy GE Services ANSI Requirements for Unbalanced Faults on Synchronous Generators Type of Machine Salient pole generator Cylindrical rotor, indirectly cooled Cylindrical rotor directly cooled < 800 MVA 11/11/2001 Permissible I2**2t 40 30 10 Abdul Wahab Continous I2 5 10 8 36
  37. 37. g • Protective Relaying Actions GE Energy Services Simultaneous trip (Type I): – Trips turbine valves closed – Opens generator breaker – Opens field breaker • Generator trip (Type II): – Opens generator breaker – Opens field breaker – Leaves turbine running at near to rated speed • Breaker Trip (Type III) – Opens the generator breaker only • Sequential Trip – Trips the turbine first, the generator breaker second and then field breaker. 11/11/2001 Abdul Wahab 37
  38. 38. g Protective Relaying Actions Trip Type / Protective Relay Type I Type II Type III Sequential 87 S,G 64G S,G 24 S G GE Energy Services 59 S G 32 G S S = Steam Turbine Generator Set G = Gas Turbine Generator Set 11/11/2001 Abdul Wahab 38 40 S G 46 S G
  39. 39. g 11/11/2001 Breaker Trip Circuit Abdul Wahab GE Energy Services 39
  40. 40. g 11/11/2001 Breaker Trip Circuit Abdul Wahab GE Energy Services 40
  41. 41. g 11/11/2001 DGP Files Abdul Wahab GE Energy Services 41
  42. 42. g DGP Files GE Energy Services DGP Settings 11/11/2001 Abdul Wahab 42
  43. 43. Most Common Problems g GE Energy Services • Generally speaking, the most common problems found with the protective relaying systems are: – – – – – – Incorrect CT and PT polarities Improper type of CTs Wire connections Excessive burden load on the secondary of the CTs Damaged DGP cards Lack of DGP settings 11/11/2001 Abdul Wahab 43

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