Report on Boiler Performance Audting in a Paper Plant by K.K.parthiban

8/13/2019 Report on Boiler Performance Audting in a Paper Plant by K.K.parthiban

1/129

2 November, 2013

REPORT ON STUDY AND RECOMMENDATIONS FOR EVAPORATION RATIO

IMPROVEMENT IN 80 TPH AND 125 TPH AFBC BOILERS

By Venus energy audit system

The study was undertaken to review the present evaporation ratio in 80 TPH and 125 TPH AFBC

boilers. Our engineers and undersigned collected lot of operational data to analyse the present

evaporation ratio. The study lasted for duration of 12 days. Further 5 days were spent in analysis and

preparation of the report and necessary drawings.

REVIEW OF EVAPORATION RATIO

Evaporation ratio terminology

At present the evaporation ratio is used to measure the performance of the boilers. The quantity of

steam produced and the quantity of fuel fed are used to calculate the performance. This number can

be used for review provided the fuel is same and the GCV variance is minimum. The fuel with lowerGCV will produce less evaporation ratio. Instead it is necessary to compare the expected evaporation

ratio and actual ratio achieved. The expected evaporation ratio is the steam that can be produced

based on the representative GCV. The representative GCV has to be arrived at the fuel mix and their

GCV at the time of feeding in to the raw coal hopper. Standard GCV / receipt GCV cannot be used

for this.

Expected evaporation ratio- FUEL GCV

Expected evaporation ratio needs the steam flow, enthalpy of steam, enthalpy of water, normal

efficiency for the fuel mix and the mix fuel GCV.

Steam flow is taken from flowmeter readings. Enthalpy of steam and water can be taken from steam tables for the average steam / water

pressure and average temperature.

Expected efficiency of the FBC boiler is in general above 80% for Indian coal / imported coal,provided the load is steady and there are no disturbances in boiler operation. The efficiency for

saw dust will be 75% for a moisture of 35%.

Fuel GCV in a fired fuel is to be based on a fuel sample. It is seen that the fuel combinationkeeps varying due to various reasons. Hence the GCV itself varies in 24 hours period. It becomes


2/129

separate feeders. A common drag chain feeder transports the blend to under feeding nozzles. Two

independent bunkers are used to store two different fuels. Units with this kind of arrangement do

not have much discrepancy on efficiency.

CLARITY REQUIRED FOR STEAM FLOW INDICATION

Steam flow measurement compensation block not visible

The steam produced is measured by steam flow meters. Steam flow indicated is corrected for

variations in steam pressure and steam temperature. There is considerable shift in current operating

pressure as compared to design pressure. Invariably the steam pressure fluctuation is also more. The

compensation logic was not seen in the DCS engineering screen. However the block logic was

available for FBC 02. See Photo 1, 3 and 4 in annexure 1. For FBC 03 & FBC 04 this logic could not

be found.

Steam flow units from transmitters square rooted

The engineering unit for local display is % for FBC 03 steam flow indication. This value is already

square rooted. See photo 2 in annexure 1. It was not clear whether the square root is being done at

DCS again or not. The engineering unit for local display is TPH for FBC 04 steam flow transmitter

value. See photo 5. Again it is not clear whether % is used in compensation block or actual field

value is used or not.

Span of transmitters

The steam flow transmitter is calibrated for a range of 180 TPH in FBC 04. This shall be reduced to

150 TPH to improve the accuracy in indication. Again for steam pressure the range is selected as 100

kg/cm2. This shall be made as 75 kg/cm2 for improving the accuracy. The steam temperature range

is 600 deg C. This can be revised to 550 deg C. The steam flow transmitter is calibrated for 96 TPH

for FBC 03. This is 1.2 times the MCR flow. This is OK. However the steam temperature transmitter

and steam pressure transmitter ranges are to be reduced for better accuracy.

Average steam pressure and average steam temperature for the day

It is necessary to report the average steam temperature and pressure for the day. This may be taken

from the trend chart which generally displays the minimum, maximum and average. Or else this

needs to be programmed. In some plants, the heat output is calculated based on enthalpy at small

time intervals. Thus the steam enthalpy used for heat output calculation will be realistic. Steam flow

i h h


3/129

FBC 04 will be correct. When a compartment is not in operation the load on load cells will be

unequal. This can add up error. This may need a check when the bunker is emptied any time.

Review of the data- boiler efficiency

The entire data on coal consumption for the year 2013 was taken for analysis. The heat input given to

boiler and heat output from the boiler are calculated. The direct efficiency of the boiler is arrived at

by this method. The data is presented in annexure 2. Efficiency of the boiler is a right way of

knowing the performance of the boiler. For solid fuel fired boilers indirect efficiency calculation is

recommended by codes for the reasons in measurement accuracy. The reason behind this can be seenin the data reviewed in annexure 2.

The day efficiency of the boiler is seen to be as high as 102.3 % and as low as 59.9%. Both arenot practically possible. But that is what the data says. This proves the various errors in

measurement.

The month efficiency of the boiler is however seen to be varying between 73% and 82%. This isfor the entire month and hence the error on coal consumption measurement and GCV

measurement and steam flow meter are reducing.

By the above we have seen that the data available are not accurate enough to show the consistency in

efficiency. On some days the efficiency is too low and on some days the efficiency is too high.

Hence the present methods of measurements of coal consumption, GCV, Steam flow, average steam

pressure and average steam temperatures have to be improved. The coal consumed during troubled

times have to be deducted properly as they introduce error. Extra fuel is consumed when there is a

coal flow problem and when there is a cold start up of the boiler.

Ash balancing

At present the ash disposed is being monitored by stores. It is possible to tally the ash produced

versus the coal consumed. As the feed coal is fed known from the hopper feed, we can back calculate

the ash that must be produced. This can be compared with the bed ash and fly ash production. The

numbers should tally. If the ash actually produced is more, then the ash content in the fed coal ismore than what is found in a sample.

The bed ash disposal data is compared with actual ash produced for the month between Jan 2013 and

Sept 2013. This is about 10 % of the total coal fed. See table 4 in annexure 2. This means about 10%

of the ash produced is the bed ash. Balance 90% has to be fly ash.


4/129

It may be worth considering the samples taken are immediately analysed after sampling in a shift.

Two samples may be oven dried for total moisture, TM. One dried sample can be used for GCV,

which will be bone dry GCVbone dry. Another can be used for ASH bone dry. As fired GCV can be found

from

GCVas fired= (100- TM) * GCVbone dry/ 100.

In the same manner ASH as fired can be calculated from ASH bone dry.

Thus in a day 3 samples of each fuel fed to ground hopper and 3 samples of mix fuel will have to be

analysed. If the mix has two fuels, then the number of samples to be analysed would be 9 samples intotal. Analysing these samples can be laborious. There are good automatic bomb calorimeters are

available now to test 6 samples per hour.

Cold start of the boiler

A boiler started from cold consumes more energy. This coal used for start up brings down the

evaporation ratio. It is advised to estimate the coal consumed during start up. This quantity must be

deducted while arriving at evaporation ratio.

GCV variance

To know the GCV variance the entire data on each coal were analysed. The analysed data are

presented in annexure 3.

Table 9 shows the receipt coal analysis for the imported coal as reported by plant lab. We havecalculated the GCV arb, 100- TM-ash, GCV / (100-TM-ash) and FC/ VM. GCV arb is the actualfuel heat content. The coals were received from various parties. Hence party-wise the GCV

variance was checked. The summary is presented in table 10. One can see there is a difference of

GCV to an extent of 758 kcal/kg. The GCV difference as a percentage to the average is seen to

be as high as 13.8%. If this is taken as a percentage of the best GCV it is about 27.6%. This GCV

variance causes wide variance in steam to fuel ratio.

Table 7 shows the entire data on GCV and proximate analysis data from lab for the Indian coals.The GCV variance is presented in table 8. The GCV difference can be seen as high as 1077

kcal/kg. Again when this is the variance in receipt coal, it is natural that the steam to fuel ratio

will vary to a large extent. Incidentally the FC/ VM ratio for Gujarat NRE coke is around 2. This

coal is not suitable for FBC boilers. It does not burn properly.

Table 6 is the data from the imported coal analysis reports received from port samples The


5/129

From the above analysis, it is important to note that there is deterioration of coal in the yard. Yard

management is becoming an important subject so that the heat is not lost. In addition a coal GCV has

to be analysed at the ground hopper inlet.

Counter checking the fuel feeder GCV and the hopper fuel GCV

The TM is being analysed once in a day. The GCV sample is taken in all shifts and collective sample

is given to lab. This is OK when there was only one coal. It is advisable to take the sample of each

fuel before feeding the hopper. Based on the tonnage break up, weighted ash and weighted total

moisture, the mix GCV can be calculated. This can be compared with the feeder fuel GCV which isthe mix GCV. The variation in GCV should be 5%. This should be brought out in MIS report as

explained already.

What can be done to reduce the error in the MIS report?

1. Avoid mixing of different lots.2. Sample each coal that is mixed and analyse for its GCV. GCV of the mix can be calculated based

on the mix ratio. After the mix is received at feeder analyse for the mix fuel GCV and tally withcalculated GCV.

3. Instead of taking a cumulative sample for the 24 hours, shift wise samples must be taken to arriveat the GCV. This will help to arrive at an equivalent GCV value close to actually used. In

addition the variance can be found. This is different from mixing the samples for the day and

analysing the mix sample.

4. Instead of mixing all coals for all boilers, the mix should be avoided for one boiler. Indian coal ofsay 100% can be burnt in one boiler. Imported coal with some minimum percentage of Indian

coal can be added to another boiler. Large GCV variance must be avoided. As the GCV varies

the coal consumption will vary.

5. Instead of basing the daily analysis on steam to fuel ratio, it should be based on the heatutilisation. That is the steam generation / heat input should be used as a measure of daily

performance. If the steam to fuel ratio should be used for MIS then the expected and actual

evaporation ratio should be used.6. The report should contain data on bed ash disposed and fly ash disposed. A tally must be shown

with calculated ash production. Even if the daily data does not tally at least monthly data should

tally.

Recommended MIS report


6/129

moisture pick up problems and loss in handling as well. See annexure 4. It is seen that the

deterioration is more if the coal is stocked for more than 5 days even in closed storage.

Considering loss in fuel it is necessary to invest on stacker and reclaimer to avoid loss of GCV at

yard.

Losses in fuel handing system

There are losses in coal that is fed in the raw coal hoppers. Conveyor misalignment is seen to cause

spillage. However the weight booked for a day includes the spillage. It is learnt that the spilled coals

are fed back to hopper instead of dumping back to fuel yard. That is good. But the weight booked fora day goes wrong. Screen blinding and overflowing is another cause for spillage. Indonesian coals

have high moisture content. Currently the flip flop screen is found to be the best screen which avoids

the problem of blinding and thus overflowing of screen is avoided. See annexure 5. There are dust

collection systems deployed to reduce losses in transfer points. This loss also adds up to reduction in

steam generation from the heat input.

Losses due to fuel flow problems in bunker

When moisture coals are handled the flow problems begin. In plants using 100% imported coal fly

ash blending is done to avoid flow problems. Rat hole formation in bunker is prevalent in bunkers.

The rat holes cause more problems.

Regular cleaning of bunkers by air blasters are recommended to ensure the bunker is free fromaccumulations.

When lumps descend to rotary feeders, flow problems are experienced. When experienced, thereis disturbance in combustion conditions in furnace. The fuel feed rate raised in another feeder

does not burn well as the combustor size increases. An excess coal fed in 1 st / 2nd / 3rd

compartments will not completely burn for a problem encountered in 5 th compartment. This

because the air flow is not increased or not available for burning. A coal feed rise in adjacent

compartments will help to some extent. However the fines do escape unburnt thus causing the

variance in LOI. It can be seen that there is large variance in unburnt in ash. The root cause of thecoal flow problem boils down to moisture. Moisture can be removed by air driers in the system.

Depending on relative humidity the drying of coal by means of low temperature drying system is

possible. There are systems being used in some countries. Heat available in flue gas is used for

this.

L f d t b k t l d t f d At th ti l t f l i t d t Thi


7/129

that disturb the combustion conditions in the boiler. The factors are hereby reviewed and

recommendations are given.

Excess air operation anticipating the load change & fuel dumping

The oxygen levels are never optimised at present since any time there will be load change. The

operators do not know when there is going to be load change. Hence the operators tend to keep a

higher Oxygen level expecting the load change any time.

It is advised to provide a CCTV to show the load centres. If the loads are known, low pressure

operation will be avoided. This will avoid the excess fuel required due to sudden load increase. Alsoventing losses can be minimised. This sort of exercise was done by undersigned at a paper mill long

back. This helps the operator to reduce the pressure swings. Thus the turbine would operate at

optimum specific steam consumption. This will result in fuel savings.

Sudden fuel dumping in case of low pressure will not allow the coal to burn. Thus the LOI keeps

varying. The increment rpm rise for recovering the pressure varies from person to person. Thus more

savings can be expected from this measure.

See photo 6 in annexure 6. The effect of excess air for various fuels is shown in annexure 6. At

present excess air operation cannot be avoided by operators, since the load change takes the

operators by surprise. This can be minimised once the operators are accustomed to observe the load

centre visuals.

Wide feeder rpm limits

In the combustion control loop, the upper limit of the feeder rpm is made use of. For a boiler running

at say 20 rpm, without changing the fuel GCV, the rpm is seen to go up to upper limit when there is a

pressure signal error. A demand may go up momentarily or there may be a fuel flow problem in the

feeder. At that time the entire range is made use of by the combustion control loop. This leads to

dumping of the fuel. It is a normal practice to set motor rpm on display. Then the operator does not

set wide limits. For example if the feeder operates at 600 rpm, he may choose to keep 650 rpm as the

upper limit. This is about 8% rise. When it is a percentage, for example for the case in photo 1 inannexure 6, the rise is 32/20 = 1.6. That is, the rpm is increased up to 60% more. The fuel dumped to

this level, will not burn fully.

Operators must always set the limit to narrow range. There are situations of sudden demands. At that

time the feeders rpm should rise proportional to load Very high limits are not advised See other


8/129

Over-riding the pressure control loop

In boiler 4, it is seen that the operators chose to interfere manually with some feeders to respond topressure signal. It is a good aspect. But rpm limits are to be kept in mind. It is advised to add CO

meter in the flue path and provide trend in DCS. We can track the situations under which, the

operators had to fault on excess fuel dumping.

Low bed temperatures in boiler 3

In boiler 3, the bed temperatures are mostly around 750 deg C. The bed temperatures do vary as per

load and as per the fuel fed. The load on the boiler 3 is seen to be a maximum of 70 TPH. Importedcoal has higher fuel moisture and VM burns above the bed. The bed coil HTA requirement is less for

this. Indian coal needs more bed coil area to restrict the bed temperature to 925 deg C maximum.

Very low bed temperatures cause various problems. The problems are listed below.

Activation of a compartment will take a long time. It calls for more fuel. The rpm is being set ashigh as 50% where the normal rpm is 30%. Then also the response is slow. The ignition is slow.

Upsets in fuel flow will result in excess fuel for revival of bed temperature. Flame out situation occurs. This has happened sometimes. At the time of visit, there was a coal

flow problem. Bed temperatures dropped further. Then the flame out occurred. Dry coal was fed

to revive the bed. Indonesian coal had high VM and hence the there is a tendency to have high

free board temperature than the bed temperature during such situations. The option is to

pressurise the furnace for improving the bed temperature. Such a problem is not experienced in

boiler 4. It is because in boiler 4, the bed coils HTA is less than the requirement. The bed coils

are widely pitched and less studded too. In addition there is refractory applied over the bed coils

above the coal nozzle points.

Generally poor combustion due to low bed temperature. Three Ts time, temperature andturbulence decide the combustion completeness.

Start up will be a problem. This is because the bed coils cool the charcoal fire.The design of FBC 03 bed coil HTA was checked for various fuels. It is necessary to cover the bed

coils to a length of 1.5 m in each outer coil in FBC 03. See the calculations on bed coil area

requirement for a case of 50% Indian coal and 50% imported coal mix at 80 TPH load attached in

annexure 7. The recommendation on bed coil refractory covering is given at the end of annexure 7.

Every operational disturbance causes extra fuel consumption. That is the reason boiler PG test is

d d t bl diti d i i bl ffi i t i i 82% i b b il


9/129

FD fan loading. See photo on annexure 8.

In addition there is false air ingress from FBC 03. The oxygen in FBC 3 is around 6.5% to 7%. Theefficiency loss or extra fuel consumption on this account is to an extent of 1.5%. The Oxygen in

FBC 04 is already at the optimum. The false air ingress in FBC is due to improper sealing

arrangement at roof. This can be arrested by going in for POP finish for insulation. At many plants

the air ingress is minimised / arrested only by this method. See the photographs at the end of

annexure 8.

It is estimated that around 15 % of the air directly connects to flue gas side. The air flow leak to fluegas increases the power consumption of ID fan and FD fan.

Steam leakages and passing of vent valves

Passing & leakages in valves in FBC 3 & FBC 4 were checked using IR camera. IR camera identifies

passing but the flow cannot be quantified. However higher temperatures mean more passing. In FBC

03, the following were seen.

a. Gland leak in MSSV in boiler 3.b. Steam drum SV passing in boiler 3c. Drum levels gauge drain valve passingd. Start up vent passing

In FBC 4, following are the passing and leakages noticed.

e. Steam drum left side safety valvef. Gland leaks in two valves SH headerg. Drum pressure transmitter line punctureh. Drum pressure gauge line puncture

The photographs showing the leakages and passing are summarised. There are some guidelines

followed by energy auditors regarding the steam wasted from a hole. Based on this we can have an

estimate on the energy loss. The energy loss due to steam loss is presented in annexure 9. Also the

passing of valves as identified by an infrared camera is presented in annexure 9.

Bed draining practice

The heat loss from furnace ash can be reduced by resorting to cold ash draining. The gates should be

closed once the hot ash begins to come out from the drain pipe. See photo 7 in annexure 6. The drain


10/129

recovery boiler were seen. Inside of the tubes show Iron carry over from process. See photo 1 in

annexure 10. When iron is dissolved from MS shell plates, silica also gets dissolved. This aspect is

seen in Air cooled condensers of many power plants. Due to low pH situations during start up, ACC

tubes corrode and raise silica in condensate return. In water cooled condensers the tubes are of

noncorrosive material. Hence silica does not rise in the condensate.

Iron carryover to boiler needs to be prevented by incorporating magnetic screen for condensate

polishing. Filtration system may also help. The loss due to blow down can be high when the silica

increase in condensate return.

The economiser tube failures are experienced in the first pass of chemical recovery boiler, where the

dirt is unable get flushed out against gravity. Deposits seemed to hinder the heat transfer creating

stress assisted corrosion.

The failed tube was not available for checking. Hence some photos are given in annexure 10,

showing the steam drum appearance and tube failures on account of condensate contamination.

Higher blow down leads to high fuel consumption. See photo 3 & 4. A typical blow downcalculation is given in annexure 10. The conductivity used here should be after the subtraction of the

volatile chemicals.

Compartmental operation

In the event of compartment shut down, the leakage air that passes through idle bed, adds up to heat

loss. This amounts to excess air and can efficiency to a level of 1%. This leakage air does not

contribute much to combustion as it is not fed at active bed. During this period the unburnt in fly ashcan go up as all the air is not used for combustion. This is to be checked over specific trials. It is seen

that during load variation, the LOI is varying from 6% to 10%. The efficiency loss is more as the ash

percent increases. For a 40% ash coal, the additional loss is to an extent of 2.56% for the increase in

LOI from 6% to 10%. It is advised to check the compartment dampers during shut down. In boiler 4,

there will be seals which need to be replaced. In boiler 3, asbestos pad is provided as seal at the

compartment damper flap to seating plate area.

Shallow bed operation in FBC 04

In FBC 04, the positive pressure is experienced at venturi in PA lines. When the air box pressure is

restricted to 500 mmWC, the suction effect at venturi is OK. This problem is seen in Thermax Units.

The throat size was changed at two 125 TPH FBC boilers at another plant Shallow bed results in


11/129

1. Imported coal shall be used within 3 days of arrival at plant.2. Coke shall not be used as it results in poor combustion.3. Fuels fed at ground hopper must be sampled in 3 shifts and analysed for Total moisture. Samples

shall be further analysed for GCV and ash, which will be on bone dry basis. Based on the mix

ratio, equivalent TM, GCVafand Ashafshall be found out.

4. Feeder samples shall be collected in 3 shifts and shall be analysed for total moisture and then onbone dry basis for GCV and ash. GCVafand Ashafshall be calculated.

5. The feeder sample report and ground hopper report should match. Depending on the consumptionthe time lag shall be accounted for matching the calculated GCV and the feeder GCV.

6. The coal lot shall be stacked with dates and GCV on receipt and the name. As per point 3, thesame coal GCV will be analysed at the time of feeding to CHP. This will help to measure the

deterioration of GCV on storage.

7. Coal stacking and reclaiming can be automated based on the point 6. Based on the annual coalconsumption and the deterioration level, we can decide on the need for covered storage with

stacker and reclaimer.

8. LED screen display of each load centre shall be added at each boiler control room. The locationof camera shall be discussed and decided with process persons.

9. The steam flow transmitter at boiler 4 shall be calibrated for a lower range to improve theaccuracy.

10.Steam temperature transmitters shall be calculated for 550 deg C or 525 deg C.11.The steam flow compensation logic screen shall be clarified by the supplier in person.12.Hourly / shift average steam pressure and steam temperature shall be obtained from DCS.Suitable additional software shall be obtained for generating log sheets. This is required to obtain

the steam enthalpy and to calculate the heat output of boilers.

13.Air blasters shall be installed in coal bunkers to facilitate removal of lumps as the bunker goesempty.

14.Bar screens shall be added at feeder inlet chutes to trap the lumps from bunker.15.Ash generation measurement shall be given importance and the calculated ash generation and the

actual ash generation must be tallied at the end of the month.

16.Improve the coal handling system maintenance to reduce / eliminate the loss in handling.17.Add CO meter to improve the fuel feed regulation by boiler operators.18.Reduce the effectiveness of bed coils in boiler 3 in order to improve the bed temperatures. This is

to be done by applying phoscast refractory on the tubes as per recommended drawing During


12/129

compartment slumping.

26.Incorporate rpm indication for fuel feeder instead of %. This is to correct the operators tendencyto dump fuel.

27.Procure new mixing nozzles with reduced throat diameter for boiler 4. Resort to increasing theoperating height. Ensure the refractory is applied in advance in the newly procured coils.

28.Reduce the radiation losses in FBC 3.29.Modify the MIS with expected steam to fuel ratio / actual steam to fuel ratio. In addition heat

input / heat output ratio shall be computed as it reflects the boiler efficiency trend. The work

sheet given may be suitably modified.

K.K.Parthiban


13/129

ANNEXURE 1- STEAM FLOW METER CALIBRATION


14/129

Photo 01 : The above photo shows the screen shot of steam flow meter compensation block of boiler

3. It is seen that the boiler steam flow is calibrated for 96 TPH. The steam flow transmitter is

selected for 1.2 times the MCR flow. The steam pressure is calibrated for 100 kg/cm2. This is on the

higher side. This may be calibrated for a range of 75 kg/cm2 for better accuracy. Similarly

temperature range shall be checked and reduced for better accuracy.


15/129

Photo 03: The photo shows the compensation logic seen in FBC 02. Such a screen shot was not

available both for boiler 3 & 4.


16/129

Photo 05: The above photo shows the steam flow reading which is already square rooted at

transmitter itself. This shall be checked in the logic of steam flow compensation. This logic was not

available in the DCS engineering screen. It may be checked whether the DCS signal is taken as

percentage or the flow itself.


17/129

ANNEXURE 2- REVIEW OF THE EVAPORATION RATIO


18/129


19/129

FBC 3 FBC 4 FBC 3 FBC 4 FBC 3 FBC 4 FBC 3 FBC 4

Min 3.8 3.8 902.3 909.7 2.3 2.0 63.3 61.3

Max 4.3 4.5 1306.0 1271.3 6.9 5.6 91.6 85.7

Average 4.1 4.2 1110.5 1144.5 4.7 3.1 77.9 77.1

Min 3.9 4.0 1098.8 1096.1 2.0 1.4 77.0 73.9

Max 4.1 4.3 1311.6 1436.7 6.2 4.3 92.0 96.9

Average 4.0 4.2 1150.0 1216.8 4.5 2.7 80.6 82.0

Min 3.8 3.9 912.7 1025.1 1.8 1.5 64.0 69.1

Max 4.1 4.5 1370.3 1244.0 8.0 7.2 96.1 83.9

Average 4.0 4.2 1122.9 1139.7 5.3 3.4 78.7 76.8

Min 3.7 3.9 849.1 895.3 4.7 2.9 59.5 60.4

Max 4.1 4.2 1567.0 1423.1 26.1 15.0 109.9 95.9

Average 4.0 4.0 1133.4 1144.1 8.6 6.2 79.5 77.1

Min 3.9 4.1 920.4 1045.2 0.9 2.8 64.5 70.5

Max 4.1 4.2 1308.3 1434.9 21.1 14.8 91.7 96.7

Average 4.0 4.2 1169.1 1207.5 9.4 7.3 82.0 81.4

Min 2.7 3.6 694.0 902.0 1.7 1.6 48.7 60.8

Max 4.0 5.3 1251.9 1681.3 7.7 7.0 87.8 113.3

Average 3.7 4.1 1014.5 1131.0 4.1 3.1 71.1 76.2

Min 3.4 3.5 915.3 888.9 2.9 1.9 64.2 59.9

Max 3.9 4.1 1232.2 1518.2 6.1 5.3 86.4 102.3

Average 3.6 3.8 1073.7 1126.8 4.2 3.3 75.3 76.0

Min 3.5 3.5 864.8 891.9 1.9 1.2 60.6 60.1

Max 4.0 4.2 1216.7 1414.5 5.3 4.9 85.3 95.4

Average 3.7 3.9 1025.6 1083.7 3.0 2.4 71.9 73.1

Min 3.6 3.8 819.8 890.9 0.8 0.9 57.5 60.1

Max 4.2 5.8 1358.7 1605.7 4.6 3.7 95.3 108.2

Average 3.8 4.1 1031.7 1152.3 2.4 1.9 72.2 77.7

Jul-13

Aug-13

Sep-13

Jan-13

Feb-13

Mar-13

Apr-13

May-13

Jun-13

Performance review of FBC 3 and FBC 4

Evap ratio Steam prodn Heat loss due to ash / heatinput

Efficiencykg/kg kg/10^3 kcal


20/129

Trips Nearby Ddl Trips Nearby Dd Trips Nearby Dd Trips Nearby Dd Trips Nearby Dd Trips Nearby Dd Trips Nearby Dd Trips Nearby Dd Trips Nearby Ddl

MT MT MT MT MT MT MT MT MT

1 4 78.32 2 33.64 7 108.87 1 14.9 6 85.852 1 19.88 1 17.98 3 35.88 1 16.12

3 1 20.07 2 36.03 2 32.07 6 92.12 1 16.98 2 22.91 3 36.22

4 1 17.57 1 16.24 3 47.18 5 75.02 4 53.88

5 1 16.33 1 15.52 1 15.41

6 3 64.04 1 16.3 1 16.07 2 30.3

7 1 16.98 1 19.46 5 79.61 1 14.24

8 1 17.36 2 41.74 4 61.34 2 27.91

9 3 54.04 1 18.04 5 79.3 2 24.05 2 30.33

10 1 19.48 3 52.20 3 45.63 1 15.05 4 62.90 4 53.76 1 13.52 1 11.06

11 2 36.96 3 44.73 2 31.22 1 15.27 1 11.4712 1 16.59 7 120.3 6 76.97

13 1 15.2 2 30.51 1 14.27 7 115.04 1 13.32 1 14.21

14 1 16.7 1 19.21 1 14.2 1 15.03 6 96.23 6 79.28 3 41.33

15 1 18.69 1 17.72 1 15.21 3 48 1 16.02

16 1 15.55 3 57.02 6 103.89 4 63.67 3 39.19

17 2 34.38 5 82.42 1 15.65 1 15.05 8 129.68 1 11.06 1 12.19

18 1 17.49 2 31.48 6 100.22 2 24.29 2 33.48 2 33.34

19 3 52.36 3 47.11 1 15.37 3 40.80 1 15.99 1 16.83

20 1 18.64 2 35.22 2 29.71 3 47.67 1 11.87

21 1 8.8 1 18.52 2 30.69 2 35.31 4 62.74 2 22.96 5 63.8 2 34.6422 1 18.48 3 50.40 2 31.00 2 31.51 3 35.08 4 60.56

23 3 58.25 2 32.33 1 15.81 3 47.74 3 46.53 2 32.13

24 1 17.99 3 53.06 1 16.48 2 26.97 1 15.11

25 3 50.64 1 16.99 1 13.04 9 111.12 1 15.74

26 3 52.44 1 15.38 1 14.57 5 79.62 1 15.82 4 47.84

27 2 38.84 1 15.78 6 97.31 2 33

28 2 35.54 2 35.85 1 18.52 5 79.48 8 110.04

29 1 14.4 3 47.67 1 14.97 7 108.3 3 49.29

30 2 35.56 3 46.67 2 28.33 1 16.13

31 2 36.19 4 61.42 3 43.37 5 66.34

total 16 264.80 44 818.59 50 839.41 16 252.24 35 551.02 92 1466.47 25 331.69 82 1127.57 41 596.30

6248.1

249072.0

62268.0

10.03

Sep'13January'13 February'13 Mar'13 Apr'13 May'13 Jun'13

Total disposal of bed ash

total coal used in this period

Percentage bed ash disposed

total ash production in this period with 25% ash

TABLE 4: Waste Bed Material during January 2013 to September 2013

Date Jul'13 Aug'13


21/129

FBC 03 FBC 04 TM IM ASH

adb ASH af TM IM

ASH

adb

ASH

af FBC-03 FBC-04 Total FBC-03 FBC-04 Total calc

1/9/2013 402 607 34 8.3 15.2 10.94 36 8.7 14.8 10.37 43.98 62.95 106.93 37.38 53.51 90.89

2/9/2013 357 512 36 11.1 14.6 10.51 34 10 11.5 8.43 37.52 43.16 80.68 31.89 36.69 68.58

3/9/2013 438 647 32 5.3 29.5 21.18 30.5 8.4 22.9 17.38 92.77 112.45 205.22 78.85 95.58 174.44

4/9/2013 381 573 34 13.9 14.9 11.42 30 10.6 18.4 14.41 43.51 82.57 126.08 36.98 70.18 107.17

5/9/2013 379 586 38.5 7.7 20.1 13.39 36.5 9.3 19.1 13.37 50.75 78.35 129.1 43.14 66.6 109.74

6/9/2013 378 524 34 5.9 17.8 12.48 37 7.3 18.2 12.37 47.17 64.82 111.99 40.09 55.1 95.19

7/9/2013 398 589 36.5 5.8 13.3 8.97 37.5 5.9 11 7.31 35.7 43.06 78.76 30.35 36.6 66.95

8/9/2013 395 597 37.5 7.5 11.9 8.04 38.5 8.6 15.1 10.16 31.76 60.66 92.42 27 51.56 78.56

9/9/2013 384 563 37 8.2 12 8.24 37 8.5 13.7 9.43 31.64 53.09 84.73 26.89 45.13 72.02

10/9/2013 362 561 35 9.2 9.4 6.73 37 8.2 19.7 13.52 24.36 75.85 100.21 20.71 64.47 85.18

948.72

Total coal 3874 5759 Average ash % 11.59 total ash 1116.12

FBC 03 FBC 04 TM IM ASH

adb ASH af TM IM

ASH

adb

ASH

af FBC-03 FBC-04 Total FBC-03 FBC-04 Total calc

1/5/2013 356 624 23 4.7 33.9 27.39 21 4.4 34 28.10 97.51 175.34 272.85 82.88 149.04 231.92

2/5/2013 356 493 32.5 7 33.3 24.17 34 6 34.6 24.29 86.05 119.75 205.8 73.14 101.79 174.93

3/5/2013 377 572 29 11 22.1 17.63 31 13 22.1 17.53 66.47 100.27 166.74 56.5 85.23 141.734/5/2013 379 605 32 4.1 36.1 25.60 33.5 5.6 32.2 22.68 97.02 137.21 234.23 82.47 116.63 199.1

5/5/2013 383 569 33.5 4.5 27.9 19.43 30.5 4.4 26.7 19.41 74.42 110.44 184.86 63.26 93.87 157.13

6/5/2013 384 577 34.5 6 24.2 16.86 32.5 5.3 30.8 21.95 64.74 126.65 191.39 55.03 107.65 162.68

7/5/2013 398 598 35 4.5 30.5 20.76 35 4.4 32.3 21.96 82.62 131.32 213.94 70.23 111.62 181.85

8/5/2013 399 607 32.5 4.6 30.5 21.58 33 5.3 32 22.64 86.1 137.42 223.52 73.19 116.81 189.99

9/5/2013 357 560 32 6.9 36.1 26.37 35 5.7 36.4 25.09 94.14 140.5 234.64 80.02 119.43 199.44

10/5/2013 363 559 35 9.7 22.7 16.34 29 9.9 19.9 15.68 59.31 87.65 146.96 50.41 74.5 124.92

Only for FBC-03&04 Boilers Running t ime- sample data 1

difference

DateFBC 3 FBC 4 Total Ash Disposal as per calc Fly ash calculated (85%) Fly ash gen

as per stores

105.49

93.74

99.19

170.9

204.57

164.05

143.84

171.13

186.3

164.14

1503.35

Date

FBC 3 FBC 4 Total Ash Disposal as per calc Fly ash calculated(85%)Fly ash gen

as per stores

236.15

232.84

244.36258.24

96.21

214.23

255.83

209.04

128.08

170.76

Coal used

Total

Only for FBC-03&04 Boilers Running t ime- sample data 2

TABLE 5: FLY ASH BALANCING REPORT - COMPARISON OF FLY ASH AS PER CALCULATION AND AT ACTUALS

Coal used

Percentage difference

554.6

58.5


22/129

11/5/2013 388 526 29 3.1 32.9 24.11 28 3.7 30.9 23.10 93.55 121.51 215.06 79.52 103.28 182.8

12/5/2013 388 471 31.5 7.2 22 16.24 29.5 7.9 18.6 14.24 63.01 67.07 130.08 53.56 57.01 110.57

13/5/2013 359 545 27.5 8.5 27.3 21.63 31.5 4.9 40.6 29.24 77.65 159.36 237.01 66 135.46 201.46

14/5/2013 360 547 25.5 3.9 40.3 31.24 28 4.5 41.6 31.36 112.46 171.54 284 95.59 145.81 241.415/5/2013 365 545 22.5 3.8 41.2 33.19 24 3.9 40 31.63 121.14 172.38 293.52 102.97 146.52 249.49

16/5/2013 381 553 22.5 3.3 2.8 2.24 23 3.3 42.3 33.68 8.53 186.25 194.78 7.25 158.31 165.56

17/5/2013 377 483 19.5 3.1 40.9 33.98 25 4.2 40.8 31.94 128.1 154.27 282.37 108.89 131.13 240.01

18/5/2013 364 498 24 3.9 39.5 31.24 24.5 4.6 41.8 33.08 113.71 164.74 278.45 96.65 140.03 236.68

19/5/2013 293 487 25 6.9 29.8 24.01 23 10.4 23.5 20.20 70.35 98.37 168.72 59.8 83.61 143.41

20/5/2013 305 464 24 3.5 38.4 30.24 20 3 39.9 32.91 92.23 152.7 244.93 78.4 129.8 208.19

21/5/2013 355 516 25.5 5 38 29.80 29 5.1 32.1 24.02 105.79 123.94 229.73 89.92 105.35 195.27

22/5/2013 300 470 24 8.6 30.8 25.61 25 9.8 33.1 27.52 76.83 129.34 206.17 65.31 109.94 175.24

23/5/2013 321 461 17.5 3.7 40.4 34.61 13.5 3.9 40.1 36.09 111.1 166.37 277.47 94.44 141.41 235.85

24/5/2013 307 555 13.5 2.7 43.8 38.94 12.5 2.9 43.2 38.93 119.55 216.06 335.61 101.62 183.65 285.27

25/5/2013 310 490 30 4.4 40.5 29.65 29 5.3 38.4 28.79 91.92 141.07 232.99 78.13 119.91 198.04

26/5/2013 324 505 33.5 7.7 32.2 23.20 29 7.4 30.4 23.31 75.17 117.72 192.89 63.89 100.06 163.96

27/5/2013 330 521 18 5.8 25.4 22.11 19 5.4 31.8 27.23 72.96 141.87 214.83 62.02 120.59 182.61

28/5/2013 343 489 18 5.3 30.2 26.15 20 5.5 27.4 23.20 89.69 113.45 203.14 76.24 96.43 172.67

29/5/2013 318 461 16 7.8 23 20.95 18 7 28.4 25.04 66.62 115.43 182.05 56.63 98.12 154.74

30/5/2013 320 482 24 4.7 33 26.32 23 5.4 30.8 25.07 84.22 120.84 205.06 71.59 102.71 174.3

31/5/2013 334 520 21.5 7.7 32.2 27.39 20 5.1 32.1 27.06 91.48 140.71 232.19 77.76 119.6 197.36

5878.57

Total coal 10894 16353 25.38 total ash 6915.98 differenceAverage ash %

113.98

188.83

146.07

172.07154.65

439.74

228.68

195.25

259.04

159.58

298.21

182.46

144.15

185.38

190.21

248.57

342.26

391.46

277.77

317.73

6831.26

149.43

16.2Percentage difference

Total

952.7


23/129

ANNEXURE 3- REVIEW OF THE HEAT CONTENT IN COAL- THE VARIANCE


24/129


25/129


26/129


27/129

Av erag e 35.96 15.89 8.20 5504.50 0.63 41.23 5.54 4190.08 58.51 71.72 34.69 0.84

1 39 Indonesia 59 / 29.07.13 3699.2 40.1 19.9 10.9 5550 0.5 39.6 6.9 4150.4 53 78.3 29.60 0.75

2 42 Indonesia 59 / 10.08.13 3598.4 35.1 16.8 7.7 5430 0.62 41.3 5.3 4235.7 59.6 71.1 34.20 0.833 45 Indonesia 59 / 16.08.13 3735.9 34.8 16.3 9.7 5470 0.57 40.8 6.7 4261 58.5 72.8 33.20 0.81

4 46 Indonesia 59 / 20.08.13 3805.4 36.5 16.8 10.7 5440 0.59 42 7.2 4151.9 56.3 73.7 30.50 0.73

5 48 Indonesia 59 / 23.08.13 3796.6 38.3 18.6 8.6 5480 0.55 40.3 5.6 4153.8 56.1 74 32.50 0.81

Min GCV 4150.4

Max GCV 4261

Av erag e 36.96 17.68 9.52 5474.00 0.57 40.80 6.34 4190.56 56.70 73.98 32.00 0.78

1 40 Indonesia 58 / 02.08.13 3634 18.5 7.6 19 5140 20.2 33 16.3 4533.7 65.2 69.5 40.40 1.22

2 41 Indonesia 59 / 07.08.13 3700 18.3 9.5 18.1 5160 0.4 33.5 15.6 4658.3 66.1 70.5 38.90 1.16

3 47 South America 59 / 24.08.13 3584.3 18.8 9.7 21.2 5170 0.47 32.8 18.1 4649 63.1 73.7 36.30 1.11

4 50 Indonesia 57 / 28.08.13 3534.3 18.8 8.7 18.3 5120 0.43 35 15.6 4553.6 65.6 69.4 38.00 1.09

Gupta Imported Coal

Maheshwari Imported Coal

Difference between

max & min110.60 2.64


28/129

VM

GCV arb /

(100-TM-

Ash)

FC/VM TMASH

arbMin GCV Max GCV

GCV arb

average

GCV diff bet

min & max

GCV diff

in %Comment

Agarwal lot 1 41.60 67.7 1.00 35.4 4.92 3794.9 4192.6 4043.2 397.7 9.8

Agarwal lot 2 42.12 67.9 1.00 37.8 4.47 3529.8 4072.2 3918.7 542.4 13.8

Maheswari 1 41.81 69.6 0.93 31.7 5.93 3956.2 4714.1 4339.4 757.9 17.5

Gimpex 32.81 68.3 0.98 32.8 5.55 4135.4 4315.7 4206.1 180.3 4.3

Gupta 1 41.73 70.0 0.89 33.4 6.40 4029.9 4319.1 4210.9 289.2 6.9

Gandhar 1 41.23 71.7 0.84 36.0 5.54 3812.1 4295.0 4190.1 482.9 11.5

Gupta 2 40.80 74.0 0.78 37.0 6.34 4150.4 4261.0 4190.6 110.6 2.6

TABLE 10- IMPORTED COAL FC/VM RATIO- range of GCV - from receipt coal analysis reports f rom LAB

In all coals, the GCV range is very high. It is rather difficult to base the steam to fuel ratio as the measure of plant performance


29/129


30/129

31 87 MAJRI 59 / 18.02.201 3777.65 12.60 4.80 28.40 4590.00 0.62 30.70 26.1 4213.9 61.3 68.7 36.10 1.18

32 90 MAJRI 59 / 1.03.2013 3765.10 11.50 4.10 35.10 4350.00 0.64 27.30 32.7 4014.3 55.8 71.9 33.50 1.23

33 91 MAJRI 1150.70 11.70 6.90 29.00 4350.00 0.62 26.10 27 4125.7 61.3 67.3 38.00 1.46

34 95 MAJRI 59 / 18.03.201 3839.70 12.40 5.40 30.90 4480.00 0.51 26.70 28.5 4148.5 59.1 70.2 37.00 1.39

Min GCV 3555.3

Max GCV 4486.5

Av erag e 12.95 6.50 31.23 4473.38 0.63 27.76 28.61 4158.3 58.44 71.33 34.50 1.25

Median 12.60 6.50 30.70 4485.00 0.64 28.10 27.80 4183.8 58.80 71.30 34.55 1.23

1 46 SCCL 59 / 15.09.201 3970.90 17.80 7.50 40.90 3500.00 0.68 24.60 35.4 3110.3 46.8 66.5 27.00 1.10

2 70 SCCL 59 / 28.11.201 3743.70 19.40 8.70 28.00 4520.00 0.65 30.00 23.8 3990.3 56.8 70.3 33.30 1.11

3 76 SCCL 59 / 23.12.201 3876.55 11.60 6.70 29.60 4420.00 0.62 27.30 27.5 4187.9 60.9 68.8 36.40 1.33

4 80 SCCL 58 / 05.01.201 3809.50 12.30 5.50 27.50 4250.00 0.65 27.50 25.4 3944.2 62.3 63.3 39.50 1.44

5 82 SCCL 58 / 13.01.201 3961.45 13.60 4.80 30.70 4560.00 0.63 29.40 27.9 4138.5 58.5 70.7 35.10 1.19

6 96 SCCL 58 / 19.03.2013 11.20 4.50 37.00 4375.00 0.56 26.50 34.6 4068.1 54.2 75.1 32.00 1.21

Min GCV 3110.3

Max GCV 4187.9

Av erag e 14.32 6.28 32.28 4270.83 0.63 27.55 29.10 3906.55 56.58 69.12 33.88 1.23

1 92 GUJRAT 32 Trucks 442.85 10.10 1.80 40.00 3940.00 0.50 19.70 37.9 3607 52 69.4 38.50 1.95

1 1 MAJRI 59 / 09.04.13 3835.10 12.20 04.40 40.80 4250.00 00.45 25.10 37.5 3903.2 50.3 77.6 29.70 1.18

2 5 MAJRI By Truck 987.79 11.80 04.80 38.90 4290.00 00.63 25.20 36 3974.6 52.2 76.1 31.10 1.23

3 10 MAJRI 59 / 18.04.13 3850.70 12.80 06.20 32.90 4460.00 00.60 28.60 30.6 4146.2 56.6 73.3 32.30 1.13

4 12 MAJRI 59 / 18.04.13 3756.30 12.90 07.00 30.30 4580.00 00.54 28.50 28.4 4289.4 58.7 73.1 34.20 1.20

5 16 MAJRI 59 / 28.04.13 3736.35 12 5.2 42.7 4200 0.62 21.4 39.6 3898.7 48.4 80.6 30.70 1.436 19 MAJRI 59 / 17.05.13 3813.85 10.1 7.7 32.5 4480 0.58 27.9 31.7 4363.5 58.2 75 31.90 1.14

7 21 MAJRI 59 / 23.05.13 3830.4 12.6 6.2 39.4 4280 0.6 23.9 36.7 3988 50.7 78.7 30.50 1.28

8 24 MAJRI By Truck 1346.52 10 5.6 40.1 4205 0.52 23.5 38.2 4009 51.8 77.4 30.80 1.31

9 28 MAJRI 59 / 26.05.13 3866.8 10.7 6.5 34.5 4377 0.55 23.6 33 4180.4 56.3 74.3 35.40 1.50

10 29 MAJRI 59 / 30.05.13 3959.65 10.2 6 40.4 4220 0.52 22.4 38.6 4031.4 51.2 78.7 31.20 1.39

11 35 MAJRI 59 / 12.06.13 3989.4 12 6.8 32.2 4475 0.58 27.4 30.4 4225.3 57.6 73.4 33.60 1.23

12 36 MAJRI 59 / 28.06.13

3884.2 14.3 6.9 31.6 4540 0.59 26 29.1 4179.1 56.6 73.8 35.50 1.37

13 37 MAJRI By Truck 750.70 10.5 7.8 31.7 4550 0.59 26.2 30.8 4416.8 58.7 75.2 34.30 1.31

Min GCV 3898.7

Max GCV 4416.8

SCCL

GUJRAT NRE

WCL :

Difference between max

& min931.20 22.39


& min1077.6 27.58


& min518.10 12.56


31/129

Av erag e 11.70 6.24 36.00 4377.46 0.57 25.36 33.89 4123.51 54.41 75.94 32.40 1.29

14 52 GHUGUS 59 / 02.09.13 3914.70 15.7 8.2 29.9 4520 0.41 26.4 27.5 4150.7 56.8 73.1 35.50 1.34

15 54 GHUGUS 59 / 14.09.13 4028.10 16.6 7.2 34.4 4410 0.38 25.1 30.9 3963.3 52.5 75.5 33.30 1.33

Min GCV 3963.3

Max GCV 4150.7

Av erag e 16.15 7.70 32.15 4465.00 0.40 25.75 29.20 4057.00 54.65 74.30 34.40 1.34

16 55 CHARGA 59 / 20.09.13 3831.50 15.5 7.1 30.7 4550 0.37 25.8 27.9 4138.6 56.6 73.1 36.40 1.41

17 56 CHARGA 58 / 25.09.13 3683.40 15.2 8.5 28.1 4550 0.38 29 26 4216.8 58.8 71.7 34.40 1.19

Min GCV 4138.6

Max GCV 4216.8

Av erag e 15.35 7.80 29.40 4550.00 0.38 27.40 26.95 4177.70 57.70 72.40 35.40 1.30

18 58 BY Truck 6 truck 211.88 13.8 7.2 31.5 4440 0.34 25.8 29.3 4124.2 56.9 72.5 35.50 1.38

1 6 4 31.03.2013 Qty e as 2.40 40.70 4080.00 0.50 20.00

2 7 66 10.04.2013 1088.41 12.80 1.70 38.40 4380.00 0.48 19.10 34.1 3885.4 53.1 73.2 40.80 2.14

3 8 66 16.04.2013 1150.52 12.60 1.80 38.00 4480.00 0.42 20.00 33.8 3987.3 53.6 74.4 40.20 2.01

4 11 61 22.04.2013 1161.5 10.2 1.9 40 4530 0.38 18.8 36.6 4146.7 53.2 77.9 39.30 2.09

5 13 55 27.04.2013 1023.28 9.7 2 40.6 4480 0.37 19 37.4 4128 52.9 78 38.40 2.02

6 22 55 04.05.2013 1071.93 8.4 1.7 41.4 4625 0.35 18.5 38.6 4309.8 53 81.3 38.40 2.087 25 72 14.05.2013 1319.45 9.1 1.8 41 4640 0.37 18.2 38 4295.1 52.9 81.2 39.00 2.14

8 26 58 21.05.2013 1136.18 8.6 2.2 41.9 4564 0.32 18.6 39.2 4265.3 52.2 81.7 37.30 2.01

9 27 52 29.05.2013 1032.8 10.2 2 41.9 4563 0.31 17.3 38.4 4181.2 51.4 81.3 38.80 2.24

Min GCV 3885.4

Max GCV 4309.8

Av erag e 10.20 1.89 40.40 4532.75 0.38 18.69 37.01 4149.85 52.79 78.63 39.03 2.09

S.n Report the Wagons recd Qty e as in test ( on 5% c Value r ( V.M %

1 18 SCRM 57 / 11.05.201 3723.8 10.6 6.8 39.9 4315 0.53 25.5 38.3 4139.1 51.1 81 27.80 1.09

2 38 SCRM 59 / 17.07.201 3854.3 14.1 5.9 38.2 4320 0.55 24.2 34.9 3943.5 51 77.3 31.70 1.31

3 44 59 / 11.08.201 3938.1 15.1 6.1 40.3 4250 0.33 25.1 36.4 3842.7 48.5 79.2 28.50 1.14

4 60 CXSG 58 / 30.09.201 3956.83 11 5.9 24.5 4140 0.32 24.5 23.2 3915.6 65.8 59.5 45.10 1.84

Min GCV 3842.7

Max GCV 4139.1Average 12.70 6.18 35.73 4256.25 0.43 24.83 33.20 3960.23 54.10 74.25 33.28 1.34


& min 187.40 4.62

SCCL


& min

296.40 7.48


& min78.20 1.87


& min424.40 10.23

Gujarat NRE COKE : BY Truck


32/129

VMGCV arb / (100-TM-

Ash)

FC/VM TM ASH arb Min GCV Max GCVGCV arb

average

GCV diff

bet min &

max

GCV diff

in %

Comment

Majri 27.8 71.3 1.2 13.0 28.6 3555.3 4486.5 4158.3 931.2 22.4 Wide range of GCV

SCCL 27.6 69.1 1.2 14.3 29.1 3110.3 4187.9 3906.6 1077.6 27.6 Ash reported is less

Gujrat NRE coke 19.7 69.4 2.0 10.1 37.9 Difficult to burn

Majri 25.4 75.2 1.3 11.7 33.9 3898.7 4416.8 4123.5 518.1 12.6

Chugus 25.8 74.3 1.3 16.2 29.2

Chargaon 27.4 72.4 1.3 15.4 27.0

Gujrat NRE coke 18.7 78.6 2.1 10.2 37.0 3885.4 4309.8 4149.9 424.4 10.2 Difficult to burn

SCCL 24.8 74.3 1.3 12.7 33.2 3842.7 4139.1 3960.2 296.4 7.5 Ash reported is less

TABLE 8- INDIAN COAL FC/VM RATIO- range of GCV - from receipt coal analysis repor ts f rom LAB

Only one report is available

Only two reports available

Only two reports available

In all coals, the GCV range is very high. It is rather difficult to base the steam to fuel ratio as the measure of plant performance


33/129


34/129

TRENDANALYSISOFIMPORTEDCOAL

8

Asharbtrend GCVarbtrend Totalmoisturetrend

4

5

6

7

3000

4000

5000

6000

20

25

30

35

40

0

1

2

3

1 3 5 7 9 11 13 15 17 19 21 23 25 27

0

1000

2000

1 3 5 7 9 11 13 15 17 19 21 23 25 27

0

5

10

15

1 3 5 7 9 11 13 15 17 19 21 23 25 27


35/129

S.No Feeder Coal Parameter Unit 12.10.2013Calculated

GCV

Loss in GCV,

%

1 Total moisture % 20 GCV 4216.8

2 Res.Moisture % 4.1 % 50

3 Ash on AD % 41.4 GCV 4131

4 V.M on AD % 25.9 % 25

5 G.C.Value on AD Cals/gm 3790 GCV 4026

6 G.C.Value on ARB Cals/gm 3162 % 25


GCV

Loss in GCV,

%

1 Total moisture % 18.5 GCV 4216.8

2 Res.Moisture % 7.4 % 40

3 Ash on AD % 34.9 GCV 4173.7

4 V.M on AD % 27.3 % 40

5 G.C.Value on AD Cals/gm 4140 GCV 40266 G.C.Value on ARB Cals/gm 3644 % 20

7 Sulphur % 0.64


GCV

Loss in GCV,

%

1 Total moisture % 20.5 GCV 4216.8

2 Res.Moisture % 7.2 % 253 Ash on AD % 33.9 GCV 4173.7

4 V.M on AD % 29 % 50

5 G.C.Value on AD Cals/gm 4270 GCV 4131.6

6 G.C.Value on ARB Cals/gm 3658 % 25

7 Sulphur % 0.51

TABLE 2: Comparison of calculated GCV based on receipt analysis and actual GCV in the fuel mix fed to the boiler

Coal combination , receipt GCV & % mix



986

23.77

518

12.44

516

12.36

Chargaon

Maheswari

Gandhar

4147.65

4161.4

4173.95

Chargoan

Gandhar

Singareni

Chargaon

Maheswari

Singareni


36/129


37/129

ANNEXURE 4- COAL STORAGE AND RECLAIMING & SPONTANEOUS COMBUSTION


38/129


39/129


40/129

ABOUT SPONTANEOUS COMBUSTION


41/129

Spontaneous combustion is an oxidation reaction thatoccurs without an external heat source. The process changes

the internal heat profile of the material leading to a rise intemperature. This can eventually lead to open flame and

burning of the coal. Coal fires require three basic elements to

exist as shown in figure.

The process leading to spontaneous combustion can be

summarised as follows:

Oxidation occurs when oxygen reacts with the fuel, i.e. coal The oxidation process produces heat If the heat is dissipated, the temperature of the coal will not increase If the heat is not dissipated then the temperature of the coal will increase At higher temperatures the oxidation reaction proceeds at a higher rate Eventually a temperature is reached at which ignition of the coal occurs.Combustible matter can interact with the oxygen in the air at ambient temperature releasing heat.

Favourable conditions for spontaneous heating would be the accumulation of heat caused by a rise in

temperature and hence an increase in the reaction rate. Although, at ambient temperature, the

reaction can be so slow that it is unnoticed, when heat accumulates the temperature is raised and,

according to the Arrhenius law, the reaction rate increases exponentially. The following are the

factors affecting spontaneous combustion

Factors inherent to coal:

Size of the coal particles and surface area Moisture content Coal composition, quality and rank of coal Heat conductivity of the particles Coal friability, particle size and surface area Moisture content & ash content The presence of iron pyrites.Extrinsic conditions:

D f ti


42/129

particular circumstances. Temperature difference Heat haze and steam plumes may be observed

on cold mornings and in times of high humidity. Hot spots may also be detected by infrared

monitoring instruments. Routine surveying of stockpiles using infrared scanning devices is anexcellent precaution in situations where spontaneous combustion may be likely to occur.

Some characteristics of spontaneous combustion as well as guidelines for minimising the probability

of a fire are listed below.

The higher the inherent moisture, the higher the heating tendency The lower the ash-free calorific value, the higher the heating tendency The higher the oxygen content in the coal, the higher the heating tendency Sulphur, once considered a major factor, is now thought to be a minor factor in the spontaneous

heating of coal.

The finer the size of the coal, the more surface is exposed per unit of weight and the greater theoxidising potential, all other factors being equal.

Segregation of the coal particle sizes is often a major cause of heating. Coarse sizes allow air toenter the pile at one location and react with the high surface area fines at another location. Coalswith a large top size (>100mm) will segregate more in handling than those of smaller size

(


43/129

increased propensity to oxidation. Higher size particles roll down to bottom causing voidage.

This helps air to penetrate.

Proper attention must be given to the preparation and maintenance of the stockpile. Pilemaintenance might be crucial in avoiding channels where air can easily creep into the dump.

Haphazard storage must be avoided.

Proper compaction. Air circulating within the stockpile should be restricted by propercompacting and dozing off. Or else the coal piles must be covered at the bottom ends of say up to

1 m height.

Moisture contributes the spontaneous combustion as it aids in the oxidation process. Moisturecontent should be limited to about 3 percent to avoid enhanced oxidation. Measures must betaken to keep stored coal from being exposed to moisture. This is not practical in Imported coal.

But addition of moisture by water spray aids combustion. Only burning coal must be separated.

Dimensions of stockpile. Size and area of stockpile should be based not only on estimatedtonnage but also on design principles of stockpile management. Proper dimensioning of

stockpiles helps negate weathering of coal. Just dumping the coal in a big pile might lead to

problems. Rather coal should be packed in horizontal layers of about 1.3 to 3 feet high followed

by leveling and compaction by dozers. It helps in evenly distribution of coal thus avoidingsegregation of fine coal. Pile unlayered, uncompacted high grade coal should be limited to about

15 feet and while layered and packed coal pile height should be limited to about 26 feet.

Use of protective covering. Inert covering material such as tarpaulin sheets with sufficient heatresistivity can be used to cover the openly kept stockpile to reduce the loss of calorific value and

further oxidation of coal. It helps in cutting off oxygen to come in contact with coal.

Regular use of IR camera for identification of the hot zones will help to identify the hot spots andremoval of burning zones from the main pile must be attempted.


44/129


45/129

Photo 1 : Misalignment in conveyor is seen in a conveyor. The spilled coal may be transported backto yard or to bunker. Yet it causes a reduction of evaporation ratio or it increases the specific coal

consumption.


46/129

Photo 4: Coal spillage due to lumps coming from bunker. Bunker generates lumps due to powder and

moist coals at the corners. Conical bunkers are not causing this problem.


47/129

Photo 6: Photo shows the air blaster used in a bunker for clearing rat holes and arches. This device

can be used in raw coal hopper to remove the accumulated coal due to moisture. There are

electrically operated vibrators, but they tend to compact the coal. These air blasters are to be operated

when the coal level is less so that the bunker is kept free of big lumps.


48/129


49/129


50/129


51/129


52/129

Photo 3: This photo shows the trend in boiler 03 taken when the operator had set wide rpm limits.

The pressure signals made use of the entire rpm range and dumped fuel. This can be the reason for

inconsistent ash LOI.


53/129


54/129

Photo 7: It is advisable to avoid the draining of hot ash from the bed. The drain must be closed, once

the hot ash begins to pour out. The drains should be partly opened to enable drain out only coarse

particles. Presence of coarse particles affects the fluidization quality.


55/129

ANNEXURE 7: BED COIL SIZING FOR FBC 03

EWS 604


56/129

PROJECT :

INPUTS FOR COMBUSTION CALCULATIONSAIR & GAS CALCULATIONS

Ta Ambient temperature 40 Deg C

P1 Relative humidity 60 %

Ma Moisture in dry air ( from tables) 0.02825 kg/kg

E Excess air 20 %

Te Boiler outlet gas temperature 135 Deg C

El Site elevation 200 Metres

P Flue gas pressure 5 mmwc

Moisture

10 34 12 10 36

Std As fired Std As fired Std As fired Std As fired Std As fired

42.65 41.97 54.95 44.32 49.29 48.13 36.67 36.67 38.32 31.44

2.65 2.61 4.75 3.83 3.06 2.99 3.00 3.00 4.54 3.737.23 7.12 12.43 10.03 8.35 8.15 31.02 31.02 32.64 26.78

0.41 0.40 0.81 0.65 0.47 0.46 0.08 0.08 0.00 0.00

0.51 0.50 0.87 0.70 0.59 0.58 0.40 0.40 0.23 0.22

8.55 10.00 18.17 34.00 9.88 12.00 10.00 10.00 22.00 36.00

38 37.40 8.02 6.47 28.35 27.68 18.83 18.83 2.27 2.22

100 100 100

4060 3995.63 5598.00 4515.07 4690.00 4579.67 3150.00 3150.00 3350.00 2748.72

91.45 90 81.83 66 90.12 88 90 90 78 64

0 50 50 0 0

0 7566 7566 0 0

0.00 54.41 45.59 0.00 0.00

Constituents of fuel

FUEL

C Carbon 46.23 % by wt

H Hydrogen 3.41 % by wt

O Oxygen 9.09 % by wt

S Sulphur 0.56 % by wt

WCPM SCCL coal 80 TPH- designing bed coi l HTA

Fuel Mix

Indian coal- SCCL Imported coal- des Indian coal Majiri Rice husk Saw dust

Weight percentage

actual weight

heat input ratio

EWS 604

Locations


57/129

A1 % Ash collection at location 1 Bed 20 %

A2 % Ash collection at location 2 Bank 10 %

A3 % Ash collection at location 3 Economiser 5 %A4 % Ash collection at location 4 Airheater 5 %

A5 % Ash collection at location 5 Dust collector 55 %

A6 % Ash collection at location 6 Wet bottom 5 %

100

T1 Temperature of ash at location1 900 Deg C






INPUTS FOR BOILER DUTY CALCULATIONS

**Adjusted for heat duty Steam generation rate Nett 80000 Kg/h

Main steam pressure 63 kg/cm2 g

Main steam temperature 485 Deg C

Feed water inlet temperature 108 Deg C

Superheater Pressure drop 3.5 kg/cm2 gSaturated steam flow from dru 0 kg/h

Boiler efficiency Calculated 84.37

Actual boiler efficiency 81.37 %

INPUTS FOR FLUIDISED BED SIZING CALCULATIONS

Design bed temperature = 900 Deg C

Fluidisation velocity = 2.6 m/s

EWS 604

COMBUSTION CALCULATIONS FOR FUEL PER KG BASIS Date & time: 10/31/13 5:31 AM


58/129

PROJECT :

INPUTS FOR AIR & GAS CALCULATIONS Fuel Mix

Ta, Ambient temperature = 40 deg C

P1, Relative humidity = 60 %

Ma, Moisture in dry air = 0.02825 kg / kg

E, Excess air = 20 %

Constituents of fuel ( % by weight )

C, Carbon = 46.23 %

Carbon lost in ash = 0.92 %

carbon burnt = 45.31 %

H, Hydrogen = 3.41 %

O, Oxygen = 9.09 %

S, Sulphur = 0.56 %

N, Nitrogen = 0.64 %

M, Moisture = 23 %

A, Ash = 17.08 %

Ai r requirement calculations

O2 reqd, kg/kg of Carbon in fuel = 2.644 kg/kg

O2 reqd, kg/kg of Hydrogen in fuel = 7.937 kg/kg

O2 reqd, kg/kg of Sulphur in fuel = 0.998 kg/kg

Solid crbon unburnt from Efficiency calc, = 0.0092 kg/kg

O2 reqd, for the Carbon in fuel =( 0.4623 - 0.0092)x2.644 /100) kg/kg

= 1.198 kg/kg

O2 reqd, for the Hydrogen in fuel =( 7.937x3.41 /100) kg/kg

= 0.271 kg/kg

O2 reqd, for the Sulphur in fuel =( 0.998x0.56 /100) kg/kg

= 0.006 kg/kg

Stochiometric O2 reqd / kg of fuel = O2 reqd for C,H,S in fuel - O2 in fuel) kg/kg

Stochiometric O2 reqd / kg of fuel = ( 1.198+0.271+0.006) -(9.09 / 100) kg/kg

= 1.3841 kg /kg of fuelExcess O2 required / kg of fuel = ( 1.3841x / 100 ) kg /kg of fuel

= ( 1.3841x 20 / 100 ) kg /kg of fuel

= 0.27682 kg/kg

Total O2 required / kg of fuel = ( 1 3841+ 0 27682) kg/kg

WCPM SCCL coal 80 TPH- designing bed coil HTA

EWS 604

Gas weight const ituents calculations


59/129

CO2 produced, kg/kg of Carbon in fuel = 3.644 kg/kg

H2O produced, kg/kg of Hydrogen in fuel = 8.937 kg/kg

SO2 produced, kg/kg of Sulphur in fuel = 1.998 kg/kg

CO2 produced, for the Carbon in fuel =( 3.644x45.31 /100) kg/kg

= 1.651 kg/kg

H2O produced, for the Hydrogen in fuel =( 8.937x3.41 /100) kg/kg

= 0.305 kg/kg

H2O in combustion air = 0.02825x7.221 kg/kg

= 0.204 kg/kg

H2O due to moisture in fuel = 23/100 kg/kg

= 0.23 kg/kg

H2O due to air & H2 combustion& fuel moisture =( 0.204+0.305+0.23) kg/kg

= 0.739 kg/kg

SO2 produced, for the Sulphur in fuel =( 1.998x0.56 /100) kg/kg

= 0.011 kg/kg

O2 in flue gas ( Excess O2 added ) = 0.27682 kg/kg

N21,Nitrogen due to fuel = N kg/kg

= 0.0064 kg/kg

Weight fraction of Nitrogen in Dry Air = 0.77 kg/kg

N22 due to Air, kg per kg of fuel = 0.77 x 7.221 kg/kg

= 5.560 kg/kg

Total N2 in flue gas , kg/kg of fuel fired = N21+N22 kg/kg

= ( 0.0064+5.560) kg/kg

= 5.5664 kg/kg of fuel

Qfgw, Total wet flue gas produced per kg of fuel fired = 1.651+0.739+0.011+0.27682+5.5664

= 8.24422 kg/kg

Wet flue gas produced, kg /kg of fuel fired = 8.244 kg/kg

Qfgd, Total dry flue gas produced per kg of fuel fired = 1.651+0.011+0.27682+5.5664

= 7.505 kg/kg

Dry flue gas produced, kg /kg of fuel fired = 7.505 kg/kg

wet gas

kg / kg of

fuel

Mol.

weight

Flue gas ( wet ) composition

by % wt

Flue gas ( wet ) composition by %

vol

No of moles / kg of

fuel

Composition of Flue gas

EWS 604


60/129

Results Summary

Dry air required, kg /kg of fuel fired = 7.221 kg/kg

Wet air required, kg /kg of fuel fired = 7.425 kg/kgDry Flue gas produced, kg /kg of fuel fi red = 7.505 kg/kg

Flue gas produced, kg /kg of fuel fired = 8.244 kg/kg

Flue gas composition summary

Wet by vol % Dry by vol%

Carbon di oxide = 12.94 % = 15.11 %

Water vapour = 14.34 % = 0 %

Sulfur di oxide = 0.00 % = 0.00 %

Oxygen = 3.15 % = 3.68 %

Nitrogen = 69.58 % = 81.23 %

EWS 604

DESIGN EFFICIENCY CALCULATIONS Date & time : 10/31/13 5:31 AM


61/129

PROJECT :

INPUTS FOR EFFICIENCY CALCULATIONSHLS1, assumed unburnt carbon loss = 3 %

HLS6, Assumed radiation loss = 0.5 %

HLS7, Manufacturer margin = 0 %


Rh, Relative humidity = 60 %

Ma, Moisture in dry air = 0.02825 kg / kg

E, Excess air = 20 %

Te, Boiler outlet gas temperature = 135 Deg C

A1, % Ash collection at location 1 = 20 % Bed

A2, % Ash collection at location 2 = 10 % Bank

A3, % Ash collection at location 3 = 5 % Economiser

A4, % Ash collection at location 4 = 5 % Airheater

A5, % Ash collection at location 5 = 55 % Dust collector

A6, % Ash collection at location 6 = 5 % Wet bottom

T1, Temperature of ash at location1 = 900 deg C







H, Hydrgen = 3.41 %

M, Moisture = 23 %

A, Ash = 17.08 %

GCV, Gross calorific value of fuel = 4547.37 kcal /kg

DESIGN EFFICENCY CALCULATIONSAssumed heat loss through unburnt carbon in ash

Heat loss through unburn t carbon in furnace ash

A, Ash content in fuel = 0.1708 kg/kg

M1 % ash collection in furnace hopper = 20 %

WCPM SCCL coal 80 TPH- designing bed coi l HTA

EWS 604

LOI in ash = 6 %

C l ifi l f b 8050 k l/k


62/129

Calorific value of carbon = 8050 kcal/kg

Fuel GCV = 4547.37 kcal/kg

Carbon Loss =M1x A x LOI x 8050 / ((100-LOI) x 4547.37) %=80 x 0.1708 x 6 x 8050 /( (100-6 ) x 4547.37) %

HLS1-1, Unburnt carbon loss in fly ash = 1.5440 %

HLS1, Total unburnt carbon loss = 1.6361 %

Solid carbon loss = 1.6361x4547.37 / 8050 %

= 0.92 %

HLS1, Unburnt carbon loss = 1.6361 %

Calculations for Heat loss though ash


C, Specific heat of ash = 0.22 kcal/kg Deg C

HLn, % Heat lost through ash at n'th location = A x (An /100 ) x C x (Tn-Ta) x 100 / GCV

HL1, % Heat lost through ash at a location 1 = 0.1708x (20 / 100 ) x0.22x (900-40) x 100 / 4547.37 %

HL1, % Heat lost through ash at a location 1= 0.14 %











HLS2, Total Heat loss through the ash = HL1+HL2+HL3+HL4+HL5+HL6

= ( 0.14+0.02+0.01+ 0.00+0.05+0.00 )%

HLS2 Total Heat loss through the ash = 0 22 %

EWS 604

HLS3, % Heat lost through moisture in air = Ww x Wd x{(Cp1x Te)-(Cp2 x Ta)}x100/(GCV)

= 0 02825x7 221x[(0 4967x135) (1x40]x100 /(4547 37)


63/129

= 0.02825x7.221x[(0.4967x135)-(1x40]x100 /(4547.37)

HLS3, % Heat lost through moisture in air= 0.12 %

Calculations for Heat loss through moisture & hydrogen in fuel

H, hydrogen in fuel = 0.0341 kg/kg

M, moisture in fuel = 0.23 kg/kg

Cp1, Specific heat of water vapor at boiler exit temp = 0.4967 kcal/kg

L, latent heat of water = 595.4 kcal/kg


Te, Boiler exit temperature = 135 deg C

HLS4, % Heat lost through moisture & H2 in fuel ={M+(8.94 x H)} x [595.4+(Cp1 x Te) -Ta] x 100 / (GCV)

HLS4, % Heat lost through moisture & H2 in fuel

HLS4, % Heat lost through moisture & H2 in fuel= 7.32 %

Calculations for Heat loss through dry flue gas

Qfgd, Dry flue gas produced per kg of fuel = 7.505 kg/kg

Cp3, specfic heat of flue gas at boiler exit temp = 0.242 kcal/kg deg C

Cp4, specfic heat of flue gas at ambient temp = 0.236 kcal/kg deg C


Te, Boiler exit temperature = 135 deg C

HLS5, % Heat lost through dry flue gas =Qfgd x{ (Cp3 x Te) - (Cp4 x Ta)} x100/(GCV)

HLS5, % Heat lost through dry flue gas = 3.83 %

Assumed heat loss through radiation

HLS6, Radiation loss = 0.5 %

Manufacturer margin

HLS7, blow down & vent loss = 2 %Total effici ency break up

HLS1, Unburnt carbon loss = 1.64 %

HLS2, Total Heat loss through the ash = 0.22 %

HLS3 Heat lost through moisture in air = 0 12 %

={ 0.23+ (8.94 x 0.0341)}x [ 595.4+(0.4967x 135) -

40]x100/(4547.37) %

=7.505x { ( 0.242 x 135) - (0.236x40)} x 100/(4547.37) %

EWS 604

BOILER HEAT DUTY CALCULATIONS Date & time: 10/31/13 5:31 AM

PROJECT : WCPM SCCL coal 80 TPH- designing bed coil HTA


64/129

PROJECT :

INPUTS FOR BOILER DUTY CALCULATIONS

Steam generation rate Nett = 80000 Kg/h

Main steam pressure = 63 kg/cm2 g

Main steam temperature = 485 Deg C

Feed water inlet temperature = 108 Deg C

Superheater Pressure drop = 3.5 kg/cm2 g

Saturated steam flow from drum = 0 kg/h

Selected boiler efficiency = 81.37 %

BOILER HEAT DUTY CALCULATIONS

Msup, Steam generation rate = 80000 kg / h

P1, Main steam pressure = 63 kg/cm2 g

Ts, Main steam temperature = 485 deg C

Tw, Feed water inlet temperature = 108 deg C

Hw, Feed water inlet enthalphy = 108 kcal / kg

Hs, Main steam enthalpy = 807.91 kcal / kgH, Heat added per kg of water = ( Hs - Hw )

= ( 807.91 - 108) kcal / kg

H, Heat added per kg of water = 699.91 kcal / kg

Heat output of the boiler ( SH steam) = ( Msup x H) kcal / hr

= ( 80000 x 699.91) kcal / hr

Qo Heat output of the boiler ( SH steam) = 55992800 k cal / h

Msat Saturated steam flow from drum = 0 kg / h

Saturated steam enthalpy = 663.57 kcal/kg

Heat output thorugh the sat. steam = 0x( 663.57-108) kcal/kg

Qs heat outpu t o f the boi ler ( saturated s team) = 0 kcal /h r

Qt Total heat output of the boiler = Qo+Qs kcal/hr

= ( 55992800 + 0 )kcal/hr

Qt Total heat output of the boiler = 55992800 kcal/hr

Selected Boiler efficiency = 81.37 %

Fuel GCV = 4547.37 kcal /kg

Fuel firing rate = Qt x 100 / ( Eff x GCV )

= 55992800 x 100 / ( 81.37 x 4547.37 ) %

= 15,132 kg / hr

Results

Total heat output of the boi ler = 55992800 kcal / hr

WCPM SCCL coal 80 TPH designing bed coil HTA

EWS 604

UNDER FED FLUIDISED BED SIZING Date & time : 10/31/13 5:31 AM

PROJECT : WCPM SCCL coal 80 TPH- designing bed coil HTA


65/129

PROJECT :

INPUTS FOR FLUIDISED BED SIZINGVf, Fluidisation velocity = 2.6 m/s

Tb, Design bed temperature = 900 Deg C

Steam generated nett = 80000 kg/h

Main steam temperature = 485 Deg C

Main steam pressure = 63 kg/cm2 a

Fuel burnt rate = 15,132 kg/h

Wet air required, kg /kg of fuel fired = 7.425 kg/kg

Flue gas produced, kg /kg of fuel fired = 8.244 kg/kg

Flue gas molecular weight = 28.78

Te, Boiler exit temperature = 135 Deg C

Tca, Combustion air temperature = 150 Deg C

Ta, Ambient temperature = 40 Deg C

Assumed carbon loss = 4 %

Ts, Saturation temperature = 283.4 deg C


H, Hydrgen = 3.41 %

M, Moisture = 23 %

A, Ash = 17.08 %

GCV, Gross calorific value of fuel = 4547.37 kcal /kg

UNDERBED FLUIDISED BED SIZING

Calculations for bed cross sectional area

Wet flue gas produced per kg of fuel = 8.244 kg/kg

Fuel firing rate = 15,132 kg/h

Wet flue gas flow rate = 8.244 x 15,132 kg/h

= 124748.208 kg/h

Molecular wt of flue gas = 28.78 from air & gas calcK, altitude correction factor = 0.977

Flue Gas volume flow rate at 0 deg C = 124748.208 x 22.4 / 28.78 x 0.977

= 99,379.54 Nm3 /hr

Flue Gas volume flow rate at 0 deg C = 27 61 Nm3 / sec

WCPM SCCL coal 80 TPH designing bed coil HTA

EWS 604

Calculations for bed heat transfer area

Unburnt carbon loss


66/129

U bu ca bo oss

HL1, % design Unburnt carbon loss= 4 %

Calculations for Heat loss though ash


C, Specific heat of ash = 0.22 kcal/kg Deg C


Tb, Design bed temperature = 900 deg C

HL2, % Heat lost through ash = A x C x (Tb-Ta) x 100 / GCV

= 0.1708x 0.22x (900-40) x 100 / 4547.37 %

HL2, % Heat lost through ash= 0.71 %

Calculations fo r Heat loss through moisture in air

Ww, weight of water in air = 0.02825 kg/kg

Wd, Dry air required per kg of fuel = 7.221 kg/kg from combustion calc

Cp1, specific heat of water vapor at bed temp = 0.577 kcal/kg C

Cp2, specific heat of water vapor at ambient temp = 0.3592 kcal/kg C

Tca, Combustion air temperature = 150 deg CTb, Design bed temperature = 900 deg C

HL3, % Heat lost through moisture in air = Ww x Wd x {(Cp1 x Tb) -(Cp2 x Tca)}x 100 / GCV

= 0.02825x7.221x[(0.577x900)-(0.3592x150]x100 /454

HL3, % Heat lost through moisture in air= 2.09 %

Calculations fo r Heat loss through moisture & hydrogen in fuel

H, hydrogen in fuel = 0.0341 kg/kg

M, moisture in fuel = 0.23 kg/kg

Cpb, Specific heat of water vapor at bed temp = 0.577 kcal/kg

L, latent heat of water = 595.4 kcal/kg


Tb, Design bed temperature = 900 deg C

HL4, % Heat lost through moisture & H2 in fuel ={M+(8.94 x H)} x [595.4+(Cpb x Tb) -Ta] x 100 / GCVHL4, % Heat lost through moisture & H2 in fuel

HL4, % Heat lost through moisture & H2 in fuel= 12.64 %

={ 0.23+ (8.94 x 0.0341)}x [ 595.4+(0.577x 900) -

40]x100/4547.37 %

EWS 604

HL5, % Heat lost through dry flue gas= 36.72 %


67/129

Calculation for Heat loss through radiation to waterwall

Ab, Bed cross sectional area = 45.63 m2e, Emissivity of waterwall surface = 0.9

S, Steafan boltzmann constant = 4.9 x 10 ^ -8

Tb, bed temperature = 900 Deg C

Ts, saturation temperature = 283.4 Deg C

Radiation heat loss to waterwall =Ab x e x S x {( Tb + 273 )^4 - ( Ts + 273 )^4}

= 45.63x0.9x4.9 x 10^-8x{( 900+273)^4-(283.4+273)^4}

= 3,616,757 kcal/h

Fuel heat input in the bed = 15,132x 4547.37= 68810802.84 kcal/h

HL6, % Radiation loss to waterwall = 100x 3,616,757/ 68810802.84

HL6, % Radiation loss to waterwall = 5.26 %

Bed heat balance & HTA required

HL1, Unburnt carbon loss = 4 %

HL2, Total Heat loss through the ash = 0.71 %

HL3, Heat lost through moisture in air = 2.09 %HL4, Heat lost through moisture & H2 in fuel = 12.64 %

HL5, Heat lost through dry flue gas = 36.72 %

HL6, % Radiation loss to waterwall = 5.26 %

Total losses = 4+0.71+2.09+12.64+36.72+5.26

= 61.42 %

Therefore, % heat to be transferred to Bed coil = 100 - 61.42 %

% Heat transferred to Bed coil = 38.58 %

Fuel heat input in the bed = 68810802.84 kcal/h

Actual heat to be transferred to Bed coil = 38.58 x 68810802.84/ 100

= 26,547,208 kcal/h

Tb, bed temperature = 900 Deg C

Ts, Saturation temperature = 283.4 Deg C

Temperature difference = (900 - 283.4)= 616.6 deg CHeat transfer coeff = 220 kcal / kg m2 Deg C

Bed coil area required = 26,547,208/ ( 220 x 616.6)

Bed Coil HT area required, if plain = 195.70 m2

free board combustion = 0 %

EWS 604

Summary of results

Bed cross sectional area required = 45.63 m2


68/129

Bed cross sectional area available = 42.6 m2

Bed Coil length requi red = 1221.44 mBed Coil length available = 1537.58 m

Bed coil eff length to be covered by refractory = 316.14 m

Actual length to be covered by refractory = 243.2 m

Bed coil length to be covered by refractory = 223.8 m For SCCL

Bed coil length to be covered by refractory = 246.4 m For Majiri

Bed coil length to be covered by refractory = 368.1 m For Imp coal

= 250 m

= 1.51 m

= nil

Selected length to be covered by refractory

Per coil length to be covered on outer coil

Per coil length to be covered on inner coil


69/129

ANNEXURE 8: AIRPREHEATER LEAKAGE REPORT- CO & O2 PROFILE


70/129


71/129


72/129

OXYGEN CO PROFILE FROM APH INLET TO ID FAN FBC 3


73/129

VENUS ENERGY AUDIT SYSTEM

Log Sheet-1

Flue gas analys is for FBC-3

Customer name: West Coast Paper Mills Ltd,.


74/129

DATE: 06.10.13 TIME: 11.15am FUEL COMBINATION: 100% coal

Feeder

1

Feeder

2

Feeder

3

Feeder

4

Feeder

5

Feeder

6

Feeder

7

Feeder

8

Feeder

9

Feeder

10

6.5 205 4.54

6.4 226 4.52

6.3 214 4.52

10.2 150

10.7 159

10.4 155

10.4 160

10.8 166

10.8 157

DATE: 06.10.13 TIME: 12.30am FUEL COMBINATION: 100% coal

45 - -

3 ID FAN I/L

1 APH I/L

2 APH O/L 45 45-

-

FLUE GAS ANALYSIS (TRIAL - 1)

S.No LOCATIONO 2

(Field %)

CO

(PPM)

O 2

(DCS %)

MainSteam

Flow (TPH)

FD Flow

(TPH )

COAL FEEDER RPM

45 45 45 45 45 78 to 79 52.7 to 53.5

Feeder

1

Feeder

2

Feeder

3

Feeder

4

Feeder

5

Feeder

6

Feeder

7

Feeder

8

Feeder

9

Feeder

10

6.7 220 4.7

6.6 227 4.3

6.3 206 4.4

11 140

10.8 144

10.9 160

10.9 167

10.6 170

APH O/L

3

- --

-

48

ID FAN I/L

-

S.No LOCATIONO 2

(Field %)

CO

(PPM)

O 2

(DCS %)

COAL FEEDER RPM FD Flow

(TPH )

MainSteam

Flow (TPH)

1 APH I/L

2 48 48 48 48 48 48 48 79 to 80 53 to 54

DATE: 06.10.13 TIME: 02.30pm FUEL COMBINATION: 100% coal

Feeder

1

Feeder

2

Feeder

3

Feeder

4

Feeder

5

Feeder

6

Feeder

7

Feeder

8

Feeder

9

Feeder

10

COAL FEEDER RPM


FD Flow

(TPH )

MainSteam

Flow (TPH)S.No LOCATION

O 2

(Field %)

CO

(PPM)

O 2

(DCS %)


75/129

1 2 3 4 5 6 7 8 9 10

6.1 240 4.54

6.3 266 4.52

6.2 253 4.52

9.8 179

10.2 165

9.9 169

10 157

10.2 155

10 163

DATE: 06.10.13 TIME: 4.15pm FUEL COMBINATION: 100% coal

Feeder

1

Feeder

2

Feeder

3

Feeder

4

Feeder

5

Feeder

6

Feeder

7

Feeder

8

Feeder

9

Feeder

10


S.No LOCATIONO 2

(Field %)

CO

(PPM)

O 2

(DCS %)

COAL FEEDER RPMFD Flow

(TPH )

MainSteam

Flow (TPH)

- -45 45 45 45 45 45 45 45 78 to 79 52 to 532 APH O/L

3 ID FAN I/L

-

-

( ) ( )

1 APH I/L

(Field %) ( ) (DCS %)

6.9 217 4.92

6.7 229 4.71

6.7 243 4.52

10.5 160

10.7 157

9.9 163

10.1 162

10.2 159

10.2 163

3 ID FAN I/L -

50 - -2 APH O/L -

1 APH I/L

50 45 45 45 45 45 45 80 to 81 52 to 53

AIRPREHEATER LEAKGE REPORT- FBC 04


76/129

8/13/2019

Report on Boiler Performance Audting in a Paper Plant by K.K.parthiban

Documents