generator static protection system gsx10 upgrade

Integrated Power Generation Services _______________________________________________________________________________________

_______________________________________________________________________________________ Copyright © 2011, ABB®. All Rights Reserved.

GSX-10 Static Protection System Upgrade

for

Combustion Turbine Generators

Protective Settings Report

ABB Inc. Integrated Power Generation Services Instrumentation, Control, & Electrical (ICE)

29801 Euclid Avenue Wickliffe, OH 44092

Tel: +1 440 585 3847 E-mail: [email protected]

Authored By: Muhanad N. Sharaf, P.E.

Date: Nov. 15, 2011

____________________________________________________________________________________________

i Integrated Power Generation Services

Preface

This document provides a background for migrating protective settings from the

obsolete GSX-10 static protection system into a new redundant protection system

composed of ABB Generator Protection Relay REG670 and Beckwith Generator

Protection Relay M-3425A. In addition to providing complete generator protection, ABB

REG670 also provides (i) phase overcurrent and ground fault protection for the 13.8KV

Busbar, (ii) ground fault protection for the 138/13.8KV Main Transformer, and (iii) thermal

and phase overcurrent protection for the 13.8/4.16KV Auxiliary Transformer.

Sincerely,

Muhanad N. Sharaf, P.E. Muhanad Sharaf Senior Electrical Engineer, ABB Instrumentation, Controls, & Electrical Services (ICE) 29801 Euclid Avenue Wickliffe, OH 44092 1832, USA Tel: (440) 585-3847 E-mail: [email protected]

____________________________________________________________________________________________

ii Integrated Power Generation Services

TABLE OF CONTENTS

I. PROTECTIVE RELAYING UPGRADE PROJECT DATA............................................................................................................... SECTION I

II. GENERATOR PROTECTION SYSTEM I (REG670)

GENERATOR PROTECTION SETTINGS CALCULATIONS............................... SECTION IIA

138/13.8KV MAIN TRANSFORMER SETTINGS CALCULATIONS...................... SECTION IIB

13.8KV BUSBAR PROTECTION SETTINGS CALCULATIONS........................... SECTION IIC

AUXILIARY TRANSFORMER PROTECTION SETTINGS CALCULATIONS.... SECTION IID

III. GENERATOR PROTECTION SYSTEM II (M-3425A)

GENERATOR PROTECTION SETTINGS CALCULATIONS............................... SECTION III


Combustion Turbine Generator System Data

SECTION I ABB, Inc. - Integrated Power Generation Services Page 1 of 3 Wickliffe, OH

SECTION I

System Data




A) Generator Nameplate Ratings: Rated Apparent Power (MVA): 119.2 Rated Active Power (MW): 101.32 Rated Power Factor: 0.85 Rated Voltage (KV): 13,800 Rated Current (Per-Phase Ampere): 4,987 A Number of Phases: 3 Rated Frequency (Hz): 60 Rated Speed (RPM): 3,600

B) Generator Impedance Values at Rated MVA and KV (Direct Axis):

Synchronous Unsaturated (Xd): 267 % Transient Saturated (X'd): 25.9 % Subtransient Saturated (X''d): 17.5 % Negative Sequence Unsaturated (X2): 22.5 Zero Sequence Unsaturated (X0): 9.7 % Short-Circuit Ratio (Kc): 0.406

C) Generator Time Constants: 3-Phase Subtransient Short Circuit (T"d): 0.017 Sec. 3-Phase Transient Short Circuit (T'd): 0.81 Sec. Open Circuit Time Constant (T'do): 7.57 Sec.

D) Generator Excitation Values:

No-Load Excitation Voltage (VFO): 58 V No-Load Excitation Current (IFO): 341 A Rated Excitation Voltage (VFN): 259 V Rated Excitation Current (IFN): 1,111 A

E) Generator Sensing Elements: CT ratio (6000/5): 1200 VT ratio (14400/120): 120 Nominal Secondary Current (4,987/1,200): 4.156 A Nominal Secondary Voltage (L-L) (13,800/120): 115 V F) Generator Unbalanced Current Capability:

Generator "K" Constant [I22t]: 10

Maximum Continuous I2: 8.00% G) Generator Breaker:

Opening Time (ms): 50 +/-3 Closing Time (ms): 60 +/-5




H) Generator Neutral Grounding:

Grounding Transformer Ratio (14,400/240): 60.0

I) Main (GSUT) Transformer: Base Power (MVA): 60 Impedance (%): 9.22 X/R Ratio: 32.57 Generator Side Base Voltage (KV): 13.8 System Side Base Voltage (KV): 138.0 Neutral CT ratio (600/5): 120

J) Auxiliary Transformer: Base Power (KVA): 3,750 Impedance (%): 4.9 X/R Ratio: 11.43 Generator Side Base Voltage (KV): 13.8 MV Switchgear Side Base Voltage (KV): 138.0

K) System: Base Voltage (KV): 138.0 Base Power (MVA): 100 Impedance (Per Unit): 0.022 3-Phase Short-Circuit (KA): 19.02 1-Phase Short-Circuit (KA): 22.5

Integrated Power Generation Services _______________________________________________________________________________________ Generator Protection System I (REG670)

Settings Calculations

SECTION IIA ABB, Inc. - Integrated Power Generation Services Page 1 of 17 Wickliffe, OH

SECTION IIA

GENERATOR PROTECTION SYSTEM I SETTINGS CALCULATIONS




Generator Overexcitation Function (ANSI Device 24)

A) Generator Data Generator Data: 119.2 MVAG 13.8 kV 0.85 pf

PT Ratio (PTR): 14,400:120 = 120:1,

(2) PT’s Configuration: Primary Connection: L-L , Secondary Connection: Open-∆

1 Per-Unit V/HZ: (13,800/120) / 60 = 1.92 (Rated Secondary Voltage / Rated Frequency)

B) Settings Calculations Relay Setting Philosophy: This is a new protection function that was not provided in the original protection system GSX10. This function will be blocked for VTFF and when Field CB is open. The generator is capable of continuous operation at 1.05 Per-Unit V/Hz. Therefore, a 1.074 Per-Unit V/HZ (2.063 V/HZ) alarm setting with a 5-second delay to avoid nuisance alarms is recommended. Corrective action should be taken for operation of the machine above 105% V/Hz. The characteristics of this protective function will be composed of IEEE Inverse-Time curve and a definite-time delay which will actuate for greater than or equal to 140% of Per-Unit V/HZ in 2 seconds. Basically, over-excitation protects against thermal damage. Therefore, a reset time is introduced in such a fashion as to allow cooling process to coordinate with the operating time of this protection function. For example, if an over-excitation condition reoccurs shortly after voltage and frequency have returned to their normal values, the time to trip will be shorter than it would be otherwise. As stated above, the maximum allowable continuous V/HZ seen by this protective element is:

[(13800 / 120) X 1.05] / 60 = 120.75 / 60 = 2.0125 = 2.01 (1.05 X 1 PU V/HZ)

A safety margin of 5.0%, however, will be applied to allow operation at the maximum permissible voltage while taking into consideration relay and PT errors. With that, the overall setting margin will be:

Relay Error = 0.5% PT Error = 2% Safety Margin = 5.0% (To allow operation at maximum permissible voltage) Total = 7.5%

Set Inverse-Time Pickup (Trip) = 2.01 X 1.075 = 2.16 V/HZ (112.5% of 1 PU V/HZ) To maintain coordination, the operating time should be above that of the generator V/HZ Limiter but below the generator V/HZ capability curve:

Set Inverse-Time Curve to IEEE Type with a Time Multiplier (K) = 3 Set Reset K Time (Cooling Time Constant) = 600 Seconds

Set Definite-Time Pickup (Trip) = 140% of Rated 1 PU V/HZ = (1.4 X 1.92) = 2.689 V/HZ Set Time Delay = 2.0 Second

Set Alarm Pickup = 95.5% of Inverse-Time Pickup = 2.063 V/HZ (107.4% of 1 PU V/HZ) Set Time Delay = 5.0 Seconds




Generator Undervoltage Function (ANSI Device 27A & 27T)


(2) PT’s Configuration: Primary Connection: L-L , Secondary Connection: Open-∆ PT Ratio (PTR): 14,400:120 = 120:1 , Generator Base Voltage (VGen_Base): 13,800 V

B) Settings Calculations

Relay Setting Philosophy: The 27 function was not provided in the original protection system GSX10. It is now applied to separate the generator from the utility system for a severe undervoltage condition caused by generator loss of field (LOF) event. The logic behind the threshold setting is to isolate the generator at the maximum voltage at which stability could be lost or system voltage collapse is imminent. This undervoltage threshold setting, however, requires a tremendous amount of dynamic analysis and, in the end, an ideal setting may not be achievable. As a practical alternative, the undervoltage drop-out setting is typically set to 80% of generator nominal voltage. However, given that there is an aggregate generation (multiple units) at this generating facility, the 27 function is recommended to trip at 85% of rated generator voltage (13.8KV) to ensure function drop-out. The function is time delayed in order to coordinate with (i) Voltage-Controlled Overcurrent function (51V) and (ii) Loss-of-Field (LOF) protection outer element (See settings for LOF function element 40-2). Alarm setting will be at 90% of rated generator voltage with a shorter time delay. This function will be blocked for Voltage Transformer Fuse Failure (VTFF), when either Generator or Field CB is open, and when the generator is in De-Energized Mode (See Instantaneous Overcurrent Function 50DE). Set 27T Trip Pickup = 85% of VGen_Base = 11,730 V (Primary) Set 27T Trip Time Delay = 1.5 Sec Set 27T Trip Curve Characteristic = Definite Time Set 27A Alarm Curve Characteristic = Definite Time Set 27A Alarm Pickup = 90% of VGen_Base = 12,420 V (Primary) Set 27A Alarm Time Delay = 0.5 Sec (To avoid nuisance alarms due to system faults) This function will be blocked for Voltage Transformer Fuse Failure (VTFF), and when either Generator or Field CB is open. Further, it is conditioned such that it is only enabled when generator relay phase current is above an appreciable value. This criterion is intended to guard against false operation of Breaker Failure Function (50BF) when the generator load current is virtually zero and the Undervoltage (U/V) Function has dropped out. Basically, an instantaneous element (50) is used to condition U/V Function such that when generator phase current is below 2% of IGen_Base (99.74A Primary), the U/V Function is prevented from operating regardless of the status of Generator or Field CB. Without this criterion, 50BF Function will consequently operate falsely if both Generator and Field CB’s are closed during maintenance work where the generator is de-energized and isolated from the grid.




Generator Reverse Power Function (ANSI Devices 32-1 & 32-2)

A) Generator Data Generator Base MVA Rating: 119.2 MVAG

Generator Full-Load (Base) Current (IGen_Base): 4,987 Amperes

CT Ratio (CTR): 6,000:5 = 1,200:1

PT Ratio (PTR): 14,400:120 = 120:1

Relay Full-Load (Base) Current (IRel_Base): (4,987) / (1,200) = 4.156 Secondary Amperes

Or, 0.83 pu On CT Rating Base

B) Settings Calculations Relay Setting Philosophy: Gas turbines require 10-50% of rated power to motor depending on design. This function is blocked for voltage transformer fuse failure (VTFF). Since the Generator CB set of CT’s used for this function does not sense the current introduced by the Static Frequency Starter (SFC), “Starting Sequence On” signal is not used for blocking as it was done in the original GSX10 system. The settings for this function have been transferred from the original protection system GSX10, which uses a single-phase Definite-Time Power relay of type RE-91. Two relays of this type were used to provide two-stage reverse power protection with following ratings and settings:

1. RE-91 Nominal Ratings: IN = 5A, UN = 100V, PN = 5 x 100 = 500 W (Relay Base)

2. Stage I Settings: P: 0.001 x 70 x 500 = 35 W, T: 0.1 x 2 = 0.2 Seconds

3. Stage II Settings: P: 0.001 x 15 x 500 = 7.5 W, T: 0.1 x 50 = 5 Seconds

The above settings were transferred as follows: First, it should be noted that since each single-phase RE-91 relay has nominal values of 100V and 5A corresponding to primary values of 13.8KV and 6000A respectively, the actual relay per-phase nominal power in primary value is:

13800/√3 x 6000 = 47.8 MW (And not 13800 x 6000A = 82.8 MW) For Stage I, the Per-Phase Power (Primary) = (35/500) x 47.8 = 3.346 MW, but REG670 is designed to be calibrated for 3-phase reverse power. With that, the setting should be:

3.346 x 3 = 10.04 MW

Set 32-1 (Overpower) Pickup = 10.04 / 119.2 = 0.084 PU (8.4 % of Generator Base MVA Rating) Set 32-1 (Overpower) Delay = 0.2 Sec.

For Stage II, the Per-Phase Power (Primary) = (7.5/500) x 47.8 = 0.717 MW, but REG670 is designed to be calibrated for 3-phase reverse power. With that, the setting should be:

0.717 x 3 = 2.15 MW

Set 32-2 (Overpower) Pickup = 2.15 / 119.2 = 0.018 PU (1.8 % of Generator Base MVA Rating) Set 32-2 (Overpower) Delay = 5 Sec.




Generator Loss of Field (LOF) Function (ANSI Devices 40-1 & 40-2)


ZBase (Base Impedance) = (Gen_kV2 /MVAG ) = 1.6 Ω (Primary) Synchronous Unsaturated (Xd): 267 % of ZBase Transient Saturated (X'd): 25.9 % of ZBase

CT Ratio (CTR): 6,000:5 = 1,200:1

PT Ratio (PTR): 14,400:120 = 120:1, Generator Base Voltage (VGen_Base): 13,800 V

CTR/ PTR: 10.0

Relay Full-Load (Base) Current (IRel_Base): 4,987 Amperes (4.156A Secondary)

Or, 0.83 pu CT Rating Base

B) Settings Calculations Relay Setting Philosophy: During loss of excitation, this function will detect Var flow from the system into the generator. The apparent impedance measured by the LOF function as the generator slips poles each slip cycle will vary between X'd and X'q if, at time of LOF event, the generator was operating at full load and between Xd and Xq if it was operating at light load. To account for all those apparent impedances indicative of a LOF event, the LOF function has been conventionally set to have its impedance characteristics encompass all reactance values between (-0.5X'd) and [(-Xd) + (-0.5X'd)] along the negative X-axis on the R-X Impedance diagram. In order to strike a balance between fast tripping for severe cases of LOF and preventing LOF function from operation for stable swings, a scheme with two distance (Mho) elements is used. The first distance element (40-1) is set to operate with minimal delay for severe cases of LOF. This minimal delay is introduced to provide security against operation in case a stable swing did encroach the 40-1 zone which is intended to be set away from the trajectory impedance paths (loci) of most, if not all, stable swings. The other distance element (40-2) is intended to cover a larger zone including the first distance element zone. Since most stable swings and less severe cases (light loading) of LOF do reach into this larger zone, a much longer time delay is used. However, this time delay is conditioned with an Undervoltage (U/V) element where it is cut in half if the terminal voltage drops below 85%. Such a drop in terminal voltage during an LOF event indicates the system is weak and its stability could be lost as a result of the large Var drain imposed by the loss of field. On the other hand, if the U/V element did not drop out, the power system is strong enough to supply the Var requirements of the failed unit without significant voltage degradation. Note that U/V drop-out setting is higher than the usual setting of 80% as it is assumed this generating facility will have more than one unit operating most of the time. Without this higher setting, the boosted Var generation from the other healthy unit(s) could prevent the UV element from dropping-out. This function is blocked for voltage transformer fuse failure (VTFF).




Generator Loss of Field (LOF) Function (ANSI Devices 40-1 & 40-2) (Continued)

The original protection system GSX10 provided this function using a minimum reactance (single mho element) relay type ZPX-103a along with a time integrator type SGX115. The original ratings and settings are as follows:

1. ZPX-103a Rated Current & Voltage: IN = 5A (Relay Base), VN = 100V (Relay Base)

2. Pick-Up Point A (or Xd Implemented in terms of a1 (%) ): a1 (%) = 25%.

3. Drop-Out Point B (or 0.5X'd implemented in terms of a2 (%) ): a2 (%) = 56%. 4. Time Delay: t = 2 Seconds 5. Time Integrator’s Timers: ta (On-Delay) = 6 Seconds, tr (Off-Delay) = 3 Seconds

Note: In the Minimum Reactance Relay (ZPX-103a) literature and under Principle, it is stated that time integrator (SGX-115) can be used in conjunction with ZPX-103a to detect loss of synchronism (out-of-step) when excitation is still intact. The literature explains this detection is possible because the impedance vector during an out-of-step event oscillates in and out of the pick-up circle; where in the case of a LOF event, the impedance vector lies continuously within the pick-up circle. In contrast to this claim in the literature, the impedance vector for certain LOF events can actually exit and reenter the relay trip characteristic (pick-up circle) each slip cycle. Nonetheless, it is believed that SGX-115 was used to prevent ZPX-103a from failure to operate in the event its set time delay (which was 2 Seconds) exceeded the time it took for the LOF impedance locus to enter and exit ZPX-103a trip pick-up circle each slip cycle. In such case, the Minimum Reactance Relay (ZPX-103a) would have failed to operate if no time integrator was used to turn this periodic intermittent pick-up signal into a continuous one. The new scheme is set as follows: First, Xd and X'd need to be converted from per unit on MVAG and kV bases to secondary ohms: ZSEC = ZPRIM x (CTR/ PTR) ZBASE_SEC (Relay Base Impedance) = (Gen_kV2 /MVAG ) x ( CTR/ PTR ) = 16.0 Ω (Secondary) Xd_SEC = ( Xd x ZBASE_SEC ) = 42.66 Ω (Secondary) X'd_SEC = ( X'd x ZBASE_SEC ) = 4.14 Ω (Secondary)

1 PU-Relay = (1.0 PU x ZBASE_SEC ) = 16.0 Ω (Secondary)

Set 40-1 (Inner element): Diameter = 1 PU-Relay = 16.0 Ω (Secondary)

Offset = - ( 0.5 x X'd_SEC ) = - 2.07 Ω (Secondary) Time Delay = 0.4 Seconds

Set 40-2 (Outer element):

Diameter = Xd_SEC = 42.66 Ω (Secondary) Offset = - ( 0.5 x X'd_SEC ) = - 2.07 Ω (Secondary) Undervoltage Element Drop-Out = 85% of VGen_Base = 11,730 V

Time Delay without U/V Element Drop-Out = 2.0 Seconds Time Delay with U/V Element Drop-Out = 1.0 Second




Generator Negative Sequence Overcurrent Function (ANSI Device 46A & 46T)


CT Ratio (CTR): 6,000:5 = 1,200:1




Continuous Unbalanced Current (I2C) Capability: 8%

I22 t Capability Constant (KC): 10

B) Settings Calculations Relay Setting Philosophy: The 46A (Alarm) settings are calculated slightly below the continuous limit of 8%. The 46T (Trip) settings are calculated to operate when the machine is operating at its full negative sequence current capability to ensure tripping before damage to the stator occurs due to overheating. The original protection system GSX10 provided this function using a two-stage definite-time negative sequence relay type IPX-132b with the following rating and settings:

1. IPX-132b Rated Current: IN = 5A (Relay Base)

2. 1st Stage Pickup & Time Delay Settings: I = 7% of IN (Equivalent to 8% of IFL), T = 5 Sec.

3. 2nd Stage Pickup & Time Delay Settings: I = 20% of IN (Equivalent to 24% of IFL), T = 5 Sec.

The new protective device, however, provides this function with the capability to allow the user to pick a time-current curve that matches the machine I2

2 t characteristic. The relay’s time dial (K-Value) setting must be set such as to allow for accumulation of additional I2

2t as a result of the current decay after the generator and field breakers have been tripped. With that, the K value for 46T element will be set to 7 in the relay. The trip and alarm settings are as follows:

Set 46T Inverse-Time Pickup: I2C = 8.0% Set 46T K-Value: 7 Set 46T Min Operate Time: 0.0 Seconds Set 46T Max Operate Time: 1000 Seconds Set Reset Multiplier (K): 20

Set 46A Pickup Setting: 0.75 x I2C = 6.0% Set 46A K-Value: 10 Set 46A Delay: 3 Seconds




Generator Breaker Failure Function (ANSI Device 50BF)



Relay Full-Load (Base) Current (IRel_Base): (4,987) / (1,200) = 4.156 Secondary Amperes Or, 0.83 pu On CT Rating Base

Generator CB Opening Time: 50 +/-3 ms

B) Settings Calculations Relay Setting Philosophy: This is a new protection function intended to guard against failure of the Generator CB to interrupt a fault. This function will be initiated any time Generator CB trip output contacts (AC and DC Trip Coils) are actuated by a protective element within the relay. Breaker Failure function operates if any phase current persists in excess of 10% of IFL or if Generator CB status has not changed to “Open” in 9 cycles or less since the function timer was first initiated. The expected interrupting time (Opening Time + Arcing Time) for this Generator CB is around 5 Cycles. With a safety margin of 4 Cycles, the time delay (timer set time) is set to 9 Cycles. Set Phase Overcurrent (50BF) Threshold: 10% of IGen_Base = 498.7A (Primary) Set Breaker Failure Time Delay (Timer): 9 Cycles




Generator Inadvertent Energization Function (ANSI Device 50/27 or 50AE)




PT Ratio (PTR): 14,400:120 = 120:1

Generator Base Voltage (VGen_Base): 13.8KV

B) Settings Calculations Relay Setting Philosophy: This is a new protection function intended to detect an erroneous closure of the Generator CB and minimize the possibility of any damage. Moreover, Inadvertent Energization refers to an energization from standstill without field excitation. This function is blocked for voltage transformer fuse failure (VTFF). Set Undervoltage (27) Drop-Out (Arming the Function):: 85% of VGen_Base = 11,730 V Set Undervoltage (27) Drop-Out Time Delay (Time to Arm): 2 Seconds Set Overcurrent (50) Pickup: 12% of IGen_Base = 598.4 A Set Overvoltage (59) Pickup (Disarming the Function): 50% of VGen_Base = 6.9KV Set Overvoltage (59) Pickup Time Delay (Time to Disarm): 0.25 Seconds




Static Frequency Converter Backup Overcurrent Function (50SFC)




B) Settings Calculations Relay Setting Philosophy: This is a new protection function intended to provide backup overcurrent protection to Static Frequency Converter (SFC). At unit start-up, SFC is used to motor the generator to a certain speed at which the gas turbine is capable on its own to take over in further driving the generator to its rated synchronous speed (3600 RPM). During generator motoring by the SFC, only the neutral-end CT’s will sense the SFC current which could be 4% to 10% of the generator base current. Set Overcurrent (50SFC) Pickup: 25% of IGen_Base = 1,247 A (Primary) This function is only enabled when Field CB is open.




Generator Overcurrent (Voltage-Controlled) Function (ANSI Device 51V)

A) System, Main Transformer, and Generator Impedance Data System: 138 KVS 22,582 A, 1∅ -G Fault @ Angle -88.5°

19,409 A, 3∅ -G Fault @ Angle -88.6°

Main Transformer (GSUT): ZGSU = 9.22% @ 60 MVA

Generator Data: 119.2 MVAG 13.8 kV 0.85 pf

Synchronous Unsaturated (Xd): 267 %, Rated Excitation Current (IFN): 1111 A Transient Saturated (X'd): 25.9 %, T"d: 0.017 Sec. Subtransient Saturated (X''d): 17.5 %, T'd: 0.81 Sec.

Generator Base Current (IGen_Base): 4,987 A, Relay Base Current (IRel_Base): 4.156A Or, 0.83 pu On CT Rating Base

PT Ratio (PTR): 14,400:120 = 120:1 , Generator Base Voltage (VGen_Base): 13,800 V

B) Settings Calculations Relay Setting Philosophy: This function is applied to backup transmission line relaying.

This function is blocked for voltage transformer fuse failure (VTFF).

The original protection system GSX10 provided this function using a voltage-controlled relay type IUX-159 with the following rating and settings:

1. IUX-159 Rated Current & Voltage: IN = 5A (Relay Base), VN = 100V (Relay Base)

2. Overcurrent (51) Pickup & Time Delay Settings: I = 0.2% of IN (Equivalent to 24% of IFL), T = 1 Sec

3. Instantaneous Overcurrent (50) Pickup & Time Delay Settings: I = ∞ (Instantaneous trip ineffective)

4. Undervoltage Pickup Setting: V = 70% of VN = 70% of Generator Base Voltage The generator-main transformer unit including the 138KV high-voltage short-circuit data was modeled in an engineering software application (Easypower) using the above listed data. The settings provided by the original protection system were checked against the generator decrement curve, fault currents at the high side of GSUT, and at the far end of the high-voltage impedance. The settings were found to be proper; however, the Undervoltage drop-out setting should be increased to ensure drop-out for a phase-to-ground fault at the far end of the simulated system high-voltage impedance. Set Definite-Time Overcurrent (51) Pickup: 125% of IGen_Base = 1.25 X 4,987 A = 6,233.75 A Set Undervoltage (27) Pickup (Used for 51V): 75% of VGen_Base = 10,350 V Set Voltage-Controlled Overcurrent (51V) Pickup: 20% of (51) Pickup (0.2 X 1.25 X 4,987 A) Set Time Delay for Both Overcurrent (51) & Voltage-Controlled Overcurrent (51V): 1.0 Second




Generator Overvoltage Function (ANSI Device 59)


PT Ratio (PTR): 14,400:120 = 120:1,


Generator Voltage (VGEN_Base): 13,800 V


Relay Setting Philosophy: The 59 function should be set with a safe margin below the overvoltage capability of the generator. The time delay should be set such as to coordinate with the V/Hz Limiter and 24 protection function. Further, this function is blocked for Voltage Transformer Fuse Failure (VTFF) and when Field CB is open. The original protection system GSX10 provided this function using voltage definite-time relay type UT-91 with the following rating and settings:

1. UT-91 Rated Voltage: UN = 100V (Relay Base) = 13.8KV (Primary Rated Voltage)

2. Pickup Setting: 120% of UN = 16.56KV (Primary)

3. Time Delay: 2.0 Seconds

The original definite-time pickup setting along with its associated time delay will not provide complete protection between 105% of generator rated voltage, which is the maximum allowable continuous generator voltage, and its pickup setting (120% of rated voltage). Nor, will it provide adequate protection for any voltage excursions beyond that setting. The new recommended settings are as follows: The limiting Voltage = 105% of VGEN_Vbase = (1.05 X 13800) / 120 = 120.75 V The overall setting margin: Relay Error = 0.5% PT Error = 2.0% Safety Margin = 2.5% (To allow operation at maximum permissible voltage) Total = 5.0%

Set Inverse-Time (Type B) Pickup (Trip) = 110% of VGEN_Vbase = 15,180 V Set Time Multiplier (K) = 0.4

Set Instantaneous-Time Pickup (Trip) = 140% of VGEN_Vbase = 19,320 V

Alarm is initiated once the above Inverse-Time Overvoltage element is picked up.




Generator 100% Stator Ground Fault Function (ANSI Device 59THD)


PT Ratio (PTR): [3 X (14.4KV / √3)] : [3 X (120V/ √3)] = 24941.5 : 207.85 = 120:1,

(3) PT’s Configuration: Primary Connection: L-G , Secondary Connection: Broken-∆

Note: A ballast resistor (85 Ω ) was added across the secondary broken-∆ circuit to mitigate the possibility of ferroresonance.


Relay Setting Philosophy: This is a new protection function intended to provide complete ground fault protection for stator winding. Conventional protection lacks the capability to detect a ground fault in the last 5% of stator winding toward the neutral end. The basic principle of this function is based on the 3rd harmonic voltage imbalance that results when a ground fault occurs at any point on the stator winding except at a null point which is determined where the generated 3rd harmonic voltage is divided between neutral and terminal shunt impedances (mostly capacitive). This explains why conventional protection is still applied in addition to this new protection function which relies solely on the imbalance of 3rd harmonic voltage generated and distributed across the stator winding. A stator ground fault near the neutral end causes the 3rd harmonic terminal voltage to rise by the same magnitude the 3rd harmonic neutral voltage drops. Since the generated 3rd harmonic voltage is a function of machine design and also loading, a 3rd harmonic voltage vs. loading profile had to be first established so that a proper parameter (Beta) can be applied, as explained below. This was accomplished during commissioning of this new protection system by capturing 3rd harmonic-related measurements as the generator load increased from low to almost rated MVA power output. Those captured readings can be found in the final Test Report, and one can easily observe that 3rd harmonic neutral voltage was consistently around 141% of the difference magnitude between 3rd harmonic neutral and terminal voltages. The function operates when the difference magnitude is larger than the 3rd harmonic neutral voltage. As a matter of security, the relay logic allows the user to apply a safety factor to 3rd harmonic neutral voltage by setting Beta to a certain multiplier. Mathematically, the operating criterion is expressed as follows: ⇾ ⇾ ⇾

| V3N + V3T | ≥ Beta|V3N|

Set Beta: 1.5 Set 59THD Time Delay: 0.5 Seconds

The relay can compensate for the isolated shunt capacitive impedance when Generator CB is open. However, the relay generator-terminal potential source is located on the Main Transformer side of the Generator CB. This will cause the function 59THD element to fail to operate properly; and therefore, the function 3rd harmonic-based element (59THD) is blocked when Generator CB is open. For the fundamental-frequency neutral overvoltage protection element parameters built in this function, refer to 59GN/64G Function settings.




Generator Stator Ground Fault Function (ANSI Device 59GN/64G)

B) Generator Data Generator Data: 119.2 MVAG 13.8 kV 0.85 pf

Neutral Grounding Transformer Ratio (NGTR): 14,400:240 = 60:1

Neutral Grounding Transformer Secondary Resistor (ZRES): 0.44 Ω


Relay Setting Philosophy: 59GN/64G pickup is set as sensitive as possible to provide maximum stator ground fault coverage. The settings for this function have been transferred from the original protection system GSX10, which uses stator earth-fault relay type UBX-117 with the following rating and settings:

1. UBX-117 Rated Voltage: UN = 100V (Relay Base)

2. Overvoltage Pickup Setting: 5% of UN

3. Relay Operation Time Delay: 0.5 Seconds

The above settings were transferred as follows:

First, a ground fault at the line terminal side of generator (full winding voltage) is limited to 5.03A (Primary) as calculated in the following equation:

IGnd_Fault_Prim = VL-N / (ZRES * NGTR

2) = 5.03 Amps (Where VL-N = 13.8KV / √3 )

(Note: It is assumed the Neutral Grounding Transformer (NGT) secondary resistor was originally chosen such that the ground fault current passing through the primary winding of this NGT is equal to or greater than the charging capacitive current created when a full-winding voltage (13.8KV / √3) is imposed onto ground.)

Neural Grounding Transformer Secondary Voltage at IGnd_Fault_Prim:

VGnd_Fault_Sec = IGnd_Fault_Prim * NGTR * ZRES = 132.79 Volts

Set 59GN/64G Pickup: V59N_Sec = 5.3 Volts (4% of VGnd_Fault_Sec)

Stator Ground Fault Coverage = [1- (V59N_Sec / VGnd_Fault_Sec)] X 100 = 96%

Set 59GN/64G Time Delay: 0.5 Seconds




Potential Transformer Fuse Loss Detection Function (ANSI Device 60FL) A) Generator Data

Generator Data: 119.2 MVAG VBase_Pri = 13.8 kV 0.85 pf



Or, 0.83 pu On CT Rating Base PT Ratio (PTR): 14,400:120 = 120:1, VBase_Sec = 115 V

No-Fault Sequence Magnitudes: IPos_Seq = 4,987 A, INeg_Seq = 0 A, IZero_Seq = 0 A

VPos_Seq = 7,967.4 V,VNeg_Seq = 0 A, VZero_Seq = 0 A

B) Settings Calculations Relay Setting Philosophy: This is a new function intended to detect loss of phase-potential feed into the relay due to voltage transformer fuse. Fuse failure detection is based on the general principle that if measured values of negative and zero sequence voltages are high while their respective currents are very low, then this is indicative of a fuse-loss condition. Once detected, all voltage-dependent protection elements are blocked to prevent misoperation.

Since the generator is high-impedance grounded, only negative-sequence quantities are compared to detect loss of one or two fuses. Failure of all 3 fuses is detected only if all 3 phase voltages dropped below a certain voltage setting (VSealIn) and after negative-sequence settings had been picked up for 5 seconds.

Set Negative-Sequence Overvoltage (3U2): 30% of VBase_Pri

Set Negative-Sequence Undercurrent (3I2<): 10% of IGen_Base

Set Seal-In Undervoltage (VSealIn<): 70% of VBase_Pri

In addition to comparing negative-sequence values, the function also provides other technique where changes in voltages relative to currents are compared and a fuse loss is detected if a phase voltage drops rapidly while the respective phase current magnitude exhibits a little or no change. This feature is termed Delta Current and Delta Voltage (DU/DI) Detection.

Set Delta-Voltage Increase (DU>): 60% of VBase_Pri

Set Delta-Current Decrease (DI<): 15% of IGen_Base

To prevent false operation, the (DU/DI) Detection is conditioned such that certain criteria must be met before a loss of fuse is declared. They are as follows:

Set Phase Overvoltage (UPh>): 70% of VBase_Pri

Set Phase Overcurrent (IPh>): 10% of IGen_Base

Note: For a simplified graphical representation of Fuse Loss (60FL) Function Logic, see Figure 239 in the REG670 Technical Reference Manual (September 2011 Issue).




Generator Underfrequency Function (ANSI Device 81U) A) Generator Data


Nominal Frequency: 60 Hz

PT Ratio (PTR): 14,400:120 = 120:1


Relay Setting Philosophy: Settings will back up the turbine under-speed protection of the unit combustion gas turbine. The settings implemented in REG670 reflect previous settings used for this function. The exact settings have been transferred from the original protection system GSX10, which had a four-stage Frequency Protection relay type FC-95 with the following settings:

1. Stage I Settings: I f = 58.2 Hz, t = 0 Sec,

Blocked When: Gen CB is Open, Used For: Alarm Only.

2. Stage II Settings: II f = 57.5 Hz, t = 0 Sec, Blocked When: Gen CB is Open, Used For: Alarm Only.

3. Stage III Settings: III f = 57.0 Hz, t = 0 Sec,

Blocked When: Gen CB is Open, Used For: Trip Gen Breaker.

4. Stage IV Settings: IV f = 54.0 Hz, t = 0 Sec, Blocked When: Field CB is Open, Used For: Trip Unit.

In addition to implementing the above settings along with the blocking logic in this new Generator Protection System I, all four stages are also blocked for Voltage Transformer Fuse Failure (VTFF).




Generator Phase Differential Function (ANSI Devices 87G-1, 87G-2) A) Generator Data


CT Ratio (CTR): 6,000:5 = 1,200:1 ANSI CT C-Rating: C400 Generator Full-Load (Base) Current (IGen_Base): 4,987 Amperes



B) Settings Calculations Relay Setting Philosophy: The 87G function primarily provides phase fault protection for the generator and should be set as sensitive as possible, yet not trip for CT errors that can occur during an external fault. The original protection system GSX10 provided this function using a Three-Phase Biased Differential relay type DT-92 with the following rating and settings:

1. DT-92 Rated Current: IN = 5A (Relay Base) 2. Ratio Correction for Terminal and Neutral CT’s: IN / IFL_Rel = 1.2 (1L = 1R = II, 2L = 2R = I) 3. Phase Angle Correction Between Terminal and Neutral CT’s: T1 = T2 = 0 4. Sensitivity and Pick-Up Ratio Settings: g = I (20%) , v = 50% 5. Section I [0 To 5A]: Operate Current = 1A 6. Section II [5A To 15A]: Operate Current = (0.5 x IH) - 1.5 7. Section III [15A To 27.5A]: Operate Current = (1.5 x IH) – 16.5

Given that both neutral and terminal end CT’s have the same ANSI C-Rating, C400, the error current should be minimal but not necessarily non-existent as there is always design tolerances even for CT’s made by the same manufacturer. However, the overall burdens for those CT’s are not equal as the terminal side CT’s are located at the Generator CB Switchgear, which is a good distance away from the generator itself. This can cause differing degrees of saturation in the neutral and terminal side CT’s during a high asymmetrical fault current and contribute to a larger error current. With that and to provide adequate sensitivity yet avoid misoperation, the new settings are as follows:

⇾ ⇾ ⇾ ⇾ With, Restraint Current: IH = (I1 + I2) / 2, Operate Current: I∆ = I1 - I2

Set 87G Minimum Pick-Up (IdMin): 0.25 A (0.06 pu) Set 87G-1 (EndSection1) Break Point: 1.67 A (0.4 pu) Set 87G-1 Percent Slope (SlopeSection2): 15 % Set 87G-2 (EndSection2) Break Point: 8.3 A (2.0 pu) Set 87G-2 Percent Slope (SlopeSection3): 80 %

Set 87G Unrestrained Pickup (IdUnre): 37.4A (9.0 pu) Note: For a graphical representation, see Operate-Restraint Curve (Figure 52) in the REG670 Technical Reference Manual (September 2011 Issue).



SECTION IIB ABB, Inc. - Integrated Power Generation Services Page 1 of 2 Wickliffe, OH

SECTION IIB

138/13.8KV MAIN TRANSFORMER PROTECTION SETTINGS CALCULATIONS



SECTION IIB ABB, Inc. - Integrated Power Generation Services Page 2 of 2 Wickliffe, OH

Main Transformer (GSUT) Ground Fault Function (ANSI Device 51N/64T)

A) Data Main Transformer (GSUT) Data: 60 MVABase , 138 kVPri , 13.8 kVSec

IGSUT_Base = [(60 MVA) / (√3 X 138KV)] = 251A (Primary),

Zt = 9.22% , X/R = 32.5702, Neutral CT Ratio (CTR): 600:5 = 120:1

System Ground Fault Data: 22,582 A, 1∅ -G Fault @ 138 kVsys , Angle -88.5°

B) Settings Calculations Relay Setting Philosophy: 59N/64T pickup is set to provide ground fault protection for the Main Transformer caused by a ground fault on the 138KV system. The settings for this function have been transferred from the original protection system GSX10, which uses a single-phase definite-time overcurrent relay type IBX-164 with the following rating and settings:

1. IBX-164 Rated Current: IN = 5A (Relay Base)

2. Overcurrent Pickup Setting: IE = (K1) X (K2) X (IN)= 1A (Where K1 = 0.2 and K2 = 1)

3. Overcurrent Time Delay: tan = C(t1 + t2) = 2 Seconds (Where C = 1, t1 = 2 and t2 = 0)


Set 59N/64T Pickup (ISET): 47.8% of IGSUT_Base = 120 A (Primary)

Note that GSUT Neutral CT current at ISET is: (0.478 X IGSUT_Base) / 120 = 1A (Secondary)

Set 59N/64T Time Delay: 2 Seconds



SECTION IIC ABB, Inc. - Integrated Power Generation Services Page 1 of 3 Wickliffe, OH

SECTION IIC

13.8KV BUSBAR PROTECTION SETTINGS CALCULATIONS




Generator Busbar Ground Fault Function (ANSI Device 59N/64B)

A) Generator Busbar Data Generator Busbar Data: 13.8 kV Iso-Phase Bus Duct

PT Ratio (PTR): [3 X (14.4KV / √3)] : [3 X (120V/ √3)] = 24,941.5 : 207.85 = 120:1,

(3) PT’s Configuration: Primary Connection: L-G , Secondary Connection: Broken-∆

PT’s Accuracy Class & Standard Burden: 0.6Y (Y Refers to 75VA Burden)

B) Settings Calculations Relay Setting Philosophy: 59GN/64G pickup is set to provide ground fault protection for the ungrounded 13.8KV Busbar when the generator breaker (generator offline) is open and the Main Transformer (GSUT 09-G-X-801) is backfeeding the 4.16KV auxiliary system. This function is blocked when Generator CB is closed. This is required to avoid operation of this function while the generator is online and the ground fault is any point downstream from the Generator CB including the stator windings.

To mitigate the possibility of ferroresonance, a ballast resistor of 85Ω is added across the secondary open delta circuit. Since a ground fault will impose about 200V across this resistor when the primary operating voltage is 13.8KV, the PT’s will be subjected to an excessive amount of thermal overload (200%). With that, all power sources contributing to this ground fault must be interrupted to avoid damage to those PT’s. Unit 09 and parallel Unit 10 along with all associated HV (138KV) breakers will be tripped in 0.875 Seconds after inception of a ground fault. This time delay is required to coordinate with generator stator ground fault protection and also to avoid operation for system ground faults.

The settings for this function have been transferred from the original protection system GSX10, which uses Earth-Fault relay type UBX-117 with the following rating and settings:


2. Pickup Setting: 6% of UN = 12V



A ground fault occurring while the Busbar operating voltage is at 13.8KV would impose a 3 times line-to-neutral voltage across the PT’s secondary open-delta circuit. Thus,

VL_N_Sec = (13800 / √3) / 120 = 66.4 V

VGnd_Fault_Sec = 3 X VL_N_Sec = 199.2V ([13800 / √3) X 3] = 23.9KV is the Primary Fault Voltage)

Set 59N/64B Pickup (VSET): 11.95 Volts

(Note that VSET is 6% of VGnd_Fault_Sec , or 18% of VL_N_Sec which is used by the relay)

Set 59N/64B Time Delay: 0.875 Seconds




13.8KV BusBar Phase Differential Function (ANSI Devices 87B-1, 87B-2) A) BusBar Differential Circuit Data


Main Transformer (GSUT): 60 MVABASE , 138 kVpri , 13.8 kVsec , 9.22% Zt , X/R 32.5702

Auxiliary Transformer Data: 3,750 KVABASE , 13.8 kVpri , 4.16Y/2.4 kVsec , 4.9% Zt , X/R 11.4271

Equipment CT’s Ratio (CTR) and ANSI C-Rating: 6,000:5 = 1,200:1 , ANSI C-Rating: C400




B) Settings Calculations Relay Setting Philosophy: The 87B function primarily provides phase fault protection for the 13.8KV Busbar and should be set as sensitive as possible, yet not trip for CT errors that can occur during an external fault. The original protection system GSX10 provided this function using a Three-Phase Biased Differential relay type DT-93 with the following rating and settings:

1. DT-93 Rated Current and Frequency: IN = 5A (Relay Base) , Frequency = 60HZ 2. Ratio Compensation Parameters: a = 52 , Ma = 2 , v = 0 3. Basic Sensitivity Setting: g = 2 X 0.1 X IN = 1 (20% of IN) 4. Limiting Value of Integrated KL Impulse & Time Step Multiplier: TM = 0.4 X T , Mt = 1 5. Section I [0 To 2 X IN]: Operate Current = 1A 6. Section II [Above 10A]: Operate Current ≥ IH - 1.0 7. Time Step Characteristics: SKL = BL , ST = A

Since all equipment CT’s have the same ratio and ANSI C-rating, the error current should be minimal but not necessarily non-existent as there is always design tolerances even for CT’s made by the same manufacturer. Further, depending on the physical locations of those pieces of equipment, the burdens for the multiple CT circuits might be quite different. With unequal burdens due to different cable routings, varying degrees of saturation in those CT’s during a high asymmetrical fault current would cause a larger error current. With that and to provide adequate sensitivity yet avoid misoperation, the new settings are as follows:

⇾⇾ ⇾ ⇾ Given that Restraint Current is: IH = (I1 + I2) / 2 , and Operate Current is: I∆ = I1 - I2

Set 87B Minimum Pick-Up (IdMin): 0.3 A (0.07 pu) Set 87B-1 (EndSection1) Break Point: 4.156 A (1.0 pu) Set 87B-1 Percent Slope (SlopeSection2): 20 % Set 87B-2 (EndSection2) Break Point: 12.47 A (3.0 pu) Set 87B-2 Percent Slope (SlopeSection3): 85 %

Set 87B Unrestrained Pickup (IdUnre): 37.4A (9.0 pu) Note: For a graphical representation, see Operate-Restraint Curve (Figure 52) in the REG670 Technical Reference Manual (September 2011 Issue).



SECTION IID ABB, Inc. - Integrated Power Generation Services Page 1 of 2 Wickliffe, OH

SECTION IID

13.8/4.16KV AUXILIARY TRANSFORMER PROTECTION SETTINGS CALCULATIONS



SECTION IID ABB, Inc. - Integrated Power Generation Services Page 2 of 2 Wickliffe, OH

Auxiliary Transformer Overload and Overcurrent Functions (ANSI Devices 49/51-1,-2)

A) Data Aux Transformer Data: 3750 KVABase (@ 55° C Rise), 13.8 kVPri , 4.16Y/2.4 kVsec , 4.9% Zt , X/R 11.4271

LV-Side Fault Data: 9,885 A, 3∅ FaultWith_Gen @ Angle -85.3°, 9,367 A, 3∅ FaultWithout_Gen @ Angle -85.4°

HV-Side CT Ratio (CTR): 400:5 = 80:1

B) Settings Calculations Relay Setting Philosophy: Thermal overload protection is applied to prevent from excessive overheating which over time could lead to premature insulation aging and, in severe cases, to internal faults as a result of insulation failure. Also, a two-step Phase Time-Overcurrent protection is applied so that phase faults inside the transformer and/or at the 4.16KV Main Bus can be detected and interrupted using a time-delay Overcurrent element (51-2). And, a slower time-delay Overcurrent element (51-1) can act as backup protection if primary relaying for faults downstream from the 4.16KV Main Bus failed to operate. The original protection system GSX10 provided these functions using a Universal Phase and Earth Fault relay type MC-91 with the following ratings and settings:

1. MC-91 Rated and Basic Currents: IN = 5A (Relay Base), IE = 0.4 X IN X (400/5) = 160 A 2. Thermal Overload Alarm and Trip Settings: Alarm @ 90%, Trip @ 110% 3. Heating and Cooling Time Constants: Heating τ↑ = 60 Minutes, Cooling τ↓ = 90 Minutes 4. Time-Delay Overcurrent Settings: ITOC = 4 X IE = 640 A @ 6 Seconds 5. *Instantaneous Overcurrent With Time Delay: IIOC = 20 X IE = 3200 A @ 0.4 Seconds

*This protective element should not have been called “Instantaneous” as the operating time (time delay) was set at well over 3 cycles. Further, the pickup setting for this protection element was set too high such that it would not have operated had there been a true solid 3-phase fault at the transformer secondary terminals. This is because for such a fault, the maximum short-circuit current, as simulated in Easypower application, is 2980 A at 13.8KV side [Or, 9,885 / (400/5)]. The new settings are implemented as follows:

Set Auxiliary Transformer Full-Load (Base) Current: IAuxXfmr_Base = 160A

Thermal Overload Protection: Set Heating Time Constant: Heating τ↑ = 60 Minutes Set Heat Content (Current-Based) Trip Pickup: 110% of IAuxXfmr_Base = ITrip

Set Heat Content (Current-Based) Alarm1 Pickup: 80% of ITrip Since the Aux Transformer is not equipped with forced cooling, no rescaling is applied to the above settings. Nor, are they modified when the load is higher or lower than a certain value.

Overcurrent Protection: Set First Time-Overcurrent (51-1): ITOC1 = 4 X IAuxXfmr_Base = 640 A @ 6 Seconds Set Second Time-Overcurrent (51-2): ITOC2 = 10 X IAuxXfmr_Base = 1600 A @ 0.4 Seconds

Integrated Power Generation Services _______________________________________________________________________________________ Generator Protection System II (Beckwith M-3425A)


SECTION III ABB, Inc. - Integrated Power Generation Services Page 1 of 17 Wickliffe, OH

SECTION III

GENERATOR PROTECTION SYSTEM II (Beckwith M-3425A)

SETTINGS CALCULATIONS




Generator Overexcitation Function (ANSI Device 24)


PT Ratio (PTR): 14,400:120 = 120:1,


1 Per-Unit V/HZ: (13,800/120) / 60 = 1.92 (Rated Secondary Voltage / Rated Frequency)

B) Settings Calculations Relay Setting Philosophy: This is a new protection function that was not provided in the original protection system GSX10. This function will be blocked for VTFF and when Field CB is open. The generator is capable of continuous operation at 1.05 Per-Unit V/Hz. Therefore, a 1.074 Per-Unit V/HZ (2.063 V/HZ) alarm setting with a 5-second delay to avoid nuisance alarms is recommended. Corrective action should be taken for operation of the machine above 105% V/Hz. The characteristics of this protective function will be composed of Volts/Hz Inverse Curve Family #1 (Inverse Square) and a definite-time delay which will actuate for greater than or equal to 140% of Per-Unit V/HZ in 2 seconds. Basically, over-excitation protects against thermal damage. Therefore, a reset time is introduced in such a fashion as to allow cooling process to coordinate with the operating time of this protection function. For example, if an over-excitation condition reoccurs shortly after voltage and frequency have returned to their normal values, the time to trip will be shorter than it would be otherwise. As stated above, the maximum allowable continuous V/HZ seen by this protective element is:

[(13800 / 120) X 1.05] / 60 = 120.75 / 60 = 2.0125 = 2.01 (1.05 X 1 PU V/HZ)

A safety margin of 5.0%, however, will be applied to allow operation at the maximum permissible voltage while taking into consideration relay and PT errors. With that, the overall setting margin will be:

Relay Error = 0.5% PT Error = 2% Safety Margin = 5.0% (To allow operation at maximum permissible voltage) Total = 7.5%

Set Inverse-Time Pickup (Trip) = 2.01 X 1.075 = 2.16 V/HZ (112.5% of 1 PU V/HZ) To maintain coordination, the operating time should be above that of the generator V/HZ Limiter but below the generator V/HZ capability curve:

Set Volts/Hz Inverse Curve #1 Time Multiplier (K) = 3 Set Reset K Time (Cooling Time Constant) = 600 Seconds

Set Definite-Time Pickup (Trip) = 140% of Rated 1 PU V/HZ = (1.4 X 1.92) = 2.689 V/HZ Set Time Delay = 2.0 Second

Set Alarm Pickup = 108% of Rated Generator Voltage = (1.08 X 13800) / 120 = 124.2V Set Time Delay = 5.0 Seconds




Generator Undervoltage Function (ANSI Devices 27A & 27T)


PT Ratio (PTR): 14,400:120 = 120:1, PT Configuration: L-L (Line side PT is Open-∆) Generator Relay Base Voltage (VRel_Base): 115 V Relay Full-Load (Base) Current (IRel_Base): (4,987) / (1,200) = 4.156 Secondary Amperes

Or, 0.83 pu On CT Rating Base B) Settings Calculations

Relay Setting Philosophy: The 27 function was not provided in the original protection system GSX10. It is now applied to separate the generator from the utility system for a severe undervoltage condition caused by generator loss of field (LOF) event. The logic behind the threshold setting is to isolate the generator at the maximum voltage at which stability could be lost or system voltage collapse is imminent. This undervoltage threshold setting, however, requires a tremendous amount of dynamic analysis and, in the end, an ideal setting may not be achievable. As a practical alternative, the undervoltage drop-out setting is typically set to 80% of generator nominal voltage. However, given that there is an aggregate generation (multiple units) at this generating facility, the 27 function is recommended to trip at 85% of rated generator voltage (13.8KV) to ensure function drop-out. The function is time delayed in order to coordinate with (i) Voltage-Controlled Overcurrent function (51V) and (ii) Loss-of-Field (LOF) protection outer element (See settings for LOF function element 40-2). Alarm setting will be at 90% of rated generator voltage with a shorter time delay.

Set 27T (F27 #1) Trip Pickup = 85% of VRel_Base = 97.75 V (Secondary) Set 27T (F27 #1) Trip Time Delay = 1.5 Sec Set 27T (F27 #1) Trip Curve Characteristic = Definite Time Set 27A (F27 #2) Alarm Curve Characteristic = Definite Time Set 27A (F27 #2) Alarm Pickup = 90% of VRel_Base = 103.5 V (Secondary) Set 27A (F27 #2) Alarm Time Delay = 0.5 Sec (To avoid nuisance alarms due to system faults) This function will be blocked for Voltage Transformer Fuse Failure (VTFF), and when either Generator or Field CB is open. Further, 27T (F27 #1) is conditioned such that it is only enabled when generator relay phase current is above an appreciable value. This criterion is intended to guard against false operation of Breaker Failure Function (50BF) when the generator load current is virtually zero and the Undervoltage (U/V) Function element F27 #1 has dropped out. Basically, F50 #2 Function is used to condition U/V element F27 #1 such that when relay phase current is below 0.1A (120A Primary), F27 #1 element is prevented from operating regardless of the status of Generator or Field CB. Without this criterion, 50BF function will consequently operate falsely if both Generator and Field CB’s are closed during maintenance work where the generator is de-energized and isolated from the grid.

Set Overcurrent (F50 #2) Pickup: 9.6% of IRel_Base = 0.4 A (Secondary) The logic for function element F27 #1 is programmed via IPS Logic #5.




Generator Reverse Power Function (ANSI Devices 32-1 & 32-2)

A) Generator Data Generator Base MVA Rating: 119.2 MVAG


CT Ratio (CTR): 6,000:5 = 1,200:1

PT Ratio (PTR): 14,400:120 = 120:1


Or, 0.83 pu On CT Rating Base B) Settings Calculations

Relay Setting Philosophy: Gas turbines require 10-50% of rated power to motor depending on design. This function is blocked for voltage transformer fuse failure (VTFF). The original GSX10 system used “Starting Sequence On” signal for blocking; however, it was determined during commissioning that this signal was not safe to be used as it, for some unknown reason, causes its wire when terminated to overheat. Consequently, the signal wire was lifted and to be tagged with a warning not to re-terminate this wire. In lieu of that, “Field CB Open” signal is used to block F32 #2 only. The first element (F32 #1) is not blocked when Field CB is open as it is set at a much higher pickup setting which far exceeds the reverse power the SFC generates during startup.

The settings for this function have been transferred from the original protection system GSX10, which uses a single-phase Definite-Time Power relay of type RE-91. Two relays of this type were used to provide two-stage reverse power protection with following ratings and settings:

1. RE-91 Nominal Ratings: IN = 5A, UN = 100V, PN = 5 x 100 = 500 W (Relay Base)

2. Stage I Settings: P: 0.001 x 70 x 500 = 35 W, T: 0.1 x 2 = 0.2 Seconds

3. Stage II Settings: P: 0.001 x 15 x 500 = 7.5 W, T: 0.1 x 50 = 5 Seconds


First, it should be noted that since each single-phase RE-91 relay has nominal values of 100V and 5A corresponding to primary values of 13.8KV and 6000A respectively, the actual relay per-phase nominal power in primary value is:

13800/√3 x 6000 = 47.8 MW (And not 13800 x 6000A = 82.8 MW)

For Stage I, the Per-Phase Power (Primary) = (35/500) x 47.8 = 3.346 MW, but M-3425A is designed to be calibrated for 3-phase reverse power. With that, the setting should be:

3.346 x 3 = 10.04 MW

Set 32-1 (Overpower) Pickup = 10.04 / 119.2 = 0.084 PU (8.4 % of Generator Base MVA Rating) Set 32-1 (Overpower) Delay = 0.2 Sec.

For Stage II, the Per-Phase Power (Primary) = (7.5/500) x 47.8 = 0.717 MW, but M-3425A is designed to be calibrated for 3-phase reverse power. With that, the setting should be:

0.717 x 3 = 2.15 MW

Set 32-2 (Overpower) Pickup = 2.15 / 119.2 = 0.018 PU (1.8 % of Generator Base MVA Rating) Set 32-2 (Overpower) Delay = 5 Sec.




Generator Loss of Field (LOF) Function (ANSI Devices 40-1 & 40-2)


ZBASE (Base Impedance) = (Gen_kV2 /MVAG ) = 1.6 Ω (Primary) Synchronous Unsaturated (Xd): 267 % of ZBASE Transient Saturated (X'd): 25.9 % of ZBASE

CT Ratio (CTR): 6,000:5 = 1,200:1

PT Ratio (PTR): 14,400:120 = 120:1, Generator Relay Base Voltage (VRel_Base): 13,800:120 = 115 V

CTR/ PTR: 10.0



B) Settings Calculations Relay Setting Philosophy: During loss of excitation, this function will detect Var flow from the system into the generator. The apparent impedance measured by the LOF function as the generator slips poles each slip cycle will vary between X'd and X'q if, at time of LOF event, the generator was operating at full load and between Xd and Xq if it was operating at light load. To account for all those apparent impedances indicative of a LOF event, the LOF function has been conventionally set to have its impedance characteristics encompass all reactance values between (-0.5X'd) and [(-Xd) + (-0.5X'd)] along the negative X-axis on the R-X Impedance diagram. In order to strike a balance between fast tripping for severe cases of LOF and preventing LOF function from operation for stable swings, a scheme with two distance (Mho) elements is used. The first distance element (40-1) is set to operate with minimal delay for severe cases of LOF. This minimal delay is introduced to provide security against operation in case a stable swing did encroach the 40-1 zone which is intended to be set away from the trajectory impedance paths (loci) of most, if not all, stable swings. The other distance element (40-2) is intended to cover a larger zone including the first distance element zone. Since most stable swings and less severe cases (light loading) of LOF do reach into this larger zone, a much longer time delay is used. However, this time delay is conditioned with an undervoltage (UV) element where it is cut in half if the terminal voltage drops below 85%. Such a drop in terminal voltage during an LOF event indicates the system is weak and its stability could be lost as a result of the large Var drain imposed by the loss of field. On the other hand, if the UV element did not drop out, the power system is strong enough to supply the Var requirements of the failed unit without significant voltage degradation. Note that UV drop-out setting is higher than the usual setting of 80% as it is assumed this generating facility will have more than one unit operating most of the time. Without this higher setting, the boosted Var generation from the other healthy unit(s) could prevent the UV element from dropping-out. This function is blocked for voltage transformer fuse failure (VTFF).




Generator Loss of Field (LOF) Function (ANSI Devices 40-1 & 40-2) (Continued)

The original protection system GSX10 provided this function using a minimum reactance (single mho element) relay type ZPX-103a along with a time integrator type SGX115. The original ratings and settings are as follows:

1. ZPX-103a Rated Current & Voltage: IN = 5A (Relay Base), VN = 100V (Relay Base)

2. Pick-Up Point A (or Xd Implemented in terms of a1 (%) ): a1 (%) = 25%.

3. Drop-Out Point B (or 0.5X'd implemented in terms of a2 (%) ): a2 (%) = 56%. 4. Time Delay: t = 2 Seconds 5. Time Integrator’s Timers: ta (On-Delay) = 6 Seconds, tr (Off-Delay) = 3 Seconds

Note: In the Minimum Reactance Relay (ZPX-103a) literature and under Principle, it is stated that time integrator (SGX-115) can be used in conjunction with ZPX-103a to detect loss of synchronism (out-of-step) when excitation is still intact. The literature explains this detection is possible because the impedance vector during an out-of-step event oscillates in and out of the pick-up circle; where in the case of a LOF event, the impedance vector lies continuously within the pick-up circle. In contrast to this claim in the literature, the impedance vector for certain LOF events can actually exit and reenter the relay trip characteristic (pick-up circle) each slip cycle. Nonetheless, it is believed that SGX-115 was used to prevent ZPX-103a from failure to operate in the event its set time delay (which was 2 Seconds) exceeded the time it took for the LOF impedance locus to enter and exit ZPX-103a trip pick-up circle each slip cycle. In such case, the Minimum Reactance Relay (ZPX-103a) would have failed to operate if no time integrator was used to turn this periodic intermittent pick-up signal into a continuous one. The new scheme is set as follows: First, Xd and X'd need to be converted from per unit on MVAG and kV bases to secondary ohms: ZSEC = ZPRIM x (CTR/ PTR) ZBASE_SEC (Relay Base Impedance) = (Gen_kV2 /MVAG ) x ( CTR/ PTR ) = 16.0 Ω (Secondary) Xd_SEC = ( Xd x ZBASE_SEC ) = 42.66 Ω (Secondary) X'd_SEC = ( X'd x ZBASE_SEC ) = 4.14 Ω (Secondary)

1 PU-Relay = (1.0 PU x ZBASE_SEC ) = 16.0 Ω (Secondary)

Set 40-1 (Inner element): Diameter = 1 PU-Relay = 16.0 Ω (Secondary)

Offset = - ( 0.5 x X'd_SEC ) = - 2.07 Ω (Secondary) Time Delay = 0.4 Seconds

Set 40-2 (Outer element):

Diameter = Xd_SEC = 42.66 Ω (Secondary) Offset = - ( 0.5 x X'd_SEC ) = - 2.07 Ω (Secondary) Undervoltage Element Drop-Out = 85% of VRel_Base = 97.75 V

Time Delay without UV Element Drop-Out = 2.0 Seconds Time Delay with UV Element Drop-Out = 1.0 Second




Generator Negative Sequence Overcurrent Function (ANSI Device 46A & 46T)


CT Ratio (CTR): 6,000:5 = 1,200:1


Relay Full-Load (Base) Current (IRel_Base): (4987) / (1200) = 4.156 Secondary Amperes


Continuous Unbalanced Current (I2C) Capability: 8%

I22 t Capability Constant (KC): 10

B) Settings Calculations Relay Setting Philosophy: The 46A (Alarm) settings are calculated slightly below the continuous limit of 8%. The 46T (Trip)settings are calculated to operate when the machine is operating at its full negative sequence current capability to ensure tripping before damage to the stator occurs due to overheating. The original protection system GSX10 provided this function using a two-stage definite-time negative sequence relay type IPX-132b with the following rating and settings:

1. IPX-132b Rated Current: IN = 5A (Relay Base)

2. 1st Stage Pickup & Time Delay Settings: I = 7% of IN (Equivalent to 8% of IFL), T = 5 Sec

3. 2nd Stage Pickup & Time Delay Settings: I = 20% of IN (Equivalent to 24% of IFL), T = 5 Sec

The new protective device, however, provides this function with the capability to allow the user to pick a time-current curve that matches the machine I2

2 t characteristic. The relay’s time dial (K-Value) setting must be set such as to allow for accumulation of additional I2

2 t as a result of the current decay after the generator and field breakers have been tripped. With that, the K value will be set to 7 in the relay. The alarm and trip settings are as follows:

Set 46A Pickup Setting: 0.75 x I2C = 6.0% Set 46A Delay: 3 Seconds Set 46T Inverse-Time Pickup Setting: I2C = 8.0%

Set 46T Time-Dial Value: 7 Set 46T Max Operate Time: 1000 Seconds Set 46T Reset Time (Cooling): 250 seconds




Generator Breaker Failure Function (ANSI Device 50BF)



Relay Full-Load (Base) Current (IRel_Base): (4987) / (1200) = 4.156 Secondary Amperes Or, 0.83 pu On CT Rating Base

Generator CB Opening Time: 50 +/-3 ms

B) Settings Calculations Relay Setting Philosophy: This is a new protection function intended to guard against failure of the Generator CB to interrupt a fault. This function will be initiated any time Generator CB trip output contacts (AC and DC Trip Coils) are actuated by a protective element within the relay. Breaker Failure function operates if any phase current persists in excess of 10% of IFL or if Generator CB status has not changed to “Open” in 9 cycles or less since the function timer was first initiated. The expected interrupting time (Opening Time + Arcing Time) for this Generator CB is around 5 Cycles. With a safety margin of 4 Cycles, the time delay (timer set time) is set to 9 Cycles. Set Phase Overcurrent (50BF) Threshold: 10% of IRel_Base = 0.42A (Secondary) Set Breaker Failure Time Delay (Timer): 9 Cycles




Generator Inadvertent Energization Function (ANSI Device 50/27)




PT Ratio (PTR): 14,400:120 = 120:1

Generator Base Voltage (VGen_Base): 13.8KV

Relay Base Voltage (VRel_Base): 115V

B) Settings Calculations Relay Setting Philosophy: This is a new protection function intended to detect an erroneous closure of the Generator CB and minimize the possibility of any damage. Moreover, Inadvertent Energization refers to an energization from standstill without field excitation. This function is blocked for voltage transformer fuse failure (VTFF).

Set Overcurrent (50) Pickup: 12% of Generator Base Current 4,987 A

Set Undervoltage (27) Pickup: 50% of VRel_Base = 57.5 V (Secondary)

Set Undervoltage (27) Pickup Time Delay (Time to Arm): 2 Seconds

Set Undervoltage (27) Drop-Out Time Delay (Time to Disarm): 0.25 Seconds




Static Frequency Converter Backup Overcurrent Function (50SFC)




B) Settings Calculations Relay Setting Philosophy: This is a new protection function intended to provide backup overcurrent protection to Static Frequency Converter (SFC). At unit start-up, SFC is used to motor the generator to a certain speed at which the gas turbine is capable on its own to take over in further driving the generator to its rated synchronous speed (3600 RPM). During generator motoring by the SFC, only the neutral-end CT’s will sense the SFC current which could be 4% to 10% of the generator base current. Function element (F50 #1) is used to sense SFC Overcurrent. Set Overcurrent (F50 #1) Pickup: 24% of IRel_Base = 1.0 A (Secondary) This function is only enabled when Field CB is open, and its logic is programmed via IPS Logic #4.




Generator Overcurrent (Voltage-Controlled) Function (ANSI Device 51V)

A) System, Main Transformer, and Generator Impedance Data System: 138 KVS 22,582 A, 1∅ -G Fault @ Angle -88.5°

19,409 A, 3∅ -G Fault @ Angle -88.6°

Main Transformer (GSUT): ZGSU = 9.22% @ 60 MVA


Synchronous Unsaturated (Xd): 267 %, Rated Excitation Current (IFN): 1111 A Transient Saturated (X'd): 25.9 %, T"d: 0.017 Sec. Subtransient Saturated (X''d): 17.5 %, T'd: 0.81 Sec.

Generator Base Current (IGen_Base): 4,987 A, Relay Full-Load Current (IRel_Base): 4.156A Or, 0.83 pu On CT Rating Base

PT Ratio (PTR): 14,400:120 = 120:1 , Generator Base Voltage (VGen_Base): 13,800 V

Generator Relay Base Voltage (VRel_Base): 13,800:120 = 115 V

B) Settings Calculations Relay Setting Philosophy: This function is applied to backup transmission line relaying.

This function is blocked for voltage transformer fuse failure (VTFF).

The original protection system GSX10 provided this function using a voltage-controlled relay type IUX-159 with the following rating and settings:

1. IUX-159 Rated Current & Voltage: IN = 5A (Relay Base), VN = 100V (Relay Base)

2. Overcurrent (51) Pickup & Time Delay Settings: I = 0.2% of IN (Equivalent to 24% of IFL), T = 1 Sec

3. Instantaneous Overcurrent (50) Pickup & Time Delay Settings: I = ∞ (Instantaneous trip ineffective)

4. Undervoltage Pickup Setting: V = 70% of VN = 70% of Generator Base Voltage The generator-main transformer unit including the 138KV high-voltage short-circuit data was modeled in a fault engineering software application (Easypower) using the above listed data. The settings provided by the original protection system were checked against the generator decrement curve, fault currents at the high side of GSUT, and at the far end of the high-voltage impedance. The settings were found to be proper; however, the Undervoltage drop-out setting should be increased to ensure drop-out for a phase-to-ground fault at the far end of the simulated system high-voltage impedance. Set Undervoltage (27) Pickup: 75% of VRel_Base = 86V (Secondary) Set Overcurrent (51) BECO Definite-Time Pickup: 24% of IRel_Base = 1A (Secondary) Set Overcurrent (51) BECO Definite-Time Dial: 4.0




Generator Overvoltage Function (ANSI Devices 59-1, 59-2, 59-3)


PT Ratio (PTR): 14,400:120 = 120:1,

(2) PT’s Configuration: Primary Connection: L-L , Secondary Connection: Open-∆ Generator Relay Base Voltage (VRel_Base): 13,800:120 = 115 V

B) Settings Calculations Relay Setting Philosophy: The 59 function should be set with a safe margin below the overvoltage capability of the generator. The time delay should be set such as to coordinate with the V/Hz Limiter and 24 protection function. Further, this function is blocked for Voltage Transformer Fuse Failure (VTFF) and when Field CB is open.

The original protection system GSX10 provided this function using voltage definite-time relay type UT-91 with the following rating and settings:

1. UT-91 Rated Voltage: UN = 100V (Relay Base) = 13.8KV (Primary Rated Voltage)

2. Pickup Setting: 120% of UN = 16.56KV (Primary)


This definite-time pickup setting along with its associated time delay will be not provide complete protection between 105% of generator rated voltage, which is the maximum allowable continuous generator voltage, and its pickup setting (120% of rated voltage). Nor, will it provide adequate protection for any voltage excursions beyond that setting. The new recommended settings are as follows:

The limiting Voltage = 105% of VRel_Base = (1.05 X 13,800) / 120 = 120.75 V

The overall setting margin: Relay Error = 0.5% PT Error = 2.0% Safety Margin = 2.5% (To allow operation at maximum permissible voltage) Total = 5.0%

Set 59-1 Definite-Time Pickup = 110% of VRel_Base = (1.10 X 115) = 126.5 V Set 59-1 Time Delay = 1 Second (Alarm programmed via IPS Logic #1) Set 59-1 Time Delay = 20 Seconds (Trip Generator and Field CB’s)

Set 59-2 Definite-Time Pickup = 118% of VRel_Base = (1.18 X 115) = 135.7 V Set 59-2 Time Delay = 4 Seconds (Trip Generator and Field CB’s)

Set 59-3 Definite-Time Pickup = 140% of VRel_Base = (1.4 X 115) = 161V Set 59-3 Time Delay = 1 Cycle (Trip Generator and Field CB’s)




Generator Stator Ground Fault Function (ANSI Device 59GN/64G)


Neutral Grounding Transformer Ratio (NGTR): 14,400:240 = 60:1

Neutral Grounding Transformer Secondary Resistor (ZRES): 0.44 Ω


Relay Setting Philosophy: 59GN/64G pickup is set as sensitive as possible to provide maximum stator ground fault coverage. The settings for this function have been transferred from the original protection system GSX10, which uses stator earth-fault relay type UBX-117 with the following rating and settings:


2. Overvoltage Pickup Setting: 5% of UN

3. Relay Operation Time Delay: 0.5 Seconds


First, a ground fault at the line terminal side of generator (full winding voltage) is limited to 5.03A (Primary) as calculated in the following equation:

IGnd_Fault_Prim = VL-N / (ZRES * NGTR

2) = 5.03 Amps (Where VL-N = 13.8KV / √3 )

(Note: It is assumed the Neutral Grounding Transformer (NGT) secondary resistor was originally chosen such that the ground fault current passing through the primary winding of this NGT is equal to or greater than the charging capacitive current created when a full-winding voltage (13.8KV / √3) is imposed onto ground.)

Neural Grounding Transformer Secondary Voltage at IGnd_Fault_Prim:

VGnd_Fault_Sec = IGnd_Fault_Prim * NGTR * ZRES = 132.79 Volts

Set 59GN/64G Pickup: V59N_Sec = 5 Volts (3.8% of VGnd_Fault_Sec)

Stator Ground Fault Coverage = [1- (V59N_Sec / VGnd_Fault_Sec)] X 100 = 96%

Set 59GN/64G Time Delay: 0.5 Seconds




Potential Transformer Fuse Loss Detection Function (ANSI Device 60FL) A) Generator Data

Generator Data: 119.2 MVAG VBase_Pri = 13.8 kV 0.85 pf Generator Full-Load (Base) Current (IGen_Base): 4,987 Amperes

Relay Full-Load (Base) Current (IRel_Base): (4987) / (1200) = 4.156 Secondary Amperes

Or, 0.83 pu On CT Rating Base PT Ratio (PTR): 14,400:120 = 120:1, VBase_Sec = 115 V

No-Fault Sequence Magnitudes: IPos_Seq = 4,987 A, INeg_Seq = 0 A, IZero_Seq = 0 A

VPos_Seq = 7,967.4 V,VNeg_Seq = 0 A, VZero_Seq = 0 A

B) Settings Calculations Relay Setting Philosophy: This is a new function intended to detect loss of phase-potential feed into the relay due to voltage transformer fuse. Fuse failure detection is based on the general principle that if measured values of negative and zero sequence voltages are high while their respective currents are very low, then this is indicative of a fuse-loss condition. Once detected, all voltage-dependent protection elements are blocked to prevent misoperation.

For fuse loss detection of one or two fuses, negative and zero sequence quantities are compared. For the loss of all three phase potentials, the manual states the following: “Comparison of the three phase voltages is made to the three phase currents. If all three potentials are under 0.05 VNom

and all three currents are below 1.25 INom combined with IPos_Seq > 0.33A (Secondary), a three-phase potential loss is declared. A seal-in circuit is provided to ensure a three-phase fuse loss condition is not declared during a three-phase fault if fault current decays below the 1.25 INom

pickup setting.”

Set Time Delay: 1 Cycle (Relay Minimum)

Set Input Initiate: FL (Required for relay to use internal fuse loss logic)

Set Three Phase Fuse Loss Detection: Enable

Note: For a complete graphical representation of Fuse Loss (60FL) Function Logic, see Figure 2-52 in Beckwith M-2545 Manual (800-3425A-IB-08 07/10).




Generator Rotor Field Ground Fault Function (ANSI Device 64F) A) Rotor Winding Data

Rotor Winding Data: 0.201 Ω @ 75º C, INO_LOAD = 341 A, IRATED_LOAD = 1111 A

Rotor Winding Insulation Class: F

Rotor Field Winding Capacitance to Ground (CFLD-GRD): Not Provided in Generator Data Sheet Exciter Type: Brushless

B) Settings Calculations Relay Setting Philosophy: In normal operation, rotor field winding is intentionally ungrounded though it is naturally grounded through the presence of capacitance between the winding and ground. A breakdown of field winding insulation can be detected when this capacitance is shunted with the insulation fault resistance. A single ground fault at one point does not pose an immediate damage though it does result in higher voltage stress across other points in the winding. However, a second ground will bypass a portion of the field winding and unbalance the air-gap flux. The degree of unbalance and the resulting vibration depends on the location of the ground fault which in turn determines the extent to which the winding is bypassed. The vibration can be severe enough to cause massive damage not to mention that a second failure can cause local heating which ultimately lead to rotor distortion that produces damaging vibration. It is understood that the original protection philosophy was to alarm only but monitor the rotor vibration closely using installed vibration-level-measuring probes. The original protection system GSX10 provided this function using Rotor Earth-Fault relay type IWX-161a-1 along with Ancillary Unit YWX-111-11 with the following rating and settings:

1. RC Bridge Capacitors:

i. Balancing Capacitor (One Branch): CX = 0.58 μF ii. Coupling Capacitors (CK1 & CK2 ) and CFLD-GRD (Connected In Series in Opposite

Branch): CK1 = CK2 = 2 μF, CFLD-GRD is calculated as follows: CFLD-GRD = [(CK1 + CK2 ) x CFLD-GRD ] / [(CK1 + CK2 ) + CFLD-GRD] = 0.678 μF

2. Calibration Potentiometer (Trigger) Resistance: 1000 Ω 3. Time Delay: 1 Second

The new protection scheme for this function injects a voltage signal (low frequency squarewave) to detect deterioration or breakdown in the rotor winding insulation. A coupling network device (M-3921) between the relay squarewave voltage signal generator and the field measurement (pilot) brush is used to facilitate the injection of this signal, to isolate the field high DC voltage from the relay, and to limit the signal current in the event of a ground.

Set Ground Fault Resistance Pickup: 20 KΩ Set Time Delay (Alarm): 10 Seconds

Set Injection Signal Frequency: 0.57 Hz

Note: The Injection Signal Frequency is a very important parameter that was initially set based of the value of CFLD-GRD (0.678 μF). However, this frequency was fine-tuned during field testing and 0.57Hz was determined to be the best choice. Field winding-to-ground resistance measurements can be found in the final Test Report.




Generator Underfrequency Function (ANSI Devices 81U-1, 2, 3, 4) A) Generator Data


Nominal Frequency: 60 Hz

PT Ratio (PTR): 14,400:120 = 120:1


Relay Setting Philosophy: Settings will back up the primary under-speed protection of the unit combustion gas turbine. The settings implemented in M-3425A reflect previous settings used for this function. The exact settings have been transferred from the original protection system GSX10, which had a four-stage Frequency Protection relay type FC-95 with the following settings:

1. Stage I Settings (81U-1): I f = 58.2 Hz, t = 3 Cycles (Relay Minimum)

Blocked When: Gen CB is Open, Used For: Alarm Only.

2. Stage II Settings (81U-2): II f = 57.5 Hz, t = 3 Cycles (Relay Minimum) Blocked When: Gen CB is Open, Used For: Alarm Only.

3. Stage III Settings (81U-3): III f = 57.0 Hz, t = 3 Cycles (Relay Minimum)

Blocked When: Gen CB is Open, Used For: Trip Gen Breaker.

4. Stage IV Settings (81U-4): IV f = 54.0 Hz, t = 3 Cycles (Relay Minimum) Blocked When: Field CB is Open, Used For: Trip Unit.

In addition to implementing the above settings along with the blocking logic in this new Generator Protection System II, all four stages are also blocked for Voltage Transformer Fuse Failure (VTFF).




Generator Phase Differential Function (ANSI Devices 87G-1, 87G-2) A) Generator Data


CT Ratio (CTR): 6,000:5 = 1,200:1 ANSI CT C-Rating: C400 Generator Full-Load (Base) Current (IGen_Base): 4,987 Amperes



B) Settings Calculations Relay Setting Philosophy: The 87G function primarily provides phase fault protection for the generator and should be set as sensitive as possible, yet not trip for CT errors that can occur during an external fault. The original protection system GSX10 provided this function using a Three-Phase Biased Differential relay type DT-92 with the following rating and settings:

1. DT-92 Rated Current: IN = 5A (Relay Base) 2. Ratio Correction for Terminal and Neutral CT’s: IN / IFL_Rel = 1.2 (1L = 1R = II, 2L = 2R = I) 3. Phase Angle Correction Between Terminal and Neutral CT’s: T1 = T2 = 0 4. Sensitivity and Pick-Up Ratio Settings: g = I (20%) , v = 50% 5. Section I [0 To 5A]: Operate Current = 1A 6. Section II [5A To 15A]: Operate Current = (0.5 x IH) - 1.5 7. Section III [15A To 27.5A]: Operate Current = (1.5 x IH) – 16.5

Given that both neutral and terminal end CT’s have the same ANSI C-Rating, C400, the error current should be minimal but not necessarily non-existent as there is always design tolerances even for CT’s made by the same manufacturer. However, the overall burdens for those CT’s are not equal as the terminal side CT’s are located at the Generator CB Switchgear, which is a good distance away from the generator itself. This can cause differing degrees of saturation in the neutral and terminal side CT’s during a high asymmetrical fault current and contribute to a larger error current. With that and to provide adequate sensitivity yet avoid misoperation, the new settings are as follows:

⇾ ⇾ ⇾ ⇾ With, Restraint Current: IH = (I1 + I2) / 2, Operate Current: I∆ = I1 - I2

Set 87G-1 Pick-Up: 0.25 A Set 87G-1 Time Delay: 1 Cycle (Minimum) Set 87G-1 Percent Slope: 15 % (Relay automatically increases the percent slope value to 4 times this setting (4 x 15% = 60%) at 2 x IFL_Rel)

87G-2, which is intended to be used only during Static Frequency Converter (SFC) operation, is disabled. Instead, Function 50-SFC is dedicated to provide backup overcurrent protection for the SFC. Note: See Figure 2-72 in the Beckwith Manual for a graphical representation.


_______________________________________________________________________________________ Copyright © 2011, ABB®. All Rights Reserved.

ABB Inc. Integrated Power Generation Services Instrumentation, Control, & Electrical (ICE)

Muhanad N. Sharaf, P.E. 29801 Euclid Avenue Wickliffe, OH 44092

Tel: +1 440 585 3847 E-mail: [email protected]

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