RAIGARH TPP OCTOBER : 2010 VOLUME : 14 - BHEL - … OCTOBER 2010 TS TIDINGS TECHNICAL SERVICES / PSSR Published by Technical Services / PSSR RAIGARH TPP OCTOBER : 2010 VOLUME : 14.05

1 OCTOBER 2010 TS TIDINGS

TECHNICAL SERVICES / PSSR

RAIGARH TPP OCTOBER : 2010 VOLUME : 14.05

Published by Technical Services / PSSR For 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.



INSIDE

1. STATUS OF PROJECTS COMMISSIONED / TO BE COMMISSIONED DURING 2009 - 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 TS TIDINGS are welcome and may please be addressed to ADDL. GENERAL MANAGER (TSX)/BHEL-PSSR/CHENNAI



STATUS OF PROJECTS COMMISSIONED / TO BE COMMISSIONED DURING 2009 – 2011 : AMARKANTAK – UNIT 5 :

Unit was synchronized on 05.10.2010 after overhaul and PG test preparations.

TG PG test (100% and 80% load) , auxiliary power consumption test and Boiler

PG 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 was attended 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.



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

ESP : Charging of ACP and controller panels was completed. ESP – A pass CERM, EERM & GDRM trial run was completed. Dummy load test of all field controller panels was carried out in ESP – A pass. OCC and SCC tests for 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 unit control 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 auxiliary drive 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. It tripped 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.



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 with two 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 was carried out.

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

HFO pump house temperature control valve and pressure control valve were commissioned 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 the CW pump house parameters were checked from control room.



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 on 04.10.2010.

72 hours full load trial operation was completed successfully on 11.10.2010.

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 on 30.10.2010

VIJAYAWADA UNIT 7:

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

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

Unit is presently running around 450 – 500 MW.



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 200 MW.

Mill – D scrapper replacement work was completed.

Unit tripped twice on 21.10.2010 due to (1) generator differential fault on R phase and (2) opening of GCB. Unit was resynchronized on 22.10.2010 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 of Boiler 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



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 was completed.

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

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 carried out.

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 run were completed.

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



SERVICES RENDERED TO CUSTOMER /SAS/MUs: Shri. P Muthu, AGM/Kakatiya site and Shri. R Ganeshram, Engineer, TSX, Chennai were deputed to Neyveli for attending to high shaft vibration problem of unit number 7 of TS II.

CUSTOMER TRAINING & TECHNICAL PAPER PRESENTED:

--- NIL ---

APPRECIATION FROM CUSTOMER FOR SERVICES RENDERED :

--- NIL ---



FEED BACK NO.1

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

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 Babbitt damage and pitting. After the overhaul, the vibration value at HP (front) shaft was found 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 HP rotor. After second trim balancing, the vibration levels were slightly found reduced, but in due course the vibration levels increased with HP front shaft vibration level maintaining 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 slight reduction of HP shaft vibrations from 175 microns to 160 microns. However, turbine vibrations 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 in Aug/Sep 2010.The significant defects noticed and rectification works carried out are given below in brief.

• Shifting of total turbine rotor along with combined thrust and journal bearing in axial direction towards Generator by 1 mm when compared to previous assembly position ( 2008).

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



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

• Axial key pitting marks in the pedestal were removed by grinding and matching was ensured.

Turbine cold rolling was done on 18.09.2010. The load could not be raised beyond 115 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 bearing no.2 reached the trip value of 45 microns. Again turbine rolling was done and the load was raised gradually up to about 190 MW. The pedestal vibrations were found to be higher 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 aligning problem 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 was brought back into service, the vibration values at HP front and HP rear shaft went beyond 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 by BHEL-SAS from 01.10.2010 to 09.10.2010 . The major defects noticed are given below 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 slope of 0.85 mm/meter (High at turbine side i.e., front).

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



• The support was removed form location and checked .The measurement reveal slope as 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 measurement levels 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 proper self 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 on 10.10.2010 @ 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 on 11.10.2010.Performance of the machine was satisfactory and the vibration levels are as follows.



BrgNo Shell 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 bearing No.2

CONCLUSION:

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

Prepared by :

V.Naga Raju, Jr.Executive(Engg) Staff No : 2767554 BHEL-PSSR-SAS Secunderabad.



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 with ACW water and subsequently with DMCW water. High vibration and noise was heard during 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 casing and NDE side wear ring was found jammed on to the impeller. It was cleaned by light emery polishing, and pump was reassembled. During the reassembly, the DE / NDE end 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 had to 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 and pump 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 impeller and rubbing/ scoring marks were observed on the impeller wear ring area. Polishing was carried out on wear ring,.

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

On 08/10/2010, a senior pump service engineer was deputed by M/s. Flow more to 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 dislocation of spring retention pin (Refer seal drawing),caused by jamming.

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



Hence a suction strainer from ACW system was borrowed from customer and was 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. After stopping, again it got jammed. Minor buffing on NDE wear ring saw it run for 72hrs continuously. But upon stopping it again got jammed.

Resolution:

Pump – B was opened and the wearing ring to top casing blue contact was checked. It was found that there is no contact of top half casing with the wearing ring 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 of 1mm parting plane gasket. The wearing ring was also found to be oval and hence both NDE and DE wearing rings ovality were removed. After box up of pump – B it was rotating freely after trial run for 2hrs. No further correction was necessary.

SGDMCW Seal Drawing





Conclusion:

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

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



GENERATOR PROTECTION FUNCTIONS

Introduction Protection against internal and external faults and immediate isolation of the network are extremely important for even small sized generators and transformers. The prompt isolation against the faults will save the equipment from further damage and also saves the human life. This article provides an overview of the basic protection concepts applied for large generators with respect to numerical protection relays. The figure 1 shows the typical protection scheme for a medium sized generator. The figure also points out the Current and Voltage measuring regions for each protection. Each protection is discussed briefly in this article.



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 protection to provide shortest possible tripping times for short-circuits in the synchronous machine, on the terminal leads as well as in the lower voltage winding of the unit transformer. It thus provides a fast back-up protection to the generator and transformer differential relays



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

Typically the first zone of protection is set to an impedance value enough in

excess of the first external protective section (typically the unit transformer) to assure 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 the

origin. This offset is usually set at zero. (See Figure 3, Phase Distance (21) Function Applied For System Backup.) The impedance angle should be set as closely as possible to the actual impedance angle of the zone being protected. The time delays are set to coordinate with the primary protection of those overreached zones and, when applicable, with the breaker failure schemes associated with those protective zones.

The Phase distance Second stage zone settings can be set for the second

external section of protection on the system (typically transmission Zone 1 distance relays) plus adequate overreach.

Figure 2: Phase Distance coverage



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

Volts/Hz (24) The overexcitation protection is used to detect impermissible overexcitation

conditions which can endanger generators and transformers. The overexcitation protection must pick up when the induction admissible for the protected object (e.g. power station unit transformer) is exceeded. The transformer is endangered, for example, 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 sufficiently fast 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 saturation of the iron core and to large eddy current losses.

The overexcitation protection feature servers to measure the voltage/frequency

ratio which is proportional to the B induction and puts it in relation to the BN nominal induction. In this context, both voltage and frequency are related to nominal values of the object to be protected (generator, transformer).



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

The thermal characteristic is prespecified by 8 value pairs concerning the U/f

overexcitation (related to nominal values) and the t trip time. In most cases, the specified characteristic related to standard transformers provides for sufficient protection. If this characteristic does not correspond to the actual thermal behavior of the object to be protected, each desired characteristic can be implemented by entering customer-specific trip times for the specified U/f overexcitation values. Intermediate values are determined by a linear interpolation within the device. The figure 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-circuit protection of the protected object. It also provides backup protection for downstream network faults which are not promptly disconnected and thus may endanger the protected object.



Each phase current is compared individually with the overcurrent common setting value. Currents above these value are recorded and signalled individually. As soon as the corresponding time delay has elapsed, a trip signal is transmitted. The overcurrent stage has an undervoltage stage. This stage maintains the pick-up signal for a settable seal-in time if the value falls below a settable threshold of the positive-sequence component of the voltages after an overcurrent pickup – even if the current falls again below the overcurrent pick-up value. But if the voltage recovers before the seal in time has elapsed, the function will not be activated. The function can also be implemented without undervoltage detection keeping that option disabled

Inverse-Time Overcurrent Protection (51V)

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

In generators where the excitation voltage is derived from the machine terminals, 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 excitation voltage the current decreases within a few seconds to a value below the pick-up value of the overcurrent time protection. In order to avoid a drop out of the pickup, the positive sequence component is monitored additionally. This component can influence the overcurrent detection according to two different methods.

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

• Voltage controlled:

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

• Voltage restraint:



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

Figure 5: Voltage dependent overcurrent functions

Thermal Overload Protection (49)

The thermal overload protection feature of the 7UM61 is designed to prevent overloads from damaging the protected equipment. The device is capable of projecting excessive operating temperatures for the protected equipment in accordance with a thermal model, based on the following differential equation:

- Actual operating temperature expressed in per cent of the operating temperature corresponding to the maximum permissible operating current.

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

- Thermal time constant for the heating of the equipment being Protected

I - Operating current expressed in per cent of the maximum permissible operating current



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

The thermal overload protection calculates the operating temperature of the

protected equipment in per cent of the maximum allowable operating temperature. When the calculated operating temperature reaches a settable percentage of the maximum allowable operating temperature, a warning message is issued to allow time for the load reduction measures to take place. If the second temperature threshold, i.e. end temperature = trip temperature, is reached, the protected equipment is disconnected from the network.

The temperature rise is calculated from the highest of the three phase

currents. Since the calculation is based on the r.m.s. values of the currents, it also considers 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 unbalanced

load conditions. Under such circumstances double frequency eddy currents are induced in 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 low levels of standing negative phase sequence current I2. When the I2 value is well above threshold, the thermal replica approximates to a t = K/I2

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

The tripping characteristic is shown in Figure 6. When high values of K are

selected and the negative phase sequence currents measured are near to the threshold, the operating time may be too slow. In this case, a maximum time setting tMAX 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 system protection under fault conditions. To reduce this risk, the inverse characteristic is provided with an adjustable minimum operating time setting tMIN.



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

where tperm =maximum permissible application time of the negative-sequence

current 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 or

three-phase stator windings faults which normally involve high fault currents, so that fast fault clearance is required. This function works on a per phase basis and has a dual slope bias characteristic as shown in figure 7. The lower slope provides sensitivity for internal faults, whereas the higher slope provides stability under through fault conditions, especially if the generator CTs saturate as discussed below.



Figure 7: Generator differential bias characteristic

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

Any measured current difference is a certain indication of a fault somewhere within the protected zone. The secondary windings of current transformers CT1 and CT2, which have the same transformation ratio, may be so connected that a closed circuit is formed. If now a measuring element M is connected at the electrical balance point, 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 the protected object, the summation current Ip1+Ip2 flows on the primary side. The currents on the secondary side, I1 and I2 flow through the measuring element M. as a summation current I1+I2 (see Figure)

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



(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 CT1 and CT2 under conditions of saturation may cause a significant current to flow through the element M. If the magnitude of this current lies above the response threshold, the element would issue a trip signal. To prevent the protection from such erroneous operation, a stabilizing current is brought in.

The stabilizing quantity is derived from the arithmetical sum of the absolute

values of |I1| + |I2|. The following definitions apply: The differential current Idiff = |I1 + I2| and the stabilization or restraining current Istab = |I1| + |I2| Idiff is derived from the fundamental frequency current and produces the

tripping 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 carried out. If CT polarities are found to be reversed, it has to be changed without affecting the Relay measurement circuit. Relay will usually carried out the measurements from the Generator neutral side CTs. In that case phase side CT polarities have to be reversed 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 of reactive current to be drawn from the power system which can endanger the generator. The field failure protection provided by this relay is a single phase impedance measuring element with an offset mho characteristic. An integrating timing arrangement, identical to that for the power functions, is also available in many relays. This allows the relay to trip within the pre-determined time delay even though the impedance measurement may temporarily fall outside the mho characteristic, eg. under poleslipping conditions.



For generators that are paralleled to a power system, the preferred method is to monitor for loss of field at the generator terminals. When a generator loses excitation power, it appears to the system as an inductive load, and the machine begins to absorb a large amount of VARs. Loss of field may be detected by monitoring for 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, a representative generator thermal capability curve, and an example of the trajectory following a loss of excitation. The first quadrant of the diagram applies for lagging power factor operation (generator supplies VARs). The trajectory starts at point A and moves into the leading power factor zone (4th quadrant) and can readily exceed the thermal capability of the unit. A trip delay of about 0.2-0.3 seconds is recommended 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.



When impedance relaying is used to sense loss of excitation, the trip zone typically is marked by a mho circle centered about the X axis, offset from the R axis by 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 induction generator with a positive slip. Because the unit is running above synchronous speed, excessive currents can flow in the rotor, resulting in overheating of elements not designed 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 initially generating reactive power and then draws reactive power upon loss of excitation, the reactive swings can significantly depress the voltage. In addition, the voltage will oscillate and adversely impact sensitive loads. If the unit is large compared to the external reactive sources, system instability can result.

Reverse Power Protection (32R)

Reverse power protection is used to protect a turbo-generator unit in case of failure 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 the network. This condition leads to overheating of the turbine blades and must be interrupted within a short time by tripping the network circuit-breaker. For the generator, there is the additional risk that in case of a malfunctioning residual steam pass (defective stop valves) after the switching off of the circuit breakers, the turbine-generator-unit is speeded up, thus reaching an overspeed. For this reason, the system isolation should only be performed after the detection of active power input into the machine.



Forward Active Power Supervision (32F) Forward Active Power Supervision monitors whether the active power falls

below 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 becomes so small that other generators could take over this power, and then it is often appropriate to shut down the lightly loaded machine. The criterion in this case is that the “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 disconnected quickly enough, or disconnection of coupling links which may result in an increasing of the coupling reactance, may lead to system swings. These consist of power swings which endanger the stability of the power transmission. Stability problems result in particular from active power swings which can lead to pole-slipping and thus to overloading of the synchronous machines.

The out-of-step protection detects these power swings by the well-proven impedance measurement. The trajectory of the complex impedance vector is evaluated. The impedance is calculated from the positive sequence components of the voltages and currents. Trip decision is made dependent of the rate of change of the impedance 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-Step Relay Characteristics defined by the inner region of the MHO circle, the region to the right of the blinder A and the region to the left of blinder B. For operation of the blinder scheme, the operating point (positive sequence impedance) must originate outside 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 from where the swing had originated. When this scenario happens, the tripping circuit is complete.



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 advantageous especially with regard to the judgement of stability problems. Overvoltage Protection (59)

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

Frequency Protection(81)

The frequency protection function detects abnormally high and low frequencies

in the system. If the frequency lies outside the allowable range, appropriate actions are initiated, such as separating a generator from the system.



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

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

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

The stator earth fault protection detects earth faults in the stator windings of

threephase machines. The machine can be operated in busbar connection (directly connected to the network) or in unit connection (via unit transformer). The criterion for the occurrence of an earth fault is mainly the occurrence of a neutral displacement voltage. This principle results in a protected zone of 90%to 95%of the stator winding. Beyond that the setting value cannot be lowered as it may lead to false 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-n winding (broken delta winding) of a voltage transformer set or the measurement winding of a line connected earthing transformer (Figure 13).

Figure 12: Unit Connected Generator with Neutral Earthing Transformer



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 the fundamental 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 a 100 % 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 the capacitances was short-circuited by the earth fault. During this procedure, the 3rd harmonic measured in the starpoint decreases, whereas the 3rd harmonic measured at the generator terminals increases (see figure 12). The 3rd harmonic forms a zero phase-sequence system and can thus also be determined by means of the voltage transformer switched in star/delta or by calculating the zero phase-sequence system from the phase-earth-voltages.



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

Moreover, the level of the 3rd harmonic depends on the operating point of the generator, i.e. a function of the P active power and the Q reactive power. For this reason, the working area of the stator earth fault protection is restricted in order to enhance security. 100–% Stator Earth Fault Protection with 20 Hz Voltage Injection (64G)

The 100-% stator earth fault protection detects earth faults in the stator windings of generators which are connected with the network via a unit transformer. This protection function, which works with an injected 20 Hz voltage, is independent of the system frequency displacement voltage appearing in earth faults, and detects earth faults in all windings including the machine starpoint. The measuring principle used is not influenced at all by the generator operating mode and allows to perform measurements even with the generator standing still. The two measuring principles used – measurement of the displacement voltage and evaluation of the measured quantities at an injected 20 Hz voltage – allow to implement reliable protection concepts that complement one another. If an earth fault in the generator starpoint or close 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 that may have an extremely high fault current because the generator zero impedance is very small. Figure 15 shows the basic protection principle. An external low-frequency alternating voltage source (20 Hz) injects into the generator starpoint a voltage of max. 1 % of the rated generator voltage. If an earth fault occurs in the generator



starpoint, the 20 Hz voltage drives a current through the fault resistance. From the driving voltage and the fault current, the protective relay determines the fault resistance. The protection principle described here also detects earth faults at the generator 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 excitation circuit of the synchronous machines. One earth fault in the rotor winding does not cause immediate damage; however, if a second earth fault occurs, then this represents a winding short-circuit of the excitation circuit. Magnetic unbalances can occur 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 an example. It uses an external auxiliary voltage of approximately 36 to 45 V AC, which can be taken from the voltage transformers via a coupling unit. This voltage is symmetrically coupled to the excitation circuit via the capacitors of the coupling unit and simultaneously connected to the measurement input of the relay. The capacitors CK of the coupling unit are protected by series resistors R series. The auxiliary AC voltage 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 few mA during normal operation and is measured by the device



Figure16 : Determination of the Rotor Earth Resistance RE

The rotor earth fault calculation calculates the complex earth impedance from the 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 also considers the coupling capacitance of the coupling unit CK, the series (e.g. brush) resistance Rseries and the capacitance to the earth excitation circuit CE. This method ensures that even relatively high-ohmic earth faults (up to 30 kΩ under ideal conditions) can be detected. In order to eliminate the influence of harmonics - such as occur in static excitation equipment (thyristors or rotating rectifiers) - the measured quantities are filtered prior to their evaluation

Breaker Failure Protection (50BF)

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



• Checking whether the current in all three phases drops below a set threshold following a trip command, • Evaluating the position of a circuit breaker auxiliary contact for protective functions, 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 (breaker failure), a higher-level circuit breaker can be initiated for the disconnection Inadvertent Energization (50/27)

The inadvertent energizing protection serves to limit damages by accidental connection of the standing or already started, but not yet synchronized generator by a fast actuation of the mains breaker. A connection to a standing machine corresponds to the connection to an inductivity. Due to the nominal voltage impressed by 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 may finally 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 of the standing machine) or if an undervoltage below the nominal frequency is present (machine already started, but not yet synchronized). The inadvertent energizing protection is blocked by a voltage criterion on exceeding a minimum voltage, in order to avoid that it picks up during normal operation. This blocking is delayed to avoid that 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 measuring limited in time.



UNITS WHICH HAVE ACHIEVED 100% OA

THERMAL

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

SIMHADRI UNIT – 2

210 MW MUDDANUR UNITS – 1 & 3

RAICHUR UNIT – 1 & 4 METTUR UNIT – 4

TUTICORIN UNIT – 1 & 4 NORTH CHENNAI UNIT – 2 & 3

UNITS WHICH HAVE ACHIEVED PLF MORE THAN 100%

500 MW RAMAGUNDAM UNIT - 7

SIMHADRI UNIT - 2

UNITS WHICH HAVE ACHIEVED PLF BETWEEN 90 & 100%

THERMAL

500 MW RAMAGUNDAM UNITS – 4

TALCHER UNITS – 2,4,5 & 6 SIMHADRI UNIT – 1

SIPAT UNIT - 4

250 MW KOTHAGUDAM UNIT – 9

210 MW

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

RAICHUR UNIT - 4 METTUR UNIT – 4

NORTH CHENNAI UNIT - 3



PLF

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20.00

40.00

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80.00

100.00

120.00

North

Che

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Neyve

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Raich

ur

Tutic

orin

Ramag

unda

m

Mud

danu

r

Koth

agud

am

Vijaya

wada

VTPS

- 7

Met

tur

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er

Simha

dri

Sipa

t

UNIT

PLF PE

RCEN

TAGE

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 66.15 Vijayawada 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

RAIGARH TPP OCTOBER : 2010 VOLUME : 14 - BHEL - … OCTOBER 2010 TS TIDINGS TECHNICAL SERVICES / PSSR Published by Technical Services / PSSR RAIGARH TPP OCTOBER : 2010 VOLUME : 14.05