Environmentally sound energy efficient strategies: India

This study was taken up by the Indira Gandhi Institute of Development Research (IGIDR) on initiative from UNEP Collaborating Centre for Energy and Environment (UCCEE), Risų National Laboratory. IGIDR is involved in several policy studies related to energy and environment and took up this opportunity to explore "Environmentally Sound Energy Development Strategies for the State of Maharashtra" in the phase 1 of the study. The objective of the study was to identify potential for Environmentally Sound Energy Technologies (ESETs) and provide a strategy for implementation of a few ESETs in the State, which could also be replicated by other states. The study was extended to estimate potential at all India level during the second phase. This report combines the two phases of the project.

It may be worthwhile to state that prior to this, IGIDR carried out a project on Limiting Carbon Dioxide Emissions through Economic Instruments: Applications to India and Canada, supported by Indo-Canada Link Project and carried out with North-South Institute and Conference Board of Canada, both located in Ottawa, Canada. This project report provides a policy framework for economic instruments in general and joint implementation in particular. The report pointed out that the power system is one of the most important sectors for international cooperation to reduce green-house gas (GHG) emissions.

In the present work, the technologies relating to power system are discussed since power generation is predominantly coal-based, in India, thus leading to environmental degradation and hence greater feasibility of adapting them. The study covers the following:

a. Measures for reduction of Auxiliary Consumption in Thermal Power Plants, an area that has not been studied systematically so far. The study indicates substantial potential for energy savings through up-gradation of auxiliaries.

b. Reduction of Transmission and Distribution (T&D) Losses in Maharashtra State Electricity Board (MSEB) system. The study throws light on the possible savings at the transmission level and recommends a field study in the distribution side to identify loss reduction measures.

c. Demand Side Management (DSM) Options for HT Industries in Maharashtra have been identified. This part of the study is based on an earlier comprehensive study on DSM carried out by IGIDR for MSEB.

d. Barriers in Implementation, Institutional and Financial Mechanisms required for successful implementation of suggested measures have been brought out. Actions required to be taken by various agencies have also been identified.

It is well known that losses in auxiliary operation and T&D system are significant and need to be reduced. It is also accepted that potential for savings through DSM is considerable. The present work takes up case studies to suggest how and how much can be reduced and provides detailed information which can be useful for future investments in this area. It thus provides concrete opportunities for further action.

The study was conducted in two phases. In the first phase two power stations of MSEB (Nasik and Parli) were studied for exploring possible measures for reduction in auxiliary consumption and evaluate the potential. The transmission and distribution losses in MSEB system, DSM options for HT industries in Maharashtra and barriers in implementation were also covered in this phase. Interim results of the study were presented to MSEB in Feb. '94 in order to get feedback. The report of the phase 1 was submitted in October 1994.

The scope of the study was enlarged in the second phase to include case study of two more power stations outside the MSEB system. Korba Super Thermal Power Station of National Thermal Power Corporation (NTPC, a federal government utility), and Panipat Thermal Power Station of Haryana Electricity Board (a state government utility of the Haryana State) were selected to study diversity in auxiliary consumption across utilities. The second phase also included estimation of all India potential for energy and emissions savings for 200/210 MW power plants based on the above the above four case studies. It is hoped that, following this study, a plan for implementation will be prepared by the concerned agencies.

We thank UCCEE, specially Dr. Pramod Deo and Dr. John Christensen, for providing financial support for the study. The study was taken up by us on initiative from Dr. Deo, who also provided valuable help during the study. Dr. Deo also gave useful comments on the draft of the study.

We would also like to thank MSEB officials, specially Mr. M.V. Dekhne, Member (Technical), Mr. R.C. Gupta (Tech.Director) and Mr. G.G. Dalal (Dy.Chief Engineer) for their cooperation during the study. Mr. Dalal not only provided the requested information but also helped in arranging our site visits. Mr. R.G. Patil (Chief Engineer), Mr. Ghanekar (Dy.C.E), Mr. Ondkar (SE) and their colleagues provided us the valuable support in conducting field study at Nasik TPS. Mr. S.M. Phadke (Dy.C.E.) and his colleagues helped us at Parli TPS. Mr. Kukde (C.E., Koradi TPS) gave valuable comments during the interim presentation at MSEB, Bombay office.

We take this opportunity to thank Mr. S.M.C. Pillai, Director (Operations), NTPC, New Delhi, for making the plant visit to Korba STPS successful. We appreciate the help and cooperation extended by Mr. B.M. Bhattacharya, DGM (OS) and Mr. K. Ratna Rao, Manager (OS) of NTPC Western Region Headquarters, Nagpur. We thank Mr. J.N. Sinha, General Manager, Mr. S.R. Yadav, DGM (O&M), Mr. R.S. Sharma, DGM (O&M) and their colleagues at Korba STPS who were extremely helpful in providing relevant information, fruitful discussions and advice on our study, in spite of their busy schedule.

We thank Mr. J.L. Arora, Engineer-in-Chief, Panipat Thermal Power Station, for making the visit to Panipat TPS successful. We also appreciate the help and cooperation extended by Mr. A.R. Gupta, Superintendent Engineer and his colleagues at Panipat TPS.

Mr. M.V. Dekhne and Mr. J.C. Shah and Mr. Redlinger reviewed the report and gave useful comments. Mr. Dekhne specifically pointed out possibility of PF improvement in auxiliaries and proper sizing (2.9.1 and 2.9.2 was added after that). We sincerely thank him for this. We appreciate the comments and discussions provided by Dr. Bhaskar Natarajan, Director, Energy Management Center, New Delhi on this study.

2.3 Unit capacity-wise share of generating capacity and energy generation in India

Environmental protection and ecological balance are essential to ensure that a country's economic development is sustainable in the long run. Land abuse, water and air pollution, soil erosion, deforestation, loss of biological diversity, siltation of rivers, and other problems associated with resource (fuel) extraction and deployment pose a threat to ecological security and human health. Over the past decade, it has been recognized by scientists and policy makers worldwide that increasing atmospheric concentrations of greenhouse gases originating from human activities, particularly the burning of fossil fuels, may lead to catastrophic environmental impacts due to global warming/climate change.

As a developing economy, India's consumption of energy is increasing and is likely to grow, given the attempt to provide a better standard of living to her population. Thus, during the last decade, India's energy consumption more than doubled - from 91 million tons of oil equivalent (mtoe) in 1980-81 to 189 mtoe in 1990-91; it was 219 mtoe during 1994-95 (CMIE, 1995). Most of the increased energy consumption has come from coal and oil, that are also associated with emissions of carbon dioxide (CO₂), oxides of sulphur (SO_x) and nitrogen (NO_x) and particulates. CO₂ is a greenhouse gas (GHG) and limiting its high level of global emissions is a major issue in the debate on global warming and climate change. Table 1.1 gives the data on primary energy supply in India for selected years during the last decade.

Coal

Oil

Natural Gas

Hydro

Nuclear

Total supply of energy

1980-81

1985-86

1989-90

1990-91

1991-92

1992-93

1993-94

1994-95

55.97

76.76

100.73

106.63

115.29

120.06

124.02

128.52

26.76

44.78

53.58

53.73

54.37

56.37

57.52

58.00

2.02

6.97

14.55

15.42

15.98

3.88

4.24

5.17

5.96

6.05

5.82

5.86

6.88

0.25

0.42

0.39

0.52

0.46

91.38

137.12

180.61

189.17

199.97

206.83

212.72

219.24

Economic development has strong linkages with energy, since higher growth requires higher energy inputs. However, the amount of extra energy required for growth is also a function of the efficiency with which energy is used. A low energy intensive growth path (as in Japan's economy, for example) would require less incremental energy for growth. An economy adopting a low energy intensive path would require a lesser amount of energy for a particular level of GDP. It is therefore important to modify growth paths of developing economies in order to reduce pollution and future GHG emissions.

The energy sector accounts for 25 to 30 per cent of the planned investment in India. Within every sector, a major part of the increased energy requirements are met by the power sector. Electricity consumption has been growing at a rate of 8 to 10 per cent per year in India and the power sector accounts for more than 60 per cent of the investments in the energy sector. The planned investment in the power sector is about Rupees (Rs.; 1 US$ = Rs. 35 approx.) 800 billion in the Eighth Plan (1992-97), besides substantial investment proposals received from the private sector. Thermal power dominates the installed power capacity of the power sector in India (about 72 per cent of the total 81,164 MW in 1995) and also has the highest growth rate.

Most of the thermal power is generated from coal, one of the most polluting fuels. In fact, coal is a major energy source in India as well and provides more than 60 per cent of the country's commercial energy requirements. Considering India's energy resources, coal may continue to provide more than 60 per cent of her energy needs in the future too. On the other hand, as a party to the Earth Summit at Rio in 1992, India has a commitment to adopt strategies and take all possible actions that help in reduction of emission of GHGs. Besides the issue of GHG emissions, several cities in India are facing serious environmental problems due to local pollutants. Environmentally Sound Energy Technologies (ESETs) require less primary energy for the same amount of end-use energy. This is achieved through efficiency improvements in energy production and use. Therefore, they could help in reducing energy consumption and associated emissions without retarding the economic growth or output and are thus potential alternatives to reduce GHG emissions. ESETs not only address global environmental issues due to reduction in GHG emissions, but also local environmental issues, since emissions of pollutants like NO_x, SO_x, etc. are also reduced.

In a study carried out at IGIDR, on the impact of global warming due to fossil fuel use, (Parikh and Gokarn, 1993) it has been shown that the highest emissions in India are due to the power sector (42 per cent), followed by iron and steel (9.5 per cent), road and air transport, coal tar and so on. However, the construction sector accounts for the highest share, when direct and indirect emissions are considered. So far, energy policy in India has emphasized savings of oil and electricity. However, taking into account the concerns of climate change, India may have to shift its policy to include reduction in the use of coal as well, even though it might involve a net loss in savings. For example, if 250 PJ of energy (1 PJ = 10⁶ GJ) is saved from coal, it would mean a saving of Rs. 2,706 million only. If the same energy is saved from oil conservation it could save Rs. 7,710 million. Thus, conservation of energy from coal will involve a loss in savings of Rs. 5,004 million when compared to savings that can be made by oil conservation. This can be interpreted as an incremental cost to the Indian economy for following a coal conservation policy.

1.1 Environmental impacts of energy related activities in India: a review of studies

The Asian Development Bank (ADB) commissioned a study (Anon, 1993) to bring out the impacts of climate change and India's options to cope with them. The study compares the GHG emission estimates made for India by various experts. Sectoral emissions for agriculture, energy and transport are also discussed. A major part of the GHG emissions in India are from production and energy use activities. The study pointed out that climate change may affect biomass productivity and forest fires may occur frequently. It may also have adverse impacts on biodiversity. Potential abatement measures indicated in the study are increased energy utilization efficiency, deployment of renewable energy technologies and afforestation. Estimates of GHG emissions by CSIR (under the national programme for emission estimation) and other agencies like OAK Ridge and US EPA, as well as energy sector policy issues and environmental issues have been discussed in the study. The study recommends that, considering projections of increased commercial energy supplies in India, efforts are required to reduce future rates of CO₂ emissions.

Since energy use is a major source of GHG emissions, it is recognized that efforts to save energy are required in all countries. Parikh and Gokarn (1993) have examined the energy flow in the Indian economy considering a 60 sector input-output model. They argue that it would be more expensive for India to save energy from coal (which is now advocated at international levels) than from oil. India has pursued the policy of saving oil, because of her dependence on oil imports. If priority is given to GHG emissions reduction, India will have to forego substantial savings and also change her sectoral priority in favour of saving coal. The authors also show that the largest contribution to direct emissions came from the power sector while direct and indirect emissions by final demand are the largest in the construction sector. Therefore, these two sectors need in-depth analysis to identify ways to reduce emissions without compromising developmental goals.

Emissions of CO₂ and other pollutants can also be reduced by improvements in the power system. Chattopadhyay and Parikh (1993) demonstrate that reduction in emissions can be achieved at a substantially lower cost with integrated optimal operation of the regional grids. Other options include gas based generation and thermal efficiency improvements of plants.

The installed capacity of generation in India was 81,164 MW as on March 1995; this comprised 20,829 MW of hydel, 58,110 MW of thermal and 2,225 MW of nuclear units. During 1994-95, there was an increase in actual power generation of 8.5 per cent over the previous year. This was mainly due to a sharp growth of 17.3 per cent in hydro generation during the year, helped by a healthy south-west monsoon. However, thermal generation was less than the target, reportedly due to shortage and poor quality of coal, unscheduled forced outages and paucity of funds with the State Electricity Boards (SEBs). With the increasing demand situation and additions in generating capacity, power generation will increase in the future, and will lead to further environmental degradation. Table 1.2 highlights some of the key parameters of the Indian power performance during 1994-95.

The financial performance of the SEBs has been below par. The commercial losses of all the SEBs put together were Rs. 41,170 million by March 1992; this increased to Rs. 43,580 million by March 1993, to Rs. 49,950 million by March 1994 and is estimated to have reached Rs. 63,320 million by March 1995. A large portion of these losses is accounted for by the sale of power to agriculture and domestic consumers at a cost lower than the cost of production. Due to their poor financial conditions, the SEBs are unable to make further investments for environmental improvement.

A feature of the Indian power scene that causes concern is the decreasing share of hydro power as compared to thermal power, for this means increasing air pollution. The share of hydro capacity was 42 per cent of the total capacity in 1980 but only 27 per cent as on March 1994. The central government has initiated actions for evolving ways and means to increase the share of hydro power in the total installed capacity to 40 per cent by the year 2002. The Central Electricity Authority (CEA) has estimated India's hydro energy potential at 84,044 MW with 60 per cent load factor, which would mean an annual energy generation of 600 billion units. This is, however, unevenly distributed, with three-fourths of the potential situated in the northern and north-eastern regions. The Brahmaputra basin alone accounts for 41 per cent of the total potential, of which only 1 per cent has been exploited. The main reasons for low percentage of development over the potential are: (i) The bulk of the potential lies in the states which lack the resources to develop them; (ii) Inter-state disputes and sharing of river waters; (iii) Problems in land acquisition, afforestation and rehabilitation of project affected persons.

An important development is the government decision to encourage private - both domestic and foreign - investment in generation. Till July 1995, 243 project proposals for adding a total capacity of 90,368 MW at a total cost of Rs. 3,354 billion have been received. The entry of private plants raises a new set of issues concerning procedures and terms of contract and regulation.

The targets for new transmission lines during 1993-94 were fixed at 4,606 circuit-km consisting of 1,506 circuit-km of 400 kV and 3,100 circuit-km of 220 kV lines. As on November 1994, 995 circuit-km of 400 kV and 1,757 circuit-km of 220 kV lines had been completed.

All-India transmission and distribution (T&D) losses stood at 22 per cent during 1994-95. The much higher loss figure reflects considerable theft of power and inefficiency. The country lost an estimated revenue of Rs. 50,000 million due to T&D losses. Investments in the T&D systems have been much lower than the prescribed 40 per cent allocation of the total power sector outlay (it was 24.9 per cent during 1993-94), which partly accounts for the high T&D losses. It can be estimated that a one percentage point reduction in overall T&D losses would be equivalent to an addition of 800 MW of capacity.

Most of the losses occur at the distribution level (i.e 11 kV and below), where losses arising from pilferage of energy, inaccurate meter readings, defective meters etc. are also considerable. Though pilferage may not amount to a net economic loss to the country, the loss of revenue to the SEBs is significant; their ability to serve paying customers is also affected adversely. Deterioration in the efficiency of the T&D system due to overloading of transformers, transmission lines, distribution network and increased rural electrification covering thinly spread consumers, have contributed to high T&D losses.

In developing countries, reducing per capita electricity consumption to preserve the environment is not an option because consumption levels are very low. However, the efficiency with which electric power is used can be increased. In the fifties, per capita consumption of power was 16 kWh only. It crossed the 100 kWh mark in 1975-76 and rose to 200 kWh per capita in 1987-88. During 1992-93 the per capita consumption was 283 kWh.

The agricultural sector accounted for 30 per cent of power generation during 1994. This is because of the growing use of electric pumpsets in this sector. 10.5 million pumpsets had been energized by 1994-95. Domestic consumption accounted for 18 per cent of the generation. However, the share of industrial consumption has been declining from about 60 per cent in 1979-80 to 40 per cent in 1994-95. This may only partly be attributed to increasing reliance on captive power plants.

During 1994-95, the target for village electrification was 3,708 villages, against which 1,317 villages were electrified up to December 1994. About 85 per cent of the villages in India have been electrified by 1994.

In order to meet the growing demand and in view of the slippages in capacity addition from targets and unavailability of investable funds, the government has invited entry of private parties to the power sector. There are 243 private sector projects pending till July 1995. If all of them materialize, the total capacity addition from these projects would be 90,368 MW, involving an investment of Rs. 3,354 billion. Of these 43 are foreign companies and involve 33,554 MW costing Rs. 1,292 billion. Memoranda of understanding have been signed for 123 projects with a capacity addition of 55,609 MW at a cost of Rs. 2,096 billion (CMIE, 1995).

The central government on its part has decided to accord some of these projects a counter guarantee against the commitment of state governments on payment for energy supply. It has been decided that all private companies would be allowed a debt-equity ratio up to 4:1. Fixed cost including 16 per cent return on equity can be recovered at 68.5 per cent Plant Load Factor (PLF). Incentives are prescribed beyond this PLF in the form of additional Rate of Return (ROE) (up to 0.7 per cent) for each 1 per cent rise in PLF. The customs duty for import of power equipment has been reduced to 20 per cent. A 5-year tax holiday has also been allowed in respect of profits and gains of new undertakings for either generation or generation and distribution of power. Excise duty on capital goods and instruments in the power sector has been reduced to a uniform rate of 5 per cent. Foreign investors are also allowed to repatriate dividends entirely in dollar terms, with full protection against exchange rate fluctuations.

The Eighth Plan provided, for the first time, a capital outlay of Rs. 10,000 million for energy efficiency measures. The targeted energy savings are 5,000 MW and 6 Mt in the power and petroleum sectors respectively. A target of 2,250 MW of demand savings in the industrial, commercial, agricultural and domestic sectors has been set for the Eighth Plan. The National Energy Efficiency Programme during the Eighth Plan includes a policy package comprising financial arrangements including creation of a revolving fund, technical assistance, technology development, selective legislation and developing institutional capabilities. However, the targets and the capital outlay have been fixed arbitrarily with no realistic measures specified to achieve them.

Demand side management (DSM) measures include accelerated measures for energy efficiency, peak load shifting and other measures. DSM is therefore more than energy efficiency. DSM does not, by any means, eliminate the need for more power in the future. However, considering the expected high growth of power requirements, DSM reduces the need for new capacity significantly.

An integrated framework for analysis of DSM options together with electric utility planning is called for (Chattopadhyay, Banerjee, Parikh, 1994), in order to evaluate all the benefits associated with DSM programmes.

Several policy changes need to be effected to encourage energy efficiency such as abolition of customs duty for energy saving/and energy audit equipment not available in India, and waiver of excise and sales tax levies on energy saving devices.

A power plant consists of several pumps, motors and other equipments besides main equipments (boiler, turbine and generator). These are collectively known as power plant auxiliaries. Auxiliaries themselves consume power in the process of power production. Auxiliary consumption is expressed as a percentage of the power produced by the plant. It can vary in a thermal power plant depending on type of fuel, unit size, efficiency of auxiliaries, plant load factor (PLF) etc. PLF has significant impact on the auxiliary consumption. Low PLF increases percentage auxiliary consumption as the plant auxiliaries are optimized for full load operation in most of the power plants. The auxiliary consumption has been observed to vary from 5 to 14 percent in India. In a majority of cases, there is scope to reduce this below 10%.

There are several options to improve supply side efficiencies and reduce emissions through application of environmentally sound technologies. These include new technologies as well as upgradation of existing technologies. The supply side management has benefit of addressing the issue at the point of supply, a relatively limited area where efforts can be concentrated and benefits derived without involvement of too many agencies. For example, in case of electricity supply, the utility concerned is the agency, and efforts can be concentrated in specific areas such as on generating equipments within the power plants, T&D lines in the grid and so on. Supply side options offer another benefit; expertise to understand and implement the technologies is available at the agency (utility) level. The options for the electricity sector can be briefly classified as follows:

High efficiency systems. New technologies for the power plants offer quantum jumps in efficiency. Thus combined cycle plants using gas offer efficiency levels above 45%. Technologies such as Steam Injected Gas Turbines (STG), non-thermal cycles like Kalina Cycles, pressurized fluidized bed boilers, gas turbines using gasified coal etc. fall into this category.

Non carbon fuels and renewables. This includes nuclear power, solar power and other renewables, and technologies such as fuel cells etc.

Cogeneration and power from waste. These technologies are environmentally sound since the waste is currently burnt at very low efficiencies.

Supply side management options. These include plant renovation and uprating, upgradation of auxiliaries, system improvement through measures such as reduction of T&D losses, efficient grid operations, coal beneficiation etc.

Technologies and energy use patterns vary between and within the different regions in India. Under the overall policy thrust of the central government, policies to effect changes in these are made at the state levels. Therefore, policies for implementation of any measure aimed at changes in technology and energy use pattern have to be prepared at the state level. In this study, options for reduction of emissions from thermal power stations with a view to identifying ESETs have been identified. ESETs can be adopted for generation (supply side) as well as use (demand side) of electricity. We look at options for both supply and demand sides in the study. On the supply side, the possibilities of reducing auxiliary consumption in thermal power plants by using efficient technologies have been examined at an all-India level. Auxiliaries consume a significant amount of power (between 8 and 14 per cent) in thermal plants in India and therefore, even a 1 per cent reduction implies substantial savings. Transmission and distribution is another area where losses are high in India. Possibilities for reduction of T&D losses have also been explored. On the demand side we look at options for the High Tension (HT) industries in Maharashtra, which are the major consumers of power in the state. End-of-the-pipe treatments like scrubbers to reduce sulphur pollution address the problem of environmental pollution only partially. Such measures can only improve the local environment, leaving the CO₂ problem untouched. The measures discussed in this study consider CO₂ as well as local pollutants.

(i) Case study of two power stations of Maharashtra State Electricity Board (MSEB) with a view to analyse auxiliary consumption.

(ii) Preliminary study of MSEB transmission system with the view to examine losses.

(iii) Potential for demand side management options in high tension industries in Maharashtra.

(i) Extension of the phase 1 auxiliary consumption study to include two more plants outside Maharashtra. This was done with the view to get better insight into auxiliary consumption pattern and potential for improvement. One plant of the National Thermal Power Corporation (a federal government owned utility) at Korba, and one that of Haryana State Electricity Board at Panipat were included in the study.

(ii) Estimation of potential for auxiliary consumption reduction at all India level. A systems approach has been developed to evaluate the savings from reduction in auxiliary consumption at an all-India level.

The state of Maharashtra is one of the most progressive states in India accounting for the largest share of industrial output and installed capacity for power in the country. Considering the importance of the power sector within the energy sector in India and the polluting nature of thermal power, it was decided to cover efficiency aspects of the power sector in the study. Within Maharashtra, the potential for application of ESETs has been studied at a utility level. The Maharashtra State Electricity Board (MSEB), which is a major state utility in Maharashtra, was chosen for the detailed study of potential. The study covers the following:

(i) Measures for reduction of auxiliary consumption in thermal power plants, an area that has not been studied systematically so far.

(ii) Reduction of transmission and distribution losses in the MSEB system. The purpose of the study was to throw light on the possible savings at the transmission and distribution level.

(iii) Identification of Demand Side Management options for High Tension industries in Maharashtra. This part of the study is based on an earlier comprehensive study on DSM carried out by IGIDR for MSEB.

NTPC is a federal government utility engaged in generation of power and distribution in bulk to other state utilities. NTPC is considered efficiently managed utility. Therefore one power plant of NTPC (at Korba) was included in the study of auxiliary consumption.

HSEB is a relatively small utility in the northern region of India. One plant of HSEB at Panipat was included for study of auxiliary consumption.

The availability of a generating unit depends largely upon the operational reliability of auxiliaries and the ability in the auxiliary system to ensure continued availability of the unit in the event of failure of an auxiliary. In a thermal power station, auxiliaries are the consumption points. To the extent this consumption can be reduced, either by improving the design of the equipment or by optimizing auxiliary system design, generation efficiency can be increased and energy so saved be made available for sale.

A look at the progressive changes over the years in unit size and operating parameters of thermal generating sets indicates a steady development in unit sizes with a variety of technologies, upgradation of operating parameters, etc. The diversity of unit sizes in thermal power stations in India ranges from 30 MW to 500 MW of capacity. Most of the capacity addition done in the late seventies and mid-eighties have been in the 110 MW/210 MW unit capacity sizes which have completed about 50 per cent of their useful life. The present trend has been to add larger unit sizes of 250 MW/500 MW capacity. Alongside the growth in unit sizes, considerable technological innovations have also taken place in upgradation of auxiliary systems and improvement in designs of auxiliary equipment. These changes have increased the operational reliability and efficiency of the auxiliaries and of the power station in general.

As described earlier, PLF has a significant bearing on a unit's auxiliary consumption. Auxiliaries in almost all the plants are optimized for full load operation. Therefore, at part loads, the auxiliary consumption does not reduce in proportion to the output, resulting in high auxiliary consumption.

Figure 2.1 shows the state-wise average auxiliary consumption figures of thermal power stations with respect to the annual PLF. It can be seen that for those states whose auxiliary consumption is very high (Bihar and Durgapur Projects Ltd. (DPL), above 12 per cent) the annual PLF is as low as 30 per cent. For states with higher PLFs, the auxiliary consumption figures are lower. The National Thermal Power Corporation (NTPC) power plants have a significantly high annual PLF and the lowest auxiliary consumption. The SEB thermal plants also have moderately high auxiliary consumption figures on the average, with consumption in states like Uttar Pradesh (UP), West Bengal (WB), Madhya Pradesh (MP), Karnataka and Tamil Nadu (TN) being quite high.

One should, however, note that an over emphasis on thermal PLF can be a misleading indicator of power system efficiency. For example, if a good monsoon provides more water to generate electricity from hydel plants, it may be advisable to generate less from thermal plants. Thus, factors like the thermal unit backing down due to high hydro generation during the monsoon months, may lead to low thermal PLFs. Therefore, it is necessary to consider factors like backing down time and energy lost due to backing down, partial and forced outages, etc. while analyzing the PLF and associated trends in auxiliary consumption figures.

Figure 2.2 shows the unit-wise auxiliary consumption figures for all 210 MW units in India. The units have been graded into different categories based on their auxiliary consumption figures. As seen in Figure 2.2, grade F has the highest auxiliary consumption; above 12 per cent. Bokaro Thermal Power Station (TPS) units-5,6 and 7 are in this category. The grade E with auxiliary consumption between 11 to 12 per cent consists of 16 units spread over five thermal power stations. These are at Gandhinagar TPS, Satpura TPS, Kolaghat TPS, Parli TPS and Panipat TPS. The grades B, C and D, i.e. those with auxiliary consumption in the range of 8 to 11 per cent, account for the maximum number of generating units in India. Grade-D (10 to 11 per cent) has 22 units from 8 stations, Grade-C (9 to 10 per cent) has 31 units from 9 stations while Grade B (8 to 9 per cent) has 32 units from 12 thermal power stations. There are only four units of 210 MW capacity in grade A, Tuticorin-1,2,3 (7.56 per cent) and Badarpur-4 (7.95 per cent) where auxiliary consumption was less than 8 per cent.

B: Neyveli (8.11), Tuticorin 4,5 (8.2), Vijaywada 1-5 (8.22), Singrauli 1-5 (8.23), Badarpur 5 (8.29), Mettur 1-4 (8.3), Unchahaar 1-2 (8.43), Ropar 1-6 (8.55), Rayalseema 1 (8.6), Bandel 5 (8.62), Nasik 3-5 (8.72), Durgapur 4 (8.73), Ukai 3-5 (8.88), Korba STPS 1-3 (8.86)

C: Vindyachal 1-6 (9.0), Kahalgaon 1,2 (9.14), Khaperkheda 1,2 (9.2), Raichur 1-3 (9.29), Dadri 1-4 (9.6), Wanakbori 1-6 (9.65), S.Gandhi 1,2 (9.7), Kota 4,5 (9.8), Korba (W) 1-4 (9.94)

D: Farakka 1-3 (10.05), Chandrapur 1-4 (10.07), Ramagundam 1-3 (10.11), Anpara 1-3 (10.41), Obra 9-13 (10.48), Bhusawal 2,3 (10.59), Tenughat 1 (10.67), Kota 3 (10.74), Koradi 5-7 (10.07)

E: GandhiNagar 3,4 (11.28), Satpura 6-9 (11.3), Kolaghat 1-6 (11.34), Parli 3-5 (11.38), Panipat 5 (11.4)

2.3 Unit capacity-wise share of generating capacity and energy generation in India

With the growth of the power sector, there have been significant changes on the technical front in terms of unit design, sizes and design of auxiliary units. With larger system operations and increasing demand, the trend has been towards larger unit sizes for economic reasons. Thus, the earlier units in the range below 100 MW gave way to 210 MW units and lately, unit sizes of 500 MW capacity are increasingly being introduced.

Table 2.1 provides a detailed state-wise break-up of the installed capacity for the three different groups of unit capacities, i.e. less than 100 MW, 200/ 210 MW and 500 MW. Also shown is the share of the installed capacity as a fraction of the total installed capacity and the share of that capacity group in total energy generation. The following inferences can be made from an analysis of Table 2.1:

(i) At all-India level, 210 MW capacity generating unit sizes accounted for the largest share (48.3 per cent of total capacity), generating 53 per cent of the total energy supply. 110 MW or smaller size units accounted for 33.3 per cent of total installed capacity for 27 per cent of the total generation while 500 MW units had a share of 18.4 per cent in installed capacity with a 20 per cent share in energy generation.

(ii) In the western region, the highest share in the total installed capacity is of 210 MW units (51.3 per cent), which account for 56.8 per cent of energy generation. The rest of the installed capacity in the region is from 500 MW (22.45 per cent) and 110 MW or lower capacity units (24.8 per cent).

(iii) The eastern region has the highest share in total installed capacity from 100 MW or smaller units (56.5 per cent). The region has no 500 MW units in the SEB plants, but 2x500 MW of capacity in NTPC's Farakka Super Thermal Power Station (STPS). 31.8 per cent of the total capacity is of 210 MW unit sizes. In terms of energy generation, 52.4 per cent of the total generation in the eastern region was from 100 MW or smaller unit sizes and 41.5 per cent from 210 MW unit sizes. The 500 MW units however contributed less than 4 per cent of energy to the regional generation with 11.7 per cent share in capacity. It is evident that these units were operating at quite low PLFs.

(iv) The northern region has 44.4 per cent of installed capacity from 210 MW capacity units, 39.4 per cent of capacity from 110 MW or smaller capacity units and 16 per cent from 500 MW capacity units. The higher share of 110 MW and lower capacity units is due to the larger share of small hydro units in the region.

(v) 210 MW unit sizes have the largest share in the total installed capacity with a share of 64% in the southern region, 51.3 per cent in the western region and 44.4 per cent the northern region. In terms of share in energy generation too, the 210 MW units contribution was highest in all the regions. The 500 MW units also contributed a substantial part (about 20 per cent) of the total annual energy generation of the western, northern and southern regions.

2.4 Equipment-wise break-up of auxiliary consumption in thermal power station

The major electricity consuming equipment in a thermal power station can be broadly classified as follows:

(i) Boiler auxiliary system. Induced draft (ID) fan; Forced draft (FD) fan; Primary air (PA) fan; Coal mills; Electrostatic precipitators

(ii) Turbine auxiliary system. Boiler feed pump (BFP); Condensate extraction pump (CEP); Circulating water pump (CWP); Cooling tower pump (CTP); Cooling tower (CT) fan motors

(iii) Ash handling system. Low Pressure (LP) Pump; High Pressure (HP) Pump; Ash Slurry Pump; Seal Water Pump

Equipment-wise consumption figures at three thermal power stations of capacity (3x210) 630 MW each, viz., Nasik Thermal Power Station (NTPS) Stage-II of MSEB, Parli Thermal Power Station (PTPS) Stage-II of MSEB and Korba Super Thermal Power Station (KSTPS) of NTPC, have been worked out for the peak loading condition (Table 2.2). The break-up calculated in Table 2.2 shows that the auxiliary consumption is about 8 per cent at KSTPS while about 9 per cent in both NTPS and PTPS at full load condition. Figure 2.3 shows the sub-system-wise break-up (boiler, turbine or ash/coal handling) of auxiliary consumption at the three stations. It is seen that the turbine auxiliary system accounts for about 52 to 58 per cent of the total auxiliary consumption in the station while the boiler auxiliary system accounts for about 35 per cent of the total auxiliary consumption. The remaining auxiliary consumption is in ash handling and coal handling systems.

The factors responsible for high auxiliary consumption can broadly be classified into three categories: plant/unit specific factors; external factors; grid specific factors (Figure 2.4).

(i) Technical - relating to the level of technology of various equipment installed in the plant

(iii) Forced outages - occurring due to unforeseen circumstances or breakdown of equipment

(iv) Operational practices and constraints - constraints caused by external factors like poor coal quality that requires operation of additional coal mills compared to the designed numbers. Practices include idle running, improper operation of pumps etc. Thus better practices such as avoidance of idle running, parallel operation of pumps can also help reduce auxiliary power consumption.

The technological factors and related measures to reduce auxiliary consumption are described in detail in this work. The technical factor discussed in this study are only illustrative and general in nature, ie. these could be examined for all power plants. In addition to this, there may be a variety of opportunities specific to individual power plants to reduce the auxiliary consumption.

(a) Method of control of auxiliaries. Some of the major auxiliaries require flow/ capacity adjustments to operate at varied loading conditions of the unit. With fixed speed drives this is achieved by valves, dampers, etc. Inlet guide control is commonly used for ID fan and vane or variable pitch control is used for FD fans. For BFP a hydraulic coupling with scoop control is quite commonly used in 210 MW units. Such control devices create turbulence in the path of the fluid, thereby drastically reducing the device efficiency and consume full power even when partly loaded. Instead, when the flow is controlled by varying the speed of the fan/ pump, smoother fluid flow results in higher efficiency for most of the operating region of the devices and hence for the system as a whole. The energy input is also reduced at part load, resulting in energy savings.

(b) Poor part load heat rate. When the output (KW) needed from the unit is less than its capacity, the unit has to be operated at part load. The current design of the turbine requires same high inlet pressure at part loads as at full load. The inlet pressure is kept constant at part loads by throttling BFP discharge. Lot of energy is wasted in the throttling process. As a result, the heat rate (that indicates input heat per kilowatt-hour of output) deteriorates. The part load heat rate can be improved with sliding pressure operation of the units that allows for reduced inlet pressure at part loads. Similarly, in many of the units there has been a problem of high condenser back pressure at part loads that also causes poor heat rate.

(c) Lack of instrumentation and control (I&C) for proper combustion control. In the absence of total air and load auto control, especially with varying characteristics of coal, it is difficult to run the unit with optimum excess air. Therefore instrumentation for auto air-load control is essential and has to be made operative. In addition, flame monitors provided have not been reliable. As a result operators prefer to continue oil support, resulting in higher specific oil consumption. It is essential to provide reliable flame monitors with redundancy and continuous self checking features.

(d) Method of field energization of electrostatic precipitators (ESPs). ESP is used to trap flyash from the flue gases. Flyash particles are charged and forced out of the gas stream using electric field force and collected in plates. The principal components of ESPs are two sets of electrodes. The first is composed of rows of electrically grounded vertical parallel plates, called the collection electrodes, between which the gas to be cleaned flows. The second set of electrodes are wires, called the discharge electrodes, that are centrally located between each pair of parallel plates. The wires carry a unidirectional, negatively charged, high voltage (between 20 and 100 kV, but typically 40 to 50 kV) current from an external source. The applied high voltage generates a unidirectional, non-uniform electric field whose magnitude is greatest near the discharge electrodes. When that voltage is high enough, a blue luminous glow, called corona, is produced around them. The corona is an indication of the negatively charged gas ions that travel from the wires to the grounded collection electrodes as a result of the strong electric field between them.

The performance and energy consumption of ESPs can be upgraded by pulse energization. Essentially this means that a high voltage pulse is superimposed on the base voltage to enhance ESP performance when operating with high resistivity ash. This is further refined by switching off the voltage to the ESP discharge electrodes during selective periods. This allows a longer period of time between energization cycles, which limits the potential for back corona. Therefore it is possible to reduce energy consumption. Savings in consumption up to 50 per cent are possible.

(e) Energy intensive ash handling system. The presently used wet system consists of a flushing system below each hopper and discharges the slurry into sluice way trenches below the ESP. From the sluice way trench the slurry is transferred to an ash slurry sump. From thereon to the final disposal area 2.5 km away involves two more stages of pumping of slurry. This involves a number of stages of pumping in addition to the power consumed in creating water head required to create vacuum for flushing of flyash.

This enormous amount of energy consumption can be reduced considerably by evacuating the flyash from hoppers directly by a dry pneumatic dense phase conveying system. In the dry pneumatic conveying system the only power consumer is the compressor and the material to air ratio is very high, resulting in much lower energy consumption per tonne of flyash conveyed. This option also offers the advantage of using flyash in future since most of the flyash based products require dry flyash. However, these systems have a limitation on conveying distance for dry flyash. Since the disposal areas are 2 to 5 km away and dry flyash does not have immediate use, an optimum solution would be a dry dense phase pneumatic conveying system up to an intermediate storage silo, adequately sized; slurry preparation below silo; and single stage slurry pumping up to ash disposal area. Such systems are in use outside India and have the advantage of economizing on use of water.

(f) Technological/layout constraints in cooling water system. The condenser cooling water system involves pumping of water to a sump near the turbine hall and then using another set of pumps to pump water through the condenser to the cooling tower. Because of pump technology and layout constraints the number of stages of pumping required is very high, resulting in excessive energy consumption. In addition, the cooling tower technology used leaves tremendous scope for improvement. Improved design of fan blades of lighter material can result in significant savings, and can explored wherever feasible, such as for induced draft fans.

In addition, the cooling tower fan motors can be equipped with space heaters. Since these fan motors operate in highly humid environments, switching off some of them at low load periods, when fewer fans are required to be operated, leads to deterioration of insulation resistance of motor winding. However, keeping all the fans running, causes unnecessary auxiliary power consumption. This problem can be avoided by either retrofitting the motors with space heaters (which is expensive and inconvenient) or simply by making provision for application of 24 V AC power supply to the motor windings. The heating thus provided should be just sufficient to prevent moisture ingress in the insulation. The power consumption in this case is just a fraction of the normal power consumption of the motor.

Power demand in the system varies widely over a 24 hour period. The ratio of peak to off-peak demand is of the order of 1.8 to 2. This requires backing down of substantial thermal capacity during the night off peak hours, in order to regulate the frequency. Since the thermal (coal based) units are primarily designed for base load operation, backing down of units can have the following impacts on efficiency and therefore, on the environment:

(a) Unit efficiency is lower at part load and specific fuel consumption increases

(b) Percentage of auxiliary consumption is higher at part load because the reduction in auxiliary consumption is much less compared to reduction in generation due to backing down

(c) Operational constraints restrict the reduction in the number of auxiliaries in service during part load operation. For instance, due to unreliable operation of coal mills, all mills are required to be kept in service. Only the loading on the mills is reduced. Similarly, units are kept on oil support, thus increasing the fuel oil consumption.

(d) There are some technical constraints in reducing the output of auxiliaries during part loads operation, as discussed below.

Major auxiliaries like ID fans do not have variable speed drives (VSD). Control is effected by inlet guide vane control resulting in higher losses at part loads. Most of the auxiliaries have not been optimally sized from the point of view of part load operation and therefore the number of auxiliaries in service cannot be optimally selected. Some of the auxiliaries have technological constraints that prevent them from being shut down and therefore have to be kept in service even when not required. For example, at the Nasik TPS the cooling tower fan motors have not been provided with space heaters. If the fan motors are shut down during part load operation, the insulation resistance of the motor degrades due to very high humidity conditions, leading to damage to windings and other problems. Units are not designed for cyclic loading. A unit normally designed for "Sliding pressure operation" can result in substantial improvement in heat rate. The power lost in throttling (as is the case with existing units) is high, in the range of 50 to 75 per cent of full flow.

Due to mismatch of reactive power requirements in the grid and that generated, the system voltage dips. To stabilize the system voltage profile, generating units are asked to reduce the active generation and increase the reactive power generation from the unit. This is done by increasing the excitation which is limited by the cooling efficiency of the generator. When the allowable limits of the temperature are reached it is essential to reduce active power load on the machine.

(i) Coal shortages. Due to shortfall in coal receipts, thermal units operate with very little coal stocks and there have been a number of instances of units having to run at low loads or shut down due to coal shortages. This results in low PLF for the unit as well as the plant, and increases the auxiliary consumption of the unit.

(ii) Poor coal quality. It is a common experience in thermal power plants that the coal received deviates from design values in terms of calorific value as well as ash content. Table 2.3 shows the difference in qualities of coal received at the Nasik TPS.

Parameters

Average Coal Received

Plant Design Coal

Fixed Carbon

Volatile Matter

Moisture

Ash

Higher Heating Value

29.5%

18.63%

7.04%

44.88%

2825 kcal/kg

37.3%

27.7%

10%

25%

5000 kcal/kg

If the coal received is one grade inferior coal to the design coal, it implies a difference of 1,000 kcal/kg in heating value and a 7 to 8 per cent difference in ash content.

Coal is received from many sources, widely varying in quality. Such wide variation in moisture, ash content, volatile matter and calorific value of coal seriously affects the flame stability and changes the flame front. In the absence of total air and thermal load auto control in most stations (excess air measurement and auto control is now under implementation at Nasik and Parli TPS) operator confidence is low. In addition, flame monitors are also unreliable. All this results in use of oil support even though it is not required above a minimum load of 100 MW on a 210 MW unit.

In addition to the above, there is a wide assortment of extraneous material like stone, shale, clay metallic pieces etc. in the coal received. This results in inefficient loading operation, causing damage to coal handling equipment. High rate of wear and tear of coal handling equipment, specially the mills, results in non-uniform coal size in the output from the mills, which in turn affects combustion stability. This also increases the down time of coal mills and limits the number of mills available, leading to load restrictions on the units.

The ash content in non-coking coal used in thermal power stations in India, is substantially high, ranging from 35 to 55 per cent. Some of the adverse effects of the high ash content, on unit operation and auxiliary consumption are:

(a) Lower calorific value of coal and additional requirement of handling and milling capacities. The existing design of power plants does not consider the effect of high particulate presence on heat transfer and estimated value of gas temperatures. This quite often leads to high exit flue gas temperatures and consequent loss of efficiency.

(b) Higher loading of Electrostatic Precipitators (ESPs). Compared to design coal, the additional quantity of fly ash to be handled for worst quality coal for a 3x210 MW station is approximately 450 tonnes per day (TPD). This is worked out considering an average heat rate of 2640 MCal/MU. However, providing extra stream or extra field for ESPs to capture this extra ash has an impact on the length of duct and consequently the ID fan capacity. Due to this limitation the ESP upgrade efforts are limited to reducing stack emissions to the extent possible and reducing energy consumption with pulse energization of ESPs.

(c) The ash handling system has to be run for longer durations because of increased flyash quantity to be handled. The additional 450 TPD of flyash to be handled means extra operation of the flyash systems (4-6 hours), that results in high auxiliary consumptions. Normally the ash handling systems are designed for 16 hours of operation per day, but increased ash may require them to operate for 20 hours or more.

(d) Fouling of heat transfer surfaces, resulting in forced outages due to tube leakages.

2.6 Evaluation of options for reduction of auxiliary consumption: case studies

The external grid management factors, coal quality problems and plant related factors responsible for high auxiliary consumption have been discussed earlier in this chapter. A good grid management programme and improvement in the PLF can reduce auxiliary consumption of the units substantially. This study, however, focuses on strategies to reduce auxiliary consumption through improvements in plant/unit related factors. For this, plant specific case studies have been taken up to evaluate various options for reduction of auxiliary consumption. The power stations which were identified for the specific case studies presented here are:

As seen from Figure 2.2, in NTPS and KSTPS auxiliary consumption is in the range of 8 to 9 per cent (Category-B) while PTPS and PNTPS, both have significantly high auxiliary consumption, in the range of 11 to 12 per cent. Thus, this diversity in auxiliary consumption figures among different stations have been analyzed to provide an insight into the particular plant/ unit specific factors which are important.

Large steam generators require large amounts of air to be sucked in and gases and ash thrown out. Large fans are used for this. There are two types of fans in use today, Forced Draft (FD) Fan and Induced Draft (ID) Fan.

FD fans are placed at the air entrance to the air preheater and put the entire system up to the stack entrance under positive gauge pressure. ID fans are located in the gas stream between the air preheater and the stack, either before or after the dust collector. The discharge is at atmospheric pressure and the entire system is placed under negative gauge pressure. These fans handle hot gases, including the original air, the gas equivalent of the fuel added, and leakages into the system.

ID fans are normally loaded to about 70 per cent of their design capacities even at full plant load. Therefore, the potential for energy savings through use of variable speed drives (VSDs) is substantial. The static speed control methods (used in VSDs) for such large rating motors employ a converter fed synchronous motor. The scheme basically comprises two converters, one on the line side and another on the machine side. The line side converter functions as a rectifier and the one on the machine side as an inverter feeding the synchronous motor with variable voltage and variable frequency, thereby controlling the speed.

The VSDs have several advantages over currently prevailing technology of hydraulic coupling and fixed speed motor drives. These include, smooth control of air and water flow over a wider range; absence on limitation of number of starts; no voltage dips in the system from direct on-line starting of large size machines; increased efficiency over wide operating speed range; increased life of motors due to soft starts; simple arrangements, no necessity for large cooling equipment for hydraulic coupling; reduction in size of unit/station transformer rating; reduction in switchgear fault level; totally static equipment hence less maintenance.

The system consists of independent channels, each comprising isolation transformer, source converter (rectifiers), DC link reactor and load converter (inverter). The availability of the system is greatly improved since each channel is sized to 100 per cent fan rating. The isolation transformers serve to step down auxiliary bus voltage to required motor voltage and reduce fault levels of converters. A microprocessor based system can be provided for control, interlocking and protective functions of the drive.

The capital cost of the complete VSD system (for one generating unit) has been estimated to be of the order of Rs. 30 million (based on a cost of Rs. 1.2 million/kW of drive rating for similar drives for a 500 MW unit and suitably adjusted to 1994 prices). The total capital expenditure for NTPS, PTPS or KSTPS (comprising 3x210 MW generating units) would thus be Rs. 90 million. The total annual savings with the VSD system are calculated on the basis of actual running hours, load data and using estimated kW savings from VSDs, reported in the literature. Assuming energy price @Rs. 2.5/Unit, which is the maximum average tariff charged by MSEB, techno-economic studies are worked out (Box 2.1). This price has been used to evaluate the benefits from VSD because the energy so saved could be despatched to the grid for sale.

In the existing scheme 3x50% BFPs of 4MW capacity each are driven by individual fixed-speed squirrel-cage induction motors. To economize on BFP pumping energy costs, by avoiding throttling losses across feed-water control valves at part loads, a variable speed hydraulic coupling between pump and motor is provided. In the absence of confirmation from the manufacturer, it is assumed that it is possible to drive the BFP and the booster pump with the same drive. Therefore, pump costs have not been considered in capital estimates. The alternate system considered consists of 3x50% BFPs with individual driven synchronous motors, the speeds of which are varied by variation of input power using LCI drive. A comparison has been made between the existing BFP drive system consisting of 3x50% 4 MW motor each with hydraulic coupling between pump and motor, and 3x50% alternate system pumps with same rating directly coupled to motor; the speed of motor is varied through LCI drive. The capital cost of the complete VSD system has been taken to be Rs 60 million/Unit (three drives and accessories) i.e. a total capital cost of Rs 180 million for NTPS, PTPS or KSTPS. The savings accruing from VSD in BFP motors are worked out below (Box 2.2).

Pulse energization involves modification of conventional ESP power supplies. Essentially, a high voltage pulse is superimposed on the base voltage which is applied to wire or a rod discharge electrode which increases the density of emitting points and thereby ESP performance. The duration of the pulse is short enough to avoid arcing. A further refinement of this technique is intermittent energization (IE). While the ESP controls would otherwise apply unfiltered full-wave or half-wave rectified DC voltage to the discharge electrode, it facilitates the switching off of supply during selected periods. This serves two purposes: it allows a longer period between energization cycles, limiting the potential for arcing or back corona, and reduces energy consumption, without reducing charge on the particles. The retrofit of ESP with IC control system can enhance performance and achieve a reduction of about 20 per cent in emissions and a reduction of 50 per cent in energy consumption.

An ESP modernization scheme to reduce emissions and power consumption is under way at both NTPS and PTPS. Wherever possible, mechanical improvements such as improving the flue gas flow path or increasing the specific collection area (SCA) have to be incorporated in the augmentation/retrofit plan. However, this is very site specific. The capital cost of a pulse energization retrofit is assumed to be Rs. 120 million. This is based on available information from MSEB. However, although an annual benefit of Rs. 11.2 million accrues there is no feasible payback period for the scheme (Box 2.3).

The existing ash handling system can be retrofitted by employing a dry flyash evacuation system. The proposed system consists of a dense phase vessel below each hopper, conveying flyash accumulated in the hoppers to an intermediate silo. Each dense phase vessel operates as per the requirements, based either on a timer or level of flyash in the hopper. From the storage silo, the flyash is discharged into a mixing tank where the dry flyash is converted into slurry and pumped directly with high pressure slurry pumps to the ash pond area. The method involves pumping only at a single stage. In the specific case of NTPS, where an efficient last stage slurry pumping station has been installed, the scheme could be modified to reduce capital costs. In the modified scheme, slurry from the mixing tank of the storage silo could be allowed to flow in the sump of the last stage pumping station.

While the final solution will require a detailed study with complete data regarding the existing system and more interaction with equipment suppliers, an attempt has been made to arrive at the indicative economic figures with the information available. For this purpose, replacement of the wet system with a dense phase dry flyash collection system up to an intermediate distance of 500 m, where it is collected in a 900 T capacity silo, is considered (one day storage of a single 210 MW unit). From the silo, ash can be collected in dry form for selling, if required, or it can be converted into slurry and pumped to the dump area with slurry pumps. The annual energy consumption per unit in the existing system is of the order of 8 MU. Energy savings of 4.7 MU can be achieved annually from the alternate system. This will yield an annual benefit of Rs. 11.7 million. With a capital cost of Rs. 80 million for the alternate system the payback period works out to 13.8 years (Box 2.4).

A 210 MW unit has an air-conditioning load of approximately 175 tonnes of refrigeration (TR) of which, the switchyard control room, offices, I&C lab are generally common to more than one unit. The distribution of load is shown in Table 2.4.

A separate air-conditioning system is generally adopted for the ESP control room and switchyard control room. To meet the requirements of air-conditioning the control room, lab, etc., the central air conditioning system adopted consists of compressor/condenser units in the A.C plant room; condensor cooling water circuit, including cooling water pumps, cooling tower, piping etc.; chilled water circuit, including chilled water pumps, piping upto air handling units (AHU) and back etc.; AHU and supply and return air distribution system from AHU to load point.

In a vapour absorption system, steam is used to produce chilled water. Therefore, when a vapour absorption system is used, the compressor/condenser unit is replaced by the compact absorption unit. A small capacity condenser cooling water circuit is still required but generally the pumping head requirement and piping requirement is not high since cooling tower can be located in the vicinity of the absorption unit. A new chilled water circuit is required to be laid up to the existing AHUs and connnected to the AHU of the existing system with a suitable control valve arrangement. Waste steam is generally available from the steam used for oil tank heating (that contains low sulphur (LSHS) oil, and hence also known as LSHS tank) or the flashing steam from continuous blow down (CBD). The CBD is to eject impurities from the steam.

Steam is generally used for LSHS tank heating and this steam is flushed to the atmosphere. Though no measurement is available of the quantity flushed outs available, it has been estimated to be sufficient for one 75 TR vapour absorption unit. However, in case of continuous blow down, the steam is available for each unit which means an absorption unit of 75-100 TR capacity can be installed to utilise this steam. Thus, the vapour absorption system is economically very attractive.

The capital cost of a new 75 TR vapour absorption machine is about Rs. 1.8 million. Typically, the location of LSHS tanks where this unit could be located is 500 m away from the AHU room. The cost of the additional chilled water and cooling water system required, will be approximately Rs. 1.1 million. Based on these capital costs the payback period works out to two years (Box 2.5). If one additional 75 TR unit is installed using CBD, the total energy would be of the order of 3x0.58 or 1.74 MU. Total energy savings for the station will be of the order of 2.3 MU.

While change of layout of cooling tower system in an existing station may not be feasible, some improvements related to cooling tower fans are definitely cost effective. There is scope for retrofit of cooling tower fans of the circulating water system in the following areas:

(a) Replacement of fan blades with aerodynamically designed blades of lighter material. This has already been implemented at Nasik and can be planned for Parli. Therefore, no economic analysis has been carried out.

(b) For preventing ingress of moisture in the motor winding during night times at low loads, a system of application of 24 volts on the motor winding is recommended. In the specific case of Nasik this will result in annual savings of 1.1 MU amounting to Rs. 2.75 million. The payback period is less than a year (Box 2.6).

It can be seen from Table 2.5 that most of the options have a payback period below 3 years. However, it is seen that for PTPS, the payback periods are significantly higher than those of NTPS or KSTPS. This is because of low PLF at PTPS due to which energy savings and hence cost savings are affected.

Options		Capital Cost (Rs.Million)	Annual Potential Energy Saving (MU)	Annual Savings (Rs.Million)	Payback Period (Years) Discounted @14%
VSD for ID Fan	Nasik	90	15.7	39.113	2.6
	Parli	90	9.7	24.147	4.7
	Korba	90	13.715	34.2875	3.0
	Panipat	30	3.254	8.135	4.6
VSD for BFP	Nasik	180	41.3	103.21	1.9
	Parli	180	25.5	63.8	3.3
	Korba	180	39.731	99.3275	2.0
	Panipat	60	9.283	23.2075	2.9
Waste Steam Utilization		2.9	0.6	1.51	2.2
ESP Field Energization		120	4.5	11.25	Not Economical^*
Alternate Ash Handling System		80	4.7	11.75	13.8
Cooling Tower Design Improvement (NTPS)		1	1.1	2.75	0.5

* The conventional discounted (14%) payback period calculation yields infeasible payback period. However, it is justified since besides energy savings, it reduces emissions substantially, for which no credit was taken. It is justified on this ground.

Note: The data are for 3 units of 210 MW for all power stations except Panipat, that has only one unit.

Energy savings from different options in the auxiliary system, discussed in the previous section, also implies reduced emissions of GHGs and other gases to the atmosphere. The annual energy savings for one unit of 210 MW plant for the four case study plants work out between 15.4 MU (for Parli) and 22.6 MU (for Nasik). Corresponding reduction in auxiliary consumption as a percentage of electricity generation for these units is 1.53% and 2.2% respectively. If an average auxiliary consumption reduction of 19 MU is considered for 80 units of 210 MW (about 70% of the total 120 units), energy savings work out to 1520 MU and CO₂ emissions savings are approximately 1.5 million tonnes per annum.

Benefits in terms of reduced emissions have also been evaluated for various options, considering the remaining life of the plants to be 15 years. The emission coefficients used for different thermal power stations have been derived using the calorific value associated with the grade of coal actually received by that station and the station average heat-rate, available from respective station data. Table 2.6 shows the coefficients for different pollutants, viz., CO₂, SO₂ and NO_x for the four different power stations considered for the case studies. Overall energy and CO₂ savings and cost of CO₂ emissions reductions from various options are given in Table 2.7 and the reductions in SO₂ and NO_x emissions are given in Table 2.8.

Power Station

CO₂ Emission Coefficient (Tons/MWh)

SO₂ Emission Coefficient (kg/MWh)

NO_x Emission Coefficient (kg/MWh)

Nasik TPS

Parli TPS

Korba STPS

1.0

1.09

0.99

2.67

3.49

3.45

4.4

4.66

5.06

4.60

6.79

It can be seen that the cost of CO₂ reductions varies from about $1 per ton to $55 per ton (1 US$ = Rs. 35). As Table 2.7 indicates, the proposed options for reduction of auxiliary consumption result in energy savings of about 1001 MU at NTPS, 691 MU at PTPS, 965 MU at KSTPS and 351 MU at PNTPS over the remaining estimated life of 15 years of the plants. The corresponding CO₂ savings are 1, 0.75, 0.96 and 0.37 million tonnes for NTPS, PTPS, KSTPS and PNTPS respectively. Figures 2.5 to 2.8 show the potential for CO₂ savings and associated cost of various options for the case study plants.

Some of the other measures for improvement of thermal power station efficiency are discussed below. These are however, not analyzed in detail.

The auxiliaries consume significant amount of power and yet not enough attention has been paid to improve their power factor. In some cases, the PF was observed to be as low as 0.85. It is easier to improve the PF at the auxiliary consumption point. However, effect of the power factor improvement on supply voltage from the generating station need to be considered. Therefore this alternative needs a careful study before implementation.

In the four case study power plants, considerable variations in size of auxiliaries and their full load current ratings were observed. All the units were of 210 MW rating, but if smallest rated auxiliaries from the four plants were chosen, the total auxiliary consumption works out to 51.7 MW. If highest rated auxiliaries were chosen, the consumption figure reaches 57.6 MW (see Table 2.9). The actual auxiliary consumption in the plants was between these limits. Although, higher sizing of auxiliaries in some cases may be due to site specific, or plant specific reasons, in others it may be due to more than necessary margin on capacity. Detailed examination and evaluation of option to replace existing auxiliaries with properly sized auxiliaries may indicate the potential reduction in auxiliary consumption as a result of this.

A very high percentage of coal received at the thermal power stations in India is inferior grade coal, E, F or G. Due to progressive mechanization of coal mining and the trend of increasingly higher percentage of coal coming from open cast mining, the ash percentage in such coals has been increasing. Besides the inherent ash content in coal, this increase has been due to mixing up of extraneous matter like shale and stones. The objective of limited beneficiation in such a case would be the removal of extraneous matter. This limited beneficiation serves the purpose of power plants, since any coal quality close to the design requirements is desirable as the units are equipped to handle this ash efficiently. The analysis of trends shows an increase in the percentage of extraneous matters like shale and stones. Some of the economic evaluation studies have proved that beneficiation is a viable alternative, taking into account the benefits due to higher heat contents of beneficiated coal and reduced transportation costs. Additional benefits like improved heat rate, savings in mill running costs, etc. make the option still more attractive.

An extensive renovation and modernization of the units can result in improving the heat rate, extending the useful life as well as increasing the rating of the unit in some cases. Uprating of 210 MW turbines has been achieved in a number of power stations in Poland on 210 MW units of the same design. In addition to uprating the units to deliver 235 MW for the same steam parameters using the existing reserves in the design, it is also possible to achieve increased efficiency and flexibility in operation to enable restart from any thermal conditions, i.e to suit non-base load operations. Uprating would also extend the life of the unit and enable vacuum and efficiency to be achieved in spite of the higher temperature of cooling water.

There are several other possible measures to reduce auxiliary consumption. Some of these, that can be explored are use of turbo-pumps in place of BFPs, use of 11 KV motors, use of LCI drives for fan motors etc. Feasibility of a centralized coal mill for plants that are in a cluster can also be examined. It can improve reliability besides reducing electricity consumption. This has been implemented at Vijayawada TPS.

Power system operations planning is of crucial importance in view of the fact that sub-optimal operation of the system might not only mean several billion rupees being wasted by utilizing inefficient and expensive generating units more than required, but also shortages of power in various sectors directly leading to a negative impact on economic growth. Efficient operations planning involves a broad range of activities, starting from fuel supply decision making to power generation scheduling, power transmission and inter-utility coordination. In the Indian context, efficient management of the existing system merits immediate attention because current operating practices are far from satisfactory.

This chapter, addresses the important issue of power plant efficiency improvement through reduction of auxiliary consumption. Generating unit-wise characteristics have been considered in a comprehensive systems modelling framework to estimate the savings that can accrue from the measures described in Chapter 2. Thermal power generation in India has traditionally been based on steam turbine technologies with coal as the primary fuel. The issues related to the supply of coal to the power sector merit special attention because of the sector's increasing reliance on coal.

Coal supply issues have a direct bearing on power plant capacity utilization and plant efficiency. Poor quality of coal, inadequate supply and transportation bottlenecks lead to increased system costs and higher auxiliary consumption. Due to shortfall in coal supply to power stations, the thermal units have to operate with very little coal stocks and there are instances of some of the units being forced to run at low loads or shut down due to coal shortages. This results in low PLF for the unit and hence increases the auxiliary consumption. Poor quality of coal may have serious impacts. For example, in the coal received by a power station from many sources there are wide variations in moisture, ash content, volatile matter and calorific value which may seriously affect the flame stability. More oil support may be required in such circumstances, even though this is undesirable. The presence of extraneous material in coal may lead to damages in coal handling equipment and inefficient loading operation. High ash content in coal means additional coal handling and milling as well as ash handling requirements. This leads to a significant increase in power plant auxiliary consumption.

Bottlenecks on the coal supply side lead to sub-optimal system operations due to constraints on production capacity in specific mines or on transportation capacity to allocate coal to power stations, or both. These bottlenecks need to be identified and a strategy for removing them needs to be formulated to achieve optimal system operation. If there is inadequate coal production, a short run production expansion strategy needs to be formulated. This production expansion must take into account the marginal benefit from capacity expansion and the associated cost.

In the present study, an attempt has been made to analyze the importance of reduction of auxiliary consumption from thermal power plants considering a system-wide perspective of the Indian power system. The NATGRID model [9], developed here at the Indira Gandhi Institute of Development Research, has been used to simulate various scenarios for reduction of auxiliary consumption.

NATGRID is a linear programming model [9] with the total system cost as the objective function to be minimized, subject to a set of constraints. The system comprises 19 utilities (State Electricity Boards, SEBs in India) of the four major electricity regions. It contains details of 210 generating units, 90 inter-utility transmission lines, 23 major coal fields and 97 power station-coal field linkages for the existing system.

The cost objective function has been defined to be the total cost of generation and unmet energy. The operating cost for coal based generation includes costs of coal production and transportation. For all other modes of generation, viz., hydro, gas and nuclear, the generation cost is put in aggregate terms per MWh. The objective function includes the cost of unmet energy which represents the opportunity cost of shortage of electricity in any state.

(i) Generation capacity constraints. The generating units are constrained by the power output limit or the MW capability of the unit in all time blocks.

(ii) Transmission capacity constraints. Transfer of power across the states along each voltage class is limited by total transmission capacity of all lines in that voltage class in terms of MW.

(iii) Demand constraints. In each state and each time block the demand minus unmet energy must be equal to the sum of the state's own generation, the central sector's contributions, imports from other states minus exports. The loading being constant within a time block, the energy demand (MWh) constraint and power demand (MW) constraints are equivalent.

(iv) Hydro energy constraints. In addition to capacity constraints, hydro units are also constrained by the hydro energy availability in a period. While a unit can take a maximum load based on its MW capability, the total number of hours for which the unit can be run is limited by the total MWh potential in a period.

(v) Central sector's share contracts. These represent the existing practice of allocating a fixed quota of central sector generation to the states.

(vi) Calorific balances for coal based units. The energy generated must be supported by equivalent tonnage of coal supplied to the generating unit considering its efficiency and the calorific value of coal supplied.

(vii) Coal production capacity constraints. The total coal production from a mine is limited by mine-level considerations like manpower availability, mining equipment capacity, etc.

(viii) Coal transportation capacity constraints. Given the number of wagons, trucks, loading and unloading capacity in each route by each mode, there is a limit to the total amount of coal that can be transported.

The NATGRID model has been used to estimate the impact of reduction of auxiliary consumption on the Indian power system. Several scenarios have been considered on the total system auxiliary consumption figures. Comparisons have been made between the base case operations (i.e. with actually existing auxiliary consumption figures) and a scenario where in auxiliary consumption of plants exceeding 12 per cent is reduced to 12 per cent; that of plants exceeding 11 per cent is reduced to 11 per cent, etc. It is seen from Table 3.1 that when auxiliary consumption is reduced, the system costs reduce significantly. If the system auxiliary consumption is restricted to 8 per cent or less, the cost savings are Rs. 1,023 million annually. 1,459 MU of additional energy requirements of the system can be met, and there is a reduction in CO₂ emissions to the tune of 218,000 tons per year. However, since unmet energy is also met from auxiliary consumption reductions, this has to be added to calculate total energy savings. When this is done, the CO₂ savings range from 0.34 to 1.23 million tons per year.

Maharashtra has one of the lowest transmission and distribution losses among the states in India. However, as seen from Table 4.1, T&D losses in recent years have been increasing and have been higher than the limit of 15.5 per cent suggested by Electrical Power Research Institute (EPRI) and endorsed by the Rajadhakshya Committee (RCP, 1989). The losses were at a lower level - 14.3 to 14.5 per cent - during 1985-86 and 1987 and it may be possible to improve and bring current losses to these levels. The scope for improvement may exist even if overall system losses are within the acceptable limits. A detailed analysis of losses in the system may be useful in identifying inefficiencies, if any, in the subsystems. In the case of MSEB, deterioration in the efficiency of the T&D system is evident from increased losses due to overloading of transformers, transmission lines, distribution network and increased rural electrification. Investment in the T&D system has not kept pace with increased electricity generation and demand in the system, resulting in the above distortions.

Year

Haryana

Uttar Pradesh

Tamil Nadu

Maharashtra

All India

1980-81

1985-86

1986-87

1987-88

1988-89

1989-90

1990-91

1991-92

1992-93

22.6

19.8

20.6

25.4

26.6

29.2

28.2

24.2

25.5

15.6

20.5

26.8

27.4

26.1

27.1

25.3

24.1

19.1

18.7

18.6

17.7

18.5

17.9

18.4

17.3

16.2

14.5

14.3

15.8

17.6

18.3

15.5

16.4

20.6

21.7

21.5

22.1

22.3

22.9

22.8

21.8

As can be seen from Table 4.2, the distribution system losses are on the higher side and could be reduced. According to a study carried out by MSEB, about 8,000 out of a total of 100,000 distribution transformers were overloaded. Agricultural consumers were the source of large reactive loads (with power factor (PF) as low as 0.6 to 0.65) due to their failure to install proper capacitors for compensation. It was also observed that at different stages there was scope for upgradation of transmission voltage to the next higher level.

As seen from Table 4.2, most of the losses occur at the distribution level (i.e 11 kV and below). The losses can be divided into two categories: technical and non-technical losses. Breakup of the Real or Technical losses occur due to the energy dissipated in various components of distribution system. These consist of feeder losses (that vary with load) and transformer losses (that consist of iron and copper losses). The technical losses relate to the physical properties of the conductor and current flow in the circuit. To minimize these losses, an optimally designed T&D system incorporating appropriate technology is required.

Commercial or Non-technical losses comprise the losses arising from pilferage of energy, inaccurate meter readings, defective meters, etc.

Quantification of existing system losses is the first requirement in an analysis of losses. The difference between the total amount billed to consumers and energy sent out by generating stations gives an estimate of the total losses in the system. This can be used to identify sub-systems for detailed study. A typical distribution system along with associated networks can be picked up for detailed analysis.

(i) Preparation of database and maps for high tension (HT) and low tension (LT) distribution network. A system map containing information about HT and LT lines, size of conductors/cables and section-wise lengths and location of substations is required for the purpose. This is followed by a detailed survey to find out phase-wise loading of various feeders. For each feeder, information about the number of distribution transformers and their capacities, number of consumers, maximum demand, etc. is also needed. This information is used to identify the overloaded feeders. Therefore, up to-date information on existing distribution system has to be gathered for this purpose.

(ii) Measurement of actual energy losses. This is done for a few representative feeders identified in Step-(i) above. Energy meters are installed at various appropriate locations to measure energy losses in each section of the transmission, sub-transmission and distribution system. Measurements required for typical feeders are: (a) Feeder input quantities: voltage, power, power factor, energy. These are measured at the power station or substation switchboard. (b) Distribution Transformer Loads: voltage, current. Distribution of load on a feeder along its length is measured using "clip on" and recording ammeters. This is required since load depends on actual loading of transformers on the feeders and not on their connected capacities. (c) Low Voltage Feeder Distribution: voltage, current. Clip-on instruments are the easiest method of determining the distribution of load within a selected low voltage system.

(iii) Investigation of causes for high losses. Once a high loss area has been identified, reasons for high losses are to be investigated. The factors to be studied for the losses are shown in Figure 4.1. These are: (a) Inadequate conductor size: This leads to overloading of the lines and consequently increases energy losses. (b) Poor power factor: The demand for reactive power from industrial load, households and commercial establishments (due to use of fluorescent tubes and air-conditioners) and agriculture (due to induction motors used with agricultural pumps) decreases the power factor. Reactive power is supplied by the generating units and this overloads the T&D system. It increases energy losses. (c) Low load and demand factor: In some cases, low load factor of a distribution system causes high energy losses (in percentage terms) due to the no load losses (copper and iron losses). The no load losses occur because the distribution system and transformers have to be kept energized all the time. Low demand factor implies over-sizing of the distribution system, which also results in higher losses. (d) Improper location of distribution transformer: If the distribution transformer is far away from the load centre, it requires long HT and LT lines. This may happen due to unplanned extension of lines during electrification. It causes poor voltage regulations and consequently increases energy losses. (e) Poor quality and inadequate maintenance of equipment and lines: Poor quality equipment like transformers, switchgears, switches etc. cause higher energy losses. Such equipment are also prone to failure, causing interruptions in the distribution system. Lack of quality control during construction or inadequate maintenance also increase line losses and make the system unreliable. For example, loose joints, loose connections, improper switch contacts, etc. add to losses. (f) Pilferage of energy.

MSEB has a large T&D system and it has to constantly expand to meet the growing needs of the state's economy. The loss reduction measures for a system like this have to be two-fold; short term measures to remove existing distortions that cause higher losses, and long term measures, keeping the future expansion of the system in mind.

The focus of short term measures is to reduce losses in the existing system. Short term measures include:

(i) Reconductoring. First 25 per cent of the length of the HT line is responsible for a major part of the losses. Increased cross-section of this part of the line can reduce losses. While this is also true for LT lines, reallocation of injection points may be more effective in this case.

(ii) Installation of capacitors for power factor improvement. Conductor loading (and hence feeder losses) and voltage drops can be reduced by installing capacitors at the sub-stations. For 33 kV lines and above, capacitor installation at the grid substation can be taken up so that operators may switch it on as per requirements. LT and large industrial consumers can be asked to install capacitors in their premises to keep PF within acceptable level. The reactive power planning problem is best addressed locally. Static VAr Compensators (SVCs) can be installed in those areas identified as having high reactive power demand. SVCs can provide continuously varying inductive or capacitive power support.

(iii) Improved load factor. The maximum demand can be reduced by using demand side management techniques. Staggering of loads on outgoing feeders at grid substations can also reduce the maximum demand but this may not be acceptable to consumers. Load factor improvement helps in reduction of constant iron losses in the system. Automatic rostering of rural agricultural loads is an important measure to improve load factor and diversity factor. Such rostering can be done at distribution transformer stations. Some states in India have already implemented this measure. Technologies like ripple control, radio control systems, time clocks, etc. can be used for selective load management in urban areas but this has to be preceded by a proper study and survey and consumer acceptance.

(iv) Reconfiguration of network. Relocation of the distribution transformer near the load centre can also reduce losses. But this is normally possible only when transformer replacement is required. Depending on load density, load decentralization may also be useful. The length of LT lines should be minimized in order to reduce losses. This would require a study of the LT distribution system. Additional substations may have to be added to minimize line lengths for HT and LT systems.

(v) Distribution transformer load monitoring. Load balance between phases can be achieved through load monitoring at distribution transformers. It also would indicate whether the transformer is overloaded or not. Depending on load conditions, transformer rating can be decided. A transformer which is under-utilized (high rating) also causes higher losses due to high iron loss. At times, it may be possible to reduce losses by reorientation and adjustment of loads on distribution transformers so that their capacities are optimally utilized.

(vi) Upgradation of operating voltage levels. This is possible for HT as well as LT lines. In the case of HT lines, improvements in insulators can allow for upgradation of voltage level, thereby reducing losses. For example, substitution of porcelain insulators by polymer insulators can increase transmission capacity substantially with the existing structure and conductors. A systems study can be made, to identify whether parts of the system are operating with old equipments and at lower voltage than the prevailing level of demand requires. Even one such feeder can account for a majority of losses in the system. Such equipments may need to be replaced.

(vii) Improved operation and maintenance (O&M) practices. O&M practices should be reviewed periodically to identify deficiencies. Deficient practices indicate an overall poor approach to the problem of loss reduction.

(viii) Penalty for low power factor. A low power factor surcharge on tariff can be introduced to encourage consumers to improve their power factor. Since improvement in power factor will cost the consumer, the surcharge could be designed in a manner that will provide sufficient incentive to the consumer to improve the power factor.

(ix) Optimal reactive power generation. Optimization of reactive power generations from the generating units can also be helpful in reducing the losses.

Utilities need to study distribution system requirements in the long run in order to minimize losses with changing load demands and other requirements. For utilities like MSEB which have been exp

Parameters		North	East	South	West	North-East	All-India
Installed Capacity (MW)		23,820	12,302	19,459	24,301	1,282	81,164
8th plan	Capacity Added till March 1995 (MW)	3,629	3,149	2,225	3,452	221	12,675
8th plan	Balance from targeted (1992-97)	6,198	3,984	2,204	4,239	1,238	17,863
Generation		102,766	35,408	92,026	116,421	2,337	351,025
Thermal Plant Load Factor		59	44	69	64	27	60
Per Capita Consumption (kWh)		282	158	308	405	89	282

Equipment	Rating kW	Nos/Unit	Full load current	Contribution MW
Boiler Auxiliaries:
ID Fans FD Fans PA Fans Coal Mills	1000-17000 570-750 1250 320-340	2 2 2 4-5	110-130 25-32 125-130 30-31	6.59-7.13 1.37-1.76 6.86-7.13 3.29-4.25
Turbine Auxiliaries:
BFPs CEPs CWPs CT Fan Motors	3500-4000 220-470 685-1350 43-105	2 2 2 9-28	285-305 22-45 65-145 40-155	15.64-16.74 1.21-2.47 3.08-7.96 1.08-2.41
Ash Handling System:
LP Pumps HP Pump Ash Slurry Pump Seal Water Pump	130 135 120-210 25-30	1 1 1-2 1-2	0.41 0.23 0.35-0.93 0.04-.10
Coal Handling System:		4.72-5.75
Total Aux. Consumption:		51.74-57.56

Environmentally sound energy efficient strategies:

a case study of the power sector in India