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contents INTERVIEW ‘Price Stabilisation is a Myth’ VOL. 10 NO. 4 JUNE - JULY 2013 MUMBAI ` 150
- Sudhir Vasudeva, Chairman & MD, ONGC
OFFSHORE WORLD R.NO. MAH ENG/ 2003/13269 Chairman Publisher & Printer Chief Executive Officer
New Wine in Old Bottles 10
Jasu Shah Maulik Jasubhai Shah Hemant Shetty
EDITORIAL Editor Copy Editor Editorial Advisory Board Design Team Events Management Team Subscription Team Production Team
Mittravinda Ranjan (mittra_ranjan@jasubhai.com) Rakesh Roy (rakesh_roy@jasubhai.com) D P Mishra, H K Krishnamurthy, N G Ashar, Prof M C Dwivedi Mansi Chikani, Rakesh Sutar Abhijeet Mirashi Dilip Parab, Girish Kamble V Raj Misquitta (Head), Arun Madye
- Dr Rabi Bastia, President, Oilmax Energy
FEATURES Swimming Against the Tide 13 - J G Chaturvedi, Executive Director, ONGC A ‘White Elephant’ for India 17
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Scaling New Heights 22 - Kumar Saurabh Monitoring Instrumented Oil Field 24 - Taylor Milne & Andrew Weir-Jones Case Study - ‘Aberdeen’ of India 29 - Mahesh Sarode & Milind Khati On-line Moisture Analysis in Hydrocarbon Gas Streams Using Laser Spectroscopy 33 - M Fuller & A Amerov Mixed Price Movement Amongst Energy Commodities 35 - Niteen M Jain & Nazir Moulvi
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TRENDS NEWS 40
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interview
‘Price Stabilisation is a Myth’ State-owned Oil and Natural Gas Corporation (ONGC) has elaborate plans of foraying into fuel retailing business. Sudhir Vasudeva, Chairman and Managing Director, ONGC, tells Offshore World that the market is getting sufficiently primed for the entry of new players into retailing space with Government’s initiative of phased decontrolling of Motor Spirit (MS) and High Spirit Diesel (HSD) prices. While talking about the roadmap for energy self-sufficiency by 2030, he says that by 2030 ONGC aspires to become a global E&P player and strengthen its position as India’s leading energy company by doubling its production, effecting a threefold increase in revenue, fourfold increase in market capitalisation. Excerpts: Sudhir Vasudeva Chairman & Managing Director Oil and Natural Gas Corporation (ONGC)
How do you evaluate the growth in petro-retailing space in the country? Please detail the opportunities and challenges faced by the oil marketing companies, which are state-owned and privately-owned? The 12 th Plan document of GoI envisages a Compounded Annual Growth Rate (CAGR) of 8.5 per cent and 4.7 per cent for MS (Petrol) and HSD (High Spirit Diesel) respectively for the period 2012-17. This impressive projection when set in the context of an expected GDP growth rate of 6-7 per cent for the economy gives a promising scenario for the Indian petro-retail segment. Currently, state-owned oil companies own about 42,000 retail outlets. Back in 2002-03, the Government issued 11,659 new licenses to the new players who were entering the market; in that offer, ONGC acquired 1100 licenses with split authorisations for both ONGC and MRPL. However, owing to the prevalent market conditions and the uncertainties associated with the sector due to regulated price regime, ONGC decided not to venture into retailing rightaway and adopted a wait and watch policy. Though management of market entry with such a large number of outlets is a marketing challenge, the margins on MS and future margins on HSD make the business lucrative. www.oswindia.com
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Retail is a low risk business unless prices are artificially subsidised, it can guarantee a steady source of income. Ideally, venturing into retail business should coincide with the deregulation of HSD as in our case. Now, with the Government initiating the phased decontrol of diesel prices in the country, the market is getting sufficiently primed for the entry of new players into the retailing space like ONGC. As far as challenges in the sector are concerned, Retail would definitely be a new arena of business for ONGC away from its core business of E&P, but in line with the company’s overarching objective of being an integrated energy major with entrenched interests across the entire hydrocarbon value-chain. We would like to leverage the strengths of the ONGC brand, which has been acquired over many years of continued and excellent performance, in the oil & gas domain. With that in tow, establishing a new brand identity for ONGC in this space, with the assurance of the same levels of quality and performance, and making the business sustainable are challenges we are looking forward to. Amid the diesel price deregulation, what inspired ONGC to re - enter into fuel retail business? It is a market with volumes. For example, nearly 60 per cent of the total transport fuel comprises of HSD.
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And like I said, with the Government’s decision to do away with HSD subsidy, we expect reasonable profits accruing from retail. It may become a more functional and financially less uncertain market. ONGC has already license for over 1,000 retail outlets in the country. But it does not operate yet. Are you planning to reshuffle these outlets? If yes, then how ONGC is going to fix it? Between ONGC and MRPL, the ONGC group has licenses for 1100 outlets. However, as on date, only 3 outlets are in operation. Before moving further into this business, we are definitely undergoing a retail portfolio reassessment and outline the best possible expansion/ramp-up model for our outlets. Future strategy for this segment is under evaluation at the top management level and will be made public at an opportune moment. Private oil companies like Essar Oil and Reliance Industries objected the Govt’s change pricing model of petrol and diesel to sell fuel to PSUs. May we have your comment on it? Such a move to force refineries to sell products to OMCs at Export Price Parity (EPP) will also adversely affect MRPL, which is an ONGC Group Company. Anyway, Ministry of Petroleum and Natural Gas (MoPNG) is looking into this issue. Please appraise us on the company’s strategic tie up with Shell for oil retailing business? We have long-term partnership with Shell and it goes beyond petroleum retailing. We are jointly examining opportunities in the entire spectrum of hydrocarbon value-chain upstream, midstream, downstream, petrochemicals, refining, retail, and opportunities in areas such as LNG as well. We are exploring all the possible models of venturing into retailing. However, details will become clearer in the next few months. As per media reports, ONGC is likely to operate under ‘OVaL’ brand, while its subsidiary MRPL will operate under ‘HiQ’ brand to enter the oil retailing segment. What is the significance of it? Yes, originally that was the plan at the time we acquired the retail licenses; to operate ONGC’s retail chain under the brand ‘OVaL’. The strategic www.oswindia.com
>> We are jointly examining opportunities in the entire spectrum of hydrocarbon value-chain upstream, midstream, downstream, petrochemicals, refining, retail, and opportunities in areas such as LNG as well. We are exploring all the possible models of venturing into retailing. business unit Additional Retail Business (ARB) with a view to generate surplus income and put in place new streams of revenue also established tie-ups and associations with reputed brands of the sector. On the other hand, the HiQ outlets of MRPL were initially positioned in the market with the proposition of cost-effectiveness coupled with quality. However, there always remains a window and scope for revisiting the strategies before starting off with the retail operations to fine-tune the earlier adopted strategies and keep them well in step with the current market realities. The petrol & diesel prices have seen revisions at quick intervals. Do you see any stabilisation on the price front in the years to come? Not just the retail prices of the fuels, oil & gas industry and its business itself has an inherent volatility given that it has strong linkages with the movements in the global economy. Fuel prices in India move in tandem with international prices, so stabilisation is a myth. In fact, price revisions in order to do away with under recoveries in sensitive products – HSD, Kerosene & LPG. Actually it has become need of the hour. Only, a market determined pricing order can bring in a semblance of stability. On the other hand, it is not always such a bad thing, market dynamics, as it captures the state of the market and the demand-supply situation and necessitates companies to bring in efficiency and service competitiveness into the business structure. But, of course, severe volatility that is a result of a host of factors, some invariably external, is something that is not conducive to the industry. Few days back, Petroleum Minister V Moily announced that India have to achieve complete energy independence by 2030. Offshore World | 8 | JUNE - JULY 2013
In your view, what will be the detailed roadmap having well defined action plan to achieve it? Ensuring energy security of the country has always been at the centre of the overall ambit of ONGC’s pursuits. Especially, at a time when the rising crude import bill and the depreciating currency puts further strain on the country’s fiscal health, the question of energy self-sufficiency assumes much economic and strategic significance. For the last 56-57 years, ONGC has been at the forefront of ensuring hydrocarbon availability for India, and will need to continue playing this critical role. From our current understanding of the situation it emerges that to sustain a 7 to 8 per cent GDP growth rate till 2030, India will need a 3 per cent growth rate in hydrocarbon availability. A strong production growth of 4 to 5 per cent is essential for ONGC to maintain its leadership in India’s hydrocarbon space and provide the country hydrocarbon security. With 4 to 5 per cent anticipated growth, ONGC aspires to increase its share in India’s hydrocarbon consumption from the current 22 per cent to 27 per cent by 2030. A production growth rate of 4 to 5 per cent over a 20-year period is a challenging aspiration, comparable or better than what most global majors and other large National Oil Companies (NOCs) have achieved or aspired to. This thrust for accelerated growth across all segments of its business chain over the coming period of the next two decades forms the basis for ONGC’s Perspective Plan 2030. By 2030, ONGC aspires to become a truly global E&P player and strengthen its position as India’s leading energy company, by doubling its production, effecting a threefold increase in revenue, four-fold increase in market capitalisation. While doubling its total production, contribution from its overseas assets it is envisaged at 8 times of its sw current production.
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interview
NEW WINE IN OLD BOTTLES Seismic studies form the backbone of any exploration activity. It provides the image for the potential hydrocarbon resources. Dr Rabi Bastia, President, Oilmax Energy, talks to Mittravinda Ranjan & Supriya Oundhakar about the importance of seismic surveys, shale gas and CBM developments in India and more. While talking about ‘Basins Below Basins’ concept, he explains that Wilcox basin in the USA is a good example that has exploration history of over a century, where the seismic studies have unveiled some interesting stratigraphy, which indicated the presence of hydrocarbon reserves at deeper levels . Excerpts:
Dr Rabi Bastia President Oilmax Energy
May we have your comments on accelerating exploration activities in the Indian frontier basins? Seismic studies are the foremost step for carrying out any exploration activity that enables the geoscientists to understand the stratigraphy to assess the available potential. To me, most of our frontier basins are not covered with adequate seismic surveys. And with the frontier basins – I do not mean the sedimentary basins in Cambay, Assam and Mumbai, where we are already active – but the basins such as Central Indian basins, Himalayan foothills, Gangetic plains and offshore basins, where the offshore can be connected to the coast with deep-waters up to 3 kms, and even basins below basins. The potential needs to be explored in the earnest way and intensity using high-end seismic technologies and geological techniques. Tell us more about the ‘Basins Below Basins’ and the possible areas that could hold hydrocarbon potential. Metaphorically speaking, basin below basin is like ‘New Wine in Old Bottle’ which means that there could be a very fair possibility of finding hydrocarbon resources below the existing fields. Wilcox basin in the USA is a good example that has the exploration history of over a century, where the seismic studies have unveiled some very interesting stratigraphy, which indicated the presence of hydrocarbon reserves www.oswindia.com
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at deeper levels. As they went deeper, they realised the accumulations were to the order of billions of barrels – much larger than they had imagined and that is after 100 years of exploration, which have become targets for today. In India, we started with on land basins, and then moved to offshore deep water, but perhaps this could probably be only the first tier and if explored further, may be we could also come across some interesting geologies that could be holding sufficient resources to suffice for years to come. Having said this, I do not mean that all the basins would fall under this category but certain basins could possibly reveal some interesting stratigraphy and hold huge hydrocarbon potential. In your view what would be the right approach towards discovering ‘new wine in old bottles’? Traditionally, we searched conventional oil in conventional reservoirs. But there are three more quadrants that need to be considered, which include searching for conventional resources in unconventional reservoirs and shale gas would be a good example, unconventional resources in conventional reservoirs such as oil sands etc. and unconventional reserves in unconventional reservoirs such as oil shale and CBM. There is a compelling need to change our approach of searching oil & gas resources towards tracing oil & gas
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accumulations and going further to map the deeper rock formations for estimating the potential in the same old basins, would require advanced techniques. Integration of seismic technologies along with geophysical techniques for better data acquisition, imaging, interpretation and visualisation can enable the geoscientists to look at the same old basins with new eyesight for mapping the potential resources. How much have we progressed on the shale gas front in India and can we emulate the shale gas success story in USA in India? Not much. Developing the unconventional resources like shale gas would require a very prudent and pragmatic approach. The normal perception that prevails is that mapping for conventional and unconventional is the same, but it is not true. The unconventional resources need completely different treatment from the conventional ones. The unconventional reservoirs need to be understood to a greater extent that involves different imaging techniques and seismic technologies for better data acquisition, mapping and interpretation by the geologists. Though there has been much talk about the unconventional energy in the country, it is now required for us to think on the lines of making commercial project out of shale gas in India. If USA has produced about 6 per cent of its total production from this resource alone, we need to find out the basins which can give that kind of output. India would require a very prudent and pragmatic approach and a logical actionable plan, coupled with congenial policies to attract investments to develop the shale gas assets. In your view, what would be the right approach towards developing the unconventional resources? The normal perception is that the mapping for conventional and unconventional reservoirs is the same but that is not the case. These require better imaging from seismic surveys to understand the reservoir characteristics, which is the foremost step. This must be followed by proper sampling and analysis to assess the gas content and gas generation potential. The sample collection cannot be done in an open chamber but done in a confined way so that nothing escapes at the time of collection and when it is taken to the laboratory to ascertain the gas content. www.oswindia.com
What should be done to materialise the shale gas plans in Indian context? Though, there is a lot of talk currently going on, at this point of time India needs an actionable plan to emulate the success story of the USA or China. As of now there are many estimates about the potential shale gas resources in India, but we need to have the right basic input data based on seismic studies carried out to map the unconventional assets and actual pilot studies to prove the potential of shale gas in the country. At this point of time, India needs an actionable plan based on true inputs to monetise the shale gas assets. Second on the priority list is sourcing of environment friendly fracking techniques. So far, hydro fracturing has been a prominent shale gas production technique, which is both tedious and unfriendly to environment. The technology has evolved and there are some hydro fracturing equivalents that the industry is experimenting with which could result in better yields from sub surface which should be captured for better productivity and lesser damage to the environment. India holds fourth largest coal reserves globally and has a good scope for deriving energy, but till date only 10 per cent of resources have been developed. May we have your views? Coal has tremendous potential and can be treated as complete energy package whether it is CBM or coal gasification, or taking nitrogen and other gases and re-injecting them into the surface to get enhanced energy levels. As compared to other coal provinces in the world, Indian coal has higher ash content, which definitely doesn’t mean lack of potential in Indian coal. Here also the drilling and production techniques are critical and require better understanding of geological and geophysical characteristics. What about the enhancing oil recoveries in the existing fields and developing the satellite fields which can significantly contribute to the energy supplies in the country? Application of EOR & IOR has made some contribution towards enhancing hydrocarbon production from the existing hydrocarbon fields not only in India but globally as well. Many operators now try incorporating these plans at the initial development stage. Though some of the new fields can be considered for integrating EOR plans during the planning stage of developing a field. In India, I feel EOR and IOR have Offshore World | 12 | JUNE - JULY 2013
2-5 per cent of scope as far as Greenfield projects are concerned; and some of the new fields could be considered for integrating EOR during the field development plan but not all. I agree with you that satellite fields and the marginal fields are the frontier area for the E&P companies which they need to look into in India. These require proper infrastructure support and new technologies to enable the operators to produce in profitable manner. The marginal fields have smaller reserves and due to higher production costs developing the fields in India is not economically viable currently. However, the countries like Malaysia and Nigeria have very successfully developed the marginal fields, which is something India could learn from. Satellite fields can be more economically produced if there development is integrated with facilities of nearby bigger existing fields. Can India emulate doubling the gas productivity and development of hydrocarbon assets at fast pace like what China has done? E&P companies alone cannot develop the assets to meet the goal of reaching self- sufficiency. It has to be concerted effort of regulatory authorities, policy makers, E&P companies and the associated services providers. At this point of time, India needs congenial policy framework that would enable the investors to operate in a profitable manner. Irrespective of the licensing model that we follow in the country for allocation of fields, there is a need to improve the overall governance which should focus on creating congenial environment for the existing investors to operate in profitable manner, retain them and attract new investors. What do you feel about the oil & gas market opening up in Africa – often referred to as the ‘Dark Continent’? We have witnessed the revolution in Africa’s oil & gas sector that spread from Angola to Mozambique to Nigeria and Tanzania, where most of the large E&P companies are operating now. The governments are encouraging infrastructure development also in these areas. If other countries progress much faster than India and create wealth through development in oil & gas assets, India is likely to lose its competitive edge. sw
features Hidden Assets
Swimming Against the Tide J G Chaturvedi , Executive Director, ONGC has been at the helm of affairs in ONGC for development of India’s marginal field for couple of years. He strongly recommends development of these hydrocarbon assets in the interest of nation towards building indigenous upstream capacity and discusses about the white note ONGC is preparing to present to the authorities and the approach for unlocking the hidden potential of this new frontier in an exclusive interview with Mittravinda Ranjan .
The ever increasing energy demand is compelling the nations to accelerate the development of hydrocarbon reserves to build indigenous capacity in upstream sector. While US energy market is riding growth wave of shale gas, Malaysia, and Nigeria moved fast with successful development of the marginal fields. TECHNICAL ASPECTS “Marginal fields refer to discoveries which have not been exploited for long, due to one or more of the factors viz. very small sizes of reserves to the extent of not being economically viable, lack of infrastructure in the vicinity, profitable consumers, prohibitive development costs, fiscal levies and technological constraints,” Chaturvedi explains. Various cycles affecting the oil industry strongly emphasise upon the need for detailed control of expenditure for development and production of small discoveries. While field characteristics dictate the technology required for developing the marginal field, economic viability is the ultimate deciding criteria. Eventhough marginal fields are developed with conventional technologies at optimum CAPEX, high end technology induction may lead to incremental production which sometimes is not economically feasible. Typically, the gas fields have life span of 8-10 years, which is relatively shorter as compared to the oil fields. On economic consideration, it is always desirable to exploit oil or gas in shortest possible time, which is a major challenge for the operators, he emphasises. Although conventional methods of developing marginal fields largely being adopted, of late companies are using horizontal drilling, state-of-the-art sand control measures, MOPU for processing, light weight wellhead platform, subsea wells etc. Technically, operators are more concerned with the breakeven for the marginal fields, the technocrat states. Though we have put 64 marginal fields on production so far, but with the current policy regime, forget the profit - it will be difficult to even reach the breakeven for the operators, he articulates. ONGC SUCCESS ONGC has adopted two pronged strategy for marginal field development since 2002, 1) mobilisation of in-house resources wherever possible and
J G Chaturvedi, Executive Director, ONGC
2) outsourcing of work to service contractors. As a result, now 64 out of 165 marginal fields of ONGC have been put on production. Since about 84 per cent of total ultimate reserves of marginal fields are locked in offshore, ONGC has taken initiatives for development of offshore marginal fields on priority. As a result, 16 fields have already been put on production and development schemes covering 23 offshore fields are under various stages of implementation. These fields will be put on production by end 2015 and contribute significantly to enhance production over a period of 10-15 years. ONGC is executing development projects on standalone propositions, clusters, considering sharing resources with other operators, adopting innovative drilling techniques and sub-sea completions, which the company had not tried so far. The marginal field development programme had seen potential reserve growth during the field development stage, cites Chaturvedi. ONGC discovered the marginal field in Tapti Daman block of Mumbai Offshore in the year 1978. In view of ultra-shallow bathymetry, shallow reservoir, low pressure, unconsolidated sands, no nearby offshore infrastructure and the then prevailing gas price, development of the field was deferred. The standalone field development was also unviable due to lack of in-house facility for gas transport and processing. However, the hydrocarbon major went on to develop the field using the underutilised facility of a nearby joint venture for gas transport and on-shore processing to enable the monetisation of idle asset. “Meanwhile, additional discovery in deeper reservoirs through concurrent exploratory drilling led to upward revision of in-place geological estimates to 14.5 BCM a two fold increase, which further enhance the production potential of the field,” he informs. Although ONGC has gone ahead with the development of marginal fields, but Chaturvedi feels the need of having a separate marginal field development policy due to different field dynamics as compared to conventional fields. Chaturvedi remembers, Former Secretary, MoPNG as a great visionary who envisioned the need of having a separate policy for development of marginal fields in the country and had set up a committee comprising of members from the MoPNG, DGH, ONGC, and Oil India to propose the policy document on marginal field development. The members deliberated at length and came up with recommendations towards
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ONGC North Tapti, India Total marginal fields: 165 Offshore: 79; Onland: 86 Initially in place hydrocarbon: 1300MMt (O+OEG)
Field Development Plan • •
1978: Discovered in Tapti-Daman Block of Mumbai Offshore Basin 1978: First exploratory well in the crestal part of the structure encountered severe gas kick at 288m and had to be terminated. Subsequent wells drilled on flanks or plunge parts to avoid shallow gas hazards. 1984: Second well proved gas pool in a shallow Miocene reservoir. Two delineation wells on the eastern and western plunge established extension of the reservoir and discovered an additional gas pool in late Oligocene. Besides, the well on the western plunge also tested oil and gas in early Oligocene. The development of the field was deferred due to ultra-shallow bathymetry, shifting sand bars, shallow reservoirs, low pressure and volume 2002: ONGC adopts strategic decision to develop marginal fields 2003-04: 3D seismic data instil confidence on reservoir geometry and demarcates the shallow gas bearing crestal area. Development scheme envisaged drilling of six horizontal wells from two platforms to exploit 6.14 BCM initially in-place gas representing 90% of the total in-place of the field Scheme envisaged plateau gas rate of 1.8 MMm3/d with a cumulative production of 4.12 BCM in 10 years The standalone development requires major inputs in the form of a new pipeline and creation of gas processing facility and compressor; hence unviable The project becomes viable by sharing the Joint Venture facility of M/s Cairn Energy for gas transport and onshore processing. 2010: Additional discovery in deeper reservoirs through concurrent exploratory drilling led to upward revision of in-place geological estimates to 14.5 BCM and enhance the production potential 2012: The field was put into production through three producers. 2013: Development scheme completed in April 13. The field had produced 257 MMm3 by June 13.
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D-1 Field development, a success story Discovery and appraisal • • •
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Initial Development Plan
1976: Following the discovery of supergiant Mumbai High Field in 1974, a series of discoveries took place in early 1976, D-1 being the fourth, such discovery and the first marginal field in the Western Coast of India Although the first two exploratory wells struck oil in early Miocene carbonates in 1976, being a low gas-to-oil ratio fluid and the then rudimentary understanding of the reservoir led to slow pace of exploration and appraisal of the field 1977-1998: A total of ten wells had been drilled of which nine were oil bearing, a success rate of 90 percent. By that time in-place oil estimates also increased to 61MMt.
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2002: The field received attention for development only in 2002, when ONGC took a strategic decision to enhance production through monetization of marginal fields. D-1 being the largest marginal oil fields got priority over others. The initial development scheme was confined only to the southern block where twelve wells were planned in two phases, six producers and equal number of injectors. The in-place oil considered for development was 19 MMt and envisaged cumulative production of 4.57 MMt in 10 years. 2006: The field was put on production in February 2006, had achieved a peak oil production of 17,000 barrels per day after completion of Phase II. Based on reservoir performance analysis, the number of injectors has been revised from six to two and water injection rate reduced to 5000 bwpd considering slower rate of pressure decline. A mobile processing unit (Sagar Laxmi) used as a process facility at another field, was withdrawn for putting D-1 field on production.
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Upside potential established
Integrated development plan •
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2007: The success of the initial development and oil discovery in another exploratory well in an adjacent fault block, towards north had opened up further opportunity for additional development of the field. 2010: Accordingly, an integrated development scheme had been worked out in 2010 considering nearly 51MMt in-place oil volume. The scheme envisaged deployment of a higher capacity FPSO in place of MOPU, drilling of 14 additional wells for development of the northern part and additional development of south block. An enhanced production potential of nearly 36,000 barrels of oil per day was projected with additional wells from three new platforms with incremental oil production of 8.296 MMt over the base production profile. The development plan is under implementation since May 2012.
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2012: The first development well of the integrated development plan, in the northern part, was projected to be drilled to 2,648 m. As oil was detected till the projected depth, drilling was extended by 100 m initially. Since the entire deepened section was found oil-bearing, the well was further deepened and finally drilled to the depth of 2,830 m. This has unfolded an additional oil bearing zone of about 142 m and led to accretion of in-place oil to the tune of about 50 MMt. In order to appraise the new pool, the projected depth of the other development wells are being adequately increased for the deeper pays. In the meantime, another exploratory-cum-development well drilled from the vacant slot of a Platform of south block also had proved to be oil bearing. These have further improved geological in-place and paved the way for additional development of the field. 2013: The cumulative production has already exceeded 4.3 MMt.
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various fiscal concessions; tax holidays etc on the same lines as offered under the Production Sharing Contracts (PSC) signed during the NELP rounds. The draft policy was submitted by the Chairman, ONGC to the Secretary MoPNG. The proposed policy document was presented to the Planning Commission and then Ministry of Finance; however, the document was not pursued by the government. GOVERNMENT INTERVENTION “The Governments have a major say in driving the growth of the hydrocarbon resources in any country since in majority of nations these are owned or controlled by the nations,” he states. “Take examples of Nigeria and Malaysia where they came up with investor-friendly policies to attract investments and have successfully developed marginal fields in a phased manner,” he shares. The Cendor field in Malaysia was discovered by Amerada Hess in 2001. However, the discovery was initially regarded as marginal with estimated recoverable resources of 12 million barrels (MMstb) of oil and was, therefore, deemed too risky and uneconomical for development. In May 2004, Petrofac acquired Amerada Hess’ interest and assumed operatorship of Block PM304. Driven by Petronas strategy to grow resources, production and value, aggressive appraisal and development campaign was undertaken, which led to the monetisation of this once marginal field. The efforts undertaken successfully transformed Cendor from a field deemed marginal to one of the large oilfields in Malaysia. The performance of Cendor field has helped spur further activities within the field and the surrounding areas of Block PM304. This has culminated in Cendor Phase 2 development and other new developments in PM304, which increased
estimated recoverable resource to over 200 MMstb, a growth of more than 16 times from when it was discovered. Resource growths are also seen in other oil and gas fields in Malaysia, such as the fields in the Berantai risk service contracts (RSC) and Balai RSC. The Berantai field, which commenced production in 2012, achieved an estimated recoverable gas resources by 15 per cent compared to 2011, as a result of development efforts. The pre-development work of Balai Cluster has also given early indication of increase in resources estimates. He also shares how the Nigerian oil and gas industry has evolved since 1956 when it was controlled by the international oil companies to the state control after Nigeria became a part of OPEC nations that mandated the country to have national oil company with 60 per cent stake in domestic hydrocarbon reserves. Nigeria started encouraging active participation through licensing to international operators and exposed the sector to new technologies thus unveiling a new chapter in the growth of country’s hydrocarbon sector. Nigeria introduced the Marginal Fields Decree No 23 (MFD) of 1996, a legal framework, which introduced the marginal field concept for the first time and has proved to be a turning point for the Nigerian oil and gas industry. PROPOSED RECOMMENDATIONS The technocrat laments that lack of proper policy to unlock the hidden potential to expand indigenous upstream capacity is a major constraint to pursue activities in this field, which is likely to further slowdown due to the new subsidy mechanism. He further informs, “Eight months back we had submitted a proposal to ONGC board and convinced that the marginal fields that we offer to third party
Country: Malaysia Fields: Cendor, Berantai Fields and Balai Cluster Total marginal fields: 106 Proven Recoverable reserves: 580 million barrels Field Development • • • •
•
•
Strategies, Reforms & Outlook
Cendor Field discovered by Amerada Hess in 2001, estimated recoverable resources of 12 million barrels (MMstb) of oil. In 2004, Petrofac acquired Amerada Hess’ interest and assumed operatorship of Block PM304 First oil achieved in September 2006, field developed using leased Mobile Operating Production Unit (MOPU) Cendor Phase 2 development and other new developments in PM304 increased estimated recoverable resource to over 200 MMstb, a growth of more than 16 times from when it was discovered. Production commenced in Berantai field in 2012, the field achieved increase in estimated recoverable gas resources by 15% compared to 2011. Pre-development work of Balai Cluster has also given early indication of increase in resources estimates.
• • • • •
•
Petronas, Malaysian NOC had introduced Risk Service Contracts (RSC) for marginal field development These contracts extend over a period of 15 years, where the contractor is the service provider responsible for upfront capital investments. Payment to contractors commences upon first production and be paid throughout the duration of the contract. RSCs strike a balance in sharing risks with fair returns for development and production of discovered marginal fields. Introduction of tax breaks in late 2010 to spur upstream investment amid declines in oil output and reserves. The incentives included cutting tax rate to 25 per cent from 38 per cent for developing marginal fields. Petronas dominates development of Malaysia’s marginal fields, at least partly because of the high tax rate. Malaysia has 106 marginal oil fields containing 580 million barrels of oil with Petronas having firmed plans to develop 25 per cent of the fields to replenish its oil reserves and generate additional revenue streams
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Country: Nigeria Field: Umusadege Field Total marginal fields: 251 Proven Recoverable reserves: 2.3 billion
• • • • •
• • •
Field Development Field discovered through exploratory well UMU-1 in 1974 Awarded for development in 2003 to Mart Resources Inc in 2003 First commercial production commenced from the central part of the field in 2008 Dual string completions used for producing from two zones simultaneously Initially 6 development wells completed and production initiated in early 2010 @ 4000 bopd with an early production system (EPS) for phase-I development while the main central production facility being created Production level rose to 12000 bopd by 2012 through additional drilling and exploration success in eastern and western part of the field. Reserves increased from about 15 MMbbl in 2009 to 23 MMbbl in 2012 The project, despite several challenges viz. regulatory framework & approval processes, funding (initial debt and equity), exporting oil from Nigeria, oil field equipment availability, managing local relationship etc. is a success story of marginal field development in Nigeria
operator be given international crude prices to encourage them to put the fields on production. Now the 56 per barrel USD price for crude, which ONGC gets as against USD 100 per barrel of international market rate was a major constraint for the company. ” At that time ONGC advocated offering the price USD 100 per barrel to the producers based on the argument that subsidies at that point of time were being offered to the oil marketing companies for their incurred losses and not on the production, which worked well at that point of time and ONGC could offer the international price. However, now that the government is linking the subsidy burden with production will definitely affect the economics of development of marginal fields and we will not be able to offer market price to the operators,” he expresses. “Earlier, it was only the oil marketing companies, which had to bear the subsidy burden but the now policy mandates the oil producers to bear this, which is now compelling us to rethink about development of marginal fields owned by ONGC,” says the Executive Director. ONGC has spoken to the Secretary, Ministry of Petroleum and Natural Gas (MoPNG) and clearly stated that in the given scenario of subsidy mechanism it is not economically viable to develop the marginal fields. “In fact, during our discussions with the Secretary we had emphasised on monetising these assets as an imperative for India towards reduction in import dependency and outflow of the foreign currency at the time when the rupee prices are sliding against the dollars,” says he. The experts from Indian hydrocarbon major have already carried out an exercise to establish the economics of developing the marginal fields profitably and will present the note to the MoPNG. “ONGC is currently working on fresh proposal seeking concessions and recommendations, which will shortly be presented to the Ministry based www.oswindia.com
•
•
• • •
Strategies, Reforms & Outlook A real turning point - Introduction of Marginal Field’s Decree (MFD) in 90’s for indigenous participation in the industry to pursue aggressive exploration for production capacity building & increasing country’s oil & gas reserve base. Marginal Fields Programme was intended to checkmate the avalanche of reported oil and gas discoveries in the Niger Delta through time that remained undeveloped /unproduced and, in a few cases, only partially appraised. 24 licences were awarded for marginal field development in February 2003, out of which currently 9 are on production. Presently there are about 251 marginal fields in Nigeria with an estimated 2.3 billion barrels of proven recoverable. oil reserves Out of the 178 oil blocks awarded, the 90 oil fields given to indigenous companies are producing about 6 per cent of Nigeria’s crude oil, while other 83 oil fields given to multinationals, are producing the remaining 94 per cent
on which we will take the decision to pursue the plans for developing these assets,” the Executive Director states. SWIMMING AGAINST THE TIDE Despite all the challenges, we have continued with the development plans for marginal fields through in-house efforts and service contracts, Chaturvedi says. ONGC came up with first round of service contract for the onshore marginal fields development in 2004 and out of 19 fields, awarded 8 fields, one of which is already producing in Gujarat. During the second round, the NOC offered offshore fields but could attract bids for 4 fields only of which the company withdrew one field at the last minute and the cluster of 3 other fields, which was offered to a joint venture of HPCL, BPCL and Malaysian E&P operator Trenergy. The consortium could not complete the assessment/ development plan and hence withdrew. Now, ONGC is developing the field on its own, Chaturvedi informs. The NOC organised third round of outsourcing onland fields in 2006. So far, ONGC has successfully developed three fields in Andhra Pradesh, which together produce 50000 cum of gas and 7 other fields are being lined up for production. The company plans to put up 26 fields for bidding but the plans are on hold, because of the change in subsidy mechanism. “If the Government agrees to exempt marginal fields from subsidy mechanism, we may go ahead and award these fields,” he informs. Though the oil major is encouraging the private players for participation, Chaturvedi expresses that unless it is a profitable venture the private investors cannot be attracted. “We will wait for the Government’s decision and only if the government agrees that subsidy will not be loaded from the production from the marginal fields, then only probably sw we will go ahead,” he concludes.
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features Unconventional Resource
A ‘White Elephant’ for India Despite the associated challenges that come with development of shale gas assets, world over, economies have chalked out the roadmaps and trying to translate the US success story. India, with its increasing energy demand-supply gap is now compelled to address the issues and accelerate the development of existing hydrocarbon resources with special attention to this very up-and-coming energy source - shale gas. However, as Debashish Mishra , Senior Director, Deloitte India, believes, “It will certainly take more than what can just be seen to replicate the US shale success story in India.” In an exclusive interview with Mittravinda Ranjan and Rakesh Roy , he further shares his views on why at present shale gas is a distant dream for India.
Successful monetisation of shale gas assets in the USA, which accounts for almost 20 per cent of the country’s total gas production, is one of the most discussed subjects in the oil & gas industry forums world over. Recent Deloitte report Oil and Gas Reality Check 2013 explains various stages of development of shale gas assets as – dormant, where the development is confined to feasibility studies with very little or no-activity such as Poland; nascent, where the Government aims at reducing dependence on gas imports and offers subsidies to encourage development as in case of China; incubator, where commercial production has already started and new basins are being tested for development like in Argentina, which is also witnessing an increase in new entrants and M&A activities in the country. The fourth stage - decoupler, where the new supplies are linked to the demand centers and where there is a fierce competition to maintain profit margins that countries like Argentina and the USA are likely to witness in the future. And, the last stage is - globaliser, where countries have the ability to produce shale gas at highly competitive price and companies seek higher price realisation in global markets as in case of the USA. A FAR-FETCHED DREAM Although India has been discussing shale for a long time and has even announced the shale gas policy, developing the assets is still a far-fetched dream. Mishra expresses “We are not even at the dormant stage since there are not detailed studies that can prove presence of enough shale gas formations in the Indian Stage
Development Objective
Representative Country
Dormant
Feasibility
Poland
Nascent
One best way (target single shale China basin)
Incubator
Mutiple best ways (target multiple Argentina basins)
Decoupler L i n k n e w s u p p l i e s to d e m a n d Argentina centres Globaliser Access new sources of demand Stages of Development for Shale Gas
US
geology.” In the absence of such extensive information, it will be very difficult to even assess the true available potential in the country, he notes. Moreover, given the high population density and associated environmental threats such as ground water contamination etc., it may be difficult for India to pursue the plans in this direction, he adds. AN EXPENSIVE AFFAIR Mishra notes, “Though the technologies are available, these are prohibitively expensive outside USA. Drilling one well costs nearly USD 15-20 million (approx.` 120 crore) which is very steep. Moreover, most of the countries lack availability of indigenous technologies that further makes it difficult to produce the gas.” He explains that unlike other countries, USA always has technical expertise as well infrastructure for hydrocarbon sector that has enabled the companies to venture into development of shale gas assets in the country. Additionally, the business model in USA allows the investors to operate to have complete freedom of allocation and pricing the output thus enabling them to take informed investment decision, he says. Citing the example of Poland, where ExxonMobil was working on developing shale gas assets, the company quit as soon as it realised that it was not viable to produce due to prohibitive costs and that the earlier potential the company was incurring. “It would be no different in case of India as we do not have indigenous technologies and will have to acquire the required expertise,” he expresses. Mishra stresses on the need of exploring the existing sedimentary basins which could have significant potential and advocates framing congenial regulatory and policy to attract investments to address the concurrent issues. “Traditionally, India has a complex regulatory and policy framework in addition to the hydrocarbon exploring policy, which has elicited debates on production sharing and royalty issues etc,” he notes. The government has been debating on replacing PSCs with Revenue Sharing Contracts (RSC) during the 10th round of NELP, but the final decision is yet to be taken. “India needs a robust policy framework to attract investments for sustaining long term growth of country’s hydrocarbon sector,” Mishra observes.
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He considers financing of oil and gas projects as another major hurdle that the E&P players have continued facing even after this sector was opened to the private players. Comparing the capital markets in the USA and India, he states that USA has highly evolved capital market that allows a lot of flexibility for the investors to enter an investment at every stage of the development which does not exist in India at present. Adverse impact on the environment has completely taken wind out of shale gas in Europe and even many countries are discouraging development of shale gas assets despite the presence of technically proven reserves. The current process of Fracking is highly water intensive and also involves use of chemicals to extract gas from the rocks, which lie much beneath the aquifers that supply drinking water thus creating possibilities of affecting the water quantity and quality of ground water. Within India on-shore exploration has been very challenging because of high population density. In USA, most of the shale gas reserves are present in regions that are scantily populated. But even USA has been receiving a lot of flak from the locals because of ground water contamination. THE REAL CHALLENGES In addition to technology, policy, financing and environmental challenges, overground challenges such as lack of clarity in defining the ownership rights for common acreages bearing conventional and non-conventional energy resources could pose substantial risk to the operators, Mishra states. Appreciating Veerappa Moily, the Honorable Minister for Petroleum & Natural Gas, Government of India, for raising the issue of harmonisation of ownership rights for the existing developers involved exploring in same acreage, Mishra explains that being high risk business, investors always seek clarity on the ownership rights before foraying into any new investments and this surely is a positive move.
>>Energy Information Administration (EIA) estimates China having 1700 trillion cubic feet (tcf ) instead of 800 tcf, a current technically proven estimate which could be almost double of what US has. Presently, there is a lot of negative sentiment prevailing amongst investors due to intervention of Government in output pricing and allocation. He notes that investors in many countries are facing this issue wherever the government tries controlling the price, but he is confident that bringing in transparent mechanism in gas pricing will surely gravitate the interest of major players in the Indian hydrocarbon space. TAKING THE PICK Mishra informs, “In the conventional space, world is actually entering into a golden age of gas and there has been a surge in the availability of natural gas world over and many countries may put the development of shale gas on the back burner for some time.” He says that the newly discovered gas fields in Israel have revealed some mind boggling numbers and these reserves are estimated to last for over 280 years and the last few years have seen Africa become a home ground for giants of oil & gas industry in countries like Mozambique, Tanzania and Nigeria which have promising conventional gas reserves offering credible alternative as environment friendly and possibly cheaper fossil fuel. Mishra enunciates “Owing to the huge gas finds in the region, Mozambique Tanzania and Nigeria will see huge investments in the years to come. Africa will be the battle ground for the next two decades between for energy hungry countries like India and China to secure energy supplies.” He further notes that it will take 4-5 years to develop a reasonably robust LNG infrastructure throughout the world, which will make gas a global commodity and result in decoupling of gas from the oil price indexing. In the next few years, Mishra expects that disparity of gas price across globe is not going to last forever. sw
“Like the rest of the global energy sector, the Indian oil & gas sector too is government dominated with maximum acreages being held by the National Oil Companies (NOCs) and though Government opened this to the private companies through National Exploration Licensing Policy (NELP). Still Government’s constant intervention in controlling the price and allocation of output further discourages the private players from NELPs. Cairn has been a big success story with more than 40 discoveries – 26 alone in Rajasthan. If India had today 5-6 companies or success stories like Cairn, the country wouldn’t have to depend on oil imports to the tune of 79 per cent, he rues. He advocates that the encouragement be given to the private sector participation like China, which has almost doubled its gas production in short span of almost six years and is also pursuing shale gas asset development plans aggressively by creation of congenial environment to attract investments. Time and again, he stresses on India’s need of having robust policy framework to provide level playing field to the E&P companies to operate profitably. www.oswindia.com
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features Infrastructure Development
Ignition of LNG in India India’s demand for energy is going to escalate in future. Against the backdrop of decline in domestic gas production in the country, India is more reliable on imports to narrow the demand supply gap. Looking at eco-friendly nature of Liquefied Natural Gas (LNG), it is expected that LNG imports will become a key part of our energy demands. Despite planning a number of LNG infrastructure facilities, the focus is on setting up Floating Storage Regasifiaction Units (FSRUs).
The Cabinet Committee for Economic Affairs (CCEA) recently approved the proposal to hike the natural gas price by approving the Rangarajan committee’s formula for gas pricing. The Rangarajan formula uses long-term and LNG import contracts as well as international trading benchmarks to arrive at a competitive price for India. The new price will apply uniformly to all producers, be it state-owned firms or private sector. Based on the price increase, it is expected that gas prices would be at the levels of about USD 8/MMBtu, which is a sharp increase from the prevailing price of USD 4.2 /MMBtu.
15 mmscmd from around 60 mmscmd in 2009-10. This has led to significant stranded gas based end-use capacity in the country. Thus, with decline of domestic production, the LNG imports are expected to further increase.
The need for such a sharp increase was mainly felt owing to India’s burgeoning primary energy needs. The country’s primary energy consumption has more than doubled over the last two decades. India is currently the fourth largest consumer of energy in the world and is facing an increasing deficit scenario as its domestic energy resources are not able to keep pace with the growing demand.
It is also evident that given the demand–supply gap, there still would be a significant requirement of LNG imports even if the supply were to ramp up owing to increase in investments in the domestic fields. According to the working group report for XII five year plan, the dependence on LNG which is currently around 40 per cent is likely to grow to 55 per cent by 2017.
INDIA DOMESTIC DEMAND SUPPLY FOR GAS India is facing significant shortage of domestic gas supply. In India, the natural gas production in 2012-13 was around 104 mmscmd, while LNG imports are estimated to be around 50 mmscmd. Some of the key importers during the year include Petronet LNG, GSPC, Reliance Industries and GAIL.
LNG IMPORTS IN INDIA The planned LNG import infrastructure reflects the yawning deficit scenario being faced by India. The country has become the fifth largest importer of LNG after Japan, South Korea, the United Kingdom and Spain, with a 5.5 per cent share in LNG trade. Currently, the three RLNG terminals operational in India are at Dahej, Hazira and Dabhol all at the west coast of India. Dabhol terminal (5 MTPA) is expected to operate at partial capacity of 1.5 MTPA for the initial period due to lack of breakwater facility at the terminals port. The graph below represents the proposed increase in regasification capacity from the land based RLNG terminals in India.
The domestic gas output from the country’s largest gas fields in the east coast operated by Reliance Industries Limited (RIL) has declined rapidly to about
( S o u r c e : R e p o r t o f t h e R a n g a r a j a n Co m m i t t e e o n t h e P S C M e c h a n i s m i n Petroleum Industry)
According to Central Electricity Authority (CEA), the gas based power plants in India are operating at low plant load factor(s) of 30-35 per cent. Given this backdrop, the Government approved the gas price increase with the view of increasing investments domestic exploration and production in the country.
Source: KPMG Analysis, Analyst Reports
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Region
States with gas infrastructure S t ate s w i t h o u t g a s infrastructure
Western
Gujarat, Maharashtra
Goa
Northern
Delhi, UP, Rajasthan and Haryana
Punjab, J&K,HP, Uttrakhand
Central
MP
Chhattisgarh
Southern
TN, AP
Kerala, Karnataka
Eastern
-
B i h a r, We s t B e n g a l , Jharkhand, Orissa
North Eastern Assam, Tripura
Meghalaya, Sikkim, Arunachal Pradesh, Manipur, Nagaland, Mizoram
Source: Working Group Report for 12th plan – Oil & Gas Industry
Dahej LNG Terminal
Since land based terminals have a longer construction period and are capital intensive, a large number of players have proposed to set up Floating Storage and Regasification Units (FSRU) to meet the natural gas deficit. Some of the proposed FSRU projects are at Kakinada, Dighi Port, Pipavav, etc. Companies like D e l i ve r e d G a s Power Price Price ($/ MMBtu) (` per unit)
Power Price ($/unit)
LNG Price Scenario 1
20
10.2
0.17
LNG Price Scenario 2
14
7.5
0.12
Domestic Gas Block(s)
8
4.7
0.06
Source: KPMG Analysis
GAIL, APGDC, Shell, GDF Suez, Reliance Power, HPCL, Swan Energy Ltd., H-Gas, etc. have shown keen interest in setting up FSRUs at various locations. All in all, several projects are either planned or expected to come up in the coming years. However, some of the key enablers that would enhance viability of such projects include: • End-user affordability • Adequacy of gas infrastructure • Enabling policy and regulatory support Industrial
Commercial
Tariff range
INR/KWh
6.7
9.2
Affordability for LNG
USD/MMBtu
13
19
Affordability for LNG USD/MMBtu [50% Pooling with Domestic Gas]
~18
Source: KPMG Analysis
AFFORDABILITY It may be appreciated that the power tariff from coal based stations in India is around ` 4-5.50 per unit. This is expected to increase owing to increase in imports, pass through of the losses and rising costs suffered by distribution companies. However, despite the increase in tariff, the power distribution companies may not be in a position to afford LNG based power for base load requirement as it is evident in the following table. www.oswindia.com
However, if the high cost LNG were to be pooled with domestic gas, the affordability of end-consumers like power plants could increase to offtake LNG. Thus, as an example as indicated in the table below, if the industrial power tariff for a state is ` 6.7 / Kwh, the power plant would have an affordability of USD13 per MMBtu for LNG. However, if 50 per cent domestic gas is available at an assumed price of USD 8/ MMBtu, the affordability for LNG increases to USD 18/MMBtu. For one of the states, the State Electricity Regulatory Commission has allowed the electricity distribution companies to implement Expensive Power Supply Scheme based on procurement of expensive power using RLNG from state Independent Power Producers (IPPs). Thus, consumers wishing to avail continuous round the clock supply will have to make applications indicating the electricity requirement and the load factor. The electricity distribution companies would procure the power from the IPPs and supply it to the consumers on “no profit-no loss basis”. The increase in domestic gas prices would reduce the difference in domestic gas based generation and LNG based generation thus encouraging few more states to enable such schemes. Thus, even at high prices LNG offtake can happen in sectors such as power, fertilizer if the domestic gas allocation is restricted to certain defined percentage of the plant requirements or if innovative policy interventions are used. Further if there is a specific policy encouraging gas for peak power generation the affordability is likely to be higher. The other gas consuming segment i.e Industries and City Gas have comparatively better affordability for LNG as the competing fuels are liquid fuels such as Furnace Oil, LPG etc the prices of which are linked to international prices. Given the rapidly changing global gas pricing dynamics, it would be equally important to have innovative price formulation and efficient sourcing of gas in order to increase LNG offtake in the Indian markets.
>> In India, the natural gas production in 2012-13 was around 104 mmscmd, while LNG imports are estimated to be around 50 mmscmd. Some of the key importers during the year include Petronet LNG, GSPC, Reliance Industries and GAIL.
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execution of projects. On tariff determination, it is important that a level playing uniform methodology is followed. Any retrospective tariff implementation orders could send negative signals to investors and lead to sub-optimal investments in the long run. INVESTMENT OUTLAY The total capital investments in the gas midstream and downstream sector for the 12 th five year plan has been summarised in the table below: With expected investments in the gas infrastructure facility of around USD 200 billion in the next five years, natural gas is poised to play an important role in the Indian energy mix. But, this will be a reality only if enabling policy and regulatory measures are in-place. SUMMARY In summary, given the demand supply scenario, LNG would have an important role to play in the Indian energy mix. Given the requirements, a number of LNG infrastructure facilities have been planned. There is an increased focus on floating storage regasification units (FSRU) as it takes less time for implementation as compared to land based terminal. The affordability of key consuming sectors especially power is on the rise and could afford LNG with innovative mechanisms in place. Thus, it is important to ensure a stable policy and regulatory regime to develop gas infrastructure throughout the country. Furthermore, gas sourcing at the appropriate price is the single most important factor that can decide the extent of LNG penetration sw in Indian markets.
Hazira LNG Regasification Terminal
ADEQUAC Y OF GAS INFRASTRUCTURE In India, the present pipeline infrastructure is around 13,000 Kms with a total design capacity of around 334 mmscmd. The major pipeline capacity is confined to Northern and Western parts of the country. It may be pertinent to highlight that given the proposed increase in domestic prices to spur investments and planned RLNG infrastructure it is critical to implement the country-wide gas grid as envisaged. The proposed national grid would be essentially connecting many states that don’t have pipeline infrastructure. Though implementation of pipelines is typically assumed to be less intensive on time as compared to the implementation of RLNG infrastructure or development of wells, there have been case examples of extensive delays in laying pipeline infrastructure. Hence, there is a need to provide adequate thrust by the Government on pipeline infrastructure. A transparent mechanism that addresses the issues of right of way, land acquisition and other issues is required to be put-in place. An empowered coordinating mechanism at the Central Government level could help in faster 12 th Plan ( ` Billion)
Investment Particulars LNG Terminals
312
Pipelines
439
CGD Infrastructure
403
Total Investment
1154 th
Source: Working Group Report for 12 plan – Oil & Gas Industry
Arvind Mahajan Partner and National Head Energy, Infrastructure & Govt, KPMG (With contributions from Sanjay Sah, Director & Uday Alamuru, Manager, KPMG) Offshore World | 21 | JUNE - JULY 2013
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features Technological Advancements
SCALING NEW HEIGHTS Hydrocarbon companies have continued venturing into difficult terrains as the reserves have continued to diminish in the easy to explore areas. The geographical challenges and the need to monetise the unconventional resources has deemed the necessity of advanced techniques and technologies to develop the assets. The author dwells upon the technological advancements that are enabling the operators globally to enhance the production levels from existing and new fields.
Hydrocarbon sector plays a vital role in the economic growth of any country. Given the ever-increasing demand for crude oil, key driver and deterrent of country’s import bill and in-turn trade deficit would be the global energy price. India’s domestic oil and gas production have also dipped to around 5 per cent Year-On-Year. India’s hydrocarbon sector industries, along with government impetus, is focusing on having a long-term policy for the hydrocarbon sector by adding more reserves, maximising production, achieving cleaner and more energy efficient production. We need to ensure that we stay focused on oil security, technological advancements in exploration & production (E&P) and use of alternative fuels in order to meet energy requirement of the country. SCENARIO India’s oil & gas industry originated in Assam when oil was first struck at Digboi in Assam in 1889. Initially, oil exploration and production concentrated in the North-Eastern region, particularly Assam where the daily crude oil production averaged just around 5,000 barrels per day. The first refinery was set up at Digboi in 1901, as an advent in the downstream sector. The Government of India realised that oil & Gas sector plays an important role in the overall economic growth of the country and subsequently announced that petroleum would be a core sector industry, under the Industrial Policy Resolution of 1954. Government of India has further introduced many schemes and initiatives to ensure that India’s energy demand is met. Announcement of New Exploration Licensing Policy (NELP) in 1997, as part of its Hydrocarbon Vision 2025 by Ministry of Petroleum and Natural Gas India, is a landmark 25-year planning document in this direction. It also stresses on awarding licenses for exploration through competitive bidding system in order to attract major oil and gas companies by expeditious evaluation of bids and award of contracts on a time bound basis.
Supply/Demand-Petroleum Products (in MMT) Year
Demand (without meeting gas deficit)
D e m a n d Estimated Estimated (with refining crude meeting gas capacity requirement deficit)
1998-1999 91
103
69
69
2001-2002 111
138
129
122
2006-2007 148
179*
167
173
2011-2012 195
195**
184
190
2024-2025 368
368
358
364
Source: KPMG Analysis
In order to meet the oil & gas demand, enhance hydrocarbon reserves and increase oil and gas production; Indian Oil & Gas Industry is exploring and implementing various options including effective project management techniques, focus on R&D and utilising latest technological breakthroughs. Project Management Principles as professed by Project Management Institute (PMI) play a very pivotal role in seamless execution of projects. Due to increased necessity for optimising the natural resources, organisations have been stressing on various advancements over and above the conventional methods used in the hydrocarbon sector. In line with the global ideologies, Samsung Heavy Industries India Pvt. Ltd. also ensures that design and engineering of offshore projects comply with the statutory rules and regulations and address Health, Safety, Security and Environment (HSSE) concerns. Samsung Heavy Industries India Pvt. Ltd. endeavors to recommend various value engineering suggestions and optimised solution themes to customers as part of effective project execution.
>>Under a new policy aimed at boosting domestic output of fossil fuels, companies will be allowed to extract oil and gas ENHANCED OIL RECOVERY (EOR) from shale rocks in more than 250 blocks in India. Six basin; EOR is used to mobilise and recover that percentage of residual oil that cannot Cambay, Assam-Arakan, Gondawana, KG onshore, Cauvery be captured by water flooding alone, or by the use of physical, mechanical, onshore and Indo Gangetic basins, have shale gas potential. As mentioned in the Hydrocarbon Vision 2025, the gap between supply and availability of crude oil, petroleum products as well as gas from indigenous sources is likely to increase over the years as follows: www.oswindia.com
or procedural processes. EOR technologies are specifically designed to affect mostly the oil that remains in the reservoir. Few of the most commonly used EOR technologies include gas processes like nitrogen and carbon dioxide (CO2), thermal processes like steam and fire-flooding, and a variety of
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chemical processes that include surfactant, surfactant-polymer (S-P), and alkaline-surfactant-polymer (ASP). EOR increases the amount of crude oil that can be extracted from a field, over and above conventional primary depletion or basic water flooding which typically will recover 20 per cent to 40 per cent of the stock tank oil initially in place (STOIIP). By using typical EOR methods, an additional 10 per cent to 20 per cent of STOIIP can be extracted from a field. Cairn India Ltd. has been using this technology in oil fields in Barmer, Rajasthan, India and Oil & Natural Gas Corporation Ltd. (ONGC) in 14 fields. However, more efforts are required to minimise the environmental impact of using polymers and chemicals. We need to develop environmentally acceptable production and treatment systems through a holistic environment management system that include resource recovery and energy use. FRACKING Fracking, or hydraulic fracturing, is the process of extracting natural gas from shale rock layers deep within the earth. Fracking makes it possible to produce natural gas through extraction in shale rocks that were once unreachable with conventional technologies. Recent advancements in drilling technology have led to new man-made hydraulic fractures in shale rocks that were once not available for exploration. India will allow explorers to produce shale oil and gas for the first time as Asia’s second-biggest energy consumer seeks to cut reliance on imports. India will launch its first-ever bid round for exploration of shale oil and gas by December 2013. Under a new policy aimed at boosting domestic output of fossil fuels, companies will be allowed to extract oil and gas from shale rocks in more than 250 blocks in India. Six basin; Cambay, Assam-Arakan, Gondawana, KG onshore, Cauvery onshore and Indo Gangetic basins, that may have shale gas potential. It is estimated that this will slash the energy import bill by 50 per cent in seven years and to zero by 2030. However, Fracking technology is not immune to controversies. Anti-Fracking communities strongly believe that clearing land to build new access roads and new well sites, drilling and encasing the well, fracking the well and generating waste and trucking out the vast amounts of toxic waste contribute to air and water pollution risks. Global regulators, in turn, periodically assess pollution risks and delve on the fact that natural gas is the cleanest-burning conventional fuel, producing lower levels of greenhouse gas emissions than heavier hydrocarbon fuels such as coal and oil. MULTI PHASE PUMPING Multi Phase Pumping involves transportation of a mixture of oil, water and gas from a producing well to a distant processing facility. This differs from the conventional technology in which fluids are separated before being pumped and then compressed through separate pipelines. It is estimated that by using this technology, there is around 30 per cent savings in cost also due to reduction in Capex, increase in well fluid flow and decreased footprint of operations. This technology has been used in Rawa field, Cairn India and by ONGC, India. DEEP SEA DRILLING Deep sea drilling is the exploration and extraction of petroleum and natural gas at depths of several thousands of feet (approx. one thousand meters). Both oil exploration and gas exploration deep sea drilling have only become feasible in the 21st century for several key reasons. More organisations are concentrating on deep sea drilling due to the fact that rising price for fossil fuel commodities as well as
advances in technology have made the practice more proven and also the fact that lower-risk conventional oil basins are maturing. In a recent development, ONGC drilled a well at a world record 3,165 meters water depth offshore country’s east coast with Reliance Industries rig. The DDKG1 rig drilled well NA7-1 in exploratory block KG-DWN-2004/1 in India’s east coast at a water depth of 3,165 meters. COAL BED METHAN (CBM) CBM has become one of the most important energy sources of last few decades in the unconventional energy sector. As per Directorate General of Hydrocarbons (DGH) database, India is having the third largest proven coal reserves and is the 4th largest coal producer in the world. Prognosticated CBM resource has been estimated to be around 4.6 Trillion Cubic Meter (tcm). ONGC has firmed up plans to rope in strategic private sector investors in CBM assets in West Bengal and Jharkhand. ONGC has found four areas in eastern region; Raniganj (West Bengal) and Dhanbad, Bokaro and Hazaribag in Jharkhand; which have CBM reserves. Each block is estimated to have approximately one trillion cubic feet of methane reserves. We need however to take care of the environmental concerns as the residual water produced due to the result of coal seam dewatering is highly saline in content and could possibly be toxic to the soil quality and vegetation in the immediate environs of a CBM project. India’s hydrocarbon sector is witnessing massive growth and as a result many innovative technologies are being utilised and further researched including: • Intelligent Wells • Intelligent Platforms • Digital Oil Fields • Subsea Processing • Coal Gasification • Liquefied Natural Gas (LNG), Gas to Liquid (GTL) and Gas to Wire (GTW) technologies PATH AHEAD There is an urgent need to move positively towards energy security with optimised cost, in order to: • Enhance Recovery • Ensure Cost Effective Drilling • Develop modular technology solutions • Reduce CO2 Emissions • Develop greener alternative products to replace existing hazardous chemicals • Develop a holistic eco-system approach towards environmental risk assessment, monitoring, control and mitigation • Develop methodologies to avoid accidental discharge and ensure strictest compliance to HSSE guidelines. India’s hydrocarbon sector is progressing steadily and it is crucial that we all contribute in a constructive manner towards a greener environment to achieve sw energy security. Kumar Saurabh Asst General Manager Samsung Heavy Industries India Pvt Ltd Email: kr.saurabh@samsung.com
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features Optimising Information
Monitoring Instrumented Oil Field Hydraulic fracturing (Fracking) has drawn lot of flak from the environmentalists for contaminating aquifers and causing seismic activities. Fracturing requires efficient reservoir monitoring techniques to collect microseismic data of the operations to understand the heterogeneity of the reservoir and geologic conditions of the surrounding strata. The authors advocate installation of Passive Micro-seismic Monitoring (PMM) system that can provide enough reliable data to make decisions about the probability of induced fractures affecting the aquifers, other subsurface resources or low level seismicity.
We hear a lot in the media about the downsides of hydraulic fracturing (Fracking) operations in the oil and gas sector. Years ago, in some regards, these fears were well founded. But today, with the way the technology has developed, Passive Micro-Seismic Monitoring (PMM) can be deployed relatively easily and can provide enough reliable data to make decisions about the probability of induced fractures affecting aquifers, other subsurface resources, or inducing low level seismicity. A proper PMM installation will help monitor fracture growth, increase production, and avoid induced seismicity events with the potential to put lives at risk and cause substantial damage to equipment and nearby structures. When an applied load causes rock to fracture some of the released strain energy propagates through the surrounding rock mass as vibrations which can be detected by the appropriate sensors. In some cases these are felt or heard by people; mineworkers often hear minor events as snapping or clicking noises; small earthquakes, magnitude 3.0 on the Richter scale, can be felt near the epicentre by the general population.
The fracturing of the rock can be caused by tensile, compressive, or shear forces. The location and energy released by the fracture can be determined with reasonable accuracy by analysing the arrival times and characteristics of the vibrations. On a global scale this is how seismologists locate the hypocentres, and estimate the intensities of earthquakes. On a local scale the procedure can be used to locate shear surfaces beneath a landslide, or pillar failures in a mine, and on a still smaller scale, this is how the extent and location of the induced fractures created within a reservoir by a hydraulic fracturing operation can be derived. Every natural or human activity on or in the Earth’s crust causes changes in its state of stress. Under some circumstances, these perturbations of the stress field can trigger events which release enormous amounts of elastic strain energy that was stored within the deformed rock mass. An example is the 1906 San Francisco earthquake, which was caused by the shear rupture of the San Andreas fault along a length of nearly 500 km, the actual relative movement across the fault reached nearly 9 metres in some locations. Sometimes the data associated with changes of stress or strain can be used to solve practical problems. One of the first applications of acoustic monitoring in a non-mining situation in Canada was the identification of multiple shear planes beneath the Downie Slide, a post-glacial feature in the Columbia River Valley in British Columbia. There was a concern that the filling of a new reservoir would re-activate the ancient slide. To provide information about the position and level of activity on the existing failure planes, geophones and hydrophones were installed on boreholes drilled through the slide. The failure planes and the relative activity were identified and this information was used to design an extensive slope dewatering and drainage programme.
Production of data acquisitions require very precise factory acceptance test before they are shipped to the job sites.
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This work was done with very primitive analog instrumentation, chart recorders and magnetic tapes. It was a time consuming task to process the data, which saw personnel going through line after line of recorded data looking for anomalies that
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>> A proper PMM installation will help monitor fracture growth, increase production, and avoid induced seismicity events with the potential to put lives at risk and cause substantial damage to equipment and nearby structures. indicated that a particular elevation was more active than another and correlating this with the results of borehole permeability testing. There has been a dramatic evaluation of technology over the last forty years. With state-of-the-art digital recorders, tri-axial down-hole sensor packages and real-time data rendering, engineers can monitor geo-mechanical phenomena at depths of greater than 10,000 feet. In the oil and gas sector, production and fracking operations can be monitored in near real-time so precisely that they can shut down immediately if a safety or operational situation arises. The optimisation of the sensor arrays used to acquire passive microseismic data is dependent upon many factors. These include aspects of the array in relation to the expected acoustic source, number of sensors being deployed, acoustic dampening properties of the surrounding rock, surrounding natural and anthropogenic noise that could be heard by the sensors, and of course, accessibility, environmental conditions, and work crew safety. In order to understand how the acoustic waves are travelling from the source to the receiver, we must know the physical properties of the rock the wave is propagating through, specifically its density, seismic velocity, and anisotropy. Knowing these factors allows a geophysicist to accurately trace the micro-seismic signal back to its correct source location, with an acceptable degree of uncertainty. Finally, once the locations of micro-seismic events are known, real-time i n t e r p re t a t i o n s c a n b e m a d e w i t h re g a rd s t o f r a c t u re m a p p i n g, and hydraulic-fracture treatment stages can be modified on the fly for optimised production.
A central processing unit is usually responsible to supply power to measuring nodes and time stamp the detected microseismic events.
This translates directly into savings because on-site equipment, manpower and production all benefit from reduced downtime associated with past practices, in particular the need to shut down operations while local geophysicists examined multiple lines of data. There are also a couple of different strategies for deploying sensors: the first is a surface array, usually laid out in a grid pattern over several square miles above the laterals being hydraulically fractured. These types of systems suffer from inherent noise problems; they tend to pick up acoustic emissions from everything including road traffic, work-over rigs and pumps. For this reason, the number of sensors deployed is substantially more than in a down-hole array where the inherent noise level is much less. Surface geology is a very important consideration when deploying a surface array. If the surface rocks encompassing the sensors have a high degree of acoustic dampening (attenuation), the signal will be difficult to see, especially in the midst of all the noise, even with advanced filtering techniques. For example, acoustic waves do not travel well through unconsolidated sand and gravel like that deposited in glacial till, which is common for surface geology. Surface arrays must be considered from region to region.
Data acquisitions and sensors are buried under ground and they are capable of functioning in harsh environments without human intervention for tens of thousands of hours.
The second type of system is a down-hole system. This type of system is typically designed to be permanent or semi-permanent and it is deployed after an earth model
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has been developed for a specific reservoir that will go into production. Alternatively, there may be environmental concerns which need to be monitored over the ``Life Of Field� (LOF). There are some capital costs associated with the deployment of LOF systems but the major benefits include security, no ambient noise to corrupt the data and reliability. These systems can be deployed and require virtually no maintenance over their useful service life, which can easily exceed 20 or more years. Surface or buried arrays continue to evolve at an exponential rate. Reliability and clarity in the algorithms continue to provide solid data so that operators and concerned parties feel comfortable that oil and gas operations are doing everything in their power to mitigate the potential of a catastrophic failure contaminating groundwater, watercourses or human occupied areas. In addition to monitoring fracture growth and optimising production, PMM systems are helpful for monitoring and mitigating induced seismicity. This happens when fluid injection intended for reservoir stimulation enters pre-existing faults, causing earthquakes. The pore fluid pressure reduces the friction between the two faces of the fault, resulting in a sliding motion between two rock masses, which creates seismic activity of much greater magnitude than expected from hydraulic-fracturing events. The problem with many of these induced seismicity events is that the current array of global seismometers is not dense enough around the source to be detected. With a proper PMM installation using sensors that have enough bandwidth to detect the low magnitude micro-seismic events, and the higher magnitude induced seismicity fault reactivation, these hazards can be monitored and ideally avoided. The operator and the geophysicist work together to monitor the magnitude and geometry of the seismic events, and regulate pump
Data processing center can be permanently set up onsite for the life of the project. Alternatively a mobile unit can be customized to perform data processing
pressure accordingly to minimise and avoid induced seismic activity. If there is any indication that the fracture fluid is entering existing fault pathways, the operator is notified immediately and can make an informed decision for future stimulation. According to a recent study by Richard Davies of the Durham Energy Institute at Durham University, there are currently three known induced seismicity events that have created earthquakes large enough to be felt on the surface. Although this is a small number compared to the amount of fracturing operations around the world, induced seismicity cannot be ruled out. Additionally, the increasing number of planned fracturing jobs means statistically there will be an increased number of induced seismicity events. PMM provides a useful means of securing the integrity of a hydrocarbon reservoir. Each reservoir is unique and will have different geomechanical properties, will require different surface or buried array specifications, and will have different fracture characteristics, however the hazards associated with fluid injection remain consistent. sw
Taylor Milne, GIT Junior Geophysicist The Weir-Jones Group
Heavy duty cables are laid down and buried in a trench
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Andrew Weir-Jones Operations Manager The Weir-Jones Group Offshore World | 26 | JUNE - JULY 2013
features Case Study
‘Aberdeen’ of India India depends on several other nations to fulfill its petroleum energy needs. India imports more than 60 per cent of its crude oil requirement due to a huge demand-supply gap. India is the 9 th largest crude oil importer and the 6 th largest consumer of crude oil in the world. A large portion of oil is imported from the Middle East and African nations. India’s eastern coast is well known for reservoirs with extreme High Pressure/ High Temperature (HPHT) tight-gas formations, often referred to as ‘Aberdeen’ of India. Testing HPHT reservoirs and hydraulically fracturing with the same Drill-Stem Testing (DST) string is a big technological challenge. This article describes how technological development and a new approach have helped to test the extreme HPHT reservoirs in India with cost effective solutions so that the commercial viability of reservoirs can be determined. Exploring and testing such challenging zones and developing fields on the eastern coast of India will reduce the required import of oil and gas to some extent. This will also help the gross domestic product (GDP) growth. At present the oil and gas sector contributes over 15 per cent to the GDP of India.
Most operators face multiple challenges while testing such high pressure/ high temperature zones. When a major operator decided to evaluate reservoir potential in the East Coast Krishna Godavari (KG) Basin, it was recommended that all fracing or fracking (frac) and testing operations be combined into one trip, which will not only allow significant rig cost and time savings but will also provide the much needed flexibility for this critical operation. Many challenges had to be considered and mitigated for a single-trip operation, viz. reliable functioning of DST tools in extreme conditions for an extended duration, high pump rates through the DST string for effective proppant placement during hydraulic fracturing, limitations on downhole electronics from high temperature, annulus pressure limitations for annulus-pressure-responsive DST tool operations, and possible DST tool component damage during frac operations. Thus, DST tools with modifications such as a multi-cycle circulating valve with a debris tolerant mechanism, combinations of high temperature seals and a clear annulus fluid system
to enable extended testing and frac operations with a higher success rate were deployed. During multiple DSTs in HPHT environments and similar formations in India and globally, a major challenge has been observed in terms of debris settling in the ball and circulating sections of the multi-cycle circulating valve. This was addressed with tool modifications and resulted in the development of debris tolerant mechanisms. These mechanisms not only increased reliability of the tool performance in extreme conditions but also enhanced the frac operation through the DST string with high pump rate without affecting the operating capability of the equipment. After reviewing the methods to combine all required operations into one trip, the operator decided to deploy a full suite of multi-cycle DST tools rated to 450 degrees Fahrenheit (°F). The proposed string would perform pre-frac testing, mini frac, main frac, and post-frac testing operations in a single run. For the first run, tubing was run in the hole (commonly termed as the flex run) with a single shot tubing testing valve to flex the tubing using mechanical and electronic gauges. Generally, production tubing gets corroded and rusted when it is stored for a long period of time on rigs and at base. Flexing of the tubing helped to remove scale inside and outside of tubing, ensured restriction free inner bore, and also confirmed pressure test integrity of the tubing. The flex run also helped to determine static bottom-hole pressure and temperature. Static bottom-hole pressure data from this run provided the effective brine weight at DST tool depths under high temperature conditions. This accurate
Figure 1: Debris settlement in ball and circulating sections of a multi-cycle circulating valve in the past which resulted in the development of a debris tolerant mechanism for this valve
>>DST tools with modifications such as a multi-cycle circulating valve with a debris tolerant mechanism, combinations of high temperature seals and a clear annulus fluid system to enable extended testing and frac operations with a higher success rate.
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understanding of brine weight at packer/perforation depth and temperature helped to design the DST tools operating pressures precisely. After the flex run overbalance wireline perforation was carried out, the permanent sealbore packer was set on drillpipe. For the main DST-frac run, multi-cycle DST tools along-with HPHT mechanical & electronic gauges were deployed. The DST string was pressure tested at various stages while running in the hole to ensure integrity of all tubular connections. After reaching packer depth, space out was performed. Flowhead along with the blow out preventer (BOP) safety valve was connected to the string and stung into the permanent packer sealbore. The BOP safety valve has a RAM lock section which facilitates closure of a 5” BOP RAM so that the annulus can be isolated and pressure can be applied for operation of the downhole valves. The final string schematic shown in Figure 1 shows at this stage of the operation, cushion fluid was spotted through the multi-cycle circulating valve and then the multi-cycle circulating valve was cycled to well test position and the well was opened for pre-frac testing. The multi-cycle circulating valve deployed was capable of unlimited cycles with annulus operating pressure and it would go through different positions as demonstrated below in Figure 2. After pre-frac operation, a Diagnostic Fracture Injection Test (DFIT) was performed to understand hydraulic fracturing parameters such as In-situ stress, fracture closure pressure, and pump rates at various injection pressures. The operations performed as planned until the frac operation commenced, and injectivity could not be established due to gas migration and gel formation in the tubing. At this point, the multi-cycle circulating valve allowed reversal of the tubing contents by cycling it to the circulating position. After reversing out, frac fluid was spotted, the multi-cycle circulating valve was cycled to the well test position and the main frac operation was successfully performed. After main frac, a post-frac reservoir study was done. At the end of the post frac study, the well kill operation was carried out using the multi-cycle circulating valve.
Figure 2: Multi-cycle circulating valve cycle and tool position diagram
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>> DST tools maintained integrity, fraced through the string, and performed successfully to set a new record for the longest DST run under these conditions for the service company, and possibly, the industry. It’s a common phenomenon to encounter fluid losses after well kill operation on the wells where a frac was recently performed. The deployment of the multi-cycle circulating valve would have allowed the isolation of the formation after well kill operations by cycling the tool to circulating position. This would have resulted in avoiding losses of the costly brine – clear fluid system into the formation. SUMMARY This job demonstrated that the technological advances and the lessons learned from a new approach allowed successful frac operations in a single run under extreme HPHT conditions. The DST tools maintained integrity, fraced through the string, and performed successfully to set a new record for the longest DST run under these conditions for the service company, and possibly, the industry. Accurate and reliable downhole pressure and temperature data was recovered from mechanical and electronic gauges. Significant rig time and an overall cost savings was achieved. This operation will assist in planning future frac operations sw in the high temperature – high pressure environment.
Mahesh Sarode Milind Khati Halliburton Offshore World | 30 | JUNE - JULY 2013
OSW Marketing Initiative
Outokumpu: 80-yrs of Duplex Experience While some people may perceive duplex stainless steel to be a relatively new phenomenon, Outokumpu has been producing duplex grades for over 80 years. Describing duplex as the most sustainable steel, the article explains the company’s long history, the many uses of this versatile metal and emerging application for duplex stainless steels in the global market. Outokumpu history in producing duplex dates back to the 1930s when the first grades were developed to overcome shortcomings in the austenitic grades available at that time such as limited strength, susceptibility to intragranular corrosion due to difficulties to reach low carbon contents and issues related to stress corrosion cracking especially in the pulp and paper as well as chemical industry, Originally production was focused mainly on castings for the pulp and paper, chemical and petrochemical industries. Today while the oil and gas and chemical processing industries are the main consumers of duplex stainless steels, significant quantities are also used for architecture and construction, pulp and paper, desalination plants and chemical tankers.
giving low alloying costs are starting to replace commodity stainless grades like 304 and even 316, where the customer can benefit from the outstanding mechanical properties of the steel. For example demand for duplex in the building and construction industry in particular has grown due largely to these latest developments. Outokumpu have also been promoting lean duplex grades for storage tanks, from food and beverage applications where tanks are used for anything from wine to olive oil, to tanks for the chemical and petrochemical processing industries where duplex performs extremely well.” Recent Duplex Projects When considering where most duplex stainless steels are being used today there is no denying that tube manufacturers are placing very large orders, particularly those located in Germany and Italy. However new end-users are also turning to duplex. German pump and tank manufacturer Börger approached Outokumpu when they needed to fabricate larger biogas tanks than ever before, starting at 4,000 m3. The company chose the duplex
grade LDX 2404® for storage tanks and a combination of LDX 2404® and LDX 2101® for its process tanks. Switching from austenitic to duplex stainless steel reduced the weight of the tanks by 25%. For a project for Dow Chemicals in the Netherlands,lean duplex material was used in two tanks at Dow’s Terneuzen plant, the first time they have applied this lean duplex material. While the weight saving potential is always a factor – the tanks measured Ø22 x 21 m – the main focus was to optimize maintenance and inspection requirements. Terneuzen is located on the North Sea coast in a corrosive marine environment where carbon steel tanks need to be coated internally with epoxy resin and even stainless steel equipment is painted externally to prevent corrosion. Duplex stainless steels are not prone to chloride stress corrosion cracking like standard austenitic stainless steels, therefore painting can be avoided. The higher strength of lean duplex compared to carbon steel and austenitic stainless steel enabled
Technological developments for stainless steel production in the late 1960s and 1970s such as the AOD converter technology made it possible to have lower carbon contents and to put more nitrogen into the steels and particularly into duplex, leading to the production of the so-called ‘second generation’ of duplex grades. These are renowned for their improved properties such as mechanical strength and corrosion resistance. Duplex grade 2205 is still the working horse in oil & gas applications. In the past decade another trend has emerged: lean duplex grades. Duplex stainless steels with low contents of expensive and volatile alloying elements such as nickel and molybdenum content
The use of light yet high strength duplex for sluice and flood gates in a Finnish hydropower project enabled material savings and meant less hydraulicforce was needed to operate the gates.
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against wear caused by ice and floating debris. In this particular project the benefits of using duplex were manifold: material saving by utilizing the high strength results in a lighter duplex structure needing less hydraulic force to operate the gates, adequate resistance to both pitting and universal corrosion, excellent resistance to stress corrosion cracking, and good machinability and weldability. Additionally, the relative price stability of lean duplex, owing to low nickel content, ensures that the stainless steel material costs are kept stable during long projects – an important factor for companies involved in public sector projects. The choice of lean duplex LDX 2404 (R) for a fermantation residue tank in Borken, Germany reduced the weight by 25% in comparison to a 316 type stainless steel tank. Photo: by courtesy of Börger GmbH, Borken-Weseke, Germany
the customer to down-gauge the wall thicknesses, saving both material and fabrication costs. Ultimately this results in lower life cycle costs as there is no need to renew the coatings, resulting in uninterrupted availability of the tanks as there is no longer a need to empty the stored water for maintenance purposes. It is this kind of life cycle thinking that makes duplex a sustainable material. Clearly there are applications around the globe utilizing carbon steel tanks and construction elements where lean duplexes could be used to eliminate painting and maintenance and improve availability. The offshore industry is also driving developments in duplex grades. The ultra-deep oil reserves in Latin America mean the operating pressure for equipment is increased, the riser pipes bringing the to be longer and therefore heavier, and the wells are more corrosive. Simply put, which need materials with higher mechanical properties that can carry their own weight, creating a need to look into higher mechanical strengths for duplex grades. Outokumpu is working in cooperation with oil and engineering companies to develop lean duplex grades for structural components on oil rigs. This is largely motivated by maintenance and safety issues; lean duplexes eliminate the need to paint equipment which is a costly exercise on an oil platform. The weight factor is also important in this environment; using a material with higher mechanical properties means you can decrease wall thicknesses and reduce weight.
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Identifying the Right Grade How to identify the right duplex grade to use is a multi-dimensional question. The most relevant factors are the combination of strength and corrosion resistance required for each individual application. Duplex grades cover a wide range of corrosion resistances, from grades that are ‘only’ as corrosion resistant as standard 304 stainless steel to super or hyper duplex that can withstand extremely harsh environments where a 6 Moly grade of austenitic steel would be needed. There is always a grade of duplex that is suitable for your specific environment. The main advantage for end users is that the strength of duplex is much higher than that of austenitic stainless steel, providing opportunities to save on materials because you can use less. Besides the reduction in the material required, there will be also less costs for transportation, material handling, fabrication, welding consumables etc. However, there are other situations as well where the higher mechanical properties and better wear resistance of duplex can be taken advantage of such as in applications with very abrasive conditions.” A good example of the benefit duplex offers is a rebuilding project of rapid channels in the Finnish city of Tampere where LDX 2101® was chosen for all main structural parts for sluice and flood gates used for hydropower generation. The high surface hardness of the material protects the gates
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Overall, life cycle cost considerations are essential when evaluating a duplex solution. On top of direct material savings, duplex enables longer design life – 200 years in the case of the rapid channel project. Thus, you should not only consider the initial investment costs, but also any eventual costs for maintenance if you want to replace carbon steel. There is still some room for new developments in Duplex. Certainly some new grades with tailor-made properties will be developed. Other developments will be in the range of products offered; for instance Outokumpu offers value-added products such as beams and profiles for construction elements. This is an area which will bring more value to the customer. A customer who is not yet using duplex should evaluate all the benefits duplex grades can offer. We should not only focus on the kilo price but grasp the whole story to understand the full solution. Duplex offers excellent opportunities to constructing sw challenging and durable structures.
Yatinder Pal Singh Suri Country Head Outokumpu India Pvt Ltd
features Technology Upgradation
On-line Moisture Analysis in Hydrocarbon Gas Streams Using Laser Spectroscopy Measurement of water vapor in natural gas has long been of importance to the gas industry and has been addressed through the use of a variety of analytical techniques over the years. Among the most widely used techniques is Quartz Crystal Microbalance (QCM) based analysis.
Quartz Crystal Microbalance (QCM) technology is still a workhorse for production and pipeline applications and considered by most users in the natural gas industry as both dependable and accurate. However, as with all direct contact chemical sensors, sensor response changes resulting from contamination presents a significant problem that increases the long-term maintenance requirements for the analyser.
A second advantage of TDLAS is the ability to rapidly tune the lasers, so techniques like wavelength modulation spectroscopy (WMS), which yield dramatic sensitivity enhancements over a direct absorption approach, are easily implemented. Because TDLAS is an optical technique, it also offers a very fast response speed. The high specificity, sensitivity, and response speed of TDLAS make it very suitable for a variety of process measurements.
Currently, there are several direct sensor contact technologies used for the analysis of moisture in natural gas. The sensors used in these systems come into direct contact with the process gas, so there is the potential for sensor degradation over a period of time especially with streams, which contain glycol, moderate to high levels of hydrogen sulfide and other contaminants.
The specificity of TDLAS for an analyte is dependent on the sample matrix. For many simple applications, it is relatively straightforward to find, and use, an absorption line for the analyte species that is free of interference from all other species in the sample matrix. However, this condition is not guaranteed, and may provide a key limitation to implementing TDLAS for many industrial applications.
If sensor degradation occurs, system response characteristics change and, as a result, the reported moisture content may be inaccurate. In order to correct for the change in response, the analyser should be tested periodically with a known external reference sample or internally generated traceable gas sample to verify the analyser output. Necessary adjustments to the moisture calibration are made after the verification, as long as the deviation in analyser response from the known, expected concentration is within predefined limits. If the analyser response with the test sample is not within specified limits, analyser output is considered invalid and an alarm is triggered. Once the alarm occurs, the sensor would need to be repaired or replaced. This approach of verification and calibration adjustment for direct sensor contact systems has proven to work well for many natural gas streams.
This situation is not unique to TDLAS and is a common problem in making quantitative measurements with all spectroscopic techniques. As such, there is an opportunity to extend the range of applications for TDLAS by implementing some of the chemometric strategies that have been used in other fields of spectroscopy. Scanning the lasers over a range of wavelengths enables not only the possibility of compensating for potential background interferences, but also the attractive possibility of measuring more than one component with a single laser.
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The specificity of TLDAS results from the extremely high spectral resolution it achieves. Emission bandwidths for tunable diode lasers are on the order of 10-4 – 10-5 cm, which results in the ability to isolate a single rovibrational transition line of an analyte species.
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Absorbance of Natural Gas Components, AU
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In the last several years, near-infrared tunable diode laser absorption spectroscopy (TDLAS) has gained significant attention from its use in industrial applications. Three key attributes of TDLAS technique are responsible: specificity for the analyte, high sensitivity and fast response speed.
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0.00 1856
1855
Figure 1 - Absorption Spectra for Water Vapor, Methane, Ethane, and Propane.
Offshore World | 33 | JUNE - JULY 2013
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In the case of TDLAS-based systems, neither the laser source nor the detector element come in contact with the process gas and, therefore, there is no change in the system response relative to the sensor contamination issues described above. However, it is still possible for any analytical instrument to produce erroneous results. As a result, it is very important for the end-user to verify that the process analysis system is performing properly and that the results are valid. The TDLAS system described in this paper uses a unique approach to verify that the analyser is performing properly. The system contains a sealed water reference cell. PERFORMANCE VERIFICATION The principal component of consumer pipeline natural gas is methane, which is usually present at concentrations greater than 85 per cent. The other major components are ethane and propane, which are typically present in concentrations in the 0–10 per cent range. In pipeline quality gas, water vapor is present at concentrations of less than a few hundred ppmv. Absorption spectra for water vapour, methane, ethane, and propane are shown in Figure 1.
Grin Lens
Laser Module
Sample Cell
Laser Diode
Mirrors Reference Cell
Photodiode Beam Splitter Temperature Control Ball Lens Photodiode
Current Control
Electronics Unit
Figure 2 - The Schematic of the TDLAS System Showing the Relationship of the Reference Cell Relative to the Laser and the Process Gas Stream
5100 NCM Non-Contact Moisture
STATUS
H20 CONCENTRATION
SAMPLE CELL PRESSURE
SAMPLE CELL TEMPERATURE
Sampling
250ppm
14 psi
32.13 ÂşC
Home Alarms
4 0.020
REFERENCE
0.0006
SAMPLE
Trends Spectra
These spectra were recorded at room temperature and at a pressure of 1.0 atm. The spectra are ordinate scale expanded and offset for clarity. The concentrations for the spectra of water vapour and the hydrocarbon components are quite different. The concentration of water vapour was approximately 1 per cent, while the concentration of the hydrocarbons was 100 per cent. It is readily apparent that the hydrocarbons contribute almost no significant background to the measurement of water vapor at the 1854 nm laser line. A close look at the figure shows that only the methane has very small spectral features, which overlap with the absorption peak of water vapor at 1854 nm. The other species in the sample do not contribute any significant interference at 1854 nm. For measuring water vapor at low concentrations (i.e., less than 100 ppmv), even this small peak observed for methane must be compensated for adequately. With a simple analog instrument, compensating for this background can be problematic, especially when the concentration of methane in the sample gas is not constant. For this reason, finding a target wavelength with a minimum of background from methane has been a key requirement for many TDLAS instruments. However, since the AMETEK TDLAS records the spectrum of the sample around the water peak, the analytical method is able to adequately measure and compensate for the methane in the sample. Thus, the signal processing capabilities of a digital signal processor-based design offers distinct performance advantages over simple analog implementations of the TDLAS technology. A schematic of the AMETEK 5100 V TDLAS analyser is shown in Figure 2. A small portion of the laser source output is split out and passes through the reference cell. Data is essentially collected simultaneously from both the natural gas stream and the water reference sample providing a real-time confirmation that the laser is locked on the moisture absorption line. The water reference cell is also used to perform a reliability check on the quantitative measurement of the water measured in the sample cell. This verification is accomplished by using the reference cell data to check the output of the laser and the proper operation of the data collection electronics. If there is a mismatch between the expected and calculated results an error is reported. If such an error is detected an alarm is immediately generated and sent to the host computer or www.oswindia.com
0.0004
Transfer 0.0002
Settings Calibration
0.010 0.0000
0.005
-0.0002
-0.0004
0.000
-0.0006 -0.005 -0.0008
-0.010 -0.0010
-0.015
Logout
Peak Index: 123
Deviation Window: 12
-0.0012
Figure 3- Web-Based System Interface Screen Showing Real-Time Display of Signal from Reference Moisture Cell (Left) and the Process Stream Signal (Right)
through a built in Web interface (Figure 3) to a remote computer anywhere on the system network. CONCLUSION TDLAS has proven to be a viable process measurement technique for the measurement of moisture in natural gas. At low concentrations of moisture it is important that the absorption information is accurately obtained. In this implementation an internal reference cell containing a known amount of water vapor is used to verify that the measurement is locked on the water absorption sw line and that the analyzer is operating properly.
M Fuller Vice President, Marketing and Business Development AMETEK Process Instruments A Amerov Applications Scientist AMETEK Process Instruments
Offshore World | 34 | JUNE - JULY 2013
features Energy Watch
Mixed Price Movement Amongst Energy Commodities The past two months of May and June 2013 witnessed mixed price movement amongst major energy commodities. While NYMEX natural gas futures registered the maximum price fall of 17.91 per cent in the two months on sustained high gas inventory levels in US; on the other hand CER futures prices on ICE-ECX platform rose the most by 92.31 per cent (albeit with low price base) on rising expectations that the EU parliament will approve an amended backloading plan.
With slowdown in US private sector jobs growth and weakening in Chinese manufacturing, NYMEX light sweet crude oil (WTI) futures prices started the month of May 2013 at USD 91.03 per barrel, down by 2.6 per cent from previous months close. With prices then moving up, the opening day’s low of USD 90.11 eventually emerged as period (May-June) low. Thereafter, oil prices moved up as reports of decrease in US jobless claims and an interest rate cut by the ECB boosted crude oil demand sentiments. Tensions in the Middle East and expectations of violence in oil-rich regions led further strength to oil prices. The steady rise in oil prices was, however, interrupted by increase in supply by Saudi Arabia, which downgraded supply risk from the Middle East to some extent. Nevertheless, oil prices were then supported by strong Chinese export data and lower than expected US crude oil inventories. Moving further on similar trend, oil prices then continued to fluctuate, albeit moving down by the end of May. Strength in the dollar against euro and weekly released report showing only modest decline in US oil inventory level helped the fall
in oil prices. Also, China’s reduced pace of economic growth, as data released showed that its manufacturing activity contracted after a period of slowing growth helped the fall in oil prices. Since the onset of the month of June, oil prices started to move up, helped by unexpected decline in US crude oil supplies, encouragement from US job growth and continuing geopolitical tensions in the Middle East. Oil prices were fur ther boosted by release of upbeat repor ts on US jobless claims and retail sales, along with increased tensions in oil rich regions in the Middle East. Notably, the civil war in Syria became the center of attention of energy participants in the recent past, as well as the protests in Turkey; although both do not directly impact oil production, they influence the stability of the major oil producing region. The announcement by US that it will increase aid for rebels in Syria, on June 14, heightened the sense of geopolitical instability amongst oil traders, thereby providing momentum to the ongoing increase in crude oil price. Subsequently, NYMEX (CME)
300
100
295
95
290
90
285
85
280
80 NYMEX Heating Oil (USd/gal) - LHS NYMEX GasOil (USd/gal) - LHS NYMEX WTI crude oil (USD/barrel) ICE
275
75
ICE Rotterdam Monthly Coal (USD/MT) 270 5/1
/20
13
5/5
/20
13
5/9
/20
13
5/1
3/2
013
5/1
7/2
013
5/2
1/2
013
5/2
5/2
013
5/2
9/2
013
6/2
/20
13
6/6
/20
13
6/1
0/2
013
6/1
4/2
013
6/1
8/2
013
6/2
2/2
013
6/2
6/2
013
Source: Bloomberg
Offshore World | 35 | JUNE - JULY 2013
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0.60
5.50
0.50
4.50
0.40
4.00
0.30
3.50
2.50
0.20 5/1
/20
5/5 13
/20
13
5/9
/20
5/1 13
3/2
013
5/1
7/2
5/2 013
1/2
013
5/2
5/2
5/2 013
9/2
013
6/2
/20
13
6/6
/20
6/1 13
0/2
013
6/1
4/2
013
6/1
8/2
013
6/2
2/2
013
6/2
6/2
013
Source: Bloomberg
crude oil futures registered the period high (May-June) of USD 99.01 per barrel on June 19.
a n d I n d o n e s i a , t h e w o r l d ’s l a r g e s t e x p o r t e r s h e l p e d t h e f a l l in coal prices.
Later, crude oil futures prices fell sharply after the Fed Chairman, Ben Bernanke announced that monetary and economic stimulus will be reduced; thereby creating a state of uncertainty amongst crude oil trade participants. Another factor that instigated the market to struggle and took a toll on crude oil prices was the continued Chinese manufacturing slowdown. However, by the end of the period, oil prices moved up again initially on allaying of some concerns about China’s credit crunch and on news of pipeline closures in Canada, and later on release of set of encouraging economic repor ts. Finally, NYMEX crude oil futures closed the period at USD 96.56, registering a rise of 3.32 per cent in two-month period of May and June.
In emission market segment, prices of both European Union allowances (EUA) futures and Carbon Emitted Reduction (CER) futures jumped by 36.81 per cent and 92.31 per cent respectively in the two month period, on ICE-ECX platform. The spike in prices came as EU lawmakers expressed for the first time bipartisan support for efforts to fix Europe’s ailing emissions trading scheme (ETS). While, in April 2013, the EU parliament voted against a plan to temporarily ‘backload’, or remove, 900 million permits from its market in a bid to double its carbon price, resulting in carbon price plunge; in June 2013 the conservative politicians indicated they’d support an amended backloading plan. The proposal is now expected to proceed to the EU parliament once again, where it will go to a final vote on July 2. Meanwhile, according to a report from the World Bank, more than 40 national governments and 20 states or other “sub-national” governments are now charging polluters for emitting greenhouse gases, or plan to start in the sw coming years.
The largely mixed price movement in crude oil prices led a similar mixed price movement in two of crude oil’s popular derivates. While, futures prices of gasoline on NYMEX platform witnessed a fall of 1.75 per cent in the period of May-June, NYMEX heating oil futures witnessed a slim rise of 0.22 per cent. On the contrary, other major energy commodity natural gas futures (traded on NYMEX-CME platform) saw a big price fall of 17.91 per cent in two month period. Bigger-than-expected increase in US weekly gas inventories level as supply grew to more than the five-year average, led to sustained high gas inventory levels in US. As a result, natural gas futures traversed steady movement through the two month period, with registering the period low of USD 3.526 per mmBtu on the last trading session of the period (June 28). Among other energy commodities, ICE Rotterdam monthly coal futures prices declined by 11.20 percent largely on weak demand as global e c o n o m i c s l o wd o w n c o n t i n u e s to p u s h u p c o a l i n ve n to r i e s. A m i d s u b d u e d d e m a n d, t h e i n c re a s i n g s u p p l y e s p e c i a l l y f ro m Au s t r a l i a www.oswindia.com
(The views expressed by the authors are personal.)
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 | 36 | JUNE - JULY 2013
news features
Price Hike to Boost Domestic Production ”The doubling of gas prices will help boost production over 3 trillion cubic feet of gas reserves that had been declared economically unviable at current rates of USD 4.2,” says Oil and Gas Minister Veerappa Moily on gas price hike.
Indian Hydrocarbon Potential
Moily’s Vision • Reducing oil imports by 50 per cent by 2020;
• •
• • • • • • • •
75 per cent by 2025 and eventually achieve self-sufficiency India by 2030. Last fiscal India imported crude oil for Rs 600 billion Cabinet committee on investment has given clearance for 5 out 8 exploration blocks in the No Go Area. Out of another 31 exploration blocks, V Moily Union Minister for Petroleum & Natural Gas 25 exploration blocks have been cleared. The government has awarded 47.3 per cent of Indian sedimentary basin area for exploration. PSCs for 19 exploration blocks under 9th round of NELP have been signed in 2012-13. DGH has carved out exploration area of 2,70,000 sqkm. Under the CBM policy, 33 exploration blocks have been awarded. Current CBM gas production in India is 0.28 mmscmd. Rajasthan has become the largest crude oil producing state in the country with production of about 8.593 MMT in 2012-13. In 2009, first time deepwater natural gas production commenced. OVL has produced about 7.26 Million Metric Tons (MMT) of oil and equivalent gas during the year 2012-13 from its assets abroad in Sudan, Vietnam, Venezuela, Russia, Syria, Brazil, South Sudan and Colombia.
Year
Domestic Gas Production
LNG Imports Gas Gas (% of total Produced at Demandconsumption) ONGC & OIL Supply deficit
2010-2011 143 mmscmd 20 %
72.9 mmscmd
2012-13
40 mmscmd
111 mmscmd 30 %
2016-17
143 mmscmd 234 mmscmd
Yearwise decline in gas production
Blocks
Gas Potential
D-29, D-30, D-31 in KG basin
5-7 mmscmd
D-35 in Cauvery basin
4 mmscmd
D-32 & 40 in RIL’s NEC-25
Over 4 mmscmd
Gas potential in basins
Offshore World | 39 | JUNE - JULY 2013
Compiled by Supriya Oundhakar
sw
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news
India Iraq to Fill Gap Left by Iran
Essar Oil Books GSPC LNG Capacity Oil Imports (Total 171.41) Oil (mn tonnes) Country 32.63
Saudi Arabia
24.51
Iraq
17.67
Kuwait
15.79
UAE
New Delhi: With crude oil imports from Iran, due to sanctions imposed by the US and the European Union, taking a hit in the last year, Iraq has assured India that it would compensate the country’s shortfall due to decline in oil supplies from Iran. Interestingly, Iraq has already emerged as the second leading crude oil exporter to India, walking ahead of Iran. Presently, India is importing around USD 20 billion worth of crude oil from Iraq. Indian refiners imported 171.41 million tonnes of crude oil in 2011-12. Of this, 32.63 million tonnes came from Saudi Arabia, 24.51 million tonnes from Iraq, 17.67 million tonnes from Kuwait, and 15.79 million tonnes from the UAE. India imported 2,71,200 oil barrels per day (bpd) from Iran between April and February 2012-13, which was below the government’s target of 3,10,000 bpd for the fiscal year which ended on March 31. Oil imports from Iran have decreased to around 7.3 per cent in the period from last April to February, as compared to 11 per cent in the previous year.
Mumbai: Essar Oil which runs 20 million tons per annum refinery on the western coast of Gujarat, would soon be importing liquefied natural gas for use at its refinery. To facilitate the same, the company has booked 2.5 million cubic metres of capacity in Gujarat State Petroleum Corporation’s Dahej to Jamnagar pipeline. The capacity will come up by 2014. According to Business Standard, Lalit Kumar Gupta, Managing Director and CEO, Essar Oil said that they are consumer of LNG at their Vadinar refinery. They do not have regasification capacity so they are not importing directly. But in the near future they plan to import LNG. In addition, Essar Oil, is also in talks with players to secure some regasification capacity in a LNG terminal.
Reliance Industries Eyes Stake in HPL Mumbai: Six companies, Reliance Industries Ltd, ONGC, Indian Oil Corporation, GAIL, Essar and Cairn have evinced interest in acquiring 31 per cent in Haldia Petrochemical Ltd (HPL), portion of the stake that the West Bengal government holds. West Bengal commerce and Industries Minister Partha Chatterjee said that they have got a very good response for their stake in HPL. It shows the confidence of investors in Bengal. The Bengal government had initially floated expression of interest for 6750 million equity shares, which constituted 39.99 per cent of paid up equity of the company.
ONGC Inks Pact With RIL to Explore Infrastructure Sharing Mumbai: Reliance Industries Ltd (RIL) and state-run ONGC plan sign a formal pact for sharing the infrastructure in the gas-rich D6 block of Mukesh Ambani’s firm, a move that industry officials say can end the dispute over the alleged ‘gold-plating’ of costs in the deep-sea gas field of RIL. ONGC, which is developing deep-sea fields adjacent to Reliance’s D6 block, said that it had signed a significant memorandum of understanding (MoU) with RIL to work out modalities of sharing of infrastructure, identifying additional requirements and firming up commercial
terms. ONGC said this would minimise its capital expenditure and speed up development of its deep-sea gas fields, which will produce 6-9 million metric standard cubic metres a day (mmscmd) of natural gas in four years. “The companies intend to enter into a formal agreement after conducting a joint study which will be spread over the next nine months,” ONGC said in a statement.
Shell Proposes LNG Project in AP
OIL to Acquire Stake in APL
Hyderabad: A high powered team from Shell and Richard Hyde, British Deputy High Commissioner, Hyderabad called on State Infrastructure Minister to discuss their plans to set up a LNG project in Andhra Pradesh. The delegation including Roger Bounds, Shell Vice President Global LNG and Sander Stegenga, Shell Chief Executive Officer, Andhra LNG and other met with Ganta Srinivasa Rao, State Minister for Infrastructure and investment, port, airport and natural gas. They were here to discuss plans for an LNG project proposed to be taken up at Kakinada deep water port.The State is starved of gas and several gas-fired power plants are lying idle without gas supplies. The gas flow has come down as output has dwindled from the Krishna Godavari basin fields of Reliance Industries Limited.
Mumbai: In a strategic move, Oil India Ltd (OIL) is set to acquire 49 per cent equity in Assam Petrochemicals Ltd (APL), credited to be the first company in India to manufacture petrochemicals using natural gas as feedstock. A deal with the Assam government, which holds majority stake in the company through Assam Industrial Development Corporation Ltd (AIDC), is likely by October. The Assam government currently holds 88.2 per cent stake in the AIDC, while domestic institutions and others hold the remaining stake. Trading in APL scrip on BSE is currently suspended. In 2011-12, APL posted a net loss of ` 10.6 million, compared to a net loss of ` 102.30 million in 2010-11. It is in the process of de-listing from BSE to take forward the procedure for stake sale, said a person close to the development.
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Offshore World | 40 | JUNE - JULY 2013
ONGC Hires Drilling Rig Mumbai: Oil and Natural Gas Corp (ONGC) has signed a contract to hire a long-idled ultra-deepwater drillship of US-based Transocean for USD 412,000 (about ` 23.9 million) per day. ONGC hired ‘GSF Explorer’ drilling rig for one year beginning July at a day rate of USD 412,000, the oil rig contractor said in its latest fleet update. GSF Explorer is capable of drilling up to 30,000 feet in water depths of up to 7,800 feet, Transocean said. According to Transocean, GSF Explorer was built in 1972 and upgraded in 1998. ONGC
hired drillship GSF Explorer after recently cancelling a deal with a rival driller. A contract to hire the rig was signed on May 24 ending months of re-tendering and negotiations between ONGC and Transocean.
Cairn India to Invest in Rajasthan Oilfields
Pipavav Wins ` 2.55 bn Contract
Jaipur: Cairn India plans to invest USD 3 billion over the next three years in finding more oil and raising output from its showpiece Rajasthan oilfields, the company’s CEO P Elango said.
Mumbai: Private sector shipbuilder Pipavav Defence and Offshore Engineering Company has bagged a contract worth ` 2.55 billion for maintaining and dry docking of deep water draft oil rigs.
“We have planned for a net capital investment of USD 3 billion in a three year period from FY2014 to FY2016. We are focused on realising the full potential of our world-class Rajasthan assets through a combination of aggressive exploration and fast-track development,” he said in the company’s annual report.
According to a Business Standard report, Pipavav Defence has significant contracts for oil and gas assets and for the first time in the country, such critical and complex work is being done in India in this sector. The company said that Pipavav Defence bags prestigious contract for maintaining and dry docking of deep water draft oil rigs amounting to ` 2.55 billion. It, however, did not disclose the name of its client. The order comes just a week after the shipbuilder won a contract worth ` 11.60 billion for building two specialised offshore vessels from a European client.
Cairn will raise crude oil production from Rajasthan fields by as much as 23 per cent to 215,000 barrels per day by March 2014.
Essar, Reliance Aim to Produce 6.5 MMSCMD CBM Mumbai: India’s gas supply is expected to get a boost from coal bed methane (CBM) after the government removed uncertainty over its pricing. Essar Oil and Reliance Industries will add about 6.5 million standard cubic meters per day CBM output in the next two years, which is enough to generate about 1,573 mw of power. Essar is expected to commence gas production from its Raniganj CBM block next year while RIL would start CBM output from its two blocks in Sohagpur in MP a year later, oil ministry officials said. RIL is expecting 3.5 mmscmd of peak output from its two blocks. Essar said its Raniganj block was close to moving to the commercial phase. “We have drilled over 150 wells and are producing about 100,000 standard cubic meters of gas per day. This is expected to rise to 3 mmscmd by end of 2014,” an Essar spokesperson said.
Production commencement in Raniganj block
Essar
RIL
2014
2015
Sources said Transocean had emerged as the sole bidder in an initial tender floated by ONGC for hiring an ultra-deepwater rig last year. It offered a twoyear contract at USD 601,000 per day, which ONGC felt was too high.
TN Stops Work On CBM Project Chennai: In a relief to agitating farmers of Thanjavur and Tiruvarur districts, Chief Minister Jayalalithaa called for suspension of the proposed coal bed methane (CBM) exploration and production project in the two districts. She also announced the constitution of a multi-disciplinary experts’ committee to study adverse impact of the project. In a statement, she said she asked officials to ensure that the Great Eastern Energy Corporation Ltd (GEECL), which obtained petroleum exploration licence (PEL) from the previous Dravida Munnetra Kazhagam government and entered into a memorandum of understanding with the government in January 2011, was not allowed to carry out any work till her government took a decision on the basis of report to be submitted by the panel of experts in three months.
GEECL
BP Asks Oil Ministry to Compensate for KG Block New Delhi: UK’s BP plc has asked Petroleum Ministry to compensate for a KG basin block that it is being forced to surrender after Defence Ministry restrictions made oil and gas exploration impossible. BP along with Reliance Industries had won the deepsea KG-DWN-2005/2 or KG-D17 block in the seventh round of auction under NELP in 2008. About 70 per cent of the 1,949 sq km of the block falls in an area where DRDO and Navy exercises are conducted and has been classified as ‘Impact Zone’ where E&P operations are not possible, BP wrote to the Oil Ministry on May 27. The block, it said, has “practically become a ‘No— Go’ Zone for continuous exploration and subsequent development activities thereby preventing contractors from carrying out petroleum operations.”
Wells drilled (as on date) 150 Gas Production
100,000 standard cubic meters of gas per day
0.5 mmscmd
Expected Production
3 mmscmd (By end of 2014)
3 mmscmd by 2017
Offshore World | 41 | JUNE - JULY 2013
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news Punj Lloyd’s RGIPT Construction Pact Cancelled
Aban Offshore to Raise Funds
New Delhi: The oil ministry has terminated Punj Lloyd’s contract for constructing Rajiv Gandhi Institute of Petroleum Technology (RGIPT) in Amethi, Uttar Pradesh, citing ‘non-performance’ and re-tendered the ` 435-crore project.
New Delhi: Debt-laden offshore drilling and oil field service provider Aban is planning to raise more than ` 45 billion through various market instruments to replace a portion of its expensive debt. Aban Offshore has a total debt of more than 130 billion and has been struggling to repay its debt. The company is now looking to raise ` 22 billion through issue of FCCBs and GDRs and is also looking to raise an additional ` 25 billion through issue of shares to qualified institutional buyers.
The foundation stone of the project was laid in 2008. The contract to build 27 buildings for the institute was awarded to Punj Lloyd in June 2010 with a two-year deadline. The project is delayed due to disputes with the contractor and now it will be executed in phases. The first phase will have to be completed by mid-2014 and the entire project by mid-2015. After about 38 per cent completion, disputes arose between Punj Lloyd and state-run Engineers India Ltd (EIL), the project manager appointed by RGIPT.
“We want to keep the approvals from the shareholders ready so that when we want we can go ahead with our plans to raise money when we need it. We are awaiting shareholder approval to raise additional long-term resources through issue of FCCBs, GDRs and ADRs for about $400 million and an issue of equity related securities to qualified institutional buyers for ` 25 billion,” a senior official from Aban said.
India Top Buyer of Nigeria’s Crude Oil
Fire at Gujarat Refinery Unit
New Delhi: India has overtaken the US as the top buyer of Nigerian crude oil, a top Indian diplomat in Abuja has said. Indian High Commissioner to Nigeria Mahesh Sachdev said recent statistics showed that India had been buying more of Nigeria’s crude than the US over the last three months.
New Delhi: “There was a fire near the flare knock out drum (KOD) of FCC (fluidised catalytic cracking) unit of Gujarat Refinery. As a precautionary measure, the unit was taken for safe shutdown,” said Anjali Bhave, Spokesperson of the refinery.
He said that India will continue to cooperate with Nigeria to improve its economy and it will also assist the country in capacity building of workers in both the public and private sector during a courtesy visit to the Governor of Niger state in northern Nigeria recently.
“Emergency response personnel extinguished the fire in about 10 minutes and one employee sustained burn injury. No casualty has been reported,” she said.
India has recently reduced its dependence on Iranian oil in the wake of the US and European sanctions on the import of oil from the Islamic Republic.
The injured employee has been admitted to a private hospital for treatment. A multi-disciplinary committee has been constituted to investigate the cause of fire, she said. The FCC unit was the only unit involved (in the fire) and it was temporarily shutdown.
Cairn India to Invest in Crude Production
ONGC’s CBM Blocks Face Fresh Hurdles
New Delhi: Cairn India is hoping to ramp up crude production in the Barmer blocks from the current 180,000 barrels per day to 210-215,000 bpd by the end of the current fiscal, said Navin Agarwal, Chairman, Cairn India. The company also plans to invest $3 billion dollars in its energy assets in India and a lions share of this Capex will go into developing the prolific Barmer block Agarwal was speaking on the sidelines of the company’s seventh annual general meeting held in Mumbai. “We have submitted an integrated field development plan for the Barmer block to the Petroleum Ministry and we are hopeful that it will be approved soon so that we can expedite production from the Barmer block,” added P Elango, interim CEO, Cairn India. He also said, “We do not provide a break-up of the Capex planned for all our different projects but the overall capex planned for India is $3 billion.”
Mumbai: ONGC’s attempt to rope in private sector explorers as joint operators in three coal-bed methane blocks in Jharkhand and West Bengal, is facing fresh hurdle. ONGC sources said that one of the awardees, Dart Energy (formerly Arrow), refused to take 25 per cent stake in North Karanpura and 10 per cent stake in Ranigunj block. The Australian company, however, accepted the offer for 25 per cent interest in Bokaro.
Cairn currently produces over 150,000 bpd of oil from the Mangala fields and over 25,000 bpd from from Bhagyam, and the balance 10,000 bpd are being produced by the Aishwarya fields, which commenced production earlier this March. The Mangala, Bhagyam and Aishwariya fields, constitute Cairn India’s key assets in Rajasthan. These are the three largest finds in Rajasthan.
Though rated as the most prolific CBM blocks in the country with each having 1 trillion cubic feet of reserves, ONGC failed to turn them into producing assets during its decade long exploratory campaign. As a corrective measure, the PSU major was trying to rope in private sector operators, having expertise in coal bed methane operations, for the last four years.
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According to sources, the public sector oil and gas major is now considering redistributing the stake in North Karanpura and Ranigunj to other bidders for the respective blocks. ONGC currently holds 90 per cent operating interest in Ranigunj and 80 per cent each in Bokaro and North Karanpura. Coal India (Ranigunj) and IndianOil (Bokaro and North Karanpura) hold the residual stake as participatory interests.
Offshore World | 42 | JUNE - JULY 2013
GAIL Rejects TN Proposal for Gas Pipeline Along National Highways Chennai: According to the company, it rejected the proposal based on expert opinion of consultants Engineers India Ltd (EIL) and Mecon. The bitter battle between the Tamil Nadu Government and GAIL India Ltd may take a fresh twist now. The Union government-run company has rejected a proposal by the state government to lay natural gas pipeline along the National Highway across the state, terming it technically unfeasible. The state chief minister J Jayalalithaa had said in the state Assembly that her government was against the laying of pipeline on agricultural land and had asked the company to re-align it along the National Highways. It had even initiated action for removal of pipelines laid in agricultural land. Following which, the Madras High Court had stayed the Tamil Nadu government’s order directing removal of pipeline from farm lands.
For the pipeline project from Kochi to Bangalore, via Coimbatore and Salem, the Maharatna major is set to invest about ` 25 billion, out of which ` 7 billion would be for the Tamil Nadu stretch only. Out of the total 884 kilo metres, the project covers 310 kilo metres in the state only. However, the project has been facing resistance from farmers, following which the state government was asking to reroute the pipeline along the National Highways. “The above decision of Tamil Nadu government at this stage has started having huge adverse impact on the scope, schedule and cost of the project. GAIL has already conveyed that laying of large diameter high pressure cross country gas pipelines is not technically feasible along National Highways for large distances,” a senior company executive said. According to the company, it rejected the proposal based on expert opinion of consultants Engineers India Ltd (EIL) and Mecon.
IOCL to Set Up Natural Gas Terminal In Odisha
CBM Pipeline Licence for Reliance
Mumbai: Indian Oil Corporation signed an MoU with state-owned Industrial Infrastructure Development Corporation of Odisha for development of a natural gas terminal at an investment of ` 50 billion in the state. “The natural gas terminal will be set up at Dhamra coast in Odisha’s Bhadrak district at an investment of ` 50 billion. The terminal construction work will be completed by 2018,” said A K Marchanda, Executive Director (Gas) of Indian Oil Corporation Limited (IOCL) after signing the MoU. Terming the project as a milestone in the state’s economic development, Marchanda said the project would ensure distribution of natural gas to domestic users, auto-industries and others. About 150 acre of land is required for the purpose and IOCL has already signed an MoU with the Dhamra Port Company (DPCL), he said.
Mumbai: Reliance Gas Pipelines Ltd (RGPL) has won a licence to lay 312-km pipeline to transport coal gas (CBM) produced from its parent Reliance Industries’ Sohagpur block in Madhya Pradesh. Petroleum and Natural Gas Regulatory Board (PNGRB) on July 11 authorised the Mukesh Ambani-led RGPL, a subsidiary of RIL, to lay the pipeline from Shahdol in Madhya Pradesh to Phulpur near Allahabad in Uttar Pradesh. The pipeline will have a capacity to transport 4.3 million standard cubic metres per day of gas, including 0.875 mmscmd capacity that will be available for any third party for open access on non-discriminatory basis. PNGRB said in the authorisation order that the pipeline will travel from Shahdol to JaysingNagar-Beohari-Gurh and culminate at Phulpur. At Phulpur, the pipeline may be hooked into state-owned gas utility GAIL India Ltd’s main HaziraVijaypur-Jagdishpur trunk gas pipeline. Connection with HVJ would enable gas to flow to any consumer. RIL plans to produce 3.5 mmscmd of gas from its Sohagpur (east) and Sohagpur (west) coal-bed methane (CBM) blocks in Shahdol, Madhya Pradesh from 2015. “The entity (RGPL) is allowed a maximum period of 36 months from the date of issue of authorisation letter for commissioning of the natural gas pipeline project,” PNGRB said . “Any failure on the part of the entity in complying with the targets prescribed in the time schedule shall lead to consequences” including cancellation of the authorisation, it said.
To start with, the capacity of the terminal would be 5 mmtpa, which could be increased by above 10 mmtpa per annum in future, said Marchanda, adding IOCL and the state government would jointly promote necessary infrastructure in Odisha for distribution of natural gas for industries and city gas distribution. The state agencies have already assessed the requirement and demand of natural gas and subsequent development of necessary infrastructure so as to make gas reach the demand of the centres, he said.
HPCL to Partner Shapoorji Pallonji for LNG Terminal RIL to Raise KG-D6 Block Output New Delhi: Reliance Industries (RIL) can raise gas output from KG-D6 block by 40 to 60 million metric standard cubic metres a day (mmscmd) provided gas price is enough to justify further investments, RIL president and chief operating officer (E&P) B Ganguly said. Reliance-operated D6 block’s output fell sharply from 62 mmscmd in 2010 to about 14.2 mmscmd now.
New Delhi: Hindustan Petroleum Corp Ltd (HPCL) and Mumbai-based infrastructure major Shapoorji Pallonji may soon sign a joint venture pact to set up a terminal for import of liquid gas (LNG) on Gujarat coast at a cost of about ` 5,000 crore. The state-owned firm and SP Ports Pvt Ltd, a unit of Shapoorji Pallonji Group, plans to set up the liquefied natural gas (LNG) import terminal at Chhara in Gujarat’s Junagadh district through a 50:50 joint venture.
RIL argues that output fell because of geological complexities and unpredicted reservoir behavior, but the oil ministry blamed the company for the fall and accused that production dropped because it did not drill enough wells. The dispute, which resulted in an arbitration proceeding, is yet to conclude. However, several new discoveries can now be developed as higher gas prices make them commercially viable.
SP Ports is already developing a greenfield, all weather, direct berthing port in Junagadh district. HPCL and SP Ports are carrying out a detailed feasibility study for establishing technical and commercial viability of setting up a LNG import and regasification terminal of 5 million tonnes per annum capacity at the proposed Port. The port is connected to a gas pipeline grid and evacuation of the fuel would not be an issue.
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UPSTREAM Shale Oil & Gas Resources Abundant Globally: EIA/ARI US: Shale oil & gas resources are abundant around the globe. Estimated shale oil & gas resources in the US and in 137 shale formations in 41 other countries represent 10 per cent of the world’s crude oil and 32 per cent of the world’s natural gas technically recoverable resources, or those that can be produced using current technology without reference to economic profitability, according to a new EIA-sponsored study. More than half of the identified shale oil resources outside the US are concentrated in four countries—Russia, China, Argentina, and Libya—while more than half of the nonUS shale gas resources are concentrated in five countries—China, Argentina, Algeria, Canada, and Mexico.
MEO Completes Oil Potential Assessment Offshore Australia Australia: MEO Australia has completed assessment of prospective resources in the Beehive structure in its recently awarded WA-488-P permit offshore Western Australia. Jürgen Hendrich, CEO & Managing Director, MEO Australia, said that Beehive could be a giant prospect. Nearby oil discoveries at Turtle and Barnett prove the occurrence of oil in the area. Oil is also indicated, although not proven, in the Marina discovery in MEO’s nearby WA-454-P permit. He added that while the Carboniferous and Ordovician plays identified at Beehive have not yet been drilled in the Petrel sub-basin, there are giant oil field analogues in similar aged rocks elsewhere in the world.
Significant Gas Potential Offshore Ukraine Ukraine: Ukraine’s offshore and continental gas reserves could deliver a significant of oil up to 45 bcm/yr (1.6 tcf/yr) of production by 2020, according to its operator ExxonMobil. ExxonMobil is now preparing to explore the deepwater gas field Skifske in the Black Sea. It already has 2D seismic data over the field and plans further evaluation based on 3D seismic. Last August, the company and Shell, OMV Petrom, and Ukrainian state company Nadra won joint rights to develop underwater deposits at the site. Skifske is adjacent to the Romanian deepwater Neptun block, currently under exploration by ExxonMobil and OMV Petrom. Gas reserves from the Domino discovery could be in the 42-84 bcm (1.5-3 tcf) range.
Duma Starts Gravity Magnetics Survey
Kara Sea Monitoring Programme Started
Namibia: Duma Energy Corp (DUMA) has started a high-resolution gravity and magnetics survey over its exploration concession in the Owambo Basin in northern Namibia. The survey will be flown by UK-based Bridgeporth Ltd and will cover Blocks 1714A, 1715, 1814A, 1815A. The 21,200 square km (5.3 million acre) concession extends from the northern border of Etosha Park to Angola.Less than 15 per cent of the concession is covered by a vintage (1960-1990) 2D dataset. The survey will be flown at much higher spatial resolution than previous surveys, enabling Duma and its partner, Hydrocarb Energy, to delineate the structural setting and depth to basement model of the Owambo Basin with more accuracy.
Russia: Rosneft and the RosHydroMet Arctic and Antarctic Research Institute have started a programme for studies of the Kara Sea shelf off northern Russia. Last year the company began exploration of the East Prinovozemelsky 1 and 2 license areas in the Kara Sea. The company already started a field seismic survey over the at Fedynsky and Central Barentsevsky licenses in the Barents Sea. Rosneft will use the resultant data to assess the environmental influence on the proposed marine facilities for development of the Eastern Prinovozemelsky concessions. During the current Kara Sea Summer 2013 marine expedition, meteorological stations will be installed at the coasts of the Novaya Zemlya archipelago; satellite monitoring will be completed of icebergs in the area; and independent parametric buoys launched to monitor ice drift and settlement.
ADNOC, OMC Ink Exploration Pact UAE: Abu Dhabi National Oil Company (ADNOC) and OMV East Abu Dhabi Exploration GmbH (OMV) have inked a pact to pursue exploration for oil and natural gas in the Eastern Region of Abu Dhabi. As per the agreement, OMV and ADNOC will conduct a state-of-the-art exploration programme consisting of 2D and 3D seismic acquisition and the drilling of exploration wells. If the exploration campaign is successful, the two companies will jointly develop the potential discoveries in accordance with Abu Dhabi laws. The exploration activity agreement has duration of four years. www.oswindia.com
Second Oil Found Offshore Newfoundland Canada: Statoil has made second discovery of light, high-quality oil in the Flemish Pass basin offshore Newfoundland but said it cannot yet judge the find’s resource potential. The company encountered oil while drilling its Harpoon prospect in 1,100 m of water on EL 1112 about 500 km northeast of St John’s, Newfoundland and 10 km southeast of the 2012 Mizzen oil discovery that Statoil estimated to hold 100-200 million bbl of oil. As part of its 2013 three-well exploratory program off Newfoundland, Statoil is currently drilling its Federation prospect in the Jeanne d’Arc basin. The company will then return to the Flemish Pass basin to drill the Bay du Nord prospect southwest of the Harpoon and Mizzen discoveries.
Potential Oil Discovery Offshore Nigeria Nigeria: Lekoil announced that the high impact Ogo-1 well located on the OPL 310 licence offshore Nigeria has discovered a significant light oil accumulation, based on the results of drilling and wireline logs. The Ogo-1 well is being drilled by Afren Plc, as technical partner, under a farmout to Lekoil of OPL310, offshore Nigeria. The well has been drilled to a total measured depth of 10,518 ft (10,402ft true vertical depth subsea (TVDSS)), and has encountered a gross hydrocarbon section of 524 ft, with 216 ft of apparent stacked, net pay. It targeted 78 MMboe of resources, but evidence suggests reserves could be significantly higher. Further evaluation is under way with wireline log prior to extending the well to a total MD of 11,800 ft (3,597 m) to target further high potential zones. Offshore World | 44 | JUNE - JULY 2013
news Hellenic Petroleum Bags Patraikos Block
Shaikan Field Development Plan Approved
Greece: The Greek Govt has awarded Patraikos block in offshore western Greece to a consortium led by Hellenic Petroleum. Other partners are Edison International and Petroceltic. Each has an equal interest in the concession.
Iraq: Gulf Keystone, a leading independent E&P operator in the Kurdistan Region of Iraq, has got the approval of the Field Development Plan for the Shaikan field, a world class commercial discovery. The Company has commenced its development drilling programme with the spudding of Shaikan-10. In parallel, production operations from the newly commissioned Shaikan production facility (PF-1) are scheduled to commence shortly. Shaikan-10 will be followed by a minimum 3-rig development and production drilling programme, which will commence in early 2014. Based on the current development plans of the operator Shaikan’s total production capacity will be 40,000 barrels per day (bpd) in the first phase, increasing to 150,000 bpd in the next three years and to 250,000 bpd by 2018.
The block covers 1,892 sq km (730 sq mi) in the Gulf of Patra, with water depths mainly in the 100-300 m (328-984 ft) range. According to Petroceltic, it is potentially prospective for oil in the Jurassic, Cretaceous, and Eocene formations. A working hydrocarbon system was proven by the Katakolon oil discovery wells drilled in 1982, 35 km (21.7 mi) south of the block. There will be an initial three-year exploration period followed by two optional extensions, with a maximum license term of eight years. Firm work program in the first three years comprises geological studies and 2D and 3D seismic data acquisition.
Further Gas Discovery Offshore Tanzania Tanzania: Ophir Energy has updated that the Ngisi-1 appraisal well, operated by BG Group, has successfully found further gas pay in Block 4, offshore Tanzania. The Deepsea Metro I drillship drilled the Ngisi-1 well around 5 km (3 mi) northeast of the 2010 Chewa-1 gas discovery well. It was designed both to appraise Chewa and to penetrate the Ngisi exploration prospect. On completion of the initial well, two side tracks followed to further delineate both structures. These delivered gas pay in Ngisi within a high net-gross reservoir interval, and further pay as prognosed in the Chewa, confirming strong reservoir characteristics.
Chrysaor Holdings to Further Invest Offshore Ireland Ireland: Chrysaor Holdings will further invest USD 175 million for exploration in Quad 35 in the Porcupine basin offshore western Ireland and potential acquisitions. The Quad 35 contains two proven discoveries, including the Spanish Point gas/condensate field. West of Shetland, the Premier-operated Solan field development is on target for first production in 2014. Chrysaor will take over operatorship of the license at that stage. Elsewhere in UK waters, the company is evaluation export options for gas condensate from the undeveloped Phoenix field in the Moray Firth basin off northeast Scotland.
Wenchang 8-3E Oil Field Starts Production China: CNOOC Limited, the operator of Wenchang 8-3E oil field, has announced the commercial production of the oil field. The Wenchang 8-3E oil field is located in the western Pearl River Mouth Basin with an average water depth of about 110-120 meters. The project has 4 producing wells and is expected to reach its peak production within the year. Wenchang 8-3E is an independent oil field in which CNOOC holds 100 per cent interest and acts as the Operator.
New Gas Discovery Offshore Egypt Egypt: Dana Gas PJSC, the UAE-based natural gas company, has discovered a new gas discovery on the West El Manzala concession in the Nile Delta, Egypt. The Begonia-1 discovery well encountered 15 m of net pay in a good quality sandstone reservoir of the Lower Abu Madi Formation. On test the formation produced 9.4 Million standard cubic feet of gas with 133 barrel condensate. The evaluated resources for the Abu Madi Lower pay zone are between 7 and 15 billion cubic feet (bcf) and around 100,000 barrels of condensate.
KMG EP, Petrofac Enter Pact Kazakhstan: KazMunaiGas Exploration Production JSC (KMG EP) has signed a Memorandum of Understanding (MoU) with Petrofac Limited to explore opportunities in improving the efficiency of oil production and increase production from the mature Emba fields of KMG EP’s 100 per cent subsidiary EmbaMunaiGas JSC (EMG). As per the MoU, Petrofac intends to evaluate the Emba fields and to submit an offer for the long term improvement of the management and production in selected Emba fields in order to progress a potential Production Enhancement Contract.
DNO Expands Presence with Oman, Yemen Deals Norway: DNO International ASA, the Norwegian oil and gas company, announced that the company has been selected by the Ministry of Oil and Minerals of the Republic of Yemen as successful bidder for onshore Block 84 and has entered into a farm-in agreement with the Sultanate of Oman for the Block 36 onshore. The Block 36 is located in the Rub al Khali basin and covers a surface area of more than 18,000 km2, while the Block 84 onshore Yemen covers a surface area of 731 km2 and is located in the Masila-Seiyun Basin.
Chevron Bags Kurdish Oil Deal Iraq: Chevron Corp, the US-based company, has secured another oil exploration deal in Iraq’s semi-autonomous Kurdistan region. The contract to explore the Qara Dagh field, in the south of the three-province region of Erbil and covers an area of about 861 sqkm, is Chevron’s third with Kurdish, after acquiring two others in July 2012. Iraq’s central government is against the region’s deals with oil operation companies as the central government believes the deals were not approved by the federal oil ministry. Iraq barred Chevron last year from working in non-Kurdish parts of the country. Offshore World | 45 | JUNE - JULY 2013
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news Midstream Two Canadian Crude Pipeline Leaks Reported Canada: The National Energy Board (NEB) of Canada has responded to pipeline releases of crude oil in Ontario and in British Columbia. The NEB didn’t immediately determine the size of the spill but said it posed no immediate safety concern. The spill occurred along a right-of-way containing pipelines owned by Plains Midstream Canada, Imperial Oil, and Enbridge Pipelines Inc. All the pipelines were shut down. The British Columbia release occurred on the Trans Mountain Pipeline southwest of Merritt. The pipeline, owned by Kinder Morgan, was shut down.
Two Killed in Dutch North Sea Gas Platform Explosion Netherlands: Two workers were killed and one was injured in an accident on a natural gas platform in the Dutch sector of the North Sea belonging to GDF Suez, a French oil and gas company. The incident happened on the L5A platform, about 103 km north of Den Helder, a town in the north of the Netherlands. The company said it occurred when a heat exchanger exploded during a pressure test. The platform was not producing at the time and was depressurised.
Cyprus-Greek Pipeline to Get EU Cash Cyprus: The proposed gas pipeline to link Cyprus to Crete and then Greece or Italy, the Cyprus’ most ambitious plan to revive its fallen economy in utilising the country’s natural gas resources, will be include an European Union (EU) list of strategic projects eligible for financial support.
Global Gas Storage Capacity to Rise 48% by 2030 France: The global gas storage capacity to increase from 377 billion cubic meter (bcm) at the beginning of 2013 to 557-631 bcm by 2030 with an increase of 48 per cent. The incremental growth, 180-254 bcm by 2030, requires sustained investment of total EUR 120 billion by 2030 throughout the period, says Cedigaz, an international information association for the natural gas industry, in its fifth edition report report on underground gas storage. The report says in 2030, storage will represent 11.6 to 13.1 per cent of global gas demand, compared with 11.3 per cent in 2013. New storage markets (Asia and the Middle East) account for about 60 per cent of incremental capacity through 2030. Strong growth is expected in rapidly emerging gas markets, particularly China. In mature markets (US, most of Europe, and the Commonwealth of Independent States), growth in storage capacity is limited. There were 688 underground gas storage facilities in operation in the world at the beginning of 2013, representing working gas capacity of 377 bcm. More than two thirds of the sites are in North America, with 414 in the US, and 59 in Canada, and a combined working capacity of 152 bcm (40 per cent of the global total). There are 144 storage locations in Europe (99 bcm), and 51 sites in the CIS with 51 facilities (115.5 bcm). Asia-Oceania has 18 sites (9.3 bcm of working capacity). There is one site in Argentina and one in Iran, according to Cedigaz. There are 95 projects under construction globally, adding 68 bcm of working capacity. Most of this capacity will be completed by 2020-25. www.oswindia.com
George Lakkotrypis, Energy Minister, Cyprus
George Shammas, Chairman, Cyprus Energy Regulatory Authority, said that the EU will include the East Med Pipeline in its revised list of projects of common interest within the Southern Corridor for gas. The Southern Corridor is the EU name for routes to ship gas from central Asia, the Middle East and the Eastern Mediterranean basin to diversify supplies and reduce dependence on Russian gas.
George Lakkotrypis, Energy Minister, Cyprus, said that he had information the EU would include the pipeline, although adding that Cyprus had to study the feasibility of the link.
Hassan Rouhani Win could be an O&G Game-changer Iran: The win of the moderate Hassan Rouhani as Iran’s new president, on the promise of a reform agenda that includes greater nuclear transparency, may lead the UN sanctions against the Iranian state could be lifted and lead on increasing the country’s oil & gas production. Iran’s oil and gas output hasn’t grown at the pace of its Middle East peers (Iraq, Kuwait, Qatar, Saudi Arabia and UAE) during the period of the UN sanctions. As a group, production in 2012 versus 2006 when the sanctions were imposed has grown by 25 per cent, making Iran’s 4 per cent increase seem miserly.
LNG Export Plant in Canada Canada: WCC LNG Ltd, Calgary, equally owned by ExxonMobil Canada Ltd and Imperial Oil Resources Ltd, has filed an application to Canada’s National Energy Board (NEB) to build an LNG export plant at one of two sites on the British Columbia coast of a capacity of as much as 30 million tonnes/year. The application named two possible sites: Kitimat or Prince Rupert, BC. The term of the license sought is 25 years. The planned plant would consist of as many as six liquefaction trains of 5 million tpy each. The application said initial design capacity would be 10-15 million tpy ready by 2021-22. Full export capacity could come online as early as 2025. Gas supply to the plant would be from a combination of the partner companies’ proprietary gas and gas obtained through commercial supply agreements. The NEB application stated the companies have entered into confidentiality agreements with several pipeline companies and are in discussions regarding services for delivery of gas to the plant. Offshore World | 46 | JUNE - JULY 2013
Downstream CA Issues Refinery Safety Draft
Technip Secures Hydrogen Reformers Contract in Venezuela
US: California’s interagency refinery safety working group, which the state formed following a fire at Chevron USA’s Richmond plant in August 2012, has released a draft report outlining steps and recommendations to improve public and worker safety at and near refineries in the state.
Venezuela: Technip, the French oil and gas services company, has secured a significant contract from Hyundai-Wison consortium to supply its proprietary technology as well as engineering and procurement services for two hydrogen reformers in Venezuela.
Proposed actions in the draft include creating an interagency refinery taskforce within California’s Environmental Protection Agency to coordinate agencies’ activities, strengthening regulations and developing new ones to address underlying causes of safety problems, increasing public output in developing emergency response plans, and improving alerts and public access to information during emergencies.
Eni Plans Gela Refinery Investment Italy: Eni, the Italy-based integrated energy company, has announced a project for the renovation and recovery of the Gela refinery. The aim of the new project is to create an economically sound refinery capable of meeting the challenges of a competitive and constantly evolving market. The refinery will also be redesigned to be more environmentally friendly and respectful of the local area. The Gela refinery has accumalted heavy losses since 2009. The renovation and recovery project is subjected to restore the refinery’s economic sustainability by overcoming its structural weaknesses. The project is expected an divestment about EUR 700 million.
Valero Starts Hydrocracker Unit in US US: The 60,000-barrels per day new hydrocracker unit has successfully and safely begun operations at the Valero St Charles Refinery. The hydrocrackers were designed to capitalize on high crude oil and low natural gas prices, and produce primarily diesel to meet growing demand in both domestic and export markets. Each of the units cost about USD 1.6 billion to construct. Valero is pursuing projects to expand throughput capacity to 75,000 barrels per day at each of the new hydrocrackers. With successful permitting, the expansion projects are expected to be complete in 2015.
The contract covers the complete engineering, fabrication, modularisation, procurement as well as precommissioning and start-up assistance. This project will utilise Technip’s high-efficiency top-fired steam reformers, to produce high-purity hydrogen and export steam, and the latest nitrogen oxide reduction technology to ensure minimum emissions.
Sinopec Opens Lubricant Plant Singapore: Sinopec, the Chinese energy and chemical giant, has opened a lubricant manufacturing unit at Tuas in Singapore. The company has invested about 650 million YUAN (USD 136 million) in the lubricant production facility, which will also serve as its Asia-Pacific hub for logistics and service. The new plant, a key part of Sinopec’s global expansion plans, is to better serve customers across Asia, particularly South-East Asia, Australia and New Zealand.
IFC to Fund Oil Refinery in Turkey Turkey: The board of directors of the International Finance Corporation (IFC) is ready to funding USD 150 million for the construction of the Aegean refinery of the State Oil Company of Azerbaijan (SOCAR) in the Turkish port of Aliaga. According to the estimates, the cost of the project of construction and maintenance of the oil refinery with a processing capacity of 214,000 barrels of oil per day (10 million tons/year) is 5.3 billion dollars. The refinery will be built in four years and after its commissioning will be able to replace imports of diesel (45 per cent of production) and aviation fuel (15 per cent) through Turkey.
SK Global Signs Deal with Chinese Firm China: SK Global Chemical Co, a unit of South Korea’s SK Innovation Co, has signed a final agreement with Chinese state refiner Sinopec Corp for a 3.3 trillion won (USD 2.9 billion) petrochemical joint venture. An initial agreement on the project was signed in December 2011. Production at the plant in Wuhan, central China will start in the second half of the year and will have annual capacity of about 2.5 million tons of petrochemical products, including ethylene. SK Global will own 35 per cent of the project, the largest petrochemical joint venture between the two countries, while Sinopec holds the remaining stake.
Iran to Build Petrochemical Hubs Iran: Amid the eye-catching growth of Iran’s petrochemical industry, Rostam Qassemi, Oil Minister, Iran, has lauded in saying that new petrochemical hubs will be created in Lavan Island in the Persian Gulf and Chabahar region in the Southeastern province of Sistan and Baluchestan. The minister reminded that Lavan hosts Iran’s big gas and oil fields, and underlined that Iranian companies will turn the island into a major petrochemical hub. Qassemi said Iran’s seventh gasline has reached Chabahar zone in Sistan and Baluchestan province, and the creation of the country’s third petrochemical hub has started in this zone by the investments of the state welfare organization, armed forces and private sector contractors. Offshore World | 47 | JUNE - JULY 2013
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Hamworthy offers onboard regasification systems for installation on shuttle regasification vessels (SRV), floating storage regasification vessels (FSRV) and floating storage regasification units (FSRU). LNG regasification units are skid-mounted, very compact and can easily be arranged on deck. The LNG regasification unit by Hamworthy is designed for marine installations and for cryogenic working conditions.
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Activated carbon is a micro porous inert carbon with a large internal surface (up to 1,500 m2/g). On this surface organic molecules from liquids or gases can adsorb. Adsorption is the natural phenomenon in which molecules from the gas or liquid phase are attached to the surface of the solid. Carbon materials are activated by a series of processes which include: removal of all water (dehydration), conversion of the organic matter to elemental carbon, driving off the non-carbon portion (carbonization) and burning off tars and pore enlargement (activation). For details contact: V B Groups Building No: 1565, Subramani W-Island, Kochi Kerala 682 003 Tel: 0484-2429150, 4059150 Fax: 91-0484-2668407
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Offshore World | 48 | JUNE - JULY 2013
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Offshore World | 49 | JUNE - JULY 2013
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For details contact: Confidence Petroleum India Ltd 404, Satyam Apartments, 8, Wardha Road, Dhantoli, Nagpur, Maharashtra 440 016 Tel: 0712-3250318, 3250319
It brings clamp-on ultrasonic gas flow metering capability to atmospheric pressure applications at velocities up to 150 ft/s (46 m/s).
ULTRASONIC FLOW METERS Jost’s Engg offers ultrasonic flow meters and coriolis mass flow meters that can measure reliably over a wide range of pipe sizes and flow conditions. Their fixed-installation flow meters provide an unrivaled combination of powerful features to meet your needs. For testing, service and troubleshooting, their portable flow meters offer the ultimate in flexibility and ease of use. Their product range includes fixed-installation as well as ultrasonic portable flow meters. For details contact: Jost’s Engineering Co Ltd Plot No: 3, Survey No: 126, Paud Road, Pune, Maharashtra 411 038 Tel: 020-25434350, 25434565, 25431223, Fax: 91-020-25434393
DIGITAL FLOW METER Flow meter is an instrument used to measure linear, nonlinear, mass or volumetric flow rate of a liquid or a gas. The basis of good flow meter selection is a clear understanding of the requirements of the particular application. For details contact: MicroSet Instrumentation & Controls 102, Chinmay, 1103/A/10, Lakaki Rd, Model Colony Shivaji Nagar, Pune, Maharashtra 411 016 Tel: 020-25660109, Fax: 91-020-25660109 www.oswindia.com
For details contact: Test & Measurement Co No: 140, Bhagyashree Colony Opp: Vijay Nagar, Police Station Indore, Madhya Pradesh 452 010 Tel: 0731-2553780 Fax: 91-0731-2577593 E-mail: tmcindore@gmail.com / info@tmcindore.com / sales@tmcindore.com / sales2@tmcindore.com
PORTABLE GAS LEAK DETECTOR Oil & Gas Plant Engineers India Pvt Ltd offers wide range of combustible gas leak detector for various industrial applications. These detectors can be used to detect different types of gases, such as methane, isobutane, propane, ethanol, hydrogen, toluene, benzene, acetylene, carbon dioxide and more. Model XP 3140 works on the detection principle of thermal conductivity sensor. Designed using the latest technology and equipment, XP 3140 is an extractive type gas detector that delivers superior performance and long service life. For details contact: Oil & Gas Plant Engineers India Pvt Ltd No: 108-109, Chiranjiv Tower 43, Nehru Place, New Delhi 110 019 Tel: 011-26447007, 26427233, 26482594 Fax: 91-011-26482593
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events diary PetroWorld India 2013
Oil & Gas World Expo 2014
Date: August 22-24, 2013 Venue: Bombay Exhibition Center, Goregaon, Mumbai, India Event: Addressing the demanding needs of the Indian market, the inaugural PetroWorld India provides a unique platform for assembling the region’s key leaders for discussion of technical, strategic and business topics affecting the Indian oil & gas industry. With a specific focus on topics of interest to both Indian and international markets, PetroWorld India will showcase the tremendous scope of the oil & gas sector in India while providing a practical, solutions-oriented program for doing business in this rapidly expanding region of the world. PetroWorld India will bring together qualified senior management / executive decision makers who have the authority to purchase, or influence the purchase of products and services, as well as production and exploration managers, engineers and consultants from oil & gas sector across the world.
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: C K Arora/ Siddharth Chibba Inter Ads Exhibitions Pvt Ltd M: + 91- 9910863683 / 7503010430 F: + 91- 124- 438-1162; T: + 91-1244524204/4524200 Email: ckarora@interadsexhibitions.com / siddharth@interads.in
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 3rd SUBSEA INDIA 2013
PETROTECH-2014 Date: January 12-15, 2014 Venue: India Exposition Mart Limited, Greater Noida, Delhi (NCR) Event: The PETROTECH series of International Oil & Gas Conference and Exhibitions is a biennial platform for national and international experts in the oil & gas industry to exchange views and share knowledge, expertise and experiences. The event also aims to explore areas of growth in petroleum technology, exploration, drilling, production and processing, refining, pipeline, transportation, petrochemicals, natural gas, LNG, petroleum trade, economics, legal and human resource development, marketing, research & development, information technology, safety, health and environment management in the oil & gas sector. As the prime showcase of India’s hydrocarbon sector, this mega event attracts scientists, technologists, planners and policy makers, management experts and entrepreneurs to solicit their views in order to catalyse achievement of global energy security. PETROTECH-2014 is being organized under the aegis of the Ministry of Petroleum & Natural Gas, Government of India, by Oil and Natural gas Corporation Limited and PETROTECH. For details contact: PETROTECH-2014 Secretariat Oil & Natural Gas Corporation Ltd Jeevan Bharati, Tower - II, Indira Chowk, New Delhi - 110001 (INDIA) Tel.: +91-11-23312607/ 23301169/ 23301170; Fax: +91-11-23315207 Email: secretariat@petrotech.in
Date: 4-5 December 2013 Venue: Imperial Hotel, Janpath, New Delhi, India Event: The Third SUBSEA INDIA 2013 Conference and Exhibition will focus on “Subsea/Deepwater and Offshore Technology and Services. The Third SUBSEA INDIA 2013 will be attended by the officials from the Ministry of Petroleum and Natural Gas, Government of India along with senior executives, decision makers and experts of national and international oil companies and service providers. Connect with some of the world’s most renowned figures in the industry. Experts from India, US, UK, Norway, China, Malaysia, Singapore, UAE and Australia are to attend the conference. The conference besides focusing on the theme will have a high powered CEO PANEL comprising CEO’s from operator/service provider companies of the oil and gas industry. This year the CEO Panel will be Chaired by Mr.Sudhir Vasudeva, Chairman & Managing Director, Oil & Natural Gas Corporation Limited and Chairman, ONGC Group of Companies. The CEO Panel will comprise of five leaders of the industry discussing on the issues related to the subsea, deepwater and offshore segment of the industry. For details contact: DEW SYMPOSIUMS Tel: +91-9837038270, +91-135-2740559 E-mail: info@dewsymposiums.com
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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 Refinery Expansion
Bahrain
6,500,000,000
Bidding
Yateem Oxygen - Carbon Dioxide Extraction Plant
Bahrain
-
Execution
Daura Refinery - Fluid Catalyst Cracking (FCC) Unit
Iraq
2,500,000,000
Bidding
Karbala Refinery
Iraq
4,000,000,000
Bidding
Nasiriyah Grassroots Refinery
Iraq
8,000,000,000
Bidding
New Karbala Refinery
Iraq
6,500,000,000
Study
Al Zour Refinery
Kuwait
190,000,000
Bidding
Clean Fuels Project (CFP)
Kuwait
18,500,000,000
Execution
Sohar PTA Plant
Oman
680,000,000
Execution
Sohar Refinery Expansion
Oman
1,500,000,000
Bidding
Yibal Depletion Compression - Phase III
Oman
-
Bidding
Qapco Ethylene Expansion 3 (EP3) Project
Qatar
300,000,000
FEED
QP/Qapco Al Sejeel Petrochemical Complex Development
Qatar
7,400,000,000
FEED
QP/Shell - Ras Laffan Olefins Complex
Qatar
6,400,000,000
FEED
Aramco/Dow Jubail Integrated Refinery & Petrochemicals
Saudi Arabia
12,500,000,000
Execution
Middle East
IBN SINA Complex - Polyacetal (POM) Facility
Saudi Arabia
400,000,000
Execution
Jizan Export Refinery
Saudi Arabia
7,000,000,000
Execution
Normal-Butanol and Iso-Butanol Plant
Saudi Arabia
517,000,000
Execution
Borouge 3
UAE
4,500,000,000
Execution
DUGAS - MTBE Plant Expansion
UAE
-
FEED
IPIC - New Fujairah Oil Refinery
UAE
3,500,000,000
FEED
Ruwais Refinery New Facilities
UAE
3,100,000,000
Execution
Africa Algiers Refinery Revamping
Algeria
300,000,000
Execution
Skikda Refinery Upgrade
Algeria
2,600,000,000
Execution
Lobito (SonaRef ) Refinery
Angola
8,000,000,000
Execution
Soyo Refinery
Angola
-
Planning
Cameroon Ammonia Urea Fertilizer Plant
Cameroon
1,400,000
Study
Alexandria Petrochemicals Complex - Polyethylene Plant
Egypt
-
Execution
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Africa
Country
Value ($)
Status
ERC - Mostorod Refinery
Egypt
3,700,000,000
Execution
E-Styrenics Polystyrene Plant
Egypt
758,000,000
Execution
Suez Tank Terminal
Egypt
-
Study
Tahrir Petrochemicals Complex [NEW]
Egypt
3,700,000,000
Study
Port-Gentil Refinery [NEW]
Gabon
1,000,000,000
Planning
Tema Fuel Storage Tanks
Ghana
-
Study
Mbini Refinery
Guinea
404,000,000
Execution
Kenya Petroleum Refineries Limited (KPRL) Mombasa Refinery
Kenya
17,000,000
Execution
Mellitah Complex
Libya
-
Execution
OCP-Diammonium Phosphate Facilities
Morocco
170,000,000
FEED
Zinder Refinery (Soraz)
Niger
980,000,000
Execution
Akabuyo Refinery
Nigeria
7,500,000,000
Planning
Eleme Fertilizer Plant
Nigeria
1,200,000,000
Execution
Coega (Mthombo) Refinery
South Africa
10,000,000,000
FEED
Mnazi Ammonia/Urea/Methanol Project
Tanzania
-
Study
Hoima Oil Refinery
Uganda
2,500,000,000
Study
Caspian Region
Country
Value ($)
Status
Azerikimya Ethylene-Polyethylene Plant
Azerbaijan
-
Execution
Oil, Gas Processing & Petrochemical Complex (OGPC) Project
Azerbaijan
15,000,000,000
Study
Sumgayit Nitrogen Fertilizer-Urea Complex
Azerbaijan
-
Study
Abadan Refinery Upgrade
Iran
3,000,000,000
Execution
Bandar Imam Petrochemical Complex
Iran
-
Execution
Esfahan (Isfahan) Refinery Expansion
Iran
2,500,000,000
Execution
Ham - Petrochemicals Complex (Olefins 13)
Iran
-
Execution
Imam Khamenei Gas Refinery
Iran
-
Study
Karoon Isocyanates Complex
Iran
-
Execution
Lavan Refinery Upgrade
Iran
-
Execution
Parsian Gas Refinery
Iran
400,000,000
Execution
Persian Gulf Star Gas Condensate Refinery (PGSCR)
Iran
2,600,000,000
Execution
Tabriz Refinery Expansion (Shahriar Refinery)
Iran
2,000,000,000
Execution
Atyrau Refinery Upgrade
Kazakhstan
1,040,000,000
Execution
Karachaganak Gas Refinery
Kazakhstan
3,700,000,000
Study
Pavlodar Refinery
Kazakhstan
40,000,000
Execution
FEPCO Project
Russia
5,000,000,000
Study
Moscow Refinery Upgrade
Russia
-
Execution
Omsk Refinery Upgrade
Russia
5,000,000,000
Execution
Tobolsk-Polymer Complex
Russia
-
Completed
Togliatti Ammonia and Hydrogen Plant
Russia
350,000,000
Study
Tuapse Refinery Upgrade
Russia
2,000,000,000
Execution
Offshore World | 53 | JUNE - JULY 2013
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book shelf H Y D R AU L I C F R AC T U R I N G ( F R AC K I N G ) - P R O C E D U R E S, I S S U E S, AND BENEFITS AAuthor: Okon Obo PPrice: USD 4.74 PPaperback: 122 Pages P Publisher: Petroleum Zones Book Description: Hydraulic Fracturing is a unique oil and gas reservoir stimulation technique that has positioned itself as the technology of choice. Used together with horizontal well, it unlocks impervious shale rocks in order to release natural gas that otherwise would not have been possible by using conventional methods. Readers are given solid foundation in the procedures, issues and benefits associated with Hydraulic Fracturing (Fracking). Book contents, among others, include a concise explanation on: • Natural Gas (Conventional and Unconventional Gas) • Formation Preparation for Hydraulic Fracturing: Well Drilling Process, Well Completion (Perforation), Preferred Well Configuration (Horizontal Well) • Hydraulic Fracturing / Procedures • Common Misconception of Fracking Technique • Environmental Concerns of Hydraulic Fracturing • Benefits of Hydraulic Fracturing • Eco-Friendly Alternatives to Hydraulic Fracturing S U B S E A C O N T R O L A N D D ATA A C Q U I S I T I O N : F O R O I L A N D G A S P R O D U C T I O N S Y S T E M S ( A D VA N C E S I N U N D E R WAT E R T E C H N O LO G Y, O C E A N S C I E N C E A N D O F F S H O R E E N G I N E E R I N G ) Ed Editor: Society for Underwater Technology (SUT) P Price: USD 179.55 P Paperback: 264 P Publisher: Springer B Book Description: The biennial conferences of the Society for Underwater Technology have achieved an excellent reputation for the quality of their presentations, which cover topics of the most acute current interest, as well as those at the forefront of review and d development. The 1994 conference onSubsea Control and Data Acquisition formed no exception, since it covers subjects at the cutting edge of modern technology. It is a matter of increasing concern that produc ts are becoming overspecified, resulting in excessive costs and longer development schedules, while not conferring an equivalent benefit in reliability of the finished product. www.oswindia.com
SHALE GAS: THE PROMISE AND THE PERIL Author: Vikram Rao Ph.D. Price: USD 12.56 Paperback: 198 Pages Publisher: RTI International / RTI Press Book Description: Shale gas has the potential to transform the US energy-based ec economy in the electricity, transportation, and ch chemical sectors. US success can be expected t translate to Europe and other parts of to t world. Shale gas production is uniquely the enabled by hydraulic fracturing, a technique that has come under heavy scrutiny for its potential to cause environmental damage. In this book, Vikram Rao addresses the issues surrounding shale gas in a balanced fashion. The book is intended to inform both sides of the fracturing debate, where currently rhetoric is overtaking understanding. Tailored for a nontechnical audience—with technical chemistry and geology information couched in sidebars—the book culminates in suggestions for research and guidance for policymaking. ENHANCED OIL RECOVERY FIELD CASE STUDIES Authors: James Sheng Price: USD 101.52 Pages: 712 Pages Publisher: Gulf Professional Publishing Bo Description: Enhanced Oil Recovery Book F Field Case Studies bridges the gap between t theory and practice in a range of real-world E settings. Areas covered include steam EOR a polymer flooding, use of foam, in and situ combustion, microorganisms, “smart wate r ” - b a s e d E O R i n c a r b o n ate s a n d sandstones, and many more. Oil industry professionals know that the key to a successful enhanced oil recovery project lies in anticipating the differences between plans and the realities found in the field. This book aids that effort, providing valuable case studies from more than 250 EOR pilot and field applications in a variety of oil fields. The case studies cover practical problems, underlying theoretical and modeling methods, operational parameters, solutions and sensitivity studies, and performance optimization strategies, benefitting academicians and oil company practitioners alike. • Strikes an ideal balance between theory and practice • Focuses on practical problems, underlying theoretical and modeling methods • Designed for technical professionals, covering the fundamental as well as the advanced aspects of EOR
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Date of Publication: 1’st of every alternate month.
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