EMISSION STANDARDS - POWER PLANTS

The emission standards for thermal power plants in India are being enforced based on Environment (Protection) Act, 1986 of Government of India and it’s amendments from time to time.A summary of emission norms for coal and gas based thermal power plants is given below in Tables

Environmental standards for coal & gas based power plants
Capacity	Pollutant	Emission limit
Coal based thermal plants
Below 210 MW	Particulate matter(PM)	350 mg/Nm3
210 MW & above		150 mg/Nm3
500 MW & above		50 mg/Nm3
Gas based thermal plants
400 MW & above	NOX(V/V at 15% excess oxygen)	50 PPM for natural gas; 100 PPM for naphtha
Below 400 MW & up to 100 MW		75 PPM for natural gas; 100 PPM for naphtha
Below 100 MW		100 PPM -naphtha/natural gas

The norm for 500 MW and above coal based power plant being practiced is 40 to 50 mg/Nm and space is provided in the plant layout for super thermal power stations for installation of flue gas desulphurisation (FGD) system. But FGD is not installed, as it is not required for low sulphur Indian coals while considering SO X emission from individual chimney

Stack height requirement for SO2 control
Power Generation Capacity	Stock Height (Metre)
Less than 200/210 MWe	H = 14 (Q)0.3 where Q is emission rate of SO 2 in kg/hr, H = Stack height in meters
200/210 MWe or less than 500 MWe	200
500 MWe and above	275 (+ Space provision for FGD systems in future)

However the norms for SO_x are even stricter for selection of sites for World Bank funded projects. For example, if SO_x level is higher than 100 ? g/m 3, no project with further SO_x emission can be set up; if SO X level is 100 ? g/m 3, it is called polluted area and maximum emission from a project should not exceed 100 t/day; and if SO_x is less than 50 ? g/m 3, it is called unpolluted area, but the SO_x emission from a project should not exceed 500 t/day. The stipulation for NOX emission is that its emission should not exceed 260 gram s of NOX per Giga Joule of heat input.

In view of the above, it may be seen that improved environment norms are linked to financing and are being enforced by international financial institutions and not by the policies/laws of land.

BOILER WATER TREATMENT,SCALES & CORROSION

In general there are two types of boilers, low pressure and high pressure:

 A) Low pressure boilers will be found heating water or steam to be circulated around a building for heating purposes via radiators. These systems are "closed circuit" types and require little or no "make" water to top them up. Mostly low pressure boilers operate below 10 psi.

B) High pressure boilers will be found in industry, generating steam for a variety of uses, locomotion via a steam engine, or for end use of steam in laundries, rubber product manufacturing, wood pulp products, food manufacture etc. These boilers operate at over 10 psi and all require constant "make up" water as some of the steam is used.

Boiler feed water ("BFW") may either be the same as the makeup water, or may consist of returned steam condensate, or (as in most cases) will be a mixture of both.

The relative amounts of makeup and condensate may vary. A typical figure is 5% makeup with 95% condensate, but this depends on how the steam plant is operated and how much of the steam is condensed and recovered for recirculation.

In order to be non-scaling, the BFW must be a softened or demineralised water . In order to be non-corrosive to the carbon-steel or low-alloy steel components from which boilers are usually constructed, the water must be thoroughly deaerated. This is partially achieved by thermomechanical means (use of deaeration heating tanks), while the last traces of dissolved oxygen are removed by chemical agents ("oxygen scavengers").

Oxygen scavengers include both volatile products (e.g., hydrazine, or other organic products like carbohydrazine, hydroquinone, diethylhydroxyethanol, methylethylketoxime, etc.) and non-volatile salts (normally: sodium sulphite, Na2SO3, or a derivative thereof). The latter salts often contain catalysing compounds to increase of rate of reaction with dissolved oxygen (e.g., cobaltous chloride).

Oxygen Scavengers:

While the oxygen scavenging salts tend to react rapidly with oxygen, even at lower temperatures, their reaction products result in increased levels of total dissolved solids in the boiler feedwater.

To minimize this disadvantage, the salt should be fed to the storage tank of the deaerating heater and care should be taken that no precipitates are introduced into the boiler feed.

As rule of thumb, one typically feeds 10 parts of sodium sulphite per part of oxygen (to compensate for reaction with atmospheric oxygen and for impurities in the sodium sulphate).

Volatile oxygen scavengers are normally employed for higher pressure systems (e.g., above 1000 psig). These materials may react directly with oxygen and or directly with carbon steel boiler surfaces to form gamma iron oxide or magnetite. The formation of such "oxygen-impervious" oxide films precludes excessive corrosion.

Except for the common hydrazine (N2H4), most other volatile organic oxygen scavengers are sold under some proprietary name. The use of hydrazine in boiler feedwater is very common and very well documented. Because hydrazine typically does not react with oxygen at a rapid rate at lower temperatures, it may not be the preferred oxygen scavenger for low temperature boiler feedwater systems. In addition, hydrazine is seriously toxic and great care should be taken in its handling. Food production sites should consider seriously the potential consequences of using highly poisonous chemicals.

Scaling:

As water is heated and converted into steam, contaminants brought into a boiler with makeup water are left behind. The boiler functions as a distillation unit, taking pure water out as steam, and leaving behind concentrated minerals and other contaminants in the boiler. Scale forms as a result of the precipitation of normally soluble solids that become insoluble as temperature increases. Some examples of boiler scale are calcium carbonate, calcium sulphate, and calcium silicate.

Corrosion: 

Corrosion is a general term that indicates the conversion of a metal into a soluble compound. 

In the case of boiler metal, corrosion is the conversion of steel into rust. In a boiler, two types of corrosion are prevalent:

1.)     Oxygen pitting corrosion, seen on the tubes and in the preboiler section.

2.)      Low pH corrosion, seen in the condensate return system.

Corrosion of either type can lead to failure of critical parts of the boiler system, deposition of corrosion products in critical heat exchange areas, and overall efficiency loss.

Carryover:

Carryover is caused by either priming or foaming. Priming is the sudden violent eruption of boiler water, which is carried along with steam out of the boiler, usually caused by mechanical conditions. Priming can cause deposits in and around the main steam header valve in a short period of time. Foaming causes carryover by forming a stable froth on the boiler water, which is then carried out with the steam. Over a period of time, deposits due to foaming can completely plug a steam or condensate line.

Typical Boiler Failures and Causes:

Oxygen Pitting:

The time when a boiler system is most vulnerable to oxygen pitting is during idle periods. In order to prevent oxygen pitting during these times it is important to utilize proper storage techniques. Please see our technical tip on this subject at Dry Storage of Boilers and Wet Storage of Boilers.

 When a boiler is in operation, oxygen pitting is most likely to occur in feedwater heaters or economizer tubes, since this is this is where the water is first heated above the deaerator temperature. Maintaining a properly operating deaerator with sufficient oxygen scavenger is the best method of prevention.

 If oxygen pitting is noticed, it is important to note if it is “old” or active pitting. Active oxygen pits can be distinguished by the red-brown tubercle which, when removed, exposes black iron oxide within the pit.

Short-Term Overheating: 

This type of failure is usually indicated by a "thin-lipped" burst of the boiler tube. These failures occur when water circulation in the tube is interrupted, and the flue gas temperatures cause a rapid overheating of the metal to a point where the metal becomes highly plastic and a violent burst occurs. Typical causes of short-term overheating are circulation problems caused by poor operation (sudden increase in steam demand or low water level) or design, and tube blockage. Tube blockage normally occurs from deposition in the tube or supply header.

Long-Term Overheating:

 This type of failure is usually indicated by a "thick-lipped" burst of the boiler tube. Long-term overheating can result from excessive deposition, flame impingement, mild flow restrictions, or poor water or flue gas circulation patterns. Probably the most common of these is excessive deposition, which prevents proper heat transfer and excessive metal temperatures. This prolonged overheating of the tube causes metal degradation to the point that in can no longer handle the operating pressure and a "thick-lipped" failure occurs. 

Caustic Gouging:

 Caustic gouging occurs when NaOH concentrates under porous boiler water deposits. An example of such deposition would be iron, which tends to be porous. Essentially, what occurs is that boiler water is present in the deposit. As steam escapes, the NaOH concentration increases dramatically, dissolving the protective magnetite and boiler tube metal.

 In addition to the gouging of the boiler tubes you may also notice a white substance (sodium carbonate) outlining the edges of the original deposit.

 There are other failure mechanisms such as caustic and hydrogen embrittlement, stress corrosion cracking and steam blanketing. In this tip we have dealt with those we feel are the most prevalent. If you believe that you have a failure that does not fit into one of the categories we discussed please feel free to contact our staff. Finally, for a complete analysis and understanding of a failure, a sample should be sent to an independent metallurgical lab.

 

RANKINE CYCLE -PRINCIPLE

A Rankine cycle describes a model of steam-operated heat engine most commonly found in power generation plants. Common heat sources for power plants using the Rankine cycle are the combustion of coal, natural gas and oil, and nuclear fission.

The Rankine cycle is sometimes referred to as a practical Carnot cycle because, when an efficient turbine is used, the TS diagram begins to resemble the Carnot cycle. The main difference is that heat addition (in the boiler) and rejection (in the condenser) are isobaric in the Rankine cycle and isothermal in the theoretical Carnot cycle. A pump is used to pressurize the working fluid received from the condenser as a liquid instead of as a gas. All of the energy in pumping the working fluid through the complete cycle is lost, as is all of the energy of vaporization of the working fluid, in the boiler. This energy is lost to the cycle in that first, no condensation takes place in the turbine; all of the vaporization energy is rejected from the cycle through the condenser. But pumping the working fluid through the cycle as a liquid requires a very small fraction of the energy needed to transport it as compared to compressing the working fluid as a gas in a compressor (as in the Carnot cycle).

The efficiency of a Rankine cycle is usually limited by the working fluid. Without the pressure reaching super critical levels for the working fluid, the temperature range the cycle can operate over is quite small: turbine entry temperatures are typically 565°C (the creep limit of stainless steel) and condenser temperatures are around 30°C. This gives a theoretical Carnot efficiency of about 63% compared with an actual efficiency of 42% for a modern coal-fired power station. This low turbine entry temperature (compared with a gas turbine) is why the Rankine cycle is often used as a bottoming cycle in combined-cycle gas turbine power stations.

The working fluid in a Rankine cycle follows a closed loop and is reused constantly. The water vapor with entrained droplets often seen billowing from power stations is generated by the cooling systems (not from the closed-loop Rankine power cycle) and represents the waste energy heat (pumping and vaporization) that could not be converted to useful work in the turbine. Note that cooling towers operate using the latent heat of vaporization of the cooling fluid. The white billowing clouds that form in cooling tower operation are the result of water droplets that are entrained in the cooling tower airflow; they are not, as commonly thought, steam. While many substances could be used in the Rankine cycle, water is usually the fluid of choice due to its favorable properties, such as nontoxic and un reactive chemistry, abundance, and low cost, as well as its thermodynamic properties.

There are four processes in the Rankine cycle. These states are identified by numbers (in brown) in the diagram below. 

Process 1-2: The working fluid is pumped from low to high pressure, as the fluid is a liquid at this stage the pump requires little input energy.  

Process 2-3: The high pressure liquid enters a boiler where it is heated at constant pressure by an external heat source to become a dry saturated vapor. The input energy required can be easily calculated using mollier diagram or h-s chart or enthalpy-entropy chart also known as steam tables.   

Process 3-4: The dry saturated vapor expands through a turbine, generating power. This decreases the temperature and pressure of the vapor, and some condensation may occur. The output in this process can be easily calculated using the Enthalpy-entropy chart or the steam tables.  

Process 4-1: The wet vapor then enters a condenser where it is condensed at a constant temperature to become a saturated liquid.

RANKINE CYCLE

Rankine Cycle:

    Saturated or superheated steam enters the turbine at state 1, where it expands isentropically to the exir pressure at state 2. The steam is then condensed at constant pressure and temperature to a saturated liquid, state3. The heat removed from the steam in the condenser is typically transferred to the cooling water. The saturated liquid then flows through the pump which increase the pressure to the boiler pressure (state 4), where the water is first heated to the saturation temperature, boiled and typically superheated to state 1. Then whole cycle is repeated.

ENVIRONMENTAL REGULATIONS ON TPS

Thermal power Plants

Environmental Regulations ON THERMAL POWER STATIONS

A : Coal Based Thermal Power Plants

Standards for discharge of liquid effluents



S.
No.

Source

Pollutants

Concentration

(i)

Condenser
cooling water
(once through
cooling system)

pH

6.5-8.5

Temperature

More than 10°C than the intake water
temperature

Free available
Chlorine

0.5 mg/l

(ii)

Boiler blow down

Suspended
solids

100 mg/l

Oil and grease

20 mg/l

Copper (total)

1.0 mg/l

Iron (total)

1.0 mg/l

(iii)

Cooling tower
blow down

Free available
Chlorine

0.5 mg/l

Zinc

1.0 mg/l

Chromium

0.2 mg/l

Phosphate

5.0 mg/l

Other corrosion
inhibiting
materials

Limit to be established on case by case basis

(iv)

Ash pond
effluent

pH

6.5-8.5

SS

100 mg/l

Oil & grease

20 mg/l



No limits for heavy metals are given at present



Temperature Limit for discharge of Condenser Cooling Water from Thermal Power plant
A. New thermal power plants commissioned after June 1, 1999.
New thermal power plants, which will be using water from rivers/lakes/reservoirs, shall install cooling
towers irrespective of location and capacity. Thermal power plants which will use sea water for cooling
purposes, the condition below will apply.
B. New projects in coastal areas using sea water
The thermal power plants using sea water should adopt suitable system to reduce water temperature
at the final discharge point so that the resultant rise in the temperature of receiving water does not






Rise in temperature of condenser cooling water from inlet to the outlet of condenser shall not be more
than
10o C.
D. Guidelines for discharge point:

1. The discharge point shall preferably by located at the bottom of the water body at mid-stream
for proper dispersion of thermal discharge.
2. In case of discharge of cooling water into sea, proper marine outfall shall be designed to
achieve the prescribed standards. The point of discharge may be selected in consultation with
concerned State Authorities/NIO.
3. No cooling water discharge shall be permitted in estuaries or near ecologically sensitive areas
such as mangroves, coral reefs/spawning and breeding grounds of aquatic flora and fauna.




(ii) Emission Standards

Power generation capacity (MW)

Particulate matter emission

Less than 210 MW

350 mg/Nm3

210 MW or more

150 mg/Nm3



Note:

Depending upon the requirement of local situations, which may warrant stricter standards as in case of
protected areas the State Pollution Control Board and other implementing agencies within the
provisions of the EPA, 1980 may prescribe limit of 150 mg/Nm3 irrespective of the generation capacity
of the plant.

Andhra Pradesh Pollution Control Board and Delhi Pollution Control Committees have stipulated
stringent standards of 115 and 50 mg/Nm3 respectively for control of particulate matter emission.

(iii) Stack Height Requirement

In order to proper dispersion of SO2 emissions from thermal power plants, stack height criteria have
been adopted in the country. However, for larger capacities of boilers (500 m and above), space
provision for installing FGD system has been recommended;

Power generation capacity

Stack height (metre)

Less than 200/210 MW

H = 14(Q) 0.3
where Q is emission rate of SO2 in kg/hr,
H = Stack height in metre

200/210 MW or less than 500 MW

220

500 MW and above

275



Note :

The power plants sanctioned by CEA earlier to July 1, 1994 may not be required to increase existing
stack height as per regulation notified, vide Government of India notification no. GSR 742(E) dated
August 30, 1990 subject to following conditions:

• The ambient sulphur dioxide and NOx concentrations around the power plant is less than 1/3 th






prescribed ambient air quality standard for SO2 and Nox for the concerned area.

• For (1) the power plant shall install adequate number of air quality monitoring stations in and around
the power stations. The stations should be selected in consultation with the CPCB/SPCB.

( Vide office Memorandum No B-34011/1/01/PCI-II dated January 10, 1996 )

(iv) Use of beneficiated coal

In order to minimize flyash generation, it was recommended to use beneficiated coal in the power
plants. The Ministry of Environment & Forests, Govt. of India has promulgated Gazette Notification
(GSR 560(E) & 378(E), dated September 19, 1997 and June 30, 1998 respectively) on use of
beneficiated/blended coal containing ash not more than 34 percent w.e.f. June 2002 in the following
power plants :

• any thermal power plant located beyond one thousand kilometers from the pit-head and

• any thermal power plant located in urban area or sensitive area or critically polluted area irrespective
of their distance from pit-head except any pit-head power plant”.

The power plants using FBC( CFBC,PFBC & AFBC) and IGCC combustion technologies are exempted
to use beneficiated coal irrespective of their locations.

(v) Utilisation of Flyash

In order to make mondatory use of flyash and flyash based products by the brick kilns, Thermal Power
Stations and CPWD& State PWDs , vide notification no. S.O. 763(E) dated September 14, 1999,
Ministry of Environment & Forests has issued directions under sub-rule 3 of rule 5 of EPA, 1986 that

• No person, located within 50 km radius of any Thermal Power Station, shall to manufacture clay
bricks, tiles or blocks without mixing atleast 25% flyash or pond ash with soil.

• Thermal Power Plants shall submit action plan for hundred percent utilization.

New Plants

30% within three yrs
100% within 9 yrs

Existing Plants

20% within three yrs
100% within 15 yrs

Existing notification on utilisation of flyash was amended vide notification no S.O. 979(E) , dated
August 27, 2003 .by Ministry of Environment & Forests incorporating

• No person shall within a radius of 100 kms from thermal power plants, manufacture clay bricks, tiles
or blocks without mixing atleast 25% of flyash or pond ash with soil.

• Every construction Agency including private sector builders within a radius of fifty to one hundred
kilometers from coal or lignite based thermal power plant shall use minimum of following percentage of






ash based products such as: bricks, block & tiles in their construction work:

25% by 31 st August, 2004
50% by 31 st August, 2005
75% by 31 st August, 2006
100% by 31 st August, 2007

In respect of construction of buildings within a radius of fifty kilometers from coal or lignite based
thermal power plant the following minimum percentage of use of bricks, blocks and tiles shall apply:

75% by 31 st August, 2004
100% by 31 st August, 2005

• Authority sanctioning or renewing mining lease shall not grant or extend the lease if the manufacturer
does not use the 25% of the Flyash in the manufacturing of bricks, blocks and tiles.

• Utilisation of Flyash for reclamation of sea subject to compliance of the rules made under the EPA,
1986.

B: Gas/Naptha based Thermal Power Plants

(i) Emission standards for NOx


(a) For existing units 150 ppm (v/v) at 15% excess oxygen


(b) For new units with effect from 1-6-1999.

Generation capacity of gas
turbine

Limit for NOx emission (v/v), at 15% excess
oxygen)

(a) 400 MW and above

(i) 50 ppm for the units burning natural gas.
(ii) 100 ppm for the units burning naphtha

(b) Less than 400 MW but upto
100 MW

(i) 75 ppm for the units burning natural gas
(ii) 100 ppm for the units burning naphtha

(c) Less than 100 MW

100 ppm for units burning natural gas or
naphtha as fuel

(d) For the plants burning gas
in a conventional boiler.

100 ppm



(ii) Stack height H in m should be calculated using the formula H= 14 Q 0.3 , where Q is the emission
of SO2 in kg/hr, subject to a minimum of 30 mts.

(iii) Liquid waste discharge limit

Parameter

Maximum limit of concentration (mg/l except for
pH and temperature)

pH

6.5 - 8.5








Temperature

Free available
chlorine
Suspended solids
Oil & grease
Copper (total)
Iron (total)
Zinc
Chromium (total)
Phosphate

As applicable for other thermal power plants

0.5
100.0
20.0
1.0
1.0
1.0
0.2
5.0



C: Liquid fuel based Thermal Power Plants

(i) Emission Standards for Diesel Engines (Engine Ratingmore Than 0.8 Mw (800 Kw) for Power
Plant, Generator Set applications and other requirements

Parameter

Area
Category

Total engine
rating of the
plant
(includes
existing as
well as new
generator
sets)

Gerator sets commissioning date

Before
1/7/2003

Between
1/7/2003 and
1/7/2005

On or
after
1/7/2005

Nox (as NO2 ) (at 15% O2 ),
dry basis, in ppmv

A

Upto 75MW

1100

970

710

B

Upto 150MW

A

More than
75MW

1100

710

360

B

More than
150MW

NMHC (as C) (at 15% O2 ),
mg/Nm3

Both A and B



150

100

PM (at 15%
O2 ), mg/Nm3

Diesel Fuels -
HSD & LDO

Both A and B



75

75

Furnace Oils
- LSHS & FO

Both A and B



150

100

CO (at 15% O2 ), mg/Nm3

Both A and B



150

150

Sulphur content in fuel

A



<2%

B



<4%

Fuel specification

For A only

Up to 5MW

Only Diesel Fuels (HSD, LDO) shall be
used.

Stack height (for generator
sets commissioned after
1/7/2003)

Stack height shall be maximum of the following, in meter:

I. 14 Q 03 , Q = Total SO2 emission from the plant in kg/hr








II. inimum 6 m above the building where generator set is installed.

III. 30 m.



 Note: 1. Acronyms used

MW : Mega (106 ) Watt, FO : Furnace Oil, NOX : Oxides of Nitrogen HSD : High Speed Diesel, NO2 :
Nitrogen Dioxide, LDO : Light Diesel Oil, O2 : Oxygen , LSHS : Low Sulphur Heavy Stock, NMHC :
Non- Methane Hydrocarbon kPa : Kilo Pascal, C : Carbon, mm : Milli (10 -3 ) metre, PM : Particulate
Matter kg/hr : Kilo (103 ) gram per hour, CO : Carbon Monoxide, mg/Nm3 : Milli (10 -3 ) gram per Normal
metre cubic, SO2 : Sulphur Dioxide , ppmv : part per million (10 6 ) by volume

2. Area categories A and B are defined as follows

Category A: Areas within the municipal limits of towns/cities having population more than 10 lakhs and
also upto 5 km beyond the municipal limits of such towns/cities.

Category B: Areas not covered by category A.

3. The standards shall be regulated by the State Pollution Control Boards or Pollution Control
Committees, as the case may be.

4. Individual units with engine ratings less than or equal to 800 KW are not covered by this notification.

 5. Only following liquid fuels viz. High Speed Diesel, Light Diesel Oil, Low Sulphur Heavy Stock and
Furnace Oil or liquid fuels with equivalent specifications shall be used in these power plants and
generator sets.

 6. For expansion project, stack height of new generator sets shall be as per total Sulphur Dioxide
emission (including existing as well as additional load).

7. For multi engine plants, flues shall be grouped in cluster to get better plume rise and dispersion.
Provision for any future expansion should be made in planning stage itself.

8. Particulate Matter, Non-Methane Hydrocarbon and percent moisture (dry basis). Carbon Monoxide
results -are to be normalized to 25 0 C, 1.01 Kilo Pascal (760 mm of mercury) pressure and zero

 9. Measurement shall be performed at steady load conditions of more than 85% of the rated load.

10. Continuous monitoring of Oxides of Nitrogen shall be done by the plants whose total engine
capacity is more than 50 Mega Waft. However, minimum once in six month monitoring for other
parameters shall be adopted by the plants.

 11. Following methods may be adopted for the measurement of emission parameters,-

Sl.No.

Emission Parameters

Measurement Methods

1.

Particulates

Gravimetric

2.

SO2

Barium Perchlorate- Thorin indicator method

3.

NOX

Chemiluminescence, Non Dispersive Infra Red, Non
Dispersive Ultra-violet (for continuous measurement),Phenol








disulphonic method

4.

CO

Non Dispersive Infra Red

5.

O2

Paramagnetic, Electrochemical sensor

6.

NMHC

Gas Chromatograph - Flame lonisation Detector





LIST OF THERMAL POWER PLANTS IN INDIA

S. No.

Name

State

Capacity (MW)

1.

Ramagundam, NTPC

Andhra Pradesh

2100

2.

Ramagundam ‘B'

-do-

62.5

3.

Vijaywada

-do-

1260

4.

Rayalseema

-do-

420

5

Simhadri, NTPC

-do-

1000

6.

Nellore

-do-

30

7.

Kothagudem

-do-

1210

8.

Bongaigaon

Assam

740

9.

Barauni

Bihar

320

10.

Kahalgoan

-do-

840

11.

Muzaffarpur

-do-

220

12.

Korba, NTPC

Chhattisgarh

2100

13.

Korba East

-do-

440

14.

Korba [West]

-do-

840

15

Badarpur,NTPC

Delhi

705

16

Rajghat

-do-

135

17.

I.P.Station

-do-

247.5

18.

Gandhinagar

Gujrat

870

19.

Utkai

-do-

850

20.

Wanakbori

-do-

1260

21

Dhuvaran

-do-

534

22.

Sabarmati, AEC

-do-

400

23.

Sikka

-do-

240

24.

Kutch lignite

-do-,

215

25.

Surat Lignite

-do-

250

26.

Faridabad

Haryana

180

27

Panipat

-do-

1150

28.

Raichur

Karnataka

1470








29.

Bokaro ‘B'

Jharkhand

630

30.

Tenughat

-do-

420

31.

Patratu

-do-

840

32.

Bokaro (A)_( Closed0

-do-



33.

Chandrapura

-do-

750

34.

Amarkantak

Madhya Pradesh

290

35.

Birsinghpur

-do-

840

36.

Satpura

-do-

1142.5

37.

Vindhyachal, NTPC

-do-

2760

38.

Trombay

Maharashtra

1330(500)

39.

Khapakheda

-do-

840

40.

Nasik

-do-

910

41.

Koradi

-do-

1100

42.

Bhusawal

-do-

482.5

43.

Chandrapur

-do-

2340

44.

Paras

-do-

62.5

45.

Parli

-do-

690

46.

Ballarshah (closed)

-do-



47.

Dahanu

-do-

500

48.

Talcher (N), NTPC

Orissa

3000

49.

Talcher (old),NTPC

-do-

470

50.

Ib Valley

-do-

420

51.

Bhatinda, GNTP

Punjab

440

52.

GGSSTP,Ropar

-do-

1260

53.

GHTP (Lehra
Mohabbat)

-do-

420

54.

Kota

Rajasthan

1045

55.

Suratgarh

-do-

1250

56.

Ennore

Tamilnadu

450

57.

Tuticorin

-do-

1050

58.

North Madras

-do-

630

59.

Mettur

-do-

840

60.

Neyveli-Lgnite

-do-

2490

61.

Basin Bridge (Closed)

-do-



62.

Singrauli, NTPC

Uttar Pradesh

2000

63.

Rihand, NTPC

-do-

1000

64.

Anpara

-do-

1630








65.

NCTPS – Dadri,NTPC

-do-

840

66.

Panki

-do-

210

67.

Unchahar, NTPC

-do-

840

68.

Tanda

-do-

440

69.

Paricha

-do-

220

70.

Obra A
Obra B

-do

1482

71.

Harduaganj

-do-

515

72.

Farakka,NTPC

West Bengal

1600

73.

Budge-Budge, CESC

-do-

500

74.

Mezia, DVC

-do-

630

75.

Southern, CESC

-do-

135

76.

Barkeshwar

-do-

630

77.

Durgapur (DVC)

-do-

350

78.

Titagarh, CESC

-do-

240

79.

Santaldih

-do-

480

80.

DPL, Durgapur

-do-

395

81.

Kolaghat

-do-

1260

82.

Bandel

-do-

540

83.

Gauirpore (closed)

-do-






THERMAL POWER PLANTS REQUIRED TO USE BENEFICIATED COAL

A. EXISTING

S.
No.

Name of Thermal
Power Station

Capacity
(MW)

Category
+

Estimated Annual
beneficiated Coal
Requirement (MTPA)

1.

Badarpur

705

UA

2.75

2.

Indraprastha

278

UA

0.67

3.

Rajghat

135

UA

0.58

4.

Faridabad

165

UA

0.80*

5.

Panipat (Units 1-5)

650

>1000 km

3.60*

6.

Bhatinda (Units 1-4)

440

>1000 km

1.98

7.

Ropar (Units 1-6)

1260

>1000 km

5.08

8.

NCR Dadri

840

>1000 km

4.00

9.

Harduaganj

425

>1000 km

1.06

10.

Panki

274

U.A.

0.79








11.

Paricha

220

>1000 km

0.89

12.

Kota (Units 1-5)

850

U.A.

3.65

13.

Sabarmati

410

U.A.

1.32*

14.

Wanakbori (Units 1-
6)

1260

>1000 km

6.06

15.

Gandhi Nagar

660

U.A.

3.00*

16.

Ukai

850

>1000 km

3.36*

17.

Sikka (Units 1-2)

240

>1000 km

1.00*

18.

Bhusawal

478

>1000 km

2.24

19.

Koradi

1080

U.A.

5.50*

20.

Nasik

910

>1000 km

3.60

21.

Trombay

1150

U.A.

Oil/Coal

22.

Dahanu

500

S.A.

2.01

23.

DPL

390

CPA

0.49

24.

Muddanur
(Rayalaseema)

420

>1000 km

2.37

25.

North Chennai -I

630

U.A.

2.97

26.

Ennore

450

>1000 km

1.92*

27.

Raichur (1-4)

840

>1000 km

4.38

28.

Mettur

840

>1000 km

4.39

29.

Tuticorin (1-5)

1050

>1000 km

4.08*

30.

Bokaro

820

CPA

1.84

31.

Durgapur

350

CPA

1.00

Sub Total (A)

19570



77.37



B. IX Plan

S.
No.

Name of Thermal
Power Station

Capacity
(MW)

Category
+

Estimated Annual
Coal Requirement
(MTPA)

32.

Bhatinda-5&6

420

>1000 km

1.88*

33.

Wanakbori-7

210

>1000 km

1.00*

34.

Gandhinagar-7

210

>1000 km

0.95

35.

Raichur (5-6)

420

>1000 km

2.14

36.

North Chennai II

1050

U.A.

IC (Imported Coal)

37.

Mangalore

1000

>1000 km

IC

38.

Tranagallu

260

>1000 km

IC

39.

Suratgarh-I

500

>1000 km

IC








Sub Total (B)

4370



8.09



Total coal consumption based on 1999-2000 data upto ix plan 85.46 mtpa

* Revised based on data provided by SEBs/utilities

UA : Urban Area, CPA : Critically Polluted Area, SA: Sensitive Area and

IC : Imported Coal

(Source : Central Electricity Authority)

THERMAL POWER PLANTS WHICH HAVE DRY FLYASH COLLECTION FACILITIES

1. Dahanu, Maharashtra

2. Sabarmati, Gujarat

3. Budge-Budge, West Bengal

4. Titagarh, West Bengal

5. Vizaywada, AP

6. Rayalseema, AP

7. Kothagundem, AP

8. Ramagundem ‘B', AP

9. Nellore , AP

10. Rajghat, Delhi

11. Raichur, Karnataka

12. Singrauli NTPC, UP

13. Vindhyachal, MP

14. Ramagundem, AP

15. *Farakka, West Bengal

16. *Kahalgaon, Bihar

17. *Korba, Chhatisgarh

18. *Talcher (old), Orissa






19. Talcher (Kaniha N), Orissa

20. Badarpur, Delhi

21. Dadri, U.P.

22. Unchahar, U.P.

23. DPL, West Bengal

24. Nasik , Maharashtra

25. Chandrapur, Maharashtra

26. Kota , Rajasthan

27. Ropar, Punjab

28. Bhatinda, Punjab

29. Lehra Mohabbat, Punjab

30. Sabarmati, Gujrat

31. Suratgarh, Rajasthan

32. *Neyveli Lignite Corporation,TN

33. North - Chennai , TN

34. Ib Valley, Orissa

35. Meizia ,WB

36. ** Faridabad , Haryana

37. **Panipat, Haryana

38 Sikka, Gujrat

* : Facility is being provided

**: PFC has sanctioned the scheme, same is being developed

Flyash utilization during 2005-06

State

Name Capacity

Capacity

( MW)

Coal
Cons.

( mta)

Ash Gen.

( mta)

Ash Uti.

( mta)

%

utilisation






















Andhra
Pradesh

Nellore
APGENCO

30

0.149

0.065

0.158

243

Andhra
Pradesh

Ramagundam ,
APGENCO

62.5

0.283

0.106

0.073

68.9

Andhra
Pradesh

Ramagundam,
NTPC

2100

11.79

3.887

1.863

47.9

Andhra
Pradesh

Rayalseema,
APGENCO

420

1.519

0.603

0.386

61.3

Andhra
Pradesh

Simhadri, NTPC

1000

4.98

1.765

0.856

48.5

Andhra
Pradesh

Vijayawada ,
APGENCO

1260

6.81

2.646

1.501

56.7

Andhra
Pradesh

Kothagudem
APGENCO

1200

3.639

1.507

Nil

-















Assam

Bongaigaon ,
ASEB

710

Plant
Closed





















Bihar

Barauni

240

0.131

0.052

0.058

111.5

Bihar

Muzaffarpur,
BSEB

220

Nil

Nil



-

Bihar

Kahalgaon, NTPC

840

5.848

1.431

0.703

49.1















Chhattisgarh

Korba, NTPC

2100

11.66

4.832

2.288

47.4

Chhattisgarh

Korba West

840

3.975

1.75

0.589

33.6

Chhattisgarh

Korba East,
ChEB

440

2.853

1.28

1.155

90.0















Delhi

I.P. .IPPGENCO

247.5

0.974

0.331

0.157

47.4

Delhi

Rajghat ,
IPPGENCO

135

0.501

0.172

0.157

91.3

Delhi

Badarpur, NTPC

705

3.77

0.128

0.608

475















Gujarat

Ukai, Gujarat
Elect.Board,

850

3.54

1.157

0.471

40.7

Gujarat

Gandhi Nagar,
GEB

870

3.17

0.916

0.597

65.2

Gujarat

Sikka , GEB

240

0.941

0.278

0.17

61.2

Gujarat

Sabarmati, AEC,
Ahmedabad

400

1.773

0.323

0.304

94.1








Gujarat

Kutchlignite,
Kutch

215

0.735

0.108

0.1.08

100

Gujarat

Surat Lignite,

250

0.766

0.303

0.303

100

Gujarat

Wanakbori

1470

6.85

2.445

1.546

63.2















Haryana

Panipat

1360

3.85

1.54

1.668

108.3

Haryana

Faridabd

165

0.798

0.231

0.029

12.6















Jharkhand

Patratu

840

0.812

0.32

0.122

38.1

Jharkhand

Chandrapura,
DVC

750

1.396

0.592

0.675

114.0

Jharkhand

Bokaro ‘B', DVC

630

2.18

0.715

0.688

96.2















Karnataka

Raichur, KPCL

1470

6.991

2.269

0.951

41.9















Madhya
Pradesh

Satpura MPEB,
(MP)

1142.5

6.936

2.463

0.105

4.3

Madhya
Pradesh

Sanjay Gandhi
,MPEB

840

4.38

1.752

0.589

33.6

Madhya
Pradesh

Amarkantak ,
Chachai, MPEB,

290

0.977

0.298

0.247

82.9

Madhya
Pradesh

Vindhyachal
NTPC

2260

11

3.111

1.463

47.0















Maharashtra

Trombey, Tata
Poweri

1330

1.802

0.034

0.0384

112.9

Maharashtra

Koradi, MSEB

1100

4.914

1.744

0.175

10.0

Maharashtra

Parli , MSEB

690

3.799

1.578

0.376

23.8

Maharashtra

Bhusawal MSEB

482.5

2.394

0.797

0.462

57.9

Maharashtra

Dahanu ,
Relience Energy

500

2.37

0.585

0.147

25.1

Maharashtra

Khaperkheda,
MSEB

840

4.47

1.668

0.634

38.0

Maharashtra

Paras

62.5

0.325

0.102

0.102

100

Maharashtra

Chandrapur

2340

9.557

3.966

0.453

11.4

Maharashtra

Nasik

840

3.463

1.247

0.13

10.4

Orissa

Talcher ,
Angul,NTPC

460

2.82

1.073

0.66

61.5

Orissa

Ib. , OPGCL

420

2.605

1.057

0.07

6.6






















Orissa

Talcher ,
Kaniha,NTPC

2500

13.87

4.982

1.232

24.7















Punjab

Gurunanak Dev,
PSEB

440

1.747

0.539

0.223

41.3

Punjab

Lehra Mohabat,
PSEB

420

1.83

0.62

0.445

71.8

Punjab

GurugobindSingh,
PSEB

1260

6.29

2.158

1.626

75.3

Rajasthan

Kota

1045

5.325

1.506

1.198

79.5

Rajasthan

Suratgrah ,
RVUNL

1250

6.096

1.759

0.836

47.5















Tamilnadu

Tuticorin TNEB

1050

5.69

2.116

0.946

44.7

Tamilnadu

Mettur TNEB

840

4.18

1.514

1.304

86.1

Tamilnadu

North Chennai ,
TNEB

630

2.54

0.946

0.304

32.1

Tamilnadu

Ennore TNEB

450

0.58

0.233

0.061

26.2

Tamilnadu

NLC, Neyveli

2490

15.886

1.835

0.499

27.2

Tamil nadu

ST CMS Electric
(P) Ltd.

250

1.442

0.067

0.052

77.6















Uttar Pardesh

Unchahar, NTPC

840

0.705

1.838

1.565

85.1

Uttar Pardesh

Dadari, NTPC

840

4.21

1.507

0.802

53.2

Uttar Pardesh

Rihand, NTPC

1000

4.75

1.407

0.73

51.9

Uttar Pardesh

Tanda, NTPC

440

2.56

0.842

0.402

47.7

Uttar Pardesh

Singrauli, NTPC

2000

10.2

3.123

1.468

47.0

Uttar Pardesh

Parichha
,UPVUNL

220

0.726

0.218

0.41

188.1

Uttar Pardesh

Obra , UPVUNL

1550

4.94

1.884

0.014

0.7

Uttar Pradesh

Anpara, UVUNL

1630

8.47

2.974

0.072

2.4

Uttar Pradesh

Panki, UVUNL

210

0.96

0. 25

0.337

133.2















West Bengal

Meizia, DVC

630

3.32

1.32

0.0013

0.1

West Bengal

Durgapur , DVC

350

0.872

0.349

0.495

141.8

West Bengal

Durgapur Projects
Ltd.

401

1.686

0.573

0.737

128.6

West Bengal

Santaldih,
WBPDCL

480

0.843

0.253

0.875

345.8498

West Bengal

Budge Budge,

500

2.52

0.908

0.908

100








CESC

West Bengal

Titagarh , CESC

240

1.17

0.33

0.33

100

West Bengal

Sounthern ,
CESC,

135

0.68

0.24 0.24



100

West Bengal

Kolaghat.
WBPDCL

1260

5.086

1.618

1.988

122.9

West Bengal

Farrakka, NTPC

1600

9.26

3.426

2.06

60.1

West Bengal

Bakreswar,
WBPDCL

630

2.487

0.689

0.242

35.1

West Bengal

Bandel, WBPDCL

530

1.285

0.413

0.18

43.6

















Total

63738.5

285.742

95.414

45.9827

48.2



Captive Power plants

capative
power
plants

Name Capacity

Capacity

( MW)

Coal Cons.

( mta)

Ash Gen.

( mta)

Ash Uti.

( mta)

%

utilisation















UP

Renusagar,
HINDALCO

741.7

5.43

2.205

0.938

42.5

Orissa

NALCO

55.5

0.994

0.414

0.016

3.94

Gujarat

Tata Chemicals

70



0.077

0.034

44.2

Punjab

NFL, Bhatinda

*30

0.122

0.254



0

Karnataka

Rahshree Cemnet

38.2



0.096

0.305

317.7

Kerala

Hindustan News
Print

*22

0.166

0.049

0.049

100

AP

Sirpur Paper Mill

*31.9

0.29

0.139



0

Tamilnadu

TCP Limited

63.75

0.373

0.068

0.073

107.4

AP

Nava Bharat
Ferro alloy

50

0.276

0.137

0.014

10.2

Karnataka

Grasim Industries

10

0.089

0.027

0.025

92.6

Karnataka

Mysore
PaperMills

41

0.217

0.05

0.034

68

Gujarat

JK Paper ltd.

12

0.072

0.028

0.028

100

Orissa

NTPC-SAIL
Power Co.

120

0.906

0.362

0.318

87.8

MP

Orient paper Mills

22

0.204

0.0632

0.068

107.6

Chattisgarh

Bhilai ESCPL

74

0.47

0.125

0.0048

3.84

UP

IFFCO

12.5







0








Uttranchal

CPP-Century
Pulp & paper

27.8







0

Bihar

BCCL

30

0.164

0.068

0.068

100

AP

VSP

247.5

1.429

0.571

Nil

0

Karnataka

Vasavdatta





0.047

0.047

100

Orissa

Nava Bharat
Ferro alloy

30

0.196

0.095

0.009

9.5

West Bengal

NTPC-SAIL
Power Co.

120

0.639

0.25

0.0562

22.48

Jharkhand

Tata Steel

147.5

0.599

0.281

Nil

0

Maharashtra

Ballarpur

30

0.188

0.461

0.0462

10.0





1943.45

12.824

5.8672

2.1332

42.5

BOWL MILLS MAINTANACE -BLUE PRINT

A Four-Step Plan:

Blueprinting a pulverizer isn’t rocket science, but it does require close attention to the details. Here is our four-step plan to restore and improve performance of your pulverizer, regardless of its age.

STEP-I :

**Ensure that the grinding elements are in good condition.

 Make sure that the grinding surface profiles are optimum. That means using the original design grinding profiles for your mill. The majority of coal pulverizers sized around 120,000 pph use three grinding elements, referred to as journals, rolls, or tires. For best results, all three grinding elements should be replaced in matched sets. The concentricity, physical dimensions, and contours must be exactly the same. This is especially important when maximum preload pressure is required to produce maximum coal fineness and/or with lower-than-original design HGI. We have seen mills assembled with unmatched sets of three grinding journals using maximum spring pressure. The result of such setups: The main shafts break because of the unbalanced load. Matched sets of grinding elements and exactly the same size rolls with exactly the same contour are important for maximum reliability.

The grinding surfaces also must be in good condition and parallel (Figure 3). Don’t expect optimum performance if the grinding elements are well-worn or the tires are "flat" (Figure 4). Unusual wear patterns are often the result of uneven spring frame tolerances, alignment issues, pressure variations, geometry, and/or eccentricity issues. 

  **Walk the line. The profile of the roll should be parallel with the grinding ring profile.

***Perfectly round. In an MPS mill, the tire and table profiles must match, and the tires should not have flat spots.

.

STEP-II:

**Set the correct grinding pressure.  

Check your mill to confirm that the grinding roll or spring frame preload pressure is set correctly. Our experience with both RP and MPS pulverizers has been that mills designed for a throughput of about 120,000 pounds of coal per hour, an HGI of about 45 to 50, and coal fineness exceeding 75% passing 200 mesh will require about the same force on the grinding elements. It is reasonable to expect that grinding coal will take about the same amount of grinding element pressure regardless of the type of medium-speed, vertical spindle pulverizers you use.

In our experience the spring frame of an MPS mill tuned for maximum true capacity will be set at about 20 tons minimum force on the grinding tires. A bowl mill spring or hydraulic preload for this size of mill will also be about 20 tons of pressure. Lower-HGI fuel and greater than passing of 200 mesh requires the maximum pressure of the grinding elements. Keep in mind that in operation there is no metal-to-metal contact, and all coal grinding results from the pressure applied coal particle – to – coal particle on a bed of coal squeezed between the grinding elements.

Internal clearances are also very important. For example, a bowl mill spring canister can be set to the needed preload, but if it is not adjusted for the "button" to roll with assembly minimum clearance, then the preloading does not come into play until the roll rides up on a deeper bed of coal . Ensuring sufficient grinding pressure is absolutely essential, and it begins with setting this critical tolerance.

** Keep your distance. The "button" clearance between the spring canister and the journal assembly is a critical tolerance.

For a spring frame mill, the hydraulic preload must be balanced across the mill and the grinding elements perfectly centered in the assembly

* *Balanced load. The MPS spring frame hydraulic preload must be carefully balanced and the spring frame centered for optimum mill performance. 

STEP-III:

** Set the correct pulverizer throat clearance. An oversized pulverizer throat will require more than optimum primary airflow to minimize coal rejects. The pulverizer "free annular jet" of vertically flowing airflow, in our experience, must be adjusted for a minimum of 7,000 fpm under normal operation. Throats that are oversized will result in either excessive coal rejects (not tramp metal or pyrites, but raw coal).

Compounding the problem, high primary airflow is the main cause, in our experience, for poor fuel fineness, poor fuel distribution, and reduced furnace performance. Right-sizing the flow area of the pulverizer throats and matching them for compatibility with the coal pipes and burner nozzle sizes is essential for the best furnace performance. Furthermore, remember that there will be minor variation in mill capacity, fuel quality, and mill inlet airflow rates that must be considered when sizing the pulverizer throat flow area.

The vertically flowing air must be of sufficient velocity to suspend the granular coal bed in the grinding zone. Some designs use mechanical means to keep the coal above the under-bowl pyrite section, while others use airflow. Reducing coal rejects by mechanical means entails increasing the height of the "bull ring" extension ring or the extension of flat surfaces above the rotating throat to trap or dam coal particles mechanically so that they remain above the throat.

We prefer the optimum throat area fluidic solution to suspend the coal bed and reduce the potential for fires beneath the bowl or grinding table. Keep in mind that if the fuel is above 17% moisture and the air/fuel ratio is about 1.8, then the under-bowl primary air temperature will be above 450F. Any coal that falls through the throat opening will combust unless it is removed in mere minutes. Combustion of coal particles beneath the grinding zone is not a serious problem, as long as the mill is in operation. But if a mill trips or a boiler has a main fuel trip, then fires in the pyrites zone (beneath the grinding zone) are the most common cause of pulverizer "puffs," in our experience. A fire beneath the grinding zone provides the ignition temperature to initiate a mill "puff" when restarting a mill after a trip or restarting it after a main fuel trip when coal remains in the bed.

For safety as well as for performance reasons, properly sizing the mill throats is extremely important . The optimum throat area is determined by calculating the free annular jet area when the desired air/fuel ratio (usually 1.8 lb air/lb fuel) is known. Also, the throat area must be properly designed to be compatible with the flow areas of the burner coal pipes and coal nozzles

**Optimum design. Ensure optimum arrangement of the mill throat and the coal flow path to improve mill performance.

**Close tolerances. Pulverized coal mills with throats that are too wide will have corresponding low throat velocity in the mill grinding zone that contributes to excessive coal rejects and fires. This is an example of an oversized mill throat.

STEP-IV:

**Properly maintain the classifier.

Once the grinding zone is blueprinted and put in first-class condition, the next component to examine is the classifier. The best furnace combustion performance is governed by uniform coal combustion by the burners and satisfactory coal fineness. Adequate fineness for both western and eastern fuels (Powder River Basin or bituminous) is a minimum of 75% to 80% passing 200 mesh and zero to 0.1% remaining on a 50 mesh screen (Figure 9). To achieve this fineness, the pressurized mill classifier must perform two functions:

·   **      It separates particles small enough to be supplied to the burners (mean particle size about 40 to 55 microns) from larger coal particles that need return to the grinding zone for regrinding.

·     **    It balances the distribution of coal to each coal pipe.

**Why use a classifier? A classifier recirculates coarse coal in the grinding zone and balances the flow of coal to each burner line to the furnace.

The flow of coal particles through a classifier is several times the amount of coal flowing to the burners because of the large amount of coal recirculated within a pulverizer. For example, if a pulverizer is operating at 100,000 lb/hr coal feed to the burners, as much as 300,000 lb/hr or more may be flowing through the classifier for regrinding. For this reason the surface smoothness and inverted cone clearances are extremely important for good pulverizer performance.

Our experience over the years has helped us develop a number of proven minor enhancements for achieving best classifier performance. The critical dimensions indicated in Figure 10 include:

·         Surface smoothness of the classifier cone.

·         Synchronized classifier blade angles and lengths.

·         Inverted cone to classifier clearances.

·         Classifier outlet cylinder length and flared opening.

·         

**Better than good. Areas of the classifier where performance can be improved.

Other improvements that should be considered when overhauling a classifier include these:

·         Smooth surfaces in the upper turret section for good fuel spinning and uniform distribution (no surface discontinuities, such as "pad eyes").

·         Ensure the free movement and closure of the discharge doors (trickle valves).

·         Confirm the sound and good condition of the classifier cone assembly (no holes should be worn through).

·         Ensure the good mechanical condition of the classifier blades.

** Mill design guide. An internal view of  a typical vertical-spindle pulverizer and specific areas where special attention to dimensional tolerances and assembly dimensions can improve mill performance.