Generator Protection Functions

8/20/2019 Generator Protection Functions

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1 OCTOBER 2010 TS TIDINGS

TECHNICAL SERVICES / PSSR

RAIGARH TPP OCTOBER : 2010

VOLUME : 14.05

Published by Technical Services / PSSRFor internal circulation

AMARKANTAK UNIT 5: TG PG test and Boiler PG test were completed.

NALCO UNIT 10 : Unit reached full load. KUTTIYADI UNIT – 1 : 72 hours full load trial operation was completed.KUTTIYADI UNIT – 2 :

72 hours full load trial operation was completed.

MUDDANUR UNIT - 5 :

Steam blowing was completed.

KOTHAGUDAM UNIT - 11 :

Boiler was lighted up.


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INSIDE

1. STATUS OF PROJECTS COMMISSIONED / TO BE COMMISSIONED DURING2009 - 2011.

2. SERVICE RENDERED TO OTHER REGIONS/SAS/PROJECTS AFTER CONTRACT

CLOSING/ CUSTOMER TRAINING.

3. APPRECIATION FROM CUSTOMER FOR SERVICES RENDERED.

4. FEED BACK ON EQUIPMENTS FROM SITES.

5. LET US KNOW - GENERATOR PROTECTION FUNCTIONS

Feed backs and suggestions from all departments of BHEL for improvement of TSTIDINGS are welcome and may please be addressed to ADDL. GENERAL MANAGER(TSX)/BHEL-PSSR/CHENNAI


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STATUS OF PROJECTS COMMISSIONED / TO BE COMMISSIONED DURING2009 – 2011 :

AMARKANTAK – UNIT 5 :

Unit was synchronized on 05.10.2010 after overhaul and PG testpreparations.

TG PG test (100% and 80% load) , auxiliary power consumption test and BoilerPG test were completed successfully and MOM signed on 30.10.2010.

NALCO - UNIT 9 :

Unit is running at 80 – 100 MW as per the requirement of customer.

NALCO – UNIT 10 :

After servicing the thrust bearing, trial run of CEP – 2 was completed.

Unit was synchronized on 03.10.2010 and loaded to 60 MW.

Calibration of Feeder - A was carried out.

Unit reached full load for the first time on 06.10.2010.

Unit was stopped on 09.10.2010 due to HPCV-2 drain line leakage and wasattended and cleared for unit start up.

Unit was restarted on 24.10.10 as per customer requirement.

Unit was stopped on 31.10.2010 due to Boiler economizer tube leakage.

NALCO – DAMANJODI UNIT 5 :

Calibration of hot air damper and cold air damper for mill AB was completed.

Soot blower lines hydro test was completed.

AC-JOP suction line modification was carried out as per revised scheme. AC-JOP alignment of new pump and pump trial were completed.


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4 hours trial run of Mill – CD lube oil motors and trial run of mill auxiliarydrive lube oil motors were completed.

ESP : Charging of ACP and controller panels was completed. ESP – A passCERM, EERM & GDRM trial run was completed. Dummy load test of allfield controller panels was carried out in ESP – A pass. OCC and SCC testsfor five rectiformers were completed.

BFP – A lube oil flushing was declared completed.

Feeder – C trial run and tracking was carried out.

Mill – CD motor trial run was carried out.

Mill - AB & CD inert steam line hydro test was completed.

Mill – AB lube oil flushing was declared completed.

Large video screen system erection and commissioning was completed at unitcontrol room.

BFP – B motor trial run was completed and released for alignment and coupling.

Trial run of DC scanner air fan, Mill – CD auxiliary drive motor and auxiliarydrive to main reducer was completed.

Seal air fan - B damper was commissioned.

KRL KOCHI :

GT was running around 17MW with around 40 TPH HRSG steam flow. Ittripped on 11.10.2010, as PLC both processors got hanged.

TIE-3 Transformer OLTC was commissioned.

During restarting flow divider was found jammed. After attending to the flow

divider problem, GT was restarted on 14.10.2010.

Process incomer -1 hipot test was completed and charged.

ACTP – 1 feeder was charged.

Presently GT is running at 15 MW with 34 TPH HRSG steam flow.


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RAICHUR – UNIT 8 :

Unit which was under shut down since 21.09.2010 due to ID fan

problem was synchronized on 10.10.2010 and loaded to 80 MW withtwo mills.

ID fan – A was taken into service on 14.10.2010.

HP heaters were charged and level control were put on auto.

Auto synchronizer was commissioned.

Mill – E and feeder - E were taken into service on 24.10.2010.

Unit was stopped on 30.10.2010 due to bottom ash evacuation problem.

RAYALASEEMA TPP - UNIT 5 :

Second stage steam blowing was completed with total 25 blows.

Trial run of mill motors - C, E and F was completed.

BFP- 5B lube oil flushing was completed.

Steam blowing of soot blower line was completed.

Seal oil system AC motor trial run was completed.

Mill seal air fan motor and DC scanner air fan motor trial run wascarried out.

8 hours trial run of FD fan – A motor was completed.

HFO pump house temperature control valve and pressure control valve werecommissioned from remote.

BFP –B recirculation valve was commissioned from remote.

8 hours trial run of BFP -5B & CEP motors - A , B & C was completed.

PA FAN-5B 8hrs trial run was completed

Reheater hydro test was done.

CW pump – A & B motor 8 hours trial run was completed.

Fibre optic cable from CW pump house to control room was laid and all theCW pump house parameters were checked from control room.


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AC-JOP was commissioned.

CW pump butter fly valve was commissioned.

FD fan – 5A one hour trial run was carried out.

4 hours trial run of seal air fan -5B was completed.

8 hours trial run of PA fan -5A motor was completed.

Mill motor - 5D was taken trial run for 8 hours.

PA fan -5A lube oil flushing was declared completed.

GD test of ESP – A pass was completed.

KUTTIYADI UNIT 1 :

After completing the balancing work, unit was synchronized on04.10.2010.

72 hours full load trial operation was completed successfully on11.10.2010.

Unit is in service as per the requirement of customer.

KUTTIYADI UNIT 2:

Nozzle – 1 & 3 erection work was completed.

Deflector feed back mechanism setting for all corners was completed.

72 hours full load trial operation was completed successfully on30.10.2010

VIJAYAWADA UNIT 7:

Unit was synchronized on 03.10.10 after erection of PG test flow nozzle andattending to EHTC problem.

Unit was shut down on 05.10.2010 to attend to GT - Y phasetransformer bushing failure and after replacing the same, unit wasresynchronized on 20.10.2010.

Unit is presently running around 450 – 500 MW.


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KAKATIYA UNIT 1 :

Unit was under shut down since 07.10.2010 due to PA fan – A NDE

bearing failure Unit was synchronized on 13.10.2010 and loaded to 200MW.

Mill – D scrapper replacement work was completed.

Unit tripped twice on 21.10.2010 due to (1) generator differential faulton R phase and (2) opening of GCB. Unit was resynchronized on22.10.2010 and loaded to 200 MW.

PA fan –A: Trial run after new rotor assembly was completed.

Presently unit is running 440 – 450 MW.

LRSBs pressure setting is in progress.

KOTHAGUDAM 500 MW, UNIT 1 :

Boiler final hydro test was completed on 02.10.10 in the presence ofBoiler Inspector.

ID fan – B was run for one hour on 13.10.2010.

ID fan – B and FD fan – B were run and draught system was established.

LDO pump – A was run and fuel was charged upto all four corners.

All the CC pumps were erected.

SG-DMCW pumps – A & B were run after attending to the seal leakage and jamming problem.

DMCW lines flushing in CC pump cooling water suction side was carried out.

CC pump emergency cooling water circuit flushing was carried out.

Boiler expansion constraints cutting work is in progress.

CC pumps A & B was run

Boiler was lighted up for the first time on 31.10.10


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SIMHADRI STAGE II, 2 X 500 MW, UNIT 3 :

SAPH 3A – Soot blower motor 4 hours trial run was completed.

Stage 1 to stage – 2 LT-APRDS interconnection line steam blowing wascompleted.

Booster pump motor – A & B for CC pump motor– 4 hours trial run wascompleted.

ID fan – 3 A – 8 hours motor trial run through channel – 2 was completed.

ID fan – 3A motor - channel 1 & 2 parallel operation was completed.

MDBFP – C motor 8 hours trial run was completed.

SG-ECW B – 8 hrs. motor trial run was completed.

SAPH-3A fire fighting line flushing was completed.

Local commissioning of SH drain MOVs was completed.

Pre-Boiler system Detergent flushing completed.

NEYVELI TS II EXP CFBC, 2 X 250 MW, UNIT 1:

SAT & UAT were charged for the first time and power extended to boards.

ESP – B pass GD rapping motors trial run was completed.

DMCW – 1A & 1B motor trial run – 8 hours completed.

SA fan - 1B motor and IA compressor motor cable hi-pot test was carriedout.

IA compressor – 1 & 2 motor trial run - 8 hrs. was completed.

SA fan motor 1A & 1B motor trial run - 8 hrs. was completed.

PA fan – A cable hi-pot test was carried out.

DMCW system – 4 nos. actuator were commissioned.

PA fan – A – 8 hours motor trial run and HVAC motor – 4 hours trial runwere completed.

Detergent flushing motors trial run for 4 hours was carried out.


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SERVICES RENDERED TO CUSTOMER /SAS/MUs:

Shri. P Muthu, AGM/Kakatiya site and Shri. R Ganeshram, Engineer, TSX, Chennaiwere deputed to Neyveli for attending to high shaft vibration problem of unit number7 of TS II.

CUSTOMER TRAINING & TECHNICAL PAPER PRESENTED:

--- NIL ---

APPRECIATION FROM CUSTOMER FOR SERVICES RENDERED :

--- NIL ---


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FEED BACK NO.1

PROJECT: NEYVELI LIGNITE CORPORATION, TS II, UNIT NO. 7, 210 MW KWUDESIGN

PROBLEM: HIGH HP SHAFT VIBRATION PROBLEM

HISTORY OF PROBLEM:

NLC-TS-II-U#7 HP,IP turbine overhaul was carried out in August 2008 by BHEL-SAS-Secunderabad. During the overhaul, HP rotor was replaced due to excess

interstage and gland seal clearance and bearings 1 & 2 were replaced due to Babbittdamage and pitting. After the overhaul, the vibration value at HP (front) shaft wasfound to have increased to 180 microns compared to prior level of 110 microns.

Trim balancing was carried out by M/s.BHEL specialist twice at LP rotor and HProtor. After second trim balancing, the vibration levels were slightly found reduced,but in due course the vibration levels increased with HP front shaft vibration levelmaintaining at about 175 microns and showing rising trend further.

During Aug 2009, Journal bearing No.1 was replaced with a spare bearing with

minimum design clearances as per suggestion of M/s. BHEL-SAS. There was slightreduction of HP shaft vibrations from 175 microns to 160 microns. However, turbinevibrations particularly at HP front shaft increased in due course.

RECTIFICATION WORKS CARRIED OUT:

Rectification works to contain high vibrations in U#7 were entrusted to BHEL-SAS inAug/Sep 2010.The significant defects noticed and rectification works carried out aregiven below in brief.

•

Shifting of total turbine rotor along with combined thrust and journal bearing inaxial direction towards Generator by 1 mm when compared to previous assemblyposition ( 2008).

• Heavy pitting and impression were found in axial key contact areas of thrustcum journal bearing no.2 and the pedestal along with slight pitting on thespherical piece/spherical support (right side).


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• The thrust cum journal bearing No.2 along with its support was replaced by newone purchased from M/s .BHEL/Hardwar.

•

Axial key pitting marks in the pedestal were removed by grinding and matchingwas ensured.

Turbine cold rolling was done on 18.09.2010. The load could not be raised beyond115 MW due to very high value of vibration at bearing No.2 pedestal.

On 19.09.2010, the turbine was hand tripped as the pedestal vibration at bearingno.2 reached the trip value of 45 microns. Again turbine rolling was done and the loadwas raised gradually up to about 190 MW. The pedestal vibrations were found to behigher compared to prior levels of the above rectification works.

Machine vibrations are changing and sometimes allowing to synchronize and load.Sometimes even synchronization was not possible. It is attributed to self aligningproblem as the bearing No.2 is of self aligning type.

Unit got tripped on some other protection on 20.09.2010. Again while the unit wasbrought back into service, the vibration values at HP front and HP rear shaft wentbeyond trip level( more than 200 microns) and hence the unit was hand tripped.

REINSPECTION WORKS CARRIED OUT:

Further to forced shut down, inspection and rectification works were carried out byBHEL-SAS from 01.10.2010 to 09.10.2010 . The major defects noticed are givenbelow in brief.

OBSERVATIONS ON DISMANTLING:

• HPF swing check of 0.27 mm observed.

• HP/IP alignment L-R 0.0525 mm, T-B 0.0175 mm.

• Bearing No.2 level was checked using master level at P/P and found to have a slopeof 0.85 mm/meter (High at turbine side i.e., front).

•

When bottom half was removed and inspected, it was observed that the contactbetween torus and support was only on the right side with slight pitting.


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• The support was removed form location and checked .The measurement reveal slopeas follows

L-R slope at front 0.16 mm over 700 length

L-R slope at rear 0.24 mm over 700 length

No significant slope in front-rear

• Support seating surface inside the pedestal was checked and the measurementlevels slope as follows.

Front to rear slope of 0.20 to 0.24 mm over 280 mm width

No significant slope in L-R

RECTIFICATIONS:

• The above slopes (Left-Right and front-rear) were corrected by machining/grinding and matching was ensured.

• Bearings 1 & 2 Torus to support matching was done to improve and ensure properself aligning of the bearings as the existing contact was limited.

•

Pedestal 1&2 loading packers were removed, eased and put back.

After completion of above works, Machine was put on barring gear on10.10.2010 @ 05:14 Hrs. Unit was steam rolled to 3000 rpm on 10.10.2010 @11:40 Hrs. Load was gradually raised and full load reached at 10:21 Hrs on11.10.2010.Performance of the machine was satisfactory and the vibration levels areas follows.


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BrgNoShell vibrations

(microns)

Shaft vibrations

(microns)

1 16 127

2 21.5 88

3 9 50

4 16 65

5(V/H) 14/8.5 -

6(V/H) 11/6 -

Vibration specialist BHEL-PSSR and BHEL- Hardwar/Engg analyzed the case.They concluded that the vibration problem is due to improper self aligning of bearingNo.2

CONCLUSION:

During the assembly of bearings 1 & 2 self aligning of bearings is to beensured. If it does not exists, it shall be achieved by matching and ensuring propercontact between bearing spherical seat and support. Also, pedestals 1 & 2 are to beensured for free movement by easing to achieve unrestricted casing expansions.

Prepared by :

V.Naga Raju,

Jr.Executive(Engg)Staff No : 2767554BHEL-PSSR-SASSecunderabad.


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FEEDBACK NO. 2

PROJECT : KOTHAGUDAM UNIT 11 (500MW)

PROBLEM : JAMMING AND SEAL LEAKAGE OF SGDMCW PUMP

Problem Detail:

Two Nos. SG DMCW Pumps were supplied by M/s FlowMore Ltd at KTPS Unit XI .

Pump B was first commissioned on 02/10/2010 after completion of flushing withACW water and subsequently with DMCW water. High vibration and noise was heardduring first trial run. After 4hrs, when pump was stopped, it got jammed.

Pump casing was opened. Pebbles, welding slag and rust were found in the casingand NDE side wear ring was found jammed on to the impeller. It was cleaned by lightemery polishing, and pump was reassembled. During the reassembly, the DE / NDEend seal face covers were found having pin holes at parting plane through which,water was leaking profusely upon charging. Hence for attending the same, pump hadto be opened 4 times and finally silicone sealant was applied to arrest the leak.

Suction line and discharge lines flushing with DM water was thoroughly done andpump was reassembled after realignment. During running of pump, high vibration was

observed along with heavy NDE seal leak. Pump was hand tripped and got jammed.Again upon opening of the pump casing, NDE wear ring was found struck up in impellerand rubbing/ scoring marks were observed on the impeller wear ring area. Polishingwas carried out on wear ring,.

In spite of repeated efforts by supplier’s technicians, the seal leaks, and NDEwearing jamming in pump –B could not be resolved .

On 08/10/2010, a senior pump service engineer was deputed by M/s. Flow moreto assist in rectification of SG DMCW pump. Pump – B which was jammed, was opened

in his presence and found that seal got worn out by 0.4mm (slightly) due to dislocationof spring retention pin (Refer seal drawing),caused by jamming.

Seal was reassembled and pump was run. After 4hrs of trial run, pump washard to rotate on coasting down. Entry of foreign materials in the pump casing suchas rust, pebbles etc. were suspected for the problem by M/s FlowMore.


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Hence a suction strainer from ACW system was borrowed from customer andwas introduced in common suction header of SG DMCW with one isolation valve.Thorough flushing of lines was again carried out.

After clearance from piping on 12/10/10, Pump-B was run for 20 min. Afterstopping, again it got jammed. Minor buffing on NDE wear ring saw it run for 72hrscontinuously. But upon stopping it again got jammed.

Resolution:

Pump – B was opened and the wearing ring to top casing blue contact waschecked. It was found that there is no contact of top half casing with the wearingring due to higher 2.5mm parting plane gasket thickness put at shop. Hence during

servicing the wearing ring was getting jammed. It was corrected by introduction of1mm parting plane gasket. The wearing ring was also found to be oval and hence bothNDE and DE wearing rings ovality were removed. After box up of pump – B it wasrotating freely after trial run for 2hrs. No further correction was necessary.

SGDMCW Seal Drawing


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Conclusion:

In the absence of site specific O&M manuals / drawings site had to wasteprecious erection and commissioning time in attending trivial problems probably causedby poor assembly / testing of these pumps at works.

However, introduction of suitable suction strainers can be made as permanentfeature in closed CW systems were foreign material entry is inevitable during initialcommissioning. Higher size DMCW piping is being TIG welded as per plan. HoweverTIG welding of piping less than 200NB also needs to be introduced in place of arcwelding in the quality plan for erection.


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GENERATOR PROTECTION FUNCTIONS

Introduction

Protection against internal and external faults and immediate isolation of

the network are extremely important for even small sized generators andtransformers. The prompt isolation against the faults will save the equipment fromfurther damage and also saves the human life. This article provides an overview ofthe basic protection concepts applied for large generators with respect to numericalprotection relays.

The figure 1 shows the typical protection scheme for a medium sizedgenerator. The figure also points out the Current and Voltage measuring regions foreach protection. Each protection is discussed briefly in this article.


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Figure 1:Typical protection Scheme For a 100 MW Generator along with Gen Transformer and Unit

Transformer

Phase Distance Protection (21)

The machine impedance protection is used as a selective time graded protectionto provide shortest possible tripping times for short-circuits in the synchronousmachine, on the terminal leads as well as in the lower voltage winding of the unittransformer. It thus provides a fast back-up protection to the generator andtransformer differential relays


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The phase distance function (21) is designed for system phase fault backupprotection and is implemented as a two-zone mho characteristic. Three separatedistance elements are used to detect AB, BC, and CA fault types. The diameter,offset, system impedance angle (relay characteristic angle), and definite time delayneed to be selected for each zone for coordination with the system relaying in thespecific application.

Typically the first zone of protection is set to an impedance value enough inexcess of the first external protective section (typically the unit transformer) toassure operation for faults within that protective zone. (See Figure 2, Phase Distance(21) Coverage.)

A negative or positive offset can be specified to offset the mho circle from theorigin. This offset is usually set at zero. (See Figure 3, Phase Distance (21) FunctionApplied For System Backup.) The impedance angle should be set as closely as possibleto the actual impedance angle of the zone being protected. The time delays are setto coordinate with the primary protection of those overreached zones and, whenapplicable, with the breaker failure schemes associated with those protective zones.

The Phase distance Second stage zone settings can be set for the secondexternal section of protection on the system (typically transmission Zone 1 distance

relays) plus adequate overreach.

Figure 2: Phase Distance coverage


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Figure 3: Phase Distance (21) Function Applied for System Backup

Volts/Hz (24)

The overexcitation protection is used to detect impermissible overexcitationconditions which can endanger generators and transformers. The overexcitationprotection must pick up when the induction admissible for the protected object (e.g.power station unit transformer) is exceeded. The transformer is endangered, forexample, if the power station block is disconnected from the system from full-load,

and if the voltage regulator either does not operate or does not operate sufficientlyfast to control the associated voltage rise. Similarly, decrease in frequency (speed),e.g. in island systems, can endanger the transformer because of increased induction.

An increase in induction above the rated values leads very quickly to saturationof the iron core and to large eddy current losses.

The overexcitation protection feature servers to measure the voltage/frequencyratio which is proportional to the B induction and puts it in relation to the BN nominalinduction. In this context, both voltage and frequency are related to nominal values of

the object to be protected (generator, transformer).


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The overexcitation protection feature includes two staged characteristics andone thermal characteristic for an approximate modeling of the heating which theoverexcitation may cause to the object to be protected.

The thermal characteristic is prespecified by 8 value pairs concerning the U/foverexcitation (related to nominal values) and the t trip time. In most cases, thespecified characteristic related to standard transformers provides for sufficientprotection. If this characteristic does not correspond to the actual thermal behaviorof the object to be protected, each desired characteristic can be implemented byentering customer-specific trip times for the specified U/f overexcitation values.Intermediate values are determined by a linear interpolation within the device. Thefigure below shows the tyypical tripping time characteristics for the over excitation

protection.

Figure 4: Tripping Time Characteristic of the Overexcitation Protection

Definite-Time Overcurrent Protection with undervoltage seal in(50/51)

The overcurrent protection is used as backup protection for the short-circuitprotection of the protected object. It also provides backup protection for downstreamnetwork faults which are not promptly disconnected and thus may endanger theprotected object.


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Each phase current is compared individually with the overcurrent commonsetting value. Currents above these value are recorded and signalled individually. Assoon as the corresponding time delay has elapsed, a trip signal is transmitted.

The overcurrent stage has an undervoltage stage. This stage maintains thepick-up signal for a settable seal-in time if the value falls below a settable thresholdof the positive-sequence component of the voltages after an overcurrent pickup – evenif the current falls again below the overcurrent pick-up value. But if the voltagerecovers before the seal in time has elapsed, the function will not be activated.

The function can also be implemented without undervoltage detection keepingthat option disabled

Inverse-Time Overcurrent Protection (51V)

The voltage dependent overcurrent function is used for system backupprotection and can trip the generator circuit breaker, if a fault has not been clearedby other protection after a certain period of time. The voltage dependent functioncan be either voltage controlled or voltage restrained.

In generators where the excitation voltage is derived from the machineterminals, the short-circuit current subsides quickly in the event of close-up faults

(i.e. in the generator or unit transformer range) due to the absence of excitationvoltage the current decreases within a few seconds to a value below the pick-up valueof the overcurrent time protection. In order to avoid a drop out of the pickup, thepositive sequence component is monitored additionally. This component can influencethe overcurrent detection according to two different methods.

It is similar to Definite time overcurrent protection but has two modes ofoperation.

•

Voltage controlled:

When voltage controlled, the timing characteristic is changed from a load to afault characteristic when the voltage drops below a set level. It is mainly used forgenerators connected directly to the busbar.

• Voltage restraint:


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When voltage restrained, the current pick-up level is proportionally lowered asthe voltage falls below a set value, producing a continuous variation of timingcharacteristics. This is applicable to generators connected to the busbar, each via astep-up transformer.

Figure 5: Voltage dependent overcurrent functions

Thermal Overload Protection (49)

The thermal overload protection feature of the 7UM61 is designed to preventoverloads from damaging the protected equipment. The device is capable of projecting

excessive operating temperatures for the protected equipment in accordance with athermal model, based on the following differential equation:

- Actual operating temperature expressed in per cent of theoperating temperature corresponding to the maximumpermissible operating current.

- Coolant temperature or ambient temperature as a difference tothe 40 °C reference temperature.

- Thermal time constant for the heating of the equipment beingProtected

I - Operating current expressed in per cent of the maximumpermissible operating current


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The thermal overload protection feature models a heat image of theequipment being protected. Both the previous history of an overload and the heat lossto the environment are taken into account.

The thermal overload protection calculates the operating temperature of theprotected equipment in per cent of the maximum allowable operating temperature.When the calculated operating temperature reaches a settable percentage of themaximum allowable operating temperature, a warning message is issued to allow timefor the load reduction measures to take place. If the second temperature threshold,i.e. end temperature = trip temperature, is reached, the protected equipment isdisconnected from the network.

The temperature rise is calculated from the highest of the three phasecurrents. Since the calculation is based on the r.m.s. values of the currents, it alsoconsiders harmonics which contribute to a temperature rise of the stator winding.

Unbalanced Load (Negative Sequence) Protection (46)

Negative phase sequence function is for the detection of sustained unbalancedload conditions. Under such circumstances double frequency eddy currents are inducedin the rotor of a generator and can cause rapid overheating. The function has a

thermal replica curve which simulates the effects of pre-fault heating due to lowlevels of standing negative phase sequence current I2. When the I2 value is well abovethreshold, the thermal replica approximates to a t = K/I2

2 characteristic, where K isthe generator’s per-unit current thermal capacity constant in seconds.

The tripping characteristic is shown in Figure 6. When high values of K areselected and the negative phase sequence currents measured are near to thethreshold, the operating time may be too slow. In this case, a maximum time settingtMAX is available to provide a safe trip time. When I2 is high, the operating time

may become too fast and cause loss of discrimination with other power systemprotection under fault conditions. To reduce this risk, the inverse characteristic isprovided with an adjustable minimum operating time setting tMIN.


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The machine manufacturers indicate the permissible unbalanced load by meansof the following formula.

where tperm =maximum permissible application time of the negative-sequencecurrent I2.

K =Asymmetry factor (machine constant)

I2/IN =Unbal. load (ratio neg. phase-sequ. I2 nom. cur. IN)

Figure 6: Negative phase sequence tripping characteristic

Differential Protection (87G)

The generator differential function is for the protection of phase to phase orthree-phase stator windings faults which normally involve high fault currents, so thatfast fault clearance is required. This function works on a per phase basis and has adual slope bias characteristic as shown in figure 7. The lower slope provides sensitivityfor internal faults, whereas the higher slope provides stability under through faultconditions, especially if the generator CTs saturate as discussed below.


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Figure 7: Generator differential bias characteristic

Differential protection systems operate according to the principle of currentcomparison (Kirchhoff’s current law). They utilize the fact that in a healthy protectedobject the current leaving the object is the same as that which entered it (currentIp, dotted in Figure.

Any measured current difference is a certain indication of a fault somewherewithin the protected zone. The secondary windings of current transformers CT1 andCT2, which have the same transformation ratio, may be so connected that a closedcircuit is formed. If now a measuring element M is connected at the electrical balancepoint, it reveals the current difference. Under healthy conditions (e.g. on-load

operation) no current flows in the measuring element. In the event of a fault in theprotected object, the summation current Ip1+Ip2 flows on the primary side. Thecurrents on the secondary side, I1 and I2 flow through the measuring element M. asa summation current I1+I2 (see Figure)

Figure 8: Basic Principle of Differential Protection (Single-Phase

Representation)


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(Ipx = primary current, Ix = secondary current)

When an external fault causes a heavy current to flow through the protected

zone, differences in the magnetic characteristics of the current transformers CT1and CT2 under conditions of saturation may cause a significant current to flowthrough the element M. If the magnitude of this current lies above the responsethreshold, the element would issue a trip signal. To prevent the protection from sucherroneous operation, a stabilizing current is brought in.

The stabilizing quantity is derived from the arithmetical sum of the absolutevalues of |I1| + |I2|. The following definitions apply:

The differential current

Idiff = |I1 + I2|

and the stabilization or restraining currentIstab = |I1| + |I2|

Idiff is derived from the fundamental frequency current and produces thetripping effect quantity, Istab counteracts this effect.

Note: if CT ratios are different it has to be matched to the common value,ie to generator full load current and the corresponding multiplier has to be fed to the

function. For the transformer cases, Vector group matching has also to be carriedout. If CT polarities are found to be reversed, it has to be changed without affectingthe Relay measurement circuit. Relay will usually carried out the measurements fromthe Generator neutral side CTs. In that case phase side CT polarities have to bereversed after ensuring the polarities of Neutral side CTs.

Underexcitation (Loss-of-Field) Protection (40)

Severe loss of excitation caused by field failure can cause a high value ofreactive current to be drawn from the power system which can endanger thegenerator. The field failure protection provided by this relay is a single phaseimpedance measuring element with an offset mho characteristic. An integrating timingarrangement, identical to that for the power functions, is also available in manyrelays. This allows the relay to trip within the pre-determined time delay even thoughthe impedance measurement may temporarily fall outside the mho characteristic, eg.under poleslipping conditions.


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For generators that are paralleled to a power system, the preferred method isto monitor for loss of field at the generator terminals. When a generator losesexcitation power, it appears to the system as an inductive load, and the machinebegins to absorb a large amount of VARs. Loss of field may be detected by monitoringfor VAR flow or apparent impedance at the generator terminals. The power diagram(P-Q plane) of Fig. 9 shows the characteristic with a representative setting, arepresentative generator thermal capability curve, and an example of the trajectoryfollowing a loss of excitation. The first quadrant of the diagram applies for laggingpower factor operation (generator supplies VARs). The trajectory starts at point Aand moves into the leading power factor zone (4th quadrant) and can readily exceedthe thermal capability of the unit. A trip delay of about 0.2-0.3 seconds isrecommended to prevent unwanted operation due to other transient conditions. A

second high speed trip zone might be included for severe underexcitation conditions.

Figure 9: FOR LOSS OF FIELD THE POWER TRAJECTORY MOVES FROM POINT A INTO THE

FOURTH QUADRANT.


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When impedance relaying is used to sense loss of excitation, the trip zonetypically is marked by a mho circle centered about the X axis, offset from the R axisby X'd/2. Two zones sometimes are used: a high speed zone and a time delayed zone.

Figure 10: LOSS OF EXCITATION USING IMPEDANCE RELAY.

With complete loss of excitation, the unit will eventually operate as an inductiongenerator with a positive slip. Because the unit is running above synchronous speed,excessive currents can flow in the rotor, resulting in overheating of elements notdesigned for such conditions. This heating cannot be detected by thermal relay 49,which is used to detect stator overloads.

Rotor thermal capability can also be exceeded for a partial reduction in

excitation due to an operator error or regulator malfunction. If a unit is initiallygenerating reactive power and then draws reactive power upon loss of excitation, thereactive swings can significantly depress the voltage. In addition, the voltage willoscillate and adversely impact sensitive loads. If the unit is large compared to theexternal reactive sources, system instability can result.

Reverse Power Protection (32R)

Reverse power protection is used to protect a turbo-generator unit in case offailure of energy to the prime mover. In this case the synchronous generator runs as

a motor and drives the turbine, taking the required motoring energy from thenetwork. This condition leads to overheating of the turbine blades and must beinterrupted within a short time by tripping the network circuit-breaker. For thegenerator, there is the additional risk that in case of a malfunctioning residual steampass (defective stop valves) after the switching off of the circuit breakers, theturbine-generator-unit is speeded up, thus reaching an overspeed. For this reason,the system isolation should only be performed after the detection of active powerinput into the machine.


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Forward Active Power Supervision (32F)

Forward Active Power Supervision monitors whether the active power fallsbelow one set threshold, and whether a separate second set threshold is exceeded.Each of these functions can initiate different control functions. When, for example,with generators operating in parallel, the active power output of one machine becomesso small that other generators could take over this power, and then it is oftenappropriate to shut down the lightly loaded machine. The criterion in this case is thatthe “forward” power supplied into the network falls below a certain value.

Out-of-Step Protection (78)

In extensive high-voltage networks, short-circuits which are not disconnectedquickly enough, or disconnection of coupling links which may result in an increasing ofthe coupling reactance, may lead to system swings. These consist of power swingswhich endanger the stability of the power transmission. Stability problems result inparticular from active power swings which can lead to pole-slipping and thus tooverloading of the synchronous machines.

The out-of-step protection detects these power swings by the well-provenimpedance measurement. The trajectory of the complex impedance vector is

evaluated. The impedance is calculated from the positive sequence components of thevoltages and currents. Trip decision is made dependent of the rate of change of theimpedance vector and on the location of the electrical centre of the power swing.

The pickup area is restricted to the shaded area in Figure 11, Out-of-StepRelay Characteristics defined by the inner region of the MHO circle, the region tothe right of the blinder A and the region to the left of blinder B. For operation ofthe blinder scheme, the operating point (positive sequence impedance) must originateoutside either blinder A or B, and swing through the pickup area for a time greater

than or equal to the time delay setting and progress to the opposite blinder fromwhere the swing had originated. When this scenario happens, the tripping circuit iscomplete.


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Figure 11: Out-of-Step Relay Characteristics

Under-voltage Protection (27)

Under voltage protection detects and reports abnormally low voltage conditions,some of which could be related to system stability problems (voltage collapse, etc.)Two-pole short circuits or earth faults cause an asymmetrical voltage collapse.Compared with three mono-phase measuring systems, the detection of the positive

phase-sequence system is not influenced by these procedures and is advantageousespecially with regard to the judgement of stability problems.

Overvoltage Protection (59)

Overvoltage protection serves to protect the electrical machine, and theassociated electrical plant connected to it, from the effects of impermissible voltageincreases. Overvoltages can be caused by incorrect manual operation of the excitationsystem, faulty operation of the automatic voltage regulator, (full) load shedding of agenerator, separation of the generator from the system or during island operation.

Frequency Protection(81)

The frequency protection function detects abnormally high and low frequenciesin the system. If the frequency lies outside the allowable range, appropriate actionsare initiated, such as separating a generator from the system.


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A decrease in system frequency occurs when the system experiences an increasein the real power demand, or when a malfunction occurs with a generator governor orautomatic generation control (AGC) system. The frequency decrease protection is alsoused for generators which (for a certain time) function on an island network. This isdue to the fact that the reverse power protection cannot operate in case of a drivepower failure. The generator can be disconnected from the power system by means ofthe frequency decrease protection.

An increase in system frequency occurs when large blocks of load are removedfrom the system, or again when a malfunction occurs with a generator governor orAGC system. This means a risk of self-excitation for generators feeding long linesunder no load conditions.

90–%–Stator Earth Fault Protection (59N,64G)

The stator earth fault protection detects earth faults in the stator windings ofthreephase machines. The machine can be operated in busbar connection (directlyconnected to the network) or in unit connection (via unit transformer). The criterionfor the occurrence of an earth fault is mainly the occurrence of a neutraldisplacement voltage. This principle results in a protected zone of 90%to 95%of thestator winding. Beyond that the setting value cannot be lowered as it may lead tofalse trippings. So only 90-95% of the winding only could be protected using the

function.The displacement voltage UE can be measured either at the machine starpoint

via voltage transformers or neutral earthing transformers (Figure 12) or via the e-nwinding (broken delta winding) of a voltage transformer set or the measurementwinding of a line connected earthing transformer (Figure 13).

Figure 12: Unit Connected Generator with Neutral Earthing Transformer


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Figure 13: Unit Connected Generator with Earthing Transformer

100–%–Stator Earth Fault Protection with 3rd Harmonics(27/59TN)

As described in the previous section, the measuring procedure based on thefundamental wave of the displacement voltage serves to protect maximally 90 % to 95% of the stator winding. A non-line-frequent voltage must be used to implement a100 % protection range.

The 3rd harmonic is created in each machine in a more or less significant way.It is provoked by the shape of the poles. If an earth fault occurs in the generator

stator winding, the division ratio of the parasitic capacitances changes, as one of thecapacitances was short-circuited by the earth fault. During this procedure, the 3rd harmonic measured in the starpoint decreases, whereas the 3rd harmonic measured atthe generator terminals increases (see figure 12). The 3rd harmonic forms a zerophase-sequence system and can thus also be determined by means of the voltagetransformer switched in star/delta or by calculating the zero phase-sequence systemfrom the phase-earth-voltages.


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Figure 14: Profile of the 3rd Harmonic along the Stator Winding

Moreover, the level of the 3rd harmonic depends on the operating point of thegenerator, i.e. a function of the P active power and the Q reactive power. For thisreason, the working area of the stator earth fault protection is restricted in order toenhance security.

100–% Stator Earth Fault Protection with 20 Hz Voltage Injection (64G)

The 100-% stator earth fault protection detects earth faults in the statorwindings of generators which are connected with the network via a unit transformer.This protection function, which works with an injected 20 Hz voltage, is independentof the system frequency displacement voltage appearing in earth faults, and detectsearth faults in all windings including the machine starpoint. The measuring principleused is not influenced at all by the generator operating mode and allows to performmeasurements even with the generator standing still. The two measuring principlesused – measurement of the displacement voltage and evaluation of the measuredquantities at an injected 20 Hz voltage – allow to implement reliable protectionconcepts that complement one another. If an earth fault in the generator starpoint orclose to the starpoint is not detected, the generator is running with an “earthing”. A

subsequent fault (e.g. a second earth fault) causes a single-pole short-circuit thatmay have an extremely high fault current because the generator zero impedance isvery small.

Figure 15 shows the basic protection principle. An external low-frequencyalternating voltage source (20 Hz) injects into the generator starpoint a voltage ofmax. 1 % of the rated generator voltage. If an earth fault occurs in the generator


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starpoint, the 20 Hz voltage drives a current through the fault resistance. From thedriving voltage and the fault current, the protective relay determines the faultresistance. The protection principle described here also detects earth faults at thegenerator terminals, including connected components such as voltage transformers.

Figure 15: Basic Principle of Voltage Injection into the Generator Starpoint

Rotor Earth Fault Protection (64R)

Rotor earth fault protection is used to detect earth faults in the excitationcircuit of the synchronous machines. One earth fault in the rotor winding does notcause immediate damage; however, if a second earth fault occurs, then thisrepresents a winding short-circuit of the excitation circuit. Magnetic unbalances canoccur resulting in extreme mechanical forces which can lead to the destruction of the

machine.

The rotor earth fault protection in the Siemens 7UM62 relay is mentioned as anexample. It uses an external auxiliary voltage of approximately 36 to 45 V AC, whichcan be taken from the voltage transformers via a coupling unit. This voltage issymmetrically coupled to the excitation circuit via the capacitors of the coupling unitand simultaneously connected to the measurement input of the relay. The capacitorsCK of the coupling unit are protected by series resistors R series. The auxiliary ACvoltage drives a small charging current through the coupling unit, brush resistance and

capacitance to earth of the excitation circuit. This current IRE amounts to only a fewmA during normal operation and is measured by the device


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Figure16 : Determination of the Rotor Earth Resistance R E

The rotor earth fault calculation calculates the complex earth impedance fromthe auxiliary AC voltage URE and the current IRE. The earth resistance RE of the

excitation circuit is then calculated from the earth impedance. The device alsoconsiders the coupling capacitance of the coupling unit CK, the series (e.g. brush)resistance Rseries and the capacitance to the earth excitation circuit CE. Thismethod ensures that even relatively high-ohmic earth faults (up to 30 kΩ under idealconditions) can be detected. In order to eliminate the influence of harmonics - suchas occur in static excitation equipment (thyristors or rotating rectifiers) - themeasured quantities are filtered prior to their evaluation

Breaker Failure Protection (50BF)

The breaker failure protection can be assigned to the current inputs of side 1or side 2 during the configuration of the protective functions The breaker failureprotection function monitors the reaction of a circuit breaker to a trip signal. Inmachine protections, it is typically referred to the mains breaker. To determine ifthe circuit breaker has properly opened in response to a trip signal, one of thefollowing methods is used to ascertain the status of the circuit breaker:


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• Checking whether the current in all three phases drops below a set thresholdfollowing a trip command,

• Evaluating the position of a circuit breaker auxiliary contact for protectivefunctions, with which the current criterion is perhaps not expressive, e.g.frequency protection, voltage protection, rotor earth fault protection.

If the circuit breaker has not opened after a programmable time delay (breakerfailure), a higher-level circuit breaker can be initiated for the disconnection

Inadvertent Energization (50/27)

The inadvertent energizing protection serves to limit damages by accidentalconnection of the standing or already started, but not yet synchronized generator bya fast actuation of the mains breaker. A connection to a standing machinecorresponds to the connection to an inductivity. Due to the nominal voltage impressedby the power system, the generator starts with a high slip as asynchronous machine.In this context, impermissibly high currents are induced inside the rotor which mayfinally destroy it.

The inadvertent energizing protection only intervenes if measured quantities do

not yet exist in the valid frequency working area (operational condition 0 in case ofthe standing machine) or if an undervoltage below the nominal frequency is present(machine already started, but not yet synchronized). The inadvertent energizingprotection is blocked by a voltage criterion on exceeding a minimum voltage, in orderto avoid that it picks up during normal operation. This blocking is delayed to avoidthat the protection is blocked immediately by the time of an unwanted connection.Another pickup delay is necessary to avoid an unwanted operation in case of high-current faults with a heavy voltage dip. A dropout time delay allows for a measuringlimited in time.


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UNITS WHICH HAVE ACHIEVED 100% OA

THERMAL500 MW

RAMAGUNDAM UNITS – 4 & 7TALCHER UNIT – 4, 5 & 6

SIMHADRI UNIT – 2

210 MWMUDDANUR UNITS – 1 & 3

RAICHUR UNIT – 1 & 4METTUR UNIT – 4TUTICORIN UNIT – 1 & 4

NORTH CHENNAI UNIT – 2 & 3

UNITS WHICH HAVE ACHIEVED PLF MORE THAN 100%

500 MWRAMAGUNDAM UNIT - 7

SIMHADRI UNIT - 2

UNITS WHICH HAVE ACHIEVED PLF BETWEEN 90 & 100%

THERMAL 500 MW

RAMAGUNDAM UNITS – 4TALCHER UNITS – 2,4,5 & 6

SIMHADRI UNIT – 1SIPAT UNIT - 4

250 MW

KOTHAGUDAM UNIT – 9210 MW

VIJAYAWADA UNITS – 1,2,3,4 & 5MUDDANUR UNIT – 1 & 3

RAICHUR UNIT - 4METTUR UNIT – 4

NORTH CHENNAI UNIT - 3


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PLF

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20.00

40.00

60.00

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100.00

120.00

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M e t t u

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P L F P E R C E N T A G E

2009 - 10 2010 - 11

PERFORMANCE OF BHEL THERMAL SETS IN SR (210 MW AND ABOVE)

FOR THE PERIOD FROM 01/04/2010 TO 31/10/2010 COMPARED WITH THE

CORRESPONDING PERIOD IN THE PREVIOUS YEAR.

( PLF IN PERCENTAGE )

STATION 2009 - 10 2010 - 11

North Chennai 87.09 76.14

Neyveli 85.42 84.18

Raichur 77.38 55.45

Tuticorin 78.30 78.44

Ramagundam 89.07 92.55

Muddanur 82.11 80.36

Kothagudam 93.08 66.15Vijayawada 90.69 73.59

VTPS - 7 - 65.39

Mettur 91.52 79.67

Talcher 85.28 84.69

Simhadri 92.97 92.90

Sipat 91.65 97.08

Documents

Generator Protection Functions