POWER STATION MANAGEMENT Compailed by Dr.Rohit Varma Dy.Director,NPTI CAMPS,Faridabad Table of Contents Chapter 1 2 3 4 5 6 7 8 9 10 11 Coal Scenario Gas Trends in India Topics Page No. 3 34 62 80 90 131 145 157 204 215 229 Statutory Requirement of Trained Manpower Contract Labour Act Turbine Efficiency Efficiency of Hydro Power Plant Working Capital and Cost Management Strategy Safety Act Human Resource in Power Sector Boiler Efficiency MIS in Power Sector External Marks: 70 Internal Marks: 30 Time: 3 hrs. POWER STATION MANAGEMENT Paper – PM 2311 Unit I Management of Fuel, Water Resources, Electricity Demand Scenario, vis-a-vis fuel supply, storage and handling of coal/oil/gas, coal/gas linkages, pricing, contracts, inventory control. Unit II Performance Management, Boiler Efficiency, Turbine Efficiency, Cycle Efficiency, Monitoring and control of heat rate, other performance parameters, Efficiency of hydro Plants, Energy conservation & Efficiency measures, Maintenance Planning. Unit III Statutory requirements, trained manpower as per Indian Electricity Rules, Apprising of Act, Factories Act, Contract Labour Act, Environmental regulations etc. Unit IV Working capital Management, Cost Management Strategies, Human Resources Management, Management Information system. Suggested Readings: 1. 2. Power Plant Performance Management, Butter Worth, A.B. Gill – 1984 Modern Power Station Practice, Publisher British Electricity Authority. 3. Power Station Engg. & Economy by – B.G.A. Skrotzki & W.A. Vopat , Tata McGraw Hill. 4. Standard Plant Operators Manual – Third Edition – Stephen Michael Elanka, McGraw Hill Book Company Coal What is Coal? Coal is a combustible, sedimentary, organic rock formed from ancient vegetation, which has been consolidated between other rock strata and transformed by the combined effects of microbial action, pressure and heat over a considerable time period. This process is referred to as 'coalification'. Coal is called a fossil fuel because it was formed from the remains of vegetation that grew as long as 400 million years ago. It is often referred to as "buried sunshine," because the plants which formed coal captured energy from the sun through photosynthesis to create the compounds that make up plant tissues. The most important element in the plant material is carbon, which gives coal most of its energy. It is found in seams/coal beds which vary from a few inches to 100’ more in thickness. On the basis of amount of ground cover or over burden the coal can be mined by the surface method (complete removal of overburden) or deep (underground) method. The Origins of Coal Coal is a readily combustible rock containing more than 50% by a weight of carbonaceous material, formed from compaction and in duration of variously altered plant remains similar to those in peat. Most coal is fossil peat. Coal is composed mainly of carbon (50-98%), hydrogen (3-13%) and oxygen, and smaller amounts of Nitrogen, Sulphur and other elements. It also contains a little water and grains of inorganic matter that remain as a residue known as ash when coal is burnt. Peat is an unconsolidated deposit of plant remains from a water saturated environment such as a bog or mire, structure of vegetal matter can be seen and when dried peat burns freely. Coal is formed by the physical and chemical alteration of peat (coalification) by processes involving bacterial decay, compaction, heat and time. Coal is an agglomeration of many different complex hydrocarbon compounds. Peat deposits contain everything from pristine plant parts (roots, barks, spores etc) to decayed plants, decay products & even to charcoal if the peat caught fire. Peat deposits formed in a waterlogged environment where plant debris is accumulated, peat bogs and peat swamps are examples. For the peat to become coal it must be buried by sediment. Burial causes the compaction of peat and much water is squeezed out during the first stage of burial. Continued burial and addition of heat and time causes the complex hydrocarbon compounds in the deposit to start to breakdown and alter in the varieties of ways. The gaseous alteration products (methane is one) are typically expelled from the deposit and the deposit becomes more and more carbon rich (other elements drop out). The stages of this trend proceed from plant debris, peat, lignite, sub-bituminous coal, bituminous coal, anthracite coal to graphite (a pure carbon mineral). It is estimated that because of squeezing and water loss it took vertical 10 feet of original peat material to produce 1 vertical foot of bituminous coal. Coal Types 1) Anthracite is a type of coal with the highest carbon content, between 86 and 98 percent. Heat value of nearly 15,000 BTUs-per-pound. Most frequently associated with home heating, anthracite is a very small segment of the world coal market. 2) Bituminous coals are dense black solids, frequently containing bands with a brilliant lustre. The carbon content of these coals ranges from 78 to 91 percent and the water content from 1.5 to 7 percent. Bituminous coal has a heat value of 10,500 to 15,500 BTUs-per-pound. 3) Sub-bituminous coals usually appear dull black and waxy. They have carbon content between 71 and 77 percent and a moisture content of up to 10 percent and are used for electricity generation or can be converted to liquid and gaseous fuels. Heat value between 8,300 and 13,000 BTUs-perpound. 4) Brown coals or lignite have a high oxygen content (up to 30 percent), a relatively low carbon content (60-75 percent on a dry basis), and a high moisture content (30-70 percent). Heat value ranging between 4,000 and 8,300 BTUs-per-pound. Peat 5% 5% 92% Lignite 38% 19% 43% Bituminous 65% 32% 3% Anthracite 96% 1% 3% Carbon Volatile Water Proximate analysis of coal Proximate analysis indicates the percentage by weight of fixed carbon of fixed carbon, Volatiles, Ash content and moisture content in coal. The amount of fixed carbon and volatile combustible matter directly contribute to heating value of coal. Fixed carbon acts as main heat generator during burning. High volatile matter content indicates easy ignition of fuel. The ash content is important in the design of furnace grate, combustion volume pollution control equipment and ash handling systems of a furnace A typical proximate analysis of various coal is given below: - Significance of various parameters in proximate analysis a) Fixed carbon Fixed carbon is the solid fuel left in the furnace after volatile matter is distilled off. It consists mostly of carbon but also contains some hydrogen, oxygen, sulphur and nitrogen not driven off with gases. Fixed carbon gives a rough estimate of heating value of coal. b) Volatile matter Volatile matters are the methane, hydrocarbons and carbon monoxide and incombustible gases like carbon dioxide and nitrogen found in coal .Thus the volatile matter is an index of gaseous fuels present. Typical range of volatile matter is 20% to 35%. • Proportionately increases flame length and helps in easier ignition of coal. • Sets minimum limit on the furnace height and volume. • Influences secondary air requirement and distribution aspects. • Influences secondary oil support. c) Ash Content Ash is an impurity that will not burn. Typical range is 5% to 40%. Ash • Reduces handling and burning capacity. • Increases handling costs. • Affects combustion efficiency and boiler efficiency. • Causes clinkering and slagging. d) Moisture content Moisture in coal must be transported handled and stored. Since it replaces combustible matter, it decreases the heat content per kg of coal. Typical range is 0.5% to 10%.Moisture • Increases heat loss, due to evaporation and superheating of vapor. • Helps to limit, in binding fines. • Aids radiation heat transfer. e) Sulphur Content Typical range is 0.5% to 0.8%. • Affects clinkering and slagging tendencies. • Corrodes chimney and other equipment such as air heaters and economizers. • Limits exit flue gas temperature. Ultimate analysis of coal The ultimate analysis splits up fuel into all its component elements, solid or gaseous. This analysis must be carried out in a properly equipped laboratory by skilled chemist. The ultimate analysis indicates the various elemental chemical constituents such as carbon, hydrogen, oxygen, sulphur etc.It is useful in determining the quantity of air required for combustion gases. This information is required for the calculation of flame temperature and the flue ducts design etc. Relation between Proximate and Ultimate Analysis %C =0.97C+0.7(VM+0.1A)-M(0.6-0.01M) %H2 =0.036C+0.086(VM-0.1XA)-0.0035M2 (1-0.02M) %N2 =2.10-0.020VM Where C % of fixed carbon A % of ash VM % of volatile matter M % of moisture COAL RESOURCES OF INDIA As a result of exploration carried out up to the depth of 1200m by the GSI, CMPDI and MECL etc, a cumulative total of 267.21 Billion tonnes of Geological Resources of Coal have so far been estimated in the country as on 1.4.2009. The state-wise distribution of coal resources and its categorisation are as follows: (in Million Tonnes) State Geological Resources of Coal Proved Indicated Inferred Total Andhra Pradesh 9194 6748 2985 18927 Arunachal Pradesh 31 40 19 90 Assam 348 36 3 387 Bihar 0 0 160 160 Chhattisgarh 10910 29192 4381 44483 Jharkhand 39480 30894 6338 76712 Madhya Pradesh 8041 10295 2645 20981 Maharashtra 5255 2907 1992 10154 Meghalaya 89 17 471 577 Nagaland 9 0 13 22 Orissa 19944 31484 13799 65227 Sikkim 0 58 43 101 Uttar Pradesh 866 196 0 1062 West Bengal Total 11653 105820 11603 123470 5071 37920 28327 267210 Categorisation of Resources: The coal resources of India are available in sedimentary rocks of older Gondwana Formations of peninsular India and younger Tertiary formations of north-eastern/ northern hilly region. Based on the results of Regional/ Promotional Exploration, where the boreholes are normally placed 1-2 Km apart, the resources are classified into Indicated or Inferred category. Subsequent Detailed Exploration in selected blocks, where boreholes are less than 400 meters apart, upgrades the resources into more reliable ‘Proved’ category. The Formation-wise and Category-wise coal resources of India as on 1.4.2009 are given below: (in Million Tonnes) Formation Proved Indicated Inferred Total Gondwana Coals 105343 123380 37414 266137 Tertiary Coals 477 90 506* 1073 Total 105820 123470 37920* 267210 * Includes 456 Mt of Inferred resources established through mapping in NE region. The Type and Category-wise coal resources of India as on 1.4.2009 are given in table below: (in Million Tonnes) Type of Coal Proved Indicated Inferred Total (A) Coking :Prime Coking 4614 699 0 5313 Medium Coking 12449 12064 1880 26393 Semi-Coking 482 1003 222 1707 Sub-Total Coking 17545 13766 2102 33413 (B) Non-Coking:87798 109614 35312 232724 (C) Tertiary Coal 477 90 506 1073 Grand Total 105820 123470 37920 267210 Status of Coal Resources in India during Last Five Years: As a result of Regional, Promotional and Detailed Exploration by GSI, CMPDI and SCCL etc, the estimation of coal resources of India has reached to 267.21 Bt. The estimates of coal resources in the country during last 5 years are given below: (in Million Tonnes) As on 1.1.2004 1.1.2005 1.1.2006 1.1.2007 1.4.2007 1.4.2008 1.4.2009 Geological Resources of Coal Proved Indicated 91631 116174 92960 117090 95866 119769 97920 118992 99060 120177 101829 124216 105820 123470 Inferred 37888 37797 37666 38260 38144 38490 37920 Total 245693 247847 253301 255172 257381 264535 267210 Gross Calorific value of Coal The heating value of coal varies from country to country and even from mine to mine in same country. The typical values of GCV of different types of coal are as follows: Grade Useful Heat Value (UHV) (Kcal/Kg) UHV= 8900-138(A+M) A Exceeding 6200 B Exceeding 5600 but exceeding 6200 C Exceeding 4940 but exceeding 5600 D Exceeding 4200 but exceeding 4940 E Exceeding 3360 but exceeding 4200 F Exceeding 2400 but exceeding 3360 G Exceeding 1300 but exceeding 2400 Corresponding Ash% +Gross Calorific Value GCV (Kcal/ Moisture % at (60% RHKg) (at 5% moisture level) & 40O C) Not exceeding 19.5 Exceeding 6454 not19.6 to 23.8 Exceeding 6049 but not exceeding 6454 not23.9 to 28.6 Exceeding 5597 but not exceeding. 6049 not28.7 to 34.0 Exceeding 5089 but not Exceeding 5597 not34.1 to 40.0 Exceeding 4324 but not exceeding 5089 not40.1 to 47.0 Exceeding 3865 but not exceeding. 4324 not47.1 to 55.0 Exceeding 3113 but not exceeding 3865 Coal Companies in India • Coal India Ltd (CIL) and its subsidiaries o Eastern Coal fields Limited o Western Coal fields Limited o Northern Coal Fields Limited o Bharat Coking Coal Limited o South Eastern Coalfields Limited • Neyveli Lignite Corporation (NLC) • Singraeni Colliery Company Limited (SCCL) Coal Linkages The Linkages of coal demand is primarily done with the objective of planning of coal supplies, keeping in view indigenous coal resources as well as the need to supply fuel of appropriate quality to the consumers and at the same time making the most economic use of the available capacity for production and of coal. For thermal power stations, whether belonging to state or central generating stations coal linkage is given by Coal Ministry’s standing committee on coal linkages. The linkages are classified in two types:• Long term linkages • Short term linkages Standing Linkage Committee (Long Term) for Power & Cement Sectors The consumers desiring linkage for supply of coal should apply for linkage to the SLC (long Term). The consumers should route the application through the concerned Ministry to the Chairman, SLC (LT). For example, for setting up a Power Plant, the application has to be routed through the Central Electricity Authority and Ministry of Power. In case of cement unit, it has to be routed through the Ministry of Industry, Ministry of Industrial Policy & Promotion. The SLC (LT) has the Additional Secretary in the Ministry of Coal as the Chairman. Other members of the SLC (LT). Are representatives of CIL, representatives of SCCL, CMPDIL, Railways, Planning Commission, Central Electricity Authority, Ministry of power and representative of Ministry of Industry, Dept. of Industrial Policy & Promotion (as the case may be). The Committee decides the linkage of coal for source of supply, quantum of coal and the made of transportation. Standing Linkage Committee (Short Term) for Power and Cement Sectors The Additional Secretary in the Ministry of Coal, Govt. of India is the Chairman of the Committee. Representatives of Coal India Limited, Central Electricity Authority, Ministry of Power, Railways, and Representatives of Singareni Collieries Co. Ltd. are the member of SLC (ST) for power sector. In SLC (ST) for cement sector besides Chief of Marketing of CIL, representatives of SCCL, Railways, Ministry of Industry, Dept.of Industrial Development are the other members. The committee meets in March, June, September and December each year to review the coal supplies to Power and Cement Sectors in the quarter and finalise the linkage to consumers in Power and Cement Sectors for the next quarter. Time to time adjustment/incorporation in the quarterly linkages is done by the Chairman’s (ST). Minutes of the meetings are drawn and circulated to all concerned for implementation. As per MoP guidelines coal linkage & coal block allotment to Power Plants is done in following order: (i) Projects proposed to be executed by Central Public Sector Undertakings / organizations and state public sector organizations (namely, generating companies, Electricity Boards etc) may be accorded the first priority. Within this group expansion projects will have higher priority in view of their shorter gestation. (ii) Joint Venture projects, namely, joint venture between Central Sector and State Sector or between the two states, or Central/State with private sector with substantial say in the matter of management of the Joint Venture by the public sector, may be accorded next priority. (iii) IPP projects, which have been allowed tariff approval by the appropriate tariff commission under Section 62 of the Electricity Act, 2003. (iv) Projects being developed on the basis of competitive bidding for tariff under Section 63 of the Electricity Act. This would include Ultra Mega Projects and projects being developed on similar lines by the distribution companies/State Electricity Boards or agencies authorized by them to be the Nodal Agency for development of such projects. (v) Expansion of existing IPP plants which are already supplying power to the grid as per tariff policy and captive power plants supplying at least 25% of their capacity to the grid. (vi) Other captive power plants. (vii) Merchant Power Plants. (a) Linkage to the plant upto a capacity of 1,000 MW; and (b) Captive coal block allotment for plants in the range of 500 – 1000 MW capacity. (viii) Any other category not covered above. Coal Pricing in India Production costs of coal vary widely between open cast and deep pit mines and between mining areas: Some mines produce coal at a profit and clearly below the price of imported coal – some mines produce at a loss compared to domestic and international prices. In the coal value chain from mines mouth to power plant and to the final electricity consumer, many decisions on cost optimization have to be made: Coal transport vs. wheeling of electricity, coal transportation by ship or by rail, reducing the ash content at the mine mouth or transportation of higher volumes. SCHEDULE- IX [This shall form SCHEDULE- IX to CSA ] Breaking down the total washed coal price into its components and development of Price Escalation Formula [ for supply of washed coal from Piparwar Washery of CCL to NCPP- Dadri Power Station of NTPC]. I: Total Washed Coal Price comprises of (a) Raw Coal Price Component with statutory charges on Raw Coal (b) Washing Charges Component with Statutory Charges on Washed Coal II: Escalation Formula for – (a) Raw Coal Price Component (b) Washing Charges Component With adjustment in Price due to Revision of Statutory Charges DETAILS: The price of coal delivered consists of following components: 1. Basic Price 2. Other Charges 3. Statutory Charges 1. Basic Price of Run Of Mine coal shall be determined as under: • Under Price Notification: Price was notified by Government of India and/or notified by any other body designated by Government of India Coal Price Under De-Control Regime ( With price escalation provision): In the event of decontrol of the price of coal in full or in part, or any exemption duly notified by the Government of India in respect of any mine. The Basic prices of coal as mentioned earlier shall be subject to escalation in accordance with a Price Escalation formula. 2. Other Charges: • Transportation Charges: Where coal is transported by the seller beyond the distance of 3 Kms from the pit-head to be delivery /unloading point and the purchaser shall pay transportation charges as applicable time to time • Sizing/Crushing Charges: Where the coal is crushed by mechanical means for limiting the top size to 200mm -250 mm depending on coal agreement. The purchaser shall pay sizing/crushing charges as applicable from time to time. • Rapid Loading Charges: Where coal is loaded through Rapid Loading System either into Indian Railways system or into Purchaser’s Own MGR, Purchaser shall pay Rapid Loading charges as applicable from time to time> (Note : Rapid Loading Charges should be paid only if Rapid Loading system (cl1.25) which automatically loads coal i.e. 3500 or more tonnes per hour. 3. Statutory Charges: The Statutory Charges shall comprise of : Royalties, Cesses, Duties, Taxes, Levies etc. if any, shall be payable by the purchaser subject to –Provisions of relevant statute and not included in the basic price, shall become effective from the date as Notified by the Government. Compensation for Excess Superficial Moisture: • If the monthly weighted average total moisture in coal exceeds the permissible % age level given in clause 10.2 of this agreement over the monthly weighted average equilibrated moisture at 40 Oc and 60% RH equilibrated moisture • Pro-rata correction factor equivalent of the percentage by which the total moisture exceeds the equilibrated moisture. • Shall be applied to the weights recorded by the weighment system • This aspect should be taken care of for the purpose of billing and payment supplies during that month. • The agreement provides that- The permissible limits are to be reviewed and revised based on study through Joint reference to Central Fuel Research Institute, Dhanbad. If the studies are not completed within six months, the permissible moisture limits provided in this agreement shall be taken as final for adjustments in quantity of coal with retrospective effect. The total moisture determination shall be jointly undertaken forthwith as per BIS, without waiting for the norms to be fixed through the • Study to be conducted by CFRI I. Breaking up of total price of washed coal ( P ) into Raw Coal Component (P R ) ; Statutory Charges Component on Raw Coal (Psr) ; Washing Charges Component (PW) and Statutory Charges Component on Washing Charges, if any (Psw) : Corresponding price break up of Rs 715 and Rs. 930 per tonne are – Component Symbol Rs/ tonne Rs/ tonne (effective from (effective from 1.4. 1997) 1.4.2001) Basic Raw coal Price (BP) 332 431 + Crushing Charges (CR) PR 20 20 Statutory Charges on Raw Coal (Ro) =Royalty + (SE)= SED Add: Adjustment due to Yield Factor (Yc) Total Raw Coal Component Price Washing charges = + Wage Revision Adjustment Total Price of Washed Coal PSr Extra  PW (P) 50 3.50 83.78 489.28 225.72 715.00 50 3.50 154.97 659.47 268.48 +2.04 930.00 The above shall be the base prices for the purpose of escalation w.e.f. 1-4-1997 and 1-4-2001 respectively. II. Derivation of price escalation formula for the components of washed coal i.e. A-I: Raw Coal Component(PR) A-II: Washing Charges Component(PW) In addition: Adjustment for Statutory Charges (PSr and PSw ) and adjustment due to Wage revision Yearly Escalated Price of coal in terms of Rs / Tonne may be determined by the following formula: Let, PR0 = Price of coal on a mutually agreed date to be termed as “Base Date”(from which date price escalation to be calculated for the first time or any subsequent times) PR1 = Escalated price of coal to be calculated annually on the date of revision A-I: Price escalation formula for the RAW COAL components: PR1 = PR0 + dPR1 + dPR2 + dPRW + Escalation on Breaking Charges A1 B1 C1 dPR1 PR0 X [{ 44 + W1 X ------+ W2 x-------+W3 x --------= A0 B0 C0 D1 E1 ------- + W5 x ----- } / 100] – PR0 D0 E0 W1 , W2 , W3 , W4 , W5 are respectively the Weights for (1) Salaries & Wages (2) POL (3) Explosives ; (4) Power and (5) Other stores including spares. PART-2: dP2 =Coal price escalation in Rs/tonne on account of Depreciation, Interest and Pre-tax Return which are based on the variation in Net Block per Tonne of Coal (related to capacity) of the linked / dedicated mine of the Seller. = For variation of every Rs 10 in the net block per tonne of coal (related to capacity), the impact of price on per tonne of Coal (Rs per tonne) shall be: dP2 = Rs 2.50 * (F1 – Fo)/10) per tonne PART 3 (dPRW ) : Escalation factor to take care of the revision of salaries and wages for the regular employees of CCL engaged in the linked / dedicated mine catering to supplies of coal to Piparwar Washery: + W4 x By using the following formula tonne (Rs./tonne) : Total additional amount payable per month to the regular employees as additional salaries & wages on account of salary / wage revision for the linked / dedicated mine, after such revised amount is officially declared and is actually paid after 1-4-2001 dPRW = -----------------------------------------------------------Total installed capacity of the mine on MT basis, related to linked / dedicated mine supplying coal to Piparwar Washery / 12 . Escalation of Breaking Charges: The escalation of breaking charges shall be based on following formula: E1 Escalated Breaking Charges (CR )= CR x ( 0.75 + 0.25 x -------- ) E0 A-II: Price escalation formula for the Washing Charges components: (A) Formula for dPW1 : The agreed formula of price escalation for the washing charges part derived from the Minutes of Meeting dt. 7-8-1988 is as under: a1 b1 c1 d1 e1 n dPw1 = Pw0 x ( w1 x-----x (1.03) --+w2x--+w3x -----+w4 x ----+w5 x----a0 b0 c0 d0 e0 f1 +w6 x-------+w7 }/100 - PWO + { PSw + (g1 - g0) } f0 Weights, Indices, Notifications for Price ESCALATION CALCULATIONS are detailed below: Compon ent Salaries & Wages POL Explosiv es Power Other stores Symbo l W1 Weigh ts in % 9 Indices / basis Symbols Part 1: Items of Cost of Sales which is linked to published indices/ SEB tariff notifications / Govt. notification on Diesel Price and CIL rate contract on SMS. W2 W3 W4 W5 4 5 6 32 AICPI for industrial workers available Ai in www.chd.nic.in (published by Govt of India) Actual Diesel price notified by the Bi Govt. Rate Contract for SMS notified by CIL Ci Tariff Revision notified by SEBs WPI available www.eaindustry.nic.in (published by Govt of India) Di in Ei ANNEXURE- A Calculation of Price break-up for of WASHED COAL supplies to DADRI from Piparwar as on 1-4-1997 and 1-4-2001 Unit of Measurement As of 1.4.97 Tonne 6,500 5,525 4,585 940 Amount (in 000) 1,834,300 110,500 276,250 19,338 Amount per Tonne Escalated as on 1-4-2001 1 2 3 4 I a b c e II III a b c d e f g h IV Rated Capacity Raw Coal input ( 85% of 1) here the capacity of the mine is considered at 85%. Tonne Beneficiated Coal ( 83% of 2 ) here taken as the agreed yield for beneficiated coal Tonne Rejects & Slurry ( 2 - 3 ) Tonne Raw Coal Part: Raw Coal Input Costs Basic Price (Bp) Rs Breaking charges (CR) Rs Total Raw Coal Price (PR) Royalty (Ro) Rs Stowing Excise Duty(SE) Rs Total Statutory Charges (Psr) Rs Total PR+Psr Yield adjustment Factor (Yc) Yield adjustment Amount Raw Coal Component Price Rs Washing Charges Variable Costs : Wages Cost(W1) – AICPI Rs Stores - PoL (w2) - Diesel) Rs Stores - Others (w3) -WPI Power (W4) - SEB Tariff Rs Misc Expenses (w5) - WBI Rs Admn Charges - (W6) Rs TOTAL Variable --> Fixed Costs: Int on Working Capital (Fixed) Rs Depreciation (Fixed) Rs Int on Loan Capital ( Fixed) Rs Return on Equity ( Fixed ) Rs Total Washing Charges (excl Wage Revision)--> PW Wage Revision (as per CCL)-PWW Price of Washed Coal (P) Transportation Cost TOTAL Price incl Surface Transportation 0 431 20 451 50 3.5 53.50 504.50 1.205 104.24 608.74 23,429 31,070 74,568 38,652 51,306 53,690 7.39 14.10 19.58 12.33 13.81 14.46 2,889 231,130 262,766 264,047 0.63 50.47 57.39 57.66 247.83 1.89 858.46 50.10 908.56 (say 909) V VI VII Rs Rs Rs Calculation of increase in coal price during the period Jan 2000 to Dec 2004 as per escalation formula submitted to XXXX. Proposed price escalation formula: A1 B1 C1 D1 E1 F1 P1 = PO ( X + w1 x ---- x (1 + y) + w2 x ---- + w3 ---- + w4 x ---- + w5 x ---- x w6 x -----) A0 B1 C0 D0 E0 F0 X Y AO A1 BO B1 CO CI DO D1 EO E1 FO F1 W1 W2 W3 W4 W5 W6 = = = = = = = = = = = = = = = = = = = = % of total sale price considered as fixed = 10% Annualized increase in wages due to pay revision = 3.35% AICPI as on Jan 2000 = 2125 AICPI as on Dec 2004 = 2588 RBI index of mineral oil as on Jan 2000 = 172.04 RBI index of mineral oil as on Dec 2004 = 330.8 RBI index of explosives as on Jan 2000 = 124.03 RBI index of explosives as on Dec 2004 = 127.00 RBI index of power as on Jan 2000 = 166.3 RBI index of power as on Dec 2004 = 252.2 WPI for all commodities as per RBI Index as on Jan 2000 = 146.1 WPI for all commodities as per RBI Index as on Dec 2004 = 188.2 RBI index for “Heavy Machinery” as on Jan 2000 = 143.4 RBI index “Heavy Machinery” as on Dec 2004 = 189.9 Weightage for salary & wages = 42 % Weightage for POL = 6% Weightage for explosive = 3% Weightage for Power = 9% Weightage for other expenditure including other stores & spares = 21% Weightage for Heavy Machinery = 9% 2588 330.8 127.0 252.2 188.2 189.9 P1 = 100 ( 0.10 + 0.42 x ------- x (1 + 0.0335) + 0.06 x -------- + 0.03 -------- + 0.09 x ------- + 0.21 x -------x 0.09 x ----- ) 2125 172.04 124.3 166.3 146.1 143.4 Increase in 5 years = 37.54% Annualized increase = 6.58 Note: The weightage have been arrived at on the basis of cost sheet of CIL (OCP & UG) for the year 03-04 Government of India deregulated the prices of Non-Coking Coal of grades A, B & C, Coking coal and Semi/Weakly coking coal on 22.03.1996. Subsequently, on 12.03.1997, Government of India deregulated the prices of non-coking coal of grade D, Hard Coke and Soft Coke and also allowed Coal India Ltd. to fix coal prices for grades E, F & G till Jan'2000 once in every six months by updating cost indices as per escalation formula contained in the 1987 report of the Bureau of Industrial Cost & Prices. With effect from 01.01.2000, CIL was free to fix the prices of all grades of coal in relation to the market prices. Pursuant of the above, CIL fixed the prices of deregulated coal from time to time and last such revision has been made on 15-10-09, to be effective w.e.f 00 hrs of 16-10-09. Grade wise Basic Price of coal at the Pit-head excluding statutory levies for Run-of-mine (ROM) Non-LongFlame Coal ,Long flame Coal, Coking Coal, Semi Coking Coal& Weakly Coking Coal ,direct feed Coal, Assam Coal for various subsidiaries of CIL are tabled below : Table: IA Table: IB Table: IC NOTE: 1. In Grade "A" for every additional UHV of 100K Cal /Kg. exceeding 6299 K Cal /Kg, Additional Rs.90 /M Te. shall be added to the price of " A "Grade. 2. For UHV exceeding 7099 k. Cal./ kg. ,the price of coal shall be Rs.3680 per tonne for ROM Coal and the price difference among the steam ,slack and run of mine coal shall remain same. The revised pithead prices of all varieties of Run of Mine Coals have been given in tables I to V. Notes: 1. Additional Rs.20 per tonne shall be charged on pithead price of Run of Mine coal for the supply of Slack Coal. 2. Additional Rs.180 per tonne shall be charged on pithead price of Run of Mine Coal for the supply of Steam Coal. 3. Where the top size is being limited to any maximum limit within the range of 200 mm – 250 mm through manual facilities or mechanical means, a charge at the rate of Rs.39.00 per tonne will be levied, in addition to the price applicable for Run of Mine coal. 4. Where the top size is being limited to 100 mm through manual facilities or mechanical means, a charge at the rate of Rs.61.00 per tonne will be levied, in addition to the price applicable for Run of Mine coal. 5. Where the top size is being limited to 50 mm through manual facilities or mechanical means, a charge at the rate of Rs.77.00 per tonne will be levied, in addition to the price applicable for Run of Mine coal. 6. Where coal is loaded, either into Indian Railways system or into the purchasers’ own system of transport, through high capacity loading system with a nominal capacity of 3500 tonnes per hour or more, additional charge of Rs.20.00 per tonne shall be levied for such loading. 7. Where coal is transported beyond a distance of 3 kms to the loading point, the coal companies shall be entitled to charge additional transport costs from the purchasers at the following rates 1. For a distance of more than 3 kms but not more than 10 kms Rs.44.00 per tonne. 2. For a distance of more than 10 kms but not more than 20 kms Rs.77.00 per tonne. In cases, where coal is transported for more than 20 kms to the loading points, transport charges will be payable on actual basis, to be borne by the purchaser. 8. The pit head prices fixed are exclusive of Royalty, Cess, Taxes and Levies, if any, levied by the Govt., Local Authorities or any other bodies of Excise and Sales Tax from time to time. 9. Grading/ classification of coal and the definitions relating to the same have been given in Annexure –X. 10. The prices given in this notification are either FOR or FOB, as the case may be. Surface transportation charges, where applicable, would be levied extra. 11. The prices do not apply to coal sold for export. 12. For undertaking special sizing or beneficiation of coal, additional charges as may be negotiated between the purchaser and the producer may be realized over and above the pithead prices . 13. A rebate of 5% for supply of wahsery grade coking coal will be given to power houses other than captive ones. 14. The revised basic price of ROM coal for ECL being notified shall be applicable except for the portion of Raniganj coal of grades A & B from such mines of ECL which are supplied under MOU to specific consumers at special price. ROYALTY ON COAL The rates of royalty, which shall be a combination of specific and ad valorem rates of royalty which shall be as follows: R (Royalty Rs/Tonnes) = a +bP Where ‘P’ (Price) shall be the basic pit head price of ROM (run-of time) coal and lignite excluding taxes, levies and other charges. And the value ‘a’ is Fixed Components and ‘b’ is Variable or ad valorem Components. Latest in Coal Pricing Coal Pricing, at present, is fixed by coal ministry in consultation with Coal India Ltd. (CIL) & Singareni Collieries Company ( SCCL ) . The prices are determined on the basis of cost incurred in Coal Production from different mines. Present domestic coal prices range between Rs 770 and Rs 1,700 a tonne. • The expert committee on Integrated Energy Policy headed by Kirit Parikh, has recommended setting up of an independent Coal Regulator to replace government committees for determine coal prices for different user industries. Functions of Regulators:• • • • • Ensure price revisions. Suggest measures for Setting Coal prices. Regulate trading margins. Ensure that price discovery through e-auctions is free of distortions. Ensure coal supply to the power sectors under commercially driven Long – term Fuel Supply & Transport Agreements ( FSTAs) New Coal Royalty System in India The present system of royalty charging is likely to change to combined royalty rates ( fixed plus ad valorem ) to balance the aspirations of the coal producing states and apprehensions of the consumers. This new system of royalty would jack up coal prices by 10 to 15 % taking up the overall royalty components on coal prices to 15 -20 % level. Inventory Control of Coal Implication of CERC and CEA CERC (Terms & Conditions of Tariff) Regulations, 2009 As per the CERC (terms and conditions of tariff) Regulation, 2004 the 2 months coal cost (non peat head) power plant and 1 and half months of coal cost (pit head) has to be taken in the working capital. E.g. for a 1000 MW plant Coal consumption for 1 day = 10000 ton Cost of coal for 1 day = Rs.800 X 10000 = Rs.8000000 Cost of coal for 2 months = Rs. 48 Crore Coal cost for 1 and half month = Rs. 36 Crore The 75% of the working capital has to be taken from the short term debts; on this debt around 12% interest rate can be applicable which can be equal to Interest on working capital = Rs. 5.76 to Rs. 4.32 Crore. CEA Guidelines As per the CEA guidelines 40 days dead stock of coal has to be kept and 8 – 10 hrs. Of live stock of coal has to be maintained. E.g. for a 1000 MW plant Coal cost for 40 days = 400000 x Rs. 800 = Rs. 32 Crore Stacking Area Requirement E.g. for a 1000 MW plant Coal consumption for 1 day = 10000 tonnnes Density of Coal: 1 m3 = 1 Tonne For 40 Days, Coal Required to be stored = 10000 x 40 = 400000 tonnnes Volume = 400000 m3 Height of Coal Stack = 10 m Area required for Storage = 400000/10 = 40000 m2 ≈ 10 acres Captive Coal Mining Under the Coal Mines (Nationalisation) Act, 1973, coal mining was mostly reserved for the public sector. By an amendment to the Act in 1976, two exceptions to the policy were introduced viz., Captive Mining by private companies engaged in production of iron & steel. ii) Sub lease for coal mining to private parties in isolated small pockets not amenable to economic development and not requiring rail transport. The Coal Mines (Nationalisation) Act, 1973 was amended in June, 1993 to allow coal mining for captive consumption for generation of power, washing of coal obtained from a mine and other end uses to be notified by Govt from time to time. The Central Govt, a govt company including state govt company, a corporation owned, managed and controlled by the central govt can do coal mining without the restriction of captive use. The allocation of coal blocks to private parties is done through the mechanism of an inter-ministerial and inter-govt body called the screening committee. It is chaired by the Secretary (Coal) and has representation from Ministry of Steel, Ministry of Power, Ministry of Industry and Commerce, Ministry of Environment and Forest, Ministry of Railways, CIL, CMPDIL and concerned state govts. There are 229 coal blocks for allocation to specified end users. 208 coal blocks have been so far been allocated to eligible companies. So far, production has commenced in 25 blocks. Production from these coal blocks for 2009-10 is about 23.66 million tonnes. Effect of coal utilisation by the imported coal based UMPP in India on the international prices World steaming coal trade around 550 Mt. Till date India has been a small player in the global markets with imports of 17.5 Mt of thermal coal in 2005, up from 15 Mt in 2004 and 10 Mt in 2003. With each UMPP requiring about 12-14 million tonnes of coal, India would become a major player in the world coal markets in the coming decade. Presently there are nine numbers of UMPPs proposed in India having capacities of 4000 MW each, out of these there are four numbers of UMPPs are imported coal based. If we consider the four imported coal based UMPPs then there is need of 16000MW energy generated from imported coal i.e. we need an import of around 48-60 mtpa of coal. This requirement of coal will come up in between 2010 to 2016 i.e. a four fold attainment in coal imports. Coal Bed Methane New area of clean technologies like Coal Bed Methane and Coal Mine Methane, Underground Coal Gasification and Coal Liquefaction are under focus and Government is taking all the necessary steps for development of these areas within the existing legal framework. CMS is one of the potential greenhouse gases and is in adsorbed state on the coal surface and possess a potential threat from safety angle during mining operation. If extracted separately, it forms a supplementary source of energy. In view of the abundant resource of coal in the country, there is a significant scope for commercial development of CBM. Methane associated with virgin coal beds is conventionally termed as Coal Bed Methane. Similarly extraction of Methane from working mines is termed as Coal Mine Methane. Consequent to the formulation of CBM Policy in 1977, Govt of India has so far allocated 26 CBM blocks to various operators for exploration and exploitation of CBM. 10 more blocks to various operators were offered in 4th round of bidding concluded in Oct’09. The offers received against this bidding are under consideration of the Govt for their allotment for commercial development. CBM is jointly managed by Ministry of Coal and Ministry of Petroleum and Natural Gas. CMM related activities are being addressed by Ministry of Coal separately. Central Mine Planning & Design Institute Ltd, CMPDI has taken up a CIL R&D project for delineation of prospective CMM blocks in ECL, BCCL and CCL areas of CIL and preparation of data dossier for 1 or 2 most prospective and commercial viable CMM blocks. CIL & ONGC is working on collaborative project on CBM. Some of the identified CBM blocks are Jharia & Raniganj. A CMM/CBM clearing house has been established at CMPDI, Ranchi under the aegis of Ministry of Coal and United States Environmental Protection Agencies on 17th Nov’08. The clearing house will function as the nodal agency for collection and sharing of information on CMM/CBM related data of the country and help in the commercial development of CMM projects in India by public/private participation, technological collaboration and bringing financial investment opportunities. Great Eastern Energy Corporation is the first private sector company to take up coal bed methane exploration in India. As the third largest coal producer in the world, India has good prospects for commercial production of coal bed methane. Nevertheless, with demand for gas rising sharply, CBM will have to compete with imported (liquefied) natural gas. Methane is, however, a viable alternative to compressed natural gas (CNG) and its use as automotive fuel will certainly help reducing pollution levels. India is one of the select countries which have undertaken steps through a transparent policy to harness domestic CBM resources. The Centre has received an overwhelming response from prospective producers with several big players starting operations on exploration and development of CBM in India. It is envisaged that in India operational CBM fields may contribute about 8-10 mmscmd of gas production in the next five years. Investment in coal and gas transportation infrastructure, including gas gathering, transportation and distribution, is necessary to fill the gap and move CBM from coal fields to local and more distant end-use markets which include rural and commercial power generation and transportation fuels. India is set to become the fourth after US, Australia and China in terms of exploration and productionof coal bed methane. In order to fully develop India's CBM potential, delineation of prospective CBM blocks is necessary. There are other measures like provision of technical training, promotion of research and development, and transfer of CBM development technologies that can further the growth of the sector. With growing demand and rising oil and gas prices, CBM is definitely a viable alternative supplementary energy source. Moreover, CBM extraction also potentially offers the opportunity of earning carbon credits under Clean Development Mechanism of Kyoto Protocol, being an environmentally friendly fuel. Coal bed methane will clearly emerge as the one of the viable and clean routes to India's energy security. The development plan for Sohagpur CBM blocks (MP) has been approved by the Government and development activities have been planned to commence in FY 2010-11 by drilling and completion of additional wells. Prolonged production testing was undertaken in the wells drilled in Sohagpur CBM blocks with favourable results. The plan for 2010– 11 is to monetise the production capability from the present as well as the proposed wells. During the year, two CBM blocks BS-1 and BS-2 were relinquished. With this, RIL currently holds a total of 3 CBM blocks. CBM Exploration Experience – Reliance (Sohagpur) CBM Discovery – 3.65 TCF, validated by DGH Technology used for drilling – Air Drilling (First ever used in India) Gas Production Potential – 3-5 MMSCMD in a frontier area Water Production Potential – 50000-70000 BPD of good quality water Investment potential – Over 3000 Cr OIL NEW EXPLORATION LICENSING POLICY • In view of the inherent risk of hydrocarbon exploration and the huge financial investment associated with such risky exploration ventures, it has been felt that the efforts of the upstream National Oil Companies (NOCs) may not be adequate to achieve the set mandate. • Hence opening up of the acreages for active exploration by private or joint venture companies, in addition to the efforts of the NOCs, was considered necessary. • The acreages offered by the Government under various exploration rounds earlier met with only partial success. The main thrust for acceleration of exploration activities has, however, begun with the introduction of New Exploration Licensing Policy (NELP) by the Government in 1997. • NELP has introduced a level playing field for public as well as private sector players. NOCs are also required to compete with the private and joint venture companies in acquiring exploration acreages in Indian sedimentary basins. • Under this policy, all companies would be required to bid for a committed work programmes to profit petroleum share expected by the contractor at various levels of pre-tax multiple of investments and percentage of annual production sought to be allocated towards cost recovery. OBJECTIVES OF NELP ROUNDS • Intensive exploration of Indian basins. • Opening up of acreages in ultra deep water & frontier areas. • To stimulate & promote interest and activity from a wide range of E & P players. • To bring-in new & state of art technology in exploration & exploitation. • Level playing field to all participating companies. • Transparent Bid Evaluation system . The other main features of the terms offered by the Government inter alia include: • no signature, discovery or production bonus by the bidder; • income tax holiday for seven years from the start of commercial production, • no customs duty on imports required to be payable for petroleum operations, • biddable cost recovery limit up to 100 per cent, royalty to be payable by the contractor on ad voleram basis, • freedom to the contractor for marketing of oil and gas in the domestic market, • fiscal stability provision in the contract and • Incentive for deepwater exploration with only half of the royalty payable in the initial seven years from the beginning of commercial production. There are certain differences between the earlier rounds of bidding for exploration blocks and NELP. • While NOCs were to bear royalty, cess and PEL fees on behalf of private companies in the earlier rounds, companies are now required to bear royalty. • Cess and fees have now been exempted under NELP. • Under the policy, NOCs are no longer needed to participate as Government nominees. The policy exempts them from payment of customs duty and cess for the blocks offered. Table 9.14: Progress under new exploration license policy • Parameter NELPI NELP II 23 23 2001 2,63,050 NELP III 23 23 2003 2,04,588 NELP IV 21 20 2004 1,92,810 NELP V 20 20 2005 1,15,180 NELP VI 52 52 2007 3,06,200 NELP VII 44 41 2008 1,21,000 No. of blocks 25 awarded No. of PSCs 24 signed Signed in 2000 Area awarded 1,94,735 (sq. km) Source : Ministry of Petroleum & Natural Gas PSC: Production Sharing Contract NELP I– JANUARY 8, 1999 • World class gas discovery by RIL-NIKO in 2002 in KG off shore block • Cairn energy’s discovery in KG deep water block • Gas discovery by RIL in Mahanadi shallow water block NELP II – 2000 • Discoveries were made in Cambay Basin GSPC discovered OIL & NIKO discovered natural gas NELP III – 2001 • GSPC - jubilant - GGR consortium made world class gas discovery in KG ( KG-OSN-2001/3) offshore block in June, 2005 NELP IV – 2003 • Provision of fast track arbitration • Higher weightage for technical and financial viability of deep water block • Surcharge on foreign companies abolished • Bank guarantee to be returned after completion of MWP NELP V – 2005 • Workstations were provided in data centers in London, Houston, Calgary & Dubai to facilitate companies to review and analyze data. • Govt. decided to take its profit share of natural gas in cash or kind for a block of 5yrs instead of such option being made every year. • Co.’s with net worth US $500million or more not required to give bank guarantee towards MWP commitment as against the threshold limit of US $ 1 billion earlier. NELP VI – 2006 • Check on aggressive/speculative bidding • Uniform seismic coverage of basins • Participation of E&P companies with global experience – Induction of new technology – Global knowledge – Better geological models – Better E&P practices • Better Government take NELP VII • Approximately 50 to 60 blocks have been identified for the offering. NELP VIII- 2009 • 70 new blocks for bids to the Indian and foreign companies for exploration of oil and natural gas • bidding would lead to 42 billion dollars of gas in the next 11 years. NELP IX-2010 • more tax benefits • investment- based incentives The New Exploration Licensing Policy, a vehicle designed by the Government of India, has so far been successful in accelerating the pace of hydrocarbon exploration in the country. The hydrocarbon sector in India is one of the most crucial industries for determining energy security as nearly 45 per cent of the country’s total energy needs are met by the oil and gas sector. Production of indigenous oil and gas is therefore a major plank of oil security for the nation. Through the New Exploration Licensing Policy, the Government of India is making a concerted effort to expeditiously explore the inadequately explored and unexplored areas of the country’s sedimentary basins. Linkage THE LINKAGE BETWEEN OIL CONSUMPTION AND ECONOMIC GROWTH IN INDIA The relationship between use of energy and economic growth has been a subject of greater inquiry as energy is considered to be one of the important driving forces of economic growth in all economies unable to meet up the world demand for oil. The supply constraint of energy could be attributed to the frequent geo-political tensions between the nations or natural physical supply constraints in the oil extracting regions 1. The increasing world demand for oil,2 leads to frequent escalation in the world oil prices.3 Like shortage of oil, there exists shortage of electricity and other forms of energies viz. natural gas.4 The shortage can significantly affect the consumption and production in the economy. One or the other forms of energy becomes vital to all the sectors of the economy viz. agriculture, industry and services. This energy dependence being common to every sector of the economy justifies the association between energy utilization and the overall economic growth rate in an economy. Hence, any deficiency in supply of oil, natural gas and electricity generations can directly constrain the economic activities, thereby inhibiting the growth rate. The declining supply of these sources of energy not only raises the input prices5 but also influences the prices of other commodities leading to a rise in overall inflation rate and thereby dampening the aggregate demand and growth rate. In India, the transport sector is the principal consumer of petrol and diesel, followed by big and small industrial units. India in the past had experienced a huge import bill on account of an increase in the price of crude oils. The inelastic oil demand and rising oil import bill had put pressure on the scarce foreign exchange resources and had also been largely responsible for shortages in energy supply. The linkage between oil, gold prices in recession Underlying the rise in the oil price has been the basic strength of oil as a commodity. The world has probably reached the point at which oil supply has peaked - if not, we are close to that point. The growth of the huge economies of China and India is limited by the long term constraints of the oil supply, more than by any other factor. If the recovery does continue, the oil price will regain the level of $100 a barrel, and the gold price will rise well above $1,000 an ounce. My own expectation is that these figures will be exceeded substantially, perhaps to $150 or $200 a barrel and $1,500 or $2,000 an ounce. But that will limit the possible global recovery. The world has, indeed, been living beyond its means, in terms of the oil supply. Everything else depends on that, and will have to adjust to a higher oil price. Oil and gold prices have been linked for most of the period of the recession. In recent, both have been in a stage of recovery. The gold price has reached $982 an ounce, close to its peak when it touched $1,000 an ounce. Oil prices fell in the recession by about 70 per cent, and have now received about 50 per cent. The recovery in the gold price reflects a number of factors. The Asian economies have accumulated excessive quantities of dollar securities, and the Asian central banks are reluctant to continue accumulating dollars, except on a purely speculative basis. The weakening of the dollar has had a reciprocal effect in the strengthening of the gold price. There is also a fear that the Keynesian policies which have helped to create the appearance of a global recovery will, at some point, lead to a revival of inflation. Oil Pricing Oil Price History and AnalysisIntroduction Crude oil prices behave much as any other commodity with wide price swings in times of shortage or oversupply. The crude oil price cycle may extend over several years responding to changes in demand as well as OPEC and non-OPEC supply. The U.S. petroleum industry's price was heavily regulated through production or price controls throughout much of the twentieth century. In the post World War II era U.S. oil prices at the wellhead averaged $26.64 per barrel adjusted for inflation to 2008 dollars. In the absence of price controls, the U.S. price would have tracked the world price averaging $28.68. Over the same post war period the median for the domestic and the adjusted world price of crude oil was $19.60 in 2008 prices. That means that only fifty percent of the time from 1947 to 2008 have oil prices exceeded $19.60 per barrel. (See note in box on right.) Until the March 28, 2000 adoption of the $22-$28 price band for the OPEC basket of crude, oil prices only exceeded $24.00 per barrel in response to war or conflict in the Middle East. With limited spare production capacity, OPEC abandoned its price band in 2005 and was powerless to stem the surge in oil prices, which was reminiscent of the late 1970s. Crude Oil Prices 1947 - August, 2009 Post World War II Pre Embargo Period Crude Oil prices ranged between $2.50 and $3.00 from 1948 through the end of the 1960s. The price oil rose from $2.50 in 1948 to about $3.00 in 1957. When viewed in 2008 dollars an entirely different story emerges with crude oil prices fluctuating between $17 and $19 during most of the period. The apparent 20% price increase in nominal prices just kept up with inflation. From 1958 to 1970, prices were stable near $3.00 per barrel, but in real terms the price of crude oil declined from above $19 to $14 per barrel. The decline in the price of crude when adjusted for inflation for the international producer suffered the additional effect in 1971 and 1972 of a weaker US dollar. World Events and Crude Oil Prices 1947-1973 Middle East Supply Interruptions Yom Kippur War - Arab Oil Embargo In 1972, the price of crude oil was about $3.00 per barrel. By the end of 1974, the price of oil had quadrupled to over $12.00. The Yom Kippur War started with an attack on Israel by Syria and Egypt on October 5, 1973. The United States and many countries in the western world showed support for Israel. Because of this support, several Arab exporting nations and Iran imposed an embargo on the countries supporting Israel. While these nations curtailed production by 5 million barrels per day other countries were able to increase production by a million barrels. The net loss of 4 million barrels per day extended through March of 1974 and represented 7 percent of the free world production. Any doubt the ability to control crude oil prices had passed from the United States to OPEC was removed during the Arab Oil Embargo. The extreme sensitivity of prices to supply shortages became all too apparent when prices increased 400 percent in six short months. U.S. and World Events and Oil Prices 1973-1981 Crises in Iran and Iraq In 1979 and 1980, events in Iran and Iraq led to another round of crude oil price increases. The Iranian revolution resulted in the loss of 2 to 2.5 million barrels per day of oil production between November 1978 and June 1979. At one point production almost halted. US Oil Price Controls - Bad Policy? The rapid increase in crude prices from 1973 to 1981 would have been much less were it not for United States energy policy during the post Embargo period. The US imposed price controls on domestically produced oil. The obvious result of the price controls was that U.S. consumers of crude oil paid about 50 percent more for imports than domestic production and U.S producers received less than world market price. In effect, the domestic petroleum industry was subsidizing the U.S. consumer. Did the policy achieve its goal? In the short-term, the recession induced by the 1973-1974 crude oil price spike was somewhat less severe because U.S. consumers faced lower prices than the rest of the world. However, it had other effects as well. In the absence of price controls, U.S. exploration and production would certainly have been significantly greater. Higher petroleum prices faced by consumers would have resulted in lower rates of consumption: automobiles would have achieved higher miles per gallon sooner, homes and commercial buildings would have has better insulated and improvements in industrial energy efficiency would have been greater than they were during this period. Consequently, the United States would have been less dependent on imports in 1979-1980 and the price increase in response to Iranian and Iraqi supply interruptions would have been significantly less. US Oil Price Controls 1973-1981 OPEC Fails to Control Crude Oil Prices OPEC has seldom been effective at controlling prices. While often referred to as a cartel, OPEC does not satisfy the definition. One of the primary requirements is a mechanism to enforce member quotas. The old joke went something like this. What is the difference between OPEC and the Texas Railroad Commission? OPEC doesn't have any Texas Rangers! The only enforcement mechanism that has ever existed in OPEC was Saudi spare capacity. With enough spare capacity at times to be able to increase production sufficiently to offset the impact of lower prices on its own revenue, Saudi Arabia could enforce discipline by threatening to increase production enough to crash prices. In reality even this was not an OPEC enforcement mechanism unless OPEC's goals coincided with those of Saudi Arabia. From 1982 to 1985, OPEC attempted to set production quotas low enough to stabilize prices. These attempts met with repeated failure as various members of OPEC produced beyond their quotas. During most of this period Saudi Arabia acted as the swing producer cutting its production in an attempt to stem the free fall in prices. In August of 1985, the Saudis tired of this role. They linked their oil price to the spot market for crude and by early 1986 increased production from 2 MMBPD to 5 MMBPD. Crude oil prices plummeted below $10 per barrel by mid-1986. Despite the fall in prices Saudi revenue remained about the same with higher volumes compensating for lower prices. A December 1986 OPEC price accord set to target $18 per barrel bit it was already breaking down by January of 1987and prices remained weak. The price of crude oil spiked in 1990 with the lower production and uncertainty associated with the Iraqi invasion of Kuwait and the ensuing Gulf War. The world and particularly the Middle East had a much harsher view of Saddam Hussein invading Arab Kuwait than they did Persian Iran. The proximity to the world's largest oil producer helped to shape the reaction. Following what became known as the Gulf War to liberate Kuwait crude oil prices entered a period of steady decline until in 1994 inflation adjusted prices attained their lowest level since 1973. The price cycle then turned up. The United States economy was strong and the Asian Pacific region was booming. From 1990 to 1997 world oil consumption increased 6.2 million barrels per day. Asian consumption accounted for all but 300,000 barrels per day of that gain and contributed to a price recovery that extended into 1997. Declining Russian production contributed to the price recovery. Between 1990 and 1996 Russian production declined over 5 million barrels per day. OPEC continued to have mixed success in controlling prices. There were mistakes in timing of quota changes as well as the usual problems in maintaining production discipline among its member countries. Non-OPEC Production & Crude Oil Prices OPEC Production & Crude Oil Prices Current Scenario –International (oil pricing uncertainty)The world’s energy ministers and oil producers are trying to agree on ways to prevent oil price spikes in the immediate future – although at least one economist is predicting “triple-digit” oil later this year. The elite group is today (Wednesday, March 31) concluding their three-day International Energy Forum meeting in Cancun, Mexico. According to papers published ahead of the event, participants considered “demand and supply uncertainties,” having to balance Opec’s claim of spare oil capacity “exceeding 6 million barrels per day” against the claims of neutral strategic advisors PFC Energy that oil will be “peaking between 2020-2025 around 95.0 mmb/d.” The majority of oil consuming nations are siding with Opec, the producers and consumers should work together to avoid a repeat of 2008’s market volatility.The change in attitude marks a significant shift in political relations between Opec, other producers and the world’s biggest oil-consuming countries. Opec’s efforts to control the market once made it the enemy of the US and many European nations. However, nothing from the meeting has yet indicated how this will be achieved, or at what price Opec should endeavour to maintain oil. In the first place, the US is reportedly pushing for a free-market approach.But there was at least one important dissenter this week. At least publicly, the US insisted at the discussions that markets needed to be left to determine the oil price. Daniel Poneman, US deputy energy secretary, said: “The goal of the US is a clear and long-standing one and that is to let the laws of supply and demand set prices.” Meanwhile, delegates are quoted by Reuters agreeing that oil at $70-80 per barrel “was good for both sides,” maintaining producers’ revenues and consumers’ economies. It continues: But there was no sign of a clear consensus by OPEC members at what price they would ramp up production if prices broke above the band Saudi Arabian Oil Minister Ali al-Naimi this week called "most appropriate". "Prices above $85 for a sustained period of time could well be harmful. We have to be aware that the economic recovery is still fragile," an OPEC delegate told Reuters on the sidelines of the forum, which is aimed at promoting dialog between oil consumers and producers. US crude is currently up to around $82 a barrel, with Reuters citing analysts suggesting “it could push even higher as demand from the United States and other industrialized nations rebounds as their economies recover.” But how much longer can the world pretend that it won’t soon be facing another energy shock, one every bit as challenging as the one it faced two years ago? Does anyone still believe the reassuring forecasts from discredited feel-good organizations like the International Energy Agency about new sources of cheap supply, like those that once flowed from places like Prudhoe Bay in Alaska or the North Sea? If so, where is that supply of new affordable oil coming from? Surely not from tar sands or from ultra-deep water fields six miles below the ocean’s floor. He goes on to predict further price shocks in the immediate future: By the fourth quarter of this year, oil prices will be back in triple-digit range, and by next year oil prices will rise to record highs, taking out the high-water mark of $147 per barrel set back before the recession began in 2008. We’re barely out of the recession, and already we face prices that, just a few years ago, our government, our oil industry and our economists toldus we would never see. Current Scenario – India India’s imports of oil are increasing. Our import dependence has reached 80 per cent and is likely to keep growing. At the same time 2008 saw an unprecedented rise in oil price on the world market. Oil price volatility has also increased. Though future oil prices are difficult to predict, they are generally expected to rise. Given our increasing dependence on imports, domestic prices of petroleum products have to reflect the international prices. When the average monthly price of Indian basket of crude oil on the world market increased from US$ 36 / barrel in May 2004 to US$132.5 / barrel in July 2008, the government did not permit Public Sector Oil Marketing Companies (OMCs) to pass the full cost of imports on to domestic onsumers of major oil products, i.e., petrol, diesel, domestic LPG. The consumers of these products thus received large subsidies. As a consequence, OMCs had large under-recoveries1, which were financed partly by Government through issuing bonds, and partly by upstream public sector companies ONGC and OIL, and GAIL through price discounts. The OMCs also absorbed a part of the under-recoveries themselves. These policies had a number of consequences. They put stress on government’s finances. They reduced the cash surplus of upstream public sector oil companies restricting their ability for exploration of domestic fields and acquisitions overseas. As the oil bonds were not issued to OMCs on time, they created cash flow problems for OMCs who had to borrow from the market, which increased interest payments and reduced their surplus. Since only the OMCs were provided financial support, the private sector companies withdrew from oil marketing. This not only made in fructuous the large investments they had made in setting up retail outlets, it also reduced competition in oil marketing. Subsidizing domestic consumers also did not incentivize them to economize on use of petroleum products. Rather, as prices remained low, and personal incomes rose, the demand for petroleum products such as petrol and diesel recorded double digit growth – higher than the GDP growth. Continuation of the present policies is not viable, particularly once oil prices rise again. Over the years, Government has followed a variety of policies for pricing of petroleum products, all of which have been found to have some deficiency or the other. A viable long-term strategy for pricing major petroleum products is required. A viable policy has to be workable over a wide range of international oil prices and has to meet the various objectives of the government. It should limit the fiscal burden on government and keep the domestic oil industry financially healthy and competitive. OBJECTIVES OF POLICY AND ISSUES The very first question is: Should the government intervene at all in the market and set prices? The first reason for intervention is to protect poor consumers so that they may afford kerosene for lighting, which is a necessity for those who do not have access to electricity. Another objective may be to provide merit goods to consumers such as clean cooking fuels like natural gas, LPG and kerosene to replace use of biomass-based fuels such as firewood and dung. These biomass based fuels create indoor air pollution that causes respiratory diseases, eye infections and result in many premature deaths, particularly of women and children. Also, use of firewood encourages deforestation and dung is better used as a fertilizer. Moreover, the task of gathering these fuels keeps girls away from schools. Thus, use of clean cooking fuels has many social and environmental externalities, and as merit goods the government may promote them through subsidies. Another frequently reported reason for Government's intervention is to insulate the domestic economy from the volatility of petroleum prices on the world market. It is feared that complete passthrough of increase in world oil prices may cause inflation which may persist even when oil price comes down. There is no clear evidence that in an increasingly open and competitive economy, price movements triggered by changes in the prices of oil products would persist over the medium-run. In addition, attempts to insulate the domestic economy against volatility requires discriminating between a secular price rise due to demand-supply forces and a price rise due to transient causes such as speculation in the world market. This is difficult to do. To the extent the level of self-sufficiency in domestic oil production increases, the impact of international oil prices on domestic economy would be reduced. Thus, keeping domestic oil firms viable and in good financial health and providing an environment in which they can grow are also important policy objectives. It is equally important to keep domestic private sector firms viable as it is to keep public sector firms viable. A level playing field between public and private sector firms as well as among public sector firms is desirable to promote competition. A major objective of policy is to have an efficient and competitive oil economy that promotes efficient use by consumers, appropriate choice of fuels among substitutes and a proper choice of technique. This is best ensured by a competitive energy sector. Intervention through price control necessitates that someone bears the financial costs. The issue therefore is to assess the costs and incidence of the burden of alternative mechanisms on different groups in the society. On whom the burden falls depends on the policy and the instruments used. If the costs are financed by a general increase in taxes, or by increasing fiscal deficit or by cutting other government expenditure, all these affect certain sections of the people adversely. Price control means setting prices. If it is done on a cost-plus basis, it creates incentives for gold plating and creative accounting. Also, price calculations involve rigid specifications of items to be considered and their costs. This discourages innovation. For example, storage of LPG in large underground caverns facilitates imports by larger ships and reduces unloading time compared to storage in over-ground tanks. But, it may involve increase in operating costs. If the cost formula has set item-wise limits on operating costs, the project may be discouraged even if its total cost is much less. If prices are to be fixed by the Government, that has to be based on some principle. Prices can be fixed based on pre-determined formula, which is derived from principles like import parity (IPP), trade parity (TPP), or export parity (EPP). This approach is also fraught with major deficiencies. The formula often involves elements of cost-plus. In an industry, which is continuously changing, a prescriptive and biased cost-plus pricing formula requires continuous monitoring and periodic adjustments in certain components of the formula. For instance, there is no single or unique formula for import parity which is applied globally (Note 3, Appendix). The Rangarajan Committee (February 2006) suggested a pragmatic approach of TPP for pricing of petrol and diesel which was accepted by the Government. It has, since then, been applied to petrol and diesel. It was derived as a weighted average of IPP and EPP in the ratio of 80:20. The weight of 20 for EPP was based on the share of petroleum product exports in the total consumption in 2004-05. As suggested by the Committee, this ratio was required to be assessed periodically and adjustments made to align the formula to the current position. The trade parity pricing was also recommended by the Parikh Committee on Integrated Energy Policy (August 2006) as one which reflects the opportunity costs of a consumer or a producer. According to the Integrated Energy Policy, IPP is to be used for a product for which the country is a net importer and EPP for a product for which it is a net exporter. As long as the country exports a particular product, EPP equals TPP, as suggested by the Integrated Energy Policy. All these call for administrative and regulatory tasks to be performed by the Government or its agency on a permanent basis. Also, a prescriptive, formula-based approach involving direct government intervention does not result in a competitive price discovery process. Instead, it increases administrative burden. A competitive price discovery process empowers companies to follow their own judgments of market conditions and results in fair pricing of products. In the event of any company adopting unfair pricing methods, such activities can be curbed by the regulatory authorities set up by the Government. Price control, subsidies and taxes can introduce distortions which may not be desirable. Apart from inefficient use, it also leads to erroneous choice of technique. For example, if diesel is cheap, it may encourage freight movement by trucks rather than by train. When the price difference between petrol and diesel is high, diesel driven vehicles may be preferred. If there is a large difference between the prices of diesel and kerosene, kerosene may be used to adulterate diesel. In 2008, we have even seen diesel being used in place of furnace oil. Intervention in pricing must be carefully thought out for its possible consequences. NEED FOR CHANGE IN POLICY We have worked out domestic prices of the four products under alternative assumptions of crude price on the international market. Provides estimated retail selling prices of petrol, diesel, LPG and kerosene at Delhi corresponding to a range of prices of the Indian basket of crude oil from $60/bbl to $150/bbl. It reveals that when crude oil prices rise from US$70/bbl to $120/bbl, the price of petrol in Delhi is required to be increased by Rs.20/litre, the price of diesel by less than Rs. 20/litre and LPG by around Rs. 200 per cylinder. Domestic Prices of Petrol, Diesel, Kerosene and LPG derived from different levels of prices of the Indian Basket of Crude Oil. International Prices Crude Oil (Indian Basket) Petrol Diesel Kerosene LPG Petrol Indicative Retail Selling Price(at Delhi) Diesel Kerosene LPG 60 70 80 90 100 110 66 77 88 99 110 121 ($/bbl.) 70 72 81 83 93 94 104 115 127 ($/MT) 538 595 652 106 709 117 765 128 822 43.75 47.71 51.66 55.61 59.56 63.51 (Rs./Litre) 32.23 36.08 39.92 43.76 47.61 51.45 23.82 27.29 30.76 34.23 37.70 41.18 (Rs. / Cyl.) 455.42 495.41 535.42 575.42 615.42 655.42 120 132 130 143 140 154 150 165 Current Retail Prices 138 149 161 172 140 151 162 173 879 936 993 1,049 67.46 71.41 75.37 79.32 44.72 55.29 59.13 62.98 66.82 32.92 44.65 48.12 51.59 55.06 9.23 695.43 735.43 775.42 815.42 281.20 The product prices of Petrol, Diesel, Kerosene, LPG have been derived through regression equations of crude and product prices in international market during January '07 to December '09. The equation, Y = a + bX, in which Y is product price and X is crude oil price, gives the following estimates. Coefficients Petrol Diesel Kerosene LPG a 0.41 2.31 3.93 197.31 b 1.10 1.13 1.13 5.68 Exchange Rate considered at Rs. 47 per US Dollar. Indicative retail selling prices of PDS Kerosene and Domestic LPG are after netting off fiscal subsidy at current level of Rs.0.82/litre for PDS Kerosene and Rs.22.58 per cylinder for Domestic LPG. In order to assess the financial burden that may arise from rising under-recoveries of OMCs in the face of another price spiral in the international market, we have projected consumption based on two assumptions: (i) the annual average compound growth rates of petrol, diesel, kerosene and LPG during 2002-03 to 2008-09 apply to 2020-21 and 2030-31. (ii) The current level of prices set by the government will continue. The projected consumption of petroleum products by 2020-21 and 2030-31 is given in Table C2. Table C2: Consumption of Petroleum Products, 2001-02 to 203031 Actual Consumption 2001-02 2004-05 2008-09 CAGR Product 2002-09 MS 7.0 8.3 11.3 7.0 HSD SKO LPG Sensitive Products Free Industrial Products TOTAL Source: PPAC 36.5 10.4 7.7 61.7 38.7 100.4 39.7 9.4 10.2 67.5 44.1 111.6 51.7 9.3 12.2 84.4 49.0 133.4 5.1 -1.6 6.7 4.6 3.4 4.1 Projections 2020-21 2030-31 25.4 93.5 7.6 26.6 144.4 73.3 217.0 49.9 153.4 6.5 51.1 226.0 102.6 325.6 Based on these projected demand, the under-recoveries of oil marketing companies on these four products have been worked out (Figure C1) At crude oil price of $80/bbl, the total under-recoveries of OMCs on sale of petrol, diesel, LPG and PDS kerosene work out to Rs.1,57,000 crore by 202021. If oil prices rise by 25% to $100/bbl, the under-recoveries will rise higher by 77%. Likewise if oil prices rise to $120/bbl (50% increase) the under-recoveries will rise by 155%. Higher the growth rate of GDP and longer the period beyond 2020-21, the much higher will be the under-recoveries. At different levels of crude oil prices, product-wise under-recoveries of OMCs on sale of petrol, diesel, LPG and PDS Kerosene is presented in the Figure C2. These estimates reveal the dominant share of diesel in OMC’s under-recoveries. It will rise from 45% at crude oil price of $80/bbl to 58% at $150/bbl by 2020-21. Such a trend needs to be stemmed early. It suggests that at current levels of prices of petrol, diesel, PDS kerosene and domestic LPG, the financial burdens on the companies as well as on the government will be unsustainable. Therefore, there is a need to change the existing policy which can strike a balance between the capacity of the consumer to bear higher prices and fiscal stability of the government SUMMARY OF RECOMMENDATIONS • India’s imports of oil are increasing. Our import dependence has reached 80 per cent and is likely to keep growing. At the same time 2008 saw an unprecedented rise in oil price on the world market. Oil price volatility has also increased. Though future oil prices are difficult to predict, they are generally expected to rise. Given our increasing dependence on imports, domestic prices of petroleum products have to reflect the international prices. • The Government has not permitted public sector oil marketing companies to pass global prices to domestic consumers. We have examined the impact of the formula-based prescriptive pricing of major petroleum products devised by the Government from time to time, particularly since 2002. The present system of price control on petrol and diesel in particular has resulted in major imbalances in the consumption pattern of petroleum products in the country, and has put undue stress on finances of the PSU oil marketing companies as well as of the Government. It has also led to withdrawal of private sector oil marketing companies from the market. This has affected competition in the domestic petroleum product market. • Intervention through price control necessitates that someone bears the financial costs. The issue therefore is to assess the costs and incidence of the burden of alternative mechanisms on different groups in the society. On whom the burden falls depends on the policy and the instruments used. • A viable long-term strategy for pricing major petroleum products is required. A viable policy has to be workable over a wide range of international oil prices and has to meet the various objectives of the government. It should limit the fiscal burden on government and keep the domestic oil industry financially healthy and competitive. • The petrol is largely an item of final consumption. An analysis of the trend of petrol consumption by the automobile owners reveals that increase in prices of petrol can be borne by motorized vehicle owners. Accordingly, we recommend that petrol prices should be market determined both at the refinery gate and at the retail level. • We have examined the implications of increase in retail price of diesel on various groups of consumers and do not find any compelling reason to subsidize them. Therefore, we recommend the price of diesel should also be market determined both at the refinery gate and at the retail level. • Petrol and diesel used in cars, including SUVs, are for final consumption. The higher excise duty on petrol compared to diesel encourages use of diesel cars. While greater fuel efficiency of a diesel vehicle should not be penalized, a way needs to be found to collect the same level of tax that petrol car users pay from those who use a diesel vehicle for passenger transport. An additional excise duty, based on the model outlined in paragraph 4.14, should be levied on diesel car owners. • A transparent and effective distribution system for PDS kerosene and domestic LPG can be ensured through UID/Smartcards framework. Until it becomes operational, the following measures need to be taken. • There is disparity in per capita allocation of PDS kerosene amongst States, as also decline in the percentage of households using kerosene. Besides, households have flexibility in absorbing increases in price of PDS kerosene to certain extent. Therefore, PDS kerosene allocation across states should be rationalized, which will bring down all-India allocation by at least 20%. Further reduction in PDS kerosene allocation can be done on the basis of progress of rural electrification, LPG and piped gas availability which is expected to reflect much larger reductions in next NSSO surveys. • The price of PDS kerosene needs to be increased by at least Rs.6/litre so that the share of expenditure on kerosene in the total consumption expenditure of rural households remains at the same level as in 2002. Thereafter, price of PDS kerosene be raised every year in step with the growth in per capital agricultural GDP at nominal price. • Our analysis shows that prices of domestic LPG can be increased by at least Rs. 100 per cylinder. Thereafter, the price of domestic LPG should be periodically revised based on increase in paying capacity as reflected in the rising per capita income. The subsidy on domestic should be discontinued for all others except the BPL households once an effective targeting system is in place. • For calculation of the under-recoveries incurred by the OMCs on sale of PDS kerosene and domestic LPG, the extant methodology based on import parity pricing may be continued so long as the country remains a net importer of kerosene and LPG. • A mechanism for financing under-recoveries on PDS kerosene and domestic LPG has been provided in Table UR2 in paragraph 4.49. This mechanism involves periodic reduction in PDS kerosene allocation, increase in prices of PDS kerosene and domestic LPG from time to time, and mopping up a portion of the incremental revenue accruing to ONGC/OIL from production in those blocks, which were given by the Government on nomination basis, at the rates indicated in paragraph 4.48, and providing cash subsidy from the Budget to meet the remaining gap. The OMCs marketing PDS kerosene and domestic LPG should be compensated fully for their under-recoveries based on this mechanism. • We are not recommending a windfall profit tax since MOPNG ought to have flexibility in mopping up incremental incomes of ONGC and Oil India for the purpose of meeting a part of the under-recoveries of OMCs on sale of domestic LPG and PDS kerosene as outlined in paragraph. OIL CONTRACTS (a) Forward Contract: It is a tool which is used to hedge against system price. Considering the volatility of prices in the spot market, buyers and sellers often agrees on price, quality and quantity of goods in advance of actual delivery and the goods are delivered on a future date. These contracts will have mode and timing of payments as also penalties, if any, or failure to deliver goods or failure to make payment. These are called as forward contracts. However, instead of having one to one relationship, many buyers and sellers may develop a market for trading of goods in advance of the delivery. Price discovery in such a market is based on more informed choice as compared to one to one contracts. Besides, the market also facilitates development of standard contracts. So from buyer’s point of view, whatever the system price in there, or how the price is fluctuating he doesn’t have to bother. For him, the system price will be the price at which he has made contract. And from seller’s point of view, whatever the system price in there, or how the price is fluctuating he doesn’t have to bother. For him also, the system price will be the price at which he has made contract. (b) Futures Contract:Future contact in the power exchange would mean that the participant can hedge their risk in the fluctuation of Oil prices for longer terms. For example, a Oil Pproducing company expecting a decrease in the Oil prices can sell the futures now to be able to ensure higher prices at the time of delivery in future. Various kinds of contracts under this type of instrument can be of varying time horizon. (c) Options:Unlike futures, in options buyer does not have any obligation to exercise the contract. Options can also be used to hedge the risk of price fluctuations. The only difference being that an upfront payment of premium has to be made in case of an option whereas a trader does not need any upfront payment in case of futures. Fundamental option positions Calls and puts There are two basic types of options: buy (call) options and sell (put) options. A call option entitles, but does not obligate, the holder to purchase the underlying product i.e Oil at a price that has been agreed to in advance (the exercise price) -- no later than at the agreed-to date (the exercise date). A put option entitles the holder to sell the underlying product on corresponding terms. The decision to invest in a call or put option is made according to the investor's expectations about the price movement of the underlying instrument. OIL TRANSPORTATION • Movement of oil takes place in two steps: 1.crude oil(from well to gathering station& gathering station to refineries) 2. finished products(from refineries &port to consumption centre) • MODES OF PRODUCT TRANSPORTATION 1 Rail 2 Road 3 Pipelines 4 coastal Most of the major consumption centres in India are land-locked. This makes only Road, Rail and Pipeline as the feasible means of transportation of petroleum .Tankers are used for movement between coastal locations. Road: It Plays a crucial role in country’s transport sector for goods and passengers. For movement of petroleum products over long distances, road transportation is not very cost effective and efficient. Feasible only for short distances and secondary movement of petroleum products. Though movement by road results in excessive consumption of diesel and is a potential safety and environmental hazard, it still enjoys a large share in the modal mix due to unavoidable short distance movement from bulk depots to retails outlets. Railways: • Railway Traditionally, Railways have been the largest transporter of POL; developed since earlier days and cover substantial parts of the country. Besides petroleum products, railways also transport goods and passengers. Capacity of railways has already been over-stretched. With continuing growth on all spheres, railways transportation capacity would fall short of the transportation requirements. Due to cross-subsidisation, the freight for petroleum products is high. Rail transportation also leads to high energy consumption, environmental pollution and transit losses. • Coastal: Since the major consumption centers of the country are located in the hinterland, the movement of petroleum products through tankers is somewhat limited. Tankers are used for movement between coastal locations. This mode also suffers from capacity constraints in terms of draft availability, navigational facilities, jetties etc. Pipelines: • The term pipeline in broader sense means a facility used to transport commodities from point of receipt to the point of delivery. Many commodities are transported through pipelines. Crude oil, petroleum products and gas are perhaps the most common commodities transported by pipelines. • Development of Pipelines in India • Most of the earlier Refineries in India were installed at coastal locations, thus depending on coastal movement of crude oil. Further, the refining capacities being low, the products were either consumed locally or transported to the consumption centres by rail or road. After 1960, most of the Refineries were installed in land-locked locations necessitating laying of crude & product pipelines. During 1960-63, Oil India Limited laid the first trunk crude oil pipeline, 1156 km long from Naharkatiyaand Moran oil fields to the Refineries at Guwahati and Barauni. The first cross country product pipeline was laid by IOCL during 1962-64 to transport products from Guwahati Refinery to Siliguri. • • NATURAL GAS Introduction: India is one of the top 10 oil-consuming countries in the world. Oil and gas represent over 40 per cent of the total energy consumption in India. The consumption of petroleum products in the country is on the rise and demand already far exceeds domestic supply. Therefore, the country has to depend largely on imports. The country’s existing annual crude oil production is peaked at about 32 million tonnes as against the demand of about 110 million tonnes. With inadequate crude production, the country is heavily dependent on imports. Crude is the single largest item on India’s import list. Estimates show that the demand is likely to grow at a faster pace over the next decade if India is to maintain the GDP growth target of 8 per cent. This implies larger imports unless new domestic oil reserves are found. With this in view, the government announced the New Exploration Licensing Policy (NELP) in 2000. With a view to ensure long term energy security, the government is also building oil and gas equity abroad Circa 1974, with the huge oil & gas discovery in Bombay High field in 1974, followed by the giant South Bassein free gas find in 1978, the question then was “How to develop a market for this gas?” The answer then was GAIL and the HBJ pipeline. Ten years later, the scenario turned 180 degrees, when the gas demand exceeded the supply and the question changed to “How to find more gas?” The answer then was New Exploration and Licensing Policy (NELP). The Government of India (GOI) introduced the NELP about ten years ago to spur exploration and development in oil and natural gas. Since then, significant gas finds have been found off the Indian shores, thus achieving NELP’s goal and also helping to move India towards self sufficiency in natural gas. While this is a very positive development of the NELP regime, there are also some concerns regarding utilization, pricing and policy issues surrounding NELP and other gas finds under it. During 2007-08, crude oil production in the country is expected to be about 34.763 million metric tones (MMT) and 31.67 billion cubic metres (BCM) of natural gas production as against the production of 33.99 MMT of crude oil and 31.74 BCM of natural gas in 2006-07. During XI Plan period, crude oil production is likely to increase 24% as against actual crude oil production during X plan period. With exploration and development efforts made under New Exploration Licensing Policy (NELP), Natural Gas production in the country is likely to be doubled from the present level of gas production of about 90 million standard cubic meters per day (MMSCMD) by end of 11th Five AVAILABILITY & UTILISATION OF NATURAL GAS Natural gas has emerged as the most preferred fuel due to its inherent environmentally benign nature, greater efficiency and cost effectiveness. The demand of natural gas has sharply increased in the last two decades at the global level. In India too, the natural gas sector has gained importance, particularly over the last decade, and is being termed as the Fuel of the 21st Century. Production of natural gas, which was almost negligible at the time of independence, is at present at the level of around 87 million standard cubic meters per day (MMSCMD). The main producers of natural gas are Oil & Natural Gas Corporation Ltd. (ONGC), Oil India Limited (OIL) and JVs of Tapti, Panna-Mukta and Ravva. Under the Production Sharing Contracts, private parties from some of the fields are also producing gas. Government have also offered blocks under New Exploration Licensing Policy (NELP) to private and public sector companies with the right to market gas at market determined prices. Out of the total production of around 87 MMSCMD, after internal consumption, extraction of LPG and unavoidable flaring, around 74 MMSCMD is available for sale to various consumers. Most of the production of gas comes from the Western offshore area. The on-shore fields in Assam, Andhra Pradesh and Gujarat States are other major producers of gas. Smaller quantities of gas are also produced in Tripura, Tamil Nadu and Rajasthan States. OIL is operating in Assam and Rajasthan States, whereas ONGC is operating in the Western offshore fields and in other states. The gas produced by ONGC and a part of gas produced by the JV consortiums is marketed by the GAIL (India) Ltd. The gas produced by OIL is marketed by OIL itself except in Rajasthan where GAIL is marketing its gas. Gas produced by Cairn Energy from Lakshmi fields and Gujarat State Petroleum Corporation Ltd. (GSPCL) from Hazira fields is being sold directly by them at market determined prices. Natural gas has been utilised in Assam and Gujarat since the sixties. There was a major increase in the production & utilisation of natural gas in the late seventies with the development of the Bombay High fields and again in the late eighties when the South Bassein field in the Western Offshore was brought to production. STORAGE OF NATURAL GAS The gas produced in the western offshore fields is brought to Uran in Maharashtra and partly in Gujarat. The gas brought to Uran is utilised in and around Mumbai. The gas brought to Hazira is sour gas which has to be sweetened by removing the sulphur present in the gas. After sweetening, the gas is partly utilised at Hazira and the rest is fed into the Hazira-Bijaipur-Jagdhishpur(HBJ) pipeline which passes through Gujarat, MadhyaPradesh, Rajasthan, U.P., Delhi and Haryana. The gas produced in Gujarat, Assam, etc; is utilised within the respective states. Natural Gas is currently the source of half of the LPG produced in the country. LPG is now being extracted from gas at Duliajan in Assam, Bijaipur in M.P., Hazira and Vaghodia in Gujarat, Uran in Maharashtra, Pata in UP and Nagapattinam in Tamil Nadu. Two new plants have also been set up at Lakwa in Assam and at Ussar in Maharastra in 1998-99. One more plant is being set up at Gandhar in Gujarat. Natural gas containing C2/C3, which is a feedstock for the Petrochemical industry, is currently being used at Uran for Maharashtra Gas Cracker Complex at Nagothane. GAIL has also set up a 3 lakh TPA of Ethylene gas based petrochemical complex at Auraiya in 1998-99. Natural Gas Allocation & Supply Scenario As against the total allocation of around 118 MMSCMD, the gas supplies by GAIL is of the order of 63 MMSCMD spread over about 300 major consumers. Around 32% is supplied to the fertiliser sector, 41% to power, 4% to sponge iron and the balance 23% (including shrinkage) goes to other sectors. All India Region-Wise & Sector-Wise Gas Supply By GAIL - (2003-04) Region/Sector HVJ & Ex-Hazira Onshore Gujarat Uran K.G. Basin Cauvery Basin Assam Tripura Grand Total Power 12.61 1.66 3.57 4.96 1.07 0.41 1.37 25.65 Fertilizer 13.63 1.04 3.53 1.91 0.04 20.15 2.58 S. Iron 1.24 1.33 Others 9.81 2.08 1.41 0.38 0.25 0.29 0.01 14.23 Total 37.29 4.78 9.85 7.25 1.32 0.74 1.38 62.61 OIL is also supplying around 3 MMSCMD in Assam against allocations made by the Govt. Around 8.5 MMSCMD of gas is being directly supplied by the JVs/private companies at market prices to various consumers. This gas is outside the purview of the Government allocations. IMPORT OF NATURAL GAS TO INDIA THROUGH TRANSNATIONAL GAS PIPELINES. Iran-Pakistan-India (IPI) Pipeline Project In pursuance of Government decision in February 2005, Minister (P&NG) led a delegation to Pakistan during 4-8 June 2005. During the talks, the two Ministers reviewed the Iran-Pakistan-India gas pipeline proposal. They agreed that the project, which envisaged supply of gas to Pakistan and India through a transnational pipeline, would go a long way in meeting the energy security requirements of the two countries, and thus should be seen as a significant project for the benefit of the people of these countries. The Indian and Pakistani delegations agreed to exchange information in regard to the financial structuring, technical, commercial, legal and related issues to realize a safe and secure world class project. To this end, it was agreed that the momentum pertaining to the project should be accelerated by constituting a Joint Working Group at the Secretary level at the earliest, which will meet regularly and report the progress to the Ministers to facilitate definitive decisions by them. An Indian delegation also visited Iran from 11-14 June 2005 and discussed the issue of import of natural gas from Iran through on-land pipeline transiting via Pakistan. Both sides noted with satisfaction that as a result of regular discussions on technical issues pertaining to the project, a Heads of Agreement between NIGEC and the Indian companies concerned had been finalized. With a view to undertaking further studies and discussions in regard to relevant issues so that the project could take off by early next year, it was agreed to establish a special JWG on the Iran-Pakistan-India gas pipeline project. A Pakistani delegation led by the Secretary, Ministry of Petroleum and Natural Resources, Govt. of Pakistan visited New Delhi on July 12-13, 2005 for the first meeting of India-Pakistan JWG. The second meeting of the JWG was held in Islamabad on 8-9 September, 2005. The first meeting of the Special JWG on Iran-Pakistan-India Pipeline Project was held in New Delhi on 3-4 August, 2005. The second meeting of the Special JWG on Iran-Pakistan-India Pipeline Project was held in Tehran on 24th October,2005. The Indian side was led by Secretary (P&NG). Indian side has already appointed financial consultants i.e., M/s Ernst & Young and is in the process of finalizing appointment of legal & technical consultants for the project. During the 2nd JWG meeting, the Pakistani side informed that they will also shortly be appointing their Financial Consultants. At the latest due to various pricing and the security related unsolved issues with Pakistan, the deal had been shelved, and Iran has signed the modified deal with Pakistan as the sole partner in may 2009. Myanmar-Bangladesh-India Gas Pipeline Project. To pursue the matter at the Government level, for bilateral and trilateral discussions with Myanmar and Bangladesh, the Minister (P&NG) visited Yangon during 11-13th January 2005. A Memorandum of Understanding (MOU) for cooperation in the petroleum sector between the two Governments was signed. The MOU provides for furthering cooperation in the hydrocarbon sector and for establishing a cooperative institutional relationship in the field of petroleum industry on the basis of equality and mutual advantage, taking into account the possibilities for cooperation available in each country. The two Governments will designate a body of experts comprising three representatives of each party to identify and implement the projects in the hydrocarbon sector. A trilateral meeting between the Petroleum Ministers of India, Myanmar and Bangladesh held on 12.1.2005. After the meeting a Joint Press Statement was issued by the three Ministers. The three sides agreed to transport of natural gas from Myanmar to India by pipeline transiting through Bangladesh. The route of the pipeline will be determined by mutual agreements of the three Governments. It was also decided to establish a Techno-Commercial Working Committee (TCWC) comprising duly designated representatives of the three Governments to prepare a draft MOU prescribing the framework of cooperation among the three Governments, including the Myanmar-Bangladesh-India gas pipeline project. The MOU would be signed at Dhaka at the earliest mutually convenient date. In pursuance of the MoU, a Techno-Commercial Working Committee has been constituted by the three Governments. The First Meeting of the TCWC was held on 24-25 February, 2005. The TCWC has finalized draft MoU proposed to be signed by the three oil Ministers. However, there are certain bilateral issues which have to be sorted out with Bangladesh. Simultaneously, India is also exploring the other option of import of natural gas from Myanmar. A high level delegation led by Minister, Energy, of Myanmar recently visited India during July 5-7, 2005. All aspects of Myanmar-Bangladesh-India gas pipeline were discussed. Minister (P&NG) visited Bangladesh during 5-6 September 2005 to pursue the matter with Government of Bangladesh. The matter is being pursued vigorously and the proposed gas imports from Myanmar would be finalized shortly notwithstanding the response of Government of Bangladesh. GAIL has been asked to do a pre-feasibility study of the onland pipeline route from Myanmar to India through North-Eastern Indian States, bypassing Bangladesh territory. The option of getting Bangladesh on board is also being simultaneously pursued. Another official level meeting was held in Yangon on 29-30 August 2005, where two sides agree to take definite steps for gas supply from Myanmar. Turkmenistan-Afghanistan-Pakistan (TAP) pipeline Daulatabad area of Turkmenistan has reported to have sufficient gas reserves. The Governments of Turkmenistan-Afghanistan-Pakistan (TAP) proposed the transnational gas pipeline to exploit the available gas reserves in Turkmenistan. They designated ADB as the lead development partner. ADB has carried out the study and approached India for participating in the project. Minister (P&NG) discussed this matter with Pakistani side during his visit to Pakistan 4th to 8th June 2005. This was also discussed by Secretary (P&NG) with President ADB during the latter's visit to New Delhi on 1.9.2005. Although, India is not yet formally involved in TAP project, Minister (P&NG) has been invited to the next Steering Committee Meeting to be held in Ashgabat in early December, 2005. LIQUEFIED NATURAL GAS (LNG) Natural gas at -1610C transforms into liquid. This is done for easy storage and transportation since it reduces the volume occupied by gas by a factor of 600. LNG is transported in specially built ships with cryogenic tanks. It is received at the LNG receiving terminals and is regassified to be supplied as natural gas to the consumers. LNG projects are highly capital intensive in nature. The whole process consists of five elements: Dedicated gas field development and production.  Liquefaction plant.  Transportation in special vessels.  Regassification Plant.  Transportation & distribution to the Gas consumer. LNG supply contracts are generally of long term nature and the prices are linked to the international crude oil prices. However, the LNG importing countries in recent times had started asking for medium/short term contracts with varying linkages. LNG Imports to India The LNG trade started in mid 60's and has increased rapidly. In 1992 it was around 80 Billion Cubic Metres (BCM) per annum and crossed the 100 BCM mark in 1996. World trade in LNG is currently in the range of 150 BCM. The major exporting countries of LNG are Algeria, Qatar, Indonesia, Malaysia, Australia, whereas, the major importers are Japan, South Korea, Taiwan and Western Europe. Geographically, India is very strategically located and is flanked by large gas reserves on both the east and west. India is relatively close to four of the world's top five countries in terms of proven gas reserves, viz. Iran, Qatar, Saudi Arabia and Abu Dhabi. The large natural gas market of India is a major attraction to the LNG exporting countries. In order to encourage gas imports, the Government of India has kept import of LNG under Open General License (OGL) category and has permitted 100% FDI. LNG Projects Petronet LNG Limited (PLL), a JV promoted by GAIL, IOCL, BPCL and ONGC was formed for import of LNG to meet the growing demand of natural gas. PLL has constructed a 5 MMTPA capacity LNG terminal at Dahej in Gujarat. The terminal was commissioned in February 2004 and commercial supplies commenced from March 2004. PLL is planning to expand this terminal to 10 MMTPA capacity by 200809 to meet the growing demand of LNG. Shell's 2.5 MMTPA capacity LNG terminal at Hazira has been commissioned. Dabhol LNG terminal (total 5 MMTPA capacity, with about 2.9 MMTPA available for merchant sales) may also become operational by 2006 subject to availability of LNG for the project. LNG terminals at Kochi in Kerala, Mangalore in Karnataka and Krishnapatnam/Ennore in Tamil Nadu are also under active consideration and may fructify in next 4-5 years time. The price of LNG for the Dahej project is linked to the JCC crude oil price. It has a fixed price for the first five years, i.e. upto December 2008 and a floating floor and ceiling price thereafter. At present the selling price of LNG in Gujarat is $4.87/MMBTU (Rs. 8777/MCM) and outside Gujarat is $4.88/MMBTU (Rs. 8800/MCM). At this price, LNG is comparatively cheaper than alternative fuels/feedstock's e.g. naphtha, Furnace Oil, LSHS, Light Diesel Oil, LPG, etc. REGULATORY FRAMEWORK FOR THE GAS INDUSTRY The Ministry of Petroleum & Natural Gas (MOP&NG) has been regulating the allocation and pricing of gas produced by ONGC and OIL by issuing administrative orders from time to time. The gas produced by the JVs and by NELP operators is governed by the respective production sharing contracts (PSC) between the Government and the producers. The setting up of a Petroleum & Natural Gas Regulatory Board is under the consideration of the Government and the bill is being drafted. Under the existing policy, 100% Foreign Direct Investment (FDI) is allowed through the FIPB route for both LNG projects and natural gas pipeline projects. Import of LNG and natural gas is on OGL. If an entity requires the acquisition of Right of User (ROU) in land, it approaches MOP&NG for the acquisition under the Petroleum & Mineral Pipelines (Acquisition of Right of User in Land) Act, 1962 (P&MP Act, 1962). The draft natural gas pipeline policy covering transmission pipelines and local or city gas distribution networks is under formulation, with proposed provision in line with those under the draft regulatory board bill. Present Scenario The distribution of natural gas reserves in the country is not uniform. Around 75% of the gas is produced in the Western Offshore fields, with the balance coming mostly from Gujrat and the North-Eastern States. The production of crude oil and natural gas is currently the responsibility of two public sector undertakings (PSUs), ONGC and OIL. The Gas authority of India Ltd. (GAIL), a PSU, and OIL are engaged in transportation, distribution and marketing of natural gas. The Government of India is keen to attract private investment in the production, transportation, etc. of natural gas. Contracts have been awarded for the development of some medium/smalll sized fields and it is expected that in 1997-98 about 6 MMSCMD of gas would be produced from the private/joint venture fields. Two private sector companies and the Municipal Corporation of Baroda are at present engaged in the distribution of the natural gas in the domestic/commercial sector in Gujrat and Mumbai. Two State Government undertakings are doing the same work in the North-Eastern states in a number of small towns. City gas for Delhi and a project for supply of gas to reduce pollution in and around Taj Trapezium area are being implemented. The GAS Linkage Pricing, Contracts & Inventory Control Tariff setting in Gas Transmission- A view of Methodologies Gas consumption in any substantial manner in India began with the formation of GAIL and setting up of the Hazira-Bijaipur-Jagdishpur (HBJ) pipeline. This ling line actually boosted natural gas consumption in the country. Major consumers of gas in the country happen to be the power and fertilizer sector consuming about 40 and 34%, respectively. Domestic and household usage of gas is yet to develop. The discovery of gas in the Krishna –Godavari (KG) basin and other places and setting up of LNG terminals on the west coast of the country has suddenly changed the gas scenario in the country. And the future is likely to see a much larger share of gas in the overall energy consumption pattern. The tenth plan projects a demand of about 180 mmscd from the present level of 145 mmscd and a shortfall of about 100 mmscd and domestic supply of about 80 mmscd. This can change with the exploitation of the KG gas recourses. Natural gas, unlike other commodities, cannot be transported by road or rail. There has to be a network of pipelines for gas transmission and a local distribution zone where it can be retailed or solid in bulk. A good gas transportation network is a prerequisite for development of free market in gas. As capital costs are high, construction risk very high, and because there are network externalities. The business of gas transportation tends to be natural monopoly. Unbundling in this sector means the separation of the “pipes business”(natural monopoly), from supply which can be competitive. The pipes business, therefore, needs to be regulated and “open access common carrier” principle will have to be enforced on the lines of what obtains in the electricity sector. In such a scenario, tariffs become an important feature for selling of natural gas as a competitive fuel. Tariff will also determine the geographic spread of usage of gas. Regulation today Postage stamp tariff GAIL is the major transporter today and it has, since inception, followed postal stamp tariff. This means that tariff at any place in the country remains the same irrespective of distance. This tariff recovers capital costs, variable costs like gas consumption for pressure boosting and manpower costs, and a post tax return of 12% on network. Perhaps this kind of regime was justified because of shoratge of gas with no alternative than the allocation of gas by the central goverment. It was perhaps also the vestigial idea of equalization of cost of transport similar to freight equalization for coal and steel. With few users there could not have been a gas market. The need to corret the regional imbalances and, therefor, siting of industries in backward regions became necessary. This has led to fertilizer factories being set up in uttar pradesh while gas was available on the west coast. However, in a scenario where gas was being “allocated” , cost recovery was not really difficult. Presently this tariff is in the range of Rs 1150 per thousand SCM. APM for petroleum products has already been dismanted and it will not be long before this momentum catches up with gas also. Already, for the new discoveries the price of the commodity, that is , gas, is being marked to market. Industrial policy has long been liberalized and siting of central PSU units is more on the basis of locational economics. In such a regime, a postage stamp tariff defies economic logic.once gas sales are driven more by market consideration, fixing transmission tariffs on postage stamp principle would not be possible. In a deregulated scenario, the tariff system must: a) Allow for cost recovery so that the system is bankable b) Be transparent, stable and practicable c) Enable transition to the market-based system on gas transactions d) Send economically appropriate signals to foster greater utilization of capacity and permit gas to be a competitive fuel. This would imply the unbundling of the tariff with respect to the pressure and area that is,the pricing regime would be different fora local distribution zone and different for a trunk transmission line. Similarly, pricing would be differnt for high and low pressure lines. There are two important components in the gas transmission tariff: They are : Capacity charge to recover fixed cost and variable charge to cover the through put costs. A third element of costs which includes inter alia connection charge and system gas charges, would be subsumed in the above two categories. In practice, one has seen in that capacity charge/variable cost split can be as high as 90/10. But, at this split level, it would be difficult to sell transmission capacity except for very large buyers with firm demands for long perionds. Therefore, an appropriate tariff methodology needs to be developed. Transmission lines have fairly long lives. Once the loan is fully paid out the tariff structure would change. Average accounting cost Here, the total cost of setting and operating the system is allocated over the entire capacity and average unit cost is developed from that.it is transparent and strainght forward system and charges customers for excess capacity. And also distant customers paying high tariff. Long run marginal cost(LRMC) This approach takes into account incremental capital and operating cost required to meet sustained increase in throughtput. It provides an economically sound basis for tariff setting and users do not have to pay for surplus capacity.it also requires an incremental capacity to be defined over which LRMC would be applied. Therefore, a pure LRC has better applicability in a mature market, where demand patterns have stabilized and stabilized and investment pattern in pipelines over a period of time is more or less known a priori. When applied to gas pipelines the following methods are important in leading to the appropriate regulation: Virtual pipeline method: While the transmission company may like to set up a large system to cater for full demand, the user may not like to pay the capital charge for the full capacity. Therefore, one basis for tariff setting is to assume only the capacitytaht the user is likely to use. In this method we assumed as if a line is actually being set up for taht user and for the capacity that he wants to use within the main line. Thus the entire line gets divided into a large number of virtual pipelines. This permits the user to pay for a limited capacity even if the pipeline size is large.this is a tendency for the transporter to incentivize additional usage of capacity and thus permit an aggressive pricing regime.in a virtual pipeline methodology, since the user virtually owns part of the line, the capacity charges tend to be on the higher side, about 85% of the total charges. Such pipelines normally set up with higher equity and around 50-70 % of the total project cost. Cluster approach: Also known as entry/exit pricing. For such demand centre uniform pricing is done relative to an entry point. If there are more tahn one entry poiunts, than those many different slabs of rates would exist with respect to entry and exist points. An attempt is made to capture all the costs pertaining to one demand centre within the tariff itself. Thus, costs for each demand centre is effectively segregated. This policy also helps in reducing tariffs for distant demand centres. No single tariff methodology can capture all the requiremnets of both the users and the transmission company. Factors as demand,demand pattern, cost of laying impact on the choice of tariff methodology. Gas transmission lines are seen as natural monopolies. It is diffecult for the user to shift from one line to the other.the west coast has seen multiple operators, signalling a certain amount of contestability at the entry point of the value chain. Here the risk is high and revenue is shaky, so the relationship between user and the transmission entity is normally maintained through a contractual framework known as Gas Transmission Agreement(GTA). Some saliant features of a normal GTA are: 1. It specifies the capacity that is offered to the user. It also specifies the uptime for the system. These are backeds by penalties if these requirements are not met.normally, the shortfall or the excess use of the capacity is measured on a daily basis and penalities are determined at the end of the month. 2. There is a mix of slightly different gases,therefore, what the user puts in and gets out of the system is the energy per and this remains a unit of transcation.however, the properties of gas on entry are regulated on such parameters as such parameters as waxing properties, dew point, pressure, etc. 3. Depending upon the type of tariff methodology used, there are invariably incentives for using larger volumes of capacity. However, where capacity is a constraint the pricing methodology may be reversed. 4. Capacity charges ensure that even non-usage of the capacity does not impact the revenues of the transmitting entity. However, in case the user reneges on his promise to use the capacity, then most of the contacts make a provision for a lump-sum compensation to ythe transmitting entity. CURRENT NEWS:India launches ninth edition of NELP Hoping to attract more foreign companies to explore its vastly unexploited sedimentary basin, India launched its ninth round of oil and gas block auction, made up mostly of previously discarded areas. Petroleum Minister Murli Deora launched the ninth edition of New Exploration Licensing Policy, offering 34 exploration blocks, almost half of the previous round in 2009. Out of 34 blocks, 19 blocks are totally new areas -- 7 in deep sea, 2 in shallow waters and 10 onland blocks. Rest 15 (1 in deep water, 5 in shallow water and 9 onland blocks) are recycled blocks . Of the recycled blocks, five are discards of state-owned Oil and Natural Gas Corporation, the largest bidder in the previous eight rounds of NELP. ONGC relinquished the areas it had won in first and second round of NELP, after it made no discovery. An investment commitment of more than $1.1 billion in NELP-VIII is expected for the current blocks being offered. Last date of bidding for blocks offered under NELP-IX is March 18, 2011, exactly five months from the date of first roadshow to be held in Mumbai. This time in the new policy, impact of absence of seven year holiday or exemption from payment of income tax from profits earned from the oil and gas produced from the areas awarded in NELP-IX.The proposed Draft Tax Code, to be implemented from April 2012, has done away with profit-linked incentives for all sectors. Instead an investment linked incentive will be available. In the eight rounds of NELP since 1999, 235 blocks have been awarded till date.This has resulted in enhancement of exploration coverage from 11 per cent to about 58 per cent of Indian sedimentary basin between 2000 and 2010. The discoveries made under the NELP have resulted in in-place hydrocarbon reserve accretion of a staggering 642 million tonnes of oil and oil equivalent gas. A total of 87 oil and gas discoveries have been made in 26 blocks under NELP during this period. The discoveries have added over 640 million tonnes of oil equivalent reserves. In the first eight rounds of NELP, $11.1 billion investment was committed but actual investment so far has been $14.3 billion. The blocks offered in NELP-IX include 8 deep-sea, 7 shallow water and 19 onland. The onland blocks include 8 small blocks for which there is technical qualifying criteria for companies to bid.These 34 blocks cover a sedimentary area of about 88,807 square kilometer, which is 2.9 per cent of Indian sedimentary basin area. The onland blocks fall in Assam (2), Gujarat (11), Rajasthan (2), Madhya Pradesh (2), Tripura (1) and Uttar Pradesh (1). The seven shallow water and eight deep water blocks on off the east and west coast but no area in the prolific Krishna Godavari basin is on offer. Out of 87 oil and gas discoveries made in NELP rounds, natural gas production in Reliance Industries eastern offshore KG-D6 block commenced from April 2009. The 8th round, which closed on October 12, 2009 attracted investment commitment of $1.34 billion for 36 blocks that received offers. Under NELP-VIII, 70 areas or blocks for exploration were offered, the biggest licensing round in India. Of the 36 areas bid for, the government had awarded 33 blocks to successful bidders. The road shows/investors Meets at Moscow Houston, Calgary, Perth and Singapore are planned to promote NELP-IX. The government has hired UK-based Furgo Data Solutions Ltd to market the blocks. Conclusion Gas market in india is still in its infancy. The “allocation” based system is changing to markets for gas. There are various components of costs in usage of gas when unbundled, which users will have to consider before ruling out alternative fuels. Market of gas only improved by the transmission system is in place. So transmission entity, which does not club sale of commodity along with transmission and follows coman carrier principles with a tariff regime that is appropriate to the development of markets. Virtual pipelines and cluster methods are possible otins. One is also witnessing a slow shift from a single source of gas to multiple entry points. This would also facilitate short-term and spot contracts in gas apart from standard long-term contracts. This would mean short term pricing of transmission capacity as well. This will provide additional cash flow streams to the gas transportation entities and we might soon see a tariff regime for short term users and one for long-term users. Water resources The Central Electricity Authority (CEA) is worried that securing water linkages for thermal power plants is becoming tougher and could hurt plans to boost India’s power generation capacity. “Already we are having problems in setting up some projects. There has to be a comprehensive plan for setting up water resource facilities in states having potential for thermal development,” said Rakesh Nath, chairman of CEA, the country’s apex power sector planning body. Of India’s 167,278MW installed capacity, 108,602 MW is thermal-power based. Of this 108,602 MW, around 89,778MW is coal-fired, while the remaining is fuelled by gas & diesel. The country plans to add 78,577MW by 2012. Of this, 4,290MW will be gas-based and around 46,600MW is expected to come from coal-based projects. “Reservoir creation leads to issues relating to environment, rehabilitation and relocation. We have already taken up the issue with our ministry (power ministry) to take up the issue with the ministry of water resources,” Nath said. While it takes 40 cu. ft per second (cusec) of water for a 1,000MW coal-based thermal power project, the requirement is 20cusec for a gas-based thermal power unit. Cusec is a measure of the flow rate. “For all new projects, there is no water linkage available. They have no option but to go for coastal projects by using sea water for the purpose. Only in monsoons there is water in the rivers. We have to create dams for different seasons,” said another CEA official, who didn’t want to be identified. According to the Central Water Commission, while the average annual rainfall in India is 4,000 billion cu. metres (bcm), the estimated utilizable surface water resources are 690bcm. An official in the ministry of water resources confirmed the problem that thermal power plants are facing, but said: “States are diverting water meant for agricultural use for power generation.” PROCEDURE TO GET WATER LINKAGES: • Signing up of MoU between the state government & the private entity. While signing the memorandum of understanding government of the concerned state agrees to supply the water for the upcoming power plant. • Allocation of water by the WRD (water resource department) of the concerned district. The committee here decides the amount of water to be allocated for the power plant from the total amount of water allocated for that district for the industrial purpose. The water cess is paid in advance for the one quarter of a year. • To identify a suitable location on the river near the plant site for constructing a water harvesting structure. • To analyze the available monthly and yearly surface flow at the specified location. • To estimate the extent of annual water availability at the site at 75% and 90% dependable surface flow. • To estimate the extent of water volume needing storage, if any, to meet the requirements during lean flow periods in the river at 75% & 90% dependable surface flow. • To conduct Topographical survey of the area to estimate area of submergence for the above storage and height of structure. • To conduct geological and geotechnical survey of proposed site for fixing suitability of structure. • To conduct soil test for designing of structure. • To indicate location of Intake and Pump house for withdrawal of water for the Plant area. • To indicate the route of raw water main from the Intake to Plant site. SELECTION OF WATER HARVESTING SITE: • • • • • • The catchment area should be sufficient to fulfill the plant requirement of water. It should be at the optimum distance from the proposed plant site. The site should be approachable through existing road. The bed of the river is likely to provide a suitable foundation for providing water harvesting structure. No such settlement (Housed) would come under submergence. Other sites than this proposed site have few disadvantages like  Increase in Pumping cost due to more level difference.  Increase in length of pipe line and its cost. ESTIMATION OF ANNUAL WATER DEMAND: The coal based thermal power plant of capacity 100 MW requires 3.6 MCM of water annually for its successful operation. For e.g.: A coal based power plant of capacity 1000 MW will require = 3.6 X 10 MCM. So it comes out to be= 36 MCM. Water requirement for township & other miscellaneous uses= 6 MCM So total amount of water required for 1000 MW capacity coal based power plant is = 42 MCM The monthly requirement of water=42/12 =3.5 MCM STORAGE REQUIREMENT: The storage requirements at 90% dependability site have been estimated keeping following points in view. The Gross storage is calculated keeping all points in view. • • • Dead storage is taken as 2 MCM for the plant capacity of 2000 MW. Evaporation / seepage loss taken as 10% of Storage need. Route loss @ 3% is also considered. DETERMINATION OF THE PARAMETERS OF THE STRUCTURE: In order to determine the height of the structure first of all we have to calculate the storage capacity of the reservoir. After this we have to determine the following aspects of the reservoir • • • • Submergence area. Height of the structure. FRL (Full Reservoir Level). Barrage with radial width. • • • • MDDL (Minimum Draw Down Level). HFL (High Flood Level). MWL (Maximum Water Level). DSL (Dead Storage Level). Water allocation & charges In the planning and operation of system water allocation priorities shall be as under: • Drinking water supply • Irrigation and afforestation. • Power generation/industrial and other uses. • Tourism Water resources department shall be made a nodal department for permitting different uses of water resources. Clear provision for reservation of drinking water shall be made in proposed irrigation projects of the state, on river, reservoirs, tanks etc. WATER is priced far too cheaply in India to prompt industrialists into conserving or recycling it, says a detailed study prepared by the National Institute of Public Finance and Policy (NIPFP) for the Ganga Project Directorate. But the government has let the NIPFP recommendations lie in its cupboards. The study assessed the water pollution caused by a dozen types of industrial units situated in the Ganga basin in Uttar Pradesh and West Bengal. The study, which was undertaken by a group of researchers led by M N Murty and D B Gupta, found that the production cost of water in this region, because of its good ground and surface water resources, was very low -- about 20 paise a kilolitre. Not surprisingly, none of the units surveyed in the Ganga basin practised water conservation measures. On the other hand, in the dry regions of the country where water is priced higher, there were several good examples of water conservation. For instance, Madras-based Tamil Nadu Petro Products Ltd spends about Rs 47 a kilolitre to conserve water for cooling purposes Water pricing in India depends more on socio-economic and political factors rather than on the cost of production and distribution or the willingness of people to pay. Consumers are usually classified as domestic, commercial and industrial, and charged accordingly. Pricing of water for industrial use is based on ad hoc criteria, says the NIPFP study. "In most of the municipalities and boards, water tariffs have not been revised for years. The few cases where it has been revised, has been without any guidelines. In fact, due to inadequate information on production and distribution costs in the case of most local bodies, it is not possible to analyse the tariff structure." Murty and his fellow-researchers say there should be no free-riding on public goods such as water, air and land. Water prices cannot be determined by market forces alone as water is more or less freely accessible to everyone. And when the user -- industrial or domestic -- disposes effluents into a river or lake, it affects all of society and this social cost is difficult to estimate. Tax-based approach Given that environment is a public good and the polluter a free-rider, the polluter should be asked to pay for pollution control. The government should levy taxes that take into account pollution control costs. Setting standards, the researchers argue, is a political process that should involve both the victims and perpetrators of pollution. Any pollution standard fixed without ascertaining the views of pollution victims cannot be regarded as a national standard. The minimum national standards developed by the Central Pollution Control Board (CPCB) try to keep the cost of pollution control to within one per cent of the annual turnover of a firm, which means the interests of polluters have been taken care of, but not that of the victims. The researchers point out effluent standards can be fixed in two stages. In the first, national standards can be set based on technological and economic considerations alone and applied to all industries, without considering local conditions. In the second stage, however, more stringent standards should be imposed depending upon local water quality requirements. The CPCB standards correspond only to the first stage. Only standards developed in the second stage will relate directly to the damages borne by the victims, say the researchers. Two components Generally, industries either get their water supply from the local municipal administration or make their own arrangements, or use a combination of both. The researchers suggest the price of water should include two components: its production cost and a pollution tax. If the factory uses its own tubewell, the municipality charge should consist of its pollution abatement cost, fixed on the basis of each kilolitre of water used. At the moment, factories drawing water from their own tubewells do not pay any charge. The study also shows that the cost of treatment of polluted water varies across industries, depending on the quantity and nature of pollutants released. Therefore, to recover the full cost of providing effluent treatment services, pollution control boards will have to levy different pollution taxes on different industries. However, for practical purposes, it may be useful to separate water costs from pollution taxes. While costs can be dealt with by water supply authorities, taxes ought to be based on the pollution loads of different industries and pollution standards. The researchers also point out that the objective of the pollution tax could vary depending on the region in which it is being levied. For instance, in the water-rich Gangetic basin, the pollution tax should aim only at ensuring factory effluents are of the desired quality. But in drier areas, pollution taxes should provide industries with an incentive to recycle effluents and conserve water. Since there are economies of scale in the treatment of polluted water, it is better to treat higher volumes of effluents. Studies have shown the social cost of controlling water pollution per tonne of paper produced is Rs 145 for a mill with a daily capacity of 10 tonnes, and only Rs 30 for a mill with a daily capacity of 115 tonnes. So, it is not economical for small units to have their own effluent treatment plants. Instead, the combined effluents of a number of small units should be treated by the water pollution control board or a local administration unit. The cost of such plants can be realised through a pollution tax on these units. Boiler Efficiency The performance parameters of boiler, like efficiency and evaporation ratio reduces with time due to poor combustion, heat transfer surface fouling and poor operation and maintenance. Even for a new boiler, reasons such as deteriorating fuel quality, water quality etc. can result in poor boiler performance. Boiler efficiency tests help us to find out the deviation of boiler efficiency from the best efficiency and target problem area for corrective action. Boiler efficiency, in the simplest terms, represents the difference between the energy input and energy output. Boiler Efficiency related to the boilers energy output to the boilers energy input The Boiler Efficiency is defined as “The ratio of heat actually utilized in generation of steam to the heat supplied by the fuel in the same time” i.e. Boiler efficiency= Heat gained by the steam from the boiler per unit time/Calorific value of the fuel in kJ/Kg i.e. = [ma (h-hf )]/C Where, ma = Mass of water actually evaporated into steam per Kg of fuel at the working pressure h = Enthalpy of steam per Kg under the generating conditions hf = Specific enthalpy of water at a given feed temperature C = Calorific value of the fuel in kJ/Kg The boiler efficiency depends on following factors: 1) Fixed factors 2) Variable factor The Fixed factors are: 1) Boiler design: It includes the arrangement & effectiveness of the heating surfaces, the shape & volume of the furnace, the arrangement of flues, the arrangement of steam & water circulation. 2) Heat recovery equipment: It includes the economizer, superheater, air preheater & feed water heater. 3) Built in losses: It includes the heat transfer properties of the settings & construction materials, flue gas & ash heat losses. 4) Rated rate of firing, the furnace volume & heating surface. 5) Properties & characteristics of fuel burnt. The variable factors are 1) 2) 3) 4) 5) 6) 7) Actual firing rate Fuel condition as it is fired The condition of heat absorbing surfaces Excess air fluctuations Incomplete combustion & combustibles in the refuse Charge in draught from the rated due to atmospheric conditions Humidity & temperature of the combustion air The performance parameters of boiler, like efficiency and evaporation ratio reduces with time due to poor combustion, heat transfer surface fouling and poor operation and maintenance. Even for a new boiler, reasons such as deteriorating fuel quality, water quality etc. can result in poor boiler performance. Boiler efficiency tests help us to find out the deviation of boiler efficiency from the best efficiency and target problem area for corrective action. Boiler efficiency, in the simplest terms, represents the difference between the energy input and energy output. Boiler Efficiency related to the boilers energy output to the boilers energy input . Boiler Efficiency may be indicated by • Combustion Efficiency - indicates the burners ability to burn fuel measured by unburned fuel and excess air in the exhaust • Thermal Efficiency - indicates the heat exchangers effectiveness to transfer heat from the combustion process to the water or steam in the boiler, exclusive radiation and convection losses • Fuel to Fluid Efficiency - indicates the overall efficiency of the boiler inclusive thermal efficiency of the heat exchanger, radiation and convection losses - output divided by input. This image shows a typical boiler energy balance for a boiler in good running condition with no energy efficiency measures added. By first identifying the areas of energy loss and roughly quantifying it, it is easier to estimate the overall savings potential by taking efficiency action in that area. High boiler efficiency is the result of specific design criteria which directly effects the fixed factor for boiler efficiency, including: • Number of boiler passes ( Normally we have two pass boiler) • Burner / boiler compatibility • Repeatable air/fuel control • Heating surface • Pressure vessel design Boiler efficiency calculations that are accurate and representative of actual boiler fuel usage require the use of proven and verified data, including: • Proven stack temperature • • • • Accurate fuel specification Actual operating excess air levels Proper ambient air temperature Proper radiation & convection losses Boiler Efficiency Thermal efficiency of boiler is defined as the percentage of heat input that is effectively utilized to generate steam. There are two methods of assessing boiler efficiency. 1) The Direct Method: Where the energy gain of the working fluid (water and steam) is compared with the energy content of the boiler fuel. 2) The Indirect Method: Where the efficiency is the difference between the losses and the Energy input. 1. The Direct Method of testing: This is also known as ‘input-output method’ due to the fact that it needs only the useful output (steam) and the heat input (i.e. fuel) for evaluating the efficiency. This efficiency can be evaluated using the formula Boiler efficiency= Merits and Demerits of Direct Method Merits • Plant people can evaluate quickly the efficiency of boilers • Requires few parameters for computation • Needs few instruments for monitoring Demerits • • Does not give clues to the operator as to why efficiency of system is lower Does not calculate various losses accountable for various efficiency levels Type of boiler: Coal fired Boiler Heat output data Quantity of steam generated (output) Steam pressure / temperature Enthalpy of steam (dry & Saturated) at 10 kg/cm2(g) pressure Feed water temperature Enthalpy of feed water Heat input data Quantity of coal consumed (Input) GCV of coal : 8 TPH : 10 kg/cm2 (g)/ 180 0C : 665 kCal/kg : 85 C : 85 kCal/kg : 1.6 TPH : 4000 kCal/kg 0 Boiler efficiency = = 72.5% 1 The Indirect Method of testing: Indirect method is also called as heat loss method. The efficiency can be arrived at, by subtracting the heat loss fractions from 100. The standards do not include blow down loss in the efficiency determination process. Here the efficiency is the difference between the losses and the energy input. The efficiency can be arrived at, by subtracting the heat loss fractions from 100. An important advantage: In this method the errors in measurement do not make significant change in efficiency. Thus if boiler efficiency is 90%, an error of 1% in direct method will result in significant change in efficiency. i.e.90 + 0.9 = 89.1 to 90.9. In indirect method, 1% error in measurement of losses will result in Efficiency = 100 – (10 + 0.1) = 90 + 0.1 = 89.9 to 90.1 The Various heat losses occurring in the boiler are: Measurements Required for Performance Assessment Testing The following parameters need to be measured, as applicable for the computation of boiler efficiency and performance. a) Flue gas analysis 1. Percentage of CO2 or O2 in flue gas 2. Percentage of CO in flue gas ( also given by oxygen indicator) 3. Temperature of flue gas b) Flow meter measurements for 1. Fuel 2. Steam 3. Feed water 4. Condensate water 5. Combustion air c) Temperature measurements for 1. Flue gas 2. Steam 3. Makeup water 4. Condensate return 5. Combustion air 6. Fuel 7. Boiler feed water d) Pressure measurements for 1. Steam 2. Fuel 3. Combustion air, both primary and secondary 4. Draft e) Water Condition 1. Total dissolved solids (TDS) 2. pH 3. Blow down rate and quantity 1 The following losses are applicable to liquid, gas and solid fired boiler 1. L1- Loss due to dry flue gas (sensible heat) This is the greatest boiler loss and can be calculated with the following formula: 2. L2- Loss due to hydrogen in fuel (H2) The combustion of hydrogen causes a heat loss because the product of combustion is water. This water is converted to steam and this carries away heat in the form of its latent heat. Where, H2 - kg of H2 in 1 kg of fuel Cp - Specific heat of superheated steam (0.45 kCal/kg °C) 3. L3- Loss due to moisture in fuel (H2 O) Moisture entering the boiler with the fuel leaves as a superheated vapour. This moisture loss is made up of the sensible heat to bring the moisture to boiling point, the latent heat of evaporation of the moisture, and the superheat required to bring this steam to the temperature of the exhaust gas. This loss can be calculated with the following formula Where, M – kg of moisture in 1kg of fuel Cp – Specific heat of superheated steam (0.45 kCal/kg)°C 584 is the latent heat corresponding to the partial pressure of water vapour. 4. L4- Loss due to moisture in air (H2 O) Vapour in the form of humidity in the incoming air, is superheated as it passes through the boiler. Since this heat passes up the stack, it must be included as a boiler loss. AAS- Actual mass of air supplied/kg of fuel. 5. L5- Heat loss due to incomplete combustion Products formed by incomplete combustion could be mixed with oxygen and burned again with a further release of energy. Such products include CO, H2, and various hydrocarbons and are generally found in the flue gas of the boilers. Carbon monoxide is the only gas whose concentration can be determined conveniently in a boiler plant test. L6- Heat loss due to radiation and convection The other heat losses from a boiler consist of the loss of heat by radiation and convection from the boiler casting into the surrounding boiler house. Normally surface loss and other unaccounted losses is assumed based on the type and size of the boiler as given below For industrial fire tube / packaged boiler = 1.5 to 2.5% For industrial water tube boiler = 2 to 3% For power station boiler = 0.4 to 1% Radiation and unaccountable loss An empirical formula for determining this loss is Log10B = 0.8167 – 0.4238 log10C Where, B= radiation and unaccounted loss C= specific boiler capacity in kg/s. Total radiation and unaccounted loss = 1.5B + 0.5 6. 7. L7- Heat loss due to unburned carbon in fly ash and bottom ash Heat loss due to unburnt in fly ash (%) 8. L8- Heat loss due to unburnt in bottom ash (%) Boiler Efficiency by indirect method =100 –(L1+L2+L3+L4+L5+L6+L7+L8) Example: Efficiency Calculation for Coal Fired Boiler The following are the data collected for a boiler using coal as the fuel. Find the boiler efficiency by indirect method. Fuel firing rate = 5599.17 kg/hr Steam generation rate = 21937.5 kg/hr Steam pressure = 43 kg/cm2(g) Steam temperature = 377 oC o Feed water temperature = 96 C %CO2 in Flue gas = 14 %CO in flue gas = 0.55 Average flue gas temperature = 190 oC Ambient temperature = 31 oC Humidity in ambient air = 0.0204 kg / kg dry air Surface temperature of boiler = 70 oC Wind velocity around the boiler = 3.5 m/s Total surface area of boiler = 90 m2 GCV of Bottom ash = 800 kCal/kg GCV of fly ash = 452.5 kCal/kg Ratio of bottom ash to fly ash = 90:10 Fuel Analysis (in %) Ash content in fuel Moisture in coal Carbon content Hydrogen content Nitrogen content Oxygen content GCV of Coal SOLUTION = 8.63 = 31.6 = 41.65 = 2.0413 = 1.6 = 14.48 = 3501 kCal/k Boiler efficiency by indirect method Step – 1 requirement Find theoretical air = Theoretical air required for complete combustion = kg/kg of coal [(11.6 x 41.65) + {34.8 x (2.0413 – 14.48/8)} +(4.35 x 0)] / 100 = Step – 2 Find theoretical CO2% % CO2at theoretical condition ( CO2)t Where, Moles of N2 = 4.91 kg / kg of coal = Moles of N2 = 77% of nitrogen in air Where moles of C ( CO2)t ( CO2)t = = = 0.4165/12 = 0.0347 20.37% Step – 3 To find Excess air supplied Actual CO2 measured in flue gas = 14.0% % Excess air supplied (EA) = = = 45.17 % Step – 4 To find actual mass of air supplied Actual mass of air supplied = {1 + EA/100} x theoretical air = = {1 + 45.17/100} x 4.91 7.13 kg/kg of coal Step –5 To find actual mass of dry flue gas Mass of = Mass of CO2 +Mass of N2content in the fuel+ Mass of N2 in the dry flue supplied + Mass of oxygen in flue gas gas Mass of = dry flue gas = 7.54 kg / kg of coal Step – 6 To find all losses 1. % Heat loss in dry flue gas (L1) = = L1 = 7.88 % combustion air 2. % Heat loss due to formation of water from H2in = fuel (L2) = L2 = 3.44 % 3. % Heat loss due to moisture in fuel (L3) = L3 = = 5.91 % 4. % Heat loss due to moisture in air (L4) = = L4 = 0.29 % 5. % Heat loss due to partial conversion of C to CO (L5) = L5 6. Heat loss due to radiation and convection (L6) = = = = Total radiation and convection loss per hour % radiation and convection loss L6 7. % Heat loss due to unburnt in fly ash % Ash in coal Ratio of bottom ash to fly ash GCV of fly ash Amount of fly ash in 1 kg of coal = Heat loss in fly ash = % heat loss in fly ash L7 8. % Heat loss due to unburnt in bottom ash GCV of bottom ash Amount of bottom ash in 1 kg of coal = = = = = = 2.58 % 0.548 x [ (343/55.55)4– (304/55.55)4] + 1.957 x(343 304)1.25x sq.rt of [(196.85 x 3.5 + 68.9) /68.9] 633.3 w/m2 633.3 x 0.86 544.64 kCal / m2 544.64 x 90 49017.6 kCal 49017.6 x 100 3501 x 5599.17 0.25 % = = = = = = = 8.63 90:10 452.5 kCal/kg 0.1 x 0.0863 0.00863 x 452.5 3.905 x 100 / 3501 0.11 % 0.00863 kg 3.905 kCal / kg of coal = = = = = = = = 800 kCal/kg 0.9 x 0.0863 0.077 kg 0.077 x 800 62.136 kCal/kg of coal 62.136 x 100 / 3501 1.77 % 100 – (L1+ L2+ L3+ L4+ L5+ L6+ L7+ L8) =100–(7.88+3.44+5.91+0.29+ 2.58+ 0.25+ 0.11+1.77) Heat loss in bottom ash % Heat loss in bottom ash L8 Boiler efficiency by indirect method =100-22.23 =77.77 % Input/Output Parameter kCal / kg of coal % loss 100 7.88 3.44 5.91 0.29 2.58 0.25 0.11 1.77 Heat Input = 3501 Losses in boiler 1. Dry flue gas, L1 = 275.88 2. Loss due to hydrogen in fuel, L2 = 120.43 3. Loss due to moisture in fuel, L3 = 206.91 4. Loss due to moisture in air, L4 = 10.15 5. Partial combustion of C to CO, L5 = 90.32 6. Surface heat losses, L6 = 8.75 7. Loss due to Unburnt in fly ash, L7 = 3.85 8. Loss due to Unburnt in bottom ash, L8 = 61.97 Boiler Efficiency= 100 – (L1+ L2+ L3+ L4+ L5+ L6+ L7+ L8) = 77.77 % Since, the optimum efficiency of boilers occurs at 65–85% of full load, it is usually more efficient, on the whole, to operate a fewer number of boilers at higher loads, than to operate a large number at low loads. Boiler Replacement The potential savings from replacing a boiler depend on the anticipated change in overall efficiency. A change in a boiler can be financially attractive if the existing boiler is : • Old and inefficient • Not capable of firing cheaper substitution fuel • Over or under-sized for present requirements • Not designed for ideal loading conditions The feasibility study should examine all implications of long-term fuel availability and company growth plans. All financial and engineering factors should be considered. Since boiler plants traditionally have a useful life of well over 25 years, replacement must be carefully studied. The discussion on Boiler efficiency would not be over without discussing about the Technical standards for construction of electric plants and lines, Regulations 2010, issued by CEA. According to theses regulations the efficiency of the steam generator (on high heat value basis) in %, as guaranteed by the manufacturer shall be not less than the value as arrived with the following formulae for the quality of performance of coal and lignite: Minimum steam generator efficiency (%) = 92.5 – ((50*A+630(M+9*H))/HHV) Where, A=% ash in fuel, M=% moisture in fuel, H=% hydro in fuel and; HHV= High heat value of fuel in Kcal/Kg. STATION HEAT RATE According to “Terms and Conditions of Tariff Regulations 2009-14”, the station heat rate is specified as follows Existing Thermal Generating Station 200/210/250 MW Sets 500 MW Sets (Sub-critical) 2500 KCal/kWh 2425 kCal/kWh In respect of 500 MW and above units where the boiler feed pumps are electrically operated, the gross station heat rate shall be 40 kCal/kWh lower than the gross station heat rate specified above New Thermal Generating Station achieving COD on or after 1.4.2009 (a) Coal-based and lignite-fired Thermal Generating Stations = 1.065 X Design Heat Rate (kCal/kWh) Design Heat Rate of a unit means the unit heat rate guaranteed by the supplier at conditions of 100% MCR, zero percent make up, design coal and design cooling water temperature/back pressure. Provided that the design heat rate shall not exceed the following maximum design unit heat rates depending upon the pressure and temperature ratings of the units: Provided further that in case pressure and temperature parameters of a unit are different from above ratings, the maximum design unit heat rate of the nearest class shall be taken Provided also that where unit heat rate has not been guaranteed but turbine cycle heat rate and boiler efficiency are guaranteed separately by the same supplier or different suppliers, the unit design heat rate shall be arrived at by using guaranteed turbine cycle heat rate and boiler efficiency. Provided also that if one or more units were declared under commercial operation prior to 1.4.2009, the heat rate norms for those units as well as units declared under commercial operation on or after 1.4.2009 shall be lower of the heat rate norms arrived at by above methodology and the norms as per the regulation 26 (ii) A (a) of existing thermal power plants. TURBINE EFFICIENCY The Carnot cycle The Carnot cycle when acting as a heat engine consists of the following steps: 1. Reversible isothermal expansion of the gas at the "hot" temperature, TH (isothermal heat addition). During this step (A to B on Figure) the expanding gas causes the piston to do work on the surroundings. The gas expansion is propelled by absorption of quantity Q1 of heat from the high temperature reservoir. 2. Isentropic (Reverrsible adiabatic) expansion of the gas. For this step (B to C on Figure) we assume the piston and cylinder are thermally insulated, so that no heat is gained or lost. The gas continues to expand, doing work on the surroundings. The gas expansion causes it to cool to the "cold" temperature, TC. 3. Reversible isothermal compression of the gas at the "cold" temperature, TC. (isothermal heat rejection) (C to D on Figure) Now the surroundings do work on the gas, causing quantity Q2 of heat to flow out of the gas to the low temperature reservoir. 4. Isentropic compression of the gas. (D to A on Figure) Once again we assume the piston and cylinder are thermally insulated. During this step, the surroundings do work on the gas, compressing it and causing the temperature to rise to TH. At this point the gas is in the same state as at the start of step 1. Rankine cycle Processes of the Rankine cycle There are four processes in the Rankine cycle, each changing the state of the working fluid. These states are identified by number in the diagram to the right. • Process 1-2: The working fluid is pumped from low to high pressure, as the fluid is a liquid at this stage the pump requires little input energy. • Process 2-3: The high pressure liquid enters a boiler where it is heated at constant pressure by an external heat source to become a dry saturated vapor. • Process 3-4: The dry saturated vapor expands through a turbine, generating power. This decreases the temperature and pressure of the vapor, and some condensation may occur. • Process 4-1: The wet vapor then enters a condenser where it is condensed at a constant pressure and temperature to become a saturated liquid. The pressure and temperature of the condenser is fixed by the temperature of the cooling coils as the fluid is undergoing a phase-change. Variables Heat flow rate to or from the system (energy per unit time) Mass flow rate (mass per unit time) Mechanical power consumed by or provided to the system (energy per unit time) Thermodynamic efficiency of the process (net power output per heat input, dimensionless) Isentropic efficiency of the compression (feed pump) and expansion (turbine) processes, dimensionless The "specific enthalpies" at indicated points on the T-S diagram The final "specific enthalpy" of the fluid if the turbine were isentropic The pressures before and after the compression process ηtherm ηpump,ηturb h1,h2,h3,h4 h4s p1,p2 Equations Rankine cycle with reheat In this variation, two turbines work in series. The first accepts vapor from the boiler at high pressure. After the vapor has passed through the first turbine, it re-enters the boiler and is reheated before passing through a second, lower pressure turbine. Among other advantages, this prevents the vapor from condensing during its expansion which can seriously damage the turbine blades, and improves the efficiency of the cycle. The Rankine Cycle with Rengeration Improving cycle efficiencies Improving cycle efficiency almost always involves making a cycle more like a Carnot cycle operating between the same high and low temperature limits. The Carnot cycle is maximally efficient, in part, because it receives all of its heat addition at the same temperature, which is the highest temperature in the cycle. Similarly, it rejects all of its heat at the same low temperature. The T-s diagram below details the working of a Carnot cycle operating between the same temperature limits as our Rankine cycle. How regeneration works Figure 4: a Rankine cycle with regeneration Choosing regeneration assumptions With the design layout complete, we turn to adding the assumptions which allow CyclePad to solve the cycle. For this example, there are four places where we have to make new assumptions: the outlet of the high-pressure turbine (S2), the splitter (SPL1), the outlet of the low-pressure pump (PMP2), and the inlet of the high-pressure pump (PMP1). We will look at each of these in turn. The High-Pressure Turbine Outlet (S2) What pressure do we choose for the extracted feedwater? We don't know yet, so we'll choose 200 kPa, which gives the two turbines pressure ratios of 25 and 20. This makes them roughly equal and keeps either one from having an astronomically high pressure ratio. (The original Rankine cycle had a turbine PR equal to 500!) Later, when we have the cycle solved and we can let CyclePad do sensitivity analyses, we will see if another pressure works better. The Splitter (SPL1) The splitter is used to draw some of the working fluid from the high-pressure turbine stage and direct it towards the mixer. This means that the stuff exiting the splitter is the same as the stuff entering it. Quick Note This simulates situations when we use a special splitter that allows us to separate the saturated mixture into two streams that each have different proportions of liquid and vapor. For instance, we could split 1 kg/sec, 60% quality stream into a pair of 0.4 kg/sec, 0% quality and a 0.6 kg/sec, 100% quality streams. This allows each stream to have different specific properties (v, h, and so on), though they still have the same temperature and pressure. The Low-pressure Pump Outlet (S5) What pressure should the water at this state have? This water, which enters the pump at the cooler pressure, needs to be pumped up to the pressure of the water extracted from the high-pressure turbine. This is a matter of simple hydrostatics: if we make it lower, the higher pressure extract water will flow backward through the low-pressure pump and, if we make it higher, the low pressure pump water will flow backward through the splitter. The High-Pressure Pump Inlet (S6) Our whole purpose in adding heat to this water is to raise its temperature before it enters the heater and improve the cycle efficiency. The water exiting the low-pressure pump is only at 46 C and the water entering the heater in the original Rankine cycle was at about the same temperature (adding pressure to an incompressible fluid doesn't raise its temperature much). How high can we heat the water to improve this? Brayton cycle Brayton-type engine consists of three components: • A gas compressor • A mixing chamber • An expander In the original 19th-century Brayton engine, ambient air is drawn into a piston compressor, where it is compressed; ideally an isentropic process. The compressed air then runs through a mixing chamber where fuel is added, a constant-pressure isobaric process. The heated (by compression), pressurized air and fuel mixture is then ignited in an expansion cylinder and energy is released, causing the heated air and combustion products to expand through a piston/cylinder; another theoretically isentropic process. Some of the work extracted by the piston/cylinder is used to drive the compressor through a crankshaft arrangement. The term Brayton cycle has more recently been given to the gas turbine engine. This also has three components: • A gas compressor • A burner (or combustion chamber) • An expansion turbine Ideal Brayton cycle: • isentropic process - Ambient air is drawn into the compressor, where it is pressurized. • isobaric process - The compressed air then runs through a combustion chamber, where fuel is burned, heating that air—a constant-pressure process, since the chamber is open to flow in and out. • isentropic process - The heated, pressurized air then gives up its energy, expanding through a turbine (or series of turbines). Some of the work extracted by the turbine is used to drive the compressor. • isobaric process - Heat Rejection (in the atmosphere). Actual Brayton cycle: • adiabatic process - Compression. • isobaric process - Heat Addition. • adiabatic process - Expansion. • isobaric process - Heat Rejection. Since neither the compression nor the expansion can be truly isentropic, losses through the compressor and the expander represent sources of inescapable working inefficiencies. In general, increasing the compression ratio is the most direct way to increase the overall power output of a Brayton system Here are two plots, Figure 1 and Figure 2, for the ideal Brayton cycle. One plot indicates how the cycle efficiency changes with an increase in pressure ratio, while the other indicates how the specific power output changes with an increase in the gas turbine inlet temperature for two different pressure ratio values. Figure 1: Brayton cycle efficiency Figure 2: Brayton cycle specific power output Methods to increase power The power output of a Brayton engine can be improved in the following manners: • Reheat, wherein the working fluid—in most cases air—expands through a series of turbines, then is passed through a second combustion chamber before expanding to ambient pressure through a final set of turbines. This has the advantage of increasing the power output possible for a given compression ratio without exceeding any metallurgical constraints (typically about 1000°C). • Intercooling, wherein the working fluid passes through a first stage of compressors, then a cooler, then a second stage of compressors before entering the combustion chamber. While this requires an increase in the fuel consumption of the combustion chamber, this allows for a reduction in the specific volume of the fluid entering the second stage of compressors, with an attendant decrease in the amount of work needed for the compression stage overall.. • Regeneration, wherein the still-warm post-turbine fluid is passed through a heat exchanger to preheat the fluid just entering the combustion chamber. This directly offsets fuel consumption for the same operating conditions improving efficiency. It allows also results in less power lost as waste heat. • A Brayton engine also forms half of the combined cycle system, which combines with a Rankine engine to further increase overall efficiency. • Cogeneration systems make use of the waste heat from Brayton engines, typically for hot water production or space heating. Reverse Brayton cycle A Brayton cycle that is driven in reverse, via net work input, and when air is the working fluid, is the air refrigeration cycle or Bell Coleman cycle. Its purpose is to move heat, rather than produce work. This air cooling technique is used widely in jet aircraft. The Otto cycle The Otto Cycle consists of adiabatic compression, heat addition at constant volume, adiabatic expansion and rejection of heat at constant volume, characterized by four strokes, or reciprocating movements of a piston in a cylinder: intake (induction) stroke 2. compression stroke 3. power stroke 4. exhaust stroke The cycle begins at top dead center (TDC), when the piston is furthest away from the axis of the crankrshaft. On the intake or induction stroke of the piston, the piston descends from the top of the cylinder, reducing the pressure inside the cylinder. A mixture of fuel and air is forced (by atmospheric or greater pressure) into the cylinder through the intake (inlet) port. The intake (inlet) valve (or valves) then close(s), and the compression stroke compresses the fuel–air mixture. The air–fuel mixture is then ignited near the end of the compression stroke, usually by a spark plug (for a gasoline or Otto cycle engine) or by the heat and pressure of compression (for a Diesel cycle or compression ignition engine). The resulting pressure of burning gases pushes the piston through the power stroke. In the exhaust stroke, the piston pushes the products of combustion from the cylinder through an exhaust valve or valves. 1. Diesel cycle The Ideal Diesel Cycle P-v Diagram for the Ideal Diesel cycle. The cycle follows the numbers 1-4 in clockwise direction. The image on the left shows a P-v diagram for the ideal diesel cycle; where P is pressure and v is specific volume. The ideal diesel cycle follows the following four distinct processes (The color references refer to the color of the line on the diagram.): • Process 1 to 2 is isentropic compression (blue) • Process 2 to 3 is reversible constant pressure heating (red) • Process 3 to 4 is isentropic expansion (yellow) • Process 4 to 1 is reversible constant volume cooling (green) The diesel is a heat engine: it converts heat into work. Work in (Win) is done by the piston compressing the working fluid Heat in (Qin) is done by the combustion of the fuel Work out (Wout) is done by the working fluid expanding on to the piston, this produces usable torque • Heat out (Qout) is done by venting the air Maximum thermal efficiency The maximum thermal efficiency of a diesel cycle is dependent on the compression ratio and the cut-off ratio. It has the following formula: • • • Where ηth is thermal efficiency α is the cut-off ratio (ratio between the end and start volume for the combustion phase) r is the compression ratio γ is ratio of specific heats (Cp/Cv) The cut-off ration can be expressed in terms of temperature as shown below: T2 = T1rγ − 1 T3 can be approximated to the flame temperature of the fuel used. The flame temperature can be approximated to the adiabatic flame temperature of the fuel with corresponding air-to-fuel ratio and compression pressure, P3. T1 can be approximated to the inlet air temperature. This formula only gives the ideal thermal efficiency. The actual thermal efficiency will be significantly lower due to heat and friction losses. The formula is more complex than the Otto cycle (petrol/gasoline engine) relation that has the following formula; The additional complexity for the diesel formula comes around since the heat addition is at constant pressure and the heat rejection is at constant volume. The Otto cycle by comparison has both the heat addition and rejection at constant volume. Thermodynamic cycle A thermodynamic cycle is a series of thermodynamic processes which returns a system to its initial state. Properties depend only on the thermodynamic state and thus do not change over a cycle. Variables such as heat and work are not zero over a cycle, but rather are process dependent. The first law of thermodynamics dictates that the net heat input is equal to the net work output over any cycle. The repeating nature of the process path allows for continuous operation, making the cycle an important concept in thermodynamics. Thermodynamic cycles often use quasi static processes to model the workings of actual devices. Example of P-V diagram of a thermodynamic cycle. The area enclosed by the loop is the work (W) done by the process: . This work is equal to the balance of heat (Q) transferred into the system: . Equation (2) makes a cyclic process similar to an isothermal process: even though the internal energy changes during the course of the cyclic process, when the cyclic process finishes the system's energy is the same as the energy it had when the process began. Thermodynamic power cycles Heat engine diagram. Heat engine Thermodynamic power cycles are the basis for the operation of heat engines, which supply most of the world's electric power and run almost all motor vehicles. Power cycles can be divided according to the type of heat engine they seek to model. The most common cycles that model internal combustion engines are the Otto cycle, which models gasoline engines and the Diesel cycle, which models diesel engines. Cycles that model external combustion engines include the Brayton cycle, which models gas turbines, and the Rankine cycle, which models steam turbines. The clockwise thermodynamic cycle indicated by the arrows shows that the cycle represents a heat engine. The cycle consists of four states (the point shown by crosses) and four thermodynamic processes (lines). For example the pressure-volume mechanical work done in the heat engine cycle, consisting of 4 thermodynamic processes, is: If no volume change happens in process 4->1 and 2->3, equation (3) simplifies to: STEAM TURBINE Steam are a major energy consumer. Optimizing process operating conditions can considerably improve turbine water rate, which in turn will significantly reduce energy requirement. Various operating parameters affect condensing and back pressure turbine steam consumption and efficiency. There are two type of the steam turbineA) Impulse turbine-- Impulse turbines change the velocity of a steam jet. The jet impinges on the turbine's curved blades which change the direction of the flow. The resulting change in momentum (impulse) causes a force on the turbine blades. Newton's second law describes the transfer of energy for impulse turbines. B) Reaction turbine--- Reaction turbines are acted on by steam, which changes pressure as it moves through the turbine and gives up its energy. They must be encased to contain the water pressure (or suction), or they must be fully submerged in the water flow. Newton's third law describes the transfer of energy for reaction turbines. Other forms of the turbine are --a) Impulse turbine b) Velocity compounding c) Pressure compounding d) Pressure – Velocity compounding Turbine efficiency High Pressure Turbine efficiency (HPT)-80% Reason- Small blades, tip clearance 0.5 mm, Ratio of blade size to tip clearance is highest. Intermediate Pressure Turbine efficiency (IPT)-95% Reason- Big blade size, tip clearance 0.5 mm, Low tip leakage, Ratio is smallest. Low Pressure Turbine efficiency-85% Reason- Very big blades, tip clearance 4mm,Load tip leakage ratio is smaller. Effect of operating conditions on steam turbines A condensing turbine system is shown in figure below. Turbine exhaust operating below atmosphere, is condensed in a shell and tube exchanger called surface condenser. Condensate flows in the shell side of the condenser and steam is condensed by the cooling water. Vacuum in the surface condenser i.e. turbine exhaust vacuum is controlled/ maintained by vacuum ejector system of the surface condenser. Turbines are designed for a particular operating conditions like steam inlet pressure, steam inlet temperature and turbine exhaust pressure/ exhaust vacuum, which affects the performance of the turbines in a significant way. Variations in these parameters affects the steam consumption in the turbines and also the turbine efficiency. Theoretical turbine efficiency is calculated as workdone by the turbine to the heat supplied to generate the steam. Efforts are made to show the impact of various operating conditions by considering the following steam conditions as illustration. In the above referred turbines, 1 % reduction in steam consumption saves around $ 47000 annually for condensing turbines and around $ 84000 annually in back pressure turbine. LHV of the fuel for generating steam is considered as 10500 kcal/kg and boiler efficiency is taken as 87 %. Effect of various operating parameters is illustrated in the succeeding paragraphs. 2.1 Effect of Steam inlet pressure Steam inlet pressure of the turbine also affects the turbine performance. All the turbines are designed for a specified steam inlet pressure. For obtaining the design efficiency, steam inlet pressure shall be maintained at design level. Lowering the steam inlet pressure will hampers the turbine efficiency and steam consumption in the turbine will increase. Similarly at higher steam inlet pressure energy available to run the turbine will be high, which in turn will reduce the steam consumption in the turbine.Figure - 2a & 2b represents the effects of steam inlet pressure on steam consumption and turbine efficiency respectively, keeping all other factors constant for the condensing type turbine. Figure - 2a & 2b indicates that increase in steam inlet pressure by 1 kg/cm2 in condensing type turbine reduces the steam consumption in the turbine by about 0.3 % and improves the turbine efficiency by about 0.1 % respectively. In case of back pressure type turbine increase in steam inlet pressure by 1 kg/cm2 reduces the steam consumption in the turbine by about 0.7 % and improves the turbine efficiency by about 0.16 % as shown in figure - 3a & 3b . Improvement in back pressure type turbine is more than the condensing type turbine. Effect of Steam inlet temperature Enthalpy of steam is a function of temperature and pressure. At lower temperature, enthalpy will be low, work done by the turbine will be low, turbine efficiency will be low, hence steam consumption for the required output will be higher. In other words, at higher steam inlet temperature, heat extraction by the turbine will be higher and hence for the required output, steam consumption will reduce. Figure - 4a & 4b represents the effects of steam inlet temperature on steam consumption and turbine efficiency respectively, keeping all other factors constant for the condensing type turbine. Figure - 4a & 4b indicates that increase in steam inlet temperature by 10 deg C in condensing type turbine reduces the steam consumption in the turbine by about % and improves the turbine efficiency by about 0.12 % respectively. In case of back pressure type turbine increase in steam inlet temperature by 10 deg C reduces the steam consumption in the turbine by about 1.5 % and improves the turbine efficiency by about 0.12 % as shown in figure - 6a &6b. Improvement in back pressure type turbine is more than the condensing type turbine. Effect of exhaust pressure/ vacuum Higher exhaust pressure/ lower vacuum, increases the steam consumption in the turbine, keeping all other operating parameters constant. Exhaust pressure lower than the specified will reduce the steam consumption and improves the turbine efficiency. Similarly exhaust vacuum lower than the specified, will lower the turbine efficiency and reduces the steam consumption. Figure 6a & 6b represents the effects of exhaust vacuum on steam consumption and turbine efficiency respectively, keeping all other factors constant for the condensing type turbine. Figure 6a & 6b indicates that improvement in exhaust vacuum by 10 mm Hg, reduces the steam consumption in the turbine by about 1.1 %. Improvement in turbine efficiency varies significantly from 0.24 % to 0.4 %. In case of back pressure type turbine reduction in exhaust pressure by 1.0 kg/cm2, reduces the steam consumption in the turbine by about 0.8 % and improves the turbine efficiency by about 0.14 % as shown by figure - 7a & 7b. The leaving velocity is proportional to the specific volume, the specific volume increases rapidly with improvement in vacuum. The gain in available energy due to higher vacuum is partly offset by the increase in specific volume hence of exhaust losses. The turbine manufacturer’s curves should give some indication. In our country, the turning point is well below the reach even with coldest CW water in winter. The terminal temperature difference (TTD) which is defined as the temperature difference between steam and saturation to outgoing to CW water is intact a measure of its log mean temperature differential (LMTD).A high value of TTD is an indication of contamination of CW side of the tubes by lime and dirt and also that of air ingress in steam space. Under cooling of the condensate is due to air leakage only, therefore this temperature differential is also of important .Because of partial pressure of the air at the bottom of the condenser, the condensate temperature lies lowered below that corresponding to the total pressures since it is corresponding the partial pressure of the steam only. Main thing to realize is that when there is ingress, the heat transfer coefficient become poor, therefore temperature differential increases by way of increase in condensing temperature in order to get heat across air barrier. This makes the vacuum worst. Factors affecting the exhaust vacuum in the condensing type turbines · Vacuum ejector system Vacuum ejector system creates and maintains the vacuum in the surface condenser by removing the air/ inerts ingress. Removal of air/ inerts ingress is important, as accumulation of this hampers the performance of surface condenser, which reduces the surface condenser vacuum. Motive steam condition shall be maintained as specified. Inter-after condenser shall be cleaned in the available opportunity, as they get choked due to foreign material coming with cooling water. · Flange joints shall be tightened properly to avoid any ingress of air. · Exhaust side of the turbine shall be properly steam sealed to avoid any ingress of air. · Higher size of exhaust pipe In many condensing turbines it is observed that the exhaust vacuum of these turbines is much less than the vacuum at the condenser. Mainly, it is due to the higher pressure drop in the exhaust pipeline from turbine exhaust to the condenser. In order to improve the vacuum at turbine exhaust so as to reduce steam consumption in the turbine, exhaust pipeline of these turbines can be replaced with higher size. In one of the turbine, exhaust line size of 900 mm was replaced with 1300 mm. The pressure drop in the exhaust pipe reduced by 50 mm Hg i.e. vacuum at the turbine exhaust improved by 50 mm Hg. Pay back period of replacing the exhaust pipeline was 6 months with investment of $ 40000. TURBINE LOSS Internal loss Nozzle friction loss- Due to this loss the head of the pressure drop it mean that there is loss in the pressure. b) Blade friction loss- Due to friction there is the loss of the pressure in the each blade this loss decrease the pressure of the steam turbine. c) Disc friction loss – d) Diaphragm glad and blade tip leakage- Pressure compounding turbine there is a pressure drop across each fixed nozzle that is across diaphragm so the gap between the diaphragm and shaft is source of the steam leakage. It can be minimize when we put inter stage glands between shaft and glands between shaft and diaphragm. There is also balancing hole in disc to equalize the pressure on the both side. e) Partial admission loss- To improve the load bearing capacity the steam is to inter at the three or four stage. Due to this the there is loss in the steam head. This loss is called as the Partial admission loss. f) Exhaust loss - At the exhaust of the turbine the steam loss its pressure and there is loss of the velocity of the steam. Let assume that at the exhaust hood the steam having the velocity = V Exhaust loss = 0.5 X (M V2) g) Wetness – At the exhaust of the turbine, steam condensate into the water and due to the water’s weight there is the loss of the velocity of the turbine shaft. External loss a) a) Shaft gland leakage- In the turbine there is arrangement that steam should not go out of the turbine and air should not enter in the bearing oil of the turbine so there is system called gland which used to protect the turbine from the above problem. But due to leakage in the balancing disc there is loss of the pressure in the high pressure side. b) Journal and thrust bearing- In the bearing there is loss due to the friction of the shaft and the bibet material. Due to the friction the heat is generated and the heat is taken away by the cooling oil. c) Governing and oil pump – For the operating of the governing there is requirement control oil and the function of the control oil is to control the operation of the system properly such that the turbine should having continuous supply of the load. FACTOR AFFECTING THE OPERATING EFFICIENCY OF THE TURBINE a) b) c) d) Nozzle governing Throttle governing Overload governing Effect of the vacuum e) Effect of mean steam and reheat temperature. f) Condenser losses 1 .Losses due to high cooling water temperature Cooling towers when installed are performing satisfactory, this loss must be accepted to some extent. It is possible, of course to minimize the loss by having abnormal quantity of cooling water flowing through the condenser, this give smaller cooling water, temperature rise across the condenser than optimum. 2. Loss due to incorrect cooling water quantity This is a loss which can normally be eliminated. If the cooling water temperature rise across the condenser is less than optimum, then he opening of the condenser cooling water outlet valve should be reduced. This condition may also be shown u when the condensate temperature is lower that the saturated steam temperature. 3. Loss due to air ingress This loss can be eliminated and steps should be taken to locate and stop any air ingress into the system under the vacuum as soon as the condition occurs. Excessive air in the condenser may lead to an increased reading on the condensate oxygen meter. The thermal resistively of a layer of air 0.254mm thick is approximately the same as that offered by a slab o copper 3.35 meters thick. 4. Loss due to dirty tubes Operationally, little can be done to eliminate the cause of this loss, as the tubes must normally be cleaned when the unit is of f load. However soon as loss due to dirty tubes is determined it should be ascertained that the chlorine injection to the affected condensed is satisfactory. It may be that the station chemist will wish to have the dosage increased, so he should always be informed. The effect of this loss on vacuum can be minimized by increasing the flow of cooling water through the condenser. GAS TURBINES In a gas turbine, the working medium for transforming thermal energy into rotating mechanical energy is the hot combustion gas, hence the term “gas turbine.” Gas turbines are also referred to as combustion turbines, or combustion gas turbines. Industry groups, users, and manufacturers use the terms interchangeably. Gas turbine generators are self-contained packaged power plants. Air compression, fuel delivery, combustion, expansion of combustion gas through a turbine, and electricity generation are all accomplished in a compact combination of equipment, usually provided by a single supplier under a single contract. In contrast to steam turbine-generators, which are designed for a particular application, the manufacturers of gas turbines have a defined product, allowing for substantial standardization and assembly line manufacturing. The modular concept of the package power plants made gas turbines relatively quick and easy to install. Standardization and modularization combine to provide product benefits of relatively low capital cost and fast installation of power generation capacity. The benefits of low capital cost and fast installation were initially offset by higher operating costs when compared to other installed capacity. Therefore, early utility applications of gas turbine generators were strictly for peak load operation for a few hundred hours per year. Improvement in efficiency and reliability and application of combined cycles have added to the economic benefits of the technology and now give gas turbine-based plants a wider range of application on electric systems. An economic screening of power plant is shown in fig1. project specific comparison will depend on fuel costs, capital costs and maintenance requirements. Gas turbine technology can be used in a variety of configurations for electric power generation. Conventional applications are simple cycle, combined cycle or cogeneration. Of the conventional applications, simple cycle operation is generally the least efficient and is used primarily for peaking power generation. Combined cycles combine the gas turbine and steam turbine cycles into more efficient power plants by utilizing the gas turbine exhaust gas heat. Cogeneration cycles use the steam generated from exhaust gas for process or heating requirements. Electric utility companies use gas turbines predominantly in simple cycle and combined cycle applications. Non-utility generator companies predominantly use combined cycles, either strictly for power generation or in conjunction with an industrial company as cogeneration power plants. Most gas turbine applications rely on natural gas or fuel oil for fuel. During the late 1980s and early 1990s the availability and economics of natural gas made gas turine-based power plants the preferred choice for the majority of new power generation additions in the United States. Fuel flexibility and efficient thermodynamic cycles have become important characteristics for gas turbine applications. Further improvements in the areas of fuel flexibility, cycle efficiency and reduced exhaust gas emissions are the primary technical challenges to advancing gas turbine technology. Gas turbine products and applications are changing rapidly. The technology continues to evolve through innovations in component cooling techniques, metallurgy improvements and cycle innovations. Future enhancements in gas turbine technology can be expected from higher firing temperatures, increased pressure ratios, improved materials, multi-staged combustion techniques and emission control capability. The gas turbine generator will continue to play an important role in meeting power generation requirements as technology advances and as the product and cycle designs respond to changes in fuel economics and allowable plant emissions. Thermodynamic fundamentals: The simple open cycle gas turbine is shown schematically in fig2. The gas turbine consists of compressor section, combustor and turbine section. As indicated in fig 2, ambient air is first compressed from state point 1 to state point 2 in the compressor section. Fuel is added and combusted in the combustor. The combustion products exit the combustor at state 3 and expand from state point 3 to state point 4 (atmosphere) in the turbine section. The expansion process produces useful shaft work. Typically, over 50% of the turbine shaft work produced is required to drive the compressor. The remaining work (Wnet) is available to drive an electric generator or for mechanical drive applications. Fu el Igniti on Work Out Compre ssor Turbine Air In Fig 2: Typical open cycle gas turbine system Flue Gases Operation of and actual gas turbine approaches that of an idealized thermodynamic cycle called the airstandard Brayton cycle. Consequently, reviewing the characteristics of the Brayton cycle provides useful insights into the operating and performance characteristics of an actual gas turbine system. Air, the working fluid of the Brayton cycle, is assumed to be an ideal gas. It is further assumed that the mass flow rate through the cycle is constant, the air is of fixed composition, and the specific heat of the air is constant. Four thermodynamic processes make up the Brayton cycle: compression, heat addition at constant pressure, expansion and heat rejection at constant pressure. The compression and expansion portions of the cycle are internally reversible and adiabatic ( isentropic) processes. Because the mass flow rate is assumed to be constant throughout the process, the direct combustion process of an actual gas turbine is conceptualized by heat exchanger that transfers heat to the working fluid from an external source. The actual inlet and exhaust processes of the gas turbine are conceptualized by a heat exchanger that rejects heat at constant pressure to the surroundings to complete the cycle. Fu el Heat Excha nger Compr essor Turbine Work Out Air In Heat Excha nger Fig 3: Air-Standard Brayton Cycle A Typical Air Standard Byayton Cycle Flue Gases Figure 3 depicts the air-standard Brayton cycle. A comparison of figs 2 and 3 highlights the major differences between an open cycle gas turbine and air-standard Brayton cycle. Figure 4 shows the generalized pressure-volume (P-v) and temperature-entropy (T-s) diagrams for the airstandard Brayton cycle. The state point numbers in fig 4 correspond to the numbers shown in fig 3. Fig 4 P-v and T-s diagrams for the Brayton cycle Actual gas turbine performance would approach that of the Brayton cycle if not for the following: • Irreversibilities that occur in the compressor and turbine; • Pressure losses that occur in the flow passages and the combustor; • Heating of the compressed air by direct combustion rather than an indirect heat exchanger, thereby increasing the mass flow rate throughout the system downstream if the combustor; • Thermal, mechanical and electrical losses. Referring to fig 3 the thermal efficiency of Brayton cycle is defined as follows: ηth= Wnet/QH=(QH-QL)/QH= 1-(QH-QL)=1-{CP(T4-T1)/CP(T3-T2)}………….1 where Wnet= useful work available, QH= heat added to the system, and QL= heat rejected from the system. Since the specific heat is assumed constant, the expression may be simplified such that thermal efficiency is solely a function of cycle temperatures, ηth=1- T1(T4/ T1-1)/ T2(T3/ T2-1) …………………..2 reffering to fig4 and noting that P3/P4=P2/P1 And also noting that, T3/T4=T2/T1 or T3/T2=T4/T1 …………………..3 …………………...4 Consequently, Eq 2 can be simplified and thermal efficiency can be written as follows: ηth=1- T1/ T2 or ηth=1- T4/T3 …………………...5 for an ideal gas undergoing isentropic compression, the compressor pressure ratio is related to the temperature ratio by, P2/ P1=( T2/T1)^k/(k-1) ………………6 Where k= ratio of specific heats for air If eq.6 is solved for T1/T2 and the results submitted into eq.5, then the resulting equation defines thermal efficiency as a function of compressor pressure ratio. ηth=1-1/( P2/ P1)^(k-1)/k ………………7 if eq.7 is evaluated for various compressor pressure ratios, it is clear that cycle efficiency increases as the pressure ratio increases. Fig 5 shows the relationship of pressure ratio to cycle thermal efficiency of the Brayton cycle assuming a ratio of specific heats for air of 1.4. Fig 5 Brayton cycle thermal efficiency versus pressure ratio at constant temperature. By inspecting the generalized T-s diagram shown in fig 6 and referring to eq.5 and eq.7 it can be seen that if turbine exhaust temperature, T4, is constant, increasing the combustion temperature and the resultant turbine inlet temperature from T3 to T3A will increase the cycle’s thermal efficiency. However,in actual gas turbines, these temperatures cannot be increased indefinitely because of temperature limitations of the materials. From this, it is quite understandable why many research and development efforts by gas turbine manufacturers continue to focus on improving hot gas path component metallurgy and cooling methods to increase the allowable turbine inlet temperatures and thereby increase cycle efficiency. Fig 6: Generalized T-s diagram As previously mentioned, increasing the pressure ratio (P2/ P1) increases the cycle efficiency. However, as pressure ratio changes, the net specific work per unit mass of working fluid also changes. Both thermal efficiency and specific work are strongly influenced by pressure ratio and turbine inlet temperature. However, the maximum net specific work and maximum thermal efficiency do not occur at the same pressure ratio. Therefore in designing gas turbines, the design pressure ratio must be a compromise between the maximum thermal efficiency and the maximum specific work. A typical performance curve for a real (non-ideal) turbine is shown in fig.7. As the compressor pressure ratio (P2/ P1) increases from 4 to 8, the specific work produced by the turbine section increases more rapidly than the specific work that the compressor consumes. The result is an increase in shaft specific work output and efficiency as pressure ratio increases. Fig 7: Typical (non-ideal) real gas turbine simple cycle performance curve-efficiency vs specific work at various pressure ratios at constant temperature. As the compressor pressure ratio increases, the temperature rise across the compressor also increases. This in turn reduces the combustor temperature rise necessary to achieve a given turbine inlet temperature. As a result, the combustor heat input decreases and cycle efficiency increases. At the point corresponding to the maximum shaft specific work output, the turbine specific work produced and the compressor specific work consumed increase at the same rate. As pressure ratio increases further (beyond the point where the shaft specific work output is a maximum), the compressor specific work consumed increases at a greater rate than the turbine specific work produced and, as a result the shaft specific work output actually decreases. However, because the combustor heat input continues to decrease, the efficiency continues to increase as pressure ratio increases. However with further increases in pressure ratio, thermal efficiency of rea gas turbines will begin to decrease. The maximum shaft specific work for the example of fig.7 occurs at a pressure ratio of 8. As the pressure ratio is increased from 8 to 16, the shaft specific work output decreases because compressor specific work consumed is increasing faster than turbine specific work output. Therefore, shaft specific work output (turbine specific work produced minus compressor specific work consumed) decreases. However because higher compressor outlet temperature occur at the higher pressure ratios, fuel consumption is reduced and overall thermal efficiency increases. After a point, the increase in compressor specific work consumed more than offsets the advantage of higher compressor outlet temperature and overall efficiency begins to decrease. In fig.7 this occurs at pressure ratios greater than 16. The actual pressure ratio at which this occurs depends on the specific gas turbine considered. The efficiencies of the compressor and turbine for an actual cycle are typically defined in relation to isentropic and non-isentropic processes. Considering the state points for isentropic and non-isentropic cycle fig.8 the compressor and turbine efficiencies are as follows: Fig 8 T-s diagram for an isentropic and non-isentropic cycle ηcomp=(h2s-h1)/(h2-h1)……………………8 where h1= enthalpy at compressor inlet h2s=enthalpy at constant entropy and compressor discharge pressure, and h2= actual enthalpy at compressor discharge pressure and ηturb=(h3-h4)/(h3-h4S)…………………….9 where h3= enthalpy at turbine inlet, h4S= enthalpy at constant entropy and turbine exit pressure and h4= actual enthalpy at turbine exit pressure. It is these process inefficiencies which cause real devices to depart from the ideal behavior described by eq.7. Performance parameters: Gas turbine generator performance is characterized by generator output and heat rate. Generator output is the electrical generation of the turbine generator and typically is measured at the generator terminals. Generator output is measured in units of kilowatts or megawatts. Heat rate is the ratio of heat consumption to generator output and usually expressed in units of British thermal units per kilowatt-hour (Btu/kWh) heat consumption represents the thermal energy consumed by the gas turbine and can be calculated as the product of the fuel mass flow rate and the heating value of the fuel. For gas turbines, the convention is to use the lower heating value. Therefore, heat rates for gas turbines are typically expressed on a lower heating value basis. In equation form, the heat rate for a combustion turbine generator is calculated as follows: Heat rate (Btu/kWh) = Heat consumption (Btu)/Generator output (kW) Or Heat rate (Btu/kWh) = fuel consumption rate (lb/h) X fuel lower heating value ( Btu)/ Generator output (kW) Heat rates are inverse form of thermal efficiency. A lower heat rate value indicates a higher thermal efficiency. Likewise, a higher heat rate value indicates a lower thermal efficiency. Other principal gas turbine performance parameters are listed below, with their English units of measure in parentheses: • Compressor inlet temperature (˚F) • Compression ratio • Turbine inlet temperature (˚F) • Exhaust temperature (˚F) • Exhaust gas flow (lb/h) • Exhaust heat (Mbtu/h) • Inlet pressure loss (in.H2O) and • Exhaust pressure loss (in.H2O) Each performance parameter is shown in fig.9 and is defined in following paragraphs: Compressor inlet temperature is dry bulb temperature of the inlet air to the compressor section. When the gas turbine is not equipped with an evaporative cooler or an inlet chiller, the compressor inlet temperature is equal to the ambient dry bulb temperature. Fig 9: Gas turbine generator performance parameters. When the gas turbine is equipped with an evaporative cooler or an inlet chiller the compressor inlet temperature is equal the outlet temperature of the cooler or chiller. The compression ratio or pressure ratio is a measure of the compressor discharge pressure to the compressor inlet pressure. Theoretically, higher compression ratios are limited by the costs associated with the additional compressor stages required to reduce the temperature of the compressed inlet air. For heavy-duty industrial gas turbines, compression ratios of 10-18 are most common. For aero-derivative gas turbines is toward higher compression ratios to achieve lower heat rates. The turbine inlet temperature sometimes referred to as the turbine firing temperature is the average temperature of the combustion gases entering the turbine section of the gas turbine. Firing temperature may be defined differently by various manufacturers. Higher turbine inlet temperature result in higher specific outputs ( kilowatts per pound of fuel ) and lower heat rates. In practice, higher turbine inlet temperatures are limited by the material properties of the turbine. In recent years, higher turbine inlet temperatures have been achieved by using ceramic and composite materials. In addition, improved turbine cooling technology has allowed increases in turbine inlet temperatures. Currently, the most advanced heavy-duty gas turbines have turbine inlet temperatures of approximately 2,350˚F, an increase of about 350˚F over the preceding generation of heavy-duty gas turbines. The exhaust temperatures is the average gas temperature leaving the turbine. For a given turbine inlet temperature, a lower exhaust temperature indicates higher thermal efficiency and higher specific output. Aero-derivative units generally have exhaust temperatures in the range of 800 to 950˚F and are therefore more efficient in simple cycle. By contrast, current heavy-duty units generally have exhaust temperatures of 950 to 1100˚F. Exhaust temperature is significant for heavy heat recovery applications where an HRSG generates steam from gas turbine exhaust gases. The maximum temperature and pressure of steam generated in an HRSG are limited by the gas turbine exhaust temperature (assuming that the HRSG is not supplmentally fired). Higher exhaust temperatures allow higher steam temperatures and pressure results in significantly lower combined cycle heat rates. Because of this effect, heavy-duty gas turbines are more commonly used in combined cycle units. Exhaust gas flow is the mass flow rate of exhaust gases from the turbine. Since leakages are minimal and bleed air flow is ultimately redirected into the main turbine flow, the exhaust gas flow is essentially equal to the sum of the inlet air mass flow, the fuel mass flow and any water/steam injection. The mass flow rate of steam that can be generated in an HRSG is directly proportional to the gas turbine exhaust gas flow. Exhaust heat is a measure of the thermal energy contained in the exhaust gas flow. Exhaust heat is the product of the exhaust gas flow and the exhaust gas enthalpy. Exhaust heat can be estimated by calculating a heat balance around the gas turbine. By this method, exhaust heat is calculated as the heat input from fuel, inlet air, and injection water/steam, minus the thermal equivalent of the generator output and miscellaneous losses (including generator losses and turbine/generator bearing friction). Some manufacturers do not guarantee exhaust heat. This guarantee is of significance for heat recovery applications only. Inlet pressure loss is the pressure loss associated with the inlet air flow through the inlet air filter, silencer, evaporative cooler (if used), and inlet ductwork to the compressor section of the gas turbine. Inlet pressure loss typically is measured in units of inches of water. For “new and clean” performance, inlet pressure loss values of 3.0 to 4.0 inches of water are common. Exhaust pressure loss is the pressure loss associated with the exhaust gas flow from the exit of the turbine section of the gas turbine through the exhaust ductwork, silencer, and stack. In heat recovery applications the exhaust gas flow through the HRSG results in additional exhaust pressure losses. For simple cycle applications exhaust pressure losses of 4.0 to 5.0 inches of water are typical. For heat recovery applications exhaust pressure losses of 10.0 to 17.0 inches of water are typical, depending on the HRSG configuration and the presence of emission-reduction or noise-abatement equiopment. Factors that Influence Performance: Factors that influence performance include the following: • Ambient conditions, • Inlet/exhaust pressure losses, • Fuels and • Water/steam injection flow rates Ambient conditions: Because gas turbines are open cycle internal combustion engines, their performance is significantly affected by ambient conditions. Ambient conditions that directly affect performance include dry-bulb temperature, specific humidity, and barometric pressure (or elevation). Ambient dry-bulb temperature has a pronounced effect on electrical output. Lower air temperatures provide higher air densities which result in higher mass flows, and turbine output is directly proportional to higher mass flow. Higher air temperatures, which provide lower air densities and mass flows, which result in lower output. Lower ambient air temperatures also result in lower heat rates and better efficiency due to an increase in compressor pressure ratio. Likewise, higher ambient air temperatures result in higher gas turbine generator heat rates. A typical correction curve showing the effect of ambient air temperature on output, heat rate and other parameters is shown in fig 10. Specific humidity affects gas turbine performance through the slight variance in water mass flow. For higher specific humidities, more moisture is contained in the inlet air flow stream, making the air less dense and resulting in a lower electrical output and a higher rate. Typical correction curves showing the effect of specific humidity on output and heat rate are shown in fig 11. Fig 11 correction curves for humidity Barometric pressure of site elevation has an effect on output because of the variance in air-density. Lower barometric pressure which occurs at higher elevation, result in lower air density, lower inlet air mass flow rates, and lower electrical outputs. Barometric pressure has no effect on heat rate since the compressor pressure ratio and turbine inlet temperature are unaffected. A typical correction curve showing the affect of site elevation output is shown in fig 12. Fig 12: correction curves for output and exhaust flow vs. site elevation Inlet and exhaust pressure losses: Higher inlet pressure losses reduce the air flow through the unit and thereby reduce output. A typical correction curve showing the effect of inlet pressure loss is shown in fig 13. Fig 13: Gas turbine generator correction curves for inlet pressure drop In practical terms inlet pressure loss is a function of the inlet air system design and cleanliness of the inlet air filters. Lower inlet air pressure losses can be achieved by designing for lower inlet air velocities through the filter, silencer and duct. The improved operating performance associated with a lower inlet air velocity design must be evaluated against the associated higher capital cost. A similar cost evaluation determines the optimum point that dirty air filters which have higher pressure losses, should be changed out. Higher exhaust pressure losses increase the turbine back pressure, thereby reducing power output and increasing heat rate. A typical correction curve showing the effect of exhaust pressure loss on performance is shown in fig 14. Fig 14: Gas turbine generator correction curves for exhaust pressure drop. Higher exhaust pressure losses are primarily a function of the exhaust system design. For simple cycle applications, the exhaust system typically consists of an exhaust duct, silencers, and a stack. Exhaust pressure losses of 4.0 to 5.0 inches of water are typical for simple cycle gas turbines. For combined cycle or cogeneration applications, the exhaust gases pass through an HRSG with the associated additional pressure loss. Exhaust pressure losses of 10.0 to 17.0 inches of water are typical for combined cycle and cogeneration applications depending on the complexity of the cycle arrangement, exhaust emission control, or noise-abatement. Fuels: gas turbine output and heat rate are also affected by the type of fuel burned. The two most common fuels used today are natural gas and fuel oil. Turbine output and heat rate are both slightly better for operation on natural gas than for operation on fuel oil, assuming no water or steam injection is used for NOX control or power augmentation. Coal gasification combined cycle technology is being developed for future large-scale commercial use. The coal gasification process produces low to medium Btu gas which can be used as gas turbine fuel. Using the coal gas as the fuel results in the higher fuel mass flow rate to achieve the same heat consumption rates as for conventional fuels. As a result of the higher fuel mass flow rates, higher electrical outputs can be generated, depending on the fuel heating value. Water and Steam Injection: The most common method of controlling gas turbine NOX emissions rates is to inject water or steam into the combustor to reduce the peak flame temperature. Besides reducing the rate of formation of NOX, water or steam injection results in higher mass flow rates through the turbine section, electrical output is increased. Water injection increases gas turbine generator heat rate because of the additional heat consumption required to vaporize the water. Steam injection improves gas turbine generator heat rate because of its higher entering the combustion zone. Water or steam can be injected into gas turbine at rates beyond what is required for NOX control. For these applications, water or steam is injected for power augmentation (power boost). For power augmentation, the effect of water or steam injection on gas turbine generator output and heat rate is identical to the effect of water or steam injection for NOX control. To obtain higher thermal efficiency, it is essential to have a thermodynamic cycle using a high temperature heat source and a low temperature heat sink. The higher the temperature differences the greater the cycle efficiency (average temperature at which the heat is transmitted to the working medium~ average temperature at which the heat is rejected to the cooling medium). Neither the Brayton Cycle nor the Rankine Cycle can have much difference in temperature to have higher efficiency due to technical limitations. The gas turbine cycle is having the high source temp. of 1000 to 1200 c hence it could be the best option for the topping cycle. The rankine cycle working on steam is the most techno economic solution to use as bottoming cycle since it could maintain the sink temp close to the cooling water temperature. In a combined cycle power plant, the gas turbine cycle (brayton) is combined with that of steam turbine cycle (rankine). The combination of the two makes it possible to achieve the highest efficiency rates obtainable in the current state of the art technology, with values up to 47% for the overall plant. With certain new generation gas turbines, it is possible to attain efficiencies even upto 58-60%. This is much higher than the efficiency of the best available fossil fuel fired conventional thermal power plant. To achieve the best efficiency it is necessary for the optimization of combined cycle plant and heat rate. The following factors are to be considered in the optimization of combined cycle power plant.. A.Cycle Optimisation:• Configuration of combined Cycle Plant. • Number and capacity of gas turbine units • Number and Capacity of HRSGs • HRSG sizing • Combined cycle plant optimized cost. B. Combined Cycle Plant Heat Rate The following are the optimizations of combined cycle power plant are as 1, Combined Cycle Performance The site output of a gas turbine unit depends on ambient conditions and type of fuel whereas the steam turbine generator output primarily depends on the turbine throttle flow, the steam inlet condition (pressure & temperature) and condenser back pressure. The maximum amount of heat that can be expected from the HRSG is limited by the lowest stack temp possible for a given type of fuel. Corrosion may result on the HRSG point corresponding to the fuel being burn. Again for a specify stack temp more heat can be extracted by providing more surface area ( by adjusting lower pinch point temperature differences) resulting in higher steam production and steam turbine power, but this advantage has to be balance against to detrimental factors, viz :• Increase in HRSGs cost • Derating of gas turbine power due to increase gas pressure drop across HRSGs 2. Combined Cycle Optimization:The optimization combined cycle can be broadly carried out as follows: 1) Fixed configuration of GT HRSG & STGs 2) Seclect steam parameters ( Pressure, Temperature & Feed water temp. of HRSG) 3) Select stack temperature 4) Select pitch point 5) Perform heat & mass balance in HRSG 6) Size of HRSG 7) Compute GT output & TG output 8) Compute total capital cost 9) Compute output at CCP 10) Compute capitalize differential output 11) Compute total evaluated cost Heat Rate of CCP: Heat rate is defined as unit of heat added to the cycle per unit electric energy. Heat rate = Heat added to the cycle / Power generated = Fuel input x LCV of the fuel ( power generated in the gas turbine generated + power generated in the steam turbine generated) Formulae CERC norms for calculation of heat rate of a CCGT Q.A A steam trubine opening at a presssure of 170kg/cm2 and temperature of 560`C (Enthalpy 825 kCal/kg of steam) at electrical load of 500MW with final feed temperature of 270`C (Enthalpy 283 kCal/kg of water) and flow of 1250 Tonnes/hr of economizer inlet. What will be the heat rate of turbine? Turbine effieciency 85%. Soln:Given: Enthalpy of steam = 825 kcal/ kg Enthalpy of water = 283 kcal/ kg Flow = 1250 Tonnes/hr Turbine effieciency = 85% Heat Rate = = = = = kcal / K W hr { Qs ( Hs – Hf ) x 100 / kw hr } { 1250 ( 825 – 283 ) x 100 / ( 500 x 103 kw hr) } { 1250 ( 542 ) x 1000 / 500 x 103 1355 kcal / kw hr. 1 Cal = 4.185 J = 1355 x 4.1856 = 5671.75 kJ/ kw hr. Corrosponding, Efficiency n = = ( 3600 x 100) / 5671.25 63.47 % Efficiency of Hydro Power Plant Worldwide, hydropower plants produce about 24 percent of the world's electricity and supply more than 1 billion people with power. ± 2700 TWH is generated every year. Hydropower supplies at least 50% of electricity production in 66 countries and at least 90% in 24 countries. The world's hydropower plants output a combined more than 675,000 megawatts and The hydro power potential of India is around 1,48,701 MW and at 60% load factor, it can meet the demand of around 84,000 MW, the energy equivalent of 3.6 billion barrels of oil, according to the National Renewable Energy Laboratory. Use of hydropower peaked in the mid-20th century, but the idea of using water for power generation goes back thousands of years. A hydropower plant is basically an oversized water wheel. Hydropower plants harness water's energy and use simple mechanics to convert that energy into electricity. Hydropower plants are actually based on a rather simple concept -- water flowing through a dam turns a turbine, which turns a generator. Here are the basic components of a conventional hydropower plant:1. Dam - Most hydropower plants rely on a dam that holds back water, creating a large reservoir. Often, this reservoir is used as a recreational lake, such as Lake Roosevelt at the Grand Coulee Dam in Washington State. 2. Intake - Gates on the dam open and gravity pulls the water through the penstock, a pipeline that leads to the turbine. Water builds up pressure as it flows through this pipe. 3. Turbine - The water strikes and turns the large blades of a turbine, which is attached to a generator above it by way of a shaft. The most common type of turbine for hydropower plants is the Francis Turbine, which looks like a big disc with curved blades. A turbine can weigh as much as 172 tons and turn at a rate of 90 revolutions per minute (rpm). 4. Generators - As the turbine blades turn, so do a series of magnets inside the generator. Giant magnets rotate past copper coils, producing alternating current (AC) by moving electrons. 5. Transformer - The transformer inside the powerhouse takes the AC and converts it to highervoltage current. 6. 7. Power lines - Out of every power plant come four wires: the three phases of power being produced simultaneously plus a neutral or ground common to all three. Outflow - Used water is carried through pipelines, called tailraces, and re-enters the river downstream. Hydropower Basics Flowing water creates energy that can be captured and turned into electricity. This is called hydropower. The most common type of hydropower plant uses a dam on a river to store water in a reservoir. Water released from the reservoir flows through a turbine, spinning it, which, in turn, activates a generator to produce electricity. But hydropower doesn't necessarily require a large dam. Some hydropower plants just use a small canal to channel the river water through a turbine. Another type of hydropower plant—called a pumped storage plant—can even store power. The power is sent from a power grid into the electric generators. The generators then spin the turbines backward, which causes the turbines to pump water from a river or lower reservoir to an upper reservoir, where the power is stored. To use the power, the water is released from the upper reservoir back down into the river or lower reservoir. This spins the turbines forward, activating the generators to produce electricity. Classification of Hydro Projects based on Installed Capacity in following types:Micro: upto 100 KW Mini: 101KW to 2 MW Small: 2 MW to 25 MW Mega: Hydro projects with installed capacity >= 500 MW Thermal Projects with installed capacity >=1500 MW Types of Hydropower Impoundment An impoundment facility, typically a large hydropower system, uses a dam to store river water in a reservoir. The water may be released either to meet changing electricity needs or to maintain a constant reservoir level. Diversion A diversion, sometimes called run-of-river, facility channels a portion of a river through a canal or penstock. It may not require the use of a dam. Pumped Storage When the demand for electricity is low, a pumped storage facility stores energy by pumping water from a lower reservoir to an upper reservoir. During periods of high electrical demand, the water is released back to the lower reservoir to generate electricity. Turbine Technologies There are two main types of hydro turbines: impulse and reaction. The type of hydropower turbine selected for a project is based on the height of standing water—referred to as "head"—and the flow, or volume of water, at the site. Other deciding factors include how deep the turbine must be set, efficiency, and cost. Impulse Turbine The impulse turbine generally uses the velocity of the water to move the runner and discharges to atmospheric pressure. The water stream hits each bucket on the runner. There is no suction on the down side of the turbine, and the water flows out the bottom of the turbine housing after hitting the runner. An impulse turbine is generally suitable for high head, low flow applications. Cross-Flow A cross-flow turbine is drum-shaped and uses an elongated, rectangular-section nozzle directed against curved vanes on a cylindrically shaped runner. It resembles a "squirrel cage" blower. The cross-flow turbine allows the water to flow through the blades twice. The first pass is when the water flows from the outside of the blades to the inside; the second pass is from the inside back out. A guide vane at the entrance to the turbine directs the flow to a limited portion of the runner. The cross-flow was developed to accommodate larger water flows and lower heads than the Pelton. Pelton A pelton wheel has one or more free jets discharging water into an aerated space and impinging on the buckets of a runner. Draft tubes are not required for impulse turbine since the runner must be located above the maximum tailwater to permit operation at atmospheric pressure. A Turgo Wheel is a variation on the Pelton and is made exclusively by Gilkes in England. The Turgo runner is a cast wheel whose shape generally resembles a fan blade that is closed on the outer edges. The water stream is applied on one side, goes across the blades and exits on the other side. Reaction Turbine A reaction turbine develops power from the combined action of pressure and moving water. The runner is placed directly in the water stream flowing over the blades rather than striking each individually. Reaction turbines are generally used for sites with lower head and higher flows than compared with the impulse turbines. Propeller A propeller turbine generally has a runner with three to six blades in which the water contacts all of the blades constantly. Picture a boat propeller running in a pipe. Through the pipe, the pressure is constant; if it isn't, the runner would be out of balance. The pitch of the blades may be fixed or adjustable. The major components besides the runner are a scroll case, wicket gates, and a draft tube. There are several different types of propeller turbines: Bulb turbine The turbine and generator are a sealed unit placed directly in the water stream. Straflo The generator is attached directly to the perimeter of the turbine. Tube turbine The penstock bends just before or after the runner, allowing a straight line connection to the generator. Kaplan Both the blades and the wicket gates are adjustable, allowing for a wider range of operations. Francis A Francis turbine has a runner with fixed buckets (vanes), usually nine or more. Water is introduced just above the runner and all around it and then falls through, causing it to spin. Besides the runner, the other major components are the scroll case, wicket gates, and draft tube. Kinetic Kinetic energy turbines, also called free-flow turbines, generate electricity from the kinetic energy present in flowing water rather than the potential energy from the head. The systems may operate in rivers, manmade channels, tidal waters, or ocean currents. Kinetic systems utilize the water stream's natural pathway. They do not require the diversion of water through manmade channels, riverbeds, or pipes, although they might have applications in such conduits. Kinetic systems do not require large civil works; however, they can use existing structures such as bridges, tailraces and channels. Major Effects of Reservoir Sedimentation • It reduces the active storage capacity, which may reduce the capability of the reservoir to deliver the benefits in course of time. • It makes the flood management in the reservoir more difficult. • Damages to turbines and other under water parts due to abrasive action of silt. Approaches to Tackle Sedimentation Problem of reservoir • Catchment Area Treatment (CAT) for reduction of silt load includes forestations of the catchment area and constructions of check dams on the tributaries and upstream of the river. • Effective desilting arrangements for prevention of silt. • Silt resistant equipments of withstanding the silt. • Effective operation of the reservoir to minimize silt deposition. Important Recommendations for Silt Control SHORT TERM Experiment with reservoir Operation-Optimization of gate operation advised by study on model and prototype. MEDIUM TERM Dredging pumps at intake-Recommended for Silt removal near intake gate. LONG TERM Catchment area treatment to reduce bank erosion. New diversion Tunnel-Preliminary study indicates it is beneficial, further model studies & detailing of proposal has been advised. Thrust areas in the field of Environmental Conservation & Management for developing Hydropower Following safeguards/management plans are implemented at various NHPC projects to ensure development of hydropower in an environmentally sustainable manner: • Compensatory Afforestation in lieu of forest land diverted for the project. • Catchment Area Treatment (CAT) to minimise erosion in the catchment of the reservoir, thereby reducing siltation in the reservoir. • Resettlement & Rehabilitation of Project Affected Population. • Restoration of Dumping Sites and Quarry Sites using engineering and biological measures. • Reservoir Rim Treatment plan to stabilise reservoir periphery. • Conservation measures for flora and fauna, to conserve flora and fauna native to the ecosystem of the area. • Subsidized Fuel Distribution to worker population and project affected population to minimise fuel demands on the adjacent forests. • Health Management Plan for the worker population and affected population to prevent epidemics and maintain optimum health standards. • Fishery Management by construction of fish ladders wherever possible, to enable migration of fishes and by promoting reservoir fisheries.Green Belt Plan to make the surroundings of project construction areas green. • Dam Break Analysis and Disaster Management Plan for downstream areas vulnerable to flooding in case of Dam breach. Soil Erosion due to Water Erosion, removal of sediment, rock, and soil from the landscape, resulting in the formation of new landforms and the lowering of the land surface, a process known as denudation. During transportation the sediment further erodes the landscape by battering and rubbing against the surfaces over which it passes. The fragments also knock against each other, and break into smaller pieces. Water is probably the most significant agent of erosion today, and rivers carry more sediment from the land to the oceans every year than either ice or wind. Rivers move sediment downstream as part of their load. Vertical erosion predominates near the source, cutting downward, while downstream rivers erode laterally, thus widening their valleys. Sediment transport becomes more important as the debris is removed from the drainage basin. During transport sediment helps aggrade the bed and banks, and attrition of the particles causes them to be reduced in size. As rivers become larger, they are able to carry more sediment from the landscape, and the sediment becomes more denuded. The landforms of river valleys therefore represent stages in the denudation of the landscape. Slope angles reduce and valley cross-sections become wider downstream, developing from steep V-shaped upland valleys to wide, open floodplains. When rivers meet resistant rock, unique and distinctive features may develop including waterfalls, rapids, and gorges. When they flow through floodplains, rivers cut into valley floors and sides as they meander, reworking deposits laid down in earlier periods. Water can erode sediment on slopes where overland flow or runoff occurs. Weathered material washes downslope and enters river channels directly. This can also cause gullies to form as material is removed. Gullying is most effective where vegetation is sparse, and sporadic intense rainfall occurs. Some dramatic erosional landscapes have occurred as a result of this process, such as the Badlands of North and South Dakota and Nebraska, United States. Human activities can increase the erosion process where vegetation has been removed by agriculture, fire, overgrazing, or deforestation, and accelerated soil erosion results. Policy measures The Union Ministry of Power has taken several steps to accelerate capacity addition from hydroelectric projects. These include: • higher budgetary allocation for the hydel sector. • investment approval of new hydro-electric projects; • identification of new projects in the Central Sector for advance action; • promoting State Sector projects which were languishing or could not progress due to Inter-State disputes; • improving tariff dispensation for hydel projects; • simplification of procedure for transfer of clearance; • levy of 5% development surcharge to supplement resources for hydro electric projects by NHPC allowed by CERC. Basin-wise Policy The policy measures undertaken to accelerate hydro power development inter-alia lay emphasis on basinwise development. World Bank assistance for survey, investigation and preparation of DPRs of the projects in Sutlej and Ravi basins is being considered. States with substantial undeveloped Hydro potential Region/State Arunchal Pradesh Himachal Pradesh Assessed (MW) 50328.00 In Operation Under (MW) Construction 10.50 1609.85 3822.95 405.00 3453.00 1926.00 Balance (MW) 49912.50 13835.15 13071.05 U.P./Uttaranchal 18898.00 18820.00 Jammu Kashmir Sikkim Karnataka Meghalaya Mizoram & 14146.00 4286.00 6602.00 2394.00 2196.00 1394.25 84.00 2789.40 185.20 0.00 098.10 1799.50 300.50 105.00 65.00 1837.50 469. 0 519.00 222.00 0.00 60.00 30.21 20.2% 936.00 90.00 24.00 66.00 12282.75 3683.00 3590.60 2208.80 2136.00 1684.25 1684.25 1604.50 1589.00 1475.00 1095.50 M.P./Chhattishg 4485.00 arth Kerala West Bengal Manipur Nagaland Orissa 3514.00 2841.00 1784.00 1574.00 2999.00 THE SURVEY AT A GLANCE The surveyoutlines the approach and provides a road map for development of the balance untapped potential of the country by the year 2025-26. The paper analyses the Anticipated Demand-Supply scenario likely to prevail in the country by making use of the results of Long term Perspective Plan Studies carried out by CEA (up to the end of 11th Plan i.e. 2011-12) as well as Demand Forecasts available up to the end of 12th Plan (2016-17) as per 16th Electric Power Survey The Demand Projections for the period beyond 2017 have been made by extrapolating the projections made in 16th EPS. Based on the above, the demand for power by the year 2025-26 is likely to be of the order of 353000 MW with corresponding probable installed capacity of 463000 MW. Further, hydro capacity additions in different Plan periods till 2025-26 have been so planned as to develop complete hydro potential by the year 2025-26 which would gradually improve the share of the hydro in the system to about 32% by 2025-26. The Paper discusses about status of hydro schemes under various stages of Development i.e. projects under construction, cleared by CEA, under examination in CEA, under Survey & Investigation etc. and outlines various factors inhibiting the growth of hydro potential in the country. It stresses upon the need to complete the on-going projects and to develop the projects already cleared by CEA expeditiously. It also stresses upon the need to carry out Survey and Investigations works in a time bound manner by the year 2016-17 in order to ensure development of the balance hydro potential in the country by the year 2025-26. The surveyanalyses projects languishing due to various reasons like funds constraints, Inter-state aspects etc. and suggests their quick development by addressing the involved issues at appropriate level. In addition, by resolving the pending issues, 42 schemes with installed capacity of about 13250 MW, which were examined earlier in CEA and returned to project authorities for resubmission, can also be taken up for implementation with minimal of S&I works. The surveysuggests the Action Plan/ Methodology for preparation of Pre-Feasibility Reports for balance about 400 schemes and broadly discusses criteria for carrying out prioritisation / ranking study for their development in order to provide a shelf of HE Projects in each basin which could be developed in a systematic manner starting from sites which are ranked to be attractive. The Paper proposes carrying out of Survey and Investigation of the selected schemes by Central Agencies like CWC, NTPC, NHPC and WAPCOS etc. These S&I activities have been proposed to be completed in next 10-15 years so as to accomplish development of entire untapped potential in the country by 2025-26. The cost of development of the remaining untapped potential in the country has been estimated as about Rs. 5,00,000 Crs. while requirement of funds by 2016-17 for carrying out S&I activities would be of the order of Rs. 5000 Crs. In view of the massive fund requirements over next 20 to 25 years, the paper impresses upon the need to immediately explore all avenues for mobilisation of funds. The survey also calls for review of studies carried out for Re-assessment of Hydro Electric Potential of major/ medium HE Schemes to bring out most realistic features of the sites by making use of updated hydrological/ topographical data with inter-action with MOEF. The paper contains following recommendations for expeditious development of the balance hydro potential in the country by the year 2025-26: • About 4759 MW of hydro capacity can be added without much of efforts, if funds to the tune of Rs.14522Crs. are tied up. These include projects languishing due to funds constraints and those projects that are awaiting Planning Commission/ CCEA clearance. • By expeditious resolution of pending issues, the "Returned" projects could be taken up for implementation which would lead to an addition of about 13268 MW of Hydro capacity in the Indian system at a cost of about Rs.35,000Crs. In addition, by resolving inter-state aspects, about 4797 MW of capacity could be added to the system at an estimated cost of about Rs. 13500 Crs. Since preliminary surveys and investigations for most of these schemes have already been carried out for preparation of DPR, these projects could be taken up immediately for implementation and are likely to yield benefits during the next 10-15 years. • In order to achieve development of an installed capacity of about 150,000 MW from the entire identified hydro potential of the country (excluding about 25,000 MW already developed), Planwise additions of hydro capacity has to grow substantially from present levels to comparatively much higher additions during the subsequent Plans as given below: Likely Hydro Likely funds Plan Period Capacity Addition requirement (MW) (Rs. Crs.) 23200 9th Plan (1997-2002) (Balance) 5800 10432 41728 10th Plan (2002-2007) 11th Plan (2007-2012) 12th Plan (2012-2017) 13th Plan (2017-2022) Part 14th Plan (2022-2026) 01288 2300 31000 35000 85152 92000 124000 140000 Total : 126520 506080 • The total requirement of funds for development of entire untapped potential in the country is likely to be around Rs.5,00,000Crs. in the next 25 years at present price level. • The sources / agencies for raising necessary funds need to be identified well in advance to arrange large fund requirement of the order of about Rs.1,00,000Crs. per plan period on an average i.e. about Rs.20,000Crs. on an average per annum, so that implementation of these projects could be undertaken expeditiously. • In order to develop the entire potential by the year 2025-26, Survey & Investigation activities have to be completed by the end of 12th Plan i.e. by 2016-17. Completion of Survey & Investigation activities by the year 2016-17 for development of balance out of 1,50,000 MW by 2025-26 would involve an expenditure of around Rs.5,000Crs. • Prioritisation studies would be carried out for ranking of the schemes for their implementation considering their relative attractiveness in terms of their location, cost effectiveness, minimal civil works etc. based on the available data. This would provide classification of schemes to be undertaken for implementation in a systematic manner starting from sites of less problems/ risks to others having difficult terrain and accessibility. Submergence of Land Thereby loss of flora and fauna and large scale displacement, due to the hydropower projects is sometimes exaggerated. The following table shows that project catering only to hydro power needs, cause little submergence. A sample of following 12 projects contributing 6231 MW of power required submergence of only 4850 ha of land i.e. the area of submergence per MW is only 0.78 ha. l. Jo Name of the project 1 2 3 4 5 6 7 8 9 10 11 12 Total Chamera-I Chamera-II Chamera-III Parbati-II Parbati-III Tanakpur Dhauliganga-I Rangit Teesta-V Uri Dul Hasti Subansiri Lower State H.P. H.P. H.P H.P. H.P Uttarakhand Uttarakhand Sikkim Sikkim J&K J&K Arunachal Pradesh Capacity (in MW) 540 300 231 800 520 120 280 60 510 480 390 2000 6231 Submergence area ha) 175 25 29.90 27 21.61 140 29 13 68 Nil 85 3436 4849.51 ~ 4850 ( in Hydropower Projects cause huge Destruction of Forests Due to virtue of being located in hilly areas, where forest cover is comparatively better than plain areas, diversion of forest land is sometimes unavoidable. However, NHPC aims at minimum utilization of forests. Compensatory Afforestation is mandatory in accordance with Forest (Conservation) Act, 1980, which has to be fulfilled along with other conditions imposed by MOEF while according forest clearance to a project. Forest land diverted for a project may be a notified forest land, however, this land may include river bed and degraded forests. The actual forest cover in such type of land may be quite low. Inspite of the fact, NHPC undertakes compensatory afforestation either on equal non forest land or on degraded forest land, double the forest area diverted. Massive afforestation has been undertaken at the commissioned as well as ongoing projects of NHPC. In seven commissioned projects of NHPC viz. Tanakpur, Chamera-I, Chamera-II, Uri, Rangit, Dhauliganga, Dul Hasti and three under construction projects viz., Teesta-V, Parbati-II, TLDP-III, afforestation has been undertaken over an area of 3875.42 ha. of degraded/non forest land, in lieu of diversion of 2156.44 ha of forest land required. In these 10 projects, against 102826 affected trees, NHPC has planted more than 78 lakh trees under Compensatory Afforestation. S.No Project Forest affected(ha) Area Afforested (ha) Trees affected Trees planted Commissioned Projects 1 Tanakpur 293.35 2 Chamera-I 982.50 3 Chamera-II 78.70 4 Uri 54.71 5 Rangit 37.10 6 Dhauliganga 138.62 7 Dulhasti 1.10 Sub total (A) 1586.16 Under-construction Projects 8 Teesta-V 122.17 9 Parbati-II 145.62 10 TLDP-III 302.49 Sub total (B) 570.28 Total (A+B) 2156.44 350.00 2000.00 173.00 62.70 168.50 140.73 18.00 2912.93 250.00 291.00 421.49 962.49 3875.42 17368.00 40000.00 1380.00 4000.00 5027.00 1517.00 687.00 69979 17495.00 8124.00 7228.00 32847.00 102826.00 666165.00 3981186.00 239100.00 321000.00 338250.00 287887.00 785673.00 6619261 400000.00 177700.00 645634.00 1223334.00 7842595.00 Benefits of Hydropower Projects Hydropower is a renewable, economic, non polluting and environmentally benign source of energy. It saves scarce fossil fuel resources of the country, which are non renewable. Hydropower projects have certain distinctive advantages over other sources of electricity generation, as discussed below: a) Technical Benefits Hydropower projects are known to have much longer life and provide cheaper electricity as there is no fuel cost and as the recurring cost involved in generation, operation and maintenance is lower than that in case of other sources of energy. b) Environmental Benefits • Uses Renewable and pollution free source of Energy i.e water • Increase in Agriculture Productivity through development of irrigation and multipurpose schemes, having generation of electricity as one of the objectives, wherever possible and feasible. • Avoided Green House Gas (GHG) emissions from equivalent thermal and other fuel based power projects. • Involve large scale afforestation activities under various schemes like Compensatory Afforestation, Catchment Area Treatment, Green Belt Development, Voluntary Afforestation etc. which ultimately improves the environmental quality of the project area. • Flood Mitigation through large storage dams. • Source of Drinking Water c) Social Benefits Hydro projects are a boon to the society and the population at and around the projects. With enhanced employment opportunities, increased earnings, enriched life style and improved standard of living, the people in these localities experience an economic and social upliftment. Reservoir area is an ideal place for recreation and source of eco-tourism promotion in the area. The reservoirs are also used for promoting pisciculture. There are other direct benefits accruing from hydro projects and dams such as increased water for improved irrigation, and drinking water to villages and people living in and around the project area. Que:- Assuming constant discharge of water of a flowing river, it is given that the installed capacity is 100MW when the height is 50meter.What will be the installed capacity if the height is reduced to 10meter? Ans:-The energy of flowing water can be converted into shaft work passing through hydraulic prime mover and ultimately into electrical energy. The shaft power developed by the water passing through the prime mover is given by: kW(power)=mgH x ηh x ηm x ηg 1000 Where m = rate of water flow in kg/sec H = height of fall in meters ηh= hydraulic efficiency of prime mover ηm= mechnical efficiency ηg= generating efficiency kW(power)=mgH x ηoverall 1000 Where ηoverall= ηh x ηm x ηg Keeping other parameters constant we find:kW = constant x H Therefore:kW1 = H1 kW2 H2 100000 = 50 kW 10 power developed = 20MW Maintenance planning Maintenance Planning Guideline Although the development project may be completed and released, the project deliverable simply enters a new phase of its lifecycle. The major project deliverables require ongoing support from the company. That support includes such activities as responding to user issues, maintaining the system hardware, incorporating enhancements, and performing preventative maintenance. For the success of the product or system in the field, thoroughly planning ahead for proper maintenance support is crucial. 1. Read the guidelines starting on page 2:  Introduction to Maintenance  Defining the “Maintenance Concept”  Maintenance Planning Overview—Types and Timing 2. Determine which aspects of maintenance apply to the project deliverables. 3. Using the information on page 3, “Maintenance Planning Overview—Types and Timing,” determine when you should begin writing a maintenance plan in your project cycle. 4. Adapt the Maintenance Plan outline (starting on page 5) to your specific projects. 5. If your project is in its early stages, add maintenance planning activities to your project schedule. 6. If your project has already started and there is no maintenance plan, have a maintenance planning meeting so discussions and planning information can benefit any associated design work. 7. Ensure that maintenance planning includes a specific “owner” going forward who continues to be a regular part of your project and has adequate inputs to development and test reviews. 8. As you move through the project, update the plan iteratively; thus, yielding a detailed maintenance plan later in the project to ensure all aspects of personnel and processes are in place when the product or system is released to production/deployment. Maintenance Planning Guidelines and Plan Outline Introduction to Maintenance Maintenance refers to ongoing support and evolution of a system once it is released to users/customers. Maintenance planning needs to occur while a system is in the development stage. Purpose of the Maintenance Process:  Sustain and monitor system capability to provide services.  Record problems for analysis.  Take corrective, adaptive, perfective, and preventive actions.  Confirm restoration capability. Expected Outcomes of Maintenance Process:  A maintenance strategy is developed.  Maintenance constraints are provided as inputs to requirements.  Replacement system elements are made available.  Services meeting stakeholder requirements are sustained.  The need for corrective design changes is reported.  Failure and lifetime data is recorded. Defining the Maintenance Concept The maintenance concept is developed first. It is really the high-level design of the approach to system maintenance. This concept sets the overall parameters for doing more detailed maintenance planning. It should cover:  The scope of the maintenance, e.g. an overview of covered hardware and software systems/subsystems, whether maintenance of third-party system elements is included, or what types of maintenance are covered (see list below).  Post-delivery processes, e.g. an overview of the approach to problem resolution, change control, and deployment of updates or whether any tailoring from standard company processes is necessary or allowable.  Overall responsibilities for maintenance, what group(s) will be responsible for fulfilling which aspects of the maintenance processes.  Estimates of life-cycle costs, guidelines for acceptable life-cycle costs that will drive maintenance approaches and budgets. Based on the overall guidelines established in this maintenance concept, a detailed maintenance plan can be developed. Maintenance Planning Overview: Types and Timing The Maintenance Plan must address detailed processes for the development of changes as well as their deployment. It addresses subjects such as:  Scope of maintenance effort.  Schedule for any regular maintenance releases.  Types of maintenance releases allowed.  Maintenance processes and techniques, including for issues recording, escalation, prioritization, change reviews, and control.  Organizational responsibilities and staffing.  Tools and equipment including configuration management, defect tracking, spares requirements, and test equipment.  Processes for acceptance testing, releases, and deployment communication.  Budgets.  Ongoing monitoring of maintenance effectiveness and customer satisfaction with the system. Major aspects of maintenance which must be addressed in maintenance planning:  Maintaining control over the system's day-to-day functions.  Maintaining control over system modification.  Perfecting existing acceptable functions.  Preventing system performance from degrading to unacceptable levels. Categories of maintenance:  Corrective Maintenance – Changes necessitated by actual errors/bugs or design deficiencies. Corrective maintenance consists of activities normally considered to be error correction required to keep the system operational. By its nature, corrective maintenance is usually a reactive process. Corrective maintenance is related to the system not performing as originally intended. The three main causes of corrective maintenance are (1) design errors, (2) logic errors, and (3) coding errors.  Adaptive Maintenance – Changes initiated as a result of changes in the environment in which a system must operate. These environmental changes are normally beyond the control of the maintainer and consist primarily of changes to the: (1) rules, laws, and regulations that affect the system; (2) hardware configuration, e.g., new terminals, local printers, etc.; (3) data formats and file structures; and (4) system software, e.g., operating systems, compilers, utilities, etc.  Perfective Maintenance (also known as enhancements and upgrades) – All changes, insertions, deletions, modifications, extensions, and enhancements made to a system to meet the evolving and/or expanding needs of the user. It is generally performed as a result of new or changing requirements, or in an attempt to augment or fine-tune the existing software/hardware operations/performance. Activities designed to make the code easier to understand and to work with, such as restructuring or documentation updates, are included in the Perfective category.  Preventive Maintenance – Changes required avoiding or detecting problems before they cause operational problems. Hardware maintenance could include regular checks of performance and physical inspection for wear and resulting adjustments as necessary. Software maintenance in this category could include regular review of performance metrics, analysis of loads and trends and any emerging issues with system performance, and adjustments of the system to ensure that operations are not disrupted. How Maintenance Planning and Preparation Fit in the System Development Life Cycle:An inherent element of the system requirements is the maintainability of the system. This can be captured in the design alternatives analysis, maintained as part of the configuration management of the system, and verified during the operational phase of the project. The maintenance concept above leads to high-level and detailed maintenance requirements. Implementation of the system would also result in implementation of the maintenance management program, verification that the system is as maintainable as hoped, and finally concurrent operations and maintenance activities. The cross-cutting activity of system validation assessment during the operation phase would also be paralleled by a validation that the maintenance concept was captured in the management of the system and the verification that maintenance requirements were being met. Taking it phase by phase, consideration of maintenance implications leads to this typical involvement of support personnel during development of the system.  System requirements definition and alternatives investigation: Maintenance concept development and planning must be done in parallel with the development of the system to be maintained. Starting with the overall requirements definition and investigation of design alternatives. The overall concept of maintenance may drive tradeoffs in system development. For example, how much time and money will be spent developing highly automated diagnostic tools to ease troubleshooting and contain costs of field visits? Or developing sophisticated online automated code update capabilities to reduce physical shipment of new software versions to the field? Those who will be responsible for maintenance should be involved in such trade-off discussions early in the project so that the life-cycle costs associated with maintenance are considered in the initial system design.  Development: As elements of the system are developed (detailed design and implementation performed), features that influence or implement directly the maintenance concept are created by the development team. Those responsible for maintenance and support should be included in appropriate reviews and prototyping. They will have detailed input on how to make the system most easily diagnosed maintainability of sub-systems, etc.  Testing and documentation: As the time for deployment nears, maintenance personnel can begin to learn a new system, even assisting with testing to learn hands-on about installation, configuration, and system troubleshooting. They can also review and help hone technical publications such as user manuals and installation guides.  Deployment: System deployment marks the official beginning of transition to ongoing maintenance and support. The handoff between development and maintenance personnel should be done with attention to understanding of state of the system—open issues, any features that did not make the release, etc., as well as readiness of the maintenance organization and processes and any need for initial support from development. MAINTENANCE PLAN OUTLINE: Typical Items Covered in a Maintenance Plan  Overview and Scope 1. Types of Maintenance included:Provide brief overview statements of how/whether corrective, adaptive, preventive, and perfective maintenance is covered by this plan. 2. Systems Included in Software Maintenance:Calls out the types of software included in the maintenance and corresponding systems or subsystems, such as:  Operating System: Maintenance issues include system administration, network security, upgrades or “patches” to the latest version, and dealing with potential incompatibilities between the OS and other hardware and software in the system.  Commercial Off-the-Shelf: Sometimes called COTS software, this includes commercially available applications that are part of the overall operation, such as relational database management systems, word processing, and/or spreadsheets. Examples include Oracle, Word, and Excel. Maintenance issues include configuration and user administration of COTS implementations, software maintenance contracts, upgrades, and potential incompatibilities between COTS and other hardware and software in the system.  Application Software: Maintenance issues include system configuration management, software maintenance contracts, backup and disaster recovery, user and operator administration, and system security. In addition, the issue of intellectual property rights and source code ownership has a tremendous impact on maintenance issues and costs. 3. Items Included in Hardware Maintenance:Calls out all hardware (electronic, mechanical) elements of the product/system that must be maintained, including enclosures, electronics, and third-party modules or systems. 4. Release and Maintenance Phase Schedule Provides a timeline view showing key milestones and release cycles, including the following items:  Initial deployment: The schedule should show the start of ongoing maintenance with respect to initial deployment—for example, is there a transition period during which Development or other       non-maintenance personnel are expected to stay involved or continue to lead efforts? The schedule should define at which point each responsible group is assuming ownership of support. Regularly-scheduled/ongoing maintenance: Summarize and provide an overview timeline of the overall maintenance cycle. For example, for software, show the schedule for the types of maintenance releases covered by this plan. Also, hardware-related timelines can show regular preventive maintenance trips. Software-related timelines can show regular back-up schedules and database maintenance. See next section, Types of Maintenance Releases. All types appropriate for your company should show up in the Maintenance Schedule, with either hard timing or estimates of frequency. Ad hoc individual patches: e.g. small, timely fixes for urgent problems. Regular patch releases: e.g. larger subsystem roll-up patches for the delivery of less time critical fixes. Full system deliveries: Driven by integration activities that requires the establishment of a new maintenance baseline. External milestones: For example, releases of new versions of operating systems or third party components that must be migrated into the system. Linkage with company development plans: By definition, maintenance involves supporting evolving systems. The linkage of maintenance activities to ongoing development programs should be shown, i.e. is there a cycle by which maintenance items are fed into development portfolio planning? 5. Types of Maintenance Releases:Some companies will define different levels of releases allowable under various circumstances; specifically, the ability to quickly release engineering or test level code to quickly address emergency situations. If such cases are to be allowed, the maintenance plan can specify constraints and guidelines for each type of release. The following paragraphs are examples of software releases: Engineering Software: Definition and purpose: Engineering software is software delivered in response to an emergency. It is only provided at the specific request of an internal group, with the goal of mitigating a critical operations problem within hours of the onset of the problem  Approach: Engineering software may be delivered at any time of the day or day of the week. Engineering software is built in a developer’s view from source code that is not yet merged to the baseline and typically only unit tested by the developer. The goal within sustaining engineering will be to merge corresponding fixes (tested and approved) to the appropriate baseline within 48 hours of sending the engineering software. The team will continue to use a custom Clear Case tool developed that controls and documents the delivery of engineering software to the field. This tool, accessible only by senior developers (subsystem leads) who are authorized to send engineering software, captures and documents what engineering software has been sent. Test Executables (TEs): Definition and purpose: Test executables are software deliveries designed to fix a specific problem with the smallest possible delivery footprint. The footprint of a change is the number of delivered components required to implement the change. The goal of a TE is to provide a fix for an urgent problem as soon as it is available (possibly before final, definitive testing is completed), in a form that can be promoted into operations by the internal receiving group as quickly as possible. TEs are also only provided at the specific request of a user location. TEs are normally delivered during the standard work week, but can be built and delivered during off hours for especially urgent problems.  Approach: TEs are delivered from the controlled baseline (after a merge and build), either from the maintenance baseline or from an Emergency Bug Fix branch. TEs are delivered under a configuration change request routed through the change control board. Software CM uses custom tools to send the TE tar files, document the receipt of the delivery by each site, and distribute all of the technical data to all interested parties. TEs are installed and tested by the test group in the test environment, but this testing may be done in parallel with the delivery to the user site depending on the urgency of the request. The delivery of TEs will be planned and managed on a daily basis by the lead of the Deployment team. The Custom Software Delivery process governs the delivery of Test Executables as well as Patches. Patches: Definition and purpose: Patches are larger software deliveries, usually covering an entire subsystem. The goal of a patch is to deliver all of the fixes that have been applied to the maintenance baseline for an entire component or subsystem. Sometimes the fix to a problem will require the simultaneous delivery and installation of components from multiple subsystems; when this happens, multiple subsystem patches are generated, tested, and delivered as a group. Deliveries are planned and scheduled by the Deployment team, taking into account the program priority list, the list of program mission milestones, development progress in merging fixes for specific problems, and inter-relationships between fixes among subsystems. We will provide a subsystem patch for each major subsystem every 6 to 8 weeks.  Approach: Patch delivery follows a rigorous process. The Software Integration and Test Team sends a request to software CM to build tar files for the patch, identifies the issues fixed in the patch, and generates draft installation instructions. The test group tests the installation of the patch in the code control system, providing redlines to the installation instructions as required, and verifies the issues fixed in the patch. Additional functional regression testing is performed as required. When testing is completed, the patch is presented at a pre-ship review by the DPT. The installation instructions and the issues are discussed with the receiving user sites, including any changes in operational procedures or troubleshooting methods required by the fixes. A change control record is executed to deliver the software, and software CM uses custom tools to send the patch tar files, document the receipt of the delivery by each site, and distribute the technical data package for the delivery. Drop/Release The delivery of the full system is usually referred to as a drop or a release, and is accompanied by the transition to a new maintenance baseline. Full system deliveries will be performed only as necessary to deliver capabilities and upgrades that require changes in a majority of the subsystems. Extensive regression and performance testing precede full system deliveries. Transition/Training Occasionally, deliveries will require a set of transition activities to be performed (e.g. building of a database index or updating values in a database table) either before or after installation of the software. Scripts are provided to perform these activities. A detailed transition plan is developed and the users are provided hands-on transition training. With proactive support from sustaining engineers, the customer will test the installation. Feedback from this exercise is incorporated into installation and transition instructions prior to deployment to all locations. For new capabilities not requiring the scope of support described above, the primary development engineer is invited to one of the bi-weekly deployment team meetings to discuss the new capability. 1. Maintenance Staffing and Environment 1. Staffing and Roles and Responsibilities  Overall responsibilities and required skills and resources: This section makes clear who has responsibility for what maintenance activities, and what resources in the support organization(s) are involved (at least by skill set and number of resources, if not by name).  Leads and customer contacts: This section identifies key leads, as well as any primary contacts for user groups or customer sites. Those customer/user contacts should include specific contacts for different maintenance activities, e.g. the contact for escalation of user issues, for planning cutin of new releases, etc. 2. Tools and Equipment Needs for Maintenance Activities  “Infrastructure” inherent to the Maintenance process: Internal tools such as configuration management software and defect and enhancement request tracking databases.  Spare Parts: Specify inventory of spare parts to replace failed or damaged equipment during ongoing operations and maintenance. Many maintenance contracts and even some procurement contracts use a rule of thumb of between 5 and 10 percent spares; that is, 5 to 10 percent times the total installed base of certain critical items. A quantitative estimate for spare parts may be calculated if certain variables are known or can be estimated with confidence. For example, if the MTBF and MTRR are known, it is possible to calculate how many spares will be required to have on hand to meet a desired level of availability (i.e. 95% of all cameras online at any given time).  Test Equipment and Test Beds: Specify test equipment or environments that must be available to support debugging of problems and testing of changes before they are released to production. 3. Training Required  Maintenance/support personnel: Define what training the company’s support personnel should receive (usually prior to release) min maintenance procedures.  User/Customer training: Define what training the users of the product or system should receive related to their role in maintaining the system (for example, proper back-ups). 4. Maintenance Procedures Handling change requests:The following procedures must be developed and documented in the Maintenance Plan (or the Maintenance Plan would reference company processes for these items). Fielding change requests  Submitting modification requests  Reviewing and prioritizing requests 1. Developing and testing changes  Analyzing and verifying a problem, developing implementation options  Performing reviews of implementation options, assessing system and company impacts, and choosing an option  Performing technical reviews of changes and approving those changes  Implementing and testing the changes Release planning and configuration management  Allocating problems and fixes to specific releases  Defining deployment of changes, including developing and communicating migration plans  Implementing configuration management of the system and changes to the system  Deciding on retirement of particular elements of a system, planning and communicating the retirement, and executing switchover 2. Acceptance Testing and Signoff The plan can indicate what acceptance testing processes will be employed and signoffs required for different types of releases. This might include referencing specific User Acceptance Test plans that must be run or Customer Acceptance Checklists that must be executed by sites accepting new hardware or software releases. 3. Deployment Communication Delivery plans for software updates need to be flexible and clearly communicated. The Maintenance Plan can identify what approaches will be used to communicate deployment of system changes, such as:  Teleconferences: Releases can have a standard release communication teleconference scheduled, where representatives from affected groups can hear a summary of the upcoming release and deployment plans and ask questions about how their environment is affected.  Email: Notification to a standard distribution list of affected groups as well as other parties who need to stay informed about the big picture, i.e. to understand how often the system is being updated, with what kinds of changes. Both delivery plans and distribution notices should be communicated.  “Patch plans”: The maintenance organization can generate and distribute a regular patch plan communicating a look-ahead schedule for all deliveries to the field. For example, it can document the 3-month plan; this plan should be updated more frequently than the look-ahead period, to keep it current with any changes in priorities. 4. Life-cycle Costs and Maintenance Budgets Based on the staffing, equipment needs, and processes to be included in maintenance, this section summarizes expected life-cycle costs for the product or system and outlines the budget requirements for executing the maintenance. 5. System/Product Design Implications from the Maintenance Concept and Processes As this plan is developed, the team is thinking through how the system will be maintained and supported. This planning process will provide insights that must be communicated to the design team. For example, the maintenance concept and process details may require that specific diagnostic tools be created or certain error codes are included in the software. 6. Performance Monitoring and Management during the Maintenance Phase 1. Measures of Performance:-Whether the maintenance activities are conducted by in-house personnel or contracted out, there are several measures of performance that can be used to determine the state of the original system when released, as well as the effectiveness of ongoing maintenance. These include:  Mean time between failures – the average time between device failures, usually expressed in      hours. Mean time to repair – the average time to repair (or replace) a device, typically this includes the response time, expressed in hours. System Availability – the time that the system provides its designed functionality, expressed in hours. Typically, this excludes scheduled downtime due to maintenance or system administration activities. System Reliability – similar to Availability, but expressed as the probability that the system will be available. User help-desk inquiries – measure of how much support users required. Defects reported – measure of how many problems were discovered after release. 2. Monitoring of Customer Satisfaction – Regular Reviews This section documents how customer satisfaction with system performance will be assessed as part of the maintenance process. The goal is to have up-to-date understanding of the needs of the customer, the perceived performance of the current system, and to identify possible future applications to incorporate into future releases. Although it is expected that users will raise issues through the issues reporting or enhancement request system, the goal of this section is to also identify a regular overarching review process with the users—periodically scheduling a time to review status and solicit input for improvements. This section of the plan should include:  How the measures of performance above will be measured at customers  Frequency of reviewing enhancement request database  Frequency and types of regular reviews with customers, including not only system functionality, but also any new needs for training or documentation  How issues or requests raised in these forums will be prioritized and assigned and how results communicated to the customer. 3. Performance Reports This section calls out what reports should be produced regularly as part of the above processes, what they should contain, and who should receive them. 4. Managing Execution of the Maintenance Plan With the maintenance plan developed, approved, and funded, there must be a structured practice for managing the plan. The basics of plan management are similar to other practices and should include:  Performance Monitoring: Regular checking of plan metrics and budgets against the maintenance plan projections, as documented in 5.1 above  Oversight Support: Support of the plan over time and its relationship to training, and staffing issues  On-going Multi-year Planning: Plan for changes in system components, emerging issues, changes in the process and new or evolving needs of stakeholders. Check that the level of effort and resources are appropriate to support a multi-year maintenance program plan.  Operational Needs: Check that the maintenance concept is consistent with operational concept. What is Maintenance  Function of system/equipment is to provide desired output at desired quality with control on hazards to safety of man / machine / environment.  Maintenance is the combination of all technical and associated administrative actions intended to retain an item in, or restore it to, a state in which it can perform its required function throughout its life cycle. as user wants them to do under present operating context. Cost ImProper Maintenance Effect of improper maintenance is reflected in terms of financial loss due to many factors. These are –  Increase in machine down time,  Loss of production,  Loss of potential sales,  Idle man power - direct and indirect labours  Feeding delays - stopping of the further lines.  Increased scrap of off-standard unit.  Quality loss, Customer's dissatisfaction possible delays  Loss of goodwill and Actual cost of repair of equipment. What is Maintenance Management “Organizing Maintenance Operation” Objectives of a Maintenance Management System:1. To provide a Maintenance Management programme that will allow maximum operating time and use of facilities, at a min. maintenance cost and with proper protection of capital investment. 2. To provide a means of collecting cost and other information that will be useful in improving maintenance and other performance. 3. To establish methods of evaluating work performance which will be useful to management in general and to maintenance engineer in particular. 4. To improve safe working conditions for both operating department and maintenance personnel by establishing and keeping proper maintenance standards. Basic element of a general Management System 1) Establishing policies & objective 2) Defining responsibilities and authority. 3) Planning actions. 4) Setting up accounting and budgeting procedures. 5) Securing and controlling funds. 6) Staffing and training. 7) Detailing and defining work groups. 8) Conducting performance review and evaluation. WMS/CMMS: Tried at generation (CMMS was implemented at SBI & CCPP during 1990) but  could not sustain primarily due to its non-linkage  of data entry with the direct business process, non  integration with associated business processes &  subsequently software functional limitation &  technology obsolescence. EAM: In the long term & present requirement of  the integration of various function, a mid range  solution (EAM) allowing to fulfill present needs & remaining scalable for future enhancement &  further seamless integration. ERP: Present implementation & design shall be  adaptable to migrate to ERP solution in future. Streamlining CMMS Broad Interface for CMMS Features  Maintenance requests/orders can be created online by operation/production operators manually.  “Or” are triggered automatically by time based preventive maintenance schedules already fed to the system.  “Or” are triggered based on the operating parameters or Measurement data entered going beyond specified limits.(Condition based maintenance request)  Maintenance requests/orders can be viewed/accepted by maintenance crew from their computer node.  Further Isolation/permission required to work with operating staff is communicated on their nodes.  Work completion can be notified online  Data related to manpower used, work carried out,spares used are entered in to a system by maintenance staff to create maintenance history for the equipment Advantages-CMMS Facilitates  Work order management  Work crew planning & scheduling  Resources planning & scheduling  Maintenance schedule/period planning  Authorization planning  Ready details available from system for parameters, equipment details, grouping structure,analysis & review, history details for defect or equipment, trouble shooting, Standard operating/maintenance procedures, critical spares details,drawing details,actual resource consumption,contract work details,shut down jobs/ project work details,inspection/lubrication schedules,safety guidelines, safety permits & line clearance permit details,work execution & completion details, material planning,planned cost v/s actual cost for work order STATUTORY REQUIREMENTS FOR TRAINED MANPOWER Introduction About the Indian Electricity Rules, 1956 The Indian Electricity (IE) Rules, 1956 was enacted as per section 37 of the Indian Electricity Act. 1910 in order to regulate the generation, transmission, supply and use of electrical energy and generally to carry out the purposes and objects of the above said Act. The IE Rules, 1956 is a 143 rules document with eleven chapters and fourteen Annexure. Some of the salient features of IE rules are being discussed below: Salient Features of Indian Electricity Rules, 1956: 1. 2. 3. 4. 5. 6. 7. 8. 9. Chapter-1 highlights the preliminary definitions to be used hereby in the document. Chapter-2 highlights the functions and responsibilities of an electrical inspector and the requirements for the same. Chapter-3 highlights the role of the license and states the limits for the area of supply for the licensee. Chapter-4 and Chapter-5 envisages upon the general safety requirements and general conditions relating to the supply and use of electricity respectively. Chapter- 6 deals with the electric supply lines, systems and apparatus for low and medium voltages; while Chapter-7 deals the same for high and extra high voltages. Chapter-8 deals with the technical requirements to be met by the laying down of the overhead lines. Chapter-9 gives the rules to be followed for lying down of electric traction. Chapter-10 deals with the additional precautions to be adopted in mines and oil fields. Chapter-11 discusses the various miscellaneous activities, ranging from relaxation by government and inspector to various penalties to be imposed for the breach of rules. In lieu with the captive generation being taken up after the enactment of Indian Electricity Act, 2003, it is necessary to discuss Article 3 (2A). Article 3 (2A): “a) No person shall be authorized to operate or undertake maintenance of any part or whole of a generating station of capacity 100MW and above together with the associated sub-station unless he is adequately qualified and has successfully undergone the type of training specified in Annexure XIV; Provided that the provisions contained in this sub-rule shall have effect in respect of the persons already authorized to operate or undertake maintenance of any part or whole of a generating station as aforesaid from the date to be specified by the appropriate Government, but such a date shall not be later than a period of 4[6 years 2 months] from the date this rule comes into force; (b)The appropriate Government may, on the recommendations of the owner of such generating station, relax the conditions stipulated in clause (a) of this sub-rule for any engineer and such other person who have already sufficient experience in the operation and maintenance of a generating station; (c)The owner of a generating station, in consultation with Central Electricity Authority may alter the duration and manner of training in respect of those persons who have already been engaged in the operation and maintenance of a generating station or a substation;” Article- 3 (2B) “The provisions contained in rule 3(2A) will also be applicable in respect of other sub-stations of 132KV and above from a date to be specified by the appropriate Government but such a date shall not be later than 3 years from which this rule comes into force;” The training aspects of the personnel in various generating stations are discussed in the Annexure XIV of the IE rules, 1956. Annexure- XIV “The owner of every generating station of capacity of 100MW and above shall arrange for training of personnel engaged in the operation and maintenance of his generating station, in the manner specified below:(1) (A) The training may be arranged in his own institute or any other institute established for this purpose. (b) Any institute where such training is arranged shall have been recognized by the Central Electricity Authority. (2) There shall be separate training courses for the persons to be engaged in operation and maintenance of thermal power stations and hydro power stations together with associated sub-stations. In respect of thermal stations, separate course may be arranged for the operating and supervisory staff and other skilled persons who are to assist them. (3) Refresher courses shall be arranged periodically for the persons who have already undergone training under and those who have already sufficient experience in the operation and maintenance of a generating station and are engaged in its operation and maintenance under clause (b) of sub-rule 2(A) of rule 3 to familiarize with modern practices of operation and maintenance. The content and duration of training in the thermal power stations is discussed in the later part of the Annexure- XIV: The duration of the training courses for the operating supervisory staff (both electrical and mechanical) shall not be less than 12 months.(186 hours) The duration of the training course for the skilled person to assist the operators and supervisory staff in a thermal power stations shall not be less than nine month.(82 hours) The duration of the training course for the operation and supervisory staff to work in hydro power stations shall not be less than nine months.(124 hours) The duration of the training course for operation and maintenance of the sub-station associated with the generating station shall not be less than six months. The duration and contents of the refresher course shall be determined jointly by the owner of the generating station and the training institute. Trained Manpower in Power Sector: The main objective of electricity industry is to achieve customer satisfaction through generation of electricity of the right quality and quantity at an affordable cost and supply to the consumers efficiently whenever and wherever required. Trained manpower is required at every stage of planning, design, engineering, procurement, handling and storage, commissioning, operation and maintenance of power • • • • • plants, sale of energy and collection of revenue. The growing concern over environmental degradation and depletion of the conventional energy sources has made the task more challenging. Due to the introduction of more sophisticated technology and automation, the Man/MW ratio is declining. The Man/MW ratio in thermal sector in India has declined from 4.71 in the Sixth plan to less than 2.0 in the Ninth plan. In the hydro sector too, the Man/MW ratio has come down from 6.04 in the Sixth plan to 2.0 in the Ninth plan. The same trend is evident in terms of the number of personnel/million units supplied - declining from 4.6 in 1992-93 to 2.5 in 2000-2001, a 45% decrease in eight years. This indicates the increasing importance of each individual, which in turn makes manpower quality criteria more demanding. Added to this is the fact that electricity industry is a highly capital intensive industry. This necessitates the operation of the plants and equipment in the most safe and efficient manner to minimize the cost of supply. To survive in this competitive market, organizations will have to challenge the existing core beliefs, processes and methodologies and focus on hands-on learning to inculcate the necessary knowledge, skills and attitudes in their personnel. Excerpts from the National Training Policy Basically three types of training infrastructures/facilities are available: i) Training institutes recognized by CEA for imparting statutory induction training. ii) Lineman Training Institutes iii) Other Training facility (Class/board rooms for refresher/management programs) including networking with academic/training institutions outside power sector. Decentralization of training, especially for the operational staff would be necessary. At the same time, expensive infrastructure need not be created at each plant level. There are thirty eight training institutes recognized by the Central Electricity Authority (CEA). These institutes mostly cater to the training needs of the thermal power stations. Other Training institutes at the National level includes National Power Training Institute, established a Centre for Advanced Management & Power Studies (CAMPS) at Faridabad. In addition to a number of short-term courses on Technology-Management interface, it also conducts a two-year full time MBA Program in Power Management. NPTI also conducts professional courses, integrating power-training experience with academics, like PDC & PGDC in Power Plant Engineering and B.E./B.Tech. in Power Engineering etc. These products should be gainfully utilized in the reforming power sector. Training Institutes in Power Sector recognized by CEA Region Owning Agency SL Name of the Institute A. Northern Region HINDALCO 1 Technical Training & Management Development Centre, HINDALCO, Renusagar, (U.P) Linemen Training Centre, Himachal Pradesh State Electricity Board, Solan (H.P.) Thermal 08/2008 Field Type Recognized up to HPSEB 2 T&D 08/2005 NHPC 3 4 5 6 NPTI 7 8 NTPC 9 10 11 12 13 Power Management Institute (PMI), Thermal, Hydro & 12/2007 Noida (U.P.) Power Management Employee Development Centre, Thermal 06/2009 Badarpur (Delhi) Employee Development Centre, Thermal 08/2008 Singrauli STPS, Singrauli (U.P.) Employees Development Centre, Thermal 08/2008 Rihand STPS, Rihand (U.P.) Employees Development Centre, Thermal 05/2009 National Capital Power Station, Dadri (U.P.) Employee Development Centre, 400KV Ballabgarh Sub-station, Ballabgarh (Haryana) Name of the Institute Employee Development Centre, 800/400/220 KV Sub-station, Kishenpur Thermal Training Institute, GGSSTPS, PSEB, Ropar (Punjab) Electricity Training Institute, U.P. Power Corporation Ltd, Lucknow (U.P.) Thermal Training Institute, Obra Thermal Power Station T&D 02/2005 NPTI (NR), Badarpur (Delhi) NPTI, Faridabad (Haryana) All Fields All Fields 10/2006 10/2009 Training Centre, Chamera Power Station -I, Chamba (H.P.) Training Centre Uri HEP, Baramulla (J&K) Training Centre, Salal HEP Udhampur (J&K) Training Centre Tanakpur Power Station, Champawat (Uttaranchal) Hydro Hydro Hydro Hydro 01/2008 04/2008 12/2007 12/2007 PGCIL 14 Region Owning Agency SL 15 Field Type T&D Recognized up to 02/2007 PSEB 16 UPPCL 17 UPRVUNL 18 B. Western Region Autonomous Society 19 Thermal 02/2007 T&D 02/2008 Thermal 04/2008 Centre for Research and Industrial Staff Performance Hydro 01/2008 CSEB 20 Power Generating Training Institute, Korba TPS, Chattsgarh SEB, Korba (East) (Chattsgarh) Koradi Training Centre, Koradi TPS, MSPGCL ,Kordi (Maharashtra) Training Research and Development Centre, Nashik TPS, MSEDCL, Nashik (Maharashtra) NPTI (WR), Nagpur (Maharashtra) Employees Development Centre, Korba STPS, Korba - 495 450 Employees Development Centre, Kawas GPS, Distt.Surat (Gujarat) Employee Development Centre, Vindhyachal STPS, Distt.Sidhi (M.P.) Employee Development Centre 400 KV Itarsi Sub-station, Itarsi (MP) Name of the Institute Thermal 03/2010 MAGAGENCO 21 MAHADISCOM 22 Thermal &T&D 07/2007 Thermal 03/2009 NPTI 23 NTPC 24 25 26 PGCIL 27 T&D 01/2007 Thermal Gas Thermal 06/2009 04/2007 08/2008 All Fields 05/2006 Region Owning Agency SL Field Type Recognized upto REL 28 Technical Training Centre, Dahanu TPS, Reliance Energy Ltd, Thane (Maharashtra) Reliance Energy Management Institute, Reliance Energy Ltd., Mumbai (Maharashtra) Versova Technical Training Centre, Reliance Energy Ltd, Mumbai Main Training Center Trombay Thermal Power Station, Tata Power Company, Mumbai (Maharashtra) Plant Training Centre, Bhira Hydro Generating Station, Bhira Plant Training Centre at Dharvi Receiving Station, Tata Power Company, Mumbai (Maharashtra) Thermal 09/2007 29 Power Management 05/2008 30 Tata Power Co. 31 Thermal 01/2009 Thermal 04/2007 32 33 Hydro Thermal 09/2007 04/2007 Torrent Power AEC 34 C. Southern Region APGENCO 35 KSEB 36 NLC 37 NPTI 38 39 NTPC 40 Training Centre Sabarmati PS, Torrent Power AEC, Ahmadabad (Gujarat) Thermal 03/2007 Training Institute, Vijay Wada TPS APGENCO, (AP) Power Engineers' Training & Research Centre, Moolamattom (KSEB) Thermal Power Station Training Centre, Neyveli (T.N.) Power System Training Institute, Bangalore (Karnataka) NPTI (SR), Neyveli (T.N.) Employee Development Centre, Ramagundam STPS, Distt. Karim Nagar (A.P.) Name of the Institute Thermal 11/2009 Thermal 11/2009 Thermal 05/2008 T&D Thermal and T&D Thermal 04/2007 07/2006 12/2008 Region Owning Agency SL Field Type Recognized upto PGCIL 41 TNEB 42 43 44 Thermal Training Institute, Vallur Camp North Chennai TPS, TNEB Hydro Training Institute, TNEB Kuthiraikalmedu, Distt. Erode (T.N.) Transmission and Sub-station Training & Development Institute, TNEB, Madurai (T.N.) Thermal Hydro T&D 03/2010 08/2009 06/2008 Employee Development Centre, 400KV Sub-station, Hyderabad (A.P.) T&D 10/2006 D. Eastern Region CESC Ltd, Kolkata 45 DVC 46 OPTCL 47 O&M Training Centre, CESC Ltd., Kolkata (WB) Training Institute at Chandrapura TPS, Distt. Bokaro (Jharkhand) Power Training Centre at Chandaka, Power Grid Corporation of Orissa Ltd., Bhubaneshwar (Orissa) Thermal 12/2006 Thermal 05/2009 T&D 12/2007 NPTI 48 NTPC 49 Orissa HPCL 50 SAIL 51 WBPDCL 52 Power Plant Training Simulator Centre at Bakreswar Thermal Power Station Thermal 05/2008 Central Power Training Institute at Rourekela (Orissa) Thermal 11/2008 OHP Training Centre, Orissa Hydro 02/2008 Employee Development Centre, Farakka STPS, Distt. Murshidabad Thermal 07/2007 NPTI(ER), Durgapur All Fields 06/2006 Categories of Training: • Training for the Foreman engaged in the operation and maintenance of thermal power stations. • Training for the Foreman engaged in the mechanical works of the thermal power stations. • Training for the Foreman engaged in the electrical works of the thermal power stations. • Training for the lineman for assisting the operation and maintenance of thermal power stations. • Training for the lineman engaged in mechanical works of the thermal power stations. • Training for the lineman engaged in the operation and maintenance of hydro-electric generating station. • Specialized training for the personnel engaged in the extra high voltage sub-station. The main thrust in the training of a foreman lies in operation, control and supervision of boilers, turbines, excitation systems, auxiliaries and other major equipments of a thermal power plant. Also, the focus will be on the conceptual orientation of generators, turbines, fault analysis and protection of transformers. The main thrust in the training of operating and supervisory staff lies in the conceptual orientation of modern thermal power stations, its layout, construction details of various boilers and turbines. Along with major equipments, the training is provided for the maintenance of all the auxiliaries in the power stations. Also, the trainee is well equipped with the Indian Boiler Rules, Factory Act, Indian Electricity Act, 1910. The other part of the training revolves around the following areas: • Coal Handling Plant. • Details of switchgear engineering. • Basic flow diagrams in a power plant- fuel cycle, air and gas cycle, bearing cooling systems • Principles of material management and inventory control. The training for the operating personnel in a hydro station undergoes a specialized course of which the following are the highlights: • Concept of a modern hydro station. • Hydraulic systems- reservoirs, surge tanks, water tunnels, penstocks. • Types of water turbines. • Specifications of generators- Types and ratings. • Protection of generators and transformers • Excitation systems. • Statutory Electricity Acts and Rules The assessment for all the training courses is on the basis of 100 marks. Training for Franchise Development: The training institutes/organizations have often not taken up the task of marketing training as a major element of personnel management system aimed at raising the productivity within an organization. Training Institutes and training managers must consider training as a service they are offering to the various customers, which need to be marketed like any other service. The principles of marketing a service effectively hence, need to be used extensively by them. Creation of awareness about availability of training facilities shall be the first step in this direction. The second step will be to highlight the contribution of training towards improving productivity of individuals and thereby organizations. Training Institutes should evolve a mechanism to be in constant touch with the customer organizations to continuously upgrade, match the course contents with the specific needs of the organization and use innovative methods to deliver the training inputs. Looking Ahead in the Eleventh Plan (2007-2012): With the enactment of the Act, the message is clear that major emphasis would be laid on private developers and to mitigate the challenges posed by the competitors, firms would invest heavily in manpower. Therefore, the training and development programs will be accounting for at least 1.5 % of the total investment in the power sector. Factory Act The workings of the factories act, 1934, which was in operation prior to 1948, was found unsatisfactory & its provision inadequate in the changed conditions of growing industrial activities. Hence the comprehensive factories act was enacted in 1948 to ensure adequate safety measures & to promote the health & welfare of the workers employed in factories. It also seeks to prevent haphazard growth of factories through the provisions therein relating to the approval of the plans by the chief inspector of factories before the erection of a factory building is started. The extends to the whole of India & applies to all establishments employing 20 or more workers where power is used & to establishments employing 20 or more workers where power is not used. The main provisions of the act, inter alia, relate to (i) health, safety & welfare; (ii) hours of work; (iii) employment of young persons & women; (iv) annual leave with wages; (v) occupational diseases; (vi) administration; (vii) enforcement; and (viii) penalties for offences. The detailed provisions on the above aspects are fairly exhaustive. Factories employing 500 or more workers are required to appoint Labor Welfare officers to look after the welfare of workers. The state Govt. is empowered to prescribe the duties, qualifications & service conditions of these officers. It is also empowered to order the management of any factory or class of factories to associate the representatives of employees in matters relating to provision of welfare facilities. Under the act, the maximum hours of work for adult workers have been fixed at 48 hours per week, and 8 hours per day spread over 10½ hours in a day, inclusive of intervals. Employment of women and children (below 17 years) is prohibited during the night (7pm to 6pm) Energy Conservation and its Importance Coal and other fossil fuels, which have taken three million years to form, are likely to deplete soon. In the last two hundred years, we have consumed 60% of all resources. For sustainable development, we need to adopt energy efficiency measures. Today, 85% of primary energy comes from non-renewable and fossil sources (coal, oil, etc.). These reserves are continually diminishing with increasing consumption and will not exist for future generations What is Energy Conservation? Energy Conservation and Energy Efficiency are separate, but related concepts. Energy conservation is achieved when growth of energy consumption is reduced, measured in physical terms. Energy Conservation can, therefore, is the result of several processes or developments, such as productivity increase or technological progress. On the other hand Energy efficiency is achieved when energy intensity in a specific product, process or area of production or consumption is reduced without affecting output, consumption or comfort levels. Promotion of energy efficiency will contribute to energy conservation and is therefore An integral part of energy conservation promotional policies. Energy efficiency is often viewed as a resource option like coal, oil or natural gas. It provides additional economic value by preserving the resource base and reducing pollution. For example, replacing traditional light bulbs with Compact Fluorescent Lamps (CFLs) means you will use only 1/4th of the energy to light a room. Pollution levels also reduce by the same amount. Nature sets some basic limits on how efficiently energy can be used, but in most cases our products and manufacturing processes are still a long way from operating at this theoretical limit. Very simply, energy efficiency means using less energy to perform the same function. Although, energy efficiency has been in practice ever since the first oil crisis in 1973, it has today assumed even more importance because of being the most cost-effective and reliable means of mitigating the global climatic change. Recognition of that potential has led to high expectations for the control of future CO2 emissions through even more energy efficiency improvements than have occurred in the past. The industrial sector accounts for some 41 per Cent of global primary energy demand and approximately the same share of CO2 emissions. Policy Framework - Energy Conservation Act - 2001 With the background of high energy saving potential and its benefits, bridging the gap between demand and supply, reducing environmental emissions through energy saving, and to effectively overcome the barrier, the Government of India has enacted the Energy conservation Act - 2001. The Act provides the much-needed legal framework and institutional arrangement for embarking on an energy efficiency drive. Under the provisions of the Act, Bureau of Energy Efficiency has been established with effect from 1st March 2002 by merging erstwhile Energy Management Centre of Ministry of Power. The Bureau would be responsible for implementation of policy programmes and coordination of implementation of energy conservation activities. Energy Conservation Opportunities in Boiler The various energy efficiency opportunities in boiler system can be related to combustion, heat transfer, avoidable losses, high auxiliary power consumption, water quality and lowdown. Examining the following factors can indicate if a boiler is being run to maximize its efficiency: 1. Stack Temperature The stack temperature should be as low as possible. However, it should not be so low that water vapour in the exhaust condenses on the stack walls. This is important in fuels containing significant sulphur as low temperature can lead to sulphur dew point corrosion. Stack temperatures greater than 200°C indicates potential for recovery of waste heat. It also indicates the scaling of heat transfer/recovery equipment and hence the urgency of taking an early shut down for water / flue side cleaning. 2. Feed Water Preheating using Economiser Typically, the flue gases leaving a modern 3-pass shell boiler are at temperatures of 200 to 300 °C. Thus, there is a potential to recover heat from these gases. The flue gas exit tempera-true from a boiler is usually maintained at a minimum of 200 °C, so that the sulphur oxides in The flue gases do not condense and cause corrosion in heat transfer surfaces. When a clean fuel Such as natural gas, LPG or gas oil is used, the economy of heat recovery must be worked out, and as the flue gas temperature may be well below 200 °C. The potential for energy saving depends on the type of boiler installed and the fuel used. For a typically older model shell boiler, with a flue gas exit temperature of 260 °C, an economizer could be used to reduce it to 200 °C, increasing the feed water temperature by 15 °C. Increase in overall thermal efficiency would be in the order of 3%. For a modern 3-pass shell boiler firing natural gas with a flue gas exit temperature of 140 °C a condensing economizer would reduce the exit temperature to 65 °C increasing thermal efficiency by 5%. 3. Combustion Air Preheat Combustion air preheating is an alternative to feed water heating. In order to improve thermal Efficiency by 1%, the combustion air temperature must be raised by 20 °C. Most gas and oil Burners used in a boiler plant are not designed for high air preheats temperatures. Modern burners can withstand much higher combustion air preheat, so it is possible to consider such units as heat exchangers in the exit flue as an alternative to an economizer, when neither pace or a high feed water return temperature make it viable. 4. Incomplete Combustion Incomplete combustion can arise from a shortage of air or surplus of fuel or poor distribution of fuel. It is usually obvious from the colour or smoke, and must be corrected immediately. In the case of oil and gas fired systems, CO or smoke (for oil fired systems only) with normal or high excess air indicates burner system problems. A more frequent cause of incomplete combustion is the poor mixing of fuel and air at the burner. Poor oil fires can result from improper viscosity, worn tips, carbonization on tips and deterioration of diffusers or spinner Plates. With coal firing, unburned carbon can comprise a big loss. It occurs as grit carry-over or carbon-inash and may amount to more than 2% of the heat supplied to the boiler. Non uniform fuel size could be one of the reasons for incomplete combustion. In chain grate stokers, large lumps will not burn out completely, while small pieces and fines may block the air passage, thus causing poor air distribution. In sprinkler stokers, stoker grate condition, fuel distributors, wind box air regulation and over-fire systems can affect carbon loss. Increase in the fines in pulverized coal also increases carbon loss. 5. Excess Air Control Excess air is required in all practical cases to ensure complete combustion, to allow for the Normal variations in combustion and to ensure satisfactory stack conditions for some fuels. The optimum excess air level for maximum boiler efficiency occurs when the sum of the losses due to incomplete combustion and loss due to heat in flue gases is minimum. This level varies with furnace design, type of burner, fuel and process variables. It can be determined by conducting tests with different air fuel ratios. 6. Radiation and Convection Heat Loss The external surfaces of a shell boiler are hotter than the surroundings. The surfaces thus lose Heat to the surroundings depending on the surface area and the difference in temperature Between the surface and the surroundings. The heat loss from the boiler shell is normally a fixed energy loss, irrespective of the boiler output. With modern boiler designs, this may represent only 1.5% on the gross calorific value at full rating, but will increase to around 6%, if the boiler operates at only 25 percent output. Repairing or augmenting insulation can reduce heat loss through boiler walls and piping. 7. Automatic Blow down Control Uncontrolled continuous blow down is very wasteful. Automatic blow down controls can be Installed that sense and respond to boiler water conductivity and pH. A 10% blow down in a 15kg/cm2 boiler results in 3% efficiency loss. 8. Reduction of Scaling and Soot Losses In oil and coal-fired boilers, soot build-up on tubes acts as an insulator against heat transfer. Any such deposits should be removed on a regular basis. Elevated stack temperatures may indicate excessive soot build-up. Also same result will occur due to scaling on the water side. High exit gas temperatures at normal excess air indicate poor heat transfer performance. This condition can result from a gradual build-up of gas-side or waterside deposits. Waterside deposits require a review of water treatment procedures and tube cleaning to remove deposits. An estimated 1% efficiency loss occurs with every 22 °C increase in stack temperature. Stack temperature should be checked and recorded regularly as an indicator of soot deposits. When the flue gas temperature rises about 20 °C above the temperature for a newly cleaned boiler, it is time to remove the soot deposits. It is, therefore, recommended to install a dial type thermometer at the base of the stack to monitor the exhaust flue gas temperature. It is estimated that 3 mm of soot can cause an increase in fuel consumption by 2.5% due to increased flue gas temperatures. Periodic off-line cleaning of radiant furnace surfaces, boiler Tube banks, economizers and air heaters may be necessary to remove stubborn deposits. 9. Reduction of Boiler Steam Pressure This is an effective means of reducing fuel consumption, if permissible, by as much as 1 to 2%. Lower steam pressure gives a lower saturated steam temperature and without stack heat Recovery, a similar reduction in the temperature of the flue gas temperature results. Steam is generated at pressures normally dictated by the highest pressure / temperature requirements for a particular process. In some cases, the process does not operate all the time, and there are periods when the boiler pressure could be reduced. The energy manager should consider pressure reduction carefully, before recommending it. Adverse effects, such as an increase in water carryover from the boiler owing to pressure reduction, may negate any potential saving. Pressure should be reduced in stages, and no more than a 20 percent reduction should be considered. 10. Variable Speed Control for Fans, Blowers and Pumps Variable speed control is an important means of achieving energy savings. Generally, combustion air control is affected by throttling dampers fitted at forced and induced draft fans. Though dampers are simple means of control, they lack accuracy, giving poor control characteristics at the top and bottom of the operating range. In general, if the load characteristic of the boiler is variable, the possibility of replacing the dampers by a VSD should be evaluated. 11. Effect of Boiler Loading on Efficiency The maximum efficiency of the boiler does not occur at full load, but at about two-thirds of the full load. If the load on the boiler decreases further, efficiency also tends to decrease. At zero output, the efficiency of the boiler is zero, and any fuel fired is used only to supply the losses. The factors affecting boiler efficiency are: • As the load falls, so does the value of the mass flow rate of the flue gases through the tubes. This reduction in flow rate for the same heat transfer area reduced the exit flue gas temperatures by a small extent, reducing the sensible heat loss. • Below half load, most combustion appliances need more excess air to burn the fuel Completely. This increases the sensible heat loss In general, efficiency of the boiler reduces significantly below 25% of the rated load and as far as possible, and operation of boilers below this level should be avoided 12. Proper Boiler Scheduling Since, the optimum efficiency of boilers occurs at 65–85% of full load, it is usually more Efficient, on the whole, to operate a fewer number of boilers at higher loads, than to operate a Large number at low loads. 13. Boiler Replacement The potential savings from replacing a boiler depend on the anticipated change in overall Efficiency. A change in a boiler can be financially attractive if the existing boiler is: _ Old and inefficient _ Not capable of firing cheaper substitution fuel _ Over or under-sized for present requirements _ Not designed for ideal loading conditions The feasibility study should examine all implications of long-term fuel availability and Company growth plans. All financial and engineering factors should be considered. Since boiler plants traditionally have a useful life of well over 25 years, replacement must be carefully studied. Energy Saving Opportunities in steam 1. Monitoring Steam Traps For testing a steam trap, there should be an isolating valve provided in the downstream of the trap and a test valve shall be provided in the trap discharge. When the test valve is opened, the following points have to be observed: Condensate discharge––Inverted bucket and thermodynamic disc traps should have intermittent condensate discharge. Float and thermostatic traps should have a continuous ondensate discharge. Thermostatic traps can have either continuous or intermittent discharge depending upon the load. If inverted bucket traps are used for extremely small load, it will have a continuous condensate discharge. Flash steam––This shall not be mistaken for a steam leak through the trap. The users sometimes get confused between a flash steam and leaking steam. The flash steam and the leaking steam can be approximately identified as follows: • If steam blows out continuously in a blue stream, it is a leaking steam. • If a steam floats out intermittently in a whitish cloud, it is a flash steam. 2. Continuous steam blow and no flow indicate, there is a problem in the trap Whenever a trap fails to operate and the reasons are not readily apparent, the discharge from the trap should be observed. A step-by-step analysis has to be carried out mainly with reference to lack of discharge from the trap, steam loss, continuous flow, sluggish heating, to find out whether it is a system problem or the mechanical problem in the steam trap. 3. Avoiding Steam Leakages Steam leakage is a visible indicator of waste and must be avoided. It has been estimated that a 3 mm diameter hole on a pipeline carrying 7 kg/cm2 steam would waste 33 KL of fuel oil per year. Steam leaks on high-pressure mains are prohibitively costlier than on low pressure mains. Any steam leakage must be quickly attended to. In fact, the plant should consider a regular surveillance programme for identifying leaks at pipelines, valves, flanges and joints. Indeed, by plugging all leakages, one may be surprised at the extent of fuel savings, which may reach upto 5% of the steam consumption in a small or medium scale industry or even higher in installations having several process departments. To avoid leaks it may be worthwhile considering replacement of the flanged joints which are rarely opened in old plants by welded joints. 4. Providing Dry Steam for Process The best steam for industrial process heating is the dry saturated steam. Wet steam reduces total heat in the steam. Also water forms a wet film on heat transfer and overloads traps and Condensate equipment. Super heated steam is not desirable for process heating because it gives up heat at a rate slower than the condensation heat transfer of saturated steam. It must be remembered that a boiler without a super heater cannot deliver perfectly dry saturated steam. At best, it can deliver only 95% dry steam. The dryness fraction of steam depends on various factors, such as the level of water to be a part of the steam. Indeed, even as simple a thing as improper boiler water treatment can become a cause for wet steam. As steam flows through the pipelines, it undergoes progressive condensation due to the loss of heat to the colder surroundings; the extent of the condensation depends on the effectiveness of the lagging. For example, with poor lagging, the steam can become excessively wet. Since dry saturated steam is required for process equipment, due attention must be paid to the boiler operation and lagging of the pipelines. Wet steam can reduce plant productivity and product quality, and can cause damage to most items of plant and equipment. Whilst careful drainage and trapping can remove most of the water, it will not deal with the water droplets suspended in the steam. To remove these suspended water droplets, separators are installed in steam pipelines. 5. Utilising Steam at the Lowest Acceptable Pressure for the Process A study of the steam tables would indicate that the latent heat in steam reduces as the steam pressure increases. It is only the latent heat of steam, which takes part in the heating process When applied to an indirect heating system. Thus, it is important that its value be kept as high as possible. This can only be achieved if we go in for lower steam pressures. As a guide, the steam should always be generated and distributed at the highest possible pressure, but utilized at as low a pressure as possible since it then has higher latent heat. However, it may also be seen from the steam tables that the lower the steam pressure, the lower will be its temperature. Since temperature is the driving force for the transfer of heat at lower steam pressures, the rate of heat transfer will be slower and the processing time greater. In equipment where fixed losses are high (e.g. big drying cylinders), there may even be an increase in steam consumption at lower pressures due to increased processing time. There are, however, several equipment in certain industries where one can profitably go in for lower Pressures and realize economy in steam consumption without materially affecting production time. Therefore, there is a limit to the reduction of steam pressure. Depending on the equipment design, the lowest possible steam pressure with which the equipment can work should be selected without sacrificing either on production time or on steam consumption. 6. Proper Utilization of Directly Injected Steam The heating of a liquid by direct injection of steam is often desirable. The equipment required is relatively simple, cheap and easy to maintain. No condensate recovery system is necessary. The heating is quick, and the sensible heat of the steam is also used up along with the latent heat, making the process thermally efficient. In processes where dilution is not a problem, heating is done by blowing steam into the liquid (i.e.) direct steam injection is applied. If the dilution of the tank contents and agitation are not acceptable in the process (i.e.)direct steam agitation are not acceptable, indirect steam heating is the only answer. Ideally, the injected steam should be condensed completely as the bubbles rise through the liquid. This is possible only if the inlet steam pressures are kept very low-around 0.5 kg/cm2 -and certainly not exceeding 1kg/cm2. If pressures are high, the velocity of the steam bubbles will also be high and they will not get sufficient time to condense before they reach the surface. 7. Minimising Heat Transfer Barriers The metal wall may not be the only barrier in a heat transfer process. There is likely to be a film of air, condensate and scale on the steam side. On the product side there may also be baked-on product or scale, and a stagnant film of product. Agitation of the product may eliminate the effect of the stagnant film, whilst regular cleaningon the product side should reduce the scale. 8. Proper Air Venting When steam is first admitted to a pipe after a period of shutdown, the pipe is full of air. Further amounts of air and other non-condensable gases will enter with the steam, although the proportions of these gases are normally very small compared with the steam. When the steam condenses, these gases will accumulate in pipes and heat exchangers. Precautions should be taken to discharge them. The consequence of not removing air is a lengthy warming up period, and a reduction in plant efficiency and process performance. Air in a steam system will also affect the system temperature. Air will exert its own pressure within the system, and will be added to the pressure of the steam to give a total pressure. Therefore, the actual steam pressure and temperature of the steam/air mixture will be lower than that suggested by a pressure gauge. Of more importance is the effect air has upon heat transfer. A layer of air only 1 mm thick can offer the same resistance to heat as a layer of water 25 μm thick, a layer of iron 2 mm thick or a layer of copper 15 mm thick. It is very important therefore to remove air from any steam system. Automatic air vents for steam systems (which operate on the same principle as thermostatic steam traps) should be fitted above the condensate level so that only air or steam/air mixtures can reach them. The discharge from an air vent must be piped to a safe place. In practice, a condensate line falling towards a vented receiver can accept the discharge from an air vent. In addition to air venting at the end of a main, air vents should also be fitted 9. Condensate Recovery The steam condenses after giving off its latent heat in the heating coil or the jacket of the Process equipment. A sizable portion (about 25%) of the total heat in the steam leaves the Process equipment as hot water. 10. Insulation of Steam Pipelines and Hot Process Equipments Heat can be lost due to radiation from steam pipes. As an example while lagging steam pipes, It is common to see leaving flanges uncovered. An uncovered flange is equivalent to leaving 0.6 metre of pipe line unlagged. If a 0.15 m steam pipe diameter has 5 uncovered flanges, there would be a loss of heat equivalent to wasting 5 tons of coal or 3000 litres of oil a year. This is usually done to facilitate checking the condition of flange but at the cost of considerable heat loss. The remedy is to provide easily detachable insulation covers, which can be easily removed when necessary. The various insulating materials used are cork, Glass wool, Rock wool and Asbestos. 11. Flash Steam Recovery Flash steam is produced when condensate at a high pressure is released to a lower pressure and can be used for low pressure heating. The higher the steam pressure and lower the flash steam pressure the greater the quantity of flash steam that can be generated. In many cases, flash steam from high pressure equipments is made use of directly on the low pressure equipments to reduce use of steam through pressure reducing valves. 12. Reducing the Work to be done by Steam The equipments should be supplied with steam as dry as possible. The plant should be made efficient. For example, if any product is to be dried such as in a laundry, a press could be used to squeeze as much water as possible before being heated up in a dryer using steam. therefore, to take care of the above factors, automatic draining is essential and can be achieved by steam traps. The trap must drain condensate, to avoid water hammer, thermal shock and reduction in heat transfer area. The trap should also evacuate air and other non-condensable gases, as they reduce the heat transfer efficiency and also corrode the equipment. Thus, a steam trap is an automatic valve that permits passage of condensate, air and other non-condensable gases from steam mains and steam using equipment, while preventing the loss of steam in the distribution system or equipment. TIPS FOR ENERGY EFFICIENCY IN THERMAL UTILITIES Boilers • Preheat combustion air with waste heat. (22°C reduction in flue gas temperature increases boiler efficiency by 1%) • Use variable speed drives on large boiler combustion air fans with variable flows. • Burn wastes if permitted. • Insulate exposed heated oil tanks. • Clean burners, nozzles, strainers, etc. • Inspect oil heaters for proper oil temperature. • Close burner air and/or stack dampers when the burner is off to minimize heat loss up the stack. • Improve oxygen trim control (e.g. -- limit excess air to less than 10% on clean fuels). (5% reduction in excess air increases boiler efficiency by 1% or: 1% reduction of residual oxygen in stack gas increases boiler efficiency by 1%) • Automate/optimize boiler blow down. Recover boiler blow down heat. • Use boiler blow down to help warm the back-up boiler. • Optimize deaerator venting. • Inspect door gaskets. • Inspect for scale and sediment on the water side. (A 1 mm thick scale (deposit) on the water side could increase fuel consumption by 5 to 8%.) • Inspect for soot, fly ash, and slag on the fire side. (A 3 mm thick soot deposition on the heat transfer surface can cause an increase in fuel Consumption to the tune of 2.5%) • Optimize boiler water treatment. • Add an economizer to preheat boiler feed water using exhaust heat. • Recycle steam condensate. • Study part-load characteristics and cycling costs to determine the most-efficient mode for Operating multiple boilers. • Consider multiple or modular boiler units instead of one or two large boilers. • Establish a boiler efficiency-maintenance program. Start with an energy audit and follow-up, then make a boiler efficiency-maintenance program a part of your continuous energy Management program. Steam System • Fix steam leaks and condensate leaks. (A 3 mm diameter hole on a pipe line carrying 7 Kg/cm2 steam would waste 33 Kilo litres of fuel oil per year) • Accumulate work orders for repair of steam leaks that can't be fixed during the heating season due to system shutdown requirements. Tag each such leak with a durable tag with a good description. • Use back pressure steam turbines to produce lower steam pressures. • Use more-efficient steam desuperheating methods. • Ensure process temperatures are correctly controlled. • Maintain lowest acceptable process steam pressures. • Reduce hot water wastage to drain. • Remove or blank off all redundant steam piping. • Ensure condensate is returned or re-used in the process. (6°C raise in feed water temperature by economiser/condensate recovery corresponds to a 1% saving in fuel consumption, in boiler) • Preheat boiler feed-water. • Recover boiler blow down. • Check operation of steam traps. • Remove air from indirect steam using equipment (0.25 mm thick air film offers the same resistance to heat transfer as a 330 mm thick copper Wall) • Inspect steam traps regularly and repair malfunctioning traps promptly. • Consider recovery of vent steam (e.g. -- on large flash tanks). • Use waste steam for water heating. • Use an absorption chiller to condense exhaust steam before returning the condensate to the boiler. • Use electric pumps instead of steam ejectors when cost benefits permit • Establish a steam efficiency-maintenance program. Start with an energy audit and followup, then make a steam efficiency-maintenance program a part of your continuous energy management program. Furnaces • Check against infiltration of air: Use doors or air curtains • Monitor O2 /CO2/CO and control excess air to the optimum level • Improve burner design, combustion control and instrumentation. • Ensure that the furnace combustion chamber is under slight positive pressure • Use ceramic fibres in the case of batch operations • Match the load to the furnace capacity • Retrofit with heat recovery device • Investigate cycle times and reduce • Provide temperature controllers • Ensure that flame does not touch the stock Insulation • Repair damaged insulation. (A bare steam pipe of 150 mm diameter and 100 m length, carrying saturated steam at 8 kg/cm2 would waste 25,000 litres furnace oil in a year) • Insulate any hot or cold metal or insulation. • Replace wet insulation. • Use an infrared gun to check for cold wall areas during cold weather or hot wall areas during hot weather. • Ensure that all insulated surfaces are cladded with aluminium • Insulate all flanges, valves and couplings • Insulate open tanks (70% heat losses can be reduced by floating a layer of 45 mm diameter polypropylene (Plastic) balls on the surface of 90°C hot liquid/condensate) Waste heat recovery • Recover heat from flue gas, engine cooling water, engine exhaust, low pressure waste Steam, drying oven exhaust, boiler blow down, etc. • Recover heat from incinerator off-gas. • Use waste heat for fuel oil heating, boiler feed water heating, outside air heating, etc. • Use chiller waste heat to preheat hot water. • Use heat pumps. • Use absorption refrigeration. • Use thermal wheels, run-around systems, heat pipe systems, and air-to-air exchangers. THE CONTRACT LABOUR (REGULATION AND ABOLITION) ACT, 1970 ACT NO. 37 OF 19701 [5th September, 1970.] An Act to regulate the employment of contract labour in certain establishments and to provide for its abolition in certain circumstances and for matters connected therewith. PRELIMINARY 1. Short title, extent, commencement and application (1) This Act may be called the Contract Labour (Regulation and Abolition) Act, 1970. (2) It extends to the whole of India. (3) It shall come into force on such date 1* as the Central Government may, by notification in the Official Gazette, appoint and different dates may be appointed for different provisions of this Act. (4) It applies-(a) To every establishment in which twenty or more workmen are employed or were employed on any day of the preceding twelve months as contract labour; (b) to every contractor who employees or who employed on any day of the preceding twelve months twenty or more workmen: Provided that the appropriate Government may, after giving not less than two months' notice of its intention so to do, by notification in the Official Gazette, apply the provisions of this Act to any establishment or contractor employing such number of workmen less than twenty as may be specified in the notification. (5) (a) It shall not apply to establishments in which work only of an intermittent or casual nature is performed. (b) If a question arises whether work performed in an establishment is of an intermittent or casual nature, the appropriate Government shall decide that question after consultation with the Central Board or, as the case may be, a State Board, and its decision shall be final. Explanation. -- For the purpose of this sub-section, work performed in an establishment shall not be deemed to be of an intermittent nature: (i) if it was performed for more than one hundred and twenty days in the preceding twelve months, or (ii) if it is of a seasonal character and is performed for more than sixty days in a year. 2. Definitions. - (1) In this Act, unless the context otherwise requires,-- 2[(a) "appropriate Government" means,-(i) in relation to an establishment in respect of which the appropriate Government under the Industrial Disputes Act, 1947 (14 of 1947), is the Central Government, the Central Government; (ii) in relation to any other establishment, the Government of the State in which that other establishment is situated;] (b) a workman shall be deemed to be employed as "contract labour" in or in connection with the work of an establishment when he is hired in or in connection with such work by or through a contractor, with or without the knowledge of the principal employer; (c) "contractor", in relation to an establishment, means a person who undertakes to produce a given result for the establishment, other than a mere supply of goods of articles of manufacture to such establishment, through contract labour or who supplies contract labour for any work of the establishment and includes a sub-contractor; (d) "controlled industry" means any industry the control of which by the Union has been declared by any Central Act to be expedient in the public interest; (e) "establishment" means-(i) any office or department of the Government or a local authority, or (ii) any place where any industry, trade, business, manufacture or occupation is carried on; (f) "prescribed" means prescribed by rules made under this Act; (g) "principal employer" means-(i) in relation to any office or department of the Government or a local authority, the head of that office or department or such other officer as the Government or the local authority, as the case may be, may specify in this behalf, (ii) in a factory, the owner or occupier of the factory and where a person has been named as the manager of the factory under the Factories Act, 1948 (63 of 1948) the person so named, (iii) in a mine, the owner or agent of the mine and where a person has been named as the manager of the mine, the person so named, (iv) in any other establishment, any person responsible for the supervision and control of the establishment. (h) "wages" shall have the meaning assigned to it in clause (vi) of section 2 of the Payment of Wages Act, 1936 (4 of 1936); (i) "workman" means any person employed in or in connection with the work of any establishment to do any skilled, semiskilled or un-skilled manual, supervisory, or clerical work for hire or reward, whether the terms of employment be express or implied, but does not include any such person-(A) who is employed mainly in a managerial or administrative capacity; or (B) who, being employed in a supervisory capacity draws wages exceeding five hundred rupees per mensem or exercises, either by the nature of the duties attached to the office or by reason of the powers vested in him, functions mainly of a managerial nature; or (C) who is an out-worker, that is to say, a person to whom any articles or materials are given out by or on behalf of the Principal employer to be made up, cleaned, washed, altered, ornamented, finished, repaired, adapted or otherwise processed for sale for the purposes of the trade or business of the principal employer and the process is to be carried out either in the home of the out-worker or in some other premises, not being premises under the control and management of the principal employer. THE ADVISORY BOARDS 3. Central Advisory Board.- (1) The Central Government shall, as soon as may be, constitute a board to be called the Central Advisory Contract Labour Board (hereinafter referred to as the Central Board) to advise the Central Government on such matters arising out of the administration of this Act as may be referred to it and to carry out other functions assigned to it under this Act. (2) The Central Board shall consist of-(a) a Chairman to be appointed by the Central Government; (b) the Chief Labour Commissioner (Central), ex-officio; (c) such number of members, not exceeding seventeen but not less than eleven, as the Central Government may nominate to represent that Government, the Railways, the coal industry, the mining industry, the contractors, the workmen and any other interests which, the opinion of the Central Government, ought to be represented on the Central Board. (3) The number of persons to be appointed as members from each of the categories specified in sub-section (2), the term of office and other conditions of service of, the procedure to be followed in the discharge of their functions by, and the manner of filling vacancies among, the members of the Central Board shall be such as may be prescribed: Provided that the number of members nominated to represent the workmen shall not be less than the number of members nominated to represent the principal employers and the contractors. 4. State Advisory Board.(1) The State Government may constitute a board to be called the State Advisory Contract Labour Board (hereinafter referred to as the State Board) to advice the State Government on such matters arising out of the administration of this Act as may be referred to it and to carry out other functions assigned to it under this Act. (2) The State Board shall consist of-(a) a Chairman to be appointed by the State Government; (b) the Labour Commissioner, ex-officio, or in his absence any other officer nominated by the State Government in that behalf; (c) such number of members, not exceeding eleven but not less than nine, as the State Government may nominate to represent that Government, the industry, the contractors, the workmen and any other interests which, in the opinion of the State Government, ought to be represented on the State Board. (3) The number of persons to be appointed as members from each of the categories specified in sub-section (2), the term of office and other conditions of service of, the procedure to be followed in the discharge of their functions by, and the manner of filling vacancies among, the members of the State Board shall be such as may be prescribed: Provided that the number of members nominated to represent the workmen shall not be less than the number of members nominated to represent the principal employers and the contractors. 5. Power to constitute committees.(1) The Central Board or the State Board, as the case may be, may constitute such committees and for such purpose or purposes as it may think fit. (2) The committee constituted under sub-section (1) shall meet at such times and places and shall observe such rules of procedure in regard to the transaction of business at its meetings as may be prescribed. (3) The members of a committee shall be paid such fees and allowances for attending its meetings as may be prescribed: Provided that no fees shall, be payable to a member who is an officer of Government or of any corporation established by any law for the time being in force. REGISTRATION OF ESTABLISHMENTS EMPLOYING CONTRACT LABOUR 6. Appointment of registering officers.- The appropriate Government may, by an order notified in the Official Gazette-(a) appoint such persons, being Gazetted Officers of Government, as it thinks fit to be registering officers for the purposes of this Chapter; and (b) define the limits, within which a registering officer shall exercise the powers conferred on him by or under this Act. 7. Registration of certain establishments.(1) Every principal employer of an establishment to which this Act applies shall, within such period as the appropriate Government may, by notification in the Official Gazette, fix in this behalf with respect to establishments generally or with respect to any class of them, make an application to the registering officer in the prescribed manner for registration of the establishment: Provided that the registering officer may entertain any such application for registration after expiry of the period fixed in this behalf, if the registering officer is satisfied that the applicant was prevented by sufficient cause from making the application in time. (2) If the application for registration is complete in all respects, the registering officer shall register the establishment and issue to the principal employer of the establishment a certificate of registration containing such particulars as may be prescribed. 8. Revocation of registration in certain cases.- If the registering officer is satisfied, either on a reference made to him in this behalf or otherwise, that the registration of any establishment has been obtained by misrepresentation or suppression of any material fact, or that for any other reason the registration has become useless or ineffective and, therefore, requires to be revoked, the registering officer may, after giving an opportunity to the principal employer of the establishment to be heard and with the previous approval of the appropriate Government, revoke the registration. 9. Effect of non-registration.- No principal employer of an establishment, to which this Act applies, shall-(a) in the case of an establishment required to be registered under section 7, but which has not been registered within the time fixed for the purpose under that section, (b) in the case of an establishment the registration in respect of which has been revoked under section 8, employ contract labour in the establishment after the expiry of the period referred to in clause (a) or after the revocation of registration referred to in clause (b), as the case may be. 10. Prohibition of employment of contract labour.(1) Notwithstanding anything contained in this Act, the appropriate Government may, after consultation with the Central Board or, as the case may be, a State Board, prohibit, by notification in the Official Gazette, employment of contract labour in any process, operation or other work in any establishment. (2) Before issuing any notification under sub-section (1) in relation to an establishment, the appropriate Government shall have regard to the conditions of work and benefits provided for the contract labour in that establishment and other relevant factors, such as-(a) whether the process, operation or other work is incidental to, or necessary for the industry, trade, business, manufacture or occupation that is carried on in the establishment: (b) whether it is of perennial nature, that is to say, it is of sufficient duration having regard to the nature of industry, trade, business, manufacture or occupation carried on in that establishment; (c) whether it is done ordinarily through regular workmen in that establishment or an establishment similar thereto; (d) whether it is sufficient to employ considerable number of whole-time workmen. LICENSING OF CONTRACTORS 11. Appointment of licensing officers.-- The appropriate Government may, by an order notified in the Official Gazette,-(a) appoint such persons, being Gazetted Officers of Government, as it thinks fit to be licensing officers for the purposes of this Chapter; and (b) define the limits, within which a licensing officer shall exercise the powers conferred on licensing officers by or under this Act. 12. Licensing of contractors.(1) With effect from such date as the appropriate Government may, by notification in the Official Gazette, appoint, no contractor to whom this Act applies, shall undertake or execute any work through contract labour except under and in accordance with a licence issued in that behalf by the licensing officer. (2) Subject to the provisions of this Act, a licence under sub-section (1) may contain such conditions including, in particular, conditions as to hours of work, fixation of wages and other essential amenities in respect of contract labour as the appropriate Government may deem fit to impose in accordance with the rules, if any, made under section 35 and shall be issued on payment of such fees and on the deposit of such sum, if any, as security for the due performance of the conditions as may be prescribed. 13. Grant of licences.(1) Every application for the grant of a licence under sub-section (1) of section 12 shall be made in the prescribed form and shall contain the particulars regarding the location of the establishment, the nature of process, operation or work for which contract labour is to be employed and such other particulars as may be prescribed. (2) The licensing officer may make such investigation in respect of the application received under subsection (1) and in making any such investigation the licensing officer shall follow such procedure as may be prescribed. (3) A licence granted under this Chapter shall be valid for the period specified therein and may be renewed from time to time for such period and on payment of such fees and on such conditions as may be prescribed. 14. Revocation, suspension and amendment of licences.(1) If the licensing officer is satisfied, either on a reference made to him in this behalf or otherwise, that-(a) a licence granted under section 12 has been obtained by misrepresentation or suppression of any material fact, or (b) the holder of a licence has, without reasonable cause, failed to comply with the conditions subject to which the licence has been granted or has contravened any of the provisions of this Act or the rules made there under, then, without prejudice to any other penalty to which the holder of the licence may be liable under this Act, the licensing officer may, after giving the holder of the licence an opportunity of showing cause, revoke or suspend the licence or forfeit the sum, if any, or any portion thereof deposited as security for the due performance of the conditions subject to which the licence has been granted. (2) Subject to any rules that may be made in this behalf, the licensing officer may vary or amend a licence granted under section 12. 15. Appeal.(1) Any person aggrieved by an order made under section 7, section 8, section 12 or section 14 may, within thirty days from the date on which the order is communicated to him, prefer an appeal to an appellate officer who shall be a person nominated in this behalf by the appropriate Government: Provided that the appellate officer may entertain the appeal after the expiry of the said period of thirty days, if he is satisfied that the appellant was prevented by sufficient cause from filing the appeal in time. (2) On receipt of an appeal under sub-section (1), the appellate officer shall, after giving the appellant an opportunity of being heard dispose of the appeal as expeditiously as possible. WELFARE AND HEALTH OF CONTRACT LABOUR 16. Canteens.(1) The appropriate Government may make rules requiring that in every establishment-(a) to which this Act applies, (b) wherein work requiring employment of contract labour is likely to continue for such period as may be prescribed, and (c) wherein contract labour numbering one hundred or more is ordinarily employed by a contractor, one or more canteens shall be provided and maintained by the contractor for the use of such contract labour. (2) Without prejudice to the generality of the foregoing power, such rules may provide for-(a) the date by which the canteens shall be provided; (b) the number of canteens that shall be provided, and the standards in respect of construction, accommodation, furniture and other equipment of the canteens; and (c) the foodstuffs which may be served therein and the charges which may be made thereof. 17. Rest-rooms.(1) In every place wherein contract labour is required to halt at night in connection with the work of an establishment-(a) to which this Act applies, and (b) in which work requiring employment of contract labour is likely to continue for such period as may be prescribed, there shall be provided and maintained by the contractor for the use of the contract labour such number of rest-rooms or such other suitable alternative accommodation within such time as may be prescribed. (2) The rest rooms or the alternative accommodation to be provided under subsection (1) shall be sufficiently lighted and ventilated and shall be maintained in a clean and comfortable condition. 18. Other facilities.It shall be the duty of every contractor employing contract labour in connection with the work of an establishment to which this Act applies, to provide and maintain-(a) a sufficient supply of wholesome drinking water for the contract labour at convenient places; (b) a sufficient number of latrines and urinals of the prescribed types so situated as to be convenient and accessible to the contract labour in the establishment; and (c) washing facilities. 19. First-aid facilities.- There shall be provided and maintained by the contractor so as to be readily accessible during all working hours a first-aid box equipped with the prescribed contents at every place where contract labour is employed by him. 20. Liability of principal employer in certain cases.(1) If any amenity required to be provided under section 16, section 17, section 18 or section 19 for the benefit of the contract labour employed in an establishment is not provided by the contractor within the time prescribed thereof, such amenity shall be provided by the principal employer within such time as may be prescribed. (2) All expenses incurred by the principal employer in providing the amenity may be recovered by the principal employer from the contractor either by deduction from any amount payable to the contractor under any contract or as a debt payable by the contractor. 21. Responsibility for payment of wages.(1) A contractor shall be responsible for payment of wages to each worker employed by him as contract labour and such wages shall be paid before the expiry of such period as may be prescribed. (2) Every principal employer shall nominate a representative duly authorized by him to be present at the time of disbursement of wages by the contractor and it shall be the duty of such representative to certify the amounts paid as wages in such manner as may be prescribed. (3) It shall be the duty of the contractor to ensure the disbursement of wages in the presence of the authorized representative of the principal employer. (4) In case the contractor fails to make payment of wages within the prescribed period or makes short payment, then the principal employer shall be liable to make payment of wages in full or the unpaid balance due, as the case may be, to the contract labour employed by the contractor and recover the amount so paid from the contractor either by deduction from any amount payable to the contractor under any contract or as a debt payable by the contractor. PENALTIES AND PROCEDURE 22. Obstructions.(1) Whoever obstructs an inspector in the discharge of his duties under this Act or refuses or wilfully neglects to afford the inspector any reasonable facility for making any inspection, examination, inquiry or investigation authorized by or under this Act in relation to an establishment to which, or a contractor to whom, this Act applies, shall be punishable with imprisonment for a term which may extend to three months, or with fine which may extend to five hundred rupees, or with both. (2) Whoever wilfully refuses to produce on the demand of an inspector any register or other document kept in pursuance of this Act or prevents or attempts to prevent or does anything which he has reason to believe is likely to prevent any person from appearing before or being examined by an inspector acting in pursuance of his duties under this Act, shall be punishable with imprisonment for a term which may extend to three months, or with fine which may extend to five hundred rupees, or with both. 23. Contravention of provisions regarding employment of contract labour.- Whoever contravenes any provision of this Act or of any rules made there under prohibiting, restricting or regulating the employment of contract labour, or contravenes any condition of a licence granted under this Act, shall be punishable with imprisonment for a term which may extend to three months, or with fine which may extend to one thousand rupees, or with both, and in the case of a continuing contravention with an additional fine which may extend to one hundred rupees for every day during which such contravention continues after conviction for the first such contravention. 24. Other offences.- If any person contravenes any of the provisions of this Act or of any rules made there under for which no other penalty is elsewhere provided, he shall be punishable with imprisonment for a term which may extend to three months, or with fine which may extend to one thousand rupees, or with both. 25. Offences by companies.(1) If the person committing an offence under this Act is a company, the company as well as every person in charge of, and responsible to, the company for the conduct of its business at the time of the commission of the offence shall be deemed to be guilty of the offence and shall be liable to be proceeded against and punished accordingly: Provided that nothing contained in this sub-section shall render any such person liable to any punishment if he proves that the offence was committed without his knowledge or that he exercised all due diligence to prevent the commission of such offence. (2) Notwithstanding anything contained in sub-section (1), where an offence under this Act has been committed by a company and it is proved that the offence has been committed with the consent or connivance of, or that the commission of the offence is attributable to any neglect on the part of any director, manager, managing agent or any other officer of the company, such director, manager, managing agent or such other officer shall also be deemed to be guilty of that offence and shall be liable to be proceeded against and punished accordingly. 26. Cognizance of offences.- No court shall take cognizance of any offence under this Act except on a complaint made by, or with the previous sanction in writing of, the inspector and no court inferior to that of a Presidency Magistrate or a magistrate of the first class shall try any offence punishable under this Act. 27. Limitation of prosecutions.- No court shall take cognizance of an offence punishable under this Act unless the complaint thereof is made within three months from the date on which the alleged commission of the offence came to the knowledge of an inspector: Provided that where the offence consists of disobeying a written order made by an inspector, complaint thereof may be made within six months of the date on which the offence is alleged to have been committed. MISCELLANEOUS 28. Inspecting staff.(1) The appropriate Government may, by notification in the Official Gazette, appoint such persons as it thinks fit to be inspectors for the purposes of this Act, and define the local limits within which they shall exercise their powers under this Act. (2) Subject to any rules made in this behalf, an inspector may, within the local limits for which he is appointed-(a) enter, at all reasonable hours, with such assistance (if any), being persons in the service of the Government or any local or other public authority as he thinks fit, any premises or place where contract labour is employed, for the purpose of examining any register or record or notices required to be kept or exhibited by or under this Act or rules made there under, and require the production thereof for inspection; (b) examine any person whom he finds in any such premises or place and who, he has reasonable cause to believe, is a workman employed therein; (c) require any person giving out work and any workman, to give any information, which is in his power to give with respect to the names and addresses of the persons to, for and from whom the work is given out or received, and with respect to the payments to be made for the work; (d) seize or take copies of such register, record of wages or notices or portions thereof as he may consider relevant in respect of an offence under this Act which he has reason to believe has been committed by the principal employer or contractor; and (e) exercise such other powers as may be prescribed. (3) Any person required to produce any document or thing or to give any information required by an inspector under sub-section (2) shall be deemed to be legally bound to do so within the meaning of section 175 and section 176 of the Indian Penal Code (45 of 1860). (4) The provisions of the Code of Criminal Procedure, 1898 (5 of 1898), shall, so far as may be, apply to any search or seizure under sub-section (2) as they apply to any search or seizure made under the authority of a warrant issued under section 98 of the said Code.3 29. Registers and other records to be maintained.(1) Every principal employer and every contractor shall maintain such registers and records giving such particulars of contract labour employed, the nature of work performed by the contract labour, the rates of wages paid to the contract labour and such other particulars in such form as may be prescribed. (2) Every principal employer and every contractor shall keep exhibited in such manner as may be prescribed within the premises of the establishment where the contract labour is employed, notices in the prescribed form containing particulars about the hours of work, nature of duty and such other information as may be prescribed. 30. Effect of laws and agreements inconsistent with this Act.- (1) The provisions of this Act shall have effect notwithstanding anything inconsistent therewith contained in any 3 other law or in the terms of any agreement or contract of service, or in any standing orders applicable to the establishment whether made before or after the commencement of this Act: Provided that where under any such agreement, contract of service or standing orders the contract labour employed in the establishment are entitled to benefits in respect of any matter which are more favourable to them than those to which they would be entitled under this Act, the contract labour shall continue to be entitled to the more favourable benefits in respect of that matter, notwithstanding that they receive benefits in respect of other matters under this Act. (2) Nothing contained in this Act shall be construed as precluding any such contract labour from entering into an agreement with the principal employer or the contractor, as the case may be, for granting them rights or privileges in respect of any matter, which are more favourable to them than those to which they would be entitled under this Act. 31. Power to exempt in special cases.- The appropriate Government may, in the case of an emergency, direct, by notification in the Official Gazette, that subject to such conditions and restrictions, if any, and for such period or periods, as may be specified in the notification, all or any of the provisions of this Act or the rules made there under shall not apply to any establishment or class of establishments or any class of contractors. 32. Protection of action taken under this Act.(1) No suit, prosecution or other legal proceedings shall lie against any registering officer, licensing officer or any other Government servant or against any member of the Central Board or the State Board, as the case may be, for anything which is in good faith done or intended to be done in pursuance of this Act or any rule or order made there under. (2) No suit or other legal proceeding shall lie against the Government for any damage caused or likely to be caused by anything which is in good faith done or intended to be done in pursuance of this Act or any rule or order made there under. 33. Power to give directions.- The Central Government may give directions to the Government of any State as to the carrying into execution in the State of the provisions contained in this Act. 34. Power to remove difficulties.- If any difficulty arises in giving effect to the provisions of this Act, the Central Government may, by order published in the Official Gazette, make such provisions not inconsistent with the provisions of this Act, as appears to it to be necessary or expedient for removing the difficulty. 35. Power to make rules.(1) The appropriate Government may, subject to the condition of previous publication, make rules for carrying out the purposes of this Act. (2) In particular, and without prejudice to the generality of the foregoing power, such rules may provide for all or any of the following matters, namely:-(a) the number of persons to be appointed as members representing various interests on the Central Board and the State Board, the term of their office and other conditions of service, the procedure to be followed in the discharge of their functions and the manner of filling vacancies; (b) the times and places of the meetings of any committee constituted under this Act, the procedure to be followed at such meetings including the quorum necessary for the transaction of business, and the fees and allowances that may be paid to the members of a committee; (c) the manner in which establishments may be registered under section 7, the levy of a fee thereof and the form of certificate of registration; (d) the form of application for the grant or renewal of a licence under section 13 and the particulars it may contain; (e) the manner in which an investigation is to be made in respect of an application for the grant of a licence and the matters to be taken into account in granting or refusing a licence; (f) the form of a licence which may be granted or renewed under section 12 and the conditions subject to which the licence may be granted or renewed, the fees to be levied for the grant or renewal of a licence and the deposit of any sum as security for the performance of such conditions; (g) the circumstances under which licences may be varied or amended under section 14; (h) the form and manner in which appeals may be filed under section 15 and the procedure to be followed by appellate officers in disposing of the appeals; (i) the time within which facilities required by this Act to be provided and maintained may be so provided by the contractor and in case of default on the part of the contractor, by the principal employer; (j) the number and types of canteens, rest rooms, latrines and urinals that should be provided and maintained; (k) the type of equipment that should be provided in the first-aid boxes; (l) the period within which wages payable to contract labour should be paid by the contractor under subsection (1) section 21; (m) the form of registers and records to be maintained by principal employers and contractors; (n) the submission of returns, forms in which, and the authorities to which, such returns, may be submitted; (o) the collection of any information or statistics in relation to contract labour; and (p) any other matter which has to be, or may be, prescribed under this Act. (3) Every rule made by the Central Government under this Act shall be laid as soon as may be after it is made, before each House of Parliament while it is in session for a total period of thirty days which may be comprised in one session or in two successive sessions, and if before the expiry of the session in which it is so laid or the session immediately following, both Houses agree in making any modification in the rule or both Houses agree that the rule should not be made, the rule shall thereafter have effect only in such modified form or be of no effect, as the case may be; so, however, that any such modification or annulment shall be without prejudice to the validity of anything previously done under that rule. Working Capital Management Working capital is defined as the portion of assets used in current operations. The movement of funds from working capital to income and profits and back to working capital is one of the most important characteristics of the business. Sufficient liquidity is important and must be achieved and maintained to provide the funds to pay off obligations as they arise or mature. The adequacy of cash and other current assets together with their efficient handling determine the survival or demise of the company. A businessman should be able to judge the accurate requirement f working capital and should be quick enough to raise the required funds to finance the working capital needs. Working capital is cardinal part of power station management. There are two concept of working capital 1. Gross working capital 2. Net working capital Gross working capital: Gross working capital refers to the firm’s investment in current asset. Current asset are the assets which can be converted in to cash within accounting year and include cash, short term securities, debtors, bill receivables and inventory. Net working capital: Net working capital refers to difference between current asset and current liabilities. Current liabilities are those claims of outsiders which are expected to mature for payment within accounting year and include creditors, bill payable, outstanding expenses. WORKING CAPITAL = CURRENT ASSETS - CURRENT LIABILITIES Net working capital can be positive or negative or negative. Positive net working capital will arise when current asset exceeds current liabilities and vise a versa. Cash flows in a cycle into, around and out of a business. It is the business's life blood and every manager's primary task is to help keep it flowing and to use the cash flow to generate profits. If a business is operating profitably, then it should, in theory, generate cash surpluses. If it doesn't generate surpluses, the business will eventually run out of cash and expire. The faster a business expands the more cash it will need for working capital and investment. The cheapest and best sources of cash exist as working capital right within business. Good management of working capital will generate cash will help improve profits and reduce risks. Bear in mind that the cost of providing credit to customers and holding stocks can represent a substantial proportion of a firm's total profits. There are two elements in the business cycle that absorb cash - Inventory and Receivables (debtors owing you money). The main sources of cash are Payables (your creditors) and Equity and Loans. Each component of working capital (namely inventory, receivables and payables) has two dimensions time and money. When it comes to managing working capital, then time is money. If you can get money to move faster around the cycle (e.g. collect monies due from debtors more quickly) or reduce the amount of money tied up (e.g. reduce inventory levels relative to sales), the business will generate more cash or it will need to borrow less money to fund working capital. As a consequence, you could reduce the cost of bank interest or you'll have additional free money available to support additional sales growth or investment. Similarly, if you can negotiate improved terms with suppliers e.g. get longer credit or an increased credit limit; you effectively create free finance to help fund future sales. Components of Working Capital The elements of working capital are as follows: • Current assets 1. Cash 2. Bank balance 3. Short term investments 4. Trade debtors 5. Inventory  Finished goods  Work in process  Raw materials  Stores and spares • Current liabilities 1. Trade creditors 2. Bank overdraft or cash credit 3. Short term borrowings 4. Provision for taxes 5. Provision for dividends If current assets are the source from which current liabilities are to be met during the course of business operations, then their strengths and weaknesses will have significant bearing on the short run liquidity of the company. The importance of preserving this short term liquidity need not be emphasized and hence the need to manage the working capital. Factors Influencing Working Capital To determine the quantum of required working capital, the following factors need to be taken into consideration: 1. Profit levels A company earning huge amount of profits can add to the working capital pool a large quantum of funds. Such companies should, however, guard against the temptation of expanding beyond necessity and tying up the funds in unproductive capital expenditure or allow unnecessary increase in overheads. Some companies with high profit levels become lax in management of funds and usually mismanage by blocking funds excessively in stocks and debtors. 2. Tax levels and planning Income tax laws provide for payment of advanced tax in installments. Any working capital must make adequate and timely provision for Excise and sales tax as all of them involve cash outlays. 3. Dividend policies and retained earnings Dividend policy and retained earnings are directly related. Dividends once declared become a short term liability which has to be paid for in cash and this impact should be recognized in the working capital budget. Reserves in the form of retained earnings are a very important source of augmenting working capital. 4. Depreciation policy The extent to which depreciation provision is made during the course of making financial statements has a direct bearing on the dividend policy and retained earnings. This is because higher depreciation would leave lesser profits resulting in reduced retained earnings and dividends. As provisions for depreciation are actually only book entries and represent no cash flow at that time, they will have no bearing on working capital to the extent they may hold back distribution of dividends. 5. Expansion/diversification plans Addition of fixed assets to produce new products, resorting to multiple shifts, or marginally adding to the plant and machinery are some of the common known ways to expand or diversify. In such situations, it is unwise to strain the internal resources for avoiding external funding. 6. Price level changes in raw material and finished goods Inflation has got a direct bearing on working capital. It depends to a large extent on the companies’ ability to readjust its own prices to cover the increase in cost. In case the product or service requires government approval or is administered as far as the price is concerned, inflation has a very significant bearing on the working capital needs. 7. Operating efficiency of the company The operating efficiency of a company plays a major role in working capital management. An efficient company will have a shorter manufacturing period, long term credits available from suppliers and minimal customer’s credit outstanding. If this is achieved then the quantum of working capital required will be naturally reduced. Strategies for The Working Capital Management  RECEIVABLES MANAGEMENT If we are getting trade credit to fund our needs, then we also have to extend credit to our customers. There are several affects of extending credit to the customers on various operating parameters of the company. These include: Revenue effects: as the customers are extended credit, payment for goods is received later giving the customers time to generate sales from the goods and pay back the company. This may allow the company to charge a higher price and also the quantity sold may increase. ii) Cost effects: extending credit means that the company has to maintain a credit department. This involves costs. Also collecting receivables has its own costs associated in it. iii) The cost of debt: if the company has to extend credit it must finance these receivables from its own money from borrowings. iv) The probability of nonpayment: the company always gets paid if it sells for cash but if it extends credit, there is a probability that the customer may not pay. This means that the company may not get its payments resulting in a loss to the company. v) The cash discount: the cash discount affects payment patterns and amounts that the company receives early. If the cash discount is high then there is high probability that the company will get more cash up front and vice versa. There are three ways of management control in connection with credit policy: 1. Debtors expressed in relation to sales- either as a percentage or as a number of weeks sales. This provides an overall confirmation that the business is effective in carrying out its own credit policy. 2. Bad debts as a percentage of sales value, or reported otherwise in detail. 3. Credit control sales. This means that the credit control involves three types of action: Deciding the normal credit period to be allowed: if a business is offering a unique product or service, or one for which demand exceeds supply, there may be no need to offer credit terms at all. In other cases the starting point in deciding credit policy is a review of the credit terms offered by competitors and from this basis, the credit terms of the particular business will be developed. Long credit period may be offered to the customers if this enables the business to capture a larger share of the available market, or the break into a new market. Shorter credit may be imposed if demand is elastic, so that the quantity sold will not be affected simply by changes in credit terms. Establishing credit limits for the individual customers: Business has a credit policy does not mean that credit terms will be granted to every customer. It is not always easy t decide whether a particular customer is credit worthy in the sense that he has both the ability and the inclination to pay at the due date. Five Cs of credit that should be looked after: • Character: willingness to pay back the credit • Capacity : ability to pay back • Capital: financial reserves including cash • Collateral: what assets could be pledged or are pledged to others that hinder payments. • Conditions: relevant economic conditions Implementing the system Vetting incoming orders The amount appearing on the customer’s ledger account at any time will result from the invoicing the orders he has placed, so that if the value of orders in any period were t exceed the original forecast this might not become until after invoicing. At that time the outstanding balance on the ledger would suddenly be found to be in excess of the agreed limit. To safeguard against this possibility an order register may be kept for each customer, showing the value of orders placed for delivery in particular months. Each incoming order will then be checked against the register to confirm that it will not cause the credit limit to be exceeded. This could be a cumbersome procedure and it would only be used in respect of: • New customers whose compliance with credit limits has not been established i) • Customers who had consistently failed to adhere to their credit limits in the past. Sales invoicing So far as the customer is concerned, the company’s credit period does not begin until he receives an invoice. It is therefore important that delays in invoicing be kept to minimum. The causes of delay are nearly all within the control of the company and may include: • An inflexible routine in the sales invoicing department • A requirement for approval or signature of sales invoices • Failure to agree prices for special work • Slow procedures for calculating costs. Debt collection There must be no slackness in pursuing the collection of debts. There should be early personal contact with the customer either by telephone or salesman’s visit or by a letter addressed to a named person in the customer company. If necessary, there may be a follow up at higher level of authority and this should be followed by a threat to cut off supplies. Overdue debts should be the subject of formal discussion between sales and financial managers. The reasons for delayed payment should be noted, and decisions should be minuted on the action to be taken in each case and the people responsible for taking it. Cost of credit control The cost of credit control includes the cost of: • Assessing and reviewing creditworthiness • Checking incoming orders • Sales ledger keeping and invoicing • Debt collection Cash discount An alternative or supplement of a formal credit policy is to offer discount for prompt payment. It is important to bear in mind that: • Customers who normally pay promptly will now become entitled to discount • Some late payers will nevertheless deduct discount from their settlements. Personal guarantees An alternative form of protection against bad debts is to take a personal guarantee in support of the customer’s account. The value of personal guarantees varies considerably and they are likely to present two problems: • It may be more difficult to assess the creditworthiness of an individual guarantor than of the trade customer. • The guarantor does not normally expect to be called upon to pay, and there may be difficulties in obtaining money from him when the need arises.  PAYABLES MANAGEMENT: When the company gets the trade credit, it would like to pay back as late as possible, because these are the funds that require no interest payments and are free of cost. Following points needs to be taken into consideration: • Cost Of Trade Credit: for purpose of measuring the true cost, or the effective annual rate of interest associated with use of trade credit as a discretionary source of short term business funds, it is necessary to consider the effects of its use both when: • a company fails to take its cash discounts but nevertheless pays within the net period • A company fails to take its discounts and allows its payable to become overdue. • Proper Use of Trade Credit: as compared with other kinds of short term business credit-bank loans, trade credit is almost automatic. And because it may be much more readily acquired, business companies must exercise continuing care to avoid falling into the habit of using trade credit to excess. Trade credit is exceedingly useful and valuable precisely because business companies can usually obtain it when, as, and to the extent that it is needed. Thus, a company’s financial officer while assuring that his company benefits from the availability of trade credit in every legitimate way should always maintain the business liquidity required to pay all his company’s bills as they come due.  INVENTORY MANAGEMENT: Inventory contains finished goods, semi finished goods, raw materials. The financial decisions relating to stockholding have certain special features but it can be used as an object of increasing sales and object of increasing sales is to increase profit. Why should increased stocks give rise to increase in sales? One reason would be that the business may offer a wider range of gods and it diversifies its range. Another could be that with the existing range the business was offering the better level of service that is it was less frequently out of stock of an item when it was required. The inventory management can be done by taking care of following: • Stock Service Levels: in deciding an inventory policy it is necessary to define the level of service to be offered to the customer, in the sense of percentage of order which can be satisfied immediately from stock. This will depend on the nature of the business. When the required level of service has been defined, the next problem is to decide how much stock is needed to meet that requirement. This will be the minimum holding, and not the average holding which will be influenced by the stockholding costs. • Economic Order Quantity: the economic order quantity is defined as the point where the total costs of restocking and carrying costs are the lowest. It is calculated on the basis of differential calculus. EOQ =√ (2×FC ×S) ÷ (I×P) There are 4 assumptions for an EOQ model: • Sales can be forecasted perfectly • Sales are evenly distributed throughout the year • Orders are received as soon as they are placed This set of assumptions mean is perfectly restrictive. There are 2 important things to note about EOQ: Although a precise EOQ can be calculated, there is likely to be a range f order quantities within which total costs remain at a low level. The choice f order quantity within this low cost range may not significantly affect the overall financial plan. The key factor in the calculations is usually the cost of capital. The inventory holding costs will go up very steeply, and one’s conclusion will be that stockholdings should be kept to the lowest figure possible having regard to any practical difficulties in obtaining frequent replacement supplies. o Safety Margins in Stockholding: we always assume that the company will be placing an order at regular intervals of time for a fixed quantity of any particular item. The possibility of doing this depends on demand remaining constant from period to period and on supplies being available as and when required. To correct for random delays in supply, it may be possible to anticipate changes in the trend of demand and to modify the purchasing procedure to meet them in one of the following ways:  To order in economic order quantities but at varying time intervals according to the rate of demand currently being experienced or anticipated in the near future known as fixed order quantity or reorder level system.  To order at regular intervals but in varying quantities determined by the current rate of demand, this is the fixed interval or periodic review system. Modified Ordering Systems: the reorder level system involves deciding a level of stockholding at which new purchase orders shall be placed. The quantity to be ordered is constant, and an order for that quantity will be placed whenever stock falls to the pre-determined order level. The system thus responds quickly to variations in demand though there is a danger that in doing so, it may reflect purely short term or random fluctuations in sales. The operation of reorder level system include the use of:  A maximum stock level. This would correspond to the normal peak holding under stable conditions. If the stockholding exceeds the peak level this provides a warning that demand has been running below the rate expected when the EOQ was fixed.  A minimum stock level which is probably the amount of the safety margin. The minimum stock level provides a warning of a potential out of stock position. When the stockholding falls to that level, the sock controller will review his outstanding purchase orders and their due dates and also the current level f demand and can then decide whether additional emergency procurement is necessary. It is in fact a common experience that the reorder system level gives slightly lower average stock levels and it is sometimes thought to be the cheaper system to operate because reordering is triggered automatically at the reorder levels, however, requires reviewing in the light of changes in the rate of demand. Any system can appear cheap in the short run if it is operated in a slovenly manner. • The Total Inventory: the techniques described above all relate to single line items of stock. The assumption is such that of each item is held at its own economic level then the overall holding of stock will be correctly balanced. This would be true provided that the two conditions were satisfied. o That there was enough space available to hold all the stocks required. o That enough money could be found to finance them. o Neither condition is likely to be fulfilled in practice, so some form of mathematical program might be used to constrain the ideal unit quantities within the limiting factors. There are, however, number of simple pragmatic approaches t inventory reduction and these include: o Modifying the service level offered o Letting the company’s suppliers act as stockholders o Disconnecting those items which are the least profitable having regards to their marginal contribution and relevant fixed costs per unit of the limiting factor. • Raw Materials Stocks and Work In Progress: so far in considering inventory control, we have been discussing saleable stocks but the same principles apply to stocks of raw materials. The main difference is that demand for raw materials is not direct from the outside customers but indirect through the production plans of the factory using the raw materials. A big problem with work in progress is that work passes in sequence through series of operations. What is economic batch for lathe work may not be economic for drilling, milling or assembly operations. Applying EBQ(economic batch quantity) to one operation in isolation can cause bottlenecks in the flow or production creating excessive holdings of partly completed work because it could be produced cheaply in a large batch even though there will be no demand for that work for some time ahead. As the number of items could be very large in case of raw materials it is necessary to find ways to selectively pay attention to those items that represent the highest value. A categorization method known as ABC analysis is used for the same purpose. The idea behind ABC analysis is that attention is focused on the highest value items that are usually less in number categorized as A category items and the lowest value items are categorized as C and are ordered in more quantities so that less attention is required there. o For example , in figure 6.6,the A category items represent only 10% of total inventory items but represent 57% of the total value. While C category items represent 50% of the total items but only 16%of the value. By concentrating more on the A category items the company is able to manage its raw material inventory better. 100 (PERCENT OF INVENTORY VALUE) 80 GROUP A 60 40 20 0 20 40 60 80 10% 40% 57% GROUP B GROUP C 27% 16% 50% ABC INVENTORY ANALYSIS 100 (PERCENT OF INVENTORY ITEMS) Inventories are lists of stocks-raw materials, work in progress or finished goods-waiting to be consumed in production or to be sold. In case of power plant inventory is stock of coal needed for daily operation. The total balance of inventory is the sum of the value stock. Stock records are needed: o To provide an account of activity within each stock line; o As evidence to support the balances used in financial reports. Inventory management is an important aspect of working capital management because inventories themselves do not earn any revenue. Holding either too little or too much inventory incurs costs. Costs of carrying too much inventory are: o opportunity cost of foregone interest; o warehousing costs; o damage o Obsolescence; o Insurance. Costs of carrying too little inventory are: • Stock out costs: - Results into shut down of power plant and lots of sale. • Ordering cost:  freight  order administration  loss of quantity discount a. The best ordering strategy requires balancing the various cost factors to ensure the department incurs minimum inventory costs. The optimum inventory position is known as the Economic Reorder Quantity (ERQ). There is a trade-off to be made between carrying costs, ordering costs, and stock out costs. b. Analytical review of inventories can help to identify areas where inventory management can be improved. STRATEGIES TO CONTROL DEBTORS AND CREDITORS Debtors: Debtors (Accounts Receivable) are customers who have not yet made payment for goods or services which the department has provided. The objective of debtor management is to minimize the time-lapse between completion of sales and receipt of payment. The costs of having debtors are: • Opportunity costs (cash is not available for other purposes); • Bad debts Debtor management includes both pre-sale and debt collection strategies. Pre-sale strategies include: 1. offering cash discounts for early payment and/or imposing penalties for late payment; 2. agreeing payment terms in advance; 3. setting credit limits; 4. billing as early as possible; 5. Requiring deposits and/or progress payments. Post-sale strategies include: 1. Placing the responsibility for collecting the debt upon the center that made the sale. 2. Identifying long overdue balances and doubtful debts by regular analytical reviews 3. Having an established procedure for late collections, such as a reminder a letter cancellation of further credit telephone calls legal action Creditors: Creditors (Accounts Payable) are suppliers whose invoices for goods or services have been processed but who have not yet been paid. Organizations often regard the amount owing to creditors as a source of free credit. While it is unnecessary to pay accounts before they fall due, it is usually not worthwhile to delay all payments until the latest possible date., Regular weekly or fortnightly payment of all due accounts is the simplest technique for creditor management. Electronic payments (direct credits) are cheaper than cheque payments, considering that transaction fees and overheads more than balance the advantage of delayed presentation. Some suppliers are reluctant to receive payments by this method, but in view of the substantial cost advantage (and the advantages to the suppliers themselves) departments may wish to encourage suppliers to accept this option. However, electronic payments are likely to be used in conjunction with, rather than as a replacement for, cheque payments. Working Capital According To CERC Guidelines As per central Electricity Regulatory commission (CERC) guidelines on tariff calculation (2009-2014) for generating stations, working capital shall cover: For coal based/Lignite fired generating stations 1. Cost of coal or lignite 2. Cost of secondary fuel oil 3. Operation and Maintenance expenses 4. Maintenance spares 5. Receivables • Cost of coal or lignite and limestone, if applicable, for 1½ months for pit-head generating stations and two months for non-pit-head generating stations, for generation corresponding to the normative annual plant availability factor. Cost of coal consumes highest part of working capital in coal based generating stations. As per CERC guidelines cost of coal or lignite for 1.5 months for pit head generates stations and two months for non pit head generating stations, corresponding to target availability. Cost of coal depends upon following parameters; a. b. c. d. Capacity of power plant Gross station heat rate Market price of coal Calorific value of coal Gross station heat rate: Gross station heat rate means the heat energy input in kcal required to generate one kWh of electricity energy at generator terminals. As per CERC guidelines; Gross station heat rate for coal base Thermal power plant 200/210/250 MW sets 500 MW and above sets During stabilization period 2600 Kcal/Kwh 2550 Kcal/Kwh Subsequent period 2500 Kcal/Kwh 2425 Kcal/Kwh Gross Calorific Value: Gross calorific value in relation to thermal power generating station means heat produced in Kcal by complete combustion of solid fuel or one liter of liquid fuel or standard cubic meter of gaseous fuel. Calorific value of Indian coal is less as compared to imported coal due to high ash contents. • Cost of secondary fuel oil for two months for generation corresponding to the normative annual plant availability factor, and in case of use of more than one secondary fuel oil, cost of fuel oil stock for the main secondary fuel oil. • Maintenance spares @ 20% of operation and maintenance expenses specified in regulation 19. • Receivables equivalent to two months of capacity charges and energy charges for sale of electricity calculated on the normative annual plant availability factor, and • Operation and maintenance expenses for one month. OPEN-CYCLE GAS TURBINE/COMBINED CYCLE THERMAL GENERATING STATIONS • Fuel cost for one month corresponding to the normative annual plant availability factor, duly taking into account mode of operation of the generating station on gas fuel and liquid fuel; • Liquid fuel stock for ½ month corresponding to the normative annual plant availability factor, and in case of use of more than one liquid fuel, cost of main liquid fuel. • Maintenance spares @ 30% of operation and maintenance expenses specified in regulation 19. • Receivables equivalent to two months of capacity charge and energy charge for sale of electricity calculated on normative plant availability factor, duly taking • Operation and maintenance expenses for one month. HYDRO GENERATING STATION • Receivables equivalent to two months of fixed cost. • Maintenance spares @ 15% of operation and maintenance expenses specified in regulation 19; • Operation and maintenance expenses for one month. The cost of fuel shall be based on the landed cost incurred (taking into account normative transit and handling losses) by the generating company and gross calorific value of the fuel as per actual for the three months preceding the first month for which tariff is to be determined and no fuel price escalation shall be provided during the tariff period. OPERATION AND MAINTENANCE EXPENSES Coal based and lignite fired (including those based on CFBC technology) generating stations, other than the generating stations: 200/210/250 MW 300/330/350 500 MW sets 600 MW and sets MW sets above sets 2009-10 18.20 16.00 13.00 11.70 2010-11 19.24 16.92 13.74 12.37 2011-12 20.34 17.88 14.53 13.08 2012-13 21.51 18.91 15.36 13.82 2013-14 22.74 19.99 16.24 14.62 Talcher Thermal Power Station (TPS), Tanda TPS, Badarpur TPS of NTPC and Bokaro TPS, Chandrapura TPS and Durgapur TPS of DVC (Rs. in lakh/MW) Year Talcher TPS Tanda and Badarpur, Bokaro Chandrapura TPS and Durgapur TPS 2009-10 32.75 26.25 31.35 2010-11 34.62 27.75 32.25 2011-12 36.60 29.34 33.17 2012-13 38.70 31.02 34.12 2013-14 40.91 32.79 35.09 Open Cycle Gas Turbine/Combined Cycle generating stations (Rs. in lakh/MW) Gas Turbine/ Combined Small gas turbine power Agartala GPS Year Cycle generating stations generating stations other than small gas turbine power generating stations 2009-10 14.80 22.90 31.75 2010-11 15.65 24.21 33.57 2011-12 16.54 25.59 35.49 2012-13 17.49 27.06 37.52 2013-14 18.49 28.61 39.66 (Rs. in lakh/MW) Year HYDRO GENERATING STATION • Operation and maintenance expenses, for the existing generating stations which have been in operation for 5 years or more in the base year of 2007-08, shall be derived on the basis of actual operation and maintenance expenses for the years 2003-04 to 2007-08, based on the audited balance sheets, excluding abnormal operation and maintenance expenses, if any, after prudence check by the Commission. • The normalized operation and maintenance expenses after prudence check, for the years 2003-04 to 2007-08, shall be escalated at the rate of 5.17% to arrive at the normalized operation and maintenance expenses at the 2007-08 price level respectively and then averaged to arrive at normalized average operation and maintenance expenses for the 2003-04 to 2007-08 at 2007-08 price level. The average normalized operation and maintenance expenses at 2007-08 price level shall be escalated at the rate of 5.72% to arrive at the operation and maintenance expenses for year 200910: Provided that operation and maintenance expenses for the year 2009-10 shall be further rationalized considering 50% increase in employee cost on account of pay revision of the employees of the Public Sector Undertakings to arrive at the permissible operation and maintenance expenses for the year 2009-10. • The operation and maintenance expenses for the year 2009-10 shall be escalated further at the rate of 5.72% per annum to arrive at permissible operation and maintenance expenses for the subsequent years of the tariff period • In case of the hydro generating stations, which have not been in commercial operation for a period of five years as on 1.4.2009, operation and maintenance expenses shall be fixed at 2% of the original project cost (excluding cost of rehabilitation & resettlement works). Further, in such case, operation and maintenance expenses in first year of commercial operation shall be escalated @5.17% per annum up to the year 2007-08 and then averaged to arrive at the O&M expenses at 2007-08 price level. It shall be thereafter escalated @ 5.72% per annum to arrive at operation and maintenance expenses in respective year of the tariff period. • In case of the hydro generating stations declared under commercial operation on or after 1.4.2009, operation and maintenance expenses shall be fixed at 2% of the original project cost (excluding cost of rehabilitation & resettlement works) and shall be subject to annual escalation of 5.72% per annum for the subsequent years. TRANSMISSION SYSTEM • Norms for operation and maintenance expenses shall be as under: Norms for substation (rupees lakh/bay) 765kv 400kv 220kv 132kv and below 73.36 52.40 36.68 26.20 77.56 55.40 38.78 27.70 81.99 58.57 41.00 29.28 86.68 61.92 43.34 30.96 91.64 65.46 45.82 32.73 Norms for AC and HVDC lines (Rs lakh/km) Single Circuit (Bundled conductor with four or more sub-conductors) Single Circuit (Twin & Triple Conductor) Single Circuit (Single Conductor) Double Circuit (Bundled conductor with four or more sub-conductors) Double Circuit (Twin & Triple Conductor) Double Circuit (Single Conductor) Norms for HVDC stations HVDC Back-to-back stations (Rs lakh per 500 MW) Rihand-Dadri HVDC bipole scheme (Rs Lakh) Talcher-Kolar HVDC bipole scheme (Rs lakh) .537 .358 .179 .940 .627 .269 443.00 1450.00 1699.00 .568 .378 .189 .994 .663 .284 468.00 1533.00 1796.00 .600 .400 .200 1.051 .701 .301 495.00 1621.00 1899.00 .635 .423 .212 1.111 .741 .318 523.00 1713.00 2008.00 .671 .447 .224 1.174 .783 .336 553.00 1811.00 2122.00 The total allowable operation and maintenance expenses for the transmission system shall be calculated by multiplying the number of bays and kms of line length with the applicable norms for the operation and maintenance expenses per bay and per km respectively. Depending upon the above mentioned values and strategies, the working capital needs to be managed effectively for the growth of the company and industry as whole. Interest on working capital in case of renewable energy sources The Working Capital requirement in respect of wind energy projects, small hydro power, solar PV and Solar thermal power projects shall be computed in accordance with the following Wind Energy / Small Hydro Power /Solar PV / Solar thermal a) Operation & Maintenance expenses for one month; b) Receivables equivalent to 2 (Two) months of energy charges for sale of electricity calculated on the normative CUF; c) Maintenance spare @ 15% of operation and maintenance expenses The Working Capital requirement in respect of biomass power projects and non-fossil fuel based co-generation projects shall be computed in accordance with the following clause : Biomass Power and Non-fossil fuel Co-generation a) Fuel costs for four months equivalent to normative PLF; b) Operation & Maintenance expense for one month; c) Receivables equivalent to 2 (Two) months of fixed and variable charges for sale of electricity calculated on the target PLF; d) Maintenance spare @ 15% of operation and maintenance expenses Interest on Working Capital shall be at interest rate equivalent to average State Bank of India short term PLR during the previous year plus 100 basis points. Solved questions on working Capital 1. Classic Petrochemical company offers trade credit to its customers of net 30. Credit sales average rs 620,000/day on which the company earns a contribution margin of 20%. The average accounts receivable collection period is 50 days. The appropriate after tax discount rate is evaluating accounts receivable policy changes is 9%. N the company marginal tax is 40%. What is the average balance in accounts receivable? What is the average investment in accounts receivable? What is annual financing cost associated with the investment in receivables? The sales manager believes she can implement a credit policy change that will reduce the average collection period by 4 days without affecting the level of sales. If this policy works as expected then what will be company’s investment in accounts receivables? What will be the net annual after tax advantageto the company of adopting this policy? Suppose the credit policy change will also reduce sales by rs 5,000/day. What would be company’s investment in accounts receivable? What will be the expected effect of this policy change on the company’s after tax net income? Solution The average balance of accounts receivable is: Average A/R balance = rs 620000 * 50= 31000000. Average investment in A/R = 31000000 * .80= 24800000 The cost of financing the investment I receivables is : Cost of financing A/R = 24800000 * .09= 2232000 Reducing the collection period by 4 days will free up: Cash freed up= 4*620000*.80= 1984000 The net advantage is reduced financing cost of the cash freed up: Reduced financing cost = 1984000*.09=178560/year If sales decrease and the average collection period is reduced, new investment in A/R = 615000/(.80) (46)=22632000 New financing cost of A/R = (22632000)(.09)=2036880 There are two effects on sales: Dfinancing cost of A/R= (2232000-2036880)=195120 Dnet profit from lower sales = (5000/day)(365)(.20)(.60)=219000 ∆NIAT ( 195120-219000)= 23880 rupees NOTES: The financing cost of carrying receivables is based on the cost sales since the cost of sales represents the cash paid out in advance of collections. The cash paid out creates a financing need. Here D means additional. 2. Rupesh, credit manager of shell company, is considering a change in the company’s credit terms from net 60 to net 30. Shell has daily credit sales of rs 50,000 and its variable cost ratio is 15%. Tightening credit standards would reduce the average collection period from 75 days to 40 days, reduce daily sales by rs 2000 and lower bad debts from 5% of sales is 40 % and its use an after tax discount rate of 12% to evaluate accounts receivable policy changes. How would be be changes in credit terms affect shell’s after tax income? Solution Old investment In A/R = (75)(50000)(.85)= 3187500 New investment in A/R = (40) ( 48000/day)(.85)= 1632000 ∆Investment in A/R = Rs 1555500 There are three expected changes in after tax net income: ∆Financing cost of A/R investment = (1555500) (.20)= 186660 ∆bad debt expense [(.05)(50,000)(365)-(.03)(48000)(365)](60)= 232140 ∆profit on sales= (2000)(365)(.15)(.60)= 65700 ∆Net profit= 232140-65700= 353100 3. Let’s compare the coal consumption in two different UMPP( mundra, sasan). Mundra using international coal and sasan using domestic coal so how both utilizing the working capital management. Solution According to CERC 40 days cerc should be allowed. For 4000 MW, coal consumption is 40000tonne/day. Shipment charge for the international coal, $6.5/tone/day. So shipment charge, 6.5*50= 325/tone/day. Coal charge =$47=47*50=2350 Total charge = 2350+325=2675/tone/day For international coal we use only 30000tonne/day for 4000mw. So total cost= 2675*30000*40=3210000000 rupees. For domestic coal, the coal rate is 1000, and we use 40000 tonne/day for 4000 mw plant. So the total cost= 1000*40000*40= 1600000000 rupees. So by comparing the two we come to an conclusion , that using international coal, tariff is increasing but the gross calorific value is better in case of international coal. HRM AT POWER STATIONS INTRODUCTION Human resources is a term used to describe the individuals who comprise the workforce of an organization, although it is also applied in labor economics to, for example, business sectors or even whole nations. Human resources is also the name of the function within an organization charged with the overall responsibility for implementing strategies and policies relating to the management of individuals. Under this topic we do the comparative study of HR practices at power stations. For this a comparative analysis of HR policies of NTPC and TNEB has been done. Following diagram shows the general HR hierarchy of a power plant. Fig: HR Hierarchy (A) National Thermal Power Station Overview of the Organisation India’s largest power company, NTPC was set up in 1975 to accelerate power development in India. NTPC is emerging as a diversified power major with presence in the entire value chain of the power generation business. Apart from power generation, which is the mainstay of the company, NTPC has already ventured into consultancy, power trading, ash utilisation and coal mining. NTPC ranked 317th in the ‘2009, Forbes Global 2000’ ranking of the World’s biggest companies. The total installed capacity of the company is 32, 694 MW (including JVs) with 15 coal based and 7 gas based stations, located across the country. In addition under JVs, 3 stations are coal based & another station uses naptha/LNG as fuel. By 2017, the power generation portfolio is expected to have a diversified fuel mix with coal based capacity of around 53000 MW, 10000 MW through gas, 9000 MW through Hydro generation, about 2000 MW from nuclear sources and around 1000 MW from Renewable Energy Sources (RES). NTPC has adopted a multi-pronged growth strategy which includes capacity addition through green field projects, expansion of existing stations, joint ventures, subsidiaries and takeover of stations. NTPC has been operating its plants at high efficiency levels. Although the company has 18.79% of the total national capacity it contributes 28.60% of total power generation due to its focus on high efficiency. At NTPC people before Plant Load Factor is the mantra that guides all HR related policies. NTPC has been awarded No.1, Best Workplace in India among large organisations for the year 2008, by the Great Places to Work Institute, India Chapter in collaboration with The Economic Times. NTPC has taken initiative to develop and implement viable DG projects in remote villages and ensure sustainability for integrated growth of the village. Vision "A world class integrated power major, powering India’s growth, with increasing global presence“ Mission "Develop and provide reliable power, related products and services at competitive prices, integrating multiple energy sources with innovative and eco – friendly technologies and contribute to society" Corporate Objectives • • • • • • • • Business portfolio growth Customer focus Agile corporation Performance leadership HRD Financial soundness Sustainable power development R&D Manpower Profile • • • HRD • • • Installed Capacity Total Human resources Executive Non Executive Man-MW ratio 32694 MW 25944 9500 16444 0.8/MW To enhance organizational performance by institutionalizing an objective and open performance mgmt system. To align individual and organizational needs and develop business leaders by implementing a career development system. To enhance commitment of employees by recognizing and rewarding high performance. Code of Conduct • The Company currently has Conduct, Discipline & Appeal Rules (“CDA Rules”), which govern the conduct of all permanent employees of the Company including Whole-time Directors but excluding Non Whole-time Directors and those governed by the Standing Orders under the Industrial Employment (Standing Orders) Act, 1946. This Code for Board Members has now been framed specifically in compliance with the provisions of Clause 49 of the Listing Agreements entered into by the Company with the Stock Exchanges. In respect of Whole-time Directors this Code is to be read in conjunction with the CDA Rules. • Competence Building • • • • • • • • Talent induction through ET Recruitment system Leadership Development Integrated Career Development system Training infrastructure at CC/Regions/Projects Comprehensive Training System Foreign training Long term education Knowledge Generation & Sharing Culture Building • • • • • Creating a sense of higher purpose by emphasizing Actualization of Vision and Core Values Effective two way Communication System System for Employees’ Participation in Management Partners in Progress workshops Culture of celebration • • • Programs on attitudinal change, Team building Culture of creativity Building HR Competencies amongst Line People Commitment Building • • • • • NTPC Rewards and Recognition systems Strong social security net Mentoring Corporate identity (NTPC geet, NTPC Flag) Sparsh- caring culture Systems Building • Benchmarking • TQM tools such as QC, Business Excellence Model • Performance Management System • Simplification of policies/Single window • Cost control measures • IT enabled KM system(Proposed) Human Resource Policies • • Powering India's Growth : Through people NTPC believes in achieving organizational excellence through Human Resources and follows "People First" approach to leverage the potential of its 25,944 employees to fulfill its business plans. Human Resources Function has formulated an integrated HR strategy which rests on four building blocks of HR viz. Competence building, Commitment building, Culture building and Systems building. All HR initiatives are undertaken within this broad framework to actualize the HR Vision • HR Vision “Enabling the employees to be a family of committed world class professionals making NTPC a learning organization”. HR POLICIES FOR WELFARE AND HEALTH • Demonstrating its high concern for people, NTPC has developed strong employee welfare, health & well-being and social security systems leading to high level of commitment. NTPC offers best quality-of-life through beautiful townships with all amenities such as educational, medical and recreational opportunities for employees and their family members. • • The motivation to perform and excel is further enhanced comprehensive NTPC Rewards and Recognition system. through a HR POLICIES IN TRAINING • To induct talent and groom them into a dedicated cadre of power professionals "Executive Trainee" Scheme was introduced in the year 1977 for recruitment in the disciplines of Mechanical, Electrical, Civil, Control & Instrumentation and now encompasses Computer Science, Chemistry, HR and Finance disciplines also. Besides a comprehensive one year training comprising theoretical inputs as well as on-the-job training, the new recruits are also attached with senior executives under a systematic and formal 'Mentoring System' of the company to integrate them into the Culture of the company. • HR Policies • As part of post employment training and development opportunities, a systematic Training plan has been formulated for ensuring minimum seven man days training per employee per year and includes level-wise planned intervention designed to groom people for assuming positions of higher responsibility, as well as specific need-based interventions based on scientific Training Needs Analysis. NTPC has set up 15 project training centres, 2 simulator training centres and an apex institute namely 'Power Management Institute' (PMI). While the project training centres (Employee Development Centres) have specialized in imparting technical skills and knowledge, PMI places emphasis on management development. Besides opportunities for long term education are also provided through tie ups with reputed Institutions like IIT, Delhi, (M.Tech in Power Generation Technology), MDI, Gurgaon (Executive MBA programme), BITS, Pilani (B.Tech) etc. • • HR Policies For Continued Learning • In order to realize the HR Vision of making NTPC a learning Organization by providing opportunities to continually learn new capabilities a number of initiatives have been taken. NTPC Open Competition for Executive Talent (NOCET) is organized every year in which teams of executives compete annually through oral and written presentation on a topical theme. Similarly "Professional Circles" have been formed department-wise where Executives of the department meet every fortnight to share their knowledge and experiences and discuss topical issues. • • In order to tap the latent talent among non executives and make use of their potential for creativity and innovation, Quality Circles have been set up in various units/offices in NTPC. Besides a management journal called "Horizon" is published quarterly to enable employees to share their ideas and experiences across the organization. In order to institutionalize a strong Culture based on Values a number of initiatives are taken to actualize the Vision and Core Values (BCOMIT) across the company. A culture of celebrating achievements and a strong focus on performance are a way of life in NTPC. NTPC has institutionalized "Development Centers" in the company to systematically diagnose the current and potential competency requirements of the employees with the objective of enhancing their development in a planned manner. These Centers give a good insight to the employees about their strengths and weaknesses, the gaps in their competencies which they can bridge through suitable support from company. Due to innovative people management practices there is a high level of pride and commitment amongst employees as reflected in the various external surveys including “Great Places to Work for in India” in which NTPC was rated third Great Place to work for in the country in 2005. • • • • • Establishment matters pertaining to NTPC employees i) ii) iii) iv) iv) v) vi) vii) Employees’ (Conduct, Discipline and Appeal) Rules. Leave Rules Medical Attendance and Treatment Rules. Post-Retirement Medical Scheme. Promotion Policies. Rules pertaining to House Building Advance, Conveyance Advance; etc. Directives regarding recruitment & promotion of SC/ST Directives regarding recruitment of OBC, Physically Handicapped, Women and minorities. Human Resources Development & Community Development i) Training Policies ii) Guidelines for Community Development, donation to charities, etc. iii) Scholarship schemes for SC/ST students Awards • • • Analysis of HR metrics (Business Today) o NTPC ranked:-1 National award for welfare of person with disability in best employer category Greentech safety award for 2003-04 • • Golden peacock award for excellence in corporate governance Ranked 3rd best employer in business today (B) TAMIL NADU ELECTRICITY BOARD (TNEB) HR practices at TNEB PHILOSOPHY The basic philosophy of the Training is to make training an effective instrument to the personnel of Tamil Nadu Electricity Board in providing the updated knowledge and upgraded skill with positive attitude for consumer delight oriented service. It is viewed that training is no longer expenditure, but construed as an investment. OBJECTIVES The Objectives of the Training Policy are to: Make learning one of the fundamental requirements in TNEB Ensure value addition through training for overall efficient performance.Institutionalise learning opportunities that supplement work experience. Integrate Organizational and individual development needs. Enable employees to keep abreast with the latest knowledge and skills and enable them to undertake current and future responsibilities in a more effective manner. Provide linkages between the different functionaries of training activity. Provide linkages of training activity with overall Human Resource function. Greater emphasis on improving performance with positive attitude rather than merely increasing individual change.More training is done to deal with situations as contrasted to improving the skills of individuals only. Building in - house capability rather than depending on outside experts or resources. Learning is self motivated by learner instead of being imposed upon him. Individuals trained as members of a group so that they will learn to function together in their organizational relationships. DEFINITIONS Training Training shall include on - site field oriented training programme, workshop, seminar, contact programme with manufacturers or development programme based on organizational Needs and / or Training needs analysis. Training Year Training Year shall mean a period of one year commencing from 1st April till 31st March of the subsequent year. In-House Training Programme A training programme is designed, developed and conducted with in TNEB, exclusively for the regular employees of the TNEB, with or without the assistance of external agency. External Training Programme A training programme is designed, developed and conducted with in India, by an outside agency, not exclusively for the employees of the company to which one or more employees of the TNEB may be nominated. Training Abroad Whenever necessity is felt absolute, training to upgrade special skill on latest technologies introduced may be imparted abroad for a selected group of employees. On Completion of training abroad, the employee shall serve in the selected field of training for a specified period. Distance Education The employees may be permitted to undergo distance education, for imparting special managerial skills like HRM, Finance and Project Management etc. Continuance of Education Selected meritorious employees may be deputed to continue education on Technical and managerial courses with an under taking to serve in the board for a specified period after completion of course. Continuance of Education at employees own cost : A percentage of a particular category of employees at a location as decided by TNEB may be permitted to undergo continuance of education on part time basis at their cost provided; such continuance shall not affect their normal duties expected. Planned Intervention A grade/level/category - wise In - House training programme, normally based on a template course design, and conducted to improve competency base of employees as felt necessary by the organization. Need-based Programme A training programme, designed, developed and conducted on the basis of the developmental needs felt, identified for the employees concerned in the Training Needs form. Specified Intervention An external programme or an In-House Training Programme other than a Planned Intervention or a Needbased Programme is conducted to improve certain specified competencies, as felt necessary by the Organization. TRAINING COVERED UNDER POLICY Training shall be imparted once in five years for all technical personnel and once in eight years for all nontechnical personnel. It shall be the endeavor of the TNEB to provide one week of training in a year to every employee Training in some important areas: i) Reforms in Energy Sector ii) Training for trainers iii) Human Resources Development iv) APDRP Programmes TRAINING CALENDAR All the Deputy Directors shall meet in the Regional Head quarters during first week of January to share training calendars. They would also provide inputs to Training Institutes out of the training needs identified by the employer of their respective projects. Each Training Institute / Centre shall bring out, by 15th February every year, a Training Calendar, specifying the schedules of the programmes, both planned interventions and need-based interventions, planned to be conducted by it during the following training year. Each Training centre shall circulate on bi-monthly basis, calendar of programmes scheduled for the next two months to all circle heads (Superintending Engineer). The Training Calendars of the various Training Centres and Institutes would be widely made available to all circles. Copies of training calendar shall be kept in the Training Centres and in the circles. NOMINATION SYSTEM The Objectives of the Nomination System are: To ensure that employees are nominated to training in areas which are relevant to their duties, which have been identified as their development needs (Regular and Special programmes at Institutes and Centers) To ensure that opportunitites to attend training programmes are made available to all employee to achieve the Training Target of average of one week of training in a training year for each employee (Enmass Knowledge Updating Programmes at division level). NOMINATION FOR TRAINING PROGRAMMES Planned Interventions The training Centre / Institute would send the schedules for the next three programmes of a planned intervention to the Circle Heads, who in- turn shall seek preference for nomination from the list of employees to the Training Centres / Institutes. On the basis of the preferences received for nomination, the Training Centre / Institute shall send confirmation. Need Based The training centers will ensure that employees are normally nominated to programmes related to training needs identified. An employee interested in attending any of the training programmes included in the training calendar of the training center of respective area should forward his / her request for nomination through the reporting officer, at least two weeks before the commencement of the programmes to the circle heads , who will decide considering the merit of candidature. External Training Employees may generally be considered for nomination to training programmes only in the areas identified in the Training Needs Analysis and after verifying, whether Within the State i) Engineers are to be imparted training on special field at Appadurai Chair for Power System, Constituted by TNEB at Anna University. Regular interaction may be held between TNEB & Faculties of Anna University in solving the problems. ii) Engineers are to be imparted training on special field at various Management Institutions, Educational Institutions like Anna Institute of Management, Chennai, Engineering Colleges, IIT / Chennai, Madras Productivity Council etc. iii)Engineers are imparted training on Special field of Engineering at various Technical Training Institutes, like BHEL / Trichy, NTPC / Neyveli and at Manufacturer’s works like M/s.ALSTOM, Indo-Tech Transformers, Easun Reyrolle, etc. Outside the State i) Engineers / Officers are to be imparted training on special field at various Management Institutions, Educational Institutions, Technical Training Institutes like, ESCI, ASCI, CIRE at Hyderabad, NTPC / NPTI / PMI / Noida, NITIE / IIT at Mumbai NPC / New Delhi & PSTI / CPRI / HLTC at Bangalore and at Manufacturer’s works like ABB/Vadodhara, Crompton Greaves / Nasik, BHEL/Hardwar etc. Training Abroad Engineers are sent for training abroad at the Manufacturers Works as per PO terms. Training centers shall, as far as possible try to provide training to the employees in house. Employee will normally be nominated for external programmes only for advanced programmes or where conducting the programme In-house is not feasible. The authorities competent to nominate persons for the training programmes are as given below. Deputation for Higher Education Engineers are deputed for doing post graduate courses Like , MBA in power Management at NPTI / faridabad and ME/M.Tech courses at Anna University, Chennai. Specified interventions The Authorities competent to approve specified training programmes are as given below • Plant-level Intervention at Thermal Stations • Training Programmes as per annual calendar Member-Gen. CATEGORISATION OF PROGRAMMES On the basis of duration, training programmes would be captioned as hereunder • Short-duration Up to four days • Medium-duration one week or two weeks • Long-duration above two weeks TRAINING DATABASE Training Centers should maintain a database of training details of all employees of the respective unit, which shall include, 1. Training Needs identified. 2. Training programmes nominated / attended / absented. 3. The training Centers should also maintain details of the programmes conducted, training cost and all other similar information. 4. Director of Training & Development would maintain the training database for all executives. For this, different training agencies should forward training details to Director of Training & Development on a monthly basis. 5. Training details will be periodically up-dated in the personal files of the employees, for which the Training agency would forward the details of nomination / attendance / absence of employees to the Head of personnel concerned. This is the general hierarchy of a Power Generating plant. Here the Chief Engineer is the head of the Unit below which there are a number of Superintendent Engineers for Coal section, O & M etc.. A couple of Section Engineers are reporting to the Superintendent Engineer & are responsible for their respective sections. The section engineer is the person responsible for the day-to-day generating activities in his section. Below section engineer lies the shift Engineer in the Hierarchy. He is responsible of all the shift level activities in the power plant operations which includes running of equipment, monitoring of parameters, filling of log-sheets, marking attendance of contractors & shift labors, delegating jobs to electrical & mechanical depts. etc. There are various sections in a thermal power plant which includes Boiler, Turbine, Cooling Tower etc.. Each section has a contractor & various Gangs working under him. Generally these contractors are Diploma holders & the contract labor is uneducated. Therefore they have least awareness of the amount of gravity of particular equipment in a Thermal power plant. This amount of unawareness often leads to heavy losses in terms of unwanted breakdowns, improper maintenance of equipments & even accidents in the plant. To overcome this problem NTPC designed a special job structure in all of its power plants. This structure is almost the same as above but the change lies at the Bottom most level of the hierarchy, here the contractor is replaced by an Engineer with one or two contract labours working with him. This engineer is trained & fully aware of the problem & issues which will hamper the availability of the power plant. This engineer is coming in shift & is responsible for all the maintenance activities in his area in the shift. There is also the Job rotation in the work which means that the engineer in the Boiler section working for a month will work in the control room for the next month & the person in the control room will work in the respective section replacing the person there. This way NTPC inculcated a sense of urgency & importance among the Bottom most level of the working hierarchy, which constitutes almost 85% of the Breakdowns & about 95% of the accidents in the Thermal Power plant. Conclusion Both the companies follow similar type of policies. They also have a collaboration under which the TNEB employees are trained at various NTPC branches. NTPC has engineers, as its main manpower strength. In NTPC one engineer replaced four staff members in the recent years. Now a days more stress is laid on providing various technical/managerial training to the employees to make them more responsible and growth oriented. MIS in Power Generation, Transmission & Distribution Management Information System (MIS): Management Information System (MIS) is defined as a system that collects and processes data (information) and provides it to managers at all levels who use it for decision making, planning, program implementation, and control. The components of the MIS are: 1. Hardware 2. Software 3. People 4. Communications systems such as telephone lines and data itself. Power Sector… a glance • • • • • The Indian power sector has grown manifold in size and capacity since independence. The generation capacity has increased from 1,362 MW in 1947 to 1,35,780 MW as on today. The per capita power consumption has increased to approximately 384 kWh by 2000-01 and 660 kWh in 2006-07. The access to electricity has improved tremendously with electrification of almost 87% villages and energisation of 65% pump sets. The capacity of transmission and distribution lines has also increased. The efficiency of the thermal plants has improved over the years with the plant load factor (PLF) for thermal power plants at the national level improving to 69% during 2000-01 with approximately 530 billion units generation in the same period. The reform process is in progress in several states under the overall guidance of MoP to achieve vision of “reliable, affordable and quality power for all by 2012” It is aimed at bringing about sustainable improvements in the operations of the utilities and making them viable businesses. The reforms have brought about various improvements in operational structure, commercial orientation, transparency in operation and overall customer orientation in several states. • • • The Role of IT in Reforms • • • To enable the core business operation at the transaction level, INFORMATION SYSTEM would lay the foundation for sustainable reforms. This will ensure world-class practices and controls at the operational level and would enable substantial improvement in the overall health of the utilities. The overall quality of data will improve and thereby an overall improvement in the flow of information for decision support. Information technology (IT) would thus become the key enabler in the initiatives under the reform process. To enable the core business operation at the transaction level, INFORMATION SYSTEM would lay the foundation for sustainable reforms. This will ensure world-class practices and controls at the operational level and would enable substantial improvement in the overall health of the utilities. The overall quality of data will improve and thereby an overall improvement in the flow of information for decision support. Information technology (IT) would thus become the key enabler in the initiatives under the reform process. • • • MIS In Power Sector • • • • • • Management Information System (MIS) for the power sector should provide relevant information at various decision-making levels. It should generate information for grid management and control, for monitoring agencies like regulatory commission and other central agencies like CEA and PFC, and for internal management of SEBs. For SEB management, MIS should provide relevant information at each level of the organisation in a timely and accurate manner. For MIS, information flow is required from lower level to higher level partly in real-time and in batch mode. The real-time information flow requires networking within the organisation. MIS for power sector will include information on finance, operations, customer satisfaction and development/ investment including that of human resources. The structure of MIS should be SEB-specific to address the differences in organizational structures and responsibilities at various levels, but at the same time should be generic enough to provide standard information at the national level. Requirements of MIS Figure below gives the information requirements for some key areas for different levels of management in Distribution companies/SEBs. Information Requirement at Top Level MIS in Generation The major system for power plant monitoring and control are :  Process control system  Plant monitoring system  Operational monitoring system  Power plant maintenance  Automatic generation control  Load frequency control  Economic dispatch Process control system  Closed loop control system that takes it direction from the energy management system (EMS) and automatically collect plant data by reading various measuring instruments.  Physical and electrical parameters associated with the boiler, turbine and generator are monitored on a continuous cycle basis.  Alarms and events are logged for getting any indication of any unwanted conditions.  Controls of pumps, valves and switches for routine functions and for start ups or shutdowns are provided. Plant Monitoring system  Includes Data collection system for fuel monitoring and performance calculation.  No control action are performed  Data is stored and retrieved as required to prepare reports and performance analysis Operational monitoring system  Used by plant operators to enter manually collected operational data for record keeping, report writing and analysis.  In addition to this, the power plant may also use computers for security, controlled access and chemical analysis. Power plant maintenance  It stores pertinent information for analysis of maintenance cost and evaluation of equipment performance.  The interactive portion of the system provides plant personnel with the capability to enter problem data, planning data and work execution data. Automatic Generation Control  Automatic Generation Control (AGC) is a feedback control system that regulates the power output of electric generators to maintain a specified system frequency and/or scheduled interchange.  As the load varies rapidly throughout the day, it is imperative to have a system that will maintain continuous and reliable flow of power within the system. Load frequency control  LFC system monitors generation load, constantly looking for imbalances.  The LFC system needs to maintain frequency at the scheduled value, net power interchanges with the neighboring control areas at the scheduled values and power allocation among generating units at economically desired values. Economic dispatch  The system includes an Economic Dispatch Calculation program that dispatches the system generation required to supply a given load in a manner that minimizes the cost of production.  The dispatcher also selects the appropriate economic parameter set to match the fuel that the generator is currently burning.  Different generating units that are online have different cost of generation.  This system takes into account not only per unit generating cost of power plants but also their geographical location. MIS in Operation  Boiler Operation - Pressure control. - Temperature control. - Steam water mixture control. - Water level control.  Turbine Operation => Valve control - Main steam valve, Emergency stop valve, Control valve MIS in Maintenance • Breakdown Maintenance - After the fault, Corrective measures. • Preventive Maintenance - Before the fault. - Preventive measures. MIS in Power Transmission  Power Transmission manages the construction, operation, and maintenance of grids, transmission substations, and switch stations. The transmission of power is monitored by LDC owned by State/Central. Load Dispatch Centre  The objectives of LDCs are the increasing of the network security and reliability of grid operation, the supporting of grid control with high developed software functions for higher efficiency of generation, transmission and distribution, the promoting of the Energy Management Functions and Scheduling, and the accelerating of the information exchange for economical energy and plant management.  The LDCs have modernized SCADA including RTU in sub-stations and the required telecommunication equipment and links (PLC, Microwave) through which the real time data of whole region system is being displayed. This is very essential for time stamping of the happenings of the system and analysis of the data being acquired through SCADA system.  With the implementation of Availability Based Tariff (ABT), the Techno- commercial aspects of grid operation has become prominent and inter-regional and intra-regional power trading is being done with surplus/ deficit of power. Hence the role of Load Dispatch Centre becomes more vital in trading this power on the basis of frequency of the system. MIS Reports from LDC  Energy Import/Export from one state to other.  Feasibility studies for setting up new Sub Station/Transmission line & Generating Stations.  Reliability Index of each EHT line and Sub Station  Load flow studies  Gap between demand and supply MIS in Distribution Sector  For MIS, information flow is required from lower level to higher levels with some information in real time and some in batch mode. For real time information flow, networking within the organization is needed. In addition to this, information management required for monitoring and decision-making will be different at various levels in hierarchy. MIS should be able to take care of different needs at various levels. Otherwise huge data generated from MIS will not be of any significant use. The structure of MIS should be SEB specific because of difference in their organizational structures and responsibilities at various levels across the organization.  A generalized framework of MIS is presented which may be tailored to suit the needs of specific SEB/utilities.  MIS should not only cover Money Matters but all those major aspects of Power Business, like operations, customer service, development / investment, human resources, information for decision support etc.  Not a standard can be adopted across all utilities, but a generic institutional framework in a national perspective, can specifically be tailored to suit the prevailing culture in each of the utilities leaving ample scope for information concentration and comparison. Flow of Information in Power Distribution Sector Requirement for Implementation of MIS • Periodically collect, collate and convert data into a standard format • Store and analyse the collated data • Identify deficiencies in the existing system by analysing the data • Strategic planning for bringing improvements in the system Benefits of MIS  Availability of accurate and timely information  Effective mechanism for decision Support  Enables pro-active decision making (Such as load planning and demand management)  Identifies possible areas of energy loss (through analysis of consumption and billing patterns)     Target based monitoring mechanism for increased accountability Transparency in administration Aids strategic planning in areas Such as tariff structuring management Develops what if Scenarios Such as analyzing the impacts in tariff plans on the revenue and financial health of the organization Thumb Rules Bolier efficiency- 87.5% Turbine efficiency- 90% (max. efficiency of IPT out of three modules) Condenser efficiency-50%(reasons for imperfect vaccum- air ingress, tube deposits) Fuel cost -66% , operating cost-6%, capital cost-28% Cycle work done heat rejected Carnot 60% 40% Rankine 33% 67% Rankine+reheat 37% 63% Rankine+reheat+regeneration 41% 59% For producing 1 unit of electricity – 620 gms of coal + 5 kg of air is required MW= MVA * power factor 1 MW of plant will require 1 acre of land for coal stacking Maximum height of coal stack- 10 meters Subcritical condition = 170 kg/cm² & 535 ºC supercritical condition = 247 kg/cm² & 535 ºC ultra supercritical condition = 270 kg/cm² & 585 ºC AD 700 technology = 375 kg/cm² & 700-725 ºC, efficiency - 50- 52%, fuel saving & CO2 emission reduction -15% DM water cost = cost of petrol in market Coal washing charge= 249/- / ton At same heat content, price of gas= 60% ( price of oil) 1.0% Deviation in findings means 25000 tons of coal loss/annum for 200 MW Unit or approx Rs. 5 crores / year (4000Kcal coal GCV & Rs.2000/ton coal cost) Difference in cost of Energy Audit between B & A is 12 to 14 lacs as against 6 to 8 lacs. ECONOMIC ASPECTS OF INEFFICIENT MACHINES (200 MW) SHORT FALL LOSS CRORES ANNUM 5.0 5.0 1.75 2.5 IN PER TURBINE CYCLE HEAT RATE TG OUTPUT BOILER EFFICIENCY AUX. POWER CONSUMPTION 1.0 % 1.0% 1.0% 5.0 % NOTE:  TG CYCLE HEAT RATE IS TAKEN AS 2000 KCAL / KWh  COAL CV IS TAKEN AS 4000 KCAL / Kg  PRICE OF COAL TAKEN AS Rs. 2000 / TON  LOSS INCREASES WITH MACHINE SIZE Impact of Turbine Efficiency on HR/Output Description Effect on Effect on TG HR KW 1% HPT Efficiency 1% IPT Efficiency 0.16% 0.16% 0.3% 0.16% 1% LPT Efficiency 0.5 % 0.5 % Output Sharing by Turbine Cylinders are around HPT IPT LPT 28% 23% 49% Effect of Condenser Vacuum on Heat Rate 10 MM HG IMPROVEMENT IN CONDENSER VACUUM LEADS (1%)IMPROVEMENT IN HEAT RATE FOR A 210 MW UNIT EFFECT ON HEAT RATE FOR PARAMETER DEVIATION (500MW UNIT) DEVIATION IN PARAMETER EFFECT ON HEAT RATE (KCAL/KWH) 1. 2. 3. 4. 5. 6. 7. HPT inlet press. by 5.0 ata HPT inlet temperature by 10.0 deg C IPT inlet temperature by 10.0 deg C Condenser pressure by 10.0 mm of Hg Re spray water quantity by 1.0% HPT Cylinder efficiency by 1.0% IPT Cylinder efficiency by 1.0% 6.25 6.0 5.6 9.0 4.0 3.5 4.0 TO 20 Kcal/kwh
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PSM Compilation

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POWER STATION MANAGEMENT Compailed by Dr.Rohit Varma Dy.Director,NPTI CAMPS,Faridabad Table of Contents Chapter 1 2 3 4 5 6 7 8 9 10 11 Coal Scenario Gas Trends in India Topics Page No. 3 34 62 80 90 131 145 157 204 215 229 Statutory Requirement of Trained Manpower Contract Labour Act Turbine Efficiency Efficiency of Hydro Power Plant Working Capital and Cost Management Strategy Safety Act Human Resource in Power Sector Boiler Efficiency MIS in Power Sector External Marks: 70 Internal Marks: 30 Time: 3 hrs. POWER STATION MANAGEMENT Paper – PM 2311 Unit I Management of Fuel, Water Resources, Electricity Demand Scenario, vis-a-vis fuel supply, storage and handling of coal/oil/gas, coal/gas linkages, pricing, contracts, inventory control. Unit II Performance Management, Boiler Efficiency, Turbine Efficiency, Cycle Efficiency, Monitoring and control of heat rate, other performance parameters, Efficiency of hydro Plants, Energy conservation & Efficiency measures, Maintenance Planning. Unit III Statutory requirements, trained manpower as per Indian Electricity Rules, Apprising of Act, Factories Act, Contract Labour Act, Environmental regulations etc. Unit IV Working capital Management, Cost Management Strategies, Human Resources Management, Management Information system. Suggested Readings: 1. 2. Power Plant Performance Management, Butter Worth, A.B. Gill – 1984 Modern Power Station Practice, Publisher British Electricity Authority. 3. Power Station Engg. & Economy by – B.G.A. Skrotzki & W.A. Vopat , Tata McGraw Hill. 4. Standard Plant Operators Manual – Third Edition – Stephen Michael Elanka, McGraw Hill Book Company Coal What is Coal? Coal is a combustible, sedimentary, organic rock formed from ancient vegetation, which has been consolidated between other rock strata and transformed by the combined effects of microbial action, pressure and heat over a considerable time period. This process is referred to as 'coalification'. Coal is called a fossil fuel because it was formed from the remains of vegetation that grew as long as 400 million years ago. It is often referred to as "buried sunshine," because the plants which formed coal captured energy from the sun through photosynthesis to create the compounds that make up plant tissues. The most important element in the plant material is carbon, which gives coal most of its energy. It is found in seams/coal beds which vary from a few inches to 100’ more in thickness. On the basis of amount of ground cover or over burden the coal can be mined by the surface method (complete removal of overburden) or deep (underground) method. The Origins of Coal Coal is a readily combustible rock containing more than 50% by a weight of carbonaceous material, formed from compaction and in duration of variously altered plant remains similar to those in peat. Most coal is fossil peat. Coal is composed mainly of carbon (50-98%), hydrogen (3-13%) and oxygen, and smaller amounts of Nitrogen, Sulphur and other elements. It also contains a little water and grains of inorganic matter that remain as a residue known as ash when coal is burnt. Peat is an unconsolidated deposit of plant remains from a water saturated environment such as a bog or mire, structure of vegetal matter can be seen and when dried peat burns freely. Coal is formed by the physical and chemical alteration of peat (coalification) by processes involving bacterial decay, compaction, heat and time. Coal is an agglomeration of many different complex hydrocarbon compounds. Peat deposits contain everything from pristine plant parts (roots, barks, spores etc) to decayed plants, decay products & even to charcoal if the peat caught fire. Peat deposits formed in a waterlogged environment where plant debris is accumulated, peat bogs and peat swamps are examples. For the peat to become coal it must be buried by sediment. Burial causes the compaction of peat and much water is squeezed out during the first stage of burial. Continued burial and addition of heat and time causes the complex hydrocarbon compounds in the deposit to start to breakdown and alter in the varieties of ways. The gaseous alteration products (methane is one) are typically expelled from the deposit and the deposit becomes more and more carbon rich (other elements drop out). The stages of this trend proceed from plant debris, peat, lignite, sub-bituminous coal, bituminous coal, anthracite coal to graphite (a pure carbon mineral). It is estimated that because of squeezing and water loss it took vertical 10 feet of original peat material to produce 1 vertical foot of bituminous coal. Coal Types 1) Anthracite is a type of coal with the highest carbon content, between 86 and 98 percent. Heat value of nearly 15,000 BTUs-per-pound. Most frequently associated with home heating, anthracite is a very small segment of the world coal market. 2) Bituminous coals are dense black solids, frequently containing bands with a brilliant lustre. The carbon content of these coals ranges from 78 to 91 percent and the water content from 1.5 to 7 percent. Bituminous coal has a heat value of 10,500 to 15,500 BTUs-per-pound. 3) Sub-bituminous coals usually appear dull black and waxy. They have carbon content between 71 and 77 percent and a moisture content of up to 10 percent and are used for electricity generation or can be converted to liquid and gaseous fuels. Heat value between 8,300 and 13,000 BTUs-perpound. 4) Brown coals or lignite have a high oxygen content (up to 30 percent), a relatively low carbon content (60-75 percent on a dry basis), and a high moisture content (30-70 percent). Heat value ranging between 4,000 and 8,300 BTUs-per-pound. Peat 5% 5% 92% Lignite 38% 19% 43% Bituminous 65% 32% 3% Anthracite 96% 1% 3% Carbon Volatile Water Proximate analysis of coal Proximate analysis indicates the percentage by weight of fixed carbon of fixed carbon, Volatiles, Ash content and moisture content in coal. The amount of fixed carbon and volatile combustible matter directly contribute to heating value of coal. Fixed carbon acts as main heat generator during burning. High volatile matter content indicates easy ignition of fuel. The ash content is important in the design of furnace grate, combustion volume pollution control equipment and ash handling systems of a furnace A typical proximate analysis of various coal is given below: - Significance of various parameters in proximate analysis a) Fixed carbon Fixed carbon is the solid fuel left in the furnace after volatile matter is distilled off. It consists mostly of carbon but also contains some hydrogen, oxygen, sulphur and nitrogen not driven off with gases. Fixed carbon gives a rough estimate of heating value of coal. b) Volatile matter Volatile matters are the methane, hydrocarbons and carbon monoxide and incombustible gases like carbon dioxide and nitrogen found in coal .Thus the volatile matter is an index of gaseous fuels present. Typical range of volatile matter is 20% to 35%. • Proportionately increases flame length and helps in easier ignition of coal. • Sets minimum limit on the furnace height and volume. • Influences secondary air requirement and distribution aspects. • Influences secondary oil support. c) Ash Content Ash is an impurity that will not burn. Typical range is 5% to 40%. Ash • Reduces handling and burning capacity. • Increases handling costs. • Affects combustion efficiency and boiler efficiency. • Causes clinkering and slagging. d) Moisture content Moisture in coal must be transported handled and stored. Since it replaces combustible matter, it decreases the heat content per kg of coal. Typical range is 0.5% to 10%.Moisture • Increases heat loss, due to evaporation and superheating of vapor. • Helps to limit, in binding fines. • Aids radiation heat transfer. e) Sulphur Content Typical range is 0.5% to 0.8%. • Affects clinkering and slagging tendencies. • Corrodes chimney and other equipment such as air heaters and economizers. • Limits exit flue gas temperature. Ultimate analysis of coal The ultimate analysis splits up fuel into all its component elements, solid or gaseous. This analysis must be carried out in a properly equipped laboratory by skilled chemist. The ultimate analysis indicates the various elemental chemical constituents such as carbon, hydrogen, oxygen, sulphur etc.It is useful in determining the quantity of air required for combustion gases. This information is required for the calculation of flame temperature and the flue ducts design etc. Relation between Proximate and Ultimate Analysis %C =0.97C+0.7(VM+0.1A)-M(0.6-0.01M) %H2 =0.036C+0.086(VM-0.1XA)-0.0035M2 (1-0.02M) %N2 =2.10-0.020VM Where C % of fixed carbon A % of ash VM % of volatile matter M % of moisture COAL RESOURCES OF INDIA As a result of exploration carried out up to the depth of 1200m by the GSI, CMPDI and MECL etc, a cumulative total of 267.21 Billion tonnes of Geological Resources of Coal have so far been estimated in the country as on 1.4.2009. The state-wise distribution of coal resources and its categorisation are as follows: (in Million Tonnes) State Geological Resources of Coal Proved Indicated Inferred Total Andhra Pradesh 9194 6748 2985 18927 Arunachal Pradesh 31 40 19 90 Assam 348 36 3 387 Bihar 0 0 160 160 Chhattisgarh 10910 29192 4381 44483 Jharkhand 39480 30894 6338 76712 Madhya Pradesh 8041 10295 2645 20981 Maharashtra 5255 2907 1992 10154 Meghalaya 89 17 471 577 Nagaland 9 0 13 22 Orissa 19944 31484 13799 65227 Sikkim 0 58 43 101 Uttar Pradesh 866 196 0 1062 West Bengal Total 11653 105820 11603 123470 5071 37920 28327 267210 Categorisation of Resources: The coal resources of India are available in sedimentary rocks of older Gondwana Formations of peninsular India and younger Tertiary formations of north-eastern/ northern hilly region. Based on the results of Regional/ Promotional Exploration, where the boreholes are normally placed 1-2 Km apart, the resources are classified into Indicated or Inferred category. Subsequent Detailed Exploration in selected blocks, where boreholes are less than 400 meters apart, upgrades the resources into more reliable ‘Proved’ category. The Formation-wise and Category-wise coal resources of India as on 1.4.2009 are given below: (in Million Tonnes) Formation Proved Indicated Inferred Total Gondwana Coals 105343 123380 37414 266137 Tertiary Coals 477 90 506* 1073 Total 105820 123470 37920* 267210 * Includes 456 Mt of Inferred resources established through mapping in NE region. The Type and Category-wise coal resources of India as on 1.4.2009 are given in table below: (in Million Tonnes) Type of Coal Proved Indicated Inferred Total (A) Coking :Prime Coking 4614 699 0 5313 Medium Coking 12449 12064 1880 26393 Semi-Coking 482 1003 222 1707 Sub-Total Coking 17545 13766 2102 33413 (B) Non-Coking:87798 109614 35312 232724 (C) Tertiary Coal 477 90 506 1073 Grand Total 105820 123470 37920 267210 Status of Coal Resources in India during Last Five Years: As a result of Regional, Promotional and Detailed Exploration by GSI, CMPDI and SCCL etc, the estimation of coal resources of India has reached to 267.21 Bt. The estimates of coal resources in the country during last 5 years are given below: (in Million Tonnes) As on 1.1.2004 1.1.2005 1.1.2006 1.1.2007 1.4.2007 1.4.2008 1.4.2009 Geological Resources of Coal Proved Indicated 91631 116174 92960 117090 95866 119769 97920 118992 99060 120177 101829 124216 105820 123470 Inferred 37888 37797 37666 38260 38144 38490 37920 Total 245693 247847 253301 255172 257381 264535 267210 Gross Calorific value of Coal The heating value of coal varies from country to country and even from mine to mine in same country. The typical values of GCV of different types of coal are as follows: Grade Useful Heat Value (UHV) (Kcal/Kg) UHV= 8900-138(A+M) A Exceeding 6200 B Exceeding 5600 but exceeding 6200 C Exceeding 4940 but exceeding 5600 D Exceeding 4200 but exceeding 4940 E Exceeding 3360 but exceeding 4200 F Exceeding 2400 but exceeding 3360 G Exceeding 1300 but exceeding 2400 Corresponding Ash% +Gross Calorific Value GCV (Kcal/ Moisture % at (60% RHKg) (at 5% moisture level) & 40O C) Not exceeding 19.5 Exceeding 6454 not19.6 to 23.8 Exceeding 6049 but not exceeding 6454 not23.9 to 28.6 Exceeding 5597 but not exceeding. 6049 not28.7 to 34.0 Exceeding 5089 but not Exceeding 5597 not34.1 to 40.0 Exceeding 4324 but not exceeding 5089 not40.1 to 47.0 Exceeding 3865 but not exceeding. 4324 not47.1 to 55.0 Exceeding 3113 but not exceeding 3865 Coal Companies in India • Coal India Ltd (CIL) and its subsidiaries o Eastern Coal fields Limited o Western Coal fields Limited o Northern Coal Fields Limited o Bharat Coking Coal Limited o South Eastern Coalfields Limited • Neyveli Lignite Corporation (NLC) • Singraeni Colliery Company Limited (SCCL) Coal Linkages The Linkages of coal demand is primarily done with the objective of planning of coal supplies, keeping in view indigenous coal resources as well as the need to supply fuel of appropriate quality to the consumers and at the same time making the most economic use of the available capacity for production and of coal. For thermal power stations, whether belonging to state or central generating stations coal linkage is given by Coal Ministry’s standing committee on coal linkages. The linkages are classified in two types:• Long term linkages • Short term linkages Standing Linkage Committee (Long Term) for Power & Cement Sectors The consumers desiring linkage for supply of coal should apply for linkage to the SLC (long Term). The consumers should route the application through the concerned Ministry to the Chairman, SLC (LT). For example, for setting up a Power Plant, the application has to be routed through the Central Electricity Authority and Ministry of Power. In case of cement unit, it has to be routed through the Ministry of Industry, Ministry of Industrial Policy & Promotion. The SLC (LT) has the Additional Secretary in the Ministry of Coal as the Chairman. Other members of the SLC (LT). Are representatives of CIL, representatives of SCCL, CMPDIL, Railways, Planning Commission, Central Electricity Authority, Ministry of power and representative of Ministry of Industry, Dept. of Industrial Policy & Promotion (as the case may be). The Committee decides the linkage of coal for source of supply, quantum of coal and the made of transportation. Standing Linkage Committee (Short Term) for Power and Cement Sectors The Additional Secretary in the Ministry of Coal, Govt. of India is the Chairman of the Committee. Representatives of Coal India Limited, Central Electricity Authority, Ministry of Power, Railways, and Representatives of Singareni Collieries Co. Ltd. are the member of SLC (ST) for power sector. In SLC (ST) for cement sector besides Chief of Marketing of CIL, representatives of SCCL, Railways, Ministry of Industry, Dept.of Industrial Development are the other members. The committee meets in March, June, September and December each year to review the coal supplies to Power and Cement Sectors in the quarter and finalise the linkage to consumers in Power and Cement Sectors for the next quarter. Time to time adjustment/incorporation in the quarterly linkages is done by the Chairman’s (ST). Minutes of the meetings are drawn and circulated to all concerned for implementation. As per MoP guidelines coal linkage & coal block allotment to Power Plants is done in following order: (i) Projects proposed to be executed by Central Public Sector Undertakings / organizations and state public sector organizations (namely, generating companies, Electricity Boards etc) may be accorded the first priority. Within this group expansion projects will have higher priority in view of their shorter gestation. (ii) Joint Venture projects, namely, joint venture between Central Sector and State Sector or between the two states, or Central/State with private sector with substantial say in the matter of management of the Joint Venture by the public sector, may be accorded next priority. (iii) IPP projects, which have been allowed tariff approval by the appropriate tariff commission under Section 62 of the Electricity Act, 2003. (iv) Projects being developed on the basis of competitive bidding for tariff under Section 63 of the Electricity Act. This would include Ultra Mega Projects and projects being developed on similar lines by the distribution companies/State Electricity Boards or agencies authorized by them to be the Nodal Agency for development of such projects. (v) Expansion of existing IPP plants which are already supplying power to the grid as per tariff policy and captive power plants supplying at least 25% of their capacity to the grid. (vi) Other captive power plants. (vii) Merchant Power Plants. (a) Linkage to the plant upto a capacity of 1,000 MW; and (b) Captive coal block allotment for plants in the range of 500 – 1000 MW capacity. (viii) Any other category not covered above. Coal Pricing in India Production costs of coal vary widely between open cast and deep pit mines and between mining areas: Some mines produce coal at a profit and clearly below the price of imported coal – some mines produce at a loss compared to domestic and international prices. In the coal value chain from mines mouth to power plant and to the final electricity consumer, many decisions on cost optimization have to be made: Coal transport vs. wheeling of electricity, coal transportation by ship or by rail, reducing the ash content at the mine mouth or transportation of higher volumes. SCHEDULE- IX [This shall form SCHEDULE- IX to CSA ] Breaking down the total washed coal price into its components and development of Price Escalation Formula [ for supply of washed coal from Piparwar Washery of CCL to NCPP- Dadri Power Station of NTPC]. I: Total Washed Coal Price comprises of (a) Raw Coal Price Component with statutory charges on Raw Coal (b) Washing Charges Component with Statutory Charges on Washed Coal II: Escalation Formula for – (a) Raw Coal Price Component (b) Washing Charges Component With adjustment in Price due to Revision of Statutory Charges DETAILS: The price of coal delivered consists of following components: 1. Basic Price 2. Other Charges 3. Statutory Charges 1. Basic Price of Run Of Mine coal shall be determined as under: • Under Price Notification: Price was notified by Government of India and/or notified by any other body designated by Government of India Coal Price Under De-Control Regime ( With price escalation provision): In the event of decontrol of the price of coal in full or in part, or any exemption duly notified by the Government of India in respect of any mine. The Basic prices of coal as mentioned earlier shall be subject to escalation in accordance with a Price Escalation formula. 2. Other Charges: • Transportation Charges: Where coal is transported by the seller beyond the distance of 3 Kms from the pit-head to be delivery /unloading point and the purchaser shall pay transportation charges as applicable time to time • Sizing/Crushing Charges: Where the coal is crushed by mechanical means for limiting the top size to 200mm -250 mm depending on coal agreement. The purchaser shall pay sizing/crushing charges as applicable from time to time. • Rapid Loading Charges: Where coal is loaded through Rapid Loading System either into Indian Railways system or into Purchaser’s Own MGR, Purchaser shall pay Rapid Loading charges as applicable from time to time> (Note : Rapid Loading Charges should be paid only if Rapid Loading system (cl1.25) which automatically loads coal i.e. 3500 or more tonnes per hour. 3. Statutory Charges: The Statutory Charges shall comprise of : Royalties, Cesses, Duties, Taxes, Levies etc. if any, shall be payable by the purchaser subject to –Provisions of relevant statute and not included in the basic price, shall become effective from the date as Notified by the Government. Compensation for Excess Superficial Moisture: • If the monthly weighted average total moisture in coal exceeds the permissible % age level given in clause 10.2 of this agreement over the monthly weighted average equilibrated moisture at 40 Oc and 60% RH equilibrated moisture • Pro-rata correction factor equivalent of the percentage by which the total moisture exceeds the equilibrated moisture. • Shall be applied to the weights recorded by the weighment system • This aspect should be taken care of for the purpose of billing and payment supplies during that month. • The agreement provides that- The permissible limits are to be reviewed and revised based on study through Joint reference to Central Fuel Research Institute, Dhanbad. If the studies are not completed within six months, the permissible moisture limits provided in this agreement shall be taken as final for adjustments in quantity of coal with retrospective effect. The total moisture determination shall be jointly undertaken forthwith as per BIS, without waiting for the norms to be fixed through the • Study to be conducted by CFRI I. Breaking up of total price of washed coal ( P ) into Raw Coal Component (P R ) ; Statutory Charges Component on Raw Coal (Psr) ; Washing Charges Component (PW) and Statutory Charges Component on Washing Charges, if any (Psw) : Corresponding price break up of Rs 715 and Rs. 930 per tonne are – Component Symbol Rs/ tonne Rs/ tonne (effective from (effective from 1.4. 1997) 1.4.2001) Basic Raw coal Price (BP) 332 431 + Crushing Charges (CR) PR 20 20 Statutory Charges on Raw Coal (Ro) =Royalty + (SE)= SED Add: Adjustment due to Yield Factor (Yc) Total Raw Coal Component Price Washing charges = + Wage Revision Adjustment Total Price of Washed Coal PSr Extra  PW (P) 50 3.50 83.78 489.28 225.72 715.00 50 3.50 154.97 659.47 268.48 +2.04 930.00 The above shall be the base prices for the purpose of escalation w.e.f. 1-4-1997 and 1-4-2001 respectively. II. Derivation of price escalation formula for the components of washed coal i.e. A-I: Raw Coal Component(PR) A-II: Washing Charges Component(PW) In addition: Adjustment for Statutory Charges (PSr and PSw ) and adjustment due to Wage revision Yearly Escalated Price of coal in terms of Rs / Tonne may be determined by the following formula: Let, PR0 = Price of coal on a mutually agreed date to be termed as “Base Date”(from which date price escalation to be calculated for the first time or any subsequent times) PR1 = Escalated price of coal to be calculated annually on the date of revision A-I: Price escalation formula for the RAW COAL components: PR1 = PR0 + dPR1 + dPR2 + dPRW + Escalation on Breaking Charges A1 B1 C1 dPR1 PR0 X [{ 44 + W1 X ------+ W2 x-------+W3 x --------= A0 B0 C0 D1 E1 ------- + W5 x ----- } / 100] – PR0 D0 E0 W1 , W2 , W3 , W4 , W5 are respectively the Weights for (1) Salaries & Wages (2) POL (3) Explosives ; (4) Power and (5) Other stores including spares. PART-2: dP2 =Coal price escalation in Rs/tonne on account of Depreciation, Interest and Pre-tax Return which are based on the variation in Net Block per Tonne of Coal (related to capacity) of the linked / dedicated mine of the Seller. = For variation of every Rs 10 in the net block per tonne of coal (related to capacity), the impact of price on per tonne of Coal (Rs per tonne) shall be: dP2 = Rs 2.50 * (F1 – Fo)/10) per tonne PART 3 (dPRW ) : Escalation factor to take care of the revision of salaries and wages for the regular employees of CCL engaged in the linked / dedicated mine catering to supplies of coal to Piparwar Washery: + W4 x By using the following formula tonne (Rs./tonne) : Total additional amount payable per month to the regular employees as additional salaries & wages on account of salary / wage revision for the linked / dedicated mine, after such revised amount is officially declared and is actually paid after 1-4-2001 dPRW = -----------------------------------------------------------Total installed capacity of the mine on MT basis, related to linked / dedicated mine supplying coal to Piparwar Washery / 12 . Escalation of Breaking Charges: The escalation of breaking charges shall be based on following formula: E1 Escalated Breaking Charges (CR )= CR x ( 0.75 + 0.25 x -------- ) E0 A-II: Price escalation formula for the Washing Charges components: (A) Formula for dPW1 : The agreed formula of price escalation for the washing charges part derived from the Minutes of Meeting dt. 7-8-1988 is as under: a1 b1 c1 d1 e1 n dPw1 = Pw0 x ( w1 x-----x (1.03) --+w2x--+w3x -----+w4 x ----+w5 x----a0 b0 c0 d0 e0 f1 +w6 x-------+w7 }/100 - PWO + { PSw + (g1 - g0) } f0 Weights, Indices, Notifications for Price ESCALATION CALCULATIONS are detailed below: Compon ent Salaries & Wages POL Explosiv es Power Other stores Symbo l W1 Weigh ts in % 9 Indices / basis Symbols Part 1: Items of Cost of Sales which is linked to published indices/ SEB tariff notifications / Govt. notification on Diesel Price and CIL rate contract on SMS. W2 W3 W4 W5 4 5 6 32 AICPI for industrial workers available Ai in www.chd.nic.in (published by Govt of India) Actual Diesel price notified by the Bi Govt. Rate Contract for SMS notified by CIL Ci Tariff Revision notified by SEBs WPI available www.eaindustry.nic.in (published by Govt of India) Di in Ei ANNEXURE- A Calculation of Price break-up for of WASHED COAL supplies to DADRI from Piparwar as on 1-4-1997 and 1-4-2001 Unit of Measurement As of 1.4.97 Tonne 6,500 5,525 4,585 940 Amount (in 000) 1,834,300 110,500 276,250 19,338 Amount per Tonne Escalated as on 1-4-2001 1 2 3 4 I a b c e II III a b c d e f g h IV Rated Capacity Raw Coal input ( 85% of 1) here the capacity of the mine is considered at 85%. Tonne Beneficiated Coal ( 83% of 2 ) here taken as the agreed yield for beneficiated coal Tonne Rejects & Slurry ( 2 - 3 ) Tonne Raw Coal Part: Raw Coal Input Costs Basic Price (Bp) Rs Breaking charges (CR) Rs Total Raw Coal Price (PR) Royalty (Ro) Rs Stowing Excise Duty(SE) Rs Total Statutory Charges (Psr) Rs Total PR+Psr Yield adjustment Factor (Yc) Yield adjustment Amount Raw Coal Component Price Rs Washing Charges Variable Costs : Wages Cost(W1) – AICPI Rs Stores - PoL (w2) - Diesel) Rs Stores - Others (w3) -WPI Power (W4) - SEB Tariff Rs Misc Expenses (w5) - WBI Rs Admn Charges - (W6) Rs TOTAL Variable --> Fixed Costs: Int on Working Capital (Fixed) Rs Depreciation (Fixed) Rs Int on Loan Capital ( Fixed) Rs Return on Equity ( Fixed ) Rs Total Washing Charges (excl Wage Revision)--> PW Wage Revision (as per CCL)-PWW Price of Washed Coal (P) Transportation Cost TOTAL Price incl Surface Transportation 0 431 20 451 50 3.5 53.50 504.50 1.205 104.24 608.74 23,429 31,070 74,568 38,652 51,306 53,690 7.39 14.10 19.58 12.33 13.81 14.46 2,889 231,130 262,766 264,047 0.63 50.47 57.39 57.66 247.83 1.89 858.46 50.10 908.56 (say 909) V VI VII Rs Rs Rs Calculation of increase in coal price during the period Jan 2000 to Dec 2004 as per escalation formula submitted to XXXX. Proposed price escalation formula: A1 B1 C1 D1 E1 F1 P1 = PO ( X + w1 x ---- x (1 + y) + w2 x ---- + w3 ---- + w4 x ---- + w5 x ---- x w6 x -----) A0 B1 C0 D0 E0 F0 X Y AO A1 BO B1 CO CI DO D1 EO E1 FO F1 W1 W2 W3 W4 W5 W6 = = = = = = = = = = = = = = = = = = = = % of total sale price considered as fixed = 10% Annualized increase in wages due to pay revision = 3.35% AICPI as on Jan 2000 = 2125 AICPI as on Dec 2004 = 2588 RBI index of mineral oil as on Jan 2000 = 172.04 RBI index of mineral oil as on Dec 2004 = 330.8 RBI index of explosives as on Jan 2000 = 124.03 RBI index of explosives as on Dec 2004 = 127.00 RBI index of power as on Jan 2000 = 166.3 RBI index of power as on Dec 2004 = 252.2 WPI for all commodities as per RBI Index as on Jan 2000 = 146.1 WPI for all commodities as per RBI Index as on Dec 2004 = 188.2 RBI index for “Heavy Machinery” as on Jan 2000 = 143.4 RBI index “Heavy Machinery” as on Dec 2004 = 189.9 Weightage for salary & wages = 42 % Weightage for POL = 6% Weightage for explosive = 3% Weightage for Power = 9% Weightage for other expenditure including other stores & spares = 21% Weightage for Heavy Machinery = 9% 2588 330.8 127.0 252.2 188.2 189.9 P1 = 100 ( 0.10 + 0.42 x ------- x (1 + 0.0335) + 0.06 x -------- + 0.03 -------- + 0.09 x ------- + 0.21 x -------x 0.09 x ----- ) 2125 172.04 124.3 166.3 146.1 143.4 Increase in 5 years = 37.54% Annualized increase = 6.58 Note: The weightage have been arrived at on the basis of cost sheet of CIL (OCP & UG) for the year 03-04 Government of India deregulated the prices of Non-Coking Coal of grades A, B & C, Coking coal and Semi/Weakly coking coal on 22.03.1996. Subsequently, on 12.03.1997, Government of India deregulated the prices of non-coking coal of grade D, Hard Coke and Soft Coke and also allowed Coal India Ltd. to fix coal prices for grades E, F & G till Jan'2000 once in every six months by updating cost indices as per escalation formula contained in the 1987 report of the Bureau of Industrial Cost & Prices. With effect from 01.01.2000, CIL was free to fix the prices of all grades of coal in relation to the market prices. Pursuant of the above, CIL fixed the prices of deregulated coal from time to time and last such revision has been made on 15-10-09, to be effective w.e.f 00 hrs of 16-10-09. Grade wise Basic Price of coal at the Pit-head excluding statutory levies for Run-of-mine (ROM) Non-LongFlame Coal ,Long flame Coal, Coking Coal, Semi Coking Coal& Weakly Coking Coal ,direct feed Coal, Assam Coal for various subsidiaries of CIL are tabled below : Table: IA Table: IB Table: IC NOTE: 1. In Grade "A" for every additional UHV of 100K Cal /Kg. exceeding 6299 K Cal /Kg, Additional Rs.90 /M Te. shall be added to the price of " A "Grade. 2. For UHV exceeding 7099 k. Cal./ kg. ,the price of coal shall be Rs.3680 per tonne for ROM Coal and the price difference among the steam ,slack and run of mine coal shall remain same. The revised pithead prices of all varieties of Run of Mine Coals have been given in tables I to V. Notes: 1. Additional Rs.20 per tonne shall be charged on pithead price of Run of Mine coal for the supply of Slack Coal. 2. Additional Rs.180 per tonne shall be charged on pithead price of Run of Mine Coal for the supply of Steam Coal. 3. Where the top size is being limited to any maximum limit within the range of 200 mm – 250 mm through manual facilities or mechanical means, a charge at the rate of Rs.39.00 per tonne will be levied, in addition to the price applicable for Run of Mine coal. 4. Where the top size is being limited to 100 mm through manual facilities or mechanical means, a charge at the rate of Rs.61.00 per tonne will be levied, in addition to the price applicable for Run of Mine coal. 5. Where the top size is being limited to 50 mm through manual facilities or mechanical means, a charge at the rate of Rs.77.00 per tonne will be levied, in addition to the price applicable for Run of Mine coal. 6. Where coal is loaded, either into Indian Railways system or into the purchasers’ own system of transport, through high capacity loading system with a nominal capacity of 3500 tonnes per hour or more, additional charge of Rs.20.00 per tonne shall be levied for such loading. 7. Where coal is transported beyond a distance of 3 kms to the loading point, the coal companies shall be entitled to charge additional transport costs from the purchasers at the following rates 1. For a distance of more than 3 kms but not more than 10 kms Rs.44.00 per tonne. 2. For a distance of more than 10 kms but not more than 20 kms Rs.77.00 per tonne. In cases, where coal is transported for more than 20 kms to the loading points, transport charges will be payable on actual basis, to be borne by the purchaser. 8. The pit head prices fixed are exclusive of Royalty, Cess, Taxes and Levies, if any, levied by the Govt., Local Authorities or any other bodies of Excise and Sales Tax from time to time. 9. Grading/ classification of coal and the definitions relating to the same have been given in Annexure –X. 10. The prices given in this notification are either FOR or FOB, as the case may be. Surface transportation charges, where applicable, would be levied extra. 11. The prices do not apply to coal sold for export. 12. For undertaking special sizing or beneficiation of coal, additional charges as may be negotiated between the purchaser and the producer may be realized over and above the pithead prices . 13. A rebate of 5% for supply of wahsery grade coking coal will be given to power houses other than captive ones. 14. The revised basic price of ROM coal for ECL being notified shall be applicable except for the portion of Raniganj coal of grades A & B from such mines of ECL which are supplied under MOU to specific consumers at special price. ROYALTY ON COAL The rates of royalty, which shall be a combination of specific and ad valorem rates of royalty which shall be as follows: R (Royalty Rs/Tonnes) = a +bP Where ‘P’ (Price) shall be the basic pit head price of ROM (run-of time) coal and lignite excluding taxes, levies and other charges. And the value ‘a’ is Fixed Components and ‘b’ is Variable or ad valorem Components. Latest in Coal Pricing Coal Pricing, at present, is fixed by coal ministry in consultation with Coal India Ltd. (CIL) & Singareni Collieries Company ( SCCL ) . The prices are determined on the basis of cost incurred in Coal Production from different mines. Present domestic coal prices range between Rs 770 and Rs 1,700 a tonne. • The expert committee on Integrated Energy Policy headed by Kirit Parikh, has recommended setting up of an independent Coal Regulator to replace government committees for determine coal prices for different user industries. Functions of Regulators:• • • • • Ensure price revisions. Suggest measures for Setting Coal prices. Regulate trading margins. Ensure that price discovery through e-auctions is free of distortions. Ensure coal supply to the power sectors under commercially driven Long – term Fuel Supply & Transport Agreements ( FSTAs) New Coal Royalty System in India The present system of royalty charging is likely to change to combined royalty rates ( fixed plus ad valorem ) to balance the aspirations of the coal producing states and apprehensions of the consumers. This new system of royalty would jack up coal prices by 10 to 15 % taking up the overall royalty components on coal prices to 15 -20 % level. Inventory Control of Coal Implication of CERC and CEA CERC (Terms & Conditions of Tariff) Regulations, 2009 As per the CERC (terms and conditions of tariff) Regulation, 2004 the 2 months coal cost (non peat head) power plant and 1 and half months of coal cost (pit head) has to be taken in the working capital. E.g. for a 1000 MW plant Coal consumption for 1 day = 10000 ton Cost of coal for 1 day = Rs.800 X 10000 = Rs.8000000 Cost of coal for 2 months = Rs. 48 Crore Coal cost for 1 and half month = Rs. 36 Crore The 75% of the working capital has to be taken from the short term debts; on this debt around 12% interest rate can be applicable which can be equal to Interest on working capital = Rs. 5.76 to Rs. 4.32 Crore. CEA Guidelines As per the CEA guidelines 40 days dead stock of coal has to be kept and 8 – 10 hrs. Of live stock of coal has to be maintained. E.g. for a 1000 MW plant Coal cost for 40 days = 400000 x Rs. 800 = Rs. 32 Crore Stacking Area Requirement E.g. for a 1000 MW plant Coal consumption for 1 day = 10000 tonnnes Density of Coal: 1 m3 = 1 Tonne For 40 Days, Coal Required to be stored = 10000 x 40 = 400000 tonnnes Volume = 400000 m3 Height of Coal Stack = 10 m Area required for Storage = 400000/10 = 40000 m2 ≈ 10 acres Captive Coal Mining Under the Coal Mines (Nationalisation) Act, 1973, coal mining was mostly reserved for the public sector. By an amendment to the Act in 1976, two exceptions to the policy were introduced viz., Captive Mining by private companies engaged in production of iron & steel. ii) Sub lease for coal mining to private parties in isolated small pockets not amenable to economic development and not requiring rail transport. The Coal Mines (Nationalisation) Act, 1973 was amended in June, 1993 to allow coal mining for captive consumption for generation of power, washing of coal obtained from a mine and other end uses to be notified by Govt from time to time. The Central Govt, a govt company including state govt company, a corporation owned, managed and controlled by the central govt can do coal mining without the restriction of captive use. The allocation of coal blocks to private parties is done through the mechanism of an inter-ministerial and inter-govt body called the screening committee. It is chaired by the Secretary (Coal) and has representation from Ministry of Steel, Ministry of Power, Ministry of Industry and Commerce, Ministry of Environment and Forest, Ministry of Railways, CIL, CMPDIL and concerned state govts. There are 229 coal blocks for allocation to specified end users. 208 coal blocks have been so far been allocated to eligible companies. So far, production has commenced in 25 blocks. Production from these coal blocks for 2009-10 is about 23.66 million tonnes. Effect of coal utilisation by the imported coal based UMPP in India on the international prices World steaming coal trade around 550 Mt. Till date India has been a small player in the global markets with imports of 17.5 Mt of thermal coal in 2005, up from 15 Mt in 2004 and 10 Mt in 2003. With each UMPP requiring about 12-14 million tonnes of coal, India would become a major player in the world coal markets in the coming decade. Presently there are nine numbers of UMPPs proposed in India having capacities of 4000 MW each, out of these there are four numbers of UMPPs are imported coal based. If we consider the four imported coal based UMPPs then there is need of 16000MW energy generated from imported coal i.e. we need an import of around 48-60 mtpa of coal. This requirement of coal will come up in between 2010 to 2016 i.e. a four fold attainment in coal imports. Coal Bed Methane New area of clean technologies like Coal Bed Methane and Coal Mine Methane, Underground Coal Gasification and Coal Liquefaction are under focus and Government is taking all the necessary steps for development of these areas within the existing legal framework. CMS is one of the potential greenhouse gases and is in adsorbed state on the coal surface and possess a potential threat from safety angle during mining operation. If extracted separately, it forms a supplementary source of energy. In view of the abundant resource of coal in the country, there is a significant scope for commercial development of CBM. Methane associated with virgin coal beds is conventionally termed as Coal Bed Methane. Similarly extraction of Methane from working mines is termed as Coal Mine Methane. Consequent to the formulation of CBM Policy in 1977, Govt of India has so far allocated 26 CBM blocks to various operators for exploration and exploitation of CBM. 10 more blocks to various operators were offered in 4th round of bidding concluded in Oct’09. The offers received against this bidding are under consideration of the Govt for their allotment for commercial development. CBM is jointly managed by Ministry of Coal and Ministry of Petroleum and Natural Gas. CMM related activities are being addressed by Ministry of Coal separately. Central Mine Planning & Design Institute Ltd, CMPDI has taken up a CIL R&D project for delineation of prospective CMM blocks in ECL, BCCL and CCL areas of CIL and preparation of data dossier for 1 or 2 most prospective and commercial viable CMM blocks. CIL & ONGC is working on collaborative project on CBM. Some of the identified CBM blocks are Jharia & Raniganj. A CMM/CBM clearing house has been established at CMPDI, Ranchi under the aegis of Ministry of Coal and United States Environmental Protection Agencies on 17th Nov’08. The clearing house will function as the nodal agency for collection and sharing of information on CMM/CBM related data of the country and help in the commercial development of CMM projects in India by public/private participation, technological collaboration and bringing financial investment opportunities. Great Eastern Energy Corporation is the first private sector company to take up coal bed methane exploration in India. As the third largest coal producer in the world, India has good prospects for commercial production of coal bed methane. Nevertheless, with demand for gas rising sharply, CBM will have to compete with imported (liquefied) natural gas. Methane is, however, a viable alternative to compressed natural gas (CNG) and its use as automotive fuel will certainly help reducing pollution levels. India is one of the select countries which have undertaken steps through a transparent policy to harness domestic CBM resources. The Centre has received an overwhelming response from prospective producers with several big players starting operations on exploration and development of CBM in India. It is envisaged that in India operational CBM fields may contribute about 8-10 mmscmd of gas production in the next five years. Investment in coal and gas transportation infrastructure, including gas gathering, transportation and distribution, is necessary to fill the gap and move CBM from coal fields to local and more distant end-use markets which include rural and commercial power generation and transportation fuels. India is set to become the fourth after US, Australia and China in terms of exploration and productionof coal bed methane. In order to fully develop India's CBM potential, delineation of prospective CBM blocks is necessary. There are other measures like provision of technical training, promotion of research and development, and transfer of CBM development technologies that can further the growth of the sector. With growing demand and rising oil and gas prices, CBM is definitely a viable alternative supplementary energy source. Moreover, CBM extraction also potentially offers the opportunity of earning carbon credits under Clean Development Mechanism of Kyoto Protocol, being an environmentally friendly fuel. Coal bed methane will clearly emerge as the one of the viable and clean routes to India's energy security. The development plan for Sohagpur CBM blocks (MP) has been approved by the Government and development activities have been planned to commence in FY 2010-11 by drilling and completion of additional wells. Prolonged production testing was undertaken in the wells drilled in Sohagpur CBM blocks with favourable results. The plan for 2010– 11 is to monetise the production capability from the present as well as the proposed wells. During the year, two CBM blocks BS-1 and BS-2 were relinquished. With this, RIL currently holds a total of 3 CBM blocks. CBM Exploration Experience – Reliance (Sohagpur) CBM Discovery – 3.65 TCF, validated by DGH Technology used for drilling – Air Drilling (First ever used in India) Gas Production Potential – 3-5 MMSCMD in a frontier area Water Production Potential – 50000-70000 BPD of good quality water Investment potential – Over 3000 Cr OIL NEW EXPLORATION LICENSING POLICY • In view of the inherent risk of hydrocarbon exploration and the huge financial investment associated with such risky exploration ventures, it has been felt that the efforts of the upstream National Oil Companies (NOCs) may not be adequate to achieve the set mandate. • Hence opening up of the acreages for active exploration by private or joint venture companies, in addition to the efforts of the NOCs, was considered necessary. • The acreages offered by the Government under various exploration rounds earlier met with only partial success. The main thrust for acceleration of exploration activities has, however, begun with the introduction of New Exploration Licensing Policy (NELP) by the Government in 1997. • NELP has introduced a level playing field for public as well as private sector players. NOCs are also required to compete with the private and joint venture companies in acquiring exploration acreages in Indian sedimentary basins. • Under this policy, all companies would be required to bid for a committed work programmes to profit petroleum share expected by the contractor at various levels of pre-tax multiple of investments and percentage of annual production sought to be allocated towards cost recovery. OBJECTIVES OF NELP ROUNDS • Intensive exploration of Indian basins. • Opening up of acreages in ultra deep water & frontier areas. • To stimulate & promote interest and activity from a wide range of E & P players. • To bring-in new & state of art technology in exploration & exploitation. • Level playing field to all participating companies. • Transparent Bid Evaluation system . The other main features of the terms offered by the Government inter alia include: • no signature, discovery or production bonus by the bidder; • income tax holiday for seven years from the start of commercial production, • no customs duty on imports required to be payable for petroleum operations, • biddable cost recovery limit up to 100 per cent, royalty to be payable by the contractor on ad voleram basis, • freedom to the contractor for marketing of oil and gas in the domestic market, • fiscal stability provision in the contract and • Incentive for deepwater exploration with only half of the royalty payable in the initial seven years from the beginning of commercial production. There are certain differences between the earlier rounds of bidding for exploration blocks and NELP. • While NOCs were to bear royalty, cess and PEL fees on behalf of private companies in the earlier rounds, companies are now required to bear royalty. • Cess and fees have now been exempted under NELP. • Under the policy, NOCs are no longer needed to participate as Government nominees. The policy exempts them from payment of customs duty and cess for the blocks offered. Table 9.14: Progress under new exploration license policy • Parameter NELPI NELP II 23 23 2001 2,63,050 NELP III 23 23 2003 2,04,588 NELP IV 21 20 2004 1,92,810 NELP V 20 20 2005 1,15,180 NELP VI 52 52 2007 3,06,200 NELP VII 44 41 2008 1,21,000 No. of blocks 25 awarded No. of PSCs 24 signed Signed in 2000 Area awarded 1,94,735 (sq. km) Source : Ministry of Petroleum & Natural Gas PSC: Production Sharing Contract NELP I– JANUARY 8, 1999 • World class gas discovery by RIL-NIKO in 2002 in KG off shore block • Cairn energy’s discovery in KG deep water block • Gas discovery by RIL in Mahanadi shallow water block NELP II – 2000 • Discoveries were made in Cambay Basin GSPC discovered OIL & NIKO discovered natural gas NELP III – 2001 • GSPC - jubilant - GGR consortium made world class gas discovery in KG ( KG-OSN-2001/3) offshore block in June, 2005 NELP IV – 2003 • Provision of fast track arbitration • Higher weightage for technical and financial viability of deep water block • Surcharge on foreign companies abolished • Bank guarantee to be returned after completion of MWP NELP V – 2005 • Workstations were provided in data centers in London, Houston, Calgary & Dubai to facilitate companies to review and analyze data. • Govt. decided to take its profit share of natural gas in cash or kind for a block of 5yrs instead of such option being made every year. • Co.’s with net worth US $500million or more not required to give bank guarantee towards MWP commitment as against the threshold limit of US $ 1 billion earlier. NELP VI – 2006 • Check on aggressive/speculative bidding • Uniform seismic coverage of basins • Participation of E&P companies with global experience – Induction of new technology – Global knowledge – Better geological models – Better E&P practices • Better Government take NELP VII • Approximately 50 to 60 blocks have been identified for the offering. NELP VIII- 2009 • 70 new blocks for bids to the Indian and foreign companies for exploration of oil and natural gas • bidding would lead to 42 billion dollars of gas in the next 11 years. NELP IX-2010 • more tax benefits • investment- based incentives The New Exploration Licensing Policy, a vehicle designed by the Government of India, has so far been successful in accelerating the pace of hydrocarbon exploration in the country. The hydrocarbon sector in India is one of the most crucial industries for determining energy security as nearly 45 per cent of the country’s total energy needs are met by the oil and gas sector. Production of indigenous oil and gas is therefore a major plank of oil security for the nation. Through the New Exploration Licensing Policy, the Government of India is making a concerted effort to expeditiously explore the inadequately explored and unexplored areas of the country’s sedimentary basins. Linkage THE LINKAGE BETWEEN OIL CONSUMPTION AND ECONOMIC GROWTH IN INDIA The relationship between use of energy and economic growth has been a subject of greater inquiry as energy is considered to be one of the important driving forces of economic growth in all economies unable to meet up the world demand for oil. The supply constraint of energy could be attributed to the frequent geo-political tensions between the nations or natural physical supply constraints in the oil extracting regions 1. The increasing world demand for oil,2 leads to frequent escalation in the world oil prices.3 Like shortage of oil, there exists shortage of electricity and other forms of energies viz. natural gas.4 The shortage can significantly affect the consumption and production in the economy. One or the other forms of energy becomes vital to all the sectors of the economy viz. agriculture, industry and services. This energy dependence being common to every sector of the economy justifies the association between energy utilization and the overall economic growth rate in an economy. Hence, any deficiency in supply of oil, natural gas and electricity generations can directly constrain the economic activities, thereby inhibiting the growth rate. The declining supply of these sources of energy not only raises the input prices5 but also influences the prices of other commodities leading to a rise in overall inflation rate and thereby dampening the aggregate demand and growth rate. In India, the transport sector is the principal consumer of petrol and diesel, followed by big and small industrial units. India in the past had experienced a huge import bill on account of an increase in the price of crude oils. The inelastic oil demand and rising oil import bill had put pressure on the scarce foreign exchange resources and had also been largely responsible for shortages in energy supply. The linkage between oil, gold prices in recession Underlying the rise in the oil price has been the basic strength of oil as a commodity. The world has probably reached the point at which oil supply has peaked - if not, we are close to that point. The growth of the huge economies of China and India is limited by the long term constraints of the oil supply, more than by any other factor. If the recovery does continue, the oil price will regain the level of $100 a barrel, and the gold price will rise well above $1,000 an ounce. My own expectation is that these figures will be exceeded substantially, perhaps to $150 or $200 a barrel and $1,500 or $2,000 an ounce. But that will limit the possible global recovery. The world has, indeed, been living beyond its means, in terms of the oil supply. Everything else depends on that, and will have to adjust to a higher oil price. Oil and gold prices have been linked for most of the period of the recession. In recent, both have been in a stage of recovery. The gold price has reached $982 an ounce, close to its peak when it touched $1,000 an ounce. Oil prices fell in the recession by about 70 per cent, and have now received about 50 per cent. The recovery in the gold price reflects a number of factors. The Asian economies have accumulated excessive quantities of dollar securities, and the Asian central banks are reluctant to continue accumulating dollars, except on a purely speculative basis. The weakening of the dollar has had a reciprocal effect in the strengthening of the gold price. There is also a fear that the Keynesian policies which have helped to create the appearance of a global recovery will, at some point, lead to a revival of inflation. Oil Pricing Oil Price History and AnalysisIntroduction Crude oil prices behave much as any other commodity with wide price swings in times of shortage or oversupply. The crude oil price cycle may extend over several years responding to changes in demand as well as OPEC and non-OPEC supply. The U.S. petroleum industry's price was heavily regulated through production or price controls throughout much of the twentieth century. In the post World War II era U.S. oil prices at the wellhead averaged $26.64 per barrel adjusted for inflation to 2008 dollars. In the absence of price controls, the U.S. price would have tracked the world price averaging $28.68. Over the same post war period the median for the domestic and the adjusted world price of crude oil was $19.60 in 2008 prices. That means that only fifty percent of the time from 1947 to 2008 have oil prices exceeded $19.60 per barrel. (See note in box on right.) Until the March 28, 2000 adoption of the $22-$28 price band for the OPEC basket of crude, oil prices only exceeded $24.00 per barrel in response to war or conflict in the Middle East. With limited spare production capacity, OPEC abandoned its price band in 2005 and was powerless to stem the surge in oil prices, which was reminiscent of the late 1970s. Crude Oil Prices 1947 - August, 2009 Post World War II Pre Embargo Period Crude Oil prices ranged between $2.50 and $3.00 from 1948 through the end of the 1960s. The price oil rose from $2.50 in 1948 to about $3.00 in 1957. When viewed in 2008 dollars an entirely different story emerges with crude oil prices fluctuating between $17 and $19 during most of the period. The apparent 20% price increase in nominal prices just kept up with inflation. From 1958 to 1970, prices were stable near $3.00 per barrel, but in real terms the price of crude oil declined from above $19 to $14 per barrel. The decline in the price of crude when adjusted for inflation for the international producer suffered the additional effect in 1971 and 1972 of a weaker US dollar. World Events and Crude Oil Prices 1947-1973 Middle East Supply Interruptions Yom Kippur War - Arab Oil Embargo In 1972, the price of crude oil was about $3.00 per barrel. By the end of 1974, the price of oil had quadrupled to over $12.00. The Yom Kippur War started with an attack on Israel by Syria and Egypt on October 5, 1973. The United States and many countries in the western world showed support for Israel. Because of this support, several Arab exporting nations and Iran imposed an embargo on the countries supporting Israel. While these nations curtailed production by 5 million barrels per day other countries were able to increase production by a million barrels. The net loss of 4 million barrels per day extended through March of 1974 and represented 7 percent of the free world production. Any doubt the ability to control crude oil prices had passed from the United States to OPEC was removed during the Arab Oil Embargo. The extreme sensitivity of prices to supply shortages became all too apparent when prices increased 400 percent in six short months. U.S. and World Events and Oil Prices 1973-1981 Crises in Iran and Iraq In 1979 and 1980, events in Iran and Iraq led to another round of crude oil price increases. The Iranian revolution resulted in the loss of 2 to 2.5 million barrels per day of oil production between November 1978 and June 1979. At one point production almost halted. US Oil Price Controls - Bad Policy? The rapid increase in crude prices from 1973 to 1981 would have been much less were it not for United States energy policy during the post Embargo period. The US imposed price controls on domestically produced oil. The obvious result of the price controls was that U.S. consumers of crude oil paid about 50 percent more for imports than domestic production and U.S producers received less than world market price. In effect, the domestic petroleum industry was subsidizing the U.S. consumer. Did the policy achieve its goal? In the short-term, the recession induced by the 1973-1974 crude oil price spike was somewhat less severe because U.S. consumers faced lower prices than the rest of the world. However, it had other effects as well. In the absence of price controls, U.S. exploration and production would certainly have been significantly greater. Higher petroleum prices faced by consumers would have resulted in lower rates of consumption: automobiles would have achieved higher miles per gallon sooner, homes and commercial buildings would have has better insulated and improvements in industrial energy efficiency would have been greater than they were during this period. Consequently, the United States would have been less dependent on imports in 1979-1980 and the price increase in response to Iranian and Iraqi supply interruptions would have been significantly less. US Oil Price Controls 1973-1981 OPEC Fails to Control Crude Oil Prices OPEC has seldom been effective at controlling prices. While often referred to as a cartel, OPEC does not satisfy the definition. One of the primary requirements is a mechanism to enforce member quotas. The old joke went something like this. What is the difference between OPEC and the Texas Railroad Commission? OPEC doesn't have any Texas Rangers! The only enforcement mechanism that has ever existed in OPEC was Saudi spare capacity. With enough spare capacity at times to be able to increase production sufficiently to offset the impact of lower prices on its own revenue, Saudi Arabia could enforce discipline by threatening to increase production enough to crash prices. In reality even this was not an OPEC enforcement mechanism unless OPEC's goals coincided with those of Saudi Arabia. From 1982 to 1985, OPEC attempted to set production quotas low enough to stabilize prices. These attempts met with repeated failure as various members of OPEC produced beyond their quotas. During most of this period Saudi Arabia acted as the swing producer cutting its production in an attempt to stem the free fall in prices. In August of 1985, the Saudis tired of this role. They linked their oil price to the spot market for crude and by early 1986 increased production from 2 MMBPD to 5 MMBPD. Crude oil prices plummeted below $10 per barrel by mid-1986. Despite the fall in prices Saudi revenue remained about the same with higher volumes compensating for lower prices. A December 1986 OPEC price accord set to target $18 per barrel bit it was already breaking down by January of 1987and prices remained weak. The price of crude oil spiked in 1990 with the lower production and uncertainty associated with the Iraqi invasion of Kuwait and the ensuing Gulf War. The world and particularly the Middle East had a much harsher view of Saddam Hussein invading Arab Kuwait than they did Persian Iran. The proximity to the world's largest oil producer helped to shape the reaction. Following what became known as the Gulf War to liberate Kuwait crude oil prices entered a period of steady decline until in 1994 inflation adjusted prices attained their lowest level since 1973. The price cycle then turned up. The United States economy was strong and the Asian Pacific region was booming. From 1990 to 1997 world oil consumption increased 6.2 million barrels per day. Asian consumption accounted for all but 300,000 barrels per day of that gain and contributed to a price recovery that extended into 1997. Declining Russian production contributed to the price recovery. Between 1990 and 1996 Russian production declined over 5 million barrels per day. OPEC continued to have mixed success in controlling prices. There were mistakes in timing of quota changes as well as the usual problems in maintaining production discipline among its member countries. Non-OPEC Production & Crude Oil Prices OPEC Production & Crude Oil Prices Current Scenario –International (oil pricing uncertainty)The world’s energy ministers and oil producers are trying to agree on ways to prevent oil price spikes in the immediate future – although at least one economist is predicting “triple-digit” oil later this year. The elite group is today (Wednesday, March 31) concluding their three-day International Energy Forum meeting in Cancun, Mexico. According to papers published ahead of the event, participants considered “demand and supply uncertainties,” having to balance Opec’s claim of spare oil capacity “exceeding 6 million barrels per day” against the claims of neutral strategic advisors PFC Energy that oil will be “peaking between 2020-2025 around 95.0 mmb/d.” The majority of oil consuming nations are siding with Opec, the producers and consumers should work together to avoid a repeat of 2008’s market volatility.The change in attitude marks a significant shift in political relations between Opec, other producers and the world’s biggest oil-consuming countries. Opec’s efforts to control the market once made it the enemy of the US and many European nations. However, nothing from the meeting has yet indicated how this will be achieved, or at what price Opec should endeavour to maintain oil. In the first place, the US is reportedly pushing for a free-market approach.But there was at least one important dissenter this week. At least publicly, the US insisted at the discussions that markets needed to be left to determine the oil price. Daniel Poneman, US deputy energy secretary, said: “The goal of the US is a clear and long-standing one and that is to let the laws of supply and demand set prices.” Meanwhile, delegates are quoted by Reuters agreeing that oil at $70-80 per barrel “was good for both sides,” maintaining producers’ revenues and consumers’ economies. It continues: But there was no sign of a clear consensus by OPEC members at what price they would ramp up production if prices broke above the band Saudi Arabian Oil Minister Ali al-Naimi this week called "most appropriate". "Prices above $85 for a sustained period of time could well be harmful. We have to be aware that the economic recovery is still fragile," an OPEC delegate told Reuters on the sidelines of the forum, which is aimed at promoting dialog between oil consumers and producers. US crude is currently up to around $82 a barrel, with Reuters citing analysts suggesting “it could push even higher as demand from the United States and other industrialized nations rebounds as their economies recover.” But how much longer can the world pretend that it won’t soon be facing another energy shock, one every bit as challenging as the one it faced two years ago? Does anyone still believe the reassuring forecasts from discredited feel-good organizations like the International Energy Agency about new sources of cheap supply, like those that once flowed from places like Prudhoe Bay in Alaska or the North Sea? If so, where is that supply of new affordable oil coming from? Surely not from tar sands or from ultra-deep water fields six miles below the ocean’s floor. He goes on to predict further price shocks in the immediate future: By the fourth quarter of this year, oil prices will be back in triple-digit range, and by next year oil prices will rise to record highs, taking out the high-water mark of $147 per barrel set back before the recession began in 2008. We’re barely out of the recession, and already we face prices that, just a few years ago, our government, our oil industry and our economists toldus we would never see. Current Scenario – India India’s imports of oil are increasing. Our import dependence has reached 80 per cent and is likely to keep growing. At the same time 2008 saw an unprecedented rise in oil price on the world market. Oil price volatility has also increased. Though future oil prices are difficult to predict, they are generally expected to rise. Given our increasing dependence on imports, domestic prices of petroleum products have to reflect the international prices. When the average monthly price of Indian basket of crude oil on the world market increased from US$ 36 / barrel in May 2004 to US$132.5 / barrel in July 2008, the government did not permit Public Sector Oil Marketing Companies (OMCs) to pass the full cost of imports on to domestic onsumers of major oil products, i.e., petrol, diesel, domestic LPG. The consumers of these products thus received large subsidies. As a consequence, OMCs had large under-recoveries1, which were financed partly by Government through issuing bonds, and partly by upstream public sector companies ONGC and OIL, and GAIL through price discounts. The OMCs also absorbed a part of the under-recoveries themselves. These policies had a number of consequences. They put stress on government’s finances. They reduced the cash surplus of upstream public sector oil companies restricting their ability for exploration of domestic fields and acquisitions overseas. As the oil bonds were not issued to OMCs on time, they created cash flow problems for OMCs who had to borrow from the market, which increased interest payments and reduced their surplus. Since only the OMCs were provided financial support, the private sector companies withdrew from oil marketing. This not only made in fructuous the large investments they had made in setting up retail outlets, it also reduced competition in oil marketing. Subsidizing domestic consumers also did not incentivize them to economize on use of petroleum products. Rather, as prices remained low, and personal incomes rose, the demand for petroleum products such as petrol and diesel recorded double digit growth – higher than the GDP growth. Continuation of the present policies is not viable, particularly once oil prices rise again. Over the years, Government has followed a variety of policies for pricing of petroleum products, all of which have been found to have some deficiency or the other. A viable long-term strategy for pricing major petroleum products is required. A viable policy has to be workable over a wide range of international oil prices and has to meet the various objectives of the government. It should limit the fiscal burden on government and keep the domestic oil industry financially healthy and competitive. OBJECTIVES OF POLICY AND ISSUES The very first question is: Should the government intervene at all in the market and set prices? The first reason for intervention is to protect poor consumers so that they may afford kerosene for lighting, which is a necessity for those who do not have access to electricity. Another objective may be to provide merit goods to consumers such as clean cooking fuels like natural gas, LPG and kerosene to replace use of biomass-based fuels such as firewood and dung. These biomass based fuels create indoor air pollution that causes respiratory diseases, eye infections and result in many premature deaths, particularly of women and children. Also, use of firewood encourages deforestation and dung is better used as a fertilizer. Moreover, the task of gathering these fuels keeps girls away from schools. Thus, use of clean cooking fuels has many social and environmental externalities, and as merit goods the government may promote them through subsidies. Another frequently reported reason for Government's intervention is to insulate the domestic economy from the volatility of petroleum prices on the world market. It is feared that complete passthrough of increase in world oil prices may cause inflation which may persist even when oil price comes down. There is no clear evidence that in an increasingly open and competitive economy, price movements triggered by changes in the prices of oil products would persist over the medium-run. In addition, attempts to insulate the domestic economy against volatility requires discriminating between a secular price rise due to demand-supply forces and a price rise due to transient causes such as speculation in the world market. This is difficult to do. To the extent the level of self-sufficiency in domestic oil production increases, the impact of international oil prices on domestic economy would be reduced. Thus, keeping domestic oil firms viable and in good financial health and providing an environment in which they can grow are also important policy objectives. It is equally important to keep domestic private sector firms viable as it is to keep public sector firms viable. A level playing field between public and private sector firms as well as among public sector firms is desirable to promote competition. A major objective of policy is to have an efficient and competitive oil economy that promotes efficient use by consumers, appropriate choice of fuels among substitutes and a proper choice of technique. This is best ensured by a competitive energy sector. Intervention through price control necessitates that someone bears the financial costs. The issue therefore is to assess the costs and incidence of the burden of alternative mechanisms on different groups in the society. On whom the burden falls depends on the policy and the instruments used. If the costs are financed by a general increase in taxes, or by increasing fiscal deficit or by cutting other government expenditure, all these affect certain sections of the people adversely. Price control means setting prices. If it is done on a cost-plus basis, it creates incentives for gold plating and creative accounting. Also, price calculations involve rigid specifications of items to be considered and their costs. This discourages innovation. For example, storage of LPG in large underground caverns facilitates imports by larger ships and reduces unloading time compared to storage in over-ground tanks. But, it may involve increase in operating costs. If the cost formula has set item-wise limits on operating costs, the project may be discouraged even if its total cost is much less. If prices are to be fixed by the Government, that has to be based on some principle. Prices can be fixed based on pre-determined formula, which is derived from principles like import parity (IPP), trade parity (TPP), or export parity (EPP). This approach is also fraught with major deficiencies. The formula often involves elements of cost-plus. In an industry, which is continuously changing, a prescriptive and biased cost-plus pricing formula requires continuous monitoring and periodic adjustments in certain components of the formula. For instance, there is no single or unique formula for import parity which is applied globally (Note 3, Appendix). The Rangarajan Committee (February 2006) suggested a pragmatic approach of TPP for pricing of petrol and diesel which was accepted by the Government. It has, since then, been applied to petrol and diesel. It was derived as a weighted average of IPP and EPP in the ratio of 80:20. The weight of 20 for EPP was based on the share of petroleum product exports in the total consumption in 2004-05. As suggested by the Committee, this ratio was required to be assessed periodically and adjustments made to align the formula to the current position. The trade parity pricing was also recommended by the Parikh Committee on Integrated Energy Policy (August 2006) as one which reflects the opportunity costs of a consumer or a producer. According to the Integrated Energy Policy, IPP is to be used for a product for which the country is a net importer and EPP for a product for which it is a net exporter. As long as the country exports a particular product, EPP equals TPP, as suggested by the Integrated Energy Policy. All these call for administrative and regulatory tasks to be performed by the Government or its agency on a permanent basis. Also, a prescriptive, formula-based approach involving direct government intervention does not result in a competitive price discovery process. Instead, it increases administrative burden. A competitive price discovery process empowers companies to follow their own judgments of market conditions and results in fair pricing of products. In the event of any company adopting unfair pricing methods, such activities can be curbed by the regulatory authorities set up by the Government. Price control, subsidies and taxes can introduce distortions which may not be desirable. Apart from inefficient use, it also leads to erroneous choice of technique. For example, if diesel is cheap, it may encourage freight movement by trucks rather than by train. When the price difference between petrol and diesel is high, diesel driven vehicles may be preferred. If there is a large difference between the prices of diesel and kerosene, kerosene may be used to adulterate diesel. In 2008, we have even seen diesel being used in place of furnace oil. Intervention in pricing must be carefully thought out for its possible consequences. NEED FOR CHANGE IN POLICY We have worked out domestic prices of the four products under alternative assumptions of crude price on the international market. Provides estimated retail selling prices of petrol, diesel, LPG and kerosene at Delhi corresponding to a range of prices of the Indian basket of crude oil from $60/bbl to $150/bbl. It reveals that when crude oil prices rise from US$70/bbl to $120/bbl, the price of petrol in Delhi is required to be increased by Rs.20/litre, the price of diesel by less than Rs. 20/litre and LPG by around Rs. 200 per cylinder. Domestic Prices of Petrol, Diesel, Kerosene and LPG derived from different levels of prices of the Indian Basket of Crude Oil. International Prices Crude Oil (Indian Basket) Petrol Diesel Kerosene LPG Petrol Indicative Retail Selling Price(at Delhi) Diesel Kerosene LPG 60 70 80 90 100 110 66 77 88 99 110 121 ($/bbl.) 70 72 81 83 93 94 104 115 127 ($/MT) 538 595 652 106 709 117 765 128 822 43.75 47.71 51.66 55.61 59.56 63.51 (Rs./Litre) 32.23 36.08 39.92 43.76 47.61 51.45 23.82 27.29 30.76 34.23 37.70 41.18 (Rs. / Cyl.) 455.42 495.41 535.42 575.42 615.42 655.42 120 132 130 143 140 154 150 165 Current Retail Prices 138 149 161 172 140 151 162 173 879 936 993 1,049 67.46 71.41 75.37 79.32 44.72 55.29 59.13 62.98 66.82 32.92 44.65 48.12 51.59 55.06 9.23 695.43 735.43 775.42 815.42 281.20 The product prices of Petrol, Diesel, Kerosene, LPG have been derived through regression equations of crude and product prices in international market during January '07 to December '09. The equation, Y = a + bX, in which Y is product price and X is crude oil price, gives the following estimates. Coefficients Petrol Diesel Kerosene LPG a 0.41 2.31 3.93 197.31 b 1.10 1.13 1.13 5.68 Exchange Rate considered at Rs. 47 per US Dollar. Indicative retail selling prices of PDS Kerosene and Domestic LPG are after netting off fiscal subsidy at current level of Rs.0.82/litre for PDS Kerosene and Rs.22.58 per cylinder for Domestic LPG. In order to assess the financial burden that may arise from rising under-recoveries of OMCs in the face of another price spiral in the international market, we have projected consumption based on two assumptions: (i) the annual average compound growth rates of petrol, diesel, kerosene and LPG during 2002-03 to 2008-09 apply to 2020-21 and 2030-31. (ii) The current level of prices set by the government will continue. The projected consumption of petroleum products by 2020-21 and 2030-31 is given in Table C2. Table C2: Consumption of Petroleum Products, 2001-02 to 203031 Actual Consumption 2001-02 2004-05 2008-09 CAGR Product 2002-09 MS 7.0 8.3 11.3 7.0 HSD SKO LPG Sensitive Products Free Industrial Products TOTAL Source: PPAC 36.5 10.4 7.7 61.7 38.7 100.4 39.7 9.4 10.2 67.5 44.1 111.6 51.7 9.3 12.2 84.4 49.0 133.4 5.1 -1.6 6.7 4.6 3.4 4.1 Projections 2020-21 2030-31 25.4 93.5 7.6 26.6 144.4 73.3 217.0 49.9 153.4 6.5 51.1 226.0 102.6 325.6 Based on these projected demand, the under-recoveries of oil marketing companies on these four products have been worked out (Figure C1) At crude oil price of $80/bbl, the total under-recoveries of OMCs on sale of petrol, diesel, LPG and PDS kerosene work out to Rs.1,57,000 crore by 202021. If oil prices rise by 25% to $100/bbl, the under-recoveries will rise higher by 77%. Likewise if oil prices rise to $120/bbl (50% increase) the under-recoveries will rise by 155%. Higher the growth rate of GDP and longer the period beyond 2020-21, the much higher will be the under-recoveries. At different levels of crude oil prices, product-wise under-recoveries of OMCs on sale of petrol, diesel, LPG and PDS Kerosene is presented in the Figure C2. These estimates reveal the dominant share of diesel in OMC’s under-recoveries. It will rise from 45% at crude oil price of $80/bbl to 58% at $150/bbl by 2020-21. Such a trend needs to be stemmed early. It suggests that at current levels of prices of petrol, diesel, PDS kerosene and domestic LPG, the financial burdens on the companies as well as on the government will be unsustainable. Therefore, there is a need to change the existing policy which can strike a balance between the capacity of the consumer to bear higher prices and fiscal stability of the government SUMMARY OF RECOMMENDATIONS • India’s imports of oil are increasing. Our import dependence has reached 80 per cent and is likely to keep growing. At the same time 2008 saw an unprecedented rise in oil price on the world market. Oil price volatility has also increased. Though future oil prices are difficult to predict, they are generally expected to rise. Given our increasing dependence on imports, domestic prices of petroleum products have to reflect the international prices. • The Government has not permitted public sector oil marketing companies to pass global prices to domestic consumers. We have examined the impact of the formula-based prescriptive pricing of major petroleum products devised by the Government from time to time, particularly since 2002. The present system of price control on petrol and diesel in particular has resulted in major imbalances in the consumption pattern of petroleum products in the country, and has put undue stress on finances of the PSU oil marketing companies as well as of the Government. It has also led to withdrawal of private sector oil marketing companies from the market. This has affected competition in the domestic petroleum product market. • Intervention through price control necessitates that someone bears the financial costs. The issue therefore is to assess the costs and incidence of the burden of alternative mechanisms on different groups in the society. On whom the burden falls depends on the policy and the instruments used. • A viable long-term strategy for pricing major petroleum products is required. A viable policy has to be workable over a wide range of international oil prices and has to meet the various objectives of the government. It should limit the fiscal burden on government and keep the domestic oil industry financially healthy and competitive. • The petrol is largely an item of final consumption. An analysis of the trend of petrol consumption by the automobile owners reveals that increase in prices of petrol can be borne by motorized vehicle owners. Accordingly, we recommend that petrol prices should be market determined both at the refinery gate and at the retail level. • We have examined the implications of increase in retail price of diesel on various groups of consumers and do not find any compelling reason to subsidize them. Therefore, we recommend the price of diesel should also be market determined both at the refinery gate and at the retail level. • Petrol and diesel used in cars, including SUVs, are for final consumption. The higher excise duty on petrol compared to diesel encourages use of diesel cars. While greater fuel efficiency of a diesel vehicle should not be penalized, a way needs to be found to collect the same level of tax that petrol car users pay from those who use a diesel vehicle for passenger transport. An additional excise duty, based on the model outlined in paragraph 4.14, should be levied on diesel car owners. • A transparent and effective distribution system for PDS kerosene and domestic LPG can be ensured through UID/Smartcards framework. Until it becomes operational, the following measures need to be taken. • There is disparity in per capita allocation of PDS kerosene amongst States, as also decline in the percentage of households using kerosene. Besides, households have flexibility in absorbing increases in price of PDS kerosene to certain extent. Therefore, PDS kerosene allocation across states should be rationalized, which will bring down all-India allocation by at least 20%. Further reduction in PDS kerosene allocation can be done on the basis of progress of rural electrification, LPG and piped gas availability which is expected to reflect much larger reductions in next NSSO surveys. • The price of PDS kerosene needs to be increased by at least Rs.6/litre so that the share of expenditure on kerosene in the total consumption expenditure of rural households remains at the same level as in 2002. Thereafter, price of PDS kerosene be raised every year in step with the growth in per capital agricultural GDP at nominal price. • Our analysis shows that prices of domestic LPG can be increased by at least Rs. 100 per cylinder. Thereafter, the price of domestic LPG should be periodically revised based on increase in paying capacity as reflected in the rising per capita income. The subsidy on domestic should be discontinued for all others except the BPL households once an effective targeting system is in place. • For calculation of the under-recoveries incurred by the OMCs on sale of PDS kerosene and domestic LPG, the extant methodology based on import parity pricing may be continued so long as the country remains a net importer of kerosene and LPG. • A mechanism for financing under-recoveries on PDS kerosene and domestic LPG has been provided in Table UR2 in paragraph 4.49. This mechanism involves periodic reduction in PDS kerosene allocation, increase in prices of PDS kerosene and domestic LPG from time to time, and mopping up a portion of the incremental revenue accruing to ONGC/OIL from production in those blocks, which were given by the Government on nomination basis, at the rates indicated in paragraph 4.48, and providing cash subsidy from the Budget to meet the remaining gap. The OMCs marketing PDS kerosene and domestic LPG should be compensated fully for their under-recoveries based on this mechanism. • We are not recommending a windfall profit tax since MOPNG ought to have flexibility in mopping up incremental incomes of ONGC and Oil India for the purpose of meeting a part of the under-recoveries of OMCs on sale of domestic LPG and PDS kerosene as outlined in paragraph. OIL CONTRACTS (a) Forward Contract: It is a tool which is used to hedge against system price. Considering the volatility of prices in the spot market, buyers and sellers often agrees on price, quality and quantity of goods in advance of actual delivery and the goods are delivered on a future date. These contracts will have mode and timing of payments as also penalties, if any, or failure to deliver goods or failure to make payment. These are called as forward contracts. However, instead of having one to one relationship, many buyers and sellers may develop a market for trading of goods in advance of the delivery. Price discovery in such a market is based on more informed choice as compared to one to one contracts. Besides, the market also facilitates development of standard contracts. So from buyer’s point of view, whatever the system price in there, or how the price is fluctuating he doesn’t have to bother. For him, the system price will be the price at which he has made contract. And from seller’s point of view, whatever the system price in there, or how the price is fluctuating he doesn’t have to bother. For him also, the system price will be the price at which he has made contract. (b) Futures Contract:Future contact in the power exchange would mean that the participant can hedge their risk in the fluctuation of Oil prices for longer terms. For example, a Oil Pproducing company expecting a decrease in the Oil prices can sell the futures now to be able to ensure higher prices at the time of delivery in future. Various kinds of contracts under this type of instrument can be of varying time horizon. (c) Options:Unlike futures, in options buyer does not have any obligation to exercise the contract. Options can also be used to hedge the risk of price fluctuations. The only difference being that an upfront payment of premium has to be made in case of an option whereas a trader does not need any upfront payment in case of futures. Fundamental option positions Calls and puts There are two basic types of options: buy (call) options and sell (put) options. A call option entitles, but does not obligate, the holder to purchase the underlying product i.e Oil at a price that has been agreed to in advance (the exercise price) -- no later than at the agreed-to date (the exercise date). A put option entitles the holder to sell the underlying product on corresponding terms. The decision to invest in a call or put option is made according to the investor's expectations about the price movement of the underlying instrument. OIL TRANSPORTATION • Movement of oil takes place in two steps: 1.crude oil(from well to gathering station& gathering station to refineries) 2. finished products(from refineries &port to consumption centre) • MODES OF PRODUCT TRANSPORTATION 1 Rail 2 Road 3 Pipelines 4 coastal Most of the major consumption centres in India are land-locked. This makes only Road, Rail and Pipeline as the feasible means of transportation of petroleum .Tankers are used for movement between coastal locations. Road: It Plays a crucial role in country’s transport sector for goods and passengers. For movement of petroleum products over long distances, road transportation is not very cost effective and efficient. Feasible only for short distances and secondary movement of petroleum products. Though movement by road results in excessive consumption of diesel and is a potential safety and environmental hazard, it still enjoys a large share in the modal mix due to unavoidable short distance movement from bulk depots to retails outlets. Railways: • Railway Traditionally, Railways have been the largest transporter of POL; developed since earlier days and cover substantial parts of the country. Besides petroleum products, railways also transport goods and passengers. Capacity of railways has already been over-stretched. With continuing growth on all spheres, railways transportation capacity would fall short of the transportation requirements. Due to cross-subsidisation, the freight for petroleum products is high. Rail transportation also leads to high energy consumption, environmental pollution and transit losses. • Coastal: Since the major consumption centers of the country are located in the hinterland, the movement of petroleum products through tankers is somewhat limited. Tankers are used for movement between coastal locations. This mode also suffers from capacity constraints in terms of draft availability, navigational facilities, jetties etc. Pipelines: • The term pipeline in broader sense means a facility used to transport commodities from point of receipt to the point of delivery. Many commodities are transported through pipelines. Crude oil, petroleum products and gas are perhaps the most common commodities transported by pipelines. • Development of Pipelines in India • Most of the earlier Refineries in India were installed at coastal locations, thus depending on coastal movement of crude oil. Further, the refining capacities being low, the products were either consumed locally or transported to the consumption centres by rail or road. After 1960, most of the Refineries were installed in land-locked locations necessitating laying of crude & product pipelines. During 1960-63, Oil India Limited laid the first trunk crude oil pipeline, 1156 km long from Naharkatiyaand Moran oil fields to the Refineries at Guwahati and Barauni. The first cross country product pipeline was laid by IOCL during 1962-64 to transport products from Guwahati Refinery to Siliguri. • • NATURAL GAS Introduction: India is one of the top 10 oil-consuming countries in the world. Oil and gas represent over 40 per cent of the total energy consumption in India. The consumption of petroleum products in the country is on the rise and demand already far exceeds domestic supply. Therefore, the country has to depend largely on imports. The country’s existing annual crude oil production is peaked at about 32 million tonnes as against the demand of about 110 million tonnes. With inadequate crude production, the country is heavily dependent on imports. Crude is the single largest item on India’s import list. Estimates show that the demand is likely to grow at a faster pace over the next decade if India is to maintain the GDP growth target of 8 per cent. This implies larger imports unless new domestic oil reserves are found. With this in view, the government announced the New Exploration Licensing Policy (NELP) in 2000. With a view to ensure long term energy security, the government is also building oil and gas equity abroad Circa 1974, with the huge oil & gas discovery in Bombay High field in 1974, followed by the giant South Bassein free gas find in 1978, the question then was “How to develop a market for this gas?” The answer then was GAIL and the HBJ pipeline. Ten years later, the scenario turned 180 degrees, when the gas demand exceeded the supply and the question changed to “How to find more gas?” The answer then was New Exploration and Licensing Policy (NELP). The Government of India (GOI) introduced the NELP about ten years ago to spur exploration and development in oil and natural gas. Since then, significant gas finds have been found off the Indian shores, thus achieving NELP’s goal and also helping to move India towards self sufficiency in natural gas. While this is a very positive development of the NELP regime, there are also some concerns regarding utilization, pricing and policy issues surrounding NELP and other gas finds under it. During 2007-08, crude oil production in the country is expected to be about 34.763 million metric tones (MMT) and 31.67 billion cubic metres (BCM) of natural gas production as against the production of 33.99 MMT of crude oil and 31.74 BCM of natural gas in 2006-07. During XI Plan period, crude oil production is likely to increase 24% as against actual crude oil production during X plan period. With exploration and development efforts made under New Exploration Licensing Policy (NELP), Natural Gas production in the country is likely to be doubled from the present level of gas production of about 90 million standard cubic meters per day (MMSCMD) by end of 11th Five AVAILABILITY & UTILISATION OF NATURAL GAS Natural gas has emerged as the most preferred fuel due to its inherent environmentally benign nature, greater efficiency and cost effectiveness. The demand of natural gas has sharply increased in the last two decades at the global level. In India too, the natural gas sector has gained importance, particularly over the last decade, and is being termed as the Fuel of the 21st Century. Production of natural gas, which was almost negligible at the time of independence, is at present at the level of around 87 million standard cubic meters per day (MMSCMD). The main producers of natural gas are Oil & Natural Gas Corporation Ltd. (ONGC), Oil India Limited (OIL) and JVs of Tapti, Panna-Mukta and Ravva. Under the Production Sharing Contracts, private parties from some of the fields are also producing gas. Government have also offered blocks under New Exploration Licensing Policy (NELP) to private and public sector companies with the right to market gas at market determined prices. Out of the total production of around 87 MMSCMD, after internal consumption, extraction of LPG and unavoidable flaring, around 74 MMSCMD is available for sale to various consumers. Most of the production of gas comes from the Western offshore area. The on-shore fields in Assam, Andhra Pradesh and Gujarat States are other major producers of gas. Smaller quantities of gas are also produced in Tripura, Tamil Nadu and Rajasthan States. OIL is operating in Assam and Rajasthan States, whereas ONGC is operating in the Western offshore fields and in other states. The gas produced by ONGC and a part of gas produced by the JV consortiums is marketed by the GAIL (India) Ltd. The gas produced by OIL is marketed by OIL itself except in Rajasthan where GAIL is marketing its gas. Gas produced by Cairn Energy from Lakshmi fields and Gujarat State Petroleum Corporation Ltd. (GSPCL) from Hazira fields is being sold directly by them at market determined prices. Natural gas has been utilised in Assam and Gujarat since the sixties. There was a major increase in the production & utilisation of natural gas in the late seventies with the development of the Bombay High fields and again in the late eighties when the South Bassein field in the Western Offshore was brought to production. STORAGE OF NATURAL GAS The gas produced in the western offshore fields is brought to Uran in Maharashtra and partly in Gujarat. The gas brought to Uran is utilised in and around Mumbai. The gas brought to Hazira is sour gas which has to be sweetened by removing the sulphur present in the gas. After sweetening, the gas is partly utilised at Hazira and the rest is fed into the Hazira-Bijaipur-Jagdhishpur(HBJ) pipeline which passes through Gujarat, MadhyaPradesh, Rajasthan, U.P., Delhi and Haryana. The gas produced in Gujarat, Assam, etc; is utilised within the respective states. Natural Gas is currently the source of half of the LPG produced in the country. LPG is now being extracted from gas at Duliajan in Assam, Bijaipur in M.P., Hazira and Vaghodia in Gujarat, Uran in Maharashtra, Pata in UP and Nagapattinam in Tamil Nadu. Two new plants have also been set up at Lakwa in Assam and at Ussar in Maharastra in 1998-99. One more plant is being set up at Gandhar in Gujarat. Natural gas containing C2/C3, which is a feedstock for the Petrochemical industry, is currently being used at Uran for Maharashtra Gas Cracker Complex at Nagothane. GAIL has also set up a 3 lakh TPA of Ethylene gas based petrochemical complex at Auraiya in 1998-99. Natural Gas Allocation & Supply Scenario As against the total allocation of around 118 MMSCMD, the gas supplies by GAIL is of the order of 63 MMSCMD spread over about 300 major consumers. Around 32% is supplied to the fertiliser sector, 41% to power, 4% to sponge iron and the balance 23% (including shrinkage) goes to other sectors. All India Region-Wise & Sector-Wise Gas Supply By GAIL - (2003-04) Region/Sector HVJ & Ex-Hazira Onshore Gujarat Uran K.G. Basin Cauvery Basin Assam Tripura Grand Total Power 12.61 1.66 3.57 4.96 1.07 0.41 1.37 25.65 Fertilizer 13.63 1.04 3.53 1.91 0.04 20.15 2.58 S. Iron 1.24 1.33 Others 9.81 2.08 1.41 0.38 0.25 0.29 0.01 14.23 Total 37.29 4.78 9.85 7.25 1.32 0.74 1.38 62.61 OIL is also supplying around 3 MMSCMD in Assam against allocations made by the Govt. Around 8.5 MMSCMD of gas is being directly supplied by the JVs/private companies at market prices to various consumers. This gas is outside the purview of the Government allocations. IMPORT OF NATURAL GAS TO INDIA THROUGH TRANSNATIONAL GAS PIPELINES. Iran-Pakistan-India (IPI) Pipeline Project In pursuance of Government decision in February 2005, Minister (P&NG) led a delegation to Pakistan during 4-8 June 2005. During the talks, the two Ministers reviewed the Iran-Pakistan-India gas pipeline proposal. They agreed that the project, which envisaged supply of gas to Pakistan and India through a transnational pipeline, would go a long way in meeting the energy security requirements of the two countries, and thus should be seen as a significant project for the benefit of the people of these countries. The Indian and Pakistani delegations agreed to exchange information in regard to the financial structuring, technical, commercial, legal and related issues to realize a safe and secure world class project. To this end, it was agreed that the momentum pertaining to the project should be accelerated by constituting a Joint Working Group at the Secretary level at the earliest, which will meet regularly and report the progress to the Ministers to facilitate definitive decisions by them. An Indian delegation also visited Iran from 11-14 June 2005 and discussed the issue of import of natural gas from Iran through on-land pipeline transiting via Pakistan. Both sides noted with satisfaction that as a result of regular discussions on technical issues pertaining to the project, a Heads of Agreement between NIGEC and the Indian companies concerned had been finalized. With a view to undertaking further studies and discussions in regard to relevant issues so that the project could take off by early next year, it was agreed to establish a special JWG on the Iran-Pakistan-India gas pipeline project. A Pakistani delegation led by the Secretary, Ministry of Petroleum and Natural Resources, Govt. of Pakistan visited New Delhi on July 12-13, 2005 for the first meeting of India-Pakistan JWG. The second meeting of the JWG was held in Islamabad on 8-9 September, 2005. The first meeting of the Special JWG on Iran-Pakistan-India Pipeline Project was held in New Delhi on 3-4 August, 2005. The second meeting of the Special JWG on Iran-Pakistan-India Pipeline Project was held in Tehran on 24th October,2005. The Indian side was led by Secretary (P&NG). Indian side has already appointed financial consultants i.e., M/s Ernst & Young and is in the process of finalizing appointment of legal & technical consultants for the project. During the 2nd JWG meeting, the Pakistani side informed that they will also shortly be appointing their Financial Consultants. At the latest due to various pricing and the security related unsolved issues with Pakistan, the deal had been shelved, and Iran has signed the modified deal with Pakistan as the sole partner in may 2009. Myanmar-Bangladesh-India Gas Pipeline Project. To pursue the matter at the Government level, for bilateral and trilateral discussions with Myanmar and Bangladesh, the Minister (P&NG) visited Yangon during 11-13th January 2005. A Memorandum of Understanding (MOU) for cooperation in the petroleum sector between the two Governments was signed. The MOU provides for furthering cooperation in the hydrocarbon sector and for establishing a cooperative institutional relationship in the field of petroleum industry on the basis of equality and mutual advantage, taking into account the possibilities for cooperation available in each country. The two Governments will designate a body of experts comprising three representatives of each party to identify and implement the projects in the hydrocarbon sector. A trilateral meeting between the Petroleum Ministers of India, Myanmar and Bangladesh held on 12.1.2005. After the meeting a Joint Press Statement was issued by the three Ministers. The three sides agreed to transport of natural gas from Myanmar to India by pipeline transiting through Bangladesh. The route of the pipeline will be determined by mutual agreements of the three Governments. It was also decided to establish a Techno-Commercial Working Committee (TCWC) comprising duly designated representatives of the three Governments to prepare a draft MOU prescribing the framework of cooperation among the three Governments, including the Myanmar-Bangladesh-India gas pipeline project. The MOU would be signed at Dhaka at the earliest mutually convenient date. In pursuance of the MoU, a Techno-Commercial Working Committee has been constituted by the three Governments. The First Meeting of the TCWC was held on 24-25 February, 2005. The TCWC has finalized draft MoU proposed to be signed by the three oil Ministers. However, there are certain bilateral issues which have to be sorted out with Bangladesh. Simultaneously, India is also exploring the other option of import of natural gas from Myanmar. A high level delegation led by Minister, Energy, of Myanmar recently visited India during July 5-7, 2005. All aspects of Myanmar-Bangladesh-India gas pipeline were discussed. Minister (P&NG) visited Bangladesh during 5-6 September 2005 to pursue the matter with Government of Bangladesh. The matter is being pursued vigorously and the proposed gas imports from Myanmar would be finalized shortly notwithstanding the response of Government of Bangladesh. GAIL has been asked to do a pre-feasibility study of the onland pipeline route from Myanmar to India through North-Eastern Indian States, bypassing Bangladesh territory. The option of getting Bangladesh on board is also being simultaneously pursued. Another official level meeting was held in Yangon on 29-30 August 2005, where two sides agree to take definite steps for gas supply from Myanmar. Turkmenistan-Afghanistan-Pakistan (TAP) pipeline Daulatabad area of Turkmenistan has reported to have sufficient gas reserves. The Governments of Turkmenistan-Afghanistan-Pakistan (TAP) proposed the transnational gas pipeline to exploit the available gas reserves in Turkmenistan. They designated ADB as the lead development partner. ADB has carried out the study and approached India for participating in the project. Minister (P&NG) discussed this matter with Pakistani side during his visit to Pakistan 4th to 8th June 2005. This was also discussed by Secretary (P&NG) with President ADB during the latter's visit to New Delhi on 1.9.2005. Although, India is not yet formally involved in TAP project, Minister (P&NG) has been invited to the next Steering Committee Meeting to be held in Ashgabat in early December, 2005. LIQUEFIED NATURAL GAS (LNG) Natural gas at -1610C transforms into liquid. This is done for easy storage and transportation since it reduces the volume occupied by gas by a factor of 600. LNG is transported in specially built ships with cryogenic tanks. It is received at the LNG receiving terminals and is regassified to be supplied as natural gas to the consumers. LNG projects are highly capital intensive in nature. The whole process consists of five elements: Dedicated gas field development and production.  Liquefaction plant.  Transportation in special vessels.  Regassification Plant.  Transportation & distribution to the Gas consumer. LNG supply contracts are generally of long term nature and the prices are linked to the international crude oil prices. However, the LNG importing countries in recent times had started asking for medium/short term contracts with varying linkages. LNG Imports to India The LNG trade started in mid 60's and has increased rapidly. In 1992 it was around 80 Billion Cubic Metres (BCM) per annum and crossed the 100 BCM mark in 1996. World trade in LNG is currently in the range of 150 BCM. The major exporting countries of LNG are Algeria, Qatar, Indonesia, Malaysia, Australia, whereas, the major importers are Japan, South Korea, Taiwan and Western Europe. Geographically, India is very strategically located and is flanked by large gas reserves on both the east and west. India is relatively close to four of the world's top five countries in terms of proven gas reserves, viz. Iran, Qatar, Saudi Arabia and Abu Dhabi. The large natural gas market of India is a major attraction to the LNG exporting countries. In order to encourage gas imports, the Government of India has kept import of LNG under Open General License (OGL) category and has permitted 100% FDI. LNG Projects Petronet LNG Limited (PLL), a JV promoted by GAIL, IOCL, BPCL and ONGC was formed for import of LNG to meet the growing demand of natural gas. PLL has constructed a 5 MMTPA capacity LNG terminal at Dahej in Gujarat. The terminal was commissioned in February 2004 and commercial supplies commenced from March 2004. PLL is planning to expand this terminal to 10 MMTPA capacity by 200809 to meet the growing demand of LNG. Shell's 2.5 MMTPA capacity LNG terminal at Hazira has been commissioned. Dabhol LNG terminal (total 5 MMTPA capacity, with about 2.9 MMTPA available for merchant sales) may also become operational by 2006 subject to availability of LNG for the project. LNG terminals at Kochi in Kerala, Mangalore in Karnataka and Krishnapatnam/Ennore in Tamil Nadu are also under active consideration and may fructify in next 4-5 years time. The price of LNG for the Dahej project is linked to the JCC crude oil price. It has a fixed price for the first five years, i.e. upto December 2008 and a floating floor and ceiling price thereafter. At present the selling price of LNG in Gujarat is $4.87/MMBTU (Rs. 8777/MCM) and outside Gujarat is $4.88/MMBTU (Rs. 8800/MCM). At this price, LNG is comparatively cheaper than alternative fuels/feedstock's e.g. naphtha, Furnace Oil, LSHS, Light Diesel Oil, LPG, etc. REGULATORY FRAMEWORK FOR THE GAS INDUSTRY The Ministry of Petroleum & Natural Gas (MOP&NG) has been regulating the allocation and pricing of gas produced by ONGC and OIL by issuing administrative orders from time to time. The gas produced by the JVs and by NELP operators is governed by the respective production sharing contracts (PSC) between the Government and the producers. The setting up of a Petroleum & Natural Gas Regulatory Board is under the consideration of the Government and the bill is being drafted. Under the existing policy, 100% Foreign Direct Investment (FDI) is allowed through the FIPB route for both LNG projects and natural gas pipeline projects. Import of LNG and natural gas is on OGL. If an entity requires the acquisition of Right of User (ROU) in land, it approaches MOP&NG for the acquisition under the Petroleum & Mineral Pipelines (Acquisition of Right of User in Land) Act, 1962 (P&MP Act, 1962). The draft natural gas pipeline policy covering transmission pipelines and local or city gas distribution networks is under formulation, with proposed provision in line with those under the draft regulatory board bill. Present Scenario The distribution of natural gas reserves in the country is not uniform. Around 75% of the gas is produced in the Western Offshore fields, with the balance coming mostly from Gujrat and the North-Eastern States. The production of crude oil and natural gas is currently the responsibility of two public sector undertakings (PSUs), ONGC and OIL. The Gas authority of India Ltd. (GAIL), a PSU, and OIL are engaged in transportation, distribution and marketing of natural gas. The Government of India is keen to attract private investment in the production, transportation, etc. of natural gas. Contracts have been awarded for the development of some medium/smalll sized fields and it is expected that in 1997-98 about 6 MMSCMD of gas would be produced from the private/joint venture fields. Two private sector companies and the Municipal Corporation of Baroda are at present engaged in the distribution of the natural gas in the domestic/commercial sector in Gujrat and Mumbai. Two State Government undertakings are doing the same work in the North-Eastern states in a number of small towns. City gas for Delhi and a project for supply of gas to reduce pollution in and around Taj Trapezium area are being implemented. The GAS Linkage Pricing, Contracts & Inventory Control Tariff setting in Gas Transmission- A view of Methodologies Gas consumption in any substantial manner in India began with the formation of GAIL and setting up of the Hazira-Bijaipur-Jagdishpur (HBJ) pipeline. This ling line actually boosted natural gas consumption in the country. Major consumers of gas in the country happen to be the power and fertilizer sector consuming about 40 and 34%, respectively. Domestic and household usage of gas is yet to develop. The discovery of gas in the Krishna –Godavari (KG) basin and other places and setting up of LNG terminals on the west coast of the country has suddenly changed the gas scenario in the country. And the future is likely to see a much larger share of gas in the overall energy consumption pattern. The tenth plan projects a demand of about 180 mmscd from the present level of 145 mmscd and a shortfall of about 100 mmscd and domestic supply of about 80 mmscd. This can change with the exploitation of the KG gas recourses. Natural gas, unlike other commodities, cannot be transported by road or rail. There has to be a network of pipelines for gas transmission and a local distribution zone where it can be retailed or solid in bulk. A good gas transportation network is a prerequisite for development of free market in gas. As capital costs are high, construction risk very high, and because there are network externalities. The business of gas transportation tends to be natural monopoly. Unbundling in this sector means the separation of the “pipes business”(natural monopoly), from supply which can be competitive. The pipes business, therefore, needs to be regulated and “open access common carrier” principle will have to be enforced on the lines of what obtains in the electricity sector. In such a scenario, tariffs become an important feature for selling of natural gas as a competitive fuel. Tariff will also determine the geographic spread of usage of gas. Regulation today Postage stamp tariff GAIL is the major transporter today and it has, since inception, followed postal stamp tariff. This means that tariff at any place in the country remains the same irrespective of distance. This tariff recovers capital costs, variable costs like gas consumption for pressure boosting and manpower costs, and a post tax return of 12% on network. Perhaps this kind of regime was justified because of shoratge of gas with no alternative than the allocation of gas by the central goverment. It was perhaps also the vestigial idea of equalization of cost of transport similar to freight equalization for coal and steel. With few users there could not have been a gas market. The need to corret the regional imbalances and, therefor, siting of industries in backward regions became necessary. This has led to fertilizer factories being set up in uttar pradesh while gas was available on the west coast. However, in a scenario where gas was being “allocated” , cost recovery was not really difficult. Presently this tariff is in the range of Rs 1150 per thousand SCM. APM for petroleum products has already been dismanted and it will not be long before this momentum catches up with gas also. Already, for the new discoveries the price of the commodity, that is , gas, is being marked to market. Industrial policy has long been liberalized and siting of central PSU units is more on the basis of locational economics. In such a regime, a postage stamp tariff defies economic logic.once gas sales are driven more by market consideration, fixing transmission tariffs on postage stamp principle would not be possible. In a deregulated scenario, the tariff system must: a) Allow for cost recovery so that the system is bankable b) Be transparent, stable and practicable c) Enable transition to the market-based system on gas transactions d) Send economically appropriate signals to foster greater utilization of capacity and permit gas to be a competitive fuel. This would imply the unbundling of the tariff with respect to the pressure and area that is,the pricing regime would be different fora local distribution zone and different for a trunk transmission line. Similarly, pricing would be differnt for high and low pressure lines. There are two important components in the gas transmission tariff: They are : Capacity charge to recover fixed cost and variable charge to cover the through put costs. A third element of costs which includes inter alia connection charge and system gas charges, would be subsumed in the above two categories. In practice, one has seen in that capacity charge/variable cost split can be as high as 90/10. But, at this split level, it would be difficult to sell transmission capacity except for very large buyers with firm demands for long perionds. Therefore, an appropriate tariff methodology needs to be developed. Transmission lines have fairly long lives. Once the loan is fully paid out the tariff structure would change. Average accounting cost Here, the total cost of setting and operating the system is allocated over the entire capacity and average unit cost is developed from that.it is transparent and strainght forward system and charges customers for excess capacity. And also distant customers paying high tariff. Long run marginal cost(LRMC) This approach takes into account incremental capital and operating cost required to meet sustained increase in throughtput. It provides an economically sound basis for tariff setting and users do not have to pay for surplus capacity.it also requires an incremental capacity to be defined over which LRMC would be applied. Therefore, a pure LRC has better applicability in a mature market, where demand patterns have stabilized and stabilized and investment pattern in pipelines over a period of time is more or less known a priori. When applied to gas pipelines the following methods are important in leading to the appropriate regulation: Virtual pipeline method: While the transmission company may like to set up a large system to cater for full demand, the user may not like to pay the capital charge for the full capacity. Therefore, one basis for tariff setting is to assume only the capacitytaht the user is likely to use. In this method we assumed as if a line is actually being set up for taht user and for the capacity that he wants to use within the main line. Thus the entire line gets divided into a large number of virtual pipelines. This permits the user to pay for a limited capacity even if the pipeline size is large.this is a tendency for the transporter to incentivize additional usage of capacity and thus permit an aggressive pricing regime.in a virtual pipeline methodology, since the user virtually owns part of the line, the capacity charges tend to be on the higher side, about 85% of the total charges. Such pipelines normally set up with higher equity and around 50-70 % of the total project cost. Cluster approach: Also known as entry/exit pricing. For such demand centre uniform pricing is done relative to an entry point. If there are more tahn one entry poiunts, than those many different slabs of rates would exist with respect to entry and exist points. An attempt is made to capture all the costs pertaining to one demand centre within the tariff itself. Thus, costs for each demand centre is effectively segregated. This policy also helps in reducing tariffs for distant demand centres. No single tariff methodology can capture all the requiremnets of both the users and the transmission company. Factors as demand,demand pattern, cost of laying impact on the choice of tariff methodology. Gas transmission lines are seen as natural monopolies. It is diffecult for the user to shift from one line to the other.the west coast has seen multiple operators, signalling a certain amount of contestability at the entry point of the value chain. Here the risk is high and revenue is shaky, so the relationship between user and the transmission entity is normally maintained through a contractual framework known as Gas Transmission Agreement(GTA). Some saliant features of a normal GTA are: 1. It specifies the capacity that is offered to the user. It also specifies the uptime for the system. These are backeds by penalties if these requirements are not met.normally, the shortfall or the excess use of the capacity is measured on a daily basis and penalities are determined at the end of the month. 2. There is a mix of slightly different gases,therefore, what the user puts in and gets out of the system is the energy per and this remains a unit of transcation.however, the properties of gas on entry are regulated on such parameters as such parameters as waxing properties, dew point, pressure, etc. 3. Depending upon the type of tariff methodology used, there are invariably incentives for using larger volumes of capacity. However, where capacity is a constraint the pricing methodology may be reversed. 4. Capacity charges ensure that even non-usage of the capacity does not impact the revenues of the transmitting entity. However, in case the user reneges on his promise to use the capacity, then most of the contacts make a provision for a lump-sum compensation to ythe transmitting entity. CURRENT NEWS:India launches ninth edition of NELP Hoping to attract more foreign companies to explore its vastly unexploited sedimentary basin, India launched its ninth round of oil and gas block auction, made up mostly of previously discarded areas. Petroleum Minister Murli Deora launched the ninth edition of New Exploration Licensing Policy, offering 34 exploration blocks, almost half of the previous round in 2009. Out of 34 blocks, 19 blocks are totally new areas -- 7 in deep sea, 2 in shallow waters and 10 onland blocks. Rest 15 (1 in deep water, 5 in shallow water and 9 onland blocks) are recycled blocks . Of the recycled blocks, five are discards of state-owned Oil and Natural Gas Corporation, the largest bidder in the previous eight rounds of NELP. ONGC relinquished the areas it had won in first and second round of NELP, after it made no discovery. An investment commitment of more than $1.1 billion in NELP-VIII is expected for the current blocks being offered. Last date of bidding for blocks offered under NELP-IX is March 18, 2011, exactly five months from the date of first roadshow to be held in Mumbai. This time in the new policy, impact of absence of seven year holiday or exemption from payment of income tax from profits earned from the oil and gas produced from the areas awarded in NELP-IX.The proposed Draft Tax Code, to be implemented from April 2012, has done away with profit-linked incentives for all sectors. Instead an investment linked incentive will be available. In the eight rounds of NELP since 1999, 235 blocks have been awarded till date.This has resulted in enhancement of exploration coverage from 11 per cent to about 58 per cent of Indian sedimentary basin between 2000 and 2010. The discoveries made under the NELP have resulted in in-place hydrocarbon reserve accretion of a staggering 642 million tonnes of oil and oil equivalent gas. A total of 87 oil and gas discoveries have been made in 26 blocks under NELP during this period. The discoveries have added over 640 million tonnes of oil equivalent reserves. In the first eight rounds of NELP, $11.1 billion investment was committed but actual investment so far has been $14.3 billion. The blocks offered in NELP-IX include 8 deep-sea, 7 shallow water and 19 onland. The onland blocks include 8 small blocks for which there is technical qualifying criteria for companies to bid.These 34 blocks cover a sedimentary area of about 88,807 square kilometer, which is 2.9 per cent of Indian sedimentary basin area. The onland blocks fall in Assam (2), Gujarat (11), Rajasthan (2), Madhya Pradesh (2), Tripura (1) and Uttar Pradesh (1). The seven shallow water and eight deep water blocks on off the east and west coast but no area in the prolific Krishna Godavari basin is on offer. Out of 87 oil and gas discoveries made in NELP rounds, natural gas production in Reliance Industries eastern offshore KG-D6 block commenced from April 2009. The 8th round, which closed on October 12, 2009 attracted investment commitment of $1.34 billion for 36 blocks that received offers. Under NELP-VIII, 70 areas or blocks for exploration were offered, the biggest licensing round in India. Of the 36 areas bid for, the government had awarded 33 blocks to successful bidders. The road shows/investors Meets at Moscow Houston, Calgary, Perth and Singapore are planned to promote NELP-IX. The government has hired UK-based Furgo Data Solutions Ltd to market the blocks. Conclusion Gas market in india is still in its infancy. The “allocation” based system is changing to markets for gas. There are various components of costs in usage of gas when unbundled, which users will have to consider before ruling out alternative fuels. Market of gas only improved by the transmission system is in place. So transmission entity, which does not club sale of commodity along with transmission and follows coman carrier principles with a tariff regime that is appropriate to the development of markets. Virtual pipelines and cluster methods are possible otins. One is also witnessing a slow shift from a single source of gas to multiple entry points. This would also facilitate short-term and spot contracts in gas apart from standard long-term contracts. This would mean short term pricing of transmission capacity as well. This will provide additional cash flow streams to the gas transportation entities and we might soon see a tariff regime for short term users and one for long-term users. Water resources The Central Electricity Authority (CEA) is worried that securing water linkages for thermal power plants is becoming tougher and could hurt plans to boost India’s power generation capacity. “Already we are having problems in setting up some projects. There has to be a comprehensive plan for setting up water resource facilities in states having potential for thermal development,” said Rakesh Nath, chairman of CEA, the country’s apex power sector planning body. Of India’s 167,278MW installed capacity, 108,602 MW is thermal-power based. Of this 108,602 MW, around 89,778MW is coal-fired, while the remaining is fuelled by gas & diesel. The country plans to add 78,577MW by 2012. Of this, 4,290MW will be gas-based and around 46,600MW is expected to come from coal-based projects. “Reservoir creation leads to issues relating to environment, rehabilitation and relocation. We have already taken up the issue with our ministry (power ministry) to take up the issue with the ministry of water resources,” Nath said. While it takes 40 cu. ft per second (cusec) of water for a 1,000MW coal-based thermal power project, the requirement is 20cusec for a gas-based thermal power unit. Cusec is a measure of the flow rate. “For all new projects, there is no water linkage available. They have no option but to go for coastal projects by using sea water for the purpose. Only in monsoons there is water in the rivers. We have to create dams for different seasons,” said another CEA official, who didn’t want to be identified. According to the Central Water Commission, while the average annual rainfall in India is 4,000 billion cu. metres (bcm), the estimated utilizable surface water resources are 690bcm. An official in the ministry of water resources confirmed the problem that thermal power plants are facing, but said: “States are diverting water meant for agricultural use for power generation.” PROCEDURE TO GET WATER LINKAGES: • Signing up of MoU between the state government & the private entity. While signing the memorandum of understanding government of the concerned state agrees to supply the water for the upcoming power plant. • Allocation of water by the WRD (water resource department) of the concerned district. The committee here decides the amount of water to be allocated for the power plant from the total amount of water allocated for that district for the industrial purpose. The water cess is paid in advance for the one quarter of a year. • To identify a suitable location on the river near the plant site for constructing a water harvesting structure. • To analyze the available monthly and yearly surface flow at the specified location. • To estimate the extent of annual water availability at the site at 75% and 90% dependable surface flow. • To estimate the extent of water volume needing storage, if any, to meet the requirements during lean flow periods in the river at 75% & 90% dependable surface flow. • To conduct Topographical survey of the area to estimate area of submergence for the above storage and height of structure. • To conduct geological and geotechnical survey of proposed site for fixing suitability of structure. • To conduct soil test for designing of structure. • To indicate location of Intake and Pump house for withdrawal of water for the Plant area. • To indicate the route of raw water main from the Intake to Plant site. SELECTION OF WATER HARVESTING SITE: • • • • • • The catchment area should be sufficient to fulfill the plant requirement of water. It should be at the optimum distance from the proposed plant site. The site should be approachable through existing road. The bed of the river is likely to provide a suitable foundation for providing water harvesting structure. No such settlement (Housed) would come under submergence. Other sites than this proposed site have few disadvantages like  Increase in Pumping cost due to more level difference.  Increase in length of pipe line and its cost. ESTIMATION OF ANNUAL WATER DEMAND: The coal based thermal power plant of capacity 100 MW requires 3.6 MCM of water annually for its successful operation. For e.g.: A coal based power plant of capacity 1000 MW will require = 3.6 X 10 MCM. So it comes out to be= 36 MCM. Water requirement for township & other miscellaneous uses= 6 MCM So total amount of water required for 1000 MW capacity coal based power plant is = 42 MCM The monthly requirement of water=42/12 =3.5 MCM STORAGE REQUIREMENT: The storage requirements at 90% dependability site have been estimated keeping following points in view. The Gross storage is calculated keeping all points in view. • • • Dead storage is taken as 2 MCM for the plant capacity of 2000 MW. Evaporation / seepage loss taken as 10% of Storage need. Route loss @ 3% is also considered. DETERMINATION OF THE PARAMETERS OF THE STRUCTURE: In order to determine the height of the structure first of all we have to calculate the storage capacity of the reservoir. After this we have to determine the following aspects of the reservoir • • • • Submergence area. Height of the structure. FRL (Full Reservoir Level). Barrage with radial width. • • • • MDDL (Minimum Draw Down Level). HFL (High Flood Level). MWL (Maximum Water Level). DSL (Dead Storage Level). Water allocation & charges In the planning and operation of system water allocation priorities shall be as under: • Drinking water supply • Irrigation and afforestation. • Power generation/industrial and other uses. • Tourism Water resources department shall be made a nodal department for permitting different uses of water resources. Clear provision for reservation of drinking water shall be made in proposed irrigation projects of the state, on river, reservoirs, tanks etc. WATER is priced far too cheaply in India to prompt industrialists into conserving or recycling it, says a detailed study prepared by the National Institute of Public Finance and Policy (NIPFP) for the Ganga Project Directorate. But the government has let the NIPFP recommendations lie in its cupboards. The study assessed the water pollution caused by a dozen types of industrial units situated in the Ganga basin in Uttar Pradesh and West Bengal. The study, which was undertaken by a group of researchers led by M N Murty and D B Gupta, found that the production cost of water in this region, because of its good ground and surface water resources, was very low -- about 20 paise a kilolitre. Not surprisingly, none of the units surveyed in the Ganga basin practised water conservation measures. On the other hand, in the dry regions of the country where water is priced higher, there were several good examples of water conservation. For instance, Madras-based Tamil Nadu Petro Products Ltd spends about Rs 47 a kilolitre to conserve water for cooling purposes Water pricing in India depends more on socio-economic and political factors rather than on the cost of production and distribution or the willingness of people to pay. Consumers are usually classified as domestic, commercial and industrial, and charged accordingly. Pricing of water for industrial use is based on ad hoc criteria, says the NIPFP study. "In most of the municipalities and boards, water tariffs have not been revised for years. The few cases where it has been revised, has been without any guidelines. In fact, due to inadequate information on production and distribution costs in the case of most local bodies, it is not possible to analyse the tariff structure." Murty and his fellow-researchers say there should be no free-riding on public goods such as water, air and land. Water prices cannot be determined by market forces alone as water is more or less freely accessible to everyone. And when the user -- industrial or domestic -- disposes effluents into a river or lake, it affects all of society and this social cost is difficult to estimate. Tax-based approach Given that environment is a public good and the polluter a free-rider, the polluter should be asked to pay for pollution control. The government should levy taxes that take into account pollution control costs. Setting standards, the researchers argue, is a political process that should involve both the victims and perpetrators of pollution. Any pollution standard fixed without ascertaining the views of pollution victims cannot be regarded as a national standard. The minimum national standards developed by the Central Pollution Control Board (CPCB) try to keep the cost of pollution control to within one per cent of the annual turnover of a firm, which means the interests of polluters have been taken care of, but not that of the victims. The researchers point out effluent standards can be fixed in two stages. In the first, national standards can be set based on technological and economic considerations alone and applied to all industries, without considering local conditions. In the second stage, however, more stringent standards should be imposed depending upon local water quality requirements. The CPCB standards correspond only to the first stage. Only standards developed in the second stage will relate directly to the damages borne by the victims, say the researchers. Two components Generally, industries either get their water supply from the local municipal administration or make their own arrangements, or use a combination of both. The researchers suggest the price of water should include two components: its production cost and a pollution tax. If the factory uses its own tubewell, the municipality charge should consist of its pollution abatement cost, fixed on the basis of each kilolitre of water used. At the moment, factories drawing water from their own tubewells do not pay any charge. The study also shows that the cost of treatment of polluted water varies across industries, depending on the quantity and nature of pollutants released. Therefore, to recover the full cost of providing effluent treatment services, pollution control boards will have to levy different pollution taxes on different industries. However, for practical purposes, it may be useful to separate water costs from pollution taxes. While costs can be dealt with by water supply authorities, taxes ought to be based on the pollution loads of different industries and pollution standards. The researchers also point out that the objective of the pollution tax could vary depending on the region in which it is being levied. For instance, in the water-rich Gangetic basin, the pollution tax should aim only at ensuring factory effluents are of the desired quality. But in drier areas, pollution taxes should provide industries with an incentive to recycle effluents and conserve water. Since there are economies of scale in the treatment of polluted water, it is better to treat higher volumes of effluents. Studies have shown the social cost of controlling water pollution per tonne of paper produced is Rs 145 for a mill with a daily capacity of 10 tonnes, and only Rs 30 for a mill with a daily capacity of 115 tonnes. So, it is not economical for small units to have their own effluent treatment plants. Instead, the combined effluents of a number of small units should be treated by the water pollution control board or a local administration unit. The cost of such plants can be realised through a pollution tax on these units. Boiler Efficiency The performance parameters of boiler, like efficiency and evaporation ratio reduces with time due to poor combustion, heat transfer surface fouling and poor operation and maintenance. Even for a new boiler, reasons such as deteriorating fuel quality, water quality etc. can result in poor boiler performance. Boiler efficiency tests help us to find out the deviation of boiler efficiency from the best efficiency and target problem area for corrective action. Boiler efficiency, in the simplest terms, represents the difference between the energy input and energy output. Boiler Efficiency related to the boilers energy output to the boilers energy input The Boiler Efficiency is defined as “The ratio of heat actually utilized in generation of steam to the heat supplied by the fuel in the same time” i.e. Boiler efficiency= Heat gained by the steam from the boiler per unit time/Calorific value of the fuel in kJ/Kg i.e. = [ma (h-hf )]/C Where, ma = Mass of water actually evaporated into steam per Kg of fuel at the working pressure h = Enthalpy of steam per Kg under the generating conditions hf = Specific enthalpy of water at a given feed temperature C = Calorific value of the fuel in kJ/Kg The boiler efficiency depends on following factors: 1) Fixed factors 2) Variable factor The Fixed factors are: 1) Boiler design: It includes the arrangement & effectiveness of the heating surfaces, the shape & volume of the furnace, the arrangement of flues, the arrangement of steam & water circulation. 2) Heat recovery equipment: It includes the economizer, superheater, air preheater & feed water heater. 3) Built in losses: It includes the heat transfer properties of the settings & construction materials, flue gas & ash heat losses. 4) Rated rate of firing, the furnace volume & heating surface. 5) Properties & characteristics of fuel burnt. The variable factors are 1) 2) 3) 4) 5) 6) 7) Actual firing rate Fuel condition as it is fired The condition of heat absorbing surfaces Excess air fluctuations Incomplete combustion & combustibles in the refuse Charge in draught from the rated due to atmospheric conditions Humidity & temperature of the combustion air The performance parameters of boiler, like efficiency and evaporation ratio reduces with time due to poor combustion, heat transfer surface fouling and poor operation and maintenance. Even for a new boiler, reasons such as deteriorating fuel quality, water quality etc. can result in poor boiler performance. Boiler efficiency tests help us to find out the deviation of boiler efficiency from the best efficiency and target problem area for corrective action. Boiler efficiency, in the simplest terms, represents the difference between the energy input and energy output. Boiler Efficiency related to the boilers energy output to the boilers energy input . Boiler Efficiency may be indicated by • Combustion Efficiency - indicates the burners ability to burn fuel measured by unburned fuel and excess air in the exhaust • Thermal Efficiency - indicates the heat exchangers effectiveness to transfer heat from the combustion process to the water or steam in the boiler, exclusive radiation and convection losses • Fuel to Fluid Efficiency - indicates the overall efficiency of the boiler inclusive thermal efficiency of the heat exchanger, radiation and convection losses - output divided by input. This image shows a typical boiler energy balance for a boiler in good running condition with no energy efficiency measures added. By first identifying the areas of energy loss and roughly quantifying it, it is easier to estimate the overall savings potential by taking efficiency action in that area. High boiler efficiency is the result of specific design criteria which directly effects the fixed factor for boiler efficiency, including: • Number of boiler passes ( Normally we have two pass boiler) • Burner / boiler compatibility • Repeatable air/fuel control • Heating surface • Pressure vessel design Boiler efficiency calculations that are accurate and representative of actual boiler fuel usage require the use of proven and verified data, including: • Proven stack temperature • • • • Accurate fuel specification Actual operating excess air levels Proper ambient air temperature Proper radiation & convection losses Boiler Efficiency Thermal efficiency of boiler is defined as the percentage of heat input that is effectively utilized to generate steam. There are two methods of assessing boiler efficiency. 1) The Direct Method: Where the energy gain of the working fluid (water and steam) is compared with the energy content of the boiler fuel. 2) The Indirect Method: Where the efficiency is the difference between the losses and the Energy input. 1. The Direct Method of testing: This is also known as ‘input-output method’ due to the fact that it needs only the useful output (steam) and the heat input (i.e. fuel) for evaluating the efficiency. This efficiency can be evaluated using the formula Boiler efficiency= Merits and Demerits of Direct Method Merits • Plant people can evaluate quickly the efficiency of boilers • Requires few parameters for computation • Needs few instruments for monitoring Demerits • • Does not give clues to the operator as to why efficiency of system is lower Does not calculate various losses accountable for various efficiency levels Type of boiler: Coal fired Boiler Heat output data Quantity of steam generated (output) Steam pressure / temperature Enthalpy of steam (dry & Saturated) at 10 kg/cm2(g) pressure Feed water temperature Enthalpy of feed water Heat input data Quantity of coal consumed (Input) GCV of coal : 8 TPH : 10 kg/cm2 (g)/ 180 0C : 665 kCal/kg : 85 C : 85 kCal/kg : 1.6 TPH : 4000 kCal/kg 0 Boiler efficiency = = 72.5% 1 The Indirect Method of testing: Indirect method is also called as heat loss method. The efficiency can be arrived at, by subtracting the heat loss fractions from 100. The standards do not include blow down loss in the efficiency determination process. Here the efficiency is the difference between the losses and the energy input. The efficiency can be arrived at, by subtracting the heat loss fractions from 100. An important advantage: In this method the errors in measurement do not make significant change in efficiency. Thus if boiler efficiency is 90%, an error of 1% in direct method will result in significant change in efficiency. i.e.90 + 0.9 = 89.1 to 90.9. In indirect method, 1% error in measurement of losses will result in Efficiency = 100 – (10 + 0.1) = 90 + 0.1 = 89.9 to 90.1 The Various heat losses occurring in the boiler are: Measurements Required for Performance Assessment Testing The following parameters need to be measured, as applicable for the computation of boiler efficiency and performance. a) Flue gas analysis 1. Percentage of CO2 or O2 in flue gas 2. Percentage of CO in flue gas ( also given by oxygen indicator) 3. Temperature of flue gas b) Flow meter measurements for 1. Fuel 2. Steam 3. Feed water 4. Condensate water 5. Combustion air c) Temperature measurements for 1. Flue gas 2. Steam 3. Makeup water 4. Condensate return 5. Combustion air 6. Fuel 7. Boiler feed water d) Pressure measurements for 1. Steam 2. Fuel 3. Combustion air, both primary and secondary 4. Draft e) Water Condition 1. Total dissolved solids (TDS) 2. pH 3. Blow down rate and quantity 1 The following losses are applicable to liquid, gas and solid fired boiler 1. L1- Loss due to dry flue gas (sensible heat) This is the greatest boiler loss and can be calculated with the following formula: 2. L2- Loss due to hydrogen in fuel (H2) The combustion of hydrogen causes a heat loss because the product of combustion is water. This water is converted to steam and this carries away heat in the form of its latent heat. Where, H2 - kg of H2 in 1 kg of fuel Cp - Specific heat of superheated steam (0.45 kCal/kg °C) 3. L3- Loss due to moisture in fuel (H2 O) Moisture entering the boiler with the fuel leaves as a superheated vapour. This moisture loss is made up of the sensible heat to bring the moisture to boiling point, the latent heat of evaporation of the moisture, and the superheat required to bring this steam to the temperature of the exhaust gas. This loss can be calculated with the following formula Where, M – kg of moisture in 1kg of fuel Cp – Specific heat of superheated steam (0.45 kCal/kg)°C 584 is the latent heat corresponding to the partial pressure of water vapour. 4. L4- Loss due to moisture in air (H2 O) Vapour in the form of humidity in the incoming air, is superheated as it passes through the boiler. Since this heat passes up the stack, it must be included as a boiler loss. AAS- Actual mass of air supplied/kg of fuel. 5. L5- Heat loss due to incomplete combustion Products formed by incomplete combustion could be mixed with oxygen and burned again with a further release of energy. Such products include CO, H2, and various hydrocarbons and are generally found in the flue gas of the boilers. Carbon monoxide is the only gas whose concentration can be determined conveniently in a boiler plant test. L6- Heat loss due to radiation and convection The other heat losses from a boiler consist of the loss of heat by radiation and convection from the boiler casting into the surrounding boiler house. Normally surface loss and other unaccounted losses is assumed based on the type and size of the boiler as given below For industrial fire tube / packaged boiler = 1.5 to 2.5% For industrial water tube boiler = 2 to 3% For power station boiler = 0.4 to 1% Radiation and unaccountable loss An empirical formula for determining this loss is Log10B = 0.8167 – 0.4238 log10C Where, B= radiation and unaccounted loss C= specific boiler capacity in kg/s. Total radiation and unaccounted loss = 1.5B + 0.5 6. 7. L7- Heat loss due to unburned carbon in fly ash and bottom ash Heat loss due to unburnt in fly ash (%) 8. L8- Heat loss due to unburnt in bottom ash (%) Boiler Efficiency by indirect method =100 –(L1+L2+L3+L4+L5+L6+L7+L8) Example: Efficiency Calculation for Coal Fired Boiler The following are the data collected for a boiler using coal as the fuel. Find the boiler efficiency by indirect method. Fuel firing rate = 5599.17 kg/hr Steam generation rate = 21937.5 kg/hr Steam pressure = 43 kg/cm2(g) Steam temperature = 377 oC o Feed water temperature = 96 C %CO2 in Flue gas = 14 %CO in flue gas = 0.55 Average flue gas temperature = 190 oC Ambient temperature = 31 oC Humidity in ambient air = 0.0204 kg / kg dry air Surface temperature of boiler = 70 oC Wind velocity around the boiler = 3.5 m/s Total surface area of boiler = 90 m2 GCV of Bottom ash = 800 kCal/kg GCV of fly ash = 452.5 kCal/kg Ratio of bottom ash to fly ash = 90:10 Fuel Analysis (in %) Ash content in fuel Moisture in coal Carbon content Hydrogen content Nitrogen content Oxygen content GCV of Coal SOLUTION = 8.63 = 31.6 = 41.65 = 2.0413 = 1.6 = 14.48 = 3501 kCal/k Boiler efficiency by indirect method Step – 1 requirement Find theoretical air = Theoretical air required for complete combustion = kg/kg of coal [(11.6 x 41.65) + {34.8 x (2.0413 – 14.48/8)} +(4.35 x 0)] / 100 = Step – 2 Find theoretical CO2% % CO2at theoretical condition ( CO2)t Where, Moles of N2 = 4.91 kg / kg of coal = Moles of N2 = 77% of nitrogen in air Where moles of C ( CO2)t ( CO2)t = = = 0.4165/12 = 0.0347 20.37% Step – 3 To find Excess air supplied Actual CO2 measured in flue gas = 14.0% % Excess air supplied (EA) = = = 45.17 % Step – 4 To find actual mass of air supplied Actual mass of air supplied = {1 + EA/100} x theoretical air = = {1 + 45.17/100} x 4.91 7.13 kg/kg of coal Step –5 To find actual mass of dry flue gas Mass of = Mass of CO2 +Mass of N2content in the fuel+ Mass of N2 in the dry flue supplied + Mass of oxygen in flue gas gas Mass of = dry flue gas = 7.54 kg / kg of coal Step – 6 To find all losses 1. % Heat loss in dry flue gas (L1) = = L1 = 7.88 % combustion air 2. % Heat loss due to formation of water from H2in = fuel (L2) = L2 = 3.44 % 3. % Heat loss due to moisture in fuel (L3) = L3 = = 5.91 % 4. % Heat loss due to moisture in air (L4) = = L4 = 0.29 % 5. % Heat loss due to partial conversion of C to CO (L5) = L5 6. Heat loss due to radiation and convection (L6) = = = = Total radiation and convection loss per hour % radiation and convection loss L6 7. % Heat loss due to unburnt in fly ash % Ash in coal Ratio of bottom ash to fly ash GCV of fly ash Amount of fly ash in 1 kg of coal = Heat loss in fly ash = % heat loss in fly ash L7 8. % Heat loss due to unburnt in bottom ash GCV of bottom ash Amount of bottom ash in 1 kg of coal = = = = = = 2.58 % 0.548 x [ (343/55.55)4– (304/55.55)4] + 1.957 x(343 304)1.25x sq.rt of [(196.85 x 3.5 + 68.9) /68.9] 633.3 w/m2 633.3 x 0.86 544.64 kCal / m2 544.64 x 90 49017.6 kCal 49017.6 x 100 3501 x 5599.17 0.25 % = = = = = = = 8.63 90:10 452.5 kCal/kg 0.1 x 0.0863 0.00863 x 452.5 3.905 x 100 / 3501 0.11 % 0.00863 kg 3.905 kCal / kg of coal = = = = = = = = 800 kCal/kg 0.9 x 0.0863 0.077 kg 0.077 x 800 62.136 kCal/kg of coal 62.136 x 100 / 3501 1.77 % 100 – (L1+ L2+ L3+ L4+ L5+ L6+ L7+ L8) =100–(7.88+3.44+5.91+0.29+ 2.58+ 0.25+ 0.11+1.77) Heat loss in bottom ash % Heat loss in bottom ash L8 Boiler efficiency by indirect method =100-22.23 =77.77 % Input/Output Parameter kCal / kg of coal % loss 100 7.88 3.44 5.91 0.29 2.58 0.25 0.11 1.77 Heat Input = 3501 Losses in boiler 1. Dry flue gas, L1 = 275.88 2. Loss due to hydrogen in fuel, L2 = 120.43 3. Loss due to moisture in fuel, L3 = 206.91 4. Loss due to moisture in air, L4 = 10.15 5. Partial combustion of C to CO, L5 = 90.32 6. Surface heat losses, L6 = 8.75 7. Loss due to Unburnt in fly ash, L7 = 3.85 8. Loss due to Unburnt in bottom ash, L8 = 61.97 Boiler Efficiency= 100 – (L1+ L2+ L3+ L4+ L5+ L6+ L7+ L8) = 77.77 % Since, the optimum efficiency of boilers occurs at 65–85% of full load, it is usually more efficient, on the whole, to operate a fewer number of boilers at higher loads, than to operate a large number at low loads. Boiler Replacement The potential savings from replacing a boiler depend on the anticipated change in overall efficiency. A change in a boiler can be financially attractive if the existing boiler is : • Old and inefficient • Not capable of firing cheaper substitution fuel • Over or under-sized for present requirements • Not designed for ideal loading conditions The feasibility study should examine all implications of long-term fuel availability and company growth plans. All financial and engineering factors should be considered. Since boiler plants traditionally have a useful life of well over 25 years, replacement must be carefully studied. The discussion on Boiler efficiency would not be over without discussing about the Technical standards for construction of electric plants and lines, Regulations 2010, issued by CEA. According to theses regulations the efficiency of the steam generator (on high heat value basis) in %, as guaranteed by the manufacturer shall be not less than the value as arrived with the following formulae for the quality of performance of coal and lignite: Minimum steam generator efficiency (%) = 92.5 – ((50*A+630(M+9*H))/HHV) Where, A=% ash in fuel, M=% moisture in fuel, H=% hydro in fuel and; HHV= High heat value of fuel in Kcal/Kg. STATION HEAT RATE According to “Terms and Conditions of Tariff Regulations 2009-14”, the station heat rate is specified as follows Existing Thermal Generating Station 200/210/250 MW Sets 500 MW Sets (Sub-critical) 2500 KCal/kWh 2425 kCal/kWh In respect of 500 MW and above units where the boiler feed pumps are electrically operated, the gross station heat rate shall be 40 kCal/kWh lower than the gross station heat rate specified above New Thermal Generating Station achieving COD on or after 1.4.2009 (a) Coal-based and lignite-fired Thermal Generating Stations = 1.065 X Design Heat Rate (kCal/kWh) Design Heat Rate of a unit means the unit heat rate guaranteed by the supplier at conditions of 100% MCR, zero percent make up, design coal and design cooling water temperature/back pressure. Provided that the design heat rate shall not exceed the following maximum design unit heat rates depending upon the pressure and temperature ratings of the units: Provided further that in case pressure and temperature parameters of a unit are different from above ratings, the maximum design unit heat rate of the nearest class shall be taken Provided also that where unit heat rate has not been guaranteed but turbine cycle heat rate and boiler efficiency are guaranteed separately by the same supplier or different suppliers, the unit design heat rate shall be arrived at by using guaranteed turbine cycle heat rate and boiler efficiency. Provided also that if one or more units were declared under commercial operation prior to 1.4.2009, the heat rate norms for those units as well as units declared under commercial operation on or after 1.4.2009 shall be lower of the heat rate norms arrived at by above methodology and the norms as per the regulation 26 (ii) A (a) of existing thermal power plants. TURBINE EFFICIENCY The Carnot cycle The Carnot cycle when acting as a heat engine consists of the following steps: 1. Reversible isothermal expansion of the gas at the "hot" temperature, TH (isothermal heat addition). During this step (A to B on Figure) the expanding gas causes the piston to do work on the surroundings. The gas expansion is propelled by absorption of quantity Q1 of heat from the high temperature reservoir. 2. Isentropic (Reverrsible adiabatic) expansion of the gas. For this step (B to C on Figure) we assume the piston and cylinder are thermally insulated, so that no heat is gained or lost. The gas continues to expand, doing work on the surroundings. The gas expansion causes it to cool to the "cold" temperature, TC. 3. Reversible isothermal compression of the gas at the "cold" temperature, TC. (isothermal heat rejection) (C to D on Figure) Now the surroundings do work on the gas, causing quantity Q2 of heat to flow out of the gas to the low temperature reservoir. 4. Isentropic compression of the gas. (D to A on Figure) Once again we assume the piston and cylinder are thermally insulated. During this step, the surroundings do work on the gas, compressing it and causing the temperature to rise to TH. At this point the gas is in the same state as at the start of step 1. Rankine cycle Processes of the Rankine cycle There are four processes in the Rankine cycle, each changing the state of the working fluid. These states are identified by number in the diagram to the right. • Process 1-2: The working fluid is pumped from low to high pressure, as the fluid is a liquid at this stage the pump requires little input energy. • Process 2-3: The high pressure liquid enters a boiler where it is heated at constant pressure by an external heat source to become a dry saturated vapor. • Process 3-4: The dry saturated vapor expands through a turbine, generating power. This decreases the temperature and pressure of the vapor, and some condensation may occur. • Process 4-1: The wet vapor then enters a condenser where it is condensed at a constant pressure and temperature to become a saturated liquid. The pressure and temperature of the condenser is fixed by the temperature of the cooling coils as the fluid is undergoing a phase-change. Variables Heat flow rate to or from the system (energy per unit time) Mass flow rate (mass per unit time) Mechanical power consumed by or provided to the system (energy per unit time) Thermodynamic efficiency of the process (net power output per heat input, dimensionless) Isentropic efficiency of the compression (feed pump) and expansion (turbine) processes, dimensionless The "specific enthalpies" at indicated points on the T-S diagram The final "specific enthalpy" of the fluid if the turbine were isentropic The pressures before and after the compression process ηtherm ηpump,ηturb h1,h2,h3,h4 h4s p1,p2 Equations Rankine cycle with reheat In this variation, two turbines work in series. The first accepts vapor from the boiler at high pressure. After the vapor has passed through the first turbine, it re-enters the boiler and is reheated before passing through a second, lower pressure turbine. Among other advantages, this prevents the vapor from condensing during its expansion which can seriously damage the turbine blades, and improves the efficiency of the cycle. The Rankine Cycle with Rengeration Improving cycle efficiencies Improving cycle efficiency almost always involves making a cycle more like a Carnot cycle operating between the same high and low temperature limits. The Carnot cycle is maximally efficient, in part, because it receives all of its heat addition at the same temperature, which is the highest temperature in the cycle. Similarly, it rejects all of its heat at the same low temperature. The T-s diagram below details the working of a Carnot cycle operating between the same temperature limits as our Rankine cycle. How regeneration works Figure 4: a Rankine cycle with regeneration Choosing regeneration assumptions With the design layout complete, we turn to adding the assumptions which allow CyclePad to solve the cycle. For this example, there are four places where we have to make new assumptions: the outlet of the high-pressure turbine (S2), the splitter (SPL1), the outlet of the low-pressure pump (PMP2), and the inlet of the high-pressure pump (PMP1). We will look at each of these in turn. The High-Pressure Turbine Outlet (S2) What pressure do we choose for the extracted feedwater? We don't know yet, so we'll choose 200 kPa, which gives the two turbines pressure ratios of 25 and 20. This makes them roughly equal and keeps either one from having an astronomically high pressure ratio. (The original Rankine cycle had a turbine PR equal to 500!) Later, when we have the cycle solved and we can let CyclePad do sensitivity analyses, we will see if another pressure works better. The Splitter (SPL1) The splitter is used to draw some of the working fluid from the high-pressure turbine stage and direct it towards the mixer. This means that the stuff exiting the splitter is the same as the stuff entering it. Quick Note This simulates situations when we use a special splitter that allows us to separate the saturated mixture into two streams that each have different proportions of liquid and vapor. For instance, we could split 1 kg/sec, 60% quality stream into a pair of 0.4 kg/sec, 0% quality and a 0.6 kg/sec, 100% quality streams. This allows each stream to have different specific properties (v, h, and so on), though they still have the same temperature and pressure. The Low-pressure Pump Outlet (S5) What pressure should the water at this state have? This water, which enters the pump at the cooler pressure, needs to be pumped up to the pressure of the water extracted from the high-pressure turbine. This is a matter of simple hydrostatics: if we make it lower, the higher pressure extract water will flow backward through the low-pressure pump and, if we make it higher, the low pressure pump water will flow backward through the splitter. The High-Pressure Pump Inlet (S6) Our whole purpose in adding heat to this water is to raise its temperature before it enters the heater and improve the cycle efficiency. The water exiting the low-pressure pump is only at 46 C and the water entering the heater in the original Rankine cycle was at about the same temperature (adding pressure to an incompressible fluid doesn't raise its temperature much). How high can we heat the water to improve this? Brayton cycle Brayton-type engine consists of three components: • A gas compressor • A mixing chamber • An expander In the original 19th-century Brayton engine, ambient air is drawn into a piston compressor, where it is compressed; ideally an isentropic process. The compressed air then runs through a mixing chamber where fuel is added, a constant-pressure isobaric process. The heated (by compression), pressurized air and fuel mixture is then ignited in an expansion cylinder and energy is released, causing the heated air and combustion products to expand through a piston/cylinder; another theoretically isentropic process. Some of the work extracted by the piston/cylinder is used to drive the compressor through a crankshaft arrangement. The term Brayton cycle has more recently been given to the gas turbine engine. This also has three components: • A gas compressor • A burner (or combustion chamber) • An expansion turbine Ideal Brayton cycle: • isentropic process - Ambient air is drawn into the compressor, where it is pressurized. • isobaric process - The compressed air then runs through a combustion chamber, where fuel is burned, heating that air—a constant-pressure process, since the chamber is open to flow in and out. • isentropic process - The heated, pressurized air then gives up its energy, expanding through a turbine (or series of turbines). Some of the work extracted by the turbine is used to drive the compressor. • isobaric process - Heat Rejection (in the atmosphere). Actual Brayton cycle: • adiabatic process - Compression. • isobaric process - Heat Addition. • adiabatic process - Expansion. • isobaric process - Heat Rejection. Since neither the compression nor the expansion can be truly isentropic, losses through the compressor and the expander represent sources of inescapable working inefficiencies. In general, increasing the compression ratio is the most direct way to increase the overall power output of a Brayton system Here are two plots, Figure 1 and Figure 2, for the ideal Brayton cycle. One plot indicates how the cycle efficiency changes with an increase in pressure ratio, while the other indicates how the specific power output changes with an increase in the gas turbine inlet temperature for two different pressure ratio values. Figure 1: Brayton cycle efficiency Figure 2: Brayton cycle specific power output Methods to increase power The power output of a Brayton engine can be improved in the following manners: • Reheat, wherein the working fluid—in most cases air—expands through a series of turbines, then is passed through a second combustion chamber before expanding to ambient pressure through a final set of turbines. This has the advantage of increasing the power output possible for a given compression ratio without exceeding any metallurgical constraints (typically about 1000°C). • Intercooling, wherein the working fluid passes through a first stage of compressors, then a cooler, then a second stage of compressors before entering the combustion chamber. While this requires an increase in the fuel consumption of the combustion chamber, this allows for a reduction in the specific volume of the fluid entering the second stage of compressors, with an attendant decrease in the amount of work needed for the compression stage overall.. • Regeneration, wherein the still-warm post-turbine fluid is passed through a heat exchanger to preheat the fluid just entering the combustion chamber. This directly offsets fuel consumption for the same operating conditions improving efficiency. It allows also results in less power lost as waste heat. • A Brayton engine also forms half of the combined cycle system, which combines with a Rankine engine to further increase overall efficiency. • Cogeneration systems make use of the waste heat from Brayton engines, typically for hot water production or space heating. Reverse Brayton cycle A Brayton cycle that is driven in reverse, via net work input, and when air is the working fluid, is the air refrigeration cycle or Bell Coleman cycle. Its purpose is to move heat, rather than produce work. This air cooling technique is used widely in jet aircraft. The Otto cycle The Otto Cycle consists of adiabatic compression, heat addition at constant volume, adiabatic expansion and rejection of heat at constant volume, characterized by four strokes, or reciprocating movements of a piston in a cylinder: intake (induction) stroke 2. compression stroke 3. power stroke 4. exhaust stroke The cycle begins at top dead center (TDC), when the piston is furthest away from the axis of the crankrshaft. On the intake or induction stroke of the piston, the piston descends from the top of the cylinder, reducing the pressure inside the cylinder. A mixture of fuel and air is forced (by atmospheric or greater pressure) into the cylinder through the intake (inlet) port. The intake (inlet) valve (or valves) then close(s), and the compression stroke compresses the fuel–air mixture. The air–fuel mixture is then ignited near the end of the compression stroke, usually by a spark plug (for a gasoline or Otto cycle engine) or by the heat and pressure of compression (for a Diesel cycle or compression ignition engine). The resulting pressure of burning gases pushes the piston through the power stroke. In the exhaust stroke, the piston pushes the products of combustion from the cylinder through an exhaust valve or valves. 1. Diesel cycle The Ideal Diesel Cycle P-v Diagram for the Ideal Diesel cycle. The cycle follows the numbers 1-4 in clockwise direction. The image on the left shows a P-v diagram for the ideal diesel cycle; where P is pressure and v is specific volume. The ideal diesel cycle follows the following four distinct processes (The color references refer to the color of the line on the diagram.): • Process 1 to 2 is isentropic compression (blue) • Process 2 to 3 is reversible constant pressure heating (red) • Process 3 to 4 is isentropic expansion (yellow) • Process 4 to 1 is reversible constant volume cooling (green) The diesel is a heat engine: it converts heat into work. Work in (Win) is done by the piston compressing the working fluid Heat in (Qin) is done by the combustion of the fuel Work out (Wout) is done by the working fluid expanding on to the piston, this produces usable torque • Heat out (Qout) is done by venting the air Maximum thermal efficiency The maximum thermal efficiency of a diesel cycle is dependent on the compression ratio and the cut-off ratio. It has the following formula: • • • Where ηth is thermal efficiency α is the cut-off ratio (ratio between the end and start volume for the combustion phase) r is the compression ratio γ is ratio of specific heats (Cp/Cv) The cut-off ration can be expressed in terms of temperature as shown below: T2 = T1rγ − 1 T3 can be approximated to the flame temperature of the fuel used. The flame temperature can be approximated to the adiabatic flame temperature of the fuel with corresponding air-to-fuel ratio and compression pressure, P3. T1 can be approximated to the inlet air temperature. This formula only gives the ideal thermal efficiency. The actual thermal efficiency will be significantly lower due to heat and friction losses. The formula is more complex than the Otto cycle (petrol/gasoline engine) relation that has the following formula; The additional complexity for the diesel formula comes around since the heat addition is at constant pressure and the heat rejection is at constant volume. The Otto cycle by comparison has both the heat addition and rejection at constant volume. Thermodynamic cycle A thermodynamic cycle is a series of thermodynamic processes which returns a system to its initial state. Properties depend only on the thermodynamic state and thus do not change over a cycle. Variables such as heat and work are not zero over a cycle, but rather are process dependent. The first law of thermodynamics dictates that the net heat input is equal to the net work output over any cycle. The repeating nature of the process path allows for continuous operation, making the cycle an important concept in thermodynamics. Thermodynamic cycles often use quasi static processes to model the workings of actual devices. Example of P-V diagram of a thermodynamic cycle. The area enclosed by the loop is the work (W) done by the process: . This work is equal to the balance of heat (Q) transferred into the system: . Equation (2) makes a cyclic process similar to an isothermal process: even though the internal energy changes during the course of the cyclic process, when the cyclic process finishes the system's energy is the same as the energy it had when the process began. Thermodynamic power cycles Heat engine diagram. Heat engine Thermodynamic power cycles are the basis for the operation of heat engines, which supply most of the world's electric power and run almost all motor vehicles. Power cycles can be divided according to the type of heat engine they seek to model. The most common cycles that model internal combustion engines are the Otto cycle, which models gasoline engines and the Diesel cycle, which models diesel engines. Cycles that model external combustion engines include the Brayton cycle, which models gas turbines, and the Rankine cycle, which models steam turbines. The clockwise thermodynamic cycle indicated by the arrows shows that the cycle represents a heat engine. The cycle consists of four states (the point shown by crosses) and four thermodynamic processes (lines). For example the pressure-volume mechanical work done in the heat engine cycle, consisting of 4 thermodynamic processes, is: If no volume change happens in process 4->1 and 2->3, equation (3) simplifies to: STEAM TURBINE Steam are a major energy consumer. Optimizing process operating conditions can considerably improve turbine water rate, which in turn will significantly reduce energy requirement. Various operating parameters affect condensing and back pressure turbine steam consumption and efficiency. There are two type of the steam turbineA) Impulse turbine-- Impulse turbines change the velocity of a steam jet. The jet impinges on the turbine's curved blades which change the direction of the flow. The resulting change in momentum (impulse) causes a force on the turbine blades. Newton's second law describes the transfer of energy for impulse turbines. B) Reaction turbine--- Reaction turbines are acted on by steam, which changes pressure as it moves through the turbine and gives up its energy. They must be encased to contain the water pressure (or suction), or they must be fully submerged in the water flow. Newton's third law describes the transfer of energy for reaction turbines. Other forms of the turbine are --a) Impulse turbine b) Velocity compounding c) Pressure compounding d) Pressure – Velocity compounding Turbine efficiency High Pressure Turbine efficiency (HPT)-80% Reason- Small blades, tip clearance 0.5 mm, Ratio of blade size to tip clearance is highest. Intermediate Pressure Turbine efficiency (IPT)-95% Reason- Big blade size, tip clearance 0.5 mm, Low tip leakage, Ratio is smallest. Low Pressure Turbine efficiency-85% Reason- Very big blades, tip clearance 4mm,Load tip leakage ratio is smaller. Effect of operating conditions on steam turbines A condensing turbine system is shown in figure below. Turbine exhaust operating below atmosphere, is condensed in a shell and tube exchanger called surface condenser. Condensate flows in the shell side of the condenser and steam is condensed by the cooling water. Vacuum in the surface condenser i.e. turbine exhaust vacuum is controlled/ maintained by vacuum ejector system of the surface condenser. Turbines are designed for a particular operating conditions like steam inlet pressure, steam inlet temperature and turbine exhaust pressure/ exhaust vacuum, which affects the performance of the turbines in a significant way. Variations in these parameters affects the steam consumption in the turbines and also the turbine efficiency. Theoretical turbine efficiency is calculated as workdone by the turbine to the heat supplied to generate the steam. Efforts are made to show the impact of various operating conditions by considering the following steam conditions as illustration. In the above referred turbines, 1 % reduction in steam consumption saves around $ 47000 annually for condensing turbines and around $ 84000 annually in back pressure turbine. LHV of the fuel for generating steam is considered as 10500 kcal/kg and boiler efficiency is taken as 87 %. Effect of various operating parameters is illustrated in the succeeding paragraphs. 2.1 Effect of Steam inlet pressure Steam inlet pressure of the turbine also affects the turbine performance. All the turbines are designed for a specified steam inlet pressure. For obtaining the design efficiency, steam inlet pressure shall be maintained at design level. Lowering the steam inlet pressure will hampers the turbine efficiency and steam consumption in the turbine will increase. Similarly at higher steam inlet pressure energy available to run the turbine will be high, which in turn will reduce the steam consumption in the turbine.Figure - 2a & 2b represents the effects of steam inlet pressure on steam consumption and turbine efficiency respectively, keeping all other factors constant for the condensing type turbine. Figure - 2a & 2b indicates that increase in steam inlet pressure by 1 kg/cm2 in condensing type turbine reduces the steam consumption in the turbine by about 0.3 % and improves the turbine efficiency by about 0.1 % respectively. In case of back pressure type turbine increase in steam inlet pressure by 1 kg/cm2 reduces the steam consumption in the turbine by about 0.7 % and improves the turbine efficiency by about 0.16 % as shown in figure - 3a & 3b . Improvement in back pressure type turbine is more than the condensing type turbine. Effect of Steam inlet temperature Enthalpy of steam is a function of temperature and pressure. At lower temperature, enthalpy will be low, work done by the turbine will be low, turbine efficiency will be low, hence steam consumption for the required output will be higher. In other words, at higher steam inlet temperature, heat extraction by the turbine will be higher and hence for the required output, steam consumption will reduce. Figure - 4a & 4b represents the effects of steam inlet temperature on steam consumption and turbine efficiency respectively, keeping all other factors constant for the condensing type turbine. Figure - 4a & 4b indicates that increase in steam inlet temperature by 10 deg C in condensing type turbine reduces the steam consumption in the turbine by about % and improves the turbine efficiency by about 0.12 % respectively. In case of back pressure type turbine increase in steam inlet temperature by 10 deg C reduces the steam consumption in the turbine by about 1.5 % and improves the turbine efficiency by about 0.12 % as shown in figure - 6a &6b. Improvement in back pressure type turbine is more than the condensing type turbine. Effect of exhaust pressure/ vacuum Higher exhaust pressure/ lower vacuum, increases the steam consumption in the turbine, keeping all other operating parameters constant. Exhaust pressure lower than the specified will reduce the steam consumption and improves the turbine efficiency. Similarly exhaust vacuum lower than the specified, will lower the turbine efficiency and reduces the steam consumption. Figure 6a & 6b represents the effects of exhaust vacuum on steam consumption and turbine efficiency respectively, keeping all other factors constant for the condensing type turbine. Figure 6a & 6b indicates that improvement in exhaust vacuum by 10 mm Hg, reduces the steam consumption in the turbine by about 1.1 %. Improvement in turbine efficiency varies significantly from 0.24 % to 0.4 %. In case of back pressure type turbine reduction in exhaust pressure by 1.0 kg/cm2, reduces the steam consumption in the turbine by about 0.8 % and improves the turbine efficiency by about 0.14 % as shown by figure - 7a & 7b. The leaving velocity is proportional to the specific volume, the specific volume increases rapidly with improvement in vacuum. The gain in available energy due to higher vacuum is partly offset by the increase in specific volume hence of exhaust losses. The turbine manufacturer’s curves should give some indication. In our country, the turning point is well below the reach even with coldest CW water in winter. The terminal temperature difference (TTD) which is defined as the temperature difference between steam and saturation to outgoing to CW water is intact a measure of its log mean temperature differential (LMTD).A high value of TTD is an indication of contamination of CW side of the tubes by lime and dirt and also that of air ingress in steam space. Under cooling of the condensate is due to air leakage only, therefore this temperature differential is also of important .Because of partial pressure of the air at the bottom of the condenser, the condensate temperature lies lowered below that corresponding to the total pressures since it is corresponding the partial pressure of the steam only. Main thing to realize is that when there is ingress, the heat transfer coefficient become poor, therefore temperature differential increases by way of increase in condensing temperature in order to get heat across air barrier. This makes the vacuum worst. Factors affecting the exhaust vacuum in the condensing type turbines · Vacuum ejector system Vacuum ejector system creates and maintains the vacuum in the surface condenser by removing the air/ inerts ingress. Removal of air/ inerts ingress is important, as accumulation of this hampers the performance of surface condenser, which reduces the surface condenser vacuum. Motive steam condition shall be maintained as specified. Inter-after condenser shall be cleaned in the available opportunity, as they get choked due to foreign material coming with cooling water. · Flange joints shall be tightened properly to avoid any ingress of air. · Exhaust side of the turbine shall be properly steam sealed to avoid any ingress of air. · Higher size of exhaust pipe In many condensing turbines it is observed that the exhaust vacuum of these turbines is much less than the vacuum at the condenser. Mainly, it is due to the higher pressure drop in the exhaust pipeline from turbine exhaust to the condenser. In order to improve the vacuum at turbine exhaust so as to reduce steam consumption in the turbine, exhaust pipeline of these turbines can be replaced with higher size. In one of the turbine, exhaust line size of 900 mm was replaced with 1300 mm. The pressure drop in the exhaust pipe reduced by 50 mm Hg i.e. vacuum at the turbine exhaust improved by 50 mm Hg. Pay back period of replacing the exhaust pipeline was 6 months with investment of $ 40000. TURBINE LOSS Internal loss Nozzle friction loss- Due to this loss the head of the pressure drop it mean that there is loss in the pressure. b) Blade friction loss- Due to friction there is the loss of the pressure in the each blade this loss decrease the pressure of the steam turbine. c) Disc friction loss – d) Diaphragm glad and blade tip leakage- Pressure compounding turbine there is a pressure drop across each fixed nozzle that is across diaphragm so the gap between the diaphragm and shaft is source of the steam leakage. It can be minimize when we put inter stage glands between shaft and glands between shaft and diaphragm. There is also balancing hole in disc to equalize the pressure on the both side. e) Partial admission loss- To improve the load bearing capacity the steam is to inter at the three or four stage. Due to this the there is loss in the steam head. This loss is called as the Partial admission loss. f) Exhaust loss - At the exhaust of the turbine the steam loss its pressure and there is loss of the velocity of the steam. Let assume that at the exhaust hood the steam having the velocity = V Exhaust loss = 0.5 X (M V2) g) Wetness – At the exhaust of the turbine, steam condensate into the water and due to the water’s weight there is the loss of the velocity of the turbine shaft. External loss a) a) Shaft gland leakage- In the turbine there is arrangement that steam should not go out of the turbine and air should not enter in the bearing oil of the turbine so there is system called gland which used to protect the turbine from the above problem. But due to leakage in the balancing disc there is loss of the pressure in the high pressure side. b) Journal and thrust bearing- In the bearing there is loss due to the friction of the shaft and the bibet material. Due to the friction the heat is generated and the heat is taken away by the cooling oil. c) Governing and oil pump – For the operating of the governing there is requirement control oil and the function of the control oil is to control the operation of the system properly such that the turbine should having continuous supply of the load. FACTOR AFFECTING THE OPERATING EFFICIENCY OF THE TURBINE a) b) c) d) Nozzle governing Throttle governing Overload governing Effect of the vacuum e) Effect of mean steam and reheat temperature. f) Condenser losses 1 .Losses due to high cooling water temperature Cooling towers when installed are performing satisfactory, this loss must be accepted to some extent. It is possible, of course to minimize the loss by having abnormal quantity of cooling water flowing through the condenser, this give smaller cooling water, temperature rise across the condenser than optimum. 2. Loss due to incorrect cooling water quantity This is a loss which can normally be eliminated. If the cooling water temperature rise across the condenser is less than optimum, then he opening of the condenser cooling water outlet valve should be reduced. This condition may also be shown u when the condensate temperature is lower that the saturated steam temperature. 3. Loss due to air ingress This loss can be eliminated and steps should be taken to locate and stop any air ingress into the system under the vacuum as soon as the condition occurs. Excessive air in the condenser may lead to an increased reading on the condensate oxygen meter. The thermal resistively of a layer of air 0.254mm thick is approximately the same as that offered by a slab o copper 3.35 meters thick. 4. Loss due to dirty tubes Operationally, little can be done to eliminate the cause of this loss, as the tubes must normally be cleaned when the unit is of f load. However soon as loss due to dirty tubes is determined it should be ascertained that the chlorine injection to the affected condensed is satisfactory. It may be that the station chemist will wish to have the dosage increased, so he should always be informed. The effect of this loss on vacuum can be minimized by increasing the flow of cooling water through the condenser. GAS TURBINES In a gas turbine, the working medium for transforming thermal energy into rotating mechanical energy is the hot combustion gas, hence the term “gas turbine.” Gas turbines are also referred to as combustion turbines, or combustion gas turbines. Industry groups, users, and manufacturers use the terms interchangeably. Gas turbine generators are self-contained packaged power plants. Air compression, fuel delivery, combustion, expansion of combustion gas through a turbine, and electricity generation are all accomplished in a compact combination of equipment, usually provided by a single supplier under a single contract. In contrast to steam turbine-generators, which are designed for a particular application, the manufacturers of gas turbines have a defined product, allowing for substantial standardization and assembly line manufacturing. The modular concept of the package power plants made gas turbines relatively quick and easy to install. Standardization and modularization combine to provide product benefits of relatively low capital cost and fast installation of power generation capacity. The benefits of low capital cost and fast installation were initially offset by higher operating costs when compared to other installed capacity. Therefore, early utility applications of gas turbine generators were strictly for peak load operation for a few hundred hours per year. Improvement in efficiency and reliability and application of combined cycles have added to the economic benefits of the technology and now give gas turbine-based plants a wider range of application on electric systems. An economic screening of power plant is shown in fig1. project specific comparison will depend on fuel costs, capital costs and maintenance requirements. Gas turbine technology can be used in a variety of configurations for electric power generation. Conventional applications are simple cycle, combined cycle or cogeneration. Of the conventional applications, simple cycle operation is generally the least efficient and is used primarily for peaking power generation. Combined cycles combine the gas turbine and steam turbine cycles into more efficient power plants by utilizing the gas turbine exhaust gas heat. Cogeneration cycles use the steam generated from exhaust gas for process or heating requirements. Electric utility companies use gas turbines predominantly in simple cycle and combined cycle applications. Non-utility generator companies predominantly use combined cycles, either strictly for power generation or in conjunction with an industrial company as cogeneration power plants. Most gas turbine applications rely on natural gas or fuel oil for fuel. During the late 1980s and early 1990s the availability and economics of natural gas made gas turine-based power plants the preferred choice for the majority of new power generation additions in the United States. Fuel flexibility and efficient thermodynamic cycles have become important characteristics for gas turbine applications. Further improvements in the areas of fuel flexibility, cycle efficiency and reduced exhaust gas emissions are the primary technical challenges to advancing gas turbine technology. Gas turbine products and applications are changing rapidly. The technology continues to evolve through innovations in component cooling techniques, metallurgy improvements and cycle innovations. Future enhancements in gas turbine technology can be expected from higher firing temperatures, increased pressure ratios, improved materials, multi-staged combustion techniques and emission control capability. The gas turbine generator will continue to play an important role in meeting power generation requirements as technology advances and as the product and cycle designs respond to changes in fuel economics and allowable plant emissions. Thermodynamic fundamentals: The simple open cycle gas turbine is shown schematically in fig2. The gas turbine consists of compressor section, combustor and turbine section. As indicated in fig 2, ambient air is first compressed from state point 1 to state point 2 in the compressor section. Fuel is added and combusted in the combustor. The combustion products exit the combustor at state 3 and expand from state point 3 to state point 4 (atmosphere) in the turbine section. The expansion process produces useful shaft work. Typically, over 50% of the turbine shaft work produced is required to drive the compressor. The remaining work (Wnet) is available to drive an electric generator or for mechanical drive applications. Fu el Igniti on Work Out Compre ssor Turbine Air In Fig 2: Typical open cycle gas turbine system Flue Gases Operation of and actual gas turbine approaches that of an idealized thermodynamic cycle called the airstandard Brayton cycle. Consequently, reviewing the characteristics of the Brayton cycle provides useful insights into the operating and performance characteristics of an actual gas turbine system. Air, the working fluid of the Brayton cycle, is assumed to be an ideal gas. It is further assumed that the mass flow rate through the cycle is constant, the air is of fixed composition, and the specific heat of the air is constant. Four thermodynamic processes make up the Brayton cycle: compression, heat addition at constant pressure, expansion and heat rejection at constant pressure. The compression and expansion portions of the cycle are internally reversible and adiabatic ( isentropic) processes. Because the mass flow rate is assumed to be constant throughout the process, the direct combustion process of an actual gas turbine is conceptualized by heat exchanger that transfers heat to the working fluid from an external source. The actual inlet and exhaust processes of the gas turbine are conceptualized by a heat exchanger that rejects heat at constant pressure to the surroundings to complete the cycle. Fu el Heat Excha nger Compr essor Turbine Work Out Air In Heat Excha nger Fig 3: Air-Standard Brayton Cycle A Typical Air Standard Byayton Cycle Flue Gases Figure 3 depicts the air-standard Brayton cycle. A comparison of figs 2 and 3 highlights the major differences between an open cycle gas turbine and air-standard Brayton cycle. Figure 4 shows the generalized pressure-volume (P-v) and temperature-entropy (T-s) diagrams for the airstandard Brayton cycle. The state point numbers in fig 4 correspond to the numbers shown in fig 3. Fig 4 P-v and T-s diagrams for the Brayton cycle Actual gas turbine performance would approach that of the Brayton cycle if not for the following: • Irreversibilities that occur in the compressor and turbine; • Pressure losses that occur in the flow passages and the combustor; • Heating of the compressed air by direct combustion rather than an indirect heat exchanger, thereby increasing the mass flow rate throughout the system downstream if the combustor; • Thermal, mechanical and electrical losses. Referring to fig 3 the thermal efficiency of Brayton cycle is defined as follows: ηth= Wnet/QH=(QH-QL)/QH= 1-(QH-QL)=1-{CP(T4-T1)/CP(T3-T2)}………….1 where Wnet= useful work available, QH= heat added to the system, and QL= heat rejected from the system. Since the specific heat is assumed constant, the expression may be simplified such that thermal efficiency is solely a function of cycle temperatures, ηth=1- T1(T4/ T1-1)/ T2(T3/ T2-1) …………………..2 reffering to fig4 and noting that P3/P4=P2/P1 And also noting that, T3/T4=T2/T1 or T3/T2=T4/T1 …………………..3 …………………...4 Consequently, Eq 2 can be simplified and thermal efficiency can be written as follows: ηth=1- T1/ T2 or ηth=1- T4/T3 …………………...5 for an ideal gas undergoing isentropic compression, the compressor pressure ratio is related to the temperature ratio by, P2/ P1=( T2/T1)^k/(k-1) ………………6 Where k= ratio of specific heats for air If eq.6 is solved for T1/T2 and the results submitted into eq.5, then the resulting equation defines thermal efficiency as a function of compressor pressure ratio. ηth=1-1/( P2/ P1)^(k-1)/k ………………7 if eq.7 is evaluated for various compressor pressure ratios, it is clear that cycle efficiency increases as the pressure ratio increases. Fig 5 shows the relationship of pressure ratio to cycle thermal efficiency of the Brayton cycle assuming a ratio of specific heats for air of 1.4. Fig 5 Brayton cycle thermal efficiency versus pressure ratio at constant temperature. By inspecting the generalized T-s diagram shown in fig 6 and referring to eq.5 and eq.7 it can be seen that if turbine exhaust temperature, T4, is constant, increasing the combustion temperature and the resultant turbine inlet temperature from T3 to T3A will increase the cycle’s thermal efficiency. However,in actual gas turbines, these temperatures cannot be increased indefinitely because of temperature limitations of the materials. From this, it is quite understandable why many research and development efforts by gas turbine manufacturers continue to focus on improving hot gas path component metallurgy and cooling methods to increase the allowable turbine inlet temperatures and thereby increase cycle efficiency. Fig 6: Generalized T-s diagram As previously mentioned, increasing the pressure ratio (P2/ P1) increases the cycle efficiency. However, as pressure ratio changes, the net specific work per unit mass of working fluid also changes. Both thermal efficiency and specific work are strongly influenced by pressure ratio and turbine inlet temperature. However, the maximum net specific work and maximum thermal efficiency do not occur at the same pressure ratio. Therefore in designing gas turbines, the design pressure ratio must be a compromise between the maximum thermal efficiency and the maximum specific work. A typical performance curve for a real (non-ideal) turbine is shown in fig.7. As the compressor pressure ratio (P2/ P1) increases from 4 to 8, the specific work produced by the turbine section increases more rapidly than the specific work that the compressor consumes. The result is an increase in shaft specific work output and efficiency as pressure ratio increases. Fig 7: Typical (non-ideal) real gas turbine simple cycle performance curve-efficiency vs specific work at various pressure ratios at constant temperature. As the compressor pressure ratio increases, the temperature rise across the compressor also increases. This in turn reduces the combustor temperature rise necessary to achieve a given turbine inlet temperature. As a result, the combustor heat input decreases and cycle efficiency increases. At the point corresponding to the maximum shaft specific work output, the turbine specific work produced and the compressor specific work consumed increase at the same rate. As pressure ratio increases further (beyond the point where the shaft specific work output is a maximum), the compressor specific work consumed increases at a greater rate than the turbine specific work produced and, as a result the shaft specific work output actually decreases. However, because the combustor heat input continues to decrease, the efficiency continues to increase as pressure ratio increases. However with further increases in pressure ratio, thermal efficiency of rea gas turbines will begin to decrease. The maximum shaft specific work for the example of fig.7 occurs at a pressure ratio of 8. As the pressure ratio is increased from 8 to 16, the shaft specific work output decreases because compressor specific work consumed is increasing faster than turbine specific work output. Therefore, shaft specific work output (turbine specific work produced minus compressor specific work consumed) decreases. However because higher compressor outlet temperature occur at the higher pressure ratios, fuel consumption is reduced and overall thermal efficiency increases. After a point, the increase in compressor specific work consumed more than offsets the advantage of higher compressor outlet temperature and overall efficiency begins to decrease. In fig.7 this occurs at pressure ratios greater than 16. The actual pressure ratio at which this occurs depends on the specific gas turbine considered. The efficiencies of the compressor and turbine for an actual cycle are typically defined in relation to isentropic and non-isentropic processes. Considering the state points for isentropic and non-isentropic cycle fig.8 the compressor and turbine efficiencies are as follows: Fig 8 T-s diagram for an isentropic and non-isentropic cycle ηcomp=(h2s-h1)/(h2-h1)……………………8 where h1= enthalpy at compressor inlet h2s=enthalpy at constant entropy and compressor discharge pressure, and h2= actual enthalpy at compressor discharge pressure and ηturb=(h3-h4)/(h3-h4S)…………………….9 where h3= enthalpy at turbine inlet, h4S= enthalpy at constant entropy and turbine exit pressure and h4= actual enthalpy at turbine exit pressure. It is these process inefficiencies which cause real devices to depart from the ideal behavior described by eq.7. Performance parameters: Gas turbine generator performance is characterized by generator output and heat rate. Generator output is the electrical generation of the turbine generator and typically is measured at the generator terminals. Generator output is measured in units of kilowatts or megawatts. Heat rate is the ratio of heat consumption to generator output and usually expressed in units of British thermal units per kilowatt-hour (Btu/kWh) heat consumption represents the thermal energy consumed by the gas turbine and can be calculated as the product of the fuel mass flow rate and the heating value of the fuel. For gas turbines, the convention is to use the lower heating value. Therefore, heat rates for gas turbines are typically expressed on a lower heating value basis. In equation form, the heat rate for a combustion turbine generator is calculated as follows: Heat rate (Btu/kWh) = Heat consumption (Btu)/Generator output (kW) Or Heat rate (Btu/kWh) = fuel consumption rate (lb/h) X fuel lower heating value ( Btu)/ Generator output (kW) Heat rates are inverse form of thermal efficiency. A lower heat rate value indicates a higher thermal efficiency. Likewise, a higher heat rate value indicates a lower thermal efficiency. Other principal gas turbine performance parameters are listed below, with their English units of measure in parentheses: • Compressor inlet temperature (˚F) • Compression ratio • Turbine inlet temperature (˚F) • Exhaust temperature (˚F) • Exhaust gas flow (lb/h) • Exhaust heat (Mbtu/h) • Inlet pressure loss (in.H2O) and • Exhaust pressure loss (in.H2O) Each performance parameter is shown in fig.9 and is defined in following paragraphs: Compressor inlet temperature is dry bulb temperature of the inlet air to the compressor section. When the gas turbine is not equipped with an evaporative cooler or an inlet chiller, the compressor inlet temperature is equal to the ambient dry bulb temperature. Fig 9: Gas turbine generator performance parameters. When the gas turbine is equipped with an evaporative cooler or an inlet chiller the compressor inlet temperature is equal the outlet temperature of the cooler or chiller. The compression ratio or pressure ratio is a measure of the compressor discharge pressure to the compressor inlet pressure. Theoretically, higher compression ratios are limited by the costs associated with the additional compressor stages required to reduce the temperature of the compressed inlet air. For heavy-duty industrial gas turbines, compression ratios of 10-18 are most common. For aero-derivative gas turbines is toward higher compression ratios to achieve lower heat rates. The turbine inlet temperature sometimes referred to as the turbine firing temperature is the average temperature of the combustion gases entering the turbine section of the gas turbine. Firing temperature may be defined differently by various manufacturers. Higher turbine inlet temperature result in higher specific outputs ( kilowatts per pound of fuel ) and lower heat rates. In practice, higher turbine inlet temperatures are limited by the material properties of the turbine. In recent years, higher turbine inlet temperatures have been achieved by using ceramic and composite materials. In addition, improved turbine cooling technology has allowed increases in turbine inlet temperatures. Currently, the most advanced heavy-duty gas turbines have turbine inlet temperatures of approximately 2,350˚F, an increase of about 350˚F over the preceding generation of heavy-duty gas turbines. The exhaust temperatures is the average gas temperature leaving the turbine. For a given turbine inlet temperature, a lower exhaust temperature indicates higher thermal efficiency and higher specific output. Aero-derivative units generally have exhaust temperatures in the range of 800 to 950˚F and are therefore more efficient in simple cycle. By contrast, current heavy-duty units generally have exhaust temperatures of 950 to 1100˚F. Exhaust temperature is significant for heavy heat recovery applications where an HRSG generates steam from gas turbine exhaust gases. The maximum temperature and pressure of steam generated in an HRSG are limited by the gas turbine exhaust temperature (assuming that the HRSG is not supplmentally fired). Higher exhaust temperatures allow higher steam temperatures and pressure results in significantly lower combined cycle heat rates. Because of this effect, heavy-duty gas turbines are more commonly used in combined cycle units. Exhaust gas flow is the mass flow rate of exhaust gases from the turbine. Since leakages are minimal and bleed air flow is ultimately redirected into the main turbine flow, the exhaust gas flow is essentially equal to the sum of the inlet air mass flow, the fuel mass flow and any water/steam injection. The mass flow rate of steam that can be generated in an HRSG is directly proportional to the gas turbine exhaust gas flow. Exhaust heat is a measure of the thermal energy contained in the exhaust gas flow. Exhaust heat is the product of the exhaust gas flow and the exhaust gas enthalpy. Exhaust heat can be estimated by calculating a heat balance around the gas turbine. By this method, exhaust heat is calculated as the heat input from fuel, inlet air, and injection water/steam, minus the thermal equivalent of the generator output and miscellaneous losses (including generator losses and turbine/generator bearing friction). Some manufacturers do not guarantee exhaust heat. This guarantee is of significance for heat recovery applications only. Inlet pressure loss is the pressure loss associated with the inlet air flow through the inlet air filter, silencer, evaporative cooler (if used), and inlet ductwork to the compressor section of the gas turbine. Inlet pressure loss typically is measured in units of inches of water. For “new and clean” performance, inlet pressure loss values of 3.0 to 4.0 inches of water are common. Exhaust pressure loss is the pressure loss associated with the exhaust gas flow from the exit of the turbine section of the gas turbine through the exhaust ductwork, silencer, and stack. In heat recovery applications the exhaust gas flow through the HRSG results in additional exhaust pressure losses. For simple cycle applications exhaust pressure losses of 4.0 to 5.0 inches of water are typical. For heat recovery applications exhaust pressure losses of 10.0 to 17.0 inches of water are typical, depending on the HRSG configuration and the presence of emission-reduction or noise-abatement equiopment. Factors that Influence Performance: Factors that influence performance include the following: • Ambient conditions, • Inlet/exhaust pressure losses, • Fuels and • Water/steam injection flow rates Ambient conditions: Because gas turbines are open cycle internal combustion engines, their performance is significantly affected by ambient conditions. Ambient conditions that directly affect performance include dry-bulb temperature, specific humidity, and barometric pressure (or elevation). Ambient dry-bulb temperature has a pronounced effect on electrical output. Lower air temperatures provide higher air densities which result in higher mass flows, and turbine output is directly proportional to higher mass flow. Higher air temperatures, which provide lower air densities and mass flows, which result in lower output. Lower ambient air temperatures also result in lower heat rates and better efficiency due to an increase in compressor pressure ratio. Likewise, higher ambient air temperatures result in higher gas turbine generator heat rates. A typical correction curve showing the effect of ambient air temperature on output, heat rate and other parameters is shown in fig 10. Specific humidity affects gas turbine performance through the slight variance in water mass flow. For higher specific humidities, more moisture is contained in the inlet air flow stream, making the air less dense and resulting in a lower electrical output and a higher rate. Typical correction curves showing the effect of specific humidity on output and heat rate are shown in fig 11. Fig 11 correction curves for humidity Barometric pressure of site elevation has an effect on output because of the variance in air-density. Lower barometric pressure which occurs at higher elevation, result in lower air density, lower inlet air mass flow rates, and lower electrical outputs. Barometric pressure has no effect on heat rate since the compressor pressure ratio and turbine inlet temperature are unaffected. A typical correction curve showing the affect of site elevation output is shown in fig 12. Fig 12: correction curves for output and exhaust flow vs. site elevation Inlet and exhaust pressure losses: Higher inlet pressure losses reduce the air flow through the unit and thereby reduce output. A typical correction curve showing the effect of inlet pressure loss is shown in fig 13. Fig 13: Gas turbine generator correction curves for inlet pressure drop In practical terms inlet pressure loss is a function of the inlet air system design and cleanliness of the inlet air filters. Lower inlet air pressure losses can be achieved by designing for lower inlet air velocities through the filter, silencer and duct. The improved operating performance associated with a lower inlet air velocity design must be evaluated against the associated higher capital cost. A similar cost evaluation determines the optimum point that dirty air filters which have higher pressure losses, should be changed out. Higher exhaust pressure losses increase the turbine back pressure, thereby reducing power output and increasing heat rate. A typical correction curve showing the effect of exhaust pressure loss on performance is shown in fig 14. Fig 14: Gas turbine generator correction curves for exhaust pressure drop. Higher exhaust pressure losses are primarily a function of the exhaust system design. For simple cycle applications, the exhaust system typically consists of an exhaust duct, silencers, and a stack. Exhaust pressure losses of 4.0 to 5.0 inches of water are typical for simple cycle gas turbines. For combined cycle or cogeneration applications, the exhaust gases pass through an HRSG with the associated additional pressure loss. Exhaust pressure losses of 10.0 to 17.0 inches of water are typical for combined cycle and cogeneration applications depending on the complexity of the cycle arrangement, exhaust emission control, or noise-abatement. Fuels: gas turbine output and heat rate are also affected by the type of fuel burned. The two most common fuels used today are natural gas and fuel oil. Turbine output and heat rate are both slightly better for operation on natural gas than for operation on fuel oil, assuming no water or steam injection is used for NOX control or power augmentation. Coal gasification combined cycle technology is being developed for future large-scale commercial use. The coal gasification process produces low to medium Btu gas which can be used as gas turbine fuel. Using the coal gas as the fuel results in the higher fuel mass flow rate to achieve the same heat consumption rates as for conventional fuels. As a result of the higher fuel mass flow rates, higher electrical outputs can be generated, depending on the fuel heating value. Water and Steam Injection: The most common method of controlling gas turbine NOX emissions rates is to inject water or steam into the combustor to reduce the peak flame temperature. Besides reducing the rate of formation of NOX, water or steam injection results in higher mass flow rates through the turbine section, electrical output is increased. Water injection increases gas turbine generator heat rate because of the additional heat consumption required to vaporize the water. Steam injection improves gas turbine generator heat rate because of its higher entering the combustion zone. Water or steam can be injected into gas turbine at rates beyond what is required for NOX control. For these applications, water or steam is injected for power augmentation (power boost). For power augmentation, the effect of water or steam injection on gas turbine generator output and heat rate is identical to the effect of water or steam injection for NOX control. To obtain higher thermal efficiency, it is essential to have a thermodynamic cycle using a high temperature heat source and a low temperature heat sink. The higher the temperature differences the greater the cycle efficiency (average temperature at which the heat is transmitted to the working medium~ average temperature at which the heat is rejected to the cooling medium). Neither the Brayton Cycle nor the Rankine Cycle can have much difference in temperature to have higher efficiency due to technical limitations. The gas turbine cycle is having the high source temp. of 1000 to 1200 c hence it could be the best option for the topping cycle. The rankine cycle working on steam is the most techno economic solution to use as bottoming cycle since it could maintain the sink temp close to the cooling water temperature. In a combined cycle power plant, the gas turbine cycle (brayton) is combined with that of steam turbine cycle (rankine). The combination of the two makes it possible to achieve the highest efficiency rates obtainable in the current state of the art technology, with values up to 47% for the overall plant. With certain new generation gas turbines, it is possible to attain efficiencies even upto 58-60%. This is much higher than the efficiency of the best available fossil fuel fired conventional thermal power plant. To achieve the best efficiency it is necessary for the optimization of combined cycle plant and heat rate. The following factors are to be considered in the optimization of combined cycle power plant.. A.Cycle Optimisation:• Configuration of combined Cycle Plant. • Number and capacity of gas turbine units • Number and Capacity of HRSGs • HRSG sizing • Combined cycle plant optimized cost. B. Combined Cycle Plant Heat Rate The following are the optimizations of combined cycle power plant are as 1, Combined Cycle Performance The site output of a gas turbine unit depends on ambient conditions and type of fuel whereas the steam turbine generator output primarily depends on the turbine throttle flow, the steam inlet condition (pressure & temperature) and condenser back pressure. The maximum amount of heat that can be expected from the HRSG is limited by the lowest stack temp possible for a given type of fuel. Corrosion may result on the HRSG point corresponding to the fuel being burn. Again for a specify stack temp more heat can be extracted by providing more surface area ( by adjusting lower pinch point temperature differences) resulting in higher steam production and steam turbine power, but this advantage has to be balance against to detrimental factors, viz :• Increase in HRSGs cost • Derating of gas turbine power due to increase gas pressure drop across HRSGs 2. Combined Cycle Optimization:The optimization combined cycle can be broadly carried out as follows: 1) Fixed configuration of GT HRSG & STGs 2) Seclect steam parameters ( Pressure, Temperature & Feed water temp. of HRSG) 3) Select stack temperature 4) Select pitch point 5) Perform heat & mass balance in HRSG 6) Size of HRSG 7) Compute GT output & TG output 8) Compute total capital cost 9) Compute output at CCP 10) Compute capitalize differential output 11) Compute total evaluated cost Heat Rate of CCP: Heat rate is defined as unit of heat added to the cycle per unit electric energy. Heat rate = Heat added to the cycle / Power generated = Fuel input x LCV of the fuel ( power generated in the gas turbine generated + power generated in the steam turbine generated) Formulae CERC norms for calculation of heat rate of a CCGT Q.A A steam trubine opening at a presssure of 170kg/cm2 and temperature of 560`C (Enthalpy 825 kCal/kg of steam) at electrical load of 500MW with final feed temperature of 270`C (Enthalpy 283 kCal/kg of water) and flow of 1250 Tonnes/hr of economizer inlet. What will be the heat rate of turbine? Turbine effieciency 85%. Soln:Given: Enthalpy of steam = 825 kcal/ kg Enthalpy of water = 283 kcal/ kg Flow = 1250 Tonnes/hr Turbine effieciency = 85% Heat Rate = = = = = kcal / K W hr { Qs ( Hs – Hf ) x 100 / kw hr } { 1250 ( 825 – 283 ) x 100 / ( 500 x 103 kw hr) } { 1250 ( 542 ) x 1000 / 500 x 103 1355 kcal / kw hr. 1 Cal = 4.185 J = 1355 x 4.1856 = 5671.75 kJ/ kw hr. Corrosponding, Efficiency n = = ( 3600 x 100) / 5671.25 63.47 % Efficiency of Hydro Power Plant Worldwide, hydropower plants produce about 24 percent of the world's electricity and supply more than 1 billion people with power. ± 2700 TWH is generated every year. Hydropower supplies at least 50% of electricity production in 66 countries and at least 90% in 24 countries. The world's hydropower plants output a combined more than 675,000 megawatts and The hydro power potential of India is around 1,48,701 MW and at 60% load factor, it can meet the demand of around 84,000 MW, the energy equivalent of 3.6 billion barrels of oil, according to the National Renewable Energy Laboratory. Use of hydropower peaked in the mid-20th century, but the idea of using water for power generation goes back thousands of years. A hydropower plant is basically an oversized water wheel. Hydropower plants harness water's energy and use simple mechanics to convert that energy into electricity. Hydropower plants are actually based on a rather simple concept -- water flowing through a dam turns a turbine, which turns a generator. Here are the basic components of a conventional hydropower plant:1. Dam - Most hydropower plants rely on a dam that holds back water, creating a large reservoir. Often, this reservoir is used as a recreational lake, such as Lake Roosevelt at the Grand Coulee Dam in Washington State. 2. Intake - Gates on the dam open and gravity pulls the water through the penstock, a pipeline that leads to the turbine. Water builds up pressure as it flows through this pipe. 3. Turbine - The water strikes and turns the large blades of a turbine, which is attached to a generator above it by way of a shaft. The most common type of turbine for hydropower plants is the Francis Turbine, which looks like a big disc with curved blades. A turbine can weigh as much as 172 tons and turn at a rate of 90 revolutions per minute (rpm). 4. Generators - As the turbine blades turn, so do a series of magnets inside the generator. Giant magnets rotate past copper coils, producing alternating current (AC) by moving electrons. 5. Transformer - The transformer inside the powerhouse takes the AC and converts it to highervoltage current. 6. 7. Power lines - Out of every power plant come four wires: the three phases of power being produced simultaneously plus a neutral or ground common to all three. Outflow - Used water is carried through pipelines, called tailraces, and re-enters the river downstream. Hydropower Basics Flowing water creates energy that can be captured and turned into electricity. This is called hydropower. The most common type of hydropower plant uses a dam on a river to store water in a reservoir. Water released from the reservoir flows through a turbine, spinning it, which, in turn, activates a generator to produce electricity. But hydropower doesn't necessarily require a large dam. Some hydropower plants just use a small canal to channel the river water through a turbine. Another type of hydropower plant—called a pumped storage plant—can even store power. The power is sent from a power grid into the electric generators. The generators then spin the turbines backward, which causes the turbines to pump water from a river or lower reservoir to an upper reservoir, where the power is stored. To use the power, the water is released from the upper reservoir back down into the river or lower reservoir. This spins the turbines forward, activating the generators to produce electricity. Classification of Hydro Projects based on Installed Capacity in following types:Micro: upto 100 KW Mini: 101KW to 2 MW Small: 2 MW to 25 MW Mega: Hydro projects with installed capacity >= 500 MW Thermal Projects with installed capacity >=1500 MW Types of Hydropower Impoundment An impoundment facility, typically a large hydropower system, uses a dam to store river water in a reservoir. The water may be released either to meet changing electricity needs or to maintain a constant reservoir level. Diversion A diversion, sometimes called run-of-river, facility channels a portion of a river through a canal or penstock. It may not require the use of a dam. Pumped Storage When the demand for electricity is low, a pumped storage facility stores energy by pumping water from a lower reservoir to an upper reservoir. During periods of high electrical demand, the water is released back to the lower reservoir to generate electricity. Turbine Technologies There are two main types of hydro turbines: impulse and reaction. The type of hydropower turbine selected for a project is based on the height of standing water—referred to as "head"—and the flow, or volume of water, at the site. Other deciding factors include how deep the turbine must be set, efficiency, and cost. Impulse Turbine The impulse turbine generally uses the velocity of the water to move the runner and discharges to atmospheric pressure. The water stream hits each bucket on the runner. There is no suction on the down side of the turbine, and the water flows out the bottom of the turbine housing after hitting the runner. An impulse turbine is generally suitable for high head, low flow applications. Cross-Flow A cross-flow turbine is drum-shaped and uses an elongated, rectangular-section nozzle directed against curved vanes on a cylindrically shaped runner. It resembles a "squirrel cage" blower. The cross-flow turbine allows the water to flow through the blades twice. The first pass is when the water flows from the outside of the blades to the inside; the second pass is from the inside back out. A guide vane at the entrance to the turbine directs the flow to a limited portion of the runner. The cross-flow was developed to accommodate larger water flows and lower heads than the Pelton. Pelton A pelton wheel has one or more free jets discharging water into an aerated space and impinging on the buckets of a runner. Draft tubes are not required for impulse turbine since the runner must be located above the maximum tailwater to permit operation at atmospheric pressure. A Turgo Wheel is a variation on the Pelton and is made exclusively by Gilkes in England. The Turgo runner is a cast wheel whose shape generally resembles a fan blade that is closed on the outer edges. The water stream is applied on one side, goes across the blades and exits on the other side. Reaction Turbine A reaction turbine develops power from the combined action of pressure and moving water. The runner is placed directly in the water stream flowing over the blades rather than striking each individually. Reaction turbines are generally used for sites with lower head and higher flows than compared with the impulse turbines. Propeller A propeller turbine generally has a runner with three to six blades in which the water contacts all of the blades constantly. Picture a boat propeller running in a pipe. Through the pipe, the pressure is constant; if it isn't, the runner would be out of balance. The pitch of the blades may be fixed or adjustable. The major components besides the runner are a scroll case, wicket gates, and a draft tube. There are several different types of propeller turbines: Bulb turbine The turbine and generator are a sealed unit placed directly in the water stream. Straflo The generator is attached directly to the perimeter of the turbine. Tube turbine The penstock bends just before or after the runner, allowing a straight line connection to the generator. Kaplan Both the blades and the wicket gates are adjustable, allowing for a wider range of operations. Francis A Francis turbine has a runner with fixed buckets (vanes), usually nine or more. Water is introduced just above the runner and all around it and then falls through, causing it to spin. Besides the runner, the other major components are the scroll case, wicket gates, and draft tube. Kinetic Kinetic energy turbines, also called free-flow turbines, generate electricity from the kinetic energy present in flowing water rather than the potential energy from the head. The systems may operate in rivers, manmade channels, tidal waters, or ocean currents. Kinetic systems utilize the water stream's natural pathway. They do not require the diversion of water through manmade channels, riverbeds, or pipes, although they might have applications in such conduits. Kinetic systems do not require large civil works; however, they can use existing structures such as bridges, tailraces and channels. Major Effects of Reservoir Sedimentation • It reduces the active storage capacity, which may reduce the capability of the reservoir to deliver the benefits in course of time. • It makes the flood management in the reservoir more difficult. • Damages to turbines and other under water parts due to abrasive action of silt. Approaches to Tackle Sedimentation Problem of reservoir • Catchment Area Treatment (CAT) for reduction of silt load includes forestations of the catchment area and constructions of check dams on the tributaries and upstream of the river. • Effective desilting arrangements for prevention of silt. • Silt resistant equipments of withstanding the silt. • Effective operation of the reservoir to minimize silt deposition. Important Recommendations for Silt Control SHORT TERM Experiment with reservoir Operation-Optimization of gate operation advised by study on model and prototype. MEDIUM TERM Dredging pumps at intake-Recommended for Silt removal near intake gate. LONG TERM Catchment area treatment to reduce bank erosion. New diversion Tunnel-Preliminary study indicates it is beneficial, further model studies & detailing of proposal has been advised. Thrust areas in the field of Environmental Conservation & Management for developing Hydropower Following safeguards/management plans are implemented at various NHPC projects to ensure development of hydropower in an environmentally sustainable manner: • Compensatory Afforestation in lieu of forest land diverted for the project. • Catchment Area Treatment (CAT) to minimise erosion in the catchment of the reservoir, thereby reducing siltation in the reservoir. • Resettlement & Rehabilitation of Project Affected Population. • Restoration of Dumping Sites and Quarry Sites using engineering and biological measures. • Reservoir Rim Treatment plan to stabilise reservoir periphery. • Conservation measures for flora and fauna, to conserve flora and fauna native to the ecosystem of the area. • Subsidized Fuel Distribution to worker population and project affected population to minimise fuel demands on the adjacent forests. • Health Management Plan for the worker population and affected population to prevent epidemics and maintain optimum health standards. • Fishery Management by construction of fish ladders wherever possible, to enable migration of fishes and by promoting reservoir fisheries.Green Belt Plan to make the surroundings of project construction areas green. • Dam Break Analysis and Disaster Management Plan for downstream areas vulnerable to flooding in case of Dam breach. Soil Erosion due to Water Erosion, removal of sediment, rock, and soil from the landscape, resulting in the formation of new landforms and the lowering of the land surface, a process known as denudation. During transportation the sediment further erodes the landscape by battering and rubbing against the surfaces over which it passes. The fragments also knock against each other, and break into smaller pieces. Water is probably the most significant agent of erosion today, and rivers carry more sediment from the land to the oceans every year than either ice or wind. Rivers move sediment downstream as part of their load. Vertical erosion predominates near the source, cutting downward, while downstream rivers erode laterally, thus widening their valleys. Sediment transport becomes more important as the debris is removed from the drainage basin. During transport sediment helps aggrade the bed and banks, and attrition of the particles causes them to be reduced in size. As rivers become larger, they are able to carry more sediment from the landscape, and the sediment becomes more denuded. The landforms of river valleys therefore represent stages in the denudation of the landscape. Slope angles reduce and valley cross-sections become wider downstream, developing from steep V-shaped upland valleys to wide, open floodplains. When rivers meet resistant rock, unique and distinctive features may develop including waterfalls, rapids, and gorges. When they flow through floodplains, rivers cut into valley floors and sides as they meander, reworking deposits laid down in earlier periods. Water can erode sediment on slopes where overland flow or runoff occurs. Weathered material washes downslope and enters river channels directly. This can also cause gullies to form as material is removed. Gullying is most effective where vegetation is sparse, and sporadic intense rainfall occurs. Some dramatic erosional landscapes have occurred as a result of this process, such as the Badlands of North and South Dakota and Nebraska, United States. Human activities can increase the erosion process where vegetation has been removed by agriculture, fire, overgrazing, or deforestation, and accelerated soil erosion results. Policy measures The Union Ministry of Power has taken several steps to accelerate capacity addition from hydroelectric projects. These include: • higher budgetary allocation for the hydel sector. • investment approval of new hydro-electric projects; • identification of new projects in the Central Sector for advance action; • promoting State Sector projects which were languishing or could not progress due to Inter-State disputes; • improving tariff dispensation for hydel projects; • simplification of procedure for transfer of clearance; • levy of 5% development surcharge to supplement resources for hydro electric projects by NHPC allowed by CERC. Basin-wise Policy The policy measures undertaken to accelerate hydro power development inter-alia lay emphasis on basinwise development. World Bank assistance for survey, investigation and preparation of DPRs of the projects in Sutlej and Ravi basins is being considered. States with substantial undeveloped Hydro potential Region/State Arunchal Pradesh Himachal Pradesh Assessed (MW) 50328.00 In Operation Under (MW) Construction 10.50 1609.85 3822.95 405.00 3453.00 1926.00 Balance (MW) 49912.50 13835.15 13071.05 U.P./Uttaranchal 18898.00 18820.00 Jammu Kashmir Sikkim Karnataka Meghalaya Mizoram & 14146.00 4286.00 6602.00 2394.00 2196.00 1394.25 84.00 2789.40 185.20 0.00 098.10 1799.50 300.50 105.00 65.00 1837.50 469. 0 519.00 222.00 0.00 60.00 30.21 20.2% 936.00 90.00 24.00 66.00 12282.75 3683.00 3590.60 2208.80 2136.00 1684.25 1684.25 1604.50 1589.00 1475.00 1095.50 M.P./Chhattishg 4485.00 arth Kerala West Bengal Manipur Nagaland Orissa 3514.00 2841.00 1784.00 1574.00 2999.00 THE SURVEY AT A GLANCE The surveyoutlines the approach and provides a road map for development of the balance untapped potential of the country by the year 2025-26. The paper analyses the Anticipated Demand-Supply scenario likely to prevail in the country by making use of the results of Long term Perspective Plan Studies carried out by CEA (up to the end of 11th Plan i.e. 2011-12) as well as Demand Forecasts available up to the end of 12th Plan (2016-17) as per 16th Electric Power Survey The Demand Projections for the period beyond 2017 have been made by extrapolating the projections made in 16th EPS. Based on the above, the demand for power by the year 2025-26 is likely to be of the order of 353000 MW with corresponding probable installed capacity of 463000 MW. Further, hydro capacity additions in different Plan periods till 2025-26 have been so planned as to develop complete hydro potential by the year 2025-26 which would gradually improve the share of the hydro in the system to about 32% by 2025-26. The Paper discusses about status of hydro schemes under various stages of Development i.e. projects under construction, cleared by CEA, under examination in CEA, under Survey & Investigation etc. and outlines various factors inhibiting the growth of hydro potential in the country. It stresses upon the need to complete the on-going projects and to develop the projects already cleared by CEA expeditiously. It also stresses upon the need to carry out Survey and Investigations works in a time bound manner by the year 2016-17 in order to ensure development of the balance hydro potential in the country by the year 2025-26. The surveyanalyses projects languishing due to various reasons like funds constraints, Inter-state aspects etc. and suggests their quick development by addressing the involved issues at appropriate level. In addition, by resolving the pending issues, 42 schemes with installed capacity of about 13250 MW, which were examined earlier in CEA and returned to project authorities for resubmission, can also be taken up for implementation with minimal of S&I works. The surveysuggests the Action Plan/ Methodology for preparation of Pre-Feasibility Reports for balance about 400 schemes and broadly discusses criteria for carrying out prioritisation / ranking study for their development in order to provide a shelf of HE Projects in each basin which could be developed in a systematic manner starting from sites which are ranked to be attractive. The Paper proposes carrying out of Survey and Investigation of the selected schemes by Central Agencies like CWC, NTPC, NHPC and WAPCOS etc. These S&I activities have been proposed to be completed in next 10-15 years so as to accomplish development of entire untapped potential in the country by 2025-26. The cost of development of the remaining untapped potential in the country has been estimated as about Rs. 5,00,000 Crs. while requirement of funds by 2016-17 for carrying out S&I activities would be of the order of Rs. 5000 Crs. In view of the massive fund requirements over next 20 to 25 years, the paper impresses upon the need to immediately explore all avenues for mobilisation of funds. The survey also calls for review of studies carried out for Re-assessment of Hydro Electric Potential of major/ medium HE Schemes to bring out most realistic features of the sites by making use of updated hydrological/ topographical data with inter-action with MOEF. The paper contains following recommendations for expeditious development of the balance hydro potential in the country by the year 2025-26: • About 4759 MW of hydro capacity can be added without much of efforts, if funds to the tune of Rs.14522Crs. are tied up. These include projects languishing due to funds constraints and those projects that are awaiting Planning Commission/ CCEA clearance. • By expeditious resolution of pending issues, the "Returned" projects could be taken up for implementation which would lead to an addition of about 13268 MW of Hydro capacity in the Indian system at a cost of about Rs.35,000Crs. In addition, by resolving inter-state aspects, about 4797 MW of capacity could be added to the system at an estimated cost of about Rs. 13500 Crs. Since preliminary surveys and investigations for most of these schemes have already been carried out for preparation of DPR, these projects could be taken up immediately for implementation and are likely to yield benefits during the next 10-15 years. • In order to achieve development of an installed capacity of about 150,000 MW from the entire identified hydro potential of the country (excluding about 25,000 MW already developed), Planwise additions of hydro capacity has to grow substantially from present levels to comparatively much higher additions during the subsequent Plans as given below: Likely Hydro Likely funds Plan Period Capacity Addition requirement (MW) (Rs. Crs.) 23200 9th Plan (1997-2002) (Balance) 5800 10432 41728 10th Plan (2002-2007) 11th Plan (2007-2012) 12th Plan (2012-2017) 13th Plan (2017-2022) Part 14th Plan (2022-2026) 01288 2300 31000 35000 85152 92000 124000 140000 Total : 126520 506080 • The total requirement of funds for development of entire untapped potential in the country is likely to be around Rs.5,00,000Crs. in the next 25 years at present price level. • The sources / agencies for raising necessary funds need to be identified well in advance to arrange large fund requirement of the order of about Rs.1,00,000Crs. per plan period on an average i.e. about Rs.20,000Crs. on an average per annum, so that implementation of these projects could be undertaken expeditiously. • In order to develop the entire potential by the year 2025-26, Survey & Investigation activities have to be completed by the end of 12th Plan i.e. by 2016-17. Completion of Survey & Investigation activities by the year 2016-17 for development of balance out of 1,50,000 MW by 2025-26 would involve an expenditure of around Rs.5,000Crs. • Prioritisation studies would be carried out for ranking of the schemes for their implementation considering their relative attractiveness in terms of their location, cost effectiveness, minimal civil works etc. based on the available data. This would provide classification of schemes to be undertaken for implementation in a systematic manner starting from sites of less problems/ risks to others having difficult terrain and accessibility. Submergence of Land Thereby loss of flora and fauna and large scale displacement, due to the hydropower projects is sometimes exaggerated. The following table shows that project catering only to hydro power needs, cause little submergence. A sample of following 12 projects contributing 6231 MW of power required submergence of only 4850 ha of land i.e. the area of submergence per MW is only 0.78 ha. l. Jo Name of the project 1 2 3 4 5 6 7 8 9 10 11 12 Total Chamera-I Chamera-II Chamera-III Parbati-II Parbati-III Tanakpur Dhauliganga-I Rangit Teesta-V Uri Dul Hasti Subansiri Lower State H.P. H.P. H.P H.P. H.P Uttarakhand Uttarakhand Sikkim Sikkim J&K J&K Arunachal Pradesh Capacity (in MW) 540 300 231 800 520 120 280 60 510 480 390 2000 6231 Submergence area ha) 175 25 29.90 27 21.61 140 29 13 68 Nil 85 3436 4849.51 ~ 4850 ( in Hydropower Projects cause huge Destruction of Forests Due to virtue of being located in hilly areas, where forest cover is comparatively better than plain areas, diversion of forest land is sometimes unavoidable. However, NHPC aims at minimum utilization of forests. Compensatory Afforestation is mandatory in accordance with Forest (Conservation) Act, 1980, which has to be fulfilled along with other conditions imposed by MOEF while according forest clearance to a project. Forest land diverted for a project may be a notified forest land, however, this land may include river bed and degraded forests. The actual forest cover in such type of land may be quite low. Inspite of the fact, NHPC undertakes compensatory afforestation either on equal non forest land or on degraded forest land, double the forest area diverted. Massive afforestation has been undertaken at the commissioned as well as ongoing projects of NHPC. In seven commissioned projects of NHPC viz. Tanakpur, Chamera-I, Chamera-II, Uri, Rangit, Dhauliganga, Dul Hasti and three under construction projects viz., Teesta-V, Parbati-II, TLDP-III, afforestation has been undertaken over an area of 3875.42 ha. of degraded/non forest land, in lieu of diversion of 2156.44 ha of forest land required. In these 10 projects, against 102826 affected trees, NHPC has planted more than 78 lakh trees under Compensatory Afforestation. S.No Project Forest affected(ha) Area Afforested (ha) Trees affected Trees planted Commissioned Projects 1 Tanakpur 293.35 2 Chamera-I 982.50 3 Chamera-II 78.70 4 Uri 54.71 5 Rangit 37.10 6 Dhauliganga 138.62 7 Dulhasti 1.10 Sub total (A) 1586.16 Under-construction Projects 8 Teesta-V 122.17 9 Parbati-II 145.62 10 TLDP-III 302.49 Sub total (B) 570.28 Total (A+B) 2156.44 350.00 2000.00 173.00 62.70 168.50 140.73 18.00 2912.93 250.00 291.00 421.49 962.49 3875.42 17368.00 40000.00 1380.00 4000.00 5027.00 1517.00 687.00 69979 17495.00 8124.00 7228.00 32847.00 102826.00 666165.00 3981186.00 239100.00 321000.00 338250.00 287887.00 785673.00 6619261 400000.00 177700.00 645634.00 1223334.00 7842595.00 Benefits of Hydropower Projects Hydropower is a renewable, economic, non polluting and environmentally benign source of energy. It saves scarce fossil fuel resources of the country, which are non renewable. Hydropower projects have certain distinctive advantages over other sources of electricity generation, as discussed below: a) Technical Benefits Hydropower projects are known to have much longer life and provide cheaper electricity as there is no fuel cost and as the recurring cost involved in generation, operation and maintenance is lower than that in case of other sources of energy. b) Environmental Benefits • Uses Renewable and pollution free source of Energy i.e water • Increase in Agriculture Productivity through development of irrigation and multipurpose schemes, having generation of electricity as one of the objectives, wherever possible and feasible. • Avoided Green House Gas (GHG) emissions from equivalent thermal and other fuel based power projects. • Involve large scale afforestation activities under various schemes like Compensatory Afforestation, Catchment Area Treatment, Green Belt Development, Voluntary Afforestation etc. which ultimately improves the environmental quality of the project area. • Flood Mitigation through large storage dams. • Source of Drinking Water c) Social Benefits Hydro projects are a boon to the society and the population at and around the projects. With enhanced employment opportunities, increased earnings, enriched life style and improved standard of living, the people in these localities experience an economic and social upliftment. Reservoir area is an ideal place for recreation and source of eco-tourism promotion in the area. The reservoirs are also used for promoting pisciculture. There are other direct benefits accruing from hydro projects and dams such as increased water for improved irrigation, and drinking water to villages and people living in and around the project area. Que:- Assuming constant discharge of water of a flowing river, it is given that the installed capacity is 100MW when the height is 50meter.What will be the installed capacity if the height is reduced to 10meter? Ans:-The energy of flowing water can be converted into shaft work passing through hydraulic prime mover and ultimately into electrical energy. The shaft power developed by the water passing through the prime mover is given by: kW(power)=mgH x ηh x ηm x ηg 1000 Where m = rate of water flow in kg/sec H = height of fall in meters ηh= hydraulic efficiency of prime mover ηm= mechnical efficiency ηg= generating efficiency kW(power)=mgH x ηoverall 1000 Where ηoverall= ηh x ηm x ηg Keeping other parameters constant we find:kW = constant x H Therefore:kW1 = H1 kW2 H2 100000 = 50 kW 10 power developed = 20MW Maintenance planning Maintenance Planning Guideline Although the development project may be completed and released, the project deliverable simply enters a new phase of its lifecycle. The major project deliverables require ongoing support from the company. That support includes such activities as responding to user issues, maintaining the system hardware, incorporating enhancements, and performing preventative maintenance. For the success of the product or system in the field, thoroughly planning ahead for proper maintenance support is crucial. 1. Read the guidelines starting on page 2:  Introduction to Maintenance  Defining the “Maintenance Concept”  Maintenance Planning Overview—Types and Timing 2. Determine which aspects of maintenance apply to the project deliverables. 3. Using the information on page 3, “Maintenance Planning Overview—Types and Timing,” determine when you should begin writing a maintenance plan in your project cycle. 4. Adapt the Maintenance Plan outline (starting on page 5) to your specific projects. 5. If your project is in its early stages, add maintenance planning activities to your project schedule. 6. If your project has already started and there is no maintenance plan, have a maintenance planning meeting so discussions and planning information can benefit any associated design work. 7. Ensure that maintenance planning includes a specific “owner” going forward who continues to be a regular part of your project and has adequate inputs to development and test reviews. 8. As you move through the project, update the plan iteratively; thus, yielding a detailed maintenance plan later in the project to ensure all aspects of personnel and processes are in place when the product or system is released to production/deployment. Maintenance Planning Guidelines and Plan Outline Introduction to Maintenance Maintenance refers to ongoing support and evolution of a system once it is released to users/customers. Maintenance planning needs to occur while a system is in the development stage. Purpose of the Maintenance Process:  Sustain and monitor system capability to provide services.  Record problems for analysis.  Take corrective, adaptive, perfective, and preventive actions.  Confirm restoration capability. Expected Outcomes of Maintenance Process:  A maintenance strategy is developed.  Maintenance constraints are provided as inputs to requirements.  Replacement system elements are made available.  Services meeting stakeholder requirements are sustained.  The need for corrective design changes is reported.  Failure and lifetime data is recorded. Defining the Maintenance Concept The maintenance concept is developed first. It is really the high-level design of the approach to system maintenance. This concept sets the overall parameters for doing more detailed maintenance planning. It should cover:  The scope of the maintenance, e.g. an overview of covered hardware and software systems/subsystems, whether maintenance of third-party system elements is included, or what types of maintenance are covered (see list below).  Post-delivery processes, e.g. an overview of the approach to problem resolution, change control, and deployment of updates or whether any tailoring from standard company processes is necessary or allowable.  Overall responsibilities for maintenance, what group(s) will be responsible for fulfilling which aspects of the maintenance processes.  Estimates of life-cycle costs, guidelines for acceptable life-cycle costs that will drive maintenance approaches and budgets. Based on the overall guidelines established in this maintenance concept, a detailed maintenance plan can be developed. Maintenance Planning Overview: Types and Timing The Maintenance Plan must address detailed processes for the development of changes as well as their deployment. It addresses subjects such as:  Scope of maintenance effort.  Schedule for any regular maintenance releases.  Types of maintenance releases allowed.  Maintenance processes and techniques, including for issues recording, escalation, prioritization, change reviews, and control.  Organizational responsibilities and staffing.  Tools and equipment including configuration management, defect tracking, spares requirements, and test equipment.  Processes for acceptance testing, releases, and deployment communication.  Budgets.  Ongoing monitoring of maintenance effectiveness and customer satisfaction with the system. Major aspects of maintenance which must be addressed in maintenance planning:  Maintaining control over the system's day-to-day functions.  Maintaining control over system modification.  Perfecting existing acceptable functions.  Preventing system performance from degrading to unacceptable levels. Categories of maintenance:  Corrective Maintenance – Changes necessitated by actual errors/bugs or design deficiencies. Corrective maintenance consists of activities normally considered to be error correction required to keep the system operational. By its nature, corrective maintenance is usually a reactive process. Corrective maintenance is related to the system not performing as originally intended. The three main causes of corrective maintenance are (1) design errors, (2) logic errors, and (3) coding errors.  Adaptive Maintenance – Changes initiated as a result of changes in the environment in which a system must operate. These environmental changes are normally beyond the control of the maintainer and consist primarily of changes to the: (1) rules, laws, and regulations that affect the system; (2) hardware configuration, e.g., new terminals, local printers, etc.; (3) data formats and file structures; and (4) system software, e.g., operating systems, compilers, utilities, etc.  Perfective Maintenance (also known as enhancements and upgrades) – All changes, insertions, deletions, modifications, extensions, and enhancements made to a system to meet the evolving and/or expanding needs of the user. It is generally performed as a result of new or changing requirements, or in an attempt to augment or fine-tune the existing software/hardware operations/performance. Activities designed to make the code easier to understand and to work with, such as restructuring or documentation updates, are included in the Perfective category.  Preventive Maintenance – Changes required avoiding or detecting problems before they cause operational problems. Hardware maintenance could include regular checks of performance and physical inspection for wear and resulting adjustments as necessary. Software maintenance in this category could include regular review of performance metrics, analysis of loads and trends and any emerging issues with system performance, and adjustments of the system to ensure that operations are not disrupted. How Maintenance Planning and Preparation Fit in the System Development Life Cycle:An inherent element of the system requirements is the maintainability of the system. This can be captured in the design alternatives analysis, maintained as part of the configuration management of the system, and verified during the operational phase of the project. The maintenance concept above leads to high-level and detailed maintenance requirements. Implementation of the system would also result in implementation of the maintenance management program, verification that the system is as maintainable as hoped, and finally concurrent operations and maintenance activities. The cross-cutting activity of system validation assessment during the operation phase would also be paralleled by a validation that the maintenance concept was captured in the management of the system and the verification that maintenance requirements were being met. Taking it phase by phase, consideration of maintenance implications leads to this typical involvement of support personnel during development of the system.  System requirements definition and alternatives investigation: Maintenance concept development and planning must be done in parallel with the development of the system to be maintained. Starting with the overall requirements definition and investigation of design alternatives. The overall concept of maintenance may drive tradeoffs in system development. For example, how much time and money will be spent developing highly automated diagnostic tools to ease troubleshooting and contain costs of field visits? Or developing sophisticated online automated code update capabilities to reduce physical shipment of new software versions to the field? Those who will be responsible for maintenance should be involved in such trade-off discussions early in the project so that the life-cycle costs associated with maintenance are considered in the initial system design.  Development: As elements of the system are developed (detailed design and implementation performed), features that influence or implement directly the maintenance concept are created by the development team. Those responsible for maintenance and support should be included in appropriate reviews and prototyping. They will have detailed input on how to make the system most easily diagnosed maintainability of sub-systems, etc.  Testing and documentation: As the time for deployment nears, maintenance personnel can begin to learn a new system, even assisting with testing to learn hands-on about installation, configuration, and system troubleshooting. They can also review and help hone technical publications such as user manuals and installation guides.  Deployment: System deployment marks the official beginning of transition to ongoing maintenance and support. The handoff between development and maintenance personnel should be done with attention to understanding of state of the system—open issues, any features that did not make the release, etc., as well as readiness of the maintenance organization and processes and any need for initial support from development. MAINTENANCE PLAN OUTLINE: Typical Items Covered in a Maintenance Plan  Overview and Scope 1. Types of Maintenance included:Provide brief overview statements of how/whether corrective, adaptive, preventive, and perfective maintenance is covered by this plan. 2. Systems Included in Software Maintenance:Calls out the types of software included in the maintenance and corresponding systems or subsystems, such as:  Operating System: Maintenance issues include system administration, network security, upgrades or “patches” to the latest version, and dealing with potential incompatibilities between the OS and other hardware and software in the system.  Commercial Off-the-Shelf: Sometimes called COTS software, this includes commercially available applications that are part of the overall operation, such as relational database management systems, word processing, and/or spreadsheets. Examples include Oracle, Word, and Excel. Maintenance issues include configuration and user administration of COTS implementations, software maintenance contracts, upgrades, and potential incompatibilities between COTS and other hardware and software in the system.  Application Software: Maintenance issues include system configuration management, software maintenance contracts, backup and disaster recovery, user and operator administration, and system security. In addition, the issue of intellectual property rights and source code ownership has a tremendous impact on maintenance issues and costs. 3. Items Included in Hardware Maintenance:Calls out all hardware (electronic, mechanical) elements of the product/system that must be maintained, including enclosures, electronics, and third-party modules or systems. 4. Release and Maintenance Phase Schedule Provides a timeline view showing key milestones and release cycles, including the following items:  Initial deployment: The schedule should show the start of ongoing maintenance with respect to initial deployment—for example, is there a transition period during which Development or other       non-maintenance personnel are expected to stay involved or continue to lead efforts? The schedule should define at which point each responsible group is assuming ownership of support. Regularly-scheduled/ongoing maintenance: Summarize and provide an overview timeline of the overall maintenance cycle. For example, for software, show the schedule for the types of maintenance releases covered by this plan. Also, hardware-related timelines can show regular preventive maintenance trips. Software-related timelines can show regular back-up schedules and database maintenance. See next section, Types of Maintenance Releases. All types appropriate for your company should show up in the Maintenance Schedule, with either hard timing or estimates of frequency. Ad hoc individual patches: e.g. small, timely fixes for urgent problems. Regular patch releases: e.g. larger subsystem roll-up patches for the delivery of less time critical fixes. Full system deliveries: Driven by integration activities that requires the establishment of a new maintenance baseline. External milestones: For example, releases of new versions of operating systems or third party components that must be migrated into the system. Linkage with company development plans: By definition, maintenance involves supporting evolving systems. The linkage of maintenance activities to ongoing development programs should be shown, i.e. is there a cycle by which maintenance items are fed into development portfolio planning? 5. Types of Maintenance Releases:Some companies will define different levels of releases allowable under various circumstances; specifically, the ability to quickly release engineering or test level code to quickly address emergency situations. If such cases are to be allowed, the maintenance plan can specify constraints and guidelines for each type of release. The following paragraphs are examples of software releases: Engineering Software: Definition and purpose: Engineering software is software delivered in response to an emergency. It is only provided at the specific request of an internal group, with the goal of mitigating a critical operations problem within hours of the onset of the problem  Approach: Engineering software may be delivered at any time of the day or day of the week. Engineering software is built in a developer’s view from source code that is not yet merged to the baseline and typically only unit tested by the developer. The goal within sustaining engineering will be to merge corresponding fixes (tested and approved) to the appropriate baseline within 48 hours of sending the engineering software. The team will continue to use a custom Clear Case tool developed that controls and documents the delivery of engineering software to the field. This tool, accessible only by senior developers (subsystem leads) who are authorized to send engineering software, captures and documents what engineering software has been sent. Test Executables (TEs): Definition and purpose: Test executables are software deliveries designed to fix a specific problem with the smallest possible delivery footprint. The footprint of a change is the number of delivered components required to implement the change. The goal of a TE is to provide a fix for an urgent problem as soon as it is available (possibly before final, definitive testing is completed), in a form that can be promoted into operations by the internal receiving group as quickly as possible. TEs are also only provided at the specific request of a user location. TEs are normally delivered during the standard work week, but can be built and delivered during off hours for especially urgent problems.  Approach: TEs are delivered from the controlled baseline (after a merge and build), either from the maintenance baseline or from an Emergency Bug Fix branch. TEs are delivered under a configuration change request routed through the change control board. Software CM uses custom tools to send the TE tar files, document the receipt of the delivery by each site, and distribute all of the technical data to all interested parties. TEs are installed and tested by the test group in the test environment, but this testing may be done in parallel with the delivery to the user site depending on the urgency of the request. The delivery of TEs will be planned and managed on a daily basis by the lead of the Deployment team. The Custom Software Delivery process governs the delivery of Test Executables as well as Patches. Patches: Definition and purpose: Patches are larger software deliveries, usually covering an entire subsystem. The goal of a patch is to deliver all of the fixes that have been applied to the maintenance baseline for an entire component or subsystem. Sometimes the fix to a problem will require the simultaneous delivery and installation of components from multiple subsystems; when this happens, multiple subsystem patches are generated, tested, and delivered as a group. Deliveries are planned and scheduled by the Deployment team, taking into account the program priority list, the list of program mission milestones, development progress in merging fixes for specific problems, and inter-relationships between fixes among subsystems. We will provide a subsystem patch for each major subsystem every 6 to 8 weeks.  Approach: Patch delivery follows a rigorous process. The Software Integration and Test Team sends a request to software CM to build tar files for the patch, identifies the issues fixed in the patch, and generates draft installation instructions. The test group tests the installation of the patch in the code control system, providing redlines to the installation instructions as required, and verifies the issues fixed in the patch. Additional functional regression testing is performed as required. When testing is completed, the patch is presented at a pre-ship review by the DPT. The installation instructions and the issues are discussed with the receiving user sites, including any changes in operational procedures or troubleshooting methods required by the fixes. A change control record is executed to deliver the software, and software CM uses custom tools to send the patch tar files, document the receipt of the delivery by each site, and distribute the technical data package for the delivery. Drop/Release The delivery of the full system is usually referred to as a drop or a release, and is accompanied by the transition to a new maintenance baseline. Full system deliveries will be performed only as necessary to deliver capabilities and upgrades that require changes in a majority of the subsystems. Extensive regression and performance testing precede full system deliveries. Transition/Training Occasionally, deliveries will require a set of transition activities to be performed (e.g. building of a database index or updating values in a database table) either before or after installation of the software. Scripts are provided to perform these activities. A detailed transition plan is developed and the users are provided hands-on transition training. With proactive support from sustaining engineers, the customer will test the installation. Feedback from this exercise is incorporated into installation and transition instructions prior to deployment to all locations. For new capabilities not requiring the scope of support described above, the primary development engineer is invited to one of the bi-weekly deployment team meetings to discuss the new capability. 1. Maintenance Staffing and Environment 1. Staffing and Roles and Responsibilities  Overall responsibilities and required skills and resources: This section makes clear who has responsibility for what maintenance activities, and what resources in the support organization(s) are involved (at least by skill set and number of resources, if not by name).  Leads and customer contacts: This section identifies key leads, as well as any primary contacts for user groups or customer sites. Those customer/user contacts should include specific contacts for different maintenance activities, e.g. the contact for escalation of user issues, for planning cutin of new releases, etc. 2. Tools and Equipment Needs for Maintenance Activities  “Infrastructure” inherent to the Maintenance process: Internal tools such as configuration management software and defect and enhancement request tracking databases.  Spare Parts: Specify inventory of spare parts to replace failed or damaged equipment during ongoing operations and maintenance. Many maintenance contracts and even some procurement contracts use a rule of thumb of between 5 and 10 percent spares; that is, 5 to 10 percent times the total installed base of certain critical items. A quantitative estimate for spare parts may be calculated if certain variables are known or can be estimated with confidence. For example, if the MTBF and MTRR are known, it is possible to calculate how many spares will be required to have on hand to meet a desired level of availability (i.e. 95% of all cameras online at any given time).  Test Equipment and Test Beds: Specify test equipment or environments that must be available to support debugging of problems and testing of changes before they are released to production. 3. Training Required  Maintenance/support personnel: Define what training the company’s support personnel should receive (usually prior to release) min maintenance procedures.  User/Customer training: Define what training the users of the product or system should receive related to their role in maintaining the system (for example, proper back-ups). 4. Maintenance Procedures Handling change requests:The following procedures must be developed and documented in the Maintenance Plan (or the Maintenance Plan would reference company processes for these items). Fielding change requests  Submitting modification requests  Reviewing and prioritizing requests 1. Developing and testing changes  Analyzing and verifying a problem, developing implementation options  Performing reviews of implementation options, assessing system and company impacts, and choosing an option  Performing technical reviews of changes and approving those changes  Implementing and testing the changes Release planning and configuration management  Allocating problems and fixes to specific releases  Defining deployment of changes, including developing and communicating migration plans  Implementing configuration management of the system and changes to the system  Deciding on retirement of particular elements of a system, planning and communicating the retirement, and executing switchover 2. Acceptance Testing and Signoff The plan can indicate what acceptance testing processes will be employed and signoffs required for different types of releases. This might include referencing specific User Acceptance Test plans that must be run or Customer Acceptance Checklists that must be executed by sites accepting new hardware or software releases. 3. Deployment Communication Delivery plans for software updates need to be flexible and clearly communicated. The Maintenance Plan can identify what approaches will be used to communicate deployment of system changes, such as:  Teleconferences: Releases can have a standard release communication teleconference scheduled, where representatives from affected groups can hear a summary of the upcoming release and deployment plans and ask questions about how their environment is affected.  Email: Notification to a standard distribution list of affected groups as well as other parties who need to stay informed about the big picture, i.e. to understand how often the system is being updated, with what kinds of changes. Both delivery plans and distribution notices should be communicated.  “Patch plans”: The maintenance organization can generate and distribute a regular patch plan communicating a look-ahead schedule for all deliveries to the field. For example, it can document the 3-month plan; this plan should be updated more frequently than the look-ahead period, to keep it current with any changes in priorities. 4. Life-cycle Costs and Maintenance Budgets Based on the staffing, equipment needs, and processes to be included in maintenance, this section summarizes expected life-cycle costs for the product or system and outlines the budget requirements for executing the maintenance. 5. System/Product Design Implications from the Maintenance Concept and Processes As this plan is developed, the team is thinking through how the system will be maintained and supported. This planning process will provide insights that must be communicated to the design team. For example, the maintenance concept and process details may require that specific diagnostic tools be created or certain error codes are included in the software. 6. Performance Monitoring and Management during the Maintenance Phase 1. Measures of Performance:-Whether the maintenance activities are conducted by in-house personnel or contracted out, there are several measures of performance that can be used to determine the state of the original system when released, as well as the effectiveness of ongoing maintenance. These include:  Mean time between failures – the average time between device failures, usually expressed in      hours. Mean time to repair – the average time to repair (or replace) a device, typically this includes the response time, expressed in hours. System Availability – the time that the system provides its designed functionality, expressed in hours. Typically, this excludes scheduled downtime due to maintenance or system administration activities. System Reliability – similar to Availability, but expressed as the probability that the system will be available. User help-desk inquiries – measure of how much support users required. Defects reported – measure of how many problems were discovered after release. 2. Monitoring of Customer Satisfaction – Regular Reviews This section documents how customer satisfaction with system performance will be assessed as part of the maintenance process. The goal is to have up-to-date understanding of the needs of the customer, the perceived performance of the current system, and to identify possible future applications to incorporate into future releases. Although it is expected that users will raise issues through the issues reporting or enhancement request system, the goal of this section is to also identify a regular overarching review process with the users—periodically scheduling a time to review status and solicit input for improvements. This section of the plan should include:  How the measures of performance above will be measured at customers  Frequency of reviewing enhancement request database  Frequency and types of regular reviews with customers, including not only system functionality, but also any new needs for training or documentation  How issues or requests raised in these forums will be prioritized and assigned and how results communicated to the customer. 3. Performance Reports This section calls out what reports should be produced regularly as part of the above processes, what they should contain, and who should receive them. 4. Managing Execution of the Maintenance Plan With the maintenance plan developed, approved, and funded, there must be a structured practice for managing the plan. The basics of plan management are similar to other practices and should include:  Performance Monitoring: Regular checking of plan metrics and budgets against the maintenance plan projections, as documented in 5.1 above  Oversight Support: Support of the plan over time and its relationship to training, and staffing issues  On-going Multi-year Planning: Plan for changes in system components, emerging issues, changes in the process and new or evolving needs of stakeholders. Check that the level of effort and resources are appropriate to support a multi-year maintenance program plan.  Operational Needs: Check that the maintenance concept is consistent with operational concept. What is Maintenance  Function of system/equipment is to provide desired output at desired quality with control on hazards to safety of man / machine / environment.  Maintenance is the combination of all technical and associated administrative actions intended to retain an item in, or restore it to, a state in which it can perform its required function throughout its life cycle. as user wants them to do under present operating context. Cost ImProper Maintenance Effect of improper maintenance is reflected in terms of financial loss due to many factors. These are –  Increase in machine down time,  Loss of production,  Loss of potential sales,  Idle man power - direct and indirect labours  Feeding delays - stopping of the further lines.  Increased scrap of off-standard unit.  Quality loss, Customer's dissatisfaction possible delays  Loss of goodwill and Actual cost of repair of equipment. What is Maintenance Management “Organizing Maintenance Operation” Objectives of a Maintenance Management System:1. To provide a Maintenance Management programme that will allow maximum operating time and use of facilities, at a min. maintenance cost and with proper protection of capital investment. 2. To provide a means of collecting cost and other information that will be useful in improving maintenance and other performance. 3. To establish methods of evaluating work performance which will be useful to management in general and to maintenance engineer in particular. 4. To improve safe working conditions for both operating department and maintenance personnel by establishing and keeping proper maintenance standards. Basic element of a general Management System 1) Establishing policies & objective 2) Defining responsibilities and authority. 3) Planning actions. 4) Setting up accounting and budgeting procedures. 5) Securing and controlling funds. 6) Staffing and training. 7) Detailing and defining work groups. 8) Conducting performance review and evaluation. WMS/CMMS: Tried at generation (CMMS was implemented at SBI & CCPP during 1990) but  could not sustain primarily due to its non-linkage  of data entry with the direct business process, non  integration with associated business processes &  subsequently software functional limitation &  technology obsolescence. EAM: In the long term & present requirement of  the integration of various function, a mid range  solution (EAM) allowing to fulfill present needs & remaining scalable for future enhancement &  further seamless integration. ERP: Present implementation & design shall be  adaptable to migrate to ERP solution in future. Streamlining CMMS Broad Interface for CMMS Features  Maintenance requests/orders can be created online by operation/production operators manually.  “Or” are triggered automatically by time based preventive maintenance schedules already fed to the system.  “Or” are triggered based on the operating parameters or Measurement data entered going beyond specified limits.(Condition based maintenance request)  Maintenance requests/orders can be viewed/accepted by maintenance crew from their computer node.  Further Isolation/permission required to work with operating staff is communicated on their nodes.  Work completion can be notified online  Data related to manpower used, work carried out,spares used are entered in to a system by maintenance staff to create maintenance history for the equipment Advantages-CMMS Facilitates  Work order management  Work crew planning & scheduling  Resources planning & scheduling  Maintenance schedule/period planning  Authorization planning  Ready details available from system for parameters, equipment details, grouping structure,analysis & review, history details for defect or equipment, trouble shooting, Standard operating/maintenance procedures, critical spares details,drawing details,actual resource consumption,contract work details,shut down jobs/ project work details,inspection/lubrication schedules,safety guidelines, safety permits & line clearance permit details,work execution & completion details, material planning,planned cost v/s actual cost for work order STATUTORY REQUIREMENTS FOR TRAINED MANPOWER Introduction About the Indian Electricity Rules, 1956 The Indian Electricity (IE) Rules, 1956 was enacted as per section 37 of the Indian Electricity Act. 1910 in order to regulate the generation, transmission, supply and use of electrical energy and generally to carry out the purposes and objects of the above said Act. The IE Rules, 1956 is a 143 rules document with eleven chapters and fourteen Annexure. Some of the salient features of IE rules are being discussed below: Salient Features of Indian Electricity Rules, 1956: 1. 2. 3. 4. 5. 6. 7. 8. 9. Chapter-1 highlights the preliminary definitions to be used hereby in the document. Chapter-2 highlights the functions and responsibilities of an electrical inspector and the requirements for the same. Chapter-3 highlights the role of the license and states the limits for the area of supply for the licensee. Chapter-4 and Chapter-5 envisages upon the general safety requirements and general conditions relating to the supply and use of electricity respectively. Chapter- 6 deals with the electric supply lines, systems and apparatus for low and medium voltages; while Chapter-7 deals the same for high and extra high voltages. Chapter-8 deals with the technical requirements to be met by the laying down of the overhead lines. Chapter-9 gives the rules to be followed for lying down of electric traction. Chapter-10 deals with the additional precautions to be adopted in mines and oil fields. Chapter-11 discusses the various miscellaneous activities, ranging from relaxation by government and inspector to various penalties to be imposed for the breach of rules. In lieu with the captive generation being taken up after the enactment of Indian Electricity Act, 2003, it is necessary to discuss Article 3 (2A). Article 3 (2A): “a) No person shall be authorized to operate or undertake maintenance of any part or whole of a generating station of capacity 100MW and above together with the associated sub-station unless he is adequately qualified and has successfully undergone the type of training specified in Annexure XIV; Provided that the provisions contained in this sub-rule shall have effect in respect of the persons already authorized to operate or undertake maintenance of any part or whole of a generating station as aforesaid from the date to be specified by the appropriate Government, but such a date shall not be later than a period of 4[6 years 2 months] from the date this rule comes into force; (b)The appropriate Government may, on the recommendations of the owner of such generating station, relax the conditions stipulated in clause (a) of this sub-rule for any engineer and such other person who have already sufficient experience in the operation and maintenance of a generating station; (c)The owner of a generating station, in consultation with Central Electricity Authority may alter the duration and manner of training in respect of those persons who have already been engaged in the operation and maintenance of a generating station or a substation;” Article- 3 (2B) “The provisions contained in rule 3(2A) will also be applicable in respect of other sub-stations of 132KV and above from a date to be specified by the appropriate Government but such a date shall not be later than 3 years from which this rule comes into force;” The training aspects of the personnel in various generating stations are discussed in the Annexure XIV of the IE rules, 1956. Annexure- XIV “The owner of every generating station of capacity of 100MW and above shall arrange for training of personnel engaged in the operation and maintenance of his generating station, in the manner specified below:(1) (A) The training may be arranged in his own institute or any other institute established for this purpose. (b) Any institute where such training is arranged shall have been recognized by the Central Electricity Authority. (2) There shall be separate training courses for the persons to be engaged in operation and maintenance of thermal power stations and hydro power stations together with associated sub-stations. In respect of thermal stations, separate course may be arranged for the operating and supervisory staff and other skilled persons who are to assist them. (3) Refresher courses shall be arranged periodically for the persons who have already undergone training under and those who have already sufficient experience in the operation and maintenance of a generating station and are engaged in its operation and maintenance under clause (b) of sub-rule 2(A) of rule 3 to familiarize with modern practices of operation and maintenance. The content and duration of training in the thermal power stations is discussed in the later part of the Annexure- XIV: The duration of the training courses for the operating supervisory staff (both electrical and mechanical) shall not be less than 12 months.(186 hours) The duration of the training course for the skilled person to assist the operators and supervisory staff in a thermal power stations shall not be less than nine month.(82 hours) The duration of the training course for the operation and supervisory staff to work in hydro power stations shall not be less than nine months.(124 hours) The duration of the training course for operation and maintenance of the sub-station associated with the generating station shall not be less than six months. The duration and contents of the refresher course shall be determined jointly by the owner of the generating station and the training institute. Trained Manpower in Power Sector: The main objective of electricity industry is to achieve customer satisfaction through generation of electricity of the right quality and quantity at an affordable cost and supply to the consumers efficiently whenever and wherever required. Trained manpower is required at every stage of planning, design, engineering, procurement, handling and storage, commissioning, operation and maintenance of power • • • • • plants, sale of energy and collection of revenue. The growing concern over environmental degradation and depletion of the conventional energy sources has made the task more challenging. Due to the introduction of more sophisticated technology and automation, the Man/MW ratio is declining. The Man/MW ratio in thermal sector in India has declined from 4.71 in the Sixth plan to less than 2.0 in the Ninth plan. In the hydro sector too, the Man/MW ratio has come down from 6.04 in the Sixth plan to 2.0 in the Ninth plan. The same trend is evident in terms of the number of personnel/million units supplied - declining from 4.6 in 1992-93 to 2.5 in 2000-2001, a 45% decrease in eight years. This indicates the increasing importance of each individual, which in turn makes manpower quality criteria more demanding. Added to this is the fact that electricity industry is a highly capital intensive industry. This necessitates the operation of the plants and equipment in the most safe and efficient manner to minimize the cost of supply. To survive in this competitive market, organizations will have to challenge the existing core beliefs, processes and methodologies and focus on hands-on learning to inculcate the necessary knowledge, skills and attitudes in their personnel. Excerpts from the National Training Policy Basically three types of training infrastructures/facilities are available: i) Training institutes recognized by CEA for imparting statutory induction training. ii) Lineman Training Institutes iii) Other Training facility (Class/board rooms for refresher/management programs) including networking with academic/training institutions outside power sector. Decentralization of training, especially for the operational staff would be necessary. At the same time, expensive infrastructure need not be created at each plant level. There are thirty eight training institutes recognized by the Central Electricity Authority (CEA). These institutes mostly cater to the training needs of the thermal power stations. Other Training institutes at the National level includes National Power Training Institute, established a Centre for Advanced Management & Power Studies (CAMPS) at Faridabad. In addition to a number of short-term courses on Technology-Management interface, it also conducts a two-year full time MBA Program in Power Management. NPTI also conducts professional courses, integrating power-training experience with academics, like PDC & PGDC in Power Plant Engineering and B.E./B.Tech. in Power Engineering etc. These products should be gainfully utilized in the reforming power sector. Training Institutes in Power Sector recognized by CEA Region Owning Agency SL Name of the Institute A. Northern Region HINDALCO 1 Technical Training & Management Development Centre, HINDALCO, Renusagar, (U.P) Linemen Training Centre, Himachal Pradesh State Electricity Board, Solan (H.P.) Thermal 08/2008 Field Type Recognized up to HPSEB 2 T&D 08/2005 NHPC 3 4 5 6 NPTI 7 8 NTPC 9 10 11 12 13 Power Management Institute (PMI), Thermal, Hydro & 12/2007 Noida (U.P.) Power Management Employee Development Centre, Thermal 06/2009 Badarpur (Delhi) Employee Development Centre, Thermal 08/2008 Singrauli STPS, Singrauli (U.P.) Employees Development Centre, Thermal 08/2008 Rihand STPS, Rihand (U.P.) Employees Development Centre, Thermal 05/2009 National Capital Power Station, Dadri (U.P.) Employee Development Centre, 400KV Ballabgarh Sub-station, Ballabgarh (Haryana) Name of the Institute Employee Development Centre, 800/400/220 KV Sub-station, Kishenpur Thermal Training Institute, GGSSTPS, PSEB, Ropar (Punjab) Electricity Training Institute, U.P. Power Corporation Ltd, Lucknow (U.P.) Thermal Training Institute, Obra Thermal Power Station T&D 02/2005 NPTI (NR), Badarpur (Delhi) NPTI, Faridabad (Haryana) All Fields All Fields 10/2006 10/2009 Training Centre, Chamera Power Station -I, Chamba (H.P.) Training Centre Uri HEP, Baramulla (J&K) Training Centre, Salal HEP Udhampur (J&K) Training Centre Tanakpur Power Station, Champawat (Uttaranchal) Hydro Hydro Hydro Hydro 01/2008 04/2008 12/2007 12/2007 PGCIL 14 Region Owning Agency SL 15 Field Type T&D Recognized up to 02/2007 PSEB 16 UPPCL 17 UPRVUNL 18 B. Western Region Autonomous Society 19 Thermal 02/2007 T&D 02/2008 Thermal 04/2008 Centre for Research and Industrial Staff Performance Hydro 01/2008 CSEB 20 Power Generating Training Institute, Korba TPS, Chattsgarh SEB, Korba (East) (Chattsgarh) Koradi Training Centre, Koradi TPS, MSPGCL ,Kordi (Maharashtra) Training Research and Development Centre, Nashik TPS, MSEDCL, Nashik (Maharashtra) NPTI (WR), Nagpur (Maharashtra) Employees Development Centre, Korba STPS, Korba - 495 450 Employees Development Centre, Kawas GPS, Distt.Surat (Gujarat) Employee Development Centre, Vindhyachal STPS, Distt.Sidhi (M.P.) Employee Development Centre 400 KV Itarsi Sub-station, Itarsi (MP) Name of the Institute Thermal 03/2010 MAGAGENCO 21 MAHADISCOM 22 Thermal &T&D 07/2007 Thermal 03/2009 NPTI 23 NTPC 24 25 26 PGCIL 27 T&D 01/2007 Thermal Gas Thermal 06/2009 04/2007 08/2008 All Fields 05/2006 Region Owning Agency SL Field Type Recognized upto REL 28 Technical Training Centre, Dahanu TPS, Reliance Energy Ltd, Thane (Maharashtra) Reliance Energy Management Institute, Reliance Energy Ltd., Mumbai (Maharashtra) Versova Technical Training Centre, Reliance Energy Ltd, Mumbai Main Training Center Trombay Thermal Power Station, Tata Power Company, Mumbai (Maharashtra) Plant Training Centre, Bhira Hydro Generating Station, Bhira Plant Training Centre at Dharvi Receiving Station, Tata Power Company, Mumbai (Maharashtra) Thermal 09/2007 29 Power Management 05/2008 30 Tata Power Co. 31 Thermal 01/2009 Thermal 04/2007 32 33 Hydro Thermal 09/2007 04/2007 Torrent Power AEC 34 C. Southern Region APGENCO 35 KSEB 36 NLC 37 NPTI 38 39 NTPC 40 Training Centre Sabarmati PS, Torrent Power AEC, Ahmadabad (Gujarat) Thermal 03/2007 Training Institute, Vijay Wada TPS APGENCO, (AP) Power Engineers' Training & Research Centre, Moolamattom (KSEB) Thermal Power Station Training Centre, Neyveli (T.N.) Power System Training Institute, Bangalore (Karnataka) NPTI (SR), Neyveli (T.N.) Employee Development Centre, Ramagundam STPS, Distt. Karim Nagar (A.P.) Name of the Institute Thermal 11/2009 Thermal 11/2009 Thermal 05/2008 T&D Thermal and T&D Thermal 04/2007 07/2006 12/2008 Region Owning Agency SL Field Type Recognized upto PGCIL 41 TNEB 42 43 44 Thermal Training Institute, Vallur Camp North Chennai TPS, TNEB Hydro Training Institute, TNEB Kuthiraikalmedu, Distt. Erode (T.N.) Transmission and Sub-station Training & Development Institute, TNEB, Madurai (T.N.) Thermal Hydro T&D 03/2010 08/2009 06/2008 Employee Development Centre, 400KV Sub-station, Hyderabad (A.P.) T&D 10/2006 D. Eastern Region CESC Ltd, Kolkata 45 DVC 46 OPTCL 47 O&M Training Centre, CESC Ltd., Kolkata (WB) Training Institute at Chandrapura TPS, Distt. Bokaro (Jharkhand) Power Training Centre at Chandaka, Power Grid Corporation of Orissa Ltd., Bhubaneshwar (Orissa) Thermal 12/2006 Thermal 05/2009 T&D 12/2007 NPTI 48 NTPC 49 Orissa HPCL 50 SAIL 51 WBPDCL 52 Power Plant Training Simulator Centre at Bakreswar Thermal Power Station Thermal 05/2008 Central Power Training Institute at Rourekela (Orissa) Thermal 11/2008 OHP Training Centre, Orissa Hydro 02/2008 Employee Development Centre, Farakka STPS, Distt. Murshidabad Thermal 07/2007 NPTI(ER), Durgapur All Fields 06/2006 Categories of Training: • Training for the Foreman engaged in the operation and maintenance of thermal power stations. • Training for the Foreman engaged in the mechanical works of the thermal power stations. • Training for the Foreman engaged in the electrical works of the thermal power stations. • Training for the lineman for assisting the operation and maintenance of thermal power stations. • Training for the lineman engaged in mechanical works of the thermal power stations. • Training for the lineman engaged in the operation and maintenance of hydro-electric generating station. • Specialized training for the personnel engaged in the extra high voltage sub-station. The main thrust in the training of a foreman lies in operation, control and supervision of boilers, turbines, excitation systems, auxiliaries and other major equipments of a thermal power plant. Also, the focus will be on the conceptual orientation of generators, turbines, fault analysis and protection of transformers. The main thrust in the training of operating and supervisory staff lies in the conceptual orientation of modern thermal power stations, its layout, construction details of various boilers and turbines. Along with major equipments, the training is provided for the maintenance of all the auxiliaries in the power stations. Also, the trainee is well equipped with the Indian Boiler Rules, Factory Act, Indian Electricity Act, 1910. The other part of the training revolves around the following areas: • Coal Handling Plant. • Details of switchgear engineering. • Basic flow diagrams in a power plant- fuel cycle, air and gas cycle, bearing cooling systems • Principles of material management and inventory control. The training for the operating personnel in a hydro station undergoes a specialized course of which the following are the highlights: • Concept of a modern hydro station. • Hydraulic systems- reservoirs, surge tanks, water tunnels, penstocks. • Types of water turbines. • Specifications of generators- Types and ratings. • Protection of generators and transformers • Excitation systems. • Statutory Electricity Acts and Rules The assessment for all the training courses is on the basis of 100 marks. Training for Franchise Development: The training institutes/organizations have often not taken up the task of marketing training as a major element of personnel management system aimed at raising the productivity within an organization. Training Institutes and training managers must consider training as a service they are offering to the various customers, which need to be marketed like any other service. The principles of marketing a service effectively hence, need to be used extensively by them. Creation of awareness about availability of training facilities shall be the first step in this direction. The second step will be to highlight the contribution of training towards improving productivity of individuals and thereby organizations. Training Institutes should evolve a mechanism to be in constant touch with the customer organizations to continuously upgrade, match the course contents with the specific needs of the organization and use innovative methods to deliver the training inputs. Looking Ahead in the Eleventh Plan (2007-2012): With the enactment of the Act, the message is clear that major emphasis would be laid on private developers and to mitigate the challenges posed by the competitors, firms would invest heavily in manpower. Therefore, the training and development programs will be accounting for at least 1.5 % of the total investment in the power sector. Factory Act The workings of the factories act, 1934, which was in operation prior to 1948, was found unsatisfactory & its provision inadequate in the changed conditions of growing industrial activities. Hence the comprehensive factories act was enacted in 1948 to ensure adequate safety measures & to promote the health & welfare of the workers employed in factories. It also seeks to prevent haphazard growth of factories through the provisions therein relating to the approval of the plans by the chief inspector of factories before the erection of a factory building is started. The extends to the whole of India & applies to all establishments employing 20 or more workers where power is used & to establishments employing 20 or more workers where power is not used. The main provisions of the act, inter alia, relate to (i) health, safety & welfare; (ii) hours of work; (iii) employment of young persons & women; (iv) annual leave with wages; (v) occupational diseases; (vi) administration; (vii) enforcement; and (viii) penalties for offences. The detailed provisions on the above aspects are fairly exhaustive. Factories employing 500 or more workers are required to appoint Labor Welfare officers to look after the welfare of workers. The state Govt. is empowered to prescribe the duties, qualifications & service conditions of these officers. It is also empowered to order the management of any factory or class of factories to associate the representatives of employees in matters relating to provision of welfare facilities. Under the act, the maximum hours of work for adult workers have been fixed at 48 hours per week, and 8 hours per day spread over 10½ hours in a day, inclusive of intervals. Employment of women and children (below 17 years) is prohibited during the night (7pm to 6pm) Energy Conservation and its Importance Coal and other fossil fuels, which have taken three million years to form, are likely to deplete soon. In the last two hundred years, we have consumed 60% of all resources. For sustainable development, we need to adopt energy efficiency measures. Today, 85% of primary energy comes from non-renewable and fossil sources (coal, oil, etc.). These reserves are continually diminishing with increasing consumption and will not exist for future generations What is Energy Conservation? Energy Conservation and Energy Efficiency are separate, but related concepts. Energy conservation is achieved when growth of energy consumption is reduced, measured in physical terms. Energy Conservation can, therefore, is the result of several processes or developments, such as productivity increase or technological progress. On the other hand Energy efficiency is achieved when energy intensity in a specific product, process or area of production or consumption is reduced without affecting output, consumption or comfort levels. Promotion of energy efficiency will contribute to energy conservation and is therefore An integral part of energy conservation promotional policies. Energy efficiency is often viewed as a resource option like coal, oil or natural gas. It provides additional economic value by preserving the resource base and reducing pollution. For example, replacing traditional light bulbs with Compact Fluorescent Lamps (CFLs) means you will use only 1/4th of the energy to light a room. Pollution levels also reduce by the same amount. Nature sets some basic limits on how efficiently energy can be used, but in most cases our products and manufacturing processes are still a long way from operating at this theoretical limit. Very simply, energy efficiency means using less energy to perform the same function. Although, energy efficiency has been in practice ever since the first oil crisis in 1973, it has today assumed even more importance because of being the most cost-effective and reliable means of mitigating the global climatic change. Recognition of that potential has led to high expectations for the control of future CO2 emissions through even more energy efficiency improvements than have occurred in the past. The industrial sector accounts for some 41 per Cent of global primary energy demand and approximately the same share of CO2 emissions. Policy Framework - Energy Conservation Act - 2001 With the background of high energy saving potential and its benefits, bridging the gap between demand and supply, reducing environmental emissions through energy saving, and to effectively overcome the barrier, the Government of India has enacted the Energy conservation Act - 2001. The Act provides the much-needed legal framework and institutional arrangement for embarking on an energy efficiency drive. Under the provisions of the Act, Bureau of Energy Efficiency has been established with effect from 1st March 2002 by merging erstwhile Energy Management Centre of Ministry of Power. The Bureau would be responsible for implementation of policy programmes and coordination of implementation of energy conservation activities. Energy Conservation Opportunities in Boiler The various energy efficiency opportunities in boiler system can be related to combustion, heat transfer, avoidable losses, high auxiliary power consumption, water quality and lowdown. Examining the following factors can indicate if a boiler is being run to maximize its efficiency: 1. Stack Temperature The stack temperature should be as low as possible. However, it should not be so low that water vapour in the exhaust condenses on the stack walls. This is important in fuels containing significant sulphur as low temperature can lead to sulphur dew point corrosion. Stack temperatures greater than 200°C indicates potential for recovery of waste heat. It also indicates the scaling of heat transfer/recovery equipment and hence the urgency of taking an early shut down for water / flue side cleaning. 2. Feed Water Preheating using Economiser Typically, the flue gases leaving a modern 3-pass shell boiler are at temperatures of 200 to 300 °C. Thus, there is a potential to recover heat from these gases. The flue gas exit tempera-true from a boiler is usually maintained at a minimum of 200 °C, so that the sulphur oxides in The flue gases do not condense and cause corrosion in heat transfer surfaces. When a clean fuel Such as natural gas, LPG or gas oil is used, the economy of heat recovery must be worked out, and as the flue gas temperature may be well below 200 °C. The potential for energy saving depends on the type of boiler installed and the fuel used. For a typically older model shell boiler, with a flue gas exit temperature of 260 °C, an economizer could be used to reduce it to 200 °C, increasing the feed water temperature by 15 °C. Increase in overall thermal efficiency would be in the order of 3%. For a modern 3-pass shell boiler firing natural gas with a flue gas exit temperature of 140 °C a condensing economizer would reduce the exit temperature to 65 °C increasing thermal efficiency by 5%. 3. Combustion Air Preheat Combustion air preheating is an alternative to feed water heating. In order to improve thermal Efficiency by 1%, the combustion air temperature must be raised by 20 °C. Most gas and oil Burners used in a boiler plant are not designed for high air preheats temperatures. Modern burners can withstand much higher combustion air preheat, so it is possible to consider such units as heat exchangers in the exit flue as an alternative to an economizer, when neither pace or a high feed water return temperature make it viable. 4. Incomplete Combustion Incomplete combustion can arise from a shortage of air or surplus of fuel or poor distribution of fuel. It is usually obvious from the colour or smoke, and must be corrected immediately. In the case of oil and gas fired systems, CO or smoke (for oil fired systems only) with normal or high excess air indicates burner system problems. A more frequent cause of incomplete combustion is the poor mixing of fuel and air at the burner. Poor oil fires can result from improper viscosity, worn tips, carbonization on tips and deterioration of diffusers or spinner Plates. With coal firing, unburned carbon can comprise a big loss. It occurs as grit carry-over or carbon-inash and may amount to more than 2% of the heat supplied to the boiler. Non uniform fuel size could be one of the reasons for incomplete combustion. In chain grate stokers, large lumps will not burn out completely, while small pieces and fines may block the air passage, thus causing poor air distribution. In sprinkler stokers, stoker grate condition, fuel distributors, wind box air regulation and over-fire systems can affect carbon loss. Increase in the fines in pulverized coal also increases carbon loss. 5. Excess Air Control Excess air is required in all practical cases to ensure complete combustion, to allow for the Normal variations in combustion and to ensure satisfactory stack conditions for some fuels. The optimum excess air level for maximum boiler efficiency occurs when the sum of the losses due to incomplete combustion and loss due to heat in flue gases is minimum. This level varies with furnace design, type of burner, fuel and process variables. It can be determined by conducting tests with different air fuel ratios. 6. Radiation and Convection Heat Loss The external surfaces of a shell boiler are hotter than the surroundings. The surfaces thus lose Heat to the surroundings depending on the surface area and the difference in temperature Between the surface and the surroundings. The heat loss from the boiler shell is normally a fixed energy loss, irrespective of the boiler output. With modern boiler designs, this may represent only 1.5% on the gross calorific value at full rating, but will increase to around 6%, if the boiler operates at only 25 percent output. Repairing or augmenting insulation can reduce heat loss through boiler walls and piping. 7. Automatic Blow down Control Uncontrolled continuous blow down is very wasteful. Automatic blow down controls can be Installed that sense and respond to boiler water conductivity and pH. A 10% blow down in a 15kg/cm2 boiler results in 3% efficiency loss. 8. Reduction of Scaling and Soot Losses In oil and coal-fired boilers, soot build-up on tubes acts as an insulator against heat transfer. Any such deposits should be removed on a regular basis. Elevated stack temperatures may indicate excessive soot build-up. Also same result will occur due to scaling on the water side. High exit gas temperatures at normal excess air indicate poor heat transfer performance. This condition can result from a gradual build-up of gas-side or waterside deposits. Waterside deposits require a review of water treatment procedures and tube cleaning to remove deposits. An estimated 1% efficiency loss occurs with every 22 °C increase in stack temperature. Stack temperature should be checked and recorded regularly as an indicator of soot deposits. When the flue gas temperature rises about 20 °C above the temperature for a newly cleaned boiler, it is time to remove the soot deposits. It is, therefore, recommended to install a dial type thermometer at the base of the stack to monitor the exhaust flue gas temperature. It is estimated that 3 mm of soot can cause an increase in fuel consumption by 2.5% due to increased flue gas temperatures. Periodic off-line cleaning of radiant furnace surfaces, boiler Tube banks, economizers and air heaters may be necessary to remove stubborn deposits. 9. Reduction of Boiler Steam Pressure This is an effective means of reducing fuel consumption, if permissible, by as much as 1 to 2%. Lower steam pressure gives a lower saturated steam temperature and without stack heat Recovery, a similar reduction in the temperature of the flue gas temperature results. Steam is generated at pressures normally dictated by the highest pressure / temperature requirements for a particular process. In some cases, the process does not operate all the time, and there are periods when the boiler pressure could be reduced. The energy manager should consider pressure reduction carefully, before recommending it. Adverse effects, such as an increase in water carryover from the boiler owing to pressure reduction, may negate any potential saving. Pressure should be reduced in stages, and no more than a 20 percent reduction should be considered. 10. Variable Speed Control for Fans, Blowers and Pumps Variable speed control is an important means of achieving energy savings. Generally, combustion air control is affected by throttling dampers fitted at forced and induced draft fans. Though dampers are simple means of control, they lack accuracy, giving poor control characteristics at the top and bottom of the operating range. In general, if the load characteristic of the boiler is variable, the possibility of replacing the dampers by a VSD should be evaluated. 11. Effect of Boiler Loading on Efficiency The maximum efficiency of the boiler does not occur at full load, but at about two-thirds of the full load. If the load on the boiler decreases further, efficiency also tends to decrease. At zero output, the efficiency of the boiler is zero, and any fuel fired is used only to supply the losses. The factors affecting boiler efficiency are: • As the load falls, so does the value of the mass flow rate of the flue gases through the tubes. This reduction in flow rate for the same heat transfer area reduced the exit flue gas temperatures by a small extent, reducing the sensible heat loss. • Below half load, most combustion appliances need more excess air to burn the fuel Completely. This increases the sensible heat loss In general, efficiency of the boiler reduces significantly below 25% of the rated load and as far as possible, and operation of boilers below this level should be avoided 12. Proper Boiler Scheduling Since, the optimum efficiency of boilers occurs at 65–85% of full load, it is usually more Efficient, on the whole, to operate a fewer number of boilers at higher loads, than to operate a Large number at low loads. 13. Boiler Replacement The potential savings from replacing a boiler depend on the anticipated change in overall Efficiency. A change in a boiler can be financially attractive if the existing boiler is: _ Old and inefficient _ Not capable of firing cheaper substitution fuel _ Over or under-sized for present requirements _ Not designed for ideal loading conditions The feasibility study should examine all implications of long-term fuel availability and Company growth plans. All financial and engineering factors should be considered. Since boiler plants traditionally have a useful life of well over 25 years, replacement must be carefully studied. Energy Saving Opportunities in steam 1. Monitoring Steam Traps For testing a steam trap, there should be an isolating valve provided in the downstream of the trap and a test valve shall be provided in the trap discharge. When the test valve is opened, the following points have to be observed: Condensate discharge––Inverted bucket and thermodynamic disc traps should have intermittent condensate discharge. Float and thermostatic traps should have a continuous ondensate discharge. Thermostatic traps can have either continuous or intermittent discharge depending upon the load. If inverted bucket traps are used for extremely small load, it will have a continuous condensate discharge. Flash steam––This shall not be mistaken for a steam leak through the trap. The users sometimes get confused between a flash steam and leaking steam. The flash steam and the leaking steam can be approximately identified as follows: • If steam blows out continuously in a blue stream, it is a leaking steam. • If a steam floats out intermittently in a whitish cloud, it is a flash steam. 2. Continuous steam blow and no flow indicate, there is a problem in the trap Whenever a trap fails to operate and the reasons are not readily apparent, the discharge from the trap should be observed. A step-by-step analysis has to be carried out mainly with reference to lack of discharge from the trap, steam loss, continuous flow, sluggish heating, to find out whether it is a system problem or the mechanical problem in the steam trap. 3. Avoiding Steam Leakages Steam leakage is a visible indicator of waste and must be avoided. It has been estimated that a 3 mm diameter hole on a pipeline carrying 7 kg/cm2 steam would waste 33 KL of fuel oil per year. Steam leaks on high-pressure mains are prohibitively costlier than on low pressure mains. Any steam leakage must be quickly attended to. In fact, the plant should consider a regular surveillance programme for identifying leaks at pipelines, valves, flanges and joints. Indeed, by plugging all leakages, one may be surprised at the extent of fuel savings, which may reach upto 5% of the steam consumption in a small or medium scale industry or even higher in installations having several process departments. To avoid leaks it may be worthwhile considering replacement of the flanged joints which are rarely opened in old plants by welded joints. 4. Providing Dry Steam for Process The best steam for industrial process heating is the dry saturated steam. Wet steam reduces total heat in the steam. Also water forms a wet film on heat transfer and overloads traps and Condensate equipment. Super heated steam is not desirable for process heating because it gives up heat at a rate slower than the condensation heat transfer of saturated steam. It must be remembered that a boiler without a super heater cannot deliver perfectly dry saturated steam. At best, it can deliver only 95% dry steam. The dryness fraction of steam depends on various factors, such as the level of water to be a part of the steam. Indeed, even as simple a thing as improper boiler water treatment can become a cause for wet steam. As steam flows through the pipelines, it undergoes progressive condensation due to the loss of heat to the colder surroundings; the extent of the condensation depends on the effectiveness of the lagging. For example, with poor lagging, the steam can become excessively wet. Since dry saturated steam is required for process equipment, due attention must be paid to the boiler operation and lagging of the pipelines. Wet steam can reduce plant productivity and product quality, and can cause damage to most items of plant and equipment. Whilst careful drainage and trapping can remove most of the water, it will not deal with the water droplets suspended in the steam. To remove these suspended water droplets, separators are installed in steam pipelines. 5. Utilising Steam at the Lowest Acceptable Pressure for the Process A study of the steam tables would indicate that the latent heat in steam reduces as the steam pressure increases. It is only the latent heat of steam, which takes part in the heating process When applied to an indirect heating system. Thus, it is important that its value be kept as high as possible. This can only be achieved if we go in for lower steam pressures. As a guide, the steam should always be generated and distributed at the highest possible pressure, but utilized at as low a pressure as possible since it then has higher latent heat. However, it may also be seen from the steam tables that the lower the steam pressure, the lower will be its temperature. Since temperature is the driving force for the transfer of heat at lower steam pressures, the rate of heat transfer will be slower and the processing time greater. In equipment where fixed losses are high (e.g. big drying cylinders), there may even be an increase in steam consumption at lower pressures due to increased processing time. There are, however, several equipment in certain industries where one can profitably go in for lower Pressures and realize economy in steam consumption without materially affecting production time. Therefore, there is a limit to the reduction of steam pressure. Depending on the equipment design, the lowest possible steam pressure with which the equipment can work should be selected without sacrificing either on production time or on steam consumption. 6. Proper Utilization of Directly Injected Steam The heating of a liquid by direct injection of steam is often desirable. The equipment required is relatively simple, cheap and easy to maintain. No condensate recovery system is necessary. The heating is quick, and the sensible heat of the steam is also used up along with the latent heat, making the process thermally efficient. In processes where dilution is not a problem, heating is done by blowing steam into the liquid (i.e.) direct steam injection is applied. If the dilution of the tank contents and agitation are not acceptable in the process (i.e.)direct steam agitation are not acceptable, indirect steam heating is the only answer. Ideally, the injected steam should be condensed completely as the bubbles rise through the liquid. This is possible only if the inlet steam pressures are kept very low-around 0.5 kg/cm2 -and certainly not exceeding 1kg/cm2. If pressures are high, the velocity of the steam bubbles will also be high and they will not get sufficient time to condense before they reach the surface. 7. Minimising Heat Transfer Barriers The metal wall may not be the only barrier in a heat transfer process. There is likely to be a film of air, condensate and scale on the steam side. On the product side there may also be baked-on product or scale, and a stagnant film of product. Agitation of the product may eliminate the effect of the stagnant film, whilst regular cleaningon the product side should reduce the scale. 8. Proper Air Venting When steam is first admitted to a pipe after a period of shutdown, the pipe is full of air. Further amounts of air and other non-condensable gases will enter with the steam, although the proportions of these gases are normally very small compared with the steam. When the steam condenses, these gases will accumulate in pipes and heat exchangers. Precautions should be taken to discharge them. The consequence of not removing air is a lengthy warming up period, and a reduction in plant efficiency and process performance. Air in a steam system will also affect the system temperature. Air will exert its own pressure within the system, and will be added to the pressure of the steam to give a total pressure. Therefore, the actual steam pressure and temperature of the steam/air mixture will be lower than that suggested by a pressure gauge. Of more importance is the effect air has upon heat transfer. A layer of air only 1 mm thick can offer the same resistance to heat as a layer of water 25 μm thick, a layer of iron 2 mm thick or a layer of copper 15 mm thick. It is very important therefore to remove air from any steam system. Automatic air vents for steam systems (which operate on the same principle as thermostatic steam traps) should be fitted above the condensate level so that only air or steam/air mixtures can reach them. The discharge from an air vent must be piped to a safe place. In practice, a condensate line falling towards a vented receiver can accept the discharge from an air vent. In addition to air venting at the end of a main, air vents should also be fitted 9. Condensate Recovery The steam condenses after giving off its latent heat in the heating coil or the jacket of the Process equipment. A sizable portion (about 25%) of the total heat in the steam leaves the Process equipment as hot water. 10. Insulation of Steam Pipelines and Hot Process Equipments Heat can be lost due to radiation from steam pipes. As an example while lagging steam pipes, It is common to see leaving flanges uncovered. An uncovered flange is equivalent to leaving 0.6 metre of pipe line unlagged. If a 0.15 m steam pipe diameter has 5 uncovered flanges, there would be a loss of heat equivalent to wasting 5 tons of coal or 3000 litres of oil a year. This is usually done to facilitate checking the condition of flange but at the cost of considerable heat loss. The remedy is to provide easily detachable insulation covers, which can be easily removed when necessary. The various insulating materials used are cork, Glass wool, Rock wool and Asbestos. 11. Flash Steam Recovery Flash steam is produced when condensate at a high pressure is released to a lower pressure and can be used for low pressure heating. The higher the steam pressure and lower the flash steam pressure the greater the quantity of flash steam that can be generated. In many cases, flash steam from high pressure equipments is made use of directly on the low pressure equipments to reduce use of steam through pressure reducing valves. 12. Reducing the Work to be done by Steam The equipments should be supplied with steam as dry as possible. The plant should be made efficient. For example, if any product is to be dried such as in a laundry, a press could be used to squeeze as much water as possible before being heated up in a dryer using steam. therefore, to take care of the above factors, automatic draining is essential and can be achieved by steam traps. The trap must drain condensate, to avoid water hammer, thermal shock and reduction in heat transfer area. The trap should also evacuate air and other non-condensable gases, as they reduce the heat transfer efficiency and also corrode the equipment. Thus, a steam trap is an automatic valve that permits passage of condensate, air and other non-condensable gases from steam mains and steam using equipment, while preventing the loss of steam in the distribution system or equipment. TIPS FOR ENERGY EFFICIENCY IN THERMAL UTILITIES Boilers • Preheat combustion air with waste heat. (22°C reduction in flue gas temperature increases boiler efficiency by 1%) • Use variable speed drives on large boiler combustion air fans with variable flows. • Burn wastes if permitted. • Insulate exposed heated oil tanks. • Clean burners, nozzles, strainers, etc. • Inspect oil heaters for proper oil temperature. • Close burner air and/or stack dampers when the burner is off to minimize heat loss up the stack. • Improve oxygen trim control (e.g. -- limit excess air to less than 10% on clean fuels). (5% reduction in excess air increases boiler efficiency by 1% or: 1% reduction of residual oxygen in stack gas increases boiler efficiency by 1%) • Automate/optimize boiler blow down. Recover boiler blow down heat. • Use boiler blow down to help warm the back-up boiler. • Optimize deaerator venting. • Inspect door gaskets. • Inspect for scale and sediment on the water side. (A 1 mm thick scale (deposit) on the water side could increase fuel consumption by 5 to 8%.) • Inspect for soot, fly ash, and slag on the fire side. (A 3 mm thick soot deposition on the heat transfer surface can cause an increase in fuel Consumption to the tune of 2.5%) • Optimize boiler water treatment. • Add an economizer to preheat boiler feed water using exhaust heat. • Recycle steam condensate. • Study part-load characteristics and cycling costs to determine the most-efficient mode for Operating multiple boilers. • Consider multiple or modular boiler units instead of one or two large boilers. • Establish a boiler efficiency-maintenance program. Start with an energy audit and follow-up, then make a boiler efficiency-maintenance program a part of your continuous energy Management program. Steam System • Fix steam leaks and condensate leaks. (A 3 mm diameter hole on a pipe line carrying 7 Kg/cm2 steam would waste 33 Kilo litres of fuel oil per year) • Accumulate work orders for repair of steam leaks that can't be fixed during the heating season due to system shutdown requirements. Tag each such leak with a durable tag with a good description. • Use back pressure steam turbines to produce lower steam pressures. • Use more-efficient steam desuperheating methods. • Ensure process temperatures are correctly controlled. • Maintain lowest acceptable process steam pressures. • Reduce hot water wastage to drain. • Remove or blank off all redundant steam piping. • Ensure condensate is returned or re-used in the process. (6°C raise in feed water temperature by economiser/condensate recovery corresponds to a 1% saving in fuel consumption, in boiler) • Preheat boiler feed-water. • Recover boiler blow down. • Check operation of steam traps. • Remove air from indirect steam using equipment (0.25 mm thick air film offers the same resistance to heat transfer as a 330 mm thick copper Wall) • Inspect steam traps regularly and repair malfunctioning traps promptly. • Consider recovery of vent steam (e.g. -- on large flash tanks). • Use waste steam for water heating. • Use an absorption chiller to condense exhaust steam before returning the condensate to the boiler. • Use electric pumps instead of steam ejectors when cost benefits permit • Establish a steam efficiency-maintenance program. Start with an energy audit and followup, then make a steam efficiency-maintenance program a part of your continuous energy management program. Furnaces • Check against infiltration of air: Use doors or air curtains • Monitor O2 /CO2/CO and control excess air to the optimum level • Improve burner design, combustion control and instrumentation. • Ensure that the furnace combustion chamber is under slight positive pressure • Use ceramic fibres in the case of batch operations • Match the load to the furnace capacity • Retrofit with heat recovery device • Investigate cycle times and reduce • Provide temperature controllers • Ensure that flame does not touch the stock Insulation • Repair damaged insulation. (A bare steam pipe of 150 mm diameter and 100 m length, carrying saturated steam at 8 kg/cm2 would waste 25,000 litres furnace oil in a year) • Insulate any hot or cold metal or insulation. • Replace wet insulation. • Use an infrared gun to check for cold wall areas during cold weather or hot wall areas during hot weather. • Ensure that all insulated surfaces are cladded with aluminium • Insulate all flanges, valves and couplings • Insulate open tanks (70% heat losses can be reduced by floating a layer of 45 mm diameter polypropylene (Plastic) balls on the surface of 90°C hot liquid/condensate) Waste heat recovery • Recover heat from flue gas, engine cooling water, engine exhaust, low pressure waste Steam, drying oven exhaust, boiler blow down, etc. • Recover heat from incinerator off-gas. • Use waste heat for fuel oil heating, boiler feed water heating, outside air heating, etc. • Use chiller waste heat to preheat hot water. • Use heat pumps. • Use absorption refrigeration. • Use thermal wheels, run-around systems, heat pipe systems, and air-to-air exchangers. THE CONTRACT LABOUR (REGULATION AND ABOLITION) ACT, 1970 ACT NO. 37 OF 19701 [5th September, 1970.] An Act to regulate the employment of contract labour in certain establishments and to provide for its abolition in certain circumstances and for matters connected therewith. PRELIMINARY 1. Short title, extent, commencement and application (1) This Act may be called the Contract Labour (Regulation and Abolition) Act, 1970. (2) It extends to the whole of India. (3) It shall come into force on such date 1* as the Central Government may, by notification in the Official Gazette, appoint and different dates may be appointed for different provisions of this Act. (4) It applies-(a) To every establishment in which twenty or more workmen are employed or were employed on any day of the preceding twelve months as contract labour; (b) to every contractor who employees or who employed on any day of the preceding twelve months twenty or more workmen: Provided that the appropriate Government may, after giving not less than two months' notice of its intention so to do, by notification in the Official Gazette, apply the provisions of this Act to any establishment or contractor employing such number of workmen less than twenty as may be specified in the notification. (5) (a) It shall not apply to establishments in which work only of an intermittent or casual nature is performed. (b) If a question arises whether work performed in an establishment is of an intermittent or casual nature, the appropriate Government shall decide that question after consultation with the Central Board or, as the case may be, a State Board, and its decision shall be final. Explanation. -- For the purpose of this sub-section, work performed in an establishment shall not be deemed to be of an intermittent nature: (i) if it was performed for more than one hundred and twenty days in the preceding twelve months, or (ii) if it is of a seasonal character and is performed for more than sixty days in a year. 2. Definitions. - (1) In this Act, unless the context otherwise requires,-- 2[(a) "appropriate Government" means,-(i) in relation to an establishment in respect of which the appropriate Government under the Industrial Disputes Act, 1947 (14 of 1947), is the Central Government, the Central Government; (ii) in relation to any other establishment, the Government of the State in which that other establishment is situated;] (b) a workman shall be deemed to be employed as "contract labour" in or in connection with the work of an establishment when he is hired in or in connection with such work by or through a contractor, with or without the knowledge of the principal employer; (c) "contractor", in relation to an establishment, means a person who undertakes to produce a given result for the establishment, other than a mere supply of goods of articles of manufacture to such establishment, through contract labour or who supplies contract labour for any work of the establishment and includes a sub-contractor; (d) "controlled industry" means any industry the control of which by the Union has been declared by any Central Act to be expedient in the public interest; (e) "establishment" means-(i) any office or department of the Government or a local authority, or (ii) any place where any industry, trade, business, manufacture or occupation is carried on; (f) "prescribed" means prescribed by rules made under this Act; (g) "principal employer" means-(i) in relation to any office or department of the Government or a local authority, the head of that office or department or such other officer as the Government or the local authority, as the case may be, may specify in this behalf, (ii) in a factory, the owner or occupier of the factory and where a person has been named as the manager of the factory under the Factories Act, 1948 (63 of 1948) the person so named, (iii) in a mine, the owner or agent of the mine and where a person has been named as the manager of the mine, the person so named, (iv) in any other establishment, any person responsible for the supervision and control of the establishment. (h) "wages" shall have the meaning assigned to it in clause (vi) of section 2 of the Payment of Wages Act, 1936 (4 of 1936); (i) "workman" means any person employed in or in connection with the work of any establishment to do any skilled, semiskilled or un-skilled manual, supervisory, or clerical work for hire or reward, whether the terms of employment be express or implied, but does not include any such person-(A) who is employed mainly in a managerial or administrative capacity; or (B) who, being employed in a supervisory capacity draws wages exceeding five hundred rupees per mensem or exercises, either by the nature of the duties attached to the office or by reason of the powers vested in him, functions mainly of a managerial nature; or (C) who is an out-worker, that is to say, a person to whom any articles or materials are given out by or on behalf of the Principal employer to be made up, cleaned, washed, altered, ornamented, finished, repaired, adapted or otherwise processed for sale for the purposes of the trade or business of the principal employer and the process is to be carried out either in the home of the out-worker or in some other premises, not being premises under the control and management of the principal employer. THE ADVISORY BOARDS 3. Central Advisory Board.- (1) The Central Government shall, as soon as may be, constitute a board to be called the Central Advisory Contract Labour Board (hereinafter referred to as the Central Board) to advise the Central Government on such matters arising out of the administration of this Act as may be referred to it and to carry out other functions assigned to it under this Act. (2) The Central Board shall consist of-(a) a Chairman to be appointed by the Central Government; (b) the Chief Labour Commissioner (Central), ex-officio; (c) such number of members, not exceeding seventeen but not less than eleven, as the Central Government may nominate to represent that Government, the Railways, the coal industry, the mining industry, the contractors, the workmen and any other interests which, the opinion of the Central Government, ought to be represented on the Central Board. (3) The number of persons to be appointed as members from each of the categories specified in sub-section (2), the term of office and other conditions of service of, the procedure to be followed in the discharge of their functions by, and the manner of filling vacancies among, the members of the Central Board shall be such as may be prescribed: Provided that the number of members nominated to represent the workmen shall not be less than the number of members nominated to represent the principal employers and the contractors. 4. State Advisory Board.(1) The State Government may constitute a board to be called the State Advisory Contract Labour Board (hereinafter referred to as the State Board) to advice the State Government on such matters arising out of the administration of this Act as may be referred to it and to carry out other functions assigned to it under this Act. (2) The State Board shall consist of-(a) a Chairman to be appointed by the State Government; (b) the Labour Commissioner, ex-officio, or in his absence any other officer nominated by the State Government in that behalf; (c) such number of members, not exceeding eleven but not less than nine, as the State Government may nominate to represent that Government, the industry, the contractors, the workmen and any other interests which, in the opinion of the State Government, ought to be represented on the State Board. (3) The number of persons to be appointed as members from each of the categories specified in sub-section (2), the term of office and other conditions of service of, the procedure to be followed in the discharge of their functions by, and the manner of filling vacancies among, the members of the State Board shall be such as may be prescribed: Provided that the number of members nominated to represent the workmen shall not be less than the number of members nominated to represent the principal employers and the contractors. 5. Power to constitute committees.(1) The Central Board or the State Board, as the case may be, may constitute such committees and for such purpose or purposes as it may think fit. (2) The committee constituted under sub-section (1) shall meet at such times and places and shall observe such rules of procedure in regard to the transaction of business at its meetings as may be prescribed. (3) The members of a committee shall be paid such fees and allowances for attending its meetings as may be prescribed: Provided that no fees shall, be payable to a member who is an officer of Government or of any corporation established by any law for the time being in force. REGISTRATION OF ESTABLISHMENTS EMPLOYING CONTRACT LABOUR 6. Appointment of registering officers.- The appropriate Government may, by an order notified in the Official Gazette-(a) appoint such persons, being Gazetted Officers of Government, as it thinks fit to be registering officers for the purposes of this Chapter; and (b) define the limits, within which a registering officer shall exercise the powers conferred on him by or under this Act. 7. Registration of certain establishments.(1) Every principal employer of an establishment to which this Act applies shall, within such period as the appropriate Government may, by notification in the Official Gazette, fix in this behalf with respect to establishments generally or with respect to any class of them, make an application to the registering officer in the prescribed manner for registration of the establishment: Provided that the registering officer may entertain any such application for registration after expiry of the period fixed in this behalf, if the registering officer is satisfied that the applicant was prevented by sufficient cause from making the application in time. (2) If the application for registration is complete in all respects, the registering officer shall register the establishment and issue to the principal employer of the establishment a certificate of registration containing such particulars as may be prescribed. 8. Revocation of registration in certain cases.- If the registering officer is satisfied, either on a reference made to him in this behalf or otherwise, that the registration of any establishment has been obtained by misrepresentation or suppression of any material fact, or that for any other reason the registration has become useless or ineffective and, therefore, requires to be revoked, the registering officer may, after giving an opportunity to the principal employer of the establishment to be heard and with the previous approval of the appropriate Government, revoke the registration. 9. Effect of non-registration.- No principal employer of an establishment, to which this Act applies, shall-(a) in the case of an establishment required to be registered under section 7, but which has not been registered within the time fixed for the purpose under that section, (b) in the case of an establishment the registration in respect of which has been revoked under section 8, employ contract labour in the establishment after the expiry of the period referred to in clause (a) or after the revocation of registration referred to in clause (b), as the case may be. 10. Prohibition of employment of contract labour.(1) Notwithstanding anything contained in this Act, the appropriate Government may, after consultation with the Central Board or, as the case may be, a State Board, prohibit, by notification in the Official Gazette, employment of contract labour in any process, operation or other work in any establishment. (2) Before issuing any notification under sub-section (1) in relation to an establishment, the appropriate Government shall have regard to the conditions of work and benefits provided for the contract labour in that establishment and other relevant factors, such as-(a) whether the process, operation or other work is incidental to, or necessary for the industry, trade, business, manufacture or occupation that is carried on in the establishment: (b) whether it is of perennial nature, that is to say, it is of sufficient duration having regard to the nature of industry, trade, business, manufacture or occupation carried on in that establishment; (c) whether it is done ordinarily through regular workmen in that establishment or an establishment similar thereto; (d) whether it is sufficient to employ considerable number of whole-time workmen. LICENSING OF CONTRACTORS 11. Appointment of licensing officers.-- The appropriate Government may, by an order notified in the Official Gazette,-(a) appoint such persons, being Gazetted Officers of Government, as it thinks fit to be licensing officers for the purposes of this Chapter; and (b) define the limits, within which a licensing officer shall exercise the powers conferred on licensing officers by or under this Act. 12. Licensing of contractors.(1) With effect from such date as the appropriate Government may, by notification in the Official Gazette, appoint, no contractor to whom this Act applies, shall undertake or execute any work through contract labour except under and in accordance with a licence issued in that behalf by the licensing officer. (2) Subject to the provisions of this Act, a licence under sub-section (1) may contain such conditions including, in particular, conditions as to hours of work, fixation of wages and other essential amenities in respect of contract labour as the appropriate Government may deem fit to impose in accordance with the rules, if any, made under section 35 and shall be issued on payment of such fees and on the deposit of such sum, if any, as security for the due performance of the conditions as may be prescribed. 13. Grant of licences.(1) Every application for the grant of a licence under sub-section (1) of section 12 shall be made in the prescribed form and shall contain the particulars regarding the location of the establishment, the nature of process, operation or work for which contract labour is to be employed and such other particulars as may be prescribed. (2) The licensing officer may make such investigation in respect of the application received under subsection (1) and in making any such investigation the licensing officer shall follow such procedure as may be prescribed. (3) A licence granted under this Chapter shall be valid for the period specified therein and may be renewed from time to time for such period and on payment of such fees and on such conditions as may be prescribed. 14. Revocation, suspension and amendment of licences.(1) If the licensing officer is satisfied, either on a reference made to him in this behalf or otherwise, that-(a) a licence granted under section 12 has been obtained by misrepresentation or suppression of any material fact, or (b) the holder of a licence has, without reasonable cause, failed to comply with the conditions subject to which the licence has been granted or has contravened any of the provisions of this Act or the rules made there under, then, without prejudice to any other penalty to which the holder of the licence may be liable under this Act, the licensing officer may, after giving the holder of the licence an opportunity of showing cause, revoke or suspend the licence or forfeit the sum, if any, or any portion thereof deposited as security for the due performance of the conditions subject to which the licence has been granted. (2) Subject to any rules that may be made in this behalf, the licensing officer may vary or amend a licence granted under section 12. 15. Appeal.(1) Any person aggrieved by an order made under section 7, section 8, section 12 or section 14 may, within thirty days from the date on which the order is communicated to him, prefer an appeal to an appellate officer who shall be a person nominated in this behalf by the appropriate Government: Provided that the appellate officer may entertain the appeal after the expiry of the said period of thirty days, if he is satisfied that the appellant was prevented by sufficient cause from filing the appeal in time. (2) On receipt of an appeal under sub-section (1), the appellate officer shall, after giving the appellant an opportunity of being heard dispose of the appeal as expeditiously as possible. WELFARE AND HEALTH OF CONTRACT LABOUR 16. Canteens.(1) The appropriate Government may make rules requiring that in every establishment-(a) to which this Act applies, (b) wherein work requiring employment of contract labour is likely to continue for such period as may be prescribed, and (c) wherein contract labour numbering one hundred or more is ordinarily employed by a contractor, one or more canteens shall be provided and maintained by the contractor for the use of such contract labour. (2) Without prejudice to the generality of the foregoing power, such rules may provide for-(a) the date by which the canteens shall be provided; (b) the number of canteens that shall be provided, and the standards in respect of construction, accommodation, furniture and other equipment of the canteens; and (c) the foodstuffs which may be served therein and the charges which may be made thereof. 17. Rest-rooms.(1) In every place wherein contract labour is required to halt at night in connection with the work of an establishment-(a) to which this Act applies, and (b) in which work requiring employment of contract labour is likely to continue for such period as may be prescribed, there shall be provided and maintained by the contractor for the use of the contract labour such number of rest-rooms or such other suitable alternative accommodation within such time as may be prescribed. (2) The rest rooms or the alternative accommodation to be provided under subsection (1) shall be sufficiently lighted and ventilated and shall be maintained in a clean and comfortable condition. 18. Other facilities.It shall be the duty of every contractor employing contract labour in connection with the work of an establishment to which this Act applies, to provide and maintain-(a) a sufficient supply of wholesome drinking water for the contract labour at convenient places; (b) a sufficient number of latrines and urinals of the prescribed types so situated as to be convenient and accessible to the contract labour in the establishment; and (c) washing facilities. 19. First-aid facilities.- There shall be provided and maintained by the contractor so as to be readily accessible during all working hours a first-aid box equipped with the prescribed contents at every place where contract labour is employed by him. 20. Liability of principal employer in certain cases.(1) If any amenity required to be provided under section 16, section 17, section 18 or section 19 for the benefit of the contract labour employed in an establishment is not provided by the contractor within the time prescribed thereof, such amenity shall be provided by the principal employer within such time as may be prescribed. (2) All expenses incurred by the principal employer in providing the amenity may be recovered by the principal employer from the contractor either by deduction from any amount payable to the contractor under any contract or as a debt payable by the contractor. 21. Responsibility for payment of wages.(1) A contractor shall be responsible for payment of wages to each worker employed by him as contract labour and such wages shall be paid before the expiry of such period as may be prescribed. (2) Every principal employer shall nominate a representative duly authorized by him to be present at the time of disbursement of wages by the contractor and it shall be the duty of such representative to certify the amounts paid as wages in such manner as may be prescribed. (3) It shall be the duty of the contractor to ensure the disbursement of wages in the presence of the authorized representative of the principal employer. (4) In case the contractor fails to make payment of wages within the prescribed period or makes short payment, then the principal employer shall be liable to make payment of wages in full or the unpaid balance due, as the case may be, to the contract labour employed by the contractor and recover the amount so paid from the contractor either by deduction from any amount payable to the contractor under any contract or as a debt payable by the contractor. PENALTIES AND PROCEDURE 22. Obstructions.(1) Whoever obstructs an inspector in the discharge of his duties under this Act or refuses or wilfully neglects to afford the inspector any reasonable facility for making any inspection, examination, inquiry or investigation authorized by or under this Act in relation to an establishment to which, or a contractor to whom, this Act applies, shall be punishable with imprisonment for a term which may extend to three months, or with fine which may extend to five hundred rupees, or with both. (2) Whoever wilfully refuses to produce on the demand of an inspector any register or other document kept in pursuance of this Act or prevents or attempts to prevent or does anything which he has reason to believe is likely to prevent any person from appearing before or being examined by an inspector acting in pursuance of his duties under this Act, shall be punishable with imprisonment for a term which may extend to three months, or with fine which may extend to five hundred rupees, or with both. 23. Contravention of provisions regarding employment of contract labour.- Whoever contravenes any provision of this Act or of any rules made there under prohibiting, restricting or regulating the employment of contract labour, or contravenes any condition of a licence granted under this Act, shall be punishable with imprisonment for a term which may extend to three months, or with fine which may extend to one thousand rupees, or with both, and in the case of a continuing contravention with an additional fine which may extend to one hundred rupees for every day during which such contravention continues after conviction for the first such contravention. 24. Other offences.- If any person contravenes any of the provisions of this Act or of any rules made there under for which no other penalty is elsewhere provided, he shall be punishable with imprisonment for a term which may extend to three months, or with fine which may extend to one thousand rupees, or with both. 25. Offences by companies.(1) If the person committing an offence under this Act is a company, the company as well as every person in charge of, and responsible to, the company for the conduct of its business at the time of the commission of the offence shall be deemed to be guilty of the offence and shall be liable to be proceeded against and punished accordingly: Provided that nothing contained in this sub-section shall render any such person liable to any punishment if he proves that the offence was committed without his knowledge or that he exercised all due diligence to prevent the commission of such offence. (2) Notwithstanding anything contained in sub-section (1), where an offence under this Act has been committed by a company and it is proved that the offence has been committed with the consent or connivance of, or that the commission of the offence is attributable to any neglect on the part of any director, manager, managing agent or any other officer of the company, such director, manager, managing agent or such other officer shall also be deemed to be guilty of that offence and shall be liable to be proceeded against and punished accordingly. 26. Cognizance of offences.- No court shall take cognizance of any offence under this Act except on a complaint made by, or with the previous sanction in writing of, the inspector and no court inferior to that of a Presidency Magistrate or a magistrate of the first class shall try any offence punishable under this Act. 27. Limitation of prosecutions.- No court shall take cognizance of an offence punishable under this Act unless the complaint thereof is made within three months from the date on which the alleged commission of the offence came to the knowledge of an inspector: Provided that where the offence consists of disobeying a written order made by an inspector, complaint thereof may be made within six months of the date on which the offence is alleged to have been committed. MISCELLANEOUS 28. Inspecting staff.(1) The appropriate Government may, by notification in the Official Gazette, appoint such persons as it thinks fit to be inspectors for the purposes of this Act, and define the local limits within which they shall exercise their powers under this Act. (2) Subject to any rules made in this behalf, an inspector may, within the local limits for which he is appointed-(a) enter, at all reasonable hours, with such assistance (if any), being persons in the service of the Government or any local or other public authority as he thinks fit, any premises or place where contract labour is employed, for the purpose of examining any register or record or notices required to be kept or exhibited by or under this Act or rules made there under, and require the production thereof for inspection; (b) examine any person whom he finds in any such premises or place and who, he has reasonable cause to believe, is a workman employed therein; (c) require any person giving out work and any workman, to give any information, which is in his power to give with respect to the names and addresses of the persons to, for and from whom the work is given out or received, and with respect to the payments to be made for the work; (d) seize or take copies of such register, record of wages or notices or portions thereof as he may consider relevant in respect of an offence under this Act which he has reason to believe has been committed by the principal employer or contractor; and (e) exercise such other powers as may be prescribed. (3) Any person required to produce any document or thing or to give any information required by an inspector under sub-section (2) shall be deemed to be legally bound to do so within the meaning of section 175 and section 176 of the Indian Penal Code (45 of 1860). (4) The provisions of the Code of Criminal Procedure, 1898 (5 of 1898), shall, so far as may be, apply to any search or seizure under sub-section (2) as they apply to any search or seizure made under the authority of a warrant issued under section 98 of the said Code.3 29. Registers and other records to be maintained.(1) Every principal employer and every contractor shall maintain such registers and records giving such particulars of contract labour employed, the nature of work performed by the contract labour, the rates of wages paid to the contract labour and such other particulars in such form as may be prescribed. (2) Every principal employer and every contractor shall keep exhibited in such manner as may be prescribed within the premises of the establishment where the contract labour is employed, notices in the prescribed form containing particulars about the hours of work, nature of duty and such other information as may be prescribed. 30. Effect of laws and agreements inconsistent with this Act.- (1) The provisions of this Act shall have effect notwithstanding anything inconsistent therewith contained in any 3 other law or in the terms of any agreement or contract of service, or in any standing orders applicable to the establishment whether made before or after the commencement of this Act: Provided that where under any such agreement, contract of service or standing orders the contract labour employed in the establishment are entitled to benefits in respect of any matter which are more favourable to them than those to which they would be entitled under this Act, the contract labour shall continue to be entitled to the more favourable benefits in respect of that matter, notwithstanding that they receive benefits in respect of other matters under this Act. (2) Nothing contained in this Act shall be construed as precluding any such contract labour from entering into an agreement with the principal employer or the contractor, as the case may be, for granting them rights or privileges in respect of any matter, which are more favourable to them than those to which they would be entitled under this Act. 31. Power to exempt in special cases.- The appropriate Government may, in the case of an emergency, direct, by notification in the Official Gazette, that subject to such conditions and restrictions, if any, and for such period or periods, as may be specified in the notification, all or any of the provisions of this Act or the rules made there under shall not apply to any establishment or class of establishments or any class of contractors. 32. Protection of action taken under this Act.(1) No suit, prosecution or other legal proceedings shall lie against any registering officer, licensing officer or any other Government servant or against any member of the Central Board or the State Board, as the case may be, for anything which is in good faith done or intended to be done in pursuance of this Act or any rule or order made there under. (2) No suit or other legal proceeding shall lie against the Government for any damage caused or likely to be caused by anything which is in good faith done or intended to be done in pursuance of this Act or any rule or order made there under. 33. Power to give directions.- The Central Government may give directions to the Government of any State as to the carrying into execution in the State of the provisions contained in this Act. 34. Power to remove difficulties.- If any difficulty arises in giving effect to the provisions of this Act, the Central Government may, by order published in the Official Gazette, make such provisions not inconsistent with the provisions of this Act, as appears to it to be necessary or expedient for removing the difficulty. 35. Power to make rules.(1) The appropriate Government may, subject to the condition of previous publication, make rules for carrying out the purposes of this Act. (2) In particular, and without prejudice to the generality of the foregoing power, such rules may provide for all or any of the following matters, namely:-(a) the number of persons to be appointed as members representing various interests on the Central Board and the State Board, the term of their office and other conditions of service, the procedure to be followed in the discharge of their functions and the manner of filling vacancies; (b) the times and places of the meetings of any committee constituted under this Act, the procedure to be followed at such meetings including the quorum necessary for the transaction of business, and the fees and allowances that may be paid to the members of a committee; (c) the manner in which establishments may be registered under section 7, the levy of a fee thereof and the form of certificate of registration; (d) the form of application for the grant or renewal of a licence under section 13 and the particulars it may contain; (e) the manner in which an investigation is to be made in respect of an application for the grant of a licence and the matters to be taken into account in granting or refusing a licence; (f) the form of a licence which may be granted or renewed under section 12 and the conditions subject to which the licence may be granted or renewed, the fees to be levied for the grant or renewal of a licence and the deposit of any sum as security for the performance of such conditions; (g) the circumstances under which licences may be varied or amended under section 14; (h) the form and manner in which appeals may be filed under section 15 and the procedure to be followed by appellate officers in disposing of the appeals; (i) the time within which facilities required by this Act to be provided and maintained may be so provided by the contractor and in case of default on the part of the contractor, by the principal employer; (j) the number and types of canteens, rest rooms, latrines and urinals that should be provided and maintained; (k) the type of equipment that should be provided in the first-aid boxes; (l) the period within which wages payable to contract labour should be paid by the contractor under subsection (1) section 21; (m) the form of registers and records to be maintained by principal employers and contractors; (n) the submission of returns, forms in which, and the authorities to which, such returns, may be submitted; (o) the collection of any information or statistics in relation to contract labour; and (p) any other matter which has to be, or may be, prescribed under this Act. (3) Every rule made by the Central Government under this Act shall be laid as soon as may be after it is made, before each House of Parliament while it is in session for a total period of thirty days which may be comprised in one session or in two successive sessions, and if before the expiry of the session in which it is so laid or the session immediately following, both Houses agree in making any modification in the rule or both Houses agree that the rule should not be made, the rule shall thereafter have effect only in such modified form or be of no effect, as the case may be; so, however, that any such modification or annulment shall be without prejudice to the validity of anything previously done under that rule. Working Capital Management Working capital is defined as the portion of assets used in current operations. The movement of funds from working capital to income and profits and back to working capital is one of the most important characteristics of the business. Sufficient liquidity is important and must be achieved and maintained to provide the funds to pay off obligations as they arise or mature. The adequacy of cash and other current assets together with their efficient handling determine the survival or demise of the company. A businessman should be able to judge the accurate requirement f working capital and should be quick enough to raise the required funds to finance the working capital needs. Working capital is cardinal part of power station management. There are two concept of working capital 1. Gross working capital 2. Net working capital Gross working capital: Gross working capital refers to the firm’s investment in current asset. Current asset are the assets which can be converted in to cash within accounting year and include cash, short term securities, debtors, bill receivables and inventory. Net working capital: Net working capital refers to difference between current asset and current liabilities. Current liabilities are those claims of outsiders which are expected to mature for payment within accounting year and include creditors, bill payable, outstanding expenses. WORKING CAPITAL = CURRENT ASSETS - CURRENT LIABILITIES Net working capital can be positive or negative or negative. Positive net working capital will arise when current asset exceeds current liabilities and vise a versa. Cash flows in a cycle into, around and out of a business. It is the business's life blood and every manager's primary task is to help keep it flowing and to use the cash flow to generate profits. If a business is operating profitably, then it should, in theory, generate cash surpluses. If it doesn't generate surpluses, the business will eventually run out of cash and expire. The faster a business expands the more cash it will need for working capital and investment. The cheapest and best sources of cash exist as working capital right within business. Good management of working capital will generate cash will help improve profits and reduce risks. Bear in mind that the cost of providing credit to customers and holding stocks can represent a substantial proportion of a firm's total profits. There are two elements in the business cycle that absorb cash - Inventory and Receivables (debtors owing you money). The main sources of cash are Payables (your creditors) and Equity and Loans. Each component of working capital (namely inventory, receivables and payables) has two dimensions time and money. When it comes to managing working capital, then time is money. If you can get money to move faster around the cycle (e.g. collect monies due from debtors more quickly) or reduce the amount of money tied up (e.g. reduce inventory levels relative to sales), the business will generate more cash or it will need to borrow less money to fund working capital. As a consequence, you could reduce the cost of bank interest or you'll have additional free money available to support additional sales growth or investment. Similarly, if you can negotiate improved terms with suppliers e.g. get longer credit or an increased credit limit; you effectively create free finance to help fund future sales. Components of Working Capital The elements of working capital are as follows: • Current assets 1. Cash 2. Bank balance 3. Short term investments 4. Trade debtors 5. Inventory  Finished goods  Work in process  Raw materials  Stores and spares • Current liabilities 1. Trade creditors 2. Bank overdraft or cash credit 3. Short term borrowings 4. Provision for taxes 5. Provision for dividends If current assets are the source from which current liabilities are to be met during the course of business operations, then their strengths and weaknesses will have significant bearing on the short run liquidity of the company. The importance of preserving this short term liquidity need not be emphasized and hence the need to manage the working capital. Factors Influencing Working Capital To determine the quantum of required working capital, the following factors need to be taken into consideration: 1. Profit levels A company earning huge amount of profits can add to the working capital pool a large quantum of funds. Such companies should, however, guard against the temptation of expanding beyond necessity and tying up the funds in unproductive capital expenditure or allow unnecessary increase in overheads. Some companies with high profit levels become lax in management of funds and usually mismanage by blocking funds excessively in stocks and debtors. 2. Tax levels and planning Income tax laws provide for payment of advanced tax in installments. Any working capital must make adequate and timely provision for Excise and sales tax as all of them involve cash outlays. 3. Dividend policies and retained earnings Dividend policy and retained earnings are directly related. Dividends once declared become a short term liability which has to be paid for in cash and this impact should be recognized in the working capital budget. Reserves in the form of retained earnings are a very important source of augmenting working capital. 4. Depreciation policy The extent to which depreciation provision is made during the course of making financial statements has a direct bearing on the dividend policy and retained earnings. This is because higher depreciation would leave lesser profits resulting in reduced retained earnings and dividends. As provisions for depreciation are actually only book entries and represent no cash flow at that time, they will have no bearing on working capital to the extent they may hold back distribution of dividends. 5. Expansion/diversification plans Addition of fixed assets to produce new products, resorting to multiple shifts, or marginally adding to the plant and machinery are some of the common known ways to expand or diversify. In such situations, it is unwise to strain the internal resources for avoiding external funding. 6. Price level changes in raw material and finished goods Inflation has got a direct bearing on working capital. It depends to a large extent on the companies’ ability to readjust its own prices to cover the increase in cost. In case the product or service requires government approval or is administered as far as the price is concerned, inflation has a very significant bearing on the working capital needs. 7. Operating efficiency of the company The operating efficiency of a company plays a major role in working capital management. An efficient company will have a shorter manufacturing period, long term credits available from suppliers and minimal customer’s credit outstanding. If this is achieved then the quantum of working capital required will be naturally reduced. Strategies for The Working Capital Management  RECEIVABLES MANAGEMENT If we are getting trade credit to fund our needs, then we also have to extend credit to our customers. There are several affects of extending credit to the customers on various operating parameters of the company. These include: Revenue effects: as the customers are extended credit, payment for goods is received later giving the customers time to generate sales from the goods and pay back the company. This may allow the company to charge a higher price and also the quantity sold may increase. ii) Cost effects: extending credit means that the company has to maintain a credit department. This involves costs. Also collecting receivables has its own costs associated in it. iii) The cost of debt: if the company has to extend credit it must finance these receivables from its own money from borrowings. iv) The probability of nonpayment: the company always gets paid if it sells for cash but if it extends credit, there is a probability that the customer may not pay. This means that the company may not get its payments resulting in a loss to the company. v) The cash discount: the cash discount affects payment patterns and amounts that the company receives early. If the cash discount is high then there is high probability that the company will get more cash up front and vice versa. There are three ways of management control in connection with credit policy: 1. Debtors expressed in relation to sales- either as a percentage or as a number of weeks sales. This provides an overall confirmation that the business is effective in carrying out its own credit policy. 2. Bad debts as a percentage of sales value, or reported otherwise in detail. 3. Credit control sales. This means that the credit control involves three types of action: Deciding the normal credit period to be allowed: if a business is offering a unique product or service, or one for which demand exceeds supply, there may be no need to offer credit terms at all. In other cases the starting point in deciding credit policy is a review of the credit terms offered by competitors and from this basis, the credit terms of the particular business will be developed. Long credit period may be offered to the customers if this enables the business to capture a larger share of the available market, or the break into a new market. Shorter credit may be imposed if demand is elastic, so that the quantity sold will not be affected simply by changes in credit terms. Establishing credit limits for the individual customers: Business has a credit policy does not mean that credit terms will be granted to every customer. It is not always easy t decide whether a particular customer is credit worthy in the sense that he has both the ability and the inclination to pay at the due date. Five Cs of credit that should be looked after: • Character: willingness to pay back the credit • Capacity : ability to pay back • Capital: financial reserves including cash • Collateral: what assets could be pledged or are pledged to others that hinder payments. • Conditions: relevant economic conditions Implementing the system Vetting incoming orders The amount appearing on the customer’s ledger account at any time will result from the invoicing the orders he has placed, so that if the value of orders in any period were t exceed the original forecast this might not become until after invoicing. At that time the outstanding balance on the ledger would suddenly be found to be in excess of the agreed limit. To safeguard against this possibility an order register may be kept for each customer, showing the value of orders placed for delivery in particular months. Each incoming order will then be checked against the register to confirm that it will not cause the credit limit to be exceeded. This could be a cumbersome procedure and it would only be used in respect of: • New customers whose compliance with credit limits has not been established i) • Customers who had consistently failed to adhere to their credit limits in the past. Sales invoicing So far as the customer is concerned, the company’s credit period does not begin until he receives an invoice. It is therefore important that delays in invoicing be kept to minimum. The causes of delay are nearly all within the control of the company and may include: • An inflexible routine in the sales invoicing department • A requirement for approval or signature of sales invoices • Failure to agree prices for special work • Slow procedures for calculating costs. Debt collection There must be no slackness in pursuing the collection of debts. There should be early personal contact with the customer either by telephone or salesman’s visit or by a letter addressed to a named person in the customer company. If necessary, there may be a follow up at higher level of authority and this should be followed by a threat to cut off supplies. Overdue debts should be the subject of formal discussion between sales and financial managers. The reasons for delayed payment should be noted, and decisions should be minuted on the action to be taken in each case and the people responsible for taking it. Cost of credit control The cost of credit control includes the cost of: • Assessing and reviewing creditworthiness • Checking incoming orders • Sales ledger keeping and invoicing • Debt collection Cash discount An alternative or supplement of a formal credit policy is to offer discount for prompt payment. It is important to bear in mind that: • Customers who normally pay promptly will now become entitled to discount • Some late payers will nevertheless deduct discount from their settlements. Personal guarantees An alternative form of protection against bad debts is to take a personal guarantee in support of the customer’s account. The value of personal guarantees varies considerably and they are likely to present two problems: • It may be more difficult to assess the creditworthiness of an individual guarantor than of the trade customer. • The guarantor does not normally expect to be called upon to pay, and there may be difficulties in obtaining money from him when the need arises.  PAYABLES MANAGEMENT: When the company gets the trade credit, it would like to pay back as late as possible, because these are the funds that require no interest payments and are free of cost. Following points needs to be taken into consideration: • Cost Of Trade Credit: for purpose of measuring the true cost, or the effective annual rate of interest associated with use of trade credit as a discretionary source of short term business funds, it is necessary to consider the effects of its use both when: • a company fails to take its cash discounts but nevertheless pays within the net period • A company fails to take its discounts and allows its payable to become overdue. • Proper Use of Trade Credit: as compared with other kinds of short term business credit-bank loans, trade credit is almost automatic. And because it may be much more readily acquired, business companies must exercise continuing care to avoid falling into the habit of using trade credit to excess. Trade credit is exceedingly useful and valuable precisely because business companies can usually obtain it when, as, and to the extent that it is needed. Thus, a company’s financial officer while assuring that his company benefits from the availability of trade credit in every legitimate way should always maintain the business liquidity required to pay all his company’s bills as they come due.  INVENTORY MANAGEMENT: Inventory contains finished goods, semi finished goods, raw materials. The financial decisions relating to stockholding have certain special features but it can be used as an object of increasing sales and object of increasing sales is to increase profit. Why should increased stocks give rise to increase in sales? One reason would be that the business may offer a wider range of gods and it diversifies its range. Another could be that with the existing range the business was offering the better level of service that is it was less frequently out of stock of an item when it was required. The inventory management can be done by taking care of following: • Stock Service Levels: in deciding an inventory policy it is necessary to define the level of service to be offered to the customer, in the sense of percentage of order which can be satisfied immediately from stock. This will depend on the nature of the business. When the required level of service has been defined, the next problem is to decide how much stock is needed to meet that requirement. This will be the minimum holding, and not the average holding which will be influenced by the stockholding costs. • Economic Order Quantity: the economic order quantity is defined as the point where the total costs of restocking and carrying costs are the lowest. It is calculated on the basis of differential calculus. EOQ =√ (2×FC ×S) ÷ (I×P) There are 4 assumptions for an EOQ model: • Sales can be forecasted perfectly • Sales are evenly distributed throughout the year • Orders are received as soon as they are placed This set of assumptions mean is perfectly restrictive. There are 2 important things to note about EOQ: Although a precise EOQ can be calculated, there is likely to be a range f order quantities within which total costs remain at a low level. The choice f order quantity within this low cost range may not significantly affect the overall financial plan. The key factor in the calculations is usually the cost of capital. The inventory holding costs will go up very steeply, and one’s conclusion will be that stockholdings should be kept to the lowest figure possible having regard to any practical difficulties in obtaining frequent replacement supplies. o Safety Margins in Stockholding: we always assume that the company will be placing an order at regular intervals of time for a fixed quantity of any particular item. The possibility of doing this depends on demand remaining constant from period to period and on supplies being available as and when required. To correct for random delays in supply, it may be possible to anticipate changes in the trend of demand and to modify the purchasing procedure to meet them in one of the following ways:  To order in economic order quantities but at varying time intervals according to the rate of demand currently being experienced or anticipated in the near future known as fixed order quantity or reorder level system.  To order at regular intervals but in varying quantities determined by the current rate of demand, this is the fixed interval or periodic review system. Modified Ordering Systems: the reorder level system involves deciding a level of stockholding at which new purchase orders shall be placed. The quantity to be ordered is constant, and an order for that quantity will be placed whenever stock falls to the pre-determined order level. The system thus responds quickly to variations in demand though there is a danger that in doing so, it may reflect purely short term or random fluctuations in sales. The operation of reorder level system include the use of:  A maximum stock level. This would correspond to the normal peak holding under stable conditions. If the stockholding exceeds the peak level this provides a warning that demand has been running below the rate expected when the EOQ was fixed.  A minimum stock level which is probably the amount of the safety margin. The minimum stock level provides a warning of a potential out of stock position. When the stockholding falls to that level, the sock controller will review his outstanding purchase orders and their due dates and also the current level f demand and can then decide whether additional emergency procurement is necessary. It is in fact a common experience that the reorder system level gives slightly lower average stock levels and it is sometimes thought to be the cheaper system to operate because reordering is triggered automatically at the reorder levels, however, requires reviewing in the light of changes in the rate of demand. Any system can appear cheap in the short run if it is operated in a slovenly manner. • The Total Inventory: the techniques described above all relate to single line items of stock. The assumption is such that of each item is held at its own economic level then the overall holding of stock will be correctly balanced. This would be true provided that the two conditions were satisfied. o That there was enough space available to hold all the stocks required. o That enough money could be found to finance them. o Neither condition is likely to be fulfilled in practice, so some form of mathematical program might be used to constrain the ideal unit quantities within the limiting factors. There are, however, number of simple pragmatic approaches t inventory reduction and these include: o Modifying the service level offered o Letting the company’s suppliers act as stockholders o Disconnecting those items which are the least profitable having regards to their marginal contribution and relevant fixed costs per unit of the limiting factor. • Raw Materials Stocks and Work In Progress: so far in considering inventory control, we have been discussing saleable stocks but the same principles apply to stocks of raw materials. The main difference is that demand for raw materials is not direct from the outside customers but indirect through the production plans of the factory using the raw materials. A big problem with work in progress is that work passes in sequence through series of operations. What is economic batch for lathe work may not be economic for drilling, milling or assembly operations. Applying EBQ(economic batch quantity) to one operation in isolation can cause bottlenecks in the flow or production creating excessive holdings of partly completed work because it could be produced cheaply in a large batch even though there will be no demand for that work for some time ahead. As the number of items could be very large in case of raw materials it is necessary to find ways to selectively pay attention to those items that represent the highest value. A categorization method known as ABC analysis is used for the same purpose. The idea behind ABC analysis is that attention is focused on the highest value items that are usually less in number categorized as A category items and the lowest value items are categorized as C and are ordered in more quantities so that less attention is required there. o For example , in figure 6.6,the A category items represent only 10% of total inventory items but represent 57% of the total value. While C category items represent 50% of the total items but only 16%of the value. By concentrating more on the A category items the company is able to manage its raw material inventory better. 100 (PERCENT OF INVENTORY VALUE) 80 GROUP A 60 40 20 0 20 40 60 80 10% 40% 57% GROUP B GROUP C 27% 16% 50% ABC INVENTORY ANALYSIS 100 (PERCENT OF INVENTORY ITEMS) Inventories are lists of stocks-raw materials, work in progress or finished goods-waiting to be consumed in production or to be sold. In case of power plant inventory is stock of coal needed for daily operation. The total balance of inventory is the sum of the value stock. Stock records are needed: o To provide an account of activity within each stock line; o As evidence to support the balances used in financial reports. Inventory management is an important aspect of working capital management because inventories themselves do not earn any revenue. Holding either too little or too much inventory incurs costs. Costs of carrying too much inventory are: o opportunity cost of foregone interest; o warehousing costs; o damage o Obsolescence; o Insurance. Costs of carrying too little inventory are: • Stock out costs: - Results into shut down of power plant and lots of sale. • Ordering cost:  freight  order administration  loss of quantity discount a. The best ordering strategy requires balancing the various cost factors to ensure the department incurs minimum inventory costs. The optimum inventory position is known as the Economic Reorder Quantity (ERQ). There is a trade-off to be made between carrying costs, ordering costs, and stock out costs. b. Analytical review of inventories can help to identify areas where inventory management can be improved. STRATEGIES TO CONTROL DEBTORS AND CREDITORS Debtors: Debtors (Accounts Receivable) are customers who have not yet made payment for goods or services which the department has provided. The objective of debtor management is to minimize the time-lapse between completion of sales and receipt of payment. The costs of having debtors are: • Opportunity costs (cash is not available for other purposes); • Bad debts Debtor management includes both pre-sale and debt collection strategies. Pre-sale strategies include: 1. offering cash discounts for early payment and/or imposing penalties for late payment; 2. agreeing payment terms in advance; 3. setting credit limits; 4. billing as early as possible; 5. Requiring deposits and/or progress payments. Post-sale strategies include: 1. Placing the responsibility for collecting the debt upon the center that made the sale. 2. Identifying long overdue balances and doubtful debts by regular analytical reviews 3. Having an established procedure for late collections, such as a reminder a letter cancellation of further credit telephone calls legal action Creditors: Creditors (Accounts Payable) are suppliers whose invoices for goods or services have been processed but who have not yet been paid. Organizations often regard the amount owing to creditors as a source of free credit. While it is unnecessary to pay accounts before they fall due, it is usually not worthwhile to delay all payments until the latest possible date., Regular weekly or fortnightly payment of all due accounts is the simplest technique for creditor management. Electronic payments (direct credits) are cheaper than cheque payments, considering that transaction fees and overheads more than balance the advantage of delayed presentation. Some suppliers are reluctant to receive payments by this method, but in view of the substantial cost advantage (and the advantages to the suppliers themselves) departments may wish to encourage suppliers to accept this option. However, electronic payments are likely to be used in conjunction with, rather than as a replacement for, cheque payments. Working Capital According To CERC Guidelines As per central Electricity Regulatory commission (CERC) guidelines on tariff calculation (2009-2014) for generating stations, working capital shall cover: For coal based/Lignite fired generating stations 1. Cost of coal or lignite 2. Cost of secondary fuel oil 3. Operation and Maintenance expenses 4. Maintenance spares 5. Receivables • Cost of coal or lignite and limestone, if applicable, for 1½ months for pit-head generating stations and two months for non-pit-head generating stations, for generation corresponding to the normative annual plant availability factor. Cost of coal consumes highest part of working capital in coal based generating stations. As per CERC guidelines cost of coal or lignite for 1.5 months for pit head generates stations and two months for non pit head generating stations, corresponding to target availability. Cost of coal depends upon following parameters; a. b. c. d. Capacity of power plant Gross station heat rate Market price of coal Calorific value of coal Gross station heat rate: Gross station heat rate means the heat energy input in kcal required to generate one kWh of electricity energy at generator terminals. As per CERC guidelines; Gross station heat rate for coal base Thermal power plant 200/210/250 MW sets 500 MW and above sets During stabilization period 2600 Kcal/Kwh 2550 Kcal/Kwh Subsequent period 2500 Kcal/Kwh 2425 Kcal/Kwh Gross Calorific Value: Gross calorific value in relation to thermal power generating station means heat produced in Kcal by complete combustion of solid fuel or one liter of liquid fuel or standard cubic meter of gaseous fuel. Calorific value of Indian coal is less as compared to imported coal due to high ash contents. • Cost of secondary fuel oil for two months for generation corresponding to the normative annual plant availability factor, and in case of use of more than one secondary fuel oil, cost of fuel oil stock for the main secondary fuel oil. • Maintenance spares @ 20% of operation and maintenance expenses specified in regulation 19. • Receivables equivalent to two months of capacity charges and energy charges for sale of electricity calculated on the normative annual plant availability factor, and • Operation and maintenance expenses for one month. OPEN-CYCLE GAS TURBINE/COMBINED CYCLE THERMAL GENERATING STATIONS • Fuel cost for one month corresponding to the normative annual plant availability factor, duly taking into account mode of operation of the generating station on gas fuel and liquid fuel; • Liquid fuel stock for ½ month corresponding to the normative annual plant availability factor, and in case of use of more than one liquid fuel, cost of main liquid fuel. • Maintenance spares @ 30% of operation and maintenance expenses specified in regulation 19. • Receivables equivalent to two months of capacity charge and energy charge for sale of electricity calculated on normative plant availability factor, duly taking • Operation and maintenance expenses for one month. HYDRO GENERATING STATION • Receivables equivalent to two months of fixed cost. • Maintenance spares @ 15% of operation and maintenance expenses specified in regulation 19; • Operation and maintenance expenses for one month. The cost of fuel shall be based on the landed cost incurred (taking into account normative transit and handling losses) by the generating company and gross calorific value of the fuel as per actual for the three months preceding the first month for which tariff is to be determined and no fuel price escalation shall be provided during the tariff period. OPERATION AND MAINTENANCE EXPENSES Coal based and lignite fired (including those based on CFBC technology) generating stations, other than the generating stations: 200/210/250 MW 300/330/350 500 MW sets 600 MW and sets MW sets above sets 2009-10 18.20 16.00 13.00 11.70 2010-11 19.24 16.92 13.74 12.37 2011-12 20.34 17.88 14.53 13.08 2012-13 21.51 18.91 15.36 13.82 2013-14 22.74 19.99 16.24 14.62 Talcher Thermal Power Station (TPS), Tanda TPS, Badarpur TPS of NTPC and Bokaro TPS, Chandrapura TPS and Durgapur TPS of DVC (Rs. in lakh/MW) Year Talcher TPS Tanda and Badarpur, Bokaro Chandrapura TPS and Durgapur TPS 2009-10 32.75 26.25 31.35 2010-11 34.62 27.75 32.25 2011-12 36.60 29.34 33.17 2012-13 38.70 31.02 34.12 2013-14 40.91 32.79 35.09 Open Cycle Gas Turbine/Combined Cycle generating stations (Rs. in lakh/MW) Gas Turbine/ Combined Small gas turbine power Agartala GPS Year Cycle generating stations generating stations other than small gas turbine power generating stations 2009-10 14.80 22.90 31.75 2010-11 15.65 24.21 33.57 2011-12 16.54 25.59 35.49 2012-13 17.49 27.06 37.52 2013-14 18.49 28.61 39.66 (Rs. in lakh/MW) Year HYDRO GENERATING STATION • Operation and maintenance expenses, for the existing generating stations which have been in operation for 5 years or more in the base year of 2007-08, shall be derived on the basis of actual operation and maintenance expenses for the years 2003-04 to 2007-08, based on the audited balance sheets, excluding abnormal operation and maintenance expenses, if any, after prudence check by the Commission. • The normalized operation and maintenance expenses after prudence check, for the years 2003-04 to 2007-08, shall be escalated at the rate of 5.17% to arrive at the normalized operation and maintenance expenses at the 2007-08 price level respectively and then averaged to arrive at normalized average operation and maintenance expenses for the 2003-04 to 2007-08 at 2007-08 price level. The average normalized operation and maintenance expenses at 2007-08 price level shall be escalated at the rate of 5.72% to arrive at the operation and maintenance expenses for year 200910: Provided that operation and maintenance expenses for the year 2009-10 shall be further rationalized considering 50% increase in employee cost on account of pay revision of the employees of the Public Sector Undertakings to arrive at the permissible operation and maintenance expenses for the year 2009-10. • The operation and maintenance expenses for the year 2009-10 shall be escalated further at the rate of 5.72% per annum to arrive at permissible operation and maintenance expenses for the subsequent years of the tariff period • In case of the hydro generating stations, which have not been in commercial operation for a period of five years as on 1.4.2009, operation and maintenance expenses shall be fixed at 2% of the original project cost (excluding cost of rehabilitation & resettlement works). Further, in such case, operation and maintenance expenses in first year of commercial operation shall be escalated @5.17% per annum up to the year 2007-08 and then averaged to arrive at the O&M expenses at 2007-08 price level. It shall be thereafter escalated @ 5.72% per annum to arrive at operation and maintenance expenses in respective year of the tariff period. • In case of the hydro generating stations declared under commercial operation on or after 1.4.2009, operation and maintenance expenses shall be fixed at 2% of the original project cost (excluding cost of rehabilitation & resettlement works) and shall be subject to annual escalation of 5.72% per annum for the subsequent years. TRANSMISSION SYSTEM • Norms for operation and maintenance expenses shall be as under: Norms for substation (rupees lakh/bay) 765kv 400kv 220kv 132kv and below 73.36 52.40 36.68 26.20 77.56 55.40 38.78 27.70 81.99 58.57 41.00 29.28 86.68 61.92 43.34 30.96 91.64 65.46 45.82 32.73 Norms for AC and HVDC lines (Rs lakh/km) Single Circuit (Bundled conductor with four or more sub-conductors) Single Circuit (Twin & Triple Conductor) Single Circuit (Single Conductor) Double Circuit (Bundled conductor with four or more sub-conductors) Double Circuit (Twin & Triple Conductor) Double Circuit (Single Conductor) Norms for HVDC stations HVDC Back-to-back stations (Rs lakh per 500 MW) Rihand-Dadri HVDC bipole scheme (Rs Lakh) Talcher-Kolar HVDC bipole scheme (Rs lakh) .537 .358 .179 .940 .627 .269 443.00 1450.00 1699.00 .568 .378 .189 .994 .663 .284 468.00 1533.00 1796.00 .600 .400 .200 1.051 .701 .301 495.00 1621.00 1899.00 .635 .423 .212 1.111 .741 .318 523.00 1713.00 2008.00 .671 .447 .224 1.174 .783 .336 553.00 1811.00 2122.00 The total allowable operation and maintenance expenses for the transmission system shall be calculated by multiplying the number of bays and kms of line length with the applicable norms for the operation and maintenance expenses per bay and per km respectively. Depending upon the above mentioned values and strategies, the working capital needs to be managed effectively for the growth of the company and industry as whole. Interest on working capital in case of renewable energy sources The Working Capital requirement in respect of wind energy projects, small hydro power, solar PV and Solar thermal power projects shall be computed in accordance with the following Wind Energy / Small Hydro Power /Solar PV / Solar thermal a) Operation & Maintenance expenses for one month; b) Receivables equivalent to 2 (Two) months of energy charges for sale of electricity calculated on the normative CUF; c) Maintenance spare @ 15% of operation and maintenance expenses The Working Capital requirement in respect of biomass power projects and non-fossil fuel based co-generation projects shall be computed in accordance with the following clause : Biomass Power and Non-fossil fuel Co-generation a) Fuel costs for four months equivalent to normative PLF; b) Operation & Maintenance expense for one month; c) Receivables equivalent to 2 (Two) months of fixed and variable charges for sale of electricity calculated on the target PLF; d) Maintenance spare @ 15% of operation and maintenance expenses Interest on Working Capital shall be at interest rate equivalent to average State Bank of India short term PLR during the previous year plus 100 basis points. Solved questions on working Capital 1. Classic Petrochemical company offers trade credit to its customers of net 30. Credit sales average rs 620,000/day on which the company earns a contribution margin of 20%. The average accounts receivable collection period is 50 days. The appropriate after tax discount rate is evaluating accounts receivable policy changes is 9%. N the company marginal tax is 40%. What is the average balance in accounts receivable? What is the average investment in accounts receivable? What is annual financing cost associated with the investment in receivables? The sales manager believes she can implement a credit policy change that will reduce the average collection period by 4 days without affecting the level of sales. If this policy works as expected then what will be company’s investment in accounts receivables? What will be the net annual after tax advantageto the company of adopting this policy? Suppose the credit policy change will also reduce sales by rs 5,000/day. What would be company’s investment in accounts receivable? What will be the expected effect of this policy change on the company’s after tax net income? Solution The average balance of accounts receivable is: Average A/R balance = rs 620000 * 50= 31000000. Average investment in A/R = 31000000 * .80= 24800000 The cost of financing the investment I receivables is : Cost of financing A/R = 24800000 * .09= 2232000 Reducing the collection period by 4 days will free up: Cash freed up= 4*620000*.80= 1984000 The net advantage is reduced financing cost of the cash freed up: Reduced financing cost = 1984000*.09=178560/year If sales decrease and the average collection period is reduced, new investment in A/R = 615000/(.80) (46)=22632000 New financing cost of A/R = (22632000)(.09)=2036880 There are two effects on sales: Dfinancing cost of A/R= (2232000-2036880)=195120 Dnet profit from lower sales = (5000/day)(365)(.20)(.60)=219000 ∆NIAT ( 195120-219000)= 23880 rupees NOTES: The financing cost of carrying receivables is based on the cost sales since the cost of sales represents the cash paid out in advance of collections. The cash paid out creates a financing need. Here D means additional. 2. Rupesh, credit manager of shell company, is considering a change in the company’s credit terms from net 60 to net 30. Shell has daily credit sales of rs 50,000 and its variable cost ratio is 15%. Tightening credit standards would reduce the average collection period from 75 days to 40 days, reduce daily sales by rs 2000 and lower bad debts from 5% of sales is 40 % and its use an after tax discount rate of 12% to evaluate accounts receivable policy changes. How would be be changes in credit terms affect shell’s after tax income? Solution Old investment In A/R = (75)(50000)(.85)= 3187500 New investment in A/R = (40) ( 48000/day)(.85)= 1632000 ∆Investment in A/R = Rs 1555500 There are three expected changes in after tax net income: ∆Financing cost of A/R investment = (1555500) (.20)= 186660 ∆bad debt expense [(.05)(50,000)(365)-(.03)(48000)(365)](60)= 232140 ∆profit on sales= (2000)(365)(.15)(.60)= 65700 ∆Net profit= 232140-65700= 353100 3. Let’s compare the coal consumption in two different UMPP( mundra, sasan). Mundra using international coal and sasan using domestic coal so how both utilizing the working capital management. Solution According to CERC 40 days cerc should be allowed. For 4000 MW, coal consumption is 40000tonne/day. Shipment charge for the international coal, $6.5/tone/day. So shipment charge, 6.5*50= 325/tone/day. Coal charge =$47=47*50=2350 Total charge = 2350+325=2675/tone/day For international coal we use only 30000tonne/day for 4000mw. So total cost= 2675*30000*40=3210000000 rupees. For domestic coal, the coal rate is 1000, and we use 40000 tonne/day for 4000 mw plant. So the total cost= 1000*40000*40= 1600000000 rupees. So by comparing the two we come to an conclusion , that using international coal, tariff is increasing but the gross calorific value is better in case of international coal. HRM AT POWER STATIONS INTRODUCTION Human resources is a term used to describe the individuals who comprise the workforce of an organization, although it is also applied in labor economics to, for example, business sectors or even whole nations. Human resources is also the name of the function within an organization charged with the overall responsibility for implementing strategies and policies relating to the management of individuals. Under this topic we do the comparative study of HR practices at power stations. For this a comparative analysis of HR policies of NTPC and TNEB has been done. Following diagram shows the general HR hierarchy of a power plant. Fig: HR Hierarchy (A) National Thermal Power Station Overview of the Organisation India’s largest power company, NTPC was set up in 1975 to accelerate power development in India. NTPC is emerging as a diversified power major with presence in the entire value chain of the power generation business. Apart from power generation, which is the mainstay of the company, NTPC has already ventured into consultancy, power trading, ash utilisation and coal mining. NTPC ranked 317th in the ‘2009, Forbes Global 2000’ ranking of the World’s biggest companies. The total installed capacity of the company is 32, 694 MW (including JVs) with 15 coal based and 7 gas based stations, located across the country. In addition under JVs, 3 stations are coal based & another station uses naptha/LNG as fuel. By 2017, the power generation portfolio is expected to have a diversified fuel mix with coal based capacity of around 53000 MW, 10000 MW through gas, 9000 MW through Hydro generation, about 2000 MW from nuclear sources and around 1000 MW from Renewable Energy Sources (RES). NTPC has adopted a multi-pronged growth strategy which includes capacity addition through green field projects, expansion of existing stations, joint ventures, subsidiaries and takeover of stations. NTPC has been operating its plants at high efficiency levels. Although the company has 18.79% of the total national capacity it contributes 28.60% of total power generation due to its focus on high efficiency. At NTPC people before Plant Load Factor is the mantra that guides all HR related policies. NTPC has been awarded No.1, Best Workplace in India among large organisations for the year 2008, by the Great Places to Work Institute, India Chapter in collaboration with The Economic Times. NTPC has taken initiative to develop and implement viable DG projects in remote villages and ensure sustainability for integrated growth of the village. Vision "A world class integrated power major, powering India’s growth, with increasing global presence“ Mission "Develop and provide reliable power, related products and services at competitive prices, integrating multiple energy sources with innovative and eco – friendly technologies and contribute to society" Corporate Objectives • • • • • • • • Business portfolio growth Customer focus Agile corporation Performance leadership HRD Financial soundness Sustainable power development R&D Manpower Profile • • • HRD • • • Installed Capacity Total Human resources Executive Non Executive Man-MW ratio 32694 MW 25944 9500 16444 0.8/MW To enhance organizational performance by institutionalizing an objective and open performance mgmt system. To align individual and organizational needs and develop business leaders by implementing a career development system. To enhance commitment of employees by recognizing and rewarding high performance. Code of Conduct • The Company currently has Conduct, Discipline & Appeal Rules (“CDA Rules”), which govern the conduct of all permanent employees of the Company including Whole-time Directors but excluding Non Whole-time Directors and those governed by the Standing Orders under the Industrial Employment (Standing Orders) Act, 1946. This Code for Board Members has now been framed specifically in compliance with the provisions of Clause 49 of the Listing Agreements entered into by the Company with the Stock Exchanges. In respect of Whole-time Directors this Code is to be read in conjunction with the CDA Rules. • Competence Building • • • • • • • • Talent induction through ET Recruitment system Leadership Development Integrated Career Development system Training infrastructure at CC/Regions/Projects Comprehensive Training System Foreign training Long term education Knowledge Generation & Sharing Culture Building • • • • • Creating a sense of higher purpose by emphasizing Actualization of Vision and Core Values Effective two way Communication System System for Employees’ Participation in Management Partners in Progress workshops Culture of celebration • • • Programs on attitudinal change, Team building Culture of creativity Building HR Competencies amongst Line People Commitment Building • • • • • NTPC Rewards and Recognition systems Strong social security net Mentoring Corporate identity (NTPC geet, NTPC Flag) Sparsh- caring culture Systems Building • Benchmarking • TQM tools such as QC, Business Excellence Model • Performance Management System • Simplification of policies/Single window • Cost control measures • IT enabled KM system(Proposed) Human Resource Policies • • Powering India's Growth : Through people NTPC believes in achieving organizational excellence through Human Resources and follows "People First" approach to leverage the potential of its 25,944 employees to fulfill its business plans. Human Resources Function has formulated an integrated HR strategy which rests on four building blocks of HR viz. Competence building, Commitment building, Culture building and Systems building. All HR initiatives are undertaken within this broad framework to actualize the HR Vision • HR Vision “Enabling the employees to be a family of committed world class professionals making NTPC a learning organization”. HR POLICIES FOR WELFARE AND HEALTH • Demonstrating its high concern for people, NTPC has developed strong employee welfare, health & well-being and social security systems leading to high level of commitment. NTPC offers best quality-of-life through beautiful townships with all amenities such as educational, medical and recreational opportunities for employees and their family members. • • The motivation to perform and excel is further enhanced comprehensive NTPC Rewards and Recognition system. through a HR POLICIES IN TRAINING • To induct talent and groom them into a dedicated cadre of power professionals "Executive Trainee" Scheme was introduced in the year 1977 for recruitment in the disciplines of Mechanical, Electrical, Civil, Control & Instrumentation and now encompasses Computer Science, Chemistry, HR and Finance disciplines also. Besides a comprehensive one year training comprising theoretical inputs as well as on-the-job training, the new recruits are also attached with senior executives under a systematic and formal 'Mentoring System' of the company to integrate them into the Culture of the company. • HR Policies • As part of post employment training and development opportunities, a systematic Training plan has been formulated for ensuring minimum seven man days training per employee per year and includes level-wise planned intervention designed to groom people for assuming positions of higher responsibility, as well as specific need-based interventions based on scientific Training Needs Analysis. NTPC has set up 15 project training centres, 2 simulator training centres and an apex institute namely 'Power Management Institute' (PMI). While the project training centres (Employee Development Centres) have specialized in imparting technical skills and knowledge, PMI places emphasis on management development. Besides opportunities for long term education are also provided through tie ups with reputed Institutions like IIT, Delhi, (M.Tech in Power Generation Technology), MDI, Gurgaon (Executive MBA programme), BITS, Pilani (B.Tech) etc. • • HR Policies For Continued Learning • In order to realize the HR Vision of making NTPC a learning Organization by providing opportunities to continually learn new capabilities a number of initiatives have been taken. NTPC Open Competition for Executive Talent (NOCET) is organized every year in which teams of executives compete annually through oral and written presentation on a topical theme. Similarly "Professional Circles" have been formed department-wise where Executives of the department meet every fortnight to share their knowledge and experiences and discuss topical issues. • • In order to tap the latent talent among non executives and make use of their potential for creativity and innovation, Quality Circles have been set up in various units/offices in NTPC. Besides a management journal called "Horizon" is published quarterly to enable employees to share their ideas and experiences across the organization. In order to institutionalize a strong Culture based on Values a number of initiatives are taken to actualize the Vision and Core Values (BCOMIT) across the company. A culture of celebrating achievements and a strong focus on performance are a way of life in NTPC. NTPC has institutionalized "Development Centers" in the company to systematically diagnose the current and potential competency requirements of the employees with the objective of enhancing their development in a planned manner. These Centers give a good insight to the employees about their strengths and weaknesses, the gaps in their competencies which they can bridge through suitable support from company. Due to innovative people management practices there is a high level of pride and commitment amongst employees as reflected in the various external surveys including “Great Places to Work for in India” in which NTPC was rated third Great Place to work for in the country in 2005. • • • • • Establishment matters pertaining to NTPC employees i) ii) iii) iv) iv) v) vi) vii) Employees’ (Conduct, Discipline and Appeal) Rules. Leave Rules Medical Attendance and Treatment Rules. Post-Retirement Medical Scheme. Promotion Policies. Rules pertaining to House Building Advance, Conveyance Advance; etc. Directives regarding recruitment & promotion of SC/ST Directives regarding recruitment of OBC, Physically Handicapped, Women and minorities. Human Resources Development & Community Development i) Training Policies ii) Guidelines for Community Development, donation to charities, etc. iii) Scholarship schemes for SC/ST students Awards • • • Analysis of HR metrics (Business Today) o NTPC ranked:-1 National award for welfare of person with disability in best employer category Greentech safety award for 2003-04 • • Golden peacock award for excellence in corporate governance Ranked 3rd best employer in business today (B) TAMIL NADU ELECTRICITY BOARD (TNEB) HR practices at TNEB PHILOSOPHY The basic philosophy of the Training is to make training an effective instrument to the personnel of Tamil Nadu Electricity Board in providing the updated knowledge and upgraded skill with positive attitude for consumer delight oriented service. It is viewed that training is no longer expenditure, but construed as an investment. OBJECTIVES The Objectives of the Training Policy are to: Make learning one of the fundamental requirements in TNEB Ensure value addition through training for overall efficient performance.Institutionalise learning opportunities that supplement work experience. Integrate Organizational and individual development needs. Enable employees to keep abreast with the latest knowledge and skills and enable them to undertake current and future responsibilities in a more effective manner. Provide linkages between the different functionaries of training activity. Provide linkages of training activity with overall Human Resource function. Greater emphasis on improving performance with positive attitude rather than merely increasing individual change.More training is done to deal with situations as contrasted to improving the skills of individuals only. Building in - house capability rather than depending on outside experts or resources. Learning is self motivated by learner instead of being imposed upon him. Individuals trained as members of a group so that they will learn to function together in their organizational relationships. DEFINITIONS Training Training shall include on - site field oriented training programme, workshop, seminar, contact programme with manufacturers or development programme based on organizational Needs and / or Training needs analysis. Training Year Training Year shall mean a period of one year commencing from 1st April till 31st March of the subsequent year. In-House Training Programme A training programme is designed, developed and conducted with in TNEB, exclusively for the regular employees of the TNEB, with or without the assistance of external agency. External Training Programme A training programme is designed, developed and conducted with in India, by an outside agency, not exclusively for the employees of the company to which one or more employees of the TNEB may be nominated. Training Abroad Whenever necessity is felt absolute, training to upgrade special skill on latest technologies introduced may be imparted abroad for a selected group of employees. On Completion of training abroad, the employee shall serve in the selected field of training for a specified period. Distance Education The employees may be permitted to undergo distance education, for imparting special managerial skills like HRM, Finance and Project Management etc. Continuance of Education Selected meritorious employees may be deputed to continue education on Technical and managerial courses with an under taking to serve in the board for a specified period after completion of course. Continuance of Education at employees own cost : A percentage of a particular category of employees at a location as decided by TNEB may be permitted to undergo continuance of education on part time basis at their cost provided; such continuance shall not affect their normal duties expected. Planned Intervention A grade/level/category - wise In - House training programme, normally based on a template course design, and conducted to improve competency base of employees as felt necessary by the organization. Need-based Programme A training programme, designed, developed and conducted on the basis of the developmental needs felt, identified for the employees concerned in the Training Needs form. Specified Intervention An external programme or an In-House Training Programme other than a Planned Intervention or a Needbased Programme is conducted to improve certain specified competencies, as felt necessary by the Organization. TRAINING COVERED UNDER POLICY Training shall be imparted once in five years for all technical personnel and once in eight years for all nontechnical personnel. It shall be the endeavor of the TNEB to provide one week of training in a year to every employee Training in some important areas: i) Reforms in Energy Sector ii) Training for trainers iii) Human Resources Development iv) APDRP Programmes TRAINING CALENDAR All the Deputy Directors shall meet in the Regional Head quarters during first week of January to share training calendars. They would also provide inputs to Training Institutes out of the training needs identified by the employer of their respective projects. Each Training Institute / Centre shall bring out, by 15th February every year, a Training Calendar, specifying the schedules of the programmes, both planned interventions and need-based interventions, planned to be conducted by it during the following training year. Each Training centre shall circulate on bi-monthly basis, calendar of programmes scheduled for the next two months to all circle heads (Superintending Engineer). The Training Calendars of the various Training Centres and Institutes would be widely made available to all circles. Copies of training calendar shall be kept in the Training Centres and in the circles. NOMINATION SYSTEM The Objectives of the Nomination System are: To ensure that employees are nominated to training in areas which are relevant to their duties, which have been identified as their development needs (Regular and Special programmes at Institutes and Centers) To ensure that opportunitites to attend training programmes are made available to all employee to achieve the Training Target of average of one week of training in a training year for each employee (Enmass Knowledge Updating Programmes at division level). NOMINATION FOR TRAINING PROGRAMMES Planned Interventions The training Centre / Institute would send the schedules for the next three programmes of a planned intervention to the Circle Heads, who in- turn shall seek preference for nomination from the list of employees to the Training Centres / Institutes. On the basis of the preferences received for nomination, the Training Centre / Institute shall send confirmation. Need Based The training centers will ensure that employees are normally nominated to programmes related to training needs identified. An employee interested in attending any of the training programmes included in the training calendar of the training center of respective area should forward his / her request for nomination through the reporting officer, at least two weeks before the commencement of the programmes to the circle heads , who will decide considering the merit of candidature. External Training Employees may generally be considered for nomination to training programmes only in the areas identified in the Training Needs Analysis and after verifying, whether Within the State i) Engineers are to be imparted training on special field at Appadurai Chair for Power System, Constituted by TNEB at Anna University. Regular interaction may be held between TNEB & Faculties of Anna University in solving the problems. ii) Engineers are to be imparted training on special field at various Management Institutions, Educational Institutions like Anna Institute of Management, Chennai, Engineering Colleges, IIT / Chennai, Madras Productivity Council etc. iii)Engineers are imparted training on Special field of Engineering at various Technical Training Institutes, like BHEL / Trichy, NTPC / Neyveli and at Manufacturer’s works like M/s.ALSTOM, Indo-Tech Transformers, Easun Reyrolle, etc. Outside the State i) Engineers / Officers are to be imparted training on special field at various Management Institutions, Educational Institutions, Technical Training Institutes like, ESCI, ASCI, CIRE at Hyderabad, NTPC / NPTI / PMI / Noida, NITIE / IIT at Mumbai NPC / New Delhi & PSTI / CPRI / HLTC at Bangalore and at Manufacturer’s works like ABB/Vadodhara, Crompton Greaves / Nasik, BHEL/Hardwar etc. Training Abroad Engineers are sent for training abroad at the Manufacturers Works as per PO terms. Training centers shall, as far as possible try to provide training to the employees in house. Employee will normally be nominated for external programmes only for advanced programmes or where conducting the programme In-house is not feasible. The authorities competent to nominate persons for the training programmes are as given below. Deputation for Higher Education Engineers are deputed for doing post graduate courses Like , MBA in power Management at NPTI / faridabad and ME/M.Tech courses at Anna University, Chennai. Specified interventions The Authorities competent to approve specified training programmes are as given below • Plant-level Intervention at Thermal Stations • Training Programmes as per annual calendar Member-Gen. CATEGORISATION OF PROGRAMMES On the basis of duration, training programmes would be captioned as hereunder • Short-duration Up to four days • Medium-duration one week or two weeks • Long-duration above two weeks TRAINING DATABASE Training Centers should maintain a database of training details of all employees of the respective unit, which shall include, 1. Training Needs identified. 2. Training programmes nominated / attended / absented. 3. The training Centers should also maintain details of the programmes conducted, training cost and all other similar information. 4. Director of Training & Development would maintain the training database for all executives. For this, different training agencies should forward training details to Director of Training & Development on a monthly basis. 5. Training details will be periodically up-dated in the personal files of the employees, for which the Training agency would forward the details of nomination / attendance / absence of employees to the Head of personnel concerned. This is the general hierarchy of a Power Generating plant. Here the Chief Engineer is the head of the Unit below which there are a number of Superintendent Engineers for Coal section, O & M etc.. A couple of Section Engineers are reporting to the Superintendent Engineer & are responsible for their respective sections. The section engineer is the person responsible for the day-to-day generating activities in his section. Below section engineer lies the shift Engineer in the Hierarchy. He is responsible of all the shift level activities in the power plant operations which includes running of equipment, monitoring of parameters, filling of log-sheets, marking attendance of contractors & shift labors, delegating jobs to electrical & mechanical depts. etc. There are various sections in a thermal power plant which includes Boiler, Turbine, Cooling Tower etc.. Each section has a contractor & various Gangs working under him. Generally these contractors are Diploma holders & the contract labor is uneducated. Therefore they have least awareness of the amount of gravity of particular equipment in a Thermal power plant. This amount of unawareness often leads to heavy losses in terms of unwanted breakdowns, improper maintenance of equipments & even accidents in the plant. To overcome this problem NTPC designed a special job structure in all of its power plants. This structure is almost the same as above but the change lies at the Bottom most level of the hierarchy, here the contractor is replaced by an Engineer with one or two contract labours working with him. This engineer is trained & fully aware of the problem & issues which will hamper the availability of the power plant. This engineer is coming in shift & is responsible for all the maintenance activities in his area in the shift. There is also the Job rotation in the work which means that the engineer in the Boiler section working for a month will work in the control room for the next month & the person in the control room will work in the respective section replacing the person there. This way NTPC inculcated a sense of urgency & importance among the Bottom most level of the working hierarchy, which constitutes almost 85% of the Breakdowns & about 95% of the accidents in the Thermal Power plant. Conclusion Both the companies follow similar type of policies. They also have a collaboration under which the TNEB employees are trained at various NTPC branches. NTPC has engineers, as its main manpower strength. In NTPC one engineer replaced four staff members in the recent years. Now a days more stress is laid on providing various technical/managerial training to the employees to make them more responsible and growth oriented. MIS in Power Generation, Transmission & Distribution Management Information System (MIS): Management Information System (MIS) is defined as a system that collects and processes data (information) and provides it to managers at all levels who use it for decision making, planning, program implementation, and control. The components of the MIS are: 1. Hardware 2. Software 3. People 4. Communications systems such as telephone lines and data itself. Power Sector… a glance • • • • • The Indian power sector has grown manifold in size and capacity since independence. The generation capacity has increased from 1,362 MW in 1947 to 1,35,780 MW as on today. The per capita power consumption has increased to approximately 384 kWh by 2000-01 and 660 kWh in 2006-07. The access to electricity has improved tremendously with electrification of almost 87% villages and energisation of 65% pump sets. The capacity of transmission and distribution lines has also increased. The efficiency of the thermal plants has improved over the years with the plant load factor (PLF) for thermal power plants at the national level improving to 69% during 2000-01 with approximately 530 billion units generation in the same period. The reform process is in progress in several states under the overall guidance of MoP to achieve vision of “reliable, affordable and quality power for all by 2012” It is aimed at bringing about sustainable improvements in the operations of the utilities and making them viable businesses. The reforms have brought about various improvements in operational structure, commercial orientation, transparency in operation and overall customer orientation in several states. • • • The Role of IT in Reforms • • • To enable the core business operation at the transaction level, INFORMATION SYSTEM would lay the foundation for sustainable reforms. This will ensure world-class practices and controls at the operational level and would enable substantial improvement in the overall health of the utilities. The overall quality of data will improve and thereby an overall improvement in the flow of information for decision support. Information technology (IT) would thus become the key enabler in the initiatives under the reform process. To enable the core business operation at the transaction level, INFORMATION SYSTEM would lay the foundation for sustainable reforms. This will ensure world-class practices and controls at the operational level and would enable substantial improvement in the overall health of the utilities. The overall quality of data will improve and thereby an overall improvement in the flow of information for decision support. Information technology (IT) would thus become the key enabler in the initiatives under the reform process. • • • MIS In Power Sector • • • • • • Management Information System (MIS) for the power sector should provide relevant information at various decision-making levels. It should generate information for grid management and control, for monitoring agencies like regulatory commission and other central agencies like CEA and PFC, and for internal management of SEBs. For SEB management, MIS should provide relevant information at each level of the organisation in a timely and accurate manner. For MIS, information flow is required from lower level to higher level partly in real-time and in batch mode. The real-time information flow requires networking within the organisation. MIS for power sector will include information on finance, operations, customer satisfaction and development/ investment including that of human resources. The structure of MIS should be SEB-specific to address the differences in organizational structures and responsibilities at various levels, but at the same time should be generic enough to provide standard information at the national level. Requirements of MIS Figure below gives the information requirements for some key areas for different levels of management in Distribution companies/SEBs. Information Requirement at Top Level MIS in Generation The major system for power plant monitoring and control are :  Process control system  Plant monitoring system  Operational monitoring system  Power plant maintenance  Automatic generation control  Load frequency control  Economic dispatch Process control system  Closed loop control system that takes it direction from the energy management system (EMS) and automatically collect plant data by reading various measuring instruments.  Physical and electrical parameters associated with the boiler, turbine and generator are monitored on a continuous cycle basis.  Alarms and events are logged for getting any indication of any unwanted conditions.  Controls of pumps, valves and switches for routine functions and for start ups or shutdowns are provided. Plant Monitoring system  Includes Data collection system for fuel monitoring and performance calculation.  No control action are performed  Data is stored and retrieved as required to prepare reports and performance analysis Operational monitoring system  Used by plant operators to enter manually collected operational data for record keeping, report writing and analysis.  In addition to this, the power plant may also use computers for security, controlled access and chemical analysis. Power plant maintenance  It stores pertinent information for analysis of maintenance cost and evaluation of equipment performance.  The interactive portion of the system provides plant personnel with the capability to enter problem data, planning data and work execution data. Automatic Generation Control  Automatic Generation Control (AGC) is a feedback control system that regulates the power output of electric generators to maintain a specified system frequency and/or scheduled interchange.  As the load varies rapidly throughout the day, it is imperative to have a system that will maintain continuous and reliable flow of power within the system. Load frequency control  LFC system monitors generation load, constantly looking for imbalances.  The LFC system needs to maintain frequency at the scheduled value, net power interchanges with the neighboring control areas at the scheduled values and power allocation among generating units at economically desired values. Economic dispatch  The system includes an Economic Dispatch Calculation program that dispatches the system generation required to supply a given load in a manner that minimizes the cost of production.  The dispatcher also selects the appropriate economic parameter set to match the fuel that the generator is currently burning.  Different generating units that are online have different cost of generation.  This system takes into account not only per unit generating cost of power plants but also their geographical location. MIS in Operation  Boiler Operation - Pressure control. - Temperature control. - Steam water mixture control. - Water level control.  Turbine Operation => Valve control - Main steam valve, Emergency stop valve, Control valve MIS in Maintenance • Breakdown Maintenance - After the fault, Corrective measures. • Preventive Maintenance - Before the fault. - Preventive measures. MIS in Power Transmission  Power Transmission manages the construction, operation, and maintenance of grids, transmission substations, and switch stations. The transmission of power is monitored by LDC owned by State/Central. Load Dispatch Centre  The objectives of LDCs are the increasing of the network security and reliability of grid operation, the supporting of grid control with high developed software functions for higher efficiency of generation, transmission and distribution, the promoting of the Energy Management Functions and Scheduling, and the accelerating of the information exchange for economical energy and plant management.  The LDCs have modernized SCADA including RTU in sub-stations and the required telecommunication equipment and links (PLC, Microwave) through which the real time data of whole region system is being displayed. This is very essential for time stamping of the happenings of the system and analysis of the data being acquired through SCADA system.  With the implementation of Availability Based Tariff (ABT), the Techno- commercial aspects of grid operation has become prominent and inter-regional and intra-regional power trading is being done with surplus/ deficit of power. Hence the role of Load Dispatch Centre becomes more vital in trading this power on the basis of frequency of the system. MIS Reports from LDC  Energy Import/Export from one state to other.  Feasibility studies for setting up new Sub Station/Transmission line & Generating Stations.  Reliability Index of each EHT line and Sub Station  Load flow studies  Gap between demand and supply MIS in Distribution Sector  For MIS, information flow is required from lower level to higher levels with some information in real time and some in batch mode. For real time information flow, networking within the organization is needed. In addition to this, information management required for monitoring and decision-making will be different at various levels in hierarchy. MIS should be able to take care of different needs at various levels. Otherwise huge data generated from MIS will not be of any significant use. The structure of MIS should be SEB specific because of difference in their organizational structures and responsibilities at various levels across the organization.  A generalized framework of MIS is presented which may be tailored to suit the needs of specific SEB/utilities.  MIS should not only cover Money Matters but all those major aspects of Power Business, like operations, customer service, development / investment, human resources, information for decision support etc.  Not a standard can be adopted across all utilities, but a generic institutional framework in a national perspective, can specifically be tailored to suit the prevailing culture in each of the utilities leaving ample scope for information concentration and comparison. Flow of Information in Power Distribution Sector Requirement for Implementation of MIS • Periodically collect, collate and convert data into a standard format • Store and analyse the collated data • Identify deficiencies in the existing system by analysing the data • Strategic planning for bringing improvements in the system Benefits of MIS  Availability of accurate and timely information  Effective mechanism for decision Support  Enables pro-active decision making (Such as load planning and demand management)  Identifies possible areas of energy loss (through analysis of consumption and billing patterns)     Target based monitoring mechanism for increased accountability Transparency in administration Aids strategic planning in areas Such as tariff structuring management Develops what if Scenarios Such as analyzing the impacts in tariff plans on the revenue and financial health of the organization Thumb Rules Bolier efficiency- 87.5% Turbine efficiency- 90% (max. efficiency of IPT out of three modules) Condenser efficiency-50%(reasons for imperfect vaccum- air ingress, tube deposits) Fuel cost -66% , operating cost-6%, capital cost-28% Cycle work done heat rejected Carnot 60% 40% Rankine 33% 67% Rankine+reheat 37% 63% Rankine+reheat+regeneration 41% 59% For producing 1 unit of electricity – 620 gms of coal + 5 kg of air is required MW= MVA * power factor 1 MW of plant will require 1 acre of land for coal stacking Maximum height of coal stack- 10 meters Subcritical condition = 170 kg/cm² & 535 ºC supercritical condition = 247 kg/cm² & 535 ºC ultra supercritical condition = 270 kg/cm² & 585 ºC AD 700 technology = 375 kg/cm² & 700-725 ºC, efficiency - 50- 52%, fuel saving & CO2 emission reduction -15% DM water cost = cost of petrol in market Coal washing charge= 249/- / ton At same heat content, price of gas= 60% ( price of oil) 1.0% Deviation in findings means 25000 tons of coal loss/annum for 200 MW Unit or approx Rs. 5 crores / year (4000Kcal coal GCV & Rs.2000/ton coal cost) Difference in cost of Energy Audit between B & A is 12 to 14 lacs as against 6 to 8 lacs. ECONOMIC ASPECTS OF INEFFICIENT MACHINES (200 MW) SHORT FALL LOSS CRORES ANNUM 5.0 5.0 1.75 2.5 IN PER TURBINE CYCLE HEAT RATE TG OUTPUT BOILER EFFICIENCY AUX. POWER CONSUMPTION 1.0 % 1.0% 1.0% 5.0 % NOTE:  TG CYCLE HEAT RATE IS TAKEN AS 2000 KCAL / KWh  COAL CV IS TAKEN AS 4000 KCAL / Kg  PRICE OF COAL TAKEN AS Rs. 2000 / TON  LOSS INCREASES WITH MACHINE SIZE Impact of Turbine Efficiency on HR/Output Description Effect on Effect on TG HR KW 1% HPT Efficiency 1% IPT Efficiency 0.16% 0.16% 0.3% 0.16% 1% LPT Efficiency 0.5 % 0.5 % Output Sharing by Turbine Cylinders are around HPT IPT LPT 28% 23% 49% Effect of Condenser Vacuum on Heat Rate 10 MM HG IMPROVEMENT IN CONDENSER VACUUM LEADS (1%)IMPROVEMENT IN HEAT RATE FOR A 210 MW UNIT EFFECT ON HEAT RATE FOR PARAMETER DEVIATION (500MW UNIT) DEVIATION IN PARAMETER EFFECT ON HEAT RATE (KCAL/KWH) 1. 2. 3. 4. 5. 6. 7. HPT inlet press. by 5.0 ata HPT inlet temperature by 10.0 deg C IPT inlet temperature by 10.0 deg C Condenser pressure by 10.0 mm of Hg Re spray water quantity by 1.0% HPT Cylinder efficiency by 1.0% IPT Cylinder efficiency by 1.0% 6.25 6.0 5.6 9.0 4.0 3.5 4.0 TO 20 Kcal/kwh
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