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Petroleum Federation of India2

Governing Council

Designation Name/Organisation

Chairman : Mr. B. Ashok

ChairmanIndian Oil Corporation Limited

Vice Chairman : Mr. P. Raghavendran

President (Refinery Business)Reliance Industries Limited

Member : Mr. S.P. Gathoo

Director (HR)Bharat Petroleum Corp. Ltd.

Member : Mr. Sudhir Mathur

Chief Financial Officer

Cairn India Limited

Member : Mr. U. Venkata Ramana

Director (Technical)Chennai Petroleum Corp. Ltd.

Member : Mr. Prabhat Singh

Director (Marketing)GAIL (India) Limited

Member : Mr. Pushp Kumar Joshi

Director (HR)Hindustan Petroleum Corp. Ltd

Member : Mr. H. Kumar

Managing DirectorMangalore Refinery and Petrochemicals Ltd.

Member : Mr. P. Padmanabhan

Managing DirectorNumaligarh Refinery Limited

Member : Mr. S. K. Srivastava

Chairman & Managing DirectorOil India Limited

Member : Mr. T. K. Sengupta

Director (Offshore)Oil & Natural Gas Corp. Ltd.

Honorary Member : Mr. M. A. Pathan

Management Consultant & formerChairman, IndianOil and former ResidentDirector, Tata Group

Honorary Member : Mr. R. S. Butola

former ChairmanIndian Oil Corporation Ltd.

Member Secretary : Mr. A. K. AroraDirector GeneralPetroleum Federation of India

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Petroleum Federation of India 3

Member Organisations

S. No. Organisation CEO

1. Adani Gas Ltd. Mr. Rajeev Sharma

2. Adani Welspun Exploration Ltd. Mr. Arvind Hareendran

3. Axens India Pvt. Limited Mr. Jean Paul Margotin

4. Bharat Petroleum Corp. Ltd. Mr. S. Varadarajan

5. BP Exploration (Alpha) Ltd. Mr. Sashi Mukundan

6. BG Exploration & Production India Ltd. Mr. Shaleen Sharma

7. Bharat Heavy Electricals Ltd. Mr. B. P. Rao

8. Bharat Oman Refineries Limited Mr. R. Ramachandran

9. Cairn India Ltd. Mr. Mayank Ashar

10. Chandigarh University Mr. Satnam Singh Sandhu

11. Chennai Petroleum Corp. Ltd. Mr. Gautam Roy

12. Chemtrols Industries Limited Mr. K. Nandakumar

13. Deloitte Touche Tohmatsu India Pvt. Ltd. Mr. N. Venkatram

14. Dynamic Drilling & Services Pvt. Ltd. Mr. S. M. Malhotra

15. Engineers India Ltd. Mr. Sanjay Gupta

16. Ernst & Young LLP Mr. Rajiv Memani

17. Essar Oil Ltd. Mr. Lalit Kumar Gupta

18. ExxonMobil Gas (India) Pvt. Ltd. Mr. K. S. Kim

19. East India Petroleum Pvt. Ltd. Mr. K. Sharath Choudary

20. Fabtech Projects & Engineers Ltd. Mr. B. A. Rupnar

21. GAIL(India) Ltd. Mr. B. C. Tripathi

22. Great Eastern Energy Corporation Ltd. Mr. Yogendra Kumar Modi

23. GSPC LNG Limited Mr. D. J. Pandian

24. Gujarat State Petroleum Corporation Limited Mr. Atanu Chakraborty

25. Gujarat Power Corporation Ltd. Mr. L. Chuaungo

26. Gulf Publishing Company Mr. John T. Royall

27. Hindustan Petroleum Corp. Ltd. Ms. Nishi Vasudeva

28. HLS Asia Ltd. Mr. Rajeev Grover

29. Honeywell Automation India Ltd. Mr. Vikas Chadha

30. HPCL Mittal Energy Ltd. Mr. Prabh Das

31. Haldor Topsoe India Pvt. Ltd. Mr. Rasmus Breivik

32. IMC Ltd. Mr. A. Mallesh Rao

33. Indian Oil Corp. Ltd. Mr. B. Ashok

34. Indraprastha Gas Ltd. Mr. Narendra Kumar

35. Industrial Development Services Pvt. Ltd. Mr. R. K. Gupta

36. IHS Mr. James Burkhard

37. IOT Infrastructure & Energy Services Limited Mr. Vivek Venkatachalam

38. Jindal Drilling & Industries Limited Mr. Raghav Jindal

39. Jubilant Oil & Gas Pvt. Ltd. Mr. Rakesh Jain40. KEI-RSOS Petroleum & Energy Ltd. Lieutenant J.V. S. S. Murthy

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S. No. Organisation CEO

Mr. M. A. Pathan Management Consultant & former Chairman,IndianOil and former Resident Director, Tata Group

Mr. S. Behuria Group President, Modi Enterprises

Mr. R. S. Butola former Chairman, Indian Oil Corporation Limited

41. KPMG Mr. Richard Rekhy

42. Kellogg Brown & Root Engineering Mr. Subas C. Das

& Construction India Pvt. Ltd.

43. LanzaTech-NZ Limited Dr. Jennifer Holmgren

44. Lanco Infratech Ltd. Mr. L. Madhusudhan Rao

45. Mangalore Refinery and Petrochemicals Ltd. Mr. H. Kumar

46. Mitsui Chemicals India Private Limited Mr. Toshihiro Omura

47. Nagarjuna Oil Corp. Ltd. Mr. S. Ramasundaram

48. Niko Resources Ltd. Mr. Larry Fisher

49. Numaligarh Refinery Ltd. Mr. P. Padmanabhan

50. Oil & Natural Gas Corporation Ltd. Mr. D. K. Sarraf

51. Oil India Ltd. Mr. S. K. Srivastava

52. PCM Chemical India Pvt. Ltd. Mr. Bahrin B. Asmawi

53. Petronet LNG Ltd. Dr. A. K. Balyan

54. PMI Organization Centre Pvt Ltd. Mr. Raj Kalady

55. Praj Industries Limited Mr. Gajanan Nabar

56. PricewaterhouseCoopers Pvt. Ltd. Mr. Deepak Kapoor

57. Prize Petroleum Co. Ltd. Mr. M. K. Surana

58. Punj Lloyd Ltd. Mr. Atul Punj

59. Pandit Deendayal Petroleum University Dr. Anirbid Sircar

60. Reliance Industries Ltd. Mr. Mukesh Ambani

61. Rajiv Gandhi Institute of Petroleum Technology Dr. J. P. Gupta

62. SAP India Pvt. Ltd. Mr. Deb Deep Sengupta

63. SAS Institute (India) Pvt. Ltd. Mr. Sudipta K. Sen

64. Schlumberger Asia Services Limited Mr. S. Ramamurthy

65. Shell India Pvt. Ltd. Dr. Yasmine Hilton

66. Sud-Chemie India Pvt. Ltd. Ms. Arshia A. Lalljee

67. Shiv-Vani Oil & Gas Exploration Services Ltd. Mr. Prem Singhee

68. Tata Petrodyne Ltd. Mr. S. V. Rao

69. Tecnimont ICB Pvt. Ltd. Mr. Mario Ruzza

70. Total Oil India Pvt. Ltd. Mr. B. Vijay Kumar

71. Transocean Offshore International Ventures Ltd. Mr. Krishna Singhania

72. University of Petroleum & Energy Studies (UPES) Dr. S. J. Chopra

73. UOP India Pvt. Ltd. Mr. Steven Gimre

74. VCS Quality Services Private Ltd. Mr. Shaker Vayuvegula

75. World L. P. Gas Association Mr. James Rockall

Honorary Members

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No part of this journal shall be reproduced in whole or in part by any means without permission fromPetroFed.

The views expressed by various authors and the information provided by them are solely from theirsources. The publishers and editors are in no way responsible for these views and may not necessarilysubscribe to these views.

Ms. Marianne Karmarkar Bharat Petroleum Corporation Ltd.

Mr. S. Vaidyanathan Chennai Petroleum Corporation Ltd.

Mr. Jignesh Vasavada GAIL (India) Ltd.

Mr. Rajeev Goel Hindustan Petroleum Corporation Ltd.

Ms. Radhika Ojha IOT Infrastructure & Energy Services Ltd.

Ms. Aarshiya Dhody Indian Oil Corporation Ltd.

Ms. Madhuchanda Adhikari Choudhury Numaligarh Refinery Ltd.

Mr. Debasish Mukherjee Oil & Natural Gas Corporation Ltd.

Dr. Rahul Dasgupta Oil India Ltd.

Mr. Deepak Mahurkar PricewaterhouseCoopers Private Ltd.

Journal Coordinators

Editorial BoardEditor : Y. Sahai

Member : A. K. Arora

S.L. Das

S.S. Ramgarhia

O.P. Thukral

Biren Das

Edited, Designed & Published by:

Petroleum Federation of IndiaPHD House, 3rd Floor, 4/2, Siri Institutional Area, August Kranti Marg, New Delhi-110 016

Phone: 2653 7483, 2653 7062, 2653 7069, Fax: 2696 4840,E-mail: [email protected], Website: www.petrofed.org

Printed by: PRINTEMPS INDIA Ph.: 98101 44481,E-mail: [email protected]

Website: www.printempsindia.com

Designed by: Continental Advertising Services

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Contents

S. No. Topics Page No.

1 From the Chairman 9

2 DG's Report 10

3 Shri K. D. Tripathi is Secretary, MoP&NG 11

4 CEO Speak 12

by Mr. P. Elango, Managing Director, Hindustan Oil Exploration Company

5 Policy Options for Revenue Neutral GST for Petroleum Products and Natural Gas 14

by Prof. Sacchidananda Mukherjee, Associate Professor, National Institute of

Public Finance and Policy and Prof. R. Kavita Rao, Professor,

National Institute of Public Finance and Policy

6 Tax Holiday Relief by Gujarat High Court 18

by Ms. Neetu Vinayek, Oil & Gas Sector Expert; Mr. Hiten Sutar, Oil & Gas Sector Expert and

Mr. Jigar Haria, Oil & Gas Sector Expert

7 Managing in Times of Volatile Oil Prices 21

by Mr. Sunil Bhadu, Partner and Advisory Leader - Oil & Gas, Ernst & Young LLP

8 Water Resources Management for Sustainable Development 26

by Prof. N. Janardhana Raju, School of Environmental Sciences, Jawaharlal Nehru University

9 Role of Analytics in Security of Operation Technologies 29

by Mr. Vinayak Godse, Senior Director, Data Security Council of India (DSCI)

10 OxyMethylene Ethers: Diesel Additives for the Future 31

by Dr. Chanchal Samanta, Manager (R&D), BPCL; Dr. Ankur Bordoloi,

Scientist, IIP Dehradun; Dr. R. K. Voolapalli, Chief Manager (R&D), BPCL;

Dr. Jim Patel Scientist, CSIRO, Australia

11 Offshore Renewables 40

by Capt. D. C. Sekhar, Managing Director, AlphaMERS Private Limited

12 Job Hazard Analysis & Escalation Matrix 42

by Mr. V. V. R. Narasimhan, Head-Corp. HSE, Hindustan Petroleum Corp. Ltd.

13 Improving Corrosion Assessment and Monitoring 46

by Mr. Ulhas Deshpande, Business Leader, Advanced Solutions, Honeywell Process

Solutions and Mr. Jaideep Bhattacharya, Consultant, Advanced Solutions, Honeywell

Process Solutions

14 Pre Reformer Catalyst for Hydrogen Plant 48

by Mr. Sanjeev Mehta, General Manager - BU Syngas Catalysts,

Sud-Chemie India Pvt. Ltd. and Mr. Chetan Bhola, Assistant Manager - BU Refinery Catalysts,

Sud-Chemie India Private Limited

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Contents

15 Optimisation of Visbreaker Unit 51

by Mr. Debasis Bhattacharyya, Dy. General Manager (RT-I), IndianOil (R&D Centre);Mr. Satheesh V. K., Sr. Research Manager, IndianOil (R&D Centre); Mr. B. V. Hariprasad Gupta,

Research Manager, IndianOil (R&D Centre) and Mr. G. Saidulu, Research Manager,

IndianOil (R&D Centre)

16 Compressor Anti Surge System Trouble Shooting 57

by Mr. Mukesh K. Shivhare, Engineer, EIL; Mr. Shailendra Kumar,

Dy. Manager, EIL: Ms. R. V. Sreevidya, Dy. Manager, EIL; Mr. P. Narendra Kumar,

Dy. Manager, EIL and Mr. S. R. Singh, Dy. General Manager, EIL (R&D Centre)

17 Oxygen Enrichment for Air Oxidations in Chemical Industries: Overcoming Limitations 63

by Mr. Bernhard Schreiner, PhD, Senior Expert Chemical Process, Linde AG; Mr. Diganata Sarma,Head of Applications & Market Development, South Asia and ASEAN, Linde Gas Asia Pte. Limited

and Mr. Yogesh Desai, Manager-Application Sales (Chemical & Environmental), Linde India Limited

18 10 ppm Sulfur Gasoline Opportunity Analysis 70

by Ms. Delphine Largeteau, Senior Technologist-Mktg. Associate, Axens; Mr. Jay Ross,

Senior Technology and Mktg. Manager, Axens and Mr. Larry Wisdom, Mktg. Executive,

Heavy Oils, Axens

19 Make in India: Successful Indigenous TGTU 75

by Mr. Kaushik Ghosh Mazumdar, Deputy Manager (R&D), EIL; Mr. D. K. Sarkar,

Deputy General Manager (R&D), EIL and Ms. Vartika Shukla, General Manager (R&D), EIL

20 Overcoming Barriers to Entry into Petrochemical Markets 79

by Mr. Matthew Lippmann, UOP LLC, a Honeywell Company and

Mr. Soumendra Banerjee, UOP IPL, a Honeywell Company

21 DeNOx Technology For Refiners For a Green Footprint 86

by Mr. Sachin Panwar, Business Development Manager, Haldor Topsoe India Pvt. Ltd.

and Mr. Raman Sondhi, Vice President, Haldo Topsoe International A/S

22 Olefins Technology Options to Meet Uncertain Market Conditions 92

by Mr. Sagar Nawander, Associate Technical Professional, KBR Technology;

Mr. Sourabh Mukherjee, Chief Technical Leader, KBR Technology andMs. Tanya Aggarwal, Associate Technical Professional, KBR Technology

23 Trickle Bed and Slurry Bed Reactors in Refining Industry 96

by Ms. Megha Aggarwal, Sr. Engineer (R&D), EIL; Mr. Vijay Yalaga, Dy. Manager (R&D),

EIL; Dr. R. N. Maiti, Dy. General Manager (R&D), EIL and Ms. Vartika Shukla,

General Manager (R&D), EIL

24 Members' News in Pictures 104

25 Events 111

S. No. Topics Page No.

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From the Chairman

For the first time, India is leading the growth

chart of major economies in the World Bank's

mid-year Global Economic Prospects report.

The World Bank has projected a growth of 7.5% this

year for the country with new reforms improving

business and investor confidence, and attracting

new capital inflows. The Vice-Chairman of the NITI

Aayog expects the growth rate to accelerate to 8%

in the current fiscal with the economy surpassingUS$ 3 Trillion in less than five years.

Global growth, however, is expected to be 2.8% in

2015, which is lower than anticipated in January this

year. It is likely to expand by 3.3% in 2016 and 3.2%

in 2017, broadly in line with the Bank's previous

forecasts. Developing countries are projected to

grow by 4.4% this year, 5.2% in 2016 and 5.4% in

2017. High-income countries are projected to growby 2.0% this year, 2.4% in 2016 and 2.2% in 2017.

According to the World Bank, lower prices of oil and

other strategic commodities have intensified the

slowdown in developing countries, many of which

are heavily dependent on commodity exports. While

commodity importers are benefiting from lower

inflation, fiscal spending pressures and import costs,

low oil prices have so far been slow to spur moreeconomic activity because many countries face

persistent shortage of electricity, transport, irrigation

and other key infrastructure services; and severe

flooding and drought caused by adverse climate.

Looking ahead, says the World Bank, the growing

importance of unconventional oil production and

technological innovation could help keep oil prices

low with substantial volatility around a new

equilibrium level.B. Ashok

Chairman

The prospects of the price of oil remaining low for a

considerable period of time bodes well for India,

which is on a new cusp of growth and a big economic

leap. In the oil & gas sector, during the past one

year, the Government has brought in a new gas

pricing formula, deregulation of diesel prices, anddirect transfer of subsidy on domestic LPG into the

bank accounts of consumers. There is also work-in-

progress on several issues in other areas such as

oil exploration & production, setting up of a national

gas grid, and development of city gas distribution

networks.

The Government's aim of a double-digit growth will

be substantially aided by the economic reforms inthe offing, particularly a comprehensive Goods &

Services Tax. According to leading economists, the

maximum benefit of GST can be derived by not

leaving out any goods or services from its ambit.

This is particularly relevant for the oil & gas sector,

which impacts a wide range of economic activities.

Non-inclusion of any group of petroleum products

would result in cascading of taxes in several sectors.

The industry is hopeful that GST, on introduction, will

comprehensively cover all goods and services,

including petroleum products.

With such reforms in the offing, we can all look

forward to accelerated economic growth.

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Asian countries are making a vital contribution

to achieving global sustainable energy goals,

according to a new World Bank report titled

Progress towards Sustainable Energy: Global

Tracking Framework 2015. Asia accounted for about

60% of the global progress on energy access and

clean energy objectives during 2010-12, says the

report, contributing well beyond its share of global

population and energy consumption. The report

highlights that, among other issues, India,

Philippines and Bangladesh were the strongestperformers on electricity front and added about four

percentage points to electricity access rates. Asia's

progress, however, on reducing the energy intensity

of its economies with a compound annual growth

rate of 1.3% annually - a commonly used measure

of energy efficiency - lagged behind the global

average of 1.7%. On expanding modern renewable

energy, from sources like solar, wind and

geothermal, Asia's performance was particularly

strong. Whereas globally, consumption of modern

renewable energy grew by 4% per annum during

2010-12, in Asia that growth was almost twice as

fast at close to 8%.

Developing countries have poured in bulk

investments of USD 63 billion for solar technologies

and USD 58 billion for wind technologies - matching

figures of investment by developed nations, says

the renewables 2015 Global Status Report, released

during the recent Asia Clean Energy Forum 2015 at

Manila. Between 2013 and 2014 nearly half of the

total USD 270 billion global investments on

renewable energy were from developing countries,

according to data from the UN Environment

Programme.

In developing Asia, two countries figured in the

global top 10 list of countries generating the most

number of jobs in the renewable energy sector: India,

with 437,000 jobs and Bangladesh, with 129,000

jobs, noted the report issued by the Renewable

Energy Policy Network for the 21st century.

Climate change, however continues to be a matter

of concern and a peak in global energy - related

DG’s Report

A. K. Arora

Director General

emissions could be achieved as early as 2020 and

at no net economic cost, according to the

International Energy Agency's new World Energy

Outlook Special Report on Energy and Climate

Change. Increasing energy efficiency in the industry,

buildings and transport sectors; reducing use of the

least efficient coal fired power plants; increasinginvestment in renewable energy technologies in the

power sector from USD 270 billion in 2014 to USD

400 billion in 2030; reducing methane emissions in

oil & gas production; and gradual phasing out of

fossil fuel subsidies to end-users by 2030 are some

of the IEA recommendations for achieving a peak in

global energy released emissions as early as 2020.

The last recommendation needs careful

consideration since the cost of energy subsidies in

2015, according to a recent IMF Working Paper, is

USD 5.3 trillion or 6.5% of global GDP. Earlier work

by IMF also shows that these subsidies have

adverse effects on economic efficiency, growth and

inequality. Emerging Asia accounts for about half

of the total energy subsidies, while advanced

economies account for about a quarter. The largest

subsidies in absolute terms, are in China (USD 2.3

trillion); United States (USD 699 billion); Russia (USD

335 billion); India (USD 277 billion), and Japan (USD

157 billion). The subsidies for the European Union

at USD 330 billion are also substantial.India has already made significant headway in

reducing energy subsidies by making diesel prices

market determined and direct benefit transfer for

domestic LPG cylinders. Measures are underway

to tackle the subsidies on PDS kerosene and further

rationalize subsidy on domestic LPG cylinders.

The determined actions by the Government in this

regard are bound to bear fruit.

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Shri Kapil Dev Tripathi is Secretary to the Government of India in the

Ministry of Petroleum & Natural Gas. He took charge in June, 2015 on the

superannuation of Shri Saurabh Chandra.

A 1980 batch Assam-Meghalaya cadre officer of the Indian Administrative Service

(IAS), Shri Tripathi was earlier Secretary, Department of Public Enterprises. With

35 years' experience in Public Administration he has held important positions in the

Government of India in various Ministries/Departments like Rural Development; Steel

& Mines; Tourism; Chemicals, Petrochemicals and Pharmaceuticals; Public Enterprises,

etc. He also served as Secretary in the Central Vigilance Commission, which is the

premier Integrity Institution of the country.

Shri Tripathi is a post graduate in Physics from the University of Allahabad and did his

Masters in Business Administration in 1994 from the University of Ljubljana, Slovenia.

While posted in the North Eastern State of Assam, he served in different capacities in

Departments of Agriculture, Fisheries, Rural Development, Personnel and General

Administration, Home & Political, Industries, etc. In addition, in the Sub Division and

Districts, he functioned as Assistant Commissioner, Sub Divisional Officer, Project

Director of District Rural Development Agency and Deputy Commissioner.

Shri K. D. Tripathi is Secretary, MoP&NG

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CEO Speak

Transforming Through Technology

P. ElangoManaging Director

Hindustan Oil Exploration Company

When we reflect on the history of oil and

gas industry, it is clear that every major

growth in production is triggered by

breakthroughs achieved in either Discovery or

Recovery technologies. Whether it's rotary drilling

and reflection seismology of the 1940', to

development of 3D seismic in 1980's, to the fusion

of fracking with horizontal drilling that exploded in

shale revolution, technology has been the sole driver

for global oil production to grow from 5 million BOPD

in the 1940's to close to 90 million BOPD now.

Despite this, do we as a country, sector, company

or as individuals holding leadership responsibilities

pay the required attention to technology and its

adoption. The answer, to my mind is No. I am not

going to get into why we don't do it and but would

rather focus on what would happen if we do it.

In the context of India, where over 75% basins are

yet to be fully and thoroughly explored, where ~

130 billion barrels of resources fall in " yet -to - find "

category, where one third of basins are yet to be

explored by any one and where 96% discovered

resources are from just 6 of the 26 basins,

deployment of technology holds the key to unlock

the hydrocarbon potential.

Specifically, the statistics on Mesozoic rocks tell a

compelling story. While all over the world around

54% of world oil production and 44% of world gas

production is contributed by Mesozoic rocks, its

contribution in India is negligible, despite being

home to 400,000 square kilometers Mesozoic basin

area.

I often relate oil and exploration to search for sighting

a tiger. Both need passion, patience and

perseverance. And just because you saw pug marks

does not mean you will be lucky enough to sight the

tiger. It looks like our early explorers for oil went after

pug marks that were more prominent that led themto discover oil and gas in Assam, Cambay, Mumbai

High, Cauvery and KG basins, and these are mostly

from younger and shallower rocks. In that trail all

the Mesozoic pug marks seem to have been left

behind. It's time to retrace the path and take a

re-look at them with the benefit of advances in

technology. This should be done, and I would add,

on a mission mode.

The other insightful statistic is that if the global

average oil and gas recovery can be increased from

its current level of around 35% by one percent, the

increased production is sufficient to meet the global

oil demand for over one year. And increasing the

average recovery factor from 35 to 50% (which

prudently managed fields around the world are able

to deliver with application of recovery technology)

would add a whopping 1 trillion barrels to provenreserves. Such is the power of Enhanced Oil

Recovery (EOR) technology, and India still lags

behind in embracing it widely. Its heartening to note

that, both in Barmer and Cambay basins, Cairn and

ONGC have taken the lead to implement EOR in

their respective basins.

Similar to its independent foray in the world of space

technology, India was forced to develop its maiden

offshore oil and gas discovery on its own, without

partnership with any International Oil Company. The

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engineering talent of ONGC took up the challenge

head on and developed the Mumbai High field to

world class standards. Similarly, a large oil and gas

field with a billion barrel recoverable resource (valued

over $ 100 billion) was developed in a desert region

and a deep water gas development was executedin a record discovery-to-delivery-time by the private

sector players. India is also home to the world's

longest heated crude oil pipeline system of 600 km

length that generates 32mw of power to continuously

heat and keep the waxy & high pour point crude

flowing in the pipeline.

In the sub-surface front, advanced spectral

decomposition technology (SDT) has been usedsuccessfully in a shallow water offshore filed, whose

main reservoirs middle miocene are overlaid by thin

late miocene reservoirs. These are thin and isolated

reservoirs that are difficult to map using conventional

techniques. SDT enabled computation of attributes

at different frequencies and used 3D visualisation

environment to highlight the thin channels which

were subsequently drilled to achieve incremental

production.

4D seismic is an advanced method of acquiring,

processing and interpreting repeated 3D seismic

surveys at different time stamps. 4D technology

brings fourth dimension (time) for identifying areas

of bypassed oil reserves. A 4D OBC seismic survey

was executed for the first time in India, targeting by

passed oil. This enabled Ravva oil and gas field to

achieve a recovery rate more than 50%, while theaverage for other fields in India is less than 35%.

Despite a successful 4D seismic survey in one field,

3D seismic surveys have so far been conducted only

in 15% of the total area. This indicates the scope of

opportunity to deploy such discovery technologies

in India.

All over the world, the advances in Big Data Analytics

powered by developments in Artificial Intelligence

are leading to the construction of smart wells, and

digital oil fields on a scale that our industry has never

seen before, and these are setting new bench marks

in recovery rates. Today, High Performance

Computing is aiding Geologists and Petroleum

Engineers around the world to play their game of

poker with nature from a position of strength. A Terabyte of data is being processed from a single well

on a single day!

But where are we as a Nation, Sector, Company and

Individual.

In the corporate world, for anything to happen,

everything has to begin at the top. When CEO's

make strong commitment and walk the talk on

Safety, a culture of safety gets nurtured in an

organization. And the Indian oil and gas industry has

seen significant progress in companies adopting

safe practices in their operations and improving their

track record on safety. A similar awareness about

the significance of technology and the potential it

holds to change the fortunes of companies, sector

and our country needs to be created. I firmly believe

only technology can transform our sector and ourcountry.

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Policy Options for RevenueNeutral GST for Oil & Gas

Prof. R. Kavita RaoProfessor

National Institute of Public Finance and Policy

Prof. Sacchidananda Mukherjee Associate ProfessorNational Institute of Public Finance and Policy

India is working towards the introduction of a

comprehensive Goods and Services Tax (GST)

regime covering both the Centre and the States.

The rationale for this proposed reform is twofold:one, to expand the tax base available for taxation

for each level of government, and two, to reduce

cascading prevalent within the economy. The

proposed design for GST however keeps crude

petroleum, natural gas, and some petroleum

products outside the purview of GST (The

Constitution (One Hundred and Twenty-Second

Amendment) Bill, 2014) in the initial stage. Mukherjee

and Rao (2015) explore some alternative designs

for GST, within the constraints with which

governments work, i.e., reducing cascading,

keeping prices in check and maintaining revenues.

1. The study suggests alternative design of GSTwhere tax cascading goes down and prices falland the Government revenue remainsunchanged.

2. Substantial reduction in cascading of taxes is

observed for a shift from baseline to alternativescenarios and tax system becomes cleaner.

3. Elimination of cascading of taxes will result inrising export competitiveness of Indianindustries in the international markets.

4. In all alternative designs of GST, the pricesacross the sectors either remain unchanged ordecline

5. Dismantl ing the administered pricing

mechanism for petrol and diesel along withintroduction of comprehensive GST forpetroleum products benefits both upstream anddownstream sectors.

6. Non availability or partial availability of input taxcredit will result in stranded costs for somesectors (where direct use of out of GST itemsare high) but the costs will be spread across allsectors of the economy, through sectoral inter-linkages.

If crude petroleum, natural gas, petrol, diesel, and

aviation turbine fuel are kept out of GST, it would

result in cascading. Since, petroleum products play

an important role in India's energy use, and are useddirectly and/or indirectly as inputs in most sectors,

the proposed design would result in cascading in

sectors of the economy. The study captures the

degree of cascading across 48 sectors under

different scenarios and explores alternative policy

options to phase out under-recoveries of oil market

companies on account of sales of diesel and petrol

under the administered pricing mechanism.

However, bringing these goods into the GST regime,

without any other changes in the economy, would

imply that GST has to be levied at higher rates for

revenues to be protected.1 Introducing GST at higher

rates would make the reform more difficult to

implement. The solution for this knot lies in making

reforms of pricing of petroleum products

coterminous with introduction of GST reforms.

1The provision of subsidy (or administered pricing) reduces prices of petroleum products and at lower prices a higher tax rate is required to meet a certain revenue target. Subsidy adjusted tax rate on petroleum products is expected to be lower than the nominal tax rate and the study takes into account thisdivergence by suitably adjusting the tax rate.

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In India, crude petroleum is predominantly imported,

where imports constitute about 81 per cent of total

availability. In the absence of price control, it is

expected that volatility in international crude oil prices

as well as in exchange rate would put pressure on

domestic prices of refined petroleum products. Toprotect end users from high and fluctuating prices,

the government implements some price control

measures - the present pricing regime does not allow

full and instantaneous price pass through for a few

petroleum products (PDS kerosene, domestic LPG,

diesel and petrol). This results in under-recoveries

for oil marketing companies (OMCs).2 The

government has not been providing compensation

to OMCs for such under-recoveries in sales of diesel

and petrol.

Given that the country is working towards the

introduction of a comprehensive GST regime,

Mukherjee and Rao (2015) explore alternative

configuration of the tax regime, with specific

reference to petroleum products and evaluate the

extent of cascading under each of these. The study

also explores the configuration of revenues and

prices resultant from alternative tax/ subsidy regimes

to understand whether elimination of price control

in addition to streamlining the tax regime could be

feasible, given the multiple objectives of reducing

cascading, keeping a check on prices and

protecting revenues.

Alternative Designs of GST

The paper shows that with the proposed regime of

taxation for petroleum products and natural gas in

the GST, there will be cascading across sectors; with

the degree of cascading varying across the sectors

depending on direct and indirect uses of these out

of GST inputs. The extent of cascading is non-

negligible: some sectors with considerable export

presence are shown to be facing tax cascading of

over 2 percent of value of output which could be

detrimental for competitiveness in international

market. Sectors having substantial presence in

India's export as well as facing tax cascading are -

metallic minerals, textiles (including apparels),

rubber and plastic products, petroleum products,

chemicals, ferrous and non-ferrous basic metals,

metal products (excluding machinery), machinery

and machine tools (including tractors & agri.

implements), electronic and communication

equipments, all transport equipments (excluding

motor vehicles other than 2 wheelers).

The study presents some alternative designs of

taxation, without compromising on revenue

considerations of government. For comparing the

alternative scenarios, it is assumed government gets

the same total tax incidence as in the baseline

scenario.3 The tax rate on one or more commodities

is adjusted to ensure revenue neutrality. Here it

should be noted that revenues under all alternative

scenarios are derived under the assumptions that

all economic activity in a taxed sector will be subject

to tax, i.e., there are no turnover based exemptions

and there is full compliance. While these are strong

assumptions, the Input-Output framework adopted

for the study does not allow for further calibration to

incorporate these structural features of the tax

system. Further, this framework does not permit

calculation of revenues for Central Government and

State Governments separately.

The study considers proposed GST design as the

baseline. Since the revenue streams from the

proposed GST regime are not yet known, authors

estimate total revenues that could be derived from

the economy provided all economic activity is

subject to tax.

2

Gradual increase in price of diesel, allowing full price pass through of petrol (since 26 June 2010) and continuous fall in crude oil prices in international market, helped government to wipe out under recoveries of OMCs on account of sales in petrol as well as diesel (since 19 October 2014). Unlike petrol, policy option for diesel subsidy is still open.

3Total Tax Incidence = Direct Tax Incidence + Tax Cascading

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Baseline and alternative policy scenarios are as

follows:

Baseline Scenario (Proposed Design of GST):

Natural Gas, Crude Petroleum and Petroleum

Products are out of GST. Goods as well as services

sectors attract harmonized tax rate of 20 percent

and there are some exempted goods and services.

Partial input tax credit (ITC) is available for petroleum

product sector and for other sectors which use

petroleum products and are under GST regime.

There are under-recoveries of OMCs on account of

sales of diesel and petrol below the desired market

prices and the Government provides full

compensation.

Scenario 1 - Proposed Design of GST with no

under-recoveries in petroleum sector: The tax

structure remains same as baseline. However, it is

assumed that OMCs charge the desired market

price and there are no under-recoveries on account

of sales in diesel and petrol. In other words, in this

scenario government allows full price pass through

for diesel and petrol.

Scenario 2 - GST covering petroleum refineries

with subsidy in place: In this scenario, natural gas,

crude petroleum and petroleum products are

brought under the GST system. This would mean

that both for natural gas and crude petroleum, the

taxes on inputs would be set off and similarly other

sectors will get full ITC for purchase of natural gas

and crude petroleum as inputs. Further, for refineries,

there will be full ITC available. Full ITC for purchase

of petroleum products as inputs by other activities

however is not allowed. Goods as well as services

sectors attract harmonized standard GST rate of 20

percent (including natural gas and crude petroleum)

and there are some exempted goods and services.

Petroleum products attract a differential tax rate

(higher than the standard GST rate). Compensation

on account of under-recoveries of OMCs is providedby the Government.

Scenario 3 - GST for Petroleum Refineries without

petroleum subsidy: The conditions of this scenario

remain same as Scenario 2, except that there is no

under-recovery of OMCs on account of sales in

diesel and petrol. The present input tax credit (ITC)

rules for use of refinery products continues.

Scenario 4 - GST for Petroleum Refineries with

Additional Regulatory Levy on Petroleum

Products without Petroleum Subsidy: This is an

extension of Scenario 3, except that full ITC is allowed

up to standard GST rate for purchase of petroleum

products as inputs. In other words, the tax on

petroleum products is assumed to have two

components, a GST and a non-rebatable levy. Inthis scenario, the non-rebatable levy is calibrated to

satisfy revenue neutrality.

Scenario 5 - Comprehensive GST with uniform

rates of tax and with no petroleum subsidy: The

conditions of this scenario are similar to Scenario 3,

except that full ITC is allowed for purchase of

petroleum products as inputs for sectors subject to

GST. In this scenario, instead of a special tax on

petroleum products we estimate a standard GST

rate that will maintain revenue neutrality of the

governments.

The Revenue Neutral Rates (RNRs) for the alternative

scenarios are the rates which yield the same

computed revenues as the baseline scenario for the

study, i.e., the revenue subsequent to introduction

of proposed GST. It should be noted that these would

correspond to the total revenues for Centre and

States put together, but would not incorporate the

effects of specific features such as exemptions,

thresholds, differential tax rates, and less than full

compliance etc. In all of the policy options explored

in the study, the estimated RNR is within the realm

of reasonable and feasible, especially when

compared to the present rates of tax which are

considered as the benchmark (Table 1).

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Subsidy Scenario Natural Crude Petroleum Electricity Tax exempted Other

Gas (%) Petroleum (%) Products* (%) (%) Goods Goods &

& Services(%) Services (%)

With Baseline 17.00 2.00 40.00 5.00 0.00 20.00

Subsidy Scenario

Scenario 2 20.00 20.00 48.00 (RNR) 10.00 0.00 20.00

Without Scenario 1 17.00 2.00 29.00 (RNR) 5.00 0.00 20.00

Subsidy

Scenario 3 20.00 20.00 36.00 (RNR) 10.00 0.00 20.00

Scenario 4 20.00 20.00 47.00 (RNR) 10.00 0.00 20.00

Scenario 5 23.00 23.00 (RNR) 23.00 (RNR) 10.00 0.00 23.00 (RNR)

(RNR)

Notes: *-Petroleum Products includes Motor Spirit (also known as Gasoline/ Petrol), High Speed Diesel and Aviation Turbine Fuel and all other Petroleum Products. Separate Revenue Neutral Tax Rates are not calculated for the following two baskets - a) MS, HSD& ATF and b) other petroleum products. Input tax credit availed by refineries are taken into consideration in this analysis.

Source: Mukherjee and Rao (2015)

Table 1: Alternative Scenarios and Revenue Neutral Rates

The study suggests two alternative designs of GST

(Scenario 3 and 4) where there is no price regulation

for petrol and diesel, and petroleum products,

including natural gas, crude petroleum and electricity

are brought under the GST. In scenario 3, the presentinput tax credit (ITC) rules for use of refinery products

continues, and in scenario 4, on these products, full

ITC upto standard GST rate is allowed, beyond which

it attracts a non-rebatable levy.

The results also show that in all the alternatives

considered, the prices across the sectors either

remain unchanged or decline (except for tax

exempted sectors). In one of the scenarios, the

announced rate of tax on petroleum products is even

lower than the rates considered in the baseline

scenario (Scenario 3). These results suggest that

there is little ground for separating out petroleum

products for special treatment by keeping them out

of the base for GST. GST reforms implemented

alongside decontrolling product prices would

provide an interesting opportunity to reform without

worries about price rise.

References

Mukherjee, Sacchidananda and R. Kavita Rao (2015), "Policy options for including petroleum, natural gas and electricityin the Goods and Services Tax", Economic and Political Weekly, Vol. 50, No. 9, pp. 98-107 (28 February 2015).

The Constitution (One Hundred and Twenty-Second Amendment) Bill, 2014, Bill No. Bill No. 192-C of 2014, As Passedby Lok Sabha on 6-5-2015. Available at: http://www.prsindia.org/uploads/media/Constitution%2012

2nd /Constitution%20(122)%20as%20passed%20by%20LS.pdf

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Neetu VinayekOil & Gas Sector Expert

Hiten SutarOil & Gas Sector Expert

Tax Holiday Relief by Gujarat High Court

Jigar HariaOil & Gas Sector Expert

1Niko Resources Limited vs Union of India [ 2015 ] 55 taxmann.com 455 (Guj)

This tax holiday benefit was extended by the Finance

Act (No.2), 2009 to the undertakings engaged incommercial production of natural gas in blocks

licenced under the VII round of bidding under NELP

and under IV round of bidding for award of

exploration contracts for Coal Bed Methane blocks,

if these undertakings began commercial production

on or after 1 April 2009.

Further, an explanation was added to Section 80IB(9)

of the Act by the Finance (No. 2) Act, 2009 statingthat all blocks licensed under a single contract, which

have been awarded under the NELP or in any other

prescribed manner, shall be treated as a single

'undertaking' for claiming tax holiday.

Controversy and the Decision of

the High Court

Whether the term 'mineral oil' includes 'natural

gas'

The taxpayers producing natural gas claimed a tax

holiday by treating the production of natural gas as

production of 'mineral oil'. It was contended by the

taxpayer that the Production Sharing Contracts

('PSCs') entered into by the Government of India

provide for benefit under Section 80IB(9) of the Act

for the production and refinement of petroleum.

Recently, the Gujarat High Court1 dealt with

important issues in connection with taxholiday claimed by the exploration and

production companies in the oil and gas sector

under Section 80IB(9) of the Income-Tax Act, 1961

('the Act') and has provided major relief to these

companies. The High Court has provided much

needed clarity on the long disputed matters relating

to the interpretation of the term 'mineral oil' and effect

of the retrospective amendment brought by the

Finance Act (No. 2), 2009 relating to the meaning ofan undertaking.

Before we discuss the decision and its implications,

it will be relevant to summarise provisions of Section

80IB(9) of the Act.

Provisions of Section 80IB(9) and

amendments brought by the

Finance (No.2) Act, 2009

As per Section 80IB(9) of the Act, an undertaking of

a company can claim a tax holiday in respect of

production of mineral oil in India for a period of seven

consecutive years if it has commenced commercial

production of mineral oil, on or after 1 April 1997.

The term 'mineral oil' has not been defined in this

Section. The taxpayers were claiming tax holiday

benefits on production of crude oil and natural gas.

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2 Association of Natural Gas and others vs Union of India and others, (2004) 4 SCC 4893 Textile Machinery Corporation Limited vs Commissioner of Income Tax (1997) 2 SCC 368

Petroleum has been defined to mean 'crude oil'

including 'natural gas', under the PSC. Therefore,

the intent of the government is to provide a tax

holiday under Section 80IB(9) of the Act to every

entity with which it enters into a PSC, irrespective of

the fact whether it produces 'mineral oil' or 'naturalgas' or both.

However, the tax authorities took a view that the term

'mineral oil' referred in Section 80IB(9) of the Act does

not include natural gas and denied the taxpayers

claim for a tax holiday under Section 80IB(9) of the

Act. The author ities contended that whenever

legislature decided to include 'natural gas' within the

meaning of a Section, it has done so explicitly (fore.g. under Section 42 and 293 of the Act) and by

not defining the term mineral oil under Section

80IB(9), the legislature has not intended to give this

benefit to the production of natural gas.

Decision of the High Court

The High Court, relying on the Supreme Court2, held

that in absence of any specific definition of mineral

oil, any reference to mineral oil in its natural,

commercial and technical sense will include

petroleum products and natural gas. The High Court

also placed reliance on the allied enactments

passed by the Parliament where natural gas is

considered as mineral oil. It was observed that when

one deals with the provisions of the PSC or any

taxing statue, mineral oil is the genus and contains

within its ambit petroleum products and natural gasas its species.

Whether each well or cluster of oilwells will constitute a separate

undertaking for claiming tax benefit

Taxpayers engaged in the business of prospecting

for, exploration and production of mineral oil in India,

enter into a PSC with the Government of India to

develop specified oilfields. The taxpayers based on

the PSC developed a well or cluster of wells over a

period of the contract and claimed tax holiday under

Section 80IB(9) of the Act by treating each well or

clusters of well as a separate undertaking.

Subsequently, an explanation was introduced vide

Finance (No. 2) Act, 2009 stating that all blocks

licenced under a single contract, shall be treated as

a single 'undertaking' and hence the tax authorities

were denying the claim of the taxpayer based on

this explanation which was entered retrospectively.

Decision of the High Court

The High Court relied on the decision of the Supreme

Court 3 for interpreting the definition of the term

'undertaking' and held that commercial production

of mineral oil is carried out from each development

field consisting of a well or cluster of wells thereby

making each field an independent economic unit,

hence is a separate 'undertaking'.

Whether the explanation introduced with

retrospective effect stating that all blocks licenced

under a single contract, shall be treated as a single

'undertaking' is unconstitutional and ultra vires

The High Court observed that the right given to the

taxpayer for claiming 100per cent tax holiday for

seven years was an accrued and vested right and

the said vested right could not have been taken away

expressly or by necessary implication. A person

cannot be derived of the vested right without

following the rule of law. In the case of the taxpayer,

the claim of tax holiday was allowed considering

each well as a separate undertaking by the Income

Tax Tribunal (in the taxpayers own case), and hence

the vested right to claim the tax holiday arose .

Further, it was held that though the legislature is

entitled to depart from the meaning and can define,

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and gas sector. The ruling has brought clarity with

respect to the dispute over claiming a tax holiday

under Section 80IB(9) of the Act for companies

engaged in the business of production of natural

gas.

Further, it has struck down the explanation to the

Section wherein the term undertaking was defined

to include each well within the development field as

single undertaking. Thus, the exploration and

production companies who obtained contracts

before 31 March 2011 can explore the possibility of

claiming a tax holiday on the new wells or cluster of

wells.

Considering the recent outlook of the government

for reducing litigation and getting stability with

respect to tax issues, one will have to wait and watch

to see whether the Tax Department files an appeal

before the Supreme Court against the Gujarat High

Court order.

(The information contained herein is of a general nature and is not intended to address the specific circumstancesof any particular individual or entity. The views and opinionsexpressed herein are those of the authors.)

it has to follow the known process which is approved

by law. The explanation introduced has departed

from the settled interpretation given by various courts

to the term 'undertaking' and is sought to be clarifying

an existing ambiguity. The High Court held that there

is no ambiguity or doubt which needed to beexplained by this explanation. Settled meaning

needs to be altered only through the process of

validation and not through insertion of an explanation

which is not in the nature of validation.

In view of the above, the High Court concluded that

the amendment made in Section 80IB(9) of the Act

by adding an explanation was not clarificatory, but it

takes away the accrued and vested right of thetaxpayer which had matured after the order of the

Income Tax Tribunal and therefore, the explanation

was a substantive law.

The High Court held that this explanation is

unconstitutional and is ultra vires to Article 14 of the

Constitution of India and is liable to be struck down.

Conclusion

The ruling of the Gujarat High Court has given

substantial relief to a company operating in the oil

Do not dwell in the past, do not dream of the future,

concentrate the mind on the present moment.“ “

~Buddha

Very little is needed to make a happy life; it is all within yourself,

in your way of thinking.“ “

~Marcus Aurelius

7/21/2019 Apr June15 (1)



Managing in Times of Volatile Oil Prices

Sunil BhaduPartner and Advisory Leader - Oil & Gas

Ernst & Young LLP

Crude oil prices witnessed a downfall after a

relatively steady period at level above

US$100 per barrel. In fact, very few

predicted such prices when Brent Crude was trading

around US$42 per barrel in January 2009 - following

the collapse of global stock markets just a few

months earlier. However, within a span of two years

prices recovered to US$100 per barrel, reaching the

levels of US$125 per barrel in early May, 2011. Apart

from a few short-term dips witnessed in mid-2012

and early 2013, Brent prices were largely trading

above US$100 per barrel until September 2014.

High prices boosted activities around production of

Shale or Light Tight Oil (LTO) in the US, with US oil

production growing by more than 1 million barrel

per day in each of the last three years. These were

complemented by the geopolitical tensions and

uncertainties in Middle East and North Africa. There

were also unplanned supply outages which

compensated for the modest demand growth of oil

through early 2011 to mid-2014.

However, post June 2014, production outages were

restored in Libya and Iraq. With oil demand facing

weak growth, there was an oversupply of oil, and

soon oil prices began to fall. In times like these, the

role of OPEC has been vital in controlling the oil

prices. However, OPEC voted in late November 2014to maintain production levels, owing to the stand

taken by Saudi Arabia to maintain its market share.

This further accelerated fall in crude prices and by

late January 2015, Brent crude prices had dropped

below US$50 per barrel, more than 60% below their

most recent peak in mid-June 2014. Oil prices have

somewhat recovered and was trading around US$

60 in the end of May 2015.1

As expected, the industry reacted sharply to this fall

in crude prices. There were cuts in Capital budgets

and many companies announced substantial staff

layoffs in early 2015. According to Wood Mackenzie,

oil and gas companies have cumulatively slashed

their 2015 upstream budgets by 24% y-o-y, i.e. by

US$120 billion based on announcements from 116companies. Independents have embarked on

significant spending cuts (around 33%), followed by

NOCs (27%) and Majors (12%). In other words, this

raises the question -is a world where oil is plentiful

and relatively inexpensive - the new normal?

Going Forward - Key Considerations

OPEC supply has exceeded the market demand

since early 2014. OPEC members have resolved to

maintain their production at 30 million barrel per day

and have been successful in doing so till Q1 of 2015

which resulted in an oversupply by around 2.43

million barrels per day2. This situation brings an

interesting perspective for the rest of 2015 and early

2016. It will be interesting to know who will cut the

production first- US LTO producers or the OPEC.

Key considerations for the road ahead are as follows:

1 Source: EIA Report (www.eia.gov)2 Source: OPEC Monthly Oil Market Report, June 10, 2015

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Economic stimulus on various countries

While Oil & Gas industry generally bleeds from the

low oil price scenarios, it has varying impact on the

economies around the world. These can be

categorized in the four broad buckets:

The Big Winners Big winners are countries which have heavy demand for Oil. Countries such as India,

China, Indonesia etc., which are battling high inflation and large oil subsidy bills, will benefit

most from a lower price environment.

Oil Importers Countries which import oil but their demand for oil is not so significant fall into this

category. e.g., Emerging economies and advanced economies with lower oil

demand.

Most advanced economies also gain significantly, although as they have less

dependence on oil for every dollar of gross domestic product their proportionate

gains are smaller.

Oil Exporters Countries where oil export is the key source of income but capital reserves are not

so high. e.g., Russia, Venezuela.

For oil exporters, however, the outlook is darker. Moody's estimates that Russia

and Venezuela will be the hardest hit, since they have "large recurring expenditure

that may be politically challenging to cut".

Large Oil Countries which are dependent on oil production and have huge capital reserves

Producers fall into this category. A large oil producer such as Saudi Arabia, has much greater

fiscal buffers since it saved more than it spent. However, they still may be exposed

if the scenario continues.

The graphic below shows the annualized value of those gains and losses expected in percent of GDP3

3 Source: The Wall Street Journal research

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Substantial reduction in upstream spending,possibly 20-25%

Conventional: cutbacks in exploration;postponement/deferral of project sanctioningparticularly for high risk high cost projects butlittle impact on short-term production

Unconventional: large cutbacks indevelopment drilling; increasing high-grading ofdevelopment ("sweet spot" focus) - somereductions to production growth

Increased pressure to reduce/control costs-pressure particularly focused on OFScompanies

With increased pressure to reduce and control

costs, Oil Field service providers are the mostaffected. However, this also presents anopportunity to innovate for efficiency and cutdown unnecessary costs.

Tightened access to capital - highly-

leveraged companies may find it difficult to

fund drilling; rising default risks

Due to lower cash flows, lenders will tighten thescrew on such companies and this may lead tolower investments

Increasing consolidation/transaction activity

Large acquisitions like Shell acquiring BritishGas has already kicked off the possibility ofmore such acquisitions being planned in thefuture.

Rising political instability risks in countries

with high fiscal break-even prices and limited

fiscal reserves (e.g., Venezuela, Libya, Iraq,

Nigeria, Russia and Iran)

Such countries may find it difficult to meet thesocial costs which can cause political or civilunrest leading to increased risk of oil supplies.

Iranian nuclear negotiations - possible removalof sanctions could increase supply surplus inthe absence of OPEC/Saudi accommodations

Lifting of sanctions could lead to additionalsupply of 2 million bpd of oil from Iran which

may cause slump in oil prices in case OPEC/ Saudi do not accommodate such rise inproduction.

Given the current oversupply, lower prices will mean

that many projects, which are no longer economic,

may close down or may be deferred. So, while

today's environment may be volatile and far from

'normal', we may once again see a gradual increase

in prices.

After 2015, the medium-term price of crude should

settle into a range that is driven by both

fundamentals and expectations. We see three

possible price paths or scenarios.

1. OPEC adheres to its production ceiling of 30Million barrels per day and there is only modestgrowth in demand. There are no majordisruptions in supply owing to Geopolitical

reasons. Also, US LTO observes only moderateslow down in a production. As a result, thegradual tightening of markets will be drawn-out.These factors would mean that Oil prices willremain in the range of $60 -75 per barrel for thenext several years - US $70 world.

2. In a medium-price scenario, the markettightness becomes apparent sooner and moresharply. Although Demand growth is not so fast,OPEC responds to cut down production slightly.US unconventional oil production faces a

decline due to lower investments. Under thisscenario, oil could be in a range of US$75 toUS$85 per barrel for the next several years - US$80 world.

3. In higher-price scenario, the global economystrengthens and the global oil demandincreases. Geopolitical tensions would meanthat OPEC cuts down production significantly.Growth in US LTO production cannot surpassthe increased demand. These factors couldtrigger oil prices back into the US$85 to US$95per barrel range - US $90 world.

So, while today's environment may not exactly be a

new normal and we may once again see a gradual

increase in prices, the uncertainty is still creating

significant instability.

What it means for companies?

For companies operating in different segments it

would have different implications. The figure belowsummarizes the impact on key segments within the

Oil & Gas industry due to the oil prices.

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possible, and raising equity. Apart from capital

structure the Company should also have a

strong working capital performance. If

necessary, the company could divest assets orbusiness units to generate cash. Additionally,

understanding and managing possible

impairment risks can also be beneficial.

2. Operational Resilience

Companies should understand marginal and

break-even costs and use that knowledge to

challenge operational assumptions. In the

current environment, it is more critical than ever

to deliver capital projects on time and on

Being Resilient

For energy executives managing in this uncertain

world, there are three major areas of focus that canprovide the strength and resilience needed to

weather an extended period of lower prices.

1. Financial Resilience

With the low price scenario, the Companies will

need to manage the balance between lower

cash generation and the obligations/liabilities.

Financial resiliency includes optimizing the

company's capital structure, restructuring the

balance sheet, refinancing certain loans, if

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budget. Leadership teams must be willing to

take bold action - such as re-scoping, deferring

or stopping outright - any projects that are not

on track. In addition, companies should be

working to re-engineer their business models

to lower their cost base, as well as renegotiatingtheir supply chain and supplier arrangements

to reduce expenses and collaboratively drive

efficiency.

3. Portfolio Resilience

What are the strategic implications and risk

exposures when investment assumptions no

longer hold true? Which assets are

underperforming or are distressed and could

be carved out or divested? Now is a good time

to optimize the company's overall portfolio by

restructuring capital allocations away from high-

cost, lower-return projects. For companies with

stronger balance sheets, it may also be time to

seek out opportunistic acquisitions of challenged

businesses or expand into growth markets. Joint

ventures to share risk capital could also beexplored.

No one really knows how long the conditions we see

today will be "the new normal" in an industry known

for its volatility and cyclicality. Energy markets are

more diversified and complex today and as a result

uncertainty is heightened. But regardless of where

the price of crude settles, energy executives should

strengthen their companies by focusing on financial,operational and portfolio resilience.

(Views expressed are his personal.)

Life isn't about finding yourself. Life is about creating yourself.

“

“

~George Bernard Shaw

Life is not a problem to be solved, but a reality to be experienced.

“

“

~Soren Kierkegaard

Nobody made a greater mistake than he who did nothing

because he could do only a little.“ “~Edmund Burke

7/21/2019 Apr June15 (1)



Water Resources Management for Sustainable Development

Prof. N. Janardhana RajuSchool of Environmental Sciences

Jawaharlal Nehru University

The fundamental right to freshwater is not

exercised by about 3.5 billion women and

men across the world according to the UN

World Water Development Report 2014. They often

also lack access to reliable energy, especially

electricity. Water management is therefore, a major

challenge for city planners, builders, architects today,

not just in terms of availability of water but most

importantly its quality. The well-being of humanity,environment and economics ultimately depends on

the management of planet's natural resources. Direct

use of water is concentrated in major sectors of the

economy, which include agriculture, forestry, mining,

energy resource extraction, manufacturing, electric

power production and public water supply. The

demand for water has already increased

tremendously over the years due to an increasing

population, expanding agriculture, rapidindustrialization, urbanization and economic

development and this led to water scarcity in many

parts of the world. Simultaneously, unplanned

development of surface and groundwater resources,

haphazard disposal of municipal and industrial

wastes and application of agricultural inputs has led

to the problem of water quality deterioration/pollution

presenting new challenges on water management

and conservation front.

In most river drainage basins the hydrological cycle

is being modified quantitatively and qualitatively by

human activities such as changes in cropping

pattern, land use pattern, overexploitation of water

storage, irrigation, drainage patterns and industrial

uses. Hence, sustainable management of water and

surrounding environment for a better future has

gained considerable importance in recent years.

Drought, floods and a lack of fresh water may cause

significant global instability and conflict in coming

decades, as developing countries scramble to meet

the demand from exploding populations while

dealing with the effects of climate change. There is

risk of water issues causing wars in coming years

as they create tensions within and between states

and threaten to disrupt national and global food

markets.

Groundwater crisis is not the result of natural factors;

it has been caused by human actions. During the

past two decades, the water level in several parts of

the world has been falling rapidly due to an increase

in extraction by intense competition among userssuch as agriculture, industry and domestic sectors.

The number of wells drilled for domestic and

irrigation (both food and cash crops) have rapidly

and indiscriminately increased. The water

requirement for the industry also shows an overall

increase. Besides, discharge of untreated

wastewater through bores and leachate from

unscientific disposal of solid wastes also

contaminates groundwater, thereby reducing thequality of fresh water resources.

The collection, transport and treatment of water

require energy, while water is used in energy

production and for the extraction of fossil fuels. In

2013, water shortages shut down thermal power

plants in India, decreased energy production in

power plants in USA, and threatened hydropower

generation in many countries, including Sri Lanka,

China and Brazil. The present world's population is

around seven billion and by 2050 it reaches nine

7/21/2019 Apr June15 (1)



billion which requires a 50% increase in agricultural

production and a 15% increase in the already

strained water withdrawals. By 2035, the world's

energy consumption will increase by 35% which in

turn will increase water consumption by 85%

according to the "International Energy Agency". Anaverage of 95 litres of water is required to produce

1 kilowatt-hour of electricity. Vast quantities of water

are being used to develop unconventional fossil fuel

resources (e.g. oil/tar sands and gas production by

fracking) which consume 0.8 to 2.4 barrels of fresh

water for every barrel of oil produced. Hydraulic

fracturing (i.e. fracking) involves the injection of fluids

(fresh water, proppant (i.e. sand) and chemicals)

under pressures great enough to fracture the oil andgas producing formations. Hydraulic fracturing

activities have potential impacts on the quality and

quantity of drinking water resources and competition

for water with other water users sectors (especially

in drought areas) and the disposal of wastewater

generated from hydraulic fracturing.

The decline of water levels and drying up of shallow

wells due to overexploitation, diminishing of waterbodies and increasing number of well structures are

the present day scenario in many parts of India. Due

to urbanization, the soil surface exposed to recharge

gets drastically reduced and therefore natural

recharge gets diminished. Water crisis, created by

declining of water, is further aggravated by the

pollution of water resources. Therefore, the greater

stress is on the remaining available sources of fresh

water resources. India is heading towards a freshwater crisis mainly due to improper management of

water resources and environmental degradation,

which has lead to a lack of access to safe water

supply to millions of people. The reasons for

groundwater depletion are uncertain or erratic

rainfall, reduction of recharge area due to

urbanization, diminishing of surface water bodies,

over-exploitation of groundwater resources and

increase in number of groundwater structures

annually.

Artificial Recharge and

Rainwater Harvesting

Rainwater harvesting and artificial recharge are

made compulsory in the areas where groundwater

development has increased over the annual

replenishment. The most widely practiced methods

of artificial recharge of groundwater employ different

techniques of increasing the contact area and

resident time of surface water with the soil so that

maximum quantity of water can infiltrate and

augment the groundwater storage. The choice and

effectiveness of a particular method is governed by

local hydrogeological (topography and geology) soil

condition and ultimate use.

Rainwater Harvesting Structures in

Urban Areas

Roof-top water collection and recharge: Availability

of rainwater from rooftop is so high in urban areas

and if properly diverted and used, artificial recharge

will not only increase the groundwater but also help

in reducing the water scarcity problems in cities and

towns. Commonly runoff water from rooftop is letoff into the drains. Instead of this, the outlets can be

connected through a pipe to a storage tank and let

into gravel filled trenches, pits or existing wells to

serve as recharge pits.

Storm runoff collection and recharge: Instead of

letting out street or road runoff into drainage canals,

it can be diverted into suitably designed recharge

structures near pavements, parking lots, municipal

parks, play grounds, stadium, airports etc.

earmarking some open spaces exclusively for the

storm runoff collection. Porous pavements can be

utilized for collected road runoff for recharge

groundwater.

Recycling of household water: All the water from

wash basins and bathrooms (other than sewage)

can be let out into the garden or backyard and

excess water can be let into soak pits that canregenerate the groundwater. Thus wastewater can

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be effectively recycled and reused in facilitating

ecological activities.

Rainwater Harvesting Structures in

Rural Areas (Runoff conservation

structures)In areas receiving low to moderate rainfall, mostly

during a single monsoon season, the entire effort of

water conservation of in situ rainfall is required.

Different measures applicable in runoff zone,

recharge zone and storage zone of a watershed

basin are available.

Gully plugs: These are smallest runoff conservation

structures built across small gullies and streamsrushing down the hill slopes carrying drainage of

tiny catchments during rainy season.

Bench terraces: Sloping land with adequate soil

cover can be levelled through bench terracing for

bringing under cultivation. It helps in soil

conservation and holding water on terraced areas

for longer duration giving rise to increased infiltration

recharge.

Contour trenches and bunds: This technique is

adopted generally in low rainfall areas where the

monsoon runoff impounded by putting trenches and

bunds on the sloping ground all along the contour

of equal elevations. The water is intercepted before

it attains the erosive velocity by keeping suitable

spacing between two bunds. The spacing between

two contour trenches and bunds depends on the

slope of the area and the permeability of the soil.Lesser the permeability of soil the closer spacing of

bunds is desired.

Rock-fill dams or nala bunds: A series of small bunds

or weirs are made across selected nala sections

such that the flow of surface water in the stream

channel is impeded and water is retained on

pervious soil/rock surface for longer period of time.

As compared to gully plugs, nala bunds are

constructed across bigger nalas of second order

streams in areas having gentle slopes.

Check dams: It is masonry structure of small length

and low height constructed across a stream to arrest

surface runoff of the stream. The check dam not

only provides surface water for irrigation by gravity

flow but also is useful for artificial recharge for

groundwater development.

Subsurface dams: It is constructed below ground

level in the permeable river beds by digging a trench

across the valley reaching down to bed rock to

harness the base flow in a natural aquifer. An

impervious wall is constructed in the trench and then

the trench is filled with the excavated material. It is

eco-friendly, no submergence of fertile land and no

evaporation losses.

Conclusions

It is essential to promote community and

household involvement in urban (i.e. rooftopcollection) and in rural by undertaking watershed

development program (i.e. improving local waterharvesting systems and afforestation).

Drip and sprinkler irrigation systems are highly

advisable in water scarce areas to conservewater resources.

Change of cropping patterns in water scarcity

areas and cultivating high value but low waterrequiring crops such as pulses (beans, lentils

and peas) and oil seeds.

Recycling and reusing of sewage and industrialwastewater is valuable alternate source of water

supply in urban areas for specific uses such astoilet flushing and gardening.

Strict groundwater legislation to preventoverexploitation of groundwater resourcesi.e. maintaining spacing between wells

Maximizing the water efficiency of power plant

cooling systems and increasing the capacity ofwind, solar power and geothermal energy will

be a key determinant in achieving a sustainablewater future.

Large amount of surplus water in certain river

basins can be diverted to deficit river basins(inter-basin transfer) to meet the water demandin the water scarcity regions.

7/21/2019 Apr June15 (1)



Role of Analytics in Security of OperationTechnologies

Vinayak GodseSenior Director

Data Security Council of India (DSCI)

According to the technology consulting firm,

Gartner, Operation Technology (OT) is a

hardware and software that can detect or

cause a change through the direct monitoring and/

or control of physical devices, processes and events

in an enterprise. Supervisory Control and Data

Acquisition (SCADA) and Industrial Control System

(ICS), build a layer of Programmable Logic Controller

(PLC) and/or Remote Telemetry Units (RTU), whichafter communication networks host a software

typically referred to as OT. Apart from PLC and RTUs

the following protocols/ services are on the internet.

Energy Management Systems (EMS)

DNP3 (Distributed Network Protocol)

Many used form of communication between the

components in process automation systems

serial communication protocol ModBus

Open Platform Communications (OPC) used forexchange of data between multi-vendor devices

and control applications

Distributed Control System (DCS)

Human Machine Interface (HMI/MMI)

Industrial computer network protocol FieldBus

Inter-Control Center Communications Protocol

(ICCP TASE 2)

These technologies were destined to generate

information, which would become relevant in the age

driven by trends such as Big Data. Cost reduction

of sensors and communication, storages and

increasing processing speed using technologies

such as Hadoop, make it practically possible to

experiment with information generated by OTs. Due

to this enormous trove of OT, data available lies atdisposal of many purposes. Security is evolving as

a critical purpose, as more targeted and advanced

attacks, striving to exploit instrumentation systems,

are being witnessed.

OT is different from Information Technology, both, in

application and architectural characteristics. The

data science in Operation Technologies has different

connotations than data science talked in the

contemporary world. Less has been researched in

this area, and as a result, limited expertise is

available. Data from operation technology sensors

would be critical in understanding behavior of

instruments, recording their normal behavior, and

analyzing the pattern during the course of time and

identify abnormalities, if any. These abnormalities

may be due to the exploitation from targeted attacks,

as SCADA systems are becoming a target of security

attacks.

As per a Dell report, Sonicwall saw increase in global

SCADA attacks from 91,676 in 2012,163,228 in 2013,

and 675,186 in 2014. Buffer overflow vulnerabilities

were the primary point of attack against SCADA systems, which control remote equipment and

collect data on equipment performance, accounting

for 25% of the attacks witnessed by Dell. A report of

Industrial Control Systems Cyber Emergency

Response Team (ICS-CERT) reveals that well over

half of the incidents affected the energy (32%) and

the critical manufacturing (27%) sectors. Other

sectors are also climbing the ladder. Transportation,

healthcare, and government facilities sectors eachaccounted for 5-6% of the total number of ICS

incidents. A senior threat researcher with Trend

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Micro, recently found 13 different types of crime ware

versions disguised as Human Machine Interface

(HMI) products such as Siemens Simatic WinCC,

GE Cimplicity, and Advantech device drivers and

other files. Quite interestingly, the attacks appear to

be coming from traditional cybercriminals rather than

nation-state attackers, and are not using cyber

espionage-type malware. On the one hand, SCADA

systems are vulnerable to targeted attacks from

both, state and non-state actors, as witnessed by

malware such as Havex and BlackEnergy. On the

other hand, increasing instances of crime ware -

based attacks are also emerging against the SCADA

system, the intent of which is money making.

These attacks reveal that there would be diverse

vectors used to exploit the systems that find gaps

in engineering operations, sensor network,

communication network, interfaces and command/

host software. At present, OT systems may not have

much visibility in data exchanges across OT

networks and platforms that are vulnerable to cyber-

attacks. Even if the systems have been exploited, it

may remain hidden for a long time. On the other

hand, if IT systems interfacing with the OT systems

get compromised, it would have a cascading effect

on OT systems. There would be 'n' number of

contexts that would come out in play to cause

exploitation. These contexts may remain hidden or

isolated from the system that helps identify security

incidents. Typically, the OT systems are vendor-specific and most likely built on proprietary

technologies. Even if one builds systems to compile

relevant context that is important to take a security

decision, OT systems may not be ready to provide

contextual information required for this decision

making.

The security market is evolving to address these

challenges, with technologies such as content-

aware security appliances that can serve IT and OT

use cases. They support inspection of industrialcontrol system network protocols. They can inspect

network traffic at a granular level, down to the

machine transaction level. The alerts and information

generated by these solutions can be fed to take

decisions apart from the information collected from

sensors and other communication devices. Security

decision making is now critically dependent on the

intelligence gathered from information generating

devices and the solutions that provide context and

content specific information. Relying on internal

intelligence wouldn't serve much of the purpose,

unless it is integrated with external intelligence.

Information collected from thousands of sources

scattered across web, organized and analyzed on

leading indicators of compromises, adds critical

value to security decision making. The security

market is now equipped to provide focused

intelligence involving Operational Technologies.

Together, internal and external intelligence would

help give four type of analytics namely: Descriptive,

Diagnostic, Predictive and Prescriptive. These

pieces would improve security decision making

rather significantly and help manage security

incidents in a predictable manner. Moreover,

intelligence available real-time would help automateresponse to the incidents, thereby reducing impact

of the attack and avoiding exploitations to new

attacks.

(Views expressed here are personal.)

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The rapid growth of the global economy and

increasing use of transportation fuels has

brought energy security and environmental

issues to the fore. Transportation fuels are currently

produced primarily from crude oil, with alternative

sources viz. natural gas, coal and biomass

contributing only a small share. According to the

Petroleum Planning and Analysis Cell (PPAC), India

is expected to consume 166.9 million tonnes (mt)

of refined fuels in 2015-16 compared with 161.6 mt

in financial year 2014-2015.

Diesel is one of the most widely used transportation

fuels, accounting for more than 40% of India's refined

fuel consumption. The demand for diesel is set to

rise 4.1% in 2015-16 to 71.3 mt, while that of petrol

is expected to increase by 7.2% to 19.7 mt.

Estimates by IHS Automotive predict that by 2019

India will become the world's third-largest passenger

vehicle market, jumping three places from sixthplace in 2015. As a result, the demand for refined

fuels, in particular diesel, will also increase assuming

that global oil prices remain stable at the current

level of between USD 65-70 per barrel.

Unfortunately, an increase in the use of diesel

vehicles does pose significant challenges. The

combustion of diesel in compression ignition

engines produces a range of undesirable pollutants,

which is clearly evident when driving behind a diesel

bus or truck. The particulate emissions we see in

the form of smoke are a particular problem, but otherpollutants, such as NOx, polyaromatic

hydrocarbons and other unburnt hydrocarbons are

also problematic. Particulate matter (PM), smaller

than 10 m, PM10, is emerging as a problem of

particular concern as they penetrate deeper into

human lungs and very small particles can cross

easily into the blood stream. Such particles can carry

toxic PAHs, and are classified as human

carcinogens by the World Health Organisation.Numerous technologies, such as diesel particle

filters and catalytic converters, have been developed

to tackle this problem, however, such devices have

become highly complex and energy intensive and

it is becoming increasingly difficult to make small

improvements in the technology. With the current

engine management and exhaust gas treatment

technologies there is a trade-off between particulate

and NOx emissions, and it is difficult to reduce both

simultaneously, In this context, changing the nature

of the fuel provides an opportunity to break this

trade-off and oxygenated fuels are particularly

promising in this context. Moreover, the production

of oxygenated fuels from locally available alternative

resources, such as coal and natural gas, as well as

from renewable feedstock's, such as biomass, could

play an important role in providing energy security

while simultaneously addressing problems

associated with air pollution.

Dr. Chanchal SamantaManager (R&D)

BPCL

Dr. Ankur BordoloiScientist

IIP, Dehradun

Dr. R. K. VoolapalliChief Manager (R&D)

BPCL

Dr. Jim PatelScientist

CSIRO, Australia

OxyMethylene Ethers: Diesel Additives for the Future

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Fig 1: OMEs are promising diesel additives capable of reducing diesel exhaust emissions

diesel is a major source of air pollution, especially

particulate matter (PM) emissions through soot

formation. Diesel exhaust consists of gaseous, liquid

and solid emissions. Gaseous emission consist of

N2, CO

2, CO, H

2, NO/NO

2, SO

2 /SO

3, HC (C

2-C

15),

oxygenates and organic nitrogen and sulphur

compounds. Liquid emissions include H2O, H

2SO

4,

HC (C15

-C40

) and polyaromatics. Solid emissions are

made up of dry soot, metals, inorganic oxides,

sulphates and solid hydrocarbons. The World Health

Organization has labelled the polar fraction of diesel

particulates as carcinogenic and hence a health

hazard.

Diesel quality in India has improved significantly in

recent years. Diesel sulfur content has been reduced

from 10,000 ppm in most of the country in 1999 to a

maximum content of 350 ppm in 2012. In thirteen

major metropolitan areas the level has fallen from

2500 ppm to 50 ppm in the same time period.

Another factor that has improved over the sameperiod is the cetane number, which has increased

from 45 to 51 nationwide. At present, a total of 63

cities are receiving 50 ppm sulfur diesel. The recent

outcry over worsening air quality in Indian cities has

prompted the government to urge automakers to

move to the advanced Bharat Stage V (10 ppm sulfur

diesel) and VI emission (5 ppm sulfur diesel) norms

a year ahead of schedule, in 2019 and 2023,

respectively. The current diesel specificationsrequired for meeting Bharat Stage IV Emission

norms listed in Table 1.

Diesel and Oxygenates for Diesel

Since its invention by Rudolf Diesel in 1893, the

diesel engine has revolutionized the transportation

sector, due, in part, to its high thermal efficiency.

The fuel efficiency of a diesel engine is generally

between 30-50% higher than that of a gasoline

engine with comparable power output. In other

words, CO2 emissions will be 30 to 50% lower for

the diesel engine for the same amount of power

produced. Since CO2 is a greenhouse gas, a

transition from gasoline-powered engines to diesel-

powered engines seems to be a logical choice to

reduce emissions in the transport sector. However,

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Table 1: Diesel specifications required for meeting Bharat Stage IV emission norms

Characteristics Unit Specification

Density @ 15°C, kg/m3

kg/m3 820 to 845

Flash Point (Abel) °C Min. 35

Viscosity (Kinematic)@ 40°C cSt 2.0 to 4.5

Pour Point, °C Max. 3 (Winter)

Max. 15 (Summer)

Total Sulphur mg/Kg Max. 50

Polycyclic Aromatic Hydrocarbon (PAH) %wt Max. 11

Cetane Number (CN) Min. 51

Distillation Recovery @ 360°C %v Min. 95

Oxidation stability g/m3

Max. 25

Lubricity wsd @ 60°C, microns Max. 460

Although stringent regulations and fuel quality norms

have improved the diesel quality, with associated

reductions in CO2 emissions, there is still an urgent

need to improve the quality further, especially with

respect to particulate matter emissions. A reduction

in particulate matter emissions is achievable by

modifying the hydrocarbon component of fuels and

also by introducing oxygenates as additives.

Oxygenates are particularly attractive as diesel fuel

additives, as they are capable of reducing exhaustemissions of particulate matter (PM). Examples of

typical oxygenates considered to be suitable as

diesel additives are listed in Table 2.

Table 2: Various types of oxygenates explored as diesel additives

Types of oxygenates General Chemical structure

Alcohols R-OH

Ethers R-O-R

Glycol ethers R-O-R-O-R

Acetals R-O-C-O-R

Esters R-C(=O)-O-R

Carbonates R-O-C(=O)-O-R

Poly(oxymethylene) dimethyl ethers (POMDMEs) CH3-O-(CH2-O)n-CH3

R= hydrocarbon chain, C = Carbon and O =Oxygen

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The following important fuel characteristics need to

be considered when oxygenated substances are

evaluated as diesel additives:

Miscibility with diesel fuel - oxygenates aregenerally polar in nature, which may lead to

compatibility problems when blended withdiesel;

Energy density - the energy content ofoxygenates is lower than that of hydrocarbonfuels resulting in modifications to fuel injectionsystems, larger fuel tanks or reduced range;

Viscosity - low viscosity of fuels may causeleakages, while high viscosity may over-load theinjection system;

Lubricity - some oxygenates require the additionof lubricity agents;

Cetane number - high cetane numbers generallylead to decreased ignition delays and highercombustion temperatures, consequentlyincreasing particulate matter emission andproducts of incomplete combustion, whereasNOx emission may increase;

Particulate matter emissions - such emissionscan be reduced when fuel contains oxygen, but

this is not a linear phenomenon and the natureof functional groups may overrule the effect ofthe oxygen content;

Engine load and emission controlcharacteristics are also important parameters

In short, the optimum diesel oxygenate would be

compatible with unmodified compression-ignition

engines and infrastructure.

Some fundamental factors that promote favourable

oxygenate chemistry include:

Short carbon chains;

Linear carbon chains are better than their non-linear counterparts;

Symmetrical position of oxygen in ethers;

Cetane number, density, viscosity, boiling pointetc. are also important factors.

Low molecular weight oxygenates such as methanol,

ethanol, C4-alcohols, Dimethyl ether (DME), Diethyl

Ether (DEE), MTBE, Dimethoxymethane (DMM)

although explored widely are found not to be suitable

as diesel additives because of their low boiling and

flash points. For example the boiling points of

butanol isomers are in the range of 82-1180C,

significantly lower than the distillation range of diesel

fuel. With butanol addition, the cetane number,

lubricity, viscosity and flash point of diesel fuel may

fall below the mandated requirements as listed in

Table 1.

Dimethyl ether (DME), Diethyl Ether (DEE), MTBE,

Dimethoxymethane (DMM) have been widely

studied as diesel fuel extenders. However, due to

their low boiling points (DEE, 35 0C; DMM, 420C),

these ethers are not used as diesel additives. Acetal

or 1,1-diethoxyethane is a light compound with a

boiling point of 1030C and flash point of only -20 0C.

The best- known diesel oxygenates are fatty acid

methyl esters, FAMEs. Glycerol is formed as a side-

product in FAME production from triglycerdes, and

some glycerol derivatives are potential candidates

as diesel fuel components. However, this aspect is

not under consideration in the present paper.

High molecular weight oxygenates (listed in Table

3) have been explored as potential diesel fuel

additives. Di n-butyl ether (DBE) has a boiling point

of 141 0C, which is almost within the distillation range

of diesel fuel, whereas its flash point is only 25 0C.

Diethoxy butane, which could be produced from

ethanol and butadiene, has a cetane number of 97,

but a flash point of only 45 0C. Diglyme is a good

candidate and it has been reported that a

14.4 vol-% diglyme blend resulted in a 20-40%

reduction in PM emission with a light-duty truck. In

addition, HC and CO emissions reduced without an

increase in NOx, benzene, butadiene, formaldehyde

and PAH emissions. Di-n-pentyl ether (DNPE) has

high cetane number 103-153 and other properties

are diesel-like. DNPE is fully soluble in diesel fuel,whereas solubility in water is low.

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Table 3: Various types of high molecular weight oxygenates and their properties

Poly ethers with higher molecular weight are

reported as better fuel additives than mono-ethers.

For example, Dibutoxymethane (butylal) is solublewith diesel fuel has boiling point 180 0C and flash

point 620C. The cetane number of butylal is also high

> 74, but a lubricity additive is needed. Diesel-butyl

mixtures reduce engine exhaust opacity without

increasing NOx emission when compared with

diesel fuel. Di-pentoxy methane (DNPM), boiling

point of 2180C and cetane number 97, has also been

reported to be a favourable diesel fuel component.

Particulate matter emissions reduced with fuelcontaining DNPM when compared to diesel fuel.

Tripropylene glycol monomethyl ether (TPGME) is

also one of promising oxygenates from those having

more than 35 wt-% oxygen content. TPGME ismiscible in aromatic diesel and only upto 30 vol%

miscible in paraffinic diesel fuel, but the presence

of water may lead to phase separation.

OMEs: Promising Diesel Additives

Many promising oxygenates reported in the literature

have encountered end-use problems e.g. poor

miscibility with diesel fuel or safety concerns. Inaddition, the economic feasibility of oxygenates may

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be challenging. In order to become an effective

diesel fuel component, an oxygenated compound

must satisfy the following five basic requirements:

Ignition quality: cetane number min 51

Flash point : above 550

C

Boiling point: close to range of 118-340 0C

Solubility in diesel fuel : soluble in diesel fuel

Production : Should be produced from low-cost

widely available feedstock and with simple process

steps

Oxymethylene ethers (OME) or Poly (oxymethylene)

dimethyl ethers (POMDMEs), having the chemicalstructure of CH

3-O-(CH

2-O-)

n-CH

3, are attractive

components for tailoring diesel fuels. OMEs belong

to the group of oxygenates which can reduce soot

formation in the combustion process when added

to diesel fuels. Moreover, OMEs can be produced

from methanol or DME as a basic feedstock.

Methanol can be produced from various non-

renewable and renewable sources, thus offering

attractive flexibility w.r.t feedstocks.

The simplest OME is dimethoxymethane (DMM)

having molecular formula of CH3-O-CH

2-O-CH

3. It

has very low boiling point (42 0C) and cetane number

and is thus not suitable as "drop-in-fuel" diesel

additive. It is, however, a potential additive for

gasoline. A comparison of the properties Bharatstage IV diesel, DME and OMEs is listed in Table 4.

Table 4: Physical characteristics of diesel fuel, DME and OMEs (n =1- 4)

Characteristics Units Bharat Stage IV DME OME OME OME OME

diesel (n=1) (n=2) (n=3) (n=4)

Boiling point 0C 180-390 -25 42 105 156 201

Density, liquid at 150C Kg/m3 820-845 668 867 961 1021 1059

Kinetic Viscosity

at 400 C mm2 /s 2-4.5 < 0.1 0.64 1.05 1.75

Cetane No > 51 55 50 63 70 90

O-content (%) wt % 1.2 34.7 42.1 45.3 47.1 48.2

Volumetric Calorific

Value HU at 150C MJ/I 35-36 18 20 - 19 19

Source: MTZ vol 72, 03/2011

The optimal OME chain length for combustion in a

diesel engine is n=3-5 while the cetane number

should be between 70 and100, higher than that of

conventional diesel which is ca. 55. OMEs have an

oxygen content of between 42-53 wt% and a higher

density as compared to DME and DMM. Therefore,

less volume (to be blended into diesel fuel) is

required to reach a certain oxygen content, resulting

in fuel saving. In addition, OMEs can be used without

changing the engine's infrastructure. It is also

reported that OMEs are not corrosive towards seals

or other polymeric components of the fuel system.

Therefore, OMEs are very attractive as additives for

diesel engines.

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methylal are converted to POMDMEs. Other

methodologies have also been applied to develop

a commercial process for PODME production. One

example is the production of PODMEs by reaction

of DME and trioxane over an acidic catalyst. Another

process consists of synthesis of methylal by reacting

methanol and formaldehyde followed by reaction

with additional formaldehyde to form POMDME. This

process show poor selectivity due to the production

which reacts to form side-products.

Recently a number of redox catalyst systems based

on Ag, Fe, Re V, Ti Mo and metal oxides have been

explored for the syntheses of POMDME on

laboratory scale. The process involves the oxidationof methanol to formaldehyde followed by acidic

condensation reactions.

OME: Chemistry and Catalysis

OMEs can be obtained from methanol as illustrated

in Fig 2. In this synthetic sequence the intermediates

are methylal (Dimethoxymethane, DMM) and cyclic

trimer metaformaldehyde or 1,3,5-trioxane with theformula (CH

2O)

3. In the first step formaldehyde is

obtained by dehydrogenation of methanol. Various

catalyst systems have been explored for the

conversion of methanol to formaldehyde (Table 5).

The trioxane process consists of the trimerisation of

formaldehyde, generally catalyzed by H2SO

4, and

separation of the product, for example by a pressure-

swing distillation sequence. The preferred

production method for methylal from formaldehydeand methanol is by a heterogeneously catalyzed

reactive distillation. Subsequently, trioxane and

Fig 2: Block flow diagram of the POMDME process chain

Zeolites and acidic ion exchange resins were

exploited as catalyst by British Petroleum for

POMDME production. A range of pre-cursors canbe used, such as methanol, formaldehyde, dimethyl

ether, and methylal, however, the process suffers

from low yields of POMDE3-8 (<10%), and process

complexity. Brønsted acid catalyst such as H2SO

4

or CF3SO

3H has been used by BASF to synthesis of

POMDMEn from DMM and trioxymethylene.

Moreover, they also tried other starting materials,

such as DMM and dimethyl ether. However, product

selectivity was reported to be very low. Recently,researchers from the Lanzhou Institute of Chemical

Physics have developed a new process for the

production of POMDE3-8 based on ionic liquid base

as catalyst and raw material like methanol andtrioxymethylene. In this process, high yield of

POMDMEs (50%) were obtained with good

selectivity for POMDMEs(n=3-8) 70-80%. However,

the process has limitations for higher scale

production due to a complicated purification process

and the expensive and corrosive nature of the

catalyst system. Therefore, it is important to develop

a solid catalyst for the efficient and environmentally

benign process to synthesis POMDMEs atcommercial level.

7/21/2019 Apr June15 (1)



Table 5: Reactions and catalysts for OMEs production process chain

publications and patents on OMEs in the last five

years, revealing a renewed interest in OMEs. This is

mainly because of the stringent environmental

regulations worldwide to reduce exhaust emissions.

China's proactive energy policy combined with the

scale of its economy and infrastructure development

is promoting regional as well as global clean energy

related research. As evidence, China's oil companiesand research institutes are very active in this area

as evident by the fact that more than 70% of research

outputs are coming from China. BASF and BP are

also active in the research and development on

OMEs.

Fig 3: Publications/patents trends OMEs (Source: KIT, Germany)

OMEs: Global R&D Scenario

Stringent climate change protection legislation

requires second generation fuel components to

reduce emissions from the combustion of fossil

fuels. The European Union and China have each

made great efforts to reduce emissions from

vehicles. Publications and patents trends with

respect to OMEs from the 1990's to 2014 ispresented in Fig.3 and the R&D contribution of

various institutes on the development of OME

process technologies is presented in Fig 4.

There has been steady increase in the number of

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compared to DME and DMM. OMEs blended with

diesel fuel can be applied directly in existing diesel

engines without any technological changes and

allow an introduction to the market without

installation of new logistic infrastructure. OME

production based on the renewable feedstocks also

would help to deal with climate change and energy

security challenges. The optimum diesel oxygenate

would be compatible with unmodified compression-

ignition engines and infrastructure. OMEs blended

diesel fuels have the potential of significantly

reducing local emissions as well as global CO2

emissions.

Fig 4: R&D contributions of various companies/institutes on OMEs (Source: KIT, Germany)

Summary

Limited fossil fuels resources, climatic and human

health issues are promoting a shift from conventional

towards more renewable fuels and fuel additives.

The polyoxymethylene dimethyl ethers (POMDMEs)

or OMEs with a chain length of n=3,4, are an

attractive clean alternative to crude oil derived diesel.

OMEs can be easily produced via syn-gas and

methanol from waste biomass or from th recycling

of CO2 by H2. POMDMEs are capable of reducing

exhaust emissions, especially particulate matter

emissions. The low vapour pressure of high

molecular weight of POMDMEs (of n=3-5) and their

miscibility with diesel fuel are a clear advantage

Our prime purpose in this life is to help others.

And if you can't help them, at least don't hurt them.“ “

~Dalai Lama

Help others achieve their dreams and you will achieve yours.

“

“

~Les Brown

7/21/2019 Apr June15 (1)



Offshore Renewables

Capt. D. C. SekharManaging Director

AlphaMERS Pvt. Ltd.

Tidal Energy

The maximum tidal range in Gulf of Khambat

at locations like Bhavnagar is almost 10 m.

This is nature's bountiful gift of energy, given

to us day after day, year after year. We can harness

the energy or let it go. Unlike fossil fuels today's

unused resource does not remain for another day.

Much like the empty seats of an aircraft or empty

hotel rooms, today's resource is wasted, tomorrow

is a fresh supply.

The good news is - tides are as predictable as the

rise of the sun or moon. The power yield can be

reliably estimated today, for any given day, few years

later and an assurance given to the utility years in

advance. Unfortunately the tidal cycle, dominated

by lunar forces, does not exactly coincide with the

earth's solar day cycle. Thus the tidal power cycle

does not coincide with our work and demand cycle.

Tidal streams represent a different type of energy

from the tidal rise. This is kinetic energy in a tidal

current, and as the name implies, caused by the

tidal forces. A simplistic solution is placing turbine

in way of the water to convert water stream into

electrical power. It may be emphasized that the

current strength varies in magnitude and changes

direction as per the change of tide. This presents a

challenge to provide a steady power output.

A good optimum is a hybrid system of stored head

of water from rise of tide, supplemented by a turbineplaced in the tide induced currents. The power

output can be smoothened and matched to meet

the demand cycles. It may be important to note that

the plant's rated output will be limited by rise of water

in neap tides even though the generation capacity

during spring tides may be much substantially

higher. The neap tides will see reduced storage head

as well as the reduced strength of the tidal currents.

Most turbines placed in tidal streams must operate

in both directions to cater for flood and ebb flows. Alternatively, they must be able to vary their pitch

(CPP).

Rivers on the other hand present different

opportunities. The flow is unidirectional and the

changes are seasonal rather than daily. The change

in water levels can be large in rivers, adding to the

micro-siting challenges. There is notable benefit in

placing the turbine close to communities on the river

bank to avoid long transmission lines. The siltation

and accretion will present challenges to the stability

of the turbine foundation and flow of water through

such turbines. These are analyzed in detail through

CFD modelling software.

Wave Power

Wave created by wind, is as unpredictable as thewind itself. The 'swell' on the other hand, has its

origins from a disturbance much further and not due

to local winds. Both the wave and swell have a large

energy and can toss a large ship around effortlessly.

Simply put, any object floating on water and

anchored, will move with the waves. The energy of

these movements needs to be converted to usable

forms of energy. There are dozens of possibilities

and models. Most of the models start producingabove a threshold wavelength and have optimum

performance on a certain range of wave length.

These parameters can be configured to the

significant wavelength at the location.

The energy is obviously abundant and is right there.

If not today, mankind will learn in the decades to

come, how to smartly harness this energy. The

energy can be used to power - remote buoys,

unmanned oil platforms, Islands, coastal resorts,coastal communities, lighting requirements of fishing

boats etc. The author's firm has patent applied three

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designs for harnessing energy from waves, suitable

for different applications.

One of the high profile wave energy converter

models deployed for technology demonstration is

P2 by Edinburgh-based Pelamis. The capacity of

this plant is 750 KW.

'Penguin' is another model for wave power

conversion developed by Wello. This device weighs

1600 tons, is 30 m long, 9 m tall with a draft of 7 m.

This converter produces a continuous output of 160

to 180 kW and peak power outputs of up to 700 kW.

Offshore Wind Farm

The recent developments take the traditional mono

pile fixed (to seabed) turbine to the more futuristic

floating turbines. These floating turbines have few

advantages. One distinct advantage is they take the

theatre of action from 50 m depths to between 150

and 200 m depths, often offering more sea room for

development away from the near shore shipping

traffic and CRZ issues. They also avoid the issues

of visual pollution and turbine noise, close to

communities. They are assembled in ports and wet

towed to location, saving the need for expensive

offshore floating crane operations.

However, the floating turbine designs have to

develop further to limit the wear and tear on the

turbine parts when moving in a seaway. The Author's

firm is working on a particular design aspect of

floating turbine, enabling the conversion to electrical

power at sea level, instead of the nacelle. The

purpose is to reduce weight on top and more

importantly bring maintenance issues to sea level.

This will result in enhanced weather windows formaintenance.

There are two notable projects in floating turbines in

the world. One is 2.3 MW Hywind assembled in

Norway. The turbine draft is very high i.e. 100 m.

The second project is the 2 MW Windfloat from

Principal Power, which is moored off the coast of

Portugal. The floating turbine sizes are large and is

expected to go up to 6MW turbines in the years

to come.

Typically of wind, the resource availability varies and

is unpredictable over short timescales. Thus the

power supply and demand cycles are mismatched

and beg for a buffer or storage capacity that wouldbridge these gaps. This is one area with need for

technology development, i.e. storage of harnessed

energy. Water lift and storage is a popular model

and is more environment friendly than banks of

chemical batteries. The storage capacities can be

increased by increasing water storage capacities.

State policies are the gatekeepers of development

in any sector. Resource assessment studies in this

sector are expensive and at the same time, the

results are very site specific. This begs the question

of what comes first for private investment? Resource

assessment or securing rights to a resource bloc?

Would one invest in detailed study of the site specific

resource without assurance of the right to use? Or

would one apply or bid for the bloc without reliable

data of resource availability. Swiss challenge

proposals are a good answer for such situations.

Besides the obvious competencies in turbines and

electrical systems, some of the other competenciesrequired for offshore energy development are

resource assessments, geotechnical assessment,

offshore logistics, environmental impact

assessments, maritime security etc. The concerns

or objections can come from radar stations, fishing

traffic, shipping traffic, sensitive species habitat,

potential for other resources etc.

It can be safely summarized that the future of energy

is in renewables and a lot of that will come fromoffshore wind and waves, of course, in addition to

our abundant sunshine overland. The economy of

scale and the scale of offshore projects will continue

to get bigger. The development technology and

costs per unit will continue to decrease and compete

with other types of renewables. With our large

coastline, we have something to cheer about in our

not too distant future.

The author's firm (www.alphamers.com) assists resource assessments, provides consultancy in offshore renewable

energy sector and has filed patents in wave energy harnessing devices.

7/21/2019 Apr June15 (1)



Job Hazard Analysis & Escalation Matrix

V. V. R. NarasimhamHead-Corporate HSE

Hindustan Petroleum Corporation Limited

In hazardous process industry, the last precursoract to an incident, in most cases, is executed by

the frontline lower echelon person who interfaces

with the work-front. It could be a technician, a skilled

or unskilled worker. This makes it necessary for the

managements to ensure that "the frontline" carries

out its work in a well-established framework of work

planning, adequate knowledge, the right procedures

and that they are kept alive to the safety requirements

of every job. The onus of ensuring that he is provided

with the right tools, right procedures, safe workplace, safe circumstances and right instructions is

on the "Management". The responsibility of

"enforcing" is again on the "Management". The work

processes need to be embedded with safety.

For maintenance and project works in an operating

Refinery, the location hazards are enormous. Every

Plant and offsite location has different scale of

hazards which are encountered as the job activity

interfaces with them. Then there are a set of hazards

which are inherent to the type of work. Hot work,

excavation, elevation work themselves require

trained and well indoctrinated personnel who not

only are proficient but also know what can go wrong.

Next, the equipment they use must be suitable, safe

and fit for use. In addition, the methodology of

execution must be reviewed to be safe and suitable

to the site. For the Management, the challenge is

how all this is to be "ensured"?

The most effective approach is to have a clearlywritten down "management process". However, this

is only the first step. The crucial part is to ensure

that such process is actually implemented as

envisaged. The personnel need to be made well

versed with it. At the same time, while designing the

management processes, it is necessary to identify

the key requirements to ensure safe decision making

at every level, assurance of their planning and

monitoring during the execution. Based on this

identification, appropriate features should be

incorporated in the management process.

Embedding such features enhances the "preventive"

approach and delegates the responsibilities of

performing the specific tasks to the appropriate

different levels in the Management. Making iteffective in implementation could be quite

challenging. However, with indoctrination and

relentless pursuit it can be fully achieved. For the

context of this narrative, the reference is to the "Work

Permit Manual".

Two such features which should be incorporated in

a "Work Permit Manual" are Job Hazard Analysis

and Escalation Matrix. They can make a significant

contribution to the safety of job execution.

Job Hazard Analysis

Why a job is being started if its safety requirements

are not known? Who is responsible to ensure that

the precautions are known? Who is responsible to

identify them? Who is responsible to disseminate

them? Who is responsible to ensure that they are

actually implemented before the work is started?

Who is responsible to advise the safety requirementsduring the job execution? These are logical

questions for any field execution. "Good Leaders ask

Great questions". Asking these questions in peace

time, with no incident at hand and using the answers

to design appropriate management processes is

helpful. The leadership needs to ensure that

frameworks are created to fulfil the safety

requirements before the job is started.

Experience of various near-misses incidents

would show that the first step of proper

identification of the safety precautions itself could

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be either missing or assumed or were

unstructured in many cases. A proper back-office

engagement to review (with field visit) prior to the

actual execution could be the gap. This is to be done

by the supervisory personnel who will be actually

piloting the execution. Unless there is a framework

in place to facilitate such a review, how can it be

expected that this will happen? The responsibility

to ensure that such framework is in place, that

there is such opportunity of planning and such

planning is compulsorily done for every field job,

rests with the senior management. Creating this

framework is essential. These requirements must be

embedded in the job planning. I have come across

arguments like: that these could cause delay in the

job, these are mere documentation… etc. These are

misplaced. An abnormal event will actually upset

execution schedule apart from handling other

eventualities. Once a job is taken up, there should

be a reasonable assurance that all hazards are

already known and they are addressed. The

execution schedule must include safety

requirements and their planning. Otherwise planning

is incomplete. Re-visit the narrative of the past

incidents and we will find gaps in such processes.

The choice could be between "we control the events"

or "events control us".

The assessment process of the possible hazards

prior to actually executing the job is termed "Job

Hazard Analysis" or JHA. OSHA-3071 gives

guidance on JHA in a simplified manner. The

compulsory "gateway" for carrying out the JHA

should be incorporated in the Work Permit Manual

and should be part of the planning process. This

can be termed as "Planning for Receipt of the Work

Permit" and is by the executor. "OSHA-PSM" standard

mandates that "process conditions" associated with

the work location must be communicated to the

executor of the job. With this input and domain

knowledge, the JHA should be conducted. The

framework provided should address the jobs of

"maintenance" nature as well as "project" nature. This

needs to be separately configured because the

workflow in each case will be slightly different due

to the involvement of different entities of the

organisation.

Across the organisation, it is required that a uniform

methodology for JHA should be followed. This will

ensure certain minimum datum in the approach. That

would mean appropriate templates should be

designed and adopted. Simple templates of

classical JBS can be adopted and converted intothe JHA templates. Making in two steps improves

clarity. In the first step the "Job" should be broken

down in "Activities". In the second, the likely Hazards

associated with the "Activities" should be identified

with control (or mitigation) measure for each. And

based on this the measures should be taken before

the permit is received. These measures may include:

the features to be ensured at the worksite, key

features of work procedures, tool-Box talk content,

monitoring requirements, administrative controls and

other precautions. Knowledge, awareness are good

words but the challenge always is to "bring alive"

the workers at the site to the issues in hand regularly

through the tool Box talk. Configuring administrative

gateways at each stage also helps. The JHA should

help in identifying such inputs which should be

regularly given to the workers.

This part of the process for maintenance can be

represented as:

Fig:1 Part flow chart of Work Permit Receipt planning

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For performing the JHA, the personnel must be

experienced in the field engagement. The overall

Work requirement is divided into smaller "Jobs". And,

each "Job" is to be divided into "Activity". The extent

of detail of this breakdown is experience based and

the extent of hazards of each "job" element should

determine whether it is to be considered as one "job"

element or is required to be broken down into further

"Job" elements. This is a qualitative process and

surely the significant problems will get identified and

thus get their due attention. The templates which

can be used to achieve such breakdown analysis

are shown in Fig-2.

"spiced curry" which is ready for consumption. There

is never a perfect day and the learning curve is to

be continually travelled. A level of proficiency and

confidence of sustainability can be achieved in a

few months. It makes significant contribution to the

job safety management.

The more this process is strengthened, better the

safety at the work place. The experience of JHA

outcomes is also useful for improving the Work

Procedures of field execution. Over a period of time

which is no more than a year, there will be a

perceptible upward shift in the performance datum.

The personnel will learn how to do JHA in advance

and how to plan safe execution. This will be by the

same personnel who would have been sceptical of

its practicality at the time of its inception! To judgethe benefits, organisation should have what it takes

to perceive and recognise "prevention".

Escalation Matrix

The authorisation to "issue" the work permit in a

Petroleum Refinery is normally with the "Plant Shift

in-Charge" who is a frontline officer. There are

arrangements in some companies which require him

to take concurrence of the Shift Manager in case ofHot work permits.

Questions do remain whether we are differentiating

between the Hazards of a Water treatment plant and

the Hazards of e.g. a Hydrogen Plant, hazards of a

Boiler House & Hazards of LPG storage, hazards of

a Class A product tank and Hazards of a Class C or

a Water storage tank. Similarly are we distinguishing

between the hazards of various operational-

situations e,g. whether a normal operating plant, a

Plant under turnaround Or a Plant undercommissioning can be treated same? A Class- A

product tank, can authorisation for a spark causing

work be given by a Shift incharge? Should we not

distinguish between them? In all these cases, will

the shift in-charge be the issuer without any

additional pre-authorisation?

Administratively it is more appropriate to configure

additional pre-authorisation layers based on the

perceived scale of hazards. This layer of pre-

authorisation is required to "enforce" the adequatedue-diligence in planning based on the scale of the

hazards.

Fig-2: Templates for JHA

A question always crops up in organisational

workflow as to whether it is possible to do this for

every job? The answer to this question is the question

"Is it appropriate to start a job without knowing the

hazards and the mitigation measures?" And answer

to this question cannot be "Yes". Safety gaps are

not tolerable. The question only is how we

achieve this.

Methodologies can be adopted to make this simple,

e.g. even though no two jobs are the same, but there

are areas of similarly. It is this part which should be

used. As more and more JHA's are done, they

become a good information bank. This should be

stored in a properly indexed manner. This is the

"boiled vegetable" and should be made accessible

to all the personnel. And for each job these should

be the starting point and can be used for carryingout the customised JHA for that specific job.

Experienced personnel can easily achieve this

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Similarly, is the management permitting more than

one concurrent job at a location? That too when they

are hot jobs. And when it is so, are the scaled up

hazards addressed? What is that systemic

arrangement which prevents lower echelons from

taking such decision without the knowledge of senior

management? Is there a written down arrangementand which makes the personnel aware as to what

they can do and what they cannot? How high we go

in such layers of concurrence is left to the

management. But existence of such layers is

essential. In Safety, the good old principle is "No

need to kill a fly with a hammer, fly swatter is enough.

Don't try to drive a nail with a fly swatter, it won't go

in. Must use hammer". Balance needs to be

maintained while at the same time distinguish

between a lamb and a lion.

An "Escalation Matrix" can be inserted in the "Work

Permit Manual" to address this requirement. While

preparing this, there are three variables which can

be considered. These are:

Plant Group in which a Plant should be

considered. The Plants can be grouped based

on consideration of High Pressure, Hydrogen,

Utilities, High inventory of flammable material

etc.

Operational situation whether normal operation,commissioning, decommissioning, turnaround,

non-turnaround shutdown, partial shutdown.

Type of Permit whether cold work, hot work,

confined space entry, excavation etc.

Based on these variables, the Escalation matrix can

be prepared. A truncated example of such

Escalation Matrix is shown below :

Fig-3 Sample Escalation Matrix

A switchover from an open to an Escalation matrix

based system needs to be done with across the

board awareness and training. The personnel need

to be trained and feedback based iterative

improvements are required to be made over a period

of time. A gradual stabilisation once achieved, bringsabout a number of benefits. See Box.

The objective of such Work Permit Escalation Matrix

can be summarised as:

1. To ensure adequate review of the Safety

requirements

before a

h i g h e r

h a z a r d

work-front is

engaged.

2. To control the number of activities in high hazard area

and during high risk operations to minimise risk.

In a big facility, such a matrix could appear complex

for regular reference. This can be overcome by a

clear reference block diagram and refresher training.

How complex or simple it should be, is a decision

by the management. But its presence enhances

control and improves safety management.

These two features of JHA and Escalation Matrix can

add significant systemic safety in the Work Permit

management. However, like every other

management system, the implementation is the key.

In small steps, with training programs,

refreshers, feedbacks and iterative

improvements, full buy-in can be

achieved.

These will contribute to better control

on the activity, improved awareness of

hazards among the personnel and

establish a systemic framework to

control the hazards in job execution.

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Improving Corrosion

Assessment and Monitoring

Jaideep BhattacharyaConsultant, Advanced Solutions

Honeywell Process Solutions

Ulhas DeshpandeBusiness Leader, Advanced SolutionsHoneywell Process Solutions

Process industries are under increasing

pressure for improving margins and

reducing costs in the current economic

scenario. A way to achieve this has been investingand deploying certain productivity enhancement

tools and practices across various business

functions. Though these tools and practices help

operating companies cut costs to some extent, they

fail to take into account few of the most critical and

complex problems that if understood and handled

well can help the plant to reduce operating and

capital expenditure to a great extent.

Corrosion is one of the challenging problems in the

industry often resulting in losses to the tune of billions

of dollars. Reports around the world have confirmed

that some oil companies had their pipeline ruptured

due to corrosion and that oil spillages have resulted

in large scale ecological damage. The control of

corrosion in the oil field can be a complex problem

requiring detailed analysis and a thorough

understanding of the range of conditions expected

during the life of the system prior to the development

of a corrosion management plan.

Corrosion is one of the most significant issues

affecting asset integrity management in the oil and

gas, refining and petrochemical industries today.

Over the last few decades, these industries have

recognized the magnitude of corrosion and the

challenges that exist in the ability to detect and

mitigate its consequences.

To be specific, aged and water-absorbent insulation

is most often the culprit behind corrosion because

it is installed on carbon steel (CS) surfaces, which

are not effectively protected. While small diameter

piping has historically been the most vulnerable tocorrosion, heat exchangers, pressure vessels and

storage tanks also have been affected. This has led

to a substantial acceptance of new direct

assessment and pipeline integrity focused work by

the industry.

Current Challenges

The primary assumption of most oil and gas

operators is that corrosion does not exist in their

pipelines. This is a difficult contention to corroborate

without a detailed assessment and evaluation. On

the contrary, internal corrosion is very likely to exist

in measurable quantities where there is a presence

of liquid water and acid gases.

Furthermore, the actual areas that are affected by

corrosion in dry gas pipelines are small compared

to the lengths of pipeline transporting gas, makingit difficult to locate and mitigate corrosion. Using the

correct corrosion solving techniques, it provides the

operator with tools to inspect resources where

needed and helps make integrity assessments on

the entire pipeline.

Detecting Corrosion

The detection of existing corrosion is normally

attempted through various inspection techniques,

some of which focus on detecting and measuring

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wall loss while others merely focus on detecting wet

insulation. Industry standards and guidelines such

as NACE SP0198, EFC 55, and API RP 580 have

attempted to provide more comprehensive systems

approaches and risk-based strategies to address

corrosion. These are largely reactive and qualitativemeasures leading to broad categorization of assets

for susceptibility ranking, which may not be very

useful in quantifying and mitigating corrosion before

the damage occurs.

Oil field corrosion challenges are very common. Fluid

characteristics change overtime resulting in systems

becoming less responsive to established corrosion.

Within the sphere of corrosion control and prevention

in the oil and gas industry, there are technical options

such as cathodic and anodic protection, material

selection, chemical dosing and application of

internal and external coatings. It is widely recognized

within the oil and gas industry that effective

management of corrosion will continue towards the

maintenance of asset integrity and achieve

optimization of mitigation, monitoring and inspection

costs.

Ideal Solution

Corrosion assessment has been widely

implemented across the oil and gas industry by

many plant operators. As per feedback from some

plants, the process has been found to be highly

effective for evaluating integrity of the plant process

with respect to the corrosion threat. The overall effort

required to implement any kind of internal or externalcorrosion is not significantly more or less than any

other integrity assessment processes. A corrosion

assessment solution should provide a robust

framework for performing cost-effective integrity

assessments. Advanced technology based flow and

corrosion models vastly enhance this process to

avoid the possibility of unnecessary digging or

random inspection at the site of corrosion.

The ideal solution should incorporate four broad

technologies: Multiphase flow modelling, corrosion

prediction, current corrosion assessment

methodology and real-time corrosion monitoring.

These types of technologies are capable of not only

determining propensity for water retention but also

the corrosivity of the environment in the presence of

the aqueous medium for the identified critical

segment.

This type of system integrates a number of key

functionalities including water-phase behavior

determination, pH computation, corrosion modeling,

flow modelling and comprehensive pipelineanalyses based on lab and field data.

Real-time corrosion measurement technology can

collect corrosion rate data every minute and save

the data on the device where it will be available for

retrieval during operator rounds. If available, this

corrosion data could be routed through existing

wireless or radio communications as well. Locating

the corrosion monitors at key points along an oil and

gas plant can provide continuous reliable information

to the operator.

Conclusion

Corrosion is a phenomenon that requires

interdisciplinary concepts that incorporate

metallurgy and materials science. For an industry

like oil and gas, which spends billions of dollars for

treatment costs every year, it is worth noting that the

damage caused by corrosion is not only at the plant

level but also other areas like building construction,

transportation, production, manufacturing and so on.

Thus corrosion is an industry wide problem, which

should be addressed proactively by respective

vertical markets.

7/21/2019 Apr June15 (1)



Pre Reformer Catalyst for

Hydrogen Plant

Chetan Bhola Asst. Manager - BU Refinery Catalysts

Süd-Chemie India Private Limited

Sanjeev MehtaGeneral Manager - BU Syngas CatalystsSüd-Chemie India Private Limited

Hydrogen is produced in large quantities

both as a principal product and as a by-

product. Globally, an estimated 76.6-78

million metric tons of hydrogen is expected to be

consumed in 2018. The largest volumes of on

purpose or merchant hydrogen are consumed at

refineries, ammonia and methanol production.

(Source: IHS)'

Hydrogen for Hydro processing to meet:

Transportation fuel specification and stringent

environmental regulations

Increased use of sour and heavier crudes which

generate less by-product hydrogen during crude

processing

Hydrogen Production by SMR Route

Most hydrogen produced in the Refineries is via

steam-methane reforming (SMR) where in

hydrocarbon reforms with steam under pressure in

the presence of a catalyst to produce hydrogen and

carbon oxides. Subsequently, it involves water gas

shift reaction and in final process step, pressure

swing adsorption, to remove all impurities leaving

essentially pure hydrogen.

Benefits of Pre Reforming

Pre-reforming is the term that has been applied to

the low temperature steam-reforming of

hydrocarbons in a simple fixed bed adiabatic

reactor filled with Highly Active Catalyst. The

Pre-Reformer utilises the heat content of the

feed stream to drive the steam-reforming

reaction and resulting in a equilibrium gas mixture

containing hydrogen, carbon oxides, methane and

steam.

Counting on Life of Pre Reformer

Catalyst

Life of a Pre Reformer Catalyst majorly depends on

designed Liquid Hourly Space Velocity (LHSV) &

Sulphur poisoning (Other poisons include alkali

metals, arsenic, & silica).

Using Deep Desulphurization Catalyst ActiSorb S6 which removes sulphur to ppb level can enhance

life of Pre Reformer Catalyst by up to 20%.

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Can be Steamed for Carbon & Sulphur removal

and can be in-situ re-reduced for activation.

High activity and stability at high liquid hourly

space velocity (LHSV).

High thermal stability at elevated temperature

Lower differential pressure drop due to optimize

catalyst size and its robust structure.

Here below, we summarise two performance case

studies of ReforMax 100 pre-reforming catalyst:

Case Study 1 : Outstanding

Performance at very High Space

Velocity

At one of the Hydrogen Plant in Indian Refineries

with design feedstock as Straight Run C5-140

Naphtha & FCC Gasoline has two Pre Reformer

reactors (one online + one standby) operating at

very high LHSV of 5.5 hr-1. ReforMax 100 RS was

placed in service in June, 2014 and is currently in

operation about 12 months and expected to achieve

life of 24 months against the guaranteed life of

12 months. Present steep temperature profile

indicates rapid conversion to equilibrium presented

as below with progression caused by gradual

poisoning and can be extrapolated for accurate

prediction of residual life.

Guaranteed Life, months 12

Achieved Life, months >11

Expected Life, months >24

Due to the growing demand for Hydrogen,

application of pre-reformer has gained universal

acceptance in SMR Plants due to following key

drivers:

Feed stock flexibility since various feeds like

Naphtha/ LPG/Natural Gas/Refinery off gasescan be used.

Due to absence of higher hydrocarbons C2+,

it allows higher inlet temperature (~650°C) at

Reformer Inlet leading to reduction in radiant

heat requirement by 5-15% at Reformer Section.

Provides fuel savings against reduced export

steam, hence overall improved net thermal

efficiency of hydrogen production.

Reduces downtime due to quick start up sincecatalyst is supplied in Pre Reduced Form.

No special start up (like reduction of Reformer

Catalyst) & ease of overall plant operation and

eliminating problems (Potash Leaching)

associated with direct reforming process.

Enhanced lifetime of Steam Reformer and Shift

Catalysts as sulphur and other poisons are

arrested by pre reforming catalyst.

Süd-Chemie offers ReforMax® 100

ReforMax® 100 pre-

reforming catalysts are highly

respected amongst users and

installed in several operating

hydrogen, ammonia and

methanol plants worldwide. It

has demonstrated continual

robust operation at low steam to carbon ratios andwith various feed stocks over many years and has

proven its supremacy and potential to withstand

plant upsets and trips. ReforMax 100 series are

delivered in Pre Reduced & Stabilised form which

ensures a quick and smooth start-up.

Key advantages of ReforMax® 100

Exposure of operation with feeds like as

Naphtha (Coker Naphtha, SRN, HydrocrackerNaphtha, FCC Gasoline)/ LPG, Natural Gas and

Refinery off gases.

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Case Study 2 : Thermal Stability at

High Temperature

During Start Up activities, Naphtha passed over to

Pre Reformer Catalyst in absence of steam and bed

temperatures went to ~700°C and remained above

recommended limit (520°C) for more than 8 hours.

Post incident, catalyst was steamed for 4 hours and

re-reduced by maintaining S/H ratio as 8-10 mol/

mol to remove coke deposition on the catalyst.

As per the temperature profiles, before and after the

incident, there was no visible activity loss and

currently operating with excellent performance.

New Shape Development

ReforMax 100 is now available

in "5 Hole Rings" shape which

combines outstanding activity

of existing catalyst with lower

pressure drop.

Catalyst Size, mm Shape Relative, Dp

4.7 X 4.7 Tablets 1.00

11 X 5 X 2 5 Hole Rings 0.38

Conclusion with User's Interface

At present, ReforMax 100 is ho ld ing 59% of

installed market share in pre-reformer across

Hydrogen Units in Indian Refineries and outshines

with its performance at various operating conditions

like S/C ratio, Feed stocks, LHSV & poisoning

rates.

Most people have never learned that one of the main aims in life is to enjoy it.

“

“

~Samuel Butler

7/21/2019 Apr June15 (1)



Debasis BhattacharyyaDy. General Manager (RT-I)


Satheesh V.K.Sr. Research ManagerIndianOil (R&D Centre)

B.V. Hariprasad GuptaResearch Manager


G. SaiduluResearch Manager


Optimisation of Visbreaker Unit

Owing to deterioration of average quality ofcrude and declining demand of fuel oil,

there is an increasing pressure for

improving the Visbreaker unit operation for

minimizing the fuel oil production. The major

component of fuel oil in a refinery is either Visbroken

tar (VB tar) or heavier fractions from Delayed coker

and FCC. In order to meet the specifications, various

cutter stocks like Decant oil, Heavy gas oil, Light

gas oil, Kerosene, etc. are added. The mostfrequently faced problems associated with fuel oils

are its 'stability' and its 'incompatibility' with the cutter-

stocks The stability of the fuel oil is mainly dependent

on the composition of VB tar with respect to

asphaltene, resin, aromatics, paraffin, etc., which in

turn depends on the properties of resid feed as well

as Visbreaker unit severity

Visbreaking is a mild thermal cracking of heavy

petroleum residues. The basic objective of this

process is to reduce the viscosity of the residue so

that amount of valuable cutter stock requirement and

also the fuel oil production is minimized. The main

operating variables in Visbreaking are temperature

and residence time. Earlier, the combination of high

temperature and low residence time was adopted

in coil Visbreaking. In the concept of soaker

Visbreaking, similar conversion is obtained at

relatively lower temperature but at higher residence

time resulting in energy savings. An increase in yields

of distillates and gaseous hydrocarbons productsand viscosity cutting ratio could be achieved through

increase in operating severity. However, beyond

certain severity / unit conversion, VB tar becomes

unstable and also there will be excessive coke

formation both in coil and soaker drum reducing the

cycle length.

The present paper focuses on the importance of the

VB tar stability and the compatibility of fuel oil

components for optimization of Visbreaker unitconversion and evaluation of the same through pilot

plant study.

Stability of Heavy Oils

The heavy oil can be considered as colloidal solution

of oil (such as saturates, aromatics), resins and

asphaltenes. The stability of the heavy oil is governed

by the concentration of these components. Among

these components, asphaltene and resin play the

most important role in stability of the system. The

stability of a dispersion system in colloid science

refers to the resistance of the particles to

aggregation. The degree of this resistance is a

measure of stability. The behavior of asphaltene in

oil depends on the attractive and repulsive forces

between adjacent particles. The interactions involved

include van der Waals forces, steric effects and

possibly electric double layer forces arising from the

charge at the interfaces.

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one drop of the sample is placed on

Chromatographic paper at 100 C for 1 hr. Based on

the rings formed, the fuel oil is rated as No.1, 2, 3, 4

and 5. If the spot is homogeneous (no inner ring) or

poorly defined inner ring, then the sample is

considered as compatible. If there is any definedring or dark solid area at the center, the sample is

incompatible. Potential Sediment Test (IP 390) is

another test usually carried out to check the storage

stability of fuel oil. The total sediment is determined

by ageing a sample of residual fuel for 24 hr at

100 C under prescribed conditions.

Experimental

Experiments were conducted in a Visbreaker pilot

plant having soaker configuration using short residue

as the feedstock. The characterization of feedstock

is given in Table-1. In the pilot plant, feed is gradually

heated in an electrical furnace to the desired coil

outlet temperature (COT). Turbulizing water is added

to the coil in a location corresponding to the entry of

radiation zone in commercial furnace. The water flow

rate was kept 1 wt% of feed rate in all the runs.

Heated feed is then fed to the bottom of the

Visbreaker reactor (equivalent to a soaker drum in

commercial plant) through a transfer line whose skin

temperature is maintained the same as that of

desired COT to minimize the heat loss. There is one

backpressure control valve (BPCV) at the outlet of

soaker, which is operated to control the soaker outlet

pressure (SOP). The reactor products are separated

in batch separators into lighter and heavier fractions.The lighter liquid fraction is separated from the non-

condensable product employing a water-cooled

heat exchanger and a cold catch pot. The gas flow

is measured using wet test meter after removal of

H2S through caustic and water scrubbers.

Asphaltenes having complex structures involving

carbon, hydrogen, nitrogen, oxygen and sulfur are

essentially condensed aromatic nuclei associated

with alicyclic groups. These fractions are often

surrounded by resins and heavy aromatics, which

are considered to improve dispersion stability. In anyprocess, if the concentration of asphaltenes

increases while that of resin decreases, beyond

certain point of asphaltene-resin concentration,

asphaltene gets precipitated out of the system

making the resultant mixture as unstable. The

'stability' of VB tar or fuel oil is normally expressed in

terms of 'peptization value' (P-value) and

'compatibility' of fuel oil is determined by 'spot test'.

P-Value

P-value is the method to determine the state of

peptization of asphaltenes in heavy oil. Asphaltenes

are defined as n-heptane insoluble and aromatic

soluble. So, peptization of asphaltene can be

affected by the addition of paraffin to the heavy oil.

In this method, n-cetane is considered as the paraffin

oil to be added to the heavy oil. The p-value of a

heavy oil sample is determined using the relation,

p = 1 + X, where X is the maximum dilution of the

sample with n-cetane at which the asphaltenes are

just not flocculated, which is expressed as the

number of milliliters of n-cetane used for the dilution

of one gram of the sample. If one gram of sample

takes less than 0.3 ml of n-cetane, i.e. p-value

< 1.3, the sample is considered to be 'unstable'.

Spot Test (ASTM D 4740)

Spot test actually indicates the compatibility among

the different streams added into the fuel oil and

normally carried out using the finished fuel oil

product and not the VB tar alone. In this method,

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Table-1: Characterization of vacuum residue feedstock

Density @ 15oC, gm/cc 1.0316

CCR, wt% 20.78

S, wt% 5.38

Viscosity, cSt @135oC 202

Aromatics, wt% 56

Saturates, wt% 44

Asphaltenes, wt% 6.57

The main products from the pilot plant are gas

(C5-), light oil (C5-180 0C) and Heavy oil (180 0C+),

which are characterized using chromatography. The

material balance of all the runs were calculated and

only the experiments having material balance of

(100 + 3)% have been considered. The stability of

VB tar was measured in terms of peptization value.

Tests were conducted with varying quantity of

different cutter stocks for getting fuel oil of required

viscosity and flash point. After addition of these

cutter stocks, the compatibility of fuel oil was also

measured using spot test.

Results & Discussions

For experimental study, it is important to simulate

the pilot plant with the operation of the targeted

commercial unit. Accordingly, the base case data

as well as the product samples from the commercial

Visbreaking unit was collected. The liquid products

were analyzed for boiling point distribution and the

yield pattern was calculated considering the product

overlap. Experiments were conducted at different

temperatures (around the COT normally maintained

in the commercial unit) and 10 kg/cm2(g) SOP.

The yields of individual products were plotted against

3800C- conversion and the yield pattern was found

out as base conversion. Here, 3800C- conversion is

defined as sum of the yields of the products boiling

up to 3800C. The product yield data along with theimportant process variables of commercial and pilot

plant are compared in Table-2. It is seen that pilot

plant results are closely simulating the commercial

operation.

Table-2: Base case simulation of the pilot plant

Base Case Pilot Plant

3800C- Conversion, wt% 17.6 17.6

COT, 0C 444 445

SIT, 0C - 407

SOP, Kg/cm2 10 10

Product yields, wt%

Gas (C5 -) 1.1 1.6

VB Naphtha (C5 -180 0C) 5.2 5.5

VB Gas oil (180 -3800

C) 11.2 10.5

VB Tar (3800 C+) 82.4 82.4

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In pilot plant, after the feed furnace, the transfer line

as well as soaker drum is equipped with electrical

heaters since adiabatic operation is difficult. Since

major amount of reactions take place in the soaker

drum, soaker internal temperature (SIT) could be

considered as realistic yardstick of the reactionseverity. The 3800C- conversion is plotted against

SIT in Figure-1, from which it is seen that the

conversion increases with increase in SIT. In

commercial Visbreaker unit, COT is considered as

the main severity parameter. In order to find out the

COT from the pilot study, a correlation between COT

and SIT was established which is shown inFigure-2.

Figure-3 shows change in VB tar viscosity with

increasing conversion. It is seen that the viscosity of

VB tar decreases with increase in conversion. The

Analysis of VB tar corresponding to di fferent

conversions are summarized in Table-3. Since the

base case simulation of the commercial unit is at

SIT of 407oC, two sets of experiments were

conducted at this temperature to check the

repeatability of the result. It is evident from Table-3

that within the conversion range tested, the saturates

(paraffins & naphthenes) concentration in the VB tar

is reducing with increase in conversion while that of

the aromatics is increasing. Thermal cracking

reactions enable dissociation of various carbon and

hydrogen bonds to form free radical intermediates.

These free radicals then enter into other reactions

and thus result into wide spectrum of products. For

a given molecular weight, the ease of cracking of

different type of hydrocarbons, follows the order:

parrafins > olefins> naphthenes > aromatics.

Among the same type of hydrocarbons, the greater

Figure-1: Conversion vs Soaker internal

TemperatureFigure-2: COT vs SIT

the molecular weight, the higher is the crackability.

Therefore, as cracking proceeds, the concentration

of paraffins and naphthenes will reduce while that

of the aromatics will likely to build up. This is the

primary reason for reduction in viscosity of the VB

tar with increase in conversion. But this phenomenon

does not extend all along the conversion curve.

Figure-3: Viscosity of VB tar @ 1000C vs conversion

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Table-3: Properties of VB tar at different unit conversions

Expt. No. 1 2 3 4

SIT, C 407 407 415 424

Conversion, wt% 14.42 13.55 24.67 32.5

Sulfur, wt% 5.17 5.12 5.36 5.43

Aromatics, wt% 58.3 56.4 62.1 63.7

Saturates, wt% 41.7 43.6 37.9 36.3

CCR, wt% 23.8 23.3 25.3 26.5

In Figure-4, the asphaltene content of the VB tar

product is plotted against the conversion. Unlike theviscosity, the asphaltene in VB tar is increasing with

increase in conversion. When heavy oil is thermally

processed, side chains of asphaltenes, resin and

heavy aromatics will get chopped off and long chain

paraffins will be cracked into lighter one or olefins.

This will lead to polarization of the molecules and

polarized resins will immediately polymerize to form

more asphaltenes. Beyond certain conversion or

reaction severity, the decrease in viscosity due to

decrease of paraffin content will be lower than theincrease in viscosity resulted from formation of

asphaltene. So the reduction of viscosity of VB tar is

not a linear function of conversion in Visbreaking

process and viscosity reversal will occur beyond a

particular conversion. Further, if the severity is higher

than this, the asphaltenes will get precipitate as liquid

crystalline phase (or carbonaceous mesophases)

and quickly polymerized to form coke.

Figure-4: Asphaltene vs Conversion

As mentioned earlier, P-value is the measure of the

state of peptization of asphaltenes in heavy oil. With

increasing operation severity, the concentration of

asphaltenes increases while that of resin decreases

resulting in the precipitation of asphaltenes. This

precipitation phenomenon is not a reversible one.So even if some aromatic rich stream is added to

the unstable VB tar, stability cannot be regained

back. Therefore, in a commercial Visbreaker, it is

very much important to monitor the P-value of VB

tar while optimization of the unit conversion. The unit

conversion should never exceed the threshold

conversion at which the VB tar P-value is less than

1.3. Owing to such significance, the P-value of theVB tar samples was measured which is reported in

the Table-4.

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Table-4: Stability tests of VB tar at different unit conversions

Expt. No. 1 2 3 4

P-value >1.5 >1.5 1.2 1.0

Spot test No.1 No.1 No.4 No.4

It is seen that at 13.5 to 14.5 wt% conversion, the

P-value of the VB tar is more than 1.5 indicating that

the corresponding VB tar sample is stable. While

the VB tar samples corresponding to 24.67 and

32.5 % conversions are found to be unstable. In such

case, it is important to find out the optimum

conversion and always operate the unit below this.

Another important point is to note that in a stable

system, asphaltene gets peptized in the oily phase

comprising paraffins and light aromatics. As soon

as this peptized condition is disturbed, asphaltene

gets precipitated in the oily phase and causes the

'instability' of the system. Therefore, the absolute

P-value is also a guiding parameter for selecting the

cutter stock components.

The properties and the quantity of the cutter stocks

added to the VB tar have significant role on finished

fuel oil properties. In the commercial unit, Decant

oil, Heavy gas oil and Kerosene are normally used

as the cutter stocks for meeting the fuel oil

specifications. The same cutter stocks were added

to the VB tar samples generated in the pilot plant

following the philosophy as adopted in the

commercial unit to meet the specifications ofviscosity and flash point (40 cSt @ 100 C and 66 C

respectively). The compatibility of the components

in fuel oil blend prepared as above was checked

through spot test. The result of the spot test is shown

in Table-4. It is seen that spot test of the fuel oil blend

corresponding to stable VB tar as confirmed through

P-value measurement pass while the others fail.

Therefore, if VB tar sample is itself unstable, the

corresponding fuel oil blend is going to unstable

since it is quite difficult to bring back the precipitated

asphaltene into the solution even by addition of

aromatic rich stream. However, if VB tar sample is

stable, excess of paraffinic cutter stock beyond the

threshold value can make the final fuel oil unstable.

Conclusions

Under the scenario of declining refining profit margin,

optimal operation of existing Visbreaking unit is of

paramount importance. However, there is a tradeoff

between the Visbreaker unit conversion and stability

of VB tar product. There is an optimum operation

severity for a given hardware dimension of soaker

drum beyond which the VB tar becomes unstable

followed by viscosity reversal phenomena.

P-value of VB tar is the governing parameter for

adjusting the operation severity of a given Visbreaker

unit. Once, the stable VB tar is produced while

keeping the conversion at the optimum level, the

quality and quantity of the cutter stocks to be added

to meet the final specifications of the fuel oil are also

important. The selection of the cutter stocks

becomes more critical while operating theVisbreaker unit close to the optimum level. Spot test

is the guiding tool for assessing the compatibility

between the base VB tar and the cutter stock

components. While adopting the philosophy as

outlined above, prior pilot plant study backed by

proper simulation of the commercial plant operation

comes handy in deciding the optimal conversion

minimizing the risk of producing unstable fuel oil.

7/21/2019 Apr June15 (1)



Mukesh K. ShivhareEngineer

Engineers India Ltd. (R&D Centre)

Shailendra KumarDeputy Manager

Engineers India Ltd.(R&D Centre)

Compressor Anti Surge System Trouble Shooting

R. V. SreevidyaDeputy Manager


P. Narendra KumarDeputy Manager


S. R. SinghDeputy General Manager

Engineers India Limited(R&D Centre)

Centrifugal compressors are relatively

trouble free, dependable gas movers.

Almost any gas can be compressed by

these machines, and their extensive size and

pressure ranges made modern process plants and

efficient production of bulk chemicals possible in

many instances. Centrifugal compressors are vital

units and are often considered as heart of many

industrial processes. Often, these equipments are

critical to the operation of the plant, yet they are

seldom installed with a spare unit. Surging

represents a major threat to compressors and its

prevention is an important process control problem

in these environments as surging can result in costly

downtime and mechanical damage to compressors.

Compressor design is generally based on a set ofoperating points predicted from steady state heat

and material balance. However, compressor system

usually experiences very rapid transient operations

when it is in service such as start up, shutdown, load

fluctuation, equipment failure etc. This inherent

dynamic nature may not be sufficiently addressed

by a steady state simulation model and hence

dynamic simulation is increasingly applied for

addressing compressor systems such as surge

protection, stability during load fluctuations, etc.

Dynamic simulation is an engineering tool

to evaluate process design and is very useful in

design of compressor surge protection, evaluation

of operation envelop, field support and

troubleshooting.

Dynamic simulation involves solving of set of

differential and algebraic equations and

implementing this model on a computer to describethe time- dependent behavior of a process. The

developed model can then be used for

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Evaluation of operability of a proposed system

and necessary modification before actual

implementation

Testing of wide range of alternative control

schemes

Testing of startup procedure

Sizing and stroke time of recycle valve or othercontrol valves can be checked for all operating

conditions

Determination of initial controller gain and reset

settings. Scaling of transmitters and computing

instruments can be also checked.

Overall arrangement of exchangers, check

valves, vents etc. can be evaluated to maximize

controllability.

System performance during emergency trip or

effects of equipment failure or operator error can

be evaluated.

The aim of the work presented in this paper is to

show the application of dynamic simulation in

designing control system and verifying operability

of a plant. A case study for the adequacy checking

of the existing anti-surge valve of multistage

horizontal centrifugal propane refrigeration

compressor is discussed. In this study, dynamic

simulation is used to investigate the performanceof compressor during various process upsets to

analyze the behavior of compressor anti-surge

system and provide recommendations on the

feasibility of existing protection system.

Surge Phenomenon andCompressor Control

Every centrifugal or axial compressor has (at a given

rotational speed and inlet conditions) a characteristic

combination of maximum head and minimum flow

beyond which it will surge. Preventing this damaging

phenomenon is one of the most important tasks of

a compressor control system. The most common

way to prevent surge is to recycle or blow off a portionof the flow to keep the compressor away from its

surge limit. Unfortunately, such recycling extracts an

economic penalty due to the cost of compressing

this extra flow. So the control system must be able

to determine accurately how close the compressor

is to surging so it can maintain an adequate-but not

excessive-recycle flow rate. This task is complicated

by the fact that the surge limit, in general, is not fixed

with respect to a single variable such as pressure

ratio or the pressure drop across a flowmeter.

Instead, it is a complex function that also depends

on gas composition, suction temperature and

pressure, rotational speed, and guide vane angle.

An understanding of the principles of integrated

control and protection systems is thus extremely

important to operate turbo compressors.

Preventing Surge

Figure 1: compressor surge line on compressorperformance map

(a) (b)Figure 2: (a) compressor surge control system layout(b) compressor operating window for safe operation

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The obvious way to prevent surge is to decrease

network resistance whenever the operating point

moves too close to the surge limit line. This is

accomplished by opening an anti-surge valve to

recycle or discharge a portion of the total flow. The

chief drawback to this approach is the efficiencypenalty that it entails-the energy that was used to

compress the recycled gas goes to waste. Thus,

the control system should be tailored to open the

anti-surge valve only when-and only as far as

is-necessary. On the other hand, if we do not provide

adequate protection against surge, we risk

prohibitive repair and downtime costs. Therefore,

accurate and dependable methods of determining

the surge limit are required. Anti-surge control entailsmeasuring the distance between this surge limit and

the operating point and then maintaining an

adequate margin of safety without sacrificing

efficiency or stability. The solution is to maintain the

operating point on or to the right of a line known as

the surge control line (SCL; see Figure- 2b). The

distance between the surge control and surge limit

lines (the margin of safety) should be just enoughto allow the chosen control algorithms to counteract

an impending surge. Whenever the operating point

moves into the surge control zone (i.e., to the left of

the SCL), the anti-surge valve must be opened fast

enough to keep the operating point from reaching

the surge limit line and far enough to return it to the

surge control line. On the other hand, when the

operating point moves to the right of the SCL, the

anti-surge valve should be closed as far as possiblewithout moving the operating point into the surge

control zone.

Figure 3: Schematic diagram of Propane Refrigeration Process in LNG industry

turbine driven compressor is more than 29MW at a

speed of about 3000 rpm.

The propane from the compressor discharge is

cooled, and then condensed against sea water. An

inventory of liquid propane is held in an accumulator.The liquid propane flows from accumulator to the

shell and tube heat exchangers at three propane

Case study

Propane Refrigeration System

This system, schematically shown Figure 3 provides

secondary refrigeration to the LNG process.

Propane refrigerant is used to cool the natural gas

feed and condense the primary multi component

refrigerant. Refrigeration is provided at three

pressures (temperature levels). The compressor isa single casing 3 stage machine with two side

streams. Design power consumption of the steam

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pressure levels. The propane evaporated in these

exchangers then flows back to the compressor.

Compressor surge protection is provided by recycle

of warm gas from the desuperheater exit to the

suction drum of each section.

This compressor system combines a compressor

in which the dynamic response of one section is

directly affected by the responses of other sections

with a process which has large volumes and a large

liquid inventory. A LNG train tripped multiple times

due to over speed of propane refrigeration

compressor during summer. Anti-surge valves that

are provided in all recycle lines were initially

suspected to be inadequate and undersized. There

is a concern that process upsets or equipment

failures might impose conditions in which surge

could not be prevented. This dynamic simulation

study was proposed to analyze compressor anti-

surge control system and the adequacy of the surge

control valve to protect the compressor.

Dynamic Simulation Model andObjectives

Simulation Model

A schematic of the dynamic simulation model set

up using a commercial dynamic simulator to

Figure 4: Dynamic model of Propane Refrigeration

describe the various elements of the compression

recycle loops is presented in Figure 4. The entire

system was broken down into the compressor,

valves, and a number of volumes for associated flash

separators, knockout drums, desuperheater,

accumulator and the gas-cooler. The parameters of

every element were determined from the data

provided by the equipment manufacturers and the

gas plant engineers. In the few cases where certain

data were not available, values were assumed based

on field experience and common-sense engineering

practice.

Model Objectives

The objective of the model is to verify the

adequacy of existing anti-surge valves and

remove any bottlenecks so that increase of the flow

of propane and decrease of the discharge

pressure of propane compressor can be

maintained and prevent the compressor to go in to

surge conditions. Several test scenarios have been

performed using the dynamic model, two of these

are being discussed in detail in the following

section:

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The reduction of propane vapor flow decreased the

surge margin and surge controller moved the

compressor away from surge region by taking

appropriate action and increasing the flow across

the compressor. The existing Anti-surge valve CV's

are found sufficient to keep the compressor out of

surge during the scenario.

Figure 5:

(a) Response of percentage above surge of

1st, 2nd and 3rd stage

(b) Response of Anti-surge valves of 1st, 2nd and

3rd stage

Loss of cooling in propane cooler

and propane condenser

Heat duties of propane cooler and condenser at

compressor discharge are reduced to 40% due to

decrease of cooling water flow rate within

30 minutes.

Figure 6: (a) Loss of duty in desuperheater

(b) Response of percentage above surge of

1st, 2nd and 3rd stage

Test scenarios and results

Train Trip or propane supply to the separator is

reduced:

The compressor propane flow rate is reduced to 60

% of normal operating condition due to the trainproduction reduction and hence the propane flow

to all the exchangers(low, medium and high level)

are dropped within 30 minutes.

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(c) Response of Anti-surge valves of 1st, 2nd and

3rd stage

The reduction of cooling duty in propane

desuperheater by 60 % of the normal value created

two phase flow of propane in the circuit from the

downstream of condenser followed by the increasein the discharge temperature of Compressor. Since

the overall vapor load in the circuit is increasing

because of loss of cooling in the propane

desuperheater, the compressor would be at the risk

of high discharge temperature trip. The anti-surge

valves are able to keep the compressor out of surge

at the start of disturbance, however after the

completion of disturbance, and due to the combined

effects of pressures and temperatures in the circuits,the machine would be at the risk of high discharge

temperature trip.

Conclusion

Stable and safe compressor operation is an

essential component in providing product streams

of a plant. The importance of surge and its prevention

is discussed. The application of dynamic simulation

in verifying the operability of propane refrigerant

compressor in safe zone without surging under

various possible upsets is studied. Though existing

anti-surge valves are found to be adequate for the

scenarios that are analyzed, the third stage anti-

surge valve in case of train trip reaches up to 80 %

opening and it is recommended to replace third

stage anti-surge valve to allow some safety margin.

The study also confirmed the possibility of

compressor trips due to failure of cooling water in

cooler and condenser.

Maybe all one can do is hope to end up with the right regrets.

“

“

~Arthur Miller

You will never be happy if you continue to search for what happiness consists of.

You will never live if you are looking for the meaning of life.“ “

~Albert Camus

7/21/2019 Apr June15 (1)



From a chemist's point of view crude oil, which

is feeding all petrochemical value chains,

occurs in a highly reduced state. On these

grounds alone it is not surprising that oxidation

reactions are at the heart of countless processes in

the chemical industries. Besides the chemical

reactions for the synthetic production of

intermediates and final products, other oxidation

processes are equally essential, for example, to heat

feed streams, condition catalysts or treat waste

streams.

For the vast majority of these oxidation reactions,

molecular oxygen is the oxidizing agent of choice.

The oxygen in most cases is supplied in the highly

diluted form of process air. Almost 79 percent of air

(by volume) is inert and so its oxidation potential is

quite limited. This extra "ballast" - mainly nitrogen -also bears the implication that it has to be routed

through the different process steps, which is

associated with considerable effort such as

compressing, heating and cooling procedures.

Corresponding constraints induced by the presence

of nitrogen in the air, like e.g. capacity limits due to

compressing constraints and pressure drop, short

residence time in reaction stages and high input of

energy can often be overcome resp. mitigated byenriching process air with pure oxygen. This can be

realised either by topping up a given air flow by O2

addition or by reducing air flow and compensating

the thereby reduced oxygen by O2 addition.

Referring to the latter case - i.e. when the amount of

oxygen supplied to the oxidation step is kept at a

constant level - the diagram given in Fig 1 shows

the decrease of total air flow relative to the degree

of oxygen enrichment level:

Oxygen Enrichment for Air Oxidations in Chemical Industries:Overcoming Limitations

Yogesh DesaiManager-Application Sales(Chemical & Environmental)

Linde India Limited

Diganta SarmaHead of Applications & Market Development,

South Asia & ASEANLinde Gas Asia Pte. Ltd.

Bernhard Schreiner, PhDSenior Expert Chemical Process

Linde AG

Fig 1: Decreased flow of process air combined withO2 addition is often the key to higher feed

throughput

When looking at realised applications of

O2 enrichment the decrease of process gas flow by

a reduction of air flow - i.e. reduced nitrogen flow as

well - combined with O2 addition is often the key for

understanding the observed effects. Among them

are capacity increase, changes in selectivity as well

as energy savings in heating and cooling steps toname a few. Depending on the specific case of

oxidation process and degree of O2 enrichment the

7/21/2019 Apr June15 (1)



Fig 2: Technically applied air oxidations where

O2 enrichment has been realised

However, despite its wide range of applicability there

are cases of air oxidations which are not suitable for

O2 enrichment. Prominent here are a number of gas

phase oxidations realised over solid catalyst material

arranged as fixed beds which typically are not very

efficient in heat removal and therefore prone to hot

spots which have to be avoided. Such detrimental

effects are not to be expected to that extent at othertypes of catalytic oxidations as in fluidized beds or

in gas/liquid oxidation reactors. Here normally the

dissipation of the additional reaction heat caused

by the addition of pure oxygen is not an

insurmountable obstacle, especially in moderate

O2 concentration in the enriched process air. This

means that the latter process types lend themselves

to O2 enrichment, in particular when operating within

the low level range.

Increase of Capacity is Often the Focus

At the technical scale O2 enrichment is often applied

especially to increase the capacity of process units

based on air-only application in the oxidation step;

at such units this kind of process intensification can

be realised by combining reduction or retention of

air (resp. nitrogen) flow with O2 addition, thereby

increasing oxygen availability which in turn can allowfor increased throughput of feed. Applications of low-

level enrichment typically come with a capacity

increase of up to approx. 30 percent, as seen, for

example, at Claus units in oil refineries.

O2 enrichment is seldom considered for

process plants where air blowers/

compressors are limited in delivering

sufficient process air. This shortcoming

usually is most pronounced during hot

weather periods when air density is lowerthan usual. In such cases corresponding

economic considerations may come

down to the comparison of costs for a

bigger air blower versus implementation

and operation of O2 enrichment. However,

in many cases the increase of air flow to

increase the capacity is not a feasible

option; e.g. at the fluidised bed processes increase

in airflow could lead to enhanced catalyst loss,

excessive abrasion of catalyst material and too

pronounced erosion of metal.

consequences differ and call for individual

evaluation.

Low Enrichment Levels Prevail at

Realised Revamps

As indicated by Fig 1 the achievable flow reduction

is considerable already at a low O2 enrichment level.

This lends itself for revamp measures which typically

can be realised on the basis of only minor process

modifications. Subsequent change of process

parameters, in particular temperature increase within

the oxidation section and less diluted process

streams down-stream, often can be dealt with in

existing (air-only-based) plant installations or

adapted by minor process changes; like e.g.

increase of cooling capacity at a catalytic oxidation

step or change out of refractory within a furnace

chamber. On these grounds of typically low adoption

effort it is not surprising that most applications of

O2 enrichment are based on low enrichment levels,

characterised by an oxygen concentration in the

enriched process air of up to approx. 30 vol. % as

shown in Fig 1. This also holds for most of the cases

shown in Fig 2 which offers a variety of air oxidation

examples where O2 enrichment is applied at a

technical scale; thus can be considered to be state-

of-the-art.

7/21/2019 Apr June15 (1)



introduced into the furnace chamber via dedicated

lances. This is the case of part of the Claus units

applying O2 enrichment. The second option in

general more frequently used in chemical

applications is the admixing of oxygen into the air.

This is typically realised by injection of oxygen intothe process air pipe; i.e. up-stream the oxidation

reactor. In most of the cases O2 enrichment is a

revamp technology; therefore the respective

O2 injector typically has to be designed according

to the geometry and process conditions of the

existing main process air pipe. Fig 3 shows an

example of such an O2 injector of the well-proven

OXYMIXTM Injector type which directs the O2 jets

against the air flow.

Fig 3: OXYMIXTM Injector - Jets of gaseous oxygen

exit the holes of the ring nozzle against the air flow

By this constellation the main purpose of an O2

injector can be fulfilled reliably: This is to ensure

Built O2 injector

Positioning in air pipe - 3-D CFD view

Safety Measures: Of High Importance

Of course it has to be appreciated that O2 enrichment

not only comes with handling of technical oxygen,

but also changing conditions within the process

plant, especially temperatures and partial pressures.

Therefore, comprehensive safety considerations and

measures are mandatory. Safety aspects with

respect to the O2 supply chain depend to a

considerable degree on the O2 source applied.

Looking further downstream, the process related

safety considerations and measures largely depend

on the type and characteristics of the air oxidation

of interest. One important example is the different

appreciation of the O2 concentration in the process

gas down-stream the oxidation reactor. For thermal

partial oxidations like e.g. sulphur production by

oxidation of H2S this topic is simply irrelevant as the

oxygen coming with the air is totally consumed in

the oxidation section (also for O2 enriched

operation). In sharp contrast, this aspect can be of

utmost importance, e.g. when looking at gas/liquid

oxidations in an organic liquid phase which typically

do not totally consume all the oxygen coming with

the process air. Here the oxidation reactor off-gases

also contain combustible components and typically

the O2 content has to be kept below a certain

threshold (MOC = maximum oxygen concentration)

to avoid inflammable conditions; e.g. if needed by

installation of inerting equipment.

However, from a general perspective such safety

considerations are also of importance when looking

at oxidations on air-only basis, i.e. without additionaluse of oxygen, and normally do not represent

insurmountable problems.

Where to Inject Oxygen:

Two Alternatives Prevail

Two ways to introduce pure oxygen into an air

oxidation process are by far most abundant: one

option is to inject oxygen into the reaction zone of

the oxidation step- among the typical examples are

thermal air oxidation reactors where oxygen is

7/21/2019 Apr June15 (1)



typically offering smooth access as well as flexible

gas availability, is normally only an option within

some big industrial cluster areas. Therefore, in many

cases a decision on the type of appropriate

O2 supply is restricted to choosing between LOX

supply - i.e. delivery of liquid oxygen by tank vehicles- and erection of an on-site plant for O

2 production.

Main criterion therefore normally is not the purity of

the oxygen which typically varies depending on the

respective O2 source. The impurities in question,

namely the inert argon and nitrogen, already occur

in air which is applied in the oxidation process

anyway; on these grounds it is obvious that the

mentioned impurities of technically produced

oxygen are not of any concern as long as theO

2 content is above a certain threshold; i.e. typically

an O2 concentration of > 90 vol.% suffices. Such

quality can be expected from all O2 sources usually

offered by industrial gas companies for

O2 enrichment; therefore sufficient O

2 purity can be

realised no matter if the oxygen originates from

cryogenic generators (i.e. including LOX) or from

pressure swing adsorption units.

Fig 4: Frequently applied scheme of O2 enrichment

addition also information with respect to utility costs

and local infrastructure are important. In case high

and very high O2 volumes are needed on a

permanent basis a dedicated on-site O2 generator

is normally adequate, as is the case at many fluid

catalytic cracking (FCC) units. On the other hand

homogeneous admixing of oxygen within a short

distance of the process air pipe to exclude any

extreme oxidation conditions like local temperature

excursions within the down-stream oxidation reactor.

In order to prepare an air-based plant for O2 enriched

operation normally the only hardware modification

needed is the implementation of the tailor designed

O2 injector. Therefore an access has to be provided

for O2 injection at the pipe of the main process air.

For installation of a corresponding stud a few hours

of plant stop are needed or in case the plant cannot

be stopped, a hot tapping procedure can be

performed. As soon as the O2 injector is inserted

into the stud (see Fig 6) the plant is prepared for

operation with O2 enrichment at any appropriate

time.

Sourcing and Quality of Oxygen

Most applications of O2 enrichment are based on

the scheme shown by Fig 4. At the left it gives an

overview of the different sources which have to be

considered for O2 supply. A nearby pipeline network,

O2 provision: Specific Demand and

Economics Deserve Individual

Examination

Crucial for a decision on the appropriate O2 source

are aspects like the amount of oxygen needed and

the volume profile of O2 demand over the time. In

7/21/2019 Apr June15 (1)



The hardware arranged within a protecting cabinet

looks simple and straightforward, but it is worth a

closer look to understand how operational and safety

risks are mitigated. Therefore a few important topics

will be discussed here:

Of course the main item within the flow control

cabinet is the flow control valve. But in addition the

safety features are of high importance. Any major

deviation of the actual O2 flow must be alarmed and

- if the situation cannot be corrected - oxygen flow

has to be interrupted in a suitable way. In case the

gaseous oxygen for O2 enrichment is sourced from

a liquid O2 tank temperature control in the piping

must be provided to avoid that any too cold oxygen

enters the air duct. And during shutdown periods

an absolute separation between O2 source and

processing plant has to be ensured which includes

safeguarding against creeping gas flows.

With respect to O2 injection located down-stream of

the O2 control device Fig 6 shows a picture of an

inserted OXYMIXTM Injector, in this case designed

for a max. O2 throughput of 700 m3 /h, installed in

the process air pipe of a technical plant.

Fig 5: O2 flow control cabinet of the type OXYMIXTM

Flowtrain, well-proven also in field trials

on-site plants for O2 generation do not always

operate economically if the O2demand is fluctuating

too widely; this typically is given when O2 enrichment

is applied for peak shaving in cases where the feed

flow to the oxidation plant does significantly and

frequently vary. This is one explanation why O2

enrichment installations at Claus units for sulphur

recovery, which in many oil refineries are often

challenged by such changing operating conditions,

are often supplied by an O2 source based on LOX

delivery. Here O2 provision is highly flexible,

especially in view of O2 load fluctuations and

increasingly interesting at lower O2 demands.

Anyway, in order to select the most advantageous

O2 source for a given case a considerable variety ofaspects have to be pondered; i.e. besides O

2

demand aspects also taking into account e.g.

regional LOX availability and reliability of supply.

Hardware for Controlled Meteringand Injection of Oxygen

In order to realise O2 enrichment according to the

scheme shown by Fig 4, O2 supply hardware has to

be installed that is appropriate to the environment

and challenges at the site. This of course also holds

for the measuring and control unit for O2 metering

to the O2 injection point. Beyond functionality here

again safety considerations are in the focus of

interest. One example of a measurement and control

unit is shown by Fig 5.

Fig 6: Once implemented into the air pipe - here inpreparation of trials - the O

2 injector allows for

start-up of O2 enriched operation at any time.

Field Operational Trials - An OptionWorth Considering

Operators of air oxidation plants appreciate the

straightforward possibility to perform trials with

7/21/2019 Apr June15 (1)



O2 enrichment at their own production plant before

considering final implementation. Such trials

normally can be realised with relatively limited effort

in the industrial-scale. For preparation and execution

of trials it is recommended to involve a partner who

can not only contribute by field experience withO

2 use and process know-how. It is also for keeping

the trial costs at bay when such a partner beyond

the latter competences can bring in appropriate

hardware for supply/control/metering/injection of

oxygen which can be rented for the trial duration;

typically industrial gas companies experienced in

O2 applications lend themselves for such kind of a

co-operation. Of course the trial costs correlate to

the corresponding O2 demand, this in turn dependson trial duration which can range from approx. one

week up to even a few months. Typically the trials

are based on delivery and vaporization of liquid

oxygen (LOX) which is a flexible source of gaseous

oxygen; e.g. with respect to the pressure level of

the O2 stream generated which can be adjusted up

to 10 bar and even beyond.

Performing the trial comparison of air-only operation

with oxygen enrichment is a well-proven method to

find out on an experimental basis how an individual

processing unit, i.e., including the installations down-

stream of the oxidation step, reacts to additional

oxygen use. Typically, beyond capacity increase,

other effects and opportunities can be not only

identified but also quantified. Such concrete

information later on can prove to be very helpful in

taking the decision on a permanent installation of

Fig 7: Air oxidation of liquid toluene - Air-only vs. O2 enriched modes

O2 enrichment and its embodiment, e.g. kind and

size of the respective O2 source. Often it turns out

that the effort on off-gas treatment is reduced when

O2 enrichment is applied up-stream for the oxidation

step which typically translates into savings in

operational expenditure, e.g. if the fuel demand foroff-gas incineration is reduced. Moreover, the

performance of field trials allows for confirmation of

expected as well as identification of unexpected

limitations of O2 application; e.g. the max. possible

O2 enrichment level can be among the trial results.

In the rather exceptional case the limitations found

might exclude permanent implementation of

O2 enrichment, at least as long as the processing

plant is not adapted to additional use of oxygen.

O2 Enrichment in the Gas/Liquid

Phase

Industrial production of commodities and

intermediates like, for e.g., terephthalic acid,

acetaldehyde, phenol/acetone, cyclohexanone and

benzoic acid are based on catalytic air oxidations in

the gas/liquid phase. When considering process

intensification by O2 enrichment, laboratoryexperiments can give valuable information on the

effects of additional O2 application, especially in view

of selectivity respectively product yield. One result

based on semi-batch experiments - i.e. (enriched)

air is passed through a stirred vessel filled with

7 litres of toluene - is given by Fig 7 which shows

the dependence of toluene conversion to benzoic

acid on the O2 contents in the oxidation air (160 °C,

9 bar a).

7/21/2019 Apr June15 (1)



which often are beneficial. They depend case by

case on the type of air oxidation and can encompass

energy savings, increased plant availability,

decreasing the load on waste stream treatment and

reduced emissions. All these aspects have to be

taken into account when weighing the benefits ofO

2 enrichment, especially against the additional

operating expenditure for oxygen.

In short: additional use of oxygen for O2 enrichment

can offer technical, financial and even environmental

benefits across a wide range of applications - from

oil refinery operations to downstream chemical

processing.

In order to get a clearer picture on applicability,hardware demands, appropriate implementation

and overall justification of O2 enrichment operators

are encouraged to consider co-operating with an

adequate partner, typically gas companies

experienced in O2 applications. Such a partner can

substantially contribute to developing an application

case by running simulations, erection and

implementation of O2 supply installations and - as a

mentionable option - performing field trials incooperation with the operating company.

The results shown in Fig 7 indicate that basically

O2 enrichment does lend itself to increasing toluene

throughput in a corresponding technical installation

for production of benzoic acid.

Summary & Conclusion

O2 enrichment as an interesting option for process

intensification of air oxidations is described. Such

application of technically generated oxygen can

answer plant limitations and constraints in

production flexibility at a diversity of air oxidation

types. Accordingly O2 enrichment, typically

characterised by a low-investment effort, has already

proven its value in many thermal as well as catalytic

air oxidation processes.

A variety of starting points for considering of O2

enrichment are identified.

The main driver for the implementation of this kind

of O2 application in the majority of cases is its

potential of mitigating processing bottlenecks,

typically leading to increased plant capacity.

Besides, such additional use of oxygen at airoxidation plants usually comes with other effects

Successful people are always looking for opportunities to help others.

Unsuccessful people are always asking, ‘What’s in it for me?’“ “

~Brian Tracy

Life isn't a matter of milestones, but of moments.

“

“

~Rose Kennedy

7/21/2019 Apr June15 (1)



Acomprehensive analysis was necessary to

identify the best scenario required to meet

ULSG regulations: Severe FCC feed pre-

treatment alone or milder pre-treatment combined

with FCC gasoline post-treatment. CFHT cycle

length requirements, with and without post-

treatment, were also under scrutiny to determine their

impact.

An existing refinery reconfigured to process Heavy

Canadian Crudes while maintaining its FCC Unit was

assumed. The VGO feedstock consists of a 55,000

BPD blend of straight run VGO and Heavy Coker

Gas-Oil with 4.2 wt% sulfur. Due to the refractory

nature of this feed, it has to be hydrotreated in a

high pressure unit prior to feeding the FCCU and

the resulting gasoline constitutes about one third of

the total gasoline pool and all of the pool sulfur.

The following three cases were considered:

Case 1: A high HDS CFHT unit and FCCcapable to produce a 10-wppm Gasoline pool

sulfur without the need of a FCC Post-treatment

unit with a CFHT cycle length of 4 years to match

the FCC.

Case 2: A moderate HDS CFHT designed for a

4-year cycle length with a FCC Post-treatment

unit (Prime-G+) designed for a 4-year cycle

length to meet ULSG pool specifications.

Case 3: Similar to Case 2 but with a 2-year cyclelength target for the CFHT unit combined with a

Prime-G+ unit designed for a 4-year cycle

length. During the CFHT catalyst change-out,

the Prime-G+ unit will operate at a higher

severity to meet pool sulfur requirements.

For all cases, a relatively high pressure was

selected for the CFHT to ensure good hydrogen

addition during the whole run. Reactor residence

time was adjusted to meet the CFHT HDS and cycle

length requirement - Figure 1. The very severelevel of HDS and 4-year cycle length in Case 1

naturally leads to a much larger CFHT than the other

cases. High purity hydrogen is supplied from a

SMR plant.

10 ppm Sulfur Gasoline Opportunity Analysis

Larry WisdomMarketing Executive

Axens

Jay RossSenior Technology and Mktg. Manager

Axens

Delphine LargeteauSenior Technologist - Mktg.

Associate Axens

Figure 1 CFHT HDS & Cycle Length

A block flow diagram illustrating the three different

cases with the various configurations along with the

corresponding products considered for the

economics is shown in Figure 2.

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Figure 2 Case Studies Block Flow Diagram

The economic evaluation was based on a

Discounted Cash Flow (DCF) analysis assuming a

depreciation period and a project duration of 10

years. In addition, a profitability index comparison

in terms of Net Present Values (NPV) and Internal

Rate of Return (IRR) was conducted. The prices for

investment, catalysts, utilities, feedstock and finishedproducts were based on 2011 averaged values

assuming the plant to be located in the USA serving

a domestic market. Prices are presented in Table 1.

Table 1 Price Considerations

Feedstock 96 US $/bbl

Natural Gas 4.0 US $/MMBtu

Hydrogen 3.300 US $/MSCF

LPG 69 US $/bbl

Propylene 140 US $/bbl

Butenes 112 US $/bbl

Gasoline Premium 127 US $/bbl

Diesel/LCO 131 US $/bbl

Fuel Oil 104 US $/bbl

For all three cases considered, projections on CFHT

and FCC operations were conducted leading to

expected product yields and hydrogen requirement.

As one could have expected, the implementation of

a high severity CHFT (Case 1) leads to better product

yields in the FCC but has a major drawback of driving

hydrogen consumption up. Results in terms of main

product yields and hydrogen cost for each case arepresented in Table 2. The evaluation was based

on a Natural Gas price of $4/MMBTU resulting in a

hydrogen cost of $3.300/MSCF.

Table 2 Study Results - Product Yields & Hydrogen

Requirement

Case Case 1 Case 2 Case 3New Units CFHT CFHT+ CFHT+

Cycle Length 4 yr Post-treat Post-treat

4 yr + 4 yr 2yr+4yr

Gasoline Yield,

Vol.% / VGO Feed 61.9 56.3 55.0

Diesel + LCO Yield,

Vol.% / VGO Feed 27.2 27.6 28.0

Propylene Yield,Vol.% / VGO Feed 7.8 7.5 7.3

Butenes Yield,

Vol.% / VGO Feed 8.8 8.3 8.1

Hydrogen Cost,

$/bbl Feed 4.71 3.73 3.66

The hydrogen cost for Case 1 is almost 25% higher

than that of Case 2 or Case 3; however, the yield

improvement is quite significant over the lower

severity CFHT cases. Between the lower severity

CFHT cases, the yields and hydrogen consumption

are rather similar with the more severe and longer

cycle Case 2 providing a slight improvement in terms

of yields over Case 3 commensurate with the small

increase in hydrogen consumption.

With regards to the operating cost (OPEX) of the

different cases, the study took into consideration the

hydrogen, octane and utility costs. Compared to the

other factors, the hydrogen cost was by far the major

contributor to the OPEX. In addition to the operating

cost, a detailed Total Capital Investment (TCI) was

developed to estimate the CAPEX for each case.

The TCI trend illustrated in Figure 3 clearly shows

that Case 1 has a much higher capital requirement

than the other two cases due to the significantly

higher desulfurization and cycle length requirementsfor the CFHT.

7/21/2019 Apr June15 (1)



Figure 3 Total Capital Investment (TCI) Impact

Both Net Present Value (NPV) and Internal Rate of

Return (IRR) comparisons are shown in Figures 4

and 5. The high severity CFHT without post-

treatment, Case 1, was considered as the basis and

the IRR and NPV of the other cases were compared

to Case 1.

Figure 4 NPV Results

Figure 5 IRR Results

The NPV results favor Case 1 with a high HDS/long

cycle length CFHT and no post-treatment over more

moderate HDS CFHT cases coupled with a post-

treatment unit. On the other hand, the IRR is most

favorable for Case 3 with the lowest cost CFHT

option (moderate and 2-year cycle) coupled with a

4-year cycle post-treatment Prime-G+ unit.

A sensitivity case was examined to determine the

impact of Natural Gas (NG) cost on the NPV results.

The findings are highlighted in Table 3 where pricing

is contrasted to the 2011 basis above. Assuming a

higher NG price (6 vs. 4 $/MMBTU), the cost of

hydrogen increases and the difference in NPV

between the three cases diminishes somewhat.

Table 3 Study Results - Hydrogen Cost

Sensitivity Study

Case Study Case 1 Case 2 Case 3

NPV @10% : Base Base x 0.93 Base x 0.93

Nat. Gas =

4 $/MMBTU

(case 2011)

NPV @10% : Base Base x 0.94 Base x 0.94

Nat. Gas = 6

$/MMBTU

From and IRR perspective, the advantage of Case

3 increases when hydrogen cost increases and the

gap in NPV between Case 1 and 3 decreases.

Surprisingly, Case 2 with a 4-year CFHT cycle in sync

with the FCC cycle does not show an NPV or IRR

advantage over the shorter cycle Case 3 for either

NG pricing scenario. One could have assumed that

designing a CFHT in sync with the downstream units

compared to limiting the CFHT cycle length to only

2 years would be an advantage. However, the

4-year cycle post-treatment unit brings the additional

flexibility to continuously operate during a CFHT

catalyst change-out. Despite higher feed sulfur (that

could be partially limited with a change in crude diet

during the CFHT catalyst change-out) the design of

the post-treatment unit with the Prime-G+

technology is robust enough to handle this higher

severity requirement during the catalyst change-out.

7/21/2019 Apr June15 (1)



This flexibility is clearly illustrated in Figure 6 which

shows operating data on a Prime-G+ unit in a

refinery processing heavy crudes and equipped with

a FCC CFHT pre-treater. When the CFHT is in

operation the normal feed sulfur to the Prime-G+

unit is typically below 200 wppm. Despiteturnarounds or operation upsets on the CFHT unit,

which can lead to feed sulfur as high as 900 wppm,

the product sulfur from the Prime-G+ unit can be

maintained to the target value of 20 wppm at

all times.

When processing Full Range Cut Naphtha (FRCN),

the sulfur content in the product is maintained at

the target value (20 ppm), as shown in Figure 6,despite variations in FCRN quality thanks to the FCC

pretreatment option.

Figure 6: Prime-G+ Operation Flexibility

The flexibility brought by adding a post-treatment to

the compulsory FCC pretreater when processing

heavy crudes should be underlined and is a major

advantage over the pre-treatment alone solution. In

order to produce a gasoline pool with less than 10-

wppm, the refinery becomes a chemical plant with

no margin for error; relying on the CFHT alone leaves

little flexibility.

In summary, coupling a CFHT with a FCC Naphtha

post-treatment unit brings the following advantages:

The CFHT severity is lowered which offers thepossibility to revamp an existing CFHT.

It is possible to design the CFHT unit for a cyclelength of 2 years instead of 4 years.

The Prime-G+ post-treatment design issimplified to typically a single-stage unit.

The refinery reliability and flexibility is improved:

CFHT upset may be compensated by the Prime-G+ post-treatment unit.

CFHT severity may be decreased if needed/ permitted.

FCCU operation is more flexible in terms offractionation quality.

FCC gasoline end-point may be increased whenmargins favor gasoline production while stillcontrolling FCC naphtha sulfur through post-treatment.

The issue of SOx and NOx control in FCC flue gas is

not addressed in the above analysis. The high

severity CFHT (Case 1) may allow the typical 50 and

40 ppmv targets for SOx and NOx to be achieved

directly while a flue gas scrubber would be necessary

7/21/2019 Apr June15 (1)



10 wppm limit in transportation fuels sulfur levels.

After reviewing commercial best practices and

specific refinery challenges, meeting new ULSG

regulations with existing FCC post-treatment assets

can be achieved. Low refinery margins combined

with capital constraints will likely favor the revampingof existing FCC post-treatment units.

Although each situation is unique, the combination

of pre-treat and post-treat solutions around the FCC

Unit will often result in increased flexibility and

benefits. As a licensor of CFHT, FCC and FCC post-

treatment technologies, Axens is tailored to provide

the service that will fit each specific case.

to meet such constraints with Cases 2 and 3. The

addition of the scrubber for Cases 2 and 3 decreases

the IRR differential to Case 1 by one point while

conversely the NPV advantage over Case 1 is

increased by approximately 1%.

It is important to note that in spite of a trend in favor

of Case 3, the conclusion drawn from this particular

study is case specific and cannot be generalized to

other cases that may have different configurations

and project premise.

Conclusion

A large number of countries are working towards a

If you love life, don't waste time, for time is what life is made up of.“ “

~Bruce Lee

Everyone suffers some injustice in life, and what better motivation than to help

others not suffer in the same way.“ “

~Bella Thorne

7/21/2019 Apr June15 (1)



Increasing trend of sulphur content in crude oil

and natural gas and tightening sulphur content

in transport fuels often forces refiners and gas

processors to opt for additional sulphur recovery

capacity. On the other hand, environmental

regulatory agencies of many countries continue to

promulgate more stringent standards for sulphur

emissions from oil, gas and chemical processing

facilities. Therefore, It is important to develop and

implement reliable and cost effective technologies

to cope with the changing requirements.

In the past several technologies emerged at different

times to comply with the most stringent regulations.

Earlier, a Claus based sulphur recovery unit (SRU)

was designed and operated at an efficiency of 98%.

In the present scenario, most of the countries require

sulphur recovery efficiency in the range of 99.9% or

more. This calls for removal of additional sulphur

constituents in the Claus tail gas. It can be possible

by setting up of additional tail gas treatment unit in

the downstream of RU.

In Indian refineries, most of the old SRUs were

designed with technologies, like MCRC, CBA, etc.

They offer an overall Sulphur recovery of ~99%. As

the sulphur recovery efficiency up to 99% is not

sufficient to meet environmental regulations,

upcoming grass-root SRUs are being designed

taking 99.9%( min) sulphur recovery into

Make in India: Successful Indigenous TGTU

Vartika ShuklaGeneral Manager (R&D)Engineers India Limited

D. K. SarkarDy. General Manager (R&D)

Engineers India Limited

Kausik Ghosh MazumderDeputy Manager (R&D)Engineers India Limited

consideration. The sulphur recovery of existing SRUs

has also been increased from 99% to 99.9% by

integrating them with new Tail Gas Treating Unit

(TGTU).

EIL'S TGT Technology

EIL's TGT technology represents the best

controllability, energy optimization and is achieving

99.9+% overall sulphur recovery with emissions of

< 10 ppmv H2S.

In this process, the residual tail gas from Claus

section, containing mainly N2, H

2O and residual

sulphur species in form of H2S, SO

2, Sx, COS & CS

2,

is preheated to ~240oC using electric or steam

reheater, before sending to hydrogenation reactor.

The hydrogenation reactor employs Co-Mo catalyst

that converts the residual sulphur species to H2S.

H2 is used as a reducing stream. The following

reactions are taking place in hydrogenation reactor

a) Conversion of SO2 and elemental sulphur (Sx) is

by hydrogenation:

SO2 + 3 H

2 H

2S + 4 H

2O + H

Sx + x H2 x H

2S + H

b) Conversion of COS and CS2 is by hydrolysis:

COS + H2O

H2S + CO2 + H

CS2 + 2 H

2O 2 H

2S + CO

2 + H

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The bed temperature of hydrogenation reactor is

increased to ~270-280oC due to exothermic

reaction. The hot gas coming from hydrogen reactor

mainly contains H2O, N

2 and H

2S. The hot gas is

cooled in TGTU-WHB by producing LP steam. It is

then further cooled to 40oC in quench column. Inquench column, the hot process gas is contacted

counter currently with quench water resulting in

condensation of large quantity of water vapor. A

continuous bleed of water is done from quench

column. The quench water leaving the bottom of

quench column is cooled in Pump around cooler

before routing to top of quench column. A slip stream

of quench water is filtered in filter to remove any

accumulated particles in the circulating water.

The gas leaving the quench column is routed to

amine absorber where it is counter currently

contacted with MDEA solution. Lean amine enters

from the top of amine absorber. Lean Amine has

40%wt MDEA and remaining water. H2S and CO

2 in

the process gas are absorbed by lean amine.

Relative to H2S absorption,CO

2 absorption is slow

as MDEA is more selective towards H2S. Sweetened

gas leaves from the top of the absorber to incinerator

and rich amine is routed to regenerator from bottom

of absorber.

The following reactions are taking place in the

absorber:

MDEA + H2S MDEA + + HS-

Rich amine is preheated in lean rich exchanger

before entering the regenerator. The regenerator

consists of regenerator column, reboiler, overhead

condenser & reflux drum. Acid gas mainly H2S is

stripped off and is cooled in overhead condenser.

Water condensed is collected in reflux drum. The

gas leaving the reflux drum comprises H2S, CO2 &water vapor. Condensed water is returned to the top

of the regenerator column. Hot lean amine leaves

from the bottom of the regenerator column is cooled

in the same lean rich exchanger followed by amine

cooler before sending it to amine absorber. Filtration

of amine is done to remove heat stable salts (HSS)

& corrosive products formed during operation. The

typical flow diagram is figure I

Figure I : Typical flow diagram of EIL's TGT Process

Sulphur Recovery in SRU

Required recovery efficiency from SRU+TGTU

Available pressure of Claus Tail Gas

Key Parameters

The key parameters effecting the selection of the

TGT process configuration are:

Existing equipment and process configurationof SRU

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Availability of utilities like steam& power

Space availability

Project execution time for revamp case

Costs (capital and operating)

Commercialization of Technology: A “Makein India” Initiative

Case I : Grass-root design of SRU with TGTU

The first commercialization of EIL's TGT technology

was done successfully in May, 2013 at one Indian

refinery. EIL successfully designed & commissioned

SRU with TGTU. The capacity of the unit is 10TPD.

The tail gas coming from SRU is preheated in electric

heater to a temperature of 280oC.The bed

temperature in hydrogenation reactor is maintainedat ~300oC. The gas leaving the reactor is cooled in

TGTU-WHB to ~180oC where LP steam is

generated. The process gas from TGTU-WHB is

further treated in quench column by counter-currently

contacting with quench water at 40oC. The process

gas which leaves the top of the quench column is at

40oC and enters absorber from bottom where it is

treated with lean amine. The sweetened gas leaves

the absorber at 40oC to incinerator and rich amine

from bottom of the absorber to amine regeneration

section. The amine regeneration section is common

for processing various rich amine of different amine

treating units.

Case II : Revamping of existing SRU byintegrating TGTU and utilization of availableequipment

Sulphur recovery of existing SRUs can be enhanced

by integrating it with TGTU. The method of

revamping these units depends on the existing

configuration and availability of plot area. Revamp

of SRU uses maximum number of existing

equipment after adequacy check so that the capital

cost incurred during revamp is minimized. Revamp

has been carried out in three SRUs of sulphurrecovery efficiency 99% & capacity of 65TPD each.

Design of all the three SRUs was based on modified

Claus process. Each train had two Claus reactors

and two low temperature Claus reactors. The

configuration of SRU before revamp is given in

Figure II. SRU had main burner (MB), main

combustion chamber (MCC), four Claus reactors,

five condensers (C-I to V) & two reheaters

Figure II: Existing configuration of SRU

Since TGTU can accept tail gas from SRU which is

subjected to 96% sulphur recovery, two Claus

reactors have been considered in Claus section. Use

of two Claus reactors not only provides the required

level of sulphur recovery but also provides the backpressure sufficient to operate TGTU without any

hydraulic problem. SRU configuration has been

modified accordingly, which consists of main burner

(MB), main combustion chamber (MCC), two Claus

reactors, three condensers (C-I to III) & two

reheaters. The modified SRU configuration is shownin Figure III.

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Figure III: Modified SRU configuration

Execution for commercialization has been followeddifferent steps which included simulation of Claussection under revamp and tail gas treating section,adequacy check of existing equipment forre-utilization, dismantling of lines not in use after

revamp and conventional procedure for design,procurement, installation, erection,Precommissioning & commissioning.

It has been observed that TGTU can easily beintegrated in such SRU at minimum modification andtime.

Case III : Integration of TGTU in the downstream

of CBA/MCRC based SRU

Many of the Claus units that are in operation do nothave enough pressure to handle a new TGTU. Theupstream pressure of the Claus unit cannot be

increased at the higher pressure as this will lead to

operate the upstream amine section at higher

reboiler duty and in most cases required significant

changes in the amine unit. In such scenario, a

booster blower in the tail gas unit is installed to

overcome the pressure limitation. Retrofit Tail Gas

Units will typically require a booster blowerdownstream of the quench column to overcome the

additional pressure drop. The blower is located after

the quench column to minimize the actual volume

(by means of cooling and condensation of water),

and before the Absorber to take advantage of the

higher pressure. With proper design and operation,

booster blowers are inherently very reliable, requiring

minimal maintenance. In this case, the pre heater,

hydrogenation reactor, TGTU WHB, Quench column

will operate at slight vacuum.

The benefits of the process are:

TGTU can be started independently and no

dedicated start-up blower is required

Tail gas recycle ensures process stability at high

SRU turndown

1 X 130 TPD of TGTU at HPCL-Mumbai, TGTU, 2X

45 TPD , 2X82 TPD ( 4 Trains) of TGTU at BPCL-

Mumbai are under implementation

The flow scheme is given in figure IV.

Figure IV : Flow scheme of TGTU in the downstream of CBA/MCRC based SRU

equipments in CBA or MCRC based units to optimizethe costs and schedule by suitable retrofitting ofthese into the TGTU flow scheme.

Adding the TGTU licensing capability has further

expanded EIL's Environment friendly TechnologyPortfolio and enhanced EIL's contribution to the

success of "Make in India" initiatives.

Conclusion

EIL has supplied this indigenous technology to

several Indian Refineries for grass-root units as well

as tailoring the design for revamps.

EIL's expertise in process design and engineeringadds further value to clients to assess idle existing

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Overcoming Barriers to Entry into Petrochemical Markets

Matthew LippmannUOP LLC, a Honeywell Company

&

Soumendra BanerjeeUOP IPL, a Honeywell Company

Over the past decade, major shifts in global

energy markets have transformed the

competitive landscape for fuel and

petrochemical producers and caused many firms

to reconsider their technology investment strategies.

These changes in the global macro environment

have included events such as the shale gas

revolution in the United States, and trends such as

a widening gap between gasoline and naphtha

based petrochemical margins. While these events

have created new opportunities for existing refiners

to improve value generation by leveraging vertical

integration with downstream petrochemical

producers, there remain several barriers to entry that

continue to cause significant foregone value

creation. This paper will explore opportunities for U.S.

based fuel refineries to add petrochemical feedstock

production to their product slate and discuss how

refiners can overcome the technical and self inflicted

inhibitors that prevent many operators from

leveraging opportunities in petrochemical

integration.

Price Volatility and the

Petrochemical Hedge

Petrochemical demand growth has been matching

or exceeding global GDP growth for the past

decade. This dynamic has resulted in a widening

gap between the value of transportation fuels and

petrochemicals, making petrochemical technology

investment strategies increasingly attractive to

today's world class refiner. Another advantage of

adding petrochemicals to the product slate is thatthey can provide a hedge against feedstock price

volatility as the value uplift of petrochemicals is

remarkably stable despite significant fluctuations in

crude oil prices. Figure 1 highlights the IHS historical

and projected value uplift of aromatics and olefins

over naphtha feedstock in North America. While

there is some variation between products, the

average margin uplift has been well within the $300

to $500 per ton range, and expected to remain there

for the foreseeable future.

Figure 1: North America Margin Uplift of

Petrochemicals Over Naphtha

Even more significant is the fact that this discrepancy

in fuel and petrochemical growth rates has come ata time when the naphtha content of crude is

increasing due to the influx of shale based

production from the United States. This has resulted

in a significant regional overproduction of naphtha

around the world shown in Figure 2. In fact, the

amount of excess naphtha currently on the market

is on the same magnitude as the total amount of

the global benzene and para-xylene consumption

combined, providing a significant growth opportunityfor the petrochemical industry.

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Figure 2: Expected Regional Naphtha Oversupply

2013-2018, MMTA

A third trend specific to the United States is the shifts

in gasoline trade flows due to the impact of ShaleBased production. As lighter crudes displace heavier

feedstocks and domestic production continues to

rise, the U.S. naphtha surplus translates to reduced

gasoline imports from Canada and Europe and a

significant increase in U.S. exports to Latin America

as shown in Figure 3. However, these projections

are based upon the assumption that significant

refining expansion does not occur in Latin America

and traditional export markets will absorb theincremental gasoline production from the United

States. Should these future markets fail to

materialize; additional pressure will be placed on

U.S. based refiners to find alternative outlets for

naphtha including upgrading to petrochemicals.

Figure 3: US Gasoline Current and Forecast

Trade Flows (KBPD)

The Cultural Divide

While intermediate product streams, such as

naphtha or LPG have often provided a common

interface between refinery and petrochemical

businesses, investing in "on purpose" integration

between complexes is a relatively recent industry

trend. In most developed regions, refinery

configurations are similar to that shown in Figure 4

with conversion units such as Delayed Coking and

Fluid Catalytic Cracking, a reforming unit for gasoline

upgrading, and gasoline and distillate hydrotreating

units to meet fuel quality specifications.

Figure 4: Traditional Fuels Refinery Configuration

Conversely, in many emerging regions it is now

common practice to take an integrated approach

that offers the benefits of lower overall cost and

allows the refinery to capture production of higher-

valued petrochemical products by upgrading

internal refinery streams. Therefore new refineries

are often constructed in coordination with an

adjacent petrochemicals complex similar to Figure

5. These complexes will often include additional

propylene generation from the FCC, an aromatics

complex to recover benzene and xylene from the

reforming unit, and are typically integrated with a

steam cracker that can generate and recover

additional light olefins from refinery light naphtha and

LPG.

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Figure 5: Integrated Refinery-Petrochemical Complex exposure to new and unfamiliar markets and

technologies that don't align with existing

organizational structures. For example, while

traditional fuel refinery engineers discuss daily

strategy in terms of boiling ranges, octane barrels,

and product yields, petrochemical producers speakin terms of product selectivities, metric tons per year,

and cash cost of production. Figure 6 provides an

example of how refiners and petrochemical

producers may differ in the performance evaluation

of the same technology solution. The chart on the

left shows para-xylene yield versus units of activity

for a variety of Continuous Catalyst Regeneration

(CCR) reforming catalysts. The chart on the right

shows the same catalysts ranked as a function ofCash Cost of Production (CCOP).

Yet despite common understanding of integration

advantages, refiners in developed regions often

hesitate to invest capital in petrochemical productiontechnologies. One simple cause is reluctance to add

Figure 6: Different Views of CCR Reforming Catalyst Technology Evaluation

A further complication is that crude selection and

optimization in a refinery with petrochemical

integration will be different than for traditional fuels

production. For traditional fuel producers, simple

boiling range and gas chromatograph

characterization of the naphtha components is

sufficient. However, for the integrated complex,

characterization of petrochemical intermediates

such as aromatic ring potential through a reformer,

or olefin selectivity in a steam cracker is increasingly

important. Figure 7 shows the relative benzene and

para-xylene yields for various C6-C8 naphtha

compounds in a CCR reforming unit and Figure 8

shows the relative light olefin yields for various

C4-C6 isomers in a naphtha steam cracker.

In each case, developing tools that can predict

selectivity of individual molecules to desired

petrochemical products is the key to selecting the

optimal feed slate, conversion technology, and

distillation cut points in the complex to fully leverage

intermediate streams and maximize high value

products.

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The Outdated Investment Model

Due to the poorer intrinsic margins, a fuels refinery

will generally push to the maximum capacity required

to achieve acceptable margins. For an integrated

complex, the right extent of integration may be a

more important question than refinery throughput.

Because of the higher margin returns it is often

preferential to direct incremental capital to

petrochemical units to optimize returns. This is

highlighted in Figure 9 which shows the incremental

IRR improvement as a function of capital investment

for a fuels only refinery, a moderately integrated

refinery with an aromatics complex, and a fully

integrated refinery with an aromatics complex and

steam cracker. As shown, while the incremental

capital investment shows a peak return for the fuels

refinery as units reach optimal economies of scale

and break into multiple process trains, the

incremental capital investment applied to

petrochemical technologies continues to leverage

economies of scale while providing higher margin

uplift for products. Understanding these economic

breakpoints often means updating economic

models to fully leverage the higher margin per

incremental capital investment that petrochemical

technologies deliver in the integrated complex.

Figure 9: IRR vs. Capital Investment Analysis for Different Refinery Configurations

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A couple of specific examples are shared in more

detail below.

Case Study I: The Benzene Opportunity

As highlighted earlier, the market demand growthfor petrochemicals have led to unique opportunitiesin the U.S. One such example is benzene whereimports into North America have been increasing ata significant rate over the past decade and areexpected to remain elevating over the next several

years as shown in Figure 10.

Figure 10: North America Benzene

Import/Export Rates

scheme but with a Sulfolane™ benzene extraction

unit added in place of the saturation unit.

Figure 12: Benzene Extraction Flows Scheme

Source: IHS Annual Services, 2013

This trend is due in part due to reductions inreforming severity and gasoline production due toethanol blending requirements and lower productionvolumes of aromatic rich pygas from steam crackersas operators switch to lighter shale gas basedfeedstocks. However, in what seems a marketdisconnect, many companies invest in benzenesaturation technologies such as shown in Figure 11to meet EPA MSAT I, and MSAT II regulations of

0.62v% benzene in the refiner's gasoline pool.

Figure 11: Typical Benzene Saturation Flow Scheme

However, other alternatives exist to meet MSAT II

benzene regulations without consuming valuable

hydrogen or downgrading high value petrochemical

compounds to fuels. Figure 12 shows a similar flow

The summary economic evaluation for upgrading

the complex away from an existing benzene

saturation unit and adding a benzene extraction unit

is shown in Figure 13. While the operating expenses

for the BenSat unit present a significant drag onoverall refining economics due to the cost of

hydrogen consumption, on purpose benzene

recovery can provide significant return on investment

using historical benzene and gasoline price spreads

with payback timelines approaching one year.

Figure 13: Economic Evaluation of Benzene

Saturation vs. Sulfolane Extraction

Case Study II: The Mixed Xylene Opportunity

While the benzene extraction evaluation shows

significant return, on purpose benzene investments

can often suffer from economies of scale as benzene

makes up a lower portion of the reformate aromatic

pool, and regulatory concerns as benzene handling

and shipment logistics can often be problematic.

As shown in Figure 14, mixed xylenes make up a

much larger portion of the reformate product

distribution.

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Figure 14: Typical Reformate Product Distribution Figure 16: CCR Yield Loss for Standardand Next Generation UOP CCR

Technology

Therefore it is worth considering whether the

extraction investment would be better positioned at

capturing incremental mixed xylenes from therefinery as shown in Figure 15 by adding a simple

fractionation unit.

Figure 15: Fractionation for Mixed Xylene Recovery

One significant downside of this configuration is that

in order to crack the non aromatic components in

the xylene cut to the proper specification, the

reformate severity needs to be increasedsignificantly which can lead to significant C5+ yield

loss. UOP's technology innovation teams have been

recently focused on this issue and are in the process

of developing next generation reforming technology

that minimizes C5+ yield loss at higher reforming

severity. As shown in Figure 16, the new advanced

CCR technology from UOP can significantly improve

C5+ yield retention even at higher severity operation

providing an additional opportunity for refiners togenerate aromatics much more selectively than in

the past and further improve investment returns.

Another technology option that solves the xylene

purity issue without an increase in reformer severity

is to add solvent extraction. In addition there is an

option of adding a Tatoray™ unit to disproportionate

and transalkylate toluene with C9/C10+ aromatics

to produce additional benzene and xylenes as

shown in Figure 17.

Figure 17: Extraction and Toluene Transalylation for

Benzene and Xylene

Figure 18 shows the incremental petrochemical

production that can be expected for a nominal 25

MPBD CCR reforming unit by adding a fractionatorto recover xylenes, or a fractionator and Tatory unit

to generate additional benzene and xylene.

Recovery

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Figure 18: Product Breakdown for Fractionation and Extraction/Transalkylation

A final consideration for any investment is also to

consider shipping costs and logistics. Depending

on location, transportation costs can play a large

role in the overall investment returns. Figure 19

evaluates the sensitivity of shipping costs on the

estimated 10 year NPV for both the xylene

fractionation recovery scheme and the full Tatoray

recycle scheme examples highlighted above.

Figure 19: Transportation Cost Sensitivities on NPV for Aromatic Recovery Options

risk models limit many opportunities but with

the introduction of new optimization tools that

have allowed companies to better understand

technology integration strategies, combined

with new technology developments that target

on purpose integration strategies, the opportunity

for fuels producers to enter the petrochemical

markets has never been better and should bea key part of any world class refinery growth

strategy.

Summary and Conclusions

At first glance, the addition of petrochemicals to the

product slate appears to be a straightforward

opportunity for today's world class refiner who

desires to leverage synergies between technologies

to ensure stable margin uplift in dynamic market

environments. However, in spite of the evident value

of integration, the number of fuel producers in the

United States that have modified their facilities toleverage petrochemical production is relatively low.

Simple barriers such as cultural biases and outdated

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DeNOx Technology For Refiners

For a Green Footprint

Raman SondhiVice President

Haldor Topsoe International A/S

Sachin PanwarBusiness Development ManagerHaldor Topsoe India Pvt. Ltd.

In recent years there has been increasing concern

worldwide and also in India for air pollution

caused by industry off gases and vehicular

emission. Sulfur Oxides and Nitrogen Oxides (SOx& NOx) are two major pollutants, which are generally

believed to be precursors of acid rain and depletion

of Ozone layer and these have substantial damaging

effects on our health and environment. NOx also

reacts in the atmosphere to form ground- level

Ozone, bringing yellow smog in urban areas.

In response to the concern, worldwide action has

been taken to reduce SOx and NOx. India has

stringent SOx emission norms' following the

footsteps of US & Europe, but for NOx emission

control India is far behind western Countries. China

has recently imposed major policy reforms for NOx

emission in order to fight the adverse effects of NOx

on health and environment.

In modern India there is huge demand of Power,

Fuel and Petrochemical products for meeting the

day today requirements. Capacity augmentation oraddition of new plants is foreseen in all areas

including Refineries. To meet the product demand,

refineries are implementing state of art technologies

& up-gradation of existing operation, and the

measures being taken for NOx reduction include

installing low NOx burners on fired heaters and

boilers, water injection system in gas turbines. Such

methods reduce NOx generation, but do not

significantly remove the NOx which is generated.

Various technologies have been developed to

control emissions of nitrogen oxides. The SCR

(Selective Catalytic Reduction) process is by far the

predominant choice of technology. The SCR process

works by reacting the NOx with gaseous ammoniaover a vanadium catalyst to produce elemental

nitrogen and water vapor. It has been applied to a

variety of applications since the 1970s including flue

gases from boilers, refinery off-gas combustion, gas

and diesel engines, gas turbines and chemical

process gas streams. SCR is the technology which

gives the highest possible NOx removal rates.

NOx emissions from refineries primarily originate

from utility boilers, co- generation units, process

heaters, steam methane reformers, ethylene

cracking furnaces and FCC regeneration units.

Topsoe is a supplier of catalyst and technology for

environmental processes and has catalysts for NOx

reduction in operation in such units in several

refineries in the USA and Europe. The results from

SCR's installed in the process industry are that they

are very reliable and actually have very low runningand maintenance costs. By selecting SCR, plant

operators are getting a very forgiving system.

e.g. the burners in furnaces will not have to be tuned

to low NOx but can instead be tuned to optimum

combustion and stable flames which gives a safer

and more reliable operation of the furnaces.

The DNX® SCR catalyst is developed with a tri-

modal, highly porous pore structure which enables

the catalyst to tolerate high levels of chromium,

across a wide operating range of temperature.

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Figure 1: Basic Flow diagram for SCR Process.

The ammonia reducing agent can be either

anhydrous ammonia under pressure or it can be an

aqueous ammonia solution (typically 25% by weight)

at atmospheric pressure. A 30-40% solution of urea

which decomposes into ammonia and CO2 at high

temperature can also be used if warranted by safety.

The ammonia is evaporated in a heated evaporator

and is subsequently diluted with air before it is

injected into the flue gas duct upstream the SCRreactor. The SCR process requires precise control

Trouble-free operation has been achieved even with

the catalyst in a high-particulate atmosphere without

an ESP upstream the SCR. Also installation of

Topsoe's SCR on the highest NOx-producing units

serve as a buffer to the overall NOx-emission balance

of the refinery, allowing for compensation of higherNOx emissions of other sources, without exceeding

the refinery's cap of total NOx emission. In some of

the installation NOx reduction rate has been in

excess of 98% with slippage of ammonia up to

2ppm.

Fundamental of De-NOx Technology

NOx is the generic term for nitrogen monoxide, NO,

and nitrogen dioxide, NO2. At high temperature

gaseous ammonia will react with nitrogen oxides to

produce elemental nitrogen and water vapour. In the

presence of a catalyst, a lower reaction temperature,

typically 250°C - 450°C, can be used. Both versions

of the process - with and without a catalyst - are

used commercially. They are known as SCR,

Selective Catalytic Reduction, and SNCR, Selective

Non-Catalytic Reduction, respectively. The NOx

removal rates with SNCR are limited, typically around

60% whereas reduction of NOx over a vanadia-titania

catalyst can yield removal rates in excess of 95%.

Nitrogen oxides are primarily reduced according to

the following stoichiometry:

4 NO + 4 NH3 + O 2 4 N

2 + 6 H

2O

H 0 = -1,627.7 kJ /mol

NO + NO2 + 2NH3 2 N2 + 3 H2O H0= -757.9 kJ /mol

Nitrogen monoxide, NO, is the primary component

in flue gases, meaning that the first reaction is the

more significant one. As seen, NOx and ammonia

react in a 1:1 atomic ratio. A minor amount of NH3

and SO2 is oxidised in accordance with the following

reaction schemes:

4 NH3 + 3 O2 2 N2 + 6 H2O H0= -1,268.4 kJ / mol

2 SO2 + O

2 2 SO

3 H0 = -196.4 kJ / mol

The reactions are exothermal, resulting in a small

temperature rise of the flue gas having passed the

DeNOx catalyst.

Topsoe's SCR DeNOx Technology

The main components of the SCR system basically

are composed of a reactor with the catalyst, an

ammonia storage and injection system and a control

system. Figure 1 shows the typical Process Flow

Diagram of an SCR system. The abatement of

nitrogen oxides results from injection of ammonia

into the gas and subsequent passage through the

catalyst, forming elemental nitrogen and water. Ammonia is injected into the gas at slightly above

the molar equivalent ratio as its NOx concentration.

The ammonia injection rate is automatically

controlled by combining feed-forward control based

on amount of NOx to the SCR DeNOx unit and

feedback control measuring outlet NOx downstream

of the catalyst.

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of the ammonia injection rate. Insufficient injection

results in low conversion of NOx and an injection

rate which is too high results in an undesirable

release of unconverted ammonia to the atmosphere

referred to as ammonia slip. In the flue gas duct,

before the reactor, the NOx mass flow rate will varyacross the cross section area. A homogeneous

distribution of the ammonia in the flue gas is of

crucial importance to achieve efficient NOx

conversion. Topsoe's patented STARMIXER®

system placed in the flue gas duct helps in

achieving a uniform mixing of the ammonia with

the flue gas (Figure 2).

Topsoe has optimized design of a mixing system

for completeness of the chemical reactions, as well

as minimum ducting and an attractive plant layout

with the help of Computational Fluid Dynamics

(CFD). It also ensures a high degree of velocity

uniformity upstream the ammonia injection and at

the entrance to the catalyst layers and to verify

proper mixing of ammonia into the flue gas. Further,

it assists in optimizing the lay-out of ducts, reactor

and necessary flow control devices to minimize

overall pressure loss.

Catalyst

Catalyst is based on a porous titanium-dioxide

carrier material on which the catalytically active

components in the form of vanadium pentoxidecombined with tungsten- and/or molybdenum

oxides are dispersed. To cater for a large gas contact

area with a minimum pressure loss, the catalysts

has corrugated element containing a large number

of parallel channels (Figure 3).

Each type of catalyst is offered in a number of

different models with varying channel size (often

referred to as pitch), wall thickness and with varyingchemical composition adapted to specific operating

conditions. The choice of pitch and wall thickness

for a given SCR installation is determined mainly by

the concentration and properties of the dust in flue

gas. For low-dust applications, channel sizes of up

to approximately 5 mm are selected. Larger-channel

catalysts (6-10 mm pitch) should be selected for

operation in dust-laden gases in SCR units on e.g.

Fluid Catalytic Cracking (FCC) units in which FCCcatalyst fines are carried over from the regenerator.

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Comparison between Topsoe

Catalyst versus Extruded

A high porosity of the catalyst helps minimise the

SO2 -oxidation by providing a high fraction of SCR-

active surface vanadium sites. Figure 5 shows the

high pore volume of Topsoe's DNX® -type SCR

catalyst in comparison with extruded-types SCR

catalysts. The high porosity of DNX® is achieved

via a unique tri-modal pore structure, i.e. a pore

structure featuring pores in three size regimes.Extruded-type catalysts typically obtain the pore

volume from a micro-porous structure within a

narrow size range.

both the inner and outer surface of the catalyst. As

the outer surface fouls with foreign substances

deposited from the flue gas, maintaining access to

the interior becomes increasingly important. Large-

size pores, macro-pores, serve to ensure this access

to the active interior even if large amounts of poisons

have been deposited on the catalyst as illustrated

in Figure 6. The macro-pores further enhance gas-

phase diffusion of NOx and ammonia into the

catalyst and thereby the overall activity of Topsoe

Catalyst.

Figure 4: Different Channel Sizes to take care Particulate matter.

Figure 5: Pore volume in extruded SCR DeNOx

catalyst and Topsoe's DNX®

The pore volume of the DNX® catalyst is roughly

twice that of extruded catalyst types. The high

porosity is achieved from pores in three size regimes,catering to a high resistance towards poisoning. The

conversion of NOx on the catalyst takes place on

Figure 6: The tri-modal pore system of Topsoe'sDNX® catalyst (right) provides a high resistancetowards poisoning as the presence of macro-and

meso-pores ensures access to active sites.

Refinery SCR Application

SCR can be applied in various areas of refinery:

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It's very important to note that after assembling a

list of NOx emitting equipment, a refiner and its

consultant should review the options, taking in to

account the technology, catalyst availability, capital

costs and budget. Also installation of SCR on the

highest NOx-producing units serve as a buffer to

the overall NOx-emission balance of the refinery,

allowing for compensation of higher NOx emissions

of other sources, without exceeding the refinery'scap of total NOx emission.

One of the largest NOx emissions sources in a

refinery is the regenerator of the fluid catalytic

cracking (FCC) unit. FCC is the most important

process in a petroleum refinery and is used to

convert high-molecular weight hydrocarbons in the

crude oil to high-octane gasoline and fuel oils. FCC

catalysts are fine powders with crystalline zeolite

being the primary active component. The FCC unitconsists of the catalyst riser in which the

hydrocarbons are vaporized and cracked by contact

with the hot catalyst recirculated from the

regenerator. The mixture of catalyst and hydrocarbon

flows upward to the reactor where the hydrocarbons

are separated from the catalyst, which has

deactivated from depositing of carbonaceous

material, coke. The catalyst is returned to the

regenerator where it is regenerated by burning offthe coke with air blown into the regenerator. NOx is

produced in the regenerator from burning of nitrogen

contained in the coke.

Haldor Topsoe's design philosophy for FCCU SCR

applications calls for a vertical down flow unit. This

takes advantage of gravity to address the catalyst

fines entrained in the flue gas. Turning vanes are

required to prevent uneven stratification of the solids

and ensure a uniform velocity profile leading at the

inlet face of the SCR catalyst. The most economical

place for an SCR installation in an FCC unit is

upstream of the convection section.

Figure 7: SCR DeNOx Plant at Preem Refinery, Sweden

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technology to achieve maximum NOx reduction and

SCR units for NOx abatement can be designed to

meet today's stringent requirements by offering

95%+ NOx reduction. SCR units have successfully

been installed on ethylene cracking furnaces and

steam methane reformers. NOx emission mainsource in a refinery is the flue gas coming from the

regenerator in the fluid catalytic cracking unit. It can

be the source of 50% of the total NOx emitted from

the refinery. The high sulphur oxides concentration

and carry-over of FCC fines in the flue gas represent

a challenge. With the use of a properly designed

SCR reactor and catalyst, experience shows that

very low levels of NOx emissions can be achieved

from FCC units that have high NOx, SOx and

particulates in the flue gas. Flow modelling by CFD

as well as cold-flow modelling in scale models of

the SCR unit is useful tools to verify proper ammonia

mixing and flow conditions to the catalyst as well as

to identify and eliminate areas for possible dust build-

up. Use of SCR also enables refiners to switch over

to cheaper & readily available fuel source (to avoid

use of NG).

Industrial Experience

Topsoe has a rich experience of implementing

DeNOx technology in various Industrial sectors i.e.

around 1152 references worldwide. The reference

mainly covers:

Fired boilers based Coal, Oil, Gas, Biomass andPetcoke : 282 units

Refinery / Petrochemical: 203 units

Gas Turbine application: 342 units

Stationary diesel engines: 107 units

From the above it is clear that there is a long list ofsatisfied customers, just to name a few:

Chevron Phillips, Cedar Bayou, Texas, USA (ethylene plant)

Shell, Deer Park Refinery, Texas, USA

CITGO Petroleum, Lemont Refinery, Illinois, USA

Preem Refinery, Gotenburg, Sweden

Conclusions

Selective catalytic reduction, SCR, is the best proven

Life is ten percent what happens to you and ninety percent

how you respond to it.“ “

~Lou Holtz

The good life is one inspired by love and guided by knowledge.

“

“

~Bertrand Russell

7/21/2019 Apr June15 (1)



Olefins Technology Options to Meet Uncertain Market Conditions

Tanya Aggarwal, AssociateTechnical Professional

KBR Technology

Sourabh MukherjeeChief Technical Leader

KBR Technology

Sagar Nawander Associate Technical Professional

KBR Technology

During the second quarter of 2014, the world

witnessed an unprecedented slump in the

global crude oil prices that precipitated a

flurry of speculations about the future of crude oil

price. International Energy Agency (IEA) cites weak

demand, a strong dollar, and booming U.S. shale

oil production, exacerbated by the unwillingness of

the OPEC countries to reduce production, as the

major reasons behind this fall.

While the prices have managed to scale upwards

from the historic drop to less than 45 USD in March

2015, emerging above 60 USD since May 2015, the

trajectory that the production and supply/ demand

curves shall trace in the coming months cannot be

predicted with certainty. Geopolitical scenario does

not allow even the most practiced pundits to make

sure claims, as in the near future Iranian oil is

expected to be freely traded in the global crude

market, and OPEC's unwillingness to wind down the

production levels to bring the market to an

equilibrium against the rising demand and shale oil

production levels.

In the last decade, prices of petrochemicals have

become very sensitive to movement in crude oil

prices. There has been a surge in demand for

petrochemicals from the emerging economies of Asia, notably China and India, and in North Western

Europe and the Mediterranean.

Hydrocarbons like naphtha, ethane, propane,

butane, and fuel oil serve as feed for producingethylene and propylene, the two major basic

chemicals- which further serve as feed stocks for

downstream polymerization units producing

polyethylene and polypropylene. Steam cracking of

naphtha, LPG, and ethane feeds has been the

ubiquitous process used in the manufacture of

ethylene and propylene, with the yields of ethylene

being higher than those of propylene. Catalytic

cracking, on the other hand, is known to favorpropylene over ethylene and has a proclivity for

heavier feeds.

(Reference: International Business Times)

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World Olefins Market

Ethylene: Feed stock prices, being a primary factor

guiding ethylene production costs, have allowed a

shift of steam crackers from demand rich regions to

territories that boast of favorably priced feed stocks.

This is evident from the spurt of new ethylene plant

announcements in the USA, owing to the shale gas

boom (though with the weaning of naphtha prices,

this cost advantage merits a relook). China is an

exception to this general trend, where demand still

drives the establishment of ethylene production

facilities. China also seeks to champion technologies

that could allow it to exploit its abundant coal

reserves and investments in coal-based ethylene

will, perhaps, contribute about half of all announced

capacity additions there.

The reducing availability of ethane supplies in the

Middle East, as well as the need felt to broaden their

product portfolio to counter the US Shale gas wave,

will see producers there focus on integrating steam

crackers with refinery projects.

Propylene: The global propylene and derivativesmarket is in the midst of a metastasis. The gradual

tilt towards lighter feeds among steam cracker

operators has spawned developments that affect

the type and location of new investment, regional

pricing levels, and profitability for the producers of

propylene and derivatives. The reduction of

propylene supplies from steam crackers and

refineries, coupled with growing propylene prices,

is driving investments in targeted production, mainlythrough propane-dehydrogenation and, in China,

through coal-based processes. Polypropylene is

expected to remain the largest propylene derivative

well into the future.

Ethylene Plant Economics

The ethylene industry is highly cyclical and sees

heavy swings in profitability due to uncertainfluctuations in product prices. For example if we look

at butadiene, one of the major co-products from a

Liquid cracker, we observe extreme price swings

over the last 5 years. While we can perhaps foresee

trends in the industry over the next couple of years,

taking a call on the long term scenario is more

challenging. Ethylene production cost rides on

several factors that govern the plant economics likecosts of feed stocks, variable and fixed expenditure,

and the value of the co-products.

To be able to counter the variability of feed costs,

processes need to introduce flexibility into

operations, such that different feeds can be

processed as and when their prices are lower.

Integrating steam crackers with adjacent refineries

to upgrade lower value refined products to olefin

feedstock becomes quite economical.

Maximizing the value of co-products like propylene,

butadiene, pyrolysis gasoline, and fuel oil, also helps

offset the cost of production and enhances the

profitability margins for ethylene producers.

To respond to changing market dynamics, operating

flexibility becomes an invaluable foundation of any

new grassroots plant or revamp project, allowing

the producer to continuously adjust operations to

maximize profit at any given time with small,

justifiable increase in capital outlay.

KBR Olefins Technology Portfolio

With challenging market needs, Petrochemical

producers are seeking innovative ways to elevate

the value of their products while minimizing the cost

of production. KBR offers a suite of technologiesthat target enhanced operational flexibility and

maximize the value of ethylene crackers.

SCORETM Technology

KBR SCORETM Ethylene technology is the

combination of three leading Olefins Technologies.

MW Kellogg, which pioneered research on short

residence time cracking to improve the furnace

yields, collaborated with C. F. Braun, the industry

leader in optimized recovery section design and the

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innovators of the De-propaniser first and De-

ethaniser first recovery schemes. In the late nineties,

we went into partnership with Exxon Mobil- the

leaders in Ethylene production and profitability- thus

integrating Exxon Mobil's research and development

on Furnace improvements, reliability, andmaintainability into our technology.

Being a leader in olefins technology development

and construction for over 50 years, KBR provides

cost-effective designs for the production of ethylene,

propylene, butadiene, and other by-products using

feed stocks ranging from ethane to vacuum gas oils.

Since the 1990s, over twenty new ethylene plants

based on KBR Technology have been brought on-

stream, producing a combined ethylene capacity

of 13 million metric tons per year. Through

continuous improvement and technology

innovations, KBR SCORE™ Technology has

established itself as one of the pioneers in the

development of Ethylene technology.

SCORE technology confers several advantages:

- Cracking furnaces that provide the highest

olefins yields available in the industry,

- Low-capital, high-efficiency product recoveryscheme based on low-pressure distillation towerdesigns. Depending on the feed, KBR SCOREEthylene technology may produce 4 to 12percent more ethylene than typical designs, withless energy input per unit of ethylene produced.

- Unmatched feed flexibility to the operatorthrough our unique "Hybrid Cracking" feature.

SCORE is distinguished by our furnace coil portfoliocovering the broadest range of reaction times in

industry (with single pass (SC-1), two pass (SC-2),

and serpentine (SC-4) coil designs), by its low

CAPEX design and superior performance in

reliability, operability, maintainability and flexibility.

When revamping or setting up a grassroots plant,

proper selection of pyrolysis technology with the right

ethylene selectivity is critical.

Hybrid Cracking: Considering the fluctuations in

product prices and high price of energy in the

HybridCracking

market, operators are seeking the

ability to handle different blends of

feedstock to maximize profits. KBR

offers the unique benefit of hybrid

cracking. SCORE furnaces are

extremely flexible and are designed tocrack multiple feeds in the same

furnace at the same time, each at the

most optimum cracking severity. For

instance, a single SCORE furnace can

crack fresh ethane feed (plus recycle

stream) in selected passes at high

conversions to limit recycles, while the balance of

the furnace may be cracking naphtha at low severity

to maximize propylene yield. This allows the plantto be designed with a superior degree of feedstock

flexibility while maintaining a small number of large

capacity furnaces, reducing overall cost. The figure

alongside depicts the hybrid cracking concept with

four passes of the furnace handling ethane/propane

feed and the other four passes handling

naphtha feed.

As a result of this unique feature, a KBR SCORE

liquid cracker would not require a dedicated "Recycle

Gas" furnace to accommodate the recycle Ethane

stream, hence reducing the number of furnaces in

the complex.

KBR designed SCORE furnaces are successfully

handling feed stocks, which range from as light as

ethane to as heavy as gas oils, in the same plant

using Hybrid Cracking.

KBR K-COTTM Technology

While KBR SCORE Steam Cracking technology

provides unique advantages in terms of handling

multiple feed stocks in the same unit, KBR K-COT

offering augments flexibility by allowing cracking of

olefinic feeds, which is not possible in traditional

Steam crackers.

KBR K-COT technology can use feed stocks as

diverse as:

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commercially proven catalytic olefins technology

which can:

Use as feed stock olefins-rich feeds, such assteam cracker by-products and C4 gasolineproduced from refinery FCC and Coker unitsand/ or commonly available, straight runparaffinic feeds,

Crack them to produce a higher quantity ofolefins than conventional pyrolysis, with P/Eratios between 1:1 and 2:1 depending on feedtype,

Easily be integrated with revamp or grass rootsEthylene plants.

Since the steam cracking and refinery sources will

not be able to keep pace with future propylene

demand, "on-purpose" propylene technologies arebecoming more prevalent. Existing naphtha

crackers, comprising nearly half of all ethylene

production capacity worldwide, would perhaps

continue to depend on the crude oil price, which

likely to stay unfathomable at present, as also in the

immediate future.

KBR studies, using actual feed/product price from

the past six years certify KBR K-COT technology's

capacity to ensure very good economics, under

different feed and product pricing scenarios.

With market trends expected to guide future

investments, operators will be well advised to take

a holistic view, and make production more integrative

by opting for technologies that offer maximum

flexibility to meet uncertain pricing scenario.

Typical Refinery and Steam Cracker

- Straight- run paraff inic streams from C4s

onwards to heavy naphtha - producing a

Propylene/Ethylene ratio of ~1/1.

- Olefins-rich feeds such as steam cracker by-

products or Refinery streams ranging from C4s

to FCC/Coker/ Visbreaker Naphtha producing

a Propylene/Ethylene ratio of ~2/1.

- Fischer Tropsch Naphtha (from Coal

Liquefaction process)

- Oxygenates such as methanol or ethanol.

Presently, propylene is predominantly obtained as

a by-product from steam cracking and refinery FCC

units. However, the annual growth in propylene

demand is expected to exceed 5% over the next

few years. With the ethylene market expected to

grow at a slower pace than that of propylene,propylene supply from neither ethylene expansion

nor new FCC units is expected to meet the demand.

KBR's Catalytic Olefins Technology (K-COT) offers

flexibility to use many types of feeds, targets

propylene as a primary product, and produces a

number of valuable products.

K-COT uses the fluidized catalytic cracking (FCC)

process, which is similar to a traditional refinery FCC

unit. KBR has spearheaded FCC technology ever

since its construction of the world's first FCC Unit

for ExxonMobil in Baton Rouge, Louisiana in 1942,

and has licensed several units worldwide.

KBR's patented catalyst design with continuous fuel

firing is commercially proven. The recovery section

for the plant is very similar to that used in steam

cracking designs. K-COT targets propylene and

aromatics yields.

K-COT converters can either be integrated with a

steam cracker or be used as a stand-alone unit toget high propylene yields from straight-run naphtha

feed. The substantial volatility in prices of naphtha

feed, and various ethylene plant by-products,

governs the optimal choice.

Conclusion

To remain competitive, steam crackers of the future

will need to be flexible and agile to meet the market

challenges. Apart from its proven feed flexible steam cracking

technology, KBR offers extremely flexible,

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Megha AggarwalSenior Engineer (R&D)

Engineers India Ltd.

Vijay YalagaDy. Manager (R&D)Engineers India Ltd.

Dr. R. N. MaitiDy. General Manager (R&D)


Vartika ShuklaGeneral Manager (R&D)


Trickle Bed and Slurry Bed Reactors in Refining Industry

Present day requirements of improvedconversion and product quality have

brought hydroprocessing to the forefront of

refining operations. As there is a depletion of

conventional light and sweet crude, the crude oil

will be heavier in the future. So, importance of

hydroprocessing (viz hydrocracking, hydrotreating,

hydrodesulfurisation) will be enhanced, i.e.

application of catalytic reactors used in

hydroprocessing will be more.

Most of the hydroprocessing reactors are fixed bed

of solid catalyst particles contacted by trickling flow

of liquid in presence of gas, carrying both reactants

and products downwardly. These trickle bed type

reactors(TBRs) are usually operated at elevated

pressures of about 2-30 MPa in order to slow down

catalyst deactivation, increase the concentration of

the gaseous component in the liquid phase, attain

high conversion, achieve better heat transfer and

handle large gas volumes at less capital expense.

However, with increased processing of heavy sour

crudes, upgradation of heavy oils containing

asphaltene, S, N, heavy metals (Ni, V) with fixed bed

hydrocracking face a critical problem of catalyst

deactivation caused by coke deposition.

Hydrocracking in slurry phase is suitable to solve

this problem due to achievable high conversionthrough enhanced mass transfer rate and good

temperature control. In this process a small amountof catalyst and hydrogen is mixed with feed and the

mixture is sent to the reactor chamber where the

hydrocracking conversion occurs.

Hydrocarbons will continue to be our major source

of energy in the future; whereas the demand and

supply gap are growing and to be met by imports.

One of the other efficient way of reducing oil

consumption by refinery is resource exploration by

way of utilization of coal and petcoke to syngas and

conversion of syngas to premium quality diesel

through Fischer-Tropsh synthesis in slurry bubble

column reactor in presence of solid catalyst. The

diesel obtained through this FT synthesis has a

cetane number >70 which may be used in quality

improvement of product mix.

Hydrodynamics of these trickle bed and slurry phase

reactors which ensure proper distributions ofreactants for efficient contact and removal of product

from reaction site are extremely important for fullest

utilization of highly active catalyst developed by

catalyst manufacturers to meet the stringent

specifications of environment friendly fuels. The

following sections detail the hydrodynamic aspects

of trickle bed and slurry bed reactors, an important

category of multiphase reactor used widely in oil

industry along with capabilities built up at EIL - R&Dcenter.

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catalyst. The observed and expected reaction rates,

when the particles are fully covered with liquid, are

directly related to partial wetting of the catalyst. It is

generally recognized that pressure drop, liquid

holdup, wetting efficiency, i.e., surface coverage by

liquid and gas, other reactor parameters are closelycoupled to these complex flow pattern and

distribution. So one of the major challenges in design

and operation of this type of reactor is the

understanding of the fluid distribution at macro, i.e.,

bed level as well as at the micro, i.e., particle level.

Figure 1: Flow Regimes

In the macro level, the distribution of phases is well

established along with prediction of flow boundaries

of various flow regimes like trickling flow, pulsing

flow, spray flow, and bubble flow (Figure 1). In the

trickling flow regime, the liquid flows down the

column from particle to particle on the surface

of the packing while the gas phase travels in

the remaining void space of the flow channels.

At the micro or part ic le level, the liquid flow

texture in a bed consists of a number of

features: liquid flows as films, rivulets over the

particles, pendulum structures, liquid-

filled channels and liquid-filled pockets

(Figure 2).

Hydrodynamics of Trickle Bed

Hydroprocessing Reactors

Most of the hydroprocessing reactors are fixed bed

of solid catalyst particles contacted by trickling flow

of liquid in presence of gas, carrying both reactantsand products downwardly. In general, the reaction

occurs between the dissolved gas and liquid phase

reactant at the interior surface of the catalyst. In some

cases, the liquid phase may be an inert medium for

contacting the dissolved gaseous reactant with the

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pressure and with hydrocarbon system (Figure 2).

Pressure drop profile, liquid distribution and liquid

dispersion studies data generated for

hydrodynamics with various packings, operating

fluids system. Correlations for pressure drop, liquid

holdup and wetting efficiency have been developedand flow regime maps have been generated.

Column dial: 15/30 cm

Packed bed height: 1.7/2.0 m

Design pressure: 40 bar

Distributor: chimney type

Liquid collector: annular

Operating liquid: hydrocarbon

Trickle Bed Reactor Internals

Reactor internals are located at the reactor inlet, inter

bed zones, and at the reactor outlet. Various types

of internals present in TBRs are inlet diffuser,

distributor tray fitted with various types of distributors,

quench system, catalyst support grid, outlet

collector, layers of inert balls, etc. as shown in Figure

3. Among these internals, the most important are

the distributors placed above the catalyst beds.

Figure 3: Typical Trickle-bed reactor with different

internals

The relative amount of these features are expected

to vary with factors such as inlet distribution of gas

and liquid, size and shape of the packing, wetting

properties, method of packing, method used for

start-up operation, gas and liquid flow rates and fluidphysical properties.

Most of the published information on hydrodynamics

are at atmospheric pressure and air water system.

At present, an engineer attempting to evaluate the

hydrodynamic parameters needed for design or

scale-up, such as external liquid holdup, flow regime

and pressure drop, has to wade through a jungle of

numerous correlations. The discrepancy in

predictions can be very large. Hence, in companies

that have experience with fixed beds with two-phase

flow, one normally ends up using and relying on the

"in-house" unpublished proprietary correlations

generated in their cold stand setup at simulated flow

conditions.

Cold Flow Trickle Bed Reactor

Facilities at EIL-R&D

Various sizes of cold flow facilities have been created

at EIL R&D to generate hydrodynamics at high

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The extent of uniform distribution of liquid through

the catalyst bed at micro level is grossly affected

by proper design and functioning of reactor

internals. Poor liquid distribution can contribute to

channeling through catalyst bed resulting in

inefficient utilization of the catalyst, development ofhot spots and catalyst deactivation due to coke

formation. The parameters that are important in the

design of a vapor liquid distributor tray for a trickle

bed reactor are drip point spacing, tray levelness,

plugging, proper liquid mixing, pressure drop, and

flow at various conditions. Several designs of

distributor are used in TBR. Most of the known

designs of vapor liquid distributors fall into one of thefour categories (Figure 4a-d) i.e., sieve tray, chimney

tray, bubble cap tray, and vapor assist lift tube.

Figure 4: Typical distributors: (a) Perforated tray, (b) Multiport chimney, (c) Bubble cap (d) Vapor lift tube

Several designs of distributor trays are commercially

available:

(1) Perforated Tray/Sieve Tray Type Distributors-

These are the earliest type of distribution trays used

in the trickle bed reactors. They consist of aperforated tray or sieve tray with gas chimneys. This

tray is simple to construct and is capable of providing

the greatest number of drip points over the cross

section of the catalyst bed.

(2) Chimney Type Distributors- These designs have

chimneys evenly spaced across the distribution tray.These chimneys allow the vapor to pass through

the top opening. The liquid flow is distributed through

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weep holes or notches cut into the side of riser. This

design eliminates the sensitivity to plugging. This

type of device is essentially equivalent to a

perforated tray with elevated liquid ports. A further

improvement of this simple chimney distributor is

the multi-port chimney. This distributor design hasweep holes spaced vertically up the axis of the

chimney, which provide greater flexibility to changing

vapour/liquid ratios. These have increased tolerance

to tray levelness problems.

(3) Bubble-cap Type Distributors - Bubble-cap

design operates on a vapour assisted principle

compared to liquid overflow principle employed in

the chimney type distributors. In this design, vapour

passing through slots in the bubble cap aspirate

liquid held up on the tray, carrying it over a central

down comer. The bubble cap design is much less

sensitive to tray levelness than others because the

liquid on tray is carried by the vapour. It is also less

sensitive over a broad range of liquid loading.

Another advantage of this type of distributor is that

it acts like an additional quenching device, bringing

the liquid and vapour closer to an equilibrium

temperature before they enter the catalyst bed. Also

this is less prone to fouling compared to chimney

type distributor.

(4) Vapour-lift Distributor- These distributors

incorporate all advantages like vapour liquid mixing,

low vulnerability to plugging normally associated with

vapour assist distributor such as bubble-cap

distributor tray. But this tray has much smaller

diameter chimney, which enables the installation ofmore distribution points across the tray area. These

distributors exhibit very stable, low sensitivity

operation over a broad range of vapour/liquid ratios.

Drawbacks Connected with

Hitherto known Devices

A number of problems are encountered in the use

of these known distributing devices. Perforated tray

type distributors have high sensitivity to tray

levelness. The perforations can easily be plugged

by coke, corrosion products or other particles carried

into the reactor by the feed. The main disadvantage

of bubble cap type distributor is that it requires large

diameter and thus less number of drip points on tothe catalyst bed. Vapour-lift design is basically a

vapour assist distributor like bubble cap distributor

and the vapour assist distributor; in general have

the problem of non-uniform secondary

distribution.

In chimney type distributors, the liquid flow is

governed by the overflow principle. This design is

also very sensitive to the tray levelness and changesin liquid loading. It offers fewer drip points than the

perforated tray. To provide the turndown capability,

these distributors are designed to maintain a liquid

level at the design conditions above the level of the

weep holes or notch bottom. If the feed rate is

increased or a heavier feed is processed, the level

on the tray will increase and can flood over the top

of the chimney.

To overcome the above disadvantages in chimney

distributors, EIL has developed a novel chimney

distributor tray (Figure 5). It consists of a central pipe

top covered with circumferential opening at top end

for gas entry and annulus pipe (top opened) with

holes at pipe wall at various axial locations for liquid

entry to the annulus region. Bottom of the distributor

is fitted with a basket type assembly with notched

skirt attached for mixing and lateral spreading. Gasenters into the gas tube from top end and liquid

enters from the annulus in to the gas tube at the

bottom end, get mixed and distributed uniformly on

catalyst bed after intimate mixing through secondary

distributor. The distributor provides high density of

primary distribution points, good quality secondary

distribution of liquid, operates at high turndown ratio

and is resistant to fouling.

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Figure 5: Modified Chimney Distributor with

Secondary Vapor - liquid Distribution

To study the performance of the internals, it is always

better to have a large size cold stand. A large scale

cold flow facility (120 cm diameter column) has been

created at EIL R&D, Gurgaon for generating

hydrodynamic performance data (Figure 6) fitted

with all the reactor internals (inlet diffuser, distributor

tray, quench box, out collectors etc). The modified

chimney distributor has been developed, evaluated

in this large diameter column and implemented

commercially for diesel hydrotreating at IOCL- BGR.

Figure 6: Large Scale Cold Flow Facility at EIL-R&D,

Gurgaon (1.2 m dia column)

Figure 7: Typical Slurry Bubble Column

The main attractive features of slurry bubble columns

are:

- A high liquid mixing which should providehomogeneous catalyst concentration andtemperature distributions.

Hydrodynamics of Slurry

Phase Reactor

Bubble column reactors are invariably chosen as

the reactor type for carrying out relatively slow liquid-

phase reactions and where the liquid-phase backmixing is a desirable feature in order to achieve

temperature equalization that is important for

exothermic reactions. It is important to have enough

information on the hydrodynamics of the multiphase

reactors (SBCR) such as gas holdups, gas-liquid

mass transfer, liquid re-circulation etc.

Slurry bubble column reactors are simple vertical

cylindrical vessels with intense contact between gas,

liquid and solid phases. In most applications, gas

is the reactant; liquid is the product of reaction and

solid is the catalyst. The "liquid + solid particle"

suspension can be represented as a homogeneous

fluid phase and is named as slurry. The gas phase

is dispersed into the slurry phase using specific gas

distributors at the bottom of the column. A simplified

representation of a slurry bubble column is shown

in Figure 7.

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- The use of small catalyst particle size (about50 m), which reduces intra-particle diffusion.

- Easy catalyst addition and withdrawal from thereactor.

- Low-pressure drop.

In particular, slurry bubble column reactors aresuitable for carrying out highly exothermic reaction,

such as methanol synthesis or Fischer-Tropsch

synthesis.

There are considerable reactor design and scale-

up problems associated with the slurry bubble

column reactor. Firstly, large gas throughputs are

involved, necessitating the use of large diameter

reactors, typically 5-8 m, often in parallel. Secondly,

the process operates under high-pressure

conditions, typically 30-40 bar. Thirdly, in order to

obtain high conversion levels, large reactor heights,

typically 30 m tall, are required along with the use of

highly concentrated slurries, approaching 40 vol%.

Finally, the process is exothermic in nature, requiring

heat removal by means of cooling tubes inserted in

the reactor. Reliable design of the reactor to achieve

high conversion levels requires reasonable

information on the gas holdup, bubble size

distribution and type of distributor to ensure uniform

distribution of gas/liquid.

The effect of various parameters (superficial gas

velocity, pressure, gas density, physical properties

of liquid, solid concentration, column size and gas

distributor) has been studied through available

literature. Various authors developed the gas holdup

correlations at ambient pressure conditions.

However they did not take into account the effect of

pressure.

Cold Flow Slurry Bed Reactor at

EIL-R&D

Experimental facilities have been created at EIL-R&D

complex to study the effect of various parameters

(superficial gas velocity, pressure, gas density,

physical properties of liquid, solid concentration,

column size and gas distributor) on slurry

hydrodynamics. Two different sized slurry bubble

column reactors have been setup viz. 0.45 m and0.2 m dia column respectively. The design pressures

of both the columns is 12 barg and to operate at

ambient temperature. There is a provision to

measure the differential pressure across six points.

There is a facility for changeover of the distributor at

the bottom of each column. Two types of distributors

viz. sieve plate and spider type have been tested

for hydrodynamics with slurry phase at ambient

temperature, water & hydrocarbon liquids and with

solids.

The hydrodynamic design information of slurry

reactor can be generated under wide range of

pressures, superficial gas velocities, solid

concentrations (0-30 vol. %) and with different

distributors (spider and Sieve plate) towards design

of slurry bed reactors

Conclusions

Apart from highly active catalyst, hydrodynamics is

an important factor for fullest use of catalyst potential.

Due to presence of solid, gas and liquid,

understanding of hydrodynamics in trickle and slurry

bed type reactor and design of suitable distributors

is a challenge. In case of trickle bed reactor,

important hydrodynamic parameters for design are

pressure drop, liquid holdup and wetting efficiency.These are influenced by particle level hydrodynamic

phenomena like flow texture which is linked to

uniform distribution of liquid. Internals like chimney

distributor with dense drip points and with lateral

spreading ensures the proper flow regime and

catalyst wetting for exploiting benefits of highly active

catalyst. Similarly in case of slurry reactor, the

distribution of gas/liquid and formation of various

sizes of bubbles depends on distributor at thereactor inlet.

Cold experimental facilities with various column sizes

(15 - 120 cm dia) for trickle bed and (20-45 cm dia)

for slurry bed fitted with important reactor internals

have been created at EIL-R&D complex to generate

data bank for hydrodynamics and for evaluation of

various types and sizes of packings and internals

used in Trickle and slurry bed reactors, important

category of multiphase reactors used in refining

industry.

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Members’ News in Pictures

Mr. Dharmendra Pradhan, Hon'ble Minister of State (Independent Charge), Petroleum and Natural Gas

(4th from left) urged fellow countrymen to voluntarily give up their LPG Subsidy at a function held at Bengaluru in the

presence of Mr. S.C. Khuntia, SS&FA, MoP&NG (2 nd from right), Mr. S. Varadachari, GM (I/c), Karnataka

(extreme left); Shri K. K. Gupta, Director (Mktg.), BPCL (2 nd from left).

Shri Dharmendra Pradhan, Hon'ble Union Minister of State (Independent Charge) for Petroleum and Natural Gas

inaugurated the Patna project office of GAIL (India) Limited for the construction of the Jagdishpur - Haldia pipeline on May 25, 2015 in the presence of Shri Giriraj Singh, Hon'ble Union Minister of State for Micro, Small &Medium Enterprises; GAIL Chairman and Managing Director, Shri B. C. Tripathi; Director (Projects), Dr. AshutoshKarnatak and other dignitaries.

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A full-fledged Customer Awareness Week was organized in Nashik, Sholapur and Ahmedabad as part of Bharat Mela-"Saal Ek, Shuruwat Anek". At Nashik the event was launched by Social Worker, Mr. Suhas Pharande, in the

presence of Shri M S Patke, GM (Brand & PR), Shri K. Ravi, Regional Manager Lubes (West), BPCL Territory Managers and others on 26 May 2015.

The Hon'ble Union Minister of State (I/C) for Petroleum & NaturalGas, Shri Dharmendra Pradhan (extreme left)at the first StrategicCrude Oil Storage facility at Visakhapatnam on June 25, 2015.Other (L-R): Shri A. K. Sawhney, Additional Secretary, MoP&NG;Shri S. Poundrik, Joint Secretary (Refinery), MoP&NG (at the back); Shri H. P. S Ahuja, Deputy CEO, ISPRL; Shri K. D. Tripathi,Secretary, MOP&NG; Shri Rajan K. Pillai, CEO&MD, ISPRL.

Hon'ble Minister of State (I/C) for Petroleum and Natural Gas,Shri Dharmendra Pradhan (sitting centre) reviewing the performance of NRL during his visit to Numaligarh on 16th of April' 15. Also seen in the picture are Hon'ble MPs from Jorhat and Dibrugarh, Shri Kamakhya Prasad Tasa (sitting 4th from right) and Shri Rameswar Teli (sitting 3 rd from right); NRL MD Shri P.Padmanabhan (sitting 1 st from left), NRL Director (Technical)Shri S. R. Medhi (sitting 2 nd from right); NRL Director (Finance)Shri S. K. Barua (sitting 1 st from right); Ministry officials and senior officials of NRL.

Bharat Petroleum Corp. Ltd. wasdeclared Public Sector Unit of the Year at the premier edit ion of the ICICILombard & CNBC - TV18 India RiskManagement Awards. This award for the best processes and practices adopted by BPCL in ri sk management was presented to Shri . S. Varadara jan,Chairman & Managing Director (extreme left) in New Delhi on 7th May 2015.

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Unveiling of Inaugural Plaque of Polypropylene Unit at MangaloreRefinery and Petrochemicals Limited by the Hon'ble Minister for Petroleum & Natural Gas, Shri Dharmendra Pradhan.

Ms. Veena Swarup, Director (HR) has been honoured as Legend Director of the Year 2014 by News Ink Media. She received the award from Hon'ble Governor of Haryana Prof. Kaptan SinghSolanki during News Ink Legend PSU Shining Awards 2014function held on April 27, 2015 in New Delhi.

'Breaking Barriers', a book on organizational change management, authored by Shri Satchidananda Rath, Director (Operations), Oil India Limited and Shri Prakash Deka, Chief Manager (Vigilance), Oil India Limited, was released on May 26,2015 at the SCOPE Complex, New Delhi by Shri S.K. Srivastava,Chairman & Managing Director, OIL in the presence of Dr. U.D.Choubey, Director General, SCOPE, Chief Guest at the event.Guests of Honour were Shri S. Mahapatra, Director (E&D), Shri Anand Kumar, IPS, CVO and Shri N.K.Bharali, former Director (HR&BD), OIL.

Shri Vishnu Agrawal, Director (Finance), MRPL (extreme left) was adjudged winner of the 'BT-STAR Excellence Award in thecategory PSU-small,-DIRECTOR-FINANCE OF THE YEAR' by the Jury of the BT-Star Excellence Awards 2015. Others (L-R): Hon'bleLieutenant Governor of Andaman & Nicobar Islands, Lt. General A. K. Singh (Retd.); Ustad Ghulam Ali, Pakistani Ghazal Singer.

HPCL sole winner of CII Supply Chain And Logistics Excellence (SCALE) Award inOil & Gas Industry.

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EIL organized an interactive Supplier Meet for 'MAKE IN INDIA' programme inMumbai on April 28, 2015 which was attended by suppliers from Mumbai and Pune belonging to Fabrication, Bulk,Pump, Electrical and Instrumentation indust ries. Shri Sanjay Gupta, thenDirector (Commercial); Shri Ajay

Deshpande, Director (Technical); Shri A.K. Chaudhary, ED (Inspection); Shri Niraj Sethi, ED (CS & BD) and several other senior officials from EIL graced theoccasion.

Oil India Limited was conferred the 'Certificate of Merit - BelieversCategory', at the Frost & Sullivan's Green ManufacturingExcellence Awards (GMEA), 2015. The certificate was received by Mr. A.C. Patowary, General Manager (E&I), OIL on behalf of Oil India Limited from Mr. Gowtham Sivabalan - AssociateDirector, Frost & Sullivan, Middle East, North Africa & South Asia, at the Award function held on May 22, 2015 in Mumbai.

Memorandum of Understanding (MoU) being signed on20th April, 2015 at Dhaka between GM (Mktg. & BD) NRL-Mr. B. Ekka (sitting left) and GM (Planning and Development),Bangladesh Petroleum Corporation - Mr. Mustafa Qudrat-I-Elahi (sitting right) in presence of MD NRL Mr. P. Padmanabhan,Chairman Bangladesh Petroleum Mr. A. M. Badrudduja and senior Govt, NRL and BPC officials. The MoU provides for export

of petroleum products from NRL's Marketing Terminal in Siliguri to Bangladesh Petroleum's Depot at Parbatipur through the proposed 130 kms 'Indo-Bangla Friendship Pipeline (IBFPL)'.

Rajasthan State Gas Limited (RSGL) has signed Heads of Agreement (HoA) with GAIL (India) Limited to procure

natural gas which will pave the way for dispensing of CNG along Delhi-Jaipur Highway corridor and distribution of Natural Gas to various industrial clusters in Rajasthan. The agreement was signed on May 1, 2015 in the presenceof GAIL Director (Marketing), Shri Prabhat Singh by GAIL Zonal General Manager, Jaipur, Shri S. Bairagi and RSGLManaging Director, Shri Ravi Agarwal.

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Swachh Mangaluru. Swachh Bharat - Flag off by the Hon'bleUnion Minister of State (I/C) for Petroleum & Natural Gas (extreme right) organised by Mangalore Refinery and PetrochemicalsLimited when Managing Director, Shri H. Kumar was also present.

Boat Clinic 'Kaliyani' sponsored by NRL as part of its CSR activities being formally inaugurated by MD NRL Mr. P. Padmanabhan(right) in presence of Managing Trustee C-NES Mr. Sanjay Hazarika (left) and Director (Finance) NRL Mr. S. K. Barua (center)on 18th of May 2015 at Guwahati. The boat clinic would cater tothe medical needs of the marginalized and needy people inhabi ting the numerous sand bars dott ing the mighty Brahmaputra in Kamrup District of Assam.

Managing Dierctor, MRPL, Shri H. Kumar reiterates MRPL'scommitment to the Nation at the function.

A series of retail initiatives were launched by IndianOil during AllIndia State and Regional Heads' Conference held at MarketingHead Office, Mumbai recently. The XTRAPOWER Rural card was launched by Mr. B. Ashok, Chairman, IndianOil by handing over

a replica to Mr. U. V. Mannur, ED, TNSO in the presence of Mr. A.K. Sharma, Director (Finance). This is a first-of-its kind initiative in the oil industry and potentially 20% HSD sales can be tapped through the Rural card.

Hon'ble Minister of State (I/C) for Petroleum &Natural Gas,Shri Dharmendra Pradhan handing over a motorized tricycleduring EIL's CSR Camp at Bhubaneswar on June 20, 2015. Theevent was also graced by Dr. Sruti Mohapatra, an eminent socialworker and champion of disability causes in Odisha, Ms. VeenaSwarup, Director (HR), EIL and other senior officials from EIL & Artificial Limbs Manufacturing Corporation of India (ALIMCO).

Mr. Dharmendra Pradhan, Hon'ble Minister of State for Petroleum& Natural Gas and Mr. Sarbananda Sonowal, Hon'ble MoS (I/c)Ministry of Youth Affairs and Sports Visited IndianOil (AOD) installations at Digboi. Mr. Sanjiv Singh, Director Refineries,D-I-C (AOD) welcomed and felicitated the Ministers.

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The Hon'ble Union Minister of State (I/C) for Petroleum & NaturalGas, Shri Dharmendra Pradhan inspecting the strategic crudeoil storage facility at Visakhapatnam.

The First International Yoga Day on 21 st June 2015 was celebrated with enthusiasm and vigour by employees of IndianOil's ParadipRefinery by participating in the mass Yoga Camp arranged at Jawaharlal Indoor Stadium, Cuttack. The event was inaugurated by Hon'ble Union Minister of State (I/c) for Petroleum and NationalGas, Mr. Dharmendra Pradhan.

Shri Sanjay Gupta, C&MD, EIL receiving the India Pride Award 2014-15 in "Excellence in CSR/Environment Protection &Conservation" category from Shri Arun Jaitley, Hon'ble UnionCabinet Minister for Finance, Corporate Affairs and Information& Broadcasting during an Award function organized by DainikBhaskar on June 4, 2015 in New Delhi.

Mr. B Ashok, Chairman, IndianOil inaugurated Liquid Chromatography - Mass Spectromety (LC-MS) facility at IOC-DBT Centre for Bio-Energy Research at R&D Centre. This state-of-the-art facility, a first at IndianOil R&D Centre, will be used for the complete analysis of pretreated biomass degradation products.

Handing over of Keys of the Toilets at Schools under Swachh Bharat Abhiyan at MRPL.(L-R): Shri D. K. Sarraf, CMD, ONGC; Shri S. S. Khuntia, SS&FA, MoP&NG; Shri DharmendraPradhan, Hon'ble Union Minister for Petroleum & Natural Gas.

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EVENTS

Working around poor or moderate data quality can be devastating to productivity and operationalexpenses in oil & gas exploration and production which is a knowledge-intensive, high-risk andhigh-reward business where the resource owner or operators have to depend on several others fortheir success. Stating this in his opening remarks Dr. Avinash Chandra, former Director General,Directorate General of Hydrocarbons brought out the importance of data and information standardsin E&P while chairing a guest lecture by Mr. Jay Hollingsworth, Chief Technology Officer at Energistics,Houston, USA organised by PetroFed at New Delhi on April 10, 2015.

Mr. Hollingsworth spoke on 'Leveraging Upsteam Business Efficiencies Through Energistics E&PStandards Collaborative Development & Implementation Process' in PetroFed's series of Guest

Lectures and Thought Leadership Programmes during his short visit to India. He has over twentyyears of upstream O&G industry experience and is a recognized global authority on the design anddeployment of upstream master data management solutions for petrotechnical and upstreamGIS data.

Standards, Mr. Hollingsworth said, provide requirements, specifications, and guidelines that areused to ensure that processes, products and services are fit for purpose. Energistics, he elaborated,is a global, not-for-profit, membership consortium that serves as the facilitator, custodian andadvocate for the development and adoption of technical open data exchange standards in theupstream oil and gas industry. Its membership consists of integrated, independent and national oilcompanies, oilfield service companies, software vendors, system integrators, regulatory agencies

and the global standards user community.The lecture ended with an intense Q&A session.

Dr. Avinash Chandra, former Director General, Directorate

General of Hydrocarbons (L) being welcomed by Mr. A. K. Arora,Director General, PetroFed with a bouquet of flowers.

Mr. Jay Hollingsworth, Chief Technology Officer at Energistics,

Houston, USA (L) being greeted by Session Chairperson,Dr. Avinash Chandra.

E&P Standards

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Lecture in progress.Mr. Jay Hollingsworth making his presentation.

Mr. Jay Hollingsworth replying to a query. A query being raised by Mr. A. K. Tyagi, General Manager,IndianOil.

Session Chairperson, Dr. Avinash Chandra delivering concluding remarks.

Session Chairperson, Dr. Avinash Chandra delivering opening remarks.

Mr. S. L. Das, Director (BD&C) welcoming participants.

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The importance of health, safety and environmental (HSE) issues in the hydrocarbon industry has

grown manifold with increasing regulatory oversight and public scrutiny. Companies need toimplement effective measures and management systems in these areas to protect their workers,the general public and the environment.

In this backdrop, to discuss and share the experience of industry professionals with the academia,the Petroleum Federation of India organized a workshop on ‘Safety Health and Environmental

Management in Hydrocarbon Industry’ in association with Indian Oil Corporation Ltd.(Haldia Refinery), the Oil Industry Safety Directorate (OISD) & Lovraj Kumar Memorial Trust (LKMT)from April 17-19, 2015 at the IndianOil Management Academy, Haldia, West Bengal.

The programme was conducted by experts from the industry and OISD and was intended for theteaching faculty of the Engineering Colleges and Universities. Twenty three participants from nineeducational Institutes participated in the programme which included a site visit to the refinery.

Inaugurating the workshop Shri S.N.Jha, former Director (P/L), IOCL & former President, IOTL sharedhis vast knowledge & experience in the field of Safety & Environment and gave several exampleslinking theoretical knowledge with his applied practical experience.

Earlier, Shri A.C. Mishra, ED (IC), Haldia Refinery while welcoming participants emphasized on theimportance of HSE and occupational health of employees in a refinery. He further emphasized onprocess safety and thanked PetroFed for organizing such programmes for enhancing knowledgeof teaching faculty.

Addressing the august gathering during the inaugural session, Shri A. K. Arora Director General,Petroleum Federation of India began by saluting the 'gurus' and went on to add that such Industry- Academia programmes provided an excellent platform for exchange of knowledge,sharing ofexperience and exposure to technology at work. Such programmes benefit both, the academicinstitutions and the industry, he added.

Shri Hirak Dutta, ED,OISD in his address focused on the reliability and integrity of plant & machineryto deliver sustained operations with sharper focus on safety & environment.

Shri H.P. Sahi, ED (Eastern Region), IOCL Pipelines in his address covered the key aspects ofsafety in pipelines operation and maintenance.

Shri A.P. Gangopadhyay, ED (Haldia Refinery) proposed a vote of thanks at the Inaugural Session.

Shri S L Das, Director (BD&C), PetroFed highlighted the utility of such workshops and hoped thatthey would help prepare students better before they step into the world of industry. He profusely

thanked Haldia Refinery for facilitating and hosting this programme.

Industry Academia Interface at Haldia on Health,Safety and Environment

Sh. G.J. Tyagarag, GM(HR), Haldia Refinery welcoming the participants.

Group photograph.

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Session in progress. Sh. A. K. Arora, Director General, PetroFed addressing the participants.

Industry Academia Interface on ‘A-Z of Natural Gas & LNG’

The share of gas in India’s energy mix is expected to go up steadily with the development of gasmarket, new LNG Terminals and a Gas Pipeline grid in the country. These developments envisagesubstantial requirement and deployment of skilled manpower in the gas sector. Considering thecurrent shortage of skilled manpower in the sector, there is an urgent need for revisiting and expandingthe course curriculum by the Technical Institutes including augmenting the knowledge and skills ofthe teaching faculty for building the required workforce.

In this backdrop, the Petroleum Federation of India organized the 4th Industry-Academia workshopon ‘A-Z of Natural Gas & LNG’ in association with the Lovraj Kumar Memorial Trust (LKMT) andPetronet LNG Limited (PLL) from April 30 to May 2, 2015 at Dahej, Gujarat.

The programme was conducted by experts from the industry and designed for the teaching faculty

of Engineering Colleges, Universities and Industry members. Thirty-seven participants from seveneducational Institutes, including 21 from the oil & gas industry attended the programme, whichincluded a field visit to the LNG Terminal of Petronet LNG who hosted the event.

The last few years have seen a lot of changes in the Natural Gas & LNG Industry with many newterminals coming up globally and in India said Mr. Rajender Singh, Director (Technical), PLL whileinaugurating the workshop. The supply side, he added, was impacted due to the decline in domesticproduction and costly imports resulting in idling of about 25000 MW power generation capacity inthe country. Notwithstanding these setbacks, the country needs additional terminal capacity tomeet the future demand. With expansion of Dahej Terminal to 15.00 MMTPA at the end of the IIIrdPhase of expansion (2016) and further addition of 2.5 MMTPA capacity during the IVth Phase (2018),the Dahej Terminal with a total capacity of 17.5 MMTPA will become one of the largest LNG Terminals

globally, he added.

Welcoming participants, Mr. A. K. Chopra, VP (HR & PR), PLL gave a brief background about PLL’sphased development, future expansion programme and the challenges faced on account of non-availability of skilled manpower to suit its needs. It is to meet these challenges and bridge the skillgap that these workshops are organized to provide a hands-on exposure to the teaching faculty onNatural Gas & LNG.

Mr. Suresh Mathur, founding CEO & MD, Petronet LNG Ltd while speaking on 'Challenges of LNG &Economics of its Use' touched upon the impact of gas on replacement of liquid fuels and theresultant saving of foreign exchange for the country. The pipeline grid and last mile connectivity forthe end user however is a must, duly supported by market determined pricing of gas in the country,

he added. Mr. Mathur also chaired the Valedictory session.Mr. S.S. Ramgarhia, Director (Policy & Planning), PetroFed while proposing a vote of thankselaborated on the background of Industry-Academia Interface programmes organized by PetroFed.

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Group photograph. Mr. Pankaj Wadhwa, Vice-President (F), PLL taking a session.

A section of the participants.

Mr. A K Chopra, VP (HR & PR), PLL welcoming the participants.Seated (L-R) Mr. S. Boutalik, VP(Projects) PLL; Mr. Sham Sunder.Former Director (Tech), PLL; Mr. Rajender Singh, Director (Tech),PLL; Mr. S.S. Ramgarhia, Director (P&P), PetroFed.

Mr. Rajender Singh, Dir (Tech), PLL delivering inaugural address.Seated (L-R) Mr. A. K. Chopra; Mr. S.S. Ramgarhia.

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Business Sustainability in Oil & Gas

An integrated approach towards energy pricing and usage and technological advancements wouldbe key factors for sustainable business growth in oil & gas in the near future, said Dr. Kirit Parikh,Chairman, Integrated Research and Action for Development (IRADe) and former Member, PlanningCommission in his opening remarks at a Top Management Conclave on 'Business Sustainability inOil & Gas: 2015 and Beyond' at New Delhi on May 4, 2015. The conclave was organised jointly bythe Petroleum Federation of India and DuPont.

In his keynote address, Mr. Matthew Trerotola, Executive Vice President, DuPont addressed the

issue of 'Managing Sustainable Growth in the wake of Changing Dynamics of the Oil & Gas Sector'.He opined that oil prices may hover in the US$ 65-70 per barrel range for an year or two by the endof 2015.

During the panel discussion, six key industry experts addressed the issues of 'Minimizing OperationalRisk & Enhancing Operational Excellence in India's Oil & Gas Sector'. The discussion was moderatedby Mr. Srinivasan Ramabhadran, Managing Partner - Asia Pacific & Global Director-OperationalRisk, DuPont Sustainable Solutions.

The downstream refining perspective was presented by Mr. Sanjiv Singh, Director (Refineries),IndianOil while the pipelines issues were addressed by Mr. P. K. Chakraborti, President-North Region,IOT Infrastructure & Energy Services Limited. The upstream E&P issues were addressed by

Mr. P. K. Sharma, GGM (OSD), OIL while those of the services sector in E&P were tackled byMr. Jayant Malhotra, Vice President and Global Accounts Director, Schulmberger. The issues ofHealth, Safety & Environment and Project Safety Management were comprehensively covered byMr. Ian Thorpe, Vice President (Health & Safety), HMEL and Mr. Hirak Dutta, Executive Director,Oil Industry Safety Directorate.

The deliberations witnessed healthy floor participation.

A vote of thanks was proposed by Mr. Balvinder Singh Kalsi, President, South Asia and ASEAN,DuPont.

Dr. Kirit Parikh, Chairman, IRADe and former Member, PlanningCommission being welcomed by Mr. Balvinder Singh Kalsi,President, South Asia and ASEAN, DuPont.

Mr. Matthew Trerotola, Executive Vice President, DuPont being greeted by Mr. A. K. Arora, Director General, PetroFed with a bouquet of flowers.

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Dr. Kirit Parikh delivering opening remarks. Participants in rapt attention.

Mr. Matthew Trerotola delivering keynote address. Session in progress.

Dr. Kirit Parikh commenting on the key issues for paneldiscussion.

Mr. Srinivasan Ramabhadran, Managing Partner - Asia Pacific &Global Director - Operational Risk, DuPont Sustainable Solutions introducing the subject.

Mr. Sanjiv Singh, Director (Refineries), IndianOil making his presentation.

A section of the participants.

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Panel discussion in progress. Seated (L-R): Mr. Hirak Dutta,Executive Director, OISD; Mr. Jayant Malhotra, VP and Global Accounts Di rector, Schlumberger ; Mr. Sanj iv Singh,Dr. Kirit Parikh, Mr. Srinivasan Ramabhadran, Mr. P. K. Sharma,GGM (OSD), Oil India Limited; Mr. P. K. Chakraborti, President-North Region, IOT Infrastructure & Energy Services Limited;Mr. Ian Thorpe, Vice President (Health & Safety), HMEL.

Mr. M.S. Ramachandran, former Chairman, IndianOil making his viewpoint.

Dr. Kirit Parikh concluding the session with his observations. Session Chairman, Dr. Kirit Parikh presenting a memento toMr. Matthew Trerotola.

Mr. A. K. Arora presenting a memento to Session Chairman,Dr. Kirit Parikh.

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A brilliant analysis of the historical perspective and events leading to the Companies Act 2013 waspresented by Mr. B.D. Gupta, former President, J M Morgan Stanley Ltd. and Director (Finance),

IndianOil during his Inaugural Address at a Workshop on the subject at New Delhi on May 15, 2015.It was organised by PetroFed in knowledge partnership with member company KPMG on 'Companies Act 2013, Ind AS & ICDS : Catching up with the Developments'. The subject was comprehensivelycovered in three technical sessions.

The Theme Address was delivered by Mr. Ashish Aul, Partner, KPMG who highlighted the significanceof the developments and set the tone and tenor for the day-long proceedings.

Mr. Kaushal Kishore, Partner in the Audit division in BSR & Cos. led the first technical session onthe recent updates and financial reporting under Companies Act 2013. He was assisted in the laterhalf by Mr. Ashish Bansal, Director, BSR & Co.

Mr. Pravin Tulsyan, Partner, BSR & Co. addressed issues pertaining to Ind AS in the second technical

session.

The third technical session was addressed by Mr. Mradul Sharma, Director, KPMG who covered theissues of Income Computation and Disclosure Standards.

The workshop helped in clarifying several doubts engaging the attention of industry members andresulted in intense interactions with the experts.

Companies Act 2013

Mr. B.D. Gupta, former President, JM Morgan Stanley Ltd. &Director (Finance), IndianOil (right) being greeted by Mr. A. K. Arora, Director General, PetroFed (center) with a bouquet of

flowers. Also seen in the picture is Mr. Ashish Aul, Partner, KPMG.

Mr. Ashish Aul, Partner, KPMG being welcomed by Mr. A. K. Arorawith a bouquet of flowers.

Mr. Ashish Aul delivering theme address. Mr. B.D. Gupta delivering inaugural address.

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Mr. Kaushal Kishore, Chartered Accountant making his presentation during Technical Session-1.

Participants keenly watching presentation.

Mr. Ashish Bansal, Chartered Accountant sharing his perspective. Mr. Pravin Tulsyan, Chartered Accountant making his presentationduring Technical Session-2 on 'Ind AS'.

Mr. Mradul Sharma, Director, KPMG making his presentationduring Technical Session-3 on ‘Income Computation and Disclosure Standards’.

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The risks in the global economy have intensified, to a large extent due the un-coordinatednormalization of monetary policies in major G-20 countries. These can have adverse impacts on

financial markets of emerging economies like India, through outflow of foreign exchange and upwardpressure on domestic interest rates.

These were some of the issues highlighted by Dr. N.R. Bhanumurthy, Professor, National Institute ofPublic Finance and Policy (NIPFP) while addressing an invited audience at New Delhi on May 26,2015. He was speaking in PetroFed's continuing series of Guest Lecures and Thought LeadershipProgrammes on issues of 'Global Developments and the Indian Economy'.

The emerging markets, Dr. Bhanumurthy said are already staring at a low economic growth andhigh stress in the banking sector and need to have policies that can withstand anticipated risksthrough building foreign exchange reserves and prudent domestic macroeconomic and financialpolicies.

Dr. Bhanumurthy holds a PHD in International Finance and his research areas are developmenteconomics, macro-monetary economics, international money and finance and macro economicmodelling.

The lecture was well received by the select audience and generated intense floor participation.

Global Developments and the Indian Economy

Dr. N. R. Bhanumurthy, Professor, National Institute of PublicFinance and Policy (L) being greeted by Mr. S.L. Das, Director (BD&C), PetroFed (R ) with a bouquet of flowers.

Dr. N.R. Bhanumurthy delivering his lecture.

Mr. Nirmal Singh, former Secretary, Govt. of India sharing hisview point. Others (L-R): Mr. V. S. Jain, former Chairman,SAIL and Mr. B. D. Gupta, former President, JM Morgan Stanley Ltd. & Director (Finance), IndianOil.

Lecture in progress.

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Some of the industry concerns pertaining to the Companies Act 2013 as well as Ind AS and IncomeComputation and Disclosure Standards (ICDSs) were brought out by Shri Atanu Guha, CFO,Tata Petrodyne Ltd. while inaugurating a workshop on the subject at Mumbai on May 29, 2015.

Organised by PetroFed in knowledge partnership with KPMG, the workshop on subject 'Companies Act 2013, Ind AS & ICDS : Catching up with Developments' was intended to take stock of thesignificant developments till date and discuss the implementation issues that arose therefrom.

The Theme Address at the workshop was delivered by Shri Sai Venkateshwaran, Head, Accounting Advisory Services, KPMG India. He dwelt on the key issues which are currently of concern.

In the first technical session, Shri Kaushal Kishore, Partner in the Audit division of BSR & Co. dealt

with the recent updates of the Companies Act 2013. He was assisted in the later half by Shri AshishBansal, Director, BSR & Co.

In the second technical session, the subject of Ind AS was comprehensively covered by KPMG,Partner, Shri Koosai Lehery.

The last technical session on Computation and Disclosure Standards (ICDSs) was tackled byShri Dinesh Jangid, Director, KPMG.

There was intense floor participation throughout the workshop since there were several concernson implementation which were agitating the industry members. The KPMG experts tackled all queriescompetently.

Catching up with Developments under Companies Act

A section of the participants.Shri Sai Venkateshwaran delivering Theme Address.

Shri Atanu Guha, CFO, Tata Petrodyne being welcomed by Shri S.S. Ramgarhia with a bouquet of flowers.

Shri Sai Venkateshwaran, Head, Accounting Advisory Services,KPMG India (L) being greeted by Shri S.S. Ramgarhia, Director (Policy & Planning), PetroFed with a bouquet of flowers.

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Shri Kaushal Kishore, Partner in the Audit Division of BSR &Co. making his presentation during Technical Session - I.

Shri Atanu Guha delivering Inaugural Address.

Shri Ashish Bansa, Director, BSR & Co. addressing participants.Q&A session in progress.

Shri Koosai Lehery, Partner, KPMG making his presentation duringTechnical Session-II.

Session in progress.

Shri Dinesh Jangid, Director, KPMG making his presentationduring Technical Session III.

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The 2015 theme for the World Environment Day celebrated every year on June 05 is sustainableconsumption and production. It focuses on how the wellbeing of humanity, environment and

economies ultimately depends on the responsible management of the planet's natural resources.The slogan for the theme is 'Seven Billion Dreams. One Planet. Consume with Care'.

In consonance with the theme of World Environment Day PetroFed organized a lecture on 'WaterResources Management for Sustainable Development' by Prof. Janardhana Raju, Professor ofEnvironmental Geosciences at the School of Environmental Sciences, Jawaharlal Nehru Universityon June 5, 2015 at New Delhi.

Prof. Raju, who is an expert on Groundwater Hydrology and Environmental Geosciences focussedon harvesting, conservation and application of surface water. The importance of these issues wasbrought out by him by pointing out the fundamental right to freshwater is not exercised by about3.5 billion women and men across the world according to the UN World Water Development Report

2014. There is enough water on earth - we need to manage it better.The great interest was evinced by participants in the subject particularly on the issue of waterharvesting.

Water Resources Management

Prof. Janardhana Raju, Prof. of Environmental Geosciences at the School of Environmental Sciences, Jawaharlal NehruUniversity being welcomed by Shri A.K. Arora, DG, PetroFed with a bouquet of flowers.

Participants keenly watching the presentation. A section of the participants.

Prof. Janardhana Raju delivering his lecture.

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Options for Revenue Neutral GST for Oil & Gas

As a result of PetroFed representations before the Standing Committee of Parliament as well as the

Empowered Committee of State Finance Ministers, the current Constitution Amendment Bill does

not exclude crude oil & select petroleum products. Stating this, Shri R.S. Butola, former Chairman,

IndianOil stressed that we should take the matter forward and ensure inclusion of all petroleum products

in the scheme of GST while chairing a session on the subject at New Delhi on June 12, 2015.

Organised under PetroFed's series of Guest Lectures and Thought Leadership Programmes, the

lecture was on 'Options for Revenue Neutral GST for Oil & Gas' by Prof. Sacchidananda Mukherjee,

Associate Professor, National Institute of Public Finance and Policy (NIPFP). In a detailed presentation

Prof. Mukherjee brought out the fact that there were alternatives for inclusion of Oil & Gas in the

scheme of GST from the beginning since their elimination would lead to cascading of taxes which

could be detrimental for competitiveness of Indian industries in international market.

Non availability or partial availability of input tax credit will result in stranded costs for some sectors

and the costs may be spread across all sectors of the economy through sectoral inter-linkages.

Prof. Mukherjee concluded by highlighting that there is little ground for separating out petroleum

products for special treatment by keeping them out of the base of GST.

The subject being of great importance to the sector witnessed intense floor participation.

Shri R.S. Butola, former Chairman, IndianOil (R) being greeted by Shri A.K. Arora Director General, PetroFed (L ) with a bouquet of flowers.

Prof. Sacchidananda Mukherjee, Associate Professor, NationalInstitute of Public Finance and Policy (NIPFP) (R) beingwelcomed by Shri A.K. Arora (center) with a bouquet of flowers.

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Prof. Mukherjee responding to a question. A section of the participants.

Shri R.S. Butola delivering his opening remarks. Prof. Sacchidananda Mukherjee making his presentation.

Shri R.S. Butola presenting a memento to Prof.Sacchidananda Mukherjee.

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The Governing Council of the Petroleum Federation of India at its 38 th meeting on June 15, 2015welcomed Chandigarh University as a member of the Federation.

It deliberated on the reorganization and succession plan of PetroFed and conveyed its appreciationfor the diverse set of activities that had been taken up since the previous meeting. In this regardparticular note was taken of the study report sent to the Government on ‘Stimulating DomesticExploration and Production in India - Policy Recommendations’.

It was noted that PetroFed employees had contributed their one-day salary to the Prime Minister'sNational Relief Fund for assisting earthquake victims in April, 2015. A similar contribution had beenmade in July 2014 for assistance to the victims of floods in Jammu & Kashmir.

38 th Governing Council Meeting

Chairman, Shri B. Ashok addressing the Governing Council. Shri P. Raghavendran, Vice Chairman, PetroFed participated inthe meeting through video conferencing.

The Governing Council members at New Delhi interacting withShri P. Raghavendran through video conferencing.

Meeting in progress (L-R) Shri U. Venkata Ramana, Director (Technical), CPCL; Shri T.K. Sengupta, Director (Offshore),ONGC; Shri A.K. Arora, Director General, PetroFed; Shri B. Ashok,Chairman, PetroFed and Chairman, IndianOil; Shri M.A. Pathan,

Management Consultant & former Chairman, IndianOil and former Resident Director, Tata Group; Shri R.S. Butola, Honorary Member and former Chairman, IOCL and Shri S.P. Gathoo,Director (HR), BPCL.

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