ROGTEC Magazine - Russian Oil & Gas Technologies - News, Reviews & Articles

ROGTEC Magazine - Russian Oil & Gas Technologies - News, Reviews & Articles

Andrew Gould Delivers Keynote Speech at Howard Weil Energy Conference 2011 in New Orleans

Monday, March 28th, 2011

Ladies and gentlemen good morning—it’s a great pleasure to be back in New Orleans for the 39th Howard Weil Energy Conference.

In spite of the political turmoil and natural disasters that we have seen over the past two months, I’m going to try and convince you that the fundamentals for oil and gas remain unchanged, and that the case for investment in the premier oilfield services company has never been stronger.

To do this, I’m going to cover three topics.

First, I will review the macro environment for oil and gas, showing how this has evolved and how it is evolving. I’ll demonstrate that the theme of increasing complexity in finding and developing hydrocarbons remains valid, while new opportunities have arisen from technology or changed circumstances.

Second, I will describe how Schlumberger is uniquely positioned to address industry needs through size, technology offering, geographical presence, infrastructure, workforce, together with our industry-leading efforts to improve operational performance.

Finally, I’m going to outline some of our ambitions for the next five years.

Looking at the broad picture, 2010 saw the most astonishing rebound in oil demand in recent history with the increase of 2.8 million barrels per day being the second highest in 30 years. The average demand increase in 2011 from the three principal forecasting agencies is for an additional 1.4 million barrels per day. While spare capacity, almost exclusively concentrated in the Middle East OPEC countries, is significantly higher than in 2006, it is not enough to absorb a rapid increase in demand and the rate at which new supply is added will decrease in the coming year. The absence of Libya from this market creates additional tensions and oil prices have recently begun to reflect a fear of supply shortage and disruption.

US natural gas prices on the other hand remain subdued with high levels of storage and the perception that supply is abundant and can be quickly increased. Following a 1.8% decrease in demand in 2009, the EIA has recently estimated a 5.4% increase in 2010 followed by a flat 2011 at 66.2 billion cubic feet per day. The 2010 increase is the largest year-on-year growth since 2007.

Longer term, the 2010 IEA World Energy Outlook projects fossil fuels still to be  dominant by 2035, even if low carbon policies are implemented. They also predict natural gas to show the largest increase in absolute terms by that time.

To enable such growth in oil and gas supply, investment of some 450 billion dollars is estimated to be needed every year in upstream activity for the next 25 years.

To illustrate the size of the task ahead, the IEA estimates that approximately half of the conventional oil production needed by the end of this decade has yet to be developed or discovered. By 2035, that figure may have increased to more than 70%.

Of this production, offshore activities—and deepwater operations in particular—merit significant attention. In the last ten years, more than half of all new oil and gas reserves discovered worldwide has been offshore. As a result, offshore oil could be supplying approximately one third of the world’s needs by the late 2020s. And by then, deepwater production will have increased to about one third of offshore supply, or approximately 10% of global supply.

For natural gas, the IEA projects demand to increase by 1.4 to 1.6% per year between 2008 and 2035, with the bulk of that increase coming from the non-OECD economies. Other forecasts are even more bullish, projecting annual growth rates of around 2.0%. In addition, a reassessment of the energy mix following the nuclear accident in Japan is likely to confirm higher demand growth for natural gas.

My task today is to convince you that absent a second economic shock and a further drop in demand, the industry will face an increasingly harder task of turning resources into reserves, and reserves into production—particularly for conventional oil.

It is instructive to look at the broad context of the last decade to understand why this is so. That decade was marked by a fundamental shift in the security of supply argument, which, having been an OECD concern for the last hundred years, became China’s obsession, with it, and to some extent India, now driving demand. This is the first, and undoubtedly the most important, shift of the last decade.

The second shift of the decade was undoubtedly the emergence of Russia as the world’s single largest producer. Following the collapse of the Soviet Union, Russian production fell to as low as 6.1 million barrels per day. In the six years following 1999 it rose by more than 3 million barrels per day, becoming the major reason why oil prices had not risen faster earlier in the decade.

This leads me to the supply response. At the beginning of the decade when supply-demand balances started to tighten, the industry faced its first supply challenge in 25 years. In the years following 2003, the thin margin of excess capacity coupled with rapid price increases, led to the explosion in exploration and production capex from $130 billion in 2000 to $500 billion in 2008—a compound growth rate of over 18%.

All of this led to a period of frantic growth in activity that has had major effects on the industry structure and I‘d like now to look at some of the short- and long-term consequences. The first, and by far the most important effect was the re-emergence of resource nationalism.  This isn’t new, but in the 2000s resource nationalism was rife. Russia sought to capture a greater share of the rent. Venezuela closed again, and the Middle East did not open significantly. Mexico didn’t open at all. Libya opened but recent events have showed how transitory that was. Sanctions kept Iran and Sudan largely off limits. And after a spate of extraordinary discoveries, Brazil started to restrict access—not to investment but to foreign operators in the pre-salt domain.

The net result is that perhaps 75% of the world’s known conventional oil reserves are closed to international private capital today, while 60% of production originates from non-NOC operators.

The consequence of this has been to give a whole new meaning to the words “major resource holder”. The range of national companies, both in structure and in competence is now vast. Some are major offshore operators, such as Statoil or Petrobras, while others have mastered complex project management, such as Saudi Aramco. Such companies are capable of competing with the best while other NOCs are emerging with increasingly large international portfolios.

All these restrictions led the industry, particularly the IOCs and independents, to opportunities offshore, in more remote and harsh environments, and to the heavier end of the hydrocarbon chain. In addition, discoveries of conventional oil accumulations became smaller, and therefore more difficult to produce economically.

These sources of conventional oil production are increasingly complemented by unconventional oils, such as heavy or shale oils, which require massive projects of long duration that require huge amounts of capital. As a result, if there is one common characteristic in the oil exploration and development projects to be executed in the future, both for deep offshore and complex unconventional oils, it is that they will become more difficult and more expensive to execute

The 2000s were equally a decade of tremendous change for gas. Natural gas economics are governed by geography and by transportation to market. Today’s multiple sources of supply should allay fears of any rupture in supply to Western Europe, while shale gas in the USA has changed the dynamics of US supply. And the rapid development of deposits in Australasia has changed the availability of long-term supply for China, Korea and Japan.

However, two phenomena marked the 2000s. The first was the huge expansion in LNG capacity, which is still increasing due to projects begun in the late 2000s and which is expected to represent 15% of global capacity by 2020. This is essentially a play for very large companies as investments are massive, and projects long to come to market.

The second was the development of North American shale gas.  The shale gas revolution required technology, market forces and entrepreneurship to make its production economic. And while today’s combination of horizontal wells and hydraulic fracturing has made certain shales economic, technology will have to move much further to systematically extract full value from every shale as current methods are both wasteful and expensive.

In the rest of the world, where knowledge of shales is vastly inferior to that of the US, countries and companies are actively searching to understand the prospectivity of their own deposits. Much remains to be done before we can be assured that the rest of the world’s shales are as prospective as those of the United States.

I have now outlined the context for supply and demand, and indicated how the industry will focus more and more on complex, difficult-to-reach resources. Some of that focus has already occurred as the growth in new projects clearly shows.

For example, the cost of new deepwater exploration and development projects in increasingly remote locations coupled with the complex logistics associated with areas such as Russia, the Caspian and Iraq are fundamentally changing the importance of project management and project execution. There are now over 200 exploration and production projects worldwide that have a budget in excess of $1 billion.

In addition, it is extraordinary that NOCs and Independents now represent over 80% of total industry capex spend. No less than 30 oil and gas companies have annual capex budgets in excess of $4 billion—up from only 10 in 2001. While not wishing to embarrass any of my customers, I would add that many Greenfield projects suffer significant cost overruns. Indeed, as a general rule 30% of such projects experience budget overruns of 50%.

Clearly, the service company that can bring the best in technology, process and workforce competency to limit such expense stands to gain the greatest advantage. In other words, the future will all be about raising the bar on execution.

If I now compare our top 30 customers in 2010 to those of 2002, there has been little change. There were and are 5 super majors. In 2010 we counted 13 NOCs, up from 12 in 2002. On the other hand, there are 12 independents, down from 13. However, the shift in revenue between customer groups is extraordinary. In 2002 the super majors represented 33% of the top 30. This had declined to 22% by 2010. In the same period revenues from the NOCs almost doubled, while independents declined slightly.

However, there is another dynamic in our ability to meet our customers’ requirements. The consequences of the Deepwater Horizon tragedy where eleven men died and which led to the largest oil spill in US history will change some of the ways the service industry works forever.

Among these, the reliability of technology as well as the operating efficiency in project planning and execution and the regulatory consequences of Macondo will add a new dimension to offshore operations in three areas—regulation, technology and capability. Stricter standards of regulation will require much improved process from the service industry. Technology will be needed to improve both safety as well as operational performance, and capability will need to be managed through improved processes.

It is therefore essential that our technology not only address the challenges of exploration and increased drilling intensity and the challenges of a changing customer base, larger projects, more remote operations, increasingly complex geological settings and higher pressures and temperatures. It must also respond to new deepwater requirements post Macondo and help mitigate higher operating costs, particularly offshore.

I would like now to look at these technologies in more detail beginning with exploration, where our own technology portfolio is unmatched and we are uniquely positioned to profit from increased exploration spend.

Whether in seismic through WesternGeco, in openhole wireline, logging while drilling or testing we are the leading player. Following the acquisition of the minority interest in WesternGeco in 2006, we are now in a position to provide customers with innovative processing and interpretation routines that allow us to move directly from seismic processing to Petrel workflow process and back again thus helping reduce risk and move more rapidly to field development planning. This has allowed Petrel to increase market penetration over the last year as it expands into the growing exploration market.

The significance of this is obvious when you look at industry performance as measured by a wide group of oil companies. This clearly shows that the world has been consuming considerably more oil than has been discovered, and the need to accelerate exploration is therefore a necessity. Exploration will be a key driver over the near term.

The availability of deepwater rigs will accelerate this as more deepwater provinces become active. We have recently signed an exploration contract for an ultra deepwater rig that will drill successively in Australia, East Timor, India, Indonesia and Mozambique. This type of roving exploration campaign is becoming increasingly common and you can imagine that the planning and logistics involved are extraordinarily complex. The exploration market is also one where the value of data is increasing.

Indeed, the intensity of exploration spend has increased much faster than overall upstream cost indexes. There are good reasons for this. Location, reservoir complexity and hydrocarbon composition all require higher technology to be properly addressed.

For some time we have stressed that maintaining production and bringing new reserves on line would require an increase in drilling intensity. The emphasis is not just on the number of wells to be drilled, but also on their increasing complexity and cost be it for expensive deepwater wells or for the technology required to make unconventional hydrocarbons economic through the introduction of practices such as factory drilling.

Given this context, in addition to investment in new technology, it is becoming increasingly apparent that the old adage of the oil industry holds truer than ever. If you want to find oil you have to drill. And if you want to produce unconventional gases or oils it is even truer.

I have already referred to the increase in exploration and development offshore and in deepwater. At the same time differing hydrocarbon types require greater degrees of drilling technology—both to improve the reliability of operations and to reduce overall finding and development costs.

In addition to new exploration drilling technologies, drilling to help recover unconventional gases and unconventional oils requires technologies for better extraction, lower cost and smaller environmental footprint. The dramatic change in the North American well count from vertical to horizontal over a very short period of time demonstrates the extent to which this change is already underway.

Another area for increased drilling concerns those reserves already in production. Prolonging their exploitation and increasing their recovery represents a significant opportunity and it is here that increased drilling intensity is likely to make the biggest difference in the short to medium term. The rehabilitation of the productive capacity in Iraq is an example that implies higher rig counts and this pattern is likely to be increasingly seen around the world.

It is the technology needs for the market opportunities that I have just discussed that have led us to the acquisitions of Smith and Geoservices.

We believe that the combination of our own leading positions in directional drilling, measurement-while-drilling and logging-while-drilling with Smith’s positions in drill bits, drilling tools and drilling fluids through M-I SWACO together with our joint venture with National Oilwell Varco for wired drillpipe will allow us to help customers with the three components of the drilling workflow, drilling optimization, well placement and wellbore assurance.

Integrating the drilling workflow is complex, and will require a concerted effort all the way from research and engineering to well planning and wellsite operations. In doing so, we will need to transform the overall drilling process from being partly a form of art, to becoming a full-fledged science.

New drilling technology is also needed to stem production decline or increase recovery through an increase in reservoir contact with the well bore. In this market we hold a leading position. In well placement for example, which is perhaps the most important technology in enhancing recovery, we lead the market through our geosteering capabilities.

In other highly pertinent production-focused technologies, our advanced intelligent completion products are having considerable success in managing reservoir contact. Furthermore, our position in deepwater completions is strong.

In pressure pumping we are pleased with the progress that has been made in the North America stimulation market. We are excited by the initial success of HiWay fracture stimulation, and we occupy a leading position in the market in the rest of the world.

Lastly, Schlumberger leads the industry in the three principal methods of evaluating and treating old wells to enhance production. These are wireline production services, slickline and coiled tubing. In each of these markets we enjoy the number one position and are introducing increasingly differentiated technologies such as the ACTive Technology Platform, a coiled-tubing system that combines wireline-quality cased-hole measurements with coiled tubing to create a unique industry product.

The application of our technology and our ability to grow is dependent on our building on a set of strengths that are unique to Schlumberger. I do not have time to go through them all in detail and therefore will concentrate today on technology leadership, global footprint, operational integrity, and organization. Our commitment to a fully diverse equal opportunity workforce is well known and forms a fundamental competitive advantage, as does our size.

From the company’s origins in wireline logging, we have over time expanded our technology portfolio into a wide range of oilfield services and products, establishing leadership positions in most of the markets we have entered. Today our portfolio is by far the broadest in the industry spanning 16 strong product lines.

By being able to offer the complete range of technologies in a workflow, we can eliminate this misalignment and ensure that all the focus is kept on solving the customer’s challenge. This is why we have organized and expanded our technology portfolio in line with the three main workflows of our customers—reservoir characterization, drilling, and production

Supporting this technology portfolio is a product development machine made up of more than 15,000 people in 65 centers around the world. The global footprint of these centers mirrors that of our operations to enable close coordination between the two.

We invest more than USD 1 billion a year in product development ranging from ground-breaking research that drives innovation to detailed engineering of our next-generation commercial products. And today, our product development organization manages over 700 projects and supports more than 2,500 commercial products for our product lines.

In 2007, we conducted a comprehensive evaluation comparing our product and project performance against leading companies in other technology driven industries. From this work we concluded that we have huge potential for achieving better reliability and lowering the cost of ownership for our products. These changes represent one part of the “Excellence in Execution” program, which we started in 2007 and that will ensure that we widen our technology lead going forward.

In terms of global footprint, our local knowledge and infrastructure is enormous and sustainable. We operate in approximately 80 countries, many of which for more than 70 years. Our long and rich history has created deep customer relationships and extensive local knowledge.

Throughout this time we have also made continuous investments in infrastructure and actively recruited and developed local talent. For example in 2009 alone, we recruited over 4,000 engineers and technicians globally, and we opened 9 new state-of-the-art facilities around the world.

In addition to having created strongholds in most of the oil and gas basins around the world, our global footprint has other advantages. For example our operational flexibility allowed us in the two months following the imposition of the Gulf of Mexico moratorium to move 580 of our deepwater experts to new locations around the world.

Iraq is another example of how we leverage our global footprint. Even though we were not the first to return to Iraq due to security concerns, we have quickly taken the lead in terms of operations on the ground. We have also won more than our fair share of the contracts so far awarded, and we are doing well in terms of field operations.

Today we have three rigs drilling for BP, and we have another three being mobilized for ExxonMobil. In addition, we have won a workover rig contract for ENI, as well as several individual products and services contracts for other operators. Indeed in the last week we were awarded two further products and services contracts valued at approximately $100 million.

Our position within the worldwide unconventional gas market is another example of leveraging a global presence. In addition to our activity in North America we are engaged today in unconventional gas projects in all parts of the world. Looking at shale gas in particular we are convinced that the brute force approach established in North America will not be practical overseas, either from a financial or an operational standpoint and to exploit the full potential of shale gas globally, we will need to establish a workflow and corresponding technology offering built around better evaluation and characterization of shale gas reservoirs.

Moving to operational integrity, Schlumberger was one of the first in the industry to introduce a QHSE management system back in the early 1990s. Over the past 20 years we have established industry-leading performance within the areas of quality, health, safety and environment. The growing complexity and cost of oil and gas development is an opportunity to set ourselves further apart in terms of operational integrity, which is all the more important following the Deepwater Horizon incident.

Therefore in 2007 as part of the Excellence in Execution program, we started to look at what we could learn from other leading industries in terms of operational quality and reliability.

This operational side of Excellence in Execution targets field and wellsite operations in terms of people and process as well as product maintenance.

As part of our major drive towards better product maintenance we have over the past 4 years invested more than USD 500 million in building new and larger operations bases in all parts of the world. These new and larger bases enable standardization and more robust maintenance practices based on LEAN principles. This leads to reductions in maintenance times and in numbers of operational failures—factors that drive asset utilization. In North America pressure pumping for example, we have doubled our asset utilization during the past year based on these principles.

Our focus on operational integrity is also closely linked to people competency and having the right operational processes.

The maturity of our organizational model is also a distinct competitive advantage.

After having operated our product lines as standalone businesses since the company was founded, we moved to a matrix organization in 1998 creating the original GeoMarket structure. Transforming a set of standalone product lines into a matrix framework takes both time and investment, because it requires a step change in teamwork and trust, more clarity of roles and responsibilities, as well as common business processes and systems.

Thirteen years into the matrix transformation, we have successfully created a common customer interface and grown our IPM business significantly through the GeoMarket organization. We have also maintained or even strengthened the competitive position of all of our product lines.

But while we have made some progress on lowering the support costs and driving technology integration, we still have significant upside potential in these areas, which we are actively pursuing by giving the product lines management control of their day-to-day operations to allow the GeoMarket organization to focus more on support costs and technology integration.

The recent restructuring of our North America operations is a good example of how we can use our maturity to tune and optimize the organization in a non-traditional market.

The standard GeoMarket model was never optimized for North America land, which is quite different from the traditional high-tier markets. Our restructuring created a separate focus on this business by organizing the product lines into the workflows of reservoir characterization, drilling, and production—and by centralizing overall business management as well as our shared support organization.

At the beginning of 2010 we told you that our North America performance would be fixed in 12 months. While our fourth-quarter results benefited from year end and IPM impacts, it is clear that we have made huge progress and that our ambition of being leaders in North America in both size and margins is now within reach.

Before ending, I need to update you on events affecting the current quarter. Firstly I would remind you as we did in the fourth-quarter conference call that the effect of year-end product deliveries and multiclient data sales does not repeat in the first quarter. This year, the pattern of a sharp drop in multiclient sales and the fluctuation in marine activity has been particularly pronounced. I would remind you all that the year-end surge in Multiclient sales contributed about three cents to our fourth-quarter earnings.

In addition, adverse weather materially impacted North America land and Australia, while the earthquake in Japan had a minimal effect on the quarter. Minor revenue disruptions due to political disturbances were felt in Ivory Coast, Yemen, Bahrain and Oman, and in Algeria due to logistics from Tunisia. Significant revenue disruption occurred in Egypt, Tunisia and Libya. The total after-tax effect of these events on the quarter is expected to be in the range of 8 to 10 cents. While activity has returned to normal in Egypt and Tunisia, we expect continued disruptions in Yemen, no short-term return of activity in Libya and uncertainty at the current time over activity in Bahrain.

Schlumberger has doubled in size since 2005 and as the search for oil and gas becomes more global, more intense and more difficult there is no reason why the company should not, overtime, double in size again.

Today I have reviewed a very favorable macro scenario for Schlumberger that together with our technology portfolio and our unique structural strengths will allow us to meet our stated ambitions. We will be stronger for longer but it will mean raising the performance bar for our customers, our shareholders and our competition.

Our leadership in measurements combined with our international presence will put us in the forefront of exploring and developing unconventional gas plays outside North America.

Our position in IPM will provide a further leg to our growth—particularly in production enhancement and field development

In all our activities, and particularly in deepwater, the investment we have made in Excellence in Execution will pay big dividends, and we will continue to produce exceptional financial results

Ladies and gentlemen, this will be the last time I address this conference as CEO of Schlumberger. I would like to thank everybody for the kind attention you have given to my words over the last eight years and to Howard Weil for continuing to attract so many investors to listen to them.

Finally, I am conscious of leaving behind me a management team that I have every confidence will be able to execute the ambitions I have outlined.


Regular Meeting of the Board of Directors of OAO TATNEFT

Monday, March 28th, 2011

A regular meeting of the Board of Directors of OAO TATNEFT was held in the Cabinet of Ministers of the Republic of Tatarstan (Kazan) on March 26, 2011.

The Board of Directors reviewed the budget execution of OAO TATNEFT for two months of 2011 and approved the budget for April and the second quarter of this year.

The Board of Directors heard the information on introduction of new technologies of oil fields development and production and measures to significantly improve the efficiency of enhanced oil recovery (EOR) methods application in TATNEFT.  Application of tertiary enhanced oil recovery methods application resulted in production of over 5.3 million tons of crude oil in 2010 and application of hydrodynamic methods of the oil recovery enhancement resulted in production of more than 6.2 million tons. Application of EOR methods allowed producing 44.8% of the total oil recovery volume.

The Board of Directors discussed the progress in the use of intelligent systems in mature oil production fields. The third block of   Berezovskaya area was selected to implement this program. In the framework of this project a plot was selected in the area of development equipped with a means of measurement of a large number of well operating parameters, which enable to significantly improve the quality of performance with the existing well stock. The site is an ideal testing ground for experimental work, training of specialists of the geological and technological services of the Company. The next stage of the project will be establishment of methodological approaches for monitoring the progress of the field development with the use of automated controls.

The Board of Directors considered the issue of OAO TATNEFT’s auditor for the statutory auditing of the annual financial statements for 2011 prepared in accordance with the Russian accounting rules. It was decided to recommend to the annual general shareholders’ meeting to approve ZAO Energy Consulting/Audit as an auditor for one year period.

The Board of Directors specified the date of the annual general shareholders’ meeting on the results of 2010: it will be held on June 23 of the current year at  Neftche Palace of Culture in Almetyevsk.

The Board also reviewed a number of other issues of financial and economic activity of OAO TATNEFT.


BP Remains Committed to Partner with Russia

Friday, March 25th, 2011

BP announced today that an arbitral tribunal has ruled that the interim injunction issued to prevent BP’s proposed transaction with Rosneft, which includes Arctic exploration and a share swap transaction, from proceeding should continue.

BP will now apply for a determination whether the share swap may proceed on its own.

BP said it looks forward to finding a way to resolve its differences with its Russian partners to allow these important Russian Arctic developments to proceed in future.

BP has a long history as a leader in oil and gas exploration and the development of new technologies. BP intends to continue in that role for decades to come as the world looks to satisfy its increasing demand for secure, affordable energy supplies. BP has the scale and experience to use these new technologies to develop frontiers like the Russian Arctic.


Polarcus launches first 3D multi-client project

Thursday, March 24th, 2011

Polarcus Limited is pleased to announce that the Company will commence acquisition in Q2 2011 of its first 3D multi-client project, in Quad 28 of the UK Continental Shelf. The survey, with the potential to cover an area of up to 2,000 square kilometers, is supported through industry pre-funding. The data will be acquired by the vessel POLARCUS NADIA with acquisition expected to take from 70 to 100 days depending on final program size. Data processing will be undertaken by GX Technology, the imaging solutions group of ION Geophysical. To enable companies to use the data for their UK 27th Round block evaluations a preliminary dataset will be available within one month from the end of acquisition, with delivery of the final migrated data volume expected to take place within December 2011.

“Polarcus is especially excited to announce this survey, our first ever 3D multi-client project”, commented Rolf Rønningen, CEO Polarcus. “Our investment in strategic partnerships with experienced and highly regarded industry professionals in this field is enabling us to develop a strong portfolio of robust multi-client project opportunities worldwide. This first project targets an area receiving significant attention as a result of the recent oil discoveries announced subsequent to the UK 26th Round. We anticipate this area will attract considerable industry focus in the next UK licensing round, with the Polarcus survey being the reference data for company evaluations.”

The survey, designed in conjunction with GeoPartners Limited, covers the Western Platform of the Central Graben and includes the Catcher discoveries (28/9-1 ‘Catcher’, 28/9-2 ‘Varadero’ and 28/9-4 ‘Burgman’). These discoveries, drilled in 2010 and 2011, encountered excellent quality hydrocarbon bearing sandstones with light oil (26 to 31 degree API) in thick, high porosity sandstones of both the Eocene Tay and Paleocene Cromarty intervals at depths ranging between 3,500ft and 4,600ft. The new high trace density 3D seismic will provide a significantly improved interpretation of these shallow sand bodies where amplitudes and direct hydrocarbon indicators (DHI’s) are critical.


ABS Says The Time Is Now for Floating LNG Concept

Wednesday, March 23rd, 2011

ABS Vice President of Global Gas William J. Sember says the classification society is in advanced stages of design review for a number of Floating LNG (FLNG) concepts, as this technology moves ever closer to reality.

Speaking at the Gastech 2011 conference, where he chaired the technical session on FLNG terminals and systems, Sember noted that as recently as five years ago, floating solutions for the import and export of LNG were still considered new and novel concepts.

“Today emerging proprietary technologies and transport designs have come of age and industry is poised for the first projects. With more than one-third of global gas reserves stranded by their location or field size without commercially viable access to world markets the attractiveness of FLNG cannot be denied,” he told attendees.

Major projects in progress include Shell’s Prelude field in the Browse Basin off Western Australia, which gained environmental approval in late 2010 and has a target production start date of 2016. Also being closely followed are several projects offshore Papua New Guinea and Inpex’s Abadi Field gas project offshore Indonesia.

FLNG offers a number of advantages over land-based terminals. FLNG installations can result in  lower overall project costs and reduced environmental footprint because facilities such as long pipelines to shore, onshore development and offshore compression platforms are not needed. With gas deposits often in remote or stranded areas far from the coast the ‘marinizing’ of production, liquefaction and export facilities offers great potential for many future development projects.

Sember noted that the shipping and offshore industries have spent the past five years successfully advancing both the technology and commercial attractiveness of the FLNG concept as a means of delivering new sources of cleaner energy.

Technology developments have addressed issues as the integration of subsea architecture with FLNG; offloading systems, in particular for harsher environments with tandem configurations based on cryogenic hoses or flexible pipes; and the qualification and testing of components with regard to LNG transfer systems.

“From a class society perspective there are no technology showstoppers for FLNG. Liquefaction plants have been suitably optimized in order to efficiently use deck space while taking into account the safe and efficient operation of process equipment,” said Sember. “The advances and level of sophistication in all these subjects are evident. The time for commercialization and the first project is now.”

Founded in 1862, ABS is a leading international classification society devoted to promoting the security of life, property and the marine environment through the development and verification of standards for the design, construction and operational maintenance of marine-related facilities.

New Schlumberger Quartz Gauges Deliver Reliable High-Resolution HPHT Measurements

Tuesday, March 22nd, 2011

Signature Gauges Help Reveal Reservoir Quality in all Testing Operating Environments

Schlumberger today announced the introduction of Signature* quartz gauges for well testing operations. The new gauges operate reliably in rugged downhole conditions to obtain high-quality pressure measurements throughout a test, even in high-pressure high-temperature (HPHT) conditions up to 30,000 psi and 410 degF.

New-generation ceramic-based electronics were designed by Schlumberger metrology experts specifically for pressure measurement, with data acquisition and processing combined into a purpose-built circuit. This integrated design optimizes power consumption and allows less physical connections for enhanced reliability.

″With our Signature quartz gauges, operators can run detailed tests for longer to reveal the finer features of the reservoir,″ said Devan Raj, marketing and technology manager, Schlumberger Testing Services. ″Clients can see beyond the near-wellbore area for better reservoir characterization compared to tests run using standard pressure gauges.″

The gauges have been field tested in India, Saudi Arabia, Norway and the United Kingdom under a variety of reservoir conditions.

In a HPHT offshore well, the 410 degF temperature rating of the Signature gauges allowed the operator to position them at a depth of 5,108 meters, which was 1,750 meters closer to the reservoir than conventional gauges. The well test lasted 15 days and met the operator’s test objective of confirming the reservoirs commercial viability.

For more information, visit

Exillon Energy Updates

Tuesday, March 22nd, 2011

Exillon Energy plc, a British listed independent oil producer, with assets in two oil-rich regions of northern Russia, Timan-Pechora (“Exillon TP”) and West Siberia (“Exillon WS”), is pleased to announce that well EWS I – 38 successfully found oil on the eastern part of the East EWS I field, and legacy exploration well EWS I – 1 on the southern part of the EWS I field has been successfully re-completed.

EWS I – 38

EWS I – 38 well which was spudded on 2 March 2011 was drilled in 17 days on an eastern part of the East EWS I field on a turn-key contract for a total consideration of 0.8 million.

The well encountered the Jurassic P reservoir at 1,858m which is 2m higher than previously thought. Results of wire line logging combined with oil shows and sample analysis whilst drilling, have confirmed the presence of at least 9m of net oil pay within the Jurassic. Testing of the well will be completed mid-April.

The well was drilled directionally 1.1km to the north-east from the existing well pad. On completion of testing the well will be connected up to existing production facilities. The well is a result of the continued application of 3D seismic combined with a thorough understanding of reservoir geology.

EWS I – 1

Exploration well EWS I -1 is located on the southern part of the EWS I field. The well was originally drilled in 1971, and was subsequently suspended due to the absence of production infrastructure.

In March 2011, after re-interpreting the well logs, the Group saw that wire line logging indicates the presence of 7.2 m of net oil pay within the Jurassic P reservoir, which represents more than a three fold increase from the previous estimate. The Group perforated additional intervals and the well flowed water-free oil naturally to the surface with a flow rate of 530 bbl/day on a restricted 8 mm choke.

With 19 new successful wells drilled since 2006 the Group continues to maintain 100% drilling success rate, which is the result of continued application of 3D seismic combined with a thorough understanding of reservoir geology.

The ROGTEC Interview: Eric Blossom, Director for Russia & CIS, INOVA

Friday, March 18th, 2011

I understand there have been recent changes at INOVA – what is your position and how long have you held this position?
In March 2010, INOVA Geophysical was formed as the result of a joint venture between ION Geophysical and BGP, the world’s largest geophysical service company. The new venture provided mutual benefits for both companies, ION needed the ability to test its new technology in the field, and BGP needed access to the latest technology. With our new found DNA, INOVA was established already with a compelling advantage in the marketplace.

I came onboard in November 2010 as the Director for Russia and CIS, to enhance INOVA’s customer experience in the Russian/CIS market. It’s critical to our success that we increase our local capabilities. As our presence was once a sales outlet, we are working toward providing a more consistent customer experience with the same local offerings and capabilities as one would expect when interacting with our headquarters.

One major step towards this goal is that we have formed a relationship with xPort Group, a company that provides local inventory of rental equipment and spare parts in the region. They’ve been in this market for some time, and it’s what they do. We hope that our new partnership with them will help increase our opportunities to support our rental business in this region and improve the overall services that our company is able to offer by leveraging their strengths.

How long have you personally been involved within the Russia marketplace? What experience do you have in the regions O&G sector?
I originally came to Russia seven years ago to open ION’s branch office in Moscow. Before that I had traveled throughout Russia and Central Asia in various roles with the company.

One of the many challenges of working in Siberia and other remote areas on time critical projects is having robust, durable equipment at your fingertips. By looking at INOVA’s ARIES II cable-based land recording system and AHV-IV vibrator buggies it’s not too difficult to see that these are best in class products for the environment in which we work.

Since INOVA’s inception, how has business been in Russia? What do you forecast for the coming year?
I think the crisis and the downturn in the O&G business was tough on everyone. We’ve seen consistent growth both within Russia and abroad. We’ve just announced a sale of 13,000 ARIES II channels to outfit a crew in Southern Iraq, and we are making strong headway within the Caspian and Arctic areas of Russia as well.

What is your most recent success in the market?
I would have to say that solidifying the partnership with xPort Group and paving the way ahead for an improved customer experience has been the largest success since November. This will allow us to leverage their experience in the industry in ways that weren’t possible for us before.

Initially, we will be bringing over a considerable investment ($10+ million) in rental inventory into the market and will have an ample rolling inventory of spares. This will greatly enhance the turnaround time and serviceability of our install base, allowing us to better serve our customer’s short term needs.

Have you had any recent product launches for the region?
We are making strong headway with our ARIES II land recording system in the market. This is a product line that has been extremely successful in other Arсtic areas because of its physical ruggedness and robust telemetry system. The system itself can support up to 60,000 channels, along with other features that we see growing in this market such as continuous recording for micro-seismic work. It’s by far the most rugged system, made from bullet-proof polycarbonates, aircraft grade aluminum, and stainless steel, and it’s the only system that can go from land to transition zone in up to 75M of water depth.

Secondly, our new geophysical vibrator buggy, the AHV-IV Commander is also expected to do very well in the region due to it’s newly designed stiffer base plate and re-engineered hydraulic system which delivers lower harmonic distortion and greater fundamental force. This offers a considerable advantage of competitive products where these issues have proven to be a sore spot.

Exploration projects often take a “back seat” for many companies during these tough economic periods – what does the Rosneft / BP deal do to re-ignite interest in the regions exploration sector?
I think that we are all hoping for some stability to be brought out of these new fields and projects. It’s been difficult for us all, including the oil companies, but the more international players that are coming into Russia to work on interesting projects the better. It’s good for Russia’s image as an investment opportunity and it’s good for the local geophysical companies as well. It will be some time before Russia runs out of frontier.

And finally, what do you like best about Moscow?
My family and I have been in Moscow for some time and love the energy here. From a personal perspective, every day is new. It’s an ever evolving place that always holds a new surprise.

From a business perspective, the book is still being written – anything can still be done here.

Russian Offshore: Tapping the Potential Part 2: The Caspian

Friday, March 18th, 2011

Mark Thomas

While the Arctic region is only now opening up its doors, another Russian offshore sector is already forging head with projects – the northern part of the Caspian Sea.

The shallow waters here have seen companies like Lukoil establish itself as a major force in the region, in many sectors such as Azerbaijan as well as Russia’s. With eight large fields discovered and 16 prospective structures identified, recoverable reserves are already put at more than 1 billion tons of oil equivalent.

Last year Lukoil produced first oil from the Yury Korchagin field, discovered in 2000. The ice-resistance production facility is expected to produce recoverable reserves of nearly 29 million tons of oil and 63 Bcm of gas. The operator has invested around $1 billion in this project so far. This pioneering field will be followed by the planned development of the Vladimir Filanovsky field in 2014, and 2 years later the two gas-condensate discoveries Sarmatskoye and Khvalynskoye, all of which will add to the growing logistical infrastructure being established in Astrakhan.

Lukoil estimates a requirement for up to 28 new platforms and more than 1,000km of pipeline to develop these and other oil fields in this area over the next 10 years, representing several billion dollars more of investment.

Many observers now see the Caspian as Russia’s proving ground for testing its capabilities for operating large-scale offshore projects, which can then be transferred to the offshore continental shelf.

Other players have also recognised this. Sweden’s Lundin Petroleum is aiming to resume appraisal of its Morskaya oil discovery in the Russian sector of the Caspian once discussions with potential new partners are complete. The field, discovered in 2008, lies in the Lagansky block where Lundin has recently completed its work program for the year, including the acquisition of 103 square kilometers of 3D seismic.

Far East
Russia’s highest profile offshore sector thus far has of course been Sakhalin, where the Sakhalin I and II projects have established production from this harsh-environment region, and with the required foreign contributions in terms of investment and technologies.

The shelves of the Far East and also Eastern Siberia are known to have highly-promising prospects for large-scale developments, with potential recoverable resources put at billions of tons of oil equivalent. These reserves are mostly concentrated in the Sea of Okhotsk and the Chukchi, Bering and East Siberian Seas. More than 20 oil and gas bearing basins have been identified.

But the Sakhalin shelf very much leads the way, with Exxon, Shell, Marathon and others have already accomplished much to establish producing projects in the eastern and north-eastern areas. ExxonMobil subsidiary Exxon Neftegas Limited recently started up production from the Odoptu field at the Sakhalin-1 project, with the field expected to add up to 11 million barrels (1.5 million tons) to Sakhalin-1 oil production this year (2011). The startup is on schedule and within development cost expectations, it says.

Development of Odoptu has included world-class performance in the drilling and completion of seven extended-reach wells. The Sakhalin-1 project utilises one of the world’s most powerful land-based rigs, which drilled horizontally under the Sea of Okhotsk to the Odoptu oil reservoir more than 9 kilometers offshore.

The Sakhalin-1 project includes the phased development of the Chayvo, Odoptu and Arkutun-Dagi fields, with an estimated total resource of 2.3 billion barrels (307 million tons) of oil and 17 trillion cubic feet (485 billion cubic meters) of natural gas. Chayvo, which was the initial phase of the project, began producing in 2005. Odoptu will produce around 30,000 barrels per day in 2011, with total output at Sakhalin-1 expected to hit 156,000 b/d.

Future project phases will see the development of the Arkutun-Dagi field as well as expanded gas production and sales from the Chayvo field. These later phases will sustain production well into the future, says the operator.

The main immediate development activity going forward in this area is on Gazprom’s Sakhalin III project, where as part of the project it has opted for a subsea production system to develop the Kirinskoye field.

Significantly, this will be the country’s first all-subsea (subsea-to-beach) development, to be carried out by FMC Technologies. FMC recently signed a letter of intent for the Grenland Group to fabricate and deliver a manifold and foundation plus two protection structures for use on the field. Delivery is scheduled to start in the second quarter of 2011 and the total weight of the hardware will be around 450 metric tons.

The field lies in water depths of approximately 90 metres within the Kirinsky block of the Sakhalin III project, 28 kilometres offshore Sakhalin Island. Gazprom plans to perform follow-up exploration drilling and studies over the next 3 years, it says.

Sakhalin III is also made up of the Vostochno-Odoptinsky and Ayashky blocks. Gazprom estimates current discovered gas reserves within the Sakhalin III area at 1.4 Tcm. The gas will be exported through the Sakhalin-Khabarovsk-Vladivostok pipeline system.

On top of the above offshore sectors, Russia’s emerging plays also include other high-potential areas including the Baltic Sea, Black Sea and Azov Sea, where exploration has been carried out or is underway, and where in some cases developments have taken place.

The number of potential upcoming development projects throughout Russia’s offshore sector are almost too numerous to mention. But the sector looks set to become one of the world’s necessarily most innovative and industrious offshore plays, where the adaptation of existing technologies and the adoption of new breakthroughs will both be required if Russia’s offshore future is to match its breathtaking onshore past.

Russian Arctic Thaws with Rosneft-BP Deal

Friday, March 18th, 2011

Mark Thomas

Russia’s offshore arctic shelf has become one of the most scrutinized frontier oil and gas sectors in the world, thanks to the ground-breaking deal done between Rosneft and BP. But while most western observers have chosen to look at what the agreement means in terms of benefits for the UK oil major, for some the big question is: What’s in it for Russia’s offshore future?

The Rosneft/BP deal has injected huge interest and momentum into the potential of Russia’s Arctic offshore because the area remains one of the last great untapped resources for accessing new hydrocarbon reserves.

With several western oil majors having jockeyed for position in recent years to place themselves in line for some of Russia’s virgin Arctic exploration territory, including ExxonMobil, Total, Shell, ConocoPhillips and Statoil to name but a few, BP’s mega-deal gives it an unmatched exploratory position in Russia that will be regarded enviously by its rivals.

The UK major’s commercial motivation for the arrangement is simple – it gets access to 125,000 square kilometers of prime prospective territory in the South Kara Sea that, by Russian estimates, could contain around 35 billion barrels of oil and 10 trillion cubic feet of natural gas. “A major oil company’s growth potential in increasingly defined by its ability to penetrate national oil company turf,” said a research note from analysts Bernstein Research. BP has achieved this in spades, and it is a strategy the company is systematically employing globally as it cautiously moves on from its Deepwater Horizon nightmare in the US Gulf. For example, it revealed a partnership just weeks later with Reliance Industries that also gives it access to huge areas of frontier deepwater acreage offshore India.

But that company-threatening time that followed in the aftermath of the Horizon incident has, paradoxically, helped it cement its relationship with Russia. The Russian government appears to appreciate what BP has been through, and the fact that it has lived to tell the tale.

The operator’s experience in the Gulf of Mexico, “provided the company with one of its competitive advantages, which we will rely upon as we develop offshore,” said Igor Sechin, Russia’s Deputy Prime Minister and Chairman of Rosneft.

Prime Minister Vladimir Putin agreed, expressing the same sentiment in typically sardonic fashion by quoting the old Russian proverb: “One beaten is worth two unbeaten.”

The question remains, however: What’s in it for Russia?

From Rosneft’s perspective the company will benefit because a large majority of its existing oil production comes from declining regions in the Urals and Western Siberia. At the same time it recognises that it currently lacks both the technical know-how and available cash reserves to open up the Arctic’s potentially vast offshore riches.

BP, of course, has the upstream exploration and development technology, personnel, project management skills and available funds to help Rosneft achieve its growth aims.
It does have to first overcome Anglo-Russian joint venture TNK-BP’s initial objections, which lead to that company’s Russian shareholders blocking the deal via a London court injunction. But with TNK-BP’s management essentially angling for a possible participating role in its UK parent’s alliance with Rosneft, and TNK-BP’s Board currently in discussions about it as ROGTEC went to press, this is seen more as a matter of arbitration rather than as a deal-breaking dispute.

In offshore terms Russia remains largely untouched, with only the country’s Sakhalin region currently possessing producing fields in the Arctic. Projects are in the pipeline to come onstream over the next 5 or 6 years, most notably Gazprom’s flagship Shtokman field in the Barents Sea but significant doubts remain over their schedules.

Smaller projects will come onstream first, such as the Prirazlomnoye oil field in the Pechora Sea and the Kamennomskoye More gas field in Obskaya bay but the major part of future offshore spending predictions by observers are based on Shtokman progressing to an onstream date by 2016 or 2017. Some would say that is far too optimistic, especially with the changing nature of the global gas market caused by the emergence of cheaper shale gas opportunities around the world.

The Rosneft/BP strategic alliance, the first major equity-linked partnership between a National Oil Company and an International Oil Company, sees Rosneft take 5% of BP’s ordinary voting shares in exchange for approximately 9.5% of Rosneft’s. They will establish a joint operating company (Rosneft 66.67%/BP 33.33%).

The deal will first spark exploration activity in the South Kara Sea but few expect it to remain focused on just that area, large though it is. Initially the two companies will explore and develop three licences – EPNZ 1, 2 and 3 – on the Arctic continental shelf.

These licences off Russia’s northern coast were awarded to Rosneft last year and both companies are banking on finding substantial reserves of oil and gas, although it will take several years to find, appraise and develop initial discoveries. So the benefits may not be seen until nearer the end of this decade, in terms of booked reserves.

Of more significance to many is the agreement by the two companies to establish an Arctic technology centre in Russia that will work with leading Russian and international research institutes, design bureaus and universities “to develop technologies and engineering practices for the safe extraction of hydrocarbon resources from the Arctic shelf”. The technology centre will build on BP’s deepwater experience and learnings, with full emphasis on safety, environmental integrity and emergency spill response capability.

They have also agreed to continue their joint technical studies in the Russian Arctic to assess hydrocarbon prospectivity in areas beyond the Kara Sea, in other words the country’s Arctic continental shelf is essentially an open playing field for them. BP’s chief executive, Bob Dudley (himself a former head of TNK-BP, and hugely experienced in dealing with the Russian authorities), said the agreement would see them “jointly explore some of the most promising parts of the Russian Arctic, one of the world’s last remaining unexplored basins”.

Rosneft’s President, Eduard Khudainatov, described it as a move that would significantly move forward his company’s – and country’s – offshore strategy.

It is a strategy that must work. Russia’s need to find and develop its offshore Arctic resources is paramount, as its existing production threatens to tail off from its maturing fields onshore.

It has been the growing awareness that it is in danger of reaching something of a cliff, in terms of its production plateau, that has pushed it into acting relatively quickly to try and access an estimated 132 billion boe of oil and gas resources lying in its Western Siberian Basin, both on and offshore. That equates to around 32% of the entire Arctic region, with around 108 Bn boe made up of gas, 20 Bn boe of natural gas liquids and 4 Bn bbl of oil.

According to industry analysts Infield Systems, no less than 95 billion boe of these reserves are gas reserves lying in Russia’s offshore Arctic region (and not including Sakhalin Island). This represents 70% of the total offshore reserves in designated Arctic and sub-Arctic regions, says the analyst. The bulk of these reserves are fields operated by Gazprom subsidiary Sevmoreneftegaz, and Rosshelf, in which Gazprom has a 56.8% stake and Rosneft a further 26.4%).

There are discoveries already out there to be developed – data shows at least seven discovered offshore gas fields in the Basin, including three in the Kara Sea and four in the Tazovskoya and Obskaya Bays to the east of the Yamal Peninsula. That’s on top of discoveries such as Rusanovskoe and Leningradskoe that alone are estimated to hold 5 trillion cubic metres of gas.

The resulting business opportunities that also lie offshore are also potentially huge.  Infield estimates in its new ‘Offshore Arctic Oil and Gas Report’ that just over US $33 billion in capital expenditure will be spent over the period 2008-2017 on pipelines/control lines, floating production units, fixed platforms and subsea infrastructure in international Arctic regions.

Of that, just over half (nearly $18 billion) of that global Arctic spend is expected to be invested offshore Russia. With projects such as Prirazlomnoye and Shtokman planned to come onstream within the next 5 years or so, Infield says it expects Russia to drive Arctic offshore oil and gas Capex until at least 2017.

The investment will also see a growing number of exploration wells throughout Russia’s offshore sectors, not only in the Barents and Kara Seas but also the Pechora, Northern Caspian, Azov, Okhotsk, Chukchi and Bering Seas as well as offshore Sakhalin.

This leads, however, into an area that will require significant focus by the oil industry and international drilling contractors, that of appropriately qualified rigs. With circa 800 offshore rigs around the world, it should be of concern to all players eyeing Arctic opportunities that only 1% of these units are currently suitable for operations in the ultra-harsh waters of the Arctic, with only eight either possessing ice-class classifications and/or having significant Arctic experience.

These include the Aker Barents and Aker Spitsbergen semisubmersibles operating in the Norwegian North Sea, and the Noble Discoverer, soon to be drilling offshore Canada and Alaska’s Arctic coastline. Of these eight drilling units four are operational in Norway, two in Egypt and New Zealand, and a further two idle in China and the US, according to Infield.

The good news is that there are six ultra-harsh Arctic capable newbuilds that are expected to be delivered before the end of this year. Features such as ice-class hulls, increased deck loads and fully winterised equipment will allow these rigs to operate in and around the Arctic, while also being fully capable of operations elsewhere in the world. Three are intended for indefinite work off Russia’s Arctic coast, while two Noble ‘Bully’ drillships are already contracted with Shell for the next 10 years, most likely for work initially offshore Alaska.

The other unit is the Arctic-dedicated Stena DrillMAX ICE. At a cost of $1.15 billion to build, it will be the most expensive drilling rig ever built.

Such a scarcity of suitable rigs for future Arctic operations will be of concern to Russia, and is likely to result in several further newbuilds being ordered for construction within the next 5 years, specifically for the country’s own offshore sector. Some observers believe Rosneft and BP may well sign long-term drilling contracts, such as Shell did with Noble Drilling for the Bully-design drillships, to ensure they have sufficient units to meet the demands of their future drilling programmes.


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