Study of Combined Gas Cycle Power Plant and Modernization of Siemens V94.2

A report based on internship at NTPC, Faridabad

Submitted by:

Bhushan Maskay

Department of Mechanical Engineering

INDIAN INSTITUTE OF TECHNOLOGY, GUWAHATI

GUWAHATI- 781039, ASSAM

June-July, 2010

Preface

This report is a summary of the study done at NTPC Limited (Formerly National Thermal Power Corporation) based on 2 months (June-July 2010) training at its gas based power plant in Faridabad. During the project I was introduced to the various departments and their workings in the plant. I was also introduced to the various components involved in the generation of electricity, their running parameters and the necessary precautions taken to prevent their damage. During this training I enhanced my engineering knowledge as I developed an entire concept of combined gas cycle power generation from scratch.

There are three parts of this report: (I) Introduction to NTPC (II) Faridabad Gas based power plant (III) Mechanical Design .

Part I covers the history of NTPC and its growth through the years. It also gives an insight into its upcoming projects, joint ventures and other key data related to the company.

Part II introduces the details of the Faridabad plant. It provides the particulars of the components used and the procedure used in power generation. It also briefs on the working of the major departments of the plant and their workings.

Part III deals mainly with the gas turbine design, and also includes the latest modernization products from Siemens V94.2 (also known as SGT5-2000E).

Acknowledgement

I owe thanks to a great many people who helped and supported me during the training period at NTPC.

My deepest thanks to Mr. Niranjan for guiding the training and arranging the lectures timely. I express my thanks to Mr. K K Sharma (Sr Manager, Chem.), Mr. S K Bhargava (MTP), Mr. V K Garg(Operations), Mr. Manoj Agarwal (Mechanical Maintenance), Mr. Rohit Sharma (C & I) and Mr. S K Baliyan (Electrical Maintenance).

I extend my gratitude to Mr. Amit Tyagi (Mechanical Maintenance) for his guidance and support during the period.

Thanks and appreciation to all the helpful people at NTPC Limited for their support.

I would also thank my institution and my faculty members for developing in me a basic understanding of the concepts without which this report would have been a distant reality.

Index

1. Part I: Introduction to NTPC 1.1. About the company 1.2. Evolution of NTPC 1.3. NTPC group 1.4. Power Generation 1.5. NTPC Operations 1.6. Turnaround Capability 1.7. NTPC Strategies 1.8. International Cell 1.9. Ecological Monitoring Programme

2. Part II: Faridabad gas based power plant 2.1. Overview 2.2. Combined Cycle Gas Turbine (CCGT) power plant 2.3. Water treatment

2.3.1. Pre-Treatment(PT) plant 2.3.2. De-Mineralization(DM) plant

2.4. Components 2.4.1. Air Filter 2.4.2. Compressor-Gas Turbine- Generator 2.4.3. Diverter-Damper 2.4.4. Heat Recovery Steam Generator (HRSG) 2.4.5. Steam Turbine Generator 2.4.6. Main Control Room (MCR) 2.4.7. Cooling tower

2.5. Switchyard 2.6. Major Departments

2.6.1. Human resources (HR) 2.6.2. Maintenance Planning (MTP) 2.6.3. Operation & Maintenance: Mechanical (O&M- MM) 2.6.4. Operation & Maintenance: Electrical (O&M- EMD) 2.6.5. Operation & Maintenance: Control & Instrumentation (O&M- C&I) 2.6.6. Operation & Maintenance: Chemical (O&M-Chem)

3. Part III: Gas Turbine Design and Modernisation

3.1. Introduction to Siemens V94.2 3.2. Auxiliaries

3.2.1. Lube oil system 3.2.2. Lube oil cooling system 3.2.3. Fuel oil system 3.2.4. Purge water system 3.2.5. Hydraulic system 3.2.6. Ignition Gas system 3.2.7. Filter Housing 3.2.8. Turbine

3.2.9. Generator 3.2.10. Generator cooling system 3.2.11. Exhaust

3.3. Overview of GT Modernistation Products 3.3.1. Turbine Inlet Temperature Upgrade(TT1+) and Extended Maintenance

interval (41 MAC) 3.3.2. Compressor Mass Flow Upgrade(CMF+) 3.3.3. Dry- Low- NOX (DLN) Upgrade using HR3-burner 3.3.4. Performance Boost with Wet Compression (WetC) 3.3.5. Humidity I & C Module for GT control system 3.3.6. Fuel Conversion Upgrade 3.3.7. Siemens innovative 3-D Turbine Blades & vanes 3.3.8. Lifetime Extension

3.4. SGT5-2000E adjustment to site conditions 3.5. Configuration after Modernization

Bibliography

1.1 About the company Corporate Vision: “A world class integrated power major, powering India’s growth, with increasing global presence” Corporate Mission: “Develop and provide reliable power, related products and services at competitive prices, integrating multiple energy sources with innovative and eco-friendly technologies and contribute to society.” Core Values: BCOMIT B-Business Ethics C-Customer Focus O-Organizational & Professional pride M-Mutual Respect and Trust I- Innovation & Speed T-Total quality for Excellence

India’s largest power company, NTPC was set up in 1975 to accelerate power development in India. NTPC is emerging as a diversified power major with presence in the entire value chain of the power generation business. Apart from power generation, which is the mainstay of the company, NTPC has already ventured into consultancy, power trading, ash utilization and coal mining. NTPC ranked 317th in the 2009’s Forbes Global Ranking of the World’s biggest companies.

The total installed capacity of the company is 31,704 MW (including JVs) with 15 coal based and 7 gas based stations, located across the country. In addition under JVs, 3 stations are coal based & another station uses naptha/LNG as fuel. By 2017, the power generation portfolio is expected to have a diversified fuel mix with coal based capacity of around 53000 MW, 10000 MW through gas, 9000 MW through Hydro generation, about 2000 MW from nuclear sources and around 1000 MW from Renewable Energy Sources (RES). NTPC has adopted a multi-pronged growth strategy which includes capacity addition through green field projects, expansion of existing stations, joint ventures, subsidiaries and takeover of stations.

NTPC has been operating its plants at high efficiency levels. Although the company has 18.10% of the total national capacity it contributes 28.60% of total power generation due to its focus on high efficiency.

In October 2004, NTPC launched its Initial Public Offering (IPO) consisting of 5.25% as fresh issue and 5.25% as offer for sale by Government of India. NTPC thus became a listed company in November 2004 with the government holding 89.5% of the equity share capital. The rest is held by Institutional Investors and the Public. The issue was a resounding success. NTPC is among the largest five companies in India in terms of market capitalization.

At NTPC, People before Plant Load Factor is the mantra that guides all HR related policies. NTPC has been awarded No.1, Best Workplace in India among large organisations and the best PSU for the year 2009, by the Great Places to Work Institute, India Chapter in collaboration with The Economic Times.

The concept of Corporate Social Responsibility is deeply ingrained in NTPC's culture. Through its expansive CSR initiatives, NTPC strives to develop mutual trust with the communities that surround its power stations.

1.2 Evolution of NTPC · 1975

o Incorporated on November 7.

· 1976 o On December 8, the Government of India cleared NTPC's first pithead

super thermal power project at Singrauli in Uttar Pradesh. o The authorised share capital of the Company was Rs. 125 crore.

· 1977 o NTPC acquired the first patch of land at Singrauli in September. o The first major contract of Rs. 57.5 million was awarded for site leveling

work at Singrauli in June.

· 1978 o Implementation of Korba and Ramagundam Projects cleared by the

Government of India in January and February respectively. o Late Shri Morarji Desai, the then Prime Minister of India, laid the

foundation stone for Ramagundam Project on November 14th o Construction of the first transmission network Singrauli-Kobra-Kanpur

of 400 KV system started

· 1979 o Government of India approved the implementation of Farakka Project in

March o The authorised share capital of the Company rose from Rs.125 crore to

Rs. 300 crore

· 1980 o Former Soviet Union offered to assist in setting up of power stations.

Vidhayachal was identified as the first project for such assistance. o The authorized share capital was raised from Rs. 300 crore to Rs. 800

crore in June.

· 1981 o Farakka Super Thermal Power Project in West Bengal was the fourth

among the first series of four super thermal power projects taken up by NTPC. On December 29, late Smt. Indira Gandhi, the then Prime Minister of India, laid the foundation stone for the Project.

o On December 25, the fifth and last unit of 210 MW at Badarpur Thermal Power Station was synchronised by NTPC, marking the completion of the 720 MW project

· 1982 o The first 200MW unit at Singrauli was commissioned o The first direct foreign currency borrowing for NTPC- a consortium of

foreign banks led by Standard Chartered Merchant Bank extended a loan of GBP 298.41 million for the Rihand project.

o Power Management Institute, Delhi, a centre for education established. o On November 12, Late Smt. Indira Gandhi, the then Prime Minister of

India laid the foundation stone for Vindhyachal Super Thermal Power Project in Madhya Pradesh.

· 1983 o On March 1, the first 200 MW unit of Korba Super Thermal Power

Project was commissioned in a record time of 48 months after the placement of order for the main plant equipment

o Another significant achievement was the supply of uninterrupted power from Badarpur during Asian Games and Non-Aligned Meet held at Delhi.

o Ramagundam became operational on November 26 by commissioning its first 200 MW Unit.

o In the very first year of its commercial operation, NTPC earned a profit of Rs. 4.51 crore in the financial year 1982-83

· 1984 o The transmission line based on HVDC (High Voltage Direct Current)

technology, commissioned for power transmission from Rihand to Delhi. o Singrauli project received a World Bank loan of USD 150 million through

the Government of India

· 1985 o This year marked the completion of a decade (1975-1985) of NTPC's

existence. NTPC achieved a generating capacity of 2200 MW by commissioning 11 units of 200 MW each at its various projects in the country.

o In December '85, the Government of India approved the setting up of three gas-based combined-cycle projects by NTPC at Kawas in Gujrat, Auraiya in Uttar Pradesh and Anta in Rajasthan. For these projects, the World Bank agreed to provide US$ 485 million, which was the largest single loan in the history of the bank.

· 1986 o Synchronisation of its first 500 MW unit at Singrauli. o NTPC launched its maiden public issue of Bonds and raised a total of Rs.

163.37 crore. This issue was over-subscribed by 63 percent.

· 1987 o Crossed the 5000 MW installed capacity mark. o Korba also entered the 500 MW phase by synchronizing its first 500 MW

unit on May 31

· 1988 o Rihand entered the Operational phase by commissioning its first 500

MW unit on March 31. o The first 500 MW unit of Ramagundam was commissioned on June 26.

· 1989 o Consultancy division launched. o First unit (88 MW) of first gas based combined cycle power plant at

Anta, Rajasthan commissioned

· 1990 o Total installed capacity crossed 10000 MW

· 1991 o Vindhyachal recorded completion of stage I activities by synchronising

its sixth and last 210 MW unit in February. o The first unit of NCPP (Dadri) was commissioned on December 21.

· 1992 o Acquisition by the Company of Feroze Gandhi Unchahar Thermal Power

Station (2x210MW) from Uttar Pradesh Rajya Vidyut Utpadan Nigam of Uttar Pradesh.

o Pursuant to legislation by the Parliament of India, the transmission systems owned by the company was transferred to Power Grid Corporation of India Limited.

· 1993 o For the first time, IBRD extended direct loan of USD 400 million under

time slice concept for its projects.

· 1994 o Crossed 15000 MW of installed capacity. o Declared a dividend of Rs. 65 crore for the first time. o Jhanor-Gandhar (Gujarat) becomes the first thermal power station to

have commissioned an integrated Liquid Waste Treatment Plant (LWTP)

· 1995 o NTPC celebrated 20 years (1975-1995) of its existence. A new logo was

adopted. o On June 3rd, NTPC formally took over the 460 MW Talcher Thermal

Power Station from Orissa State Electricity Board o On July 25th, the new campus of Power Management Institute (PMI)

was inaugurated.

· 1996 o Continuous running of sixth unit (210 MW) of Ramagundam for 406

days for the first time in India. o PLF of Talcher Thermal reached 43.7 % from 18.7 % at the time of

takeover

· 1997 o Identified by the GOI as one of the Navratna public sector undertakings o Achieved 100 billion units generation in one year. o A consortium of foreign banks led by Sumitomo Bank, Hong Kong

extended foreign currency loan of 5 billion Japanese Yen for the first time without GOI guarantee.

· 1998 o Commissioned the first Naphtha based plant at Kayamkulam with a

capacity of 350 MW

· 1999 o Dadri Thermal Power Project, Uttar Pradesh adjudged the best in India

with a PLF of 96.12% o Dadri, Uttar Pradesh certified with ISO-14001 on October 7""

· 2000 o Commenced construction of a first hydro-electric power project of

800MW capacity in Himachal Pradesh

· 2001 o Main plant turnkey package of Rihand Stage-II (2x500MW) and

Ramagundam Stage-Ill (IX 500 MW) were awarded to BHEL in August · 2002

o Three wholly owned subsidiaries of NTPC viz. NTPC Electric Supply Company Limited, NTPC Hydro Limited and NTPC Vidyut Vyapar Nigam Limited incorporated

o Crossed the 20000 MW installed capacity mark

· 2003 o Raised funds through bonds (Series Xlllth & XlVth) for prepayment of

high cost GOI loans

· 2004 o Awarded contract for the first Super Critical Thermal Power Plant at

Sipat NTPC's Feroze Gandhi Unchahar Thermal station achieved a record PLF of 87.43% in current year, up from 18.02% in February' 92 when it was taken over by NTPC

o LIC extended credit facility of Rs.70 billion. Rs.40 billion was in the form of unsecured loans and Rs.30 billion in the form of bonds

o NTPC made its debut issue of euro bonds amounting to USD 200 million in the international market

· 2005 o NTPC received the International Project Management Award, 2005 for

its Simhadri project at the International Project Management Association World Congress. NTPC became the only Asian Company to receive this award

o NTPC was ranked as the Third 'Great Place to work for in India' for second time in succession by a survey conducted by Grow Talent and Business World 2005.

o The Company's name changed to NTPC Ltd.

· 2006 o For the fourth consecutive year, NTPC continued to realize 100% of

current bills o On June, 1, the Badarpur Thermal Power Station with an installed

capacity of 705 MW was transferred to NTPC by the Government of India

o Another 740 MW was added through its Joint Venture, Ratnagiri Gas and Power Private Limited, Dabhol. Thus taking installed capacity of the NTPC group to 27904 MW

o MOA with Govt. of Sri Lanka and Ceylon Electricity Board for development of 2 x 250 MW Coal based power project at Trincomalee in Sri Lanka

o Energy Technology Centre set up with the mandate of being a world class research institute

· 2007 o Ministry of Coal, Government of India granted in-principle approval for

allocation of a new coal block, namely, Chhati Bariatu South to NTPC, subject to the conditions stipulated in the approval letter. The share of reserves was indicated as 354 million tonnes

o Tripartite agreement signed with the Government of Assam, Assam Power Generating Co. Ltd., and NTPC for transfer of existing plant at Bongaigaon and to set up a new plant of 750 MW with 3 units of 250 MW each

o 765 KV switchyard transmission system energised at Sipat, the largest in the country

o MOU signed between NTPC and Ministry of Energy, Federal Government of Nigeria(FGN) for Energy cooperation

o Vindhyachal Super Thermal Power Project became the largest power station in the country with an installed capacity of 3260 MW

· 2008 o Joint Venture Company under the name "National Power Exchange

Limited" was incorporated on 11th December 2008 with NHPC Ltd., PFC Ltd., and TCS Ltd., to operate Power Exchange at national level

o NTPC was ranked Number 1 in the 'Best Work places for Large Organisations' and Number 8 overall for the year 2008 by Great Places to Work Institute's, India chapter in collaboration with the Economic Times

· 2009 o 500 MW Unit VI of Sipat brought under commercial generation o NTPC has achieved the highest ever single day generation of 655.22 MUs

on 2nd March, 2009 with highest ever single day coal based generation of 579.02 MUs

· 2010 o Installed capacity reaches 31,704 MW (including 2864 MW under JVs). o 17,830 MW under construction at 17 locations. o New national benchmark: Dadri Unit-5 (490 MW) begins commercial

operation in 39 months from zero date. o Generation increased by nearly 6% to 218.84 BUs compared to 3%

generation growth achieved in 2008-09; Exceeded the MoU ‘Excellent’ target of 217 BUs.

1.3 NTPC Group · One of the three largest Indian companies with market cap of Rs.1778 billion · Ranks 126th on the basis of market Cap globally (Forbes 2009 data) · Has a net worth of Rs. 574 billion · Owns total assets of Rs. 1052 billion

Subsidiaries(6)

Generation

NTPC Hydro Ltd.(100%)

Kanti Bijlee Utpadan Nigam

Ltd. (51%)

Bhartiya Rail Bijlee Company

Ltd. (74%)

Pipavav Power Development Co

Ltd (100%)*

Services

NTPC Electric Supply Company

Ltd. (100%)

Power Trading

`NTPC Vidyut Vyapar Nigam

Ltd. (100%)

Joint Ventures (15)

Generation

Aravali Power Company Pvt Ltd

(50%)

NTPC Tamil Nadu Energy Company Ltd

(50%)

Nabinagar Power Generating Company

Pvt. Ltd (50%)

Meja Urja Nigam Pvt. Ltd (50%)

NTPC SAIL Power Company Pvt Ltd

(50%)

Ratnagiri Gas and Power Pvt Ltd

(28.33%)

Services

Utility Powertech Ltd (50%)

NTPC Alstom Power Services Pvt Ltd

(50%)

National High Power Test Laboratory Pvt

Ltd (25%)

Equipment Manufacturing

NTPC BHEL PowerProjects Pvt Ltd

(50%)

BF NTPC Energy Systems Ltd (49%)

Transformers and Electricals Kerala

Ltd.(44.6%)

Coal Acquisition

International Coal Ventures Pvt. Ltd

(14.29%)

NTPC SCCL GlobalVentures Pvt Ltd

(50%)

Power Trading

`National Power Exchange Ltd

(16.67%)

1.4 Power Generation Be it the generating capacity or plant performance or operational efficiency, NTPC’s Installed Capacity and performance depicts the company’s outstanding performance across a number of parameters.

NO. OF PLANTS CAPACITY (MW)

NTPC Owned Coal 15 24,885 Gas/Liquid Fuel 7 3,955 Total 22 28,840 Owned By JVs Coal & Gas 5 2,864 Total 27 31,704

Regional Spread of Generating Facilities

REGION COAL GAS TOTAL

Northern 7,525 2,312 9,837 Western 6,360 1,293 7,653 Southern 3,600 350 3,950 Eastern 7,400 - 7,400

JVs 924 1,940 2,864 Total 25,809 5,895 31,704

1.4.2 Coal Based Power Stations

With 15 coal based power stations, NTPC is the largest thermal power generating company in the country. The company has a coal based installed capacity of 24,885 MW.

COAL BASED (Owned by NTPC)

STATE COMMISSIONED CAPACITY(MW)

1. Singrauli Uttar Pradesh 2,000 2. Korba Chhattisgarh 2,100 3. Ramagundam Andhra Pradesh 2,600 4. Farakka West Bengal 1,600 5. Vindhyachal Madhya Pradesh 3,260 6. Rihand Uttar Pradesh 2,000 7. Kahalgaon Bihar 2,340

8. NCTPP, Dadri Uttar Pradesh 1,330 9. Talcher Kaniha Orissa 3,000 10. Feroze Gandhi, Unchahar Uttar Pradesh 1,050 11. Talcher Thermal Orissa 460 12. Simhadri Andhra Pradesh 1,000 13. Tanda Uttar Pradesh 440 14. Badarpur Delhi 705 15. Sipat-II Chhattisgarh 1,000 Total 24,885

Coal Based Joint Ventures:

COAL BASED (Owned by JVs)

STATE COMMISSIONED CAPACITY

1. Durgapur West Bengal 120 2. Rourkela Orissa 120 3. Bhilai Chhattisgarh 574 4. Kanti Bihar 110 Total 924

1.4.3 Gas/Liquid Fuel Based Power Stations The details of NTPC gas based power stations is as follows

GAS BASED (Owned by NTPC)

STATE COMMISSIONED CAPACITY(MW)

1. Anta Rajasthan 413 2. Auraiya Uttar Pradesh 652 3. Kawas Gujarat 645 4. Dadri Uttar Pradesh 817 5. Jhanor-Gandhar Gujarat 648 6. Rajiv Gandhi CCPP

Kayamkulam

Kerala 350

7. Faridabad Haryana 430 Total 3,955

Gas Based Joint Ventures:

COAL BASED (Owned by JVs)

STATE COMMISSIONED CAPACITY

1. RGPPL Maharashtra 1940 Total 1940

1.4.4 Hydro Based Power Projects (Under Implementation) NTPC has increased thrust on hydro development for a balanced portfolio for long term sustainability. The first step in this direction was taken by initiating investment in Koldam Hydro Electric Power Project located on Satluj river in Bilaspur district of Himachal Pradesh. Two other hydro projects under construction are Tapovan Vishnugad and Loharinag Pala. On all these projects construction activities are in full swing.

HYDRO BASED STATE APPROVED CAPACITY(MW)

1. Koldam (HEPP) Himachal Pradesh 800 2. Loharinag Pala (HEPP) Uttarakhand 600 3. Tapovan Vishnugad (HEPP) Uttarakhand 520 Total 1,920

1.4.5 Renewable & Distributed Generation

Renewable Energy Renewable energy (RE) is being perceived as an alternative source of energy for “Energy Security” and subsequently “Energy Independence” by 2020. Renewable energy technologies provide not only electricity but offer an environmentally clean and low noise source of power. Objectives NTPC plans to broad base generation mix by evaluating conventional and non-conventional sources of energy to ensure long run competitiveness and mitigate fuel risks. Portfolio of Renewable Power NTPC has also formulated its' business plan of capacity addition of about 1,000 MW through renewable resources.

Sl. No. RENEWABLE ENERGY SOURCES CAPACITY 1. Wind energy Farms 650 MW 2. Small Hydro Project 300 MW 3. Solar PV Power Project 5 MW 4. Solar Thermal 10 MW 5. Biomass Power Project 15 MW 6. Geothermal Power Project 30 MW Total 1,010 MW

1.4.6 Distributed Generation India’s ambitious growth plans require inclusion of all sectors, especially the rural sector where two third of our population lives. Such economic development cannot be achieved without availability of energy and subsequently efficient energy management which is crucial for rural development. As per census 2001, about 44% of the rural households do not have access to electricity. Some of the villages are located in remote & inaccessible areas where it would be either impossible or extremely expensive to extend the power transmission network. Objective

· Implementation of distributed generation projects using locally available renewable resources such as biomass, wind, solar, micro hydel, bio-fuel etc.

· Training & capacity building of local community to enable them to independently manage, operate & maintain the plant • To ensure viability and long term sustainability of DG projects

· Integrated growth & development of rural areas by enhancing employment

education, income generation & livelihood opportunities

· To ensure implementation of various technologies as demo/pilot project

1.5 NTPC Operations In terms of operations, NTPC has always been considerably above the national average. The availability factor for coal based power stations has increased from 89.32% in 1998-99 to 91.76% in 2009-10, which compares favourably with international standards. The PLF has increased from 76.6% in 1998-99 to 90.81% during the year 2009-10.

The table below shows that while the installed capacity has increased by 62.15% in the last twelve years the generation has increased by 99.84%.

Description Unit 1998-99 2009-10 % of Increase Installed Capacity MW 17,786 28,840 62.15

Generation MUs 1,09,505 2,18,840 99.84 * Excluding JVs and Subsidiaries

The table below shows the detailed operational performance of coal based stations over the years. OPERATIONAL PERFORMANCE OF COAL BASED NTPC STATIONS

Year Generation(BU) PLF(%) Availability Factor(%) 2009-10 218.84 90.81 91.76 2008-09 206.94 91.14 92.47 2007-08 200.86 92.24 92.12 2006-07 188.67 89.43 90.09 2005-06 170.88 87.52 89.91 2004-05 159.11 87.51 91.20 2003-04 149.16 84.40 88.79 2002-03 140.86 83.57 88.70 2001-02 133.20 81.11 89.09 2000-01 130.10 81.80 88.54 1999-00 118.70 80.39 90.06 1998-99 109.50 76.60 89.36

1.6 Turnaround Capability NTPC has played an extremely important role in turning around sub-optimally performing stations. The phenomenal improvement in the performance of Badarpur, Unchahar, Talcher and Tanda by NTPC make them our big success stories.

Badarpur (705 MW) The expertise in R&M and performance turnaround was developed and built up by NTPC with the operational turnaround of Badarpur TPS through scientifically engineered R&M initiatives. The PLF of the power station improved from 31.94% at the time of the takeover to 86.46% for the year 2007-08.

Unchahar (420 MW) The Feroze Gandhi Unchahar Power Station was taken over by NTPC whereby the cash strapped UPSEB was rescued by the turnaround expertise of NTPC. The remarkable speed and extent of the turnaround achieved can be seen in the table.

Talcher (460 MW) An even more challenging turnaround story was being scripted at the OSEB's old power plant at Talcher. Taken over in June 1995, the table indicates the dramatic gains in the performance of the power plant as a result of NTPC’s expertise.

Tanda (440 MW) Tanda Thermal Power Station was taken over by NTPC on the 15 January 2000.The PLF of the power station improved from 21.59% at the time of the takeover to 91.66% for the year 2007-08.

While NTPC bettered PPA commitments, from the viewpoint of capital requirements, turning around such old units is a low cost, high and quick return option. This unprecedented success helped the concerned SEBs and the entire nation in terms of economy and power availability.

1.7 NTPC Strategies

1.8 NTPC International Cell Towards the end of last century, many countries started structural changes in their infrastructure sectors. Many countries decided to un-bundle their hitherto government controlled power sector. Further, in order to meet the growing demand for power, privatization of power projects emerged as the most outstanding choice. These actions of many progressive governments resulted in a number of opportunities for private players in power sector. These include development of power projects as Independent Power Producers (IPP).

Keeping its proactive tradition, NTPC launched a separate International Cell to meet the varied needs of IPPs and other International clients who are looking for a world

class service in power sector. The International Cell is fully backed by NTPC’s three decades of experience and expertise. The Cell is especially tuned to meet the requirements of International clients in terms of quick response, flexible service options and to deliver value for money.

1.8.1 Rich International Experience

NTPC has a rich experience of executing power sector related projects abroad. Some of the projects are:

· Turnkey supply and installation of 400 kV & 132 kV Transmission lines for Dubai Electricity & Water Authority, Dubai

· Turnkey supply and installation of 132 kV Sub-stations for Dubai Electricity & Water Authority, Dubai

· Turnkey execution of 21 sub-stations for Asian Development Bank assisted 7th Power Project for Nepal Electricity Authority, Nepal.

· Feasibility Studies for Mchuchuma Mining-cum-Power Project of about 400 MW for National Development Corporation, Tanzania.

· Preparation of Procurement plan for IDA funded National HIV / AIDS Prevention Project of Ministry of Health, Nutrition & Welfare, Govt. of Sri Lanka.

· Executive training to ALBA Engineers for ALBA Bahrain

· Training to Technical personnel of Oman Refinery Company for Petroleum India International (PII).

· Deputation of experts to Nigeria to act as shift charge engineers for gas fired project AFAM at Nigeria from Steag encotec, India.

· Status assessment of Kipevu Power Station of KenGen. Kenya.

· Energy audit of power plants of Saudi Electricity Company in Kingdom of Saudi Arabia from YBAK of Saudi Arabia.

· Deputation of Metallurgical expert to Mangalore and USA for technical discussion with M/s General Electric in connection with failure of one of the Barge mounted Gas turbine belonging to GMR Energy Ltd. in India.

· Deputation of expert for assistance in due diligence of 683 MW Sidi Krier Power project Egypt.

· Review of design engineering of 4 Nos. 132/33kV substations in Dubai for DEWA, Dubai Investment Park & Tajera town.

· Experts’ services for supervision of commissioning and materials management at 800MW Az Zour Gas Power Plant in Kuwait.

· Review of protocol document and performance data sheet at home office and attending meeting at Kuwait and review of PG test calculation for 252 MW open cycle gas plant at Shuwaikh, Kuwait.

· Analysis of root cause for internal corrosion in HRSG tubes in Fujairah Independent water and power project, UAE.

Pursuing Business Opportunities In:

Bahrain Bangladesh China Egypt

Indonesia Iran Jordan Kazakhstan

Malaysia Nigeria Saudi Arabia Sri Lanka

Thailand UAE Vietnam Yemen

1.9 Ecological Monitoring Programme

NTPC has undertaken a comprehensive Ecological Monitoring Programme through

Satellite Imagery Studies covering an area of about 25 Kms radius around some of its

major plants. The studies have been conducted through National Remote Sensing

Agency (NRSA), Hyderabad at its power stations at Ramagundam, Farakka, Korba,

Vindhyachal, Rihand and Singrauli. These studies have revealed significant

environmental gains in the vicinity areas of the project as a result of pursuing sound

environment management practices. Some of these important gains which have been

noticed are increase in dense forest area, increase in agriculture area, increase in

average rainfall, decrease in waste land etc. In general, the studies, as such, have

revealed that there is no significant adverse impact on the ecology due to the project

activities in any of these stations. Such studies conducted from time to time around a

power project have established comprehensive environment status at various post

operational stages of the project.

2.1 Overview The natural gas-fired combined cycle gas turbine (CCGT) based power plant and associated transmission and transformer facilities (T&T facilities) is located in an area of 324.58 acres in the village of Mujhedi, Neemka, Faridabad district, Haryana State, in India’s Northern region, targeting the elimination of supply deficits and contributions to living standard improvements and industrial development within the region.

*A indicates location of the plant

A yen loan of 56,154 million was extended from OECF (Overseas Economic Cooperation Fund) Japan to the President of India / National Thermal Power Corporation Ltd. (NTPC) and Powergrid Corporation of India Ltd. (POWERGRID) to cover the power plant and T&T facilities costs, excluding the land acquisition costs, project management costs, taxes and part of the costs for the switchyards, however, the portion necessary for the works to be undertaken by the end of FY95 (23,536 million yen) was in fact provided.

Outline of Loan Agreement Loan Amount 23,536 million yen Loan Disbursed Amount 19,937 million yen Exchange of Notes December 1993 Loan Agreement January 1994 Terms and Conditions -Interest Rate 2.6% -Repayment Period (Grace Period)

30 years (10 years)

-Procurement General untied Final Disbursement Date March 2001

(10 years)

Initially the entire Northern region was established as the project’s beneficiary area, and plant output was projected to be around 800MW so as to be capable of supplying an adequate volume of power. However, an 800MW output scale was found to be excessive in terms of securing fuel. In addition, with the exception of Haryana State, all other states in the region expressed reservations about future purchases of power from the plant, citing high fuel costs, thus a proposal was made to the Haryana State government regarding the conclusion of a power purchase contract, on condition that the entire volume of power produced at the Faridabad Power Station be supplied to the state. This proposal was accepted by NTPC and approved by the central government, in consequence of which the project’s beneficiary area was narrowed down from the entire Northern region to Haryana State alone. The “Flare Gas Reduction Project” and "HBJ (Hazira-Bijaipur-Jagdishphur) Gas Pipeline Reinforcement Project” that were instituted as external requirements (the drilling for and supply of natural gas) for the establishment of this plant were respectively completed in 1999 and 1998. Both projects were jointly funded by JBIC and the World Bank as well as the Asian Development Bank (ADB), and their completion was also a precondition of gas supplies to the Faridabad Power Station. The projects were divided into a number of components; these dates indicate completion of the final components. Power Plant Output Due to the comparatively favorable nature of the terms for generation facilities stipulated by the winning contractor, plant output was fixed at 430MW*6. Switchyard facilities were also changed from the initial 400kV to 220kV compatibility since with the reduction in plant scale (800MW→400MW) and hence the plant was connected to 220kV power lines. Transmission & Transformer Facilities Since the plant turned out to be connected to the 220kV system, the construction / expansion of 400kV substations and the construction of incoming 400kV transmission lines were omitted, and two 220kV transmission line routes were constructed from the plant to existing substations. Implementation Schedule (1) Power Plant The power plant was completed in July 2000, two years and seven months behind the initially planned date (December 1997). This delay was caused by approval procedures accompanying the changes to output scale and so on, however, as Table 3 illustrates, construction of the plant per se progressed extremely smoothly.

Construction Schedule for Key Power Plant Components Component Initial schedule Actual No. 1 Gas turbine generator 30 months 23 months No. 2 Gas turbine generator 32 months 27 months Steam turbine generator 42 months 36 months

(2) Transmission & Transforming Facilities For the same reason as cited above, construction started three years behind schedule, but was completed in 16 months, which was essentially as per the plans (14 months). The delays occurring prior to construction are believed to have been the product of limitations in NTPC’s ability to deal, unassisted, with the numerous state governments and related organizations involved in the process. However, given the fact that debate over the changes in output scale linked to hold ups in the approval process, it might have been possible to confirm / verify the prospects for power purchase by each of the states in advance, thereby reducing the duration of the delays. However, it would be beneficial to evaluate how the construction work was completed in less time than initially projected under such circumstances. Contribution of the plant in Haryana State The Faridabad Power Station commenced on-grid generation in 1999 and all power produced (100%) at the plant is being supplied to Haryana State. Assuming that the plant had not existed in FY99, the supply deficit in the state would have deteriorated from 2.3% to 9.0%*11. Moreover, in a trial calculation for the following year, FY00, the supply deficit would worsen from 2.8% to 15.8%. In fact, the peak supply deficit dropped from 8.3% in FY98 to 3.3% in FY00, a circumstance to which the Faridabad Power Station is believed to making a certain contribution*12. The net electric energy production had reached approximately 2,797MWh in FY01. This is roughly equivalent to 16% of total power consumption in Haryana State (17,856MWh). Further, peak demand (FY01) was 3,004MW with the plant supplying 12.7% of the demand during peak times. In summary, the plant has attained the initially set targets.

Environmental Impacts

NTPC periodically measures effluent and atmospheric concentrations of environmental pollutants including nitrogen oxide (NOx) and sulfur oxide (SOx), as well as the quality of effluent and water in the river into which said effluent is discharged (suspended particulate matter, heated effluent, etc.). All results to date have been in conformity with the standards governing emissions and the environment established by the national government, and there have been no specific reports of adverse environmental impacts.

Power produced at the Faridabad Power Station is purchased by Haryana Vidyut Prasaran Nigam Ltd., (HVPNL), the distribution company that came into being as the result of the unbundling of Haryana State Electricity Board (HSEB).

Item Plan Actual 1) Project Scope Power station Transmission / transformer facilities

1) Gas turbine generators, 140MW × 2 2) Steam turbine generators, 130MW × 1 3) Heat recovery steam gas boiler × 2 4) Monitoring /control equipment, water treatment facilities, etc. 5) Switchyard and related facilities 1) 400kV Dadri-Ballabgarh transmission line 2) 400kV Ballabgarh-Jaipur transmission line 3) Construction and expansion of substation facilities

1) Gas turbine generators, 137MW × 2 2) Steam turbine generators, 156 MW × 1 3) As planned 4) As planned 5) Changed from 400kV to 220kV 1) 220kV Faridabad-Samaypur transmission line 2) 220kV Faridabad-Palla transmission line 3) Only 220kV bay constructed

2) Implementation schedule Power plant Transmission lines Substations

Dec. 1994 - Dec. 1997 Aug. 1995 - Sep. 1996 Aug. 1994 - Sep. 1996

Jan. 1998 - Jul. 2000 Aug. 1998 - Dec. 1999 Aug. 1998 - Dec. 1999

2.2 Combined Cycle Gas Turbine (CCGT) plant A combined cycle is characteristic of a power producing engine or plant that employs more than one thermodynamic cycle. Heat engines are only able to use a portion of the energy their fuel generates (usually less than 50%). The remaining heat (e.g., hot exhaust fumes) from combustion is generally wasted. Combining two or more thermodynamic cycles, such as the Brayton cycle and Rankine cycle, results in improved overall efficiency.

In a combined cycle power plant (CCPP), or combined cycle gas turbine (CCGT) plant, a gas turbine generator generates electricity and the waste heat is used to make steam to generate additional electricity via a steam turbine; this last step enhances the efficiency of electricity generation.

Design Principle In a thermal power station water is the working medium. High pressure steam requires strong, bulky components. High temperatures require expensive alloys made from nickel or cobalt, rather than inexpensive steel. These alloys limit practical steam temperatures to 655 °C while the lower temperature of a steam plant is fixed by the boiling point of water. With these limits, a steam plant has a fixed upper efficiency of 35 to 42%.

An open circuit gas turbine cycle has a compressor, a combustor and a turbine. For gas turbines the amount of metal that must withstand the high temperatures and pressures is small, and lower quantities of expensive materials can be used. In this type of cycle, the input temperature to the turbine (the firing temperature), is relatively high (900 to 1,400 °C). The output temperature of the flue gas is also high (450 to 650 °C). This is therefore high enough to provide heat for a second cycle which uses steam as the working fluid; (a Rankine cycle).

In a combined cycle power plant, the heat of the gas turbine's exhaust is used to generate steam by passing it through a heat recovery steam generator (HRSG) with a live steam temperature between 420 and 580 °C. The condenser of the Rankine cycle is usually cooled by water from a lake, river, sea or cooling towers. This temperature can be as low as 15 °C.

Typical size of CCGT plants For large scale power generation a typical set would be a 400 MW gas turbine coupled to a 200 MW steam turbine giving 600 MW. A typical power station might comprise of between 2 and 6 such sets.

Efficiency of CCGT plants By combining both gas and steam cycles, high input temperatures and low output temperatures can be achieved. The efficiency of the cycles add, because they are powered by the same fuel source. So, a combined cycle plant has a thermodynamic cycle that operates between the gas-turbine's high firing temperature and the waste heat temperature from the condensers of the steam cycle. This large range means that the Carnot efficiency of the cycle is high. The actual efficiency, while lower than this, is still higher than that of either plant on its own.

Supplementary firing and blade cooling The HRSG can be designed with supplementary firing of fuel after the gas turbine in order to increase the quantity or temperature of the steam generated. Without

supplementary firing, the efficiency of the combined cycle power plant is higher, but supplementary firing lets the plant respond to fluctuations of electrical load. Supplementary burners are also called duct burners. More fuel is sometimes added to the turbine's exhaust. This is possible because the turbine exhaust gas (flue gas) still contains some oxygen. Temperature limits at the gas turbine inlet force the turbine to use excess air, above the optimal stoichiometric ratio to burn the fuel. Often in gas turbine designs part of the compressed air flow bypasses the burner and is used to cool the turbine blades. Fuel for combined cycle power plants Combined cycle plants are usually powered by natural gas, although fuel oil, synthesis gas or other fuels can be used. The supplementary fuel may be natural gas, fuel oil, or coal. Bio-fuels can also be used. Integrated solar combined cycle power stations combine the energy harvested from solar radiation with another fuel to cut fuel costs and environmental impact. Configuration of CCGT plants The combined-cycle system includes single-shaft and multi-shaft configurations. The single-shaft system consists of one gas turbine, one steam turbine, one generator and one Heat Recovery Steam Generator (HRSG), with the gas turbine and steam turbine coupled to the single generator in a tandem arrangement on a single shaft. Key advantages of the single-shaft arrangement are operating simplicity, smaller footprint, and lower startup cost. Single-shaft arrangements, however, will tend to have less flexibility and equivalent reliability than multi-shaft blocks. Additional operational flexibility is provided with a steam turbine which can be disconnected, using an SSS Clutch, for start up or for simple cycle operation of the gas turbine. Multi-shaft systems have one or more gas turbine-generators and HRSGs that supply steam through a common header to a separate single steam turbine-generator. In terms of overall investment a multi-shaft system is about 5% higher in costs. Single- and multiple-pressure non-reheat steam cycles are applied to combined-cycle systems equipped with gas turbines having rating point exhaust gas temperatures of approximately 540 °C or less. Selection of a single- or multiple-pressure steam cycle for a specific application is determined by economic evaluation which considers plant installed cost, fuel cost and quality, plant duty cycle, and operating and maintenance cost. Multiple-pressure reheat steam cycles are applied to combined-cycle systems with gas turbines having rating point exhaust gas temperatures of approximately 600 °C. The most efficient power generation cycles are those with unfired HRSGs with modular pre-engineered components. These unfired steam cycles are also the lowest in cost. Supplementary-fired combined-cycle systems are provided for specific application. The primary regions of interest for cogeneration combined-cycle systems are those with unfired and supplementary fired steam cycles. These systems provide a wide range of thermal energy to electric power ratio and represent the range of thermal

energy capability and power generation covered by the product line for thermal energy and power systems.

2.2 Water treatment Raw water for steam turbine generation (STG), use as circulating water (CW) and other purposes is taken from the Agra canal through an extensive piping system. The water is contaminated with various minerals and other impurities which readily dissolve in it. They have to be removed from the raw water before it can be used for any industrial applications. For this purpose water is treated first by a Pre-Treatment (PT) plant and then by a De-Mineralization (DM) plant. 2.2.1 Pre-treatment (PT) plant Pre-treatment plant consists mainly of clarifiers, chemical house, gravity filter, pressure filter and Chlorine dozing. A Cooling Water (CW) clarifier caters water requirement of CW makeup, HVAC makeup, fire fighting and auxiliary water requirements. For back washing gravity filters, blowers have been provided. Sand in the form of quartz, free from clay, fine particles and soft grains is used in the gravity filters with sizes ranging between 0.45 to 0.70 mm. The nature and concentration of impurities and objectionable constituents of water determine the methods to be employed for the treatment of water. Different techniques are used for removal of mechanical impurities, Clayey turbidities, Colloidal, dissolved impurities, organic matter, detergents, polycyclic aromatics,

colouring substances, oils and aliphatic hydrocarbons etc. which impart taste or odour, polyvalent heavy-metal compounds, germs and bacteria.

The water is given an initial dose of chlorine when it is in the raw water tank. This water is pumped by three CW pumps for use as circulating water while other three pump this water for further processing as described below:

1. The pumped water is passed to an Aerator, which oxidizes soluble iron in the Raw Water (RW) from Ferrous to Ferric State.

2. Water flows to the Stilling Chamber to break the turbulence. 3. Water is then taken into the Flash Mixer for intimate mixing of chemicals with

the raw water. 4. The raw water is dosed with Alum or PAC (Poly Aluminium Chloride), Lime

and Polyelectrolyte to coagulate and flocculate the suspended / colloidal matter and form floc of higher nuclei thereby enhancing the efficiency of sedimentation.

5. Chemically dosed raw water is then fed into the clariflocculator unit wherein flocculation and clarification of raw water takes place.

6. The sludge generated in the clariflocculator is bled via Telescopic Bleeds to an underground Sludge Pit. The sludge collected from the plant is finally pumped out.

7. Clarified water is collected in the launder of the clarifier located on the top periphery from where it flows to the clarified water reservoir.

The clearified water is then pumped to the De-Mineralisation (DM) plant for removing inorganic impurities and making the water suitable for use in Heat Recovery Steam Generator (HRSG) and Steam Turbine (ST).

2.2.2 De-Mineralisation (DM) plant Demineralisation is the process of removing the mineral salts from water by ion-exchange. Impurities that remains dissolved in water dissociate to form positive and negative charged particles known as ions. These impurities or compounds are called electrolytes. Generally, all natural water has electrolytes in varying concentrations. An ion-exchange vessel holds ion-exchange resin of the required type through which water is allowed to pass. The selective ions in the water are exchanged with ions or radicals loosely held by the resin. In this way, the water is passed through several vessels or a mixed bed vessel so that both positive and negative ions are removed and water is demineralised. The DM plant at Faridabad gas power plant (FGPP) was provided by Ion Exchange (I) Ltd (Mumbai), over a period of 20 months on 30-03-2000. The demineralization plant is a two stream plant having a normal treatment capacity of 100 m3/hr. Each demineralising chain comprises of following units:

a) ACF : Activated Carbon Filter b) WAC :Weak Acid Cation Exchanger c) SAC :Strong Acid Cation Exchanger d) DG & DGWT :Degasser Tower and Degassed Water Storage Tank e) WBA :Weak Base Anion Exchanger f) SBA : Strong Base Anion Exchanger g) MB :Mixed Bed Exchanger

Apart from the above a hot water tank is provided for heating “power water” required for regeneration of SBA/WBA unit & when residual silica at outlet is high. Each exchanger is mounted with several instruments for local and/or panel indication, control or alarm to monitor the various parameters for smooth running of the plant. Each exchanger is mounted with flow instrument (Rotameter) at the service inlet, pressure gauge at inlet and outlet, and resin trap at the outlet. The plant has predominantly DOPC diaphragm valves mounted on the service inlet, backwash inlet and outlet, bleed and air release, Service outlet and regenerant valves are DOPO diaphragm valves. The block valves open and close with the regenerant inlet valve while the bleed valves open and close when the block valves and regenerant inlet valves open and close respectively. Needle valves are used for transmitter, pH sample, pressure indicator isolation, drain and sample while ball valves are used for flow indicator and flow switch isolation, inter connecting valves between service outlet header of two streams of two streams are manually operated butterfly valves. Carbon filters are provided upstream for residual chlorine reduction and organic removal in the water supply to the demineraliser. Downflow service and upflow regeneration is employed for the primary Cation and Anion exchangers. The mixed bed is designed with simultaneous regeneration of cation and anion resin. For anion resin, the caustic dilution system is designed with on-line hot caustic regeneration.

The WAC and SAC remove the cationic inorganic impurities while the WBA and SBA remove the acidic inorganic impurities present in water.

2.4 Components 2.4.1 Air filters Ambient air can be contaminated by solids, liquids, or gases. Of these three, contamination by solids is the most common, and usually the most serious situation. When account is taken of ’the large flow rates of gas turbines, it is evident that the total quantity of dust which is ingested can be appreciable when summed over hundreds or thousands of fired hours. Therefore, Inlet air filtration systems are essential on any gas turbine. Some of the consequences of poor inlet filtration are fouling, erosion, and corrosion.

Feed Water

ACF WAC SAC

Degasser

WBA SBA MB CST

Five basic filtration mechanisms are described below: The first filtration mechanism is inertial impaction. This type of filtration is applicable to particles larger than 1 micron in diameter. The inertia of the large heavy particles in the flow stream causes the particles to continue on a straight path as the flow stream moves to go around a filter fiber. The particulate then impacts and is attached to the filter media and held in place as shown in the top picture of figure .This type of filtration mechanism is effective in high velocity filtration systems.

The next filtration mechanism, diffusion, is effective for very small particles typically less than 0.5 microns in size with low flow rates. These particles are not held by the viscous forces in the fluid and will diffuse within the flow stream along a random path (second picture). The path the particle takes depends on its interaction with nearby particles and gas molecules. As these particles diffuse in the flow stream, they collide with the fiber and are captured. The smaller a particle and the lower the flow rate through the filter media, the higher probability that the particle will be captured. The next two filtration mechanisms are the most well known; interception and sieving. Interception occurs with medium sized particles that are not large enough to leave the flow path due to inertia or not small enough to diffuse. The particles will follow the flow stream where they will touch a fiber in the filter media and be trapped and held. Sieving is the situation where the space between the filter fibers is smaller than the particle itself, which causes the particle to be captured and contained. Another type of filtration mechanism which is not shown in Figure is viscous impingement. This type of mechanism uses the inertial impaction mechanism to capture particles. What makes this mechanism unique is that the filter is covered with a thin layer of oil which causes the captured particles to adhere to the filter surface, thus preventing them from being released downstream. The amount of particles captured is maximized by creating a torturous path for the air. This results in a filter

with many changes in flow direction. This filtration mechanism is effect for medium to large size particles. The last filtration mechanism is electrostatic charge. This type of filtration is effective for particles in the 0.01 to 10 micron size range. The filter works through the attraction of particles to a charged filter. In gas turbine applications, this charge is applied to the filter before installation during the manufacturing process. Filters always lose their electrostatic charge over time because the particles captured on their surface occupy charged sites, therefore neutralizing their electrostatic charge. As the charge is lost, the filter efficiency for small particles will decrease. However, it should be noted that as the filter is loaded, the filtration efficiency increases. This will offset some of the loss of filtration efficiency due to the lost charge. Figure below shows a comparison of a filter’s total efficiency based on the various filtration mechanisms that are applied.

2.4.2 Compressor-Gas Turbine- Generator A gas turbine is a rotary engine that extracts energy from a flow of combustion gas. It has an upstream compressor coupled to a downstream turbine, and a combustion chamber in-between. Energy is added to the gas stream in the combustor, where fuel is mixed with air and ignited. In the high pressure environment of the combustor, combustion of the fuel increases the temperature. The products of the combustion are forced into the turbine section. There, the high velocity and volume of the gas flow is directed through a nozzle over the turbine's blades, spinning the turbine which powers the compressor and drives the generator.

Before starting the turbine, compressor has to be started. For this purpose, an electric motor is mounted on the same shaft as that of the turbine. The motor is energised externally. Upon reaching 20% of the rated rpm the gas turbine is ignited. It is speeded up higher and takes the system to approximately 50% or its rated rpm. From this point on, any further increase in speed is accomplished by the gas turbine and the motor is disconnected. Once the unit starts, a part of the mechanical power of the turbine drives the compressor and there is no need of the motor. Faridabad plant is equipped with two gas turbines provided by Siemens (V94.2 model 3) with a capacity of 137.6 MW. Each turbine consists of a 16 stage compressor and a four stage turbine mounted on a single shaft with four bearings as shown in figure.

Generator Compressor Turbine

Journal Bearing

Thrust Bearing

2.4.3 Diverter-Damper Since the gas turbine has two options; one is to run in open cycle i.e. by passing HRSG or waste heat recovery boiler (WHRB) and second (normal) mode in which HRSG is in circuit, hence a damper has been provided on the path of flue gas. This damper will close the path either towards HRSG or towards the by-pass stack.

. Movement of the damper is 900 and it is basically rectangular shaped plate which seats perfectle on its seal provided at the two places. Blade of diverter damper is made off carbon steel supported on suitable modification on both sides to resist temp of 5400C and sudden cooling and heating during operation.

2.4.4 Heat Recovery Steam Generator (HRSG) Faridabad gas power project, popularly known as FGPP, is equipped with two HRSGs of 277 t/hr each. A heat recovery steam generator or HRSG is an energy recovery heat exchanger that recovers heat from a hot gas stream. It produces steam that can be

used in a process or used to drive a steam turbine. HRSGs consist of three major components. They are the Evaporator, Superheater, and Economizer. The different components are put together to meet the operating requirements of the unit. In horizontal type HRSGs, exhaust gas flows horizontally over vertical tubes as shown in figure.

Direct Benefits: Recovery of waste heat has a direct effect on the efficiency of the process. This is reflected by reduction in the utility consumption & costs, and process cost. Indirect Benefits: a) Reduction in pollution: A number of toxic combustible wastes such as carbon monoxide gas, sour gas, carbon black off gases, oil sludge, Acrylonitrile and other plastic chemicals etc, releasing to atmosphere if/when burnt in the incinerators serves dual purpose i.e. recovers heat and reduces the environmental pollution levels. b) Reduction in equipment sizes: Waste heat recovery reduces the fuel consumption, which leads to reduction in the flue gas produced. This results in reduction in equipment sizes of all flue gas handling equipments such as fans, stacks, ducts, burners, etc. c) Reduction in auxiliary energy consumption: Reduction in equipment sizes gives additional benefits in the form of reduction in auxiliary energy consumption like electricity for fans, pumps etc. Flue gas from the combustion turbine enters the HRSG at a temperature of around 5400C and is reduced in temperature by the superheater, reheater, dram evaporative surfaces, and economizer before it enters the stack. Condensate from the combined cycle condenser enters the deaerator, and flows through the economizer to the drum. Steam from the drum flows to the superheater and then to the high pressure turbine. Steam from the high pressure steam turbine flows through the reheater and then to the intermediate pressure turbine.

Pinch points and approach temperatures are important HRSG design parameters. Reducing these temperatures will increase cycle efficiency. 2.4.5 Steam Turbine-Generator The Faridabad gas power plant is equipped with BHEL 156 MW steam turbine. The heat energy in the steam from HRSG is converted to mechanical energy in the steam turbine. The turbine uses the mechanical energy from the steam to turn the generator which then converts the mechanical energy to electrical energy. The steam expands and cools in the energy conversion in the steam turbine. A small fraction of the steam condenses in the steam turbine and appears as small water droplets. The mixture of steam and water exhausts from the steam turbine to the condenser where the remaining steam is condensed into water, usually referred to as condensate. The heat required to change the state between steam and water, called the heat of vaporization, is rejected to the circulating water through heat transfer in the condenser. The condensate is then pumped back to the HRSG through heat exchangers designed to capture more heat through heat transfer. The process is then repeated. Bearing and Lubication: Two types of bearings are used to support and locate the rotors of steam turbines: Journal bearings are used to support the weight of the turbine rotors. A journal bearing consists of two half-cylinders that enclose the shaft and are internally lined with Babbitt, a metal alloy usually consisting of tin, copper and antimony; and Thrust bearings axially locate the turbine rotors. A thrust bearing is made up of a series of Babbitt lined pads that run against a locating disk attached to the turbine rotor.

High-pressure oil is injected into the bearings to provide lubrication. The oil is carefully filtered to remove solid particles. Specially designed centrifuges remove any water from the oil. Shaft Seals The shaft seal on a turbine rotor consist of a series of ridges and groves around the rotor and its housing which present a long, tortuous path for any steam leaking through the seal. The seal therefore does not prevent the steam from leaking, merely reduces the leakage to a minimum. The leaking steam is collected and returned to a low-pressure part of the steam circuit. Turning gear: Large steam turbines are equipped with "turning gear" to slowly rotate the turbines after they have been shut down and while they are cooling. This evens out the temperature distribution around the turbines and prevents bowing of the rotors.

2.4.6 Main Control Room (MCR) The control room is the heart of the processing system. It is the core of the plant and the main part of the supervision is carried out here. Working as an operator involves many hours in front of computer screens. A pleasant and appropriate surrounding enhances the work spirit and stamina. An interface provides the operator with the general following information:

· After initiating an action within a system the operator is clearly informed of the result of their action.

· If there is a delay in the system that prevents the operator from being informed of the result of his/her action, the system informs the operator of this fact.

· If an action is made in error then it is possible to reverse such an action where it would not be detrimental to plant safety to do so.

· The system informs the operator of any deviations from safe operating levels, through alarms.

For large plants, control rooms are likely to be situated in separate buildings away from the process plant which they serve. For medium or small plants control rooms may be within the plant building or control panels may be located local to the plant. 2.4.7 Cooling tower Induced Draft Cooling Tower of 29000 m3/hr capacity has been built to cool the hot water coming out of condenser of steam turbine. It is capable to reduce water temperature by 110.

The primary task of a cooling tower is to reject heat into the atmosphere. This heat rejection is accomplished through the natural process of evaporation that takes place when air and water are brought into direct contact in the cooling tower. The evaporation is most efficient when the maximum water surface area is exposed to the maximum flow of air, for the longest possible period of time. Cooling towers are designed in two different configurations, counter flow and cross flow. The specific configuration indicates the direction of air flow through the tower relative to the direction of the water flow.

Induced draft cooling towers are constructed such that the incoming circulating water is dispersed throughout the cooling tower via a spray header. The spray is directed down over baffles that are designed to maximize the contact between water and air. The air is drawn through the baffled area by large circulating fans and causes the evaporation and the cooling of the water. The heat exchanger media in the cooling tower is PVC fills packed in box form after gluing each other suitably at the top of the cooling tower. Placed just below the propeller fans drift eliminator, PVC fills (grey coloured) are cross corrugated with minimum sheet thickness of 0.2 mm and minimum sheet spacing is 17 mm. Drift Eliminator: It is placed between propeller fan and PVC fills boxes. The purpose of drift eliminator is to arrest carry over of minute water particles form air so that drift loss is a minimum of .05% of total water circulation. Drift eliminator is nothing but closely packed PVC sheet arrangements.

2.5 Switchyard A Switchyard or Substation, consisting of large breakers and towers, is located in an area close to the plant. The substation is used as the distribution center where:

· electrical power is supplied to the plant from the outside, and · electrical power is sent from the plant

Often there are at least 2 main Buses. The generated power at FGPP is transmitted as 220 kV to the grid thorugh four output lines: 2 to Samaipur (ballabgarh) and 2 to palla( faridabad), where other substations step down the voltage for distribution to households. The switchyard at FGPP was erected by Power Grid Corporation Of India Ltd. (NR) in 1998.

2.6 Major Departments Departments are the entities organizations form to organize people, reporting relationships, and work in a way tht best supports the accomplishment of the organization's goals. Departments are usually organized by functions. 2.6.1 Human resources (HR) The human resource department is devoted to providing effective policies, procedures, and people-friendly guidelines and support within companies. Additionally, the human resource function serves to make sure that the company mission, vision, values or guiding principles, the company metrics, and the factors that keep the company guided toward success are optimized. It focuses on recruitment of, management of, and providing direction for the people who work in the organization. 2.6.2 Maintenance Planning (MTP) The MTP department increases the Maintenance department’s ability to complete work orders. Work plans avoid anticipated delays, improve on past jobs, and allow scheduling. Advance scheduling allows supervisors to assign and control the proper amount of work. A work crew is ready to go immediately to work upon receiving a planned and scheduled assignment because all instructions, parts, tools, clearances, and other arrangements are ready. The required jobs are ready to go. 2.6.3 Operation & Maintenance: Mechanical (O&M- MM) Mechanical Maintenance is a support service department that caters to the maintenance needs of the refrigeration and mechanical sections of the plant. It does works at an approximate rate of 6 jobs per day. They facilitate uninterrupted working of the plant, including getting the spares as scheduled by the MTP department. 2.6.4 Operation & Maintenance: Electrical (O&M- EMD) The EMD department takes care of electrical repairs of all types including primary as well as the secondary systems. It continuously monitors the output of the plant and takes necessary steps of efficient working of the plant. It also works with POWERGRID, the transmission company, and caters to the requirements of the grid with respect to plant capacity. 2.6.5 Operation & Maintenance: Control & Instrumentation (O&M- C&I) Control & Instrument Department(C&I) is responsible for the operation and maintenance of all the electronic sensors, actuators and controllers. It takes care of the following functions: Maintenance of all existing systems, Procuring related Spares and In-House Modification. It monitors the various parameters of the plant and notifies the concerned department if case of any problems. 2.6.6 Operation & Maintenance: Chemical (O&M-Chem) This department looks after the chemical maintenance of the DM plant and the PT plant. It continuously monitors the pH values, pressures, storages, concentration of chemicals, etc and takes measures accordingly as required for the healthy functioning of the plant.

3.1 Introduction to Siemens V94.2 The gas turbine has a nominal generation capacity of 137 MW at site condition (average temperature of about 30 degree C) and can be operated in open-cycle mode as well as closed-cycle mode with either natural gas or Naptha as fuel. It generates at 10.5 kV, and transmits electrical power at 220 kV via a step-up transformer. It is also equipped with black-start diesel engine generator to allow for total black-start conditions (as an option). The GT is a Siemens SGT5-2000E (formerly known as the V94.2) heavy-duty gas turbine. It is of single-shaft, single casing design, equipped with 2 silo-type combustion chambers, a 16-stage compressor and a 4-stage turbine. An air-cooled generator, rated at 125 MVA and generating at 10.5 kV is driven from the cold (compressor) end of the GT unit. The unit is installed with dual fuel Siemens diffusion-type burners, capable of operation on distillate-oil liquid and natural gas. Other important features can be summarised as follows:

· 16-stage compressor, adjustable inlet guide vanes (IGVs), optionally fast-acting for grid frequency stabilisation;

· two large external silo-type combustors equipped with 2x8 hybrid burners for premix and diffusion mode operation with natural gas, fuel oil and special fuels, such as heavy oil and refinery residues;

· hot casings weld-fabricated from Ni-based material, designed with single shell for elbow-shaped mixing casings or double shell for inner casing;

· four-stage turbine with conventionally cast blading made of Ni-based material, stages 1 and 2 having conventional cooling providing fuel flexibility (including ash forming fuels, that cannot be burnt when film-cooled blading is used);

· built-up disc rotor with a self-centring radial Hirth serrations and one central tie rod;

· four bearing design; · generator drive at cold end; · axial exhaust design; · fast starting capability, a major advantage for peaking and black start

applications; · compressor and turbine blades and vanes exchangeable with rotor in place; · high availability due to long maintenance intervals; and · Capability for hot-gas-path to be inspected without cover lift thanks to the

walk-in combustion chambers. When looking at the silo-type combustor design, its robustness and simplicity become evident:

· Flame tubes are lined with easily replaceable ceramic tiles; for ash-forming fuels a specific flame tube option is available as well as for low-Btu gas

· Walk-in combustion chamber design enables minor walkthrough inspection without cover lift, only one manhole is opened

· Hybrid burners in premix mode for dry low NOx and low CO emissions (natural gas & fuel oil)

· Diffusion burners for special fuels, e.g. ash-forming fuel oil or low-Btu gas such as synthetic gas or coal gas used in V94.2 and V94.2K; these burners have options for integrated water or steam injection

· The combustion chamber dome can easily be modified when required for low-Btu gas diffusion burners

· Turbine blading benefits from highly uniform hot-gas temperature distribution due to the considerable mixing distance and from non-exposure to flame radiation.

Compressor blades

· Variable pitch inlet guide vanes allow operation down to half load while maintaining a constant exhaust temperature.

· All stationary and moving blades of the compressor and turbine can be replaced individually without removing the rotor from the lower casing.

Turbine blades · Convective air-cooling of the first three stationary and first two

moving turbine blade rows protects the blade material against high inlet temperatures. The first three stages of the turbine are protected with a special coating.

· No film cooling is used to allow ash-forming fuel firing. · The free-standing moving blades of the compressor and turbine

are tuned to permit continuous full load operation over a wide off-frequency range.

Rotor · The light, highly rigid rotor of disk design allows rapid start-ups. · Internal air-circulation paths in the rotor minimize thermal

stresses. · Hirth facial serrations at the outer perimeter of the disks ensure

self-centering of all the rotor components under steady and nonsteady- state operating conditions.

These features make the V94.2 highly attractive for both continuous-duty combined cycles as well as peaking applications.

During the tender process of choosing the technology, two dominant reasons led to the selection of the Siemens V94.2 turbine over other competitors. Firstly, this technology makes use of a dry-NOX system. This means that the amount of water used by the turbine to keep the NOX levels within statutory requirements is minimal, when compared to other machines. Secondly, these units are very robust and able to absorb the stresses of frequent start-ups.

Standstill/Turning Gear to Generating The units are very rarely at complete standstill. When not generating or in the synchronous condenser operation (SCO) mode they are generally in “turning gear”. The changes from standstill or turning gear modes to generating are very similar. When a unit starts up, the generator initially acts as a motor, driving the rotor shaft and therefore the compressor/turbine shaft. This function is performed by the static frequency converter. The static frequency converter (SFC) draws power to drive the shaft, via the start-up transformer, from the medium-voltage supply of the plant auxiliary power supply system. As the shaft speeds up the turbine also begins to play a role in accelerating the shaft as the compressor blades begin to set up the vacuum effect which assists in driving the machine. While the unit is still at these relatively low speeds, extra lube oil is pumped into the bearings to provided additional lubrication and reduce the frictional forces that the unit experiences.

When the speed of the unit is between 5.5 – 6.5 Hz the ignition gas system activates and the gas is ignited by two spark plugs located near each burner. These receive their energy from the ignition transformer. Hi- speed diesel is used to start the generator in case the system has to run on Naptha.

Once the burners are running, the turbine begins to play the dominant role in accelerating the shaft. When the shaft reaches approximately 36.5 Hz the ignition transformer is switched off, the ignition gas valves close and diesel is pumped into the burners. The unit now enters diffusion mode. During this mode only some of the fuel is injected into the burners and the rest is returned via the return line to the storage tanks. This means that there is an opportunity to influence the amount of fuel entering the combustion chamber so that the process can be better controlled. The benefit of diffusion mode is that it is very stable over the entire output range of the machine. A negative, however, is that the emission levels are much higher when the machine is run in diffusion rather than in premix mode. The SFC continues to assist in the acceleration of the shaft until it turns at a speed greater the 38.6 Hz. At this point the SFC is shut down and its external isolator is opened. The turbine is now completely responsible for rotating the shaft. Once the unit is ready to synchronize with the grid the generator breaker closes and the static excitation equipment (SEE) begins to provide energy to the rotor so that the generator can begin to produce power.

Once the unit reaches about 50 % of base load and an output temperature greater than 500 ºC the unit switches to premix mode. In this mode the fuel enters the burner at a different location which allows it to be mixed with air before the combustion zone. This reduces both the fuel consumption and the emissions. Standstill/Turning Gear to SCO In SCO mode the generator is operated as a motor to either send out or absorb reactive power from the grid. There are two options by which the generator can be run-up to synchronize with the grid. The first is to run the unit up using the SFC to a speed greater than 50 Hz. The SFC is then switched off and the machine can synchronize with the grid as the machine slows down naturally. The second method is to run the unit up in the standard manner with the turbine and then disconnect the turbine from the generator once the unit has linked with the grid. The turbine, however, incurs superfluous equivalent operating hours (EOH). This means that maintenance intervals are reached earlier and required more frequently, which contributes to the running expenses of the unit. Generation to Turning Gear/Standstill Before the unit can be completely shutdown it is first de-loaded at 11 MW/ min to a point below an 8MW output. Once it has reached this level it is further de-loaded until zero MWs are sent out. The reason for de-loading in stages is that it allows the other sub-systems on the unit to complete their own shutdown procedures. When the generator reaches this stage it is disconnected from the grid and the turbine is switched off. The shaft is then allowed to run down naturally until it reaches turning gear speed at which it is rotated for 24 hours to ensure that the shaft and turbine cool down uniformly and that no warping occurs. When the unit is not operating, dehumidified air is circulated through both the turbine and the generator to ensure that any corrosion is kept to a minimum. Ambient air is also prevented from entering the turbine while it is not running so that it does not counteract the dehumidifying system.

3.2 Auxilliaries 3.2.1 Lube Oil System The Lube Oil System has four main functions. Firstly it provides lubricating oil to the bearings along the shaft so as to minimize the friction within, and to remove heat from, the bearings. The lube oil is continually circulated within the system and also ensures that any wear debris or solid contaminants are flushed from the bearings. Secondly the lube oil is sprayed onto a single-stage hydraulic turbine which is connected to the gas turbine shaft by gearing. This enables the shaft to turn at approximately 2 Hz or 120 rpm at Turning Gear or Barring Speed. This is an important function as it is vital that the shaft is rotated at this speed for 24 hours after being in

either synchronous condenser operation (SCO) or generation mode to ensure that the turbine cools down uniformly so that the shaft does not warp. Thirdly, the Lube Oil System is used to jack the shaft up slightly when the unit is first activated after being at either a very low speed or standstill. The jacking oil is necessary as, at these low speeds, the lube oil in the bearings is not sufficient to create an adequate hydrodynamic lubricating film. The presence of the jacking oil, therefore, helps to further reduce the friction in the bearings, ensuring that the inertia of the shaft can be overcome with less force being required. Fourthly, lube oil is used by the synchronous condenser clutch to operate its locking control and output brake. 3.2.2 Lube Oil Cooling System The lube oil cooling is completed in two stages. The lube oil itself is water cooled through the plate-type heat exchangers that can be found on top of the lube oil skid. This water is in turn air cooled via three fin fan coolers which release the heat into the atmosphere. The system is a closed system, meaning that no additional water is required unless a leak occurs. This system uses demineralised water to ensure that the system is maintained in as new a condition as possible. 3.2.3 Fuel Oil System The Fuel Oil System links the Fuel Forwarding System to the turbine to provide the burners within the combustion chambers with fuel oil as well as to remove any fuel that is not burnt. The fuel enters the system at a pressure of between 4 and 7 bar, although it is generally maintained above 6 bar. The fuel is passed through a 10 micron duplex filter before entering the injection pump to remove any debris that could influence the system. The injection pump is a 16-stage centrifugal pump which increases the pressure of the fuel to approximately 80 bar which is required for atomization to take place in the burners. There are three different fuel lines going to and leaving the combustion chambers, namely the diffusion supply and return lines and the premix supply line. Each of these lines has a control valve which ensures that the correct amount of fuel is being injected into the burners. The Fuel Oil System thus comprises the fuel injection pump, duplex filters and the fuel lines. It also has a fuel oil leakage tank to collect any fuel from the various drain and relief lines in the system. 3.2.4 Purge Water System The Purge Water System uses demineralised (demin.) water from the DM plant on site. The system supplies demin. water at the required pressure to the premix burners whenever the unit changes from diffusion to premix mode or vice versa. The reason for this flushing is to firstly cool off the premix burners before use and then to clean the burners afterwards. This prevents coking and ensures that the nozzles stay clear. The length of each flush on start-up Diffusion-Premix mode, lasts 10 seconds and uses 37,5 litres of water. On shutdown, the Premix-Diffusion mode flush lasts for 20 seconds and uses 75 litres of water.

3.2.5 Hydraulic System The Hydraulic System provides pressurized hydraulic fluid for the operation of the position actuators in the auxiliary systems. Predominant of these are the control valves on the fuel lines in the Fuel Oil System. The condition of the hydraulic oil is very important and must remain within the ISO 4406 specifications. For this reason the oil is filtered continuously. 3.2.6 Ignition Gas System The Ignition Gas System is responsible for the storage of the ignition gas as well as supplying the gas to the combustion chambers. The gas used on site is 90 - 97 % propane and is contained in two 6.5m3 tanks at a pressure of 9 – 15 bar. The tanks are, however, only filled to 60 % of their capacity. 3.2.7 Filter Housing The air enters the unit through the filter housing situated on the top of the unit. The filter house includes weather hoods, bird screens, pre- and fine filters. The measurement for these filters is 25 micron and 4 micron respectively. The air enters the housing from three sides after which it is fed through silencers into the air intake and then into the compressor. 3.2.8 Turbine The turbine is viewed as the portion of the unit that incorporates the air intake, compressor section, combustion chambers, turbine section and diffuser. It is 9.45 m long and 4.1 m in diameter. The compressor section has 16 stages and converts mechanical energy into the kinetic and potential energy of the compressed air. The combustion chambers are silo type chambers and are found on either side of the turbine, weighing approximately 6 tons each. There are eight individual hybrid burners per chamber and both the liquid petroleum (LP) gas and fuel are fed into the same burner, although at different locations. The flame cylinder at the top of each combustion chamber is covered with ceramic tiles, similar to those of space shuttles, to protect the structure from the heat as the temperature ranges from 10300C to 12000C. There are four sets of turbine blades after which the air passes through to the exhaust. The turbine also incorporates three blow-off pipes which bleed air from the compressor stages and release it via the exhaust to prevent surging in the turbine during start up. 3.2.9 Generator The generator is the heaviest single component on site, weighing 223 tons. The generator has a rated output of 15.75 kV and 6 818 A at 3 000 rpm with a power factor of 0.9. The rotor conductors are made of copper with a silver content of approximately 0.1 %. This combination increases the strength at higher temperatures to eliminate coil deformation due to thermal stresses. The insulation between the individual turns is made of layers of glass fibre laminate. The field winding consists of several coils connected in series and inserted into the longitudinal slots of the rotor body. The coils are electrically connected in series so that one north and one south magnetic pole are obtained.

3.2.10 Generator Cooling System The generators are not 100% efficient, a lot of energy being produced in the form of heat. The generators are equipped with indirectly air cooled stator windings and a radial direct air cooled rotor winding. The cooling air for the generator is drawn by axial-flow fans arranged on the rotor via lateral openings in the stator housing. The heat generated in the generator interior is dissipated through air. The rotor is directly air-cooled with heat losses being transmitted directly from the winding copper to the cooling air. Cooling air is supplied at a rate of 50 m3/s at 28°C . 3.2.11 Exhaust The exhaust stack transfers the hot air from the turbine and releases it into the atmosphere at a maximum temperature of 560 ºC. The stack is 30 m high and has a diameter of approximately 10 m. The exhaust gas has a mass flow rate of around 520 kg/ s and a velocity of approximately 40 m/ s.

3.3 Overview of GT Modernization Products A wide range of products which are either already available or currently under development by modernization engineering is shown in Figure 13. The upgrade packages can be grouped systematically in the following main categories:

· Efficiency -through increasing turbine inlet temperature, enhancing turbine aerodynamics, advanced compressor cleaning system and wet compression / Power –through larger compressor mass flow, water injection and wet compression

· Combustion- reducing emissions and reducing fuel consumption, diversification of fuels (by dry low NOx combustion, fuel conversion and water injection)

· Increasing operational flexibility - through fuel diversification, grid frequency stabilization, improved starting behavior

· Reliability and Availability - through I&C improvement, extended maintenance intervals, reduced maintenance time.

3.3.1 Turbine Inlet Temperature Upgrade (TT1+) or Extended Maintenance Interval (41MAC) This upgrade product features attractive alternatives which increase either availability or turbine inlet temperature. These consist of extending the inspection interval or increasing the turbine inlet temperatures from 1060°C to 1075°C for base-load operation. Regarding the hot gas path starting in the combustion chamber the flame tubes, mixing casings and inner casing are improved. In the mixing casings additional horizontal guides are installed, which require a modification of the mixing casing as well as of the combustion chamber pressure shell. The additional horizontal guides minimize wear at the mixing casing/inner casing transitions and thus contribute to longer inspection intervals for the GT. The inner casing of the V94.2 GT is specially redesigned in response to inspection findings encountered in recent years. The hub, the part of this casing most exposed to thermal fatigue, is redesigned for higher thermo-elasticity and better cooling; this feature and modifications made at other locations have already been discussed in greater detail later.

An upgrade of the premix gas spider piping is also necessary for the maintenance approach; other recommended features are recaulking of the inner compressor vane shrouds at two locations and an upgrade of the manhole insert in the mixing casings. A most important upgrade feature is enhanced protective coatings for the turbine blading. The coating choice has been based on finite element structural analysis and metallographic investigations of service-exposed blades. Representative McrAlY-coated blades and vanes coming especially from fleet leader units at overhaul time have been examined

· by visual inspection for cracks and oxidation · by metallographic analysis for examining internal surfaces and distinctive

structural features (e.g. brittle phases) · by metallographic investigation to estimate blade material temperatures by

means of the gamma-prime-coarsening criterion: the gamma-prime-coarsened metal structure of the service blade is compared to a material structure catalog containing reference structures for various temperatures.

The results were very useful tool for calibrating the heat transfer and structural stress analysis. It should be emphasized that investigations for the upgrade discussed here also require recalculation of the baseline blades and vanes using state-of-the-art stress analysis tools. The original analyses performed many years ago are no longer sufficient; the tools from that time have meanwhile been replaced by state-of-the-art analysis tools. Over the past years Siemens has channeled considerable R&D effort into validation and improvement of turbine blading. The associated calculations for rotor blades include both static and dynamic component loading (creep strength and low cycle fatigue (LCF)). It should also be mentioned at this point that the LCF strength analysis is based on the latest insights gained. Validation of the LCF strength analysis in particular is based on a comparison of calculated component strength with crack indications revealed during standard inspections and refurbishing of GT blades; in this case a crack propagation analysis has to be included. Raising the turbine inlet temperature (TIT) in the operating regime from 1060°C to 1075°C or using extended maintenance requires specific protective thermal barrier coatings to appropriately reduce the temperature gradients (hot gas side/cooling air side), thus sufficiently reducing the static and dynamic loads on the blade to achieve correspondingly long service lives. The protective coating systems must also ensure optimum bonding between the less ductile thermal barrier coating (TBC) and the base material. Specially developed bond coats are required for bonding the TBC to the base material (Ni-based casting) because of the extreme differences in the physical properties of these materials. These protective coatings (bond coats) must also provide protection against high-temperature oxidation and corrosion. Premature wall thinning due to internal oxidation in the cooling air channels is prevented by aluminizing the cooling air side using a process developed by Siemens that is known as Sicoat1411. Siemens design their components in such a way that this internal coating does not require renewal over the entire service life of the blades used in its V94.2 fleet.

This applies for turbine airfoils in the first three rows. Internal aluminizing is not necessary for blade row #2 due to lower thermal loading. Stage-3 turbine vanes are protected against oxidation by an McrAlY-type coating applied using HVOF (High Velocity Oxygen Fuel Thermal Spray Process); refurbishment of this coating is not necessary during the entire lifetime. Refurbishment of the blading is planned for the other externally coated vanes #1 and #2, and blades #1 to #3. The upgraded blading discussed here can be implemented according to the customer’s needs to make the transfer to the operating and maintenance upgrade as smoothly as possible:

· As a complete upgrade package of new parts to replace the original ones · By using single upgraded rows of blades or vanes with the additional benefit of

longer component life and the option for transferring to the upgrade concept at a later point in time when the package has been completed.

· Upgrading the coating of original service-exposed blades and vanes through refurbishment to meet the new requirements.

In the latter case the service life of the blades which has already been utilized must be known in order to precisely determine the subsequent operating cycle following advanced refurbishment. This is done based on the rule of linear damage accumulation and uses the results of the baseline calculation of the original blading as well as the evaluation of the upgrade version. Benefits The Firing Temperature Increase modernization can be a highly cost effective means for improving the performance of your gas turbine plant. Benefits can include:

· Up to 6% power increase (simple cycle) · Heat rate improvement · Increased exhaust energy for cogen or combined cycle applications.

Scope of supply The Siemens Firing Temperature Increase is just one of the many innovative modernization packages available. The scope of this modernization includes:

· Inner casing – new design · Mixing casing modification – horizontal guides · HR3 burners · Upgraded turbine blading materials and coatings.

3.3.2 Compressor Mass Flow Increase Upgrade (CMF+) An output upgrade with a certain increase in efficiency can be achieved by increasing compressor mass flow. As this was not feasible by simply higher loading of the original compressor blading, this was accomplished by redesigning the airfoils of the first four compressor blade rows (including inlet guide vanes!) with new controlled-diffusion-type airfoils (CDAs). The CDAs produce a controlled deceleration in the axial direction. Figure 17 shows the velocity profile on blade#2 and inlet guide vane before and after optimization. The new profile exhibits higher axial velocities with a uniform velocity distribution and thus reduced flow separation compared to the original design. The calculated simple-cycle output gain is approximately 3.5% with an efficiency increase potential of up to 1%. An output increase of up to 2.8% can be anticipated in combined-cycle operation.

Benefits The Compressor Mass Flow Increase upgrade can be a cost-effective means to help improve the overall performance of your gas turbine and combined cycle power plant. Benefits may include:

· Increased gas turbine power output of up to 3% in simple cycle duty · Higher combined cycle power output and lower heat rate due to increased

exhaust mass flow.

The modified airfoil profile is state-of-the-art for new Siemens gas turbines of all V-frames manufactured since July 2005.

Scope of Supply The scope of this upgrade includes:

· State-of-the-art controlled diffusion airfoil profiles · Replacement of the first four rows of blades and vanes · Diaphragm (vane 1) · Inlet guide vane modification · Instrumentation and control modification for surge control.

3.3.3 Dry Low-NOx (DLN) Upgrade Using HR3 Burner Since 1986 Siemens has supplied a hybrid burner for natural-gas dry low-NOx premix firing producing NOx values below 25 ppm and CO values below 9 ppm in the load range from 50% base load to 100% base load. Dry low-NOx fuel oil firing became available in 1993 and since 1995 the HR3 burner design is available and used as the standard equipment in new plants since. Lowered or even eliminated temperature peaks in the combustion zone result in lower NOx emissions. The new diagonal swirlers generate a higher outlet velocity with their optimized flow channel and thus provide maximum flashback resistance. In market we find the following business cases for modernizations using the HR3 fuel gas burner:

· Installed diffusion burner can no longer meet the stricter regulations for emissions of combustion products: this was the market driver for a recent retrofit order for HR3 burners won for a power plant with four V94.2 units in Singapore;

· Hand in hand with a gas conversion, the latest technology represented by the HR3 design: this was the case for a gas conversion carried out at two V94.2 units in Yang Pu/China;

· Retrofitting of existing H burners with HR3 burners to protect against flashbacks resulting from higher hydrocarbons in the fuel gas: a current order for a power plant with six V94.2 units in Egypt was driven by this;

· Compared to the H burner design, further NOx reduction provides benefits in connection with a turbine inlet temperature increase especially for sites in the USA with 9-ppm-NOx requirements.

The latter aspect will now be analyzed more closely. An increase in turbine inlet temperature always involves an increase in NOx emissions. One part of all HR3 burner retrofits is a flame tube upgrade. This is because the increased flow velocity from the

new diagonal swirlers resulted in an increased angle in the flame cone which in turn - compared to the H burner design - shifted the hotter recirculation zone within the silo combustion chamber from the center more towards the upper region of the combustion chamber. This shift is also evident from increased oxidation findings on the metal tile holders in rows A1/A2 detected during inspections after operation with HR3 burners. For H burners comparable findings were already known but less distinctive. A subsequent computational fluid dynamics (CFD) analysis of the new temperature distribution in the silo combustion chambers also verifies that the higher temperatures now occur in the upper region of the combustion chamber. When installing the HR3 burners, the A1/A2 tile rows need to be shifted from the upper position to the center position with lower temperatures.

A gas premix spider-shaped pipe connects the diagonal swirler of each burner to the central pear-shaped gas distributor. Originally welded from a ferritic steel though located in the combustion chamber this part is subject to wet corrosion from the outer surface because of condensing water on the cold fuel gas pipes. To date the ferritic gas spider piping is subject to maintenance activities during hot-gas-path inspection and, depending on the remaining wall thickness, replacement of individual pipes can be necessary. In one case this maintenance work was neglected during the hot-gas-path inspection and caused internal fire damage in the area above the flame tube bottom plates. A redesign has been released to make the gas premix spider maintenance-free over an interval of 123 kEOH using a wet-corrosion-resistant material instead of the original material. This spider upgrade is also a requirement for the 41MAC upgrade. NOx production and emissions depend on the combustion temperature which increases due to a higher turbine inlet hot-gas temperature and increases when the ambient temperature drops. To generate a customer benefit with our turbine inlet temperature increase even in connection with strict environmental requirements, we have developed a special GT NOx control concept. This concept enables adjustment of the turbine inlet hot-gas temperature as a function of ambient temperature for a specified constant NOx limit curve (e.g. 9 ppm). Looking at the low ambient

temperature of -8°C we find an allowable TT1-ISO = 1040°C. With increasing ambient temperatures the turbine inlet temperature can be raised, thus achieving higher power output and better efficiency. Doing so the diagram shows an output gain of 3.6% at 15°C and increases of up to 6.4% at 30°C based on a turbine inlet temperature of 1075°C. All these values are valid for constant NOx emissions of 9 ppm (@15% oxygen in the exhaust). Another relevant parameter is humidity. The operating curves shown here hold for optimized cooling air losses, optimized pilot gas flow and precisely adjusted radial blade clearances. These conditions prevail after a major inspection performed by the OEM Siemens AG. This open-loop control function thus enables adjustment of the entire turbine inlet temperature operating range and hence output and efficiency of the plant based on the specified NOx values. Benefits The HR3 Burner Retrofit modernization can be a highly cost-effective means to help improve the performance, reliability and availability of your gas turbine plant. Benefits may include:

· Extended range of stable combustion fuel gas operation · Protection against flame flash back · Corrosion-free material of fuel gas distribution skid · Decrease of NOx-emissions < 25 ppm (@ 15% O2, dry).

Scope of Supply The Siemens HR3 Burner Retrofit is just one of the many innovative modernization packages available. The scope of this modernization includes new burner assemblies with the following features:

· Improved F-Ring design to avoid overheating · Improved impingement cooled tile holders reduce cooling air consumption by

2% · Tile holder exchange from row A1/A2 to F.

3.3.4 Performance Boost with Wet Compression (WetC) The different locations in a GT application where water can be used for performance improvements are:

· evaporative cooling with water in the air filter house, · fogging makeup water in the air intake · wet compression with makeup water in the air intake · makeup water injection (PAG operation) into the combustor

The following focuses on the particularly effective wet compression upgrade. After Siemens and Westinghouse became one company, they were able to develop wet compression in an R&D program for the V94.2 frames for both the 50-Hz and 60-Hz fleet based on applications and operating experience with Westinghouse W501 engines.

In wet compression, atomized water is injected through a nozzle rack into the compressor air intake. Part of the injected water evaporates in the air intake; the remaining water enters the compressor in liquid form (droplets of approx. 20μm diameter at 90% probability). This achieves an inter-cooling effect. The injected water evaporates in the compressor stages. The energy required for evaporation is taken from the compressed air mass flow, which is thus continuously cooled. This cooling, coupled with the mass flow increase of the working fluid drawn in, results in a significant performance gain in both output and efficiency. In the baseline wet compression the performance gain is independent from ambient conditions. During the development of this upgrade, the design criteria assembled were analyzed and met, and validation tasks for first-time application were defined. For example, we needed to ensure that water injection is homogeneous to prevent casing deformation due to non-uniform temperature fields. The spray pattern in the intake duct was therefore specified in advance on the basis of 3-CFD analyses and temperature field of the casings measured during the validation run.

The amount of water is controlled by a mass flow control loop comprising the injection pump, a variable-frequency drive (VFD) and a controller. In order to maintain a desired mass flow the controller activates the VFD to set the appropriate speed at the pump motor. The pump directly feeds the desired amount of water into the feeding line. Thus an additional return line is no longer necessary. The entire equipment is arranged on the high-pressure wet-compression skid. As for thermodynamic performance a typical increase in the efficiency of the overall gas turbine in an open GT cycle is up to 5%, with an output increase of up to 20%. Before wet compression implementation, the GT was operated with power augmentation (PAG), i.e. water injection in the combustion chamber, achieving an output increase at a NOx limit of 9 ppm and a turbine inlet temperature of 1040°C. When using just the wet compression system without simultaneous power augmentation, the result was an efficiency increase of 6%, compared to an efficiency loss of 5% in the case of water injection into the combustion chamber.

The measured output increase for a relative ambient humidity of approximately 90% was around 13% at 17.5°C ambient temperature. In contrast to wet compression, inlet cooling systems such as evaporative cooling or fogging coolers yield only a negligible increase or no increase whatsoever in output or efficiency under ambient conditions with high humidity or cold temperatures. As for combustion performance at a turbine inlet temperature of 1040°C, NOx

emissions were reduced from 9 ppm to 6 ppm, making it legitimate to conclude that a level of 9 ppm will not be exceeded at a turbine inlet temperature of 1060°C. Any potential corrosion occurring on the compressor blades and vanes can be limited by coating the compressor parts.

The first compressor stages must be monitored for erosion and corrosion during inspections performed at the standard intervals. Vibration measurements of blade row #1 of the first unit will be repeated after a sufficient number of wet compression operating hours and compared to the initial testing in order to evaluate erosion effects on the vibration behavior of the compressor rotor blading. This will be done at the fleet leader in wet compression operation. In addition an R&D program was started this year to provide new corrosion-resistant compressor blade materials and protective measures against erosion in the near future. Experience gathered at a specific Siemens Westinghouse GT W501D5A after some 25,000 operating hours with wet compression demonstrated that GT maintenance follows the standard inspection intervals. As is also the case for the implementation of power augmentation, the water factor must be included in the calculation of equivalent operating hours.

Benefits Wet Compression can be an effective system for recovering power loss experienced at high ambient temperature. The mutual occurrence of peak load electricity demand and high ambient temperature make Wet Compression more beneficial and valuable. Benefits can include:

· Power increase of up to 15% and potentially more depending on the frame and operational requirements *

· Up to 3% gas turbine heat rate improvement * · Higher exhaust energy for increased steam production · Greater operational flexibility.

These benefits can lead to the ability to produce more power in peaking and base load operation. Wet Compression is largely independent of the ambient relative humidity. While somewhat higher performance improvement can be available in a very hot dry climate, Wet Compression can also be very effective at times of high humidity. * Actual results may vary Scope of supply Besides a diligent original equipment manufacturer assessment of the gas turbine and the involved power plant components, the scope of this modernization includes:

· Compressor inlet Wet Compression water distribution system with nozzles · Inlet duct treatment · Wet Compression pump skid · Piping between pump skid and distribution system · Compressor coating (where required by gas turbine frame and version · Compressor upgrade (depending on gas turbine frame and version) · Modification of existing control logic Gas turbine customization (e.g. axial trust

compensation and compressor drains where applicable). Installation and commissioning of Wet Compression can require an outage from one to three weeks depending on plant and gas turbine configuration. 3.3.5 Humidity I&C module for gas turbine control system The turbine can be operated significantly closer to the thermodynamically correct performance point if the humidity in the gas turbine control system is taken into consideration. An I&C module makes this increase in performance possible at a reasonable price. Although humidity has frequently not been measured, it is relevant for calculation of the corrected outlet temperature (ATK). Consequently the gas turbine is often operated under suboptimal conditions, especially at locations with major day/night or seasonal humidity fluctuations. This disturbed performance balance can be significantly improved with the help of the humidity I&C module. The humidity module takes the current humidity into account and automatically uses the plant specific ambient conditions as the basis for thermodynamic control. A sensor continuously records the changing values and transfers them to the control system.

This ensures that the gas turbine comes closer to its design point with less wear on components.

The special benefit of this measure lies in the fast return on investment. The module itself can easily be retrofitted and demonstrates its effectiveness from Day 1. There is a significant increase in performance in the case of changing levels of humidity. 3.3.6 Fuel Conversion Upgrade Siemens offers a Fuel Conversion upgrade designed to enable the plant to use many types and grades of natural gas and liquid fuels.

The Fuel Conversion upgrade is designed to give you operational flexibility to use a range of both gas and liquid fuel, thus enabling you to benefit from different fuels, whether it is the reduced emissions from using a high-grade fuel or the economy of a lower grade fuel. Benefits Depending upon the configuration and interests of the customer, the Fuel Conversion Upgrade offers several important benefits that can include:

· Reduced emissions · Increased output and efficiency due

to removal of firing temperature restrictions

· Improved plant economics by enabling the use of a less expensive fuel

· Being able to utilize many refinery products, such as H2, ethane, propane or LSWR

· Operating flexibility through fuel availability

· Power increase and heat rate improvement.

Outage time and lead time will vary depending on fuel types. Scope of Supply The scope of supply for implementing the Fuel Conversion Upgrade includes:

· Gas turbine interconnect piping and cabling · Packaged fuel measurement and control equipment including high pressure gas

turbine (GT) supply pumps and control valves · Fuel treatment equipment (as required) · Pipe manifolds (as required) · Purge air systems (as required) · Drain system integration · Control system modification · Hydraulic system modification and expansion · Water or steam control equipment (as required) · Combustion system modifications or replacement (as required) · BOP supply or design requirements.

3.3.7 Siemens Innovative 3-Dimensional Turbine Blades & Vanes One of the innovative solutions offered by Siemens Energy to help you improve your operating plant competitiveness and profitability are the Siemens innovative 3-dimensional blades and vanes for the turbine stages.

Siemens innovative 3-dimensional blades and vanes are characterized by an aerodynamic blade and vane design with optimal efficiency as well as ability for retrofitting during service life. This generation of turbine stages blades and vanes has a new, optimized aerodynamic airfoil designed with enhanced material, coatings, an improved cooling air path and a reduction of parasitic losses. Benefits Siemens innovative 3-dimensional turbine blades and vanes can include the following benefits: Turbine stages 1 and 2:

Schematic illustration of Siemens innovative 3-dimensional blades and vanes on turbine stages 1 and 2

· Increased gas turbine power up to 5 MW *)

· Increased gas turbine efficiency up to 0.8%-pts.*)

· Reduced life cycle costs · Compatible with the Siemens 41,000

EOH maintenance concept upgrade. ·

Turbine stages 3 and 4: Installation of Siemens innovative 3-dimensional blades and vanes on turbine stages 3 and 4

· Increased gas turbine power up to 2,5 MW *)

· Increased gas turbine efficiency up to 0.5 %-pts.*)

· Reduced life cycle costs · Compatible with the Siemens 41,000

EOH maintenance concept upgrade. Siemens innovative 3-dimensional blades and

vanes for turbine stages 1 and 2 are state-of-the-art for new Siemens gas turbines of the SGT5-2000E (V94.2). *) Actual results may vary

Scope of Supply Siemens innovative 3-dimensional blades and vanes for the turbine stages modernization include the following new designed profiles and additional turbine parts: Turbine stages 1 and 2:

· Turbine vane 1 (including riffle seals) · Turbine blade 1 · Turbine vane 2 (including riffle seals and U-shaped seal ring segments) · Turbine blade 2 · Cooling air throttle for vane 2

Siemens innovative 3-dimensional blades

· Control optimization of corrected turbine outlet temperature. The upgrade includes execution of the following field work:

· Machining of the turbine vane carrier in vane 2 section inserting the cooling air throttle.

Turbine stages 3 and 4: · Turbine vane 3 (including riffle seals and U-shaped seal ring segments) · Turbine blade 3 · Turbine vane 4 (including riffle seals) · Turbine blade 4.

Siemens innovtive 3-dimensional blades and vanes can potentially be implemented in a row-by-row replacement. A major outage for the installation of this modernization is estimated. We offer a full range of field service capabilities to help you manage your maintenance and outage schedules. 3.3.8 Lifetime Extension Currently, there are two basic maintenance inspection concepts: Minor Inspection (MI) The minor inspection comprises the visual inspection of the accessible regions of the ma-chine, the compressor and turbine inlet, the combustion chamber and the exhaust. Optionally, non-accessible regions may be examined using borescopes. The minor inspection includes the examination of various external gas turbine components. Hot Gas Path Inspection (HGPI) The turbine is opened for the hot gas path inspection. Based on the findings, the vanes and blades of the turbine are inspected, refurbished or replaced based on the maintenance concept. Various non-destructive examinations (NDE) are performed to determine the condition of the essential components. Major Overhaul (MO) At a major overhaul, the compressor casing is removed and all compressor blades are in-spected, as necessary and according to the checklist. The coated compressor front stages are refurbished. The compressor guide vane carrier and the inlet casing are inspected as well. Non-destructive examinations (NDE) and detailed visual inspections are performed, the rotor is removed from the machine. Major components of the Siemens V-frame gas turbines – especially components of the hot gas path and rotor – are designed for a set operational duration. Our experience shows that for gas turbines being operated beyond the components’ original design life, the risk of operational failure can increase substantially.

These measures have been developed based on our knowledge of the original design parameters and our fleet operating experience as original equipment manufacturer. Implementation of the V-frame Lifetime Extension measures can not only help reduce operational risk to your unit, but can also help reduce potential downtime due to unscheduled outages or maintenance activities. Also, power and efficiency, which gradually decline during the first 100,000 equivalent operating hours (EOH) or 3,000 starts, can potentially be restored or even in some cases increased by implementing new technologies developed since the time of installation.

Benefits Benefits may include:

· Detailed unit specific engineering analysis of the operation and maintenance of your gas turbine, taking into consideration the specific characteristics of your gas turbine, such as operating mode and unit history, leads to tailored, cost-optimized Lifetime Extension recommendations.

· Positioning your unit for operation up to another 100,000 EOH or 3,000 starts · Reduction of the operational risk when operating your unit past 100,000 EOH

or 3,000 starts · An opportunity to upgrade previous technology with Siemens improved

components. Scope of Supply The Lifetime Extension outage includes a detailed, unit specific engineering analysis of the operation and maintenance of your gas turbine. We deliver unit specific recommendations through:

· Consideration of unit’s available operational history, duty cycle, findings and component sample investigations (unit specific investigation)

· Fleet operational history and frame specific modeling (frame specific investigation).

The unit specific investigation includes an evaluation of:

· Rotor · Compressor · Turbine

· Combustion section · Burners.

The recommended scope of work to be performed, including modernization and upgrade measures, will be defined with consideration of your long-term operating requirements. 3.4 SGT5-2000E adjustment to site conditions

3.5 Configuration after Modernisation Grid frequency (Hz) 50 Gross power output (MW) 168 Gross efficiency (%) 34.7 Gross heat rate (kJ/kWh) 10,366 Gross heat rate (Btu/kWh) 9,825

Exhaust temperature (°C/°F) 536/998 Exhaust mass flow (kg/s) 531 Exhaust mass flow (lb/s) 1,170 Pressure ratio 11.7 Length x width x height (m)*) 10x12x7.5** Weight (t) 234** * Standard design; ISO ambient conditions ** Dimensions and weight incl. combustion chambers

Bibliography · www.energy.siemens.com · www.ntpcindia.com · www.wikipedia.org · www.ionindia.com/ · www.jica.go.jp · www.emea.donaldson.com · www.bhel.com · www.npti.in · Handbook for cogeneration and combined cycle power plant by Meherwan P.

Boyce · Combined-Cycle Gas & Steam Turbine Power Plants By Rolf Kehlhofer, Bert

Rukes, Frank Hannemann, Franz Stirnimann · Other resources on the world wide web.