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contents OIL & GAS WORLD EXPO 2014

VOL. 11 NO. 2 FEBRUARY- MARCH 2014 MUMBAI ` 200

OFFSHORE WORLD R.NO. MAH ENG/ 2003/13269 Chairman Publisher & Printer Chief Executive Officer

Jasu Shah Maulik Jasubhai Shah Hemant Shetty

EDITORIAL

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Transcending Boundaries

– Sudhir Vasudeva, Former CMD, ONGC

‘ While there can be room for power politics but there shall not be politics on power’ 10

– A K Jha, Technical - Director, NTPC ‘Pricing should be driven by market, energy security will automatically come’ 13

– ‘A K Balyan, MD & CEO, Petronet LNG Ltd

INTERVIEW ‘The enormity of GGSR leverages proximity of petroleum products in Northern parts of India’

22

– Prabh Das, Managing Director & Chief Executive Officer, HMEL, Bathinda

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Sensor Technology to Enhance Gas Detection Safety in Asia Pacific 15

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– Wilson Tan

FEATURES Completions Evaluation for Hydraulic Fracture Monitoring in Unconventional Resources 17

– Sudhendu Kashikar Achieving Predictable Operational Efficiencies 20

– Philip Wade

Slurry Phase Hydrocracking: Bottoms Upgrading for Today’s Market 25

– Steve Mayo, Mitra Motaghi & Rahul Ravi

Different Energy Commodities on Different Paths 31

– Niteen Jain & Nazir Moulvi

NEWS FEATURE

Iranian Gas Export through Pipeline 33

– Hedayat Omidvar LNG - Fuelling the Future 38

– Rakesh Roy India Awards 46 Blocks in NELP-X 40

– Rakesh Roy

MARKETING INSIGHT

Lowdown on Indian Refining Sector 41

– Mittravinda Ranjan

TRENDS

News 43

Products 50

Events Diary 55

PROJECT UPDATE 53

BOOKSHELF 56 Offshore World | 4 | February - March 2014

LeaderSpeak

Transcending Boundaries “Oil & Gas World Expo is one of the most important events in the Western India,” complemented Sudhir Vasudeva, Chairman & Managing Director, ONGC & General Chairman Oil & Gas World Expo 2014. In his address, he expressed grave concerns regarding the rising energy demand and identified five critical key areas that must be addressed for resurgence of India’s oil & gas industry during the inauguration of Oil & Gas World Expo 2014 in Mumbai. Excerpts…

Recent news about India overtaking Japan as the third largest crude oil importer is a matter of deep concern, which somehow was not covered well by the media. In my belief, such news should find place in the headlines if not for anything but to enhance awareness in people about the extent of energy consumption, which is going to cause a lot of problem as we move forward.

Earlier, the 4 th largest energy and oil consumer , India has now become 3 rd largest oil impor ter with 3.86 MBOPD and exceeded Japan’s crude imports of 3.64 MBOPD by 6 per cent. China is the largest consumer of oil and imports 6.3 MBOPD followed closely by USA with imports of 6.24 MBOPD crude imports.

Indian economy is expected to grow at 4.9 per cent according to latest repor ts, which implies greater energy intensit y and higher cost of converting energy into GDP, not a good indication for growing economy like India. Although India is becoming a refining hub and expor ter of petrochemicals, however growing crude oil consumption despite a slowing economy indicates highly inelastic nature of our demand in India. Diesel has continued to be a big contributor to the subsidy despite the fact that the Government has decided making diesel prices market determined gradually.

The other side that in news that is going to add to the woes is the energy forecasts by BP Energy Outlook & IEA. New BP Energy Outlook 2035 report suggests that global energy consumption is likely to grow by an average of 1.9 per cent per year from 2012 to 2035. International Energy Agency www.oswindia.com

(IEA), in its latest market oil repor t has indicated an increase in global oil demand over the last 18 months driven by economic recovery in the developed world. Agency has forecasted that global oil demand would touch 92.5 MBOPD by the end of 2014, an increase of 1.3 MBOPD over last year’s demand.

Market Shifts Most of OECD countries have recovered from the pain of recession and are back on the path of growth and few countries like Syria, Iraq and Iran have increased their production. However rising oil demand will continue putting spanner in the expectations of softening crude oil prices in the near future. India’s current oil import bill stands at USD 164 billion per year which is already 10 per cent of GDP thus putting more pressure on the already stressed current account deficit.

I am an optimist and strongly believe that we have the capacity and capability to overcome such crisis. We are well aware about the widening demand supply gap in oil & gas that forms nearly 40 per cent of our primary energy basket and the policy makers are equally aware of the requisite steps. At the moment, I want to draw attention emphasise upon the fact that there is no room for compromises if we are really aspiring to grow as we are.

The Ministry of Oil & Natural Gas has taken several actions in the recent past, which clearly indicates that Indian oil & gas sector means business. On one hand the Ministry instituted Rangarajan Comiitee and Kelkar Committee to comprehensively sort out the issues plaguing the growth of industry and on the other hand taken initiatives like simultaneous exploration in Pre NELP and

Offshore World | 6 | February - March 2014

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NELP blocks along with the announcement of NELP-X round and shale gas policy. The Government has also chalked out priority list of further reforms and pursuing on war footing to bring in new hope and enthusiasm in the industry.

Couple of months back, the Minister for Oil & Gas addressed the audience of journalists, investors and analysts for candid assessment of what was ailing the Association of Oil & Gas Operators (AOGO). At that time, if somebody would have called and asked about the industr y outlook , we would have said that it was pessimistic. But exactly one year down, the outlook has become ‘cautiously optimistic’. The Minister and the Secretar y asked that what should be done fur ther to remove the word ‘cautious’ to be ‘optimistic’ and promised working on the prescribed solutions during the next two to three months to achieve long term gains. In the last two months, most of that has been done including revision of gas prices and announcement if shale gas polic y which is making the industr y more vibrant. Also the cabinet committee has taken the bold decision of clearing almost 79 blocks that were stalled for couple of years and ushered new era of confidence amongst the investors. Government is also giving significant attention to setting up infrastructure for gas transpor tation which includes LNG re-liquefaction terminals, gas distribution network, and transnational pipelines.

Unbearable Subsidy Burden The concepts of energy conser vation or energy sufficienc y are much below the levels that are desired; and thanks to the government largesse in terms of offering substantial subsidies offered to the consumers.

Increasing subsidy burden is a matter of grave concern to the oil & gas industr y causing sleepless nights. Last quar ter we were burdened with ` 1 3 7 9 6 c ro re s u b s i d i e s w h i c h c l e a r l y m e a n s s u b s i d y b u rd e n o f ` 50,000 crore this year too that will leave the E&P companies with a margin of USD 2 for oil production. The fear of subsidies offered to the fertiliser industry is looming at large due to increase in gas prices or on account of LPG cylinders, where capping has been increased from 9 to 12 that will account for ` 5000 crore subsidies.

The subsidy burdens are becoming unbearable for the upstream companies a n d e ro d i n g t h e s t re n g t h to i nve s t m o re i n E & P a c t i v i t i e s a n d t h e morale of work force as well as this directly impacts the per formance i n ce nt i ve s. D e s p i te t h e h a rd wo r k p u t u p towa rd s m a i nt a i n i n g a n d s u s t a i n i n g p ro d u c t i o n f ro m ve r y o l d o i l f i e l d s, t h e e m p l o ye e s d o n o t g e t t h e i r p e r f o r m a n ce p a y s, w h i c h i s e x t re m e l y d e m o r a l i z i n g for them.

While operators are encouraged and motivated by reforms being taken by the Ministr y or recommendations by Rangarajan committee towards increasing gas price or change from cost recovery mechanism to revenue sharing mechanism, subsidies have continued being the major concern

>>Indian economy is expected to grow at 4.9 per cent according to latest reports, which implies greater energy intensity and higher cost of converting energy into GDP, not a good indication for growing economy like India. www.oswindia.com

for the E&P upstream companies. I am glad to share that with repeated requests from our side, the government has decided to act and already moved the note to CCEA to provide ONGC & OIL India, USD 65 per barrel of production rather than USD 56 per barrel. Once our revenue streams stabilise, everyone would come to know about our performance and we will be able to generate sufficient funds to support our outlays and may be even the future expansion plans.

Moving Forward At this juncture, higher emphasis on exploration and urgent focus on investments, greater effor ts and more resources into strengthening the domestic energy base through more ex tensive exploration of Indian sedimentar y basins are need of the hour for Indian oil & gas sec tor.

Fur ther overseas forays for sourcing equit y oil are equally impor tant to ramp up the domestic production for sound national energy supply situation which will mitigate the degree of uncer tainty and associated risks with overseas ventures due to geopolitical disturbances to significant ex tent. Second, India needs unambiguous, transparent and stable policy framework and create more enabling and conducive polic y regime to encourage oil & gas players. Most impor tantly, the reforms have to be well timed and incorporated in the policy regime like the recent decision of shift in domestic gas price to market linked price with effect from April is a welcome move. Third, gas is the future fuel for India with large demand supply gap. In fact India needs to create required infrastructure in gas and related business that includes setting up LNG infrastructure and transnational pipelines etc. for all inclusive growth of countr y with the last mile connec tivit y to reach out to the gas consumers at affordable cost.

Research & D evelopment is cornerstone for securing energy supplies of future which requires knowledge sharing across wider gamut of oil & gas industr y players rather than being bottled up in countries or restricted within companies. India needs to pursue more focussed R&D in collaboration through global alliances to gainfully deploy technology for efficient and safe monetisation of resources. While we are contending with the reality of big changes taking place in Indian oil and gas industry, we must integrate the energy of youth to leverage the creative potential and enterprise of our country more so during the time when youth are looking at the sector.

Wi t h t h i s, I co n c l u d e t h i s o i l a n d g a s ex p o t ra n s ce n d s t h e boundaries of the event and this will finally ac t as catalyst for the g ro w t h o f t h e o i l a n d g a s i n d u s t r y a n d a b o ve a l l t h e e co n o my o f the country.

Offshore World | 8 | February - March 2014

Offshore World | 1 | OCTOBER - NOVEMBER 2013

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LeaderSpeak

‘While there can be room for power politics but there shall not be politics on power’ Energy security is a critical issue for India because of continuously increasing dependence on imports to meet the ever widening demand- supply gap. A K Jha, Director - Technical, National Thermal Power Corporation (NTPC) & Chairman Central Advisory Board (CAB) EnerTECH World Expo 2014, expressed, “It would be an idea worth exploring that whether we can have a combine ministry of energy rather than having separate ministries for Coal, Gas and Power etc” while inaugurating the power and energy exposition held concurrently during the Oil & Gas World Expo 2014. Excerpts …

Energy security mandates optimum utilisation of both available as well as scarce resources through 360 degree approach that involves all stakeholders of the energy value chain from energy production to power generation, transmission & distribution along with all systems working efficiently; balancing demand and supply sides most effectively to provide affordable power to the achieve desired growth rates and meeting individual energy needs.

Although India is the 6 th largest country in terms of power generation, per capita consumption stands at 800 units per capita, which is very low as compared to the world average of 2400 units per capita. Industry is the largest consumer of energy and accounts for 38 per cent of consumption, while agriculture and domestic consumers form 22 per cent each, commercial 8 per cent and miscellaneous 10 per cent of India’s energy pie.

Thermal power has a dominant share in India’s energy basket and comprises 65 per cent of country’s power generation followed by hydropower 22 per cent, renewable sources like wind, solar & biomass 10 per cent; and nuclear energy which accounts for 3 per cent of total power generation.

Under the 11 th Five Year Plan, India added record capacity of 54,964 MW of capacity and envisages augmenting the capacity by 85,000 MW by the end of 2017. Thermal energy will continue dominating the energy sector as setting up gas based plants would still be a challenge due to scarcity of availability. www.oswindia.com

Government has set ambitious target of scaling up renewable capacity from current 27,000 MW and add another 30,000 MW. India has committed to producing 30,000 MW of nuclear power by 2032. Thus the power portfolio of India is well diversified in terms of fuel mix which mitigates the risk of the energy security to a very large extent.

In India, mainstream capacity comes from coal based stations. However, the irony of situation is that despite having the 5 th largest coal reserves globally, India has to still depend on imports to meet the coal requirement of power plants. In order to meet the augment the targeted capacity by 2017, power plants would require around 688 million tonne per annum (MTPA) by 2017 and projected supplies are likely to be short by 159 MTPA which would require India to rely on coal imports for the supply deficit. Over the past five years, while power generation capacity has increased at CAGR 14 per cent, coal supplies have grown only at 6 per cent CAGR. Bottlenecks in land acquisitions and receiving environmental clearances and issues such as payment crisis have proved to be major deterrents for the growth of power sector. There are also logistics issues related to moving coal production from the mines because of lack of railway connectivity that India’s national company, Coal India Ltd (CIL) is facing.

The Government has entrusted CIL & NTPC with the work to develop the rail lines to create the necessary logistics supply chain for movement of coal to power stations.

Demand supply gap has compelled the power producers to enter the fuel supply agreements for 65 per cent of Plant Load Factor (PLF) capacity as against the

Offshore World | 10 | February - March 2014

>>Thermal power has a dominant share in India’s energy basket and comprises 65 per cent of country’s power generation followed by hydropower 22 per cent, renewable sources like wind, solar & biomass 10 per cent; and nuclear energy which accounts for 3 per cent of total power generation. promised coal linkage for 85 per cent PLF. As a result, out of 89 generating stations, only 55 are working below their full capacity.

On the other hand, gas based power plants of 15000 MW capacity are also stranded due to gas deficit. Post gas discovery in KG basin, power producers had shown lot of interest in establishing fuel linkages for the proposed gas based power plants however this request was turned down by the regulators who decided to allocate the gas on the basis of priority depending on the completion of power project. This was in stark contrast with the existing policy for thermal plants where the coal linkages were mandatory to even get environmental clearances. NTPC decided had to put the plans of capacity addition of 5000 MW gas based plant on back burner, however many private players forged ahead with the plan and now the entire capacity is stranded and capital blocked!! In fact, NTPC’s existing gas based capacity of 4000 MW is also running at 13 PLF due to gas shor tage and the government has decided not to provide ay clearances for setting up more gas based capacity until 2016.

Poor financial health of Distribution Companies (DISCOMs) is another major constraint due to which power companies have to resort to load shedding.

The paradox is that during load shedding consumers generate their own energy using diesel generators at the rate of ` 18-20 per unit. Cumulative loss to DISCOMs has reached figure of ` 2,40,000 crore in 2012 and combined debt reached ` 1,90,000 crore as most of DISCOMs had opted for short term loans to meet their operational cost requirement. In 2001, the Government did come up with one time settlement policy scheme for dues with the hope that in 15 year time, by 2016 the DISCOMS would become financially viable. But in 2012, Government announced the financial restructuring package for debt ridden distribution entities however, for long term healthy growth, it is critical for DISCOMs to reduce the losses. As a matter of fact, practice of following annual tariff rationalisation according to changing input cost by State Electricity Regulators instead of past practice non division of tariff for years together and timely payment of subsidy announced by the state for cer tain section of consumers can positively impact on the health of DISCOMs. Out of 195 allocated coal blocks to public and private sector companies, some are under scrutiny by the cour ts, which is another major issue, as such assets stand great chance of becoming Non Per forming Assets (NPA) for banks, capital investors and developers. Such distress assets may lead to the perception of power projects as high risk investments which may lead to interest hikes for project financing, escalating the cost of power generation and eventually impacting the tariff for the end user or consumer. www.oswindia.com

Indian government’s efforts to speed up nuclear energy capacity addition though joint venture of central PSU with Nuclear Power Corporation of India Ltd (NPCIL) are also on hold due to the amendment required in Atomic Energy Act. Moreover, the clearance of nuclear liability bill is taking long time which is proving to be a major deterrent towards the interest of foreign nuclear power equipment suppliers due to high risk and liability for the manufacturer. NTPC has already entered the JV with NCPIL for construction of 2X700 MW nuclear power stations in Haryana.

Way Forward In today’s context, it is important to have an integrated energy policy but that is not enough unless there is integration in implementation of policy by all the concerned departments at all levels - in tandem.

It would be an idea worth exploring that whether we can have a combine ministr y of energy rather than having separate ministries for Coal, Gas and Power etc. There is also the need to speed up of setting up nuclear plan to address the twin issues of CO 2 emission & the rising imported fuel cost and amendment to the Atomic Energy Act needs to be expedited.

Early commercial flow of energy between Southern grid and rest of the country will help in balancing the power cost in the two different regions.

Fur ther strengthening of inter-region grids are necessity to ensure the free flow of power is done then we are able to avoid blackout as we witnessed in 2012.

Challenges of having large amount of renewable energy in the grid, available for only limited hours and forecasting its availability needs to be addressed through implementation of smar t grid. This would require our DISCOMs to be financially viable and technically competent for effective implementation and management of smar t grids towards consumer benefit.

Appointment of coal regulator to fix reasonable price to check the e l e c t r i c i t y p r i ce s s h o u l d b e co n s i d e re d g i ve n t h e f a c t t h at I n d i a n co n s u m e r s a re e x t re m e l y p r i ce s e n s i t i ve. A co m m i t te e to f i n a l i s e railway goods tariff would also be a good move to keep a check on cross subsidies which adds substantially to the power cost and cannot be totally eliminated.

Last but not the least, political leadership should agree that while there can be room for power politics but there shall not be politics on power; and then only India can think of taking quantum leap to 800 unit per capita power consumption as compared to the world average of 2400 unit per capita to be truly in the category of developed nation.

Offshore World | 12 | February - March 2014

LeaderSpeak

‘Pricing should be driven by market, energy security will automatically come’

Dr A K Balyan, Managing Director & CEO, Petronet LNG Ltd receives ‘Outstanding Achievement (Natural Gas) - Oil & Gas 2014 Leadership & Excellence Award’ from L N Gupta, Secretary, Oil Industry Development Board, MoPNG.

High economic growth would lead to increase in the energy consumption of the country. So oil & gas sector of a country like India, a developing economy coupled with more than 1.25 billion people, needs to resurgence in a manner that the energy needs can be met.

Coal remains the dominant fuel in the Indian energy mix with a robust 53 per cent share in the primary energy consumption, followed by crude oil at 30 per cent and gas at 9 per cent. Other sources include 5 per cent hydroelectricity, 2 per cent renewable and 1 per cent nuclear energy.

India has now become 3 rd largest oil consumer worldwide exceeding Japan.

The country’s share in oil consumption now stands 4.2 per cent of the total oil produced worldwide. The country must be conscious that this energy is coming at a cost, at a much higher cost and consider the Indian economy’s affordabilit y to bear the much higher prices in accessing the energy; therefore it is not only the consumption but also the conservation that is equally important.

India’s per capita oil consumption is very low - just about 142 to 143 kg per person compared to China which is more than double of India - about 360.07 kg, and nowhere near the developed countries like the US & Japan about 2612.33 kg and 1713.1 kg, respectively.

For a country like India, a developing nation with a vast population, to ensure energy availability and accessibility to all at affordable price and guarantee uninterrupted and smooth supplies within the framework of inclusive growth is always a challenge.

According to Dr A K Balyan, Managing Director & CEO, Petronet LNG Ltd, “In making the ability to meet the growing energy demand of the country, we need to find out the way how can we achieve it, looking it within the country, looking it outside the country.”

Edited excerpts from Balyan’s presentation delivered during the inauguration of Oil & Gas World Expo 2014…

Again per capita gas consumption in India stands very low - about 45 cubic meters per person, which is less than half of China, and far away from the developed economies like the US & Japan. Over the last two and half years, the country has been seeing a remarkable reduction in overall gas consumption due to the decrease of domestic production despite of a growth on the primary energy mix.

India’s LNG Import profile is highly dependent on Qatar which contributes nearly 79 per cent of the total. The country must widen its portfolio in quickly diversifying the supply sources in getting LNG from other regions of the world from the energy security point of view.

Role of Natural Gas Currently, India is the 13th largest gas consumer (55 BCM), and 4th largest gas/LNG importer globally after Japan, Korea and Spain. India would marginally increase the domestic production in the coming year, but dependency on import gas would continue. Resurgence in oil & gas sector, and taking petro products and gas to the consumers becomes very important. So there is one area, which should be epidemic to that resurgence, is the pipeline network infrastructure development.

Over next years, there will be substantial increase in natural gas demand from power, fertiliser and industrial sectors. Currently, power and fertiliser sectors are the two

Offshore World | 13 | February - March 2014

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>>Coal remains the dominant fuel in the Indian energy mix with a robust 53 per cent share in the primar y energy consumption, followed by crude oil at 30 per cent and gas at 9 per cent. Other sources include 5 per cent hydroelectricity, 2 per cent renewable and 1 per cent at Kochi). The proposed terminals at Gangavaram, Mundra, Ennore is likely nuclear energy. biggest contributors to natural gas demand in India and continue to account for more than 65-70 per cent of gas consumption both domestic and LNG put together. But one sector - City Gas suggests a sustained increase in the level of natural gas consumption in the country in the coming years, where several hundred cities have been identified for supplying gas in the next couple years time. This sector will certainly drive the pipeline industry in the country.

Demand Supply Projections & Gap India’s natural gas demand, which stood at approximately 227 MMSCMD in 2012-13, is forecasted to see steep increase to around become three folds reaching 713 MMSCMD in 2029-30. On the supply side, it is certain that over the next several years, E&P efforts will result in an increase in the availability of natural gas in the country, but it is not possible to visualise a situation where increase in domestic gas production will be able to completely meet incremental domestic demand going forward. The demand supply gap will increase steadily and is expected to be around 482 MMSCMD in period 2029-30.

The question is that how will the country meet the supply demand gap? The answer would be high dependence on gas imports which can be achieved by two ways – one is transnational pipelines and the other would be establishing LNG linkages.

Though there has been some progress on the front of transnational pipeline projects that have been in a limbo for quite some time, but even these projects are not going to result in dramatic changes to the bridge the demand supply gap. Even with these pipelines in place the landed volumes are going to be of the order of 30-35 MMSCMD while the shortfall would stand at approximately 400 MMSCMD. In such scenario, LNG would perhaps be the best bet to bridge the supply deficit and this is certainly showing signs of resurgence in the oil and gas sector.

LNG Sourcing Currently, LNG is imported in India through mix of long term and short term linkages and spot basis. India currently has long term contracts between Petronet LNG and RasGas, Qatar for 7.5 MMTPA and Petronet LNG and Mobil Australia Resources Limited for 1.44 MMTPA from Gorgon Project, Australia, GAIL and Chenniere Energy, USA for 3.5 MMTPA and GAIL and Gazprom, Russsia for 2.5 MMTPA. LNG Regasification Capacity As on date, India’s LNG re-gasification capacity is 23.00 MMTPA (10 MMTPA at Dahej, 5.00 MMPTA at Hazira, 3.00 MMTPA at Dabhol, and 5.00 MMPTA www.oswindia.com

add 15 MMPTA to raise the capacity 45 MMPTA by 2016 and the possible in the west-coast, Kakinada, Pipavav will add total of 12.50 MMPTA by 2020 and thus the country’s total capacity is likely to raise to 62.5 MMPTA by 2020 with each or majority of existing LNG terminal in India having the option to expand further. It would be a good solution for the country’s energy demand.

The challenge remains how the country can get contracts for affordable, larger quantity of the gas into the country.

Gas Transportation Infrastructure Pipeline infrastructure is the nervous system of the gas business in India.

India, currently, has a network of more than 13,000 km of natural gas transmission pipelines with a design capacity of around 330 MMSCMD, and there is proposal to add equal number km of pipeline in two-three years time, but these requisite is still inadequate, and a larger area would still need more pipeline connec tivit y. This pipeline net work is expected to expand to around 28,000 km with a total design capacity of around 731 MMSCMD in next 5-6 years, putting in place most of the National Gas Grid that would connect all major demand and supply centers in India.

The east, west and south - each region of the country, need adequate pipeline network to take the gas from the terminals to the different markets of the country and that will definitely enhance the development of the gas market in the country.

Way Forward While the country is emerging as major LNG market of future, the country needs to work towards developing an India specific index from LNG point of view.

This would facilitate more business and more resurgence in the gas business, with all round development in LNG terminals, gas storage, and gas pipelines on national and transnational basis to attain desired sustainable growth. Also this would help the country in terms of affordability of the pricing because this would be reflecting the Indian economics’ affordability level.

India would also need to take strategic decisions to attract global players and ensure they participate in infrastructure development. Creation of robust City Gas Network across country is of utmost importance for the smooth supplies of natural gas and to ensure the allocation of gas to every corner of the country.

Last but not the least; the country needs to work towards the mindset of consumers on pricing. Pricing should be driven by market forces and ultimately it will lead to energy security of the country. A comprehensive approach, which can meet suppliers’ expectation on one side and meet consumers’ price expectation on other side, needs to be firmed up.

Offshore World | 14 | February - March 2014

guest column

Sensor Technology to Enhance Gas Detection Safety in Asia Pacific Twenty years ago, we all bought computers with little understanding of inner component workings or the clever technology that actually made our device perform so well and effectively. Today, thanks to a highly effective global marketing campaign from a leading processing chip manufacturer, who taught us to ‘look inside’ our PCs, we now all appreciate that our computers are only ever as good as their processing capacity, regardless of any other impressive functionality they might offer.

This is a good analogy for the gas detection industry; there is much focus on the gas detection solution itself and all the value such a device can bring in terms of enhancing safety, reducing costs or providing simplified use, but the sensor component itself is equally important.

A gas detector is comprised of essentially two core elements; its sensor, which provides the means of identifying and quantifying a cer tain g a s i n t h e s u r ro u n d i n g at m o s p h e re a n d i t s hardware/software, which uses this data to deliver real-time concentration readings and trigger alarms, if pre-defined levels are reached. Both aspects are critical and without a high-quality sensing element, a gas detector is nothing more than electrical components and software that has no real use or value.

Wilson Tan, Business Leader for City Technology in Asia Pacific, is a gas sensing expert well-versed in the importance of high quality sensing principles and why they are so essential to high performance gas detec tion. Wilson Tan talks t o O f f s h o r e Wo r l d a b o u t t h e challenges facing many industries, like offshore oil and gas, where the considerable dangers make highly sensitive sensor detection even more important than ever.

In today’s ever-more safety conscious World, the protection of assets and personnel is always top of mind for businesses but industries like off-shore oil and gas demand the highest levels of performance and enhanced safety, owing to the sizeable explosive and toxic risks presented by the myriad of gases present. These include diverse Hydrocarbons like Methane (CH 4 ) and toxic gases like Hydrogen Sulphide (H 2 S), Carbon Monoxide (CO), Carbon Dioxide (CO 2 ) and Sulphur Dioxide (SO 2 ) and also Oxygen (O 2) depletion.

The applications for gas detection in the upstream industry are diverse. Driller stands, mud return line receiver tanks and pit rooms, compressors, pipelines and seals all require flammable, H 2S and O 2 monitoring. Water supplies need flammable and H 2S, CO 2, SO 2 and NOx toxic gas detection to monitor run off gullies.

HVAC ventilation systems and air intakes require flammable and toxic cross-duct remote sensor mounting for effective monitoring. If H 2S is being removed from crude mix on a platform, dehydration and temporary refuge area/H 2S refuges should also be monitored for flammables and toxics including CO 2, SO 2 and H 2S.

Failure is Not an Option In reality, a sensor has a very hard job to undertake – not only must it detect gas risks, but it must do so consistently in all environmental conditions it may be subjected to. The sensor must also be selective only to the gas it is detecting because crossinterference can cause inaccurate readings. Added to these aspects is a need for a sensor to be able to protect itself from compounds that can adversely affect its detection; namely ingress by particulates or water and also potential ‘poisoning’ from reactive compounds in the atmosphere that could adversely affect its performance.

Offshore World | 15 | February - March 2014

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P l a t f o r m p ro c e s s e s a re d e s i g n e d t o d e l i ve r maximised yield and gas detec tion must be capable of delivering not only high sensitivity but maximised uptime and stability; just one nuisance alarm that requires a process shutdown of 60 minutes on an oil rig producing 15,000 BPD, can equate to a revenue loss of USD 60,625 ( b a s e d o n a 2 4 h o u r p ro d u c t i o n d a y a n d a price of USD 97/barrel – barrel price source: Financial Times).

Geological and Environmental Impacts A s i d e f ro m t h e o bv i o u s a s s o c i ate d i n d u s t r y risks, it is wor th noting that regional factors in Asia Pacific can have a considerable impact and increase the dangers, making sensitive, accurate, high performance detection even more imperative to worker safety. Although fracking is an on-shore activity, it does provide a good example of environmental impact. Shale gas reserves in the Asia Pacific region typically exist in deeper wells that can also feature increased geological complexity and this can cause higher levels of H 2 S to be present. The abundance of CH 4 also makes flammable sensor performance key to application safety. Added to this are other local factors such as the location of shale gas reserves, which are predominantly in the arid west and southwest, w h e re te m p e rat u re s a re h i g h a n d h u m i d i t y is low.

>> In reality, a sensor has a very hard job to undertake – not only must it detect gas risks, but it must do so consistently in all environmental conditions it may be subjected to. The sensor must also be selective only to the gas it is detecting because cross-interference can cause inaccurate readings. gas sensors to work in. There is the potential for ingress by compounds and water vapour/ sea spray that must be prevented using filters, sinters and small capillaries. Ambient conditions can change dramatically and temperature can fluctuate considerably in a single day in arid locations. Sensors from leading manufacturers should be designed and tested to respond to such conditions, working bet ween -40°C and 55°C making them capable of meeting the needs of Asia Pacific. They should include technologies and components that allow the sensor to adapt quickly to large temperature fluc tuations effec tively so diurnal fluctuation in arid locations is not an issue.

Other Sensor Challenges Humidity is a particular concern for Electrochemical Cell (ECC) sensors, which use an aqueous system that is potentially susceptible to humidity effects.

Leading-edge ECC sensors should be able to work effectively between across a wide range of RH conditions, meeting the demands of even the most challenging locations through their intelligent component design, which must prevent drying out or saturation.

Accidents happen and devices can easily be dropped, so sensors need to be highly robust and capable of withstanding impacts and mechanical vibrations. D rop tests should be performed from 6.7 ft/ 2 m to meet certifications and a sensor must be able to withstand the force of such an impact as well as high levels of ambient vibration.

What to Look for in a Sensor I am often asked what to consider when selecting the right sensor solution. The oil and gas industry p ro v i d e s t h e i d e a l co nte x t to h i g h l i g ht t h e core attributes needed, because it represents s o m e o f t h e m o s t c h a l l e n g i n g l o cat i o n s f o r www.oswindia.com

S e n s o r s m u s t a l s o b e a b l e to m i n i m i s e t h e e f f e c t s o f c ro s s - i n t e r f e re n c e , w h i c h c o u l d cause inaccurate readings and nuisance alarms. There are various compounds that can impact performance including cer tain alcohols w h e n d e te c t i n g H 2 S a n d t h e s e e f f e c t s m u s t be negated.

Long life sensors are a considerable advantage because they can help to ex tend maintenance Offshore World | 16 | February - March 2014

inter vals. This can have a dramatic impact on your ongoing costs and a good manufac turer w i l l h ave s o l u t i o n s t h at ca n o f f e r ex te n d e d operational life, helping you to make future savings over the product life of your por table gas detector.

A quick response is also imperative; even when rapid concentration changes are experienced. An example is hydrocarbon cracking processes within a refinery where large levels of CO can be released and must be detected without delay.

S o m e t h i n g t h a t i s o f t e n o v e r l o o ke d i s t h e importance of repeatability; you need to be able to rely on your manufac turer’s processes and controls so that each sensor you use works exactly as it should, every time. Take a holistic approach to selecting a manufacturer and be sure that their production practices can deliver consistent high quality results.

Why Knowing What’s Inside is so Important The sensor you use is so much more than the little unseen component inside your gas detector.

It’s the difference between nuisance-alarms or maximised accurate detection performance; the difference between reduced ongoing device care requirements or a more frequent maintenance regime need; the difference between adaptability to changing environmental fac tors or an inability to perform in harsh locations. And most important of all, it’s the difference between an engineer going home safe to his/her family after a hard day’s work or not.

Yo u w i l l a l re a dy b e awa re t h at t h e s e n s i n g technology you use protects the lives of your employees, but you may not have considered the effect it could have on your business efficiency.

Make sure you provide as much consideration to the sensor in your gas detection device as you do to the device functionality itself – it save lives AND also saves money in the long run, so take the time to consider ‘what’s inside’ YOUR’ gas detector and choose wisely.

features Fracture Evaluation

Completions Evaluation for Hydraulic Fracture Monitoring in Unconventional Resources Today ‘fracture evaluation’ is performed using various simulations that use microseismic data to qualitatively calibrate the model. This article demonstrates new developments that enable valuable information to be extracted by combining contextual information such as geology, well logs, treatment data, etc with deterministic analysis of the microseismic measurements, providing quantification of the hydraulic fracturing.

Microseismic is now an accepted technology used to monitor hydraulic fracturing. It is used to measure the geometr y, location and complexity of the fractures. Although microseismic monitoring has added value in understanding hydraulic fractures, there is still significant information and value that can and should be extracted from any microseismic monitoring programme. Most of the microseismic analysis per formed to - date is qualitative and has provided limited value in optimising completions.

To fully optimise the completion and fracture treatment, it is important to understand various aspects of fracturing treatment such as – differentiating propped and un-propped fractures, fracture growth and geometry, fracture overlap between stages and wells, stress shadowing effects, and treatment efficiency.

Currently this is achieved by a qualitative comparison of microseismic points with simulation models.

Fi g u re 1 s h o w s a n i d e a l i s e d p ro c e s s f o r c o m p l e t i o n s a n d f r a c t u re optimisation. Today ‘frac ture evaluation’ is per formed using various

simulations that use microseismic data to qualitatively calibrate the model.

This ar ticle will demonstrate new developments that enable valuable information to be extracted by combining contextual information such as geology, well logs, treatment data, etc with deterministic analysis of the microseismic measurements. The result of this deterministic analysis provides quantification of the hydraulic fracturing. Some of the key aspects of this analysis are: • Fracture geometry - height, length, and azimuth • Fracture complexity and tortuosity • Fracture coverage (overlap between stages and wells) • Characterisation of fracture mechanisms (dip-slip, strike-slip, etc.)

• Identification and avoidance of geo-hazards such as faults Completions Evaluation Analysis The completions evaluation analysis provides a mechanism to better calibrate and build underlying geo-mechanical and reser voir models; improving forecasting of fracture placement and production helping to accelerate optimisation of future wells and treatment designs.

This distinct process of Completions Evaluation consists of a workflow and tools to perform diagnostic analysis of microseismic data, enabling accurate evaluation of the fracture treatment.

It is designed to precisely characterise the fracture network growth and complexity, while providing a methodology to evaluate the wellbore spacing, stage lengths, cluster spacing, and treatment parameters. The basic workflow is outlined in Figure 2.

Figure 1: Completion and Fracture Optimisation

>> To fully optimise the completion and fracture treatment, it is important to understand various aspects of fracturing treatment such as – differentiating propped and un-propped fractures, fracture growth and geometry, fracture overlap between stages and wells, stress shadowing effects, and treatment efficiency.

Offshore World | 17 | February - March 2014

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Figure 2: Completions Evaluation Workflow

The workflow consists of the following steps: 1. Compute a magnitude calibrated Productive Discrete Fracture Network (P-DFN) and Productive-Stimulated Reservoir Volume (P-SRVTM) 2. Quantify optimum well spacing, stage lengths, and treatment efficiency based on P-DFN and P-SRV 3. Quantify permeability for the P-SRV and predict long term production Magnitude Calibrated DFN To accurately define a distributed fracture network, it is essential to start with a microseismic data set that enables computation of the absolute magnitude of each event. There are special processing techniques that preserve the signal amplitude and enable computation of the absolute magnitude.

Once acquisition has commenced and magnitude calibrated, microseismic point sets are created, a DFN is modeled onto the microseismic events in two steps: 1. Through source mechanism analysis, strike and dip of the failure plane are identified for each individual event. The geometry of each individual failure plane is then determined through the magnitude of an event, incorporating rock and fluid properties resulting in a Discrete Fracture Network (DFN), shown in Figure 3.

2. Length, height, and aperture of the fractures are obtained using a methodology incorporating the magnitude of a microseismic event, the rigidity of the reservoir rock, the injected fluid volumes, and, if available, fluid efficiency.

Using a relationship between the aperture of the fracture and its length, along with an assumed aspect ratio for a layer cake medium, the geometry of the three-dimensional fracture is obtained and a fracture volume can be computed.

Assuming that the total detected seismicity is directly related to the injected fluid volume, and that the change in volume is completely accommodated by the seismic failure, minus leak-off, the calculated fracture volume should equal the injected fluid volume.

Magnitude Calibrated Productive Stimulated Rock Volume Events in the hydrocarbon-bearing target zone are most likely to represent rock failure that contributes to production in the long term. Estimating the propped www.oswindia.com

fracture length and volume is performed by filling the DFN set with proppant from the wellbore outwards on a stage-by-stage basis. The packing density of the proppant is variable and can be adjusted based on the specific gravity of the proppant and available fracture models. The default value is approximately the density of loosely packed sand. Proppant filling is constrained by tortuosity of the flow path using a

Figure 3: Distributed Fracture Network and Productive Stimulated Rock Volume

proprietary method. The fracture volume inside the respective stage DFN is filled with proppant until all proppant that was pumped is accounted for. The estimated propped half-length is determined by taking the distance between the last fracture that contains proppant and the center of the stage at the wellbore.

In order to calculate the total Stimulated Rock Volume (SRV), a three-dimensional grid is applied to the total DFN. Every grid-cell containing a non-zero fracture property is included in the magnitude calibrated SRV. The total SRV is dependent on the size of the model cells and can be adjusted based on known reservoir flow properties.

It represents the total rock volume that was affected by the treatment. In order to discern between the part of the SRV that is assumed to be drained over the lifetime of the well, the same workflow is applied to the proppant filled DFN. The subset SRV

Offshore World | 18 | February - March 2014

that is calculated from the part of the DFN containing proppant then represents the Productive-SRV that is expected to contribute to production in the long term, as illustrated in Figure 3.

Wellbore Spacing and Stage Length Evaluation One of the most important aspects of evaluating a hydraulic fracture treatment is to determine the effectiveness of the treatment as measured by the fracture growth and fracture complexity. Key parameters of the fracture growth can be determined directly using a sub-set of fractures that are filled with proppant or the P-DFN. Selecting fractures that are filled with proppant allows accurate determination of the effective propped fracture growth in all directions from the wellbore. It is these propped fractures that will ultimately control the long term production from the well and should be used to determine the required well spacing and stage lengths.

Figure 5 shows the fracture growth in the horizontal plane. In this instance, there is a very clear bias of the fracture growth towards the west. This bias may be caused by several factors such as geology, structure, stress shadow from previous wells, depleted zones, etc. Analysing this data with reference to contextual information will enable the engineer to better diagnose the fractures as well as improve design for future wells.

Another aspect of evaluating the fracture growth is to look at the cumulative fracture growth as a function of pumped fluid and proppant volume. The fracture surface area can be estimated from the absolute seismic moment of any event. The seismic moment is a measure of the size of a fracture, based on the area of fracture, the average amount of slip, and the force that was required to overcome the friction holding the rocks

Figure 6: Fracture Volume

Figure 4: Stage-by-Stage Vertical Fracture Growth

Figure 4(a) shows the stage-by-stage analysis of the vertical fracture growth while Figure 4(b) shows the average vertical growth for the entire well. It clearly shows where the stages with fracture growth are effective, and the stages with limited fracture growth are less effective. Combining this with other contextual information – such as structure, geology, and stress regimes enables a better understanding of the treatment effectiveness in creating the desired fracture geometry.

together. Figure 6 shows a cumulative fracture volume plot as a function of normalised pumped volume. A linear increase in the fracture volume as seen at the start of the pumping indicates generation of new fractures or opening of pre-existing fractures resulting in additional open fracture area. The sudden increase in the fracture volume at point ‘X’ indicates potential activation of a much larger pre-existing fracture. After pumping about 75 per cent of the fluid, a reduction in generation of a new fracture volume can be seen. During this period, it is possible that existing fractures are being opened by the pumped fluid and proppant. The cumulative fracture volume plot thus provides a very useful diagnostic tool to evaluate whether new fractures are being created, or if existing fractures are being opened.

Summary Completions Evaluation provides a deterministic analysis of microseismic data. This, in conjunction with contextual information, provides a valuable tool in evaluating the effectiveness of hydraulic fracturing treatment. This analysis allows operators to finally answer the questions- where did the proppant go? How far do my propped fractures extend? How many stages do I need? With this analysis, it can be determined if hydrocarbons are being left behind, if there is over-spending on the number of wells, and the optimum number of stages required in completing each well.

Figure 5: Stage-by-Stage Horizontal Fracture Growth

Sudhendu Kashikar Vice President - Business Development Microseismic Inc E-mail: skashikar@microseismic.com Offshore World | 19 | February - March 2014

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features Factory Drilling

Achieving Predictable Operational Efficiencies As development of oil & gas reservoirs requires intensive, efficient drilling programmes, many operators are turning to ‘Factory Drilling’ for maximising drilling efficiencies to address wellbore-related Non-Productive Time (NPT) issues and for more optimally & faster drilled. The drive for speed is placing more stress on drilling equipment, especially downhole equipment. The article explains on predictive analytics as a solution to identify NPT issues like mud motor failure early that can help operators to minimise the risk and cost to operations and improve drilling efficiency by mitigating damage to downhole drilling equipment.

Operators are increasingly focused on maximising drilling efficiencies in land operations, and many are turning to factory drilling. While factory drilling helps isolate and address wellbore -related Non-Productive Time (NPT) issues and allows for more optimally and faster drilled wells, the drive for speed is placing more stress on drilling equipment, especially downhole equipment. The more companies turn to factory drilling principles and the total volume of wells continues to increase, the more supply chain concerns are necessitating steps to mitigate damage to equipment. To address these issues, operators are looking for ways to reap the benefits of factory drilling while minimising the risks, and many are turning to predictive analytics as a solution.

Using predictive analytics to identify NPT issues like mud motor failure early can help operators to minimise the risk and cost to operations and improve drilling efficiency.

The Benefits of Factory Drilling Factor y drilling operations employ specialised rigs designed to maximise drilling efficiency and reduce drilling time and associated costs. These highly mobile units are optimised for rig moves and pad skidding, and are operated by experienced crews familiar with advanced automation technology.

Many oil and gas reser voirs require factor y drilling to reduce the time and cost of drilling. For an oil company, Non-Produc tive Time (NPT ) can account for USD 50,000 per incident, so while drilling efficienc y delivered through factor y drilling techniques is impor tant, it is equally impor tant to ensure that drilling operations continue uninterrupted to avo i d t h e co s t o f n o n - p ro d u c t i ve t i m e l a p s e d w h i l e o p e rat i o n s are down.

Case Study Factory drilling operations, for example, have reduced the average time to drill a well from 22 days to 7-9 days in Mexico. In Russia, a similar approach impacted drilling efficiency where drilling rate increased from 19,685 ft a month to more than 32,808 ft a month reducing time and cost. (Reference from a recent article of Drilling Contractor) The ar ticle specified that better drilling techniques, such as fac tor y drilling, account for significant time reduc tion in wells that 3 years a g o m i g ht h ave ave ra g e d 3 0 - 3 5 d ay s to d r i l l a 1 0 , 0 0 0 - f t ve r t i c a l section and 10,000-ft horizontal lateral section and now might average 17-23 days.

Factory drilling is typically applied to high-volume operations with repeated well designs and known downhole risks where the same fit-for-purpose rigs and drilling techniques are used. One of the most significant benefits of factory drilling is that standardisation is allowing land operators to ‘engineer out’ common wellbore-related NPT issues such as twist off, differential sticking, mechanical sticking, and mud losses.

But even as wellbore-related NPT has less impact on the overall well operations’ drilling cost, operators are pushing the performance envelope across the entire drilling system, causing previously less common types of NPT issues to be the latest cost impact/performance barrier.

The Challenges of Factory Drilling The development of many oil and gas reservoirs requires intensive, efficient drilling programmes focused on reducing time-based costs in economically marginal fields. Generally speaking, factory drilling supply chain issues with personnel and equipment, and premature equipment wear and failure thru driving equipment too hard or long to see continuous marginal improvement pose a major challenge to the equipment used in factory drilling.

>> Factory drilling operations employ specialised rigs designed to maximise drilling efficiency and reduce drilling time and associated costs. These highly mobile units are optimised for rig moves and pad skidding, and are operated by experienced While factor y drilling helps isolate and address wellbore -related noncrews familiar with advanced automation technology. productive time (NPT) issues and allows for more optimally and faster www.oswindia.com

Offshore World | 20 | February - March 2014

drilled wells, the drive for speed is placing more stress on drilling equipment, especially downhole equipment. And the more companies turn to factory drilling principles and the total volume of wells continues to increase, the more supply chain issues are necessitating steps to mitigate damage to them.

One equipment-related form of NPT is wear and tear on downhole equipment, prompting the need for more robust tool sets, especially in regard to critical measurement while drilling (MWD) and mud motor systems. And of these two systems, it is mud motor damage which frequently is the limiting factor for further incremental drilling improvement in established factory drilling projects.

One operator has noted that mud motor damage accounts for 35 per cent of its NPT, and can cost USD 150,000 per incident.

Getting Ahead of Mud Motor Failures By using predictive analytics such as case based reasoning (CBR), land operators can identify key indicators of potential mud motor failure early and take action before drilling operations are impacted or costly tool damage occurs.

In one mud motor damage/failure example, there are measureable early symptoms of damage sustained ahead of an outright failure that is observable using Mechanical Specific Energy (MSE), a well-established concept that links standard surface sensor measurements to downhole drilling performance.

Sustained oscillation of MSE can be indicative of micro-stalling behavior down hole, which can result in pre-mature motor failure. These oscillations can be difficult to detect with the human eye but can be easily identified using properly designed and calibrated mathematical algorithms. Identification of operations currently exhibiting these symptoms enables real-time mitigation to prolong BHA life.

>> Companies with well-established factory drilling operations looking for continuous incremental improvement are beginning to understand the power of this approach and are leading the charge in using predictive analytics and CBR to stay ahead of downhole tool damage.

Companies with well-established factor y drilling operations looking for continuous incremental improvement are beginning to understand the power of this approach and are leading the charge in using predictive analytics and CBR to stay ahead of downhole tool damage or outright failures, and others will need to follow suit to recognise the benefits this technology and approach provides as factory drilling becomes the prevalent drilling process or wherever downhole tool damage is the predominate NPT cost.

Using this mathematical approach with a CBR system, once the possibility of symptomatic mud motor damage has been identified, other failure modes (such as chunking, debonding, thermal fatigue, issues related to drilling fluids, or a plugged motor) can be determined and addressed before it affects operations.

Using this approach, it may also be possible to link MWD tool failure to oscillating MSE, or similar damaging patterns, which then addresses another costly downhole component issue.

What Next?

There is tremendous opportunity for companies looking to break ground in shale plays if they understand the risks and how to effectively mitigate them. Many are looking at factory drilling as a way to tap into shale plays, and it is a technique that they can use successfully if they understand that continuous efficiency will require new technologies to assist in cost control and performance improvement. As they look to achieve that optimization, land operators can utilise predictive analytic technologies such as DrillEdge™ mud motor capability to monitor for the indicators of premature downhole tool damage, to quickly recognise the continuous improvement factor y drilling provides to maximise their production.

Philip Wade Chief Operating Officer Verdande Technology E-mail: philwade@verdandetechnology.com

Offshore World | 21 | February - March 2014

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interview

‘The enormity of GGSR leverages proximity of petroleum products in Northern parts of India’

Rationale behind commissioning of the 9-MMTPA Guru Gobind Singh Refinery (GGSR) operated by HPCL-Mittal Energy Limited (HMEL) at Bathinda in Punjab is to leverage the proximity of the deficit in petroleum products in the Northern parts of the country. Prabh Das, Managing Director & Chief Executive Officer, HMEL, Bathinda, talks about the opportunities & challenges and the future trends of refinery businesses in the country in an exclusive interview with Offshore World. He further articulates the expansion plans, new product mixes, marketing & distribution strategy, and the future refinery configuration of GGSR.

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How do you evaluate India’s refining capacity?

What are the key drivers?

India is an important player on the global refining map accounting for about 4.5 per cent of the refining capacity of the world, and this fraction is expected to get bigger in 2017. With Indian refineries going for accelerated capacities, the footprint of India on the global refining map as a major player is worth taking note of. The refining industry in India is all set to see an increase in margins and product portfolio.

The rapid increase in refining capacities to cater to domestic demand with a competitive edge, the capability of producing high-end products, the value addition to provide the industry a supply security are key drivers for the industry.

How do you maintain the gross refining margins of HMEL refinery amidst high volatility in feedstock pricing and subsidy burdens? What strategies do you undertake to maintain the positive momentum?

The Guru Gobind Singh Refinery (GGSR) is a zero bottoms, energy efficient, environmental friendly, high distillate yielding complex that produces clean fuels Offshore World | 22 | February - March 2014

and polypropylene meeting Euro IV specifications by processing heavy, sour and acidic crudes.

Our Bathinda refinery is a state-of-the-art complex refinery that has the ability to process relatively economically priced tough (heavy and sour) crudes that are selected through the best-in-itsclass LP software that has been tuned to deliver the best possible margins for the given refinery configuration. We are continuously on the lookout for and regularly undertake low investment Gross Refining Margins (GRM) improvement projects which would help the company in performing well in volatile scenarios.

HPCL-Mittal Energy Limited (HMEL) is committed to maintaining high standards of safety, health and environmental care at all its operating locations, always ensuring that its operations have no negative impact on the safety, health and environment standards. HMEL has established a long term goal of zero injuries, incidents/ accidents and environmental violations. The company has a strong focus on preserving the environment, sustainable development, safe work place and enrichment of the quality of life of employees, customers and the community.

>>The biggest challenges currently facing the Indian refining and petrochemical industries include the squeezing GRMs, capital intensive nature of new projects, high rates of interest, volatility in exchange rates, plateauing of growth rates of certain fuel products.

GGSR received the BS OHSAS 18001:2007 certification in January 2014 given by the British Standards Institution (BSI) for Occupational Safety Management system. The BSI is the world authority on management systems and having been certified with 18001:2007, it is symbolic of HMEL’s testament to committed quality of sound Health, Safety and Environmental practices.

What are the current biggest challenges ahead and how are you gearing up to address the same?

The biggest challenges currently facing the Indian refining and petrochemical industries include the squeezing GRMs, capital intensive nature of new projects, high rates of interest, volatility in exchange rates, plateauing of growth rates of certain fuel products. However,

The typical slate for name plate capacity (MMPTA) of HMEL - Light Distillate: 2.1 - Middle Distillate: 4.5 - High/Solid Distillate: 1.5

HMEL has a long term off take, which gives it an assured market.

What are the current capacity and the product mix of the refinery? How do you plan to expand the product basket and marketing & distribution strategy for the new products in India and foreign countries?

Our current refining capacity is 9 million metric tonnes per annum (MMTPA). However, we are able to run the refinery at a higher level.

The product mix is always worked up based on economic viability and demand in the market place.

Northern India faces a deficit in petroleum products, and The Guru Gobind Singh Refinery leveraging on its proximity to the northern states namely Punjab, Jammu & Kashmir, Himachal Pradesh, Uttarakhand, Uttar Pradesh, the National Capital Region of Delhi and parts of Haryana and Rajasthan is ideal to fill the fuel deficit that the region faces.

We are marketing all liquid products by supplying the same to HPCL or their nominated companies.

The three solid products i.e. Polypropylene (PP), Sulphur and Pet coke are being marketed by HMEL directly. These products have been well received Offshore World | 23 | February - March 2014

by the industries in North as well in other parts of the country. While Sulphur and Petcoke are mainly consumed within Northern region, PP is being marketed on an all India basis through our network of distributors in all parts of the country. HMEL is currently focussed on meeting the demand in the domestic market.

However, we continue to explore opportunities for export based on economic viability. We export our Naphtha production, as at present there is limited domestic demand. A small quantity of Pet coke is also exported to Nepal and Pakistan to seed the market looking at opportunities for these products in the near future in those regions.

Product evacuation of all liquid products from the refinery is done by rail, road and through dedicated pipelines. Solid products are evacuated through rail and a very minimal quantity is transported through road. Most of the product evacuation is through pipeline in the most efficient manner.

May we have your comments on value addition at the refinery and integration with petrochemicals unit as an economic growth driver? How are you implementing this at www.oswindia.com

>>Unconventional hydrocarbons can play a big role in securing India’s energy security. These are new areas, and therefore have to be carefully nurtured. So Indian refiners will need to gear up for the impact of change in the upcoming unconventional energy scenario.

HMEL refinery and how will this improve the overall profitability of the refinery?

The nine MMTPA, Guru Gobind Singh Refinery is the single largest investment and first Oil and Gas industry to be set up in the state of Punjab, India.

The refinery has brought in rich economic benefits in terms of industrialisation and development of support industries in the state of Punjab. A recent study by University Business School (University of Punjab) has established significant growth in State GDP if associated downstream industry comes up in the state.

The refinery includes a world class mother polypropylene plant for developing several medium and small scale industries. Very few refineries in the country have the capacity to produce polypropylene. HMEL’s refinery has created a big potential for industrialisation of the area. If capitalised, it could lead to development of petrochemical industry in Punjab bringing prosperity to the state. HMEL has been engaging with the Government to realise this potential. So far production of these granules is mainly located in Gujarat and Maharashtra. The refinery has been a game changer of sorts leading to product security, direct and indirect employment opportunities and higher tax revenues for Punjab and nearby States with the potential for new investments to develop a downstream industry and make Bathinda a major petro-chemical hub.

Petrochemical and other value addition units such as Aromatics manufacturing facilities enhance the profitability of refineries to a great extent as petrochemicals and aromatics command a significant premium over liquid and gaseous fuel products. For instance, the petrochemical polypropylene is sold at a premium over liquid fuels. This is precisely the reason why HMEL chose to set up a polypropylene plant with a capacity of over 400KT per annum.

How are you addressing the factors influencing refinery configuration in future – convergence of refining & petrochemical www.oswindia.com

operations, energy optimisation, achieving environmental protection, economies of scale and feedstock flexibility?

HMEL’s refinery has been set up keeping factors such as convergence of refining and petrochemical operations, energy optimisation, achieving environmental protection, economies of scale and feedstock flexibility. It is a zero bottoms, energy efficient, environment-friendly, high distillate yielding complex refinery that produces clean fuels meeting Euro-IV specifications. It has one of the highest Nelson Complexity Indices in the region and is designed to process a wide variety of crude oils including heavy, sour and other opportunity crudes. It follows a strict compliance to liquid and solid waste management norms.

World class environmental friendly technologies such as sulphur recovery units, hydro-treaters, desulphurisation units, state-of-the-art effluent treatment plant, vapour recovery systems and low NOx burners in the furnaces have been implemented at our refinery. The refinery has a blending facility to process fuels between 15 API – 55 API. Additionally, keeping economies of scale in mind the refinery and associated facilities for crude receipt and transport have been developed in such a manner that they can be expanded to 18 Million Metric Tonnes per Annum. The refinery’s Delayed Coker Unit (DCU) produces petroleum coke and ensures that the refinery draws maximum value from the bottom of the barrel.

The environmental impact assessment report for refinery was prepared by the National Environmental Engineering Research Institute (NEERI), the institute renowned for assessing the environmental impact on the Taj Mahal.

Post conducting stipulated procedures, the Punjab State Pollution Control Board has also granted a No Objection Certificate (NOC) to our refinery.

A green belt around the refinery has been developed with the help of the Punjab State Forest Department.

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HMEL is one of the five refineries in the world to commence integrated operations from day one.

The implementation of Manufacturing Execution Systems (MES) integrates information from the various components of the MES, Enterprise Resource Planning (ERP), and control systems within the refinery and delivers a consolidated, single view of the data. The new technology enables HMEL to analyse key corporate business processes including, planned versus actual investments, production, key performance indicators, among others. The system generates near real-time information for HMEL business executives to use to make more intelligent decisions around optimising productivity and margins.

What are the new and niche products the refinery is producing currently or in the pipeline?

Our refinery has the capability to make specialty products such as Hexane and Mineral Turpentine Oil (MTO). Hexane is mainly used as solvent in the solvent extraction units for vegetable oil. It is also used by the pharmaceutical industry as a solvent. MTO is a clear, transparent liquid which is a common organic solvent and is used in painting, decorating, dry cleaning etc. Additionally, ours is one of the few refineries in India that has the capability to produce eight grades of polypropylene which have a wide variety of film, injection moulding and woven & non-woven fabric manufacturing applications. The new product in the pipeline is asphalt which is primarily used in road construction, as the glue or binder mixed with aggregate particles to create asphalt concrete. The refinery has been operating at full capacity.

What are the other external future unforeseen challenges the Indian refiners will have to be prepared for? How should the Indian refining industry counter the same?

Unconventional hydrocarbons can play a big role in securing India’s energy security. These are new areas, and therefore have to be carefully nurtured. Shale gas and solar power can become a major source of energy, provided these assets are developed to their full potential. Indian refiners will need to gear up for the impact of change in the upcoming unconventional energy scenario.

features Resid Conversion Technology

Slurry Phase Hydrocracking: Bottoms Upgrading for Today’s Market The article focuses on the significance of resid processing methods which has emerged as a big concern for many refineries as they struggle to improve product qualities and refinery margins simultaneously while dealing with their large residuum pool. The authors shares insights into the Residuum Landscape and advocates on ‘Slurry Phase Hydrocracking’ which has not enjoyed widespread acceptance as the technology as choice for resid upgrading.

In the face of high crude oil prices, low natural gas prices, and ever increasing product quality regulations, refiners are presented with an unprecedented situation of improving margins by re -evaluating their resid processing options. The ability to reliably eliminate fuel oil production, maximise high quality distillate yields, and achieve almost complete conversion to high value transportation fuels, is essential for sustaining the value of installed assets in the years to come.

In its simplest form, refining is a process of changing the carbon to hydrogen ratio of naturally occurring crude oils. At a molecular level, the operation of all refineries in the world is essentially targeted at converting low hydrogen to carbon ratio feedstocks into high hydrogen to carbon ratio transportation fuels. Changing the H/C (Hydrogen/Carbon) ratio between feedstocks and products can only be accomplished through the rejection of carbon molecules or the addition of hydrogen molecules.

Carbon rejection is favoured by low crude prices and high hydrogen prices.

Under these conditions it is more economical to reject the residuum as petroleum coke, while producing the required transport fuel volumes by incremental crude oil processing. Conversely, hydrogen addition is favored by high crude prices and low hydrogen prices, when it is more economical to upgrade nearly ever y molecule of residuum to transpor t fuels, while

also maximising transport fuels production from the base crude capacity.

In the United States, shale gas production has had a dramatically reduced the price of natural gas, relative to crude oil, on a comparable energy basis. This provides a relatively low cost source of hydrogen in many geographical regions. Conver ting inexpensive hydrogen into high value liquid transportation fuels by hydrogen addition to low H/C ratio feedstocks provides a good economic return. Economic analysis clearly points to a transition from carbon rejection to hydrogen addition at USD 50-60/barrel crude, even when considering natural gas prices of USD 10/MMBTU. Lower natural gas prices provide an even more significant tailwind to hydrogen addition economics. As the new gas production techniques spread to other parts of the world, projections are that hydrogen addition economics will remain favored for many years to.

Another significant factor in bottoms upgrading economics is the problem of stranded streams. Many refineries are littered with low value streams that must be blended off, disposed or sold at loss in order to accommodate processing equipment limitations from a different era. The bulk of operating refineries around the world have little or no residuum processing capability and produce large volumes of high sulfur fuel oil and bunker fuel. Falling demand for these undesirable products will continue into the future and already negative margins for these streams will only get worse.

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Regulatory pressures on residuum outlets such as marine bunker fuels are expected to worsen in the future. As world governments move towards cleaner bunker fuels, refiners will be forced to find new ways to deal with their large residuum pool. It is a task that is becoming more pressing as oil producers bring to market increasing amounts of heavy crudes, which cost less, but feature substantial increase in resid content. While shale oil production has provided a temporary respite from declining average API and rising sulfur contents, most projections do not expect shale oil production increases to offset the increasingly heavy sources of crude oil production from new discoveries and reserve development.

Not only refinery products but also by-products must be considered when evaluating bottoms upgrading process technology. The market for coke from delayed cokers is highly dependent on availability of local outlets for the material, such as power plants. An abundance of coke on the market creates prices that only marginally cover costs or are negative. Combined with the economic considerations are the environmental considerations of burning or disposing of this low H/C material.

On the product side of the economic equation, the gasoline to distillate ratio continues to move in favour of distillate on a worldwide basis. Even

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in markets where Fluid Catalytic Cracking (FCC) units are the primar y conversion process and gasoline the predominant transpor tation fuel, rising worldwide demand is driving investments aimed at maximising p ro d u c t i o n o f h i g h ce t a n e, u l t ra l o w s u l f u r d i e s e l. Th e r i s i n g D / G ( D i e s e l / G a s o l i n e ) r a t i o i s f o re c a s t t o c o n t i n u e , w i t h m o s t o f t h e incremental increase in transportation fuel volume for future years coming from distillate.

This is an important consideration for refiners, when making long-term, high CAPEX investment decisions. Current economics clearly point to hydrogen addition as opposed to carbon rejection especially for increased distillate production.

Today, the market imposed challenge to refiners is to find a hydrogen addition based resid conversion technology which suppor ts the strong economics of near complete conversion, high selectivity towards diesel, Euro V quality and high operating reliability – all at a reasonable capital investment and strong ROI. A convincing case for slurry bed hydrocracking as the technology choice for today’s market conditions will be laid out in this paper.

Offshore World | 26 | February - March 2014

The Residuum Landscape Residuum oils can be broadly classified by their contaminant metal (Ni + V) and Conradson Carbon Residue (CCR) content. These two parameters broadly define the suitability and type of conversion technology which can be applied to these heavy oils.

More recently, ebullated bed hydrocracking technology has been the choice for hydrogen addition to residue with higher levels of metals and CCR. Conversion is higher than prior technologies but still limited to less than 80 per cent conversion and in some cases, significantly less. The nature of the e-bed conversion process creates an unstable asphaltene phase which usually limits overall conversion by causing severe fouling in downstream equipment. Introducing aromatic solvents and high recycle rates can help maintain asphaltene solubility and reduce fouling but these solutions have a cost and there is still an upper limit on the level of asphaltene conversion which can be achieved.

Slurry phase hydrocracking offers the greatest potential for a robust residue conversion technology which encompasses the entire residue landscape. Only coking is as immune to high levels of CCR or metals content in the feed and, being a hydrogen addition process, slurry hydrocracking has the advantage over coking of ne near complete conversion of the residuum to high value products.

One such slurr y phase technology is Veba Combi Cracking ( VCC™), a commercially proven bottoms upgrading technology suitable for converting 95 wt% of residues into high quality distillates.

Fixed bed hydroprocessing is suitable for processing atmospheric or vacuum residue with modest amounts of metals and CCR and mainly for desulfurisation rather than conversion. Conversion is typically 15-20 per cent and fur ther conversion of the products in other units is necessar y.

Nonetheless, operating pressures are high, increasing investment costs and operating costs can be high as well due to catalyst deactivation from metals and coke.

Resid FCC (RFCC) is a seemingly attractive way to convert resid with no unconver ted produc t to deal with. Unfor tunately, the more hydrogen deficient the feedstock the more of it forms coke on catalyst. This sets a limit on the amount or heaviness of the residue processed in the RFCC while keeping regenerator temperatures at an acceptable level. Catalyst coolers and other methods of heat removal can improve the range of feedstock processing possible but RFCC is still very limited.

VCC™: Veba Combi Cracking The origin of slurry phase hydrocracking and the VCC™ process dates back to 1913, when Freidrich Berguis was awarded his first patents for the process of liquefying coal. The 1931 Nobel laureate had demonstrated that liquid products can be produced by simply subjecting coal to a high enough temperature and hydrogen pressure.

Using these principles, 12 commercial units were built and operated in Germany bet ween 1927 and 1945, producing about 100,000 BPSD of transportation fuels from coal and coal tar. After WWII, several of these units were dismantled and sent to Eastern block countries. The remaining units, including the six operating trains at Gelsenkirchen, were converted to 10,000 BPSD trains for processing refinery vacuum residues. The first true VCC™ units were developed in the 1950’s when an integrated second stage fixed bed reactor was added to the slurr y phase reactor. It was realised that mild hydrofinishing of the slurry phase products could result in higher quality distillate. This integrally coupled combination of slurry phase hydrocracker and trickle bed hydrofinisher was the origin of the VCC™ process as it is known today.

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VCC™ Process Flow

These original VCC™ units operated on residues until 1967 when very low crude oil prices and the end of government subsidies forced the units to be shutdown and subsequently dismantled. Low crude oil prices make it uneconomic to add hydrogen to residue, in particular for this period when outlets for residue, such as fuel oil, existed. VCC™ technology went dormant for a period until viable economics would once again surface.

The trigger for resurrection of VCC™ was the hike in crude oil prices resulting from the oil embargo of the 1970’s. Economics of hydrogen addition and high conversion of residues turned positive and Veba Oel constructed a 3500 BPD in Bottrop, which star ted up in 1981. In addition, 200, 3.5 and 1 BPD pilot plants were built for developing the technology. Over its operating period, significant improvements were made to the process through equipment design modifications and operational adjustments. Two units were licensed by Veba to utilise VCC™ technology, but, once again, oil prices fell to levels which would not support project economics. Bottrop was decommissioned and shutdown in 2001 after a period of sustained low oil prices.

in Naperville, USA. In 2010, BP and KBR agreed to a marketing, licensing and engineering alliance to promote the technology.

Slurry Phase Hydrocracking While slurry phase hydrocracking has been reliably practiced for several decades, it has not enjoyed widespread acceptance as the technology of choice for resid upgrading. Even with its strengths of high asphaltene conversion and distillate selectivity, the specific set of economics supporting VCC was elusive until recently. Higher hydrogen consumption and CAPEX compared to alternative resid conversion technologies was not economically justified without sustained higher crude and product prices. The appropriateness of any technology choice must be weighed against the prevalent market conditions, and its relevance is deeply rooted in the principles of molecule

Following BP’s acquisition of Veba and a rise in crude oil prices from increasing market demand rather than exogenous events, VCC™ was added to BP’s Vision 2030 portfolio and the BP Advanced Refining Program. In 2008 a new 1 BPD VCC™ pilot plant was designed, built and commissioned at BP’s research facilities

>>Converting inexpensive hydrogen into high value liquid transportation fuels by hydrogen addition to low H/C ratio feedstocks provides a good economic return. Economic analysis clearly points to a transition from carbon rejection to hydrogen addition at USD 50-60/barrel crude, even when considering natural gas prices of USD 10/MMBTU. www.oswindia.com

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VCC™ Product Properties

management. Embedded in this approach is the core belief that refining margins are maximised by selectively maximising the value of every molecule in naturally occurring crude oils in every stage of processing. Vacuum residues can be broadly classified by SARA analysis (Saturates, Aromatics, Resins and Asphaltenes). These properties set the severity of operation (pressure and temperature), hydrogen uptake, and capital investment required to convert the material. Since asphaltenes are the most hydrogen deficient part of the resid and contain virtually all the impurities, the decision to convert them or remove them can be complex.

1. Will crude oil prices remain high?

2. Are outlets for byproducts, such as pet coke or fuel oil, available?

3. Is hydrogen inexpensive relative to crude?

4. Are markets for high quality distillate products growing?

The economics of not upgrading, par tially upgrading or fully upgrading high C/H molecules is substantially influenced by: crude price, natural gas price, and capital investment. Historical low crude oil prices, high natural gas prices, and until recently, an acceptable margin for fuel oil relative to lighter products all had an inhibiting effect on the value of upgrading asphaltene molecules. It was both economical and convenient to discard these molecules as coke or as unconverted residual fuel oil. While slurry hydrocracking technology was sound, the market and regulatory landscape did not suppor t the additional capital and operating cost to bring it to commercial application.

The past decade has seen a shift in the market dynamics affecting residue upgrading – crude oil prices have been sustainably higher, natural gas prices are lower, the market for high quality distillate is strong and growing and there is a shrinking market for fuel oil and petroleum coke. Conversion of asphaltenic molecules to lighter products can now be economically justified.

>> The bulk of operating refineries around the world have little or no residuum processing capability and produce large volumes of high sulfur fuel oil and bunker fuel. Falling demand for these undesirable products will continue into the future and already negative margins for these streams will only get worse.

Slurry phase hydrocracking is the preferred choice for these new market conditions and specifically VCC™ since it has been developed through decades of innovation.

A comparison of the net present value (NPV) of three technology routes derived from upgrading a refinery residue as a function of bench mark crude price shows a remarkable trend in favor of slurry phase hydrocracking. Both the economic and regulatory trends are heavily weighted in favor of VCC™, and the current and future market conditions are aligned with the inherent features of this technology.

The economic evaluation for one North American refinery clearly shows that the net present value of the ebullated bed process exceeds that of the delayed coker at a bench mark crude price of $85/bbl. This is primarily because of the lower conversion of e-bed, larger volume of lower value unconverted residuum, and the production of aromatic distillate products that need retreatment. On the other hand, the net present value of VCC™ exceeds that of the delayed coker at a bench mark crude price of $50/bbl, making it the clear choice for hydrogen addition technology.

Reliability The value of any technology can only be extracted if reliable long term operations can be sustained. In the case of VCC™, this reliabilit y can

Comparison of 1st Stage Yields

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>>S lurr y phase hydrocracking offers the greatest potential for a robust residue conversion technology which encompasses the entire residue landscape. Only coking is as immune to high levels of CCR or metals content in the feed and, being a hydrogen addition process. only be achieved if high asphaltenes conversion can be accomplished without fouling the unit. A molecular evaluation of residuum will reveal that the asphaltenes are held in solution by the aromaticity of the solvent phase.

Th e b a s i c c o n v e r s i o n c h e m i s t r y f o r s l u r r y p h a s e h y d ro c r a c k i n g i s essentially thermal in nature and relatively similar to that seen in other carbon rejection processes. The condensation chemistr y associated with these cracked molecules, which would normally lead to coke formation, is interrupted by the high hydrogen par tial pressure. Therefore, unlike a t ypical thermal conversion processes, the reaction system produces a v e r y h i g h l e v e l o f l i g h t e r p ro d u c t s w i t h l i t t l e c o n d e n s a t i o n o r coke formation.

A s co nve r s i o n p ro gre s s e s, t h e s i d e c h a i n s t h at h o l d a s p h a l te n e s i n solution are easily cracked causing them to lose solvency, and eventually precipitate. An analogy can be made to the operation of a solvent deasphalting process. In that case, when the asphaltenes are dissolved in a light paraffinic solvent, phase separation occurs, resulting in precipitation as pitch.

higher operating pressures of VCC™ which allow the unit to operate in a non-catalytic mode by inhibiting condensation chemistry.

This combination of high hydrogen par tial pressure and non- catalytic additive system is unique to VCC™ and is a major reason it has decades of reliable operation at high (>95%), once-though conversion, with no signs of fouling. Hydrogen addition needed to meet final product quality is met by adjusting the trickle bed hydrofinishing conditions. This separation of thermal conversion of residue from the catalytic conversion of converted material is key to the technology. Each stage does the job for which it was designed and this eliminates the issues often seen when using catalysts for residue conversion. The reliability of the process has been proven by operating factors that have consistently exceeded 90% over many years of operation.

Conclusion Current market and regulatory conditions substantially favor investment in hydrogen addition technologies. Slurry phase hydrocracking in general and VCC™ technology in specific, are ideally positioned to exploit the new market conditions. With VCC™ near complete, once through, distillate selective conversion to high quality finished products can be reliably achieved with high on-stream factors.

Unconverted asphaltenes precipitate and adhere to equipment surfaces – the walls of the reactor, piping, heat exchanger, etc. This severe fouling limitation leads other resid hydrocracking technologies to reduce their per pass conversion or to resor t to recycle with the addition of a large volume aromatic solvent stream in an attempt to keep these unconverted asphaltenes in solution.

VCC™ technology operates with stability and high conversion in a mode that eliminates fouling. This issue has been researched over several decades dating back to the origins of the technology. Over 1,000 patents and over 2,000 filings were made, covering the entire landscape of catalytic and additive options. These effor ts lead to the discover y and co m m e rc i a l i s at i o n o f a n o n - cat a ly t i c, n o n - m e t a l l i c a d d i t i ve w h i c h all but eliminates fouling tendencies and allows unprecedented high asphaltene conversion.

Asphaltene molecules are adsorbed to the high surface area of the additive where the required residence time is made available for the asphaltenes to continue to crack. The lighter, cracked products are released from the additive sur face and the heavier, unconver ted asphaltenes, containing all the contaminant metals, remain on the additive. Later, the additive is removed from the process along with the captured unconverted asphaltenes and any contaminant metals. This chemistr y is possible because of the www.oswindia.com

Steve Mayo Director - VCC Technology KBR Technology, Houston E-mail: steve.mayo@kbr.com Mitra Motaghi Business Development Manager KBR Technology, Houston E-mail: mitra.motaghi@kbr.com Rahul Ravi Senior Technical Professional - Process KBR Technology, India E-mail: rahul.ravi@kbr.com

Offshore World | 30 | February - March 2014

features Energy Watch

Different Energy Commodities on Different Paths Continuing with past few months’ convention, energy commodities continued to exhibit mixed price movement in the past two months of January and February 2014. Interestingly the two energy commodities from emission segment traversed complete opposite path. In above mentioned period, European Union allowances (EUA) futures prices (traded on ICE-ECX platform) rose the most amongst energy commodities by 45.3 per cent, whereas CER (Carbon Emitted Reduction) futures prices (traded on same platform) dropped the most i.e. by 18.8 per cent (albeit with low prices base).

Amidst reports of increased oil production in Libya and strengthening of US dollar, NYMEX (CME) crude oil (light sweet) futures started the month of January 2014 at USD 95.44 per barrel, down by 3.03 per cent from previous months close. News from Libya that protesters ended months-long blockade at a major oil field in the country’s south as well as Libya’s National Oil Corporation stating that southern El Sharara oil field had restarted with production of 60,000 barrels per day helped the bearish sentiments. Further, two other oil fields in the east of Libya also reopened about a week ago after being blocked for several months. Notably, oil prices continued to decline as rising production pressure outweighed support from a larger than expected drop in US crude oil supplies. Consequently, NYMEX crude oil futures registered its eventual two-months (January-February 2014) low of USD 91.24 per barrel on January 9.

330

Subsequently, oil prices reversed as China, the world’s second largest crude oil importer, showed an increase in its oil import data. Later, a sharp decline in the US dollar also benefitted dollar denominated prices for crude oil. The upward trend in crude oil prices then continued to gain momentum with weekly reports releases showed persistent decline in US crude oil inventories.

Data releases such as a rise in retail sales, better-than-expected US manufacturing reports helped the bullish sentiments in oil prices. Another development from China, wherein China’s central bank provided emergency funding support to commercial banks via a repurchase program, in hopes of easing fears of a credit crunch, provided support to crude oil prices. Moreover, rise in natural gas prices to multi-year highs on severe winter

Futures price movement (January - February 2014)

105

98

310

91 290 84 270

250

77 NYMEX Heating oil (USd/gal) - LHS

NYMEX Gasoline (USd/gal) - LHS

NYMEX WTI crude oil (USD/barrel)

ICE Rotterdam Monthly Coal (USD/MT)

70

Source: Bloomberg

Source: Bloomberg

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Futures price movement (January - February 2014) 0.45

7.50

0.40

6.50

0.35

5.50 0.30 4.50

0.25 ICE-ECX CERs (Euro/tonne) - LHS

NYMEX Natural gas (USD/mmBtu)

ICE-ECX EUAs (Euro/tonne)

0.20

3.50

Source: Bloomberg

Source: Bloomberg

conditions in US, helped the rise in crude oil prices. Intermittingly though the price rise faced some checks largely on concerns over energy demand from emerging markets and release of downbeat Chinese economic data (HSBC/Markit China manufacturing Purchasing Managers Index). Overall oil prices continued to move north helped by a data release showing drop in US jobless claims - indicating improving labour market and strength in equities market supporting an upbeat outlook for energy demand.

Meanwhile, world’s second largest consumer of oil, China, also showed high imports in oil for January. Further with series of winter storms striking US raised heating demand for oil and hence upside pressure on crude oil prices. Consequently, NYMEX crude oil futures moved up to the two-month high of USD 103.80 per barrel on February 19.

Following the high price, crude oil prices dipped due to concerns that an economic slowdown in China may dull the outlook for energy demand, as a data release indicated contraction in Chinese manufacturing sector. Rise in weekly crude oil inventories in the US also forced crude oil prices to recede. However, at the fag-end of the month of February, violent clashes in the Middle East and North African regions leading to shutting down of a major oilfield, El Shahara in Libya, increased supply concerns.

Amidst this, MCX crude oil futures closed the month of February at USD 102.59 registering a rise of 4.2 per cent in two-month period.

Unlike the price rise seen in crude oil, futures prices of its two popular derivates i.e. heating oil and gasoline (on CME-NYMEX platform) registered change of 0.4 per cent and 0.1 per cent respectively in two-month period. On the other hand, the other major energy commodity natural gas futures (traded on NYMEX-CME platform) witnessed a rise of almost 9 per cent in its prices two-month period. Fall in US gas inventory levels, freezing temperatures throughout much of the United States amidst series of severe winter storms, buoying gas demand, helped the rise in gas prices. Significantly, NYMEX natural gas futures prices moved to USD 6.493 per mmBtu on February 24, 2014, the highest price since 2009. Later, by end of www.oswindia.com

the month of February, with winter nearing end, some rise in natural gas futures prices withered away.

In emission market segment on ICE-ECX platform, European Union allowances (EUA) futures as mentioned above, registered highest price rise amongst energy commodities at 45.3 per cent. The price rise was primarily due to optimism as European Parliament approved a proposal to fast track efforts to prop up prices. Lawmakers voted in support of a request from the European Commission to shorten the scrutiny period required before it can withhold the first of 900m permits from the market from 2014-16 to 2019-20. In other words, the measure known as ‘backloading’ will tighten the market balance significantly, after a period of abundant supply of emission allowances (EUAs) and dwindling prices. On the other hand, CER prices continued to move down, in the process registering a fall of 18.8 per cent (albeit on a low price base).

Lastly, ICE Rotterdam monthly coal futures prices moved down by 5.5 per cent in two month period of January-February 2014. Mild weather in Europe pulling down demand, weather outlook suggesting that the mild winter will go directly into a mild spring amidst prospects of improved supply availability from Colombia from April led to the fall in coal prices.

(The views expressed by the authors are their personal opinions.)

Niteen M Jain Senior Analyst, Department of Research & Strategy Multi Commodity Exchange of India Ltd E-mail: niteen.jain@mcxindia.com Nazir Ahmed Moulvi Senior Analyst, Department of Research & Strategy Multi Commodity Exchange of India Ltd E-mail: nazir.moulvi@mcxindia.com

Offshore World | 32 | February - March 2014

news features

Iranian Gas Export through Pipeline Hedayat Omidvar Member of IGU Marketing Committee Head of Communication Affairs with Science & Research Centers, Research & Technology Dept., National Iranian Gas Company Email: omidvar@nigc.ir

Iran holds the second largest gas reserves in the world with over 27.5 trillion cubic meters (TCM) of natural gas. The article explores the current projects of Iran’s Natural gas export statistics through pipeline routes to regional and global markets.

Gas Export Projects via Pipeline Overview of Pipeline Projects Overview of Pipeline Projects No

Projects Title

R e q u e s t e d G a s Vo l u m e o r T h e L a t e s t Commencement Date Transmitting Lines Capacity Status

Gas –Sale Contracts

1

Turkey

2

A ze r b a i j a n g a s s w a p w i t h 0/3-0/35 Nakhchivan

Exchange Operation is underway

3

I r a n i a n g a s - A r m e n i a n 1/1-2/3 electricity barter

The contract has been signed and the national 2007 G a s Co m p a n y u n d e r t o o k t h e e x e c u t i v e operations

Gas-Purchase Contracts 1

Turkmenistan-Phase1

2-8

In progress

-

2

Turkmenistan-Phase2

To 14

In progress

Since 2007

Pakistan

21/5

Gas Sale and Purchase Agreement signed

2013-2014

Swiss EGL

0/3-1/5 within Gas Sale and Purchase Agreement signed 2010-2009 phase1 operation Agreement signed 2012-2011 2-4 within phase2

Co n c l u d e d c o n t r a c t s 1 and subject to be 2 exported Projects negotiated

being 1

7-10

Gas export has been launched since 2001 and 2001 has annually reached nearly 10 BCM from 2007 2005

30

The negotiations adjoumed by Indian party

2013-2014

2

13/7

Term Sheet signed

2011

3

28

Term Sheet signed

2013

4

28

MOU initialed and confirmed FA signed and 2013 Term Shett proposed

5

8/6

Te r m s h e e t s u b m i t te d b y t h e m i n i s te r s 3 y e a r s e v e r entourage to Kuwaiti party since the contract

6

----

M O U s i g n e d b y t h e I ra n i a n a n d Tu r k i s h ------ministers of oil andt Gas in Ankara, The preliminary feasibility studies carried out

7

----

Under consideration

-------

8

5/5-13/7

MOU&CA signed

2015

Offshore World | 33 | February - March 2014

www.oswindia.com

Persian Pipeline Project (Exporting Gas to Europe IGAT9) So as to posses a more contributive and participatory role in potential markets those of European countries and more potently carry out transactions in the realm of energy as one of the major suppliers of gas in this continent the construction of this gas in this continent the construction of this gas pipeline under the name of IGAT9 was brought into being. This pipeline extends 1863 km from Asaluyeh (South Pars Gas Field) to Bazargan border and the other pipeline routes namely Nabucco Pipeline and Persian pipeline can potentially export Iranian gas from there on. Given some anticipation into account this pipeline is to annually export 30-35 BM3. To sell this amount of gas some negotiations are underway with countries namely Greece, Austria, Italy, Germany, Switzerland and so are talks with France and Spain in the coming future. In view of the policies made, this Project is set to be designed and executed using the foreign investors capabilities and the domestic contactors.

Pipeline Project of Gas Transfer to Switzerland This pipeline is after expor ting gas to EGL Company in Romania, Italy and Switzerland within two phases totaling 5.5 BCM in one hand and consolidating Iran’s presence in European markets. This project was launched in 2006 and it was ordained that the contract be concluded after the condition of feasibility study within the framework of the following table.

Project Specifications Gas Feed

South Pars Gas Field-IGAT9

Requested Volume

Phase 1:0/3-1 BCM/Y Phase 2:4 BCM/Y

Delivery Location

Bazargan Border

GAS Export Duration

25 Years

Pipeline Project of Gas Transfer to Austria The project is to export gas to Austria via pipeline. This project intends to step inside the Northern and Western market of Europe as well as to contribute Nobbaco Consortium.

This project was launched in 2006 and the gas is to be delivered to Econgas Company after the execution of phases those of studies and pipeline construction.

Project Specifications Gas Feed

South Pars Gas Field-IGAT9

Requested Volume

5 BCM/Y

Delivery Location

Bazargan Bordre or Hub BaumGarten

GAS Export Duration

25 Years

Pipeline Project of Gas Transfer to Pakistan and India (IPI) The issue of exporting gas to India and Pakistan dates back to 1990. The tensions in between India and Pakistan made the project fail to noticeably proceed till early of the decade. National Iranian Oil Company embarked upon some studies backed by International companies so as to have a pipe construction route that best fits either through onshore, offshore, littoral lands or deep waters recognised.

In so doing, Australian B.H.P Company conducted the feasibility studies and upgrading in 2003 and the former in 2001 out of which onshore pipe construction was picked up as the superior alternative. Pursuant to that, National Iranian Gas Export Company announced its readiness to deliver gas in Pakistan and Pakistan-India border. The second course of

tri-lateral talks chasing the gas export to India and Pakistan commenced in 2003. Three companies partook in the talks those of National Iranian Gas Export Company representing iran, Inter State Gas Systems Limited representing Pakistan, Indian Oil Company Limited and Gas Authority India Limited representing India. price formulae finalised.

Gas Feed

Assalouyeh

Requested Volume(Pakistan)

7/8 BCM/Y

Requested Volume(India)

10/9 BCM/Y

Delivery Location

Border of Iran & Pakistan

Commencement Date

2013-2014

Pipeline Project of Gas Transfer to Kuwait The agreement signed by the ministers of the two countries in 2000 gave birth to a contract concluded to export gas to Kuwait via pipeline. Accordingly, having several course of talks concerned with the allocated gas fields, methods of investment, and the administration of feasibility studies held, the draft of the contract and buy-sell Term Sheet for the year 2004 got signed by the two parties. The two sides - kept pursuing the talks in order to get all the articles of the contract finalized. However, in view of the events those of the drastic changes in the structure of energy global price, disputes over the price formulae, governing rules, price revision mechanism and finally Kuwait’s refusal to stay on course, led the talks to be left dormant. www.oswindia.com

In view of the correspondence between the two countries and Kuwait’s letter issued on NIGEC’s comments over the agreed-upon Term Sheet, the second course of talks got started. In the second run of talks, while reconsidering the new formulae of gas price, Kuwaiti party was provided with the amended draft of the Term Sheet.

Project Specifications Gas Feed

Assalouyeh

Requested Volume

3/1 BCM/Y

Delivery Location

Rasolzoor in Kuwait

Gas Export Duration

3 years ever since the contract finalised

Offshore World | 34 | February - March 2014

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Pipeline Project of Gas Transfer to Oman This project aiming at expor ting gas to Oman via pipeline dates back to almost six years and became the subject of consideration for both countries ever since. There after, three agreements were signed by the two parties in 2005 and 2006. These talks paralleled with the negotiations concerned with the expansion of Kish and Hengam gas fields by Iranian offshore Company (I.O.O.C) and NIGEC with Omani oil company regarding the feasibility studies so as to transform mm3 of export gas to LNG. 30% of the liquefied gas belongs to Iran in return of the processing fee. Due to some agreements over the price of the export gas and the Kuwaiti’s low price proposal made the talks dormant and then the second course of talks began to reach a reasonable price for both par ties. The issues

namely Oman’s investment plan in Kish fields, transformation of Iranian gas to LNG, the establishment of a Iranian¬-O mani joint company, price and the formulae of Iranian gas are all on the table in these on-going talks.

Project Specifications Gas Feed

Kish Gas Field

Requested Volume

10/2 BCM/Y

Delivery Location

Sea Border of two countries

Gas Export Duration

2013

Pipeline Project of Gas Transfer to Bahrain

Project Specifications

A s p e r t h e f i n a l i s at i o n M O U b e t we e n t h e o i l m i n i s te r s o f Te h ra n & B ra h i n , B a h ra i n w i l l re ce i ve n e a r ly 2 8 m m 3 / d ay a n d w i l l i nve s t n e a r ly 4 b i l l i o n d o l l a r i n p h a s e s 1 5 a n d 1 6 S o u t h Pa r s g a s f i e l d s in return.

Gas Feed

South Pars Phases 15-16

Requested Volume

10/2BCM/Y

Delivery Location

Sea Border of Iran & Bahrain

Gas Export Duration

2013

Savex Project S a v e x p ro j e c t s t a n d i n g f o r S a v e t o E x p o r t p ro j e c t, w a s b ro u g h t i n t o b e i n g s o a s t o o p t i m i s e f u e l c o n s u m p t i o n a n d i n c re a s e t h e efficienc y of thermal power plants. This projec t also aims at expor ting the saved gas and absorbing investment utilising foreign investors’ resources.

Domestic Necessities for Execution of Savex • The ever-decreasing volume of hydrocarbon resources and the importance of it’s optimum consumption.

• The technology transference of modern power plants.

• R e d u c i n g e c o l o g i c a l c o n t a m i n a t i o n s a n d green house gases.

• The mounting energy crisis and the growing global demand for gas and LNG. • P r o g n o s t i c a t i n g t h e a s c e n d i n g t r e n d o f t h e a d d e d value of natural gas resources as compared to oil in the decades ahead.

• The negative balance of power production and consumption in view of the growing domestic consumption.

Anticipation of Annual Revenue of Savex (Quote in 200$) • Intensifying the efficiency of the power plants resulting in saving 36 MM3 of gas per day.

• Every million BTU of gas is prices at $12 and the convergence coefficient every cubic meter to thousand BTU equals 36.

• 36 MM3 of the gas saved x 365 days x 36 coefficient x $12 = $5.6 billion

Methods to Increase Output Performance and Reduce Lass • Using Turbo expanders and producing electrical energy in pressure ¬reduction stations.

• Optimising gas turbines within gas-boosting stations at distribution and export gas pipelines.

• Optimising the design and the equipment of steam and gas turbines in non-power plant industries.

• Replacing the thermal power plants with modern cycle combination and steam power plants.

Activities Carried out in Savex Project An agreement has been concluded and a joint group has been formed with some European companies so as to have arrangement made to initiate feasibility studies. The study phase of the project is expected to last 9 months. Once the study phase of the project gets terminated, the operational phase will get started. gas in Pakistan and Pakistan-India border. The second course of tri-lateral talks chasing the gas export to India and Pakistan commenced in 2003. Three companies partook in the talks those of National Iranian Gas Export Company representing iran, Inter State Gas Systems Limited representing Pakistan, Indian Oil Company Limited and Gas Authority India Limited representing India. Manifold trilateral meetings have been run on the level of the counterpart deputies of the ministries of oil and energy accompanied with some work teams from the three countries which helped them get the price formulae finalised.

Offshore World | 37 | February - March 2014

www.oswindia.com

news features

LNG – Fuelling the Future It is expected that domestic production in India is to reach 230.00 MMSCMD by 2029-30 against a projected demand of 746.00 MMSCMD. Keeping in view the scarcity of domestic gas gap of 485.9 MMSCMD, the article explains the natural gas consumption, the viability of using imported natural gas & RLNG for various industries, LNG trend dynamics, and economics viability of R-LNG in the country.

India’s Natural gas reserves are limited. As of end of 2013, India has 1354.76 billion cubic meters (BCM) of confirmed natural gas reserves.

Reserves of Natural Gas in India (BCM)

Consolidated Natural Gas Supply Projection Development of unconventional resources of gas has been scare in India due to lack of data, low intensity of exploration, pricing regulatory policy and lack of domestic infrastructure & expertise. Hence, domestic natural gas production is unlikely to keep pace with the increasing demand. It is expected that domestic production is to reach 230.00 MMSCMD while pipelines will add only 30 MMSCMD to the supply by 2029-30 against a projected demand of 746.00 MMSCMD. A gap of 486 mmscmd (131 million tonnes per annum) is expected between demand and supply by 2029-30, representing an enormous opportunity for LNG. Source Domestic Sources

2005

2006 2007 2008 2009 2010 2011 2012 2013

1100.99 1075.15 1054.58 1089.97 1115.27 1148.57 1278.06 1330.24 1354.76 Source: Vision 2030, Natural Gas Infrastructure of India

Sector Wise Projected Gas Demand Currentely, India is the 13 th largest gas consumer (55 BCM) and 4 th largest LNG importer globally. The natural gas demand is all set to grow significantly at a CAGR of 6.8 per cent from 227 MMSCMD in 2012-13 to 443 MMSCMD in 2019-20. Power and Fertiliser sector remain the two biggest contributors to natural gas demand in India and continue to account for more than 55 per cent of gas consumption.

2026-27

2029-30

156.7

181.6

210.6

230.1

Gas Imports (Transnational Pipelines)

0.0

30.0

30.0

30.0

Total Supply (MMSCMD)

156.7

211.6

240.6

260.1

Total Demand (MMSCMD)

378.7

517.7

655.4

746

Gap (MMSCMD)

222

306.1

414.8

485.9

Gap (MMTPA) (LNG Opportunity)

59.9

82.6

112.0

131.2

The LNG Opportunity: Current Scenario The share of LNG in total natural gas consumption in India reached 25.5 per cent in FY12 and increased to 30 per cent in FY13. The total natural gas consumption in India in 2012-13 was 127.80 MMSCMD, in which RLNG contributed 41.60 MMSCMD (~32 per cent) of the total gas.

Gas Demand (MMSCMD)

India LNG Consumption (2012-13) Sector

Sector

2016-17 2021-22

2012-13 2013-14 2014-15 2015-16 2016-17 2019-20

Domestic Gas (MMSCMD)

RLNG (MMSCMD)

Total

Fertilizers

30.4

5.8

36.2

Power

31.0

8.4

39.4

CGD/CNG

6.7

7.3

14.0

Refineries

2.0

8.6

10.7

LPG

6.0

0.4

6.4

Petrochemicals

3.5

1.4

4.9

Sponge Iron/Steel

1.1

3.5

4.6

Court Mandated Consumers

1.0

2.9

3.9

Small Consumers

2.4

0.0

2.4

Other Users

0.8

3.3

4.0

Power

86

104

122

139

157

202

Fertilizer

60

60

60

72

97

106

City Gas

15

16

17

18

22

36

Industrial

20

20

22

25

27

35

Petchem/Refineries/Internal Consumption

38

40

42

44

47

54

Sponge Iron/Steel

7

8

8

8

8

10

Internal Consumption in Pipelines

1.5

0.0

1.5

227

248

272

307

358

443

Total

86.4

41.6

127.8

Total Realistic Demand

Source: Vision 2030, Natural Gas Infrastructure of India

www.oswindia.com

Source: Vision 2030, Natural Gas Infrastructure of India

Offshore World | 38 | February - March 2014

news features LNG Imports (MMSCMD) LNG Consumption Industry-wise Currently, Refineries are the largest consumers of LNG in India, accounts for 20.8 per cent as a cheaper substitute of naphtha used in the production of hydrogen. The fertiliser sector accounts for 20.1 per cent of LNG consumption used as a cheaper & more alternative for naphtha.

City gas distribution (CGD) is the third largest consumer of LNG with a 17.6 per cent share. The power sector accounts for 14 per cent of LNG consumption and others like Petrochemicals, LPG, Sponge Iron/Steel, etc accounts remaining 27.5 per cent of LNG consumption of the country.

44.6

143.0

188

214

214

Source: Vision 2030, Natural Gas Infrastructure of India

India LNG Import Profile (2012-13) In the year 2012-13, India imported total 13.7 MMPTA LNG & Qatar is the largest exporter of LNG to India contributing 80 per cent (10.9 MMPTA) of the total.

India’s Re-gasification Capacity Currently the natural gas demand far exceeds domestic supply in India and the situation is likely to prevail in future as well. Given that there are very few new domestic sources available, additional demand is likely to be catered through RLNG in future or through transnational pipelines in absence of any large domestic discoveries. As of December 2013, LNG re-gasification capacity of India is 23.00 MMPTA, of which 10.00 MMPTA at Dahej, 5.00 MMPTA at Hazira, 3.00 MMPTA at Dabhol and 5.00 MMPTA at Kochi.It is expected to reach 47.50 MMPTA by 2016 and 62.50 MMPTA by 2020 with the capacity expansion of existing and the planned & possible LNG terminals on India.

Location

Capacity (MMPTA)

Owned By

2013

2016

2020

Dahej

10.00

15.00

20.00

Petronet LNG

Hazira

5.00

5.00

5.00

Shell & Total

Dabhol

3.00

5.00

5.00

GAIL

Kochi

5.00

5.00

5.00

Petronet LNG

Total

23.00

30.00

35.00

-

-

-

Gangavaran

5.00

5.00

Petronet LNG

Mundra

5.00

5.00

Adani/GSPC

Ennore

5.00

5.00

IOCL

Total

15.00

15.00

Existing

Under Construction Total Proposed Country

Imports (MMPTA)

% Share

Algeria

0.4

3%

Egypt

0.6

4%

Nigeria

1.4

10%

Qatar

10.9

80%

Yemen

0.4

3%

Total

13.7

100%

Source: Vision 2030, Natural Gas Infrastructure of India

Possible West Coast

2.50

Hiranandani

Kakinada

5.00

Shell or GAIL

2.50

5.00

Swan Energy

2.50

12.50

47.50

62.50

Pipavav (FSRU) Total Grand Total

It is projected LNG import is all set to reach from 44.6 MMSCMD by 2012-13 to 214.00 MMSCMD by 2029-30.

23.00

Source: Petronet LNG

Offshore World | 39 | February - March 2014

- Rakesh Roy www.oswindia.com

news features

India Awards 46 Blocks in NELP-X The oil ministry has zeroed in on 46 onshore and offshore hydrocarbon blocks which have auctioned in the tenth round of New Exploration and Licensing Policy or NELP-X. The blocks which have been finalised include 17 onland, 15 shallow water and 14 deepwater in 13 prospective sedimentary basins of India for exploration of Oil & Natural Gas, covering an area of 166,053 sq km. These 46 blocks are falling in basin of Gujarat-Kutch, Gujarat- Saurashtra, Mumbai, Kerela-Konkan, Cauvery, Krishna Godavari, Mahanadi-NEC, Andaman, Bengal, Punjab plain, Rajasthan, Cambay & Deccan Syneclise. The 46 blocks have already received statutory clearances. The blocks on offer are lower than the earlier indicated number of 86.

Total Area : 166,053 Sq.km Deepwater : 94,364 Sq.km Shallow water : 47, 745 Sq.km Onland : 23, 944 Sq.km

14.42% 28.75%

Source: Directorate General of Hydrocarbons (DGH), Govt of India

www.oswindia.com

56.83%

Compiled by Rakesh Roy Offshore World | 40 | February - March 2014

Marketing Insight

Lowdown on Indian Refining Sector From total capacity of 62.8 MMTPA in 1998, Indian Refining sector has increased three folds to 215.6 MMTPA at present and will increase to 310 MMTPA by the end of 12th Five Year Plan in 2017. Industry experts deliberated over the Emerging Trends & Technologies in the Indian Refining Sector during the recently convened “International Refining Conference” organised during the Oil & Gas World Expo 2014. We bring you the lowdown on emerging technologies & trends in Indian refining sector based on the deliberations that were organised during one and a half day meet. Mittravinda Ranjan Reports...

Since the deregulation of sector in 1998, India’s refining sector has witnessed paradigm shift and India has gained significant prominence in the global market as net exporter petrochemicals.

While giving a lowdown on the country’s refining sector, L N Gupta, Secretary Oil Industry Development Board, Ministry of Petroleum & Natural Gas, Government of India acknowledged the last decade as the period of fastest growth for India’s refining sector and there has there has been a sizable increase from 62 MMTPA in 1998, country’s refining capacity stood at 215.06 MMTPA by the end of 2012.

Indian PSUs started phased capacity addition to meet the growing product demand with emphasis on upgradation of product quality and bottom of barrel along with enhancement of complexity factor.

Currently, Indian public sector companies comprise approximately 63 per cent of country’s total refining capacity while 37 per cent of capacity if owned by private sector companies. By the end of 2013-14, with the Paradip & Cuddalore grass root refineries, country’s refining capacity is projected to reach around 236 MMTPA which is expected to increase to 333 MMTPA by 2022.

Currently India has surplus refining capacity of 60 MMTPA which is equivalent to 38 per cent of its consumption. This sector has grown at 5 per cent CAGR over the last couple of years and accorded impressive export earnings of USD 59.3 billion during 2012-13.

Refiner

No. of Refineries

Capacity as on 01.10.2012

IOC Group

10

65.70

BPCL group

4

30.50

HPCL group

3

23.80

ONGC/MRPL

2

15.06

Total PSU

19

135.06

RIL (Pvt.)

2

60.00

Essar (Pvt.)

1

20.00

Total Private

3

80.00

Total

22

215.06

Amidst Highly Volatile Markets Crude prices saw maximum swing during 2008 when per day barrel rate peaked to all time high. Globally, over 70 refineries have closed on account of failing to maintaining high profitability so far.

World over, refiners are walking tight rope for maintaining the Gross Refining Margins (GRM) in the era of highly volatile markets and fluctuating crude prices. Report by McKinsey & Company suggests notes that Indian refiners need at least USD 5-6 per barrel to cover the operating cost and an additional USD 7-8 per barrel to generate an adequate return on capital. Energy is pivotal issue for the refiners since it is the largest component of OPEX and accounts for average of 34 per cent in America, 58 per cent in Europe, 69 per cent in Asia Pacific and 81 per cent in India. As a part of long term sustainable growth strategy, refiners are using cheap petcoke to produce power taking several energy saving measures to optimize energy usage. In addition to carrying out the yield and optimization studies across hydrogen units, the refiners are emphasizing on adoption of energy savings technologies, deriving cheap energy out of petcoke, low level heat recovery and improving power generation efficiency. Petcoke gasification using CBFC technology for power generation has gained noteworthy momentum as refiners have been able to achieve remarkable decline in the energy costs hence improving GRM. Deploying CFBC technology to produce power is one of the common routes

Offshore World | 41 | February 2014 - March 2014

www.oswindia.com

Marketing Insight Lowdown on the Future

which involves typical investments of approximately ` 700 crore for 2X300 TPH CFBC boilers , 2X37 MWH STGs result in significant saving in power and steam cost which results in improving GRM of USD 1.3 per barrel and fuel savings of ` 2.4 crore per day.

Refiners are also adopting various routes to improve GRMs right from enhancing capabilities to process different crude mixes such as - High Sulphur Crudes, Heavy Crudes, High Acid crudes, Unconventional Crudes etc. HMEL, BORL and PDRP refineries are designed for 100 per cent HS crude. Refiners are further widening the product basket through continuous addition of opportunity crudes by setting up refineries with higher complexities.

The Saviour Changing market dynamics are driving the shift in technology trends , some of them include - preference of HCU over FCC, use of hydroprocessing a n d m i l d hyd ro c ra c ki n g to m e e t p ro d u c t d e m a n d & q u a l i t y , R F CC operation to shift towards petrochemical mode , reforming to shift towards high oc tane operation, Use of Alkylation & Dimerization to meet MS q u a l i t y, H y b r i d s e p a rat i o n s ( M e m b ra n e s / D i v i d e d Wa l l Co l u m n f o r l i g h te r p ro d u c t s ) , M u l t i f u n c t i o n a l R e a c to r s (Ca t a l y t i c D i s t i l l a t i o n Units), and Hydrogen Generation Process (Single Stage) etc. to name a few.

Diesel & gasoil leads the pack in refined product demand and maximum demand will come from the BRIC nations. Indian refiners have consistently improved the processes in accordance with the auto fuel policy and introduced BS IV auto fuels in 13 major cities in 2010 which will be extended to 50 additional cities by 2015.

• • • • • • • • • • • • • • • • • •

Bottom upgrading to distillates or value added products Refinery Residue to clean fuel Hydrogen Production from Petcoke Advanced Process Control & Optimization Upgradation of FCC streams to Petrochemical feedstocks Improving efficiency of LPG Stove by 5-10% Waste to fuel using refinery spent catalyst Non-HDS based desulphurization technologies Bio-refining Catalyst/Additive development New process development Scale-up of multiphase reactors Separation technologies (Progressive Distillation, Divided Wall Column) Process intensification for large scale application Alternative Energy Source Development of high performance lubricants Development of technology for fuel from plastic Coal to Liquid, Gas to Liquid (GTL), CO2 Capture Technologies

Gazing into the Crystal Ball Future refineries would be high capacity, fully automated, integrated & energy efficient, ZLD, environmental compliance from carbon capture. Refiners will be compelled to maintain refining margins above benchmark refining margins which can only be achieved through technological interventions for meeting product quality with minimum hydrogen consumption, processing heavy crudes optimizing refinery costs, emission control and exploring ways to curb water footprint.

Indian refiners have significantly invested in capacity increase and reasonably in research & development and are geared up to play a notable role in the international market. However in the changing scenario like availability of cheap feedstock like shale gas in the US, Indian refiners could find themselves in the tight spot lest they address the energy issues to cut down the overall OPEX and maintain the GRMs. S M Vaidya, Deputy General Manager, Panipat Refinery & Petrochemical Complex , IOCL reiterated A T Kearney’s statement based on global refinery study, “With one in five oil refineries expected to cease operations over the next five years, choosing the right operating model and level of integration will be crucial for survival and sustained profitability”.

However the refinery - petchem integration is one of the most preferred routes for the refiners. Complete integration of refinery, aromatics & petrochemical complex with super-site concept to sustain global competitiveness. Addition of value added specialty products widens the product slate and enables the refiners to balance the oil and petrochemical products in line with market opportunities and leads to better profit realization. www.oswindia.com

Offshore World | 42 | February 2014 - March 2014

news

India India Crude Import from Iran on Rise New Delhi: Aftermath the easing of sanctions against Iran following a US-EU deal on Tehran’s nuclear programme, India has started doubling its monthly crude purchase from Iran, with imports about 3 million tonnes (mt) in January 2014. India will also build a container terminal at the Chabahar port in Iran at a cost of USD 174 million to handle the extra load of tankers and container ships carrying oil to India.

Moily Picks Saurabh Chandra as Petroleum Secy

Saurabh Chandra, Petroleum Secy, MoPNG

New Delhi: Petroleum Minister M Veerappa Moily has managed to have the final say in deciding the new Petroleum Secretary. Based on his choice, the Union government has approved the name of Saurabh Chandra as the replacement for Vivek Rae. Chandra is a 1978-batch officer from the Uttar Pradesh cadre, currently serving as Secretary, Department of Industrial Policy and Promotion.

He becomes the topmost officer of the petroleum ministry at a time when it is to launch two key initiatives - the revision of domestic natural gas prices due from April 1, and the 10 th round oil and gas block auctions under the New Exploration Licensing Policy (NELP).

In April-December 2013, India imported 6.88 mt (metric tonne) of crude, or an average of 1.15 mt a month. The jump in crude imports could eventually raise India’s oil imports from Iran back to levels prior to sanctions of 21 mt annually.

India will end 2013-14 by importing about 11 mt of crude. If sanctions had continued, this would have been reduced by another 15 per cent.

India to Drive Global Oil Demand by 2020: IEA News Delhi: India is set to become the biggest driver of global oil demand by year 2020, according to International Energy Agency (IEA). In a report, IEA stated that the growth in global oil demand is expected to remain moderate due to global economic weakness as well as more fuel-efficient technologies. Supplies are likely to get a fillip from shale gas & oil and deep & ultra-deep drilling campaigns. This means the world is likely to have a stable pricing regime in the crude oil in next 5-7 years. India needs to utilise this period in ensuring stable and long-term energy security.

India’s haphazard policy making in the fields of subsidies, strategic petroleum reserves, natural gas sourcing, pipeline infrastructure, NELP etc has left it susceptible to energy shocks, the report said. The report also said that the Indian government’s policy to encourage exploration and exploitation of shale gas would be a distant dream due to land acquisition pose key hurdles in exploiting shale reserves in the country. As a result, India will continue to depend on imported energy - be it crude oil or liquefied natural gas (LNG) - in the foreseeable future.

ONGC Makes Four Discoveries in 3Q of FY14 Subsidy Groan for PSUs in 2013-14 New Delhi: ONGC’s share of the subsidy burden in 2013-14 is likely to touch 34 per cent from 31 per cent last year, while Oil India’s share may go up to 5.5 per cent from 5 per cent.

These two upstream oil companies are likely to bear more of the petroleum subsidy burden in 2013-14 than initially estimated. This is because the Government has restricted its share of the burden to 60 per cent, the oil marketing companies (Indian Oil, HPCL and BPCL) are not likely to contribute, and GAIL’s burden has been capped. At ` 85,480 crore, the revised estimate of the Government’s petroleum subsidy for 2013-14 works out to 60 per cent of the total estimated petroleum subsidy for the year (` 1,43,000 crore). This is the same proportion as last year.

Due to the rupee’s weakness since June 2013, under-recoveries on fuel sales have been significantly higher than envisaged at the beginning of the fiscal. The oil marketing companies, which incur the under-recoveries in the first place, are likely to be spared from subsidy sharing to prevent them from slipping into losses.

Ergo, the remaining 40 per cent of the burden, once again, will fall on the upstream companies (ONGC, Oil India) and GAIL. But GAIL’s burden for 2013-14 has been restricted to ` 1,400 crore. This means more burden on ONGC and Oil India.

Mumbai: ONGC has made Four (on-land: 3, offshore: 1) new oil & gas discoveries during the Third Quarter of 2013-14. Exploratory well MBOS51NAA#1 in NELP block MB-OSN-2005/1, Western offshore basin was drilled to a depth of 3,385 m. Interval 2,549.5 to 2,555 m in Tertiary Daman formation on testing through produced gas 250,107 m 3/day and condensate 255 barrels/day through 3/8 inch choke. Another interval 2,515.5-2,526.5 m also in Tertiary Daman formation on testing through produced gas 209,734 m 3/day and condensate 180 barrels/day through 3/8 inch choke. This is the 2 nd discovery in this block after earlier notified discovery MBOS51NBA#1. These discoveries in close vicinity of C-37/ C-39, B-9 areas will enhance the overall gas potential of the area.

Indian PSUs’ Gas Reserves at Mozambique Raises Mumbai: Gas reserves in Mozambique’s Rovuma basin have been upgraded to 4570 trillion cubic feet from 35-65 tcf where Indian firms hold a 30 per cent stake.

ONGC has invested USD 4 billion in the project. BPCL, which also holds a stake along with Oil India, informed the stock exchanges that Anadarko, the operator of the block announced this month that reserves estimates had been scaled up. The field is expected to ship out its first LNG cargo in 2018. ONGC Videsh Ltd (OVL) bought 16 per cnet in this project for USD 4 billion, Oil India took another 4 per cent for close to a USD 1 billion. State run fuel retailer BPCL already owns a 10 per cent in this project. The gas reservoir is seen as the third largest potential producer of liquid gas after Australia and Qatar.

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New DGH Emphasises on More Investor Friendly Environment New Delhi: With India slated to become the third largest energy consumer in the world by 2020, B N Talukdar, the newly appointed DGH, has called for creating a more investment friendly environment to produce more oil and gas in the country.

B N Talukdar, DGH, GoI

He said that the country have to create more investment friendly environment, enable suitable regulations in place so that a much

NIO to Collect Geophysical Data of KG Basin Vishakhapatnam: Oil and Natural Gas Corporation (ONGC) has been awarded a project worth ` 17.94 crore to collect geophysical data from its oil fields in the Krishna-Godavari basin to National Institute of Oceanography (NIO), a constituent laboratory of the Council of Scientific and Industrial Research (CSIR).

The project is being implemented by a joint team of scientists both from CSIR-NIO Regional Centre at Vishakhapatnam and Goa. VSN Murty, Scientistin-Charge & Principal Scientist, NIO, Vizag, said that CSIR-NIO will carry out surveys involving multi-beam bathymetry, magnetic, high-resolution sparker. It will also determine water column temperature and salinity up to a depth of approximately 900 m. The data will help ONGC in laying pipelines for transporting oil and gas from their G-4, D and E oil and gas fields, and the development of other offshore production facilities.

HPCL to Acquire Australian Gas fields New Delhi: Prize Petroleum Co, the upstream arm of state-run refiner Hindustan Petroleum Corp Ltd ( HPCL), has signed an agreement with Australian exploration firm AWE to acquire minority stakes in two gas fields and a gas infrastructure facility for 85 million Australian dollar.

more vibrant domestic energy sector evolves, in his first message since taking over as Director General of Hydrocarbons. He also added that we have to think of incentivizing the E&P companies for developing and applying advanced technologies necessary to explore, develop and produce energy to meet the growing demand of the progressing nation. He said that only 7 sedimentary basins out of a total 26 basins in the country are on production today. There is a big challenge lying before us to explore for oil and gas in all the basins within a stipulated time frame so that maximum numbers of basins are put on production to reduce the huge gap between the demand and the indigenous production in the country.

Iran Needs More Bank Accounts to Export Crude to India New Delhi: To increasing trade, especially crude import from Iran, India needs to allow Iran to open accounts in banks other than UCO Bank and from all the major port cities. Aftermath the Iran deal with the world powers eased the way import crude from Iran, but still not very clearly spell out the procedures in case of insurance cover for vessels carrying Iranian cargo to and from that country.

Two Iranian ship underwriters (Kish P & I Club and Moallem Insurance Co) have been given six months extension by the Director General of Shipping (DGS) from 28th December 2013, while asking for a ` 2,300 crore bank guarantee in rupees to pay for damages in the event of a mishap occurring in the Indian waters. Iran has sought some more time to resolve this issue.

At the moment, the National Iranian Tanker companies like Hafiz Darya Shipping Lines and Safiran Payam Darya Shipping Lines carry crude to India.

Iranian supplies of crude fell to 13.3 million tonnes (mt) in 2013 against 18.1 mt in the previous year and is likely to touch only 11 mt by March 2014.

Prize Petroleum will acquire 11.25 per cent stake in T/L1 license that includes Yolla producing field and purchase 9.75 per cent stake in T/18P permit including Trefoil development field in Australia. The shallow water fields are located the Bass basin between mainland Australia and Tasmania. Origin Energy is the operator of the fields where AWE and Toyota Tsusho are major partners.

At the moment, Iran maintains a rupee account with UCO Bank in Kolkata from where Indian exporters are paid against their shipments of various goods. With the relaxed condition of the sanction, Iran feels that trade will increase and to facilitate easy payments to exporters in India, it needs to operate from more banks in addition to UCO Bank in Kolkata. This is not an unfair or impractical demand, and the Ministry of Finance must immediately permit the opening of accounts with banks of their choice operating from all the major port cities like Mumbai, Mangalore, Cochin, Chennai, Vishakapatnam, Paradip and Kolkata, in addition to other cities that they may choose. In any case, almost all banks are governmentowned, and Ministry should not waste time in meeting this reasonable request.

Two Key Mins had Opposed Gas Price Hike

Tripura Power Project Finally to Get Gas

New Delhi: The power and fertiliser ministries had opposed the gas price hike, cited that a hike would result in a huge financial burden for the sectors that are among the main users of gas. The key two ministries, in their observations to Rangarajan committee, had made it clear that the cost of raising gas prices would be enormous on these two sectors. The increase from USD 4.2 per unit to 8.4 per unit would put the financials of gas-based power plants under strain and according to some estimates the burden could be as high as ` 30,000 crore annually. The burden on the fertiliser sector would be an additional ` 10,000 crore as subsidy.

Mumbai: State-owned ONGC has finally agreed to supply natural gas to the 101-MW capacity Monarchak power plant that is being set up by governmentrun NEEPCO in western Tripura. ONGC plans to start supplying gas to Monarchak power plant from this year end and need seven to eight months to complete the technical works to provide the gas,� said Oil and Natural Gas Corporation (ONGC) Group General Manager V P Mahawar. The state-run North East Electric Power Corporation (NEEPCO) is setting up 101 MW capacity power project at Monarchak in western Tripura, 70 km south of Agartala, at a cost of ` 9.50 billion (nearly USD 150 million).

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news FinMin Pitches to Bring DGH under Budgetary Funding Right Pricing Needed for Energy Security: Ex OilSec New Delhi: To make more professionalism and objectivity to the functioning of Directorate General of Hydrocarbons (DGH), the upstream oil regulator, the Finance Ministry has pitched for its direct budgetary funding and consequent statutory status.

If the move will get sanction from cabinet, the DGH will have to depend on the finance ministry for funds, instead of the petroleum ministry, to which it is currently attached.

New Delhi: As the country imports 75-80 per cent of crude oil and is importing more gas and more coal despite having its own reserves, you have to link the oil & gas price with international prices, said Vivek Rae, Former Oil Secretary to justify the gas price hike by saying getting pricing right for oil and gas is the key to attaining energy security.

He said that if you run a regime where the domestic prices are artificially suppressed and get lower than international prices, it’s a huge penalty on domestic production and huge burden on fiscal deficit.

The ministry wrote to Oil Ministry calling for statutory status to DGH as it performs sovereign functions that are technical in nature. The ministry feels that rather than being funded by the Oil Industry Development Board (OIDB), the DGH should be funded through the government’s own budget as is the case with other independent regulatory authorities.

India, he said, cannot buy oil at USD 110 from international markets and sell it at USD 50 to consumers and hope to survive. “Sooner or later you will go bankrupt.”

The oil ministry has responded that it was in favour of maintaining status quo and is awaiting further feedback from the finance ministry. Sources say the oil ministry’s finance wing is in favour of the finance ministry proposal, but the exploration wing wants to maintain status quo.

Domestically produced natural is currently priced at USD 4.2 per million British thermal unit while the country pays USD 16 for importing the same from abroad. From April, all domestically produced natural gas will be priced at an average of international hub price and cost of importing LNG into India.

Rates according to this formula are likely to jump to USD 8 from current USD 4.2 per mmBtu.

If funded through the budget, the DGH will be required to form a board of directors and appoint professionals in key positions. Currently, Oil and Natural Gas Corporation (ONGC) and Oil India (OIL) fill up most of the top positions in the regulator.

Energy Sufficiency by 2030 a Distant Dream for India New Delhi: India became the third-largest oil importer in the world overtaking Japan in import volume, behind China and the US. In the first nine months of 2013-14, India had imported a little over 3.8 million barrels of crude oil a day.

The International Energy Agency (IEA) estimates India will become the world’s largest oil importer by 2020 against the view of Indian government that the country will have achieve energy sufficiency by 2030, making imports unnecessary. India’s oil consumption will rise inevitably as its economy grows larger. By the 2030s, India will need about eight million barrels a day, going by expected GDP and population growth. As of now, India produces slightly less than 0.5 million barrels of crude a day and will have ramping up domestic production 16 times more in the next 15-20 years then that will border on the miraculous. It is also difficult to imagine an energy substitution process that drastically reduces the need for crude. This would require major technological breakthroughs.

Most likely, India’s import dependency will rise substantially, to around 95 per cent of consumption. This is likely even if domestic sources are tapped efficiently; unconventional shale and coal-bed-methane are developed; massive substitution results via renewable, etc.

Most First World nations are net oil importers. None of the importers offer subsidies on a commodity they must import. All ensure fuels are priced at market prices and most add punitive taxes to ensure there isn’t wasteful utilisation.

Indian policy should have gone the same way. There should have been an attempt to empower Indian oil and gas explorers and producers. Policy should also be designed to encourage consumers to be as frugal and efficient as possible.

“So if you are importing this gas, you are paying USD 16, but if you are producing here you get USD 4. So for an Indian entrepreneur (it is prudent) to invest in Africa or Australia or Latin America, and bring that gas in India at USD 16,” he said. “It (domestic price) is a huge penalty to invest domestically.”

New Fuel Efficiency Norms to Minimise Oil Imports New Delhi: The Bureau of Energy Efficiency had calculated that the new fuel efficiency standards from 2017 would help the country reduce oil consumption by 2.22 million tonnes of oil equivalent (mtoe) as compared to the business as usual scenario by 2017 and 10.5 mtoe by 2022.

The fuel efficiency norms are part of the ‘demand management’ that the government had professed for years in order to regulate the volume of oil imported. It also feeds in to the Energy Efficiency mission under the National Action Plan on Climate Change.

The setting of standards for fuel efficiency of appliances and automobiles is usually preceded by mandatory labelling of the products to ensure consumers are informed. But in the case of cars, the labelling was opposed strongly with the industry instead promoting its own parallel scheme.

With the standards being forced through, the labelling is expected to be next on the anvil. Labelling would enable the potential buyers to see where each model of the car in the market stands in comparison with other options in the same weight range.

Alongside, sources in the ministry said, there would be a need for opening up the data on testing of vehicles for mileage and other related numbers to public scrutiny to also build confidence in the consumers.

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ONGC’s New Chief Bets on Overseas Growth Drive

D K Sarraf, Chairman and Managing Director, ONGC

New Delhi: D K Sarraf, the New Chairman and Managing Director of ONGC, known for his overseas seal deals to the energy sector during his two-year tenure as managing director of ONGC Videsh Ltd (OVL), the oversea arm of ONGC. Now, as the new boss of the Oil & Natural Gas Corporation (ONGC), the parent of OVL, he expects the unit to drive growth at the company. Sarraf took charge as Chairman and

Managing Director of ONGC from his predecessor Sudhir Vasudeva. Sarraf said his priorities to bring the promising block in the Krishna Godavari (KG) Basin to production. This deep-water block lies North of the basin next to Reliance Industries KG-D6 block.

Sarraf said the ONGC block has reserves of roughly two trillion cubic feet of gas and 117 million metric tonnes of oil. “We are expecting peak production of 25-30 mmscmd gas and 70,000 barrels of oil every day.”

UAE, India Tie up to Set up Strategic Petroleum Reserve IOCL to Acquire Stake at LNG Terminals New Delhi: In a bid to further strengthen economic relations, India and the United Arab Emirates (UAE) have agreed to cooperate for setting up a strategic petroleum reserve in India. Regarding this, top leaders of the two countries discussed the possible cooperation in India-UAE High Level Joint Task Force on Investments in Mumbai. The meeting was co-chaired by India’s Commerce and Industry Minister Anand Sharma and chairman of Abu Dhabi Crown Prince Court Sheikh Hamed bin Zayed Al Nahyan.

The joint task force was established in April 2012 as a platform to address mutual issues associated with existing investments between the two countries and to promote and facilitate cross-border investments. More than 30 government and private sector representatives from India and the UAE participated at the meeting. During the meeting Sharma underlined India’s status as a major destination for foreign investments and the opportunities that exist for the UAE, especially in infrastructure areas such as roads and highways, power and utilities, civil aviation, ports, renewable energy and urban infrastructure.

Mumbai: IndianOil Corporation Ltd (IOCL), the public sector oil giant, plans to acquire stakes in liquefied natural gas (LNG) terminals at Mundra and Dahej in Gujarat and Dighi in Maharashtra, according to A K Marchanda, Executive Director - Business Development, IOCL. IOC is looking at a 25 per cent stake in the ` 5,200-crore LNG project in Mundra, which is being set up by Gujarat State Petroleum Corporation (GSPC).

In Dahej, Petronet LNG Ltd, India’s largest importer of liquefied natural gas (LNG), operates an LNG terminal with a capacity of 10 million tonnes a year, which is expected to increase 15 million tonnes at an estimated cost of ` 2,950 crore by end-2016. The 8-MT LNG terminal at Dighi port in Maharashtra is being set up by Mumbai-based Hiranandani Group.

IOC is in talks with three foreign companies for the proposed ` 4,512-crore LNG terminal project at Ennore; it is also looking for shell gas in the US and other countries. Marchanda said the project has got the environment ministry’s clearance and the tender process will commence soon.

He also highlighted India’s desire to participate in the hydrocarbon sector in the UAE, especially in the upstream petroleum sector, according to a statement released here by India’s commerce and industry ministry. Sharma said India sees greater opportunities for UAE investors as strategic partners in the country’s growth story.

IOC has also signed an initial deal with Dhamra Port to build a five-milliontonne-a-year LNG plant in eastern Odisha with an investment of around ` 5,000 crore. It could annually use 2.5 million tonnes of LNG from the Odisha terminal for its planned 300,000 barrels a day Paradip refinery and its existing Haldia and Barauni refineries, said Marchanda.

Gujarat Withdraws Approval for NELP-X Blocks

Kuwait Petroleum Eyes for Stake in Paradip Refinery

New Delhi: In a major setback to oil and gas block auction under 10th round of New Exploration Licensing Policy (NELP), the Gujarat Government has withdrawn clearance for the 9 areas falling in the state, citing revenue sharing distribution between Center and State. Gujarat wants a share of revenues that the Centre will earn from the oil and gas produced.

New Delhi: Kuwait Petroleum Corp (KPC) is in talks with Indian Oil Corp (IOC) for buying a stake in the state-owned firm’s ` 29,777-crore Paradip refinery and a proposed petrochemical complex. IOC, which will start commissioning the 15-million-tonne-a-year refinery at Paradip, is willing to offer no more than a 26 per cent stake in the project. The refinery has been built to process at least 40 per cent of toughest, heaviest and the dirtiest crudes like Maya of Mexico which are cheaper than the cleaner and easier varieties available from the Middle East.

This share of the Centre’s revenue is additional to the royalty at the rate of 12.5 per cent of price realised on the sale of crude oil and 10 per cent for natural gas that currently flows to the state government. NELP-X auction is to be held under a production-linked revenue sharing model wherein oil companies would have to pay the Government an agreed amount, depending on the level of output, and not on the investment in the exploration block. www.oswindia.com

The refinery will have a Nelson Complexity Index of 13, the highest in the world.The project will have to be spun off into a separate company if Kuwait is to participate in it. IOC plans to set up a ` 3,150 crore Polypropylene unit adjacent to the refinery.

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India Agrees to Pay for Crude Oil on Iran’s Kelkar Wants Existing Regime for Oil Contracts Currency Choice New Delhi: Vijay Kelkar, Chairman of the expert panel on energy security, New Delhi: India has agreed to clear the pending crude oil payments of over USD 3 billion in a mode of currency of Iran’s choice. These pending bills are for the period starting February 6, 2013, when the Turkey route of payment for oil sourcing was halted following the Western sanctions on Iran.

has stuck to his position that the existing regime for oil and gas contracts that governs oil and gas fields including Reliance Industries Ltd’s KG-D6 block should continue, and shrugged off allegations that parts of his report were plagiarised from a presentation from the Association of Gas and Gas Operators (AOGO).

Following the Western sanctions on Iran, India had put in place a rupee payment mechanism which allowed it to pay for 45 per cent of oil purchase in its local currency. The mechanism has so far been successful with very little money lying idle in Iran’s Rupee account held with UCO Bank.

Kelkar said the committee had requested AOGO to provide data and analysis of issues that affect the sector. These were included in its interim report, which was submitted to the government in January. The committee has also been accused of going beyond its terms of reference and making recommendations on what the contractual regime should be. In the existing system, the operator of a field first recovers the development cost and the government gets its share later.

India’s exports to Iran have almost doubled to USD 4.2 billion in the first 10 months of the current fiscal compared with USD 2.4 billion in the same period last fiscal. Also, India expects to buy 11 million tonnes of crude oil from Iran in 2013-14 and similar volumes in the next fiscal.

During the April-January period of the current fiscal, India imported 8.47 million tonnes of crude oil from Iran. Imports from Iran have fallen from 21.20 million tonnes (mt) in 2009-10, to 18.50 mt in 2010-11, 18.11 mt in 2011-12, and 13.14 mt (provisional) 2012-13.

Israel Renews Offer to India to Explore Gas New Delhi: Israel has renewed its offer to Indian oil and gas companies to exploit its huge offshore natural gas reserves, according to Alon Ushpiz, Israeli ambassador to India, to a leading English newspaper by saying “I’d like to give my personal guarantee. The minute an Indian company, private or governmental, knocks on my door and expresses interest in gas, including in its production, we are Alon Ushpiz, Israeli ambassador open to discussions.” Israel is flush with natural to India gas after its discoveries of gas in the Tamar and Leviathan gas fields in the Mediterranean Sea. These discoveries are expected to have a significant impact on the strategic balance in the West Asia. The Israeli government has decided to export 40 per cent of its gas. Recently, Australian company Woodside Petroleum Ltd inked a deal to acquire a 25 per cent stake in Leviathan gas field.

The oil ministry had initiated a cabinet proposal to change this and adopt the system of revenue sharing, where the government gets paid a part of the sales proceeds the moment production starts. The change was proposed because in the revenue-sharing system, the government is not concerned about possible cost inflation by a contractor, and there would be no scope for controversies such as the one surrounding RIL’s KG-D6 block, where the company has been accused of overstating costs. The company has been penalised for spending excessively on infrastructure, which turned out to be surplus after gas output fell sharply.

TAPI Likely to Head by US-based Consortium New Delhi: The USD 9-billion Turkmenistan-Afghanistan-Pakistan-India (TAPI) gas pipeline project is likely to see an America-based consortium leader.

“Considering the terrorism-torn terrain of the project, we are looking for a USbased company with experience in building and operating the cross-country pipeline. Moreover, in a meeting held last month, the partners were keen to register Tapi Ltd in a place like New Jersey,” said an official source.

Despite several roadshows in Singapore, New York and London, global majors were not keen to participate as a consortium leader, due to the Turkmen government’s decision not to give participating stakes for the companies in hydrocarbon fields.

Last February, the Indian government had given its nod to creation of Special Purpose Vehicle and for the participation of state-run GAIL (India) Ltd in the project. GAIL would invest USD 5 million. The project is expected to be operational by 2017-18. The Asian Development Bank is transaction advisor.

India, Saudi Arabia to Deepen Energy Partnership US to Supply Gas to India New Delhi: To transform the ‘buyer-seller’ relationship in the oil sector to one of deeper partnership, India, Saudi Arabia seek more focusing on investments and joint ventures in third countries.

The recent visit of Saudi Arabia’s Crown Prince Salman bin Abdulaziz Al Saud to New Delhi boosted strategic ties and the two countries agreed to explore ways and means to transform their buyer-seller relationship.

Saudi Arabia is India’s fourth largest trading partner and almost one-fifth of India’s oil imports come from Saudi Arabia. However, investment flows between the two countries have been far below their potential.

New Delhi: Shale gas exports to India from the US could pick up momentum in coming days, according to US India Political Action Committee (USINPAC).

This follows the introduction of legislation — HR 6, the Domestic Prosp-erity and Global Freedom Act — in US Congress to expedite export of natural gas to American allies like India and Japan.

USINPAC said that over the past year, surplus production of LNG (liquefied natural gas) in the US has given impetus to the prospect of LNG exports to countries as India, Ukraine, and Japan. The surplus is due to rapid advances in the technology and extraction of shale gas and oil over the past few years.

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International Sunbird to Pursue More Gas Offshore South Africa South Africa: Denver-based MHA Petroleum Consultants have completed an assessment of the Sunbird Energy operated block 2A offshore South Africa. The best estimate is 7.8 tcf (221 bcm) of prospective gas resources. The 5,000-sq km (1,930-sq mi) concession is currently in year five of a 30-year production right issued by South Africa’s Department of Mineral Resources.

Sunbird commissioned the assessment last October, following field development concept studies by Wood Group Kenny and a grant toward a full-field development plan. The block includes the planned Ibhubesi gas project (IGP). The aim was to identify more exploration potential for additional gas volumes for IGP. To date, seven of the 11 wells drilled on the block have discovered commercial gas volumes.

Sunbird plans to start additional geological studies this year to identify targets for future exploration drilling based on geological certainty, prospect size, and proximity to the IGP development.

KrisEnergy to Work with S antos O ffshore Bangladesh Bangladesh: KrisEnergy will partner with Santos Sangu in an exploration block offshore Bangladesh.

Santos operates the production-sharing contract (PSC) for block SS-11, covering 4,475 sq km (1,728 sq mi) in the Bay of Bengal over the Bengal fan.

Both companies have a 45 per cent interest, with the remaining 10 per cent held by Bangladesh Petroleum Exploration & Production Co. Most of the block is in shallow waters up to 200 m (656 ft), although the farthest southwest portion extends to 1,500 m (4,921 ft). The PSC has an initial five-year term, with commitments to acquire and process 1,893 km (6,210 mi) of 2D seismic data and 300 sq km (116 sq mi) of 3D data, and to drill one exploration well.

Liwan Nears Start-up Offshore China China: Husky Energy says the CNOOC-operated Liwan gas project in the South China Sea is nearing production, with commissioning of the shallow water platform and gas plant under way. Final components of the deepwater infrastructure for the Liwan 3-1 field have been installed and commissioning is proceeding.

The Liuhua 34-2 field is due to be tied into the producing Liwan deepwater facilities over a six- to eight-week period in the second half of 2014. Negotiations continue for a gas sales contract for the Liuhua 29-1 field, where Husky anticipates first production during 2016-2017. Additionally, the company is evaluating a recent new natural gas discovery on the block, along with four previous finds from 2012. Husky has a 50% interest in the MBF discovery, west of the MBH field.

Ophir Energy Begins Drilling Offshore Gabon Gabon: Ophir Energy plc has begun drilling operations on the Padouck Deep-1 well on the Ntsina block, offshore Gabon, using the Vantage Titanium Explorer drillship. The Padouck Deep-1 well is the first well targeting the presalt play offshore in the North Gabon basin, and is located in a water depth of 835 m (2,740 ft) and has a planned TD of 3,500 m (11,483 ft). Operations are expected to take approximately 45 days.

PA Resources Updates Tunisian Offshore New Deepwater Oil Play Offshore Mauritania Programmes Mauritania: Tullow Oil has discovered hydrocarbons with the first well in an exploration drilling campaign Tunisia: PA Resources (PAR) has authorised new measures to extend the life of the Didon field offshore Tunisia. These include installation scheduled this spring of an electric submersible pump in a previously shut-in production well, and drilling of an infill well during the fall.

PAR’s other offshore concession contains part of the Zarat field, which overlaps into an adjoining license.

The southern and northern tract partners are working to resolve legal and commercial issues for a Zarat Unitized Unit OperatingAgreement (UUOA). It is also formulating a full field life Unit Plan of Development (UPOD), taking into account Tunisia’s increasing gas supply demands and CO2 sequestration requirements.

An agreed southern/northern tract Zarat UUOA and UPOD both should be ready for submission to the authorities for approval in mid-year. www.oswindia.com

targeting deeper-lying plays offshore Mauritania. Frégate-1 was drilled to a depth of 5,426 m (17,802 ft) in the C-7 license. It encountered up to 30 m (98.4 ft) of net gas/condensate and oil pay in multiple sands.

Tullow says the well represents a technical breakthrough by establishing a new oil play in deepwater late cretaceous turbidites. The company plans to integrate the results with its regional 3D seismic surveys.

Kuwait to Raise Oil Output by 2015

Hashim Hashim, CEO, Kuwait Oil Company

Kuwait: Kuwait plans to raise its oil production capacity by 150,000 barrels per day to 3.4 million bpd by mid-2015. “Kuwait’s current production capacity is 3.25 million bpd. We plan to add another 150,000 bpd by mid2015,” said Hashim Hashim, CEO, Kuwait Oil Company, which is responsible for exploration and production. The company also plans to add between 400,000 and 500,000 bpd to the country’s production capacity to fulfil Kuwait’s aim to raise output capacity to 4 million bpd by 2020, Hashim said on the sidelines of the global oil and gas conference. He said Kuwait currently pumps around 3.0 million bpd and could “increase production depending on market conditions”.

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news International Solid Test Results from Oil Discovery Offshore Oman Oman: Masirah Oil says it is encouraged by test flow rates from its recent discovery in block 50 offshore Oman. The exploration well was drilled to its final depth in the Cambrian formation. Main objectives were to demonstrate the presence of movable hydrocarbons and a working petroleum system within the block. Several zones in the well provided evidence of hydrocarbons.

During a 48-hr test, hydrocarbons flowed to the surface with the well producing up to 3,000 stock tank b/d of light oil with no water production. It is currently suspended. This was the first offshore oil discovery east of Oman after more than 30 years of exploration.

Iran Re-starts Offshore Drilling in Caspian Sea Iran: Khazar Exploration and Production Co (KEPCO) has resumed exploration in the Iranian sector the Caspian Sea on the Sardar-e-Jangal field. According to Iranian news service Shana, a 16-in. liner is now installed in the second well, which is currently at a reservoir depth of 1,600 m (5,249 ft).

Yousef Etemadi, Director - Exploration Affairs, KEPCO, added that the liner hanger is installed in a 20-in. casing.

Sardar-e-Jangal is thought to hold in-place oil of 2 Bbbl, with a 25 per cent recovery rate.

Kazakhstan Aims at Oil Giants in New Flare up Kazakhstan: Kazakhstan is suing foreign oil majors developing its huge Kashagan oil field in the Caspian Sea, a tactic similar to those that secured the government large stakes in two of the three multinational energy projects on its territory. Repeated delays at the 13-year-old project, targeted to produce as much oil as Opec member Angola from a reserve almost as big as Brazil’s, have infuriated the Kazakh government.The consortium, led by Exxon, Royal Dutch Shell, Total and Eni as well as Kazakh state oil firm KazMunaiGas, may face Kazakhstan seizing a bigger stake in Kashagan or refusing to reimburse a big chunk of the USD 50 billion (Dh 183.5 billion) spent on bringing it onstream.

The latter option is written into the Kashagan contracts. Production at Kashagan, the world’s biggest oil discovery in 35 years, began in September but was stopped just weeks later after gas was found to be leaking from its pipelines.

Residual sour gas was then burnt in flares at Kashagan’s processing plants, polluting the environment.

FORM IV Statement about ownership and other particulars about newspaper OFFSHORE WORLD to be published in the first issue every year after the last day of February 1.

Place of Publication

Mumbai

2.

Periodicity of its Publication

BI-MONTHLY

3.

Printer’s Name Nationality 1[(a) Whether a citizen of India? (b)If foreigner, the country of origin] Address

MAULIK JASUBHAI SHAH INDIAN YES NOT APPLICABLE 1100, Shanudeep, 10, Altamount Road, Mumbai 400 026

4.

Publisher’s Name Nationality 1[(a) Whether a citizen of India? (b)If foreigner, the country of origin] Address

MAULIK JASUBHAI SHAH INDIAN YES NOT APPLICABLE 1100, Shanudeep, 10, Altamount Road, Mumbai 400 026

5.

Editor’s Name Nationality 1[(a) Whether a citizen of India? (b)If foreigner, the country of origin] Address

Ms. MITTRAVINDA RANJAN INDIAN YES NOT APPLICABLE 26, MAKER CHAMBERS VI, NARIMAN POINT, MUMBAI 400 021

6.

Names and Addresses of individuals who own the JASUBHAI MEDIA PVT LTD., newspaper and partners or shareholders holding more 26, MAKER CHAMBERS VI, NARIMAN POINT, MUMBAI 400 021 than one per cent of the total capital Jasu Ramniklal Shah, Maulik Jasubhai Shah, Maulik Business Services Pvt. Ltd, (1100, Shanudeep, 10, Altamount Road, Mumbai 400 026), Jasubhai Business Services P Ltd., (26, Maker Chamber VI, Nariman Point, Mumbai 400 021 I Maulik Jasubhai Shah, hereby declare that the particulars given above are true to the best of my knowledge and belief.

Signature of Publisher Date: 15 February 2014 th

Offshore World | 49 |February-March 2014

www.oswindia.com

products

HEAVY-DUTY ENGINEERING PROFI HOISTS

CONTRAFLAME UNDER DECK

J D Neuhaus launched Profi 75 TI and Profi 100 TI hoists, offering SWL capacities of 75 and 100 tonnes respectively.

Existing products in the Profi range cover lift capacities from 250 kg up to a full 60 tonnes, ideally suited to engineering environments.

The key component of these hoists is a new air motor unit, based on the well-proven J D Neuhaus motorbrake concept and incorporating a patented integrated brake system, with a stepped brake piston and a reliable self-lubricating rotor. In the standard configuration of a 6 bar air pressure supply, the motor provides a 9 kW power output, adequate for the operation of either hoist while still providing significant energy reductions.

At full nominal lift capacities (75 or 100 tonnes), the compressed air consumed is 7.6 m 3 /min which represents in excess of 30% saving over the hoists being replaced. On lowering of full loads, the air consumed is 6 m3/min. The new hoists are designed with machinery group classification according to ISO 4301/FEM 9.5 II is M3/1Bm, which is good for 400 hours full load operation.

The lifting speeds at full load have increased from 0.45 to 0.53 m/ min (Profi 75 TI) and 0.35 to 0.4 m/min (Profi 100 TI). Lifting speeds without a load increase from 0.85 to 1.33 m/min (Profi 75 TI) and from 0.7 to 1.0 m/min (Profi 100 TI). The lowering speeds at full load have also benefited, increasing from 1 to 1.25 m/min (Profi 75 TI) and from 0.8 to 0.95 m/min (Profi 100 TI). An overall weight saving of 750 kg has been achieved for the Profi 75 TI, and 640 kg for the Profi 100 TI. Some reductions in size particularly between the load bearing surfaces of the load and suspension hooks and also in sound levels during operation have also been achieved, with the new hoists registering 77 dB(A) at full load lifting and 83 dB(A) on the lowering operation. Lifting and lowering motor limiters incorporating a pneumatic pin valve design are also available as optional extras for both hoists.

For details contact: J D Neuhaus GmbH & Co KG 58449, Witten-Heven Germany Tel: +49 2302 208-219 Fax: +49 2302 208-286 E-mail: info@jdngroup.com www.oswindia.com

With the growth of offshore platforms operating in extreme environments, the need for under deck insulation systems that can cope with a combination of condensation, ice build-up, extreme heat and high humidity above the cellar deck is becoming paramount. Approved systems are designed to provide a number of operational and safety functions including thermal insulation (with typical U value ranges from 0.3 to 0.5 Wm²K); passive hydrocarbon pool and jet-fire protection per IMO classifications (eg, H60 and J120); blast resistance systems to withstand blast overpressures of 0.2 to 1.2 bar; noise reduction to a typical range of Rw 30 to 51 dB; impact resistance to withstand wave slam and ice build-up; and corrosion under insulation (CUI) longevity to maintain long term integrity and minimise the risk of CUI. To address these handling problems, Advanced Insulation has applied its ContraFlame technology to develop a lightweight under deck system that provides weight savings of up to 60% compared with traditional systems.

The ContraFlame Under Deck Lightweight solutions also provide integrated thermal insulation, passive fire protection, blast resistance and noise reduction in a single certified system. This also takes full advantage of the proven CUI performance of Advanced Insulation’s ContraFlame and ContraTherm products, both in topside and subsea applications.

Advanced Insulation offers three unique ContraFlame systems for under deck protection. ContraFlame JF120 offers fully bonded integral thermal insulation and passive fire protection to J120; H60 blast overpressure to 4.2 bar; and thermal conductivity of 0.054 Wm-¹K-¹. It also offers typical U values 0.57 W/m²K; a system thickness of 90 mm; and weight of 31 kg/m². The ContraFlame MS400 bonded pre-formed panel offers integral thermal insulation and hydrocarbon fire protection to H120 and thermal conductivity of 0.032 Wm-¹K-¹. U values for ContraFlame MS400 are typically 0.229 W/m²K, with a system thickness of 107 mm and weight of just 14.3 kg/m². Finally, its ContraFlame JF120 acoustic bonded pre-formed panels offer integral thermal insulation and jet fire protection to J120 and H60; acoustic noise reduction to Rw 51 dB; and thermal conductivity of 0.054 Wm-¹K-¹. It also offers typical U values of 0.16 W/m²K; a system thickness of 226 mm; and weight of 52.4 kg/m².

For details contact: Advanced Insulation plc Quedgeley West Business Park, Bristol Road, Gloucester, GL2 4PA, U.K. Tel: +44 (0)1452 880880, E-mail: asaf.hisherik@aisplc.com

Offshore World | 50 | February - March 2014

products

ELECTROMAGNETIC FLOW METERS Magnetrol introduces the Polaris electromagnetic flow meter, which is capable of measuring liquids with a conductivity as low as 5 µS/ cm in closed pipes. It is an accurate and repeatable flow meter that is suitable for a variety of water based and sludge flow applications.

The POLARIS transmitter is backlit and rotatable with the capability of measuring forward and reverse flow rates, as well as total volume.

HART protocol allows the use of PACTware for configuration and diagnostics. The sensor can be flanged or wafer style and is available with an assortment of standard liners and electrode materials.

For details contact: Magnetrol International NV Worldwide Level & Flow Solutions Heikensstraat 6 - 9240 Zele - Belgium Tel: +32 (0)52 45 11 11 | Fax: +32 (0)52 45 09 93 E-mail: kgeerinckx@magnetrol.be

MINIFLASH FLASHPOINT TESTER ASTM cleared the way for the new age in flashpoint testing to accept D7094 as a new method for testing diesel, fuel oils and kerosene according to the ASTM specifications D975, D396, D2880 and D3699. The positive impact of the new method on costs, safety and on resolving environmental issues will be impressive.

With the D7094 method, tests are performed through electric discharge in a completely closed cup. No open flame is generated, because the flash point is detected by the pressure increase inside a closed system. The risk of fire and obstructive fumes are eliminated.

D7094 testers are small and portable, making them suitable for use in laboratory or directly in the field.

Grabner Instruments developed the first MINIFLASH flashpoint analyzer. The new flashpoint method was standardized as ASTM D6450 method for 1 mL samples, and as ASTM D7094 method for 2 mL samples. Grabner Instruments MINIFLASH flashpoint testers are used in laboratories around the world for testing liquid or solid samples in the petrochemical, flavour and fragrance, chemical and/or waste industries.

For details contact: Grabner Instruments Messtechnik GmbH (A Member of the AMETEK Oil & Gas Business Unit) Dr Otto Neurathgasse 1, A-1220 Vienna, Austria Tel: +43 1 282 16 27-110 Fax: +43 1 280 73 34 E-mail: sales.grabner-instruments@ametek.at

NON-INTRUSIVE FLOW MEASUREMENT IN HARSH, CORROSIVE ENVIRONMENTS The FLUXUS F705 and G705 ultrasonic liquid and gas clamp-on flow meters allow for an inherently precise bi-directional, highly dynamic flow measurement of volume and mass flow rates of vir tually any gaseous and liquid media – even at wet gas applications (up to a Liquid Volume Fraction of 5%) or liquid media carr ying high contents of solids.

With the transmitter being ATEX, IECEx Zone 2 and FM Class I, Div 2 certified – transducers for ATEX, IECEX Zone 1 and FM Class I, Div 1 are available - it is also the ideal flow meter for hazardous areas.

Moreover, with its stainless steel enclosure (316L / 1.4404) it is highly corrosion-resistant and especially suited for applications Offshore.

For details contact: FLEXIM Instruments Asia Pte Ltd. TT International Tradepark 10 Toh Guan Road #06-01 Singapore 608838 Tel: +65 67 94 53 25 Fax: +65 68 62 28 36 E-mail: salessg@flexim.com

LPG GAS BURNER Veer Appliances Pvt Ltd offers quality range of LPG gas burner precisely manufactured under the strict supervision of skilled professionals following the set industrial norms using latest testing machines and technology to wipe out all possible flaws. Offered product is better known for soft pulsation free start and offers a wide adjustment facility with high constant combustion values.

For details contact: Veer Appliances Pvt Ltd E-221, Sector-63,Noida, Uttar Pradesh 201 304 Tel: 0120-2406431 | Fax: 91-0120-2406431

Offshore World | 51 | February - March 2014

www.oswindia.com

products

OPEN CHANNEL FLOW METERS Nivelco Instruments India Pvt Ltd offers an extensive range of flow measurement open channel flow meters. This range is available in 9 different sizes, compact types of parshall flumes made of plastic (PP), factory calibrated dimensions, reliable measurement with ultrasonic level transmitter and certification of measurement.

For details contact: Nivelco Instruments India Pvt Ltd Malhar, Plot No: 18, S No: 2, Opp: Chandralok Garden Nr Rajaram Bridge, Karve Nagar, Pune, Maharashtra 411 052 Tel: 020-25478313 | Fax: 91-020-25478313 E-mail: india@nivelco.com / snd@nivelco.com / pune@nivelco.com

ULTRASONIC FLOW METERS The Fuji Electric Portaflow C is a next-generation, portable ultrasonic flow meter utilizing transit time technology for the non-invasive measurement of flow rates in pipes. This compact and light weight instrument offers high performance and easy operation. Utilizing the latest electronics and digital signal processing technologies, the Fuji Electric Portaflow C offers high accuracy, quick response time, and outstanding antibubble characteristics. In addition to standard flow measurements, the Portaflow-C is capable of heat quantity measurement allowing simple management for heating and cooling applications.

The Fuji Electric Portaflow-C can be used with various type of detectors applicable for small to large diameter pipe (13 to 6,000 mm/0.5 to 236”) and low to high temperature (-40 to +200 deg C). This flow meter is designed for 12 hours of continuous operation with its own built-in battery which is re-chargeable in 3 hours with the supplied power adapter. An SD memory card allows flow, velocity and total data to be stored for later recall. A universal USB port permits communication with a PC to facilitate configuring the Portaflow-C as well as saving and reading data files. A 4.7 inch colour graphic display creates an easy-to-use operator interface. Some of the most common applications of the Fuji Portaflow-C ultrasonic flow meter include: backup for an already installed flow meter system, water supply and sewage treatment, flow measurement systems, boiler water/feed water supplies, cooling water, cooling oil and de-ionized water for semi-conductor manufacturing, among others.

For details contact: Advanced Microtech Dev Chambers, 2 nd Floor, Nr Vasant Cinema, Cinema Road Surat, Gujarat 395 003 Tel: 0261-2427320, 2411283 | Fax: 91-0261-2411283 E-mail: amtpower@gmail.com / amtpower@aol.in www.oswindia.com

ELECTROMAGNETIC FLOW METERS TKUSHAL-200M are micro-controller based full bore type electromagnetic flow meters specially used for various industrial applications. These flow transmitters accurately measures the flow rate of conductive liquids and slurries in closed pipes. Due to simple and rigid design the flow transmitter is an obstruction less and maintenance free instrument in place of conventional mechanical flow measuring device. The use of ‘Pulsed DC’ technology offers highest ability and better measuring accuracy in the form of electrical signal 4-20 MA DC linearly proportional to volumetric flow. The instrument is based on Faraday’s law of electromagnetic induction. A magnetic field is generated by the instrument in the flow tube. The fluid flowing through this magnetic field generates a voltage that is proportional to the flow velocity. Corresponding electrical output is provided with respect to measuring voltage.

For details contact: Akshat Enterprise No: 7/4539, Shop No: 7, Lakkad Kot Ni Gali Opp: Krishna Cinema Road Nr Torrent Power Delhi Gate, Station Road, Surat, Gujarat 395 003 Tel: 0261-2450859 | Fax: 91-0261-2450859

ULTRASONIC FLOW METERS Backed by enthusiastic workforce, Aman Engg Works are able to put forth a comprehensive array of ultrasonic flow meters.

These flow meters are high in demand owing to their accurate results, dependability, versatility and easy installation. In addition to this, the offered array does not need any pipe insertion and shut down time.

For details contact: Aman Engg Works C-54/55, Focal Point Extension Jalandhar Punjab 144 004 Tel: 0181-2603614, 2603616, 2603615 Fax: 91-0181-2603617, 2292367

Offshore World | 52 | February - March 2014

project update

Media Barter with gulfoilandgas.com

Projects Database Petrochemical Plants and Refineries

Major Projects in the Middle East, Africa and Caspian Sea

Project

Country

Value ($)

Status

Bahrain Deep Gas Exploration Project

Bahrain

-

Execution

NOGA - Awali Onshore Oil Field Development

Bahrain

1,500,000,000

Execution

Dohuk License Area

Iraq

40,000,000

Execution

Qaiyarah & Najmah Contract Areas

Iraq

-

Execution

Tawke Oil Field Development

Iraq

335,000,000

Execution

Zubair Oil Field Development

Iraq

-

Execution

KOC - Wara Pressure Maintenance Project

Kuwait

500,000,000

Execution

New Oil Gathering Centres

Kuwait

1,000,000,000

Bidding

Block 3 & 4 Onshore Oman

Oman

250,000,000

Execution

Block 61 - Khazzan and Makarem Gas Fields Development

Oman

650,000,000

Execution

Offshore Block 50

Oman

-

Execution

Al-Shaheen Offshore Field Development

Qatar

6,000,000,000

Execution

Block A

Qatar

100,000,000

Execution

Dukhan Oil & Gas Field Development

Qatar

-

Execution

Ahmar-1 Field

Saudi Arabia

-

Planning

Al-Khafji Offshore Field Development

Saudi Arabia

1,200,000,000

Execution

Khurais Light Crude Increment Program

Saudi Arabia

3,000,000,000

FEED

Offshore Fields Maintain Potential Programme (MPP)

Saudi Arabia

-

Execution

Dubai's Offshore Oil Fields

UAE

-

Execution

North East Bab Field (NEB)

UAE

-

Bidding

Saleh Offshore Field

UAE

-

Execution

Thammama - F Nitrogen Injection Development

UAE

-

Bidding

Africa

Country

Value ($)

Status

Angola - Block 21

Angola

-

Execution

Cabinda North Block

Angola

24,000,000

Execution

EGPC-lnternational 2013 Bid Round

Egypt

-

Bidding

North El Burg Block

Egypt

66,000,000

Execution

North West Gemsa Concession

Egypt

-

Execution

Rift Valley Block

Ethiopia

-

Execution

Middle East

Offshore World | 53 | February -March 2014

www.oswindia.com

TEN Project

Ghana

4,900,000,000

Execution

Offshore Guinea Concession

Guinea

-

Execution

Blocks CI-506 and CI-507

Ivory Coast

-

Study

Block 2A

Kenya

-

Execution

Block L8

Kenya

-

Execution

BlockLB-15

Liberia

-

Execution

Banda Gas Field

Mauritania

-

Execution

C-10PSC

Mauritania

-

Execution

Mazagan Offshore Permit

Morocco

-

Execution

Sidi Moktar Development Licence

Morocco

-

Execution

Agadem Block

Niger

-

Execution

OML 120 - Oyo Field Development

Nigeria

600,000,000

Execution

OML 56 - Umusadege Field

Nigeria

-

Execution

Tanzania - Block 2

Tanzania

-

Execution

Bir Ben Tartar (BBT) Concession

Tunisia

-

Execution

Block 2 - Ngassa Prospect

Uganda

-

Execution

Caspian Region

Country

Value ($)

Status

Chirag Oil Project (COP)

Azerbaijan

6,000,000,000

Execution

Neft Dashlari Field Development

Azerbaijan

-

Execution

Shah Deniz Stage 1 Development

Azerbaijan

4,000,000,000

Execution

Shah Deniz Stage 2 Development

Azerbaijan

25,000,000,000

Execution

Gonbadli Sweet Gas Field

Iran

-

Bidding

Khangiran Gas Field

Iran

-

Execution

Sardare Jungal Gas Field

Iran

-

Execution

South Pars Phase 12 Development

Iran

7,650,000,000

Execution

Tabnak Gas Field

Iran

16,500,000,000

Bidding

Yadavaran Oilfield Development

Iran

2,000,000,000

Execution

Akkulka Deep Exploration Project

Kazakhstan

-

Execution

Blocks A & E

Kazakhstan

-

Execution

BNG Contract Area

Kazakhstan

100,000,000

Execution

Galaz Contract Area

Kazakhstan

-

Execution

Kashagan Offshore Oil Project

Kazakhstan

136,000,000,000

Execution

Marsel Contract Territory

Kazakhstan

-

Execution

Imilor Oilfield

Russia

1,650,000,000

Study

Muromskij-2 License

Russia

-

Execution

Nine New Blocks - January 2014

Russia

-

Bidding

Palyanovskaya Tight Oil Project

Russia

-

Execution

Sakhalin-3 Kirinsky Block

Russia

-

Execution

Vankor Oil and Gas Field Development

Russia

-

Execution

www.oswindia.com

Offshore World | 54 | February -March 2014

events diary Moscow Refining, Gas & Petrochemicals Week APIC 2014 Date: 15-16 May 2014 Venue: Pattaya Exhibition and Convention Hall (PEACH), Pattaya, Thailand Event: In 1979, the East Asia Petrochemical Industry Conference (EAPIC) was originally founded by the petrochemical associations in East Asia – Japan Petrochemical Industry Association (JPCA), Korea Petrochemical Industry Association (KPIA) and Petrochemical Industry Association of Taiwan (PIAT). Over a period of more than two decades, presidents, chairmen, board directors and senior managers of the leading Asian petrochemical corporations convened to discuss issues confronting the industry. The responsibility to host the annual conference was equally shared by each of the founding association on a rotational basis.

The main objective of the conference is to spur mutual friendship and goodwill amongst the petrochemical industry players in Asia and around the world and thereby contribute to the advancement of the petrochemical industry in Asia.

For details contact: Petrochemical Industry Club, The Federation of Thai Industries (FTIPC) Queen Sirikit National Convention Center Zone D, 2nd Floor, D201/4 – 5 New Rachadapisek Road, Klongtoey, Bangkok 10110 Email: apic2014info.ftipc@gmail.com

Date: 15 - 18 September 2014 Venue: Lotte Hotel, Moscow, Russia Event: The Moscow Refining, Gas and Petrochemicals Week with its traditionally technically-strong programmes, unrivalled access to the major players in the Russian Downstream sector and the highest quality networking opportunities.

The 5 days of intensive networking and engaging presentations will be attended by over 500 attendees with over 80 respected speakers.

The pragmatic event will be a major affair of Heads of Refining, Petrochemicals and Gas Processing from Major Oil Companies, General Directors of Regional Refineries, Petrochemical and Gas Plants, Heads of Technical Departments, Chief Engineers, Chief Technologists, Project Directors, Design Institutes, Engineering Contractors, Technology, Solutions & Equipment Providers, Industry Consultants and Analysts, Government Agencies.

For details contact: Euro Petroleum Consultants 44 Oxford Drive, Bermondsey Street London, SE1 2FB, UK Tel: +44 20 7357 8394 Fax: +44 20 7357 8395 Email: conferences@europetro.com www.europetro.com Offshore Energy Exhibition and Conference 2014

Subsea Asia 2014 Date: 11-13 June 2014 Venue: Kuala Lumpur Convention Centre, Kuala Lumpur, Malaysia Event: Subsea Asia 2014 will take place at the Kuala Lumpur Convention Centre (KLCC) in Malaysia and will be Asia’s 4th SUBSEA Conference and Exhibition. The Subsea Asia Conference, organised by Subsea UK, will take place on 11th June 2014 and the Subsea Asia exhibition will open its doors on the 12th June 2014. The Subsea Asia event is Asia’s most specialised engineering event and an ideal platform to network and to discuss the latest innovations within the subsea industry within Asia, as well as being an opportunity to meet with companies involved in the deepwater oil and gas industry within Asia. Subsea Asia 2012 conference included a local overview from Malaysian NOC, PETRONAS, as well as technical presentations from companies including: First Subsea, Hallin Marine, Nautronix, SMD, Subsea 7 and Welltec.

For details contact: Malaysian Exhibition Services Suite 1401, 14th Floor, Plaza Permata, Jalan Kampar, Off Jalan Tun Razak 50400, Kuala Lumpur Tel: + 603 4041 0311 Fax: + 603 4043 7241 Email: enquiry@mesallworld.com

Date: 28-29 October 2014 Venue: Amsterdam RAI, the Netherlands Event: The 7 th edition of Offshore Energy conference will host between 500 and 600 exhibitors and is expected to attract over 10,000 professionals from all over the world. Both the exhibition and the extensive conference program of Offshore Energy 2014 will address the technical, operational and commercial challenges associated with industry growth.

The 2014 technical program will once again feature an international faculty of speakers covering a broad palette of topics. Meetings range from high caliber panels and technical sessions to annual meetings of industry organizations and masterclasses, catering to professionals from board level to operational level and young talents.

For details contact: NAVINGO BV Westerlaan 1 3016CK Rotterdam The Netherlands Tel: +31 (0)10 2092600 Fax: +31 (0)10 4368134 Email: me@navingo.com

Offshore World | 55 | February - March 2014

www.oswindia.com

book shelf N E W T E C H N O LO G I E S I N T H E O I L A N D G A S I N D U S T R Y Editor: Jorge Salgado Gomes Pages: 226 Publisher: InTech Book Description: Oil and gas are the most important non-renewable energy sources in the global energy mix. In order to successfully exploring, producing and managing these resources in compliance with HSE standards are challenging tasks. New technologies, workflows and procedures have to be implemented.

‘New Technologies in the Oil and Gas Industry’, the insightful book, deals with some of these themes and explains some of the advanced technologies related to the oil and gas industry from HSE to field management issues. New technologies such as for geo-modeling, transient well testing and digital rock physics are also introduced in aiming to researchers, petroleum engineers, geoscientists and people working within the petroleum industry. There are many more technical topics to be addressed in future books.

T E C H N O LO G Y O F O I L A N D G A S W E L L S D R I L L I N G B Y D O W N H O L E D R I L L I N G M O TO R S Author: Mikhail Dvoynikov Publisher: LAP LAMBERT Academic Publishing Paperback: 304 Price: USD 63.90 Book Description: This book is about devices that control, create and regulate weight on bit and methods of operational (automatic) control over drilling using downhole motor as a drillbit drive in the book. It concludes survey results analysis of equipment and technologies that focused on drilling optimization and automatization of directional and horizontal wells deepening. The drill string operation while combination drilling was highlighted briefly. The book represents methods and technique and also results of experimental actual weight on bit evaluation and recommends how to carry out an operational control of axial weight on bit. Also there is an analysis of patent pool in sphere of motor working elements improving. It defines the main engineering directions that increase energy characteristic values of hydraulic motors; provide reliability assurance and consistency of their operation in complicated geological and technical conditions. On the basis of recognized directions the authors present the engineering solutions, the results of these solutions survey and experimental-industrial implementation. www.oswindia.com

RISK GOVERNANCE OF OFFSHORE OIL AND GAS OPERATIONS Editors: Preben Hempel Lindøe, Michael Baram & Ortwin Renn Hardcover: 450 Price: USD 95.98 Publisher: Cambridge University Press Book Description: This book evaluates and compares risk regulation and safety management for offshore oil and gas operations in the United States, United Kingdom, Norway, and Australia.

It provides an interdisciplinary approach with legal, technological, and sociological perspectives on their efforts to assess and prevent major accidents and improve safety performance offshore. Presented in three parts, the volume begins with a review of the technical, legal, behavioral, and sociological factors involved in designing, implementing, and enforcing a regulatory regime for industrial safety. It then evaluates the four regulatory regimes that encompass the cultural, legal, and other contextual factors that influence their design and implementation, along with their reliance on industrial expertise and standards and the use of performance indicators.

The final section presents an assessment of the resilience of the Norwegian regime and its capacity to keep pace with new technologies and emerging risks, respond to near miss incidents, encourage safety culture, incorporate vested rights of labor, and perform inspection and self-audit functions. This book is highly relevant for those in government, business, academia, and elsewhere in civil society who are involved in offshore safety issues, including regulatory authorities and industrial safety professionals.

METALLURGY AND CORROSION CONTROL IN OIL AND GAS PRODUCTION AUTHOR: Robert Heidersbach HARDCOVER: 296 PRICE: USD 88.83 PUBLISHER: Wiley Book Description: This book is intended for engineers and related professionals in the oil and gas production industries. It is intended for use by personnel with limited backgrounds in chemistry, metallurgy, and corrosion and will give them a general understanding of how and why corrosion occurs and the practical approaches to how the effects of corrosion can be mitigated. It is also an asset to the entry-level corrosion control professional who may have a theoretical background in metallurgy, chemistry, or a related field, but who needs to understand the practical limitations of large-scale industrial operations associated with oil and gas production.

While the may use by technicians and others with limited formal technical training, it will be written on a level intended for use by engineers having had some exposure to college-level chemistry and some familiarity with materials and engineering design.

Offshore World | 56 | February - March 2014

RNI No: MAHENG/2003/13269. Date of Publcation: 1’st of every alternate month.

Stainless Steel housed Clamp-On Ultrasonic Flowmeter

FLUXUS® 705 for Liquids and Gases p Highly accurate and reliable bidirectional gas and liquid flow measurement over a wide turndown ratio p Extremly rugged and corrosion resistant stainless steel housing (316L / 1.4404) for the harshest environments - including Offshore (ATEX (IECEx) Zone 2, FM Class I, Div. 2 approved) p Very cost efficient: - No pipe work, - No process shut-down, - Virtually no maintenance p Highly zero point stable, drift free and independent of pipe size, material, line pressure and the medium (NIST traceable calibrated) Oil & Gas exploration and processing I Refineries (up to 400 °C and beyond) Oil & Gas Storage & Transport I Chemical industries

www.flexim.com