December 2013 - January 2014 Vol. 11 No. 1 ` 200
OFFSHORE WORLD
VOL. 11 NO.1
DECEMBER 2013 - JANUARY 2014
Mumbai
` 200
December 2013 - January 2014 Vol. 11 No. 1 ` 200
10 ONGC: India’s Energy Anchor
>>Pg 8
Relinquishment: Exploring Ultimate Recovery >>Pg 20 Intelligent Sand Control in Deepwater >>Pg 24 Momentum Building behind Global Fracking, However Challenges Remain >>Pg 28 Offshore Training: Simulation is the Path Ahead >>Pg 31 Seismic Study: Imaging Reservoir Potential >>Pg 33 Coatings: ‘Uncoating’ Corrosion >>Pg 38 Bending the Costs Downward >>Pg 40
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contents ONGC: INDIA’S ENERGY ANCHOR VOL. 11 NO. 1 DECEMBER 2013 - JANUARY 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
Editor Features Writer Sub Editor Editorial Advisory Board Design Team Events Management Team Subscription Team Production Team
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Consistent Delivery of Performance and Excellence - Sudhir Vasudeva, Chairman & Managing Director, ONGC
8
Striking the Goal of 21 MMTPA by 2021 11 – P P Upadhya, Managing Director, MRPL ONGC Success Story 13
GUEST COLUMN
Relinquishment: Exploring Ultimate Recovery 20 - T N R Rao
FEATURES
Intelligent Sand Control in Deepwater 24 - Ricki Jannise
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MARKETING TEAM & OFFICES
Offshore Training: Simulation is the Path Ahead 31
- Shravan Rewari Seismic Study: Imaging Reservoir Potential 33 - Dr M R Srinivasan Coatings: ‘Uncoating’ Corrosion 38 - Dhirendra Singh
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Bending the Costs Downward 40 - Bert Zorn Energy Commodities Continue to Exhibit Mixed Price Movement 42 - Niteen Jain & Nazir Moulvi
NEWS FEATURE
Transnational Pipeline Diplomacy - Mahesh Radhakrishnan Breaking Barriers of Traditional Plant Modelling - Mittravinda Ranjan Development of LNG infrastructure is critical for economy growth’ - Mittravinda Ranjan Iranian LNG Export Outline - Hedayat Omidvar Demand of Oil & Gas for 12 th & 13th Plan - Rakesh Roy
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Offshore World | 6 | December 2013 - January 2014
Offshore World | 7 | December 2013 - January 2014
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Consistent Delivery of Performance and Excellence
Oil and Natural Gas Corporation Limited (ONGC) - World’s No. 3 exploration & production company (Platts 2013) - under the leadership of its Chairman and Managing Director Sudhir Vasudeva has undergone a sea change and witnessed radical changes, giving boost to hydrocarbon landscape of the country. While going down the memory lane, he says that there have been countless moments of highs and lows through his eventful journey. For him, as a production engineer, completing a large offshore project or even witnessing any well starting production of oil has always been the ultimate professional kick. Acquiring MRPL in 2003 or receiving the first parcel of Sudanese crude are some of the special moments in his career. How does it feel joining as a trainee and becoming as the CMD of India’s largest oil & gas company? It has been indeed a most wonderful and fulfilling journey. For a small town boy with simple dreams of doing something meaningful in life, the last 36-37 years have been an exceedingly rewarding experience that has far exceeded my expectations to the point that all I feel now is a sense of immense satisfaction for not just having been a part of but also been accorded the chance to lead one of the most prestigious companies of the country, that is ONGC. www.oswindia.com
Having joined ONGC as a hopeful but fallow young boy in his 20s in 1976, I have grown right here – as a person and as a professional. My time with ONGC and the industry continues to be an almost inexhaustible well-head of achievements, accomplishments, pride, satisfaction, challenges, knowledge, relationships and much more. You have been a part of ONGC’s journey and witnessed the organisation transform from E&P Company to a diversified oil & gas company. Tell us about the high & low points of ONGC during your tenure with the organisation. Offshore World | 8 | December 2013 - January 2014
It is an exceedingly enriching journey through the prism of which not only have I witnessed the transformation and manifold growth of ONGC, but also witnessed the dramatic evolution of the entire oil & gas industry of the country. The industry had undergone radical changes during the timeframe particularly after the liberalisation and globalisation of early 90s. Within the country, the demand for energy has galloped. What used to be an exclusive space for public sector players, the oil & gas industry and the whole gamut of energy industry is now open for
‘’Reaching the top slot is difficult which only comes with the constant great efforts over the years. However, holding back to the top position is even more difficult, particularly in view of the fiercely growing competition in the industry.”
participation from private players as well making things more interesting and competitive in the pursuit of energy security of the country. There have been countless moments of highs and lows through this eventful journey. For me, as a production engineer, completing a large offshore project or even witnessing any well starting production of oil has always been the ultimate professional kick. Acquiring MRPL in 2003 or receiving the first parcel of Sudanese crude are also some of the special moments with which I was privileged to be associated with. Acquisition of each one of the assets of OVL has been glorious moment of success for the organisation. Recent acquisition of assets in Azerbaijan and Mozambique are among the top few ‘highs’ of my professional life. Talking about ‘lows’, the devastating Helicopter accident or the BHN fire accident are the most depressing times in my professional career. ONGC has been recognised as the fourth largest Indian company under your leadership. How did you steer the growth of ONGC as the Chairman & Managing Director? ONGC is not only one of the top four companies in Indian bourses, but it is also one of the top
three E&P companies in the world. Therefore, it is certainly a great privilege to have led a large, diverse and complex company like ONGC. Reaching the top slot is difficult which only comes with the constant great efforts over the years. However, holding back to the top position is even more difficult, particularly in view of the fiercely growing competition in the industry. Though you are enabled with the dedication of the best geoscientists and professionals in the country having inherited the expertise accrued over five and half decades of the organisation, the shrinking talent pool on account of huge attrition arising from superannuation as well as resignation for greener pastures that has arisen after the liberalisation and advent of private sector in this industry is a potential threat. As a leader of such a great company, it needs a lot of engagement with the employees, setting smart and realistic targets for them challenging their professional acumen, supporting them with the requisite technologies and managerial issues, negotiating with myriad stakeholders for their varied interests and expectations and finally envisioning a growth for the company couple of years down the line. In totality, it is an exhilarating experience. Offshore World | 9 | December 2013 - January 2014
Industry recognises you for your devotion towards development of offshore fields - a very high risk area where you successfully executed projects worth ` 60,000 crore. Tell us more about that. Part of this, I have just shared with you, delineating on our early days endeavours developing Mumbai High and other fields and infrastructures in western offshore. With recovery factor still hovering below 35 per cent and field of similar vintage in Gulf of Mexico and North Sea boasting the same around 45-50 per cent, we have still a huge potential left in our matured fields. And for that through our redevelopment and rolling redevelopments plans, we are pursuing a number of projects to improve recovery as well as to arrest the natural decline. 24 such IOR & EOR projects have been planned with a total investment of over ` 41,000 crore, 17 of which have already been completed. This is expected to give us an incremental cumulative production of 170 MMT of oil. We are also having a number of projects developing and monetising small and new marginal fields. Through cluster approach, we are in the process of monetising 37 fields with over 280 MTOE of reserves www.oswindia.com
benefit analysis. My endeavour has always been to maximise recovery from these fields to the order of 40 per cent or so by 2020 from the current level of about 32 per cent of recovery factor. through 13 projects with an investment of around ` 33,000 crore. This is expected to give us an incremental cumulative production of 40 MMT of oil and 64 BCM of gas. We are also pursuing a number of projects at realise production from deepwater of east coast as well as west coast of India. We have just commenced production from G-1 & GS-15 fields and as per the plan, we are expecting commencement of production from G-4 field (which is planned to be developed along with discoveries in the Northern Discovery Area of KG-DWN-98/2) by 2017, production from integrated development of Vasistha & S1 fields in KG deepwaters by 2015 and also from KG-DWN 98/2 by early 2017, appraisal of which is just about to complete. Thus, while your hands are full with so much of responsibilities worth thousands of crores of rupees with immense opportunity of producing energy for the country, devotion comes flowing automatically. ONGC has written many success stories during your tenure as Director Offshore & more after you resumed the position of the CMD – which achievement is closest to your heart (and why)? Obviously, this journey is full of highs and lows and many a successful stories are there to tell. Simply confining those success stories to my regime or my tenure will be like denying justice or credit to the previous leaderships and to the collective endeavours of the workforce over these years.
Discovery of upside potential of D-1 field is another example of the conviction of my team. While doing the developmental drilling, our venturing into the unchartered area resulted in discovering a huge 142 meter of oil bearing zone taking the total In-place volume to about 140 MTOE, making it the third largest field in the western offshore. By June 2014, we will be producing around 60,000 BOPD from the current level of 12,500 BOPD. Another great decision for which I can draw pride is the use of “Float-Over” technology. First time in the history of ONGC, two topsides – AP Deck weighing 7,800 MT & AQ Deck weighing 13,500 MT – of Process Platform under B-193 cluster project development got installed in Dec’12 by float over method. This demonstrated our project execution competency and strong appetite for risk for financial prudence. There are many more and mentioning all of them in this space would not be possible. However, one thing I must mention that each and all of them could not have happened without a robust team work, which is the hallmark of success in ONGC. And one of my greatest achievements has been fostering a great team wherever I have been posted to. How would you like to see your legacy at ONGC being carried forward? What are your plans for future? Carrying forward a legacy depends on both the elements; the strength of the legacy itself as well as its acceptance to the next generations. But as this industry is very dynamic, nothing is sacrosanct or nothing should be taken for granted. Rather, legacy should always be enriched with the need of the time and space.
Nonetheless, let me mention few achievements in which my direct and indirect intervention through close association mattered and which make me really proud of. “Rolling redevelopment” of Mumbai ONGC is a great company. Its legacy has not been High and Heera & Neelam fields are among such created at any particular point of time, but over five achievements. Having convinced that a lot of oil is and half decades of tireless dedication and services still left out in these offshore fields, I harped upon the by countless employees. I am fortunate to be one second phase of redevelopment of Mumbai High field. of them to serve the country through this Subsequently, the third phase of redevelopment is company, albeit with the privilege of being its also under active consideration with all the due cost- 20 th Chairman & Managing Director. At the top, you www.oswindia.com
Offshore World | 10 | December 2013 - January 2014
provide leadership; and at the end of the day, it is satisfying if your leadership fetches some more improvement, and add value to the legacy of your organisation. I, with my team in the company, have drawn a road map called Perspective Plan 2030 through which an ambitious plan for the company has been drawn. We aspire to double our production volumes, and in the process, making India more comfortable as far as its energy security is concerned. Perspective Plan 2030 intends to have two-fold production growth of the group of company, which includes six fold growth in sourcing equity oil & gas through ONGC Videsh Ltd (OVL). In the process, the plan also holds out the targets of three-fold growth in revenue & EBITDA and four fold growth in market capitalisation. In terms of absolute numbers, ‘PP – 2030’ entails an annual production of 130 MTOE with 60 MTOE from overseas in 2030. It also entails generation of over 6.5 GW of power from various renewable sources including nuclear, solar and wind; creating additional 9 MMPTA of LNG capacity; scaling up refining capacity to 21 MMPTA . And all these targets need an investment of the order of ` 11 lakh crore. This grandiose plan has been drawn by a team comprised of a thoughtful mix of senior and young officers, especially some selected few who would be serving the company till 2030 and beyond. Therefore, I am quite hopeful that the legacy etched out during my tenure will be carried forward with adequate zeal for a brighter future in the years to come. What is your message to the Indian hydrocarbon industry? In the context of the current scenario and the future energy world that is unfolding, my message would be simple – ‘Consistent delivery of Performance’ and ‘Excellence’ will define our future. I know the road ahead looks challenging, but considering our long history of proven abilities and excellence, and counting the demographic dividend of the country, I am sure Indian hydrocarbon industry is quite capable of placing India among the foremost countries in the global energy spectrum. sw
Striking the Goal of 21 MMTPA Capacity by 2021 MRPL, a subsidiary of ONGC, is a state-of-the-art grassroots refinery located in Mangalore. The refinery has got a versatile design with high flexibility to process crudes of various API and with high degree of automation. P P Upadhya, Managing Director, Mangalore Refinery and Petrochemicals Limited (MRPL), talks to Offshore World about the refinery’s expansion plans, its profit margins and many more. Excerpts:
Please apprise us the capacity MRPL is utilising at the moment and the sources of crude?
the capacity expansion and commissioning activity of MRPL?
MRPL’s name plate capacity today is 15 MMTPA. MRPL will be utilising near to 100 per cent of its capacity in the financial year 2013-14. MRPL capacity will be ramped up after stabilisation of secondary processing units of the new expansion project. MRPL sources its crude mainly from Middle East viz Iran, Saudi Arabia, Kuwait, UAE, West African countries and is looking forward to source crudes from Latin American countries in future, once secondary units are fully stabilised.
MRPL has taken up huge expansion plans at the cost of around `15,000 Cr which include:
MRPL Phase III Expansion, which is nearing completion except poly propylene unit. Can you share the detailed approach in order to enhance
P P Upadhya, MD, MRPL www.oswindia.com
• Phase-III Expansion and Upgradation Project (Cost: ` 12,160 Cr): With the commissioning of Phase-III crude unit MRPL’s refining capacity has enhanced to 15 MMTPA on 25 th March 2012. Diesel Hydrotreater and Hydrogen units are in operation. Balance units viz Sulphur Recovery Unit, Petro FCC, Delayed Coker, Coker Hydrotreating Units will be commissioned within next two months. Commissioning has got delayed due to the non availability of steam and power
>> MRPL sources its crude mainly from Middle East viz Iran, Saudi Arabia, Kuwait, UAE, West African countries and is looking forward to source crudes from Latin American countries in future, once secondary units are fully stabilised. Offshore World | 11 | December 2013 - January 2014
>> MRPL has drawn plans to augment its refining capacity to 18 MMTPA by 2018-19 and 21 MMTPA by 2021. MRPL is also looking to set up a Linear Alkyl Benzene plant with feed streams available from the refinery and OMPL (ONGC Mangalore Petrochemicals Ltd producing Para Xylene and Benzene using the feed stocks from MRPL).
PRODUCTS
2011-12 in MMT
2012-13 in MMT
PRODUCTION
NEW PRODUCT MIX in MMT PRODUCTION LPG
0.40
LPG
0.28
0.28
POLYPROPYLENE
0.44
MS
1.01
1.10
MS
1.10
MIXED XYLENE
0.15
0.15
MIXED XYLENE
0.26
NAPHTHA
1.14
1.48
NAPHTHA
1.32
SKO
0.32
0.41
SKO
0.24
HSD
5.18
5.57
ATF
2.05
ATF
1.19
1.45
HSD
5.57
FO
2.19
2.11
FO
1.25
VGO
0.08
0.05
COKE
0.75
ASPHALT
0.24
0.19
ASPHALT
0.19
CRMB
0.04
0.02
CRMB
0.02
SULPHUR
0.065
0.05
SULPHUR
0.14
from captive power plant being built by BHEL. • Poly Propylene Project (Cost: ` 1800 Cr) has achieved physical progress of 92.7 per cent as on 15 th December 2013. The unit is expected to be mechanically completed by March 2014 and will be fully on stream by July 2014. • Single Point Mooring: The refinery has set-up a Single Point Mooring (SPM) facility off the Mangalore coast at a cost of about ` 1044 Cr SPM enables MRPL to ship crude using Very Large Crude Carrier (VLCC), to source opportunity crudes from West African and Latin American countries. SPM was commissioned successfully on 29 th August 2013 and is fully operational. However, due to non availability of crude cavern for storage of crudes, only Suez Max vessels are loaded at present. MRPL has drawn plans to augment its refining capacity to 18 MMTPA by 2018-19 and 21 MMTPA by 2021. MRPL is also looking to set up a Linear
Alkyl Benzene plant with feed streams available from the refinery and OMPL (ONGC Mangalore Petrochemicals Ltd producing Para Xylene and Benzene using the feed stocks from MRPL). Amid high volatility in the crude prices and substantial rupee depreciation against the dollar, MRPL is able to register the highestever gross revenue of ` 68,834 cr in fiscal 2012-13, 19 per cent higher than previous year. How has MRPL been sustained the multi-pronged growth strategy? The revenue of the refinery is based on the crude and product prices prevailing in the international markets where refineries do not have any control. The higher revenue in the year 2012-13 was mainly on the account of increased processing crude rate viz 14.4 MMTPA vis-à-vis 12.82 MMTPA in FY 2011-12 and as well as increase in the international prices of petroleum products .
world powers will impact the long-standing payment crisis for Indian oil companies for Iran crude, Indian energy insurance pool for covering refineries’ risk and Brent crude price? MRPL Refinery has been processing Iran mix from the inception. Though MRPL has processed several grades of crude, Iran mix crude is proven to be more suitable considering the design configuration and product mix. Once phase -III units are fully on-stream MRPL has the advantage to process other opportunity crude.
As the biggest buyer of Iran Crude, how is MRPL looking into the recent Iran’s truce with
Due to sanctions, MRPL reduced only its imports from Iran and future plans depend on how the things shape up with recent relaxation in place. MRPL is paying 45 per cent of its payment in Rupees and balance payment will be made once the payment channels are made operational. MRPL is following regularly with MOP&NG and GOI with respect to creation of the Energy Insurance Pool. sw
Offshore World | 12 | December 2013 - January 2014
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ONGC has been billed as one of the best brownfield managers in the world petroleum industry, for managing the production from its old oilfields appreciably well, says Sudhir Vasudeva, CMD, ONGC
ONGC’s Consistent Performance ONGC’s consistent production profile during last few years has been driven by technological interventions on its ageing fields. The company has taken tailored projects to improve oil recovery that has helped it to maintain production from its oil-fields, which are of 30-40 years vintage. If one looks at the last five years, the hydrocarbon conglomerate’s production is stagnant at 52-53 million tonnes of oil and oil equivalent gas from India and if ONGC adds overseas production of ONGC Videsh Limited (OVL) also then it comes to around 60 million tonnes. If it is stagnant at this level, it is only because of its aggressive efforts. Had ONGC not taken these efforts, domestic production would have gone down by at least 8 million metric tonnes (MMT), which is the normal decline from such old fields globally. ONGC’s technological interventions like Increased Oil Recovery (IOR) and Enhanced Oil Recovery (EOR) efforts are giving it 8 MMT of additional oil. Its capex expenditure for these interventions is valued at around ` 41,000 crore. Out of this, ` 35,000
crore has already been spent. There are 24 schemes; 16 schemes have already been completed as it has started these back in 2000-01. Eight schemes are continuing. They have so far given the company 80 MMT and cumulatively, it expects 172 MMT would arrive from these oil-fields by 2030.
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Offshore World | 13 | December 2013 - January 2014
Today, ONGC is producing from more than 110 fields but nearly 71 per cent of its production is coming from 15 major oil fields like Mumbai High, Neelam, Heera, Navagam, Geleki, Rudrasagar, Ankleshwar, Gandhar,etc. Among these fields, Mumbai High is the youngest - 37 years old, while Rudrasagar and Ankleshwar were the first ones that the company discovered and started production 52 years earlier. It is very challenging to maintain the production from these old fields at same level at which they were started. Frontier in Shale Gas Exploration in India ONGC’s journey in Shale gas has gathered further momentum with the announcement of
Shale Gas Policy by the Goverment of India in November, 2013. As per this policy, ONGC and OIL are to explore and exploit shale resources in 176 identified on-land areas where these two companies are already engaged in either exploration or production of conventional oil and gas. ONGC has already drilled its first exploratory shale gas well in Cambay Basin area immediately after the new policy announcement. ONGC has plan of drilling 30 more wells in the next two years with an investment of about ` 600 Crore. ONGC is quite hopeful to usher in a new era of energy for the country. Plans for Foraying into Retail ONGC has licenses for 1600 retail outlets between the company and its subsidiary MRPL. It had started and today it has outlets operating in Mangalore. But when it started, the issues of all this subsidy mechanism, regulated price for diesel and gas erupted, so it had put retail business on the backburner.
Scripting Success Story ◆ Approx. ` 41,000 crore capex expenditure for EOR & IOR interventions ◆ Production from more than 110 fields ◆ Nearly 71 per cent of production from 15 major oil fields like Mumbai High, Neelam, Heera, Navagam, Geleki, Rudrasagar, Ankleshwar, Gandhar,etc. ◆ Stagnant production since last five years at 52-53 million tonnes ◆ JV with ConocoPhillips for shale gas development ◆ Plans to augment capacity of MRPL to 21MMT in 13 five year plan th
◆ MoU with Chambal Fertilisers & Chemicals Ltd. (CFCL) and Tripura Government for urea fertiliser project in the state ◆ Production target of 24.08 MMT of crude oil for the financial year 2013-14 ◆ Working with Chinese companies in various overseas projects like Sudan ◆ Budget of ` 400 crore plus for CSR every year Today, the company has a refinery in Mangalore with 15 MMT capacity and ONGC has plans to make it 18 MMT during 12 th five year plan; it will take it to 21MMT in 13 th five year plan. India’s energy anchor is also looking into Rajasthan refinery where HPCL has taken a majority stake. In Nagarjuna refinery in Kandalur, ONGC is doing the due diligence. So, ONGC is consistently increasing its refining foot-prints and with that, it wants to be in the marketing of the refined products as well. With license of 1600 outlets, as and when the diesel is fully de-regulated, it wants to be in retail business. ONGC doesn’t have experience in retail and marketing and even MRPL has a limited experience. Hence, the company will see if it wants to float a separate company for retail; ONGC is studying that various dimensions of that.
stranded in the area due to poor industrial and evacuation avenues there. ONGC’s gas-based power project at Palatana in Tripura, the largest investment in north-east India, was the first project for monetisation of the stranded gas. Expected Growth for Current Financial Year During the current financial year 2013-14, ONGC has production target of 24.08 MMT of crude oil (standalone), 6.75 per cent higher than the last year’s actual of 22.56 MMT. This year ONGC doesn’t expect much growth in gas production, which may be of the same level as the last fiscal and its target is 23.44 Billion Cubic Metres (BCM). However,
with the development of ONGC’s new fields, gas production is expected to increase from 2014-15 onwards. The capex plan for the year 2013-14 is around ` 35,049 crore compared to actual utilisation of ` 29,508 crore in 2012-13. Out of this, ONGC will be investing 30 per cent for survey and exploratory exploration drilling; 23 per cent for development drilling; 42 per cent on capital projects and purchases and balance 5 per cent on research & development, domestic joint ventures and integration projects. Impact of Rupee Depreciation Depreciation of Rupee has a mixed impact on ONGC’s financials. The positive side is that its gross realisable price for crude oil and gas increases. It has negative impact as well. ONGC’s cost of oil-field services or import of equipment increases. However, the biggest issue is that in case the existing underrecovery mechanism continues, subsidy burden may increase. As after the Government of India, ONGC bears maximum subsidy, ONGC’s net realisation on crude sales will be affected. Overseas Assets Acquisition Diplomacy plays a very crucial role in acquiring energy assets worldwide. Instead of competition,
Diversifying Business ONGC is integrating energy value chain to strengthen its balance sheet, which is required for its core business of oil & gas exploration and production. To monetize its natural gas reserves in Khubal area in north Tripura, ONGC has entered into a Memorandum of Understanding (MoU) with Chambal Fertilisers and Chemicals Ltd (CFCL) and the Government of Tripura for setting up a urea fertiliser project in the state. Unless it monetises its gas reserves there, these would be Offshore World | 14 | December 2013 - January 2014
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If anybody has any doubt on PSU capability, then I can only say bring competition. Just to give you example today in oil industry in India, all those who are heading the private oil companies are basically groomed in the business by ONGC. - Sudhir Vasudeva, CMD, ONGC
collaboration may be a more effective option in the current global energy dynamics. ONGC is working with Chinese companies in various overseas projects like Sudan. ONGC is better to leverage the positive aspects of Chinese strengths for its benefit.
supporting artisans, preserving heritage monuments, sports promotion. In sports, ONGC has more than 100 active sports-persons and over 200 are on scholarships. Last year, ONGC was the principal sponsor of Indian contingent for the London Olympics. ONGC is also opening sports academy in Dehradun at a capital investment of ` 50 crore and investing another ` 20 crore in Tripura to build a stadium. The company is also contemplating opening an archery training academy in Jharkhand or Kolkata and opening another indoor academy in Bastar in Chhattisgarh. Maintaining Taj Mahal was ONGC’s idea and finally the Minister of Tourism Chiranjeevi has now agreed upon that. Even if the project is valued over ` 100 crore, ONGC has pride in maintaining the iconic heritage monuments of this great country.
CSR Activities The kind of work public enterprises companies are doing usually goes unsung. ONGC has been into community development even before the CSR term was coined. With a profit of over ` 20,000 crore, ONGC has a budget of ` 400 crore plus for CSR every year. Many state governments do not have that kind of budget for philanthropy. ONGC started in early 2000 when the company committed 0.75 per cent and brought it up to 2 per cent. Even today when the statutory range is between 0.5-2 per cent, ONGC has voluntarily stuck to 2 per cent of the Profit-After-Tax (PAT). Today, ONGC has 12 verticals under CSR, where it has decided to invest in a projectised format. These include education, healthcare, women empowerment, entrepreneurship development,
Performance of Public Enterprise as a Whole The fundamental strength of any organisation is tested in challenging times. In the difficult times, it is the public enterprises that have sustained investments for vital economic sectors
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Offshore World | 15 | December 2013 - January 2014
in last few recessions. Today, 22 per cent of the market cap of BSE is represented by public enterprises. And this is notwithstanding the fact that full value of public enterprise scrips are yet to be fully unlocked. As a Maharatna public enterprise, ONGC has been on top of value creation indices. Sudhir Vasudeva, CMD, ONGC takes pride in articulating that we have to understand that the private company promoters are also playing on the public money while we are more accountable for the public money we are dealing with. For PSUs, I can only say that today we have a lot of constraints within which we are expected to perform and compete with private enterprises, which are relatively much less accountable. If anybody has any doubt on PSU capability, then I can only say bring competition. Just to give you example today in oil industry in India, all those who are heading the private oil companies are basically groomed in the business by ONGC. So, we can justifiably say that ONGC is sw India’s Energy
ONGC is the largest integrated petroleum company in India, operating along the entire hydrocarbon value chain. It has single-handedly scripted India’s hydrocarbon success saga. The most valuable National Oil Company ONGC is the highest profit-making and highest dividend-paying enterprise. Truly, this Maharatna is the brightest jewel in the crown.
A Maharatna - The pride of India In 1956, ONGC had a dream, as it embarked on an uncommon journey. Today, that vision has become an unstoppable force. It’s a force you may not physically see, but one that you can feel in ever y waking moment, as it energises the lives of more than a billion Indians. A force that is ONGC. In 1974, ONGC proudly marked India’s place in the global energy arena with the discovery of the colossal Bombay High Oil Field in the Arabian Sea. Since then, there has been no looking back, and ONGC has gone ahead from strength to strength. A globally acclaimed energy major today, ONGC was the first Indian corporate to be listed in the Fortune 500 ‘Most Admired Companies’ and also the World’s Number 3 Exploration & Production Company (Platts 2013).
paying enterprise. In other words, it is really a true Maharatna. Expanding Horizons While ONGC’s relentless pursuit for new oil and gas reserves continues in India, ONGC’s wholly owned subsidiary ONGC Videsh Limited (OVL) is in overdrive with ambitious plans to spot and acquire oil and gas opportunities overseas. For a decade now, OVL has strengthened its hydrocarbon foothold in diverse geologies
with a balanced portfolio spread over 17 nations in four continents. 36 hydrocarbon properties with 11 producing assets across the globe worth USD 15 billion have established OVL’s supremacy as India’s biggest energy multinational. Harnessing Po w e r of Value Chain Integration ONGC has taken strategic steps towards value chain integration and reaped the dividends.
Six out of the seven producing basins have been discovered by ONGC, making it the largest producer of oil and gas in the country, creating the highest value for its owners over a billion Indians. With a market value of 2.5 trillion rupees, not only it is the most valuable National Oil Company, but also India’s highest profit-making and highest dividendOffshore World | 16 | December 2013 - January 2014
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Moving Ahead ◆ Discovered Bombay High oil Field in 1974 Pursuing the globally-established integrated business model of the petroleum industry, ONGC took up equity in the ailing Mangalore Refinery & Petrochemicals Limited and created a transformation that resulted in the first vertically integrated oil enterprise with global reach. While a 726.6 MW gas based power plant set up at Palatana, Tripura by ONGC Tripura Power Company was dedicated to nation recently by the President of India, C2-C3, OPaL and Mangalore SEZ projects are also proceeding towards maturity. Moving ahead, ONGC has entered into LNG, petrochemicals, power to mark ONGC’s presence in the entire hydrocarbon value-chain. New Frontiers As ONGC looks for new answers beyond the conventional for an energy-hungry world, ONGC is aggressively pursuing technology-intensive solutions to leverage the potential of new sources like Coal Bed Methane, Underground Coal Gasification and Shale Gas. After a successful commissioning of a 50 MW wind farm in Gujarat, ONGC is setting up another 102 MW wind farm in Rajasthan. Under the aegis of the ONGC Energy Centre, ONGC is also pursuing energy sources through
◆ The first Indian corporate to be listed in the Fortune 500 ‘Most Admired Companies’ and also the World’s No 3 E&P co (Platts 2013) ◆ The largest producer of oil and gas in the country ◆ India’s highest profit-making & highest dividend-paying enterprise with a market value of ` 2.5 trillion ◆ OVL has presence in over 17 nations in four continents & 36 hydrocarbon properties with 11 producing assets across the globe worth USD 15 bn ◆ Pursuing energy sources through solar thermal, uranium, hydrogen through thermo-chemical processes, geothermal power, kinetic hydropower solar thermal, uranium, hydrogen through thermochemical processes, geothermal power, kinetic hydropower, etc. Towards National Energy SecurityPerspective Plan 2030 Under the Perspective Plan 2030, ONGC plans to achieve: ◆ Two-fold increase in oil and oil equivalent gas production ◆ Three - fold revenue growth (and EBITDA) ◆ Four - fold increase in market capitalisation ◆ Five shaping moves ◆ Six times international growth
ONGC Tripura Power Company’s 726.6 MW power Plant at Palatana: One of the largest CDM projects in the world. www.oswindia.com
Offshore World | 17 | December 2013 - January 2014
Business Sustainability Growth with sustainability is the driving philosophy for ONGC. This finds expression in its commitment to continually enhance the triple bottom line benchmarks of economic, environmental and social performance. ONGC has 11 registered ‘Clean Development Mechanism’ projects, a unique feat among Central Public Enterprises, which would fetch well over 1.8 million Certified Emission Reductions (CERs) in a year, for ten years. Two more CDM projects are under registration, which will significantly add to the portfolio of carbon credits, thus enhancing the sustainability approaches of ONGC carries towards the society. At ONGC, sustainable growth drives not just business decisions but Corporate Social Responsibility (CSR) initiatives as well. ONGC’s efforts are primarily focused on the protection of environment providing infrastructure support in operational areas, water management, women’s empowerment, initiatives for physically and mentally challenged people, protection and preservation of our heritage, arts and culture, promotion of sports, entrepreneurship building and sponsorship of seminars, conferences, workshops, events, etc. ONGC also extends support to India’s sportspersons to encourage sportsmanship in the country, and is proud to have on its rolls over 200 sportspersons including 15 Arjuna Awardees, one Khel Ratna and two Padmashrees. sw
Offshore World | 1 | OCTOBER - NOVEMBER 2013
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guest column
Relinquishment: Exploring Ultimate Recovery R e l i n q u i s h m e nt o f a re a s f ro m o i l / g a s f i e l d s contrac ted to investors under the produc tion sharing scheme is in the news lately, for really very wrong reasons. The Production Sharing Contract (PSC) initially delineates large areas for the contract, on the basis of indications of hydrocarbons on available scanty data. The whole exploratory and drilling phases of the PSC are meant to zero in on areas most likely to contain commercially exploitable reserves. These two phases narrow down the areas for profitable development and consequently the areas not so profitable should cease to be of interest to the contractor. But for the Govt as a resource owner, these areas continue to be of interest, as it is quite possible for another risk taker to explore fur ther again for oil/gas. To make such areas viable, they are added to contiguous areas and offered again for bids. The sooner such exercises are done, the better for the countr y, as they get subjec ted to repeated scrutiny for possible reser ves and quicker exploitation.
T N R Rao Former Petroleum Secretary MoPNG
Though India has zeroed the 10 th round of NELP through a revenue sharing regime, the fate of blocks relinquished during the last nine rounds of NELP is still under cloud. Our Guest Columnist
T N R Rao, Former Petroleum S e c r e t a r y, b e l i e v e s u n l e s s
maximising the ultimate recovery is made a bid condition, introduction of revenue sharing in the PSCs would be short-sighted and would result in loss of precious resources of the nation.
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Why Relinquished? Contractor has to obtain a Petroleum Exploration License (PEL) for the areas he decides to explore. After such exploration and explorator y drilling within the period allowed for such ac tivities under the PSC, he should decide on the area for development. He should then apply for a Petroleum Mining License (PML) for the area required for development and production only. On the expiry of the PEL for the area covered for exploration, the balance of the area other than covered by PML stands relinquished. Even within the PMLs, the areas specifically of fields for
which development plans have been approved, should only be retained and the rest should be relinquished. What PSC Says on Relinquished Blocks Th e P S C h a s t h e re f o re p rov i s i o n s t h at m a ke it mandator y for the contrac tor to decide on the areas he wants to retain for commercial exploitation and give up areas not so required. These are non-negotiable clauses of the PSC a n d a n y c o n t r a c to r s i g n ato r y to t h e P S C i s bound to honour this and quit the areas not subjected to commercial exploitation by him, to enable the Govt as owner to arrange in getting t h e v a c a t e d a re a s f o r f u r t h e r e x p l o r a t i o n . These areas, together with possible contiguous a re a s w i l l b e a u c t i o n e d a g a i n a n d n o t h i n g prevents the earlier contractor from bidding for it again. Looking Ahead The time limits laid down for each phase of work, quantum of work and work programme, mandatory relinquishment of areas not covered by development plans are very significant for a country like India, heavily dependent on imports of energy resources. With a burgeoning demand for energy, India cannot afford to be complacent in its oil/gas development plans and brook delays. It should be remembered that Indian basins are under explored and poorly drilled. Our drilling intensity, that is, number of wells drilled per unit area is one of the lowest in the world. Not withstanding the progress in technology, the only way to say definitely that hydrocarbons exist is only by ac tually digging a well and taking it out. The sooner we bring more and more areas under development, the better it is for the country.
>>With a burgeoning demand for energy, India cannot afford to be complacent in its oil/gas development plans and brook delays. It should be remembered that Indian basins are under explored and poorly drilled. Our drilling intensity, that is, number of wells drilled per unit area is one of the lowest in the world. Offshore World | 20 | December 2013 - January 2014
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Offshore World | 21 | December 2013 - January 2014
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guest column
NELP I
NELP II
NELP III
NELP IV NELP V
NELP VI NELP VII
NELP VIII NELP IX
No. of Blocks Offered
48
25
27
24
20
55
57
70
34
No. of Blocks Bid for
28
23
24
21
20
52
45
36
33
No. of PSCs Signed
24
23
23
20
20
52
41
32
19
No. of Blocks Relinquished
24
2
4
4
0
3
16
38
15
Source : Ministry of Petroleum & Natural Gas, GoI
It is in the above context that it is necessary that areas are not allowed to remain unexplored and undrilled far too long. The time limits for relinquishments should be strictly enforced. That alone will not solve the problem. Additional data, gathered if any during the earlier PSC should be suitably added on a real time basis and should be available to the bidders in the next round. This cycle of operations should be speeded up for quicker exploitation of our resources. Blocks Status (Last Nine NELP) Total Blocks Awarded 254
Active Blocks 148
Relinquished Blocks 106
Source : Ministry of Petroleum & Natural Gas, GoI
In fact re-auctioning areas not required for development benefit both the Govt and the contractor as the new PSC will give them a fresh lease of 7 yrs for exploration and another 20 to 25 years for development and production. It is a win-win for both. It is thus clear that delay in enforcing relinquishments is against public interest. Contractors should not be allowed to squat on their contract areas on one pretex t or the other. The PSC clauses are ver y clear and s h o u l d b e m a d e m o re c l e a r w h e re ve r n e ce s s a r y to e n f o rce s t r i c t ly the time limit for relinquishment. Ex tensions if any, should be rare and exceptional and never routine. Even time limits for declaration o f c o m m e rc i a l i t y, s u b m i s s i o n o f d e v e l o p m e n t p l a n s , e t c s h o u l d be enforced.
Policy Regime: Revenue Sharing in PSC It is unfortunate that regulatory enforcement & oversight has been lax and even permissive. This is compounded by crony capitalism practised by politicos. The matter is not helped by the regressive recommendations of the Rangarajan committee. The recommendation to ex tend the period to ten years for relinquishment is a backward step. Even more damaging to optimal exploitation is the proposal to bring in revenue sharing. The committee as well as the Govt have not realised that revenue maximisation does not necessarily mean maximising oil/gas extraction. In fact, there is a conflict of interest between the two. Most often revenue maximisation which is in contractor’s interest (and Govt’s also in the new dispensation) results in sub- optimal recover y, leaving scarce resource irretrievably lost in the ground and this is against Nation’s interest. Unless maximising ultimate recover y is made a bid condition, introduction of revenue sharing in the PSCs would be shor t-sighted and would result in loss of precious resources. O ver the ground problems should not be sought to be solved by sacrificing under the ground interests of the country. sw
It may be noted here that the PELs and PMLs are issued under specific legislative acts and so have statutor y force. Even the PSC has a clause which enjoins all parties to the PSC to act in good faith in the discharge of their duties and obligations under the contract. The sanctity of the contract should be maintained by all.
>>The Rangarajan committee’s recommendation to extend the period to ten years for relinquishment is a backward step, even more damaging to optimal exploitation is the proposal to bring in revenue sharing. The committee as well as the Govt have not realised that revenue maximisation does not necessarily mean maximising oil/gas extraction. www.oswindia.com
Offshore World | 22 | December 2013 - January 2014
Offshore World | 23 | December 2013 - January 2014
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features Intelligent Completions
Intelligent Sand Control in Deepwater The providers of sand control equipment have been continuously challenged by the industry to develop new and innovative sand control completion systems to enable the completion of increasingly deeper, more difficult wells in a cost-effective way. The paper explains on single-trip multizone sand control system that gives operators the ability to complete, monitor and control multiple zones within wells, without mechanical intervention and minimising its associate risks & costs. An intelligent completion enables the operator to monitor and control the reservoirs remotely in real time conditions, to significantly improve reservoir management. Wellbore intervention in deep water can be cost prohibitive on subsea wells. Intelligent completions can reduce operating expenses for deepwater projects by eliminating the intervention requirements. Since the majority of deepwater reservoirs require sand control, designing the sandface completion and the intelligent completion for maximum successful interface is important. The completion design will vary depending on the number of zones, or intervals, requiring control. Many early intelligent sand control completions were designed for two zones. Today, many operators are realising the need, and installing, completions designed for three or more zones. Moving this technology into the deep- and ultra-deepwater arena is the next frontier. Intelligent Equipment for Sand Control Completions The intelligent equipment involved includes a hydraulically controlled production sleeve for each zone, temperature and pressure gauges and sometimes flow meters. All components are connected hydraulically or electrically by hydraulic or I-wire control lines to controllers and monitors at the surface production facility; where changes in the reservoir are monitored and changes in the production sleeves’ position are controlled. The control line must be routed through completion packers, tubing hangers, trees and incorporated into the flow line umbilical. The sand control completion equipment must be sized to allow a large enough Internal Dimension (ID) to allow a parallel and segregated production flow path. Two-Zone Intelligent Sand Control Completion Deepwater intelligent sand control completions were first installed in the Gulf of Mexico in the late 1990’s. They consisted of a two-zone intelligent completion
(Figure 1) where the lower zone production flow was directed through the inside of a tubing string, or ‘dip-tube’, run across the upper zone and sealed between the zones (Clarkson et al. 2008). The flow was controlled by a shrouded hydraulic production sleeve placed just above the upper zone sand control completion. The upper zone production flow was directed in the annulus between the sand control completion and the dip-tube. The flow was controlled by another hydraulic production sleeve which opens to the annulus below the production packer and above the shrouded sleeve. Placing the hydraulic production sleeves above the sand control completion equipment allowed larger valve sizes which would not restrict flow due to flow area limitations. However, this technique is limited to two zones; any additional zones in the wellbore would be commingled to reduce the flow stream count to two. Accurate placement of the dip-tube and its production seals can be challenging in deepwater completions; especially with subsea trees. This has been accommodated with long-travel, sealing telescoping joints to ease space-out. The space-out adjustment is made while running in the well without pulling tubing back to surface. The telescoping joint is run in the stroked open position allowing a larger margin for error in space-out calculations. Also, long polished bore assemblies and accompanying seal assemblies can be used for the same purpose. These components are placed below any of the hydraulic or electrical connections; preventing flexing that would destroy the lines and wires. Single-Trip Multizone Sand Control System The advent of the generation IV single-trip multizone sand control systems designed specifically for high pump rate fracturing treatments has led to opportunities to efficiently complete more than two zones in deepwater wells (Figure 2). Generation IV multizone systems include mechanical sleeves within the screen assemblies for each zone. These sleeves are opened as each zone is treated and then closed to
Figure 1: Two-zone intelligent sand control completion
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Offshore World | 24 | December 2013 - January 2014
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Offshore World | 25 | December 2013 - January 2014
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Figure 2 - Multizone intelligent sand control completion
provide zonal isolation and fluid loss protection. The mechanical sleeves are reopened when desired to provide a production flow path for each zone. Recent intelligent multizone sand control installations have been conducted in the Asia Pacific region near the South China Sea utilising the generation IV multizone systems. Zone counts have run between three and six zones with a mixture of high rate fracture and pack treatments and high rate water pack treatments. These wells were completed with intelligent systems enabling monitoring and control of all of the zones individually. This completion design placed the hydraulic production sleeves within the zones themselves. Each zone’s production flow was directed through its hydraulic production sleeve and into the production tubing; commingling with any other open zones. Placement of the sleeves within the zones means that the sleeves must pass through, and into, the sand control completion system. This limits the size and flow area of the sleeves; however, there is a great increase in the number of accessible zones. Seal assemblies designed to allow the wires and hydraulic lines to pass through are placed between zones. The Asia Pacific wells were completed with both dry and subsea production trees. The subsea production trees were at water depths of less than 500 feet (152 meters). These were not deepwater wells. The intelligent completion space-out was conducted conventionally by locating the seals in their proper location then pulling enough tubing to install the space-out tubing and the tubing hanger. This method does not require a long-travel telescoping joint or long polished bore assembly as the seal assemblies are accurately placed. Mechanical shifters were placed at the lower end of the intelligent production tubing string to provide a means of opening the mechanical production sleeves of the multizone sand control system. As the shifters move through each sleeve it is opened; providing a pathway for production into the wellbore. Completion brine in the wellbore during installation provided an over-balanced condition to the reservoirs while the sleeves are opened. This creates an opportunity for completion brine fluid losses to the reservoir while landing the production string. In these installations, the upper zone production sleeves were open while installing the tubing hanger and terminating the hydraulic and electric lines. To control the fluid losses, a polished seal bore and mating seal assembly were strategically placed so that they were mated while installing the tubing hanger. Next Step for Intelligent Sand Control Completions The next step in the evolution of intelligent sand control completions will be to enable the control of more than two zones in true deep- and ultra-deepwater www.oswindia.com
completions. To accomplish this, the hydraulic production sleeves will need to be placed within the zones as in the recent Asia Pacific completions described above. However, the conventional space-out methods described are not feasible in deepand ultra-deepwater completions; the water depth will require pulling thousands of feet of tubing to install the tubing hanger. The risk outweighs the reward. The margin for measurement and calculation error increases with the additional tubing lengths involved. The risk of damage to the hydraulic and electrical lines run to control the intelligent completion is greatly increased by the increased handling. The rig time spent pulling the tubing for the space-out is unnecessarily expensive. Incorporating long polished bore assemblies into the multizone sand control system to land the production seals is not feasible due to interference issues with the gravel pack service tools during deployment. The solution is to adopt the method described early in the article where a longtravel, sealing telescoping joint is used to provide the ball park range of spaceout results. The space-out adjustment would be made while running in the well without pulling any tubing back to surface. Since the hydraulic production sleeves are placed within the zones, the placement of this device must be between the hydraulic production sleeves and the production packer rather than below the sleeves. This means that the telescoping joint must accommodate a bypass of the hydraulic and electrical lines without causing damage to them. Development of long-travel, sealing telescoping joints with hydraulic and electrical feed-through capability is currently on-going within the service industry. Conclusion Two-zone intelligent sand control completions in deepwater wells have been run for the last 12 to 14 years. Intelligent sand control completions with more than two zones have been run in shallow water subsea wells for 5 to 10 years. The successful introduction of the developing feed-through long-travel, sealing telescoping joint technology, coupled with the generation IV single-trip multizone sand control system and future generation V system, will enable operators to complete, monitor and control more than two reservoirs remotely in real time conditions in any single deepwater wellbore. Accessing more reservoirs per wellbore will improve the economics for operators in deep- and ultra-deepwater completions. sw (For references, please log on to www.oswindia.com)
Ricki Jannise Senior Product Champion – ESTMZ Halliburton Email: ricki.jannise@halliburton.com
Offshore World | 26 | December 2013 - January 2014
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Offshore World | 27 | December 2013 - January 2014
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features Unconventional Approach
Momentum Building behind Global Fracking, However Challeng es Remain As intense debate is underway worldwide on Hydraulic fracturing or ‘fracking’ for groundwater contamination & numerous environmental concerns, the paper examines the facts regarding the risks & benefits of trying to replicate the economic success has brought to the US through Shale gas revolution.
Hydraulic fracturing or ‘fracking’ is a process in which water is mixed with proppant and chemicals and injected at high pressures into a wellbore in order to create fractures, increase reservoir permeabilities and improve the flow of hydrocarbons into a wellbore. The process is typically used within tight, non-conventional reservoirs such as shale and has been instrumental in the US energy revolution of recent years. Even though fracking has been used widely as a method of well stimulation in conventional reservoirs, there remains a public conception that this technology is new and poorly understood. Although relatively young, the shale gas programmes in the US are the most developed in the world and the inception of shale gas programmes in other regions requires the application of lessons learned through US operations. Indeed, environmental concerns resulting from US operations represent the reason behind the fracking bans seen globally in France, Germany and areas of the US. Misconception about Fracking Analysis of published stakeholder reports and media coverage reveals that the prevailing concern related to fracking is groundwater contamination, caused by the use of chemicals during the fracking process. Although fracking fluid composition
varies per well (based on reservoir characteristics and company formulae), typical fracks constitute 99 per cent water and proppant, with the remainder typically composed of up to 12 additive chemicals (Figure 1). These chemicals serve a variety of purposes including friction minimisation, scale prevention and bacteria elimination, and are critical to the success of the process. Opponents believe that fracking can cause contamination through the mixture of chemical additives with groundwater. However, many studies prove that the process of fracking itself does not pose a threat to groundwater supplies, as it is typically undertaken at significantly lower depths to shallow groundwater aquifers. Recent research demonstrates that fracking-induced microfractures typically extend less than 180 meters vertically from the wellbore, and the probability that microfractures extend beyond 350 meters is around 1 per cent. The use of layered, pressuretested casing further improves wellbore integrity during drilling and completions. However, problems arise through human error or poor construction, leading to contamination through well integrity failure, substandard cementing or casing leaks, the mixing of surface water with groundwater by run-off, or the discharge of drill cuttings and chemicals.
Water,99.22% Acid,8.93%
Figure 1: Average Hydraulic Fracturing Fluid Composition for US Shale Plays Source: FracFocus, August 2012
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Figure 2: Average CAPEX and NPV for Key Selected US Shale Plays Source: GlobalData
Real Challenges during Fracking Numerous environmental challenges are posed by the use of water in the development of unconventional resources. Well pads are a visual eyesore, however, despite the common misconception, rigs and fracking are not permanent features or risks. Nevertheless, typical environmental concerns include noise and emissions, dust, traffic, gas methane flaring and air pollution. To drill and frack a horizontal shale gas well typically requires 2–8 million gallons of water, although this varies widely by play. Much of this is returned to the surface through back-flow, carrying its associated chemicals. Although much of this water is re-used, this must be stored in artificial ponds, which can leak if not properly constructed. Transportation of wastewater by tanker risks spillages and is very expensive. GlobalData’s research indicates that disposal costs have reached almost USD 6 per barrel in north-eastern areas of the US. While desalinisation by membrane distillation has been proven to reduce costs associated with the treatment of salty fracking wastewater, this is yet to be commercially scaled, faces strict environmental regulations, and is largely opposed by residents who mistrust company practices. Further studies are required to allay environmental fears, and until the environmental risks are fully understood, moratoriums and bans will remain in place and could proliferate. Shale Plays a Vital Role in Reducing Energy Prices in US Unconventional shale gas has played a vital role in significantly reducing US energy prices, which currently stand at less than half those in Europe. The cost drivers associated with unconventional plays are greater than those for conventional onshore operations due to the cost of fracking and the limited drainage area available per well, increasing the number of wells required. GlobalData’s analysis
of 7,449 wells of the Eagle Ford Shale, 4,510 wells of the Bakken Shale, and 1,711 wells of the Marcellus Shale reveals respective average per well Capital Expenditures (CAPEX) of USD 7.2 million, USD 8.6 million and USD 6 million, respectively (Figure 2). The per well Net Present Value (NPV) for these plays averages USD 9.7 million, USD 12.3 million and USD 3.3 million, respectively, reflecting the significant returns offered to operators through the production of unconventional oil and gas. The Shifting European Energy Landscape Recent data released by Gazprom Export indicates that Russian gas exports to Europe in 2013 increased by 16 per cent and reached a record 5,703 billion cubic feet (bcf ), at an average price of USD 13.4 per thousand cubic feet, whilst Liquefied Natural Gas (LNG) exports totaled 2,448 bcf in 2012. Algerian gas supplies remain critical in meeting European energy requirements and accounted for around 1,836 bcf out of a total African export capacity of 3,001 bcf in 2013. Given the region’s dependence on imports, European gas prices would benefit greatly from a shale gas revolution and domestic production from countries such as France, Poland, Lithuania and Ukraine would help to offset the reliance on expensive, long-term Russian contracts and volatile North African supplies. In November 2013, Chevron signed a USD 10 billion shale gas production sharing agreement with the Ukrainian government to develop the western Olesska field, followed by a similar shale gas agreement with Shell. Although political, legislative, exploratory and commercial risk remains in Ukraine, Lithuania and Poland, the potential effect of a European shale revolution on the regional energy landscape and dynamics is intriguing.
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Policy Recommendations for Successfully Monetising Shale To successfully monetise shale gas as an energy resource in non-shale gas producing countries, a number of fiscal and regulatory measures must be undertaken. Fiscal terms must be attractive to promote exploration and development and ease the balance between investor risk and reward, especially given the current uncertainty in under-appraised reserves. A controversial example of this is Argentina’s Vaca Muerta shale gas play, where the Argentinean government has introduced an exemption from oil and gas export duty for up to 20 per cent of total output for USD 1 billion five-year investment plans in order to encourage development. Even though it was believed to be the reason behind Repsol’s YPF expropriation by the Argentinean government, a recent settlement between Repsol and the Argentinean government which followed after the YPF-Chevron deal means the government is interested in attracting foreign investment to develop its unconventional resources. Nevertheless, many obstacles must be overcome for the Vaca Muerta play to be developed, including infrastructure requirements, price negotiations, economic conditions such as inflation, fiscal restrictions on generated revenues, plus fiscal and political stability. Another example is the UK, where the government recently introduced measures to stimulate shale gas exploration and development. Benefits to the company include a pad allowance and an extension of the ringfence expenditure supplement, whilst an attempt to gain public support has been made through the provision of 1 per cent of all revenues and GB£100,000 (USD 165,000) per well-site where fracking takes place in the exploration phase, to the local community. Such measures have proven successful in attracting Total to the UK shale gas industry as part of a GB£47 million (USD 77 million) investment for a 40 per cent equity stake in two exploration licenses in eastern Britain. Although a number of factors combined to trigger the US shale boom, government measures such as incentive pricing, tax credits, and research and development programmes were instrumental in promoting the development of unconventional resources. Not a Smooth Ride for India The US has heralded a new era of economic growth through shale gas, but managing the industry is extremely difficult. All wells must meet stringent environmental requirements and undergo safety studies in order to be approved by the government. Likewise, each US state possesses unique laws and regulations, many of which are linked to the local geological conditions and operational environment, for evaluating well safety. Replicating such policies in other countries is extremely difficult and may be slowed in those where the government owns subsurface rights, thus negating individual rebate agreements with landowners, as is common practice in the US. Although the allure of becoming more energy-independent is an enticing prospect for developing nations such as India, unconventional shale gas may prove a less feasible option here than in the US. The less developed pipeline and utility networks in places such as India would require massive and costly expansions, while governments would need to draft new environmental regulations concerning the use of fracking fluids and, crucially, enforce them. The bureaucratic nature of the hydrocarbon industry in India will likely prolong this process considerably. For the successful development of shale gas operations in developing countries, governments must ensure that the water required for operations does not compromise local communities. However, India’s track record on water pollution is woeful, which does not bode well for the responsible use and disposal of fracking www.oswindia.com
fluids, or in other developing countries. Further complications arise in the fact that India’s national oil company, Oil and Natural Gas Corporation (ONGC) does not have expertise in unconventional shale plays. While ONGC entered a contract with ConocoPhillips to jump-start shale gas production, almost every other international oil company, most recently BHP Billiton, has divested and exited the country. Other developing countries such as China and Indonesia face similar issues in developing their own shale gas reserves, as their limited networks of pipelines and expertise stand in contrast to the vast array of companies and infrastructure that the US boasts. Part of what made the US shale gas revolution economically feasible was that no additional investment was required to expand the country’s transportation and trade systems to develop the industry. Australia Looks to Bring Commercial Shale Gas Online in Short-term: The only country in the Asia-Pacific region that looks to bring commercial shale gas online in the short-term is Australia. Like India and China, test wells have already been drilled, however Australia possesses more developed domestic gas infrastructure. Crucially, Australia retains a stable foothold in the LNG market in Asia-Pacific, with plans to bring over 45 million metric tons per annum of LNG production online over the next 10 years. Shale gas production would not be constrained to domestic use, but could be sold at a premium to other nations. In the event that China and India safely and effectively bring shale gas production online in the next few years, the remoteness of their shale plays and their nascent unconventional industry would limit economic growth considerably, still requiring both countries to import the vast majority of their energy from other nations. Conclusion In summary, the successful inception of fracking in developing nations requires the implementation of best practices and the lessons learnt from the US industry in a sustainable manner. A significant challenge currently being faced is gaining public approval and trust, and the public disclosure of fracking constituents in the US has done little to bring peace of mind. Indeed, ‘fracktivists’ from 26 countries are currently scheduling worldwide protests. The ability to identify potential difficulties such as these and therefore develop mitigation programmes will be vital to the successful development of a well-rounded shale gas programme and for facilitating acceptance of shale gas exploration and development in Europe and developing nations such as India. Until this is the case, gas prices are likely to remain high until in-place resources are appraised, fiscal and regulatory framework is devised, infrastructure is developed, and advances in technology can drive down costs. sw Matthew Ingham Lead Analyst - North Sea and Western European Upstream Research GlobalData Email: mingham@globaldata.com Gustavo Bianchotti Senior Analyst - Europe, Middle East and North African (EMEA) Upstream Research
GlobalData Email: gbianchotti@globaldata.com
Offshore World | 30 | December 2013 - January 2014
features Simulation Systems
Offshore Training: Simulation is the Path Ahead The offshore marine industry needs to develop and maintain a large and growing pool of qualified, trained, certified, and experienced personnel to keep the industry running safely and productively. Simulation systems are the optimal platform for training, providing ‘hands-on’ experience in environments that can reproduce the complexity and the difficulty levels of real-life operations without causing any harm to life and limb.
A multipurpose offshore support vessel (MSV) is carrying out subsea inspection work by Remotely Operated Vehicle (ROV), near an offshore platform. The vessel is operating on DP and is in ‘follow ship’ mode. Four thrusters and two main propellers are online, four generators including two shaft generators are online and bus ties are closed, two Differential Global Positioning Systems, one Hydroacoustic Position Reference and laser radar system are online as well as two gyros, two Vertical Reference Units and two wind sensors. Tide rips are observed and ROV control is informed. As the tide surge passes through, the vessel loses position. The vessel is moved towards platform in an attempt to regain position. A squall develops to the south of the platform and a heading change is initiated by Dynamic Positioning Operator. The wind increases to 20 knots on the port quarter. Generator number four drops load approximately 35 per cent below the other generators. Noise is heard from turbochargers while generators show a drop in frequency. The vessel moves in an uncontrolled manner due to strong wind and heavy swell. Power to thruster one is lost. The vessel is put in heading control mode and a slow drift is experienced. The vessel pitches heavily and various position reference systems are rejected by the DP system. Position drop-out occurs. The ROV and Tether Management System are recovered and the vessel moves clear of the platform. Luckily for all those involved, all this takes place not on the oceans but in a training simulator. The incident is part of an emergency response scenario conceived by a group of offshore professionals in a large, state-of-the-art, integrated Offshore Vessel (OSV) handling simulator. Such sophisticated simulation systems, of the type recently installed at the NUSI Offshore Training Institute at Mumbai by ARI Simulation, have the potential to fill a range of the skills gaps being experienced in the offshore energy industry globally.
can be filled by moving people laterally from other similar industries is very small. There really are no clones of this industry to be found anywhere else. Between the main fleet and offshore shipping industries, some movement of qualified and trained personnel exists. However, operators have learnt to their cost that the core skill sets needed in either sector are not easily transferable. Simulation training can provide an answer to this growing dilemma. By its very nature, a well-designed, built and operated integrated simulation system is the optimal platform for imparting the type of training that requires the trainee to perform ‘hands-on’ activity and gain experience in environments that can reproduce the complexity and the difficulty levels of real-life operations - along with a sense of danger - without causing any harm to life and limb. Simulators are rapidly losing their limitations. In every area of the design and execution of a simulation project – including software architecture, hardware design, scope of functionality, user interface with system, functional integration, sophistication of mathematical modeling, integration of OEM equipment, fidelity of the visual system, assessment mechanism, and above all, the sense of realism - the challenges are being constantly overcome. The current generation of simulators has proved their usefulness as tools for promoting excellence, safety, professionalism and a work culture that relies on co-operation to get the job done safely, securely and in a timely manner. The rigours of the industry make nearly all offshore jobs highly demanding – almost all functions are skills-based and not conducive to easy development through the reading, lecturing or on-board training, despite the advantages of learning in the operational environment. The fact that operating conditions are harsh and unforgiving, highly taxing on mind and body and require long periods of focused attention and alertness, Camera Attached to Ship Move Ship using Arrow Keys Misc.
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Emergency response scenarios, such as the one above, can be prepared and practiced across a range of situations, vessel types, operations, and functional teams.
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There is no doubt that the offshore marine industry needs to develop and maintain a large and growing pool of qualified, trained, certified, and experienced personnel to keep the industry running safely and productively. The job roles involved are many and varied and the ‘feeding funnel’ mechanism by which any gap in skills Offshore World | 31 | December 2013 - January 2014
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for successful outcome of the mission. The total training value derived from such integrated simulators is much greater than the sum of its parts. In the offshore scenario, such joint missions can range from a relatively routine maneuvering and rig supply task to a more complex ROV guided offshore crane operation for a subsea construction task. In the former example, the operator will be working on the vessel handling simulator, while the machinery operations unit provides the propulsion and thruster power, with the operator using the DP system to hold position while the offshore crane operator transfers personnel to and from the vessel. In the latter, more complex scenario, the vessel may launch the ROV system, which is piloted from the ROV simulation unit to help the crane operation team perform subsea tasks, while the power management system allows the vessel operator to follow the ROV under DP control.
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makes for a scenario where an inherent shortage of skilled manpower is aggravated by the need to provide rigorous and continued training in operational and safety aspects of the job. A modern, well-designed and correctly-built offshore simulation complex can be expected to cater to the training needs of nearly the entire set of job functions related to the offshore marine industry. From towing, positioning and anchoring rigs, to keeping the rigs fully supplied, conducting subsea ROV operations, handling multiple offshore cranes, operating power management systems for dynamic positioning and operating machinery systems for propulsion, thrusters and winches - offshore vessels and the people operating them must perform at the highest level of efficiency and productivity. It is only then correct to expect the training platforms that cater to these requirements to exhibit the highest levels of performance that technology today can provide. What then constitutes a good simulation system? At the highest level, a simulation complex is expected to have a number of installations, each of which is built to train people for a specific job function. Each simulator must look and feel like the area of the vessel it is representing. The physical, behavioral and operational realism, including the fidelity of the visual system, is expected to meet the highest standards for simulation systems that are available today. This is where it starts to get more interesting. Having achieved the task of creating these individual, self-contained, and independent units, each of which satisfies the requirements of a specific set of roles or functions, the next logical step then is to combine the units in various ways to provide for a multitude of scenarios where the various teams can train and practice joint missions in a cohesive way. Each team is responsible for their own domain with all of the units being jointly responsible Camera Attached to Ship Move Ship using Arrow Keys Misc. Visibility Light Intensity
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The possibilities are large and these can still be built upon as data from real-life situations is collected and analysed to help recreate the incidents, for the benefit of learning from others’ experience. At the heart of the simulation system is its mathematical model, which has the task of providing accurate, reliable and predictable results in every possible situation, and with everything that the trainee can throw at it. The learning value derived from the time spent on the simulator is in many ways directly coupled to the robustness of the underlying mathematical model. Offshore vessel handling and operations are different from other marine operations in many ways and simulator capabilities must include the ability to capture nuances of offshore operations correctly. An offshore operator uses many visual, aural, spatial and temporal cues to perform his tasks and it’s important that the simulator provides the operator with a near-real environment in which to operate and hone his skills. A high performance, high fidelity visualisation system is essentially what creates a sense of realism in the simulator, which in turn helps to keep the trainee engaged and absorbed in the scenario as it is unfolding. So what exactly goes into making a high quality visual scenario? It includes a large number of elements; a richlytextured water surface, wave and wind effects on water, sunlight reflection off water particles and other surfaces, detailed marine craft and other objects, particle effects, variable subsea visibility, and other specific visual effects. Smart software must be able to create the high powered images at a fast enough rate to provide a smooth and seamless experience to the trainee. The MSV in our scenario successfully maneuvered itself out of the danger zone and into an area where the equipment failure could be looked at more closely and remedial action taken to prepare the vessel to continue and complete its assigned mission successfully. The crews who take on this responsibility day in, day out, would be better prepared to meet this situation in real life if they have already experienced it, and learnt from it, in near-real conditions. That is the power of simulation. sw
Shravan Rewari CEO ARI Simulation Email: info@arisimulation.com www.oswindia.com
Offshore World | 32 | December 2013 - January 2014
features Basin Seismology
Seismic Study: Imaging Reservoir Potential Seismic studies are the foremost step before carrying out any exploration activity that enables the geoscientists to understand the stratigraphy to assess the available potential. It gives the right image for hydrocarbon reservoir potential. This article gives insights into seismic exploration, types of seismic surveys, data acquisition etc. Locating high productivity areas for oil & natural gas and petroleum deposits have been transformed dramatically in the last 20 years with the advent of technology. Due to the ever increasing demand for fossil fuel energy, the necessity for more accurate methods of locating these deposits has become critical. Sources of Data Geologists and geophysicists use technology and knowledge of the properties of underground oil & natural gas deposits to gather data, which can later be interpreted and used to make matured guesses as to where natural gas deposits exist. Exploration typically begins with geologists examining the surface structure of the earth, and determining areas where it is geologically likely that petroleum or gas deposits might exist. Surveying and mapping the surface and sub-surface characteristics of a certain area, they can extrapolate, which areas are most likely to contain a petroleum or natural gas reservoir. Geological information attained from the rock cuttings and samples are collected. This information is combined to make inferences for the fluid content, porosity, permeability, age, and formation sequence of the rocks beneath the surface of a particular area. In Figure 1, a geologist studies the outcroppings of rock to gain insight into the geology of the subsurface areas.
Seismograph, Source: US Geological Survey
Figure 1: Surface Geology Source: Anadarko Petroleum Corporation
Figure 2 : Placing Geophones Source: API
Once he determines an area, where it is geologically possible for a natural gas or petroleum formation to exist, further tests are performed to gain more detailed data about the potential reservoir area. These tests allow for the more accurate mapping of underground formations, most notably with natural gas and petroleum reservoirs. These tests are commonly performed by a geophysicist, who uses technology to find and map underground rock formations.
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nes, of es, uch or
Seismic Exploration The biggest breakthrough in petroleum and natural gas exploration happened through the use of basic seismology. The Earth’s crust is composed of different layers, each with its own properties. Energy (in the form of seismic waves) travelling underground interacts differently with each of these layers. These seismic waves, emitted from a source, will travel through the earth, but also be reflected back toward the source by the different underground layers. Through seismology, geophysicists are able to artificially create vibrations on the surface and record how these vibrations are reflected back to the surface, which reveals the properties of the geology beneath. Onshore Seismology It involves artificially creating seismic waves, the reflection of which are then picked up by sensitive pieces of equipment called ‘geophones’(Figure 2) that are embedded in the ground. The data picked up by these geophones is then transmitted to a seismic recording truck, which records the data for further interpretation by geophysicists and petroleum reservoir engineers. Figure 3 shows the basic components of a seismic team. The source of seismic waves (in this case an underground explosion) creates the reflections off the different layers of the Earth, to be picked up by geophones on the surface and relayed to a seismic recording truck.
Recently we use non-explosive seismic technology to generate the required data. This Non-explosive technology consists of large heavy-wheeled or trackedvehicle carrying special equipment designed to create a large impact or series of vibrations. These impacts or vibrations create seismic waves, (Figure 4) similar to those created by dynamite.
Figure 4: A Seismic Vibrator Truck Source: Natural Resources Canada
Offshore Seismology In offshore seismic exploration, while exploring for oil & natural gas, a slightly different method of seismic exploration is used. Instead of trucks and geophones, a ship is used to pick up the seismic data, and hydrophones are used to pick up seismic waves underwater. These are towed behind the ship in various configurations (Figure 5). Instead of using dynamite or impacts on the seabed floor, the seismic ship uses a large air gun, which releases bursts of compressed air under the water, creating seismic waves that can travel through the Earth’s crust and generate the seismic reflections that are necessary. Magnetometers & Gravimeters In addition to using seismology to gather data concerning the composition of the Earth’s crust, the magnetic properties of underground formations are being measured to generate geological and geophysical data, which is done by use of magnetometers. They can measure the small differences in the Earth’s magnetic field. We can also measure and record the difference in the Earth’s gravitational field to gain different underground formations and rock
Figure 3 : Seismology in Practice Source: API
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Figure 5: Offshore Seismic Exploration Source: US Geological Survey
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>>The Earth’s crust is composed of different layers, each with its own properties. Energy (in the form of seismic waves) traveling underground interacts differently with Logging each of these layers. These seismic waves, emitted from a Logging is performing tests during & after the drilling process to allow source, will travel through the earth, but also be reflected geologists and drillers to monitor the progress of the well under drilling / back toward the source by the different underground layers. types, which have a slightly different effect on the gravitational field that surrounds the Earth and detect the potential for hydrocarbons (Gravimeters).
drilled and to gain a better picture of subsurface formations. Monitoring the logs ensure that the correct drilling equipment is used and that drilling is not continued if unfavorable conditions develop. An example of the data obtained
and recently, four-dimensional (4-D). These imaging techniques, while relying mainly on seismic data acquired in the field, are more and more sophisticated. It is now possible to incorporate the data obtained from different types of tests, such as logging, production information, and gravimetric testing, which can be combined to create a ‘visualisation’ of the underground formation. By this geoscientists are able to combine all of their sources of data to compile one clear, complete image of subsurface geology. 3-D Seismic Imaging 3-D imaging utilises seismic field data to generate a three dimensional ‘picture’ of underground formations and geologic features. This allows the geophysicist and geologist to see a clear picture of the composition of the Earth’s crust in a particular area (Figure 7). A 3-D seismic has been estimated to increase the likelihood of success rate of reservoir location by 50 per cent.
Figure 6: An Example of Well Log Data Source: US Geological Survey
through ( Figure 6 ) various forms of logging is shown. The data interpreted by a geologist, geophysicist, or petroleum engineer is able to gain a better understanding of formations beneath the surface.
It is usually used in conjunction with other exploration techniques to have a high probability of oil & Gas containing reservoirs. 3-D seismic imaging allows for the more accurate placement of wells to be drilled (Figure 8). This increases the productivity of successful wells, allowing for more petroleum and natural gas to be extracted from the ground. In fact, 3-D seismic can increase the recovery rates of productive wells to 40-50 per cent, as opposed to 25-30 per cent with traditional 2-D exploration techniques.
Data Interpretation There are many sources of data and information for the geologists and geophysicists to use in the exploration for hydrocarbons. This raw data alone will not be useful without careful and methodical interpretation. 2-D Seismic Interpretation Two-dimensional seismic imaging refers to using the data collected from seismic exploration activities to develop a cross-sectional picture of the underground rock formations. The geophysicist interprets the seismic data obtained from the field, taking the vibration recordings of the seismograph and using them to develop a conceptual model of the composition and thickness of the various layers of rock underground. This process is normally used to map underground formations, and to make estimates based on the geologic structures to determine where it is likely that deposits may exist. With 2-D CAEX it is possible to use color graphic displays to highlight geologic features that may not be apparent using traditional 2-D seismic imaging methods. Computer Assisted Exploration (CAEX) It is the use of computers to compile and assemble geologic data into a coherent ‘map’ of the underground (‘CAEX’). There are three main types of computerassisted exploration models: two-dimensional (2-D), three-dimensional (3-D),
Figure 7: Geologist Using Interactive 3-D Seismic Source: BP
4-D Seismic Imaging Yet another latest breakthrough in seismic exploration and the modeling of underground rock formations has been four-dimensional (4-D) seismic imaging. This is an extension of 3-D imaging technology. Instead of achieving a simple, static image of the underground, a 4-D imaging changes the structures and properties of underground formations that are observed over
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To assess the role of LF seismic sur veys in developing unconventional reservoirs, a survey was conducted over the Pinedale gas fields in western Wyoming. This area was chosen, in par t at well- charac terised Lance reser voir, where productivity differences were documented in the field due to faulting, which compar tmentalised the reser voir. The aim of the LF seismic sur vey was 1) To verify that there is a LF reser voir related signal in the survey area, and 2) To determine whether this signal could be used to discriminate higher productivity areas of the field from lower productivity areas.
Figure 8: An Example of 3-D Seismic Imaging Technology. Source: BP
time. Since the fourth dimension in 4-D imaging is time, it is also referred to as 4-D ‘time lapse’ imaging. Various seismic readings of a par ticular area are taken at different times, and this is fed into a powerful computer. The different images are amalgamated to create a ‘movie’ of what is going on under the ground. By studying how seismic images change over time, geologists can gain a better understanding of many properties of the rock, including underground fluid flow, viscosity, temperature and saturation. Although very important in the exploration process, 4-D seismic images are being used by petroleum geologists to evaluate the properties of a reservoir, including how it is expected to deplete once petroleum extraction has begun. 4-D imaging on a reservoir can increase recovery rates to 65 to 70 per cent. Low-frequency (LF) Seismic Survey Low-frequency (LF) seismic survey has been employed over the gas fields to verify whether changes in the LF passive wave field could discriminate the higher productivity areas. The 2D profiles of the survey crossed the field in places that show maximum contrast in well productivity. As part of the LF seismic survey processing, the anthropogenic noise generated by the operations and the infrastructure of the field was captured and analysed. Results of this analysis show that the LF seismic attributes correlate the well to reser voir proper ties like estimated ultimate recover y (EUR) and hydrocarbon pore thickness (HPT or Sg PhiH) while the anthropogenic noise was not responsible for the measured LF seismic signal anomaly. This enables the use of LF seismic surveys to extend existing tight gas sand fields in locating the high-productivity areas in exploration play. Case histories have shown that low-frequency (LF) seismic sur veys have been able to help discriminate areas containing conventional oil and gas reservoirs from non-productive areas.
>> In offshore seismic exploration, while exploring for oil & natural gas, a slightly different method of seismic exploration is used. Instead of trucks and geophones, a ship is used to pick up the seismic data, and hydrophones are used to pick up seismic waves under water. www.oswindia.com
Data Acquisition Using the published reser voir maps, the acquisition lines were laid o u t, w h i c h co n s i s te d o f s e ve n 2 D p ro f i l e s d e s i gn e d to t rave r s e t h e largest reser voir produc tivit y contrasts in the fields Understanding the types and distribution of the man-made noise sources was critical for designing a data processing flow that mitigates noise and enables an analysis of the background wave field. It was obser ved noise from car and truck traffic, drilling operations, well frac ture stimulations, pipelines, gas compressors, well production equipment, and wind in the survey area. Data Processing Processing LF seismic data involves separating man-made noise, typically sur face waves, from the weaker, secondar y wave field produced by the interaction of the earth’s ambient wave field with oil and gas reservoirs. This involves erasing noise in the time domain (removing ear thquakes and traffic noise) and the frequency domain (selecting frequencies with minimal cultural noise) In the frequency domain, cultural noise sources could be grouped into three types; higher-frequency operational noise (e.g. combustion engines); lower-frequency infrastructure-related noise (e.g. pipelines) and narrow spikes due to stationary machinery. The operational noise can be quantified by measuring the total integral of the ver tical component between 15-25 Hz (high noise proxy, HNP). The low-frequency noise (low noise proxy, LNP), indicated by arrows, is mainly related to production infrastructure. Data Analysis 1) The presence of the spectral offset between 1.5-2.0 Hz for this survey is an indication of surface waves and 2) The effect of this noise can be estimated by the height of the spectral offset (low noise proxy, LNP ). Five reservoir maps of different parameters were published on the gas field. The cross correlation between the signal, noise and reservoir parameters were compared, looking for which cross correlation resulted in the maximum correlation coefficient. If the maximum correlation was between the signal and reservoir parameters, then the signal was likely responding to changes in the reser voir. Maximum correlation between signal and noise would indicate the signal attribute which was primarily measuring the field noise. If the maximum correlation was between the noise and reser voir parameters, then the collocation of the noise and reservoir would make
Offshore World | 36 | December 2013 - January 2014
>> By studying how seismic images change over time, geologists can gain a better understanding of many properties of the rock, including underground fluid flow, viscosity, temperature and saturation. Although very important in the exploration process, 4-D seismic images are being used by petroleum geologists to evaluate the properties of a reservoir, including how it is expected to deplete once petroleum extraction has begun. the result of the analysis inconclusive. The normalized signal and reservoir parameter (SgPhiH) show a linear relationship. A similar relationship was also seen with the estimated ultimate recover y (EUR) parameter. In the noise Vs signal and noise Vs Reservoir cross plots, not only is the noise not increasing with signal or reservoir parameter, the noise is inversely related to both. This was due to the drilling and completion ac tivit y that was predominantly in the nor th par t of the field, away from the best reservoir. This comparison demonstrates that the LF signal attribute was not just a measure of this noise. Hz LF signal attribute and the reservoir parameter SgPhiH. EUR had the next best correlation to normalized signal followed by net pay. Net sand thickness and SgPhi had little or no correlation to normalized LF signal. Arrows indicate faults that compartmentalize the reservoir. Red line shows the signal attribute normalized by the LF noise proxy. Both of the noise proxies showed less correlation to the normalised LF signal attribute than the signal attribute did to the reservoir productivity parameter. Within the developed gas field, the density of the wells and infrastructure is relatively uniform, much more so than well productivity across the internal field faults. While the well infrastructure does contribute noise to the LF seismic recordings, it was possible to estimate this contribution and remove it from the measurement. Operational noise was a different story and where it was severe, it dominated the measurement, resulting in the point being removed from the analysis.
data processing for this data set, should be much reduced or non-existent. Similarly, field infrastructure noise should be reduced also. Targeting better reservoir areas earlier in the exploration program should lead to a better evaluation of the tight gas-sand play and result in better economics of the subsequent development. sw References 1) Birkelo, B., Duclos, M., Artman, B., Schechinger, B., Witten, B., Goertz, A., Weemstra, C., Hadidi, M.T., 2010, A passive low-frequency seismic survey in Abu Dhabi – Shaheen project: 80th Annual International Meeting, SEG, Expanded Abstracts, 2207-2211. 2) DuBois, D.P., Wynne, P.J., Smagala, T.M., Johnson, J.L., Engler, K.D., McBride, B.C., 2004, Geology of Jonah Field, Sublette County, Wyoming: in Jonah Field: Case Study of a Giant Tight-Gas Fluvial Reservoir, J. W. Robinson and K. W. Shanley, eds.: AAPG Studies in Geology 52 and Rocky Mountain Association of Geologists 2004 Guidebook. 3) Locating High-productivity Areas of Tight Gassand Reservoirs Using LF Seismic Surveys B. Birkelo* (Spectraseis), A. Goertz (Spectraseis), K. Cieslik (Spectraseis) & E. LaBarre (EnCana Oil & Gas (USA) Inc.)
The lesson learned from the operational noise has two parts. First, close coordination with the field completion and drilling operations could have reduced the impact of this noise on the survey. Second, having multiple nights of recording was beneficial because the noise was often more severe on one night than the other and this allowed data from the quieter night to be used. Conclusion The highest correlations were obtained between LF signal attributes and reservoir productivity measures like SgPhiH. With these relationships, it should be possible to use this data, in conjunction with other G&G data, to identify field extension opportunities. Careful analysis of the noise in the field is critical to this sort of analysis. Generalising these results to an exploration setting for tight gas sands seems straight forward. Better quality reservoir areas should exhibit higher LF signal attributes for reservoirs. In an exploration setting, the operational noise, the single biggest hurdle in the
Dr M R Srinivasan Professor, Department of Petroleum Engineering and Geoscience University of Petroleum and Energy Studies Email: mrsrinivasan@ddn.upes.ac.in
Offshore World | 37 | December 2013 - January 2014
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features Anti-Corrosion Technology
Coatings: ‘Uncoating’ Corrosion Depletion of hydrocarbon reserves in shallow offshore fields has compelled E&P players to explore deeper in sea for satiating rise in demand in harsh and challenging environments. In hydrocarbon sector, infrastructure is immune to corrosion which needs to be protected. It can be avoided by creating a barrier layer of paint, a coating or lining, or a metallic lining between the material and media. This article gives insights into the technologies for coatings.
The period of easy location of oil and gas reserves is over. Continued demand and rapid depletion of existing oil fields are propelling the industry into deeper in sea and more hostile environments and in isolated locations, which are lacking required infrastructure. Along with the offshore oil and gas exploration; long distance deep-water oil and gas transportation is becoming an ever pervasive challenge. According to the US Geological Survey, the Arctic region may contain up to 90 billion barrels of oil and a significant portion of these reserves is thought to lie in the on- and off-shore areas of Russia. There is an increase in better demanding solutions to improve the performance and life cycle of underwater extraction equipment. New methods of extracting oil from the sea bed have required the use of floating oil platforms, which have their own complexities. Pipeline assets need long-term protection in demanding conditions where the costs of failure are extreme. Despite these challenges, the project schedule expectations are getting tighter than ever before. All of the above mentioned conditions add to complexities in oil and gas process chain. The total annual cost of corrosion in the oil and gas production industry is estimated to be USD 1.372 billion, broken down into USD 589 million in surface pipeline and facility costs, USD 463 million annually in downhole tubing expenses, and another USD 320 million in capital expenditures related to corrosion. As carbon steel is used for more than 80 per cent of plant requirements as it is cost efficient, but at the same time it requires efficient methods of corrosion control. The philosophy of corrosion control rests on three basic methods: Change in the material of construction for the specific application, reduction of the intensity of corrosive attack by modifications in corrosive media and, creating a barrier layer between the material and media to avoid the direct contact, the last one offer a cost effective solution in many of the situations. A barrier layer can be paint, a coating or lining, or a metallic lining. High performance coatings, as a method of combating corrosion, are economical and less expensive than opting for a costly material of construction.
The exposure to heat could be in three areas, namely immersion (e.g. Knock Out drums, separators, vessels, steel or concrete tanks, sumps etc. where the operating temperatures or design temperatures can be up to 185 0 C or even above) or secondary containment, insulated steel (Pipes, Valves, Tanks, Vessels, other equipments), and the fluctuating temperatures (as low as -196 0 C in cr yogenic uses and as high as design temperature of 650 0 c, sweating lines). Immersion Immersion conditions that coatings/lining need to encounter in immersion situations in oil and gas industry are getting increasingly demanding because of necessity of refineries to handle sour, heavier and dirtier crude in comparison to sweet crude that is relatively easier to handle from corrosion perspective. Coatings and linings provide solutions to immersion in hydrocarbons from ambient temperatures up to 185 0 C (Flue gases up to temperature of 220 0 C operating or even higher temperatures). While Epoxy Novolacs have been found suitable to use in immersion temperature situations (up to 90 / 95 0 C) when in contact with hydrocarbons; superior modifications like polycyclamines curing agents are used to handle immersion temperatures up to 185 0 C with success. Polycyclamine curing agents based novolac epoxies have also been accepted and used successfully on buried pipelines at high temperatures, with and without cathodic protection. Areas like effluent treatment plants or alkylation plant area which handle chemicals and can have variation in pH as high as 1 to 13 with or without elevated temperatures in the range of 60 – 90 Deg C require Vinyl Ester technology or hybrid polymers to be used in the thicknesses ranging from 1 mm to 3 mm to provide long term solutions.
>>Coatings and linings provide solutions to immersion in hydrocarbons from ambient temperatures up to 185 0C (Flue gases up to temperature of 220 0C operating or even higher temperatures). While Epoxy Novolacs have been found suitable to use in immersion temperature situations (up Protecting Steel, particularly exposed to high temperatures creates most to 90 / 95 0C) when in contact with hydrocarbons; superior demanding situations faced by coatings, and coatings help delay the process in modifications like polycyclamines curing agents are used to handle immersion temperatures up to 185 0C with success. part of the areas of problem. www.oswindia.com
Offshore World | 38 | December 2013 - January 2014
Owners and specifiers both, however, need to be careful in selection of the technologies and product. Generic selection of products tends to go wrong seriously in these cases unless individual product performance is looked into thoroughly. It is, sometimes not possible to simulate the harsh exposure conditions that linings have to encounter in oil and gas industry using simple standards such as ISO 2812 as these may not give a true representation of field performance. It is necessary to have a full understanding of the conditions and how these relate to performance testing and often it is necessary to interpret results of long term performance testing taking into consideration proven field exposure. Corrosion Under Insulation Coating systems applied under insulation are required not only to resist high operating temperatures (which are often cyclic) but also to provide corrosion protection. Corrosion under insulation (CUI) is a major problem in the refining and petrochemical industry, with effects often hidden from view and not discovered until it is too late. Corrosion is not a significant problem when a metal surface remains hot and dry. But in practice, hot and dry surfaces are difficult to achieve if temperatures cycle is below 150 0C; a condition in which condensation may get created. Areas can often operate below process temperatures (which can vary) due to shut down or intermittent use of equipment, and it is not uncommon for insulation to be damaged, providing a potential pathway for moisture ingress. It has been reported that the risk of CUI rises significantly after 5–10 years of service in a plant, and that an average 60 per cent of all insulation in service for 10 years or more will contain corrosion-inducing moisture. If left unchecked, CUI can result in localised corrosion and leakage from pipes and vessels. If such equipment is operating under high pressure, the potential for a catastrophic failure poses a real threat. NACE RP0198-2004, “The Control Corrosion Under Thermal Insulation and Fireproofing Materials—A Systems Approach,” is a standard recommended practice developed by NACE and is intended for use by corrosion control personnel and others concerned with CUI of piping and other plant equipment. This standard details the current technology and industr y practices for mitigating corrosion under insulation via a systems approach; the standard refers to 3 different technologies: Epoxy/Epoxy Phenolic or Novolac, modified silicone and siloxanes.
>>New Technology developments for handling CUI include flexible polymers, which can provide both corrosion and heat resistance in wet and dry insulation situation. New generation Cold sprayed aluminum technology and use of inert polymers in comparison to traditional hightemperature coating systems provides superior performance and long service life failure. Rapid cooling and reheating may produce condensation under insulation which, through the process of evaporation, may deposit salt residues on the vessel surface, creating an extremely aggressive environment. Water ingress and the resultant wet insulation can lead to hot, wet, and humid conditions that many high-temperature coatings struggle to withstand. A number of technologies have been developed by coating industry e.g. Epoxy siloxanes, which work to the upper limit of 300 0C – 400 0C in situations not encountering thermal shocks. The technologies used in such end uses include internally flexibilised epoxies, epoxy phenolics and inorganic copolymers. One of the latest developments in coatings are Titanium modified inorganic copolymers for handling high temperatures with thermal shock and fluctuations, both for cryogenic temperatures on the colder side and high temperatures up to 650 0 C. The additional benefit from this technology is significantly reduced complexity during project stage, as a single product can go in different temperatures. In addition to the above there are developments to help industry in handling unique situations, examples being temperature indicating paints already used for visual identification of weak spots in refractory in secondary reformers, Epoxy syntactic foams that work as insulation, used especially in LNG application to avoid possible steel embrittlement in case of LNG spillage and similar application. While polymer coatings and linings cannot solve all the corrosion problems, developments of polymers, coatings and lining technology has been able to solve many of the serious problems and challenges faced by oil and gas Industry, providing cost effective solutions, reducing the frequency of shut downs and enhancing the integrity of assets. sw
New Technology developments for handling CUI include flexible polymers, which can provide both corrosion and heat resistance in wet and dry insulation situation. New generation Cold sprayed aluminum technology and use of inert polymers in comparison to traditional high-temperature coating systems provides superior performance and long service life while at the same time providing alternate to thermally sprayed Aluminum. Thermal Cycling Thermal cycling and thermal shock in particular, presents exceptional challenges to coatings. Severe temperature gradients often cause steel and its coating to contract at different rates, creating huge stresses within the coating film, which, when accompanied by insufficient flexibility, can result in premature coating
Dhirendra Singh Market Manager – Oil & Gas Protective Coatings, Akzo Nobel India Ltd Email: ANCIPL@akzonobel.com
Offshore World | 39 | December 2013 - January 2014
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features Pipe-bending Technology
Bending the Costs Downward The paper illustrates the advantages of pipe bending technologies instead of the conventional welding processes required for pipe fitting in plant and pipeline construction at oil platforms, chemical plants, refineries and power stations.
There are many kilometres of pipe on oil platforms, complex chemical plants, refineries and large power stations. In view of these quantities, pipe fitting plays a special role in plant and pipeline construction. Moreover, these constructions are essential for the function and efficiency of the plants. Instead of relying on conventional welding processes, significant cost optimisation can be achieved through time and cost efficient cold bending technologies. Challenges of Pipe Bending A cursory glance at an oil pumping facility clearly shows the central challenge: The pipes form a highly complex network and the conduit system inevitably includes many bends. As such, a large number of different formed pipe bends in a variety of dimensions, forms and angles are used in the piping installation. These components need to be welded to the straight, long pipes on the construction site to form the desired pipeline. As a result, these processes represent considerable costs in the construction of these plants. First, the curved elements must be produced in advance, is some cases at an off-site facility. Second, these components must be transported to the work-area and welded
to the corresponding pipes, including the associated cost of logistics that can generate additional costs. Additionally, it is often vital to check every finished weld joint for compliance to industry standards or special customer requirements. The processes of using ultrasound or x-ray technology to inspect the welds can also cost a great deal of time and money. It becomes clear that the many pipe bends and the processes involved to produce a complete assembly can offer a tremendous potential for savings in plant construction – if ultimately, many of the in-situ welded bends could be replaced by pre-bent pipelines that are able to be fabricated to the exact specifications of the construction site. In order to meet these production requirements, there are essentially two options: Cold and warm bending. With warm bending, the pipe is initially partially heated at the desired bend location. Through the factors of temperature and pressure, the material begins to flow. The disadvantages of the warm bending process are that it takes a long time to form the material and the energy consumption used in the production process is very high. Time and Cost Advantages of Cold Bending In comparison to the option of warm bending, cold bending offers several advantages, because this procedure eliminates the energy-intensive and protracted heating process. Only the properties of the material are what set certain limits to the plasticity. Otherwise, the pipe can be shaped into almost any form. In contrast to the 30 minutes at least that would be needed for the warm bending process. In addition, the cold bending technology offers several other advantages. For example: With cold bending, materials can be processed that cannot be bent warm or for which heating is simply not permitted because it changes the microstructure of the material. As a result, cold bending has therefore only two real constraints: The space available in the workshop and the length of the machine. If during the bending process the long pipes do not axially collide, they can be processed into complex shapes directly in one pass.
Tooling and stacked bending tooling should be designed perfectly for the respective application.
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>>It becomes clear that the many pipe bends and the processes involved to produce a complete assembly can offer a tremendous potential for savings in plant construction – if ultimately, many of the in-situ welded bends could be replaced by pre-bent pipelines that are able to be fabricated to the exact specifications of the construction site.
Offshore World | 40 | December 2013 - January 2014
Moreover, a great deal of pipe can be saved with a small bending radius. The saving with a 180-degree bend and a bending radius of 1.5x D is around 3.5 metres compared with a conventional 5x D bend – on larger production facilities, this small value naturally offers a huge effect on cost reduction.
For an oil platform or refinery, hundreds of kilometres of pipes are installed – including countless pipe bends. Great cost savings can be achieved with pre-bent pipelines. Expensive welding and checking processes are no longer required.
Additional positive points of the cold bending process are: The pipe is clamped in an index head and held in place by means of a collet in the transpor t unit and index head. After the first bend, it is direc tly transpor ted for ward and rotated as required. As a result, three dimensional pipe systems can be created ver y quickly without a single weld joint. When the Bending Radius is Critical What is par ticularly impor tant in plant construc tion is the achievable bending radius of the pipe. Ideally, cold bending machines allow bending of pipe with ver y small radii, even when the pipes are ver y large and thick-walled. What does this mean in regards to plant construc tion and why is this charac teristic so impor tant? The critical advantage of the abilit y to produce a small radius becomes apparent when installing the pipe: the tighter the bend of the pipe, the less installation space is required – ultimately, the entire pipe system or platform requires less floor area.
Focus on Quality No matter what the specific structure of the machine, it should always be based on a very rugged machine frame, so that it reliably resists the huge forces that arise during bending and has abundant power reserves for the clamping functions. In addition, the issue of quality control is particularly impor tant in respect to reduction of the wall thickness or ovality. For example, an integrated measuring system such as the SpringMatic system by the German bending machine manufac turer Schwarze -Robitec can measure the pipe bend while still in the bending machine and correct its curvature as necessary. The measuring and correction process takes only a few seconds. As a result, even pipes with unknown properties or widely fluctuating quality can be processed directly with a high level of accuracy. Additional productivity in the bending process can be gained by stacked tooling with various nominal diameters constructed one above the other. If a new batch of pipes with a different nominal diameters are used in the production sequence then only the bending mandrel and collet insert need to be changed. Thus, setup times can be reduced to only a few minutes. Consequently, the current bending process is able to continue with unchanged speed and accuracy. Likewise, the processing of flanged pipes is unproblematic. For instance, the CNC-MW series from Schwarze-Robitec achieve minimal setup times due to the stacked tooling. Even before bending, the flanges or sleeves can be welded on. The sophisticated control of the machine and its stable structure ensure accuracy. The stable structure of the machine prevents twisting and the pipe therefore going out of specification, or the flanges ending up at the wrong angle. Naturally, the structure of these specialised machines is heavily dependent on the specific requirements of the customer. If necessary, production facilities should be integrated into existing manufacturing chains, in order to organise the production time and cost efficiently. sw
The Bending Tool (Information Box) Tooling and stacked bending tooling should be fit perfectly for the respective application. Ideally, the tools have automation components for special applications which allow ‘bend in bend’ processes which can be preheated or can process special materials. Further improvement of quality and precision in bending can be ensured by additional accessories such as bend formers, clamp jaws (for clamping the pipe), pressure dies (as a counterbearing for the bending moment to be applied), bending mandrels and wiper dies.
The machines allow bending radii that are only slightly larger than the pipe diameter.
Bert Zorn Managing Director, Schwarze-Robitec GmbH Email: sales@schwarze-robitec.com
Offshore World | 41 | December 2013 - January 2014
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features Energy Watch
Energy Commodities Continue to Exhibit Mixed Price Movement Energy commodities continued to exhibit mixed price movement in the past two months of November and December 2013. While, NYMEX (CME) natural gas futures prices rose the most by 18.1 per cent on high demand amidst freezing temperatures in US; CER (Carbon Emitted Reduction) futures prices on ICE-ECX platform continued to move down by dropping the most amongst energy commodities i.e. by 37.3 per cent (albeit with low prices base).
NYMEX (CME) crude oil (light sweet) futures started the month of November at USD 94.61 per barrel, down by 1.84 per cent from previous months close. Strong advances in the dollar against other currencies pressured the crude oil prices to start of the month with decline. Further, sustained rise in US crude oil production and hence availability of abundant supplies helped the declining trend continue in oil prices. Later, progress in talks between Iran and the west, potentially easing economic sanctions that included restrictions on Iranian oil trade added to bearish sentiments in oil prices.
overhang in US crude oil supplies and on potential pullback in the US Federal Reserve’s stimulus program. On a fundamental note, Saudi Arabia being a major producer and exporter of oil, dampened crude oil prices sentiments by substantially increasing its output. Moreover, in the fag-end of month of November, oil prices moved down to the eventual two month (November-December) low of USD 91.77 (on November 27) as the US and other western powers agreed to a short-term deal to curb Iran’s nuclear program. The pact fueled concerns that an easing of sanctions on the Middle Eastern nation’s crude sales will soon follow and add to the world’s supply.
Nevertheless, release of certain upbeat economic data releases such as better than expected US job growths number denied major fall in oil prices. However, overall prices continued to be in declining trend as market participants fret over the large
Crude oil prices then recovered from lows on data releases showing growth in the manufacturing sector in China, the Euro zone and the US, thus raising prospects for energy demand. Later, more upbeat releases showing improved balance in
Source: Bloomberg
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Offshore World | 42 | December 2013 - January 2014
industrial expansion and consumer spending helped the rally in oil prices. However, expectations that the US Federal Reserve would shortly announce the tapering of its stimulus restricted big rise in oil prices. Nevertheless, the steady declining trend in US crude oil inventories continued to provide support to oil prices. In the later stage of December, renewed political unrest as Libyan leader refused to reopen oil ports in the country fuelled supply concerns; thus adding momentum to rising oil prices. Supply concerns were also bolstered with the worsening of civil unrest in South Sudan. Meanwhile, market saw the Federal Reserve’s decision to taper its stimulus program as evidence of a strengthening economy, adding to the bullish sentiments in oil prices. Subsequently, NYMEX crude oil futures moved up to the two month (November-December) high of USD 100.75 on December 27. Finally, amidst thin trading interest owing to year-end holiday sentiments, NYMEX crude oil futures closed the month of December at USD 98.42, registering a rise of 2.1 per cent in the two-month period. On an annual basis, crude oil futures registered a rise of 7.2 per cent in 2013. The trend in crude oil prices was also reflected in crude oil’s two popular derivates i.e. heating oil and gasoline (on CME-NYMEX platform). While, heating oil futures registered a rise of 3. 7 per cent, gasoline futures prices moved up by 5.8 per cent in the two months of November-December. Compared to crude oil and its derivates, the other major energy commodity natural gas futures (traded on NYMEX-CME platform) witnessed big rise in its prices i.e. 18.1 per cent in the last two months of the year. In November, first weekly decline in US gas inventory levels, in the current heating season (Nov 21), followed by another such decline as well as lifting of US demand sentiments on cold weather forecast helped gas price rise. On the other hand, the rally in gas prices continued in December on consistently falling US gas inventory levels (through December) amidst freezing temperatures in US, which buoyed the gas demand outlook.In emission market segment on ICE-ECX platform, European Union allowances (EUA) futures stayed flat, registering a rise of just 1.0 per cent over two-month period.
In an attempt to revive the carbon market, the European Commission wants EU governments on January 8 to back a proposal to delay sales of 900 million tons of carbon allowances in 2014-16 before they are returned to the market at the end of the decade. The other commodity from emission market segment, CER futures prices continued to trade down, falling 37.3 per cent amid persisting uncertainty over global CER market. With only a handful of countries committing to national emissions targets for 2020, the market has been left in chronic surplus as CDM projects continue to generate CERs. Global carbon markets traded a total EUR 38.4 billion worth of allowances and credits during 2013, registering a 38 per cent decrease from the EUR 62bn the previous year, in a continuation of the decline that started after the market peaked at EUR 96bn in 2011. Lastly, ICE Rotterdam monthly coal futures prices moved down by 2.6 per cent in November-December period. Asian power producers especially China winding down its coal purchases after a period of pre-winter stockpiling and supply glut in physical market led to decline in coal prices. Overall, calendar year 2013 saw a decline in coal prices by about 10 per cent largely due to low economic growth in China and India – the two major coal importers in the world. sw (The views expressed by 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 | 43 | December 2013 - January 2014
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news features
Transnational Pipeline Diplomacy India’s domestic natural gas production has been significantly growing for last few decades from 31.76 BCM in 2004-05 to 48 BCM in 2011-12. Also, with introduction of term LNG the gross natural gas available for usage has doubled from 2004 to 2012 to 66.01 BCM. Despite having vast natural gas reserves, the mounting consumption drives Indian energy sector to seek alternatives to domestic natural gas reserves. Some of the alternate solutions are increase LNG trade or development of LNG terminals, transnational piped natural gas supplies from our neighboring countries. One such option, which India has been considering for a long time is transnational gas pipeline. There are three transnational pipeline which are currently in talk are TAPI, IPI and MBI. Though all these pipelines were proposed at a very early stage, but still none of the project has actually kick started, except for TAPI which seems to be turning into reality by 2017. The other two projects are caught between various problems like geopolitical, socio-economic and policies issues. The paper briefly describes all these problems and how it will impact the future of Indian Natural Gas Industry.
There has been a significant development in Indian Natural Gas Industry for last few decades. With major gas discover y in KG basin by Reliance Industr y, India’s produc tion of natural gas has almost doubled from 31.76 Billion Cubic Meter (BCM) in 2004-05 to 48 BCM in 2011-12. Also, with introduction of term Liquefied Natural Gas (LNG) the gross n at u ra l g a s ava i l a b l e f o r u s a g e h a s d o u b l e d f ro m 2 0 0 4 to 2 0 1 2 to 66.01 BCM. In spite of growth in the production, the demand for natural gas has been growing at a relentless pace and is expected to do so in the future as well. The share of natural gas in India’s energy basket is expected to grow from 10 per cent to 25 per cent by 2025. The two major consumers of natural gas are power sector and fertilizer sector. Nearly 70-75 per cent of the domestic production is allocated for these priority sectors, and the remaining gas is
allocated to non-priority sector like Domestic, Tea plantation, Sponge Iron Petrochemical, Industrial fuel, LPG shrinkage etc. As per the 12th five year plan, there will be significant increase in terms of investment in both power and fertiliser sector. Low price of coal makes it a preferred choice for power generation in India, however environmental concern exist in coal-based power plants and this is coercing to move towards natural gas and other greenfield projects. Hence, Natural gas is expected to be a preferred energy source in near future. The next biggest consumer of natural gas after power and fertilizer is City Gas Distribution (CGD) and by 2016-17 the natural gas required for CGD is around 47 mmscmd, which is a significant amount. These three sectors alone will constitute more than 70 per cent of total demand.
Source: KPMG “Report on Indian Oil and Gas Market
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Offshore World | 44 | December 2013 - January 2014
Sector-wise Gas Demand Projection 2012-2017 in MMSCMD Sector
2012-13 2013-14 2014-15
2015-16
2016-17
Power
91
92
102
132
139
Fertilizer
56
79
79
80
81
City Gas
15
19
24
39
46
Industrial
20
20
22
25
27
Petrochemical/ Refineries/ Internal consumption
54
61
67
72
72
Sponge Iron/steel
7
8
8
8
8
Expected Total Demand in MMSCMD
243
279
302
356
373
Expected Total Demand in BCM
88.69
101.82
110.22
129.93
136.13
Source: Infraline Energy
Despite having natural gas reserves, the mounting consumption drives Indian energy sector to seek alternatives to domestic natural gas reserves. Some of the alternate solutions are increase LNG trade or development of LNG terminals, transnational piped natural gas supplies from our neighboring countries. India’s primary energy consumption is likely to change by 2025 and natural gas is going to contribute significantly to India’s primary energy basket. The figure below gives an indication of Indian Primary Energy sources by 2025. Demand-Supply Scenario of Natural Gas Indian natural gas production will be growing at a steady pace with a Compound Annual Growth Rate (CAGR) of 10.6 per cent, while LNG import is expected to grow at CAGR of 16.2 per cent. This growth rate is optimistic, considering the fact that the proposed LNG terminals will be operational by 2014. On contrary, the domestic output is expected to grow at a CAGR of 7.02 per cent, which is a fairly modest estimate, considering the fact that the KG-D6 production has fallen and was estimated to produce 80 mmscmd of gas. With BP and reliance JV, the output is expected to increase. Though the supply
is growing at steady pace, the demand is growing at a CAGR of 8 per cent. Even if we consider the most conservative estimates, supply-demand mismatch is likely to be high. The three major sectors Power, fertilizer and CGD, will contribute up to 70 per cent of the total demand. With the current demand level, fertilizer would require 22 per cent from Regasified Liquefied Natural Gas (RLNG) and power would require 27 per cent from RLNG by 2016-17. Declining domestic supplies and lowered supplies imposed by government drive power producers to depend on RLNG. However, RLNG is an expensive option, escalating the overall power production costs, which in turn will impact consumer. India’s Transnational Pipeline Policy With such high demand for natural gas India will have to consider alternate sourcing options from other energy rich nations and develop a robust infrastructure, for transportation of natural gas. One such option, which India has been considering for a long time is transnational gas pipeline. There are three transnational gas pipelines which are currently being considered. ◆ TAPI (Turkmenistan-Afghanistan-Pakistan-India) Gas Pipeline project ◆ IPI (Iran-Pakistan-India) Gas pipeline projects ◆ MBI (Myanmar-Bangladesh-India) Gas pipeline project For long India has been working towards converting its transnational pipeline into reality, in order to secure its energy security. With China aggressively pushing their energy needs from the Central Asian Region by tapping gas from Turkmenistan, it is mandatory for India to take giant leap, in terms of policy and convert their transnational pipeline into reality. It was noted that, India is very keen in TAPI pipeline and is pushing aggressively this 7.6 billion pipeline project and make it operational by 2017. While Asian Development Bank (ADB) has already been appointed as the transaction advisor, the consortium leader is yet to be finalised. The four nations are looking at international reputed firms who have experience in building and operation of cross country pipeline, but no international pipeline company is ready to implement the project unless Turkmenistan gives a share in its gas fields. Turkmenistan, which does not give stake to any foreign company, has flatly refused to give any interest in the upstream project to any international pipeline companies. While several financial institutions have expressed their interest to finance the project, no pipeline company has come forward to take up such challenging project for more than a year now. In considering the Iran-Pakistan-India pipeline, this was considered to be more close to realty than TAPI pipeline, considering the fact that the geopolitics has changed between India and Pakistan, the pipeline projects doesn’t look like happening. The pipeline passes through more of Pakistan than does TAPI; moreover it runs through the troubled regions of
Source: Infraline Energy
>>Indian natural gas production will be growing at a steady pace with a Compound Annual Growth Rate (CAGR) of 10.6 per cent, while LNG import is expected to grow at CAGR of 16.2 per cent. This growth rate is optimistic, considering the fact that the proposed LNG terminals will be operational by 2014. Offshore World | 45 | December 2013 - January 2014
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>>If India needs to be self-dependent in its energy needs, then it will have to take a quantum leap in its energy policies and will have to come up with alternate sourcing options fulfill its demand. India will have to make its transnational pipeline projects into reality, this will not only boost India’s economy but will also open up new trade relationship between those countries involved in the projects. Baluchistan, where some Baluchs feel discriminated against the Punjabi dominated administration. Pakistan’s dilemma is that the Iranian section of the pipeline (Over 900 km) is almost complete, but no work has commenced on the 780 km segment on its own soil, Pakistan has to pay USD 3 million per day as penalty. Pakistan’s fundamental issue is financing the project though there are other issues as well. Saudi Arabia is not happy about any Pakistan Iran links. India would for sure want a guarantee for uninterrupted supply of gas, with penalties for stoppage. Moreover the US is backing the TAPI pipeline as an alternative to the IPI pipeline in its efforts to stop Iran from Oil business, the money from which is suspected to aid nuclear weapon program. US never pressured India to drop IPI, yet India decided to pull back the project as it saw a stumbling block in the Iran Libya sanction act, though the law was never invoked. Due to Iran’s Isolation, the IPI lost its appeal. The Myanmar-Bangladesh-India (MBI) pipeline has been a victim of regional geopolitics and political constraints between India and Bangladesh. The 900 km pipeline was first proposed in the year 1997 and was set to deliver 5 BCM of gas from the Swe field in Southern Myanmar to West Bengal via Tripura, Mizoram and Bangladesh. Sixteen years later the pipeline remains nothing but a dream and is showing little signs of becoming a reality. The MBI project came to a standstill in 2005 after Bangladesh put forward precondition that were unacceptable to India. Bangladesh’s demand was mainly attributed to two main factors, the first being the gross overestimation of its domestic gas reserves, with estimation of 2 tcm of gas the government did not see the necessity of the pipeline in 2005. Second the BNP led coalition government that was in office at that was vocally anti-India and thus had its hesitation in collaborating with India. Although there has been significant improvement in India-Bangladesh bilateral relations since 2009. India must be cautious of Bangladesh’s ambivalence on energy cooperation, if there is a change in government during the upcoming elections. India must be prepared to go alone and re-route the pipeline through Mizoram, Tripura and Assam into Kolkata. With the Kaladan Multi-Modal Transit Transport Project slated to be completed by 2015, there is feasibility of building a pipeline up to Mizoram. The Kaladan project is a combination of inland water way and highway transportation system that will connect Mizoram to deep sea port of Sittwe in Western Myanmar. Despite many challenges, India is trying hard to push its dream of transnational pipeline into reality, thereby becoming self-sufficient in their energy needs. With China taking a big leap in securing its energy demands by tapping into every possible natural gas resource in and around it, if India needs to be www.oswindia.com
self-dependent in its energy needs, then it will have to take a quantum leap in its energy policies and will have to come up with alternate sourcing options fulfill its demand. In order to have a strong economic growth, India will have to make its transnational pipeline projects into reality, this will not only boost India’s economy but will also open up new trade relationship between those countries involved in the projects. Challenges for the Development of Transnational Pipeline Socio-Economic Challenges: This is a very significant factor and plays a very vital role in the initial development of the pipeline projects. As the pipeline traverse through some of the most difficult regions of the countries, were people have different perceptions, acquiring land for the ROU will be a daunting task. Many regional and political leaders have to be taken into confident, by explain the social and economic benefits of the project, that will brought to their country, by executing it. Security and External Threats: As most of this pipeline passes through the troubled regions of Iran, Afghanistan, Pakistan and Baluchistan, were most of the terrorist activity are prevalent, it would be easy for them to disrupt the supply, for their own vested interest and thereby depriving the country’s most essential energy need. During the construction phase, the employees of the international companies involved in the project will have to be protected from any such attack by the militants. Political Challenges: As many nations are involved in such kind of projects, government agencies and political leaders will play a crucial role in deciding the fate of the project. In lieu of the project, such leaders can put forward some demands which could be unfair and could create rift between the two countries and could affect the timeline of such projects. Sanctions and Embargo: Most of the countries involved in the projects are very unstable in their activities. In order to protect world peace, US usual invoke sanctions and embargo on such nation, suspecting that the money generated from the selling of gas trade might be used for nuclear armament. This will hugely impact the project star tup and the project might even be suspended. sw
Mahesh Radhakrishnan Senior Research Analyst Beroe Inc Email: mahesh.radhakrishnan@beroe-inc.com
Offshore World | 46 | December 2013 - January 2014
news features
Breaking Barriers of Traditional Plant Modelling Traditional plant modelling has quickly evolved in the last years from 2D to 3D tools. The use of 3D plant design tools is already a logical choice for most medium- and large-sized engineering companies. The business benefits are so significant – shorter design process and better and safer design quality – that carrying out plant design without it just does not make sense anymore. However, capturing intelligent as-built data to create intelligent 3D models of existing plants still used to be a challenge. Executives from Intergraph Process, Power & Marine (PP&M), the leading global provider of engineering software for the design, construction, and operation of plants, ships, and offshore facilities, visited India to share the latest developments in plant design and engineering data management. Philippe Marceau, Executive Vice President EMIA, Intergraph PP&M, and Patrick Holcomb, Executive Vice President, Global Business Development, Intergraph PP&M, recently visited Mumbai for a technical conference jointly organised by Intergraph and Rolta to promote Intergraph’s consolidated design software solution – Smart 3D™ 2014 – that will help chemical, oil and gas and allied process companies model and operate complex structures and create automated engineering deliverables. According to Marceau, technology trends have constantly evolved in tandem with the changing societal and business trends. Manufacturers face the challenge of bringing the products faster into the market at most competitive prices, dealing with complex product mixes and achieving operational excellence; while engineering companies try to help by reducing plant schedules and bringing plants into operation as quickly as possible. Inexorable global demand for capacity expansion for chemicals, use of raw feedstocks in production, complex product mixes and bringing new plants online quickly are some of the major challenges for both manufacturers and the engineering companies in the current times, adds Holcomb. “As a global trend, but also in India, industries are required to share complex engineering information to speed up project completion and ensure operational efficiency in order to achieve faster turn-around times and reaching new products to the market,” he says. The additional challenge of achieving operational excellence mandates high levels of design integrity, innovation and design quality, which puts the engineering industry in a very tight spot. “Intergraph has supported India production facilities for the past 27 years, via our partner Rolta and directly, to improved their design quality and data processes and become more efficient and productive”, Holcomb says. “For any typical engineering project, 10-15 per cent & 50-60 per cent cost are directed toward engineering design & materials, respectively. Though the cost of engineering in terms of numbers is lower, this is the heart and soul of the plant decides the entire lifecycle of a process plant. It has been almost two decades since the industry moved from conventional 2D design to 3D design. Smart 3D is the future that can easily respond to the needs of the engineering contractors through engineering excellence and further enable the plant owners to achieve operational excellence”, he says. Intergraph has always stressed the importance of 3D modelling and visualisation solutions and has been offering the same for various industrial applications. The Smart
3D solution has many new features that would not only help the engineering contractors at all stages of project management until commissioning, but also ease out the whole process of handing over the project to the owner. Holcomb says that 3D modelling and visualisation solutions support all the key aspects of project execution for the chemical industry, from conceptual plant design, through detailed design and construction, into plant operations and maintenance. “And we are here to launch the new generation module of smart plant design that supports the integrated design and manufacturing environment,” he comments. Speaking about the challenge of on-time project delivery, Holcomb deliberates regarding Intergraph’s new solution that effectively enables the engineering consultants on three key aspects of optimised design, increasing productivity and shortening productivity schedules. He says, “Project execution is no longer confined to single contractor but executed by multiple contractors working from across the globe for whom maintaining consistency is the one of the issues that one may realise only when the plant is at the commissioning stage.” This problem usually occurs due to inconsistencies in engineering schematics, such as projects’ piping, instrumentation and P&ID, which are the most critical elements of any process plant, designed at the initial design stage, he explains further. Such inconsistencies can have catastrophic effects on any project that can result in major time and cost overruns. “We have addressed this issue already as multiple EPC players working on different units for the common project are granted access to a common system that enables them to overcome this hurdle at the very initial stage and completely rule out such risk; and enable smooth integration of all the units at the time of commissioning of project,” Holcomb emphasises. FEED and detailed engineering are very time-consuming because of the amount of detailing that is involved, in terms of massive data that usually is mostly entered manually. Any kind of rectifications in the data that are carried often out result in the loss of old data, which usually gets deleted automatically once replaced and may eventually lead to a major problem at any further stage of project execution. Intergraph engineers have programmed the solution in such a way that any changes made to the basic data can be easily tracked back and the data can be reused if it is accidentally replaced or lost. Holcomb enunciates, “The EPC industry recognises procurement and construction as the high-profit high-risk area, where any kind of mismanagement in supplies can actually burn deep holes in the pockets of the contractors.” Especially in the current times, when most of the contractors procure the materials globally, the contractors are compelled to use strong vendor management programs to keep track of deliverables to meet the project completion deadlines. Intergraph’s Smart 3D solution has a centralised database management system, which allows the suppliers to enter the status of the deliverables that simplifies the rather complex process of vendor management through e-mails and curbs the risk of losing any information which can otherwise result in project delays thus leading to huge losses for the engineering services providers. sw
Offshore World | 47 | December 2013 - January 2014
- Mittravinda Ranjan
www.oswindia.com
>>According to Marceau, technology trends have constantly evolved in tandem with the
news features
‘Development of LNG infrastructure is critical for economy growth’
G Sathiamoorthy, Country Head and Managing Director, Black & Veatch, speaks to Mittravinda Ranjan on the rationality behind setting up LNG Regasification Terminals in India and its positive impact on the EPC Industry. www.oswindia.com
Black & Veatch is a dominant player in the field of power sector and has significant presence in hydrocarbon industry especially in the field of LNG liquefaction, regasification and natural gas processing. The company enjoys privilege of being one of the key players for setting up sulphur recovery and tail gas units for the downstream refining industry. “We have completed the sulphur recovery units and accompanying tail units at the Jamnagar facility of Reliance and also licensed BV technology for IOCL’s Paradeep refinery,” says elated Sathiamoorthy.
ment. He emphasises on the increasing availability globally due to phenomenal success of development of shale gas assets in the USA, which has been a game changer for the hydrocarbon industry. The USA is now gearing up to become net exporter of shale gas and setting up LNG liquefaction terminals along the East coast to become the net gas supplier. “In fact, we are engaged in some of the gas liquefaction projects in the USA, but in case of India, it would only be regasification terminals due to low indigenous gas production,” he shares.
Last eighteen months have been extremely difficult for the industry as many projects have been delayed or deferred. However, there are positive vibes from the government over the last couple of months. “We had disappointing GDP in the last two quarters, and if the economy has to perform, development of infrastructure is critical,” Sathiamoorthy articulates. He laments about the policy climate that has adversely affected the investment climate in India and lack of availability of projects in the Indian market, but it seems he is highly optimistic about the future of the projects in the country. Recent announcement by the government regarding debottlenecking of power plants will build the confidence of industry in the Indian market, he notes.
India’s existing LNG capacity cannot suffice to the need of India’s energy requirement. Currently, the Indian hydrocarbon players are establishing linkages to meet the growing energy demand that will necessitate the need to set up LNG terminals in the country. Sathiamoorthy further elucidates, setting up terminals along the East coast make a lot of sense, and once these projects are realised, supplies can be started easily. India already has a good network of gas pipelines; few more spur lines may have to be added to streamline the gas availability for critical industries such as power and fertilisers projects, which have been in a limbo for a very long time due to challenges in availability of gas.
According to Sathiamoorthy, Indian government has received a lot of feedback from the international E&P players regarding policies, but now it is taking a softer stance to attract investments towards monetising country’s hydrocarbon assets. “I feel this is going to take some time. On the other hand, gas production is not picking up in India as envisaged through some of the existing major projects. Though the E&P players are still upbeat and optimistic about the finds in India, it may not be enough to meet the country’s demand,” he adds. Advocating the idea of setting up LNG terminals along India’s coast line, he says that these terminals can be set up in a time of 3-4 years, which is very less compared to the cost intensive oil and gas field developOffshore World | 48 | December 2013 - January 2014
He comments, “Everyone has been very pessimistic about the EPC sector, but if you see investments are happening in refining sector and many projects will be on stream in next couple of years.” Despite high dependency on feedstock imports, it makes complete sense for Indian refining sector to expand since most of production is targeted for exports and there is a significant demand upsurge of refining products in the domestic market. As a part of Vision 2020 for BV intends to increase the revenue from current USD 3.3 billion to USD 7 billion, and India is expected to contribute 7 per cent to the company’s global revenue. Sathiamoorthy is leading a team of around 420 people spread across two locations in Mumbai and Pune and aims to make a big leap in the years to come. sw
news features
Iranian LNG Export Outline The paper explores the current projects of Iran’s Natural gas export statistics through LNG routes to regional and global markets.
Overview of LNG Projects Project Name
Project Executor
Project Shareholders
Project Objectives
Feed & Field
Gas Export through LNG Persian LNG Co ( Pars LNG Project)
NIGEC representing NIOC (50%), 10 MT LNG production an annum Total Co (40%), Petronas (10%)
Phase 11 of South Pars Gas Field
Gas Export through LNG Persian LNG Co (Persian LNG Project)
NIGEC representing NIOC (50%), Shell 16.2 MT LNG PRO production an Phase 13.14 of south Pars Gas Field Co (25%), Repsol Co (25%) annum within two trains (The phases may be subject to change in view of NIOC Plans so as to expand the South Pars phases)
Gas Export through LNG Natural Iranian Gas Liq- NIGEC representing NIOC (49%); Pension 11 MT LNG production within two Sour gas extracted from South Pars (Iran LNG Project) uefaction Co (Iran LNG) Fund, Saving and Welfare of Oil industry trains Phase 12 staff Co (1%); Remissible stocks to LNG buyers and investors (40%) Gas Export through LNG Malaysian Petrofild Co Malaysian Pertofild 100% investment
Golshan&Ferdowsi field expan- (Golshan & Ferlowsi LNG Project) sion and 10 MT of LNG production within two trains
Gas Export through LNG ( Chinese CINOOD Co North LNG Project)
North Pars Field expansion and 20 MT North Pars gas field of LNG production within 4 trains
Chinese CINOOK 100% investment
Iran LNG Project Iran LNG project aiming at establishing a liquefaction plant for natural gas is well underway in Tombak, 50 km NW of Asaluyeh and 15 km SE of Kangan-pars 2 (Tombak). This project comprises two phases those of feasibility and execution. The latter phase is underway within two trains each of which has one liquefaction unit. The capacity of each liquefaction unit is nearly 5.5 million tons annually. South Pars Gas Field, Phase 12 provides the feed gas for this plant and the German Linde Co undertakes the liquefaction technology. Current Shareholders NIGEC Saving, Welfare & Pension Funds of petroleum Industry Petroleum Industry Pension Fund Ready for Investors Future Shareholders
49% 10% 1% 40%
NIGC & Saving, Welfare & Pension Funds of Petroleum Industr y Investors
20% 80%
Upstream Responsible: Pars Oil & Gas Co (POGC) Midstream Responsible: National Iranian Gas Export Company (NIGEC) , Applicant investor companies: OMV, Eon, Enel, Enbw, Econgas
Main Train Figures Feed gas
27 MM3/Day
LNG Production
5.5 MTPA
Propane Production
0.26 MTPA
Butane Production
0.196 MTPA
Condensate Production
0.21 MTPA
Sulphur Production
0.133 MTPA
Plant Main Characteristics Liquefaction Technology
Linde
Mercaptan Removal
Gas Phase (Molecular Sieve &Lurgi Purisol)
Compressor Driver
Electric Motor
Sulphur Recovery
Lurgi Oel-Gas-Chemie GmBH (Claus Provess)
Acid Gas Removal
BASF (AMDEA) through Lurgi Oel-Gas-Chemie GmBH
Cooling Medium
Hybrid-Sea Water & Air
Heating Medium
Steam
Power Generation
Combined Cycle Power Plant (1000 MW)
LNG Tanks
3 Full Containment Tanks, Each 140.000 m 3
LPG Tanks
2 Full Containment Tanks, Each 30.000 m 3
Offshore World | 49 | December 2013 - January 2014
www.oswindia.com
>>Pars LNG project is deemed to annually produce 10 million tons of LNG for which the daily input gas of the plant is nearly 46 million tons of sour gas supplied by South Pars Gas field, phase 11; whereas Persian LNG project is made up of two phases, including two units for sweetening and condensation extraction and one unit for LNG production. Pars LNG Project This Projec t is deemed to annually produce 10 million tons of LNG for which the daily input gas of the plant is nearly 46 million tons of sour gas supplied by South Pars Gas Field, phase 11. There are two 32-inch pipelines through molecular sieve and demercurization, it will get refrigerated and liquefied by Axens technology. After wards, the produc t will be stored in t wo tanks each of which to 155000 m 3 of capacity and then marketed by LNG ships from the jetty. It is
notewor thy that, a 1000 MW power plant utilising gas turbines with the method that of combined c ycle will provide the power required for the project. Plant Main Characteristics/Train: Feed gas 46 MM / Day
H 2 S Cntent: 0.4%-0.9% Nitrogen: 3.5%-4.5% Mercaptan: 400 ppm
Current Shareholders NIGEC
50%
TOTAL
40%
PETRONAS
10%
CO 2 Content: 2.3%-2.5% Other Hydrocarbons: 8%
Project Specification
LNG Production
5 MTPA/Train
Propane Production
179 KTPA/Train
Butane Production
212 KTPA/Train
Location
50 km North West Assaluyeh,Tombak Village
Condensate Production 3400 BODP/Train
Feed Stock
Supplied From South pars field - Phase 11
Sulphur Production
77 KTPA/Train
Liquefaction Units
2
Project Start up
2001
Production
10 MT/Year by 2 Train
LNG Delivery Start Date 2013
Executing Agency
Pars LNG
Liquefaction Technology
Axen
The Iranian Local Content for construction of NIOC LNG Project Shall not be Less than 51%
Persian LNG Project Persian LNG Project, in pursuit of the establishment of a liquefaction plant for natural gas, is well underway in Tombak region, 50 km NW of Asaluyeh and 15 km SE of Kangan-Pars 2(Tombad). This project is made up of two phases. The first phase includes two units for sweetening and condensation extraction and one unit for LNG production. In the second phase, one more
unit that of sweetening and condensation extraction and one more for LNG Production will be added. Each LNG production unit is expected to annually meet 8.1 MT of production (16.2MT in total). South Pars Gas Field, phases 13 and 14 will provide the feed gas of the project which will daily totaling 78 MM3. Plant Main Characteristics
Current Shareholders NIGEC
50%
Liquefaction
Shell – Double Mixed Refrigrant (DMR) process
SHELL
25%
Mercaptan Removal
Sulfinol – D/Molecular Sieve
REPSOL
25%
Compressor Driver
SCOT
Sulphur Recycle
Electric Motors With Variable Speed
Power Generation
1200 MW Combined Cycle Power Plant Concept Providing Heat and Power
Acid Gas Removal
Sulfinol-D
Main Figures for Each Phase of Development: Items
Train one
Train two
Feed Gas Amount MM 3/Day
52
78
LNG Production MTPA
8.1
16.2
Heating/Cooling Medium Steam/Air Cooling
Propane Production MTPA
0.67
1
LNG Tanks
3 Full Containment Tanks , Each 160.000 m3 For 2 LNG Trains
Butane Production MTPA
0.37
0.56
LPG Tanks
Domestic Gas Production MTPA
3.1
0.2
2 Full Containment Tanks , Each 65.000 m For Butane and 105.000 m 3 for propane
Condensate Production MTPA
0.29
0.43
www.oswindia.com
LNG Delivery Start Date 2014
Offshore World | 50 | December 2013 - January 2014
>>Both North Pars Project and Golshan & Ferdowsi Projects based upon buy back with a 7-year refund through the sale of the fields’ gas and by-products. North Pars Project is being developed North Pars phase with 52 TCF of gas reserves in SE of Boushehr while Golshan & Ferdowsi Projects is firstly intended to develop Golshan and Ferdousi Gas Fields in SE of Boushehr is expected to bring an LNG plant to produce two trains each of which gas 5 MT of annual capacity. North Pars Project This Project based upon a barter and a counter purchase with a 7-year refund is after developing North Pars phase with 52 TCF of gas reserves in SE of Boushehr. The would be gas from this phase will be put to use for LNG production in a plant to be constructed by Chinese CNOOC Co in Tombak region in 2013.
Current Shareholders
Th i s p l a nt co m p ri s e s 4 t ra i n s e a c h o f w h i c h i s 5 MT o f ca p a c i t y totaling 20 MT. Half of the produc t belongs to NIOC for a 25-year tem and CNOOC will pay NIOC the cost of the remaining gas upon the agreement concluded.
Location
Tombak Port, South East Bushehr
Gas Field
North Pars Gas Field
No trains
4
Production MT/Year
20
NIGEC is to sell CNOON the feed gas on behalf of NIOC. All the equipment will be ceded to NIOC after this 25-year term.
CNOOC 100% • Based on agreements instead of tolling fee half of LNG production belongs to NIOC • Plant ownership will be delivered to NIOC often 25-year time
Agreement Duration (Between Iran &China) 25 Years Feed Gas Amount MM3 /Day
113.3
Project Start Date(Negotiation)
2006
Production Start Date
2014
Golshan & Ferdowsi Projects This project, based upon buy back with a 7-year refund through the sale of the fields’ gas and by-products is firstly intended to develop Golshan and Ferdousi Gas Fields in SE of Boushehr. Secondly this project is expected to bring an LNG plant into being through the investment of Malaysian Petrofield Company so as to produce two trains each of which gas 5 MT of annual capacity. Half of the product belongs to NIOC for a 25-year term, and Petrofield will pay NIOC the cost of the remaining gas upon the agreement concluded. NIGEC is to sell Petrofield the feed gas on behalf of NIOC. All the equipment will be ceded to NIOC after this 25-year term.
Current Shareholders SKS 100% • Based on agreements instead of tolling fee half of LNG production belongs to NIOC • Plant ownership will be delivered to NIOC often 25-year time Location
Tombak Port South East Bushehr
Gas Field
Golshan & Ferdowsi Gas Field
No trains
2
Production MT/Year
10
Agreement Duration (Between Iran & Malaysia) 25 years Feed Gas Amount MM3/Day
56.7
Project Start Date
2007
Production Start Date
2015
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 Offshore World | 51 | December 2013 - January 2014
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news
India Gas Price Hike to Boost Domestic Gas Output: Moily New Delhi: The decision to almost double the natural gas pricing, which is likely effective from April 2014, will persuade the investment sentimental in exploration and production in the country, in order to reduce its oil import dependence, said Veerappa Moily, Petroleum and Natural Gas Minister. On the sidelines of the AIMA’s 3rd PSU Summit in New Delhi, Moily justified the gas hike in saying that if you don’t raise gas price, no domestic production will come and dependence on imports will increase. You need to spend a lot of money on technology and research to access the hydrocarbon.
Pull out Continues from Indian Oil and Gas Blocks New Delhi: Another pullout from Indian oil & gas blocks in the close on the heels of mining giant BHP Billiton deciding to quit India, as Santos, Australia’s third-largest oil and gas producer, seeks to exit its two oil and gas exploration blocks in Bay of Bengal due to delays in getting approvals to start work. It offered to surrender the blocks NEC-DWN-2004/1 and NEC- DWN-2004/2 on which it has already spent USD 60 million. Santos was awarded two blocks south-east of Kolkata in February 2007 that lie close to Bangladesh border, in the 6th round of New Exploration Licensing Policy. Santos has written to the government saying it has not been able to carry out exploration in the area because of defence restrictions and maritime boundary dispute with Bangladesh.
OilMin Seeks 75% Oil Cess for Developing the Sector New Delhi: India’s Oil Ministry has insisted the Finance Ministry to provide 75 per cent of its cess collected annually from the ministry to the Oil Industry Development Board (OIDB) for developing the oil sector in the country. But the Finance Ministry is reluctant to part with the cess because of its huge share on oil subsidy bill. As per report, the oil industry has paid over ` 118,500 crore cess on the output of crude oil and natural gas in three decades, but not even 1 per cent of this could be utilised for developing the sector. The note for a parliamentary panel said the government has paid only ` 902 crore to the Oil Industry Development Board (OIDB) since its inception in 1974.
More Gas Prospect in Ravva Block Jaipur: Cairn India, the largest independent oil and gas exploration and production companies in the country, and its joint venture partners in Ravva block in the east coast have discovered a new prospect in the existing fields. The new area is expected to see hydrocarbons flow in the next three-four years. According to estimates, the LO-110 prospect holds 368 billion cubic feet (10 billion cubic metres) of ‘recoverable gas’ and 16 million barrels of ‘condensate’, which is similar to light stabilised crude oil and used as feedstock for oil refining and other petrochemical industries.
Moily was of view that giving higher gas price will help bring to production over 3 trillion cubic feet of gas reserves that had been declared economically unviable at current price of USD 4.2. Several gas discoveries of firms like state-owned Oil and Natural Gas Corporation (ONGC) as well as of RIL had been declared unviable by the Directorate General of Hydrocarbons (DGH) as the current gas price of USD 4.2 per mbtu was inadequate to cover the cost of production.
RIL to Sell D6 Gas at Higher Price Mumbai: The Cabinet Committee on Economic Affairs (CCEA) has approved the Petroleum & Natural Gas Ministry’s view that RIL be allowed to benefit from the revised gas price effective April 2014, in return for a bank guarantee for the unmet supply commitment from its KG-D6 block. The Finance Ministry, which had earlier expressed reservations on allowing RIL sell KG-D6 block gas at higher price, recently given an in-principle nod to the Petroleum & Natural Gas Ministry’s proposals.
HPCL to Set up Refinery at Kakinada or Nakkapalli Hyderabad: Hindustan Petroleum Corporation Limited (HPCL) in association with Gas Authority of India Limited (GAIL) is mulling to set up a petrochemical complex with a Greenfield refinery either at Kakinada or Nakkapalli with a total investment of USD 8 billion. The state-owned oil and natural gas company has conveyed to the Andhra Pradesh government that it would need around 5,000 acres of land for establishing the project in the Visakhapatnam-Kakinada Petroleum, Chemicals and Petrochemicals Investment Region (PCPIR). HPCL is also contemplating in expanding refining capacity at its Visakh Refinery from 8.3 to 15 million tonne with an investment of ` 12,000 crore subject to clearance from the Ministry of Environment and Forests and other agencies.
Iran Backs Deep-sea Gas Pipeline to India New Delhi: Iran is focusing on exporting natural gas to India along a deep-sea route — the move coinciding with the cancellation of a loan to Islamabad to build the Pakistani section of the Iran-Pakistan gas pipeline and the signing of the Geneva nuclear accord that could help relax sanctions against Tehran. Iran’s interest in the India-centric project coincides with the cancellation of its USD 500-million loan to Pakistan to build part of a pipeline to funnel natural gas. India’s South Asia Gas Enterprise Pvt Ltd (SAGE) had conducted feasibility studies for the multi-billion-dollar undersea pipeline, which could carry gas from Iran’s giant South Pars gas field to India’s west coast. The project cost estimated by the company was USD 4-5 billion. Once operational, it could channel 31 million cubic meters of gas per day.
Offshore World | 55 | December 2013 - January 2014
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Pipeline Trouble at New Paradip Refinery Bhubaneswar: Indian Oil Corporation’s ` 30,000-crore Paradip refinery, which is jacking up its costs and hitting its already strained finances due to a four-year delay in securing the forest clearance for the for the 1,100-km pipeline to transport products to consumers in eastern parts of the country, has faced another hurdle for laying the pipelines.
to consumers and sales outlets. The PSU posted a steep 82.5 per cent annual drop in net profit for the July-September quarter to ` 1,684 crore following forex losses and receipt of incomplete compensation from government for under-recoveries on sale of subsidised petroleum products.
The cash-strained refinery has now necessitated the issue of fresh tenders for laying long segments of the pipeline. Until this crucial infrastructure is in place, the state-run company will have to rely on the more expensive railway network and roads to transport fuels from the sophisticated refinery
The proposed Paradip-Ranchi-Raipur pipeline, which was earlier expected to be ready by September 2012, is designed to extend across the states of Orissa, Chhattisgarh and Jharkhand and transport petroleum products such as LPG, naphtha, petrol kerosene and diesel in the eastern parts of the country.
Oil-Rich Nigerian Province Seeks Indian Investment India to become Largest Oil Demand Growth New Delhi: The newly created Nigerian province, after 2020: IEA which holds 40 per cent of the country’s known oil reserves, has sought investment from Indian hydrocarbon industry. Henry Seriake Dickson, Governor of Bayelsa, a state in southern Nigeria, said that Bayelsa has various opportunities that are suitable for Indian companies Henry Seriake Dickson, Governor of Bayelsa & investors and we want them to invest in the state, on the sidelines of the Economist African High Growth Markets Summit. Bayelsa, located in the Niger Delta region of southern Nigeria, was created in 1996 after splitting Rivers state. It is the country’s largest oil producing state, contributing 40 per cent of total crude production and 60 per cent of gas. It has the nation’s largest gas reserves, exceeding 18 trillion cubic feet.
India’s Oil Reserve Buffer in Expansion Mode
Maria van der Hoeven, Head, IEA
New Delhi: India will become the largest single source of global oil demand growth after 2020, said the International Energy Agency (IEA). The agency said that the centre of gravity of energy demand is switching decisively in favour of emerging economies, particularly China, India and the Middle East, which drive global energy use one-third higher, on the sidelines of its Annual World Energy Outlook.
IEA said that China may dominate the picture within Asia, before India certainly takes as the principal engine of growth. The shifting geography of demand is further underlined by India becoming the largest single source of global oil demand growth after 2020. On the sidelines of the 8th Asia Gas Partnership Summit, Maria van der Hoeven, Head, IEA, said India’s energy demand will double by 2035 on back of economic growth and rise in population.
Mangalore: India’s strategic oil reserves capacity, now has 70 days of oil reserves in various strategic locations, is likely to set for additional 45-day buffer as the second phase of cavern storage facilities is in line. The three oil caverns - at Mangalore SEZ and Paddur near Udupi and Visakhapatnam - of Indian Strategic Petroleum Reserves Ltd will be added a 15-day buffer each and are set to operational by August 2014. The second phase of strategic oil reserves for which a detailed project report has been prepared will be set up at Bikaner in Rajasthan, Padur near Udupi in Karnataka, Rajkot in Gujarat and Chandipur in Odisha. While facilities at Bikaner, Padur and Chandipur will be underground rock caverns, the facility at Rajkot will be concrete cavern. These proposed facilities put together can store around 12.5 million tonnes of reserve crude and oil products.
IEA’s World Energy Outlook 2013 predicts the global oil demand to reach 101 million barrels per day (mbpd) by year 2035 from today’s around 87 mbpd. India’s oil consumption will exceed 8 mbpd by 2035, which is more than current consumption of Japan, Korea and Australia put together.
India, Japan to Jointly Procure LNG
The dominance of Middle East producers in the trillion-dollar Asian oil market has changed after the rising of US Shale revolution that has sapped demand in the world’s largest crude consumer; the years of shaky economic performance in Europe; and the increasing fuel efficiency have shrink Russia’s traditional market.
New Delhi: India and Japan are stepping up to jointly procure liquefied natural gas (LNG) to find ways to cut their soaring gas import bills. The modality for this will be worked out in three months, said Vivek Rae, India’s Oil Secretary. Economic expansion, nuclear plant shutdowns in Japan and South Korea and the shift toward cleaner-burning gas in smog-choked Chinese cities have contributed to rising demand for LNG in Asia, already the top destination for the fuel. Across the region, demand for LNG is rising, while new, uncontracted sources of supply are not likely until at least the end of the decade. www.oswindia.com
Indian Refineries Gain as Gulf Battles for Buyers New Delhi: As oil producers worldwide export more crude East to compensate the shrinking demand from the United States and Europe, Middle East oil exporters are locked horns in an increasingly fierce battle to becoming the world’s fastestgrowing markets in Asia.
With nowhere else to expand, producers are pushing for more sales in Asia. The competition will become even stronger if sanctions on Iran are lifted in coming months. It is hoped that India, the 4th largest global oil importer, will be benefited a lot.
Offshore World | 56 | December 2013 - January 2014
news India Emphasizes More on Mozambique Gas New Delhi: India has a major stake acquire, almost a third of a giant gas field in Mozambique. But India has pitched for buying most of the natural gas from the project to feed its starving power plants in the country. Mozambique plans to produce 34 million tonnes of liquefied natural gas from the Rovuma Area 1 offshore block, where ONGC Videsh Ltd, Oil India Ltd and Bharat Petroleum Corp Ltd (BPCL) hold 30 per cent interest. The LNG to be produced by end of 2018 equals to 136 million standard cubic meters per day of gas, 50 per cent more than India’s current gas output. The government is willing to provide all help to the consortium to commence production.
TAPI to become Reality by 2017 New Delhi: Turkmenistan-Afghanistan-Pakistan-India (TAPI) gas pipeline will become a reality by 2017-end, said M Veerapa Moily, Union Petroleum and Natural Gas Minister, after the bilateral meetings with Mukhammetnur Khalylov, Turkmenistan’s Minister for Oil and Gas. He said that Asian Development Bank, the transaction advisor, is searching for a lead partner for the consortium that will lay the network and is expected to shortlist the consortium leader by early 2014. The envisaged 1,080 km pipeline (144 km in Turkmenistan, 735 km in Afghanistan and 800 km in Pakistan) will have a capacity to transport 90 mscmd of gas — 38 mscmd each for India and Pakistan and the remaining 14 mscmd for Afghanistan. The pipeline to transport the gas from the Indian border to other parts of the country has already been constructed till Jalandhar.
Oil Refinery & Oil Trading Hub at Kochi Kochi: State-owned Cochin port has started work on setting up a 20 million tonne export-oriented oil refinery and oil trading hub with private funds as part of an ambitious deepwater outer harbour project with an investment of Rs 40,000 crore. The outer harbour project will be the biggest project in the state and has called for an expression of interest to build the oil refinery and oil trading hub. The outer harbour project involves constructing two breakwaters on both sides of the approach channel extending about 7 km into the sea, with associated land masses on either side. The two breakwaters are estimated to cost around ` 3,000 crore. A breakwater is an offshore structure constructed to protect a harbour, anchorage or a marina basin from waves. The outer harbour will also have an oil rig fabrication facility, free trade warehousing zone and a power plant.
Crude Oil Trading Process may be Changed New Delhi: Soon, the way national oil companies import crude oil could be changed. Govt is considering substituting term contracts with an oil trading desk, the way oil is imported internationally. The government is examining to set up oil trading desk rather than relying on term contracts for importing crude oil. The final report on this would be finalised by March-April. Internationally, in oil trading, most products are bought and sold through trading desks. The process is similar to forex trading that takes place on the desk of banks and commodities. Industry players say in terms of pricing, trading through an oil desk is more efficient compared to term contracts as an oil desk provides better pricing, flexibility and more opportunities.
OVL Strengthens Hydrocarbon Portfolio in Vietnam Mumbai: OVL, the overseas arm of ONGC, has signed a Memorandum of Understanding (MOU) with Petrovietnam (PVN), the trading name of Vietnam Oil and Gas Group, to promote the joint cooperation in hydrocarbon sector in Vietnam, India and other countries. OVL is present in E&P sector of Vietnam since 1988 when exploration license for Block 6.1 was acquired. This MOU is in furtherance to the agreement signed between the OVL and Petrovietnam on, 2011. Under the MOU, Petrovietnam has offered 5 blocks to OVL. ONGC Videsh would assess these blocks and if these are of interest, it would make a proposal to PetroVietnam. Vietnam is one of the focus countries for ONGC Videsh where it would like to acquire stakes in oil and gas assets depending on technocommercial viability.
IOCL Refining Capacity to Increase Panipat: Indian Oil Corp’s (IOC) Panipat refinery is likely to expand its capacity to 21 million tonne per annum, said M Veerappa Moily, Union Oil Minister. Currently, it has a capacity to turn 15 million tonne of crude oil per annum into refined petroleum products or fuel. The expansion cost could be about USD 1 billion and may be accompanied by raising capacity of the adjacent petrochemical complex. IOC currently has the refining capacity of 65 million tonne, which is being expanded to 80 million tonne. The nation’s largest refiner is also exploring the possibility of expanding capacity at its Koyali refinery in Gujarat from 13.7 million tonne to 18 million tonne, at a cost of about ` 5,500 crore. Commissioning the ` 890 crore Styrene Butadiene Rubber (SBR) project at the Panipat refinery-cumpetrochemical complex, Moily said India’s refining capacity will rise to about 333 million tonne by the end of 2022, from 215 million tonne at present.
Govt Initiates Major Reforms for NELP X Round Mumbai: India’s oil and gas sector will serve as an important barometer of investors’ sentiment as the government prepares to auction oil and gas blocks for exploration under the 10th round of NELP, which is scheduled in January 2014. The govt is expecting to attract investments worth USD 4-5 billion through NELP-X, following the lukewarm response it has been faced to oil and gas block auctions in the last few years. Keeping this in mind, petroleum minister M Veerappa Moily has undertaken a slew of measures in 2013 to alter the negative perception regarding the ease of doing business in India’s oil and gas sector, and making policies more attractive.
Gas Price to Raise from 2014: Rae New Delhi: The revised price starting April 2014 will be in the range of USD 7-8 per mmBtu, said Vivek Rae, Petroleum Secretary. This will be based on the Rangarajan Committee formula, which is a weighted average index of imported LNG and major hub prices like Henry Hub. The government has also received bids from international clearance consultants like Shlumberger and Halliburton to conduct speculative geological surveys. This is part of the national data repository that the DGH is building ahead of moving to the open acreage licensing policy.
Offshore World | 57 | December 2013 - January 2014
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Crude Price may Drop in Few Next Years: Kuwait-based Think Tank New Delhi: : The global crude price is likely to drop to USD 80 per barrel in the coming years due to forecast growth of non-conventional oil output, according to a report by the Diplomatic Center for Strategic Studies, a Kuwait-based think tank. The report said that it is difficult to make specific anticipations regarding the crude prices due to prevailing variables on the market. On unpredictable factors, the report mentioned that the international and internal conflicts, particularly in oil producing countries, such as Libya, Nigeria and Iraq. Nevertheless, the crude prices will remain, mainly, affected by supply and demand. Future oil prices will be affected with emerging factors, such as cost of supplies of non-conventional crude, namely shale oil. Other major factors are OPEC states’ readiness to invest in the oil industries, namely in drilling and exploring as well as the capacity to develop used
oil wells. World oil demand, which amounted, in 2013, to approximately 89.5 million barrels per day, would reach some 94.5 million bpd in 2018. Industrial nations’ demand, which stood at 45.5 million bpd in 2013, would drop to 44.5 million pbd in 2018. The report said the oil demand by China and India would continue to grow, by 3 million bpd, some 60 per cent of the global oil demand growth. It mentioned other factors that will influence the prices in the foreseeable future; namely world economy growth, re-stressing that extraction of nonconventional oil is forecast to be a key influencing factor in this respect. Shale oil production in 2035 is forecast to hover at 10-14 million bpd, some 12 per cent of the world crude output, and when this happens, the prices will be in the range of USD 80-100 per barrel.
IOC’s LNG Project Gets Green Nod
India Aims to Improve Ties with Oil Nations
Chennai: Indian Oil Corporation (IOC)’s ` 4,320-crore liquefied natural gas (LNG) terminal project at Ennore has obtained nod from the expert appraisal committee of the ministry of environment and forests.
New Delhi: In a move to improve the energy sources, Petroleum Minister M Veerappa Moily has held a series of bilateral meetings with officials from Libya, the UAE, Bahrain and Canada, seeking better cooperation in the oil and gas sector, including higher crude oil supplies. In this meeting, Moily and his Libyan counterpart Abdulbari A Arousi emphasised the need for increasing cooperation in terms of greater crude oil supply to India and Indian participation in upstream projects there.
The capacity of the proposed facility will be 5 million tonnes a year and can be expanded to 10-15 million tonnes a year. This is part of IOC’s ` 56,000-crore investment plan during the 12 th Plan Period (2012-17).
Mangalore-Bangalore LPG Pipeline by ’15 Mangalore: The Hindustan Petroleum Corporation Ltd (HPCL) will lay a pipeline to transport LPG (liquefied petroleum gas) between Mangalore and Bangalore, said Union Petroleum and Natural Gas Minister Veerappa Moily. He said that the 362-km LPG pipeline between Mangalore and Bangalore would be set up at a cost of around ` 701 crore. There will be a branch line from Hassan to Mysore also, he said. The project is expected to be completed by November 2015. The pipeline system has been designed based on the initial demand of 1.12 million tonnes per annum (MTPA). It can meet demands up to 1.78 MTPA.
At the meeting, OVL, the overseas arm of ONGC, proposed to sign an MoU in providing institutional framework for exploring specific projects in the North African country. BPCL, the largest public sector oil marketing company in India, also urged for the revival of a term contract for supply of crude oil to India from Libya. In the discussions of Moily with UAE’s Energy Minister Suhail Mohhamed Al Mazrouei proposed a partnership between OVL and Mubadala, an investment and development company of the Gulf nation, for investment in upstream projects. Moily also sought greater role for Engineers India Ltd in the development of the UAE’s oil sector.
ENI Can Sell Crude to Indian Refineries
India Stresses for Canadian Hydrocarbon Cooperation
New Delhi: In a move to expand the sources for crude to meet the country’s soaring energy demand, India has revised its list of foreign firms by recently adding Italy’s ENI that can sell crude at official prices to the state-owned refineries in India. The country’s procurement choices are widening as a shale boom in the United States has led to suppliers scrambling to tap alternative Asian markets such as China and India. The move called by the Govt for revising the list of companies that can sell oil to state refiners in view of the changing market scenario and due to mergers and acquisitions. State refiners together account for about 56 per cent of India’s overall 4.3 million barrels per day (bpd) refining capacity and follow the government policy on oil imports, unlike private refiners such as Reliance Industries, Essar Oil, Bharat Oman Refineries Ltd and HPCL-Mittal Energy Ltd.
New Delhi: India has emphasized for better hydrocarbon cooperation from Canada on buying crude oil and liquefied natural gas (LNG) from the country on long-term contracts to meet its vast growing energy needs.
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On the sidelines of the Petrotech 2014 conference, Oil Minister M Veerappa Moily India was seeking a long-term supply contract with Canada, a nation from where state-owned Indian Oil Corp (IOC) last November joined private refiners Reliance Industries and Essar Oil in importing oil. India is also seeking cooperation from Canada to explore technologies for shale gas exploration in the country. The premier of Province of Alberta, Canada is expected to offer Indian upstream companies like ONGC state-of-art fracking technologies, to develop the vast potential of shale in this country, Moily informed.
Offshore World | 58 | December 2013 - January 2014
India to Enhance Crude, LPG Supplies from Saudi Arabia New Delhi: Apart from seeking enhanced crude oil and LPG supplies from Saudi Arabia, India will showcase major investment opportunities to the Arab Kingdom and its companies, including offering stake in IOC’s LNG project at Ennore in Tamil Nadu, Kochi Petrochemical Project of BPCL, Opal Petrochemical project at Dahej in Gujarat during the Joint Commission Meeting to be held later this month in Riyadh. At present, India imports on an average around 700,000 barrels per day of crude oil from Saudi Arabia and is seeking to increase that quantity. Major Saudi companies like Kingdom Holding, Saudi Arabia Basic Industries Corporation (SABIC) and National Industrialisation Company (NIC), the petrochemical holding arm of the Kingdom Holding Company would be offered attractive investment opportunities, including that in the Delhi-Mumbai Industrial Corridor project.
IOCL Eyes on Vizag-Kakinada PCPIR Refinery Visakhapatnam: Indian Oil Corporation Ltd (IOCL) has shown interest in the 15 million tonne per annum integrated refinery-cum-petrochemical complex proposed to be set up in the Vizag-Kakinada Petroleum, Chemical, Petrochemical Investment Region (PCPIR). Hindustan Petroleum Corporation Ltd (HPCL), the operator of the 15 mtpa integrated refinery-cum-petrochemical complex, along with partner Gas Authority of India Limited (GAIL) in the PCPIR, had scouted foreign investors earlier. Apart from IOC, many oil companies from the Gulf region too have made enquiries, said BK Namdeo, HPCL Director (Refineries), HPCL, adding that once the land is allotted for the project, things are expected to move at a faster pace.
Govt to Ease Norms on Buying Spot Crude by PSU New Delhi: In a move to make simpler and faster for buying spot crude by the public sector oil refining companies, the government is working on a proposal that may allow PSUs to fix deals over tele-conference instead of tendering. But switching from tendering requires Central Vigilance Commission’s concurrence in safeguarding to ensure that the process is not misused. An industry group is working on the proposals to modify the spot buying process and it may take another two to three months to finalise norms. To buy crude oil from the spot market, it takes the oil companies around 15 days through the tendering process, a significantly long period in the highly volatile and dynamic global market.
GAIL Plans Advance Import on US Shale Gas New Delhi: State-run GAIL India is mulling to strike a ‘time-swap’ deal with US shale gas suppliers so that it can import shale gas by 2015-16, ahead of 2017-18 for which contracts are in place. Time-swapping deals are a rarity in the global energy market. It has a deal with Cheniere Energy Partners to buy 3.5 million tonnes per annum (mtpa) liquefied natural gas (LNG) from Sabine Pass Liquefaction, a subsidiary of Cheniere, from 2017-18. GAIL also has a 20-year sales and purchase agreement with Dominion Resources for supply of 2.3 mtpa of shale gas starting from 2017-18.
news
India to Lead Global Refining Map
New Delhi: Industry leaders across Indian hydrocarbon industry believe that India will play a major role in oil refining as West Europe is not interested in this business due to their focus on developing alternative energy resources and US oil dynamics has changed due to discovery of shale oil. Indrajit Bose, Head of Indian Oil Corporation (IOC), West Bengal, said that under the circumstances crude oil prices will not increase and likely to remain stable. He added that India has gained excess refining capacity which is at 200 million tonnes and would touch 210 by next plan. India exports 60 million tonnes of refined oil at present. “On-shore oil production is now on the higher side at 19.3 million tonnes as against the output of 18.7 million tonnes from the offshore fields,” said Bose.
Government Puts 46 Blocks on Auction in NELP X New Delhi: Government has unveiled 46 oil & gas blocks (17 Onland, 15 Shallow water and 14 deep water blocks) for bidding in the 10 th round of New Exploration Licensing Round (NELP). The 46 blocks have already received statutory clearances to encourage domestic and global companies to explore potentially hydrocarbonrich areas in the country. The government is mulling to move to revenue-sharing model from the current production-sharing scheme. There will be no profit petroleum, no cost recovery, no investment multiple. The shift from the production sharing contract (PSC) regime, where operators are first allowed to recover costs, to a revenue-sharing model will be decided by the Cabinet.
A Consortium Leader for TAPI: Moily New Delhi: Within 3 months, a consortium leader shall be appointed to lead the TAPI gas pipeline, said Petroleum Minister M Veerappa Moily. Threw light on the development of the project, Moily said that the line shall supply natural gas from bed of Caspian sea, from Turkmenistan, through Afghanistan to Pakistan and then India (TAPI), is expected to be functional by 2017–18. Backed by the Asian Development Bank, the pipeline shall bring gas to India by 2010. The TAPI project shall run at an operational cost of USD 7.6 billion. The 1,735-km-long pipeline will have a capacity to carry 90 million standard cubic meters a day (mscmd) of shale gas for 30 years.
MRPL to Process Latam Crude by 2014/15 New Delhi: Mangalore Refinery and Petrochemicals Ltd (MRPL), the state-owned refinery, aims to process as much as 40,000 bpd of Latin American grades as it is in the process of commissioning a delayed coker, said Vijay G Joshi, Head – Refinery, MRPL. Joshi added that MRPL also aims to continue processing about 80,000 barrels per day of Iranian oil in the next fiscal Vijay G Joshi, Head – Refinery, year if sanctions are eased. Latin American grades MRPL will be procured from the spot market and would help improve margins. MRPL operates a 300,000 bpd refinery at Mangalore in southern India, said Joshi.
Offshore World | 59 | December 2013 - January 2014
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International Global Oil Demand Forecast to be High: IEA UK: Amid a strong growth has recorded in the third quarter of 2013, the International Energy Agency (IEA) has increased its forecasts for global oil demand for the remainder of 2013 and into 2014. An Oil Market Report for December was published by the IEA and it was specified that the estimate of global oil demand for 2013 now stands at 91.2 mn b/d. This is an increase of 130,000 b/d compared with the previous estimate - and it was noted that growth is particularly strong in countries that are members of the Organisation for Economic Co-operation and Development (OECD). Third quarter growth in the OECD stood at 320,000 b/d, which is significantly stronger than had been anticipated. Global demand is now expected to advance by 1.2mn b/d in both 2013 and 2014, which will see the total figure hit 92.4mn b/d some time over the course of the next 12 months.
Oil Prduc tion Resumes at El Sharara Oil Field
Iran to Seek Investment at Davos Iran: Iran’s oil minister will hold a ‘face-to-face’ meeting at Davos with major oil companies to try to coax them back to the sanctions-hit country.
Libya: Oil production in Libya’s El Sharara field has resumed in the south of the troubled country, which has been suffering from severely restricted exports on its main source of income. Various blockades had hindered output from the south of the nation, but protesters have now brought an end to their activities. The state-run National Oil Corp announced that the blockade, which has been in place for two months, has now been lifted - and this increases the prospect of badly-needed oil revenues for Libya. Oil exports have fallen from over 1 million b/d in July to just 110,000 b/d now. Libya has total national revenues of around USD 50 billionn (EUR 30.5 billion), with almost all of this from the sale of oil.
China to Buy More Iranian Oil in 2014 China: China may be planning to purchase more oil from Iran over the course of the next 12 months, as a new light crude contract is being negotiated by a state trader. If the deal is completed, it could make imports from Tehran rise to levels that have not been seen since the imposition of tough Western sanctions in 2012. Chinese state-trader Zhuhai Zhenrong is in talks with the National Iranian Oil Company (NIOC) for a new contract for condensate. Aside from the new deal, China - which is the largest trade partner and oil customer for Iran - is set to roll over its existing import volumes of 505,000 b/d. Imports from Iran to China for the first 11 months of 2013 stood at 421,520 b/d, which is down approximately 0.6 percentage points when compared with the equivalent figure recorded for 2012. www.oswindia.com
“We have designed a gigantic volume of investments and technical activities to recover and produce more oil and gas from our fields...and giant international oil companies can play a role in this regard,” said Bijan Zanganeh, Oil Minister, Iran. Iran’s vital oil exports have been more than halved by a raft of international sanctions aimed at curbing its nuclear drive, which the West claims is being used to develop atomic weapons. Iran insists its programme is entirely peaceful.
Bijan Zanganeh, Oil Minister, Iran
“At the oil and gas industry meeting in Davos, which will be attended by Iran’s president, I will hold a face-to-face meeting with the high-ranking managers of major oil companies to explain (their roles),” said Zanganeh.
Natural Gas May Reduce Drought Vulnerability: Study Texas: A new study carried out by scientists at the University of Texas has found that fracking for natural gas could prove to be a positive development in terms of water scarcity - despite the vast amount of water used in the process. Research carried out in Texas - the US state that generates the most electricity - revealed that the transition from coal to natural gas is resulting in more water being conserved. It was specified that the amount of water saved by shifting a power plant from coal to natural gas is between 25 and 50 times higher than the amount that is used to extract natural gas through hydraulic fracturing.
African Nations to Strengthen Oil & Gas Developments in 2014 South Africa: A number of African nations viz South Africa, Mozambique, Kenya and Tanzania are among the countries are looking to introduce new legislation in 2014 that will help them to boost oil and gas production over the coming years. These countries are drafting laws that will allow them to have more sway in the energy sector. The legal changes are expected to include possible tax rate rises, offering state-backed oil companies automatic equity stakes in new projects and jobs targets that firms will legally be required to meet. This move comes as African governments are under increasing public pressure to safeguard wealth associated with oil and gas production. The continent accounts for 7 per cent of global gas reserves and 8 per cent of oil reserves - and both are lucrative earners. In South Africa and other nations on the continent, more and more members of the public are calling on their governments to nationalise mines and depend less heavily on foreign direct investment - a figure which totals USD 30 billion (EUR 18.10 billion) annually. Offshore World | 60 | December 2013 - January 2014
news International New Oil Find Raises Hopes for Philippines Philippines: Philippines’ e n e r g y department put out an upbeat note of a new inland oil deposit discovered Jericho Petilla, Department of in Cebu, and Energy Secretary, Philippines raising the country’s prospects as a potential future oil producer. “The discovery in the Service Contract 44 (of Gas2Grid) is a boost to the country’s ‘upstream’ industry, and we will provide necessary support to advance its development,” said Jericho Petilla, Department of Energy Secretary, Philippines. It was the Australian firm Gas2Grid Ltd which found the oil at the Malolos-1 well. The exploratory drilling contract for the Malolos-1 well was awarded in January 2004. SC 44 has been calculated by Gas2Grid to be capable of producing oil in the range of 4 to 42 million barrels a day with a “most likely” assessment at 12 million barrels per day. Petilla said the discovery of the deposit, located in Cebu’s western coast, would be good for the country’s energy security efforts as it is currently dependent on imports Indonesia.
More Oil Finds at Ebok ffshore Nigeria Nigeria: Production from the shallow-water Ebok field offshore Nigeria has averaged more than 35,100 b/d of oil, boosted by three new development wells. Two were drilled in the north fault block (NFB) and one in the west fault block (WFB). A water injector well to spud soon will is designed to optimize and support the existing NFB producers. Following completion of an ocean bottom cable 3D seismic program over the whole Ebok/Okwok/OML 115 license, Afren has firm plans for a first exploratory well early next year on the Ufon structure. The GSF Monitor will drill this potential 65-MMbbl prospect, which Afren says is structurally and geologically analogous to Ebok and Okwok.
First Oil Soon at Anguille offshore Gabon Gabon: Phase 3 of Total’s Anguille redevelopment project offshore Gabon is continuing on schedule. Four wells have been drilled from the new AGMN platform. Three subsea flowlines have been installed and connected to the platform to tie it back to the central complex. First oil should be achieved soon. Installation of the power grid for the Anguille and Torpille sectors has been completed. The onshore power plant on the PG2 site and the new electrical systems installed offshore on Anguille/Torpille sectors are undergoing tests. Commissioning of the new power grid is expected to follow next month. Elsewhere off Gabon, Total says drilling of the Diaman-1 exploration well on the Diaba license has been postponed to later in the current quarter, due to delayed availability of the drillship Ocean Rig Olympia.
Syria’s Oil Gambit Amid Conflict Syria: Amid nearly three years of mayhem and the prospect of an extended conflict in Syria, the country has signed a contract with Russia’s Soyuzneftegaz to explore, develop and produce oil and gas in an offshore block off its coast. The agreement covers a modest part of Syria’s Exclusive Economic Zone (EEZ) and is only 2,190 square kilometres between the ports of Banias and Tartus. Soyuzneftegaz is said to spend some USD 90 million (Dh331 million) initially to survey and drill in the area and if commercial finds are discovered then the contract will extend for 25 years. Not all the terms of the deal are known and, if successful, results may not be seen in Syria’s energy balances for at least another five years. Yet it is a step in the right direction. The battle for the East Mediterranean gas has been going on for years now and Israel and Cyprus have made discoveries and development of sizeable quantities of gas, while Lebanon and Syria were taking their time. Lebanon’s political situation prevented a move forward, while there was also the claim against Israel on its infringement of maritime borders.
Production Begins at West Chirag in the Caspian Sea UK: The Azerbaijan International Operating Company (AIOC), operated by BP, has announced the start-up of oil production from the West Chirag platform as part of the Azeri-Chirag-Gunashli (ACG) field development in the Azerbaijan sector of the Caspian Sea. Start-up of the West Chirag platform completes the Chirag Oil Project (COP) sanctioned in 2010. West Chirag production began from one of the pre-drilled wells - J05. The oil will first pass through the newly installed processing facilities on the platform and then will be exported to the Sangachal Terminal via a new infield pipeline linked to an existing 30” subsea export pipeline. Production will increase through 2014 as the other pre-drilled wells are brought on line. The West Chirag platform has been installed at a water depth of about 170 metres between the existing Chirag and Deepwater Gunashli platforms. The design oil capacity of the new platform is 183 thousand barrels per day. The gas export capacity is 285 million standard cubic feet per day.
UAE Oilfields Attract Global Interest UAE: Abu Dhabi has received strong interest from international firms in participating in its largest oilfields, as it weighs continuing previous partnerships with Western oil giants or letting big Asian buyers take stakes, said Suhail Al Mazrouei, Oil Minister, UAE. Abu Dhabi National Oil Company (Adnoc) took full control of the biggest oilfields in the UAE when its decades-old venture with four of the world’s largest oil companies ended on early 2014. Under the concession arrangement, Adnoc held a 60 per cent controlling stake in the Abu Dhabi Company for Onshore Oil Operations (Adco) oilfields, while ExxonMobil, Royal Dutch Shell, Total and BP each held 9.5 per cent stakes. Several companies, including those whose participation in the concession have expired, are interested in joining the project with revised terms, UAE’s oil minister Suhail Bin Mohammed Al Mazroui told reporters. Offshore World | 61 | December 2013 - January 2014
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OSW Marketing Intiative
Tekla Structures: Ideal Solution for Oil & Gas Projects Building Information Modeling (BIM) solutions have been used for many years by both engineering and fabrication companies across different projects such as Healthcare, Industrial Process, Manufacturing, Aerospace and Oil & Gas to name a few. As a process, Building Information Modeling is a one that involves a detailed generation and management of a digital representation of the structural as well as the functional aspects of any facility. As a model, it is meant to be a shared repository of knowledge to enable and facilitate decision-making regarding a facility - right from concept through design and construction, as well as through its operational cycle. Oil and Gas industry experts agree that BIM can vastly reduce project delivery times, operational cost, and manage waste over the life cycle of a project. While major plant design systems for the Oil and Gas industry still rely on generation of 2D drawings, turning to BIM solutions will help the oil and gas industry to materialize their designs in a planned and hassle-free way while reducing cost, time and energy. As opposed to traditional building designs that are largely dependent upon twodimensional drawings and plans, BIM extends this beyond 3-D in terms of the dimensions, costs and time by creating a virtual information model. The module can be used to demonstrate the entire building life cycle, supporting processes including cost management, construction management, project management and facility operation. Using BIM in the entire design process -including plant equipment, pipe spooling, electric systems and the main structure can be incorporated in a 3D rendered environment. Furthermore BIM solutions provider such as Tekla Structures (www. tekla.com) take care of the whole project lifecycle from initial conceptual studies
including 4D visualization, design of structures, safety systems, engineering, fabrication, construction, sustainability, and decommissioning. Industry decision makers, owners, contractors, engineering companies, structural engineers, steel detailers, fabricators and project managers can witness first-hand the benefit of using BIM from design to concept of construction. BIM offers a centralized information management hub allowing for more control over the project cycle, helping to drive costs down. Many Indian companies operating in the region’s Oil and Gas sector are already using BIM to manage their projects. Technip, SNC Lavlin, Black & Veatch Saipem, Petrofac, Bechtel, UHDE, Samsung, NPCC, L&T are a few of several global companies deploying BIM for their Oil & Gas projects. Tekla Customers believe that by adopting Tekla Structures there will be huge productivity gains and reduction of engineering time cycle. Tekla Structures have also helps in eliminating duplication of efforts at various stages of analysis, design and detailing and saves vast amounts of time by always giving access to the most current information. As a result, the risk of errors, misinterpretation and rework greatly reduced in this project The most significant benefit is the availability of a single structural model from which anyone can extract project plans and detailing, lists of materials, weights, welding information like weld lengths, weld volume which are pivotal to off shore industry and centre of gravity. The software also allows direct interfacing to the piping model in the PDS. Another useful function provided by Tekla Structures is simultaneous access by multiple users to the same model,” Tekla Structures is a strong tool which helps to produce a quality product. At the same time, it also helps to meet their clients’ planning targets that are often very tight. Tekla saves around 50% as the result of the switch from 2D to 3D. The Building Information Modeling solution can therefore ensure a more reliable production of consistent high quality information for structural engineering design and construction projects for the Oil and Gas sector by equipping clients with a module that offers direct manipulation, improved drawings, easier handling of changes and revisions, Interoperability, higher levels of automatic production and increased creativity and productivity. sw To know more about the Tekla Structures Solution for Oil and Gas Industry: Phone: 022 – 61387777 / Email: info.india@tekla.com
Nirmalya Chatterjee COO & Director Tekla India www.oswindia.com
Offshore World | 62 | December 2013 - January 2014
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OSW Marketing Intiative
Exxon Mobil Targets Smash Injuries as Leading Cause of Hand Injuries in Upstream Production In 2008, Exxon Mobil, along with other industry leaders in the oil and gas industry, initiated an in-depth study of onsite hand injuries. These initial studies identified smash injuries as the leading cause of on-the-job hand injuries on drilling sites. The safety organization took action on the results of the study and established safety glove guidelines and standards, which addressed both impact injuries, as well as cut and puncture injuries.
RESULTS OF HAND INJURY STUDY FIND TWO MAJOR PROBLEM AREAS: SMASH, CUT AND PUNCTURE (LACERATION) For global petro-chemical service companies like Exxon Mobil, contractor and employee hand injuries represented a disproportionate source of costly worker downtime and insurance claims. In 2008, Exxon Mobil conducted a large-scale study of hand injuries that led to the implementation of a company-wide hand protection guideline. The study found that around 45% of all hand injuries were a result of a smash or contusion. These injuries most frequently occur while moving drill pipe, pushing tools, pulling chain, and securing pipe valves. The other 50-55% of injuries reported were categorized as cut and puncture (laceration). Many of the lacerations that occur actually start as a puncture, where a sharp edge, corner, wire ‘wicker,’ or other protruding hazard can penetrate through PPE. Exxon Mobil began searching for a glove on the market capable of reducing or eliminating smash issues as well as cuts and punctures. Many of the manufacturers that were contacted simply did not have the engineering capabilities to build protection for both issues. This is when Exxon Mobil turned to HexArmor. ENGINEERING THE IDEAL GLOVE SOLUTION HexArmor’s ability to design and engineer products that address smash injuries as well as cuts and punc tures was far better than the other manufacturers that Exxon Mobil was talking to. Both par ties realized that while competitive ‘advanced technology ’ gloves provided some protection against impact injuries, they did not offer much protection from cuts and punctures.
FACT
IR-X™ Impact Guards HexArmor took feedback from field workers on oil rigs and drill sites and used these insights to develop a full line of high performance hand protection that addressed smash issues, plus the cut and puncture problems that had not been solved by previous manufacturers. Using proprietary technologies like SuperFabric® material and IR-X™ Impact Guards, HexArmor was able to help Exxon Mobil push their hand protection program to a higher level of safety. sw
• Smash/contusion make up 45% of all hand injuries on drill sites • Cuts and punctures make up the other half of injuries on drill sites with close to 50% of recorded injuries • HexArmor has been working with Exxon Mobil and other industry leaders since 2008 to design PPE solutions to solve these known problems, and has had success implementing solutions worldwide to reduce injury
2000 Oak Industrial Drive NE Grand Rapids, MI 49505 Call 1–877–MY ARMOR or visit hexarmor.com
Offshore World | 65 | December 2013 - January 2014
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Marketing Insight
Underwater Lift for Lundin FPSO Mooring Retrieval Unique Seaflex, a Unique Maritime Group company which is one of the world’s leading integrated turnkey subsea and offshore solution providers has facilitated one of the most complex underwater lift projects. The project was carried out for Lundin Tunisia BV in approximately 300 m of water. Lundin Tunisia BV is a 40 per cent stakeholder in and operator of the Oudna field 80km offshore Tunisia. Abandoned by Shell in the mid-80s when relatively small discoveries in relatively deep water were still considered unviable due to lack of pipeline infrastructure, with the advent of the FPSO came a new way to make such fields viable. Oudna was accordingly de-mothballed a decade or so ago, and serviced until recently by the FPSO Ikdam. At end of the field’s viable lifecycle, the problem arose of how best to decommission the FPSO - and in particular how to take care of the delicate operation of disconnec ting several hundred tons’ wor th of moorings without incident. After a series of technical discussions between Lundin and Unique Seaflex, it was determined that a combination of 41 different-sized parachute-style Air Lift Bags (ALBs) up to 50t in size were needed to be installed on the moorings to reduce their tension to a manageable level. The deck-mounted linear winch was rated to 450t, but because the three mooring anchors were extremely well embedded in the sandy seabed, the effective tension on the chafe chain would have increased by an estimated 1.5 to 2 times the original 400t. The use of Unique Seaflex ALBs allowed the deck-mounted linear winch to pull on the chafe chain so as to slacken the connection to the Ikdam deck hook. The connecting shaft was then pulled out from the wren hook and by doing so,
freed the chafe chain thus allowing the mooring system to gently be lowered on a wire, thereby de-tensioning the system. Once released, the chafe chain was transferred to a nearby AHTV which held the de-tensioned mooring system whilst the Ikdam FPSO disconnected. Along with the fleet of ALBs, Unique Seaflex also supplied all the heavy duty shackles and lifting slings as well as an air inflation/deflation system and a topside technician to oversee the operation and ensure the safest and most efficient use of the package of equipment. Commenting on this occasion, Graham Brading, Managing Director, Unique Seaflex who was instrumental in leading the Unique Seaflex effort on this project proudly said, “Whilst we do supply standard buoyancy products to solve standard buoyancy problems, Unique Seaflex is always dedicated to bring out world-class solutions when clients describe their operational challenges and ask us to work with them to develop methods which will deliver them the best possible technical, operational and commercial outcome.” sw
To know more about the Unique Maritime Group Solution for Oil and Gas Industry, please log on to: www.uniquegroup.com www.oswindia.com
Offshore World | 66 | December 2013 - January 2014
products
LPG FILLING MACHINE
OIL & GAS DRILLING ELEVATOR
The automatic electronic LPG filling machine is a highly efficient machine with elegant look. This multi-function multi-featured machine meets the custom requirements of filling LPG bottles. The electronic filling machine makes use of strain gauge based load cell. The tare weight of the empty LPG cylinder is entered by means of a keyboard integrated with the enclosure. This machine has a flexibility of filling 5 to 50 kg net weight cylinders. The filling machines are equipped with roller table or lifting table for mounting of cylinders thereby allowing it to install online or offline the chain conveyor. For details contact: PAM Systems Pvt Ltd 350, S I C O F, Plot No: 69, M I D C Area, Satpur, Nashik, Maharashtra 422 007 Tel: 0253-6513114, 6603285 | Fax: 91-0253-2350266
LPG VAPORISER Chandra Engineering & Mechanical offers wide range of LPG vaporizer. The entire range made available is offered at industry leading prices to meet their financial constraints using high grade raw material procured from reliable vendors.
To fit the needs of natural gas and petroleum industry, Omeshwar Steel put forth a broad array of oil and gas drilling elevators. Offered elevators are hinge devices with handles that are used for wrapping around the tool joint of drill pipe, casing or lift nipples (for collars) for facilitating the lifting and lowering of the drill string. The demand of offered elevators are widely used as these need minimum maintenance. Offered elevators have precise internal diameter, with an appropriately profiled shoulder for the purpose of accommodating the lower profile of a tool joint. These elevators work on latch mechanism has that stop the opening under radial loads of up to hundreds of tonnes. Offered elevators need to resist cross-axial loads of the weight of the pipe joints. For details contact: Omeshwar Steel No: 8, Jay Jayant Estate, Rakhial Ahmedabad, Gujarat 380 023 Tel: 079-22740875 | Fax: 91-079-22740875 E-mail: info@omsteeltube.com / omeshwarsteel@yahoo.co.in
DRILLING RIGS
For details contact: Chandra Engineering & Mechanical No: 103, Devji Keshavji I. E, Wamanrao Patil Marg Chembur, Mumbai 400 001 Tel: 022-25204192, 25200233 | Fax: 91-022-25204006, 25500235
A drilling rig is a machine which creates holes in the ground. Drilling rigs can be massive structures housing equipment used to drill water wells, oil wells or natural gas extraction wells or they can be small enough to be moved manually by one person.
LPG CYLINDER PRESSURE REGULATORS
For details contact: Royal Exim 10/1 Kammamahalli Main Road, Nr Kullappa Circle Bengaluru, Karnataka 560 033
LPG cylinder pressure regulators TYPHOON, brand regulators for BMCG/LPG, come with pressure gauges. These single stage regulators are durable and ensure accurate control of gas with minimum outlet pressure fluctuations and comparatively high gas flow rates. These are durable and practical in construction meeting high operational demands in welding, brazing, heating, cutting, gouging and assets are highly versatile. For details contact: V N Associates No: 39, Sakthi Green Land, Phase-2 Vellakkinar Road, G N Mills Post Coimbatore, Tamil Nadu 641 029 Tel: 0422-3294330, 2909148, Fax: 91-0422-2909148
OIL RIGS JK Global Infratrade have a broad range of equipment, systems and components for land drilling rigs, truck-mounted rigs, and workover rigs ; the main products include drilling rigs, rig spare parts, drilling tools and pipes, oil and gas tubes, instruments and transport vehicles. For details contact: JK Global Infratrad Euro House, 4th Floor, Chincholi Bunder Road, Malad (W), Mumbai 400 064 Tel: 022-42511155
Offshore World | 67 | December 2013 - January 2014
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products
NATURAL & LPG GAS METERS Minicon Thermal Systems offers wide range of gas meters for various flow rates and pressures. Minicon Thermal Systems mainly sell gas meters of turbine wheel technology for gas flow measurement. They are available in models such as Kromschroeder gas meter DM 10R25-40; Kromschroeder gas meter DM 25R2540; and Itron gas meter MZ 50. For details contact: Minicon Thermal Systems Gala No: U-50, Nr Paliwal Doodh, Jai Matadi Compound Opp: Rajlakshmi Complex, Thane - Bhiwandi Road, Kalher Bhiwandi, Maharashtra 421 302 Tel: 02522-662064 | Fax: 91-02522-662064
MOBILE ANALYTICAL CART SEMI-GAS Systems offers Mobilytix, a new mobile analytical cart for analyzing impurities within a process gas line. Created to monitor and protect various critical downstream gas processes and tools, the new Xturion system features a flexible design that allows for customized instrumentation and data collection.
GAS FLOW METER Apex Thermotech Technologies Pvt Ltd offers wide array of gas flow meter using optimum grade raw material and cutting-edge technologies in sync with set industrial norms of quality. These gas flow meters are extensively used to measure the rate of flow of fuel gases consumed for commercial, industrial or residential purposes. For details contact: Apex Thermotech Technologies Pvt Ltd No: 101, Surya Niketan, New Delhi 110 092 Tel: 0120-2701583 | Fax: 91-0120-2701583 E-mail: info@apexthermotech.com / apexthermotech@hotmail.com
PORTABLE ROADS ON RENT OWS Technical Services a subsidiary of Oil Field Warehouse Services Ltd offers OWS Eco-Flex Road Mats on rent. These roads offer the unique advantage of combining high load bearing roads that are completely modular and portable. Simply lay the mats on any level surface using a forklift, JCB, crane or any other similar lifting equipment. Roads are ready for immediate use once the mats have been placed on the ground, thus eliminating any waiting period for drying or curing. If due to heavy rains the sub surface is depressed or sinks, one can simply lift the mat, level the surface and put the mat back and the road is repaired.
The standard Mobilytix is designed to monitor moisture, oxygen and particle levels as well as trace impurities of nitrogen, argon and oxygen. As with all SEMI-GAS custom Xturion systems, each unit can be engineered to meet application-specific requirements including numerous mechanical, electrical and enclosure design upgrades. Various analyzer configurations are also available to precisely tailor the system’s operational needs for each application.
For details contact: Oil Field Warehouse Services Ltd. A Div of OWS Technical Services A-61, 3rd Floor, Electronic Sadan No: 1 , Mahape, Navi Mumbai 400 710 Tel: 022-67698932 | Fax: 91-022-27612008 E-mail: director@owsecoflex.com / vineet.sharma@owsecoflex.com
This new mobile cart features a colour touch screen, with intuitive navigation, views and sample trends to control day-to-year sampling and data presentation. Overall system operation is easily performed through each individual analyzer’s control panel. An integrated automatic data logging controller collects and compiles analytical data from each analyzer. Each unit features lockable heavy-duty steel casters for both stationary and mobile analytical monitoring.
ORIFICE GAS FLOW METERS
For details contact: Applied Energy Systems, Inc 180 Quaker Lane, Malvern Pa 19355, U.S.A. Tel: (610) 647-8744 E-mail: mkasper@appliedenergysystems.com
Cosmic Technologies’ gas flow computer GFC-147 is a unique instrument designed specifically for Orifice applications which computes not only the flow using ISO 5167 standards, but also the gas density using complex equations. It uses the internal database of physical and chemical properties of gas flowing to compute the flowing density of gas to ensure that the mass flow computed and totalised is accurate. For details contact: Cosmic Technologies Plot No: 87, Indl Area, Phase-9 , Mohali, Punjab 160 062 Tel: 0172-5096230 E-mail: vikram@cosmictechNo:com / info@cosmictechNo:com
Offshore World | 68 | December 2013 - January 2014
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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 ($)
Status
Bahrain Deep Gas Exploration Project
Bahrain
-
Execution
NOGA - Awali Onshore Oil Field Development
Bahrain
1,500,000,000
Execution
Block K42 (Taza Block)
Iraq
-
Execution
Halfaya Contract Area Development
Iraq
-
Execution
Majnoon Oilfield Contract Area
Iraq
-
Execution
Zubair Oil Field Development
Iraq
-
Execution
Kuwait New Facilities
Kuwait
46,000,000,000
Bidding
New Oil Gathering Centres
Kuwait
1,000,000,000
Bidding
Block 3 & 4 Onshore Oman
Oman
-
Execution
Offshore Block 50
Oman
-
Execution
Oman Block 52
Oman
-
Execution
Block A
Qatar
100,000,000
Execution
Dukhan Oil & Gas Field Development
Qatar
-
Execution
ISND Field Development - Phase 5
Qatar
3,000,000,000
Bidding
Ahmar-1 Field
Saudi Arabia
-
Planning
Al-Khafji Offshore Field Development
Saudi Arabia
1,200,000,000
Execution
Khurais Light Crude Increment Program
Saudi Arabia
-
Feed
Midyan Gas Field Development
Saudi Arabia
800,000,000
Execution
Fujairah Oil Terminal Expansion - Phase 7
UAE
200,000,000
Execution
GASCO - Hail Sour Gas Field Development
UAE
1,000,000,000
Study
Sath al-Raazboot (Sarb) Field Development Project
UAE
1,500,000,000
Execution
Umm Lulu Full Field Development - Phase 2
UAE
2,300,000,000
Execution
Africa
Country
Value ($)
Status
Angola - Block 20
Angola
-
Execution
Angola - Block 5
Angola
27,000,000
Execution
North Zeit Bay Concession
Egypt
-
Execution
South Ramadan (SR Concession)
Egypt
-
Execution
West Esh El Mallaha Development Extensions Area
Egypt
17,500,000
Execution
Ethiopia - Blocks 7 & 8
Ethiopia
-
Execution
Middle East
Offshore World | 69 | December 2013 - January 2014
www.oswindia.com
Africa
Country
Value ($)
Status
South Deepwater Tano Block (SDWT)
Ghana
-
Execution
Sinapa (Block 2) & Esperanca (Blocks 4A & 5A)
Guinea
-
Execution
Block CI-27
Ivory Coast
-
Execution
Block 2A
Kenya
-
Execution
Block L10A
Kenya
-
Execution
BlockLB-17
Liberia
-
Execution
Block C19
Mauritania
-
Execution
Block Ta 10
Mauritania
-
Execution
Foum Assaka Area
Morocco
-
Execution
Sidi Moktar Development Licence
Morocco
-
Execution
Agadem Block
Niger
-
Execution
OML 112 - Okoro & Setu Fields
Nigeria
230,000,000
Execution
OML 56 - Umusadege Field
Nigeria
-
Execution
Tanzania - Block 1
Tanzania
-
Execution
Bouhajla Permit
Tunisia
-
Execution
Block 1 (EA-1)
Uganda
-
Execution
Caspian Region
Country
Value ($)
Status
Darvin Bankasi Field
Azerbaijan
-
Execution
Gunashli Oil Field Development
Azerbaijan
500,000,000
Execution
Neft Dashlari Field Development
Azerbaijan
-
Execution
Shah Deniz Stage 2 Development
Azerbaijan
30,000,000,000
Execution
Anaran Block
Iran
.
Execution
Band-e-Karkheh Oil Field Development
Iran
-
Execution
Farzad-B (Forouz B) Offshore Gas Field - Farsi Block
Iran
5,000,000,000
Execution
Hengam Oil and Gas Field Development
Iran
300,000,000
Execution
Mansouri Oilfield
Iran
1,000,000,000
Execution
South Pars Phase 12 Development
Iran
7,650,000,000
Execution
Akkulka Deep Exploration Project
Kazakhstan
-
Execution
Block E - Zhana Makat Field
Kazakhstan
-
Execution
Blocks A & E
Kazakhstan
-
Execution
BNG Contract Area
Kazakhstan
100,000,000
Execution
Kashagan Offshore Oil Project
Kazakhstan
136,000,000,000
Execution
Marsel Contract Territory
Kazakhstan
-
Execution
Bazhenov and Achimov Tight Oil Formations
Russia
300,000,000
Study
Bortovoy Licence
Russia
-
Execution
Eleven New Blocks
Russia
-
Bidding
Kovykta Gas Field Development
Russia
773,000,000
Study
Prirazlomnoye Oil Field Development
Russia
5,000,000,000
Execution
Sevastyanovo New Field
Russia
-
Execution
www.oswindia.com
Offshore World | 70 | December 2013 - January 2014
events diary Oil & Gas Asset Integrity Management Conference Oil & Gas World Expo 2014 Date: February 10-12, 2014 Venue: Bombay Exhibition Centre, NSE Complex, Goregaon, Mumbai, India Event: Oil & Gas World Expo 2014, the 6 th International Exhibition & Conferences, scheduled in 10-12 February, 2014, will organise by CHEMTECH Secretariat and supported by CHEMTECH Foundation, who are pioneers in conceiving international Exhibitions and Conferences since 1975. For the entire ‘Upstream’ value chain related to Oil & Gas exploration, production and transportation, the expo will provide a platform to showcase India’s growing engineering and technological capabilities in the entire upstream hydrocarbon value chain. The increasing number of exhibitors since its first edition in 2004 reflect India’s growing role in the global hydrocarbon sector. For details contact: Chemtech Secretariat 26, Maker Chambers VI, Nariman Point, Mumbai 400 021, India Tel: +91-22-40373737 Fax: +91-22-22870502 Email: conferences@jasubhai.com
Date: March 24-26, 2014 Venue: Houston Marriott South at Hobby Airport, Houston, Texas Event: Returning to Houston in 2014, The 2nd Annual Asset Integrity Meeting will provide the best practice strategies for improving asset performance in critical environments and operating safely in anticipation of regulatory change in the entire oil & gas industry from operation to execution of oil platforms. It will be a learning session about technological innovations that provide definitive methods for capturing data to make more informed decisions. The Oil & Gas Asset Integrity Management will bring together 200+ frontline operators & senior leaders at one unique event, from across Asset Development, Deep water, Exploration, Pipeline Integrity incl. Pigging to Plant & Operations Integrity, Process safety, Personal Safety, etc. Asset Integrity Management is structured to give the ample time to make new connections and strengthen prior relationships with the peers of similar job function and experience. As an Invite-Only meeting, we create the conversations that matter. For details contact: Sponsorship Director Mark Barrett Phone: +1 (646) 200.7494 Mark.Barrett@wbresearch.com Offshore Energy Exhibition and Conference 2014
Shale UK Date: 04-05 March 2014 Venue: Millennium Gloucester Hotel, London Event: Shale UK is a two-day conference taking place in London on the 4 th & 5 th March to present a state-of-the-art view of geoscience relevant to shale gas exploration, production and environmental management in the UK. Shale UK is organised on behalf of the Geological Society, the world’s oldest geological society. Shale UK will unite the leading experts in relevant areas of geology with decision-makers, potential investors, representatives from the hydrocarbons and energy supply chain and all stakeholders with an interest in shale gas in the UK. The speaker line-up features experts who have helped to shape the UK’s hydrocarbons industry over many years and are helping to shape the future climate for shale gas. For details contact: Geological Society and Global Event Partners Ltd Tel: 0044 20 3488 1193 E-mail: rtopp@gep-events.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 | 71 | December 2013 - January 2014
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book shelf PROCESS INTENSIFICATION , 2 ND EDITION Author: David Reay, Colin Ramshaw , Adam Harvey Price: USD 150 ( Use code PBTY 14 to avail 25 per cent discount ) Hardcover: 540 Publisher: Elsevier Publications Reviewed by: Mittravinda Ranjan Book Description: The book provides a comprehensive overview of ‘Process Intensification (PI)’ which has been in use since the
first quarter of 20 th century in industry, however the term was recognised much later. The concept of PI started in Europe and later was picked up by East Asian countries like China, Japan & Korea. The authors elaborately narrete how PI activity has evolved over the years across various industries citing experiments and industry studies, challenges and solutions. The second edition of book has come at the right time as Process Intensification is getting significant attention across various industry applications. Twelve chapters of the book offer a clear insight into PI which is supported by proper industry case studies, comparisons with the conventional techniques and results that the industry has seen. What I like about the book is the in-depth insight it offers into the heat & mass transfer operations; reaction kinetics and detailed information on PI for application. The authors examine the mechanism of PI across the heat exchangers, reactors and in the processes of separation and intensified mixing. Separate chapters on industrial applications across petrochemicals, fine & specialty chemicals, offshore processing, nuclear industry, food processing, metal & metallurgy, textiles, leather , aerospace and biotechnology follows. Reay, Ramshaw & Harvey observe that though processors can use PI equipment for different processes in the plant however a PI process plant is still a challenge. Authors have concentrated on chemical process industries ranging from bulk chemicals, petrochemicals, fine chemicals and pharmaceutical industries where PI can have visible impact. The trio advocates application of PI in pharma and specialty chemical industries and discuss the concept of ‘Desktop Process Plants’ can bring paradigm shift in commercialising the innovations. PI can enable the researchers to increase the productivity many times at the lab scale, thus eliminating the need to set up a separate facility to scale up the production capacity, especially in the field of pharma and specialty chemicals and be a complete game changer for new products. Authors highlight application of PI in the offshore oil & gas industry where it can have profound impact on sea borne oil processing, storage and distribution systems associated with existing refinery systems. Instead of following conventional route of transporting sea borne crude to on-shore processing facilities, it can be processed on board and converted to fuel and petrochemicals which inturn result curbing safety and environmental risks & cost reduction. Reducing the weight of heavy equipment for offshore processing is one of the critical challenges for the hydrocarbon producers in terms of cost as well as risk. They have cited the example of Velocys’ microreactors which have gained significant recognition among hydrocarbon producers. The chapter also includes detailed view of technical experts from BP on downhole processing from a decade ago and current observations of Conoco Phillips’ experts. Authors go on to discuss the possibility of using PI equipment like compact heat exchangers in offshore processing , enhancing oil recoveries and also the concept of using mini refineries in oil well heads. They have also touched upon refineries where PI could be used for overcoming process restrictions due to heat and mass transfer rates, in two pages. Adding few case studies on PI in refineries would perhaps create greater interest amongst the Indian refiners. The writers have concluded that two emerging technologies in PI may have significant impact on the entire hydrocarbon value chain. First, on small scale, the concept of lab- on-a- chip and plant-on-a-chip that may open up many new possibilities for online real-time analysis and screening , and distributed processing , possibly even downhole. Second, at larger scale concept of combining gas turbine, heat exchanger and reactor technologies offers some very interesting possibilities in gas processing and conversion as well as in power generation. Chapter on ‘Systematic Approach to Selecting PI Technology’ underscores the fundamental approach that manufacturers need to adopt depending completely on the requirement of the process and emphasise on the need of bringing the engineer in the beginning and work in tandem with the chemists. In addition to use of PI technologies in high risk applications, authors explore the future application areas viz. Clean Technologies which demand greater use of sustainable materials where PI is still in infancy stage; Modern Flow Chemistry where Nano-reactors have garnered special attention from chemists; Solar Energy ; and Carbon Capture and Storage (CCS). The authors have gone to the extent of compiling the list of companies, research & development organisations and engineering consultants towards the end which would come in to be very handy for those who are looking out to connect directly with the experts engaged in the field. Wherever the authors have touched upon a topic in brief, the references are cited where the topic has been covered in detail in the book, which makes it a very easy for the reader to navigate and also choose how one wishes to read. The books has very handy information on critical design, application and selection aspects of process intensification along with the industry case studies for the working professionals and to know the latest trends and reference book for process and mechanical engineering students to have in-depth insight into latest and future technology trends. www.oswindia.com
Offshore World | 72 | December 2013 - January 2014
RNI No: MAHENG/2003/13269. Date of Publcation: 1’st of every alternate month.
Offshore World | 3 | December 2013 - January 2014
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