Condenser & Feed water heaters
Transcript of Condenser & Feed water heaters
-
7/30/2019 Condenser & Feed water heaters
1/32
498
Condenser performance is one of the important factors for efficient operation of the
plant. Higher the Rankine cycle efficiency if lower is the temperature at which heat is rejected.
Hence maintaining condenser back pressure at design value is important. Condenser design
is based on expected values of Heat load, C. W. Inlet temperature and quantity of insoluble
gases. If any one or more of these values exceed the design value, higher than expected back
pressure may result. Objective of the Condenser performance test is to know whether condenser
is performing as per the design expectations at operating parameters. Deviations are then
analyzed for finding out the causes and actions for improvement are initiated. Analysis of
condenser performance is based on following indices, which are evaluated from test results.
Per f o r m ance I nd i ces :
Absolute pressure deviation from expected/ design.
Terminal temperature Difference (TTD)
Cleanliness Factor.
Sub-cooling of condensate and air / steam mixture
Heat Transfer Coefficient
Effectiveness of tube cleaning
Circulating water velocity in tubes
Circulating water temperature rise
Flow rate of air / steam mixture
Dissolved Oxygen in condensateEffect of condenser performance on heat rate
These indices are computed from the test results in following ways.
Condense r Du t y : It is the measure of heat load on condenser. Based on test data, this
parameter is computed and deviation from design value is found out.
Condenser Duty = (Heat added in Main Steam + Heat added in HRH steam) 860 (Gross
Generator output in KW + Generator losses in KW + Heat lost by radiation)
Where Heat added in Main Steam = M.S. Flow in Kg/ Hr (Enthalpy of Main Steam
Enthalpy of Feed Water) Kcal / HrHeat added in Reheat Steam = HRH Steam Flow in Kg/ hr (Enthalpy of HRH steam Enthalpy of CRH steam) Kcal / Hr
Radiation Loss = 0.1% of Gross Generation in KW
Generator Losses = (Mechanical Losses + Iron Losses + Stator Current losses) KW,These Values taken from Generator Loss Curve
860 = Equivalent heat energy for 1 KWh electrical energy.
CONDENSER AN D FEED W ATER HEATERPERFORMANCE
-
7/30/2019 Condenser & Feed water heaters
2/32
Condenser Duty (Kcal /hr)
Condense r coo l i ng w a t e r F low = m3 / hr
Cp (Tout Tin) D
Where Cp = Specific Heat of Water = 1 Kcal / Kg deg CD = Density of water = 1000 Kg / m3
Tout = Average C W outlet temperature, deg C
Tin = Average C W inlet temperature, deg C
A l t e r n a t e M et hod : C W flow can be found out from cooling water pumps Head Vs Discharge
flow characteristics. Head developed by the pump is measured during the test. It is then
corrected for design speed as follows.
Head Developed (Nd) Computed Head =
(N)
Where Computed Head = in mwc
Head developed by the pump = in mwc
Pump Running speed N = rpm
Pump Design speed Nd = rpm
W at e r Ve loci t y i n Condenser Tubes :
C. W. Flow Rate 106
Velocity =
3600 Tube area (Number of tubes No. of tubes plugged)
Where Tube velocity is in m/sC.W. Flow rate is in m3/ hr
Tube area is in mm2
Log M ean t em per a t u r e D i f f e r ence :
Tout - TinLMTD =
Tsat - Tin
Ln
Tsat Tout
Where LMTD is in Deg C
Tsat is in deg C, (Saturation temperature corresponding to condenser pressure)
Clean l in ess Fac to r :
U actual (Actual Heat Transfer Coefficient)Cleanliness Factor =
U theoretical (Theoretical Heat transfer coefficient)
499
-
7/30/2019 Condenser & Feed water heaters
3/32
Condenser flow Cp (Tout Tin) Density of waterU actual =
A condensing LMTD
U actual = kcal/ hrm2 0CDensity of water = 1000 Kg/ m3
A condensing = (Tubes surface area No. of tubes ) in m2
U theoretical = C1 C2 C3 C4 Velocity
Values of Constants C1 through C4 are known from the tables given below
Values o f cons tan t C1
Tube diameter in inches 3/4 7/8 1.0
C1 (V in m/s and U in W/(m2-K) 2777 2705 2582
Values o f cons tan t C2
Water temp C 21.11 26.66 32.22 37.77
C1 1.00 1.04 1.08 1.10
Values o f cons tan t C3
Tube Material Tube wall Gauge - BWG
24 22 20 18 16 14 12
Admiralty Brass 1.06 1.04 1.02 1.0 0.96 0.92 0.87
Arsenical Copper 1.06 1.04 1.02 1.0 0.96 0.92 0.87
Copper Iron 194 1.06 1.04 1.02 1.0 0.96 0.92 0.87
Aluminum Brass 1.03 1.02 1.00 0.97 0.94 0.90 0.84
Aluminum Bronze 1.03 1.02 1.00 0.97 0.94 0.90 0.84
90-10 Cu-Ni 0.99 0.97 0.94 0.90 0.85 0.80 0.74
70-30 Cu-Ni 0.93 0.90 0.87 0.82 0.77 0.71 0.64
Cold rolled low Carbon Steel 1.00 0.98 0.95 0.91 0.86 0.80 0.74
Stainless Steel Type 304/ 316 0.83 0.79 0.75 0.69 0.63 0.56 0.49
Titanium 0.85 0.81 0.77 0.71 - - -
Values o f cons tan t C4
C4 0.85 for clean tubes, less for algae covered tubes.
500
-
7/30/2019 Condenser & Feed water heaters
4/32
Expec t ed LM TD f o r Dev ia t i on f r om des ign va lue :
Correction for C W Inlet temperature, Ct:
1/4
Ct = Saturation Temp Test LMTD testSaturation Temp design LMTD design
Cor r ec t ion fo r C.W. Flow , Cf :
1/2
Ct = Tube Velocity test
Tube velocity design
Cor r ec t i on f o r condense r h ea t l oad Cq :
Cq =Condenser Duty design
Condenser Duty test
Expected LMTD = LMTD test Ct Cf Cq deg. C
Expec t ed Sa t u r a t i on t em per a t u r e :
| Tin Tout Expo [ Z ] |
Expected Saturation temperature =
| 1 Expo [ Z ] |
Z = (Tout Tin) / Expected LMTD
Where Tout = Temperature of C.W at condenser outlet
Tin = Temperature of C.W at condenser inlet
Feed W a t e r Hea t e r Per f o r m ance :
Feed Water heater performance indices are :
1. Terminal Temperature Difference, also called TTD
2. Drain Cooler Approach, DCA,
3. Extraction steam flow rate to the heater.
These indices are computed from the Extraction Steam Parameters, Feed water Inlet/
outlet parameters and Drain or drip parameters. These indices are then compared with design
/ expected values and actions are planned to correct the deviations. Following discussions
explain how these indices are evaluated.
Ter m ina l t em per a t u r e D i f f e r ence, TTD :
TTD = (Saturation temperature of extraction steam Temperature of Feed Water at Heater
outlet)
Dra in Coo le r Appr oach, DCA :
DCA = (Temperature of Heater Drip Temperature of feed water at Inlet)
501
-
7/30/2019 Condenser & Feed water heaters
5/32
Desuperheating
Condensing
Drain Cooling
Extraction Steam Inlet
Drain From cascaded heater Feed Water O/ L
FW I/L
Drain Outlet
502
Desuperheating Condensing Zone Subcooling
Shell Steam
Temperature
Ex t r ac t i on St eam Flow :
The heat balance around the heater is given by
Heat Energy released from extraction steam = Heat energy absorbed by feed water
Heat Energy released from extraction steam = Extraction steam flow rate (sp. enthalpy
of steam specific enthalpy of drip water)
Heat energy absorbed by feed water = Feed flow rate through heater (Sp. Enthalpy of
Feed water at heater outlet - Sp. Enthalpy of Feed water at heater inlet) + Drain flow from
cascaded heater (Enthalpy of Drain from cascaded heater Enthalpy of drain in the
heater under analysis)
Heat energy absorbed by feed waterExtraction steam flow rate =
(Enthalpy of steam Enthalpy of drip water)
Measured values are
1) Extraction steam pressure and temperature
2) Feed water temperature and pressure at inlet and outlet of heater
3) Drip temperature4) Feed Flow rate
Typ ica l Feed Wat er Heater :
-
7/30/2019 Condenser & Feed water heaters
6/32
Pr o f i l e o f Hea t Gain by f eed w a t e r i n Hea t e r
Poor performance of the heater results in Low feed water temperature at Heater outlet.
Probable reasons can be found out from the performance indices as per following guidelines.
Reasons f o r Low Feed W a t e r Tem per a t u r e a r e1) Excessive makeup
2) Poor performance of the heater.
High T.T.D. or High D.C.A. temperature results in Poor performance.
Reasons fo r h igh TTD are :
1) Excessive Venting because of worn out vents, vent malfunction
2) High water level in heater shell due to Tube leaks or improper setting of Heater level
control
3) Leak in the partition of the header for feed water inlet / outlet
4) Noncondensible gases in shell side5) Excessive tube bundle pressure drop because of tubes internal fouling ro excessive no. of
tubes plugged
Reasons f o r h igh DCA t em per a t u r e a r e :
1) Drain cooler inlet not submerged in the drip
2) Low water level in the heater due to improper setting of the set point or Control valve
bypass left open or it is passing
3) Excessive tube bundle pressure drop because of tubes internal fouling or excessive no. of
tubes plugged
Low feed water temperature also result due to passing of the Heaters Feed sidebypass valve.
503
-
7/30/2019 Condenser & Feed water heaters
7/32
504
In thermal power plant, Chemical Energy of fuel is converted to electrical energy. The
conversion cycle is based on Thermodynamic Vapor Cycle, called Rankine Cycle. Conversion
takes place through various stages and different processes are involved for the purpose. Dueto the various limitations nature has imposed, such as Irreversibility in the process, heat
losses to atmosphere, Friction losses, Heat Transfer losses, to name a few, efficiency of
conversion is always less than 100%. In addition to these losses, some heat energy is rejected
because, steam temperature and pressure drop to such low values (after doing work in Turbine),
that further conversion to useful work is not possible. Due to all these reasons, energy input
is much more for one kWh electrical energy output from the Generator. If the Chemical /
Electrical conversion process should have been 100% efficient, 860 Kcal heat energy input
should have given one kWh electrical energy out put at Generator terminals. This r a t i o of
Electrical Energy Outputover a certain period of time to Chemical Energy inp ut to the Plant
over the same period is called Hea t r a t e.
In modern plants, designed for High temperature and pressure Steam admission to
Turbine, efficiency and heat rate can be around 36% and 2400 Kcal/ KWh respectively.
The term Heat rate is defined in many ways as follows:
Net Un i t Hea t r a t e: It is the ratio of energy input to Boiler in terms of Heat energy of fuel, for
one kWh of electrical energy output at Bus Bars, i.e. after UAT. If the out put and input is
considered for a period of an hour, then it is Net Unit Heat rate for one Hour. Similarly, it can
be calculated over a period of a Day, a Week, a Month or a Year.
In this case, it is the sent out energy that is considered, hence, consumption of electrical
energy for driving the plants auxiliaries is also accounted for.
Gross Un i t Heat r a te : It is the ratio of energy input to Boiler in terms of Heat energy of fuel,
for one kWh of electrical energy output at Generator Terminals. In this case, auxiliary
consumption is NOT accounted for.
Net Turb ine Cyc le Heat ra te : It is the ratio of heat energy contained in steam admitted to
Turbine for one kWh of electrical energy output at Generator Terminals. In this case, auxiliary
consumption and losses in Boiler are NOT accounted for.
Oper a t i ng Hea t r a t e : It is the heat rate calculated by considering the inputs and outputs
from the plant only when it is synchronized with the grid. In this case, the fuel input required
for steam conditioning, from light up to synchronization is not considered. Also auxiliaries
consumption during the period of plant shut down is not considered.
W h a t i n f o r m a t i o n d o es H e at r a t e g i v e ?
The plant is designed to generate electricity at certain design heat rate. Deviations fromdesign values give a valuable information regarding the operational and maintenance practices.
Also, by comparison with the historical data, decisions can be taken while making investments
on the maintenance and renovation. Also, problem area can be identified and analyzed for
improvements. A deviation in Gross Turbine Cycle heat rate tells us about energy conversion
scenario in turbine, including condenser and regenerative feed heating process. If Net average
unit heat rate deviates from that of design, it tells us how much extra amount of energy is put
in and how much money is wasted.
HEAT RATE OF THERMAL POW ER PLANT
-
7/30/2019 Condenser & Feed water heaters
8/32
Now a days, tariff for supply of electricity to consumers is fixed by Maharashtra Electricity
Regulatory Commission. While fixing tariff, MERC has given the benchmark heat rate values
for all power plants in MSEB. If actual heat rate is more than the benchmark heat rate, the
additional expenditure incurred shall not be considered in Generation cost for fixing tariff.
Naturally MSEB will have to absorb the cost of this expenditure. Another important aspect is
of conservation of fast depleting natural resources, such as coal and fuel oil. When power is
generated at optimum heat rate, minimum possible fuel is consumed. Less fuel consumption
also leads to lesser extent of pollutants added to the environment. Hence monitoring and
controlling the heat rate to the optimum level has many benefits.
Ca lcu lat i ons o f hea t r a t e :
Net Unit Heat rate, for given time period, is calculated by the formula,
(Coal Consumption Its Calorific Value + Oil Consumption Its Calorific Value)
Generation measured at Bus Bars
To measure coal consumption accurately is very difficult. Also the calorific value of coal
varies and its continuous, on line measurement is not possible.
Hence, in normal practice, unit heat rate is calculated by the simpler method:
Unit Heat rate = Turbine Cycle Heat rate / Boiler Efficiency calculated by loss method.
Turbine Cycle Heat rate = (Total Heat added to Turbine in Kcal) / (Generation in MU)
Total Heat added to Turbine Cycle =
((Sp. Enthalpy of S.H. Steam at Boiler Outlet x Total Steam Flow Rate to H.P.T.)
(Sp. Enthalpy of Feed Water at economizer inlet x Feed Water Flow rate at
economiser inlet))
+ (Sp. Enthalpy of R.H. Steam at Reheater outlet Sp. Enthalpy of C.R.H. steamat Reheater inlet) x Reheat Steam Flow
+ (Sp. Enthalpy of S.H. Steam at Boiler Outlet Sp. Enthalpy of S.H. spray) x
S. H. Attemperator Flow
+ (Sp. Enthalpy of R.H. Steam at Reheater outlet Sp. Enthalpy of Reheat attemporator)
x R. H. Attemperator Flow.
Values of temperature, pressure and flow rate are known from instrumentation and
specific enthalpy can be known from Steam tables. The value of generation is known from the
Energy Meters. If reading of energy meter connected to Generator terminals is considered in
this formula, the heat rate obtained is Gross Heat rate and if that from Bus Bar energy meter
is considered, then it is the net heat rate.
For method of calculation of Boiler efficiency by loss method pl. refer the chapter on the topic.
Fac t o r s a f f ect i ng t he Tu r b in e Hea t r a t e :
1) Main Steam Temperature at H.P.T Inlet
2) Main Steam Pressure at H.P.T Inlet
3) Reheat Steam Temperature at I.P.T Inlet
4) Reheat Steam Pressure at I.P.T Inlet
505
-
7/30/2019 Condenser & Feed water heaters
9/32
5) Condenser Vaccume
6) Temperature of Feed Water at Economiser Inlet.
7) Boiler efficiency
8) S.H. and R.H. attemperation flow rate.
The ef f ec t o f i nd i v idua l pa r am e t e r i s d i scussed be low :
Rankine cycle efficiency, rankine = 1 (T2/ Tm1) (1)
Where; T2 is temperature of heat rejection, (2)
Tm1 is Mean temperature of steam admission = (h1 - h4s) / (s1 - s4s). (3)
h1 & s1 are specific enthalpy and entropy of steam at admission temperature and pressure,
h4s and s4s are the Sp. Enthalpy & entropy of feed water at Economiser inlet.
1) Temperature and Pressure of steam admission (M. S. as well as H.R.H) : Forrankine tobe high, Mean temperature of Steam admission (Tm1 in expression 1 above) should be as
high as possible. Metallurgical constrains limit these values for the given Turbine. However, by
maintaining the steam parameters close to the values specified by the Manufacturer, maximum
possible Mean temperature of Steam admission is achieved thus cycle is operated at design
efficiency. Effect on heat rate due to Deviation from design values for 210 MW LMW plant is
as follows :
Parameter Expected Value Actual Value Heat rate Excess Coal Excess coal
deviation Consumption consumption
Kcal/kwh /KWh ( C.V. 3500 over the year,
Kcal/Kg) at 80% PLF
Main Steam temp. 537 C 532 C 1.648 0.0048 Tons
H.R. Steam temp. 537 C 532 C 3.3342 0.0009 2190Tons
Main Steam Pressure 140 Kg/cm 138 Kg/cm 2.417 0.0.0006 1016 tons
2) Condenser Vaccume plays a very important role in efficiency of the Rankine Cycle. Ifvaccume is less than design value, i.e. if Condenser absolute pressure is more than design
value, corresponding saturation temperature is more, thus Heat is rejected at Higher
Temperature (T2 in expression 1 is less than design) and cycle efficiency drops. This increases
Heat rate. Also the of the L.P.T. backpressure increases, thus reducing the conversion of Heat
Energy to work in Turbine. This increases specific steam rate thus increasing fuel consumption.
In Condenser, only latent heat is rejected, hence condensate temperature is always at saturation
temperature. If condenser pressure is less than design value, temperature of condensate
shall also be less. This causes low feed water temperature, thus increasing the heat rate.
Following table shows effect of deterioration of condenser vaccume on heat rate.
Parameter Expected Actual Excess Heat rate Excess Coal Consumption / Excess coal
Kcal / KWh KWh ( C.V. 3500 Kcal/Kg) consumption over theyear, at 80% PLF
Condenser 690 670 19 0.0054 7989 Tons
mm Hg. mm Hg.
3) Less Temperature of feed water at Economizer inlet causes efficiency of Rankine Cycle to
drop, as Mean temperature of steam admission decreases. Values of h4s and s4s in expression
3 above are high, thus reducing Mean temperature.
506
-
7/30/2019 Condenser & Feed water heaters
10/32
Parameter Expected Actual Excess Heat rate Excess Coal Consumption / Excess coalKcal / KWh KWh ( C.V. 3500 Kcal/Kg) consumption over the
year, at 80% PLF
Feed Water 253 C 248 C 22 0.0063 9261 Tons
Temp.
Reasons f o r Low St eam t em per a t u r e and P r essu r e :
In the Power Plant, there can be many reasons for low temperature of Steam at Boiler
and Reheater outlet. Passing spray water control valves and motorized valves, inadequately
tuned temperature control system, fouled surfaces of the Super Heaters are some of the
reasons. These reasons become more dominant when the plant is operating at loads below
maximum rating. Throttling of steam flow due to partially shut valves is the major reason for
low pressure of steam at Turbine admission.
Reasons f o r poo r vaccum e in Condenser :
1 ) Ai r in gr ace in co nd en ser : Air ejection system of the condenser has the capacity to
remove non-condensable gases present in the steam in normal operation. As the condenser isoperated at less than atmospheric pressure, it is prone for air leaking in to it. Sealing systems,
such as Turbine Gland Sealing, Water sealing of the evacuation system Valves, are provided
to prevent the air ingrace. If Gland sealing steam pressure and temperature and Valve Gland
sealing water pressure are not maintained properly, atmospheric air enters the condenser in
large quantity. Evacuation system can not remove the excess air and hence condenser pressure
increases. Condensers are also provided with many tapping points for instrumentation. Many
of these tapping points are used only for carrying out acceptance tests. Once these tests are
over, the temporary instrumentation connected to condenser is removed. If any of such tapping
point remains open by oversight, air enters the condenser. There is also a chance of cracks
developed on the connection between L.P.T. casing and condenser. Damaged gaskets on flanged
joints, leaking vent valves provided on Pressure gauges, cracked impulse lines, passing vaccume
breaker valves, atmospheric vent or drain valves on C.E.P. inlet piping, if are open, also causeair ingrace. Evacuation equipment, such as Steam Ejectors, Electrical Vaccume Pumps are
provided with airflow measuring devices. Any increase in the flow rate indicates air ingrace.
Condenser air leaks can be identified by manual inspection while the plant is on load. Helium
Leak Detectors can also check air leaks. When the unit is shut down, condenser leaks can be
detected by filling Condenser with D.M. Water up to certain high level. But this test needs lot
of prior preparation.
2 ) H igh C. W . Tem per a t u r e , I nsu f f i c i en t Flow r a t e o r Fou led hea t t r ans f e r su r f ace :
Condensers are heat exchangers. Heat transfer takes place from steam to cooling water from
the tube surface. Cooling water takes away the Latent Heat from condensing steam. The heat
transfer equation is
Q = U * A * Tm (1)
Where Q is heat load on condenser, a function of mass rate of steam condensing
U is the coefficient of heat transfer,
A is the surface area of tubes
Tm is Log Mean Temperature Difference,
507
-
7/30/2019 Condenser & Feed water heaters
11/32
Ti - Tf
Where Tm = (2)
Ln (Ti / Tf)
Ti = (saturation temperature of steam C.W. inlet temperature) (3)
Tf = (saturation temperature of steam C.W. outlet temperature) (4)Also called Terminal Temperature Difference or TTD
Relationship between Water flow rate and heat load is given by
mw = Q / ( cp * (T2 T1) ) (5)
(T2-T1) = (mw * cp) / Q (6)
Where mw is Mass flow rate of Water
cp is specific heat of water = 4.2 Kcal / Kg / C,
T2 is Temperature of Water at condenser outlet
T1 is Temperature of Water at condenser inlet,
In the installed system, Mass flow rate of water (depends on the C.C.W pumping capacity)and Heat Load (Mass of steam from LPT exhaust) becomes constant. And as per equation 3
above, heat removal capacity solely depends on (T2 - T1). Temperature of Cooling Water, T2,
at Condenser outlet can increase only up to the value decided by design T.T.D. for the condenser,
Design value for T.T.D. in Condensers is generally 2.5 C, as designing condenser for TTD
below this is not viable. Hence, ultimately, the heat removal becomes directly dependent on
Cooling Water Inlet temperature (assuming other factors to be constant for the given case).
Increase in this temperature will cause reduction in mass of steam getting condensed. In such
cases, some steam remains in vapour form, causing Condenser Pressure to increase. Similarly,
even if Cooling Water temperature is within design limits, but its mass flow rate reduces,
same scenario can be expected.
If heat transfer coefficient deteriorates, it again lead to increased Condenser Pressure,
as all the steam do not condense because of insufficient cooling.
Reasons f o r H igh C. W . t em per a t u r e :
In Cooling Towers, evaporative cooling of Hot water takes place. Air, sucked by the C.T.
Fan, flows in cross flow direction to water flow, comes in contact with air, causing evaporation
of water. The heat energy required is taken from Water, thus cooling it. The rate of evaporation
is dependent on Relative Humidity of air and its dry bulb temperature C.T. design is made
considering yearly average value of R.H. found from historical data.
If the R.H. and Dry bulb temperature of ambient air is high, evaporation is low and
hence Water temperature does not drop to the design values. This situation may arise during
some periods of the year and is not controllable. The controllable reasons are;
1. Non availability of some of the C.T. fans,2. Unequal distribution of water to individual cell of the cooling tower,
3. Some of the water not coming in contact with air stream,
4. Reduced surface are of mass of water due to damaged or plugged nozzles,
5. Sensible heat gain by cold water when it flows from C.T. to C.W. Pump sump.
508
-
7/30/2019 Condenser & Feed water heaters
12/32
Reasons fo r Low C.W. Flow ra t e ;
1) C.W. Flow rate required for maintaining Condenser Vaccume at rated generation from
the plant are calculated by designers. Accordingly C.W. Pump rating is calculated. Velocity of
cooling water through condenser tubes is the controlling factor. The pumps selection is based
on calculated values of Hydraulic Resistance of the C.W. Lines, Condenser tubes, elevation to
which hot water should reach etc. Hydraulic resistance of the C.W. circuit increases due to
following reasons :
i. Number of Plugged condenser tubes more than considered while designing the system
ii. Reduction in Tube cross sectional area due to scaling in the tube or deposit of mud, algae
or organic growth within the tubes
iii. Throttling of Flow distribution valves at C.T. Cells
iv. Throttled isolating valves in the system
v. Deterioration of pump performance due to eroded or corroded impeller.
vi. Heavy and undetected leakage from the under ground piping.
Reasons f o r de t e r i o r a t i on o f Hea t t r ans f e r coe f f i ci en t :
Scaling and fouling, corrosion, and organic growth on condenser tubes reduces the abilityof heat transfer between Steam and cooling water. Ingrace of ambient of air in to the condenser,
which blankets the tube surface. Air has very low thermal conductivity and it causes drop in
Heat Transfer coefficient.
To minimize the problems of scaling, it is extremely necessary that cooling water softness
be maintained. Calcium and Magnesium salt precipitates stick to the metal surface forming
hard and difficult to remove scales. These salts have very poor thermal conductivity. Commonly
encountered scales are
i. Calcium Carbonate
ii. Calcium Sulphate
iii. Silicate Scales
iv. Calcium Orthophosphate
v. Magnesium saltsvi. Iron salts
Fouling is caused by deposition of suspended matter, insoluble in water. Foulants are
Mud and silt, Natural Organics, Microorganisms, Air borne Dust, Vegetation etc.
Pr even t i ve M easu r es : The concentration of salts takes place because of evaporation of
water in the cooling towers. Even if softened water is used, concentration of these salts
increases in closed circulation system. One of the ways to reduce the concentration is taking
fresh water in to the cooling pond to make up for the evaporated water. But by this method,
huge quantity of make up water is required. Another way is to softening. But soft water has
greater tendency for corrosion. Maintaining pH of water between 6.0 to 8.0 by feeding acid in
the system. But there are many disadvantages such as control of pH, safety in handling huge
quantity of acid etc. On line circulation of sponge balls through condenser tubes, and occasional
acid cleaning of the condenser tubes are other ways to prevent scaling.
M ic r ob ia l Gr owt h : Microorganisms enter cooling towers through air, make up water and
dust. The major problems are Algae, Fungi and Bacteria. Chlorine is usually adequate to
prevent the growth. But, it is effective only if pH is 8.3 or below. Free chlorine of 0.2 to 0.5
ppm is sufficient. Beyond 8.3 pH Chlorination does not satisfactory results.
509
-
7/30/2019 Condenser & Feed water heaters
13/32
Tem per a t u r e o f f eed w a t e r a t Econom ize r i n le t :
Feed water temperature is another factor, which decides the efficiency of Rankine Cycle,
as is evident from expression 1 above. Tm1 decreases if temperature of feed water at Boiler
outlet is low. High availability of feed water heating system and also its optimum performance
are important factors. Reasons for poor performance of feed heaters are :
1. Scaling of the tubes
2. Inadequate venting of Feed waters before cutting those in service
3. Passing and leaking heater bypass valves
4. Heater getting bypassed frequently due to High water level of because of inefficient
heater level control instrumentation
Boi le r Losses and e f f i c iency :
Boilers are designed to operate at certain efficiency. Typical figures of the losses in the
Boiler (designed values) are :
Loss t ak in g p lace % loss
Dry Flue Gas loss 4.64
H2O and H2 in fuel 5.60
H2O in air 0.18
Unburnt Carbon 0.60
Radiation 0.19
Unaccounted 0.40
Manufacturers Margin 0.50
Total Losses 12.11
Ef f i c i en cy 8 7 .9
Controllable losses are 1) Dry Flue Gas loss and 2) Unburnt Carbon. Losses due toMoisture in fuel and air are uncontrollable. Ambient air, when introduced in the boiler, also
carries with it water vapors. Hydrogen in Coal reacts with Oxygen in air and forms moisture.
Along with flue gas, water vapors also receive heat energy produced from combustion of fuel.
This energy is lost to atmosphere through Chimney.
Flue gas loss and Unburnt Carbon loss are the controllable losses. Effect of deviation of some
of the parameters on Heat rate :
Parameter Expected Actual Excess Heat rate Excess Coal Consumption / Excess coalKcal / KWh KWh ( C.V. 3500 Kcal/Kg) consumption over the
year, at 80% PLF
Excess Oxygen 3.5 % 4.0% 3.467 0.001 1600 Tons
Unburnt Carbon 1.0% 1.5 % 3.782 0.0011 1700 Tons
Flue Gas Temp 135 145 18.67 0.00533 7853 Tons
Moisture in coal 9% 11% 2.75 .00078 1156 Tons
Flue Gas Loss :
Combustion of fuel produces flue gas. Its major constituents are
1. Carbon Di Oxide produced by Carbon & Oxygen reaction,
510
-
7/30/2019 Condenser & Feed water heaters
14/32
2. Nitrogen from air,
3. Fly ash,
4. Oxygen,
5. Water Vapours.
Temperature of flue gas leaving air pre heaters is maintained at 135 to 140 C. Total
Heat content in the flue gas is =
(Volume of flue gas in m/sec x Sp. Heat of the flue gas x Specific Weight x Flue gas temperature)
Specific Heat of the flues gas is 30.6 kJ / Kg / C.
Specific weight of the flue gas is 0.796 Kg/ m.
When boiler is operated with Optimum air supply and temperature of flue gas at APH
outlet must is maintained within the design limits, flue gas loss is at its minimum. Primary Air
+ Secondary air is the total Combustion air supplied to Boiler. Depending on the Coal Analysis
and required velocity of air + coal mixture through coal pipes, manufacturers specify P.A.
Flow through coal mill in relation to Coal Feeding.
Com bus t ion A i r r equ i r em en t f o r t he Bo i l er : Requirement of air for combustion of coalvaries as per the constituents of coal being fired. If it is less than required, incomplete
combustion takes place leading to high unburnt carbon loss. If it is more than required,
combustion can be complete but Flue gas quantity increase leading to higher flue gas losses.
For Pulverized coal fired Boilers, 20% Excess air supplied under specific conditions, ensure
complete combustion. By maintaining 3.5 % Oxygen in flue gas (On dry flue gas basis) at
Economizer outlet ensures, that the Boiler if being fed with 20% excess air. It needs to be
emphasized that Spec i f i c Cond i t i on s m us t be m e t to ensure minimum losses. These
conditions are:
1. Fuel particle size must confirm to specified dimensions.
2. All the coal nozzles must admit equal mass of fuel in furnace and hence , primary air
velocity through pipes must be equal and as P.A. flow to mill should be proportional to
mill loading as specified by the manufacturer
3. Coal / Air mixture temperature at Pulveriser outlet must be 77 C.
4. Secondary air must enter combustion chamber from pre determined places only.
5. Secondary air must enter the furnace at predetermined velocity from all elevations.
6. Diffusers on the coal nozzles must be in proper condition to ensure that the jet of air/
coal mixture, emanating from nozzle, is well distributed.
7. Furnace must be air tight to eliminate possibility of entry of ambient air.
When all these conditions are satisfied, then only efficient combustion in the furnace,
supplied with 20 % excess air is ensured. Fuel admission and combustion system has following
equipment to ensure these conditions.
1. Oxygen Analyzers : In situ, Zirconia probe Oxygen Analyzers, installed on Economiseroutlet ducts, continuously monitor Oxygen in flue gas. Automatic air flow control loop
regulates F.D. Fan Inlet Guide Vanes in such a way that 3.5% Oxygen in flue gas is
maintained through out the operation of Boiler.
2. Fuel air dampers (named after the coal elevations i.e. A, B, C, D etc) on all the Four
Corners should be open only for the elevations that are in service. Position of these
dampers must be equal for all the corners. Regulation of these dampers is as per the
quantity of coal feeding measured as Coal Feeder speed. Dampers of the elevations AA.
511
-
7/30/2019 Condenser & Feed water heaters
15/32
FF, BC and DE should open equally for all Four Corners. These dampers are regulated to
maintain Furnace Windbox D.P. to the value specified by the manufacturer. Dampers
AB, CD and EF are regulated as per Fuel Oil pressure for Oil elevation in service. For the
oil elevation not in service, dampers regulate as per the Furnace Windbox D.P.
3. Orifice plates in Coal Pipes : To ensure that all burners (nozzles) at all coal elevations
admit equal mass per sec in the furnace, two requirements should be fulfilled. Primary
air flow velocity in each of the pipe must be equal and fuel/ air ratio in all pipes should
be the same. Inserting the Orifice plates, thus equalizing the hydraulic resistance of all
the pipes equalizes pipe velocity. Cold air flow tests are conducted on coal mills at
regular intervals. Results from these tests give valuable information of condition of Orifice
plates and partially or fully choked up pipes. If coal mill is operated with Primary air flow
rate less than that specified, velocity of coal air mixture drops below 20 mtr/sec, causing
separation of coal particles from stream and consequent settlement in pipes, resulting
partial choke up. If the temperature of coal / air mixture at coal mill outlet drops below
60 C, there is a possibility of condensation of water vapor which also result in separation
of coal particles and its settlement.
4. Mill air flow control dampers : For ensuring the coal / air ratio equal, P.A. flow rate to millshould be as per mill loading and hence regulated by feeder speed. Coal mill manufactures
give the P.A. Flow rate and mill loading characteristics.
5. Mill temperature control system: By ensuring coal air mixture at 77 C, adequate dryness
of coal is ensured, which is one of the important requirements for proper and efficient
combustion.
6. Furnace Windbox DP Control system : Velocity at which secondary air enters the
furnace is determined by Furnace Wind box differential pressure. For every boiler,
value of Furnace Wind box differential pressure is specified for different loading
conditions. By sticking to the specified values, it is ensured that velocity of secondary air
is as per the combustion reaction requirement. For this purpose, opening of Secondary
Air dampers of the wind box is controlled by automatic control loop for Furnace Windbox
DP. Set point for this loop is generated as per the boiler load as indicated in the enclosedFig.1.
7. Corner Firing : For achieving efficient and sustained combus t ion a t des i r ed r a t e ,
Oxygen in Air must reach the Coal particles at that rate. Oxygen molecule reach burning
coal particles by a process called Diffusion. Ratio of Concentration of Oxygen at particle
surface to that in surrounding gas mixture decides rate of diffusion. This rate is highest
when Coal particle is surrounded by air which contains 21 % Oxygen. Furnace atmosphere
is made of mixture of Coal, Air, Flue Gases and Ash particles. To ensure that coal particles
will always remain surrounded by air, place of air admission, velocity at which air is
admitted and turbulence in the furnace are of prime importance. First two requirements
are fulfilled as discussed above. Tangential firing fulfills requirement of turbulence.
8. Air tight Furnace: Furnace pressure is always maintained at 4 5 mm W.C. below
atmosphere. If furnace is not air tight, ambient air will enter furnace. But, the velocity of
this air is very low. This air can not mix with the jets of Secondary air and Primary air /
Fuel mixture admitted at very high velocities and hence does not take part in combustion.
But, it travels with flue gas, and distorts the Oxygen reading, thus replacing the Secondary
air. It is therefore extremely important that tramp air entry be prevented.
9. Pulverization of coal for design particle size : The above discussions deal with the
importance of Fuel firing equipment and air supply to boiler. Role of particle size is as
512
-
7/30/2019 Condenser & Feed water heaters
16/32
important as that of proper supply and distribution of air in the furnace. As explained,
care is taken that coal particles will always be surrounded by air in the furnace. In
furnace, very small size air Packets are interspersed in the homogeneous mixture of
gases. Total oxygen required for complete combustion of the individual particle depends
on mass of particle, which in turn depends on the size to which particle is pulverized.
Smaller is the size of particle, smaller the quantity of Oxygen required for its complete
combustion. Hence, by ensuring that 70% of Coal passes through 200 Mesh, it will
always remain surrounded by air packet which will contain enough Oxygen. But, it is
also important that size distribution of balance 30 % coal should be:
Passing through 100 mesh; 85% and above
Retained by 50 Mesh: Less than 0.5%
Resident time of particles in the furnace is generally 1 to 2 seconds. Bigger particles will
not burn completely due to lack of Oxygen, within this time and leave the furnace as unburnt
Carbon, thus increasing losses. Coarser particles also lead to increase in slagging.
Opt im iza t i on o f Com bus t ion P r ocess : Supplying 20% excess air ensures that combustion
will be complete. How ever, there is always a possibility that in certain type of Coal and
combustion conditions, Excess Oxygen requirements can even go below 20%. It may also be
possible that in some conditions, excess Oxygen requirements may be more than 20%. In
power plants, where coal from different mines is fired regularly, such conditions may arise
very frequently. To ensure that combustion remain efficient in varying condition and Optimum
air is supplied to Boiler in all conditions, Carbon Mono Oxide monitoring in flue gas is done. If
combustion is not complete, concentration of CO in flue gases increases. Complete combustion
is indicated by 100 ppm Co in flue gas at Economizer outlet. If combustion is incomplete due
to insufficient air, Co level shot up immediately to very concentration values. Fig. 2 shows the
variations in Co with ref to Air supplied to Boiler.
Other Factors : Following factors also cause deterioration of plant performance, thus increasing
heat rate. Many times, these factors are not measurable directly by plants instrumentation.
But, their effect can be known from regular tests.
Low e f f i c iency o f H.P. Turb ines , I .P. Turb ine and L .P. Turb in e: Turbine cylinder isentropic
efficiency is the measure of how efficiently turbine has converted input heat energy in to
mechanical work. Isentropic efficiency of Turbine Cylinder is given by :
Actual Enthalpy of steam at Inlet Actual Enthalpy of steam at exhaustEfficiency =
Actual Enthalpy of steam at Inlet Ideal Enthalpy of steam at exhaust
Actual Enthalpy is known from steam parameters at Inlet and Exhaust. If steam expands
in turbine without change of Entropy, then it is called ideal expansion. By finding out Temperature
for Actual exhaust pressure and actual entropy of steam at Turbine inlet, value of ideal enthalpy
is known. Turbine manufacturers give the expected Efficiencies. Any subsequent deviation
from expected values indicate deterioration of Turbine and can be corrected in the planned
outages.
513
-
7/30/2019 Condenser & Feed water heaters
17/32
Ai r Hea t e r l eakage : In Trisector Airheaters, air leakage, through seals, in to flue gas takes
place. Due to rotating rotor, the air side and flue gas side sectors are sealed by radial as well
as axial seal plates. Deterioration of sealing arrangement increases air leakage increasing
I.D. Fans loading. Leakage of ambient air in to flue gas through damaged ducts and through
E.S.P. Hoppers is another reason of increased loading fo the I.D. Fans. The extent of both the
leakages can be so high that I.D. Fan loading reaches its maximum, leading to either restriction
on Generation or in worst case, purposeful reduction of Secondary air. By measuring Oxygen
at Air Heater outlet and ESP outlet monitoring of extent of air leakage is possible.
M ake up w a t e r consum p t ion : Consumption of make up water is because of following reasons:
1. Soot blowing
2. Steam ejectors
3. Opening of C.B.D.
4. Passing of drain valves
5. Leakages of steam or feed water.
6. Steam used for Oil heating and steam tracing of oil lines.
7. Operation of auto drain traps to remove condensate from steam pipelines.
To certain extent, steam consumed for Soot Blowing, Oil heating and Ejectors and
Water lost through C.B.D. can be calculated. If this data is monitored regularly, extent of
leakage from system can be guessed. Any leakage from system indicates heat lost and lead
to increased heat rate.
Spr ey W a t e r F low r a t e f o r S t eam t em per a t u r e Con t r o l : There is no direct effect of
attempartion flow in heat rate deviation. But increased sprey flow rate indicates deterioration
of Boiler Conditions.
Aux i l i a r y Consum pt ion : Increased Auxiliary Consumption indicates more energy consumed
by auxiliaries. It also makes less energy available for distribution to consumers. Closelymonitoring these values helps in monitoring of health of the auxiliary. Regular energy audit
gives valuable information on repairs to be carried out and planned maintenance.
Conc lus ion s : From above discussions, it can be concluded that, operation of the Thermal
Power Plant at optimum conditions reduces Gross Unit heat rate. The factors that affect heat
rate are:
1) Parameters of steam at HPT, IPT inlets,
2) Condenser Performance
3) Cooling Tower Performance,
4) Combustion of fuel in Boiler with Optimum air supply, thus reducing Dry Flue Gas loss
and Unburnt Carbon loss.
5) Auxiliary Consumption
6) Air heater leakage
7) Duct Leakage
8) Ingrace of tramp air in Boiler
9) Make up water consumption
10) Turbine Cylinder Efficiency
11) Feed Water temperature at Economizer Inlet.
514
-
7/30/2019 Condenser & Feed water heaters
18/32
Fig . 2 , Change i n CO i n f l ue gas w i t h com bus t i on a i r supp l y
Fig . 1 , Va r i a t i on i n F u rnace W indbox DP con t ro l ck t . se t po i n t w i t h l oad
140 mm Wcl.
Furnace
Windbox DP
40 mm Wcl.
40 % 70 %
Boiler Load
CO in flue gas
In ppm
Deficient air supply
100 ppm
Optimum Air Supply Air supply to Boiler
515
-
7/30/2019 Condenser & Feed water heaters
19/32
516
I . BOI L ER PERFORMA NCE
A ) Op t im i zi ng To t al ai r su pp li es :Supplying correct air quantity for combustion is vital for optimization of boiler operation.
Too little air will cause unburnt losses and too much air will increase the dry flue gas losses.Carbon mono-oxide monitor can be effectively used for enabling supply of correct air
quantity of air for combustion. Flue gasses in a pulverized fuel boiler will normally have a
residual quantity of carbon mono-oxide in the vicinity of 100 ppm.
If the amount of excess air supplied to the furnace is greater than the design excess air value,
then the flue gas flow rate and the amount of heat lost to the atmosphere will increase,
causing a decrease in energy efficiency. This situation can occur if the plant control system isdefective or there is incorrect plant operation.
B) Co m b ust ib le m at er ia l s i n a sh :
The amount of unburnt in ash is a measure of effectiveness of combustion process andmilling plant. Normally about 1.5% carbon in dust is regarded as optimum. Values higher
than this are indicative of the following.1. Poor grinding.
2. Incorrect combustion air supplies.
3. In correct p.f. classifier setting or mills in need of adjustments.
Apart from the milling plant the actual combustion process can lead to high carbon in
ash. If the air supplies are badly adjusted, even though grinding is proper, unburnt losses can
occur. For the best control of flame all mills should ideally produce the same size of product,and also all mills should be equally loaded as this spreads the fire evenly. Unequal grading
produce flames, which have different characteristic and so are insensitive to secondary air
adjustments. The air temperature is also important because of influence of the rate of ignitionand flame length. The primary air to secondary air ratio is also an important norm, which
should not be allowed to deviate too much from the recommended value.
C) A ir h ea ter g as o ut l et t em p er at u r e :
Optimum air heater gas outlet temperature recommended by manufacturer should be
adhered to.The temperature of the flue gas leaving the air heater (which is the final heat exchange
element in the boiler) has a direct influence on the station efficiency. For example, a 22OC
increase in this temperature above optimum could result in a 1% decrease in station efficiency.There are many causes of an increase in this temperature, all to do with reductions in energy
absorbed from the hot gas in or after the furnace. The most usual problems are :
1. Ineffective air heater soot blowers2. Holed & torn elements, a particular problem at the cold end plates because of corrosion.
3. Fouling, corrosion/erosion and blocking of air heater elements.4. Deposits on the external heat transfer surfaces of the furnace, super heaters, re-heaters
and economisers - many of these surfaces have to be regularly cleaned using soot
blowing for increase in efficiency resulting from cleaner heat transfer surfaces.
5. Fouling of the internal heat transfer surfaces of the furnace, super heaters, re-heatersand economisers caused mainly by incorrect chemistry of the water and steam in these
tubes; or by incorrect material selection of the tubes; or by the tube material overheating;
or combinations of these
UNI T PERFORMANCE AND OPTI MI SATI ON
-
7/30/2019 Condenser & Feed water heaters
20/32
6. Defective or non-availability of Soot Blowers.
7. High Excess Air (This will increase the gas weight and also elevate the temperature,however if excess air is very high, dilution effect may predominate and the flue gas
temperature will fall).
8. Low feed water inlet temperature at Economiser inlet.
9. Defective baffles in gas paths.10. Poor milling and poor combustion resulting in long burn off times and result in higher
outlet gas temperature in addition to fouling.11. Use of higher rows of burners at lower loads.
12. Air leakage before combustion chamber.
I I . TU RB I N E PERFORM AN CE
A) I n t e r na l Losses :
Nozzle Friction, Blade friction, disc friction, diaphragm gland and blade tip leakage,partial admission, wetness and exhaust.
B) Ex ter na l Losses : Shaft gland leakages.
The common cause of cylinder efficiency deterioration include,
1. Damage to blades caused by debris getting past the steam strainers.2. Damage to tip seals and inter stage glands.
3. Deposition on blades, normally start at last few I.P. stages and carry on to the first fewL.P. stages.
4. Increased roughness of blade surface.
I I I . FEED W ATER HEATER PERFORMANCE
Deterioration of feed water heater performance occurs for the following causes.
1. Air accumulation2. Steam side fouling
3. Water side fouling.
4. Drainage defects.
Once a i r accum u la t i on occurs it is manifested in the following.
a) Reduced heater drain water temperature
b) Increased T.T.D. (Terminal Temperature Difference)c) Possible elevation of steam to Heater temperature.
d) Reduced temperature rise of feed water or condensate.
St eam s ide f ou l i ng : The effect of steam side fouling can be observed by the followinga) Progressive increase of T.T.D.
b) Drain Temp unaffected
c) Reduced feed water temperature rise.
W at e r s ide f ou l i ng : Common cause of waterside fouling is oil.
Thermal magnification of the trouble are similar to steam side fouling except that the on-set
of increasing T.T.D. is usually sudden and rate of deterioration is rapid.
Dra inag e de fec ts : Apart from passing of valves, the usual troubles are,
a) Damaged flash box internals.
b) Reduced orifice openings.c) Enlarged orifice openings.
d) Drip pumps defective.
517
-
7/30/2019 Condenser & Feed water heaters
21/32
Ef f ec t o f hea t e r f ou l i ng : Fouling always causes increase in T.T.D. resulting from lower feed
water outlet temperature. Therefore when feed enters the next heater it will be colder thannormal and so increases the steam consumption at that heater. Increased steam flow will
cause increased velocity and mass flow, which may cause mechanical damage.
As a general guide, the turbine generator heat rate will be affected by 0.07% for 10C change
in T.T.D. of HP Heaters.It is recommended that feed heater TTD be monitored every day.
I V . CONDENSER PERFORMANCE :
It is an accepted fact that less than half the heat in fuel is converted into electrical
energy and losses in condenser account for more heat than does the electrical output. Inother words, at any time in the operation of the unit, more MW is going out through the
condenser than which is coming through the generator.
Even very small worsening of backpressure is very expensive in terms of extra heat requiredfor a given output. In fact condenser performance is the most important operating parameter
on a unit. In fact the condenser performance is the most important operating parameter on a
unit, so the factors which worsen condenser back pressure must be clearly recognized so that
effective remedial measures can be taken.The factors affecting performance of condenser are :
1. Variation of C.W inlet temperature.2. Variation of CW Quality
3. Interference with heat transfer.
Condenser T.T.D is a measure of interference with heat transfer. A high TTD means aworsened condition.
The temperature gradient, which is the main driving force for the heat transfer, is expressed
as log mean temp. difference. (LMTD).
The main factors affecting the heat transfer in a condenser are
1. Effect of air blanketing on steam side of tubes. The effect of air ingress is the main factorcausing poor performance of condensers. Air ingress can be measured by use of orifice
plates provided at the ejector outlets.2. Deposition of oil or oxides of copper or iron on the steam side (Copper Oxide etc.)
surface affecting the heat transfer adversely.
3. Deposition on the insides of the tubes due to scale, slime, mud or dirt.
OPTI MI SATI ON OF UNI T PERFORMANCE
Monitoring just a few parameters, it is possible to get a good idea whether plant is
working in optimized condition or not.
These parameters are :
1. Condenser Vacuum.2. Main steam pressure at turbine inlet.
3. Main steam Temperature inlet at turbine inlet.4. Reheat temperature at turbine inlet.5. Final feed water temperature after heater block.
6. Boiler excess air.
7. Unburnt / combustible material in ash.
8. Air heater gas outlet temperature.
9. Make up water consumption.
If each of these conditions is at optimum value there is a good chance that the unit is
518
-
7/30/2019 Condenser & Feed water heaters
22/32
being operated at or near the optimum performance limits. Therefore it is a good practice to
record the above parameters regularly, say once per shift and take action on any deviationsthat are significant.
The significance of each of these parameters in optimization of unit is discussed here as
under.
1 . CON DEN SER V ACUU M :
This is the most important parameter that is required to be monitored. The significanceof it can be understood from the fact that a vacuum drop equivalent to 10 mm of Hg would
cause a loss of approx. Rs. 415/- hour in terms of fuel cost when running the unit at full load.
(The figures are based on performance calculations done at Chandrapur in 1996.)It is therefore necessary that in every shift back pressure should be analysed for deviations
from optimum. One of the reasons for the drop in back pressure is the air ingress in the
condenser. Checks should be carried out to see if air ingress is excessive.For checking the air ingress, help of Helium leak detector may be taken to identify and
/ or quantify the air ingress points. The best way to do this is to note the air suction depression.
This is a method by which presence of air is determined by measuring temperature of contents
of air suction pipe to air ejectors / vacuum pumps. When there is only a little air present, thetemperature is very little below the saturated steam temperature say within 4.50C. as more
and more air is present the temperature falls the more air the greater depression of airsuction compared to saturated steam temperature. Preferable the thermometers are to in
direct contact with the contents of air suction pipe.
Alternately at regular intervals, say once a week confirm how long it takes for the backpressure to detoriate by a set amount when the air pump suction valves are shut. Comparison
with the time taken when condenser was known to be in good condition will indicate the
degree of air leakage.
2 . M A I N S TEA M PRESSU RE A T TU RB I N E I N L ET :
A change in turbine stop valve pressure will result in corresponding change in output.Hence it is the most important that when the unit is on full load, the turbine stop valve
pressure is kept at correct value. In general the effects of change in Turbine Stop Valvepressure are :a) Steam flow will change.
b) Changed flow will cause the pressure through the turbine to change, including bleed
steam pressure.c) Because of (b) the feed heater outlet water temperature will change.
d) Total Heat of TSV steam, R/H steam and final feed water flow will change.
e) Boiler feed pump output will change to cope-up with changed flow.
f) Because the flow through turbine has altered so the volumetric flow to condenser will
change.
Thus it is seen that a simple change in TSV pressure reflects throughout the cycle.It can be seen from the calculation that 5 Kg/cm2 pressure drop at turbine inlet would result
in a loss of Rs 185/- per hour approximately. Based on calculations done in 1996.
3 . M AI N S TEA M TEM PERA TU RE A T TU RB I N E I N LET :
Variations in the TSV steam temperature result in variations in the specific volume of the
steam and this results in a change of steam flow.
Other results are :
a) Change of total heat to TSV Steam.
b) Change of total heat to HP cylinder exhaust steam.
519
-
7/30/2019 Condenser & Feed water heaters
23/32
c) The change of flow will alter the pressure throughout the turbine and this will change the
bleed steam flow to heaters.Calculations indicate that a 50C drop in the main steam temperature could result in a
loss of around Rs. 100/- per hour at full load.
4. REHEAT OUTLET STEAM TEMPERATURE :Variations in the Reheat Outlet Steam temperature will cause:
a) Change in total heat of the steam.b) Change of steam flows to the condenser for a given loading.
50C drop in the Reheat Outlet Steam temperature would result in a loss around
Rs. 154/- per hour at full load.
5. FI NAL FEED W ATER TEMPERATURE AFTER HEATER BLOCK :
The final feed water temperature should be measured after the HP Heater block bypasshas joined the feed line and deviations from optimum should be investigated. Water flows
through the bypass will cause the final feed heater outlet temperature to be higher than final
feed. Variations of feed flow from optimum will cause changes of output and heat rate.
In addition there can be deviations from optimum at individual heaters. Whatever is thetrouble at a heater it must affect one or more of these parameters.
a) Heater Terminal Temperature Difference.b) Drain outlet terminal temperature difference.
c) Bleed steam pipe pressure drop.
d) Steam temperature at heater inlet.
6 . BOI LER EXCESS AI R :
Boiler combustion efficiency is largely dependent upon supplying correct quantity of
excess air at right place. Supplying too much of excess air will increase dry flue gas losses.
This is because the quantity of gas will increase and so will the heat content as excess air will
absorb heat more readily than the heat exchange surface, thus increasing the Air heater gasoutlet temperature.
7 . COM BU STI B LE M ATERI A LS I N ASH :
The permitted values for the carbon in ash are 0.8 % in fly ash and 4.8% in bottom ash
as per the design. Values greater than above are indicative of:
a) Poor grindingb) Incorrect combustion air supplies.
c) Incorrect pulveriser fineness classifier settings.
It is calculated that 1.5% carbon in ash is equivalent of about 0.5% boiler losses amounting
to around Rs. 236/- per hour approximately at full load.
8 . A I R HEATER GAS OUTLET TEM PERATURE :
The causes of high air heater gas outlet temperature are :
a) Ineffective A/H soot blowing.b) Holed and torn elements.c) Deposits on boiler heat transfer surface.
d) Defective soot blowers resulting in reduced heat transfer in discrete location and result
will be as in (c).
e) High excess air increases the gas weight and also elevates the temperature. However if
the excess air is very high dilution effect may predominate and the gas temperature will
fall.
520
-
7/30/2019 Condenser & Feed water heaters
24/32
f) Low final feed water temperature has to be remedied by extra firing in the boiler and this
will result in high exit gas temperature.g) Poor milling and poor combustion results in long burn off times and result in high gas
temperature at furnace exit in addition to fouling.
h) Using upper rows of burners on low loads.
Generally speaking a final gas temperature of about 200C above optimum will result inboiler efficiency loss of about 1%, which amounts to a loss of Rs. 472/- per hour at full load.
9 . M AK E U P W A TER CON SU MPTI ON :
Makeup water is replacing water and steam, which has been lost from system and contains
considerable quantities of heat.There are four usual sources of loss:
a) Passing of valves / leaks.
b) Boiler blow downs.c) Drains going to waste
d) Soot blowing.
Of the above four sources of loss, the first three can be controlled by good house keeping.
As regards the soot blowing losses if it is carried out too often heat is wasted whereas if it isnot carried out often enough the heat transfer may become heavily coated and heat transfer
will be reduced and thus the final gas temperature will rise. Hence there must be optimuminterval between soot blowing, but just that may be difficult to determine. The basic problem
is that soot blowing affects boiler efficiency and boiler availability.
An expression for heat loss due to carrying of soot blowing is :
Loss =Heat loss to soot blowing steam
Heat given to TSV Steam + Heat given to RH steam
Loss = 0.25Qs+
Qs(h
1-h
5)
(h2
h5) + Q
R(h
4 h
3)
Where Qs= Soot blowing steam as a percent of TSV steam flow.
QR
= Reheat steam flow as fraction of TSV steam flow.
h1
= Total heat of steam at A/H gas outlet temperature & pressure.h
2= Total Heat of Steam at TSV conditions.
h3
= Total Heat of Steam before Re-heater.
h4
= Total Heat of Steam after air heater.h
5= Heat in final feed water.
The term 0.25 Qs is the approximate loss due to raising the temperature of the cold
make up water to final feed water temperature.
For operational purposes it is convenient to determine some reference temperature (say
gas temperature leaving primary super heater) and commence soot blowing when it reaches
a certain value, allowance being made for boiler loading. The alternative of blowing out at
preset times (say once per shift) has little to commend except convenience. One of the main
parameters that determine the frequency of soot blowing is the ash content of coal.
The above explanations are given to bring home the importance of maintaining the fewvital parameters to their optimum values for bringing down the operating losses. If each of
the above conditions is maintained at the optimum it can be assured that the unit will be
running at minimum losses and maximum efficiency and consequently the coal rate per HWHgeneration will also come down appreciably.
521
-
7/30/2019 Condenser & Feed water heaters
25/32
Turbine performance plays a major role in Turbine Cycle Heat rate. Isentropic Efficiency
of turbine is the important parameter that indicates performance of the Turbine. In impulse
stages of the turbine, steam expands thorough nozzles, causing increase in its kinetic energy.
The high velocity steam jet is then made to impinge on the moving blades fixed on the rotor,
causing blade and rotor to move. Thus the heat energy is converted to mechanical work. As a
result of the conversion, steam temperature and pressure drop over the stages of turbine.
Amount of heat energy converted to work, by applying first law of thermodynamics,
= (Heat Energy contained by steam at admission Heat Energy contained by steam at exhaust.)
= (Enthalpy of steam at Admission Enthalpy of steam at exhaust)
If the expansion of steam had taken place ideally, the isentropic efficiency of the Turbine
cylinder would have been 100%. In such case Entropy of steam at exhaust and at admission
should have remained the same. But, due to the irreversibility in the process of expansion, all
the heat energy is not available for conversion to work.Isentropic efficiency of turbine is thus expressed as a ratio of Actual change in Enthalpy
across the turbine, compared to Theoretical change (At constant entropy) expressed as
percentage.
M et hod o f Ca lcu la t i on : The method of calculating the efficiency is demonstrated for HPT as
follows.
Isentropic efficiency of HP Turbine =
(Enthalpy of steam at HPT Inlet Actual Enthalpy of steam at HPT Exhaust)
(Enthalpy of steam at HPT Inlet Ideal Enthalpy of steam at HPT Exhaust)
En t h a lpy o f s t eam a t HPT I n le t : This is known from the steam tables for steam admissionpressure and temperature.
Actua l En th a lpy o f s team a t HPT Exhau s t : This is known from the steam tables for exhaust
steam pressure and temperature.
I dea l En t h a lpy o f s t eam a t HPT Exhaus t : This is known by first finding out the ideal
temperature of exhaust steam at actual exhaust steam pressure and entropy of steam at
admission. Then ideal enthalpy is known from steam tables, by considering actual exhaust
pressure and ideal exhaust steam temperature.
Similarly isentropic efficiencies of IPT and LPT are calculated by considering appropriate
steam parameters for these turbines.
Ef f e c t o f T u r b i n e Ef f i c i e n c y o n h e a t r a t e f o r 2 1 0 M W p l a n t : (Unit heat rate of 2500 Kcal/kWh)
One percent improvement in Efficiency of % Effect on Turbine Cycle heat rate Effect on Unit Heat Rate
HP Turbine 0.2 % Heat rate - 5 Kcal / kWh
IP Turbine 0.2 % Heat rate - 5 Kcal / kWh
LP Turbine 0.5 % Heat rate -12. 5 Kcal / kWh
TURBI NE PERFORMAN CE
522
-
7/30/2019 Condenser & Feed water heaters
26/32
In addition to the irreversibility of the expansion of steam in turbines, following losses
contribute to reduced efficiency :
1 ) Flu id Fr i ct ion : This is the biggest cause for losses in the turbines. Fluid friction loss can
amount for 10% of the total energy available to turbine. By proper design velocities,
these losses are minimized but can not be completely eliminated. Friction losses are
present due to
i) Friction in steam nozzles
ii) Blade friction, which can be minimized by reduction in velocity of steam by compounding
etc.
iii) Turbulence at blades when blade shape does not posses proper angle of entrance for
steam at loads other than design load.
iv) Friction between steam and rotor disc on which blades are mounted.
v) Rotating blades and rotor produces centrifugal action on steam. Due to which some part
of steam flows radially to casing, which gets dragged along the moving blade.
vi) Churning of steam in moving blades, especially when the turbine is on part load operation.
This loss takes occurs in impulse stages.
2 ) Leak ag e loss : Steam leakage can occur within and outside the turbine and amount to
1% loss of the total energy supplied to the turbine. The leaking steam gets throttled and
represents unavailable energy. Causes of leakage are as follows.
i) Steam leakage takes place along the blade tips and casing when there is a pressure drop
across the blades as in the case of reaction turbines. The loss is greater in high-pressure
turbines. Also ratio of blade height to clearance (between the blade tip and casing) also
affect this loss. Greater being the ratio, greater is the loss.
ii) In pressure compounded turbines, leakage of steam leaks along the shaft at diaphragms
on which nozzles are mounted.
iii) Some steam also leaks out side the turbine from the shaft glands.
3 ) Mo ist ur e Loss : Some part of steam converts to moisture in the turbine. The dropletsare generally move at a low speed. Some droplets strike the moving blades at off-design
angles and reduce the mechanical work of the rotor. Other droplets are accelerated to
velocity of steam and thus momentum exchange takes place reducing the energy in
steam. Usually, the moisture content is limited to 12% at exit steam.
4 ) Leav in g l oss : The residual steam velocity at the last row of rotating blades in a turbine
is quite high because of decrease in pressure and increase in specific volume. The
corresponding kinetic energy represents a loss from the turbine. Magnitude of the leaving
velocity is kept to the minimum by proper combination of height of last blades, speed
and area of the exhaust duct to the condenser. In large turbines, velocity of steam at
exhaust is in the range of 270 to 300 m/s. Provision of double flow paths in IP and LP
Turbines, gradually increasing the exhaust duct also reduces the leaving velocity. This
loss is to an extent of 2 to 3% in modern turbines.
Hence, if the Turbine Performance deviates from the design value, it presents an
insight in to the condition of turbine internals, and hence it is monitored in the power
plants.
523
-
7/30/2019 Condenser & Feed water heaters
27/32
524
Financial Accounting is mainly used for an instrument to record transactions of thebusiness to satisfy the requirements imposed by fiduciary relationship between the business
and its owners as well as third parties connected with business such as creditors, financial
institutes etc. Basic function is limited to recording, classifying & summerising the business
transactions of only financial character through Trial Balance, Income Statement and Balance
Sheet.
Management Accounting covers (i) Financial Accounting, (ii) Cost Accounting (iii)
Revaluation Accounting, (iv) Budgetary Control, (v) Inventory Control, (vi) Statistical Methods
(vii) Interim Reporting, (viii) Taxation, (ix) office Services (MIS- Management Information
Services) and (x) Internal audit system
Cost Accounting is the process of accounting for costs. It embraces the accounting
procedures relating to recording of all incomes and expenditures and the preparation of
periodical statements and reports with the object of ascertaining and controlling the costs. It
is, thus, the formal mechanism by means of which the cost of products or services are
ascertained and controlled.
Objec t iv es o f Cos t Accoun t in g :
Main objectives of cost accounting can be summerised as follows :
1) Determining Selling price : Cost accounting collects costs related to individual product &
services connected to such product, which plays main role in deciding selling price.
2) Determining & controlling efficiency : Cost accounting : Cost accounting involves a study
of various operations used in manufacturing a product or providing a service. It facilitates
measuring of efficiency of organisation, station, unit and section as well as means of
increasing efficiency.3) Facilitating preparation of financial & other statements : The third objective of cost
accounting is to produce statements at such short intervals as the management may
require. Financial Accounts are prepared only once at the year end and it shall be of no
use for current decision-makings by the management.
4) Providing basis for operating efficiency : Cost accounting helps the management in
formulating operating policies. These policies may relate to any of following matters
i) Determination of cost-volume-profit relationship
ii) Shutting down or operating at a loss
iii) Making or buying from outside suppliers
iv) Continuing with the existing plant and machinery or replacing them by improved &
economic ones.
Elem ent s o f Cost
There are three broad elements of cost : Material (Direct material or Indirect material),
Labour (Direct Labour or Indirect Labour and expenses (Direct expenses or Indirect expenses)
Direc t Mater ia l comprises of all materials which becomes an integral part of the finished
product and which can be conveniently assigned to specific physical units. Similarly Direc t
Labou r comprises of all labours, which takes active and direct part in the production of
COST ACCOUNTI NG, COST CONTROLAN D COST REDUCTI ON
-
7/30/2019 Condenser & Feed water heaters
28/32
particular commodity. Direc t Expenses are those, which can be directly allocated to specific
cost centers or cost units.
The term OVERHEAD includes indirect material, indirect labour and indirect expenses.
Thus all indirect costs are overheads.
A manufacturing organisation can be broadly divided into three divisions: (i) Factory or
Works where production is done, (ii) Office and administration, where routine as well as policy
matters are decided and (iii) Selling and Distribution where product is finally sold & distributed
to customer.
Components of total cost are :
Pr im e Cos t : It consists of costs of direct material, direct labour and direct expenses.
Factor y Cost = Prime Cost + Factory Overhead
(It is also known as Works cost, production or manufacturing Cost)
Cost o f Produc t ion = Works Cost + office & administrative Overheads
Cost o f Sales = Cost of production + Selling & distribution Overheads
COST SHEETS
The cost sheets are prepared for historical cost data or for estimated cost data.Ascertainment of future costs and making comparisons with the past records help the
management in fixing up the selling prices of the products. Several important decisions can also
be taken by the management regarding profit planning, production and marketing strategy, etc.
The preparation of Cost sheets call for special knowledge of cost accounting and well
trained personnel for giving appropriate treatment to computation of profit, raw material
stock and also to stock of work in progress while preparing statement of total production cost.
CLASSI FI CATI ON OF COSTS
Fixed , va r iab le and sem i - va r iab le cos t s
The cost which varies directly in proportion to every increase or decrease in the volume
of output or production is known as variable cost. The cost, which does not vary but remains
constant within given period of time and range of activities in spite of the fluctuations inproduction, is known as fixed cost. The cost, which does not vary proportionately but
simultaneously cannot remain stationary at all times is known as semi-variable cost.
Pr oduc t cos t s and pe r iod cost s : Costs, which become part of the cost of the product, are
called Product Costs and costs, which are not associated with production, are called Period
costs.
Di r ec t Cos t s and I nd i r ec t cos t s : Already explained above.
Dec is ion d r iven cos ts : Some costs are specifically attributed to particular decision. The
decision may lead to either profit or loss. It may result into comparatively better or worst
outcomes than those predicted. Abnormal loss or abnormal profit can be associated with
specific decision. For example, Koradi TPS has purchase a powder to mix with coal in anticipationto improve heat rate. But after actual use, there is no improvement in heat rate. It is decision
driven cost/ loss.
Relevan t cos t s and i r r e levan t cos t s : Relevant Costs are those, which would be changed
by the managerial decision. While irrelevant costs are those, which would not be affected by
the decision.
525
-
7/30/2019 Condenser & Feed water heaters
29/32
Shu t dow n cos t s and sunk cos t s : Due to some temporary difficulties like shortage of raw
material, non-availability of labour etc, sometimes operations may have to be suspended for
a period. During this period although no work is done, yet certain fixed costs, such as, rents,
electricity, insurance, depreciation, maintenance etc for the entire plant will have to be incurred.
Such costs are known as shut down costs.
Sunk costs are historical costs or past costs. These are the costs, which have been
created by a decision made in the past that cannot be changed by any decision that will be
made in future. These cost are irrelevant for decision-making.
Exam p le : Koradi TPS purchased a machine for Rs. 30,000. The machine has an operating life
of 5 years without any scrap value. Soon after making purchase the management of Koradi
TPS feels that the machine should not have been purchased since it cannot yield the operating
advantage originally contemplated. Of course, it is now expected to result in saving in operating
costs of Rs. 18,000 over the period of 5 years. The machine can be sold immediately for Rs.
22,000.
In taking the decision whether machine should be sold or be used, relevant amounts to
be compared are Rs. 18,000 in a cost saving over 5 years and Rs. 22,000 that can be realized
by selling the machine. Rs 30,000 invested in machine is not relevant & is a sunk cost.
Oppor t un i t y Cos t s : The Opportunity cost refers to the advantage, which has been foregone
on account of not using the facilities in a manner originally planned.
Exam p le : If Koradi TPS is to decide whether to provide certain amount of steam at offered
cost for some other operations instead of generation of electricity. Then in such decision, the
revenue which could fetch by generating electricity by such steam is the opportunity cost
which, should be taken into account for evaluating the profitability of using such steam for
other purpose.
COST REDUCTI ON A ND COST CONTROL
Cost Reduction and Cost Control are two different concepts. Cost Control has achieving
the cost target as its objective while cost reduction is directed to explore the possibilities ofimproving the targets themselves. Thus cost control ends when targets are achieved while
cost reduction has no visible end. It is a continuous process.
AREAS OF I MMEDI ATE ATTENTI ON
1. Daily Declared OLC for Unit and Station
2. Economics of Unscheduled Interchanges
3. Fixed Cost/ Variable Cost/ Consideration
4. Asset / Reliability Concept/ Availability Monitoring
5. Daily Cost of sectional works, processes/ services
FOCUS ON LONG RANGE PLANN I NG
Flexible Budgeting, Inventory, Purchase policy
Contract Monitoring/ Outsourcing
Pricing Strategy/ Transfer Pricing Concepts
Merit Order Stack Monitoring/ On Line Bidding
Monitoring External Environment & Changes in Internal Environment through SWOT
analysis & Strategic Planning
526
-
7/30/2019 Condenser & Feed water heaters
30/32
COST REDUCTI ON TECHN I QUES
The following are some important cost reduction techniques.
1. Costing & Value Chain Analysis
2. Standardisation, simplification & Quality Control
3. Job study, work study and Motion study
4. Budgetary Control
5. Inventory Control
6. Value Engineering & Learning curve effect
7. Job evaluation and Merit Rating
Cost in g & Va lu e Cha in An a lys is
The first step is to establish Cost Accounting System and standardize the basic routine
functions of cost collection, cost analysis & cost reporting.
The Costing System as being practiced in Generating Stations in MAHAGENCO recognizes
division of power generation activities in any station into different process centers and service
centers. Each process center, which is either u n i t w i se or s t a g e w i se, is further divided into
sub process centers (SPC). Every SPC has number of systems and area wise locations onwhich different operation & maintenance activities are done. The data of cost of manpower
(direct, indirect & idle), material (Raw Materials, Spares & consumables) and contracts deployed
on each of these activities based on defect card raised by Operating staff is collected through
entries in PPMS (Power Plant Monitoring System) software in Works Planning System. PPMS is
designed to give cost statements of every activity and also to arrange the cost components
incurred on every cost centers on daily basis.
Broad D iv is ions in t o Cos t Cent ers & Serv ice Cent ers .
PROCESS CEN TRE SERVI CE CENTRE
0110 Coal Handling Plant 0001 Boiler Maintenance
0210 Raw Water Intake System 0002 Turbine Maintenance
0310 Pre Treatment Plant 0003 CHP (Mech. Maint.)
0410 Soften Water Plant 0004 CHP (Elect. Maint.)
0510 D.M. Plant 0005 Vehicle Maint
0610 Hydrogen Generating Plant 0006 Elect. Maint. (Main Plant)
0710 Milling Plant 0007 Testing
0810 Boiler And Auxiliaries 0008 Instrumentation Control
0910 Fuel Oil Handling Plant 0009 Civil Maintenance
1010 Turbine & Generator 0011 Water Treatment Plant (M)
1110 CW System
1210 Ash Handling Plant
1310 Common Technical Services1410 Township
1510 Administration
The reports in three standard formats from each power station are sent to Head Office to
compile & compare for inter power station analysis. The above Costing System, which is being
practiced in a premature stage, is now to re-mould in expert style for utilisation in competitive
527
-
7/30/2019 Condenser & Feed water heaters
31/32
environment to deal with continuously changing business conditions. A sound management
Information System is the basic need for such re-orientation of Costing System.
It is utmost necessary now to re-examine the Costing System freshly at strategic level
and then for attempts to re-establish the basic process of daily cost accumulations in the
power plant as a main stream of administrative process. The plan for such implementation
needs to be strategically approved by topmost management in MAHAGENCO and responsibility
needs to be assigned to such specially constituted team with cost-benefit impacts of such
implementation as a special project. Following target steps can be considered for such attempts.
1. Preparation of Flow chart for every process & its SPC. Identifying assets in such process
centers and standard systems in each SPC. Calculation of asset for each process center
& service center.
2. Covering all activities through job/ defect card system. Establishing daily routines in all
operation sections for proper defect card entries & daily monitoring of permits issued &
cleared.
3. Establishing of daily routines of work Plan, Job Completion Sheets and Sectional daily
Cost analysis.
4. Establishing entries of important machines running, standby, under permit timings throughPPMS.
5. Establishing Centralised Purchase/ Work Order on line monitoring process through
centralised dispatch information & bills receipt system.
6. Establishing on line inventory/ stores with on line issues against defect cards.
7. Establishing Contract monitoring through daily contract work allotments & on line
monitoring of RA Bills through PPMS.
8. Establishing on line time management system & salary linking to costing tasks.
9. Establishment of On Line daily & periodic Costing System and value chain of primary &
support activities.
10. Making available full Management Information System for decision making at all levels
of management in MAHAGENCO.
St anda r d i sa t i on , s im p l i f i ca t i on & Qua l i t y Con t r o l :
T e c h n i c a l P a r a m e t e r s : Generation, Availability Factor, PLF, Heat Rate, Specific Fuel
Consumption, Auxiliary Consumption, Annual/ Capital Overhaul outages.
Elem ents o f Cost o f Genera t io n : Fixed Cost & Variable cost Contribution, Cost contribution
by Process centers & Service centers, Variance analysis, Standard cost deviations
Sta t ion as a Pro f i t Center : Return on asset, Merit Order Stack Position, ABT performance,
Technical performance, Liquidity Performance
Con t r i bu t i on o f Respons ib i l i t y Cen t e r s i n Va lue Cha in o f P r o f i t Cen t e r :
Jo b s t u d y , w o r k s t u d y a n d M o t i o n s t u d y
D e fi n i n g a l l j o b s t h r o u g h W o r k I n s t r u c t i o n s : Creating environment for scientific analysis
of job, Time bound review till satisfactory yield is ensured from job methods.
Cont in uous Process o f Job enr ichm ent : Identifying frequency of failures, Minimising repeat
works, improving work methods, definining jobs with respect to processes/ individual
responsibilities.
528
-
7/30/2019 Condenser & Feed water heaters
32/32
Budge t a r y Con t r o l
Resour ce gap ana ly s is & Cap i ta l Budget ing exer c ise : Identifying resource requirement,
resource allocation & measures to bridge resource gap at sub section/ section level, Comparative
study of in-house means & outsourcing avenues.
Fixed v . Flex ib le Bud gets : Continuous review of budget in changing environmental aspects,
linking with Long Range Planning.
Scien t i f i c Dec is ion Techn i ques : Use of statistical models, standardizing decision-making
process,Study of impact of decision.
Budge t Con t r o l Or gan isa t i on : Establishment of continuous budget monitoring exercise
and internal audit features.
I n v e n t o r y Co n t r o l
Es t ab l i sh ing On L ine Pu r chases , I nven t o r y & Aud i t t r a i l : Complete on line & totally
computerized system of purchase activi