Power Plant Familiar is at Ion v- I

THERMAL POWER PLANT FAMILIARISATION VOL - I

Contents

S.No Subject Page No

1 Organizational Structure of Electricity

supply Industry in India

1 - 26

2 Electricity Generation : Consideration and

Location of Large Thermal Power Plants

27 - 37

3 Station layout 38 - 42

4 Combustion theory

5 Steam cycle theory and cycle constraints 63 - 72

6 Power Sector - highlights & Main

Achievements

73 - 90

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ORGANISATIONAL STRUCTURE

OF

ELECTRICITY SUPPLY

INDUSTRY IN INDIA



Page 1

1.1 INTRODUCTION

Organizational structure of electricity supply industry in India has been evolutionary

in nature. To understand this evolution it would be necessary to go over the past history of

the electricity supply industry.

1.1 BEGINNING YEARS

In the year 1883 the first electric supply undertaking in the country was sponsored by

a company which constructed a small generating station in the city of Surat in Gujarat. This

was perhaps one of the earliest electric supply companies anywhere in the world. This

undertaking got as far as lighting the main streets of the city by arc lamps, but unfortunately,

in the next year, disastrous floods of the river Tapti submerged its generating plant. In the

year 1896, an undertaking started operations at, Calcutta. Thus the beginning of electric

supply industry in India was mainly due to private company effort.

The electricity legislation was first made in India in 1887. The Electricity Act of

1887 was enacted to meet the situation created by the erection of a few dynamos and lighting

appliances. This Act was based on the English Statute of 1882 and was more or less a

temporary measure. In 1903 this Act of 1887 was modified and enlarged by the Government

of India so as to enable issue of Licence to the Calcutta Electric Supply Company granted in

1907 to the a ras and Delhi electric supply companies. In 1910 the electricity supply

legislation was further revised. The Indian Electricity Act. 1910, was carefully modernised

and adopted to suit Indian conditions. The private companies were accorded a well

considered statutory footing in developing the electricity supply industry and it has remained

substantially unchanged till today, except to the extent reinforced by the provisions of the

Electricity (Supply) Act., 1948.

1.2 ORGANISATIONAL STRUCTURE OF THE ELECTRICITY SUPPLY

INDUSTRY JUST AFTER INDEPENDENCE.

India attained independence from the British Rule in 1947. It would be of interest to

investigate the organizational structure of the industrypriortoindependence.TheTable-1

shows the ownership of the electric suply undertaking as at the end of 1947



Page 2

Table – I

Ownership of Electric Supply Undertakings

at the end of 1974 in Provinces and States

Electric Undertaking Owned By

Province or State Private

Companies Manici- Palities

Govern- ment

Total

PROVINCES 1. Ajmer-Merwara 2 - - 2 2. Assam 7 - - 7 3. West Bengal 22 1 1 24 4. Bihar 21 - 1 22 5. Bombay 64 1 3 68 6. C.P. & Berar 26 - 1- 27 7. Coorg 1 - - 1 8. Delhi 1 1 1 3 9. Madras 45 35 12 92 10. Orissa 4 - - 4 11. East Punjab 14 2 1 17 12. United Provinces 28 7 9 44

Total (provinces) 235 47 28 311 STATES 1. Baroda 12 1 4 17 2. Hyderabad - - 11 11 3. Mysore - - 1 1 4. Kashmir - - 3 3 5. Travancore 3 - 4 7 6. Other States 46 2 75 123

Total States 61 3 98 162 Total (All India) 296 50 126 473

As at the end of 1947, just after independence 63% of the total installed capacity and

electricity generation was contributed by company owned undertakings, 36% by government

undertaking and nearly 1% by municipal undertakings. Details are shown in the following

table.

Table – II

Installed Capacity and Production of Electricity in 1947



Ownership No. of Undertakings

Installed In KW

Capacity % age of

total

In 1947 M.Kwh

Production % age of

total

1 Government 97 487112 35.73 1475944 36.23 2 Municipalities 14 12545 0.92 30877 0.76 3 Companies 229 863608 63.35 2566497 63.01

Total 340 1,363,265 100.00 4,073,318 100.00

Another important characteristics of the electricity supply industry was that the majority of

Page 3

undertakings owned small oil fired power plants. As a matter of fact the percentage was as

high as 77.9%. Only 5.6% of the total number of generating undertakings owned hydro

power plant and 16.5% thermal power plant.

The organisational structure of electricity supply industry started changing in 1947

itself. The year marked the taking over by the Government of a number of company

operated undertakings. The Cawnpore Electric Supply Corporation (1921) and Ajamgarh

Electric Supply Company in U.P., the Madras Electric Supply Corporation (1917) and the

Barrackpore Electric Supply Co. (1942) in West Bengal were taken over by the respective

Provincial Governments, while the Bombay Electric Supply and Tramways Co. (1905) was

acquired by the Bombay Municipality. The Delhi Electric Supply and Tramways Co. (1905)

was also taken over by the State and its management was entrusted to the Delhi Central

Electric Power Authority. The Secunderabad distribution system operated by M/s British

Insulated Callendar's Cables Ltd. came under the Hyderabad City Undertakings owned by

the Nizam's Government. After independence the process of acquiring company owned

undertakings gained momentum.

1.3 ELECTRICITY (SUPPLY) ACT, 1948

The genesis of the above legislation is provided by the proceedings of the Policy

Committee No. 30 on Electric Power, which recommended :

(a) that the development of electricity supply in areas outside existing licensed areas

should be actively pursued as far as possible, as a State, of quasistate enterprise, but if

for any reason the State is not prepared to undertake such development in any area

within a reasonable time, private enterprise should not be excluded;



(b) that, provided sufficient and economic, operation could be assured to the public options

existing under any license to acquire an undertaking should, as a general rule, be

exercised when they arise;

(c) that steps be taken to eradicate any factors that retard the healthy and economical

growth of electrical development on regional lines whether in State and local authority

owned or in commercially owned undertakings.

The then Government of India in the Department of Labour accepted this

recommendation, and there upon followed, in February, 1946, the introduction by Dr. B. R.

Ambedkar in the Legislative Assembly of the Electricity (Supply) Bill and the Act was

enacted in September, 1948.

The main inspiration for the framers of the Act of 1948 was the Policy Committee's

resolution of February 1945. The Electricity (Supply) Act, 1948, is by and large modelled

on the U.K. Electricity (Supply) Act, 1926, The framers of the Act visualised that the State

Electricity Boards are likely to be the most suitable organisation for working the country's

future electricity supply industry on quasi commercial lines. By 1956 such Electricity

Boards were formed only in four States, viz. Delhi, Saurashtra, Bombay and West Bengal.

However, in subsequent years rapid progress was made in the formation of Electricity

Boards by the various State Governments. Following table gives the year of formation of the

various Boards :

Table III

Year of Formation of Various State Electricity Boards

S.No. Name of State Electricity Board Date of formation

1. Andhra Pradesh State Electricity Boards 1.4.1959

2. Assam State Electricity Board 1.6.1958

3. Bihar State Electricity Board 1.4.1958

4. Gujarat State Electricity Board 1.5.1960

5. Haryana State Electricity Board 3.5.1967

Page 4

6. Himachal State Electricity Board 31.8.1971

7. J & K Electricity Board 05.9.1972

8. Kamataka Electricity Board 30.9.1957

9. Kerala State Electricity Board 31.3.1957



10. Madhya Pradesh Electricity Board 01.4.1957

11. Maharashtra State Electricity Board 20.6.1960

12. Meghalaya State Electricity Board 1975

13. Orissa State Electricity Board 01.3.1961

14. Punjab State Electricity Board 03.5.1967

15. Rajasthan State Electricity Board 01.7.1957

16. Tamil Nadu State Electricity Board 01.7.1957

17. U.P. State Electricity Board 01.4.1959

18. West Bengal State Electricity Board 01.5.1956

Delhi which was the first to form a State Electricity Board in 1951 was also the first

to abolish it in 1957. This Board was converted into a Municipal Undertaking under the

DMC Act, 1957. Saurashtra and Bombay Electricity.Boards were later reorganised into

Maharashtra and Gujarat Electricity Board in 1960 due to reorganisation of States.

1.3.1 The Salient Features and the Scope of the Electricity (Supply) Act, 1948.

The Electricity (Supply) Act, 1948 was the result of an effort to obtain all the

advantages of nationalisation without the handicaps inevitably associated with this policy.

The Act was however, not a compromise, but was rather a 'made to measure' statutory plan

adopted to suit the then existing organisation of electricity supply and the special

geographical, economic and political circumstances prevailing at that time in the country.

The fundamental basis of this plan was a should one. It was the requirement that in

each State a quai-autonomous body shall be constituted with powers to implement the

provisions of the Act. The bodies were to be known as State Electricity Board.

(i) Capital may be obtained at advantageous rates

Sections 63 to 66 of the Act govern the financing of State Electricity Boards. Under

the provisions of these sections the Boards are financed at, or only slightly higher than, the

State Government borrowing rate - a very satisfactory figure. Besides, States Govt. advance

loans to the Boards at cheap rates of interests.

ii) The Service can be operated on a nonprofit making basis

Section 59 of the Act dictates that the Board shall not, as far as possible, carry on its

operations at a loss. Venkatraman Committee, however, recommended that the Boards

should earn a profit of 3% since under the Act they were not debarred from earning a profit.



Very few Boards have been able to achieve this objective and most of the Boards have been

running at loss.

(iii) Large-area Planning on a Long-term Basis is facilitated

Large area planning on a long-term basis and the implementation of such planning is

the main function at the State Electricity Board. The provisions of Chapter V of the Act

explain the method to be adopted.

(iv) Gradual Take Over of Private Licensees

The 1948 Act permits adequate control be exercised over generating stations and

main transmission lines of licensees and where necessary, their purchase on a fair basis.

Acquision of private companies was envisaged to be selective and the purchase was to be at

'depreciated cost' and not a 'fair market value'.

(v) Administration of the 1948 Act

The administration of the main provisions of the Act is the responsibility of the State

Govts. and State Electricity Boards. The primary duty of these Boards was to prepare and

subsequently to implement a long-term plan for the electrification of the whole State. This

taking electricity to

Page 5

rural areas also. The Boards have very successfully carried out these objectives of the Act.

Under the 1948 Act the Boards are authorized to designate a generating station as a

'controlled station' if it is :

(i) Efficient

(ii) Capable of expansion

(iii) To be employable as a unit in the State Grid System.

Provision has also been made, where by the Board may, after tending reasonable

notice, close the station. Under Section 35, the Board, when it is a position to afford a bulk

supply to a licensee, may require the licensed to take such a supply even though the latter is

able to generate sufficient energy for his own requirements. The general intention of Section

35, however, was to empower the Board to eliminate gradually small generating units and to

replace these by bulk supplies afforded on term prescribed in the 2nd Schedule.

(vi) Financial Control to be Exercised on Private and Municipal Utilities.

Section 58 empowers a Board to direct the amortisation and tariff policies of

municipal undertaking on order to ensure that revenues derived from electricity supply will

not be directed to other activities at the expense of the consumer. In the case of private



companies, on the other hand, Sector 57 in conjunction with the Sixth Schedule lay down

principles so as to prevent a licensee from earning more than a reasonable return on the

assets employed in affording the service and at the same time it ensures that integrity of the

investment by means of a compulsory systems of depreciation.

1.3.2 Substantial Amendments to the Electricity (Supply) Act, 1948 vide the

amendment Act, 1976.

The important enhanced functions of CEA as per the 1976 amendments are as. follows :

i) to collect and record the data concerning the generation, distribution and utilisation of

power, carry out studies relating to cost, efficiency, losses, benefits and such like

matters;

ii) to advice any State Govt. Board, Generating Company or other agency engaged in the

generation or supply of electricity on such matters, as will enable such Govt. Board,

Generating Company or agency to operate and maintain the power system, under its

ownership or control, in an improved manner and, where necessary;

iii) to promote and assist in the timely completion of schemes sanctioned under Chapter

V;

iv) to make arrangements for advancing the skill of persons in the generation and supply

of electricity;

v) to carry out, or make arrangements for any investigation for the purpose of generating

or transmitting electricity;

vi) to promote research in matters affecting the generation, transmission and supply of

electricity.

The strength of full time members was also increased to eight including the Chairman.

The general duties which have now been assigned to the State Electricity Boards

as per the 1976 Amendment, are as under :

a) to arrange, in co-ordination with the generating company or generating companies, if

any, operating in the State for the supply of electricity that may be required within the

State and for the transmission and distribution of the same of the most efficient and

economical manner with particular reference to those areas which are not for the time

being supplied or adequately supplied, with electricity;



b) to supply electricity as soon as practicable to a licensee or other person requiring such

supply if the Board is competent under this Act so to do;

c) to exercise such control in relation to the generation, distribution and utilisation of

electricity within the State as is provided for by or under this Act;

d) to collect data on the demand for, and the use of electricity and to formulate

perspective plans in co-ordination with the generating company or generating

companies, if any, operating in the State,

Page 6

for the generation, transmission and supply of electricity within the State; and

e) to operate the generating stations under its control in co-ordination with the

generating company or generating companies, if any, operating in the State and with

the Government or any other Board or agency having control over a power system.

The major structural change in the organisation of the electricity supply industry is the

setting up of generating companies under the Central and State Governments. These

Companies were to be set up under the Companies Act. 1956. Three such generating

companies have been set up under the Central Govt. These are (1) National Thermal Power

Corporation Ltd. (2) National Hydro Electric Power Corporation Ltd. and (3) North Eastern

Regional Power Corporation Ltd. Already Mysore Power Corporation and Neyveli Lignite

Power Corporation were in operation in the Country. Damodar Valley Corporation under the

DVC Act was set up in early fifties on the pattern of TVA in USA. Another company in

public sector in operation in West Bengal is called Durgapur Projects Ltd. The board

approach of the 1976 Amendment Act is separation of generation and distribution functions

of the Electricity supply industry.

Subject to the provisions of the Electricity (Supply) Act, 1948 as amended by the

1976 Amendment Act a Generating Company shall be charged with the following

duties namely :

(a) to establish, operate and maintain such generating stations and tie-lines, substations

and main transmission lines connected therewith, as may be required to be established

by the promoting govemment or promoting government in relation to the generating

company;

(b) to operate and maintain in the most efficient and economical manner the generating

stations, tie-lines, sub-stations and main transmission fines assigned to it the

promoting government or promoting governments in co-ordination with the Board, as



the case may be, and the Government or agency having control over the power system

if any, connected therewith;

(c) to carry out, subject to the provisions of Section 21, detailed investigations and

prepare schemes, in co-ordination with the Board or Boards as the case may be, for

establishing generating stations and tielines, sub-stations and transmission lines

connected therewith, in such manner as may be specified by the Authority.

It is however provided in the 1976 Amendment Act that the Board shall, until a

Generating Company beings to operate in any State, perform the duties of a Generating

Company.

The Central Electricity Authority (CEA) is a statutory organisation constituted under

Section 3(1) of the Electricity (Supply) Act, 1948. It was established as a part time body in

1951 and made a full-time body in 1975. It is attached office of Ministry of Power,

Government of India.

Central Electricity Authority (CEA)

In all technical, financial and economic matters, the Ministry of Power is assisted by

the CEA. CEA is responsible for technical Coordination and supervision of programmes and

is also entrusted Secretary to the Government of India and has six full time Members, who

are of the rank of Additional Secretaries to the Government of India. They are - Member

(Thermal), Member (Hydro), Member (Economic & Commercial), Member (Power

Systems), Member (Planning) and Member (Grid & Operation).

Functions of the CEA

The Authority is generally to exercise such functions and perform such duties and act

in such a manner as the Central Government may prescribe under the Rules framed under

Section 4B(1) of the Electricity (Supply) Act, 1948 or by issue of written directions in

matters of policy involving public interest under Section 4A (1) of the said Act. Under

Section 3(1) of the Act, the CEA is particularly charged with the following functions :

1. To develop a sound adequate and uniform national power policy, formulate short-term

and perspective plans for power development and coordinate the activities of planning

agencies in relation to the control and utilisation of national power resources;

Page 7

2. To act as arbitrators in matters arising between the State Govemment or the Board and

a licensee or other person as provided in the Act;



3. To collect and record the data concerning generation, distribution and utilisation of

power and carry out studies relating to cost, efficiency, losses, benefits and such like

matters,

4. To make public from time to time information secured under the Act and to provide for

the publication of reports and investigation.

5. To advise any State Government, Board, Generating Company or any other agency

engaged in generation or supply of electricity on such matters as will enable such

Government, Board, generating company or agency to operate and maintain the power

system under the ownership or control in an . improved manner and where necessary in

coordination with any other agency owning or having the control of another power

system.

6. To promote and assist in the timely completion of schemes sanctioned under Chapter V

of the Act.

7. To make arrangements for advancing the skill of persons in the generation and supply

of electricity.

8. To carry out or make arrangement for any investigation for the purpose of generating or

transmitting electricity.

9. To promote research in matters affecting the generation, transmission and supply of

electricity.

10. To advise the Central Government on any other matter on which its advice is sought or.

make recommendations to that Government on any matter if, in the opinion of the

Authority the recommendation would help improving the generation, distribution and

utilisation of electricity, and

11. To discharge such other functions as may be entrusted to it or under any other law.

Under the provisions of Electricity (Sup-ply) Act, 1948, the Central Government has

further added a few more functions of the Central Electricity Authority. These are

(a) Coordination of research and development in the power generation field.

(b) Evaluation of financial performance of the SEBs constituted under Section 5 and

undertaking of studies concerning the economic and commercial aspects of the power

industry as well as analysis of the tariff structure in the power industry.

(c) Techno-economic appraisal of power projects;

(d) Promotion of inter-State and joint sector power projects.



Apart from the above-functions provided under the Electricity (Supply) Act, the CEA

also undertakes design and engineering of power projects with a view to developing in-house

technical know-how and also to assist the State Electricity Boards, Generating companies

and State authorities requiring such assistance under 3(1) (V) of the Electricity (Supply) Act,

1948.

Sub-Ordinate Offices

Following are the sub-ordinate offices of the CEA :

1. Northern Regional Electricity Board, New Delhi.

2. Western Regional Electricity Board, Bombay.

3. Eastern regional Electricity Board, Calcutta.

4. Southern Regional Electricity Board, Bangalore

5. North-Eastem Regional Electricity Board, Shillong.

6. Power System Training Institute, Bangalore.

7. Hot Line Training Centre, Bangalore.

8-11. Regional Power Survey Organisations at New Delhi, Bangalore, Bombay and

Calcutta.

12-15. Regional Inspection Organisation at Madras, Goa, New Delhi and Shillong.

1.4 MINISTRY OF POWER

The Ministry of Power started functioning independently with effect from the 2nd July,

1992. Earlier it was known as the Ministry of Energy comprising the Department of Power,

Coal and Non-Conventional Energy Sources.

The Ministry of Power is responsible for the administration of the Indian Electricity

Act, 1910 and the Electricity (SUPPIY) Act,

Page 8

1948 and to undertake such amendments to these Acts, as may be necessary from time to

time, in conformity With the Government's Policy objectives.

The Ministry of Power is mainly responsible for evolving general Policy in the field of

energy. The main items of work dealt with by the Ministry of Power are as below :

1. General Policy in the Electric Power Sector and issue relating to Energy Policy.

2. All matters relating to hydroelectric and thermal power except mini, micro hydel

projects and below 3 MW capacity and geo-thermal energy and transmission system

network.



3. Research development and technical assistance relating to hydroelectric and thermal

power and transmission system network.

4 Administration of the Indian Electricity Act, 1910, (9 of 1910), and Electricity (Supply)

Act, 1948 (54 of 1948).

5. All matters relating to Central Electricity Authority and Central Electricity Board.

6. Rural electrification, power schemes in UTs and issues relating to power. supply in

States and Union Territories.

7. All matters concerning energy conservation and energy efficiency pertaining to power

sector.

8. Matters relating to following Public Sector Undertakings/Organisations etc.

(a) Damodar Valley Corporation

(b) Bhakra Beas Management Board Corporation Ltd.

(c) National Thermal Power Corporation Ltd.

(d) National Hydro Electric Power Corporation Ltd.

(e) Rural Electrification Corporation Ltd.

(f) North Eastern Electric Power Corporation Ltd.

(g) Power Grid Corporation of India. Ltd.

(h) Power Finance Corporation Ltd.

(i) Tehri Hydro Development Corporation Ltd.

j) Nathpa Jhakri Power Corporation Ltd.

(k) Central Power Research Institute

(l) National Power Training Institute

(m) Energy Management Centre

1.4.1 Organisations under Ministry of Power

In all technical and economic matters, Ministry of Power is assisted by the Central

Electricity Authority (CEA) constituted under the Electricity (Supply) Act. 1948.

Badarpur Management Contract Cell (BMCC), a subordinate office of this Ministry is

responsible for administering the Badarpur Thermal Power Station (BTPS) Management

Contract between the Government of India and the NTPC.

The construction and operation of generation and transmission projects in the Central

Sector are entrusted to Central Sector Power Corporations, viz., the National Thermal Power

Corporation (NTPC), the National Hydro Electric Power Corporation (NHPC), the North

Eastern Electric Power Corporation (NEEPCO) and the Power Grid Corporation of India



Limited (PGCIL). The Powergrid is responsible for all the existing and future transmission

projects in the Power Sector and also for the formation of the National Power Grid. Two

Joint Venture Power Corporations namely, Nathpa Jhakri Power Corporation (NJPC) and

Tehri hydro Development Corporation (THDC) are responsible for the execution of the

Nathpa Jhakri Power project in Himachal Pradesh and Projects of the Tehri Power Complex

in Uttar Pradesh respectively. Two statutory bodies i.e., the Damodar Valley Corporation

(DVC) and the Bhakra Beas Management Board (BBMB) are also under the administration

control of the Ministry of Power. Programmes of rural electrification are provided financial

assistance by the Rural Electrification Corporation (REC) under the Ministry of Power. The

Power Finance Corporation (PFC) provides term-finance to projects in the power sector.

Further, the autonomous bodies (Societies) i.e., Central Power Research Institute (CPRI), the

National Power Training Institute (NPTI) and the Energy Management Centre (EMC) are

also under the administrative control of the Ministry of Power.

1.5 AMENDMENT OF ELECTRICITY RULES TO INCLUDE COMPULSORY

TRAINING AND CERTIFICATION IN 1981

A scheme of Compulsory Training and Certification for the power operatives has

been introduced under Rule 3, Sub-rule 2A of the Indian Electricity Rules, 1956, vide

notification

Page 9

number GSR 461 dated 8th May, 1981, which stipulates :

" No person shall be authorised to operate or undertake maintenance of any part or

whole of generating station of capacity 100 MW and above together with associated

substation unless he is adequately qualified and has successfully undergone the specified

recognised training."

The personnel engaged in the Operation and Maintenance of the generating stations

are, therefore, under the IE Rules, 1956, obliged to undergo compulsory training of specified

duration and curriculum and get a licence from the State Government, Necessary

institutional arrangements need to be made in this regard by the State Government.

While the Utilities have to arrange for the training, the Central Electricity Authority

has the following statutory functions to discharge :

(i) To recognise and institute where the specified training is arranged.

(ii) To provide consultancy in regard to the alteration of the duration and manner

of training in respect of the personnel al-ready engaged in the operation and



maintenance of the generating stations and the associated sub-stations etc.

(iii) To carry out inspection and establish and register for listing such recognised

establishments.

1.6 AMENDMENT OF ELECTRICITY ACT IN 1992 TO ENCOURAGE

PARTICIPATION OF PRIVATE SECTOR ENTER-PRISE IN ELECTRICITY

SECTOR

Government of India has formulated the policy to encourage greater participation by

privately owned enterprises in the electricity, generation, supply and distribution field Indian

Electricity Act, 1910 and Electricity (Supply) Act, 1948 have been amended in 1992 to

implement the above mentioned policy. The policy has widened the scope of private

investment in the electricity sector and has introduced modifications in the financial

administrative and legal environment to make investment in the sector by private units

attractive. Based on this policy, a scheme has been framed to encourage private enterprises

participation in electricity sector. Following are some of the salient feature of this scheme.'

i. Private sector units can set up thermal power projects-coal/lignite or gas based,

hydel projects and wind/solar energy projects of any size.

ii. Private sector entrepreneurs can set up enterprises, either as licensees, or as

generating companies.

iii. Debt equity ratio upto 4:1 is permissible for all prospective enterprise entrants

(i.e. for both licensees and generating companies) to the electricity sector, i.e., a

minimum of 20% of the total outlay should be the equity component; atleast

11% of the total outlay must come through promoters contribution. In the rest of

the total outlay, less equity, which may be upto 80% of the total project cost. an

amount not exceeding 40% of the outlay may come form Indian public financial

institutions, but the remaining amount should be met from other sources. In

other words, to ensure that the investor brings in additionality of resources to the

electricity sector, not less than 60% of the total outlay must come from sources

other than Indian public financial institutions.

iv. Upto 100% foreign equity participation, can be permitted for projects set up by

foreign private investors in the Indian electricity sector.

v. That rate of return for the licensing companies has been raised from 2% as

applicable over the RBI rate, to the investments already made, to 5% over the

RBI rate for investment made after this amendment.



vi. It has been decided to constitute a high Powered Board for faster clearances of

electricity generation, supply and distribution projects in the private sector. The

Board will comprise Secretaries of the Ministries may be co-opted to the Board.

vii. An Investment Promotion (]P) Cell has been set up in the Department of Power

to Provide information and assistance to Prospective entrepreneurs in the

electricity sector. The IP Cell will also monitor the processing of proposals for

setting up projects from the private sector units in the electricity sector and take

action for time bound clearances of the proposals PAGE 10

viii. Licensees companies will be granted licenses of a longer duration of 30 years in

the first instance and subsequent renewal of a longer duration of 20 years,

instead of 20 and 10 years respectively as was the case before the amendment to

the Indian Electricity Act.

ix. The tariff for sale of electricity will be in accordance with the normative

parameters regarding operation of PLF and in accordance with the rates of

depreciation and reasonable return and such other factors as will be determined

by the Central Govt. from time to time.

1.7 PUBLIC SECTOR UNDERTAKINGS AND OTHER ORGANISATIONS IN

POWER SECTOR

1.7.1 National Thermal Power Corporation Ltd. (NTPC)

National Thermal Power Corporation (NTPC) was set up in 1975, as a central sector

power generating company for the development of thermal power. The Corporation is at

present engaged in operating/setting up of several thermal power projects and Gas based

power projects. The total approved investment of the Corporation as on 31-3-1998 stands at

Rs. 36519.48 Crores (excluding the investment of Transmission System which have since

been transferred to Power Grid). The NTPC is at present placed in Schedule “A”.

The approved capacity of NTPC Projects is 20515 MW. The capacity commissioned

upto 31-3-1998 is 16795 MW. This includes acquisition of Unchahar (420 MW) and

Talcher (460 MW). Presently, NTPC has to its credit 12 coal based thermal power projects

and 7 gas/liquid fuel based combined power projects. Besides its own stations, NTPC also

manages the Badarpur Thermal Power Station in Delhi (705 MW) and Balco's Captive

Power Stations near Korba, Madhya Pradesh (270 MW), which was also constructed by

NTPC.

1.7.1.1 Generation



NTPC Stations

As on 31-3-1998 a total capacity of 16795 MW (including Talcher TPS - 460 MW)

was under operation at various NTPC stations. This comprises 30 units of 200/210 MW each

at Singrauli, Korba, Ramagundam, Farakka, Vindhyachal, Dadd, Unchahar and Kahalogaon,

14 units of 500 MW at Singrauli, Korba, Ramagundam, Farakkaand Talcher and 26

gas/steam turbine units of various capacities operating at gas based com-bined cycle plants at

Anta, Kawas, Dadri and Jhanor Gandhar gas based power Projects.

The generation performance 1 of NTPC Stations has consistently been at a high level.

Against the target of 99000 MUs upto 31-3-1998 (MOU excellent target for the year 1997-

98), the gross generation from NTPC stations was 106290 MUs. During the year 1997-98

the coal based units under commercial operation generate 86199.5 MUs at a plant load

factor of 75.20%.

STATIONS MANAGED BY NTPC

a) Badarpur Thermal Power Station (BTPS), Delhi

Badarpur Thermal Power Station (BTPS) (705 MW) owned by Government of India

is being managed by NTPC since lst April,1978. 100% power from this station is supplied to

DVB. During the year 1997-98, the station generated a total of 4475.5 MUs at a PLF of

72.5% against the target of 4200 MUs.

b) Balco Captive Power Plant (BCPP) (4 x 67.5 MW)

BCCP generated a total 2112.8 MUs at a PLF of 89.3%

1.7.1.2Memorandum of Understanding

NTPC is the first Power sector corporation to have signed a Memorandum of

Understanding (MOU) with the Govt. of India and has been rated "Excellent" for the tenth

consecutive year (every year since inception of MOU system of rating.)

The MOU tagets vis-a-vis achievement for the year 1997-98 in respect of major

performance parameters are given below.

Page 11 (Taarget) SI. No.

V.Good Excellent Actual (1997-98)

1. Generation (MUs) 98000 99000 106290 2. Heat Rate (Kcal/Kwh) 2480 2470 2470 3. Gross Margin (Rs. Cr.) 4044.63 4087 4. Net Profit to Capital employed % 4.63 4.97

4771.87 (Prov.) & Accounts under

finalisation



1.7.1.3 Growth Strategy NTPC is making significant contribution for the growth of the economy by generating

more than 1/4th of the electricity generated in the country. Also NTPC continued its

multipronged Strategy for capacity addition to maintain/augment its share in the country’s

installed generating capacity through green field projects, expansion of its existing plants,

acquisition of SEB’s plants and forming joint ventures.

During VIII plan period (1992-97) NTPC added 5002 MW capacity and acquired 460

MW Talcher TPP from Orissa SEB thus taking the total capacity addition to 5462 MW.

1.7.1.4 Ninth Plan

NTPC is planning to add 6300 MW in the IX plan. This includes a new generating

capacity of 1370 MW under construction. Details of which are as under :

Capacity under Construction :

The following projects for which investment approval has been taken up for

implemention and are scheduled to be commissioned in the IX plan period :

Project (Location) Capacity (MW) Capacity Addition in IX Plan (MW)

Commissioning Schedule

Vindhyachal-II 1000 1000 Feb.' 2001

(Madhya Pradesh) Unchahar-II 420 420 Jul.' 2000

(Uttar Pradesh) Kayamkulam 350 350 Mar.' 2000

(Kerala) Faridabad 430 400 Jan.' 2000

(Haryana) Simhadri 1000 1000 March.' 2002

(Andhra Pradesh)

Total 3200 3170

1.7.1.5 Beyond IX Plan

NTPC is also planning to add 7500-8000 MW beyond the IX Plan.

1.7.1.6 Joint Ventures

a) Utility Powertech Ltd. (UPL) – joint venture of NTPC – BSES :

UPL has been incorporated for Construction, Erection and Project management work

in Power sector and other sectors in India and abroad. UPL has raised the authorized share



capital from Rs. 50 Lakhs to Rs. 2 Crores and addtional equity of Rs. 93.10 Lakhs has been

subscribed by NTPC. NTPC and BSES have devided for award of contracts to UPL on cost

plus basis upto the value of Rs. 5 Crores.

b) JV for Ash Utilisation

A proposal has been approved by NTPC management for setting up of a fly-ash bricks

plant at Badarpur with a capacity of producing 5 lakh bricks per day in Joint Venture with a

prospective partner. A commitee has been constituted to evaluated the proposal and signing

of MOU with the joint venture partner.

Page 12

Details of NTPC Projects showing aggregate approved capacity of 20515 (MW)

A. Unit Commissioned. S. No. Name of the Region/

Project/State Approved Capacity

in MW Actual data of

Commissioning NORTHERN REGION

1 Singrauli STPP 2000 Unit-1 (200) Feb. 82 Uttar Pradesh Stage-I Unit-2 (200) Nov. 82 (3x200) Unit-3 (200) Mar. 83 stage-II Unit-4 (200) Nov. 83 (2x200+500) Unit-5 (200) Feb. 84 Unit-6 (500) Dec. 86 Unit-7 (500) Nov. 87 2 Rihand STPP 1000 Unit-1 (500) Mar. 88 Uttar Pradesh Stage-I Unit-2 (500) July 89 (2x500) 3 National Capital 840 Unit-1 (210) Oct. 91 Thermal Power Stage-I Unit-2 (210) Dec. 92 Project (Dadri) (4x210) Unit-3 (210) Mar. 93 Uttar Pradesh Unit-4 (210) Mar. 94 4 Dadri GBPP 817 Gas Turbine Uttar Pradesh Stage-I Unit-1 (131) Frb. 92 (4x131+2x146.5) Unit-2 (131) Mar. 92 Unit-3 (131) June 92 Unit-4 (131) Oct. 92 Steam Turbine Unit-5 (146.5) Feb. 94 Unit-6 (146.5) Mar. 94 5 Unchahar TPP 420 Unit-I (210) Nov. 88 Uttar Pradesh Stage-I Unit-2 (210) Mar. 89 (2x210) 6 Auraiya GBPP 652 Gas Turbine Uttar Pradesh Stage-I Unit-1 (112) Mar. 98 (4x112+2x102) Unit-2 (112) July 89 Unit-3 (112) Aug. 89 Unit-4 (112) Sept. 89 Steam Turbine Unit-5 (102) Dec. 89 Unit-6 (112) June 90



7 Anta GBPP 413 Gas Turbine Rajasthan Stage-I Unit-1 (88) Jan. 89 (3x88+1x149) Unit-2 (88) Mar. 89 Unit-3 (88) May 89 Steam Turbine Unit-4 (149) Mar. 90

Page 13 S. No. Name of the Region/




1 Singrauli STPP 2000 Unit-1 (200) Feb. 82 Uttar Pradesh Stage-I Unit-2 (200) Nov. 82 (3x200) Unit-3 (200) Mar. 83 stage-II Unit-4 (200) Nov. 83 (2x200+500) Unit-5 (200) Feb. 84 Unit-6 (500) Dec. 86 Unit-7 (500) Nov. 87 2 Rihand STPP 1000 Unit-1 (500) Mar. 88 Uttar Pradesh Stage-I Unit-2 (500) July 89 (2x500) 3 National Capital 840 Unit-1 (210) Oct. 91 Thermal Power Stage-I Unit-2 (210) Dec. 92 Project (Dadri) (4x210) Unit-3 (210) Mar. 93 Uttar Pradesh Unit-4 (210) Mar. 94 4 Dadri GBPP 817 Gas Turbine Uttar Pradesh Stage-I Unit-1 (131) Frb. 92 (4x131+2x146.5) Unit-2 (131) Mar. 92 Unit-3 (131) June 92 Unit-4 (131) Oct. 92 Steam Turbine Unit-5 (146.5) Feb. 94 Unit-6 (146.5) Mar. 94 5 Unchahar TPP 420 Unit-I (210) Nov. 88 Uttar Pradesh Stage-I Unit-2 (210) Mar. 89 (2x210) 6 Auraiya GBPP 652 Gas Turbine Uttar Pradesh Stage-I Unit-1 (112) Mar. 98 (4x112+2x102) Unit-2 (112) July 89 Unit-3 (112) Aug. 89 Unit-4 (112) Sept. 89 Steam Turbine Unit-5 (102) Dec. 89 Unit-6 (112) June 90 7 Anta GBPP 413 Gas Turbine Rajasthan Stage-I Unit-1 (88) Jan. 89 (3x88+1x149) Unit-2 (88) Mar. 89 Unit-3 (88) May 89 Steam Turbine Unit-4 (149) Mar. 90 SOUTHERN REGION 8 Ramagundam STPP 2100 Unit-1 (200) Nov. 83 Andhra Pradesh Stage-I Unit-2 (200) May 84 (3x200+1x500) Unit-3 (200) Dec. 84 Unit-4 (500) June 88 Stage-II Unit-5 (500) Mar. 89 (2x500) Unit-6 (500) Oct. 89 EASTRN REGION 9 Farakka STPP 1600 Unit-1 (200) Jan. 86 West Bengal Stage-I Unit-2 (200) Dec. 86 (3x200) Unit-3 (200) Aug. 87



Stage-I Unit-4 (500) Sept. 92 (2x500) Unit-5 (500) Feb. 94

10 Kahalgaon STPP 840 Unit-1 (210) Mar. 92 Bihar Stage-I Unit-2 (210) Mar. 94 (4x210) Unit-3 (210) Mar. 95 Unit-4 (210) Mar. 96

11 Talcher TPP 1000 Unit-1 (500) Feb. 95 Orissa Stage-I Unit-2 (2x110 MW) 1982-1983 (2x500)

12 Talcher Tpp 460 Stage-I (4x60 MW) 1967-1969 (taken over From) (4x60+2x110) Stage-II (2x110 MW) 1982-1983 OSEB on 3-6-95 WESTERN REGION

13 Korba STPP 2100 Unit-1 (200) Mar. 83 Madhya Pradesh Stage-I Unit-2 (200) Oct. 83 (3x200+1x500) Unit-3 (200) Mar. 84 Unit-4 (200) May 87 Stage-II Unit-5 (500) Mar. 88 (2x500) Unit-6 (500) Mar. 89

14 Vindhyachal STPP 1260 Unit-1 (210) Oct. 87 Madhya Pradesh Stage-I Unit-2 (210) July 88 (6x210) Unit-3 (210) Feb. 89 Unit-4 (210) Dec. 89 Unit-5 (210) Mar. 90 Unit-6 (210) Feb. 91

15 Kawas GBPP 645 Gas Turbine Gujarat Stage-I Unit-1 (106) Mar. 92 (4x106+2x110.5) Unit-2 (106) May. 92 Unit-3 (106) June 92 Unit-4 (106) Aug. 92 Steam Turbine Unit-5 (110.5) Feb. 93

Unit-6 (110.5) Mar. 93 Page 14

S. No. Name of the Region/ Project/State

Approved Capacity in MW

Actual data of Commissioning

NORTHERN REGION 1 Singrauli STPP 2000 Unit-1 (200) Feb. 82 Uttar Pradesh Stage-I Unit-2 (200) Nov. 82 (3x200) Unit-3 (200) Mar. 83 stage-II Unit-4 (200) Nov. 83 (2x200+500) Unit-5 (200) Feb. 84 Unit-6 (500) Dec. 86 Unit-7 (500) Nov. 87 2 Rihand STPP 1000 Unit-1 (500) Mar. 88 Uttar Pradesh Stage-I Unit-2 (500) July 89 (2x500) 3 National Capital 840 Unit-1 (210) Oct. 91 Thermal Power Stage-I Unit-2 (210) Dec. 92 Project (Dadri) (4x210) Unit-3 (210) Mar. 93 Uttar Pradesh Unit-4 (210) Mar. 94 4 Dadri GBPP 817 Gas Turbine Uttar Pradesh Stage-I Unit-1 (131) Frb. 92 (4x131+2x146.5) Unit-2 (131) Mar. 92 Unit-3 (131) June 92 Unit-4 (131) Oct. 92 Steam Turbine



Unit-5 (146.5) Feb. 94 Unit-6 (146.5) Mar. 94 5 Unchahar TPP 420 Unit-I (210) Nov. 88 Uttar Pradesh Stage-I Unit-2 (210) Mar. 89 (2x210) 6 Auraiya GBPP 652 Gas Turbine Uttar Pradesh Stage-I Unit-1 (112) Mar. 98 (4x112+2x102) Unit-2 (112) July 89 Unit-3 (112) Aug. 89 Unit-4 (112) Sept. 89 Steam Turbine Unit-5 (102) Dec. 89 Unit-6 (112) June 90 7 Anta GBPP 413 Gas Turbine Rajasthan Stage-I Unit-1 (88) Jan. 89 (3x88+1x149) Unit-2 (88) Mar. 89 Unit-3 (88) May 89 Steam Turbine Unit-4 (149) Mar. 90 SOUTHERN REGION 8 Ramagundam STPP 2100 Unit-1 (200) Nov. 83 Andhra Pradesh Stage-I Unit-2 (200) May 84 (3x200+1x500) Unit-3 (200) Dec. 84 Unit-4 (500) June 88 Stage-II Unit-5 (500) Mar. 89 (2x500) Unit-6 (500) Oct. 89 EASTRN REGION 9 Farakka STPP 1600 Unit-1 (200) Jan. 86 West Bengal Stage-I Unit-2 (200) Dec. 86 (3x200) Unit-3 (200) Aug. 87 Stage-I Unit-4 (500) Sept. 92 (2x500) Unit-5 (500) Feb. 94

10 Kahalgaon STPP 840 Unit-1 (210) Mar. 92 Bihar Stage-I Unit-2 (210) Mar. 94 (4x210) Unit-3 (210) Mar. 95 Unit-4 (210) Mar. 96

11 Talcher TPP 1000 Unit-1 (500) Feb. 95 Orissa Stage-I Unit-2 (2x110 MW) 1982-1983 (2x500)

12 Talcher Tpp 460 Stage-I (4x60 MW) 1967-1969 (taken over From) (4x60+2x110) Stage-II (2x110 MW) 1982-1983 OSEB on 3-6-95 WESTERN REGION

13 Korba STPP 2100 Unit-1 (200) Mar. 83 Madhya Pradesh Stage-I Unit-2 (200) Oct. 83 (3x200+1x500) Unit-3 (200) Mar. 84 Unit-4 (200) May 87 Stage-II Unit-5 (500) Mar. 88 (2x500) Unit-6 (500) Mar. 89

14 Vindhyachal STPP 1260 Unit-1 (210) Oct. 87 Madhya Pradesh Stage-I Unit-2 (210) July 88 (6x210) Unit-3 (210) Feb. 89 Unit-4 (210) Dec. 89 Unit-5 (210) Mar. 90 Unit-6 (210) Feb. 91

15 Kawas GBPP 645 Gas Turbine Gujarat Stage-I Unit-1 (106) Mar. 92 (4x106+2x110.5) Unit-2 (106) May. 92 Unit-3 (106) June 92 Unit-4 (106) Aug. 92 Steam Turbine Unit-5 (110.5) Feb. 93 Unit-6 (110.5) Mar. 93

16 Gandhar GPP 648 Gas Turbine



Gujarat (3x131+1x255) Unit-1 (131) Mar. 94 Unit-2 (131) Mar. 94 Unit-3 (131) Mar. 94 Steam Turbine Unit-4 (255) Mar. 95 Sub-Total 16795 MW

B. SCHEDULED TO BE COMMISSIONED BEYOND 1997-98 S. No. Name of the Region/




1 Unchahar Tpp 420 Unit-3 (210) Jan. 2000 (Ant.) Uttar Pradesh Stage-II Unit-4 (210) Jul. 2000 (Ant.) (2x210) Gas/Steam Turbine 2 Faridabad GPP 400 GT-1 Jan.' 2000 (Ant.) Haryana GT-2 Mar.' 2000 (Ant.) ST-1 Jan.' 2000 (Ant.) SOUTHERN REGION 3 Kayamkulam CCPP 400 Gas/Steam Turbine Kerala G.T.Uni-1 Mar.' 99 (Ant.) G.T.Unit-2 May.' 99 (Ant.) S.T. Unit-3 Mar.' 2000 (Ant.) 4 Simhadri TPP 1000 Unit-1 Mar.' 20025 (Ant.) (2x500) Unit-2 Dec.' 2002 (Ant.) WESTERN REGION 5 Vindhyachal STPP 1000 Unit-7 (500) Feb.' 2000 (Ant.) Madhya Pradesh Stage-II Unit-8 Feb.' 2001 (Ant.)

(2x500) Sub-Total 3220 MW

C. Units Yet to be Decided S. No. Name of the Region/



Commissioning EASTERN REGION

1 Farakka STPP 500 Ubit-6 (500) West Bengal Stage-III Yet to be decided. (1x500) The project not taken up due to low demand of electricity in Eastern Region. Total 500 MW

Grand Total (A+B+C) = 20515 MW (Approved Capacity)

NB: Capacity commissioned upto March, 1998 is 16795 MW.

Page 15

1.7.2.1 National Hydroelectric Power Corporation Ltd. (NHPC)



National Hydroelectric Power Corporation Ltd. (NHPC) was incorporated in . 1975

under Companies Act, 1956. The main objectives of the corporation are to plan, promote

and organise an integrated development of hydroelectric power in the country. The

authorised Share Capital of the corporation is Rs. 3500 Crores. NHPC is a Schedule 'A'

Enterprise of the Govt. of India.

1.7.1.2.1 Status of ongoing Projects

1.71.2.1,1 URI Project (480 MW) J & K

Uri Project (480 MW) in J & K was completed well within the scheduled time. The

project started commercial generation w.e.f. 1-6-1997.

1.7.2.2 Rangit H.E. Project (3x20 MW), Sikkim

Excavation of main Dam has been completed (68,000 cum). Further 23500 cum

(26%) of concrete has been placed in the dam against the total concreting of 92000 Cum.

The river has been diverted and further action has been initiated to start concerting 1398m

tunnel excavation of HRT from upstream side has been completed against the total length of

1558 m. Concreting in intake tunnel - 1 & II and silt flushing tunnels and excavation of gate

operation chamber of desilting chambers completed. Excavation and concrete lining of

surge shaft, 110 m deep pressure shaft 3 nos. penstocks completed. Erection of steel liner for

pressure 'shaft is progress. In Power House, service bay has been completed. The erection

of Unit-1,2 & 3 upto pit liner has been completed. The Stator core for Unit-1,2 & 3 has been

built up. About 99% of equipment has been received at Project site. The project is

scheduled for completion by march 1999. ,

1.7.2.3. Dulhasti H.E. Prqfect (3x130 MW, J & K

The contract for balance civil works has been awarded to M/s JSA(JV) and agreement

Was signed on 09-04-97. The new contractor has started work at site. In dam structure 36%

concreting has been completed. In HR 41% excavation has been completed. Excavation of

Power House Cavern, Transformer Cavern expansion gallery, and Switchyard has been

completed. Concreting of -transformer cavern is also in progress. The project is schduled

for completion by March 2001.

1.7.2.4 Dhautiganaga H.E. Project, Stage-1 (4x70 MW), U.P.

The forest and defence land have been acquired. Private land at Tapovan and Dobat

measuring 3.27 ha. have been taken over and development work for colony construction and

job facilities is in progress. 7.35 ha. pf private land st Nigalpani meant for main colony and

project headquarter taken over in by the project after payment of compensation to the



owners. For private land measuring 13.95 ha. coming under submergence, the award has

been approved by Commissioner, Kumaon in May '97. The work on infrastructire and pre-

construction activities started. Activities like temporary housing, development of benches

and protection works besides access and haul roads have been taken up. The work of

improvement of/Tanakpur-Tawaghat Road, being executed by Border Roads Organisation,

has been stopped for want of forestland.

The second tranche of OECF loan amounting to 16316 million Yen has become

effective from 9.2.98. The project is scheduled for completion by Sept. 2004.

1.7.2.5 Koel Karo H.E. Project (710 MW), Bihar

Work of the project could not be started due to paucity of funds and local resistance.

The project was posed to OECF for their financial assistance during 1996-97 and details of

the project execution were presented to OECF Fact Finding Mission. The response from

OECF in the matter has not been favourable. CEA has justified the execution of Koel Karo

Project even after considering coming up of Purulia H.E. Project in West Bengal. Central

Empowered Committee (CEC) recommended freezing of further expenditure on Koel Karo

Project. It was been decided to pose this project to OECF or other financing agencies for

financing the, project.

1.7.2.6 Kalpong H.E. project (2.25 MW) A & N

The execution of the project has been entrusted to NHPC as a deposit work with the

funds to be provided by A & N Island Authorities. The MOE & F has accorded the

clearance for diverting right fork of the river for additional power generation. The installed

capacity has increased

PAGE 16

to 5.25 MW (3xl.75MW) from the- original 2.25 MW. Revised tender documents of civil

works have been finansed after incorporating the increased scope of work due to clearance of

right fork.

1.7.2.7 Kurichu H.E. Project (3x1SMW), Bhutan

NHPC has been entrusted with the execution of Kurichu Hydroelectric Project in

Bhutan and an agreement was signed Kuhchu Project authority of Bhutan (KPA) and NHPC

on 27.9.1995. The infrastructure and pre-construction activities are progressing satisfactorily.

The diversion tunnel was daylighted on 14th Nov. 1997 and the benching and concreting

lining is in progress. The excavation of left abutment of dam realignment of road beyond

dam axis have done. The work of open excavation of power house is in progress. The order



for supply pf main generating equipment i.e. Turbine and Generators have been placed on

Mls BHEL and manufacturing of the same has been started. For Power Transformers and

E.O.T. Crane tenders received are under technical evaluation. The preliminary survey of 67

km long 132 kv s/c transmission line has been completed. The technical specification for

transmission line works has been accepted by WAPCOS.

1.7.2.8 New Schemes

1.7.28.1Chamera H.E. Project, Stage-ii (3x10OMW), H.P.

.The tenders were received for turnkey execution with external financial assistance.

Negotiations did not result in an acceptable and the offer considered by NHPC as

unacceptable. PiB desired fresh TEC form CEA and exploring the possibility of financing

package by indigenous financers and suppliers.

1.7.2.8.2 Teesta H. E. Project, Stage- V (51OMW), Sikkim

Teesta H.E. Project located in East Sikkim is a run of the river peaking scheme identified

on Teesta river. The installed capacity of the Project is 510 MW to generate 2172 MUs of

electricity in a 90% dependable years, Techno economic clearance for estimated project cost

of Rs. 1925.44 crores including IDC of 477.31 crores at March 1993 price level was

accorded by CEA in May 1993 and anticipated construction period of the project as 8 years.

Sikkim Govt. has decided the execution of this project through NHPC. Accordingly NHPC

completed necessary pre-construction investigations activities. DPR updating, observation

of Hydrological/ meteorological data and statutory clearances are under progress. NHPC is

firming up the final project cost estimate, construction equipment planning etc. for

submission of report for PIB clearance.

1.7.28.3Loktak Downstream H.E. Project (90MW) Manipur.

Loktak Downstream H.E. Project is located in the Tomenglong District of Manipur.

The Project envisages harnessing of hydro potential of utilising the tail water discharge of

Loktak H.E. Project. The project is expected to generate 464 MUs of energy in a 90%

dependable year. The project was accorded techno-econimic clearance by Central Electricity

Authority in Jan. 93 for an estimated cost of Rs. 418.05 crs. (June 92 Price Level). The

project has also been accorded Environmental & Forest clerance by MOEF. The State Govt.

has agreed 'in principle' of the execution of this project in the central sector through NHPC.

The project has been posted for OECF assistance during 1998-99.

1.7.3 Rural Electrification Corporation@ Limited



Rural Electrification Corporation (REC) was set up in 1969 with the primary

objective of providing financial assistance for rural electrification in the country. REC was

declared a public financial institution under Section 4-A of the Companies Act in 1992,

Rural Electrificati, Programmes financed by the Corporation cover electrification of villages

including tribal villages and Dalit Bastis, energisation of pumpsets, provision of power for

small, agro based and rural industries, lighting of rural household and street lighting. The

Corporation has been providing assistance to the State Electricity Boards for taking up

System Improvement Projects for strengthening and improving of system transmission and

distribution system and small generation power projects like wind energy and hydel projects.

REC is a schedule 'B' Organization.

During the year 1997-98, REC approved 1261 new projects involving a loan

assistance of

PAGE 17

about Rs. 1214 crores for electrification of 4459 new villages, energisation of 1.96 lakhs

pumpsets besides provision of electricity to other categories of service, electrification of

Dalit Bastis and Hamlets etc. The Corporations has (cummulatively upto March 1998

sanctioned 33187 RE Projects invovling financial assistance of over Rs. 14724 crores for

electrification of about 3.24 takh new villages and energisation of over 68 lakh pumpsets

besides provisions of electricity to other categories of services and electrification of Dalit

Bastis.

1.7.3.1 Physical Achievement

During the year 1997-98, against the target of 3000 villages and energisation of 2.4

lakh irrigation pumpsets, provisionally 3010 villages were reported electrified and 2.41 lakh

pumpsets energised. The annual plan targets'of village electrification and pumpsets were

thus exceeded.

Cumulatively, upto March, 1998 over 2.99 lakh villages have been electrified and 70.6

lakh pumpsets energised under schemes. The level of rual electrification in the country as a

whole stood at 12.8%. at the time of establishment of th Corporationm has been risen to 85%

(revised as per 1991 census) at the end of the March, 1998. Similarly, the number of

pumpsets energised which stood at 10.9 lakhs at the time of setting up of the Corporation in

1969 has sharply risen to over 118 lakhs.

1.7.4 North Eastern Electric power Corporation (NEEPCO)



The North Eastern Electric Power Corporation Ltd. (NEEPCO) was constituted in 1976

under the Company's Act 1956 with the objective of development of power generation

projects which in turn would effectively promote the development of the North Eastern

region. Since then NEEPCO has grown into one of the pioneer public sectors with an

authorised share ceipital of Rs. 1500.00 Crores. It is a schedule 'B' organisation.

The North Eastern Region of the country is blessed with highest hydro power potential

Of the country which is estimated at 48,000 MW constituting about 33% of the total reserves

of the country. The region has abundant natural gas reserves. There is ample scope of

development in this under developed region, where the main infrastructure has been

identified as power.

The main objectives of the North Eastern Electric Power Corporation are to add to the

power generating capacity in the North Eastern Regionby installing hydro and thermal

power plants; to ensure optimum utilislation of commissioned generation projects; to

generate adequate internal resources by ensuring justifiable return on investment and to

continue sustained efforts to obtain the receivable from State Electricity

Boards/Departments; to undertake long term feasibility studies for optimum development of

hydro power resources of river basins in North Eastern Region.

Out of a total effective installed capacity of 1638.43 MW (Grid) in the North Eastern

Region, NEEPCO is contributing 595 MW through its kopili Hydro Electric Projects and

Assam Gas Based Power Projects, Kathaigud under 0 & M. During 1997-98 NEEPCO has

been able to synchronise 2ST units each 30 MW of Assam Gas Based combined cycle

project and 4 units each of 21 MW of Agratala Gas Based Power Project in Tripura. lnspite

of having only 36.3% of the installed capacity in the region the Corporation has been able to

meet more than 40% of the peak demand/energy needs of the region. The Corporation

achieved a capacity addition of 251 MW within the 8th Five Year Plan and another 144 MW

in the year 1997-98. In 199899 a capacity addition of 80 MW has been targetted to be

achieved. In addition, the Corporation proposes a capacity addition of 405 MW of

Ranganadi HE Project (ongoing) and 25 MW of Doyang HE Project (ongoing) during

remaining period of 9th Plan.

The Corporation also proposes to take up the following new schemes during 9th Plan :

(a) Tudal HE Project (Mizoram ) - 60 MW

(b) Tuivai HE Project (Mizoram)/- 210 MW

(c) Kameng HE Project (Arun-ac6al Pradesh) - 600 MW



(d) Lower Kopiti HE Project (Assam) 150 MW

(e) Kopili HE Project - 2nd Stage (Assam) 25 MW PAGE 18

(f) Dikrong HE Project (Arunachal Pradesh) - 100 MW

(g) Ranganadi HE Project - 2nd State (Arunachai Pradesh) - 180 MW

(h) Sissid HE Project (Arunachal Pradesh) -225 MW

(i) Kolodyne HE Project (Mizoram) - 90 MW

POWER PROJECTS UNDER OPERATION AND MAINTENANCE (COMPLETED)

(1) Kopiti Hydro Electric Project (150 MW) Assam

(2) Kopiii Hydro Electric Project (lst stage -extension - 100 MW) Assam

ON GOING PROJECTS (GENERATION)

(1) Dayang HE Project (75 MW) - Nagaland

(2) Ranganadi HE Project (405 MW) -Arunachal Pradesh

(3) Assam Gas based combined cycle Power Project (291 MW) - Assam

1.7.5 Power Finance Corporation Limited

The Power Finance Corporation Limited(PFC) was incorporated on 10th July, 1986

under the companies Act, 1956 to function as the prime Development Financial Institution

for growth and overall development of the Power Sector. The borrower-portfolio of PFC

comprises the State Electricity Boards (SEB's), State Generation Corporations (SGCs),

Municipatity-run power utilities. The funds provided by the Corporat.ion are in the nature of

additionality of plan allocation (in respect of SEB's etc.) and based on the merits of the

individual projects. As on 31st March, 1998, the Authorised Capital and the paid-up (equity)

capital of the Corporation stood at Rs. 2000 Crores and Rs. 1030 Crores respectively. The

PFC is a schedule 'A' organisation.

1.7.5.1 Performance Highlights

The operations of the Corporation, as on 31st March, 1998, included new Loan

Sanctions during the year 1997-98, are of the order of Rs. 2922 Corors, for a wide variety of

power projects in various parts of the country and disbursements are to the tune of Rs. 2026

Crores.

The Corporation had declared a dividend of Rs. 48 Crores for the year 1996-97. to the

Government of India which owns all its equity. Besides this, PFC had paid an interim

dividend of Rs. 15 Crores to Government of India for the year 1997-98. Being a consistenity

profit making Corporation, PFC was placed in the highest category of 'Excellent' of the



fourth time in succession, by the Government of India on the basis of its all round

performance.

During the year, PFC had launched a tax- free bonds issue (through book-building

process) of Rs. 100 Crores with green shoe option of Rs.75 crores. The significant feature of

this issue is that the cut-off rate came to 8.85% which is a benchmark set by PFC for tax-free

bonds.

1.7.6 Power Grid Corporation of India Limited

The Power Grid Corporation of India Limited (PGCIL) was incorporated as a

Government of India enterprise on October 23, 1989 under the Companies Act, 1956 as a

limited Company with an authorised capital of Rs. 5000 Crores. The mandate of the

Corporation, in terms of corporate mission, is establishment and operation of Regional and

National Power Grids to facilitate transfer of power with and across the Regions with

reliability, security and economy, on sound commercial principles. In line with the mission,

POWERGRID set the following objectives :

• Efficient operation and maintenance of transmission systems-

• Strengthen Regional Power Gdds and establish Inter Regional links leading to

formation of National Grid.

• Establishment/augment Regional load despatch centres and communication facilities.

• Introduce rational tariff Structure for exchange or Power.

• Establish Power Pools to facilitate exchange of power between States/Regions leading

to formation of National Power Grid.

• Achieve constructive cooperation and build professional relations with stake-holders

peers and other related organisations.

1.7.6.1 Significant Achievements

OPERATIONAL

As on March 31, 1998, POWERGRID operates a total of 31250 CKMs transmission

PAGE 19

lines consisting of 23415. CKMs of 400 KV, 5080 CKMs of HVDC system distributed over

54 substations with over 24000 MVA of transformation capacity' Overall average

availability of transmission lines during the year was 98.9% which is comparable with

international standards.

1.7.6.2 Powergrid Projects



The projects undertaken by POWERGRID are broadly classified as Generation

Linked Projects; Grid Strengthening Projects; Inter-regional Links; and Unified Load

Despatch and Communication Schemes. Further, in view of the entry of the Power Sector,

POWERGRID is also contemplating possible investments toward implementation of

transmission projects related to IPP projects.

1.7.6.3 Generation Linked Projects

During the 8th Five Year Plan, POWERGRID met all its commitments for.providing

transmission services for evacuation under Central Sector. Major projects commissioned by

the organisation during this period are Uri transmission system, Gandhar transmission

system, Salal II transmission system, Kathalguri transmission system (part) etc. To meet the

requirements of evacuation and dispersal of power, POWERGRID is executing important

schemes like Nathpa-Jhakri (400 KV), RAPP-B (220 KV), Vindhyachal Stage 11 (400 KV)

and Vindhyachal Additional (400 KV), Kayamkulam (200 KV), and Kathalguri (400 KV)

During the last financial year none of the generating stations associated with POWERGRID's

evacuation system was affected by non availability of lines.

1.7.7 Tehri Hydro Development Corporation (THDC)

The Tehri Hydro Development Corporation (THDC) was incorporated on 12th July,

1988, as a joint venture of the Government of India and Government of Uttar Pradesh, to

execute the Tehri Hydro Power Complex (2400 MW) in Garhwal District of U.P. and also to

plan, promote and organise the development and harnessing of such other hydro electric

sites/projects in Bhagirathi, Bhilangana valley as may be entrusted to the Corporation by the

Government. The Corporation has an authorised share capital of Rs. 2000 Crores.

The Corporation is presently engaged in the implements of Tehri Projects (Stage 1)

(1000 MW). The cost of the project is being shared in the ratio of 75:25 (equity portion) for

Power Cornponent, while the Irrigation Component (20% of Stage-1) is to be entirely funded

by the Government of Uttar Pradesh.

The Tehri Power Complex Comprises of four components viz., (i) the 260.5 M high

rock fill Tehri Dam and 1000 MW Hydro Power Plant (HPP) (Stage 1 of the Complex); (ii)

103.5 high concrete Dam with 400 MW Hydro Power Plant at Koteshwar 22 KM

downstream of Tehri; and . (iii) 1000 MW Pump Storage Plant (PSP) situated just

downstream of the confluence of Bhagirathi and Bhilangana rivers at Tehri, alongwith 800

KV Associated Transmission System for evacuation of power from the Tehri Hydro Power

Complex to be executed by Powergrid Corporation of India.



1.7.8 Nathpa Jhakri Power Corporation Ltd.

The Nathpa Jhakri Power Corporation Limited (NJPC) was incorporated on May 24,

1988 as a joint venture of the Government of India and the Government of Himachal

Pradesh, to plan promote organise and execute Hydro-electric Power Projects in the Satluj

river basin in the Himachal Pradesh. The authorised share capital of NJPC is Rs. 2200 crores

with dept equity ratio as 1:1.

NJPC is presently executing its first project namely Nathpa Jhakri Hydroelectric

Power Project (NJHPP) with an installed capacity of 1500 MW in the Kinnaur and Shimla

districts of Himachal Pradesh.

The World Bank has sanctioned a loan of US $ 437 million for part financing of the

project and the Govt. of India and the Govt. of Himachal Pradesh are sharing the equity

capital in the ratio 3:1 respectively. NJPC also plan to take up investigations of new

hydroelectric projects in the Satluj river in the Himachal Pradesh.

In the implementation of its first project NJPC is supported by CWC and CEA as the

Principal Consultants, along with the consortium of Nippon Koei, Japan; Electrowatt,

Switzerland'; and WAPCOS, India as the Retainer consultants. Besides these, NJPC is also

backed by the services of a Panel of Experts, comprising both nationally / intemationally

renowned professional and an Advisor (ENVIR & R).

PAGE 20

1.7.8.1 Nathpa Jhakri Hydroeictric Power Project (6x250 MW)

The Nathpa Jhakri Hydroelectric Power Project envisages the construction of :

A 60.50 m. high concrete Dam on Satluj river at Nathpa to divert 405 cumecs of water

through four Intakes.

An underground Desilting Complex, comprising four chambers, each 525 m. long,

1631 m. wide and 27.Sm deep, is one of the largest underground complex in the World.

A 10.15 m. dia. and 27.3 km. long Head Race Tunnel (one of the longest hydro power

tunnel in the World), terminating in 21 m. dia and 301 m. deep surge shaft. Three circular

steel-liner pressure shaft each of 4.9m. dia and 633m. long bifurcating near the power house

to feed six generating units.

An underground Power House with a cavern size of 222 m. x 20 m. x 49 m. having

six Francis Units of 250 MW each to utilise a discharge of 405 cumecs; and design head of

425 m.



A 10.15 m. dia and 982 m log Tail Race Tunnel to discharge the water back into the

river Satluj.

1.7.9 Damodar Valley Corporation

1.7.9.1 Organisation and Objectives

The Damodar Valley Corporation (DVC) was established on July 7, 1948 under

the Damodar Valley Corporation Act. The Corporation has a full time Chairman and two

part time Members. The part time Members represent the States of Bihar and West Bengal.

The objectives of the Corporation include:

• Flood Control

• lrrigation and Water supply for industrial and Domestic use

• Generation, Transmission and Distribution of Electrical Energy

• Promotion of Afforestration and control of soil erosion in the Damoder valley; and

• Promotion of industrial, Economic and General well-being of the people in the

Damodar Valley and its areas of operation.

1.7.9.2 DVC Power system

DVC has also constructed five thermal power stations, three hydel power stations and one

gas turbine station. The existing power plants of DVC are :

THERMAL

Bokaro A 175 MW (3x45 MW) & (1 x40 MW)

Bokaro B 630 MW (3x21 0 MW)

Chandrapur 750 MW (3xl 30 MW) & (3xl 20 MW)

Durgapur 350 MW (1 xl 40 MW) & (1 x21 0) MW)

Mejia TPS (Unit I) 210 MW (1 x21 0 MW)

(Unit II) 210 MW (1 x21 0 MW) –oil synhronised

(Unit III) 210 MW (1 x21 0 MW) Commissioned on 25.3.98

GAS TURBINE

GTP, Maithon 82.5 MW (3x27.5 MW)

HYDEL

Titaiy 4 MW (2x2 MW)

Maithon 60 MW (3x20 MW)

Panchet 80 MW (2x40 MW)



DETAILS OF DVC NETWORK

POWER

Total Installed Capacity : 2761.5 MW

Thermal Power Station : Six (Capacity 2535 MW)

(including Mejia TPS Unit-1, 11 & 111)

Hydel Power Station : Three. (Capacity 144 MW)

Gas Turbine Station : One (Capacity 82.5 MW) PAGE 21

Power Expansion Programme : Mejia Thermal 630 MW (3x210 MW)

Unit I : Synchronized with coal on 25.3.96

Unit II : Synchronized with oil on 24.3.97

Unit III : Commissioned on 25.3.98

Mejia Stage-II 500 MW

Maithon Thermal (Proposed) 1000 MW

Combined Cycle Gas Turbine Stn. (3x15 MW extra)

Sub. Stns. & Receiving Stns. : At 220 KV : 7

At 132 KV : 31

At 33 KV : 14

Transmission Line : At 220 KV : 1121 Circuit KM

At 132 KV : 3146 Circuit KM

At 33 KV : 1004 Circuit KM

WATER MANAGEMENT

Major Dams and Barrages : Tilaiya, Konar, Maithon, Panchet and Durgapur

Barrage

Irrigation Command Area (Gross) : 5.69 Lakh hectares

Irrigation Potential Created : 3.64 Lakh hectares

Floor Reserve Capacity : 1295 million cu.m.

Cannals : 2495 KM

SOIL CONSERVATION

Forest, Farms, Upland &

Wasteland Treatment : 4 L-akh hac. (approx.)

Chek Dams : 8,400

1.7.10 Bhakra Beas ManagementBoard



Bhakra Management Boards (BMB) was constituted under section 79 of the Punjab

Reorganisation Act, 1966 for the admission, maintenance and operation of Bhakra Nangal

project w.e.f. 1 st October, 1967. The Beas Project Works, on completion were transferred

by Government of India from' Beas Construction. Board (BCB) to BMB as per Section 80

of the Act, 1966 and the Bhakra Management Board was renamed as Bhakra Beas

Management Board (BBMB) w.e.f. 15.5.1976.

1.7.10.1 Function

The Bhakra Beas Management Board manages the facilities created for harnessing the

waters impounded at Bhakra and pong in addition to those diverted at Pandoh through the

BSL Water conductor system. It has also been assigned the responsibility of delivering

water and power to the beneficiary States in accordance with their due/entitled shares. The

Board is responsible for the administration, maintenance and operation works at Bhakra

Nangal Project, Beas Project Unit 1 and Unit 11 including Power Houses and a network of

transmission lines and grid substations. The functions of Bhakra Beas Management Board

are :

• To regulate the supply of Satluj and Ravi Beas waters to the States of the Punjab,

Haryana, Rajasthan and Delhi, through a wide network of canals.

• To distribute power from Bhakra Nangal and Beas Projects to States of Punjab,

Haryana, Rajasthan, Himachal Pradesh and U.T. of Chandigarh.

• The works being managed by the BBMB are broadly grouped as three large

multipurpose projects viz. Bhakra Nangal Project, Beas Project Unit-1 (BSL Project),

Beas Project Unit-]] (Pong Dam). PAGE 22

• The Bhakra Nangal Project comprises the Bhakra Dam, Bhakra Left Bank and Bhakra

Right Bank Power Houses Nangal Dam, Nangal Hydel Channel and Ganguwal and

Kotia Power Houses. Bhakra Dam is majestic monument across the river Satluj. It is

a high straight gravity concrete dam rising 225.55 m (740 ft.) above the deepest

foundation and spanning the gorge with 518.16 m (1700 ft.) length at the top. The

Gobind Sagar Lake created by the Dam has 168.35 sq. Km. area and a gross storage

capacity of 9621 million cubic metre (7.80 MAF.) The two power houses, one on the

left bank (5xl08=540) and the other on the Right Bank (3x132+2x157=710 MW),

have a combined installed capacity of 1250 MW ' The Ganguwal and Kotia Power

Houses fed from Nangal Hydel Channel have an installed capacity of 155.3 MW.



The Beas Project Unit-1 (BSL Project) diverts Beas Water in to the Satlui Basin, failing

from a height of 320 metre (1050 ft.) and generating power at Dehar Power House having an

installed capacity of 6x165 MW=990 MW. This project comprises a diversion dam at

Pandoh, 13.1 Km long Pandoh Baggi Tunnel having a capacity of 9000 cusecs, 11.8 Km.

long Sundar Nagar Hydel Channel, Balancing Reservoir at Sunder Nagar, 12.35 km long

Sunder Nagar Satluj Tunnel, 125 Metre high Surge Shaft and Dehar Power Plant.

The Beas Dam at Pong is the highest earth - fill (earth core, gravel shell) dam in India,

being 132.6 metre (435 ft.) high with a live storage capacity of 7290 million cubic metre

(5.91 MAF). The Pong Power Plant (6x60 = 360 MW) is located in the stifling basin d/s of

penstock tunnels.

The total installed generating capacity of the BBMB Power Houses is 2755.30 MW

which is more than 1/8th (about 13%) of the total installed Hydroelectric generating capacity

in the country as under

POWER HOUSE INSTALLED CAPACITY (MW)

Bhakra (Right Bank) 3x132+2x157 710

Bhakra (Left Bank) 5x108 540

Ganguwal 2x24.2+1x29.25 77.65

Kotla 2x24.2+1x29.25 77.65

Dehar 6x165 990

Pong 6x60 360

Total : 2755.30 MW

1. 7. 10.2 Generation and Transmission system

The BBMB Power Plants have the highest plant availability factor (90 to 94%). The

generation during 1996-97 was 12083 MU against the target of 11600 MU contributing

about 17.5% of at the all India Hydro Generation against installed capacity of about 13%.

The generation during the.year 1997-98 is expected to be comparatively of the poor inflows,

low reservoir level at Bhakra and less releases during the depletion period due to poor

demand for irrigation and power.

The power generation at BBMB power stations is being evacated through BBMB

power evacuation system running into 3735 Circuit Km length of 400 KV, 220 KV, 132 KV

and 66 KV transmission lines and 24EHV sub stations. The BBMB power evacuation

system runs in an intergrated manner in the Northern grid with its transmission network

spreading over the States of Himachal Pradesh, Punjab, Haryana and Delhi. The system is



interconnected with transmission s . ystem of Power Grid and the States of Uttar Pradesh,

Rajasthan and Delhi.

1.7.11 Central Power Research Institute

The Central Power Research Institute (CPRI) was established in Bangalore by the

Governemnt of India in 1960. It was organized into an autonomous society in the year 1978

under the aegis of the Ministry of Power, Government of India. The main objective of

setting up the Institute was to serve as a National Laboratory for undertaking applied

research in electric power engineering besides functioning as an independent National

Testing and Certification Authority for electrical equipment and components to ensure

reliability and improve, innovate and develop new products. PAGE 23

1.7.l1.1 Objectives

• To serve as a national centre for applied research in electrical power engineering.

• To function as an independent and impartial authority for certification and testing of

electrical equipments manufactured in the country for quality assurance.

• Performing tests for product development.

• To offer consultant on problems referred by utilities and industries.

• Undertake sponsored research programmes on subjects of interest in the power

systems field.

The Institute is headed by a Director General and has several research laboratories

and testing facilities and employ over 300 qualified scientists and engineers besides other

supporting staff guiding and maintaining various operations. The Head Office of the

Institute is at Bangalore and its other units are located at Bhopal, Hyderabad, Nagpur,

Ghaziabad, Thiruvananthapuram and Raichur.

TEST FACILITIES

Some of the test facilities added during 1997-98 are :

• Pollution test on all types of both tension & suspension insulators upto 400 K V class.

• Puncture with stand facility for DC Insulators.

• RIV test (outdoor) and corona inception & extinction voltage test (dry) for 800 KV

line components like insulators, conductors, hardware etc.

• High voltage dielectric tests on 800 KV transmission line insulators.

• Fuel evaluation test facility at TRC, Nagpur

• Electric field -exposure facility



• Solar lantern test facility at Energy Research. Centre, Thiruvananthapuram.

1.7.12 Energy Management Centre (EMC) :

The Energy Management Centre (EMC) was established by the Government in April,

1989 (registered as an autonomous body under the Societies Registration Act) to act as a

focal point for exchange of experience and function as a centre for information, research,

training and international cooperation in the field of energy management. EMC

advises/assists the Ministry of Power in formulation of policy and designing of programmes

on energy conservation and functions as a nodal point at the Central level for monitoring and

coordination of energy conservation activities in the country. It also takes up

implementation of specific programmes on its own as well as on behalf of the Ministry of

Power and other organisations. At present, EMC is sustained by budgetary support from the

Government in the form of grants-in-aid. Its current annual budget is of the order of Rs. 55

lakhs.

1.7.12.1 Activities of the Energy Management Centre

EMC carried out the following activities:

Macro-level policy study on Energy Efficiency in Indian Economy vis-a-vis other

developing economies in Asia-Pacific region.

Preparation of Industrial Energy Efficiency booklets on :

(i) Pulp and Paper

(ii) Secondary Steel Sector

Preparation of Status Report and Action Plan on Time of Use Tariff in India.

Status reports for selected domestic appliances.

Development of informative booklet on strategic management of energy

efficiency- at the Corporate level.

Showcase demonstration project on energy savings through fan efficiency

improvement in Cement Industry.

DSM plan for Gujarat Electricity Board.

Energy Consumption norms in foundry and mini steel industry.

Development of computer aided monitoring and targeting system for a process

Industry. page 24

Energy saving in Aluminium Electrolysis by bringing down the operating

temperature of Electrolyte.

Preparation of material for inclusion in the text books prescribed in the school



curriculum.

Development of practical energy saving guide for small business and industries.

Development of Industrial Energy Efficient Booklets.

Preparation of industrial energy efficiency agenda for Secondary Steel, Pulp and

Paper and Chlor-alkali industrial subsectors.

Preparation of status report and action plan on time of use tariffs in India.

Study on prospects and strategies for energy efficient buildings

Training programmes for training of personnel on energy conservation in the

various sectors of industry.

lndo-EC Energy Management Cooperation Programme (Phase 11)

1ndo-German Technical Cooperation Programme on Energy Conservation in

Indian Industries.

Studies sponsored by a Swedish Agency for Research Cooperation for developing

countries programme (SAAREC).

Energy Efficiency Support Project of the Asian Development Bank (ADB)

lndo-US Energy Efficiency Cooperation Programme.

World Bank project on India regarding Environmental Issues in the Power Sector.

1.7.13 Cooperation with Neighboring Countries in Hydro Power

The development of the water resources of the common rivers of India and

neighbouring countries of Nepal and Bhutan for mutual benefits has been under discussions

with these countries. There is regular exchange of electric power between India and these

neighbouring countries for the supply of surplus power and meeting the power requirements

in the border areas.

India has been assisting Nepal in the utilisation of its hydro power potential and for

HE scheme viz. Pokhara, Trishuli, Western Gandak and Devighat have been implemented

with assistance from Government of India. Three major water resources projects in Nepal

viz. Karnali, Panchshwar and Saptakoshi are presently under discussions. The feasibility

report of Karnali Multipurpose Project (10800 MW) was prepared in 1989. The key

parameters of the project are to be finalised after mutual discussion. Pancheshwar MPP

(Stage 1:2000 MW) has been investigated by the two countries in their respective territories

and DPR is presently under preparation / discussion, jointly. The development of this project

is covered under integrated Mahakali River Treaty signed between HMG, Nepal and India in



February, 1996. India had offered financial and technical assistance for investigation of

Saptakoshi (3300 MW) Multi-purpose project. Joint technical experts groups have been

constituted for each of the above projects for joint guidance for investigation and preparation

of detailed project reports (DPRs).

In Bhutan, Chukha HE Project (336 MW) implemented with Indian financial and

technical assistance and operating in an excellent manner is a shining example of

cooperation between the two countries for mutual benefits. The surplus power from the

project is being imported by India. Kudchu HE Project (45 MW) in Eastern Bhutan is

presently under implementation on turnkey basis with Indian financial and technical

assistance. Another project viz. Tala HE Project (1020 MW), has been taken up for

implementation and is being executed by Tala Hydroelectric Project Authority (THPA)

comprising Indian and Bhutanese Officers and Engineers. Consultancy for the Project in

respect of both civil and elec tromechanical works is being rendered by Central Electricity

Authroity (CEA), Central Water Commission (CWC) and Water and Power Consultancy

Services (WAPCOS). The Project is being funded by India through grant and loan and the

major portion of the generation of power will be made available to India.

The investigation of two hydro electric projects namely Wangchu (900 MW) and

Bunakha (180 MW) have been completed and DPR prepared and furnished to Bhutancess

government. India is also providing technical assistance for rehabilitation of hydro projects

in Bhutan.

Page 25

Hydro Engineering Division of CEA is rendering Design and Engineering

Consultancy to Hydro Electric Projects and rehabilitation of 8 nos. mini/micro hydroelectric

projects in Bhutan.

ASSESSMENT OF SMALL HYDRO POTENTIAL IN THE COUNTRY :

India possesses sizable resource of small hydro potential and the attention of te

planners of the country has therefore been focused on its exploitation. Implementation of

small hydro stations requires comparatively lesser capital investment, shorter gestation

period and obviates the need for providing major transmission lines and, therefore, results in

substantial savings. Recognising the benefits of small hydro plants, particularly in the

development of remote and isolated areas, Central Electricity Authority carried out the

studies for assessment of small hydro potential of the country.



The study identifies small schemes in different river systems and canal systems of the

country. The inventory of schemes also includes existing on going and proposed schemes.

Such a detailed systematic study has been attempted for the first time in the country.

Statewise draft reports of studies were finalised after incorporating the comments /

suggestions of State Authorities. According to the studies, small hydro potential of the

country has been assessed as 6782 MW from a total of 1512 nos. of schemes.

1.7.14 Badarpur Thermal Power Station Performance

Badarpur Thermal Power Station consists of 3 x 100 MW and 2 x 210 MW coal-fired

units with an installed capacity of 720 MW. However, the 3 units of 100 MW each have

been derated to 95 MW w.e.f. 11.1.1990. The station is owned by Government of India and

is being managed by NTPC since lst April, 1.978. Presently, the entire energy generated at

this station is supplied to the Delhi Vigyut Board only. During the year 1997-98 upto 31st

March, 1998 the station generated a total 4475.72 MUs at a PLF of 72.47% against the target

of 4200 MUs at PLF of 68.0%. Other parameters like specific oil consumption, auxiliary

power consumption, DM water consumption during the year upto March, 1998 are 2.27

ml/kwh, 8.645% and 3.38% respectieviy. BTPS has lost 340 MUs due to low system

demand/ high frequency. The loss of generation due fixed a target of 4225 at a PLF of 68.41

% for the year 1998-99.

RENOVATION AND MODERNISATION

PHASE 1

BTPS is one of the thermal power stations identified under the centrally sponsored

scheme for Renovation and Modernisation of thermal utilities. Under the Renovation and

Modernisation Scheme Phase 1, various schemes for 3 x 100 MW of BTPS for Rs. 36.97

Crores had been approved.

Most of the schemes have already been implemented and an expenditure of Rs. 35.48

Crores has been incurred up to 31st March, 1998. After implementation of R & M - 1

scheme for BTP$ the actual annual avaerage PLF has improved from 45.30% to 65.00 %

against the estimated improvement in PLF from 45.300/. to 5.00 %. The specific oil

consumption has also been reduced to less than 5mi/kwh due to reliable operation and less

number of outages. The result of successful R & M programme of BTPS has turned out to

be exemplary. During the calender year 1994 the station generated 4586.788 MUs highest

since inception.

PHASE 11



Under R & M Phase-II programme, certain areas were identified for carrying out

further modification. BTPS submited a proposal for R & M Phase-II for an estimated cost of

Rs. 187.77 Crores for approval covering all units of BTPS. The proposal has been techno-

economically cleared by CEA and approved by PIB. At present, the proposal is under

approval by CCEA. The scheme mainly emphasizes on reduction in heat rate, increase in

PLF from 65.00% to 70.00 % and increase in generation by about 320 MUs/year.

ASH UTILISATION

BTPS has been making sincere efforts for productive utilisation of ash generated for

constructive purposes. M/s Ballarpur Industries has set up a fly ash evacuation system for

it's use for manufacture of aerated blocks and beams utilising fly ash to the tune of 12000

Cubic meters during the year 1997-98.

BTPS also used ash in site leveling at Faridabad Gas Power Project and construction

of ash dyke. The total utilisation of. fly ash was more than 22% during 1997-98.

Page 26

1.8 PROMULGATION OF ELECTRICTY REGULATORY COMMISSION

ORDINANCE, 1998

Electricity Regulatory Commission Ordinance 1998 was promulgated on 25.4.1998

for establishment of Central Electricity Regulatory Commission (CERC) and State

Electricity Regulatory Commissions (SERCS) for rationalisation of tariffs and matters

related thereto. The CERC and SERCs are required to be constituted with in a period of

three months. Necessary action is being taken by the Ministry of Power and State

Governments respectively.

1.9 RESTRUCTURING OF STATE ELECTRICITY BOARDS

A process of restructuring of the, SEBs has been initiated in several States. Organisation

restructuring aims at :

(i) Unbundling of power industry by separating generation, transmission and

distribution.

(ii) Bringing in competitiveness by distribution.

(iii) Development of a regulatory framework.

Re-structudng of Orissa SEB has been carried out from 1.4.1996 and it has been

replaced by two Corporations namely Grid Corporation of Orissa Ltd. and Orissa Hydro

Power Corporation Ltd. to look after the functions of distribution and generation



respectively. An Electricity Regulatory Commission has been established for issue of

licence, fixation to tariffs etc.

The Haryana Bill, after receiving the Presidential Assent has become and Act.

Andhra Pradesh, Rajasthan, Goa and Gujarat have also drafted their Reform Bills which are

in th process of finalization. Governments of Kamataka and Assam have assigned study on

reforms to Administrative Staff College of India, Hyderabad for the purpose of undertaking

reforms and restructuring their respective power sectors. Government of Kerala is seeking

assistance from CIDA for Kerala Energy infrastructure Project and a MOU in this regard was

signed on 8-1-97. The Other States which are at different stages of reforms are : Madhya

Pradesh, Uttar Pradesh, Maharashtra, Bihar and West Bengal.

As mandated by the Common Minimum National Action Plan for Power, the Ministry

of Power introduced the Electricity Regulatory Commission Bill, 1997 in the Lok Sabha on

14th August 1997. The Bill was referred to the Standing Committee on Energy. As per the

directions of the Standing Committee the Bill was circulated among all States for eliciting

their comments. The Committee also advertised in National Newspapers calling for the

views of the public on the Bill. But before the Committee could finalize the

recommendations the eleventh Lok Sabha was dissolved resulting in the lapsing of the Bill.

It is proposed to reintroduce the Bill after the Lok Sabha is reconstituted. The one member

committee on Private Sector Participation in Power Distribution headed by Shri S. J. Ceolho

submitted its final report in March, 1998. This has been circulated among all States/Union

Territories for taking further action.



ELECTRICITY GENERATION :

CONSIDERATION AND LOCATION OF

LARGE THERMAL POWER PLANTS



Page 27 2.1 ELECTRICITY GENERATION :

lndia's 71% power amounting to 64151 MW (As on March '98) in a total of 89167

MW comes from Thermal Power Stations. In General Thermal Power Stations burn fuels

and use the resultant heat to raise steam which drive the turbo generator. The fuel may be

'fossil' (Coal, Oil or Natural Gas) or it may be fissionable (Uranium). Whichever fuel is used

the object is same to convert heat into mechanical energy in the turbine, and to convert that

mechanical energy into electricity by rotating armature coils surrounded by magnet.

The fig. 2.1 shows a coal fired power station. Its other raw materials are air and

water. The coal, brought to the station by trains or by other means, travels from the coal

handling plant (1) by conveyor belt to the coal bunkers, from where it is fed to the pulversing

mills (2) which grind it as fine as face power. The finely powdered coal mixed with pre-

heated air & is then blown into the boiler (4) by a fan called Primary Air Fan (3) where it

burns, more like a gas than as a solid in the conventional domestic or industrial grate, with

additional amount of air called secondary air supplied by a Forced Draft Fan (3A). As the

coal has been ground so finely the resultant ash is also a fine powder. Some of it binds

together to form lumps which fall into the ash pits at the bottom of the furnace. The water

quenched ash from the bottom of the furnace is conveyed to pits (17) for subsequent disposal

or sale. Most of ash, still in fine particle form is carried out of the boiler to the precipitators

(13) as dust, where it is trapped by electrodes charged with high voltage electricity. The dust

is then conveyed by water to disposal areas (14) or to bunkers for sale (15) while the cleaned

fuel gases pass on through I.D. Fan to be discharged up the chimney (16).

Meanwhile the heat released from the coal has been absorbed by many kilometers of

tubing which line the boiler walls. Inside the tubes is the boiler feed water, which is

transformed by the heat into steam at high pressure and temperature. The steam, super

heated in Superheater (Super Heated) passes to the turbine (6) where it is discharged through

nozzles on the turbine blades. Just as the energy of the wind turns the sails of the wind-mill,

so the energy of steam, striking the blades, makes the turbine rotate.

Coupled to the end of the turbine is the rotor of the generator (7) - a large cylindrical

magnet - so that when the turbine rotates the rotor turns with it. The rotor is housed inside

the stator having heavy coils of copper bars in which electricity is produced through the



movement of the magnetic field created by the rotor. The electricity passes from the stator

windings to the step-up transformer (8) which increases its voltage so that it can be

transmitted efficiently over the power line (9) of the grid.

The steam which has given up its heat energy is changed back into water in a

condenser (10) so that it is ready for re-use. The condenser contains many kilometers of

tubing through which cold water is constantly pumped. The steam passing around the tubes

looses heat and is rapidly changed back to water. But the two lots of water (i.e., boiler feed

water and cooling water) must never mix. The cooling water is drawn from the river/sea, but

the boiler feed water must be absolutely pure, far purer than the water which we drink, for

preventing damages to the boiler tubes. Indeed the chemistry at a power station is largely the

chemistry of water.

Why bother to change the steam from the turbine back into water if it has to be heated

up again immediately ? The answer lies in the law of physics which states that the boiling

point of water is directly proportional to pressure. The lower the pressure, the lower the

temperature at which water boils. The turbine designed wants as low a boiling point as

possible because we can only utilise the energy from steam - when the steam changes back to

water we can get no more work out of it. So a condenser is required by which rapidly

changing the steam back into water creates a vacuum. The vacuum results in a much lower

boiling point which, in turn, means we can continue getting work out of the steam well

below 100oC at which it would normally change into water.

To condense the large quantities of steam, huge and continuous volume of cooling

water is essential. In most of the power stations the same water is to be used over and over

again. So the heat which the water extracts from the steam in the condenser is removed by

pumping the water out to the cooling towers (12). The cooling towers are simple concrete

shells acting as huge chimneys creating a draught (natural/mechanically assisted by fans) of

air, The water is sprayed out at top of the towers and as it falls into the pond beneath it is

cooled by the upward draught of air. The cold water in the pond is then recirculated by

pumps (11) to the condensers. Inevitably, however, some of the water is drawn upwards as a

vapour by the draught and it is this water which forms the familiar white clouds which

emerge from the towers seen sometimes. PAGE 28

2.2 CONSIDERATION FOR THE LOCATION OF LARGE THERMAL PLANTS

2.2.1 General



Large development in the thermal power generation calls for proper planning in the

choice of site, climatic conditions, unit size, coal . Requirements and transport facilities,

transmission system etc. It is normal practice to consider various alternative sites for

location thermal power stations and work out comparisons to arrive at economically feasible

location. In this unit, a brief discussion as to the various aspects that go to make such a

planning and location has been aimed at.

The preparation of feasibility report for a thermal station requires study under two

headings, viz. Area Selection and Site Selection. The Area Selection study comprises the

study of factors given below which are required for the establishment of any production

oriented industry. The area selection may give many possible sites spread over an area of

hundreds of sq. km. Some of the points given below though significant from the view point

of area selection are also applicable when final choice of site is made.

a) Supply of raw materials, which in the case of thermal power stations are coal and

water, are of extreme importance.

b) Transport facilities to haul the raw materials, viz. coal in this case and the capital

equipment.

c) Transmission of power produced to the load centres.

d) A labour force of size and quality required but this will not be of ever riding

consideration. In our country the migration of labour from one place to another does

not pose very difficult problems.

e) Means of disposal for any trade effluents or byeproducts. In case of thermal stations

both the fuel gases and the ash are effluents and the means for their disposals are to be

thought of.

f) Climatic conditions. The climatic conditions also play a part in area selection., as in

the case of thermal power stations these affect not only the capital cost of structures

and machines etc. but also the economics of generation during normal running.

2.2.2 Coal for Steam Power Stations

In India, the principal source of commercial energy is coal amounting to over 95% of

the total primary energy resource of the country. The coal reserves obtaining in our country

are of the order of 130,000 million tonnes, or even more and new reserves are being located.

The main areas where coal mines are located are eastern regions viz. Bihar, West Bengal,

Central Region viz. Singrauli coal fields, Tamil Nadu, viz., Neyveli, Small sources of coal

are located in rest of the country as well. The map (Fig. No. 2.2 ) shows the distribution of



coal reserves in India. The economic and efficient utilization of high ash coals for thermal

power generation calls for special considerations. Firstly, it is uneconomical to haul these

coals over long distances because the energy sources, the coal matter is diluted by the ash

and any transportation means paying freight and handling charges on the useless ash and

thereby adversely effecting the cost of useful heat that can be recovered form these coals.

The location of steam power station burning high Ash coals is therefore of great importance.

Since about 50% to 60% of the cost of generation of electric power is due to the delivered

cost of coal at the generating stations it is imperative that these plants should be located

either at or near the pithead or the coal washeries. Consideration of course has to be given in

locating the pit-head stations for the due cost to transmission system vis-a-vis the fuel

transport costs and other connected problems. It is a usual practice to tabulate result of these

costs for comparisons and finalising the area.

In order to rationalise the use of coal and its transport taking into consideration the

railway track loading distances from the coal fields Government of 1ndia set up a 'Linkage

committee, This committee linked various power stations and the coal fields which were

supposed to supply coals to these stations.

2.2.2.1 . Coal Washories

The Government of India on the recommendations of the

udlings utilisation Committee and the Energy Survey have laid down the policy that the

boilers of the Public Utillies should use inferior as ash content of upto 45%. This policy was

adopted firstly, to conserve good metallurgical coal and secondly, to use bye products left

over after washing medium quality middlings coal for use in the steel plants. PAGE 29

The middlings used in the power stations on an average are having very high ash

content even beyond 42% and the effects of use of byeproducts having such high ash content

have been follows :-

(i) Inability of the generating units to carry full load due to shortfall in the capacity of

pulveriser mills.

(ii) Increase in the coal mill outage for maintenance of mill parts like bushing, rollers and

exhauster fans.

(iii) Appreciable burner erosion resulting in instability of fire.

(iv) Increase in the quantity of ash handled.

(v) Increase of wear on ID fan.



Taking into account the above factors it was considered essential to recommend a

three stage washery of the coal so that the byeproducts could be clean coal, middlings and

rejects. These middlings of three stage washeries will then have ash content limited to 28%

to 32% thereby providing proper economy for thermal power station utilisation. Thus, in a

three stage washery as suggested, it is necessary to equip each washery with adequate

equipment for removal of' stones and other abrasive material limiting the ash content

reducing it appreciably between, 28 to 32%. Attempts should also be made to achieve such a

quality of middlings with suitable modifications for the existing coal (two stage) washeries

as well.

The above points are to be borne in mind in selecting the byeproducts from coal

washeries for utilisation as fuel for modem thermal power stations. The main criteria that

are to be borne in mind in selecting coal for modern steam power stations are

(a) Size

(b) Moisture

(c) Ash

(d) Feasability of ash

(e) Grindability

(f) Calorific Value and volatile

(g) lmpurties like sulphur, phosphorous and chlorine

Table No. 1 gives the ranges of properties of major types of coal and lignites in india;

2.2.3 Water for Steam Power Stations

The water requirement for thermal power stations come under two main groups. The

first requirement the water required for steam generation and the second requirement is for

the Condensers i.e. for condensing the steam, a portion of this may be included for cooling of

generator and other machines.

As for as the problem of water for steam generation is concerned the problem is not of

quantity but is of quality. The requirement of water in steam cycle is for the order of 3 or 4

cum/ hr/MW and the make up quantity is 2% to 3% of the same. Thus for a 500 MW station

in the steam cycle we may have 1500 to 2000 cu.m/ hr of water and make up will be 60

Cu.m/hr maximum. This requirement can be met from a small canal, city supply or even

through tube well. The main problem is of quality. If the water is very hard the

demineralising cost will be very high and also it will require a large water treatment plant.



The amount of water required for condenser cooling is quite significant. In once

through system of circulating water the amount required will be approximately 20,000

cu.m/hr/10OMW to dispose aprox. (103x275 Kw/hr) 500 million Btu/ hr. of heat energy.

This includes small portion of requirements for cooling of generator and other machine.

Now as in our country super thermal power stations with installed capacity above 100OMW

are being thought of, availability of water is going to be of greater importance. Direct

cooling will be possible only if perenial rivers, canals, or huge lakes are available. The Obra

Thermal Power Station (550 MW) depends for water supply on river Rihand and its lake (to

meet hydro station and low flow demands) and Badarpur Thermal Power Station

(3x10OMW and 2x210 MW) takes supplies from Okhla Canal.

Where the a variability of water is not perennial or flow through out the season is

inadequate, reservoir is not big enough, the closed

Page 30



Page 31



circuit cooling system involving cooling towers is utilised. In such a system only 3% (which

consists of 1% as losses on account of evaporation and 2% for purging the salts) of make up

water is required. Apart form the conventional sources of supply, in case of pit head stations

it has been observed that under surface water can also meet the demands of water in closed

circuit cooling systems. A case in point is the Neyveli Lignite Thermal Power Station.

As to which of the two systems of cooling should be used will not only depend upon

availability of water, but also on cost considerations which are to be compared before final

decision. It may be noted that water from whatever sources may be used has to be paid for

either in the form of direct charges or pumping charges.

2.2.4 Transport

In case of thermal power stations, the problem of transport is to be considered mainly

from the view point of fuel viz. coal economics. As for initial erection of the plant modes of

transport are also to be considered but may not be overriding factor in decision making of

feasibility. At this stage the possibility of rail and road connections capable of taking heavy

and over dimensioned loads of the machines are to be considered. The bridges or tunnels in

required area to be provided or existing ones to be strengthened. On the basis of prevalent

cohsumption pattern the daily burden on transport system for 50OMW station working at

80% load factor, due to various consumables excluding spare etc. will be as given below

Coal 4800 Tonnes

Furnace Oil 60 k.lit.

Hydro Chlofic Acid 1200 Kg.

Sodium Hydroxide and other 600 Kg.

Chemicals

The cost of transport of fuel as stated above is major consideration in economics of

power generation, for example, the study of two stations, Renusagar T.P.S. which is located

at pit head where transport of coal is done by a conveyer and Obra T.P.S. where coal is taken

by rail, which are hardly 100 Km. apart the difference in cost of generation on account of

coal works out to be 0.6 paise. The difference in cost of generation will be higher in haulage

is done to longer distances. Thus when the considerations like transmission of power,

availability of water etc. do not interfere, the other transport considerations are of minor

importance and thus it will be preferable to have stations at pit head.

In case the considerations mentioned above lead to establishment of station elsewhere

than the pit head, the decision shall again take into consideration the haulage distance



involved as it also plays in important part. For example on the basis of 1969-70 freight

structure of the Railways the difference in cost per tonne of transport of coal is about Rs. 20

to Rs. 22 between Obra and Delhi Power Stations.

Whatever may be the final choice for site of power station, it is essential that it shall

be easy to get railway siding facilities and suitable road communication links. Thus it is

usual practice to locate the site alongwith the existing rail heads as otherwise construction of

rail link lines will add to the capital cost of the scheme.

2.2.5 Transmission of Power

After taking into consideration the technical problems like stability and reliability

with respects to a particular power system, the choice regarding location of thermal power

stations will depend upon the economics of transportation of coal to a power station located

at a suitable point in the vicinity at load centre by railways versus the transmission of energy

over extra High Voltage. lines at 220 KV and above from pit head power station.

Apart from taking into consideration the basic economic factors for adopting a

transmission system vis-a-vis location of a thermal station it should be borne in mind that the

integrated system has many advantages, a few of which are given below.

i) Saving in reserve generation capacities regional diversities can be put to advantage.

ii) Facility of inter-connected operation-An inter-connected system will have merit list

of thermal stations/units in terms of heat rate and during off peak hours stations/ unit

with higher heat rates can be stopped or banked.

iii) Advantages during emergency.

iv) Less loading on the existing railway tracks.

PAGE-32

The various charges entering into cost of transmission are :

Interest and depreciation charges on account of capital cost of transmission lines and

allied equipment at both ends.

Charges on account of loss of energy in transmission. Those will depend upon

quantum of power, voltage, load factor and power factor.

Fig. No. 2.3 shows comparison of cost on transmission and transportation of coal per

kwh of energy. This is based upon studies carded out by C.E.A. in 1973.

Sometimes it is possible that economical considerations may show the location of

station at a pit head, provided transmission at a particular voltage is done. But the developed

technology within the country for the high transmission may not be available, thus site may



have to be shifted. For example, when Badarpur Thermal Power Station was planned, we

had no resources for transmitting bulk power at 400 KV, which thus necessitated location

near load centres. Similarly, it is economical to locate stations at different ends of

transmission lines as this will require lesser cross, section of conductor. Bhakra, Badarpur

and Bhatinda stations are a case in point.

2.2.5.1 HVDC - Break-Through in Transmission Technology :

A major step towards providing inter-regional transfer of power and improving the

security of the system has been taken with the commencement of work for setting up the first

500 MW HVDC back to back line in the country. This would provide an asynchronous

inter-tie 'for the system between the Northern and Western Regional grids and would permit

large power transfers between the regions.

NTPC would be introducing HVDC technology for power transmission for the first

time in the country by setting up HVDC Bi-pole from the Rihand power station to Delhi as

part of the Rihand transmission project. This line would have a capacity of transmitting

1500 MW of power.

2.2.6 Disposal of Effluents

As already stated the major effluents in case of the thermal stations are the ash and the

flue gases. The disposal of chemically treated water generated in the water treatment plant is

also an effluent which requires attention for disposal. The disposal of the gases and ash

concerns mainly the atmosphere and environment and that of water is concerned with rivers

and canals which will thus effect the marine life.

Modern thermal stations burn pulverised fuel, the combustion product will contain

about 80% of fly ash and the balance bottom ash. Before flue gas is allowed to escape into

the atmosphere fly ash is to be separated. The means to separate fly ash are mechanical or

electrical precipitators or both of them. Till recently the method of disposal of ash has been

by converting it into slurry and pumping the same by means of ash disposal pumps or

hydravacs to waste lands. It is in this connection i.e. requirement of large areas of waste land

the effluent disposal plays a decisive factor in location. At pit heads unused collieries may

be used for dumping and in hilly terrain some valleys may be used for the purpose. Near

urban centres, disposal is really a problem. In India as we know that we are utilising high

ash content which comes upto 40% the quantities of ash to be disposed are enormous. One

210 MW Unit will produce about 1000 tonnes of fly ash per day on full load.



Taking into view the huge quantities of ash involved attempts have been made to

utilise the fly ash. Now in western countries it is finding use as earth fill, as bricks after

being mixed with cement. This has led to adoption of new methods for dry ash collection.

The aspect of economical use of ash will also have a bearing on location of the thermal

power station, the basic being whether it will be economical to transmit power or to transport

ash or to transport the products of ash.

The predominent gases in the flue, apart from Nitrogen an Oxygen, are carbon

dioxide, carbon monoxide and sulphur dioxide. Of these gases carbon monoxide and sulphur

dioxide, are quite obnoxious. The amount of carbon monoxide can be limited by proper

combustion, but the amount of sulphur dioxide will depend upon the sulphur content of coal.

In India coals, except lignite where percentage of sulphur is as high as 2.5% to 7%, the

percentage varies generally from 0.2 to 0.8% thus taking an average value about 0.5%, one

tonne of coal burnt will give about 5 kg. of sulphur to from 10kg. of sulphur dioxide,

PAGE-33

PAGE-34



PAGE-35

thus a 210 MW machine in one day will produce about 25 tonnes of SO2 to be dispersed into

the atmosphere. Thus, sometimes gases may have to be washed if sulphur dioxide crossed



permissible limits. The flue emission now decides the height of chimney which now goes

upto 60Oft. This also stipulates location of stations away from densely populated areas.

2.2.7 Climatic Conditions

The climatic conditions of a place play. A significant part in the economics of capital

investment, as far as machines, certain structures and amenities are concerned. This also has

a bearing on operation economics as it will decide heat utilisation. It may be remembered

that whatever be the dictates of climatic limitations, the area for thermal station will not be

discarded on these considerations alone. This point is discussed here only to show the extent

of its effects.

The tropical climate is there in most of the parts of our country, which means high

temperature and humidity, calls for special attention to the ventilation and cooling

arrangements. The humid conditions with fluctuating temperatures lead to dew point and

hence the condensation which results in corrosion formation and affects on insulation, both

mechanical and electrical machines. It is a well known fact that for tropical countries

insulation of machines has different standards and is costly. Further the present stations use

telemetering and controls, the sensitive electronic equipment alongwith other equipment

such as relays etc. are required to be located in air conditioned rooms. This means addition

to capital costs.

The cooling water temperature which depends upon ambient temperature of a place

influences the power station operation. In Warmer places, the average cooling water

temperature is some what higher as compared to cooler zones. This will mean that while in

cooler places it may be possible to reach an absolute pressure of 25 to 35 mm of Hg. column,

in warmer places figures which can be possibly achieved may not be less than 50 to 75 mm

of Hg. -column. This will mean more heat rejection to the cooling water and hence lesser

work output. It naturally will increase operation cost.

In the selection of cooling towers as well the temperature conditions obtaining at the

sites considered play a significant role. The approach, i.e., the difference between the. tower

cooled water temperature and the wet bulb temperature decides the economic size and design

for cooling tower. In our country we will invariably have to opt for forced draft cooling

towers. Thus for varying wet bulb temperatures in different places the cooling water costs

differ thereby affecting the cost of the, power station as a whole.

Having marked different points for possible sites for the station over a widespread area,

each site is considered on its merits. The results and data are tabulated for reaching final



conclusion and making the ultimate selection of site. Some of the points given above for

area selection to play a part in principles governing the selection of site as well as the wider

area marked spreads hundreds of Km. and this distance plays considerable part in economics

of operation of power station, on account of transport of coal and cost of transmission of

energy etc. The other additional points which are taken into consideration in selection of site

are as under

2.2.8 Geology

The heavy equipment and structures involved impose heavy loads on ground under

the foundations. In an area spread over hundreds of Km. there can be differences in soil

strata formation at different places. The general nature of the soil can be obtained from

Geological Survey maps and final selection can be made after taking bore hole trials at

different locations in the area. To determine the thickness, strength and other physical

properties of the strata under the site, sample are tested both at the site and in laboratory. In

industrial areas it becomes imperative to know the previous use of land in order to locate old

foundation, mines etc.

2.2.9 Loading values for different equipments

For locating heavy foundation for machines, chimney etc. it will be better if rocky

locations are available, it will avoid deeper excavations. Approximate design values of

loading for a 500 MW machine are as on next page :

PAGE-36

1. Turbine House, Boiler House, Bunker 2.5 Ton/M2

Bay, Ground Floors

2. Turbine House, Loading bay 4.8 Ton/ M2

3. Feed Heater Bay-ground floor 1.6 Ton/ M2

4. Operating floors/Boiler house at 4Oft.

Bunker Feed Heater bay

(a) On Concrete floor 1.6 Ton/ M2

(b) On steel work 1.2 Ton/ M2

5. Deaerator floor at 138 ft. & R.C.W. tank/floor

(a) On concrete 1.1 Ton/ M2

(b) On Steel work 0.8 Ton/ M2

6. Operating walkways various levels 0.5 Ton/ M2



In certain cases it is possible that circulating water system may require tunneling as

surface carrying of water in open channels due to area topography may not be possible. In

such conditions sub soil investigations including permeability. tests and ground water tests

are necessary.

The topography of certain terrain i.e. different levels may also play an important part

in the economics of excavations and structure. the coat yard, precipitator, Boiler house,

turbine house and switch yard can be located at different levels to save overall cost of

excavation.

2.2.10 Proxomity of Air Fields

Before the site is selected its proximity to air fields must be studied. The chimney

heights now go up to 150-180 meters (500-60Oft) and boiler house structures upto 60 m.

These present obstacles in air navigation particularly during landing and take off. The Air

Safety Regulations must be taken into account before locating the power house.

2.2.11 Fisheries and Marine Life

The intake of large volumes of water from the river and consequent throw off at a hi

her temperature after being treated with chlorine will affect fish. On some rivers there are

fisheries at certain locations, those locations, are to be avoided. The intake and outake

structure may have to be shifted if location is found unsuitable on other considerations.

The effluent discharge from water treatment plant has be treated suitably before

discharge it to river.

2.2.12 Amenities

This means effects on surrounding area such as visual impact and as assimilation with

the landscape or opposition to transmission towers, conservations of flora and fauna and

effects on historical monuments. In our country there was not much awareness to this

aspect, but things are changing now. The stations structure have to be designed in such a

way that they look a part of the landscape. The direction of flues and the height of chimney

that the fuel do not spoil the historical monuments in the vicinity. As far as transmission

system is concerned it is felt that we have to live with it as the alternatives are too costly.

But certain big cities can be bypassed

Visible pollution by smoke, grit and been aggravated with the advent of P.F., fired

boilers. Oil fired boilers though reduce this amount but pollution from sulphur dioxide and

acid smuts increases. For this tall chimneys are the answer. Earlier rule viz. chimney height

should be 21/2 times the height of the tallest building is now inadequate. For super thermal



stations single chimney with multiple flues of velocity above 60 ft./sec. 200-250 meter

height is the practice. This provides the mass flow and thermal buoyance which under

normal atmospheric conditions at least doubles the effective chimney height at which the

gases dispose.

PAGE-37 TABLE NO. 2.1

PROPERTIES OF MAJOR TYPES OF INDIAN COALS AND LIGNITES AT 60% R.H. AND 40O-C

Type of coal

Reserves in

Million Tons.

Moisture Ash V.M. Gross C.V. K.Cal/Kg.

Total Sulphur

Ash fushion Range (at

Mildly Reducing atmosphere

Hardgorve Grindability Index

1. Prime coking Coal 5,200

Less than (4%)

2-14 (Mostly

above 17) 21.-28 6000-7500 0.5-0.8 Over 1400oC 65-75 2. Blendables a) Medium-coking 1-10% 13-36 17-32 5800-7300 0.5-1.5 1200oC to 50-75 b) Semi- coking 23,00 2.0-3.0 12-20 28-35 6000-7100 0.7 1400oC to 45-55 -17.50% Over 1100oC c) Wekly-coking 3.0-5.0 14-25 39-37 5500-6500 0.4-0/8 Over 1400oC 50-60 3. Non-coking and weekly 103,000 Mar-13 11-14 20-39 3800-6300 0.2-3.0 1100oC to 40-70 Over 1400oC 4. Semi-anthracite 200 0.5-3.0 10-35 8-15 5100-7400 1.6-7.0 1300oC to 60-70 Over 1400oC 5. Lignites 2,300 10-37 4-54 24-42 1700-4200 0.5-3.2 1000oC to ---------

Over 1350oC



STATION LAYOUT



PAGE-38

3.1 STATION LAYOUT

The station layout consists of lay out of turbo-generator and the auxiliaries plus the

coal crushing equipment for the boiler in an integrated building so as to achieve the

following objectives:

* Proper flow of process fluids steam, condensate, air, coal and oil

* Economy of space,

* Ease of installation/operation/maintenance

* Avoidance of interferences

* Clear passages and easy access to various floors and equipments

* Proper Safety precaution

* Streamline locations for good appearance

Basically, this lay out can be divided into two broad categories-Longitudinal and

Transverse, depending upon the arrangement of turbogenerator with respect to the boiler.

Various factors which affect the chioce of lay out between transverse and longitudinal are :-

i) length of the turbo-generator set ii) width of Boilers iii) width of electrostatic precipitators

iv) length of control cubical v) length of electrical switch gear vi) process flow scheme for

circulating water pumps, EOT crane capacity etc. Techno-economic study is made after

making broad out concepts in each case and the most economic out is chosen. Some factors

which affect the economy choice are length of the HP piping, length of bus-ducts, length of

CW ducts, arrangement of electrical switch gear and cable lengths.

3.2 GENERAL ARRANGEMENT

Normally the concept in India is to have turbo generator and its auxiliaries located.in

one big hall called turbo generator hall or T.G. bay. Adjacent to this bay is an electrical bay

compdsing of control room, electrical switch gear and other minor auxiliaries. The next bay

generally consists of coal bunkers and coal mills. Sometimes coal bunkers and electrical bay

overlap as is in the case of Badarpur 3 x 100 MW layout. Sometimes the mill bay is taken

on the other side of the boiler for various reasons. It may be pointed out here that station lay-

out is not an exact science but combination of art and science where the personal likings and

considerations weigh even more than the purely economical consideration. A proper balance



has to be struck between these two to have an acceptable lay out. Proper lay out goes in a

long way in providing necessary comforts to the operation and maintenance staff.

3.3 TURBINE LAYOUT

Once the basic concept of general arrangement is agreed to and the decision between

transverse and longitudinal is taken the more detailed studies are required to finalise turbine

lay out. This consists of proper location of the following major equipments 1) turbo

generator ii) condensate pumps ill) circulating water pumps iv) LP heaters v) HP heaters vi)

boiler feed pumps vii) oil coolers viii) stator water cooling system and various local control

panels. Turbine operating floor should be in line with the main control room as far as

possible so as to have easy and direct access between the two. This floor should have as

little obstruction on the floor as possible. Openings are left in the floor for approaching

equipment which is located underneath. The level of rails for EOT crane is chosen carefully

so that while moving one part across the T.G. bay no hindrance is possible from any existing

equipment. Generally this takes in to consideration the length of HP heater shell which may

have to be removed for periodic maintenance. Another major decision in TG bay is to have

the basement floor or not.

3.4 ELECTRICAL BAY

In this bay UCB and electrical equipment is located. The lay out on this bay depends

upon the lay out of UCB, the relative location of UCB with respect to the boiler turbine hall,

the size of UCB and the electrical cubicals. Care has to be taken in arranging the electrical

equipment in such a way so as to have easy access from turbine hall to the boiler, from one

floor to another and from UCB 'to boiler and turbine. Generally UCB is air-conditioned and

air-conditioning equipment is located on the roof of UCB. It has been observed that location

of air-conditioning equipment creates vibrations which are some times not damped to proper

limits and thus becomes a permanent source of nuisance. UCB is provided with a false

ceiling- over which the air-condition ducts are laid out. While deciding the next floor above

UCB this factor has to be kept while locating the battery room and arrangement of removal

of acid fumes is to be incorporated along with the room.

PAGE-39





PAGE-40

3.5 LOCATION OF DEAERATOR

Deaerator location has certain basic pro-cess requirements with respect to the boiler

feed pump. Each boiler feed pump is designed to operate under a particular net positive

suction head and this has to be provided by increasing the deaerator level to particular height.

Moreover relative location of deaerator with respect to the boiler feed pump should be

chosen so as to have minimum BFP suction line. Sometimes a platform is provided above

the deaerator to have easy access to various valves coming above it. Deaerator-is one of the

heaviest equipments and requires rigid as well as floating supports. Provision has to be made

in its foundation to take care of these requirements.

3.6 MILL BAY

Coal from the coal yard is crushed to 25mm size and conveyed through a conveyor

gallery to the transfer points. From the transfer point another pair of conveyor belts carry the

coal to the bunkers. Size of bunkers play an important part in deciding the necessary

structure for accommodating bunkers as well as the mill underneath. The top of coal transfer

equipment from raw coal bunkers to mill and further the fuel piping lay out affects the mill

bay lay out to a large extent. Mill bay lay out in the case of indirect firing is quite

complicated whereas in case of direct firing it becomes very simple. However lay out

engineer has to provide the necessary structure for both type of coal feeding processes.

Conventionally the milling in station with 210 MW units are. housed in the space available

between the boiler and the power house in a line and ducting have been conveniently done

with six mills. But, for 500 MW units 8 or 9 mills if they are laid in one line the ducting is

expected to get fairly complicated. So, in general designers prefer locating mills and bunkers

on the other side.



FIG. 3.3 CROSS - SECTION OF TYPICAL STATION CONTAINING 500 MW UNITS

WITH A LONGITUDIANL TURBINE ARRANGEMENT

3.7 GENERAL CONSIDERATIONS

In any plant lay out care has to be taken to provide the basic necessities such as toilets

and wash rooms, drinking water, rest rooms, engineers cabin, small stores, passages and

stairs. Generally lift is provided on two ends of the main building with a provision for an

additional goods lift somewhere in between. This leads to

PAGE-41

easy transfer to heavy equipment from one floor to another. With the higher capacity units

an additional lift for reaching the top of the boiler is also provided.

3.8 PIPING LAYOUT

Besides equipment lay out station lay out engineer has to keep in view for the pipe

routing not only for high pressure piping but also for low Pressure piping. Lay out of high

Pressure piping has to take into consideration the stress analysis point of view; pipe hatches

are provided in between the columns to take care of various pipes crossing the floor. Also

pipes are supported on brackets located in trenches as well as the tunnels so as to have

minimum interference between them and the adjoining equipment.



FIG. 3.4 SINGRAULI STPP 500 MW UNITS

3.9 ELECTRICAL CABLES

Provision has to be made in the station lay out for laying up electrical cables. For this

generally two cables galleries are provided in electrical bay. In TG bay generally cables are

taken in small cable trenches and with pipes near the motors. In boiler area they are being

taken in cable tunnels and trenches. In some of the units the practice of laying these cable

overhead is also combined with the convectional method of laying the cables in trenches.

3.10 VENTILATION

For proper ventilating in the whole building windows are provided but they are not

sufficient and hence are supplemented by having exhaust fans either on the sides or in the

roof. Space has to be provided for Ahe ventilation equipment in the main building as far as

possible.

3.11 LAYOUT AIDS

The lay out engineer has to work in close co-operation with the engineers of

electricals as

PAGE-43

well as civil design side. Sometimes he may have to change his lay out as there are certain

civil engineering constraints and also certain electrical requirements. Generally templates

are used to see the various alternative locations of an equipment and these alternatives are



studied with respect to their positive and nagative points. The best way however is to have a

scale model of the whole building drawn to 1:50 of this size. This gives an ideal concept to

the whole lay out problems and they can be discussed on a rational footing.

COMBUSTION THEORY PAGE 44

4.1 COMBUSTION

(a) Combustion is the chemical reaction which takes place when a combustible element

combines with oxygen and in so doing gives off large quantities of heat.

nearly as much as when burning to carbon dioxide.

4.2 CHEMICAL FORMULAE

Consider the combination of carbon and oxygen to from carbon dioxide. This is

written as, Symbols C+ 02 C02 (and heat is released)

Weights 12 + 32 44

Atomic or molecular weights can be considered to be pounds, grams or any other

weight unit. If the weight units is in grams then we can say that 12 grams of carbon will

combine with 32 grams of oxygen to form 44 grams of carbon dioxide.

Notice that the number of atoms of each element on the left hand side of the equation

is the same as those on the right hand side. For example, in the equation about one

molecule of carbon and two of oxygen.

Similarly the formula and weights resulting from the combination of sulphur and

oxygen is required.

S + 02 SO2 (Sulphur dioxide)

Weights (Grams) 32 + 32 64

So 32 grams of sulphur combine with 32 grams of oxygen to from 64 grams of

sulphur dioxide.

Often more than one atom or molecule is required to satisfy an equation. For example,

suppose there is only a limited supply of oxygen available for combination with carbon.

Then in-stead of forming carbon dioxide as we saw earlier, the result now will be carbon

monoxide. We might be tempted to write this formula as,

C +O2 CO2 + heat

1 (g) + 2.67 (g) 3.67 (g) + 33.94 kJ (i)



These are rounded values as undue accuracy is unnecessary. For example, 32 is really

2.66666............

So, 1 gram of carbon requires 2.67 grams of oxygen for complete combustion and will

produce 3.67 grams of carbon dioxide and release 33.94 kj of heat.

If, on the other hand, there is only limited oxygen available carbon monoxide will be

produced, and heat will be released, although not Nearly as much as when burning to carbon

dioxide.

2C + 02 2 CO + Heat

Weight 2 x 12 + 32 2 (12 + 16) + Heat

i:e., 24 + 32 56 + 242.88 kJ

For 1 gram carbon 24 + 32 56 + 242.88

24 32 56 24

i.e. 1 gram C + 1.33 grams 02 2.33 grams

CO + 10.12 kJ Heat (2)

So, 1 gram of carbon will combine with 1.33 grams of oxygen to give 2.33 grams of

carbon monoxide and release 10.2 kJ of heat

Notice the equations (i) and (ii), the dramatic reduction, about two thirds, in heat

release between burning carbon to carbon dioxide that the number of atoms of each ide, and

carbon to carbon monoxide.

In a similar manner to the foregoing the oxygen; required for all the combustible

substance can be calculated. However we are concerned with the air required for

combustion and this can be calculated from a knowledge of the oxygen required. As was

stated earlier, the oxygen is derived from air of which it forms 23.2% by weight. This means

that the are 23.2 grams of oxygen in 100 grams of air.

So, there are 23.2/23.2 grams of oxygen in 100/23.2 grams of air.

i.e. 1 gram of oxygen in 1/0.232 grams of air

or 1 gram of oxygen in 4.31 grams of air -(3)

4.3 THE NECESSARY OF AIR IN THE COMBUSTION PROCESS

When combustible substances such as carbon, hydrogen, sulphur etc. are oxidised (i.e.

combined chemically with oxygen) in the combustion process, the oxygen is obtained from

air which may be regarded as a mixture of 23.2% oxygen and 76.8% nitrogen by weight.

The trace gases present are so small in quantity that for our purpose they can be ignored.

This air is as necessary as the fuel itself if combustion is to be achieved. Of course, it is only



the oxygen which combines with fuel, the nitrogen takes no part in the combustion process

and asses through the boiler unchanged except that it becomes heated and so carries valuable

heat to the stack. PAGE 44

4.4 QUANTITY OF AIR REQUIRED FOR COMBUSTION

The necessity of oxygen in the combustion of fuel has already been stressed. If the

amount of oxygen available is abundant then complete oxidation, and therefore, complete

heat release, will take place.

If carbon is burned with sample oxygen, the final product will be carbon dioxide

which cannot be burned any further. (in fact, carbon dioxide is used as a fire fighting

substances).

So, C + 02 C02 (and heat is released in the process)

Weights (grams) 12 + 32 44 (and 407 kJ of heat)

So 12 grams. of carbon, is burned to carbon dioxide will release 407 kJ of heat, a

figure which has been determined by measurement.

To find the values for burning 1 gram of carbon, divide 'everything by 12, i.e.

12 + 32 44 + 407

12 12 12 12

Further, it has been stated that air is assumed to consist of only oxygen and nitrogen.

So if there is 1 gram of oxygen in 4.31 grams of air then it follows that there must be 3.31

gram of nitrogen per gram of oxygen (4)

Nitrogen takes no part in the combustion process but carries valuable heat to the stack

and also causes physical disadvantages. For example, ducts and fans have to be very large to

transport the enormous quantities of nitrogen in the air and gas circuits. In the case of a 500

MW boiler which requires about 1700 tonnes (3,750,00 ]b) of air per hour, about 1300

tonnes is nitrogen.

We can now calculate how much air is required to bum 1 -'gram of carbon to carbon

dioxide. The results obtained in equation (1) were

C + 02 C02 + heat

Weights 1 gram + 2.67 grams 3.67 grams + 33.94 kj

Thus 2.67 grams of oxygen must be supplied. But from equation (3) above we have

calculated that every gram of oxygen requires 4.31 grams of air. So 2.67 grams of oxygen

require 2.67 x 4.31 = 11.49 grams of air.



Therefore to burn 1 gram of carbon completely requires 11.49 grams of air which

contains 2.67 grams of oxygen and 8.82 grams of nitrogen. The products of combustion will

be 3.67 grams of carbon dioxide and the 8.82 grams of nitrogen.

Table 1 - Combustion Data Theoretically Products of Combustion Molecular Required Grams/Gram Substance Symbol Grams/Gram O2 Air CO2 H2O N2 CO SO2 Carbon (to CO2) C 2.67 11.49 3.67 ---- 8.82 ---- ---- Carbon (to CO) C 1.33 5.75 ---- ---- 4.42 2.33 ---- CO to CO2 CO 0.57 2.46 1.57 ---- 1.89 ---- ---- Sulphur (to SO2) Symbol 1.00 4.31 ---- ---- 3.31 ---- 2.00 Hydrogen (to H2O) H2 8.00 34.48 ---- 9.00 36.48 ---- ---- Methane CH4 4.00 17.24 2.75 2.25 13.24 ---- ---- Acetylene C2H2 3.08 13.26 3.38 0.69 10.18 ---- ---- Ethylene C2H4 3.43 14.78 3.14 1.29 11.35 ---- ---- Hydrogen Sulphide H2S 1.41 6.09 ---- 0.53 4.68 ---- 1.88

4.5 DERIVATION OF GENERAL FORMULA FOR WEIGHT OF AIR REQUIR£D

It will normally be found most convenient to use Table 1 for calculations. However,

there are occasions when it is helpful to have a simple formula from which the air required

can be calculated, and this will now be considered. Most fuels contain very few combustible

substances, normally they are only carbon, hydrogen and sulphur.

Consider each of the three in turn,

PAGE-45

(i) Carbon

We know that the formula is,

Weight C + 02 C02

12 + 32 44

12 32 44

i.e. 1 + 8 11

3 3

Thus the oxygen required is 813 the weight of carbon and the C02 produced is 11/3 the

weight of carbon.

i.e. O2 = 8C and CO2 = 11C (6)

3 3



(ii) Hydrogen

2H2 + 02 2H20

Weight 4 + 32 36

1 + 8 9

The oxygen required is 8 times the weight of hydrogen and the water vapour produced

is 9 times the weight of hydrogen.

i.e. 02= 8H, and H20 = 9H (7)

(iii) Sulphur

S + 02 S02

Weight 32 + 32 64

or 1 + 1 2

The oxygen require is the same as the sulphur and the sulphur dioxide produced is twice the

weight of the sulphur,

i.e. 02= 1 S and SO2 = 2 S (8)

Combining equations (6), (7) and (8) the total oxygen required for any fuel is

Oxygen in grams/gramfuel 813 C + 8H + S (9)

However, there is one complication, Fuels often contain oxygen and this available

combustion in just the same way as oxygen from the air and so allowance must be made for

it. This is done by assuming that all the oxygen in the fuel will combine with the necessary

amount of hydrogen, i.e. with 1/8 of its weight of hydrogen.

For example, if there is X grams of oxygen in a certain weight of fuel then it will

combine with X/8 grams of hydrogen. Hence the hydrogen remaining.in the fuel will be,

(H-0/8) where H is the original weight of hydrogen in the fuel 0 is the original weight

of oxygen in the fuel

So (9) becomes modified to :-

Oxygeningramslgramfuel=8/3C+8(H-018)+S (10)

Where C = weight of carbon per gram of fuel

H = weight of hydrogen per gram of fuel

O = weight of oxygen per gram of fuel of fuel

S = weight of sulphur per gram

The air required to supply this oxygen is, from equation (3) 4.31 grams per gram of

oxygen.

So the general formula for air required 1 gram of fuel



= 4.31 (8/3 C+8 (H - 0/8) + S)

grams (1 1)

It follows from equations (6), (7) and (8) that the products of complete combustion

with only the theoretical weight of air will be :-

Carbon dioxide (C02) = 11/3 C grams/gram fuel

Water vapour (H, 0) = 9 H grams/gram fue

Sulphur dioxide (S02) = 2 S grams/gram fuel

Also there will be in the gas, nitrogen (N 2) equal to 0.768 times the weight of air

supplied.

Example :

A fuel contains 54% carbon, 3.7% hydrogen, 1.0% sulphur, 0.8% oxygen, and a

further percentage mainly of ash and moisture. What is the theoretical weight of air required

per gram of fuel ?

Air required

= 4.31 (8/3C + 8 (8H - 018) + S) gram

= 4.31 (8/8 x 0.54) + 8(0.037 - 0.008/8) + 0.01) gram

= 4.31 (1.44 + 8 (0.036) + 0.016) grams

= 4.31 (1.44 + 0.288 + 0.016) grams

= 4.31 x 1.744 grams

Air required = 7.517 grams

When the combustion is complete only with the theoretical amount of air then it is

said to be PERFECT (STOICHIOMETRIC) COMBUSTION. Thus the air weight of 7.517

grams in the calculation above is that required for perfect

combustion.

Note : Stoichlometfic combustion air is the theoretical air required to bum the fuel to acheive

100% combustion without adding any excess air.

Asample datasheet is enclosed for finding the air and gas weight based on the ultimate

analysis of fuel.

PAGE-46



PAGE-47

4.6 'EXCESS AIR

In practice, if fuel is burned with only the theoretical amount of air present, then the

combustion will be very poor due to incomplete mixing of the air with the fuel. After all, it

would be expecting rather a lot to have every single particle of oxygen in exactly the fight

place for combustion at exactly the right time. Consequently, it is necessary to supply more

air than the theoretical minimum, and this is known as excess' air.

The effect of supplying only the theoretical amount of air for combustion with coal is

shown in Figure 4.1 (a). Some coal remains unburnt and some oxygen passes through the

fire without entering into chemical combination with the constituents of the fuel. This free

oxygen appears at the chimney along with unburnt gases such as carbon monoxide. This

represents a great loss of available heat as the gases are only partly burnt.



In the case being considered 10% of the heat may be lost as unbumt carbon in ash,

possibly a further 15% may be lost up the chemney as unburnt gas. Thus about 75% of the

heat is liberated in the furnace.

Admitting more air will reduce the losses considerably, as the change of the carbon

and hydrogen atoms meeting the necessary oxygen atoms has increased greatly. The

additional oxygen enables more of the carbon to be burnt and so reduces the loss due to

carbon in ash. Also there is no methane and no appreciable carbon monoxide in the fuel

gases and so the loss due to unbumt gas is almost eliminated. See Figure 4.1 (b).

PAGE 48

If even more excess air is admitted, as shown in Figure 4.1 (c) the combustion Fig 4.1

(b) losses can be reduced even further. There is now so much oxygen available that every

atom of the combustion material can easily find plenty of oxygen atoms to chemically

combine. Hence the combustion of the fuel is practically complete. The unburnt gas loss is

reduced to zero and the loss



Fig. 4. 1 (b)

15% EXCESS AIR - LESS

INCOMPLETE COMPUSTION

due to carbon in ash is low. The combustion losses are now so low that something like

99.5% of the heat in the fuel is liberated. On the other hand, the quantity of gas has

increased consid-erably because of the large amount of excess air This is equally

unsatisfactory because it carries heat away and extra fan power is used. Perhaps the

foregoing will be easier to comprehend when we study the losses influenced by the excess

air.



Fig. 4. 1 (C)

100% EXCESS AIR - ALMOST

COMPLETE COMBUSTION

LOSSES INFLUENCED BY EXCESS

There are six boiler losses. Three are influenced significantly by the excess air,

(1) Loss due to unbumt gas

(2) Loss due dry flue gas

(3) Loss due to combustible in ash (or carbon in ash)

and these are not influenced significantly by the excess air.

(4) Loss due to burning hydrogen

(5) Loss due to moisture in fuel

(6) Radiation, and unaccounted losses

(which includes moisture in air)

UNBURNT GAS LOSS



Remember the unburnt gas loss is mainly. The result of burning carbon to carbon

monoxide instead of carbon dioxide. In the first case less than one third of the potential

heat of the carbon is released.Obviously an abundant supply of oxygen i.e. more air, will

quickly reduce this loss to zero.

PAGE-49

In Figure 4.2 (a) the loss is high with no excess air but rapidly falls to zero as more air

is admitted.

Fig. 4.2 (a)

PERCENTAGE EXCESS AIR

DRY FLUE GAS LOSS

A further loss of heat is due to the dry flue gas, often referred to as the stack loss. As

more excess air is admitted this loss increases as shown in Figure 4.2 (b).

COMBUSTIBLE IN ASH LOSS

This loss is very high when there is little or no excess air, because mixing of

combustible material and oxygen is so poor. As the air quantity is increased the loss fails

rapidly. However, it does not reach zero because the loss depends upon two factors when

burning coal. Firstly, the air/coat mixture must be correct, secondly it depends upon the

fineness of grinding in the case of p.f. firing, or the grate speed in the case of stoker firing.

For p.f. which is now the dominant firing method, the more finely the coal is ground,

the greater the surface area of the coal, and so cumbustion is more nearly complete and the

carbon in ash loss is smaller. In practice, though, a stage is reached where it is not worth



grinding the coal any finer because it will cost more to grind than the extra heat release is

worth. Hence in Fig. 4.2(c) the loss does not reduce to zero. Generally, a high volatile coal is

ground until 75% of its bulk passes through a 200 mesh sieve whereas a low volatile coal is

ground until 80% passes through a similar mesh.

COMBINED HEAT LOSS

If the above three losses are added, then the result is as shown in Fig. 4.2(d). The loss

gets less as excess air is added, reaches a minimum and then increases as still more excess air

is added. Thus there is only one quantity of excess air which will give the lowest loss for the

combustion of a particular fuel. PAGE 50



Expressed another way, there is only one value of excess air which will give the

maximum efficiency. Just what that value is depends upon the quantity of fuel used and the

type of firing, e.g. oil, p.f., chain grate, etc. It is now clear to see why it is important to

operate at the optimum excess air at all times.

If it was possible to bum a fuel complete with only the theoretical amount of air (i.e. if

the combustion was perfect) the percentage CO2 produced would be the theoretical

maximum possible for the fuel, as shown in Table 11.

Table ll Theoretical Maximum CO2 for Various Fuels

Fur$ Max C02%

Bituminous Coal 18.6

Coke 19.7

Anthracite 19.5

Lignite 19.0-19.5

Peal 19.5-20.1

Fuel Oil 15.3

Natural Gas 11.8



However, as has been stated before that it is not practical to operate with only the

theoretical amount of air. Therefore excess air must be supplied and the effect of this is to

lower the CO2' Measurement of the actual CO2 level provides a simple means of determining

the excess air present as it is the ratio of the theoretical and actual CO s. For example if

bituminous coal was burned with a C02 of 15.5% the excess air would be

Theoretical maximum CO2 x 1 00% = theoretical air

Actual C02

18.6 x 100 = 120% of theoretical,air, i.e. 20% excess air

A handy formula to remember is

THEORETICAL AIR x THEORETICAL CO2 ACTUAL AIR x ACTUAL C02

The relationship between excess air and C02 is shown in Fig. 4.3

Air inleakage into boiler gas passes

From the combustion chamber onward the gas passes are normally under suction, and

the amount of suction increases nearer to the ID fan inlet. Hence, small hole in the ducting

will cause more air leak in the gas circuit.

Using the principles established earlier it is a simple matter to calculate the air ingress

between two points in the gas circuit. One of the most important places to monitor is at

rotary air heaters. The seats are never completely effective so there is always a leakage of air

in the gas side. Even on a good air heater the leakage is enough to lower the CO2 of the flue

gas by about 1% from air heater inlet to outlet.



PAGE 51

Fig. 4.4 gives typical air; coal and gas coal ratios by weight and indicates the

increasing dilution of CO, due to air inleakage in various parts of th . e gas circuit of a well

maintained coat fired boiler. Even though well maintained the air inleakage is quite

pronounced. ideally all the air admitted to a boiler is done so deliberately. Air leakage

should be eliminated as far as possible since it has several adverse effects such as :

a) Increase loading of the ID fans which, if at a maximum will limit the MW output of

the unit. Reduced boiler efficiency due to increased flue gas loss if the air ingress

occurs before the air heater gas outlet.

b) Combustion chamber cooling and interference with combustion in inleakage occurs at

ash hopper seals.

c) Possible acidic deposition in gas ducts, precipitators, and ID fans, if air ingress occurs

after air heater gas outlet.

d) Affect an automatic boiler control if air inleakage occur at open ash hopper doors, or

is lost through air duct seals and joints.

PAGE-52



PAGE-53



4.7 IGNITION TEMPERATURE

The minimum temperature at which the substance will bum, is known as Ignition

temperature of the particular substance.

Every combustible substance has an ignition temperature of which it must be raised e

re It will burn. The temperature varies with different substances as shown in Table III.

TABLE Ill - IGNITION TEMPERATURE

Ignitioon Temperature Substance Molecular Symbol

oC oF

Sulphur S 243 470

Fixed Carbon C -Bituminous coal --- 408 766

-Semi-bituminous coal --- 466 870

-Anthracite --- 496 925

Acetylene C2H2 482 900

Ethane C2H6 538 1000

Hydrogen H2 610 1130

Methane CH4 650 1202

Carbon Monoxide CO 654 1210

For combustion of a fuel to take place there are two requirements to be met. Firstly

there must. be sufficient oxygen, and secondly the ignition temperature of the fuel must be

reached. Note that the ignition temperatures of the gases in coal vary from one another, and

are considerably higher than that of the fixed carbon of the coal. When coal is burnt what

normally happens is that the gaseous constituents are distilled off (but not ignited) before the

ignition temperature of the carbon is reached. Thus the ignition temperature of coat is

regarded as the igniti6n temperature of its fixed carbon content. Once the combustion has

started, the heat evolved will maintain, under correct conditions, a high enough temperature

to sustain combustion.

4.8 HEATING VALUE OF FUELS

The heating value per unit quantity of a fuel is known as its calorific value. This is

the basic standard of value for any fuel. It is the number of heat units liberated per unit

weight of the fuel when completely burnt in oxygen. It is measured in kJ/kg or btuab for

solid or liquid fuels. Gaseous fuels normally have the CV expressed in kJ/m3 or btu/ft.

There are two calorific values for any fuel in which water vapour appears in the products

of combustion.



(i) The higher or gross calorific value (GC V)

(ii) The lower or net calorific value (NCV)

In the determination of the GCV the total heat released from the fuel is measured

until the products of combustion are reduced to 250C.

However, in a boiler the final flue gas temperature is considerably higher than 1000C.

Consequently, any water vapour present (derived from the moisture in the fuel and also from

the combustion of the hydrogen in the fuel) will pass to the chimney as vapour, and so some

of the water vapour will not be available as useful heat, reckoned as 2,442 KJ/Kg of water

vapour.

It follows that the useful heating value of the fuel is less than its GCV. Hence the net

calorific value = gross calorific value -2,442 (M + 9H) kJ/kg of fuel where M & H are the

weights of moisture and hydrogen per kg of fuel. Using the NCV acknowledges that the

latent heat of the water vapour in the flue gases is not available for transfer to the boiler and

the loss is not debited against the boiler efficiency. On the other hand, if we are concerned

with the fuel and its total heating value then the GCV is used. The gross calorific value of

coal is determined by laboratory test using a bomb calorimeter.

The approximate heat of combustion of vanous substances is listed in Table IV.

Notice that it is only those substances which bum to form wet products which have a lower

and higher heat value.

PAGE-54

Table IV Heating Value of Various Substances

(average values at atmospheric pressure and cooled to 25OC)

Heat Value KJ/Kg Substance Symbol Higher

(GCV) Lower

(LCV) Hydrogen H2 144000 122000 Carbon (to CO) C 10200 ----

Carbon (to CO2) c 33820 ---- Carbon Monoxide CO 10250 ----

(to CO2)

Methane CH4 55700 50100 Sulphur (to SO2) S 9304 ---- Fuel oil 44000 41400 Coal gas 36800 32800 Natural gas 58700 56500

Of the substances listed in the table hydrogen has highest calorific value.



With all the fossil fuel burnt in. power stations, hydrogen, carbon and sulphur which

contribute to the production of heat. The sulphur content is usually small and since its

calorific value is low the contribution of sulphur to the total heat release is not very

significant.

Thus the calorific value of fuels is prima-rily determined by the hydrogen and carbon

content. The higher the ratio of hydrogen to carbon in a fuel, the higher the calorific value of

the fuel. The effect is seen in Table V for typical analysis of natural gas, fuel oil and coal.

Table V - Effect of Hydrogen : Carbon Ratio on Heating Value of Fuels.

Fuel %

Hydrogen %

Carbon %

Sulphur H2:C

Ratio G.C.V

KJ/Kg.

Natural gas 24.3 74.06 01:03.0 50986

Fuel oil 11.63 83.52 3.27 01:07.2 43612

Midlands coal 4.4 65.1 2.1 01:14.8 21687

An approximation to the calorific value can be obtained from a knowledge of the

chemical composition of the fuel. The only combustible substances present in power

station fuels are carbon, hydrogen, and sulphur. So, by multiplying each constituent by its

heat value from Table V. a reasonable approximation of the CV can be obtained.

The formula (known as Dulong's formula) is,

GCV = 33,820C + 144,000 H - 0/8 + 9.204S KJ/Kg

Where C,H,0 and S are the proportionate parts by weight of Carbon, Hydrogen, Oxygen &

Sulphur respectively.

The term (H - 0/8) is assumed to contain a correction for the hydrogen in the fuel which

combines with oxygen in the fuel to form water vapour as explained before.

For example a coal has the following ultimate analysis.

Moisture 18.0%

Ash 8.0%

Carbon 59.0%

Hydrogen 3.7%

Nitrogen 1.2%

Sulphur 1.7%

Oxygen 8.4%

GCV 23,842 kJ/kg as determined by bomb calorimeter



Using Dulong's formula the GCV is given by.

PAGE 55

GCV (33,820 x 0.59) + 144,000 (0,037 - 0.084/8) + (9,304 x 0.017)

= 19,954 + 3,888 +,158

= 24,000 kj/kg

The difference between the two values is less than 0.7%

4.9 PULVERISED FUEL FIRING

Burning powdered (pulverised) coal for generating steam was applied commercially

in the early 1920s. Since then it has become.almost universal in central stations using coal

for fuel. Coal is first ground to dust and then this powdered coal is carried by stream, of air

into the furnace.

High temperature flames in the furnace heat the entering coal particles to distill off the

volatile matter. The volatile gases mix with the oxygen of air, further heating ignites them

and they bum quickly.

Heating the carbon raises it to ignition temperature and it reacts with the oxygen of

the hot air in the furnace to release heat energy. This forms a blanket of combustion

products on carbon particles and prevent additional oxygen from contacting unbumt portion.

To expose the unburned carbon ndemeath to fresh supplies of oxygen, the blanket of gaseous

products must be stripped off by turbulent mixing of the cabron particles and air. So we see

that proper burning required, the following conditions to be satisfied.

i) Supplying proper proportions of air.

ii) Thorough mixing of fuel and air

iii) 'Orovide enough furnace volume to allow time for completing the combustion

reaction.

iv) Maintain a furnace temperature, high enough to ignite incoming fuel-air mixture.

The ash remainin after completing corn-bustion reactions fails to the furnace bottom,

or floats in the combustion gases to the boiler flue gas outlet, or deposits on the boiler

heating surfaces.

Pulverised coal furnace must withstand the high temperature and be proportioned to

hold the volume of fuel, air and gases and allow sufficient time for complete burning.

The success of pulverized coal burning is due to the greater surface exposed by

breaking a given mass of coal into smaller pieces.



For example, at 0.1" diameter, a sphere has 60 sq in surface per cubic inch volume;

at 0.01" it has 600 sq. inch/cub. inch. Greater surface per unit mass of coal allows faster

com-bustion reaction because more carbon becomes exposedto heat and oxygen. This also

reduce the excess air needed to ensure complete combustion. In turn this reduces the dry-gas

loss and raises the overall steam generating efficiency. Added costs of coal grinding

equipment and grdinding energy partly offset these advantages.

Design of pulverised fuel burners and combustion chambers play most important role

in stabilising a flame of required dimensions. It is impossible to stabilise a small flame on a

cold unenclosed burner with pulverised fuel firing.

The reason behind this is that the existence of a P.F. flame depends on two

complementary factors :

(1) Small particle size

(2) Supporting ignition source.

Since a pulvedzed-fuel is composed of multitudes of particles, the radiation intensity

from the flames and hence the radiation heat loss is high. Obviously if this is too high,

compared to the rate of energy generated by the reaction, the flame will be extinguished.

Therefore, to maintain the flame, the ratio (heat generated/heat lost) must exceed some

critical value. This is achieved by increasing the total size of the flame so that the surface to

volume ratio is decreased and therefore the average heat loss per unit volume of flame is

decreased.

On the other hand, once the flame is established and the heat loss by radiation (which

is proportional to TI) to the surrounding combustion wall is excessively high, it may cause

fusion of coat ash.

The design of pulverized fuel burners and combustion chambers should be

compromise of the two extreme ends i.e. extension of the flame and. overheating of furnace

walls.

Flame speed is very much dependent on size and shape of flame and nature of the

materials of the furnace wall. Since these effect, the thermal load and therefore the flame

temperature, they also effect the rate of heat transfer ahead of the flame which primarily

controls the flame speed. To maintain the flame speed it is therefore necessary to maintain

the flame temperature and this reintroduces the importance of mixing the primary and

secondary air.PAGE 56

4.9.1 Application of flame speed on burner design



The coal dust is injected into the com-bustion chamber in a jet and, as the jet expands,

the velocity drops. The flame front will therefore take up a position such that the speeds of

the flame and the dust cloud are equal and opposite. Now, since the maximum conveying

speed for hidzontal delivery is roughly 6Oft/sec. this is the minimum entry speed for dust jet

and always greater than the maximum flame speed. Since it is desirable for the incoming

dust to be. ignited as fast as possible to avoid wasting of combustion space, this obviously

achieved when the cloud conditions are such that the flame speed is at its maximum i.e.

when the dust is injected as the optimum concentration.

As the optimum concentrations are greater than the stoichiometric there is insufficient

air in the primary stream for complete combustion, so this must be supplied as secondary air,

'if secondary air is introduced too soon the flame speed drops, the flame becomes less stable,

the flame front moves downstream further into the combustion chamber, and in the extreme

case moves right out of the chamber, so that ignition is lost.

The design of bumers, therefore,.should be such as to avoid the difficulties stated

above. It should be designed to give the minimum discharge velocity of 60 ft/sec. and

above. The best point for introduction of secondary air is still not known for certain but it is

probably somewhere near the tail of the volatile flame. In general it should be as rapid as

possible which is best achieved by siting the secondary parts so as to direct the secondary air

at right angles to the main stream to ensure the best penetration. Fig. 4.5 & Fig. 4.6 shows

typical oilgun and coal compartment assembly for tilting tangential firing system employed

in 110 MW & 210 MW BHEL boilers.

The above design of burner should all fight for bituminous coal (high VM), but for low

volatile coals this needs some modified treatment, if the secondary air is introduced too

quickly it will apparently kill the flame. The most probable reason is the effect of chilling

the flame by introducing large quantity of cold air. In order this secondary air must be

introduced in stages to maintainthe flame temperature.

4.9.2 Types of P.F. Firing

Three main types of firing are used in P.F. installations (1) vertical or U firing (2)

Wall firing and (3 coner (or tangential) firing. (Sel 'fig. 5.7)

(1) Vertical U firing is commonly used for burning low volatile coal. The burner is fitted

in the roof or top of the furnace with the burner directing the discharge of the fuel

downwards, thus giving longer pas-sage to flow of gases than is the case with other

systems. Since there is a considerable length of flame travel premissible before



combustion is com-plete, the burner itself i@Inot required to make an intensive

mixture.

(2) Wall firing is the arrangement in which the fuel@@ is projected more or less

horizontally into the furnace from one or more walls and is frequently used for firing

high volatile fuels. Where firing is done form one wall only of the furnace the burner

must be relied upon to provide the necessary turbulence.

(3) In corner or tangential firing, the fuel is projected horizontally from the corner of the

furnace towards the centre so as to alight tangentially on the circumference of an

imaginary circle about 4 ft. diameter in the centre of the furnace. Corner firing makes

the best use of furnace capacity and permits a reduction in furnace difficulties in the

boiler and superheating surfaces.

Turbulent combustion is achieved in corner firing by the vortex formation where the

four jets meet in the centre of the furnace (Fig. 4.8 & 4.9).

Adjustable or tilting type of bumers have been developed for tangential firing. The

P.F.

PAGE-57



PAGE-58

PAGE-59

nozzles are adjustable through a total are of 60', i.e. 3011 above and below the normal

horizontal axis by which there is control over the quantity of heat absorbed b the heating

surfaces, the gas temperature in the upper furnace and superheater. (Fig. 4.10).

Fig. 4.7



4.9.3 Advantages of pulverised fuel firing system

i) - Combustion is complete with low percentage of excess air.

ii) Higher combustion efficiency.

iii) Ability to bum wide variety of coals - a wide variety of fuel can be used from coal

of low volatile matter in large combustion spaces to high volatile bituminous coals.

Low grade fuels of high ash content can be used provided special precautions are

taken to handle the clinker and ash formed and to avoid the carrying of fine dust into

atmosphere.

iv) Lower fan power

v) Fast response to load changes.

vi) Ease of burning alternately with, or in combination with gas and oil.

vii) Ability to release large amounts of heat.

viii) For metallurgical purposes high flame temperatures are possible and the character

of the flame, whether oxidising or reducing, is under easy control.

4.9.4 Disadvantages of pulverized fuel firing

i) Added investment in coal preparation equipment.

ii) Added power needed for pulverizing coal.

iii) Large volume furnace needed to withstand high gas temperatures.

iv) Investment in stack fly-ash removal equipment.

These disadvantages effect some of the advantages cited but the net gain has led to the

wide use of pulverized coal firing.

4.10 FLUE GAS ANALYSIS

Efficient combustion is dependent upon the correct supply of air. It has been stated it

is necessary to supply excess air to ensure that combustion is complete, but the ideal amount

is quite critical - too much will lead to an increase in the stack loss and too little will lead to

incomplete combustion. The method of determining the quantity of excess air present is by

analysis of the flue gas. In the past it was common to do this by measuring the cabron

dioxide content of the flue gas. It will be appreciated that the Co. content the greater the

excess air present. However, the CO. indication has several limitations:-

(i) It is not a direct measure of excess air.

(ii) The indication is affected by the hydrogen/carbon ratio of the fuel. For example

the ratio of hydrogen to carbon is different in, say, fuel oil to coal. Thus 10% C02



when burning oil represents a different amount of excess air then loo/' C02 when

burning oil represents a different amount of excess air then 10% CO2 when

burning coal.

(iii) As the excess air is reduced %the C020/o increases until the CO 2 is at maximum.

Further reduction of excess air results in decreasing C02%. This may be interpret-

ed that the excess air has increased.

PAGE-60



PAGE-61

PAGE-62

If instead of CO2 an indication of 02 is provided then the relationship between excess air and

percentage oxygen in the flue gas is almost constant.

Oxygen analysers are ideal for use in boiler automatic control schemes for 'oxygen trim'

control.

With most CO2 and 02 analysers it is necessary to withdraw a sample.of gas from the

measuring point for external analysis. This results in practical problems, the main two

being.

- Frequent cleaning of the filter at the end of the probe.

- Condensation forming in the pipe carrying the sample to the analyser.

Considerable time and effort is required to maintain such instruments at an acceptable level

of availability. A recent development, the zirconia analyser, overcomes these problems by

analyzing the gas as it flows through the boiler gas ducting.

PAGE-63

5.0 STEAM CYCLE THEORY AND CYCLE CONSTRAINTS



5.1 Over the years, and particularly the last three decades the size and terminal

conditions of generating plants has continuously increased at a remarkable rate as shown in

the table given below :

TABLE - 1

Steam conditions Press/Temp/Reheat

Design Efficiency of Power plant

Size of set

bar/-oC % MW 41.4/462 27.5 30 62.1/482 30.5 60 103.4/566 33.7 100 103.4/538/538 Reheat 35.7 120 162/566/538 Reheat 37.3 200 158.6/566/566 Reheat 37.7 275 158.6/566/566 Reheat 38.4 550 158.6/566/566 Reheat 38.4 350 241.3/593/566 Supercritical 39 375 158.6/566/566 Reheat 39.25 500

The main incentive to keep striving for bigger and better plant is that one expects the

thermal efficiency to improve with size and the capital cost per MW decreases with the

increase of size.

It can be seen that steam temperatures have increased at quite a slow rate. This is

because increasing steam temperature is inti mately bound up with metallurgical advances

and such advances are painfully slow. On the other hand, by increasing the steam pressure,

ifitroduc- ing reheat and rapidly increasing output it has been possible to reduce the cost per

MW of installed plant considerably.

Increased output is normally associated with increasing pressure and temperature

conditions. This is because :-

i. The higher cost of high temperature components is partly effected by a reduction in

the number of components pe r MW.

ii. Losses become proportionately smaller in the large machine.

iii. High density steam must be associated with large flows to give reasonably sized

H.P. blades.

5.2 TEMPERATURE ENTROPY DIAGRAM

The temperature entropy (T-S) diagram is probably the most useful diagram of all for

illus- trating certain fundamental points about steam cycles. Ideal condition for an unit on a



T-diagram are indicated in (Fig. 5.1). The unit uses steam at a pressure of 100 bar absolute,

temp. 5660C (839"K) and rejects it to the condenser at 30m bar abs. (saturation temp.124.1

"C).

At point 'A' the condensate is at boiling- temperature corresponding to the back

(condens er) pressure. Heat (sensible) is added to this water to raise its temperature and pres

sure. At the point B it reaches its saturation temp. (310.9610C obtainable from steam table)

at a pressure of 100 bar. Evaporation beings at the pt. B. Heat (latent-because no rise in

temperature between B & C, as evident from the diagram) addition continues. At C

all the water evaporates and super-heating commences. This is shown by the curve CD and

at D and superheated steam temperature is 5660C.

Steam then expands isentropically i.e. enters the turbine and rotates it, as shown by

the line DEF. At point E there is no superheat left in the steam and so from E to F there is

increas-ing wetness. At F and steam is a pressure of 30m bar abs. and is passed out of the

turbine to the condenser and condensation of steam takes place as represented by the line FA.

At point A the steam has all been condensed and condensate is at boiling temperature ready

to begin another cycle.

PAGE-64

To summarise the above

AB - heating of feed water

(i.e., sensible heat addition)

BC - evaporation of water in boiler

(i.e., latent heat addition)

CD - superheating of steam

(i.e., superheat addition)

DF - expansion of steam in turbine, point E denotes and demarcation

between superheated and wet steam..

FA - condensation of steam in the condenser.

An important basic fact to remember is that heat is product of absolute temperature

and change of entropy. In other words the heat is represented by the area under the diagram:



Page 64

5.3 MORE INFORMATION FROM T.S. DIAGRAM

5.3.1 Sensible heat addition

In fig. 5.1 the sensible heat added is represented by the area AB. At A the

temperature is 24.IC and at B it is 311'C.

Now amount of sensible heat added can be found :

Sensible heat at A = 101 kJ/Kg

Sensible heat at B = 1408 kJ/Kg

(Both the values obtained from table)

So, sensible heat added = B - A = 1408 -101 = 1307 KJ/Kg

It should be noted that increasing pressure in the boiler to get more output in

turboalternator (i.e. more MW) means more sensible heat per kilogram Fig. 5.2 also presents



it graphically. As sensible heat is almost supplied in feed heaters and economisers number

of feed heaters of area of feed heating surface increases with more elevated steam condition.

Table 1 shows the increase of sensible heat with corresponding pressure.

PAGE-65

Table 1. Sensible Heat at saturation temperature.

Absolute pressure

(bar)

Saturation Temperature

(OC)

Sensible Heat

(KJ/kg)

50 263.9 1154.5

100 311.0 1408.0

150 342.1 1611.0

200 365.7 1826.5

221.2 374.15 2107.4

5.3.2 Latent Heat addition

As stated before almost all sensible heat is supplied in the feed heaters and

economiser. Water entering the boiler water wall tubes is almost at boiling temperature, fast



bit of sensible heat is added to water at the lower part of water wall tubes and thereafter

latent heat addition starts taking place.

As there is no change of temperatures (line BC in fig. 5.1 indicates so) the

water/steam mixture is about constant temperature from the bottom to the top of the tubes.

The area NBCI represents the latent heat added. Its amount can be calculated in the

following way :

Latent heat required = T(S2 S1),

wherePAGE-66

T = temp. of boiler water at B = 311 C

= 584.15 K

S2 = Entropy at C

= 5.6198kjlkgK (from T - S diagram.

Also available from table)

S1 = Entropy at B 11 shows this trend)

= 3.3605 (from T - S diagram. Also

available from table)

so, Latent heat required

= 584.111 (5.6198 - 3.3605)

= 1319.7 KJ/KgOK

It should be noted that unlike sensible heat at amount of latent heat required to

convert boiling water to dry saturated steam reduces with increase of pressure. At the critical

pressure of 221'.2 bar absolute it is Zero. (Fig. 5.3 and Table II shows this trend)

So in supercritical pressure boilers water after attaining saturation temperature flashes

instatane6usly to dry saturated steam and super heating commences.

Table 11 Latent heat at Saturation Temperature

Absolute pressure

(bar)

Saturation Temperature

(OC)

Lalent Heat

(KJ/kg)

50 263.9 1639.7

100 311.0 1319.7

150 342.1 1004.0

200 365.7 591.9

221.2 374.15 0



5.3.3 Superheat Addition

The curve CD in Fig. 5.1 shows the processor steam being superheated at a constant

pressure of 1 00 bar from the state of dry saturated steam of 31 1 "C to the designed stop

valve temperature of 566"C. The area piCD represents the amount of superheat. The

amount of heat required is obtained by deducting the total heat at C from total heat at D and

is equal to 811.6kJ/kg.

Quantity of heat required to superheat steam to a given temperature varies with

pressure as given in Table Ill.

Table Ill - Variation of super heat'for different pressures

(final temperature 570"C).

Pressure Bar

Absolute

Super heat reqd.

kJ/kg.

50 800.9

100 821.5

150 885.4

200 1033.2

5.3.4 Thermal Efficiency of the Cycle

Thermal Efficiency of the cycle is defined as :

Thermal Efficiency = Useful Heat

Total Heat

Use heat means that part of total heat which is used in rotating the turbine, i.e., when

the steam expand adiabatically (adiabatic expan-sion means no heat is accepted or rejected

during the process; all work done by steam at the expense of its internal energy) in the

turbine represented by the line DEF in fig. 5.4 Expansion of steam takes place upto a

pressure of 30m bar (24.11)C). The condensation takes place at a constant temperature, as

indicated by the line FA, untill all latent heat is removed.

Heat removed from steam or useless heat is shown by the rectangular pmAF. Amount

of this rejected can be calculated as follows :



PAGE-67

PAGE-68

Heat Rejected = T x (S 2 - S,) where,

T = Absolute temperature of. FA = (24.1 +273.15) = 297.250K

S2 = Entropy at F

= 6.8043 kJ/kgK

S1 = Entropy at A = 0.3455 kJ/kgK

So, Rejected heat

= 297.25 x (6.8043 0.3544)

= 1917.2 kJ/kg

Now, total heat, = Sensible heat + latent heat + superheat

= 1307 + 1319..7 + 811.6

= 3438.3 kJ/kg

Useful heat = Total heat - Rejected heat

So, Thermal Efficiency

= Total heat - Rejected heat

Total heat



= 1- (Rejected Heat) / (Total heat)

= 1 - (1917.2) / (3438.2)

= 0.4423 or 44.23%

This is the highest possible efficiency for a basic Rankine Cycle with steam at 100 bar

absolute, 566"C and back pressure is 30m bar. Ofcourse, in practice a turbine operating

under this cycle.will be less efficient.

It can also be noted that how superheating of steam adds to efficiency. If steam. is not

superheated the total amount of heat in this cycle will be addition of sensible ehat and latent

heat only i.e.

1307 + 1319.7 = 2626.7 kJ/kg

So, Thermal efficiency

= 1- (Rejected Heat) / (Total heat)

= 1 - (1917.2) / (2626.7)

= 0.2701 or 27.01%

Hence, efficiency of the basic Rankine Cycle can be improved by increasing the

superheat. But this scope becomes limited due to limitations of materials which can

withstand very high temperature and the cost associated with it.

5.4 REHEATING :

As told before, one obvious way to in-crease the heat available compared to the heat

rejected is to increase the superheated steam temperature. Unfortunately this is only

possible to a very small degree because of metallurgical limitations. Thus there is very

little scope in this direction. Therefore the alternative is to probably expand the steam in

the turbine to some suitable intermediate condition and then pass it back to the boiler to be

reheated to some high temperature. It is then piped back to the turbine to continue its

expansion.

Let us consider that same 1 00 bar cycle, now with reheat. Fig. 5.5 shows the cycle.

Steam as usually starts expanding after being superhealed. At the point G when the pressure

had dropped to 20 bar the steam is taken out of turbine and reheated to 566'C as shown by

the line GH. It is then fed to the L.P. turbine where it expands lo the condenser pressure.

The efficiency of the cycle is determined in a similar manner to the previous cases

and works out to be 46.09%

So, reheating had improved efficiency from 44.23% to 46.23% to 46.09%. A further

advantage of reheating is that the wetness of the exhaust steam is reduced considerably.



5.5 REGENERATIVE FEED HEATING

Steam in a thermal cycle will normally reject heat in two ways. Firstly the heat

rejected can go to waste via the condenser cooling water and secondly, the steam can reject

heat to the feed water by means of feed heaters. In the second case, all the heat is kept

within the cycle and not lost. The more steam which can be prevented from going to the

condenser, the more heat will be saved from rejection to waste. Consequently, if the steam is

allowed to expand to a certain extent in the turbine and perform useful work before it is

allowed to transfer its remaining heat to the feed water, then the quantity of work is obtained

without any condenser loss. and the cycle efficiency is improved. In

PAGE-69

PAGE-70

modem design of high capacity units the bled steam has been used for turbine driven feed

pump and its exhaust used for feed water heating in addition to the conventional extractions.



Let us again see the previous 100 bar cycle, this time with regenerative feed heating

(Fig. 5.6). The steam expands is entropically in the turbine until the temperature is 250"C

after which the steam is bled to an infinite number of feed heaters. The result is quantity of

heat represented by the area under the curve. KL is transferred to the water side shown by

the area under the curve AM. Note that M.and K are both at 2500C. The heat represented

by the area LFpr has been given to feed water whereas before it would have been rejected in

the condenser. The 'heat represented by the area LKF has also been transfered to feed water,

where as formerly it would have done some useful work in the turbine, So there is some loss

of work too. Yes, but on the balance it is better to loss the power from the triangle LKF to

save the heat' represented by large rectangle (LFpr) that would have been wasted.

Regenerative feed heating elevates the condensate temperature represented at A along

the boiling water line to M and the remaining sensible heat is supplied in the economiser and

boiler to poiint B.

Lest us find the efficiency with reheat

Total heat supplied = Sensible heat form M to B + latent heat + superheat



Amount of latent heat and superheat in this cycle are same on the previous cycle with

superheat (fig. 6.1) and equal to 1319.7 kJ/kg and 811.6 kJ/kg respectively.

Now, sensible heat = Total heat at B - total heat at M

= 322.2 kJ/kg (from steam table)

So, total heat supplied = 322.2 + 1319.7 + 811.6

= 2453.5 kJ/kg

Heat rejected = Area under ALRM

= 11 92.2 kJ/kg (from steam table)

So, efficiency = 1 -(Rejected heat) / (Total heat)

= 1- (1192.2) / (2453.5)

= 0.5140 or 51.4%

Hence you find how efficiency of the Rankine cycle changes with reheating and feed

heating.

Basic efficienecy (fig. 5.4) = 44.23%

Reheat cycle efficiency (fig. 5.5) = 46.09%

Feed heating cycle efficiency (fig. 5.6) = 51.4%

A combination of reheating and feed heating will give higher ideal cycle efficiency.

PAGE-71



5.5.1 Choice of Feed Water Temperature

Typical improvements possible with a straight regenerative cycle, as the number of

feed heating stages is increased are shown in Figure 5.7 for various steam conditions at

the turbine stop valve. It is clearly seen that the efficiency improves with each additional

heater but the incremental gain with each becomes progressive-ly smaller.

Increased thermal efficiency in terms of turbine heat consumption cannot be taken in

isolation since there are some obvious effects on plant generally, some of which are adverse.

They effect capital cost and design, and the resulting total change in the cost of the plant

must be compared with the value of the improvement in thermal efficiency obtained by

increasing the final feed temperature.

The main factors effecting cost of plant are :

(1) The improvement in thermal efficiency permits a reduction in the size of the boiler

since it has less heat input to do for a given load.

(2) The increased amount of steam tapped for feed heating increases the cost of the feed

heaters and the steam piping between turbine and heaters.

(3) The increase in the total steam consumption increases the cost of the steam piping

between the boiler and the turbine, the cost of the high pressure end of the turbine and

that of the feed piping and feed pumps.

(4) The decrease in the amount of steam flowing through the low pressure end of the

turbine and the amount of steam to be condensed. It d ecreases the cost of the low

pressure end of the turbine and the cost of the condensing' plant, c.w. culverts, etc.

(5) The higher feed temperature consequent upon the use of extensive regenerative feed

heating, would cause the flue gases to leave the boiler economiser at a higher

temperature, thus inevitably reducing the boiler efficiency to an extent which could

largely counter-balance the increase in turbine thennal efficiency. For this reason it is

necessary to employ a further regenerator in the form of an air heater inwhich the heat

of the flue gases is transferred to the combustion air supplied to the furnace.

PAGE 72

Another consideration with respect to boiler design is that the feed temperature at the

economiser inlet must be higher than the due point of the boiler flue gases, but not high

enough to cause steaming in the economiser also, the temperature of feed water in the

economiser outlet must be less than the saturation temperature of water at that particular

pressure, normally difference shall be 200C.



PAGE-73

6.0 POWER SECTOR-HIGHLIGHTS AND MAIN ACHIEVEMENTS

6.1 POWER GENERATION

The overall generation in the country has increased from 287 BUs during 1991-92 to 420

BUs durind 1997-98 (DIAGRAM-1).

The year-wise generation is as follows :

Year Generation (BUs)

1991-92 287

1992-93 301

1993-94 324

1994-95 351

1995-96 380

1996-97 394

1997-98 420

6.2 INSTALLED CAPACITY



The All India Installed Capacity of electric power generation stations under utilities was

85940 MW as on 31-j-97 consisting of 21658 hydro, 61157 MW Thermal and 2225 MW

Nuclear and 900 MW Wind which has increased to 89166.87 MW (Statement-1) as on 31-3-

98 consisting of 21891.08 MW Hydro, 64150.78 MW Thermal and 2225.00 (Prov.) MW

Nuclear and 900.01 MW Wind (DIAGRAM 11). At present the rerated installed nuclear

capacity is 1840 MW.

6.3 GENERATING CAPACITY ADDITION

The aggregate capacity of 3239.00 MW consisting of 516 MW Hydro, 2723 MW

Thermal was targetted for commissioning during the year 1997-98. Against the targetted

capacity, the total generating capacity commissioned/rolled during the year 1997-98 was

3283.3 MW consisting of 233.0 MW Hydro and 3050.3 MW Thermal (Fig.6.1).

6.3.1 The achievement in capacity addition during the year 1997-98 (April 1997-

March, 1998) against the programme is as under :

PROGRAMME FOR 1997-98 (APRIL '97-MARCH 1998)

ACHIEVEMENT DURING 1997-98 (APRIL '97-MARCH 1998)

TYPE CS SS PS TOTAL CS SS PS TOTAL

HYDRO 25 491 ---- 516 ---- 233 ---- 233

THERMAL 384 1263 876 2723 333 1443 626 3050.3

NUCLEAR ---- ---- ---- ---- ---- ---- 1274.3 ----

TOTAL 409 1954 876 3239 333 1676 1274.3 3283.3 CS : Central Sectors; SS : State Sector; PS : Private Sector

6.3.2 Capacity Addition (Last Five Years)

In the last six years including (Apdi-97 to March, 1998), the following new

capacities have been added.

Year Center State Total

1992-93 2475.00 1062.27 3537.27

1993-94 2340.00 2198.75 4538.75

1994-95 1531.50 3067.00 4598.50

1995-96 987.00 1136.55 2123.55

1996-97 823.50 800.00 1624.40

1997-98 333.00 2950.30 3283.3* *This also Includes figures In repect of private sector



6.3.3 A capacity addition programme of 3299.3 MW consisting of 544.5 MW Hydro

and 2754.8 MW of Thermal has been fixed for the year 1998-99.

Capacity Addition Programme (1998-99) (P) (MW)

Center State Private Total

Hydro 25 519.5 ---- 544.5

Thermal 166.3 758.5 1830 2754.8

Nuclear N.A. N.A. N.A. N.A.

Total 191.30 1278.00 1830.00 3299.30 N.A. : Not Available

PAGE-74

6.4 PLANT LOAD FACTOR (PLF)

The actual all India PLF of Thermal Power Utilities during Apdi 97 to March, 1998

was-64.7% which was 1.8% less than the target of 66.5%.

The PLF figures during the last five years including 1997-98 are as under :-

Year Center State Overall

1993-94 69.20 56.50 61

1994-95 69.20 55.00 60

1995-96 71.00 58.10 63

1996-97 71.00 60.30 64.4

1997-98 70.40 60.90 64.7

A target of 65.7% has been fixed for the year 1998-99.

Vijayawada TPS of APSEB achieved the highest PLF of 93.9% during 1997-98

6.5 TRANSMISSION AND DISTRIBUTION LOSSES

The Transmission and Distribution losses in the country are on the higher side.

Through concerted efforts, the transmission and distdbution losses in the country have

declined. They have come down from 22.83% during the year 1991-92 to 22.27% during the

year-wise details of transmission and distribution losses in the country are given below:



Year T & D Losses (%)

1991-92 22.83

1992-93 21.8

1993-94 21.41

1994-95 21.13

1995-96 22.27

PAGE-75

6.6 RURAL ELECTRICATION

Rural Electrification Programme has been pursued with determination. Nearly 85.2%

of the total villages have been electrified. By March, 1998, 500268 villages had been

electrified out of 587258 villages. Similarly, a total of 118,06,607 pumpsets were

energised upto March, 1998 out of the total estimated potential of energisation of

145 lakh of pumpsets thus achieving 81.4% of energisation target for pumpsets.

6.7 POWER SUPPLY POSITION

lnspite of significant growth in power generation the shortage ramains. The present

shortage is mainly on account of growth in de mand for power outstripping the growth in



gen eration and generating capacity addition. The power supply position in the last five

years as well as during 19997-98, was as follows :- .

Year Requirement Availability Shortage (%) 1992-93 305266 279824 25442 (8.3) 1993-94 323252 299494 23758 (7.3) 1994-95 352260 327281 24979 (7.1) 1995-96 389721 354045 35676 (9.2) 1996-97 413490 365900 47950 (11.5) 1997-98 424505 390330 34175 (8.1)

PEAK (MW)

Year Peak

Demand Peak Demand

Met Deficit Storage

(%) 1992-93 52805 41984 10821 20.5 1993-94 54875 44830 10045 18.3 1994-95 57530 48066 9464 16.5 1995-96 60981 49836 11145 18.3 1996-97 63853 52376 11477 18 1997-98 65435 58042 7393 11.3

6.8 STATE ELECTRICITY BOARDS - RATE OF RETURN

Restoration of financial health of SEBs and improvement in their operational

performance continues to remain the most crucial issue in the sector. In terms of Section 59

of the Electricity (Supply) Act, 1948, SEBs are required to earn a minimum rate of return

(ROR) or 3 per cent of their net fixed assets in service, after providing for depreciation and

interest charges. In 1991-92 after taking into account RE subsidy as provided in the

accounts, only 12 SEBs had a positive rate of return, with 8 SEBs have a ROR of about 3%

or more . During 1 995-96 after taking into account RE subsidy as provided in the accounts,

out of 17 SEBs all except those of Bihar, Assam, and Meghalaya have achieved the

minimum pre scribed 3% or more. The position has been improving. Only 3 SEBs have a

negative rate of return i.e. Bihar, Assam and Meghalaya during 1995-96.



PAGE-76



PAGE-77

PAGE-78



PAGE-79

TABLE 1

POWER SUPPLY INDUSTRY IN INDIA - HIGHLIGHTS

'Dec. 1950 31.3.71 31.3.81 31.3.91 31.3.94 31.3.95 31.3.96* I. Generating Capacity (MW)

(Total All India) 2301 16271 33316 74699 87475 92332 95183 Utilities Hydro 559 6383 11791 18753 20379 20833 20986 Steam 1005 7508 17122 43004 49174 52139 53480 Gas 168 274 2552 4883 5631 6268 Diesel & Wind 149 230 167 212 339 343 335 Nuclear 420 860 1565 2005 2225 2225 Total (Utilities) 1713 14709 30214 66086 76753 81171 83294 Public Sector (Utilities) 628 13221 28832 63344 73729 77625 79418 Private Sector (Utilities) 1085 1488 1382 2742 3024 3546 3876 Average Annual Growth Rate

(%)

during the decade 4.34 12.20 7.46 8.14 6.91 6.66 5.94 Non Utilities (including Railways) Hydro ---- ---- 3 4 4 4 4 Steam ---- ---- 2137 5010 5812 6029 6310 Gas ---- ---- 54 475 774 808 825 Diesel & Wind ---- ---- 908 3124 4132 4320 4750 Total (Non-Utilities) 588 1562 3102 8613 10722 11161 11889

267 489 1218 1363 1627 1711 1750 'Dec. 1950 1970-71 1980-81 1990-91 1993-94 1994-95 1995-96

II. Generating Capacity (GWH) (Total All India) 6675 61212 119260 289439 356335 385558 417237 Utilities Hydro 2520 25248 46542 71641 70463 82712 72598 Steam 2387 27797 60714 178322 233151 243110 273745 Gas 251 522 8113 14727 18475 24858 Diesel & Wind 200 114 65 112 311 545 704 Nuclear 2418 3001 6141 5398 5648 7982 Total (Utilities) 5107 55828 110844 264329 324050 350490 379887 Public Sector (Utilities) 2104 49562 104114 251382 310197 335293 361734 Private Sector (Utilities) 3003 6266 6730 12947 13853 15197 18153 Average Annual Growth Rate

(%)

during the decade 6.57 12.67 7.10 9.08 8.74 8.37 8.53 Non Utilities (including Railways) Hydro ---- ---- 15 15 15 15 15 Steam ---- ---- 7232 20017 25416 27390 28835 Gas ---- ---- 102 1845 3149 3407 3640 Diesel & Wind ---- ---- 1067 3233 3705 4255 4860 Total (Non-Utilities) 1468 5384 8416 25110 32285 35067 37350



(267) (489) (1218) (1363) (1627) (1711) (1750) Abbreviations used

* Provisional

- Data not available

Figure in bracket indicates number of selected industries covered.

From 1986-87 onwards coverage is for captive, plants of capacity

1M.W. and above.

PAGE-80

TABLE 1

'Dec. 1950 1970-71 1980-81 1990-91 1993-94 1994-95 1995-96*

III. SYSTEM PEAK DEMAND (AGGREGATE) Utilities (MW) 9743 19121 40672 48351 -- --

IV. FUEL CONSUMPTION Utilities-Steam Stations Coal (MTx10) Lignite (MTx10) Furnace Oil (Kilo Lts x 10) Diesel Oil (Kilo Lts x 10)

2.22 -- -- --

14.59 2.54 1.28 0.04

35.82 3.98 1.87 0.22

112.92 9.62 0.78 0.27

156.86 12.05 0.61 0.24

161.27 14.08 0.64 0.34

-- -- --

0.38 V. AVERAGE GENERATION PER KW OF INSTALLED CAPACITY (KWH/KW) @ @ (Utilities) 'Hydro 4505 3956 4075 3820 2458 3970 3459 Steam 2377 3702 3672 4147 4744 4663 5119 'Diesel & Wind 1342 917 1219 2976 2887 3184 3871 'Nuclear 0 5757 3512 3924 2693 2538 3587 'Overall 2982 3795 3772 4000 4224 4318 4561 VI. ELECTRICITY SALE (GWH) (Utilities) Doemastic 524 3840 9247 31682 43344 47915 52539 Commercial 309 2573 4682 11181 14144 15973 16999 Industrial 2604 29579 48069 84209 94503 100126 105291 Agriculture 162 4470 14489 50321 70699 79301 85736 Public Lighting 60 500 748 1648 1939 2071 2188 Railwaay Traction 308 1364 2266 4112 5621 5886 6227 Public Water Works & Sewage Pumping 189 1016 1534 3631 4838 5037 5388 Miscellaneous ----- 382 1332 3261 3481 3321 3955 Total 4157 43724 82367 190357 238569 249630 278323 Avearage Annual Growth Rate (%) 6.34 12.19 6.55 8.74 8.83 8.57 8.51 during the decade VII. PAATTERN OF ELECTRICITY SALE (%) (Utilities) Doemastic 12.6 8.8 11.2 16.8 18.2 18.5 18.9 Commercial 7.5 5.9 5.7 5.9 5.9 6.1 6.1 Industrial 62.6 67.6 58.4 44.2 39.6 38.6 37.8 Agriculture 3.9 10.2 17.6 26.4 29.6 30.5 30.8



Others 13.4 7.5 7.1 6.7 6.7 6.3 6.4 VIII. ELECTRICITY CONSUMPTION Utilities + Non-Utilities Per 1000 of Population (KWH) 15550 89760 132340 252770 298960 320100 335420 Per 1000 Sq. Kms. of area in (GWH) 1.69 15.35 25.05 64.35 8075 88.02 93.87 Per MW of connected Load (GWH) 1.86 1.85 1.34 1.57 1.67 1.75 ----- Per 1000 consumers (GWH) 3.52 3.31 2.53 2.73 3.22 3.35 -----

@ @ The Figures given under this table indicate the generation in Kwh during the year

per KW of installed capacity at the end of year.

* Provisional

---- Data not available

PAGE-81

TABLE 1 Contd.

'Dec. 1950 1970-71 1980-81 1990-91 1993-94 1994-95 1995-96* IX. PER CAPITA (KWH) (Utilities + Non Utilities) Generation 18.17 113.29 175.95 345.87 401.31 426.52 453.53 Consumption 15.55 89.76 132.34 252.77 298.96 320.1 335.42

X. NO. OF CONSUMERS (THOUSAND) Doemastic 1157 10165 22338 50389 60193 63406 ----- Commercial 259 2306 4582 8002 9209 9558 ----- Industrial **63 553 1150 2077 2337 2423 ----- Agriculture 19 1571 4233 8631 9971 10372 ----- Others 3 70 268 534 602 637 ----- Total 1501 14665 32571 69633 82312 86399 ----- XI. CONNECTED LOAD (MW) Doemastic 734 5986 13079 32051 49254 51590 ----- Commercial 401 1911 4494 8341 11800 12123 ----- Industrial **1562 11631 24844 42947 52438 54235 ----- Agriculture 118 6225 16489 32511 38511 40108 ----- Others 20 477 2492 5051 6895 7445 ----- Total 2835 26230 61398 120901 158943 165501 ----- XII. LENGTH OF T & D LINES (Circuit Kms) HVDC ----- ----- ----- ----- 1667 1667 ----- 400 KV ----- ----- 2340 21634 27129 28025 ----- 230/220/KV ----- 11211 31834 62345 72916 75572 ----- 132/110KV 2708 46160 59738 87965 93929 96551 ----- 78/66/44KV 7431 25769 26752 34947 36613 37675 ----- 15/11/6.6/3.3/2.2KV 14110 362628 784513 1329774 1470217 1509070 Distribution lines 576323 1453402 2784482 2949195 3038500 Total ----- 1117164 2522461 4533414 4878028 5018408 XIII. TRANSFORMATION CAPACITY (MVA)



Step up 972.81 16256.24 37094 75823 92861 97153 ----- Step down 1366.76 34726.7 97882 207595 264088 256664 ----- Distribution 834.37 17048.84 43829 87501 110568 139976 ----- XIV. SYSTEM LOSSES (%) All India 15.83 17.5 20.56 22.89 21.41 21.13 21.74

XV. PROGRESS OF RURAL ELECTRIFICATION No. of Villages Electrified 306($) 104942 272287 481124 494191 497745 501831 Percentage Electrified 0.54 18.5 47.3 83.1 85.1 86 86.7 Percentage of rural Populatioon benefitted 2.06 ----- 68 84.1 85.5 85.3 83.4 XVI. ENERGISTION OF PUMPSETS Total energised 21008 1629423 4330453 8909110 1027644 10721255 11104090

@ Estimated

($) Figures ending March 1951

** Including water works & traction

---- Data not Available

* Provisional

PAGE-82

TABLE 1 Contd,

XVII.GENERATING CAPACITY AS ON 31.3.96- & 31.3.95 (MW) (UTILITIES)

Hydro Thermal Nuclear Total Region

3.96 3.95 3.96 3.95 3.96 3.95 3.96 3.95 Northern 7162 7142 15883 15786 895 895 23940 23823 Western 3113 3014 20758 20428 860 860 24731 24302 Southern 8506 8505 10820 10486 470 470 19796 19461 Eastern 1710 1680 11751 10622 13461 12302 North-Eastern 495 492 871 791 1368 1283 Total 20986 20833 60083 58113 2225 2225 83294 81171

XVIII. ELECTRICITY GENERATED DURING 1995-96 1994-95 (GWH) (UTILITIES)

Hydro Thermal Nuclear Total Region

95-96 94-95 95-96 94-95 95-96 94-95 95-96 94-95

Northern 29429 30244 81763 72431 2752 1333 113764 104008

Western 7553 10298 115731 102931 3820 1883 127104 115112

Southern 28453 35056 65195 1410 2432 95058 92290

Eastern 55163 5259 34671 30542 40184 35801



North-Eastern 1830 1855 1947 1424 3777 3279

Total 72598 82712 299307 262130 7982 5648 379887 350490

XIX. ELECTRICITY SOLD DURING 1995-96' & 1994-95' (GWH) (UTILITIES)

DOMESTIC COMMERCE INDUSTRIAL AGRICULTURAL OTHERS TOTAL Region

95-96 94-95 95-96 94-95 95-96 94-95 95-96 94-95 95-96 94-95 95-96 94-95

Northern 17413 16166 6040 5528 23663 22110 24279 23883 5279 4655 76674 72342

Western 14484 12934 4590 4188 38222 36077 32019 27153 5917 5489 95232

Southern 13157 12182 3624 3672 26784 26823 26319 25330 3277 3050 73161 71057

Eastern 6622 5914 2477 2317 15675 14163 3022 2846 2659 2569 30455 27809

North-Eastern 8763 719 268 268 947 953 97 89 626 552 2801 2581

Total 52539 47915 16999 15973 105291 100126 85736 79301 17758 16315 278323 259360

* Provisional

** The rerated installed Nuclear capacity at present is 1840 MW

PAGE-83

XX ELECTRICITY GENERATION (MW) (UTILITIES)

1995-96 1996-97 Region Hydro Thermal Nuclear Total Hydro Thermal Nuclear Total

Northern 29249 81763 2752 113764 29221 85283 2823 117327 Western 7553 115731 3820 127104 7484 122657 4223 134364 Southern 28453 65195 1410 95058 25355 69842 1978 97175 Eastern 5513 34671 - 40184 4664 37281 - 41945 North-Eastern 1830 1947 - 3777 1894 2065 - 3989 Total 72598 299307 7982 379887 68618 3171558 9024 394800

PER CAPTA CONSUMPTION 1995-96* & (KWH) (UTILITIES & NON UTILITIES) DOMESTIC COMMERCIAL INDUSTRIAL AGRICULTURAL OTHERS TOTAL

REGION 95-96 94-95 95-96 94-95 95-96 94-95 95-96 94-95 95-96 94-95 95-96 94-95

Northern 66 63 23 21 113 109 92 92 20 18 314 302

Western 71 64 22 21 228 221 156 135 29 27 506 468

Southern 62 59 17 18 155 156 125 16 14 375 369

Eastern 32 30 12 12 120 114 15 14 14 12 193 182

North-Eastern 24 21 8 8 47 48 3 3 18 16 100 96

Total 57 53 18 18 147 144 93 88 20 17 335 320



* Provisional

($) Retirements & addition of small sets excluded

PAGE-84

TABLE 11 TOTAL THERMAL INSTALLED CAPACITY

YEAR BY THE END OF

TOTAL CAPACITY

MW

THERMAL CAPACITY

MW % OF TOTAL (THERMAL)

12/47 1363.00 757.00 0.56 12/50 1713.00 1005.00 0.59 12/55 2695.00 1547.00 0.57 3/61 4650.00 2436.00 0.54 3/66 9027.00 4417.00 0.49 3/69 12957.00 6641.00 0.51 3/74 1665.00 8652.00 0.52 1/77 20600.00 11030.00 0.54 4/78 41892.50 26460.00 0.63 3/85 42591.00 27026.00 0.63 3/86 46663.00 29895.00 0.64 3/87 49257.00 31733.00 0.64 3/88 57058.00 35300.00 0.65 3/91 63636.00 43764.00 0.69 3/93 72330.00 50749.00 0.70 3/94 76753.00 54369.00 0.71 3/95 81171.00 58113.00 0.72 3/96 83288.00 60067.00 0.72 3/97 85940.00 61157.00 0.71 3/98 89167.00 64151.00 0.71

Note 1. Up to 3188 the Thermal capacity is excluded Diesel and Nuclear Stations.

2. From 3/89 onwards.the Thermal capacity is calculated Including (Oil, Gas

& Wind).



4

PAGE-85

TABLE 11-

A

INSTALLED GENERATING CAPACITY AS ON 31ST MARCH, 1998 (UTILITIES)

(MW)

Region State/UTs Hydro Steam Diesel Wind Gas Nuclear Total NORTHERN Haryana 883.90 892.50 3.92 0.00 0.00 0.00 1780.32

REGION Himachal Pradesh 299.37 0.00 0.13 0.00 0.00 0.00 299.50 Jammu & Kashmir 184.06 0.00 6076.00 0.00 175.00 0.00 365.82 Punjab 1798.94 1920.00 0.00 0.00 0.00 0.00 3716.94 Rajasthan 971.08 975.00 0.00 0.00 38.50 0.00 1984.58 Uttar Pradesh 1504.75 4664.00 0.00 0.00 0.00 0.00 6168.75 Chandigarh 0.00 0.00 2.00 0.00 0.00 0.00 2.00 Delhi 0.00 371.60 0.00 0.00 282.00 0.00 653.60 Central Sector 2010.00 4980.00 0.00 0.00 1882.00 895.00 9767.00 Sub-Total 7652.10 13803.10 12.81 0.00 2377.50 895.00 24740.51

WESTERN Gujarat 467.00 4496.00 17.48 146.81 1529.00 0.00 6644.29

REGION Madhya Pradesh 846.11 3017.50 0.00 9.59 0.00 0.00 3873.20 Maharashtra 1793.22 7655.00 0.00 5.37 1092.00 0.00 10545.59 Goa 0.05 0.00 0.00 0.11 0.00 0.00 0.16 D. & N. Haveli 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Daman & Diu 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Central Sector 0.00 3360.00 0.00 0.00 1292.00 86.00 5512.00

Sub-Total 3126.28 18496.50 17.48 161.88 3913.00 860.00 26575.24 SOUTHERN Andhra Pradesh 2656.94 2952.50 0.00 54.29 542.00 0.00 6282.13 REGION Karnataka 2465.55 840.00 129.92 5.85 0.00 0.00 3441.32 Kerala 1683.50 0.00 80.00 2.02 0.00 0.00 1765.52 Tamil Nadu 1955.70 0.00 674.87 130.00 0.00 5730.57 Lakshadweep 0.00 0.00 6.92 0.00 0.00 0.00 6.92 Pondicherry 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Central Sector 0.00 4170.00 0.00 0.00 0.00 470.00 4640.00

Sub-Total 8761.69 10932.50 216.84 737.03 672.4 470 21790.46



PAGE-86

TABI'E, II-A Contd.

INSTALLED GENERARING CAPACITY AS ON 31ST MARCH, 1998 (UTILITIES)

(MW)

Region State/UTs Hydro Steam Diesel Wind Gas Nuclear Total EASTERN Bihar 174.90 1813.00 0.00 0.00 0.00 0.00 1988.40 REGION Orissa 1271.92 420.00 0.00 1.10 0.00 0.00 1693.32 West Bengal 126.51 3836.38 22.50 0.00 100.00 0.00 4085.39 D.V.C. 144.00 2427.50 0.00 0.00 90.00 0.00 2661.50 A. & N. Islands 0.00 0.00 28.33 0.00 0.00 0.00 28.33 Sikkim 32.89 0.00 2.70 0.00 0.00 0.00 35.39 Central Sector 0.00 3910.00 0.00 0.00 0.00 0.00 3910.00 Sub-Total 1750.22 12407.00 53.53 1.10 190.00 0.00 14402.23 NORTH Assam 2.00 330.00 20.69 0.00 324.00 0.00 676.69 EASTERN Manipur 2.60 0.00 9.41 0.00 0.00 0.00 12.01 REGION Meghalaya 186.71 0.00 2.05 0.00 0.00 0.00 188.76 Negaland 3.50 0.00 2.00 0.00 0.00 0.00 5.50 Tripura 16.01 0.00 40.85 0.00 85.50 0.00 106.36 Arunachal Pradesh 29.55 0.00 15.88 0.00 0.00 0.00 45.43 Mizoram 5.31 0.00 20.36 0.00 0.00 0.00 25.67 Central Sector 355.01 0.00 0.00 0.00 243.00 0.00 598.01 Sub-Total 600.69 330.00 75.24 0.00 651.50 0.00 1638.43 Total (All India) 21891.08 55969.48 375.90 900.01 7805.40 *2225.00 89166.87

* Provisional Figures. The rerated installed Nuclear Capacity at present is 1840 MW.

Note : Installed Capacity of jointly owned projects have been shown divided between the

partner states as per their theoritical share.



PAGE-87

TABLE Ill

VILLAGES ELECTRIFIED

SI. NO.

States/ UTs

Annual Target

Achievement

1 Andhra Pradesh @ 2 Arunachal Pradesh 100 100 3 Assam 230 20 4 Bihar 330 2& 5 Delhi @ 6 Goa @ 7 Gujarat 0 3 8 Haryana @ 9 Himachal Pradesh 0

10 Jammu & Kashmir 30 14 11 Kamataka @ 12 Kerala @ 13 Madhya Pradesh 500 463 14 Maharashtra @ 15 Manipur 80 59 16 Meghalaya 59 27 17 Mizoram 15 10 18 Nagaland 0 19 Orissa 250 800 20 Punjab @ 21 Rajasthan 480 680+ 22 Sikkim @ 23 Tamil Nadu @ 24 Tripura 35 15 25 Uttar Pradesh 500 812+ 26 West Bengal 400 5

Total 3000 3010

(@) 100% electrified State (excluding those villages which are technically not feasible for

electrification).

(&) Progress upto Feb., 98 (+) including State Plan



PAGE 88

TABLE Ill

PROGRESS REPORT IN RESPECT OF ENERGISATION OF PUMPSETS UPTO

MARCH. 1998

SI. NO.

States/ UTs

Estimated potential terms of

electrification of pumpset

Achievement as on 313.97 (Provisional)

% age Performance during 1997-

98

Total

achievement upto the

end 31.3.98

(Provisional)

1 Andhra Pradesh 1600000 1821291 100 2288 1823579

2 Arunachal

Pradesh 3 Assam 200000 3675 1.8 3675 4 Bihar 1000000 269345 26.9 746 270091 5 Goa 6063 391 6454 6 Gujarat 700000 591564 84.5 25931 617495 7 Haryana 430000 408461 95.0 943 409404 8 Himachal Pradesh 10000 4780 33.9 318 5088 9 Jammu & Kashmir 15000 5088 33.9 5088

10 Karnataka 850000 1049465 100 23853 1073318 11 Kerala 300000 314632 100 11597 326229 12 Madhya Pradesh 1300000 1176317 90.5 52699 1229016 13 Maharashtra 1800000 2091718 100 44396 2136114 14 Manipur 10000 45 0.5 45 15 Meghalaya 10000 65 0.7 65 16 Mizoram 17 Nagaland 10000 176 1.8 176 18 orissa 500000 70144 14.0 1071 71215 19 Punjab 700000 726221 100 9850 736071 20 Rajasthan 600000 539762 90.0 25306 565068 21 Sikkim 5000 22 Tamil Nadu 1500000 1567322 100 50000 1607322 23 Tripura 10000 1764 17.6 1764 24 Uttar Pradesh 2400000 778512 32.4 778512 25 West Bengal 500000 102773 20.6 1610 104383

Total (States) 14450000 11529183 79.8 240999 11770182 Total (UTs) 50000 36159 72.3 266 36425 Total (All India) 14500000 11565342 79.8 241265 11806607



Source : CEA

PAGE 89



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